2006Annual Report Part I.pdf

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Salt lake City, Utah 84111
June 13, 2007
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Idaho Public Utilities Commission
472 West Washington
Boise, ID 83702-5983
Attention:Jean D. Jewell
Commission Secretary
Re:2006 FERC Form
PacifiCorp (d.a. Rocky Mountain Power) hereby submits for filing an original and seven (7)
conformed copies of its 2006 FERC Form 1. The 2006 FERC Form 1 is not available in
electronic format and will be provided hard copy via overnight delivery.
It is respectfully requested that all formal correspondence and Staff requests regarding this
material be addressed to:
Bye-mail (preferred):datarequest~pacifi corp. com
By regular mail:Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, Oregon, 97232
By fax:[phone]
Informal questions should be directed to Brian Dickman at [phone].
Sincerely,
)( ~/
1?JJeffrey K. Larsen
Vice President, Regulation
Enclosures
, '
THIS FILING IS
Item 1: 00 An Initial (Original)
Submission
,',
ORD Resubmission No.
FERC FINANCIAL REPORT
FERC FORM No.1: Annual Report of
Major Electric Utilities Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and
18CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Exact Legal Name of Respondent (Company)
PacifiCorp
Form 1 Approved
OMB No. 1902-0021
(Expires 7/31/2008)
. Form 1-F Approved
OMB No. 1902-0029
" (Expires 6/30/2007)
Form 3-QApproved
OMB No. 1902-0205
(Expires 6/30/2007)
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End of
Year/Period of Report
2006/Q4
FERCFORM No.1/3-Q (REV. 02-04)
INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and
GENERAL INFORMATION
Purpose
FERC Form No.1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others
(18 C.R. 9 141.1). FERC Form No. 3-Q ( FERC Form 3-Q)is a quarterly regulatory requirement which supplements the
annual financial reporting requirement (18 C.R. 9 141.400). These reports are designed to collect financial and
operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy
Regulatory Commission. These reports are also considered to be non-confidential public use forms.
II. Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission s Uniform System of Accounts
Prescribed for Public Utilities and Licensees Subject To the Provisions of The Federal Power Act (18 C.R. Part 101),
must submit FERC Form 1 (18 C.R. 9141.1), and FERC Form 3-Q (18 C.R. 9141.400).
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).
III.What and Where to Submit
(a) Submit FERC Forms 1 and 3-Q electronically through the forms submission software. Retain one copy of each report
for your files. Any electronic submission must be created by using the forms submission software provided free by the
Commission at its web site: http://www.ferc.Qov/docs-filinQ/eforms/form-1/elec-subm-soft.asp. The software is
used to submit the electronic filing to the Commission via the Internet.
(b) The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
(c) Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the
latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to
the Secretary of the Commission at:
Secretary
Federal Energy Regulatory Commission
888 First Street, NE
Washington , DC 20426(d) For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1 , a letter or report (not
applicable to filers classified as Class C or Class D prior to January 1 1984). The CPA Certification Statement can be
either eFiled or mailed to the Secretary of the Commission at the address above.
FERC FORM 1 & (ED. 03-07)
The CPA Certification Statement should:
Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the
Commission s applicable Uniform System of Accounts (including applicable notes relating thereto and the
Chief Accountant's published accounting releases), and
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
R. 9941.10-41.12 for specific qualifications.
Reference Schedules PaQes
Comparative Balance Sheet
Statement of Income
Statement of Retained Earnings
Statement of Cash Flows
Notes to Financial Statements
110-113
114-117
118-119
120-121
122-123
The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions
explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are
reported.
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.
The letter or report must state which, if any, of the pages above do not conform to the Commission s requirements.
Describe the discrepancies that exist.
(f) Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling.
To further that effort, new selections
, "
Annual Report to Stockholders " and "CPA Certification Statement" have been
added to the dropdown "pick list" from which companies must choose when eFiling. Further instructions are found on the
Commission s website at http://www.ferc.Qov/help/how-to.asp
(g) Federal, State and Local Governments and other authorized users may obtain additional blank copies of
FERC Form 1 and 3-Q free of charge from http://www.ferc.Qov/docs-filinQ/eforms/form-1/form-pdf and
http://www.ferc.Qov/docs-filinQ/eforms.asp#3Q-Qas
IV. When to Submit:
FERC Forms 1 and 3-Q must be filed by the following schedule:
FERC FORM 1 & 3-0 (ED. 03-07)
a) FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR 9141.1), and
b) FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. 9
141.400).
V. Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC 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. The public reporting burden for
the FERC Form 3-Q 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: Information Clearance Officer); 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. 93512 (an.
FERC FORM 1 & (ED. 03-07)iii
GENERAL INSTRUCTIONSI. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret
all accounting words and phrases in accordance with the USofAII. 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 "
" "
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 submission software only. Please explain
the reason for the resubmission in a footnote to the data field.
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 periodlyear, or an appropriate explanation given as to why the different
figures were used.
Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:
FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons
and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as
described in Order No. 888 and the Open Access Transmission Tariff. "Self' means the respondent.
FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as
described in Order No. 888 and the Open Access Transmission Tariff.
LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and" firm
means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse
conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access
Transmission Tariff. For all transactions identified as LFP, provide in a footnote the
FERC FORM 1 & (ED. 03-07)
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 FERC 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. Commission 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 1 & 3-0 (ED. 03-07)
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 with:
(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 shall 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 and 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 fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there
from 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 the 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 may prescribe the manner and FERC Form in
which such reports salt 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 1 0
FERC FORM 1 & (ED. 03-07)
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 FERC Form or FERC 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
The Commission may assess up to $1 million per day per violation of its rules and regulations. See
FPA ~ 316(a) (2005),16 V.C. ~ 8250(a).
FERC FORM 1 & (ED. 03-07)vii
IDENTIFICATION
01 Exact Legal Name of Respondent 02 Year/Period of Report
PacifiCorp End of 2006/Q4
03 Previous Name and Date of Change (if name changed during year)
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
825 N.E. Multnomah, Suite 1900 Portland, OR 97232
05 Name of Contact Person 06 Title of Contact Person
Henry E. 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] 04/06/2007
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
~~:?
04 Date Signed
David J. Mendez (Mo, Da, Yr)
02 Title
Senior VP & Chief Financial Officer David J. Mendez 1/7 I)
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-
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 2006/04(2) n A Resubmission 05/17/2007
LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none
" "
not applicable," or "NA," as appropriate , where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable " or "NA"
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
Genera/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)
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
Transmission Service and Generation Interconnection Study Costs 231
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 Debt 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
Long-Term Debt 269
FERC FORM NO.1 (ED. 12-96)Page 2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) n A Resubmission 05/17/2007
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none,
" "
not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none,
" "
not applicable," or "NA"
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273
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 ISO/RTOs 331
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
Amounts included in ISO/RTO Settlement Statements 397
Purchase and Sale of Ancillary Services 398
Monthly Transmission System Peak Load 400
Monthly ISO/RTO Transmission System Peak Load 400a
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
FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/Q4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) FiA Resubmission 05/17/2007
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none
" "
not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none
" "
not applicable " or "NA"
(a)
Reference
Page No.
(b)
426-427
450
RemarksLine
No.
Title of Schedule
(c)
67 Substations
68 Footnote Data
Stockholders' Reports Check appropriate box:
I!J Four copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO.1 (ED. 12-96)Page 4
Name of Respondent
PacifiCorp
This Report Is:
(1) 00 An Original(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/04
GENERAL INFORMATION
1 . Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
David J. Mendez. Senior Vice President and Chief Financial Officer
825 N.E. Multnomah. Suite 1900
Portland. OR 97232-4116
Corporate books are kept at:
825 N.E. Multnomah. Suite 1900
Portland. OR 97232-4116
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
Incorporated on August 11. 1987 in the State of Oregon.
3. If at any time during the year the property of respondent was held by a receiver or trustee , give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession , (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not applicable.
Not applicable.
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
The Company is a regulated electric company operating in portions of the states of Utah, Oregon.
Wyoming, Washington, Idaho and California. The Company conducts its retail electric utility business as
Pacific Power and Rocky Mountain Power, and engages in electricity production and sales on a wholesale
basis under the trade name PacifiCorp Energy.
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) 00 Yes...Enter the date when such independent accountant was initially engaged: 05/31/2006(2) 0
FERC FORM No.1 (ED. 12-87)PAGE 101
Name of Respondent
PacifiCorp
This Report Is:
(1) 00 An Original(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
CONTROL OVER RESPONDENT
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.
Berkshire Hathaway Inc.
MidAmerican Energy Holdings Company (100%)(88.2% controlled by Berkshire Hathaway Inc.
PPW Holdings llC (100% controlled by MidAmerican Energy Holdings Company)
PacifiCorp (99.78% controlled by PPW Holdings llC)
FERC FORM NO.1 (ED. 12-96)Page 102
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
CORPORATIONS CONTROLLED BY RESPONDENT
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.
(a)(b)
Percent Voting
Stock Owned
(c)
100
Footnote
Ref.
(d)
Line
No.
Name of Company Controlled Kind of Business
Energy West Mining Company
Glenrock Coal Company
Mining
Mining 100
100
Interwest Mining Company
Pacific Minerals, Inc.
Mining
Mining
Mining
Mining
100
100
Environmental Services
66.
90.
Rain Forest Carbon Credits
Management Services for PERCo
100
100
Mining
Steam Delivery Service
21.40
100
Steam Delivery Service 100
FERC FORM NO.1 (ED. 12-96)Page 103
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmisslon 05/17/2007 2006104
FOOTNOTE DATA
ISchedule Page:03 Line No.Column:
In May 2000, the assets of Centralia Mining Com any were sold to TransAlta.
~chedule Page: 103 Line No.Column:
Idaho Power Corp. holds a 33.33% ownership interest in Bridger Coal Company. PacifiCorp s interest is held through Pacific
Minerals, Inc.
~chedule Page: 103 Line No.Column:
CH2MHill holds a 10.0% ownership interest in PacifiCorp Environmental Remediation Company.
chedule 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.
~chedule 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 Authori 19.93% .
chedule Pa e: 103 Line No.12 Column:
In July 2006, Intennountain Geothennal Company purchased all of the outstanding capital stock of Steam Reserve Corporation.
For a further discussion of Intennountain Geothennal Company not described in this item, refer to ITEM 2 of the Important Changes
During the Year of this Fonn No.
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 2006/04(2) nA Resubmission 05/17/2007
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 Title Name of Officer . S~~ary
No.for Year
(a)(b)(c)
~.,
Chairman of the Board and Chief Executive Officer
Senior Vice President and Chief Financial Officer 192,917
President, PacifiCorp Energy 201,Q42
President, Pacific Power 746
President, Rocky Mountain Power 330,811
Sr. VP, General Counsel & Corporate Secretary 254,463
President and Chief Executive Officer 101 355
Chief Financial Officer and Senior Vice President 398,791
Executive Vice President 645,683
Executive Vice President 703,187
Senior Vice President 577,469
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 Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
!Schedule Page: 104 Line!,/o.Column:
PacifiCorp sets forth the salary information for its "named executive officers" for the year ended December 31 , 2006, consistent with
Item 402 of Regulation S-K s promulgated by the Securities and Exchange Commission. Salary information of other officers will be
provided to the Commission upon request, but the company considers such information personal and confidential to such Officers. See
18 CFR 388.107 d ,(t).
chedule Pa e: 104 Line No.Column: b
For additional information regarding changes in the status of PacifiC ore s officers refer to page 108 Important Changes During the
Year ITEM 13, of this Form No.1. Mr. Able receives no direct compensation from PacifiCorp. PacifiCorp reimburses MERC for the
cost of Mr. Abel's time spent on PacifiCorp matters, including compensation paid to him by MERC, pursuant to an intercompany
administrative services agreement among MERC and its subsidiaries. Please refer to MERC's annual report on Form IO-K for the year
ended December 31 2006 File No. 001-14881 for executive com ensation information for Mr. Abel.
chedule Pa e: 104 Line No.Column: b
For additional information regarding changes in the status ofPacifiCorp s officers refer to page 108 Important Changes During the
Year ITEM 13, of this Form No.
!Schedule Page: 104 Line No.Column: b
For additional information regarding changes in the status ofPacifiCorp s officers refer to page 108 Important Changes During the
Year ITEM 13, of this Form No.
!Schedule Page: 104 Line No.Column: b
For additional information regarding changes in the status ofPacifiCorp s officers refer to page 108 Important Changes During the
Year ITEM 13, of this Form No.
!Schedule Page: 104 Line No.Column: b
For additional information regarding changes in the status ofPacifiCorp s officers refer to page 108 Important Changes During the
Year ITEM , of this Form No.
~chedule Page: 104 Line No.Column: b
For additional information regarding changes in the status ofPacifiCorp s officers refer to page 108 Important Changes During the
Year ITEM 13, of this Form No.1. Mr. Railer resigned as a director and executive officer ofPacifiCorp effective December 31 , 2006.
Total remuneration, includin severance benefits, for the eriod of Janua 1 2006 to December 31, 2006 was $3 254 463.
chedule Pa e: 104 Line No.Column:
PacifiCorp sets forth the salary information for its "named executive officers" for the year ended December 31 , 2006, consistent with
Item 402 of Regulation S-K s promulgated by the Securities and Exchange Commission. Salary information of other officers will be
provided to the Commission upon request, but the company considers such information personal and confidential to such Officers. See
18 CFR 388.107 d
chedule Pa e: 104 Line No.10 Column: b
For additional information regarding changes in the status ofPacifiCorp s officers refer to page 108 Important Changes During the
Year ITEM 13, of this Form No.1. Ms. Johansen resigned as a director and executive officer ofPacifiCorp on March 21, 2006. Total
remuneration, includin severance benefits, for the eriod ofJanua 1 2006 to March 21 , 2006 was $3 101 355.
chedule Pa e: 104 Line No.11 Column: b
For additional information regarding changes in the status ofPacifiCorp s officers refer to page 108 Important Changes During the
Year ITEM 13, of this Form No.1. Mr. Peach resigned as a director and executive officer ofPacifiCorp on November 22 2006.
Total remuneration, including severance benefits, for the period of January 1 2006 to December 31 2006 was $2 398 791.
!Schedule Page: 104 Line No.12 Column: b
For additional information regarding changes in the status ofPacifiCorp s officers refer to page 108 Important Changes During the
Year ITEM 13, ofthis Form No.1. Mr. Wright resigned as a director and executive officer of PacifiCorp on March 21 , 2006. Total
muneration, includi.t:!g severance benefits, for the period ofJanuary 1 2006 to March 21 , 2006 was $1 645 683.
!Schedule Page: 104 Llt'Je No.13 Column: b
For additional information regarding changes in the status ofPacifiCorp s officers refer to page 108 Important Changes During the
Year ITEM 13, of this Form No.1. Mr. MacRitchie resigned as a director and executive officer ofPacifiCorp on March 21 , 2006.
Total remuneration, includi!!g severance benefits, for the period ofJanua
!)'
2006 to March 21 , 2006 was $1 703 187.
!Schedule Page: 104 Line No.olumn: b
---
For additional information regarding changes in the status ofPacifiCorp s officers refer to page 108 Important Changes During the
Year ITEM 13, ofthis Form No.1. Mr. Watters resigned as President of Pacific Power, on September 15 2006. Total earnings for the
period of January 1 2006 to September 15, 2006 was $577 469.
I FERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent
PacifiCorp
This ~ort Is:(1) ~An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
FERC FORM NO.1 (ED. 12-95)Page 105
666 Grand Avenue, Suite DM29, Des Moines, Iowa 50309
1407 West North Temple, Suite 320, Salt Lake City, Utah 84116
825 NE Multnomah, Suite 2000, Portland, Oregon 97232
201 South Main, Suite 2400, Salt Lake City, Utah 84140
302 South 36th Street, Omaha, Nebraska 68131
825 NE Multnomah, Suite 2000, Portland, Oregon 97232
666 Grand Avenue, Suite DM29, Des Moines, Iowa 50309
4695 South 1900 West #3, Roy, Utah 84067
1407 West North Temple, Suite 320, Salt Lake City, Utah 84116
825 NE Multnomah, Suite 2000, Portland, Oregon 97232
201 South Main, Suite 2400, Salt Lake City, Utah 84140
825 NE Multnomah, Suite 2000, Portland, Oregon 97232
1 Atlantic Quay, Glasgow, Scotland G2 8SP UK
825 NE Multnomah, Suite 2000, Portland, Oregon 97232
825 NE Multnomah, Suite 2000, Portland, Oregon 97232
825 NE Multnomah, Suite 2000, Portland, Oregon 97232
825 NE Multnomah, Suite 2000, Portland, Oregon 97232
1407 West North Temple, Suite 320, Salt Lake City, Utah 84116
1 Atlantic Quay, Glasgow, Scotland G2 8SP UK
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006104
FOOTNOTE DATA
ISchedule Page: 105 Line No.Column:
Mr. Abel was elected March 21 , 2006. For additional infonnation regarding Mr. Abel refer to Page 108 Important Changes During
the Year Item 13, of this Fonn No. 1.
urrently there is only one committee, a Compensation Committee, of which the sole member is Mr. Abel.
~chedule Page: 105 Line No.Column:
Mr. Fehnnan was elected March 21 2006. For additional infonnation regarding Mr. Fehnnan refer to Page 108 Important Changes
During the Year Item 13, of this Fonn No. 1.
~chedule Page: 105 Line No.Column:
Mr. Reiten was elected September 15 2006. For additional infonnation regarding Mr. Reiten refer to Page 108 Important Changes
Durin the Year Item 13, of this Fonn No.
chedule Page: 105 Line No.Column:
Mr. Anderson was elected March 21, 2006. For additional infonnation regarding Mr. Anderson refer to Page 108 Important Changes
During the Year Item 13, of this Fonn No.
ISchedule Page: 105 Line No.Column:
Mr. Gale was elected March 21 , 2006. For additional infonnation regarding Mr. Gale refer to Page 108 Important Changes During
the Year Item 13, of this Fonn No.
ISchedule Page: 105 Line No.Column:
Mr. Goodman was elected March 21, 2006. For additional infonnation regarding Mr. Goodman refer to Page 108 Important Changes
uring the Year Item 13, of this Fonn No.
~chedule Page: 105 Line No.10 Column:
Mr. Lasich was elected March 21 , 2006. For additional infonnation regarding Mr. Lasich refer to Page 108 Important Changes
Durin the Year Item 13, of this Fonn No.
chedule Page: 105 Line No.11 Column:
Mr. Haller resigned December 31 2006. For additional infonnation regarding Mr. Haller refer to Page 108 Important Changes
Durin the Year Item 13, of this Fonn No.
chedule Page: 105 Line No.12 Column:
Mr. Moench was elected March 21 , 2006. For additional infonnation regarding Mr. Moench refer to Page 108 Important Changes
uring the Year m 13, of this Fonn No.
~chedule Page: 105 Line No.13 Column:
Mr. Watters was elected March 21 , 2006. For additional infonnation regarding Mr. Watters refer to Page 108 Important Changes
uring the Year Item 13, ohhis Fonn No.
~chedule Page: 105 Line No.16 Column:
Mr. Russell resi ed Janu 16 2006.
chedule Pa e: 105 Line No.17 Column:
Ms. Johansen resigned March 21, 2006. For additional infonnation regarding Ms. Johansen refer to Page 108 Important Changes
Durin the Year Item 13 , of this Fonn No.
chedule Page: 105 LineNo.18 Column:
Mr. Peach resigned November 22, 2006. For additional infonnation regarding Mr. Peach refer to Page 108 Important Changes
During the Year Item 13 , of this Fonn No.
~chedule Page: 105 Line No.19 Column:
Mr. MacRitchie resigned March 21 2006. For additional infonnation regarding Mr. MacRitchie refer to Page 108 Important
anges During the Year Item 13, of this Fonn No. 1.__~__n_u ,--
----~-
~hedule Page: 105 Line No.20 Column:
-- ----,-
Mr. Wright resigned March 21 2006. For additional infonnation regarding Mr. Wright refer to Page 108 Important Changes During
the Year Item 13, of this Fonn No.
~chedule Page: 105 ine No.21 Column:
---..---
Mr. Cunningham resigned March 21 , 2006. For additional infonnation regarding Mr. Cunningham refer to Page 108 Important
Changes During the Year tem 13, ohms Fonn No.
ISchedule Page: 10 ~Y!!.~..N~~Column:
--~-
-_u
Mr. Dunn resigned March 21 , 2006. For additional infonnation regarding Mr. Dunn refer to Page 108 Important Changes During the
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
Year Item 13, of this Form No.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
PacifiCorp
This Report Is: Date of Report(1) ~ An Original
(2) 0 A Resubmission 05/17/2007
IMPORTANT CHANGES DURING THE QUARTERIYEAR
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 fumish 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.
Year/Period of Report
End of 2006/Q4
PAGE 108 INTENTIONAllY lEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 108
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da , Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
ITEM 1.
Changes in Franchise Rights
State Effective Date Expiration Date Fee %
(Fee attached to franchise agreement)
California (a)
Siskiyou County 1/12/2006 1/12/2021
Idaho (b)
None
Orel!On (c)
Powers 03/20/2006 03/20/2016
Roseburg 04/08/2006 04/08/2016
Shady Cove 07/01/2006 06/30/2023
Pendleton 08/01/2006 (e)
Winston 08/05/2006 08/05/2016
Cave Junction 09/29/2006 09/29/2026
Canyonville 10/16/2006 10/16/2016
Cottage Grove 10/09/2006 10/09/2016
Utah (b)
Lehi/Micron Plant 04/07/2006 04/0712007
Panguitch 04/07/2006 04/0712011
Sevier County 05/04/2006 05/04/2031
Murray City 06/05/2006 06/05/2031
Glenwood 06/30/2006 06/30/2016
Herriman 07/01/2006 08/19/2019
Centerville City 10/11/2006 10/11/2011
North Salt Lake 10/24/2006 10/24/2011
Rush Valley 10/25/2006 10/25/2026
Alpine 11/28/2006 11/28/2026
Washineton (b)
None
omin (d)
Diamondville 01/16/2006 01/16/2026 1.0%
Big Piney 03/14/2006 03/14/2026 1.0%
Sinclair 04/07/2006 04/07/2016
Wamsutter 04/19/2006 04/19/2026
Bairoil 06/19/2006 06/19/2031
(a) In the state of Cali fomi a, franchise fees are an expense to PacifiCorp and are embedded in rates.
(b) In the states ofIdaho, Utah and Washington, PacifiCorp collects franchise fees from customers and remits them directly to the
applicable municipalities.
(c) In the state of Oregon, the fITst 3.5% ofthe franchise fee is an expense to PacifiCorp and is embedded in rates. For any amount
above the 3., PacifiCorp collects franchise fees from customers and remits them directly to the applicable municipalities.
(d) In the State of Wyoming, the first 1.0% of the franchise fees is an expense to PacifiCorp and is embedded in rates. For any
IFERC FORM NO.1 (ED. 12-96) Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1)~AnOriginal (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 05/1712007 2006/04
IMPORTANT CHANGES DURING THE OUARTERIYEAR (Continued)
amount above the 1., PacifiCorp collects franchise fees from customers and remits them directly to the applicable
municipalities.
(e) On June 6, 2006, the Pendleton City Council adopted Ordinance 3733 , amending Ordinance 2814. This ordinance remains
effective indefinitely.
ITEM 2.
Acquisition of Ownership in Other Companies
PacifiCorp Environmental Remediation Company
PacifiCorp Environmental Remediation Company ("PERCo ) became a wholly owned subsidiary ofPacifiCorp in April 2007, when
PacifiCorp acquired the outstanding 10% minority interest in PERCo for $150 000.
Intermountain Geothermal
As a result of a settlement agreement between MidAmerican Energy Holdings Company ("MEHC"), the Utah Committee of Consumer
Services and Utah Industrial Energy Consumers, MEHC contributed to PacifiCorp, at no cost, MEHC's indirect 100.0% ownership
interest in Intennountain Geothennal Company, which controls 69.3% of the steam rights associated with the geothennal field serving
PacifiCorp s Blundell geothennal plant in Utah. Intennountain Geothennal Company ("IGC") therefore became a wholly owned
subsidiary ofPacifiCorp in March 2006, subsequent to the sale ofPacifiCorp to MEHC.
Steam Reserve Corporation
In July 2006, IGC purchased all of the outstanding capital stock of Steam Reserve Corporation, which controls 24.0% of the steam
rights associated with the geothennal field serving PacifiCorp s Blundell geothennal plant in Utah. As a result, Steam Reserve
Corporation became a wholly owned subsidiary ofIGC in July 2006. Commission authorization was not required.
With this purchase and the purchase disclosed in ITEM 4, Intennountain Geothennal now owns 94.5% ofthe steam rights associated
with the geothermal field serving PacifiCorp s Blundell geothennal plant.
For a further discussion ofIGC not described in this item, refer to ITEM 4 of this Fonn No.
ITEM 3.
Purchase or Sale of an Operating Unit
Sale of Upper Beaver Hydro Project
In March 2006, PacifiCorp and the city of Beaver, Utah entered into a Project Purchase Agreement whereby PacifiCorp would request
approval from its state regulators to sell the Upper Beaver Hydro Project to the City of Beaver, Utah. The sale is contingent upon a
number of items, one of which is the separation of the generation and transmission and distribution facilities in the power plant
switchyard to facilitate wheeling ofthe future power generated. The sale is expected to close in mid-2007.
ITEM 4.
Important Leaseholds
West Valley Generating Facility
In May 2002, PacifiCorp entered into a IS-year operating lease for an electric generation facility with West Valley Leasing Company,
LLC ("West Valley ). West Valley is an indirect subsidiary ofPacifiCorp s fonDer parent ScottishPower PLC. The facility consists of
five generation units, each rated at 40 megawatts ("MW"), and is located in Utah. The lease tenDS granted PacifiCorp two independent
early tennination options that provide PacifiCorp the right to tenninate the lease and, at PacifiCorp s further option, to purchase the
facility for predetennined amounts. On May 28, 2004, PacifiCorp exercised its fIrSt option to tenninate the lease and subsequently
exercised its right to rescind the tennination on September 28, 2004. On December 1 2006, PacifiCorp waived its option to purchase
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 05/17/2007 2006/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
the facility under the lease for $122.5 million and exercised its second option to tenninate the lease. As such, PacifiCorp is committed
to future minimum lease payments of $1 0.0 million for the year ending December 31 , 2007 and $4.4 million for the year ending
December 31 , 2008.
Lake Side Gas Lateral
In February 2005, PacifiCorp entered into a 30-year Agreement for Firm Transportation to PacifiCorp Lake Side Generating Facilities
TSA") with Questar Gas Company ("Questar ). The TSA sets forth the tenns for the provision of natural gas transportation service
to the Lake Side power plant and construction of an approximately 5.3-mile natural gas pipeline and facilities necessary to connect the
Lake Side power plant to Questar's existing feeder line.
The construction of the pipeline was declared "substantially complete" by Questar on November 9, 2006 and final construction costs
are being accumulated to facilitate the calculation of the initial monthly reservation ("IMR") charge, initially estimated at $1.04654 per
decathenn based on usage of a minimum 190 000 decathenns per month. The reservation charges decrease to 85% of the IMR for
years six through ten, to 70% of the IMR for years eleven through fifteen and to 55% of the IMR for years sixteen through thirty. The
estimated monthly charges under the TSA also include a component for reimbursement of the total construction costs of the pipeline
and facilities, an amount not to exceed $13.4 million over the life of the lease, as well as executory fees such as monthly operation and
maintenance costs and property taxes.
The TSA is considered a capital lease of the facilities and requires an estimated $2.4 million in minimum lease payments per year for
years ending December 31, 2007 through 2010; $2.3 million for the year ending December 31 , 2011; $2.0 million per year for the
years ending December 31, 2012 - 2016; $1.7 million per year for the years ending December 31 , 2017 - 2020; $1.6 million for the
year ending December 31 2021; $1.3 million per year for the years ending December 31 , 2022 - 2035; and $1.1 million for the year
ending December 31, 2036.
Marengo Land Leases & Easements
In October 2006, PacifiCorp announced the purchase of the 140.4-MW Marengo wind project from Blue Sky Wind, LLC, currently
under construction near Dayton, Washington. As a result of this acquisition, PacifiCorp was assigned and assumed eighteen 35-year
wind energy ground leases and transmission access easements from Blue Sky Wind, LLC with seventeen private land owners and the
state of Washington s Department of Natural Resources, for use of the underlying land for the project.
The leases call for the payment of an installation fee of $3 ,000 per installed megawatt of nameplate-rated capacity, an annual floor
payment equal to the greater of $2 000 or $25 000 per year or $1 000 per megawatt, or the sum of monthly production based payments
based on an initial millage rate of $0.00 15 per kilowatt hour of energy generated, subject to annual inflationary increases. Monthly
production-based payments are credited towards the annual production payments.
Leaning Juniper Land Leases & Easements
In July 2006, PacifiCorp entered into an agreement with Leaning Juniper Wind Power, LLC to acquire a 1 00.MW wind energy
generation facility near Arlington, Oregon that was currently under construction and began commercial operation during September
2006. As a result of this acquisition, PacifiCorp was assigned and assumed a 30-year site easement from Leaning Juniper Wind Power
LLC with Waste Management Disposal Services of Oregon, Inc. for use of the underlying land for the project.
The site easement calls for annual production payments equal to the greater of (a) $283 824 per year, (b) $1 000 times the aggregate
megawatt capacity of all turbines on the respective properties, or (c) the sum of quarterly production based payments based on an
initial millage rate of $0.00 15 per kilowatt hour of energy generated, subject to annual inflationary increases. Quarterly production
based payments are credited towards the annual production payments.
IGC Geothermal Leases
In June 2006, PacifiCorp s wholly owned subsidiary IGC entered into an asset purchase agreement with an individual for the rights to
certain geothenna1leases. The leases represent 1.2% of the steam rights associated with the geothennal field serving PacifiCorp
Blundell geothennal plant in Utah. Commission authorization was not required.
For a further discussion ofIGC not described in this item, refer to ITEM 2 of this Fonn No.
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 05/17/2007 2006/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
ITEM 5.
Important Extension and Reduction of Transmission System
For a discussion on transmission lines added during the year refer to pages 424-425 of this Form No.1. During the year ended
December 31 , 2006 PacifiCorp did not significantly increase or decrease its distribution system.
ITEM 6.
Financing Activities
Short-Term Debt
As of May 9, 2007, PacifiCorp had $20.0 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:
Utah Public Service Commission, Docket No. 06-035-027, Report and Order dated March 17 2006.
Oregon Public Utility Commission, Docket No. UF-4120, Order No. 98-158, dated April 16, 1998.
Washington Utilities and Transportation Commission, Docket No. UE-980404, dated April 8, 1998.
Idaho Public Utility Commission, Case No. PAC-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
pursuant to 18 CFR 366.6(b).
Long-Term Debt
On March 14 2007, PacifiCorp issued $600.0 million of its 5.75% Series of First Mortgage Bonds due April 1 , 2037. PacifiCorp
intends to use the proceeds for general corporate purposes, including the reduction of short-term debt. State Commission authorizations
for this issuance were as follows:
Utah Public Service Commission, Docket No. 07-035-, Report and Order dated March 2 2007, which authorized debt issuances of
up to $1.5 billion as well as withdrew authorization for the remaining unissued $350.0 million in debt previously authorized in Docket
No. 06-035-43.
Oregon Public Utility Commission, Docket No. UF-4237, Order No. 07-085 , dated March 5, 2007, which authorized debt issuances of
up to $1.5 billion as well as withdrew authorization for the remaining unissued $350.0 million in debt previously authorized under
Order No. 05-258.
Washington Utilities and Transportation Commission, Docket No. UE-070450, Order No., dated March 7, 2007.
Idaho Public Utilities Commission, Case No. PAC-07-, Order No. 30258, dated February 27 2007, which authorized debt
issuances of up to $1.5 billion.
On August 10 2006, PacifiCorp issued $350.0 million of its 6.10% Series of First Mortgage Bonds due August 1 2036. PacifiCorp
used the proceeds for general corporate purposes, including the reduction of short-term debt. State Commission authorizations for this
issuance were as follows:
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 05/17/2007 2006/Q4
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
Utah Public Service Commission, Docket No. 06-035-43, Report and Order dated May 3, 2006, amended May 18 2006.
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 June 14 2006.
Idaho Public Utilities Commission, Case No. PAC-05-, Order No. 29787, dated May 17 2005.
Common Shareholder s Capital
On November 29 2006, PacifiCorp received a capital contribution of$69.8 million in cash from its parent company, PPW Holdings
LLC, a subsidiary ofMEHc.
On September 26, 2006, PacifiCorp received a capital contribution of $71.6 million in cash from PPW Holdings LLC.
On June 26, 2006, PacifiCorp received a capital contribution of $73.6 million in cash from PPW Holdings LLC.
On March 21 , 2006, PacifiCorp issued 9 902 728 shares of its common stock to its parent company at that time, PacifiCorp Holdings
Inc. ("PHI"), at a total price of $1 09.7 million. State commission authorizations for this issuance 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., dated May 11 2005.
Idaho Public Utilities Commission, Case No. PAC-05-, Order No. 29786, dated May 17 2005.
Revolving Credit and Other Financing Arrangements
PacifiCorp has an $800.0 million unsecured revolving credit facility expiring in July 2011 that supports PacifiCorp s commercial paper
program. The credit facility includes a variable-rate borrowing option based on the London Interbank Offered Rate (LIBOR), plus a
margin of 0.195%, that varies based on PacifiCorp s credit ratings for its senior unsecured long-tenD debt securities. At December 31
2006, there were no borrowings outstanding under this facility.
At December 31 , 2006, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements available to
provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. In addition, PacifiCorp
had approximately $21.0 million of standby letters of credit available to provide credit support for certain transactions as requested by
third parties. These committed bank arrangements were all fully available at December 31 , 2006 and expire periodically through
February 2011.
PacifiCorp s revolving credit and other financing agreements contain customary covenants and default provisions, including a
covenant not to exceed a specified debt-to-capitalization ratio of 0.65 to 1. At December 31 , 2006, PacifiCorp was in compliance with
the covenants of its revolving credit and other financing agreements.
ITEM 7.
Changes in Articles of Incorporation or Amendments to Charter
None
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IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
ITEM 8.
Estimated Annual Effect of Wage Scale Changes
PacifiCorp s bargaining unit wage scale changes was as follows:
Un ion s Effective
resented % Increase (a Date(s)
IBEW 57 Power Delivery (UT , ID & WY)80%1/ 26/2 006
IBEW 57 Generation (UT, ID & W Y)04%1/26/2006
IBEW 659 (OR & CA)3.35%1/26/2006 & 7/26/2006
IBEW 127(WY)2.56%3/26/2006 & 9/26/2006
IBEW 125 (W A & OR)46%1/26/2006 & 7/26/2006
UWUA 197 (Coos Bay, OR)3.31 %1/26/2006 & 7/26/2006
IBEW 57 Combustion (UT, ID & WY)63%5/26/2006
IBEW 57 Laramie (WY)2.59%6/26/2006
Estimated Annual
Financial Impact (b)(c)
073 970
059,302
018 542
011 257
953,441
236
864
13,563
Total 224 175
(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) Some amounts may be reimbursed by joint owners of steam generating facilities.
(c) The estimated annual impact is based on the time period ftom the effective date of the in crease
to the end ofthe calendar year.
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IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
ITEM 9.
For a discussion of other legal proceedings not described in this item, refer to Notes to the Financial Statements Note 12 -
Contingencies of this Form No.
Legal Proceedings
In addition to the proceedings described below, PacifiCorp is currently party to various items of litigation or arbitration in the normal
course of business, none of which are reasonably expected by PacifiCorp to have a material adverse effect on its fmancial results.
Legal Matters
In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a compliant against PacifiCorp in the federal district court
in Cheyenne, Wyoming, alleging violations of air quality opacity standards at PacifiCorp s Jim Bridger Power Plant in Wyoming.
Opacity is an indication of the amount of light that is obscured in the flue of a generating facility. The complaint alleges thousands of
violations of six-minute compliance periods and seeks an injunction ordering the Jim Bridger plant's compliance with opacity limits
civil penalties of$32 500 per violation, and the plaintiffs' costs of litigation. PacifiCorp believes it has a number of defenses to the
claims. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time. PacifiCorp has already
committed to invest at least $812.0 million in pollution control equipment at its generating facilities, including the Jim Bridger plant.
This commitment is expected to significantly reduce system-wide emissions, including emissions at the Jim Bridger plant.
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 fmn Holme, Roberts & Owen, LLP, who represent PacifiCorp on various
matters fTom 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 information 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. A trial has been
scheduled for January 2008. 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 fmancial results.
In October 2005, the Utah Committee of Consumer Services (the "CCS") filed a request for agency action with the Utah Public
Service Commission ("UPSC"). The request sought 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 then parent company, PHI. The CCS had
publicly announced it was seeking a refund of at least $50.0 million to Utah ratepayers. Following PacifiCorp s sale to MEHC in
March 2006, the CCS, MEHC and intervening party Utah Industrial Energy Consumers filed with the UPSC an agreement settling the
claims made by the CCS. The settlement agreement was approved by the UPSC, which dismissed the CCS request. In exchange for
dismissal of the claims, MEHC agreed to contribute to PacifiCorp, at no cost, MEHC's 100.0% ownership interest in Intermountain
Geothermal Company, which controls 69.3% of the steam rights associated with the geothermal field serving PacifiCorp s Blundell
Geothermal Plant in Utah. PacifiCorp also agreed to expand its Blundell Geothermal Plant by 11 MW and consider a further 25 MW if
economically feasible. The 11 MWexpansion is in progress; however, the 25 MW expansion was determined in 2007 to not be
economically feasible, and notice thereof was provided to the settlement parties and the UPSC.
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
sucker and steelhead in the headwaters ofthe 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 briefmg was completed in March 2006. Any fmal order will be subject to appeal. PacifiCorp believes the outcome of this
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proceeding will not have a material impact on its fmancial results.
In April 2004, PacifiCorp filed a complaint with the federal district court in Wyoming challenging the Wyoming Public Service
Commission (the "~SC") decision made in March 2003 to deny recovery of the Hunter No. I replacement power costs and certain
defeITed 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. In February 2006
PacifiCorp and certain parties intervening in its then-pending Wyoming general rate case reached a settlement ofthe terms of
PacifiCorp s general rate case request. PacifiCorp also agreed to dismiss its federal lawsuit challenging the WPSC decision. The case
was dismissed in May 2006.
In December 2004, a group of Utah customers filed a petition with the UPSC on behalf of themselves and other similarly situated
customers seeking monetary compensation from PacifiCorp as a result of a severe winter storm in December 2003. This petition was
substantially similar to an April 2004 petition that the UPSC resolved by consolidating customer requests with an ongoing regulatory
winter storm inquiry. In May 2006, PacifiCorp reached a stipulation with the petitioners that resolved all claims in consideration of
system maintenance and vegetation management commitments and additional credits for customers. The stipulation was approved by
the UPSC on May 22, 2006.
Federal Regulatory Matters
The Bonneville Power Administration Residential Exchange Program
The Northwest Power Act, through the Residential Exchange Program, provides access to the benefits oflow-cost federal
hydroelectricity to the residential and small-farm customers of the region s investor-owned utilities. The program is administered by
the Bonneville Power Administration (the "BPA") in accordance with federal law. Pursuant to agreements between the BPA and
PacifiCorp, benefits from the BPA are passed through to PacifiCorp s Oregon, Washington and Idaho residential and small-farm
customers in the form of electricity bill credits. In October 2000, PacifiCorp entered into a settlement agreement with the BP A that
provided Residential Exchange Program benefits to PacifiCorp s customers from October 2001 through September 2006. In May
2004, PacifiCorp, the BP A and other parties executed an additional agreement that provides for a guaranteed range of benefits to
customers from October 2006 through September 2011.
Several publicly owned utilities, cooperatives and the BPA's direct-service industry customers filed lawsuits against the BPA with the
United States Ninth Circuit Court of Appeals seeking review of certain aspects of the BPA's Residential Exchange Program, as well as
challenging the level of benefits previously paid to investor-owned utility customers. On May 3 , 2007, the United States Ninth Circuit
Court of Appeals issued two decisions. The fITSt decision sets aside the October 2000 Residential Exchange Program settlement
agreement as being inconsistent with the BP A's settlement authority. The second decision holds, among other things, that the BP A
acted contrary to law when it allocated to its preference customers, which includes public utilities, cooperatives and federal agencies
part of the costs of the October 2000 settlement the BPA reached with its investor-owned utility customers. These United States Ninth
Circuit Court of Appeals' decisions could affect the amount of benefits passed on to PacifiCorp s customers. Because these benefits
are passed through to PacifiCorp s customers, the outcome of this matter is not expected to have a significant effect on PacifiCorp
consolidated fmancial results. There are several other lawsuits challenging certain aspects of the BPA's Residential Exchange Program
pending at the United States Ninth Circuit Court of Appeals for which the outcomes remain unknown.
FERC Market Oversight
FERC Order No. 890
In February 2007, the FERC issued Order No. 890 adopting a fmal rule designed to strengthen the pro forma open access transmission
tariff by providing greater specificity and increasing transparency. The most significant revisions to the pro forma open access
transmission tariff relate to the development of more consistent methodologies for calculating available transfer capability, changes to
the transmission planning process, changes to the pricing of certain generator and energy imbalances to encourage efficient scheduling
behavior and to exempt intermittent generators, and changes regarding long-term point-to-point transmission service, including the
addition of conditional fIrm long-term point-to-point transmission service, and generation re-dispatch. As a transmission provider with
an open-access transmission tariff on file with the FERC, PacifiCorp will be required to comply with the requirements of the new rule.
Certain details related to the rule, such as the precise methodology that will be used to calculate available transfer capability, will be
determined prospectively and, therefore, it is difficult to make a precise determination of the effect of this new rule on PacifiCorp
transmission operations. In addition, it is difficult to determine the effect ofthis new rule, once fully implemented, on the availability
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and price of transmission service from the perspective of the wholesale marketing function. However, at least on a preliminary basis
the rule is not anticipated to have a significant impact on PacifiCorp s fmancial results, but it will likely have a significant impact on its
transmission operations, planning and wholesale marketing functions.
Enerf!V Policy Act of 2005
On August 8, 2005, the Energy Policy Act was signed into law and has significantly impacted the energy industry. In particular, the
law expanded the FERC's regulatory authority in areas such as electric system reliability, electric transmission expansion and pricing,
regulation of utility holding companies, and enforcement authority to issue civil penalties of up to $1 million per day. While the FERC
has now issued rules and decisions on multiple aspects of the Energy Policy Act, the full impact of those decisions remains uncertain.
The Energy Policy Act also gives the FERC "backstop" transmission siting authority and directs the FERC to oversee the
establishment of mandatory transmission reliability standards. The Energy Policy Act also extended the federal production tax credit
for new renewable electricity generation projects through December 3 I , 2008. Partly as a result of that portion of the law, PacifiCorp
began development efforts to add additional wind-powered generation facilities.
The Energy Policy Act also requires state regulatory commissions to consider adopting a set of five new standards under the Public
Utilities Regulatory Policy Act (PURPA). The standards address: (I) net metering, (2) fossil fuel diversity, (3) fossil fueled generating
efficiency, (4) smart metering and (5) small generation interconnection to distribution voltage facilities. PacifiCorp s state
commissions are currently in various stages of their review of these five standards.
Transmission Settlement
In January 2007, the FERC approved a settlement with PacifiCorp regarding PacifiCorp' s use of its transmission system while
conducting wholesale power transactions with third parties. PacifiCorp discovered possible violations of its FERC-approved tariff
during an internal investigation of its compliance with certain FERC regulations shortly before MEHC's acquisition ofPacifiCorp.
Upon completion of the acquisition, PacifiCorp self-reported the potential violations to the FERC. The potential violations primarily
related to the way PacifiCorp used its own transmission system to transmit energy using "network service" instead of , 'point- to-point"
service as the FERC believes is required by PacifiCorp s tariff. This use of transmission service neither enriched PacifiCorp
shareholders nor hanned its retail customers. As part of the settlement, PacifiCorp voluntarily refunded $0.9 million to other
transmission customers in April 2006 and paid a $10.0 million fme to the United States Treasury in January 2007.
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 former affiliates had been required to submit a joint market power analysis every three years. In February 2005, PacifiCorp
submitted a joint triennial market power analysis, which indicated that PacifiCorp failed to pass one of the generation market power
screens. 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 June and July
2005, PacifiCorp and its formerly affiliated co-applicants submitted additional information and analysis to the FERC to rebut the
presumption that PacifiCorp had generation market power.
In January 2006, the FERC requested PacifiCorp to amend its previous filings with additional analysis, which was filed in March 2006.
In June 2006, the FERC issued an order finding that PacifiCorp does not have market power and terminated the proceeding. In
February 2007, FERC approved a change in filing status, relating to new generation, reaching the same conclusion.
California Refund Case
On April 11 , 2007, PacifiCorp executed a settlement and release of claims agreement ("Settlement") with Pacific Gas and Electric
Company, Southern California Edison Company, San Diego Gas & Electric Company, the People of the State of California, ex reI.
Edmund G. Brown Jr., Attorney General, the California Electricity Oversight Board, and the California Public Utilities Commission
(collectively, the "California Parties ), certain of which purchased energy in the California Independent System Operator ("ISO") and
the California Power Exchange ("PX") markets during past periods of high energy prices in 2000 and 2001. The Settlement, filed with
FERC on April 11 , 2007, settles claims brought by the California Parties against PacifiCorp for refunds and remedies in numerous
related proceedings (together, the "FERC Proceedings ), as well as certain potential civil claims, arising from events and transactions
in Western United States energy markets during the period January 1 2000, through June 20, 2001 (the "Refund Period"). Under the
Settlement, PacifiCorp made a cash payment to escrows controlled by the California Parties in the amount of$16 million on April 30
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2007, and upon FERC approval of the agreement, PacifiCorp will allow the PX to release an additional $12 million to such escrows
which represents PacifiCorp s estimated unpaid receivables fiom transactions in the PX and ISO markets during the Refund Period
plus interest. The monies held in the escrows will, upon FERC acceptance of the settlement, be distributed to buyers of power fiom the
ISO and PX markets during the Refund Period. Other buyers in the ISO and PX markets will be provided the option of joining in the
Settlement, in which case they will receive payments fiom one of the escrows. The agreement provides for the release of claims by the
California Parties (as well as additional parties that join in the Settlement) against PacifiCorp for refunds, disgorgement of profits, or
other monetary or non-monetary remedies in the FERC Proceedings, and provides a mutual release of claims for civil damages and
equitable relief. As PacifiCorp previously accrued for these items, the settlement did not materially impact PacifiCorp s financial
results.
Hydroelectric Relicensing
Klamath hvdroelectric Dro;ect - (Klamath River, Oregon and California)
In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169-MW nameplate-rated
Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating
under an annual license granted by the FERC and expects to continue to operate under annual licenses until the new operating license
is issued. As part of the relicensing process, the United States Departments of Interior and Commerce filed proposed licensing terns
and conditions with the FERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage
facilities at the Klamath hydroelectric project's four mainstem dams. In April 2006 , PacifiCorp filed alternatives to the federal
agencies' proposal and requested an administrative hearing to challenge some of the federal agencies ' factual assumptions supporting
their proposal for the construction of the fish passage facilities. A hearing was held in August 2006 before an administrative law judge.
The administrative law judge issued a ruling in September 2006 generally supporting the federal agencies' factual assumptions. In
January 2007, the United States Departments of Interior and Commerce filed modified terns and conditions consistent with March
2006 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to meet and implement the federal agencies
terns and conditions as part of the project's relicensing. However, PacifiCorp expects to continue in settlement discussions with
various parties in the Klamath Basin area who have intervened with the FERC licensing proceeding to try to achieve a mutually
acceptable outcome for the project.
Also, as part of the relicensing process, the FERC is required to perfonn an environmental review. In September 2006, the FERC
issued its draft environmental impact statement on the Klamath hydroelectric project license. The public comment period on the draft
environmental impact statement closed on December I , 2006. The FERC is expected to issue its fmal environmental impact statement
in Spring 2007, after which other federal agencies will complete their endangered species analyses. The states of Oregon and
California will need to issue water quality certifications prior to the FERC issuing a fmallicense.
Lewis River hvdroelectric Dro;ects - (Lewis River, Washington)
PacifiCorp filed new license applications for the I 36.MW nameplate-rated Merwin and 240.MW nameplate-rated Swift No. I
hydroelectric projects in April 2004. An application for a new license for the 134.MW nameplate-rated 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. I applications so that the FERC could complete a comprehensive environmental analysis.
In November 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. I and Yale hydroelectric projects. As part of
this settlement agreement, PacifiCorp 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 licenses fiom the FERC
that are consistent with the settlement agreement and other required pennits. PacifiCorp has received water quality certificates and a
biological opinion from the United States Fish and Wildlife Service. PacifiCorp is expecting a biological opinion from the National
Marine Fisheries Service in summer 2007. The FERC is expected to make a fmal decision no earlier than the second quarter of 2007.
ProSDect hvdroelectric Dro;ect - (Rogue River, Oregon)
In June 2003, PacifiCorp submitted a final license application to the FERC for the Prospect Nos. I , 2 and 4 hydroelectric projects
whose nameplate ratings total 37-MW. The Oregon Department of Environmental Quality issued a 401 Water Quality Certificate for
the project in April 2007, which effectively concludes the license process. FERC is expected to issue a new Order before the end of
May 2007.
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Hydroelectric Decommissioning
Powerdale /rvdroelectric Dro;ect - (Hood River, Oregon)
In June 2003, PacifiCorp entered into a settlement agreement to remove the 6.MW nameplate-rated Powerdale plant rather than
pursue a new license, based on an analysis of the costs and benefits of relic en sing versus decommissioning. Removal ofthe Powerdale
plant and associated project features, which is subject to the FERC and other regulatory approvals, is projected to cost $5.9 million
excluding inflation. Removal ofthe plant is scheduled to commence in 2010. However, in November 2006, flooding damaged the
Powerdale plant and rendered its generating capabilities inoperable. In February 2007, the FERC granted PacifiCorp s request to cease
generation at the project until decommissioning activities begin. Also in February 2007, PacifiCorp submitted a request to the FERC to
allow the company to defer the remaining net book value and any additional removal costs ofthis project as a regulatory asset.
PacifiCorp is awaiting the FERC's reply. In addition to seeking FERC approval, PacifiCorp has filed with all of its six state
commissions for the authorization to defer the costs of decommissioning the Powerdale plant. PacifiCorp has also filed in all states
except California for the authorization to transfer the remaining net book value of the plant from electric plant in service to a regulatory
asset.
Condit /rvdroelectric Dro;ect - (White Salmon River, Washington)
In September 1999, a settlement agreement to remove the 9.MW nameplate-rated Condit hydroelectric project was signed by
PacifiCorp, state and federal agencies and non-governmental organizations. Under the original settlement agreement, removal was
expected to begin in October 2006, with 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, within the terms and conditions of the amended settlement
agreement.
Cove /rvdroelectric Dro;ect - (Grace, Idaho)
In May 2006, the FERC approved PacifiCorp s application to amend the Bear River license and authorized the removal of the 7.
nameplate-rated Cove hydroelectric plant and facilities. Decommissioning of the Cove facilities has been completed in accordance
with the license amendment and the approved removal plan. The removal of the dam, flowline and all facilities, with the exception of
the powerhouse, was completed in November 2006. As of December 31 2006, $2.8 million has been spent for the decommissioning of
the Cove hydroelectric project.
State Regulatory Matters
Utah
In December 2006, the UPSC approved a stipulation settling PacifiCorp s general rate case filed in March 2006 related to increased
investments in Utah due to growing demand for electricity. The stipulation calls for an annual increase of$115.0 million, or 9.95%
with $85.0 million of the increase effective December 11 2006 and the remaining $30.0 million effective June 1 2007. Under the
tenDS of the stipulation, PacifiCorp has agreed not to file another rate case prior to December II , 2007, with new rates effective no
earlier than August 2008.
Oregon
In April 2007, PacifiCorp filed its annual compliance filing with the Public Utiilty Commission of Oregon ("OPUC") to update
forecasted net power costs, requesting a 3.9% overall price increase, approximately $36 million, to take effect January 1 2008. The
annual filing, called the Transition Adjustment Mechanism, is due each April but will be adjusted through November 2007 based on
changes to forecasted power costs, such as coal and gas prices and new contracts. PacifiCorp expects a ruling from OPUC this fall.
In September 2006, the OPUC approved a settlement agreement resolving PacifiCorp s February 2006 general rate case request related
to investments in generation, transmission and distribution infrastructure and increases in fuel and general operating expenses
including the maintenance of low-cost but aging power plants. Pursuant to the settlement agreement, PacifiCorp received an annual
increase for non-power cost items of$33.0 million effective January 1 2007. Also on January 1 2007, PacifiCorp received a $10.
million increase for power costs through its annual transition adjustment mechanism. After 2007, PacifiCorp s rates will be adjusted
annually based on its expected power costs. PacifiCorp has agreed not to file a new rate case prior to September I , 2007. If a case is
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filed on that date, new rates would be effective July 1 2008.
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. The OPUC's order reduced PacifiCorp s revenue requirement by $26.6 million (and therefore denied any
related further rate increase) based on the OPUC's interpretation of Oregon Senate Bill 408 as discussed below. 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. In July 2006, a fmal order was issued by the OPUC affirming
its initial application of Oregon Senate Bill 408. The order also modified the tax adjustment, resulting in an additional annual increase
in PacifiCorp s revenue of $6.1 million effective July 2006, as well as granting deferred accounting for the period from October 2005
to July 2006. In September 2006, PacifiCorp filed an application for deferred accounting treatment ofthe remainder of the tax
adjustment, pending the outcome of the permanent rulemaking for Oregon Senate Bill 408. This application was necessary to ensure
that PacifiCorp is allowed the opportunity to recover any revenue shortfall related to its allocated tax expense in rates for 2006, to the
extent any such revenue shortfall is not recovered through the Oregon Senate Bill 408 automatic adjustment clause. Because the result
of the automatic adjustment clause will not be known until after the October 2007 tax reports are filed, PacifiCorp s application for
deferred accounting of the remainder of the tax adjustment will be postponed until fall 2007.
In September 2005, Oregon s governor signed into law Oregon 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.
Oregon Senate Bill 408 requires that PacifiCorp and other large regulated, investor-owned utilities that provided electric or natural gas
service to Oregon customers file an annual tax report with the OPUC. Among other information, the tax report must contain; (i) the
amount of taxes paid by the utility, or paid by the affiliated group and "properly attributed" to the regulated operations of the utility,
and (ii) the amount of taxes "authorized to be collected in rates." If the OPUC determines that the amount of taxes "authorized to be
collected" differs by more than $100 000 from the amount of taxes paid, in either direction, the OPUC will require the public utility to
implement a rate schedule with an automatic adjustment clause resulting in an increase or decrease on customer bills. The automatic
adjustment clause is applicable for years beginning on or after January 1 2006. The first tax report that can result in a rate adjustment
will be filed on or before October 15, 2007 with the resulting increase or decrease, if any, implemented in rates on or before June I
2008.
The final administrative rules define the amount offederal, state, and local taxes paid by the utility, or paid by the affiliated group and
properly attributed" to the regulated operations of the utility, as the lowest of: (i) the total tax liability of the affiliated group of which
the utility is a member, (ii) the standalone tax liability of the utility, or (iii) the tax liability calculated using the "apportionment
method." The "apportionment method" uses an evenly weighted three-factor formula premised on property, payroll and sales, with
amounts for the regulated operations of the utility in the numerator and amounts for the affiliated group in the denominator, to generate
an allocation factor that is applied against the tax liability ofPacifiCorp s respective affiliated group in order to "apportion" part of that
tax liability to the regulated operations of the utility. For federal purposes, the affiliated group of which PacifiCorp is a member is
Berkshire Hathaway Inc. and its subsidiaries. For state and local purposes, the affiliated group differs based upon jurisdictional filing
requirements.
As a result of the law and the final administrative rules, the tax liability of the affiliated group of which PacifiCorp is a member and the
affiliated group s impact on the factor determined under the "apportionment method" may impact the amount of taxes paid and
properly attributed" to PacifiCorp. PacifiCorp cannot predict the fmancial results and the related impact of its federal affiliated group,
Berkshire Hathaway Inc. and subsidiaries, and therefore, cannot determine the impact this law may have on its financial results.
Additionally, the calculation of "taxes authorized to be collected in rates " as defined by the OPUC, is based upon assumptions in the
latest rate case(s) used to set rates for the respective fmancial reporting period. As such
, "
taxes authorized to be collected in rates" does
not reflect actual tax collections. The resulting difference between actual tax collections and the amount deemed collected pursuant to
Oregon Senate Bill 408 may be a benefit or detriment to PacifiCorp and cannot be reasonably predicted.
The OPUC recognizes that a potential conflict between its rules and federal Internal Revenue Code regulations could deny PacifiCorp
the tax benefits of accelerated depreciation. As such, at the request of the OPUC, in December 2006 PacifiCorp and the other affected
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 05/17/2007 2006/04
IMPORTANT CHANGES DURING THE OUARTERIYEAR (Continued)
utilities filed requests for private letter rulings from the Internal Revenue Service on this issue, which may result in reconsideration of
further changes to the rule or underlying law.
Oregon Senate Bill 408 cannot be used to decrease utility rates below a fair and reasonable level and the fmal administrative rules
expressly provide that a utility may challenge any adjustment if it would result in rates that are not fair, just and reasonable resulting in
confiscatory rates.
PacifiCorp continues to evaluate its legal and legislative options.
In April 2006, long-term special contracts for PacifiCorp s Klamath Basin irrigation customers expired. Under the contracts, customers
r~ceived power at rates less than PacifiCorp s average rates charged to other customers on general irrigation tariffs. Following
expiration of these contracts, the OPUC issued an order authorizing the transition of Klamath Basin irrigators to generally applicable
cost-based rates.
Wyoming
In March 2006, the WPSC approved an agreement that settled the general rate case filed by PacifiCorp in October 2005 and a separate
request filed by PacifiCorp in December 2005 to recover increased costs of net wholesale purchased power used to serve Wyoming
customers. The agreement provides for an annual rate increase of$15.0 million effective March 1 2006; an additional annual rate
increase of $10.0 million effective July 1 , 2006; a power cost adjustment mechanism effective July I , 2006; and an agreement by the
parties to support the principle of a forecast test year in the next general rate case application. A power cost adjustment mechanism
addresses the changes in power costs occurring between rate cases, subject to threshold requirements and sharing arrangements. Power
costs above or below the amounts built into rates may be recovered from or returned to customers according to the provisions in the
specific power cost adjustment mechanism. Adjustments are subject to notice by the WPSC and possible intervention, challenges and
adjustments by other parties.
In March 2007, the WPSC approved PacifiCorp s request to implement the proposed power cost adjustment mechanism rate increase
effective April 1, 2007, subject to modification and possible refund. Originally filed in February 2007, the application requests
recovery of approximately $2.8 million, or 0.73%. The filing requests recovery of a portion of excess net power costs incurred by
PacifiCorp for the period July 1 2006, through Nov. 30 2006. PacifiCorp has reached a stipulation with the Intervenors for
approximately $2.5 million, which was filed with the commission in May 2007. PacifiCorp is working on scheduling an open meeting
date to get the stipulation approved.
Washington
In November 2006, Washington voters passed Initiative Measure No. 937, which modified state law to require utilities that serve more
than 25 000 Washington customers to obtain at least 15 percent of their electricity from renewable resources by the year 2020.
PacifiCorp is currently evaluating the impact of this legislation.
In October 2006, PacifiCorp filed a general rate case with the Washington Utilities and Transportation Commission ("WUTC") for an
annual increase of$23.2 million, or 10.2%. As part of the filing, PacifiCorp proposed a Washington-only cost allocation methodology,
which is based on PacifiCorp s western resources. The rate case included a five-year pilot on the proposed allocation methodology and
a power cost adjustment mechanism. In its rebuttal case filed in March 2007, PacifiCorp reduced its request to $19 million. Hearings
were held in March 2007 with the matter to be fully briefed by May 7, 2007. PacifiCorp anticipates that the WUTC will issue its order
in summer 2007.
In May 2005, PacifiCorp filed a general rate case request with the WUTC for an increase of approximately $39.2 million annually,
which was later reduced to approximately $30.0 million. In April 2006, the WUTC issued an order denying PacifiCorp s request to
increase rates. The WUTC determined that application ofPacifiCorp s cost allocation methodology failed to satisfy the statutory
requirements that resources must benefit Washington ratepayers. PacifiCorp filed a petition for reconsideration of the order and
requested an increase of not less than $11.0 million. PacifiCorp also filed a limited rate request seeking a rate increase of
approximately $7.0 million, which represented a 2.99% increase in rates. In June 2006, the WUTC suspended PacifiCorp s limited rate
request and consolidated the request with the general rate case. In July 2006, the WUTC issued an order denying PacifiCorp s request
for reconsideration and rejecting the 2.99% limited rate request filing.
IFERC FORM NO.1 (ED. 12-96)Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
Idaho
In December 2006, the IPUC approved three applications filed by PacifiCorp in June 2006 proposing adjustments to the rates of
certain Idaho customers for a total increase of$8.25 million. The applications were based on settlement agreements reached after
negotiations between PacifiCorp and the respective customers and took the place of a general rate case originally planned to be filed in
2006. The fITst application was approved effective as of September I , 2006 and the remaining two applications were approved
effective as ofJanuary 1 2007.
California
In December 2006, the California Public Utilities Commission (the "CPUC") approved an agreement settling PacifiCorp s general rate
case originally filed in November 2005. The agreement provides for a $7.3 million annual increase in rates and a 10.6% return on
equity, a dollar. for-dollar energy cost adjustment clause that allows for annual changes in the level of net power costs, a post-test year
adjustment mechanism that provides for inflation-based increases to rates in 2008 and 2009, the ability to seek recovery of the
California-allocable portion of major plant additions exceeding $50.0 million, and scheduled rate increases under the tenus of the
transition plan for Klamath irrigators.
In April 2006, long-tenD special contracts for PacifiCorp s Klamath Basin irrigation customers expired. Under the contracts, customers
received power at rates less than PacifiCorp s average rates charged to other customers on general irrigation tariffs. Following
expiration of these contracts, the CPUC approved a joint proposal for a transition to standard tariff pricing.
ITEM 10.Related Party Transaction
According to the tenus PacifiCorp s original offer letter to its fonDer Senior Vice President and General Counsel, Andrew P. Haller
PacifiCorp made a $200 000.00 loan to Mr. Haller on May 21 , 2001 for the repayment of obligations to his fonDer employer. The loan
accrued interest at the annual rate of 4.74%. The largest outstanding loan balance, including accrued interest, at any time during the
twelve months ended December 31 , 2006 was $55 521 at June 12 2006. As of December 31 2006 the loan was repaid in full.
For a further discussion on related party transactions, refer to page 122 Notes to the Financial Statements of this Fonn No.
ITEM 11.
(Reserved)
ITEM 12.
Ownership by MidAmerican; Sale of PacifiCorp
On March 21 , 2006, MEHC completed its purchase of all ofPacifiCorp s outstanding common stock from PHI, a subsidiary of
Scottish Power pIc ("ScottishPower ), pursuant to the Stock Purchase Agreement among MEHC, ScottishPower and PHI dated May
2005, as amended on March 21, 2006. The cash purchase price was $5.1 billion. PacifiCorp s common stock was directly acquired
by a subsidiary ofMEHC, PPW Holdings LLc. As a result of this transaction, MEHC controls the significant majority ofPacifiCorp
voting securities, which includes both common and preferred stock. MEHC, a global energy company based in Des Moines, Iowa, is a
majority-owned subsidiary of Berkshire Hathaway Inc.
On July 17 2006, PacifiCorp changed its Pacific Power and Utah Power operating trade names in Wyoming, Utah and Idaho to Rocky
Mountain Power. PacifiCorp continues to operate under the trade name Pacific Power in Oregon, Washington and California.
Regional Transmission Coordination
In December 1999, the FERC encouraged all companies with transmission assets to fonD regional transmission organizations that
would manage certain operational functions of the transmission grid and plan for necessary expansion. In response, several Northwest
utilities, including PacifiCorp, fonned a regional transmission entity, known as Grid West, that was intended to coordinate
transmission functions in all or portions of eight western states and western Canada.
In April 2006, the Grid West board voted to dissolve the Grid West entity. This decision resulted primarily from the decision of key
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 05/17/2007 2006/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
participants, including the Bonneville Power Administration to discontinue support and funding of Grid West efforts. To address the
continuing need for some degree of regional transmission coordination, PacifiCorp and the other parties are considering smaller-scale
initiatives that could provide value for customers.
Integrated Resource Plans
As required by state regulators, PacifiCorp uses Integrated Resource Plans to develop a long-term view of prudent future actions
required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. The Integrated
Resource Plan process identifies the amount and timing ofPacifiCorp s expected future resource needs and an associated optimal
future resource mix that accounts for planning uncertainty, risks, reliability impacts and other factors. The Integrated Resource Plan is
a coordinated effort with stakeholders in each of the six states where PacifiCorp operates. Each state commission that has Integrated
Resource Plan adequacy rules judges whether the Integrated Resource Plan reasonably meets its standards and guidelines at the time
the Integrated Resource Plan is filed. If the Integrated Resource Plan is found to be adequate, then it is formally "acknowledged." The
Integrated Resource Plan can then be used as evidence by parties in rate-making or other regulatory proceedings.
In November 2005, PacifiCorp released an update to its 2004 Integrated Resource Plan. The updated 2004 Integrated Resource Plan
identified a need for approximately 2 113.0 megawatts ("MW") of additional resources by summer 2014, to be met with a combination
of thermal generation (1,936.0 MW) and load control programs (177.0 MW). PacifiCorp also planned to implement energy
conservation programs of 450.0 average MW, to continue to seek procurement of 1 400.0 MW of economic renewable resources and
to use wholesale electricity transactions to make up for the remaining difference between retail load obligations and available
resources.
PacifiCorp, files its Integrated Resource Plans on a biennial basis and expects to file its 2006 plan in May 2007. The OPUC issued a
new set of integrated resource planning guidelines in January 2007, which apply to the 2006 plan. PacifiCorp is modifying its plan to
accommodate the new analysis and reporting requirements. In addition, PacifiCorp is developing a resource strategy that
accommodates evolving state energy policies and differences in resource preferences among the states that it serves, while still
maintaining a system-wide planning focus.
Requests for Proposals
In July 2006, PacifiCorp filed its 2012 draft request for proposals under its 2004 Integrated Resource Plan with the UPSC and the
OPUC. The draft request for proposals is for generation resources of between 840.0 MW and 915.0 MW to be available in 2012
through 2013. The scope of this draft request for proposals is focused on resources capable of delivering energy and capacity in or to
PacifiCorp s network transmission system in PacifiCorp s eastern service territory. All transaction and resource decisions will be
evaluated on a comparable least-cost and risk-balanced approach. In response to issues and concerns from stakeholders, PacifiCorp
filed a revised version of the 2012 draft request for proposals in October 2006.
In January 2007, the OPUC issued an order denying the 2012 request for proposals. This denial does not preclude the issuance of the
request for proposals. In December 2006, the UPSC issued an order suggesting modifications to the request for proposals. PacifiCorp
filed the 2012 request for proposals in Utah for final approval in February 2007. This filing included a modification to request up to
700 MW to be available through 2014. Based on feedback from the Utah stakeholders, PacifiCorp filed a revised, fmal2012 request
for proposals in March 2007 and received final approval from the UPSC in April 2007.
Pension Protection Act of 2006
On August 17 2006, the Pension Protection Act of2006 (the "Pension Act") was signed into law. The Pension Act includes a
requirement for qualified pension plans to be fully funded within seven years following the January 1 2008 effective date. PacifiCorp
does not anticipate any significant changes to the amount of funding previously anticipated through 2007. PacifiCorp is reviewing the
impacts of the Pension Act on funding requirements for its retirement plan for 2008 and beyond. As a result of the Pension Act
PacifiCorp may be required to accelerate contributions to its retirement plan for periods after 2007 and there may be more volatility in
annual contributions in the future.
Derivatives
PacifiCorp is exposed to variations in the market prices of natural gas and electricity as a result of its regulated utility operations and
uses derivative instruments, including forward purchases and sales, swaps and options to manage these inherent commodity price
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 05/1712007 2006/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
risks.
Measurement Principles
Derivative instruments are recorded on the Comparative Balance Sheets at fair value as either assets or liabilities unless they are
designated and qualifY for the normal purchases and normal sales exemptions afforded by GAAP. The fair values of derivative
instruments are determined using forward price curves. Forward price curves represent PacifiCorp s 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 uses internally developed, modeled prices when market quotations are unavailable.
The assumptions used in these models are critical, since any changes in assumptions could have a significant impact on the fair value
of the contracts.
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 s forward price curves must be estimated in other ways. 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 power plants in
converting fuel to electricity) in the region where the purchase or sale takes place and a fundamentals forecast of expected spot prices
for a commodity in a region based on modeled supply of and demand for the commodity in the region.
Classification and Recognition Methodology
The majority ofPacifiCorp s contracts are either probable of recovery in rates, and therefore recorded as a regulatory net asset or
liability, or are accounted for as cash flow hedges and therefore recorded as accumulated other comprehensive income. Accordingly,
amounts are generally not recognized in earnings until the contracts are settled. As of December 31, 2006, PacifiCorp had
$229.8 million recorded as regulatory assets and $3.3 million recorded as accumulated other comprehensive income related to these
contracts on the Comparative Balance Sheets. If it becomes probable that a contract will not be recovered in rates, the amount recorded
as a regulatory asset or liability will be written off and recognized in earnings. For cash flow hedges, PacifiCorp discontinues hedge
accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer
probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued, future changes in the value of the
derivative are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in accumulated other
comprehensive income will remain there until the hedged item is realized, unless it is probable that the hedged forecasted transaction
will not occur at which time associated deferred amounts in accumulated other comprehensive income are immediately recognized in
earnings.
Fair Value of Derivatives
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 SF AS No. 133"), for the year ended December 31 2006 and
quantifies the reasons for the changes.
Fair value of contracts outstanding at January 1 2006
Contracts realized or otherwise settled during the period
Change in valuation techniques
Change in estimate of recoverability (a)
Other changes in fair values (b)
AccmnuIated
Other
Regulatory Comprehensive
Net Asset (Liability)Net Asset (Loss)
Trading Non-trading (Liability)Income
(0.141.(92.
(170.160.
1.5 (1.
(40.(3.
(3.(198.203,
(2.(225.229.(3.
Page 109.
(Millions of dollars)
Fair value of contracts outstanding at December 31 2006
IFERC FORM NO.1 (ED. 12-96)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
(a)During the year ended December 31 , 2006, PacifiCorp reached a new general rate case stipulation with
several parties in Utah and received approval from the OPUC for a new general rate case settlement in
Oregon. Utah and Oregon together account for approximately 70.4% ofPacifiCorp s retail electric operating
revenues. Based on management's consideration of the two new rate settlements, as well as the power cost
recovery adjustment mechanisms approved in Wyoming and California earlier in 2006, PacifiCorp changed
its estimate of the contracts receiving recovery in rates. Effective July 21, 2006, PacifiCorp recorded a $40.3
million decrease in net regulatory assets for previously recorded net unrealized gains related to contracts that
it detennined were probable of being recovered in rates with a corresponding pre-tax charge to net income
of$43.9 million and a pre-tax increase to Accumulated other comprehensive income of$3.6 million.
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.
(b)
PacifiCorp s valuation models and assumptions are updated daily to reflect current market infonnation, and evaluations and
refmements of model assumptions are perfonned on a periodic basis.
The following table shows summarized infonnation with respect to valuation techniques and contractual maturities ofPacifiCorp
energy-related contracts qualifying as derivatives under SF AS No. 133 at December 31 2006:
Fair Value of Contracts at Period-End
Matmity Maturity in Total
Less Than Matwity Maturity Excess of Fair
I Year 3 Years 5 Years 5 Years Value
(3.(2.
34.(12.(19.(36.(34.
10.4 42.(20.(224.(191.2)
44.30.(39.5)(260.(225.
(39.(30.39.260.229.
(Millions of dollars)
Trading:
Values based on quoted market prices from third-party somces
N on-t rading:
Values based on quoted market prices from third-party somces
Values based on models and other valuation methods
Total
Regulatory net asset (liability)
Standardized derivative contracts that are valued using market quotations are classified as "values based on quoted market prices from
third-party sources." All remaining contracts, which include non-standard contracts and contracts for which market prices are not
routinely quoted, are classified as "values based on models and other valuation methods." Both classifications utilize market curves as
appropriate for the first six years.
The following table summarizes the estimated changes in fair value of PacifiCorp' s energy derivative contracts as of December 31
2006 based upon multiplying a hypothetical 10% increase and a 10% decrease in forward market prices by the expected volumes for
these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worst case
scenarios (in millions):
10% increase
I 0% decrease
Estimated Fair Value
after Hypothetical
Change in Price
(186.
(269.
Hypothetical Price
As of December 31, 2006
Fair Value
(228.
For a discussion of derivatives not described in this item, refer to Notes to the Financial Statements Note 8 - Risk Management and
Hedging Activities ofthis Fonn No. I.
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 05/17/2007 2006/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
ITEM 13.
Officer & Director Changes
The following is an overview of the officer and director changes ofPacifiCorp, for a further discussion of officer and director changes
during the year refer to page 104 Officers and page 105 Directors of this Fonn No. l.
On March 12 2007, PacifiCorp s Senior Vice President, Stanley K. Watters, resigned as a director and officer, effective March 16
2007.
Effective December 31 , 2006, Mr. Haller, Senior Vice President, General Counsel and Corporate Secretary of PacifiCorp resigned as a
director and executive officer ofPacifiCorp.
On November 22 2006, PacifiCorp s Senior Vice President, Richard D. Peach, resigned as a director and officer.
On August 22, 2006, PacifiCorp appointed David 1. Mendez as Senior Vice President and Chief Financial Officer. Mr. Mendez
succeeds Richard D. Peach, who continued as Senior Vice President, assisting in the transition, until his resignation as a director and
officer in November 2006.
On September 15 2006, PacifiCorp appointed Patrick Reiten as President of Pacific Power, a division ofPacifiCorp, and elected him
to PacifiCorp s Board of Directors, Mr. Reiten succeeded Stan Watters, who became Senior Vice President ofPacifiCorp until his
resignation in March 2007.
On May 23, 2006, Mr. Barry G. Cunningham, Senior Vice President ofPacifiCorp resigned.
On March 21 2006, Judith A. Johansen s previously announced resignation as President and Chief Executive Officer became
effective, and Matthew R. Wright and Andrew N. MacRitchie each resigned as executive vice presidents.
On March 21 2006, PacifiCorp s Board of Directors elected the following new officers:
Gregory E. Abel, Chairman of the Board of Directors and Chief Executive Officer, PacifiCorp
William J. Fehnnan, President, PacifiCorp Energy
A. Richard Walje, President, Rocky Mountain Power
Stanley K. Watters, President, Pacific Power
On March 21 , 2006, the Board of Directors elected PacifiCorp s Chief Financial Officer, Richard D. Peach to the position of Senior
Vice President and PacifiCorp s Treasurer Bruce N. Williams to the position of Vice President and Treasurer. The Board of Directors
did not re-elect Donald D. Larson, Vice President, Ernest E. Wessman, Vice President and Robert Klein, Senior Vice President as
officers ofPacifiCorp. Richard D. Peach, A. Richard Walje, Andrew P. Haller and Nolan E. KaITas remained Directors ofPacifiCorp.
On March 17 2006, the following directors ofPacifiCorp resigned, effective upon the closing of MidAmerican s acquisition of
PacifiCorp:
Barry G. Cunningham
Stephen Dunn
Judith A. Johansen
Andrew N. MacRitchie
Matthew R. Wright
On March 17 2006, PacifiCorp s Board of Directors elected the following individuals as new directors ofPacifiCorp, effective upon
the closing of MidAmerican' s acquisition ofPacifiCorp:
Gregory E. Abel
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 05/17/2007 2006/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
Douglas L. Anderson
William J. Fehrman
Brent E. Gale
Patrick J. Goodman
A. Robert Lasich
Mark C. Moench
Stanley K. Walters
ITEM 14.
None
IFERC FORM NO.1 (ED. 12-96)Page 109.
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Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr)
(2)A Resubmission 05/17/2007 End of 2006/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Current Year Prior Year
Line Ref.End of OuarterNear End BalanceNo.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
UTILITY PLANT
Utility Plant (101-106 114)200-201 15,526,911,439 532 898 825
Construction Work in Progress (107)200-201 734,457 063 594,604 038
TOTAL Utility Plant (Enter Total of lines 2 and 3)261 368 502 15,127 502 863
(Less) Accum. Provo for Depr. Amort. Depl. (108, 110, 111 , 115)200-201 408,699,464 129 967 945
Net Utility Plant (Enter Total of line 4 less 5)852 669,038 997 534 918
Nuclear Fuel in Process of Ref., Conv.Enrich., and Fab. (120.202-203
Nuclear Fuel Materials and Assemblies-Stock Account (120.
Nuclear Fuel Assemblies in Reactor (120.
Spent Nuclear Fuel (120.
Nuclear Fuel Under Capital Leases (120.
(Less) Accum. Provo for Amort. of Nucl. Fuel Assemblies (120.202-203
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
Net Utility Plant (Enter Total of lines 6 and 13)852 669 038 997 534 918
Utility Plant Adjustments (116)122
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutility Property (121)945 604 836,483
(Less) Accum. Provo for Depr. and Amort. (122)231 400 128,545
Investments in Associated Companies (123)695,513 579 182
Investment in Subsidiary Companies (123.224-225 113,111,98E 853,402
(For Cost of Account 123., See Footnote Page 224, line 42)
Noncurrent Portion of Allowances 228-229
Other Investments (124)93,958,194 90,179 747
Sinking Funds (125)
Depreciation Fund (126)
Amortization Fund - Federal (127)
Other Special Funds (128)847,422 053,888
Special Funds (Non Major Only) (129)
Long-Term Portion of Derivative Assets (175)234 925 374 504 831,076
Long-Term Portion of Derivative Assets - Hedges (176)
TOTAL Other Property and Investments (Lines 18-21 and 23-31)465,252 693 714,205 233
CURRENT AND ACCRUED ASSETS
Cash and Working Funds (Non-major Only) (130)
Cash (131)559 447 694 774
Special Deposits (132-134)969,784 698 954
Working Fund (135)920 720
Temporary Cash Investments (136)544 663 113,778,292
Notes Receivable (141)893 754 028 037
Customer Accounts Receivable (142)324 627 813 259 768,410
Other Accounts Receivable (143)216 920 16,666,819
(Less) Accum. Provo for Uncollectible Acct.-Credit (144)11,879,64E 876,951
Notes Receivable from Associated Companies (145)22,866,308
Accounts Receivable from Assoc. Companies (146)933 523 882 277
Fuel Stock (151)227 82,230,862 631 067
Fuel Stock Expenses Undistributed (152)227
Residuals (Elec) and Extracted Products (153)227
Plant Materials and Operating Supplies (154)227 129 731 866 117 959 772
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)(ZJ An Original (Mo, Da, Yr)
(2)A Resubmission 05/17/2007 End of 2006/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITStContinued)
Line Current Year Prior Year
No.Ref.End of OuarterNear End Balance
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)84,336 960 709,424
Advances for Gas (166-167)
Interest and Dividends Receivable (171)112,488 94,987
Rents Receivable (172)266 047 571 410
Accrued Utility Revenues (173)177 642 000 169 648,000
Miscellaneous Current and Accrued Assets (174)151,667
Derivative Instrument Assets (175)381,369,990 884 958 679
(Less) Long-Term Portion of Derivative Instrument Assets (175)234,925,374 504 831 076
Derivative Instrument Assets - Hedges (176)4,485,761
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176
Total Current and Accrued Assets (Lines 34 through 66)032,986,086 168,538 262
DEFERRED DEBITS
Unamortized Debt Expenses (181)23,745,172 071,762
Extraordinary Property Losses (182.230
Unrecovered Plant and Regulatory Study Costs (182.230 839,022 839,912
Other Regulatory Assets (182.232 395,660 386 885,243 418
Prelim. Survey and Investigation Charges (Electric) (183)727 385 388 689
Preliminary Natural Gas Survey and Investigation Charges 183.
Other Preliminary Survey and Investigation Charges (183.
Clearing Accounts (184)
Temporary Facilities (185)36,534 134,081
Miscellaneous Deferred Debits (186)233 57,976 248 65,950,331
Def. Losses from Disposition of Utility PIt. (187)
Research, Devel. and Demonstration Expend. (188)352-353
Unamortized Loss on Reaquired Debt (189)25,438 109 285,935
Accumulated Deferred Income Taxes (190)234 819 687,478
Unrecovered Purchased Gas Costs (191)
Total Deferred Debits (lines 69 through 83)333 110 334 706 169 642
TOTAL ASSETS (lines 14-16, 32, 67, and 84)684,018,151 586,448,055
FERC FORM NO.1 (REV. 12-03)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 05/17/2007 2006/Q4
FOOTNOTE DATA
~edule Page: 110 Line No.82 Column:
At December 31 , 2005, PacifiCorp kept its accounting records on a fiscal-year basis for the Securities and Exchange Commission (the
SEC") fmancia1 reporting purposes. The fiscal year end was March 31. Annual fiscal year end tax adjustments were perfonned in
March. These adjustments result in larger changes to various tax accounts between "cUlTent 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.
For a further discussion on PacifiCorp s fiscal year, refer to Notes to the Financial Statements Note 1 - Basis 0/ Presentation and
Summary o/Significant Accounting Policies of this Fonn 1.
IFERC FORM NO.(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)An Original (mo, da, yr)
(2)A Rresubmission 05/17/2007 end of 2006/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prior Year
Ref.End of QuarterlYear End BalanceNo.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
PROPRIETARY CAPITAL
Common Stock Issued (201)250-251 417 945 89E 308 226 675
Preferred Stock Issued (204)250-251 41,463 300 463 300
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)253 223,285 229 973,218
Installments Received on Capital Stock (212)252
(Less) Discount on Capital Stock (213)254
(Less) Capital Stock Expense (214)254 288,207 288,207
Retained Eamings (215, 215., 216)118-119 783,464 736 492 556,075
Unappropriated Undistributed Subsidiary Eamings (216.118-119 841 394 673,226
(Less) Reaquired Capital Stock (217)250-251
Noncorporate Proprietorship (Non-major only) (218)
Accumulated Other Comprehensive Income (219)122(a)(b)882 135 067 964
Total Proprietary Capital (lines 2 through 15)426,830,213 802,536,323
LONG-TERM DEBT
Bonds (221)256-257 048,872,000 007 276 242
(Less) Reaquired Bonds (222)256-257
Advances from Associated Companies (223)256-257
Other Long-Term Debt (224)256-257 500,000 000 000
Unamortized Premium on Long-Term Debt (225)717 46,435
(Less) Unamortized Discount on Long-Term Debt-Debit (226)853 708 397 420
Total Long-Term Debt (lines 18 through 23)080,562 OOS 046,925,257
OTHER NONCURRENT LIABILITIES
Obligations Under Capital Leases - Noncurrent (227)49,399,030 38,119,090
Accumulated Provision for Property Insurance (228.1,418,669 590 161
Accumulated Provision for Injuries and Damages (228.289 637 206,521
Accumulated Provision for Pensions and Benefits (228.690,869,211 432 165,438
Accumulated Miscellaneous Operating Provisions (228.586 470 929,426
Accumulated Provision for Rate Refunds (229)377
Long-Term Portion of Derivative Instrument Liabilities 504,511 387 533,082,317
Long-Term Portion of Derivative Instrument Liabilities - Hedges
Asset Retirement Obligations (230)797 248 393,140
Total Other Noncurrent Liabilities (lines 26 through 34)382 871 652 107 486,470
CURRENT AND ACCRUED LIABILITIES
Notes Payable (231)399,000 000 215,000,000
Accounts Payable (232)396 650,693 346,405 807
Notes Payable to Associated Companies (233)649,520
Accounts Payable to Associated Companies (234)548 784 599,395
Customer Deposits (235)23,526,476 35,286,140
Taxes Accrued (236)262-263 123 323 310,489
Interest Accrued (237)56,736,306 53,036,300
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)!XI An Original (mo, da, yr)
(2)A Rresubmission 05/17/2007 end of 2006/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIT(59ntinued)
Line Current Year Prior Year
Ref.End of QuarterlYear End BalanceNo.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
Matured Interest (240)
Tax Collections Payable (241)13,982,472 093,258
Miscellaneous Current and Accrued Liabilities (242)647 611 68,282 282
Obligations Under Capital Leases-Current (243)233 704 553 086
Derivative Instrument Liabilities (244)612 857 273 743,246,559
(Less) Long-Term Portion of Derivative Instrument Liabilities 504 511 387 533,082 317
Derivative Instrument Liabilities - Hedges (245)186 351
(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
Total Current and Accrued Liabilities (lines 37 through 53) 116,502 553 979,901,466
DEFERRED CREDITS
Customer Advances for Construction (252)10,343 762 546,023
Accumulated Deferred Investment Tax Credits (255)266-267 687,940 69,608,060
Deferred Gains from Disposition of Utility Plant (256)
Other Deferred Credits (253)269 791,513 591 991
Other Regulatory Liabilities (254)278 109,982,910 198 320 601
Unamortized Gain on Reaquired Debt (257)56,166 140,415
Accum. Deferred Income Taxes-Acce!. Amort.(281)272-277 300,173
Accum. Deferred Income Taxes-Other Property (282)005,573,266 981 854,886
Accum. Deferred Income Taxes-Other (283)427 515 994 330,902,078
Total Deferred Credits (lines 56 through 64)677 251 724 649 598,539
TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)684 018 151 12,586,448,055
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 05/17/2007 2006/04
FOOTNOTE DATA
!schedule Page: 112 Line No.62 Column:
At December 31 , 2005, PacifiCorp kept its accounting records on a fiscal-year basis for the Securities and Exchange Commission (the
SEC") financial reporting purposes. The fiscal year end was March 31. Annual fiscal year end tax adjustments were perfonned 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.
For a further discussion on PacifiCorp s fiscal year, refer to Notes to the Financial Statements Note 1 Basis of Presentation and
Summary of Significant Accounting Policies of this Fonn I.
IFERC FORM NO.1 (ED. 12-87)Page 450,
Blank Page
(Next Page is: 114)
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) 0 A Resubmission 05/1712007
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 0) 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 Quarterty Only
Title of Account Page No.QuarterNear QuarterNear No 4th Quarter No 4th Quarter
(a)(b)(c) (d) (e) (f)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301
3 Operating Expenses
Operation Expenses (401)320-323 105,021,264 1 929,373,826
5 Maintenance Expenses (402)320-323 Iii 311 914,442
Depreciation Expense (403)336-337 372,668,587
Depreciation Expense for Asset Retirement Costs (403.336-337
8 Amort. & Depl. of Utility Plant (404-405)336-337 47,633,759 48,011 207
9 Amort. of Utility Plant Acq. Adj. (406)336-337 5,479,353 5,479,353
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)674 863 256,147
Amort. of Conversion Expenses (407)
Regulatory Debits (407.696,523 307,820
(Less) Regulatory Credits (407.
Taxes Other Than Income Taxes (408.262-263 96,297 630
Income Taxes - Federal (409.262-263 106,778,946
- Other (409.1) 262-263 090,310
Provision for Deferred Income Taxes (410.234, 272-277 813,769,788
(Less) Provision for Deferred Income Taxes-Cr. (411.1)234, 272-277 753,579,201
Investment Tax Credit Adj. - Net (411.4)266 854,860 854,860
(Less) Gains from Disp. of Utility Plant (411.
Losses from Disp. of Utility Plant (411.60,094
(Less) Gains from Disposition of Allowances (411.619,250 16,224,770
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)166,477,798 919,498 202
Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117 line 27 580,803,409 519,453 886
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent This
0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04
(2) Fi A Resubmission 05/17/2007
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 concerning 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 GAS UTILITY OTHER UTILITY
Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Line
(in dollars)(in dollars)(in dollars)(in dollars)(in dollars)(in dollars)No.
(g)
(h) (i) OJ (k) (I)
105 021 264 1 929,373 826
352,406 626 311 914 442
390,945,206 372 668 587
633,759 48,011 207
479,353 5,479 353
674 863 256,147
696 523 307,820
101 034,471 297 630
106,778,946 781 130
090 310 878,018
813 769,788 690 441 169
753,579 201 623,891 591
854,860 854 860
60,094
15,619,250 16,224,770
166,477 798 919 498 202
580 803,409 519,453 886
FERC FORM NO.1 (ED. 12-96)Page 115
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) riA Resubmission 05/17/2007
STATEMENT OF INCOME FOR THE YEAR (continued)
Line TOTAL Current 3 Months Prior J 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)
Net Utility Operating Income (Carried forward from page 114)580,803.409 519.453 886
Other Income and Deductions
Other Income
Nonutilty Operating Income
Revenues From Merchandising, Jobbing and Contract Work (415)3.443,913 532,054
(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)554 683 164,391
Revenues From Nonutility Operations (417)156,069 850,397
(Less) Expenses of Nonutility Operations (417.23,117 15,559
Nonoperating Rental Income (418)60,059 41,539
Equity in Earnings of Subsidiary Companies (418.119 831 832 839,244
Interest and Dividend Income (419)7.426,781 876.811
Allowance for Other Funds Used During Construction (419.23.612 825 915,057
Miscellaneous Nonoperating Income (421)480,231 577 396.466,451
Gain on Disposition of Property (421.1)162.550 142,752
TOTAL Other Income (Enter Total of lines 31lhru 40)509 684 142 417.484,355
Other Income Deductions
Loss on Disposition of Property (421.2)342,567 650,349
Miscellaneous Amortization (425)340 099,117 629,194
Donations (426.340 144,714 948,545
Life Insurance (426.657 632 129,019
Penalties (426.10,058,546 220.420
Exp. for Certain Civic, Political & Related Activities (426.163,251 031,555
Other Deductions (426.530 547 357 355,829,911
TOTAL Other Income Deductions (Total of lines 43 thru 49)537 697 920 357,180,955
Taxes Applic. to Other Income and Deductions
Taxes Other Than Income Taxes (408.262-263 497 588 211.423
Income Taxes-Federal (409.262-263 24,842,659
Income Taxes-Other (409.262-263 371 372
Provision for Deferred Inc. Taxes (410.234, 272-277 95,532 620
(Less) Provision for Deferred Income Taxes-Cr. (411.234. 272-277 134 566,999
Investment Tax 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)388,020 20.951 662
Net Other Income and Deductions (Total of lines 41, 50, 59)15.625,758 351 738
Interest Charges
Interest on Long-Term Debt (427)245.313.780 237,603,134
Amort. of Debt Disc. and Expense (428)779 288 911,956
Amortization of Loss on Reaquired Debt (428.847,826 116,695
(Less) Amort. of Premium on Debt-Credit (429)718 718
(Less) Amortization of Gain on Reaquired Debt-Credit (429.84.249 85,275
Interest on Debt to Assoc. Companies (430)340 25,955 473.493
Other Interest Expense (431)340 043,696 26,579,047
(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)680,215 16,966 931
Net Interest Charges (Total of lines 62 thru 69)257 243,363 257 629.401
Income Before Extraordinary Items (Total of lines 27, 60 and 70)307 934,288 301,176,223
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)307 934 288 301 176.223
FERC FORM NO. 113.0 (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 05/17/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 114 Line No.Column:
Vehicle depreciation is charged to functional accounts. The following table summarizes the vehicle depreciation expense that was
charged to the functional accounts.
Twelve Months Ending
December 312006 2005
Vehicle Depreciation 268,419 $ 11 352 594
~chedule Page: 114 Line No.Column:
acifiCorp records the depreciation expense of asset retirement obligations as either a regulatory asset or (liability).
~chedule Page: 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 Ending
December 312006 2005
Payroll TaxExpense $ 36 613 788 $ 35 422 794
~chedule Page: 114 Line No.15 Column: d
At December 31 2005, PacifiCorp kept its accounting records on a fiscal-year basis for the Securities and Exchange Commission (the
SEC") fmancial reporting purposes. The fiscal year end was March 31. Annual fiscal year end tax adjustments were 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 (fITst quarter of the calendar year) report than in subsequent quarters.
For a further discussion on PacifiCorp s fiscal year, refer to Notes to the Financial Statements Note J Basis of Presentation and
ummary of Significant Accounting Policies of this Fonn 1.
~chedule Page: 114 Line No.16 Column: d
See footnote on page 114, line 15, column (d).
~chedule Page: 114 Line No.17 Column: d
See footnote on age 114, line 15, column (d).
chedule Pa e: 114 Line No.18 Column: d
See footnote on a e 114, line 15, column (d).
chedule Page: 114 Line No.24 Column:
PacifiCo records the accretion expense of asset retirement obligations as either a re ulatory asset or (liability).
chedule Page: 114 Line No.53 Column: d
ee footnote on ~e 114, line , column (d).
~chedule Page: 114 Line No.54 Column: d
ee footnote on page 114, line , column (c).
~chedule Page: 114 LineNo.55 Column: d
See footnote on a e 114, line 15 , column (c).
Schedule Page:J14 .!LIJ~fi~.56 Column: d
See footnote on page 114, line 15 , column (c).
IFERC FORM NO.1 (ED. 12-87)Page 450.
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained eamings, 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 2006/Q4
Line
No.
Item
(a)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period
2 Changes
3 Adjusbnents to Retained Eamings (Account 439)
9 TOTAL Credits to Retained Eamings (Acct. 439)
15 TOTAL Debits to Retained Eamings (Acct. 439)
16 Balance Transferred from Income (Account 433 less Account 418.
17 Appropriations of Retained Earnings (Acet. 436)
22 TOTAL Appropriations of Retained Eamings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24 Preferred Stock - Various Series and rates
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
31 Common stock
36 TOTAL Dividends Declared-Common Stock (Acct. 438)
37 Transfers from Acct 216., Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1 37)
APPROPRIATED RETAINED EARNINGS (Account 215)
Current Previous
QuarterlYear QuarterlY ear
Contra Primary Year to Date Year to Date
ccount Affected Balance Balance
(b)(c)(d)
_..'...
;f~;-' R7---
"'-
'G...
..n__
'_...."'..~..'.'.-.-...-._"
it'rj;"
309,766 120 300,336,979
238 083,790 ( 2 083,790)
083,790 083.790)
238 773 669 ( 206,524 304)
773 669
FERC FORM NO. 1/3-Q (REV. 02..Q4)Page 118
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
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 2006/Q4
Line
No.
45 TOTAL Appropriated Retained Eamings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.
47 TOTAL Approp. Retained Eamings (Acct. 215, 215.1) (Total 45,46)
48 TOTAL Retained Eamings (Acct. 215, 215., 216) (Total 38, 47) (216.
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no 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
QuarterlYear QuarterlY ear
Contra Primary Year to Date Year to Date
Account Affected Balance Balance
(b)(c)(d)
841,394 673,226
FERC FORM NO. 1/3-(REV. 02-04)Page 119
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 . 2006/Q4
FOOTNOTE DATA
ISchedule Page: 118 Line No.L37 Column: d
As previously reported in PacifiCorp s Form 3-Q for the nine months ended September 30, 2005, $669.4 million was transferred ITom
Account 216.1 to Account 216 following a review of 18 CFR 101.216 and 216.1. This transfer between accounts had no impact on
total retained earnings and except for the individual balances of Accounts 216 and 216., had no effect on the Comparative Balance
Sheet or Statement of Retained Earnings. This transfer had no effect on the Statement of Income or Statement of Cash Flows.
ISchedule Page: 118 Line No.52 Column: d
See footnote on page 118, line 37, column (d).
IFERC FORM NO.1 (ED. 12-87)Page 450,
Blank Page
(Next Page is: 120)
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) nA Resubmission 05/17/2007
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 QuarterlYear
(a)(b)(c)
1 Net Cash Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117)307 934,288 301 176,223
3 Noncash Charges (Credits) to Income:
Depreciation and Depletion 403 735 798 384 308,603
583 615 683 721
7 Unrealized (Gains)/Losses on Derivative Contracts 066,157 -42 795 968
8 Deferred Income Taxes (Net)21,156,209 66,929,034
9 Investment Tax Credit Adjustment (Net)920 120 920,120
Net (Increase) Decrease in Receivables 82,840.925 540 192
Net (Increase) Decrease in Inventory 371 890 893 280
Net (Increase) Decrease in Allowances Inventory
Net Increase (Decrease) in Payables and Accrued Expenses 116,660 014 755,843
Net (Increase) Decrease in Other Regulatory Assets 522 865 487 911
Net Increase (Decrease) in Other Regulatory Liabilities 3,472 833 20,254 639
(Less) Allowance for Other Funds Used During Construction 612 825 915 057
(Less) Undistributed Eamings from Subsidiary Companies 831 832 839,244
Amounts Due To/From Affiliates, Net 647 096 529,623
36,872,203 747 688
Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)735 752 886 901 540 530
Cash Flows from Investment Activities:
Construction and Acquisition of Plant (including land):
Gross Additions to Utility Plant (less nuclear fuel)339,383 764 984 446,581
Gross Additions to Nuclear Fuel
Gross Additions to Common Utility Plant
Gross Additions to Nonutility Plant
(Less) Allowance for Other Funds Used During Construction 23,612 825 915,057
Other (provide details in footnote):
Cash Outflows for Plant (Total of lines 26 thru 33)315 770,939 974 531 524
Acquisition of Other Noncurrent Assets (d)
Proceeds from Disposal of Noncurrent Assets (d)309 662 651,413
Investments in and Advances to Assoc. and Subsidiary Companies 211 124 682 333
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
PacifiCorp
This ~ort Is:(1) ~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
(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
(a)
Current Year to Date
QuarterlYear
(b)
Previous Year to Date
QuarterlYear
(c)
Line
No.
Description (See Instruction No.1 for Explanation of Codes)
46 Loans Made or Purchased
47 Collections on Loans
49 Net (Increase) Decrease in Receivables
50 Net (Increase) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accrued Expenses
854 645 196 012
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55)
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
70 Cash Provided by Outside Sources (Total 61 thru 69)
72 Payments for Retirement of:
73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
76 Inter-Company Borrowings (Note Agreement)
77 Repayment of Capital Lease Obligations
78 Net Decrease in Short-Term Debt (c)
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22 57 and 83)
88 Cash and Cash Equivalents at Beginning of Period
90 Cash and Cash Equivalents at End of period
109 722,222
216 766,877
374,992,877
182,634,965
857 457 592 670 907 703
310,552,000
500,000
173,234 000
500,000
595 907
547 822
18,877 300
102 322
Dividends on Preferred Stock
Dividends on Common Stock
Net Cash Provided by (Used in) Financing Activities
(Total of lines 70 thru 81)
083,790
773 669
083,790
206,524 304
107 030 131,476 786
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 (2)A Resubmission 05/17/2007 2006/Q4
FOOTNOTE DATA
!Schedule Page: 120 Line No.Column:
YTD YTD FERC
Dec. 31 2006 Dec. 31 , 2005 Account
633 759 011 207 404
099 117 629 194 425
479 353 479 353 406
371 386 563 967 407/407.3 /407.4
583 615 683 721
YTD YTD FERC
Dec. 31 2006 Dec. 31 2005 Account
481 495 354 940 151
(11 269 409)(14 715 240)501
(127 201)(1,364 968)254/411.6/411.7
(1,232 359)253.4 /253.41
(33 547 909)696 634 228
598 165 227 101 107
(1,275 241)973 218 211
075 262)409,456 228 / 253
575 518 166 547 Various
$ (36 872 203)747 688
Amortization of Software Development & Other Intangibles
Amortization of LicensingIHydro
Amortization of Electric Plant Acq. Adj. - Common
Amortization of Regulatory AssetslLiabilities
!Schedule Page: 120 Line No.Column:
Coal Depreciation & Depletion included in Cost of Fuel
PMI Equity Earnings eliminated in Cost of Fuel
(Gain)ILoss on Sale of Property
Deferred Credits - Deferred Compensation
Accumulated Provision for Pension & Benefits
Write-Off of Assets Under Construction
Share Based Compensation Expense & Section 199
Accum Provision For Mining / Environ / Decom
Other
chedule Page: 120 Line No.Column:
Line No.Column:
YTD YTD FERC
Dec. 31 , 2006 Dec. 31 2005 Account
(256 759)397 030)124/ 128
548 (74 971)185
521 392)724 011)128 / 134
174 041)101
854 645)$ (10 196 012)
YTD YTD FERC
Dec. 31 2006 Dec. 31 2005 Account
$ 214 950 000 211
330 669 211
(513 792)211
$ 216 766 877
Other Investments/Special Funds
Temporary Facilities
Restricted Cash
Business Acquisition of Steam Reserve Corporation
!Schedule Page: 120
Equity Contribution received tTom MERC
Contribution received tTom MERC from the acquition ofIGC
Other equity adjustments
Net Additional Paid-In Capital
IFERC FORM NO.1 (ED. 12-87)Page 450.
This Report Is:(1) ~ An Original(2) D A Resubmission
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and fumish 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.
Name of Respondent
PacifiCorp
Date of Report
05/17/2007
Year/Period of Report
End of 2006/Q4
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 Resubmission 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
ACIFICORP
NOTES TO THE FINANCIAL STATEMENTS
Note 1- Organization and Operations
PacifiCorp (which includes PacifiCorp and its subsidiaries) is a United States electric utility company serving retail customers in
portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp generates electricity and also engages
in electricity sales and purchases on a wholesale basis. The subsidiaries of PacifiCorp support its electric utility operations by
providing coal-mining facilities and services and steam delivery facilities.
On March 21 , 2006, MidAmerican Energy Holdings Company ("MEHC") completed its purchase of all ofPacifiCorp s outstanding
common stock from PacifiCorp Holdings, Inc. ("PHI"), a subsidiary of Scottish Power pIc ("ScottishPower ), pursuant to the Stock
Purchase Agreement among MEHC, ScottishPower and PHI dated May 23, 2005, as amended on March 21 , 2006. The cash purchase
price was $5.1 billion. PacifiCorp s common stock was directly acquired by a subsidiary ofMEHC, PPW Holdings LLC. As a result of
this transaction, MEHC controls the significant majority ofPacifiCorp s voting securities, which includes both common and preferred
stock. MEHC, a global energy company based in Des Moines, Iowa, is a majority-owned subsidiary of Berkshire Hathaway Inc.
Note 2 - Summary of Significant Accounting Policies
Basis of Presentation
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 accounting principles generally accepted in the United States of America ("GAAP"). These notes include
specific information requested by the FERC and are generally similar to the GAAP reporting requirements unless otherwise noted.
The following are the significant differences between FERC reporting standards and GAAP:
Investments in Subsidiaries
PacifiCorp accounts for certain investments in subsidiaries using the equity method rather than consolidating the assets, liabilities
revenues and expenses ofthe 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 ("SF AS") No. 94 Consolidation of All Majority-Owned Subsidiaries and revised Financial
Accounting Standards Board (the "FASB") Interpretation No. 46 Consolidation of Variable-Interest Entities, an interpretation of
Accounting Research Bulletin No. 51. In general, the accounting for investments in these certain 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 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 SFAS No. 109 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. Unrealized gains on wholesale sales, purchased power and fuel are reported in Miscellaneous nonoperating
income and unrealized losses on wholesale sales, purchased power and fuel are reported in Other deductions. For GAAP
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 ~esubmission 05/17/2007 2006/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 and Operations and maintenance expense.
Reclassifications
Certain other reclassifications of balance sheet, income statement and cash flow amounts have been made in order to conform to a
FERC basis of presentation. These reclassifications had no effect on net income.
Change in Fiscal Year
On May 10 2006, the PacifiCorp Board of Directors elected to change PacifiCorp s fiscal year-end from March 31 to December 31.
See PacifiCorp s Securities and Exchange Commission (the "SEC") Transition Report on Form 10-K for the nine months ended
December 31 , 2006 for consolidated fmancial statements and complete footnotes prepared in accordance with GAAP.
Use of Estimates in Preparation of Financial Statements
The preparation of fmancial statements in conformity with GAAP requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities at the date of the fmancial statements and the reported amounts of revenues and expenses
during the period. These estimates include, but are not limited to: unbilled receivables; valuation of energy contracts; the effects of
regulation; the accounting for contingencies, including environmental and regulatory matters; and certain assumptions made in
accounting for pension and postretirement benefits. Actual results may differ from the estimates used in preparing the Financial
Statements.
Cash Equivalents
Cash equivalents consist of funds invested in commercial paper, money market securities and in other investments with a maturity of
three months or less when purchased.
December 31 December31
(MiIlions of dollars) 2006 2005
Cash (131)17.
Working funds (135)
Temporary cash investments (136)14.113.
Total cash and cash equivalents 24.131.
Accounting for the Effects of Certain Types of Regulation
PacifiCorp prepares its fmancial statements in accordance with the provisions of Statement of Financial Accounting Standards
SFAS") No. 71 Accountingfor the Effects of Certain Types of Regulation SFAS No. 71"), which differs in certain respects from
the application of GAAP by non-regulated businesses. In general, SF AS No. 71 recognizes that accounting for rate-regulated
enterprises should reflect the economic effects of regulation. As a result, a regulated entity is required to defer the recognition of costs
or income if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates.
Accordingly, PacifiCorp has deferred certain costs and income that will be recognized in earnings over various future periods.
Management continually evaluates the applicability of SF AS No. 71 and assesses whether its regulatory assets are probable of future
recovery by considering factors such as a change in the regulator s approach to setting rates from cost-based rate-making to another
form of regulation; other regulatory actions; or the impact of competition, which could limit PacifiCorp s ability to recover its costs.
Based upon this continual assessment, management believes the application of SF AS No. 71 continues to be appropriate and its
existing regulatory assets are probable of recovery. Ifit becomes probable that these costs will not be recovered, the assets and
liabilities would be written off and recognized in income from operations.
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 05/17/2007 2006/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Allowance for Doubtful Accounts
The allowance for doubtful accounts is based on PacifiCorp s assessment of the collectibility of payments from its customers. This
assessment requires judgment regarding the outcome of pending disputes, arbitrations and the ability of customers to pay the amounts
owed to PacifiCorp. The allowance activity was as follows:
Years Ended December 31
2006 2005
10.18.
10.
(9.(17.
11.9 10.
(Millions ofdollars)
Beginning balance
Charged to costs and expenses , net
Write-offs , net
Ending balance
Derivatives
PacifiCorp employs a number of different derivative instruments in connection with its electric and natural gas, foreign currency
exchange rate and interest rate risk management activities, including forward purchases and sales, swaps and options. Derivative
instruments are recorded in the Comparative Balance Sheet at fair value as either assets or liabilities unless they are designated and
qualifying for the normal purchases and normal sales exemptions afforded by GAAP.
For all hedge contracts, PacifiCorp maintains formal documentation of the hedge. In addition, at inception and on a quarterly basis
PacifiCorp formally assesses whether the hedge contracts are highly effective in offsetting changes in cash flows of the hedged items.
PacifiCorp documents hedging activity by transaction type and risk management strategy.
Changes in the fair value of a derivative designated and qualifying as a cash flow hedge, to the extent effective, are included in the
Statements of Accumulated Comprehensive Income, Comprehensive Income, and Hedging Activities, net of tax, until the hedged item
is recognized in income. PacifiCorp discontinues hedge accounting prospectively when it has determined that a derivative no longer
qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge
accounting is discontinued because the derivative no longer qualifies as an effective hedge, future changes in the value of the
derivative are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in Accumulated other
comprehensive income will remain in Accumulated other comprehensive income until the hedged item is realized, unless it is probable
that the hedged forecasted transaction will not occur, at which time associated deferred amounts in Accumulated other comprehensive
income are immediately recognized in earnings.
Certain derivative contracts utilized by PacifiCorp are recoverable through rates. Accordingly, unrealized changes in fair value of these
contracts are deferred as regulatory net assets or liabilities pursuant to SF AS No. 71.
Derivative contracts for commodities used in PacifiCorp s normal business operations that are settled by physical delivery, among
other criteria, are eligible for and may be designated as normal purchases and normal sales pursuant to the exemptions provided by
GAAP. Recognition of these contracts in Revenue or Operations expense in the Statement of Income occurs when the contracts settle.
When available, quoted market prices or prices obtained through external sources are used to measure a contract's fair value. For
contracts without available quoted market prices, fair value is determined based on internally developed modeled prices.
Inventories
Inventories consist mainly of materials and supplies, coal stocks and fuel oil, which are valued at the lower of average cost or market.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2P07 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Property, Plant and Equipment, Net
General
Property, plant and equipment are recorded at historical cost. PacifiCorp capitalizes all construction-related material, direct labor costs
and contract services, as well as indirect construction costs, which include allowance for funds used during construction. The cost of
major additions and bettennents are capitalized, while costs for replacements, maintenance, and repairs that do not improve or extend
the lives of the respective assets are charged to operating expense.
When PacifiCorp retires its regulated property, plant and equipment, it charges the original cost and the cost of removal and salvage to
accumulated depreciation. Generally, when depreciable regulated assets are sold, the cost is removed from the property accounts and
the related accumulated depreciation and amortization accounts are reduced and any residual gain or loss is amortized through
depreciation rates in the future.
PacifiCorp records an allowance for funds used during construction, which represents the estimated cost of debt and equity costs of
capital funds necessary to fmance capital additions. Allowance for funds used during construction is capitalized as a component of
Property, plant and equipment, with offsetting credits to the Statement of Income. After construction is completed, PacifiCorp is
pennitted to earn a return on these costs by their inclusion in rate base, as well as recover these costs through depreciation expense
over the useful life of the related assets.
The weighted-average aggregate rates used for the allowance for funds used during construction were 7.7% for the year,ended
December 31 2006 and 5.7% for the year ended December 31 2005. PacifiCorp s allowance for funds used during construction rates
do not exceed the maximum allowable rates detennined by regulatory authorities.
Intangible plant consists primarily of computer software costs that are originally recorded at cost. Accumulated amortization on
Intangible plant was $358.4 million at December 31 2006 and $341.2 at December 31 2005. Amortization expense on Intangible
plant was $45.7 million for the year ended December 31 , 2006 and $46.4 million for the year ended December 31 2005. The
estimated aggregate amortization on Intangible plant for the years ending December 31, 2007 through 2011 is $44.4 million in 2007
$36.7 million in 2008, $29.2 million in 2009, $25.5 million in 2010 and $23.2 million in 2011. Unamortized computer software costs
were $177.2 million at December 31 2006 and $188.9 million at December 31 , 2005.
PacifiCorp has unallocated acquisition adjustments that represent the excess of costs of the acquired interests in property, plant and
equipment purchased from other regulated utilities over their net book value in those assets. These unallocated acquisition adjustments
had an original cost of$157.2 million and accumulated depreciation of$79.9 million at December 31 2006.
Asset Retirement Obli1!ations
PacifiCorp recognizes legal asset retirement obligations, mainly related to the fmal reclamation ofleased coal-mining property. The
fair value of a liability for a legal asset retirement obligation is recognized in the period in which it is incurred, if a reasonable estimate
of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset, which is then
depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the liability is adjusted for any revisions to
the expected value of the retirement obligation (with corresponding adjustments to Property, plant and equipment) and for accretion of
the liability due to the passage of time. The difference between the asset retirement obligations liability, the corresponding asset
retirement obligations asset included in Property, plant and equipment and amounts recovered in rates to satisfy such liabilities is
recorded as a regulatory asset or liability. Estimated removal costs that PacifiCorp recovers through approved depreciation rates but
that do not meet the requirements of a legal asset retirement obligations are accumulated in Accumulated provision for depreciation in
the Comparative Balance Sheet.
Depreciation and Amortization
Depreciation and amortization are computed by the straight-line method either over the life prescribed by PacifiCorp s various
regulatory jurisdictions for regulated assets or over the assets' estimated useful lives. Composite depreciation rates of average
depreciable assets on utility Property, plant and equipment (excluding amortization of capital leases) were 3.0% for each of the years
ended December 31 2006 and 2005.
The average depreciable lives of Property, plant and equipment currently in use by category are as follows:
IFERC FORM NO.1 (ED. 12-88)Page 123.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Generation
Steam plant
Hydroelectric plant
Wind projects
Other plant
Transmission
Distribution
Intangible plant
Other
20 - 43 years
14 - 85 years
20 - 25 years
15 -35 years
20 - 70 years
44 - 50 years
5 - 50 years
5 - 30 years
Computer software costs included in Intangible plant are initially assigned a depreciable life of 5 to 10 years.
Revenue Recognition
Revenue from customers is recognized as electricity is delivered and includes amounts for services rendered. Amounts recognized
include unbilled as well as billed amounts. Rates charged are subject to federal and state regulation.
Electricity sales to retail customers are detennined based on meter readings taken throughout the month. PacifiCorp accrues an
estimate ofunbilled revenues, which are earned but not yet billed, net of estimated line losses, each month for electric service provided
after the meter reading date to the end of the month. The process of calculating the unbilled revenue estimate consists of three
components: quantifying PacifiCorp s total electricity delivered during the month, assigning unbilled revenues to customer type and
valuing the unbilled energy. Factors involved in the estimation of consumption and line losses relate to weather conditions, amount of
natural light, historical trends, economic impacts and customer type. Valuation of un billed energy is based on estimating the average
price for the month for each customer type.
Certain taxes assessed by governmental authorities on revenue-producing transactions are collected directly from PacifiCorp s "
customers and remitted directly to taxing authorities. This collection and remittance activity is recorded on a net basis and thus has no
income statement impact.
Income Taxes
As a result of the sale of PacifiCorp to MEHC on March 21 , 2006, Berkshire Hathaway Inc. commenced including PacifiCorp in its
S. federal income tax return. PacifiCorp s provision for income taxes has been computed on the basis that it files separate
consolidated income tax returns. Prior to the sale, PacifiCorp was included in PHI's consolidated U.S. federal income tax return.
Deferred tax assets and liabilities are based on differences between the fmancial statements and tax bases of assets and liabilities using
the estimated tax rates in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and
liabilities that are associated with components of Other comprehensive income are charged or credited directly to Other comprehensive
income. Otherwise, changes in deferred income tax assets and liabilities are included as a component of income tax expense.
PacifiCorp is required to pass income tax benefits related to certain property-related basis differences and other various differences on
to its customers in most state jurisdictions. These amounts were recognized as a net regulatory asset totaling $416.2 million as of
December 31, 2006, and will be included in rates when the temporary differences reverse. Management believes the existing regulatory
assets are probable of recovery. If it becomes probable that these costs will not be recovered, the assets would be written off and
recognized in earnings.
Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by
various regulatory jurisdictions.
In detennining PacifiCorp s tax liabilities, management is required to interpret complex tax laws and regulations. In preparing tax
returns, PacifiCorp is subject to continuous examinations by federal, state and local tax authorities that may give rise to different
interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S; An Original (Mo, Da, Yr)
PacifiCorp (2)A Resub(T1ission 05/17/2907 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
these examinations are completed and these matters are resolved. The Internal Revenue Service has closed its examination of
PacifiCorp s income tax returns through 2000. Although the ultimate resolution ofPacifiCorp s federal and state tax examinations is
uncertain, PacifiCorp believes it has made adequate provisions for these tax positions and the aggregate amount of any additional tax
liabilities that may result from these examinations, if any, will not have a material adverse effect on PacifiCorp s fmancial condition
results of operations or cash flows. PacifiCorp s provision for tax uncertainties is included in current and accrued assets or liabilities in
the Comparative Balance Sheet.
Segment Information
PacifiCorp currently has one segment, which includes the regulated retail and wholesale electric utility operations.
New Accounting Standards
FERC Order No. 668
In December 2005, FERC issued order 668 Accounting and Financial Reportingfor Public Utilities Including RTOs FERC Order
No. 668"). The main purpose of FERC Order No. 668 is to establish new accounting and reporting requirements for regional
transmission organizations. However, the order also establishes new accounts and reporting for certain transmission activities for
non-regional transmission organization public utilities. This order was effective April I, 2006. The issuance of this order did not have
a material impact to PacifiCorp s fmancial position or results of operations.
FIN
In March 2005, the Financial Accounting Standards Board (the "FASB") issued FASB Interpretation No. 47 Accountingfor
Conditional Asset Retirement Obligations an Interpretation of FASB Statement No. 143 ("FIN 47"). 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 fair value of the
liability can be reasonably estimated. Upon adoption of FIN 47 at March 31, 2006, PacifiCorp recorded an asset retirement obligation
liability at a net present value of $22.7 million, increased net depreciable assets by $1.8 million and increased regulatory assets by
$20.9 million.
EITF No. 04-
On April I, 2006, PacifiCorp adopted 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 ofa mine are variable production costs that should be included in the costs of the inventory produced (that
, extracted) during the period that the stripping costs are incurred. The adoption ofEITF No. 04-6 did not have a material impact on
PacifiCorp s fmancial position or results of operations.
FIN
In July 2006, the Financial Accounting Standards Board (the "FASB") issued FASB Interpretation No. 48 Accountingfor Uncertainty
in Income Taxes- an interpretation ofF ASB Statement No.1 09 FIN 48"). FIN 48 clarifies the accounting for uncertainty in income
taxes recognized in accordance with SF AS No. 109 Accountingfor Income Taxes and prescribes a recognition threshold and
measurement attribute for the fmancial statement recognition and measurement of a tax position taken or expected to be taken in a tax
return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and
transition. FIN 48 is effective on January 1 2007. PacifiCorp is currently evaluating the impact and based upon its assessment to date
does not believe the adoption of FIN 48 will have a material effect on its fmancial position and results of operations.
SFAS No. 157
In September 2006, the F ASB issued SF AS No. 157 Fair Value Measurements SF AS No. 157"). SF AS No. 157 defines fair value
establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not
impose fair value measurements on items not already accounted for at fair value; rather, it applies, with certain exceptions, to other
accounting pronouncements that either require or permit fair value measurements. SF AS No. 157 is effective for fiscal years beginning
after November 15 , 2007 and interim periods within those fiscal years. PacifiCorp is currently evaluating the impact of adopting SF
No. 157 on its fmancial position and results of operations.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S, An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
SF AS No. 158
In September 2006, the FASB issued SFAS No. 158 Employers ' Accountingfor Defined Benefit Pension and Other Postretirement
Plans-an amendment ofFASB Statements No. , 88 106, and I32(R) SFAS No. 158"). SFAS No. 158 requires an employer to
recognize an asset or liability for the over- or underfunded status of a defined benefit postretirement plan measured as the difference
between the fair value of plan assets and the benefit obligation. For a pension plan, the benefit obligation is the projected benefit
obligation; for any other postretirement benefit plan, such as a retiree healthcare plan, the benefit obligation is the accwnulated
postretirement benefit obligation. SF AS No. 158 also requires entities to recognize as a component of other comprehensive income
net of tax, the actuarial gains and losses and the prior service costs and credits that arise during the period, but that were not recognized
as components of net periodic benefit cost of the period pursuant to SFAS No 87 Employers ' Accountingfor Pensions SFAS No.
87"), and SF AS No. 106 Employers ' Accountingfor Postretirement Benefits Other Than Pensions SFAS No. 106"). However, as
PacifiCorp is subject to SF AS No. 71 , it recognized as regulatory assets substantially all amounts that would have been otherwise
charged to other comprehensive income including the tax effect of any additional recovery expected trom regulatory treatment. SF
No. 158 does not impact the calculation of net periodic benefit cost and the amounts recognized in either Accumulated other
comprehensive income or as a regulatory asset will be adjusted as they are subsequently recognized as components of net periodic
benefit cost pursuant to the recognition and amortization provisions of SF AS No. 87 and SF AS No.1 06.
PacifiCorp adopted the recognition and related disclosure provisions of SF AS No. 158 as of December 31 , 2006. The incremental
impacts of such adoption to the Comparative Balance. Sheet as of December 31 , 2006 are as follows:
Before Increase A fier
(Millions of dollars) SFAS No. 158 (Decrease)SFAS No. 158
Deferred income taxes 654.165.819.
Regulatory assets 054.4 341.3 395.
Miscel1aneous deferred debits 71.8 (13.58.
Total assets 191.5 492.684.
Accumulated provision for
pensions and benefits 325.365.690.
Miscel1aneous current and
accrued liabilities 80.84.
Deferred income taxes 308.124.2,433.4
Total liabilities 763.493.257.
Accumulated other comprehensive
income (2.(1.3)(3.
Total shareholders' equity 428.(1.3)4,426.
SF AS No. 158 also requires that an employer measure plan assets and obligations as of the end of the employer s fiscal year
eliminating the option in SF AS No. 87 and SF AS No.1 06 to measure up to three months prior to the financial statement date. The
requirement to measure plan assets and benefit obligations as of the date of the employer s fiscal year-end is not required until fiscal
years ending after December 15 2008. PacifiCorp did not adopt the measurement date provisions of the statement during the year
ended December 31, 2006. Upon adoption ofthe measurement date provisions, PacifiCorp will be required to record a transitional
adjustment to retained earnings or to a regulatory asset depending on whether the amount is considered probable of being recovered in
rates.
For GAAP reporting purposes, the adoption of SF AS No. 158 was not reflected as a component of other comprehensive income during
the period, but rather as a component of the ending balance of accumulated other comprehensive income. For FERC reporting
purposes, the adoption of SF AS No. 158 was presented as a component of other comprehensive income during the period, as well as a
component ofthe ending balance of accumulated other comprehensive income.
SFAS No. 159
In February 2007, the F ASB issued SFAS No. 159 The Fair Value Option for Financial Assets and Financial Liabilities, Including
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 05/17/2007 2006104
NOTES TO FINANCIAL STATEMENTS (Continued)
an Amendment to SF AS No. 115 ("SF AS No. 159"). SF AS No. 159 pennits entities to elect to measure many financial instruments and
certain other items at fair value. Upon adoption of SF AS No. 159, an entity may elect the fair value option for eligible items that exist
at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at initial recognition
of the asset or liability or upon a remeasurement event that gives rise to new-basis accounting. The decision about whether to elect the
fair value option is applied on an instrument-by-instrument basis, is irrevocable and is applied only to an entire instrument and not only
to specified risks, cash flows or portions ofthat instrument. SFAS No. 159 does not affect any existing accounting standards that
require certain assets and liabilities to be carried at fair value nor does it eliminate disclosure requirements included in other
accounting standards. SF AS No. 159 is effective for fiscal years beginning after November 15, 2007. PacifiCorp is currently
evaluating the impact of adopting SF AS No. 159 on its fmancial position and results of operations.
Note 3 - Regulatory Assets and Liabilities
PacifiCorp is subject to the jurisdiction of public utility regulatory authorities of each of the states in which it conducts retail electric
operations with respect to prices, services, accounting, issuance of securities and other matters. At present, PacifiCorp is subject to
cost-based rate-making for its business. PacifiCorp is a "licensee" and a "public utility" as those tenns are used in the Federal Power
Act and is, therefore, subject to regulation by the FERC as to accounting policies and practices, certain prices and other matters.
PacifiCorp had regulatory assets not earning a return on investment of$I 269.3 million at December 31 , 2006. For a detailed view of
PacifiCorp s regulatory assets and liabilities see page 232 Regulatory Assets and page 278 Regulatory Liabilities of this FERC Fonn
Note 4 - Short-Term Borrowings
Short-Term Debt
PacifiCorp s outstanding short-tenn borrowings consisted of commercial paper arrangements of$399.0 million at an average interest
rate of5.3% at December 31 , 2006 and $215.0 million at an average interest rate of 4.3% at December 31 2005.
Revolving Credit Agreement
PacifiCorp has an $800.0 million unsecured revolving credit facility expiring in July 2011. The credit facility includes a variable
interest rate borrowing option based on the London Interbank Offered Rate (LIBOR), plus 0.195%, that varies based on PacifiCorp
credit ratings for its senior unsecured long-tenn debt securities, and it supports PacifiCorp s commercial paper program. At December
, 2006, there were no borrowings outstanding under this facility.
PacifiCorp s revolving credit and other fmancing agreements contain customary covenants and default provisions, including a
covenant not to exceed a specified debt-to-capitalization ratio of 0.65 to 1.0. At December 31, 2006, PacifiCorp was in compliance
with the covenants of its revolving credit and other fmancing agreements.
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 P5~17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 5 - Long-Term Debt, Preferred Stock Subject to Mandatory Redemption and Capital Lease
Obligations
PacifiCorp s long-tenn debt, prefeITed stock subject to mandatory redemption and capital lease obligations were as follows:
December 31
2006 2005
Average Average
Interest Interest
(Millions of dollars) Amount Rate Amount Rate
First mort e bonds
4.3% to 9.2%, due through 2011 1 ,277.6 %588.4 5 %
0% to 8., due 2012 to 2016 457.457.
4% to 8., due 2017 to 2021 21.7 21.7
7% to 8.3%, due 2022 to 2026 404.7.4 404.7.4
7% due 2031 300.300.
3 % to 6., due 2032 to 2036 850.500.
Unamortized discount (5.3)(4.
Guarantv of po llution-con tro 1 rev en ue bonds
Variable rates, due 2013 (a)(b)40.40.
Variable rates, due 2014 to 2025 (b)325.325.
Variable rates, due 2024 (a)(b)175.175.
3.4% to 5.7%, due 2014to 2025 (a)184.184.
, due 2030 12.12.
Unamortized discount (0.5)(0.
Funds held by trustees (2.
Total Ion g-t e1l11 debt 043.001.9
Otherlong te1l11 debt
PrefeITed stock subject to mandatory
redemption, due 2007 37.45.
Total other 10ng-te1l11 debt 37.45.
Capital lease obligations
10.4% to 14.8%, due through 2036 50.11.7 38.11. 7
Total capital lease obligations 50.38.
Total 131.2 085.
(a)Secured by pledged first mortgage bonds generally at the same interest rates, maturity dates and
redemption provisions as the pollution-control revenue bonds.
Interest rates fluctuate based on various rates, primarily on certificate of deposit rates, interbank
boITowing rates, prime rates or other short-tenn market rates.
(b)
First mortgage bonds ofPacifiCorp may be issued in amounts limited by PacifiCorp s property, earnings and other provisions of the
mortgage indenture. Approximately $14.6 billion ofthe eligible assets (based on original cost) ofPacifiCorp were subject to the lien of
the mortgage at December 31 , 2006.
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 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
In September 2005, the Securities and Exchange Commission declared effective PacifiCorp s shelf registration statement covering
$700.0 million of future first mortgage bond and unsecured debt issuances. During February 2007, PacifiCorp filed a shelf registration
statement with the SEC covering an additional $800.0 million of first mortgage bond and unsecured debt issuances. This registration
statement was declared effective by the SEC.
As of December 31, 2006, $2.7 billion offlfst mortgage bonds were redeemable at PacifiCorp s option at redemption prices dependent
upon United States Treasury yields. As of December 31, 2006, $541.7 million of variable-rate pollution-control revenue bonds were
redeemable at PacifiCorp s option at par. As of
December 31, 2006, $71.2 million of fixed-rate pollution-control revenue bonds were redeemable at PacifiCorp s option at par and
another $12.7 million at 102.0% of par. The remaining long-term debt was not redeemable at December 31 2006.
In August 2006, PacifiCorp issued $350.0 million of its 6.10% Series of First Mortgage Bonds due August 1 2036.
At December 31, 2006, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements available to
provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. In addition, PacifiCorp
had approximately $21.0 million of standby letters of credit to provide credit support for certain transactions as requested by third
parties. These committed bank arrangements were all fully available at December 31 , 2006 and expire periodically through February
2011.
PacifiCorp s standby letters of credit and standby bond purchase agreements generally contain similar covenants and default provisions
to those contained in PacifiCorp s revolving credit agreement, including a covenant not to exceed a specified debt-to-capitalization
ratio of 0.65 to 1. PacifiCorp monitors these covenants on a regular basis in order to ensure that events of default will not occur and at
December 31 , 2006, PacifiCorp was in compliance with these covenants.
PacifiCorp has entered into long-term agreements that expire at various dates through October 2036 for transportation services, real
estate and for the use of certain equipment which qualify as capital leases. The transportation services agreements included as capital
leases are for the right to use newly constructed pipeline facilities to provide natural gas to two ofPacifiCorp s power plants. Non-cash
additions to property, plant and equipment related to these capital leases were $12.6 million during the year ended December 31 2006
and $12.4 million during the year ended December 31 , 2005. Assets accounted for as capital leases of $49.3 million as of December
2006 and $36.7 million as of December 31 2005 were included in Utility plant on the Comparative Balance Sheet.
PacifiCorp s PrefeITed stock subject to mandatory redemption was as follows:
(Thousands of shares , millions ofdollars)
Series
December 31 2006
Shares A moun t
December 31, 2005
Shares Amount
No Par Serial PrefeITed, 16 000 shares authorized
$100 stated value
$7.48 375 $ 37.450 $ 45.
All outstanding shares are subject to mandatory redemption on June 15 2007. Holders of Preferred stock subject to mandatory
redemption are entitled to certain voting rights. PacifiCorp redeemed $7.5 million of Preferred stock subject to mandatory and optional
redemption during the years ended December 31 2006 and 2005. Dividends declared but unpaid on Preferred stock subject to
mandatory redemption that were included in Interest payable were $0.7 million at December 31, 2006 and $0.8 million at December
2005.
The annual maturities of long-term debt, preferred stock subject to mandatory redemption and capital lease obligations for the years
ending December 31 are:
IFERC FORM NO.1 (ED. 12-88)Page 123,
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Pre fen-ed
Stock Subject
Long-tenn to Mandatory Capital Lease
(Millions of dollars) Debt Redemption Obligations Total
2007 125.37.170.
2008 412.4 419.4
2009 138.145.5
2010 14.21.6
2011 586.593.
Thereafter 771.0 91.3 862.3
048.37.5 126.212.
Unamortized discount (5.(5.
Amounts representing interest (a)(75.(75.
043.1 37.50.$ 4 131.2
(a)Interest expense on capital lease obligations is recorded as rent expense.
Note 6 - Asset Retirement Obligations
PacifiCorp records asset retirement obligation liabilities for long-lived physical assets that qualify as legal obligations. PacifiCorp
estimates its asset retirement obligation liabilities based upon detailed engineering calculations of the amount and timing of the future
cash spending for a third party to perfonn the required work. Spending estimates are escalated for inflation and then discounted at a
credit-adjusted, risk-free rate. PacifiCorp then records an asset retirement obligation asset associated with the liability. The asset
retirement obligation assets are depreciated over their expected lives and the asset retirement obligation liabilities are accreted to the
projected spending date. Changes in estimates could occur due to plan revisions, changes in estimated costs and changes in timing of
the perfonnance of reclamation activities.
PacifiCorp does not recognize liabilities for asset retirement obligations for which the fair value cannot be reasonably estimated. Due
to the indetenninate removal date, the fair value of the associated liabilities on certain transmission and distribution and other assets
cannot currently be estimated and no amounts are recognized in the accompanying Financial Statements other than those included in
Accumulated provision for depreciation as established in approved depreciation rates.
On March 31 , 2006, PacifiCorp adopted F ASB Interpretation No. 47 Accountingfor Conditional Asset Retirement Obligations
interpretation of F ASB Statement No. 143 ("FIN 47"). FIN 47 clarifies that the tenD "conditional asset retirement obligation" as used
in SFAS No. 143 Accountingfor Asset Retirement Obligations refers to a legal obligation to perfonn 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.
Accordingly, PacifiCorp is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair
value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset
retirement obligation should be factored into the measurement of the liability when sufficient infonnation exists.
In conjunction with the adoption of FIN 47 at March 31, 2006, PacifiCorp recorded an asset retirement obligation liability at a net
present value of$22.7 million, which is included in Liabilities incurred in the table below. PacifiCorp also increased net depreciable
assets by $1.8 million, reclassified $13.5 million of costs accrued for removal from regulatory liabilities to asset retirement obligation
liabilities, increased regulatory liabilities by $0.4 million and increased regulatory assets by $7.8 million for the difference between
retirement costs approved by regulators and obligations under FIN 47.
The following table describes the changes to PacifiCorp s asset retirement obligation liability for the years ended December 31 2006
and 2005:
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 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(M ill ions of dolIars)December 31 2006 December 31 2005
Liability recognized at beginning of period 62.66.
Liabilities incurred 28.1.5
Liabilities settled (5.4)(10.
Revisions in cash flow (a)(3.1.4
Accretion expense (b)
Asset retirement obligation 85.62.4
(a)
(b)
Results fiom changes in the timing and amounts of estimated cash flows for certain plant reclamation.
PacifiCorp records the accretion expense of asset retirement obligations as either a regulatory asset or (liability).
Note 7 - Risk Management and Hedging Activities
PacifiCorp is directly exposed to the impact of market fluctuations in the prices of natural gas and electricity. PacifiCorp is exposed to
interest rate risk as a result of the issuance offixed and variable rate debt. PacifiCorp employs established policies and procedures to
manage its risks associated with these market fluctuations using various commodity and fmancial derivative instruments, including
forward contracts, swaps and options. The risk management process established by PacifiCorp is designed to identify, measure, assess
report and manage each of the various types of risk involved in its business. PacifiCorp s portfolio of energy derivatives is
substantially used for non-trading purposes. As of December 31 , 2006 PacifiCorp had no fmancial derivatives in effect relating to
interest rate exposure.
Commodity Price Risk
PacifiCorp is exposed to market risk due to the variations in the price of fuel used for generation and the price of wholesale electricity
to be purchased or sold. To manage this commodity price risk, as well as to optimize the utilization of power generation assets and
related contracts, PacifiCorp enters into forward purchases and sales. Such energy purchase and sales activities are governed by
PacifiCorp s risk management policy.
PacifiCorp makes continuing projections of future retail and wholesale loads and future resource availability to meet these loads based
on a number of criteria, including historical load and forward market and other economic infonnation and experience. Based on these
projections, PacifiCorp purchases and sells electricity on a forward yearly, quarterly, monthly, daily and hourly basis to match actual
resources to actual energy requirements and sells any surplus at the prevailing market price. This process involves hedging
transactions, which include the purchase and sale of finn energy under long-tenn contracts, forward physical contracts or fmancial
contracts for the purchase and sale of a specified amount of energy at a specified price over a given period of time.
PacifiCorp manages its natural gas supply requirements by entering into forward commitments for physical delivery of natural gas.
PacifiCorp also manages its exposure to increases in natural gas supply costs through forward commitments for the purchase of
physical natural gas at fixed prices and fmancial swap contracts that settle in cash based on the difference between a fIXed price that
PacifiCorp pays and a floating market-based price that PacifiCorp receives.
Derivative Instruments
Forward purchases and sales that do not qualify for the exemptions afforded by GAAP are accounted for as derivatives and are
recorded on the Comparative Balance Sheet as assets or liabilities measured at estimated fair value. Where PacifiCorp s derivative
instruments are subject to a master netting agreement and the criteria of FIN 39 Offietting of Amounts Related to Certain Contracts-
An Interpretation of APB Opinion No. 10 and F ASB Statement No. 105 are met, PacifiCorp presents its derivative assets and
liabilities, as well as accompanying receivables and payables, on a net basis in the accompanying Comparative Balance Sheet. For
those energy purchase and sales contracts that are probable of recovery in rates, the unrealized gains and losses on derivative
instruments are recorded as a regulatory net asset or liability.
Realized gains and losses on contracts that qualify as nonnal purchases and nonnal sales under GAAP (and therefore exempted from
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/1712007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
fair value accounting) are reflected in the Statement of Income at the contract settlement date.
Unrealized gains and losses on derivative contracts held for trading purposes are presented on a net basis in the Statement of Income as
Miscellaneous non-operating income. Unrealized gains and losses on derivative contracts not held for trading purposes are presented in
the Statement of Income as Miscellaneous non-operating income for unrealized gains and Other deductions for unrealized losses.
Realized gains and losses on physically settled derivative contracts not held for trading purposes are presented in the Statement of
Income as Revenues for sales contracts and as Operating expenses for purchase contracts. Realized gains and losses on non-physically
settled derivative contracts not held for trading purposes are presented on a net basis in the Statement of Income as Revenues.
The following table summarizes the various derivative mark-to-market positions included in the accompanying Comparative Balance
Sheet as of December 31 2006:
(Millions of dollars)Net Assets (Liability)Assets Liabilities Total
Commodity hedges 382.$ (614.$ (23\.5)
Foreign currency swaps
385.$ (614.$ (228.
Current 150.$ (109.4\.4
Non-current 234.(504.(269.
Total 385.$ (614.$ (228.
(a)Before income taxes.
Accumulated
Regulatory Other
Net Asset Com prehen sive
(Liability)Income (Loss) (a)
233.(3.
(3.
229.(3.
The following table summarizes the various derivative mark-to-market positions included in the accompanying Comparative Balance
Sheet as of December 31 2005:
(Millions of dollars)Net Assets (Liability)
Assets Liabilities Total
884.$ (743.14\.6
380.$ (210.169.
504.(533.(28.
884.$ (743.14\.6
Commodity hedges
Current
Non-current
Total
(a)Before income taxes.
Regulatory
Net Asset
(Liability)
Accumulated
Other
Comprehensive
Income (Loss) (a)
(92.3 )
Cash Flow Hedl!;nl!
In order to reduce the impact of fluctuations in forward prices of electricity and natural gas on PacifiCorp s results of operations
PacifiCorp initiated cash flow hedging in April 2006 for a portion of its derivative contracts, primarily electricity sales and natural gas
purchase contracts. Changes in the fair value of derivative contracts designated as cash flow hedges are recorded as other
comprehensive income to the extent the hedges are effective in offsetting changes in future cash flows for forecasted electricity and
natural gas purchase and sales transactions. Amounts included in Accumulated other comprehensive income are reclassified to the
Statement of Income when the forecasted sale or purchase transaction is recognized in earnings, or when it is probable that the
forecasted transaction will not occur.
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 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
At December 31 , 2006, PacifiCorp had cash flow hedges with expiration dates through December 2007. During the year ended
December 31, 2006, hedge ineffectiveness was insignificant. At December 31 , 2006, $3.3 million of pre-tax net unrealized gains are
forecasted to be reclassified from Accumulated other comprehensive income into earnings over the next twelve months as contracts
settle. Hedge ineffectiveness and reclassifications from Accumulated other comprehensive income to earnings are presented in
Miscellaneous non-operating income and Other deductions.
Summarv of Activity
The following table summarizes the amount of the pre-tax unrealized gains and losses included within the Statement oflncome
associated with changes in the fair value ofPacifiCorp s derivative contracts that are not included in rates:
Years Ended Decem ber 31,
(Millions of dollars)
Revenues
Miscellaneous nonoperatin g in come (421)
Other income deductions:
2006 2005
(475.(368.
526.326.
51.0 (42.
Other deductions (426.5)
Total unrealized (gain) loss on derivative contracts
Fair Value Calculations
PacifiCorp bases its forward price curves upon market price quotations when available and bases them.on internally developed and
commercial models, with internal and external fundamental data inputs, when market quotations are unavailable. Market quotes are
obtained from independent energy brokers, as well as direct information received from third-party offers and actual transactions
executed by PacifiCorp. 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, forward price curves must be developed. 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 (beyond the fIrst six years) is based upon the use of a
fundamentals model (cost-to-build approach) due to the limited information available. The fundamentals model is updated as
warranted, at least quarterly, to reflect changes in the market, such as long-term natural gas prices and expected inflation rates.
Short-term contracts, without explicit or embedded optionality, are valued based upon the relevant portion of the forward price curve.
Contracts with explicit or embedded optionality are valued by separating each contract into its physical and fmancial forward, swap
and option components. Forward and swap components are valued against the appropriate forward price curve. The optionality is
valued using a modified Black-Scholes model approach or a stochastic simulation (Monte Carlo) approach. Each option component is
modeled and valued separately using the appropriate forward price curve.
Foreien Currencv Derivatives
PacifiCorp has entered into an agreement with a turbine supplier in connection with the construction of a wind project that requires
PacifiCorp to make certain payments in Euros ("). To mitigate the related exposure to fluctuations in foreign currency exchange
rates, PacifiCorp entered into a forward contract to purchase €76.8 million at a fixed price of U.S. Dollars. This contract has a series of
payments and settlement dates extending to March 15 2007 that correspond to the payments to be made in Euros in accordance with
the supply agreement. The forward contract qualifies as a derivative instrument. As the cost of the associated wind project is expected
to be recovered in rates, the unrealized gain on this contract of $3.3 million at December 31 , 2006 was recorded as a net regulatory
asset.
Weather Derivatives
PacifiCorp had a non-exchange-traded streamflow weather derivative contract to reduce PacifiCorp s exposure to variability in weather
conditions that affect hydroelectric generation. The contract expired on September 30, 2006. PacifiCorp paid an annual premium in
return for the right to make or receive payments if streamflow levels were 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 ElTF No. 99-
Accountingfor Weather Derivatives. The net liability recorded for this contract was zero at December 31 2006 and 2005. PacifiCorp
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission . 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
recognized a loss of$12.4 for the year ended December 31, 2006 and a gain of $9.4 million for the year ended December 31 , 2005.
Note 8 - Income Taxes
Income tax expense (benefit) consists of the following:
Current:
Federal
State
YearsEndedDecmber 31,
2006 2005
131.116.
12.5
144.126.
19.61.1
2 J.l 66.
(7.(7.
157.185.
(Millions of dollars)
Total
De ferred:
Federal
State
Total
Investment tax credits
Total income tax expense
A reconciliation of the federal statutory tax rate to the effective tax rate applicable to income before income tax expense follows:
Years Ended December 31 ,2006 2005
35.35.
(2.1.5
(3.(2.
(2.(2.
33.7 %38.1 %
Federal statutory rate
State taxes, net of federal benefit
Effect of regulatory treatment
of depreciation differences
T ax reserves
T ax credits
Other
Effective income tax rate
The net deferred tax liability consists of the following:
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 Hesubmission 05/17/2007'2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
December 31 Decem ber 3 I
(Millions of dollars)2006 2005
De fer red tax asset s:
Regulatory liabilities 319.330.
Employee benefits 294.4 179.
DerivatIve contracts 1023 45,
Other deferTed tax assets 103.132.
819,6873
Deferred tax liabilities:
Property, plant and equipment (1,509.518.
Regulatory assets (726.(647.
Derivative contract regulatory assets (87.
Other defeITed tax liabilities (109.(147.
433.313.4)
Net deferred tax liability (1,613.(1,626.
As of December 31, 2006 and 2005, PacifiCorp had no federal or state net operating loss carryforwards. PacifiCorp has Oregon
business energy tax credits of approximately $3.0 million at December 31 , 2006 available to reduce future income tax liabilities. These
credits begin to expire in 2015. PacifiCorp has Idaho investnient tax credits of approximately $2.3 million at December 31 , 2006 that
are available to reduce future income tax liabilities. These credits begin to expire in 2016. PacifiCorp anticipates utilizing the tax
credits prior to the expiration dates.
PacifiCorp has established, and periodically reviews, an estimated contingent tax reserve on its Comparative Balance Sheet to provide
for the possibility of adverse outcomes in tax proceedings. In addition, tax benefits are recognized in the period in which resolution is
reached with taxing authorities. The reserve for net federal and state contingencies decreased $12.1 million during the year ended
December 31, 2006. The decrease was primarily attributable to resolution of certain items previously outstanding with the Internal
Revenue Service related to the examination of tax years ended March 31 , 2001 through 2003. PacifiCorp anticipates that the resolution
of the remaining outstanding issues related to federal income tax returns through March 31 2003 and other unresolved issues will not
have a material adverse impact on its fmancial results.
The sale of PacifiCorp to MEHC on March 21, 2006 triggered the recognition of a deferred intercompany gain or loss for tax
purposes. The recognition of the tax effects of this item is considered to have occurred immediately prior to the closing of the sale of
PacifiCorp while it was part of the PHI consolidated group. However, no adjustments have been recorded as PacifiCorp is not yet able
to estimate the amount of the tax effect, if any, or determine a range of the potential tax effect. As the transaction was deemed to be
with shareholders and as a result of fonnal agreements among PacifiCorp, MEHC, PHI and ScottishPower, PacifiCorp does not believe
any adjustments resulting from the tax effect of a deferred intercompany gain or loss will have a material impact on its fmancial results.
Note 9 - Preferred Stock
PacifiCorp s preferred stock, not subject to mandatory redemption, including issuance expense of $0.2 million which is included in
account 214 on the Comparative Balance Sheet, was as follows:
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)Resubmission 05/17/2007 '2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(Thousands of shares, millions of doHars Redemption
except per share am:nmts)Price Decemer 31, 2006 December 31 , 2005
Series Per ~are ~es Am:nmt Shares Amount
Serial Preferred, $100 stated value
500 shares authorized
52 %103.
1023
103.
100.
101.0
Non-redeemable
Non-redeemable 1.8 1.8
5% Preferred, $100 stated value
127 shares authorized 110.126 12.126 126
415 41.3 415 41.3
Generally, preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrictions. In the event of
voluntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends.
Upon involuntary liquidation, all preferred stock is entitled to stated value plus accrued dividends. Any premium paid on redemptions
of preferred stock is capitalized, and recovery is sought through future rates. Dividends on all preferred stock are cumulative. Holders
also have the right to elect members to the PacifiCorp Board of Directors in the event dividends payable are in default in an amount
equal to four full quarterly payments.
Dividends declared but unpaid on preferred stock were $0.5 million at December 31 , 2006 and $0.5 million at December 31, 2005.
Note 10 - Common Shareholder s Equity
Appropriated Retained Earnings
At December 31, 2006, PacifiCorp had $3.6 million in Appropriated retained earnings - amortization reserve, federal in accordance
with the requirements of certain hydroelectric relicensing projects.
Common Shareholder s Equity
PacifiCorp has one class of common stock with no par value. A total of750 000 000 shares were authorized and 357 060 915 shares
were issued and outstanding at December 31 , 2006 and 347 158 187 shares issued and outstanding at December 31 , 2005.
During the nine months ended December 31, 2006 and while under the control of its then direct parent company PPW Holdings, LLC
PacifiCorp received equity contributions of$215.0 million in cash from PPW Holdings LLC.
During the three months ended March 31 , 2006, PacifiCorp issued 9,902 728 shares of its common stock to PHI, its former parent
company, at a total price of$1O9.7 million.
During the year ended December 31 , 2005, PacifiCorp issued 34 982 098 shares of its common stock to PHI, its former parent
company, at a total price of$375.0 million.
Common Dividend Restrictions
Through PPW Holdings LLC, MEHC is the sole shareholder ofPacifiCorp s common stock. The state regulatory orders that
authorized the acquisition ofPacifiCorp by MEHC contain restrictions on PacifiCorp s ability to pay dividends to the extent that they
would reduce PacifiCorp s common stock equity below specified percentages of defined capitalization.
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 Resubmi&sion 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
As of December 31, 2006, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to either PPW
Holdings LLC or MEHC without prior state regulatory approval to the extent that it would reduce PacifiCorp s common stock equity
below 48.25% of its total capitalization, excluding short-tenn debt and current maturities of long-tenn debt. After December 31 , 2008
this minimum level of common equity declines annually to 44.0% after December 31, 2011. The tenns of this commitment treat 50.
ofPacifiCorp s remaining balance of preferred stock in existence prior to the acquisition ofPacifiCorp by MEHC as common equity.
As of December 31 2006, PacifiCorp s actual common stock equity percentage, as calculated under this measure, exceeded the
minimum threshold.
These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings LLC or MEHC ifPacifiCorp
unsecured debt rating is BBB- or lower by Standard & Poor s Rating Services or Fitch Ratings or Baa3 or lower by Moody s Investor
Service, as indicated by two of the three rating services. At December 31 2006, PacifiCorp s unsecured debt rating was BBB+ by
Standard & Poor s Rating Services and Fitch Ratings and Baal by Moody s Investor Service.
PacifiCorp is also subject to maximum debt-to-total capitalization percentage under various fmancing agreements as further discussed
in Notes 4 and 5.
Note 11 - Contingencies
Legal Matters
PacifiCorp is party to a variety oflegal actions arising out of the nonnal course of business. Plaintiffs occasionally seek punitive or
exemplary damages. PacifiCorp does not believe that such nonnal and routine litigation will have a material effect on its financial
results. PacifiCorp is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines
and penalties in substantial amounts.
In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a compliant against PacifiCorp in the federal district court
in Cheyenne, Wyoming, alleging violations of the Clean Air Act's opacity standards at PacifiCorp s Jim Bridger Power Plant in
Wyoming. Under the Clean Air Act, a potential source of pollutants such as a coal-flfed generating facility must meet minimum
standards for opacity, which is a measurement oflight in the flue of a generating facility. The complaint alleges thousands of violations
and seeks an injunction ordering the Jim Bridger plant's compliance with opacity limits, civil penalties of$32 500 per violation, and
the plaintiffs' costs of litigation. PacifiCorp believes it has a number of defenses to the claims , and it has already committed to invest at
least $812.0 million in pollution control equipment at its generating facilities, including the Jim Bridger plant, that is expected to
significantly reduce emissions. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time.
Environmental Matters
PacifiCorp is subject to numerous environmental laws, including the federal Clean Air Act, related air quality standards promulgated
by the Environmental Protection Agency 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 have the
potential for impacting PacifiCorp s operations. Specifically, the Clean Air Act will likely continue to impact the operations of
PacifiCorp s generating facilities and will likely require PacifiCorp to reduce emissions from those facilities through the installation of
additional or improved emission controls, the purchase of additional emission allowances, or some combination thereof. As of
December 31 , 2006, PacifiCorp' s environmental contingencies principally consist of air quality matters. Pending or proposed air
regulations would, if enacted, require PacifiCorp to reduce its electricity plant emissions of sulfur dioxide, nitrogen oxide and other
pollutants at its generating plants below current levels. PacifiCorp believes it is in material compliance with current environmental
requirements.
PacifiCorp s policy is to accrue environmental cleanup-related costs ofa non-capital nature when those costs are believed to be
probable and can be reasonably estimated. The quantification of environmental exposures is based on assessments of many factors
including changing laws and regulations, advancements in environmental technologies, the quality of infonnation available related to
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 Resubmlssion 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
specific sites, the assessment stage of each site investigation, preliminary findings and the length oftime involved in remediation or
settlement, PacifiCorp s proportionate share and any coverage provided by insurance policies. Remediation costs that are fixed and
determinable have been discounted to their present value using credit-adjusted, risk-free discount rates based on the expected future
annual borrowing costs of PacifiCorp. The liability recorded was $19.9 million at December 31 , 2006 and $13.5 million at December
, 2005 and is included in Deferred credits on the accompanying Comparative Balance Sheet. The December 31, 2006 recorded
liability included $2.5 million of discounted liabilities. Had none of the liabilities included in the $19.9 million balance recorded at
December 31 2006 been discounted, the total would have been $20.5 million. The expected payments for each of the years ending
December 31 , 2007 through 2011 and thereafter are as follows: $1.9 million in 2007, $1.7 million in 2008, $1.5 million in 2009, $0.4
million in 2010, $0.4 million in 2011 and $14.6 million thereafter.
It is possible that future fmdings or changes in estimates could require that additional amounts be accrued. Should current
circumstances change, it is possible that PacifiCorp could incur an additional undiscounted obligation of up to approximately $10.
million relating to existing sites. However, management believes that completion or resolution ofthese matters will have no material
adverse effect on PacifiCorp s fmancial position, results of operations or cash flows.
Hydroelectric Relicensing
PacifiCorp s hydroelectric portfolio consists of 50 plants with an aggregate plant net owned capacity of 1 160.1 MW. The FERC
regulates 97.9% of the net capacity of this portfolio through 18 individual licenses. Several ofPacifiCorp s hydroelectric projects are
in some stage of relic en sing with the FERc. 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 will consist primarily of
additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result
from the additional environmental requirements. PacifiCorp had incurred $79.0 million in costs at December 31 , 2006 for ongoing
hydroelectric relicensing, which are reflected in Construction work-in-progress on the Comparative Balance Sheet.
In February 2004, PacifiCorp filed with the FERC a fmal application for a new license to operate the 169.MW nameplate-rated
Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating
under an annual license issued by the FERC and expects to continue to operate under annual licenses until the new operating license is
issued. As part of the relicensing process, the United States Departments of Interior and Commerce filed proposed licensing terms and
conditions with the FERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at
the Klamath hydroelectric project's four mainstem dams. In April 2006 , PacifiCorp filed alternatives to the federal agencies' proposal
and requested an administrative hearing to challenge some of the federal agencies' factual assumptions supporting their proposal for
the construction of the fish passage facilities. A hearing was held in August 2006 before an administrative law judge. The
administrative law judge issued a ruling in September 2006 generally supporting the federal agencies' factual assumptions. In January
2007, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with March 2006 filings
and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to meet and implement the federal agencies' terms and
conditions as part of the project's relicensing. However, PacifiCorp will continue in settlement discussions with various parties in the
Klamath Basin area who have intervened with the FERC licensing proceeding to try to achieve a mutually acceptable outcome for the
project.
Also, as part of the relicensing process, the FERC is required to perform an environmental review. In September 2006, the FERC
issued its draft environmental impact statement on the Klamath hydroelectric project license. The public comment period on the draft
environmental impact statement closed on December 1 , 2006. The FERC is expected to issue its final environmental impact statement
in spring 2007, after which other federal agencies will complete their endangered species analyses. The states of Oregon and California
will need to issue water quality certifications prior to the FERC issuing a fmallicense.
In the relicensing of the Klamath project, PacifiCorp has incurred $42.1 million in costs at December 31 2006, which are reflected in
Construction work-in-progress in the accompanying Comparative Balance Sheet. While the costs of implementing new license
provisions cannot be determined until such time as a new license is issued, such costs could be material.
IFERC FORM NO.(ED. 12-88) Page 123,
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC Issues
California Refund Case
On April II, 2007, PacifiCorp executed a settlement and release of claims agreement ("Settlement") with Pacific Gas and Electric
Company, Southern California Edison Company, San Diego Gas & Electric Company, the People of the State of California, ex reI.
Edmund G. Brown Jr., Attorney General, the California Electricity Oversight Board, and the California Public Utilities Commission
(collectively, the "California Parties ), certain of which purchased energy in the California Independent System Operator ("ISO") and
the California Power Exchange ("PX") markets during past periods of high energy prices in 2000 and 200 I. The Settlement, filed with
FERC on April II, 2007, settles claims brought by the California Parties against PacifiCorp for refunds and remedies in numerous
related proceedings (together, the "FERC Proceedings ), as well as certain potential civil claims, arising from events and transactions
in Western United States energy markets during the period January 1 2000, through June 20, 2001 (the "Refund Period"). Under the
Settlement, PacifiCorp made a cash payment to escrows controlled by the California Parties in the amount of $16 million on April 30
2007, and upon FERC approval ofthe agreement, PacifiCorp will allow the PX to release an additional $12 million to such escrows
which represents PacifiCorp s estimated unpaid receivables from transactions in the PX and ISO markets during the Refund Period
plus interest. The monies held in the escrows will, upon FERC acceptance ofthe settlement, be distributed to buyers of power from the
ISO and PX markets during the Refund Period. Other buyers in the ISO and PX markets will be provided the option of joining in the
Settlement, in which case they will receive payments from one of the escrows. The agreement provides for the release of claims by the
California Parties (as well as additional parties that join in the Settlement) against PacifiCorp for refunds, disgorgement of profits, or
other monetary or non-monetary remedies in the FERC Proceedings, and provides a mutual release of claims for civil damages and
equitable relief. As PacifiCorp previously accrued for these items, the settlement did not materially impact PacifiCorp s financial
results.
Note 12 - Guarantees and Other Commitments
Guarantees
PacifiCorp is generally required to obtain state regulatory commission approval prior to guaranteeing debt or obligations of other
parties. The following represent the indemnification obligations ofPacifiCorp at
December 31 2006.
PacifiCorp has made certain commitments related to the decommissioning or reclamation of certain jointly owned facilities and mine
sites. The decommissioning guarantees require PacifiCorp to pay a proportionate share of the decommissioning costs based upon
percentage of ownership. The mine reclamation obligations require PacifiCorp to pay the mining entity a proportionate share of the
mine s reclamation costs based on the amount of coal purchased by PacifiCorp. In the event of default by any of the other joint
participants, PacifiCorp potentially may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate
share of the defaulting party's liability. PacifiCorp has recorded its estimated share of the decommissioning and reclamation
obligations.
In connection with the sale ofPacifiCorp s Montana service territory, PacifiCorp entered into a purchase and sale agreement with
Flathead Electric Cooperative in October 1998. Under the agreement, PacifiCorp agreed to indemnify Flathead Electric Cooperative
for losses, if any, occurring after the closing date and arising as a result of certain breaches of warranty or covenants. The
indemnification has a cap of$IO.I million until October 2008 and a cap of$5.1 million thereafter (less expended costs to date). Two
indemnity claims relating to environmental issues have been tendered, but remediation costs for these claims, if any, are not expected
to be material.
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 05/17/2007 2006/04 .
NOTES TO FINANCIAL STATEMENTS (Continued)
Unconditional Purchase Obligations
Paym:nts due during the 12 months endingDecerrber 31
(Millions of dollars)2007 2008 2009 2010 2011 Thereaftcr Total
Construction $ 312.24.4.1 341.7
Opcrating leases 14.8.4 20.528
Purchao;ed electricity 701.7 385.358.1 314.3 243.4 889.891.5
Tnmsnission 66.54.60.54.3 48.4824 7fij,5
Fuel 567.1 515.498.366.216.1 1,213.9 3;377.
Other 255.1 87.136.48.635.1,260.
T otallDlCorxiitional purclme obligitions 917.074.5 021.7 $ 875.$559.$ 4,241.1 690.
Construction
PacifiCorp has an ongoing construction program to meet increased electricity usage, customer growth and system reliability objectives.
At December 31 2006, PacifiCorp had estimated long-tenD unconditional purchase obligations for construction of the new natural gas
fueled Lake Side Power Plant.
Ooeratinl! leases
PacifiCorp leases offices, certain operating facilities, land and equipment under operating leases that expire at various dates through
the years ending December 31 , 2092. Certain leases contain renewal options for varying periods and escalation clauses for adjusting
rent to reflect changes in price indices. These leases generally require PacifiCorp to pay for insurance, taxes and maintenance
applicable to the leased property. Excluded trom the operating lease payments above are any power purchase agreements that meet the
definition of an operating lease.
Net rent expense, including that related to obligations accounted for as capital leases for balance sheet presentation, was $25.5 million
for the year ended December 31, 2006 and $29.4 million for the year ended December 31, 2005.
Minimum non-cancelable sublease rent payments expected to be received through the years ended December 31 , 2017 total $20.
million.
Purchased electricitv
As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-tenD purchases and/or exchange
agreements. Included in the purchased electricity payments above are any power purchase agreements that meet the defmition of an
operating lease.
Included in the minimum fixed annual payments for purchased electricity above are commitments to purchase electricity trom several
hydroelectric projects under long-tenD arrangements with public utility districts. These purchases are made on a "cost-of-service" basis
for a stated percentage of project output and for a like percentage of project operating expenses and debt service. These costs are
included in Energy costs in the Statement of Income. PacifiCorp is required to pay its portion of operating costs and its portion of the
debt service, whether or not any electricity is produced.
At December 31 , 2006, PacifiCorp s share of long-tenD arrangements with public utility districts was as follows:
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 Re!?ubmission 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(Millions of dollars)
Year Contract Nameplate Percentage
Generating Facility Expires (MW)of Output
W anapum 2009 194.18.
Rocky Reach 2011 67.
Pries t Rapids 2045 62.
Wells 2018 53.4
Total 377.4
Annual
Costs (a)
16.
(a)Includes debt service totaling $9.1 million.
PacifiCorp s minimum debt service and estimated operating obligations included in purchased electricity above for the years ending
December 31 are as follows:
Minimum Operating
(Millions of dollars) Debt Service Obli ations
2007 11.4
2008 11.3
2009 11.3
2010 5.3
2011 5.3
Thereafter 73.93.
117.130.
PacifiCorp has a 4.0% entitlement to the generation of the Intennountain Power Project, located in central Utah, through a power
purchase agreement. PacifiCorp and the City of Los Angeles have agreed that the City of Los Angeles will purchase capacity and
energy from PacifiCorp s 4.0% entitlement of the Intennountain Power Project at a price equivalent to 4.0% of the expenses and debt
service of the project.
Fuel
PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments.
Other
Unconditional purchase obligations, as derIDed by accounting standards, are those long-tenn commitments that are non-cancelable or
cancelable only under certain conditions. PacifiCorp has such commitments related to legal or contractual asset retirement obligations
environmental obligations, hydroelectric obligations, equipment maintenance and various other service and maintenance agreements.
Note 13 - Employee Benefit Plans
PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees and also provides healthcare and life
insurance benefits through various plans for eligible retirees. In addition, PacifiCorp sponsors an employee savings plan.
As a result of the sale of PacifiCorp to MEHC, plan participants that were employees or retirees of certain ScottishPower affiliates and
a fonner PacifiCorp mining subsidiary ceased to participate in PacifiCorp s plans. This separation resulted in a net $3.5 million
reduction in Common shareholder s equity during the year ended December 31 , 2006.
Pension and Other Postretirement Plans
PacifiCorp s pension plans include the Retirement Plan (the "Retirement Plan ), the Supplemental Executive Retirement Plan (the
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 Resubmisslon 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
SERP") and joint trust plans to which PacifiCorp contributes on behalf of certain bargaining units. Benefits under the Retirement Plan
are based on the employee s years of service and average monthly pay in the 60 consecutive months of highest payout of the last 120
months, with adjustments to reflect benefits estimated to be received from social security. Pension costs are funded annually by no
more than the maximum amount that can be deducted for federal income tax purposes.
In December 2006, non-bargaining employees were notified that PacifiCorp is switching from a traditional frnal average pay fonnula
for the Retirement Plan to a cash balance fonnula effective June 1 2007. Benefits under the frnal average pay fonnula will be frozen as
of May 31 2007, with no further benefit accrual under that fonnula. All future benefits will be earned under the cash balance fonnula.
The changes are expected to result in a significant reduction in Pension and other post employment liabilities and Regulatory assets.
The cost of other postretirement benefits, including healthcare and life insurance benefits for eligible retirees, is accrued over the active
service period of employees. PacifiCorp funds other postretirement benefits through a combination of funding vehicles. PacifiCorp
also contributes to joint trust plans for postretirement benefits offered to certain bargaining units.
During May 2006, the PacifiCorp board of directors elected to change its fiscal year end from March 31 to December 31. As plan
assets and obligations are measured three months prior to PacifiCorp s fiscal year end, plan assets were measured as of September 30
in the current year and as of December 31 in the prior periods. The following disclosures were generally taken directly from
PacifiCorp s Fonn lO-K filed with the SEC in March 2007 and thus disclose activity between the above-mentioned measurement
dates.
Net periodic benefit cost for the pension and other postretirement plans included the following components:
Pension Other Postretirement
Nine Months Nine Months
Ended Ended
Decem ber 31 Years Ended March 31 December 31 Years Ended March 3 I
(Millions of dollars)2006 2006 2005 2006 2006 2005
Service cost (a)22.30.25.
Interest cost 56,4 74.73.24.30,4 31.0
Ex pected return on plan assets (b)(54.(76.(77.(19.(26.(26.
Amortization of unrecognized
net transition obligation 8.4 8,4 12,12.
Amortization of unrecognized
prIor service cost 1.2 1.4
Amortization of unrecognized loss 19,21.5
Cost of termination benefits 1.8
Curtailment loss
Net periodic benefit cost (c)49.62.40.27.29.26.
(a)
(c)
Service cost excludes $6.4 million of contributions to the joint trust plans for the nine months ended
December 31 , 2006 and $1.4 million for the year ended March 31, 2006. There were no contributions to
the joint trust plans for the year ended March 31 2005.
The market-related value of plan assets, among other factors, is used to detennine expected return on plan
assets. The market-related value of plan assets is calculated by spreading the difference between expected
and actual investment returns over a five-year period beginning in the fIrst year in which they occur. As
differences between expected and actual investment returns are recognized, they are included in the
Amortization of unrecognized loss component of Net periodic benefit cost.
Net periodic benefit cost for the three months ended March 31, 2006 was $16.8 million for the pension
plans and $7.5 million for the other postretirement plans, resulting in total net periodic benefit cost for the
year ended December 31 , 2006 of $66.7 million for the pension plans and $35.0 million for the other
postretirement plans.
(b)
IFERC FORM NO.(ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table is a reconciliation of the fair value of plan assets as of the end of the period:
Pension Other Postretirement
December 31 March 31 December 31 March 31
(Millions of ebBars)2006 2006 2006 2006
Plan asrets at fair value at beginning of period 824.806.292,286.
Employer contributions 79.3 63.29.22.
Participant contributions 8.3
Actual retlDl1 on plan =ts 55.72.18.20.
Benefits paid (75.(84.1)(29.4)(41.6)
Separation offonner part icipants (32.(4.1)
Transfern (1.9)
Plan 3S!ets at fair value at end of period 883.824.318.4 292.1
The SERP has no plan assets, and accordingly, the fair value of the plan assets was zero as of December 31, 2006 and March 31, 2006.
Although the SERP had no assets, PacifiCorp has a Rabbi trust that holds corporate-owned life insurance and other investments to
provide funding for the future cash requirements of the SERP. Although the SERP liabilities are included in the table below, because
this plan is nonqualified, the assets in the Rabbi trust are not considered plan assets. The cash sun-ender value of all of the policies
included in the Rabbi trust, net of amounts bon-owed against the cash sun-ender value, plus the fair market value of other Rabbi trust
investments, was $38.6 million at December 31 2006 and $36.4 million at March 31 2006.
The following table is a reconciliation of the benefit obligation at the end of the period:
Pension Other Postretirement
December 31 March 31 December 31 March 31,
(Millions of ebBars)2006 2006 2006 2006
Benefit obli~tion, beginning of period 342.338.1 582.4 528.3
Service cost 22.30.
Intere!t cost 56.74.4 24,30.4
Participant contributions
Plan amendments 22.
Actuarial (g;iin) loss (14.4)22.(24.34.3
Benefits paid (75.(84.1)(29.4)(41.6)
Cost oftennination benefits 1.8
Separation of fanner participants (44.3)(8.
Transfers (1.5)
Benefit obli~tion, end of period 332.342.566.582.
Accumulated benefit obli~tion asofthemeasurement date 164.170.
The portion of the pension plans' projected benefit obligation , included in the table above, related to the SERP was $53.5 million at
December 31 , 2006 and $52.3 million at March 31 , 2006. The SERP's accumulated benefit obligation totaled $53.2 million at
December 31 , 2006 and $50.5 million at March 31 , 2006.
As of December 31 , 2006 the funded status of the pension and other postretirement plans was recorded in the Comparative Balance
Sheet as required under the adoption of SF AS No. 158. Balance sheet amounts recorded as of March 31, 2006 did not include the
unrecognized net actuarial losses, prior service costs and net transition obligations of $452.9 million for the pension plans and $241.3
million for the other postretirement plans. However, an additional minimum pension liability of $281.6 million was recorded for the
pension plans as of March 31 , 2006. The combined funded status of the plans and the net liability recognized in the accompanying
Comparative Balance Sheet is as follows:
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 05/17.12001 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Pension Other Postretirement
Decem ber 3 I,March 31 Decem ber 3 I March 31
(Millions of dollars)2006 2006 2006 2006
Plan assets at fair value, end of period 883.824,318.292.
Less - Benefit obligation, end of period 332.342.566.582.4
Funded status (449.(517.(247.(290.
Un recogn ized act uarial 10 sses and ot her 452.241.3
Contribution made after measurement date but before year-end 27.3 29.
Net liability recognized in the Consolidated Balance Sheets (449.(60,(220.(19.
Net amounts recognized in the Consolidated Balance Sheets consist of:
Regulatory assets 257.
Deferred charges and other assets:
Intangible assets 17.
Other current liabilities (4.
Pension and other post employment liabilities (445.(342.(220.(19.
Accumulated other comprehensive loss, pre-tax
Net liability recognized in the Consolidated Balance Sheets (449.(60,(220.(19,
Amounts not yet recognized as components of net periodic benefit cost:
Net losses 400, I 435.109.
Prior service cost 10.19.
Net transition obligation 72.
Total 413.452.201.3
SF AS No. 158 amounts have been recorded as fo Hows
based upon expected recovery in rates:
Regulatory assets 404.161.
Deferred income taxes 39.
Accumulated other comprehensive loss, before tax 0.5
Total 413.201.
138.
22.
81.1
241.
As of March 31, 2006, the net liability recognized for the pension plans was comprised of accrued pension cost of$60.7 million and an
additional minimum pension liability of $281.6 million, which resulted in a total accrued benefit liability of $342.3 million for the
pension plans. The table above reconciles the total accrued benefit liability to the accrued pension cost as of March 31 , 2006 by
presenting the offsetting effects of the additional minimum pension liability in Regulatory assets, Intangible assets and Accumulated
other comprehensive loss.
The net loss, prior service cost and net transition obligation that will be amortized from the above amounts in 2007 into net periodic
benefit cost are estimated to be as follows:
Net P nor Service Net Transition
(Millions of dollars)Lo sses Cost Obligation Total
Pension benefits 27,1.1 30.
Other postretirement benefits 12,19,
Total 31.6 14.50.
Plan Assumptions
Assumptions used to detennine benefit obligations and net benefit cost were as follows:
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 05/17/2007 2006lQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Nine Months
Ended
December 31
2006
Years Ended March 3 I2006 2005
Other Postretirement
Nine Months
Ended
December 31
2006
Years Ended March 31,2006 2005
Pension
Benefit obligation as of the measurement date:Discount rate 5.85 %
Rate of compensation increase 4.
Net benefit cost forthe period ended:
Discoun t rate
Expected return on plan assets
Rate of compensation increase
75 %
8.50
75 %25 %
N/A N/A N/A
N/A N/A N/A
Assumed health care cost
75 %75 %
trend rates as of the measurement date:
Nine Months
Ended
Decem ber 3 I ,
2006
Years Ended March 312006 2005
Health care cost trend rate assumed for next year - under 65
Health care cost trend rate assumed for next year - over 65
Rate that the cost trend rate gradually declines to
Year that rate reaches the rate it is assumed to remain at - under 65
Year that rate reaches the rate it is assumed to remain at - over 65
10,0 %
2012
2010
10.0 %
10.
2011
2011
5 %
2007
2009
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point
change in assumed health care cost trend rates would have the following effects:
(Millions of dollars)
Increase (Decrease) in Expense
One Percentage-Point One Percentage-PointIncrease Decrease
Effect on total service and interest cost
E ffee t on oth er p ostretirernen t benefit obliga tion 42,
(1.
(34.4)
Contributions and Benefit Payments
PacifiCorp expects to contribute approximately $88.0 million to the pension plans and $33.7 million to the other postretirement plan
for 2007.
PacifiCorp s expected benefit payments to participants for its pension and other postretirement plans for 2007 through 2011 and for the
five years thereafter are summarized below:
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 Resubmlssion 05/1712007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(M ill ion s of dollars)
Years endin g Decem ber 31 ,Pension
Projected Benefit Payments
Other PostretirementGross Medicare Subsidy Net of Subsidy
2007
2008
2009
2010
2011
2012 to 2016 (inclusive)
89.
90.
94.
98.
103.
568.
40.
42.
43.
45.
47.
261.
36.
38.3
39.
41.0
42.
231.430,
Investment Policy and Asset Allocation
Retirement Plan and other postretirement plan assets are managed and invested in accordance with all applicable requirements
including the Employee Retirement Income Security Act and the Internal Revenue Code. PacifiCorp employs an investment approach
that primarily uses a mix of equities and fIXed-income investments to maximize the long-term return of plan assets at a prudent level of
risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, and corporate financial condition. The
investment portfolio contains a diversified blend of primarily equity, fIXed-income and other alternative investments as shown in the
table below. Equity investments are diversified across United States and non-United States stocks, as well as growth and value
companies, and small and large market capitalizations. Fixed-income investments are diversified across United States and non-United
States bonds. Other assets, such as private equity investments, are used to enhance long-term returns while improving portfolio
diversification. PacifiCorp primarily minimizes the risk of large losses through diversification but also monitors and manages other
aspects of risk through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies.
The assets for other postretirement benefits are composed of three different trust accounts. The 401(h) account is invested in the same
manner as the pension account. Each of the two Voluntary Employees' Beneficiaries Association Trusts has its own investment
allocation strategies.
PacifiCorp s asset allocation was as follows:
Pension & Other Postretirement
December 31 March 31,2006 2006 Target
Voluntary Employees
Beneficiaries Association Trust
Decem ber 31 March 31,2006 2006 Target
Equity securities
Debt securities
Other
58.0 %
34.
7.4
58,5 % i3.0 - 57.0 %
34.5 35.0 8.12.
65.3 %
34.
N/A
66.0 % 53.0 - 65.0 %
34.0 35.
N/A 0 - 12.
Defined Contribution Plan
PacifiCorp s employee savings plan qualifies as a tax-deferred arrangement under the Internal Revenue Code. Participating employees
may defer up to 50.0% of their compensation, subject to certain statutory limitations, and can select a variety of investment options.
PacifiCorp matches 50.0% of employee contributions on amounts deferred up to 6.0% of total compensation, with the company match
vesting over the initial five years of an employee s qualifying service. Thereafter, PacifiCorp s contributions vest immediately.
PacifiCorp may also make an additional contribution equal to a percentage of the employee s eligible earnings, which are immediately
vested. PacifiCorp s contributions to the Savings Plan were $21.1 million for the year ended December 31 , 2006 and $21.5 million for
the year ended December 31 , 2005.
In December 2006, PacifiCorp communicated to its non-bargaining employees that effective June 1 , 2007, PacifiCorp will match
65.0% of employee contributions on amounts deferred up to 6.0% of total compensation.
IFERC FORM NO.(ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007.2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Severance
PacifiCorp has undertaken a review of its organization and workforce. As a result of the review, PacifiCorp incurred severance
expense of$42.8 million during the year ended December 31 2006 compared to $5.1 million during the year ended December 31
2005.
Note 14 - Fair Value of Financial Instruments
The carrying amount of cash and cash equivalents, receivables, payables, accrued liabilities and short-tenn borrowings approximates
fair value because of the short-tenn maturity of these instruments. In addition, the carrying amount of variable-rate long-tenn debt
approximates fair value because of the fTequent repricing of these instruments at market rates.
The fair value ofPacifiCorp s fixed-rate long-tenn debt, current maturities oflong-tenn debt and redeemable preferred stock has been
estimated by discounting projected future cash flows, using the current rate at which similar loans would be made to borrowers with
similar credit ratings and for the same maturities.
The following table presents the carrying amount and estimated fair value of the named fmancial instruments as of December 31 , 2006:
Carrying Fair
(M iIlions of dollars)Amount Value
Long-term debt (a)$ 4 043.$ 4 243.
Preferred stock subject to
mandatory redemption 37.37.
(a)Includes long-tenn debt classified as currently maturing, less capital lease obligations.
Note 15 - Related-Party Transactions
Transactions while owned by MEHC
As discussed in Note 1, PacifiCorp was acquired by a subsidiary ofMERC on March 21 , 2006. The following describes PacifiCorp
transactions and balances with unconsolidated related parties while owned by MERC.
As a result of a settlement agreement between MERC, the Utah Committee of Consumer Services and Utah Industrial Energy
Consumers, MERC contributed to PacifiCorp, at no cost, MERC's indirect 100.0% ownership interest in Intennountain Geothennal
Company, which controlled 69.3% of the steam rights associated with the geothennal field serving PacifiCorp s Blundell Geothennal
Plant in Utah. Intennountain Geothennal Company therefore became a wholly owned subsidiary ofPacifiCorp in March 2006
subsequent to the sale of PacifiCorp to MERC. During the year ended December 31, 2006, PacifiCorp acquired an additional 25.2% of
the steam rights associated with the geothennal field.
In the ordinary course of business, PacifiCorp engages in various transactions with several of its affiliated companies. Services
provided by PacifiCorp and charged to affiliates related primarily to the administrative services, fmancial statement preparation and
direct-assigned employees. These receivables were $0.6 million at December 31 2006. Services provided by affiliates and charged to
PacifiCorp related primarily to the transport of natural gas with Kern River Gas Transmission Company and administrative services
provided under the intercompany administrative services agreement among MERC and its affiliates. These payables were $0.7 million
at December 31, 2006. These expenses totaled $7.8 million for the year ended December 31 , 2006.
Effective March 21 , 2006, PacifiCorp began participating in a captive insurance program provided by MERC Insurance Services Ltd.
MISL"), a wholly owned subsidiary ofMERc. MISL covers all or significant portions of the property damage and liability insurance
deductibles in many ofPacifiCorp s current policies, as well as overhead distribution and transmission line property damage.
PacifiCorp has no equity interest in MISL and has no obligation to contribute equity or loan funds to MISL. Premium amounts are
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 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
established based on a combination of actuarial assessments and market rates to cover loss claims, administrative expenses and
appropriate reserves, but as a result of regulatory commitments are capped through December 31 , 2010. Certain costs associated with
the program are prepaid and amortized over the policy coverage period expiring March 20, 2007. Prepayments to MISL were $1.
million at December 31 , 2006. Receivables for claims were $8.2 million at December 31 2006. Premium expenses were $5.7 million
for the year ended December 31 2006.
As of December 31 , 2006, Prepayments included $43.5 million of income taxes receivable.
Transactions with Unconsolidated Subsidiaries of PacifiCorp
In the ordinary course of business, PacifiCorp engages in various transactions with its unconsolidated subsidiaries. Services provided
by PacifiCorp and charged to its subsidiaries related primarily to management services, income taxes and labor. These receivables
were $1.2 million at December 31 , 2006 and $0.8 million at December 31, 2005. Services provided by subsidiaries and charged to
PacifiCorp primarily related to coal purchases. These payables were $8.9 million at December 31, 2006 and $7.3 million at December
2005. Expense for these coal purchases were $94.2 million for the year ended December 31 , 2006 and $70.0 million for the year
ended December 31 , 2005.
PacifiCorp is party to an umbrella loan agreement with one of its unconsolidated subsidiaries. Regulatory authorizations permit
PacifiCorp to borrow ITom its subsidiaries (including those that are consolidated) without limitation and to loan each of these
subsidiaries up to $30.0 million at anyone time, provided that the borrowings bear interest at rates that do not exceed the interest rates
that PacifiCorp would otherwise incur externally. As of December 31 , 2006, affiliated notes receivable with unconsolidated
subsidiaries were $22.9 million, including interest. As of December 31 , 2005, affiliated notes payable with unconsolidated subsidiaries
were $1.6 million, including interest.
Transactions while owned by ScottishPower
Under ScottishPower ownership, PacifiCorp engaged in various transactions with several of its former affiliated companies pursuant to
ScottishPower s affiliated interest cross-charge policy. Services provided by PacifiCorp and charged to affiliates related primarily to
administrative services provided to ScottishPower UK pIc ("SPUK") and costs associated with retention agreements and severance
benefits reimbursable by SPUK. In addition, PacifiCorp recharged to SPUK costs and related benefits ofPacifiCorp employees
working on international assignment in the United Kingdom and recharged support services to PHI and its subsidiaries. These
receivables were $2.1 million at December 31 , 2005. Amounts allocated to PacifiCorp by SPUK were primarily for administrative
services received under the cross-charge policy and payroll costs and related benefits of SPUK employees working on international
assignments with PacifiCorp in the United States. These liabilities were $2.3 million at December 31 2005.
As of December 31 2005, Taxes accrued included $6.3 million of taxes payable to PHI. PHI was the tax paying entity for PacifiCorp
while owned by ScottishPower.
In May 2005, PacifiCorp began participating in a captive insurance program provided by Dornoch International Insurance Limited
DIlL"), an indirect wholly owned consolidated subsidiary of Scottish Power. DIlL covered all or significant portions of the property
damage and liability insurance deductibles in many ofPacifiCorp s current policies, as well as overhead distribution and transmission
line property damage. PacifiCorp had no equity interest in DIlL and had no obligation to contribute equity or loan funds to DIlL.
Premium amounts were established to cover loss claims, administrative expenses and appropriate reserves, but otherwise DIlL was not
operated to generate profits. Certain costs associated with the captive insurance program were prepaid. Prepayments to DIlL were $1.8
million at December 31 2005. Premium expenses were $5.4 million for the year ended December 31 2005.
Revenues ITom these former affiliates related primarily to wheeling services and totaled $1.9 million for the year ended December 31
2006 and $6.4 million for the year ended December 31, 2005. Expenses recharged by PacifiCorp to these former affiliates under the
affiliated interest cross-charge policy totaled $2.0 million for the year ended December 31 , 2006 and $15.5 million for the year ended
December 31, 2005. Service provided by these former affiliates and charged to PacifiCorp under the affiliated interest cross-charge
policy totaled $9.5 million for the year ended December 31 2006 and $35.6 million for the year ended December 31 2005.
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 05/17/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 16 - Jointly Owned Utility Plants
Under joint plant ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly
owned generation and transmission plants. PacifiCorp accounts for its proportional share of each plant.
Each participant has provided fmancing for its share of each unit. Operating costs of each plant are assigned to joint owners based on
ownership percentage or energy taken, depending on the nature of the cost. Operating expenses on the accompanying Statement of
Income include PacifiCorp s share of the expenses of these units.
As of December 31, 2006, PacifiCorp s share in jointly owned plants was as follows:
Plant Accumulated Construction
PacifiCorp Depreciation/Work-in-
(Millions of dollars) Share Service Amortization Progress
Jim Bridger Nos. 1 - 4 (a)66.941.8 459.10.
W yodak 80.337.167.5
HunterNo.93.305.141.9
Colstrip Nos. 3 and 4 (a)10.241.2 114.3 1.1
HunterNo.60.3 193.84.
Henniston (b)50.168.3 36.3
Craig Nos. 1 and 2 19.3 166.73.
Hayden No.24.5 42.18.
Foote Creek 78.36.11.5 0.1
Hayden No.12.26.12.
Other transmission and distribution plants Various 79.18.0.4
Total $ 2 538.5 138.15.
(a)Includes transmission lines and substations.
(b)Additionally, PacifiCorp has contracted to purchase the remaining 50.0% of the output of the Hermiston
Plant.
Under the joint ownership agreements, each participating utility is responsible for fmancing its share of construction, operating and
leasing costs. PacifiCorp s portion is recorded in its applicable construction work-in-progress, operations, maintenance and tax.
accounts, which is consistent with wholly owned plants.
Note 17 - Supplemental Cash Flow Information
A summary of supplemental cash flow information is presented in the following table:
(Millions ofdollars)
Cash paid during the year for:
Income taxes
Interest, net of amounts capitalized
Years Ended December 312006 2005
178.4
244.
86.
236.
Note 18 - Subsequent Events
On March 14 2007, PacifiCorp sold an aggregate principal amount of$600.0 million of its 5.75% First Mortgage Bonds due April 1
2037. PacifiCorp intends to use the net proceeds to repay short-term debt and for general corporate purposes.
IFERC FORM NO.1 (ED. 12-88)Page 123,
Name of Respondent This ~ort Is: Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr) End of 2006/Q4PacifiCorp (2) A Resubmission 05/17/2007
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
No.
Item
(a) .
1 Balance of Account 219 at Beginning of
Preceding Year
2 Preceding QtrlYr to Date Reclassifications
from Acct 219 to Net Income
3 Preceding QuarterlYear to Date Changes in
Fair Value
4 Total (lines 2 and 3)
5 Balance of Account 219 at End of
Preceding QuarterlYear
6 Balance of Account 219 at Beginning of
Current Year
7 Current QtrlYr to Date Reclassifications
from Acct 219 to Net Income
8 Current QuarterlYear to Date Changes in
Fair Value
9 Total (lines 7 and 8)
10 Balance of Account 219 at End of Current
QuarterlYear
FERC FORM NO.1 (NEW 06..Q2)
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Minimum Pension
Liability adjustment
(net amount)
(c)
Foreign Currency
Hedges
Other
Adjustments
(d)(e)
516 998 159)
914,447
914 447
992,768)
992 768)
922 963 990 927)
1,416 499)
503 402
913,097)
990,927
990,927
939 253)
939 253)
Page 122a
Name of Respondent This ~ort Is: Date of Report Year/Period of Report(1) ~An Original (Mo, Da, Yr) End of 2006/04PacifiCorp (2) A Resubmission 05/17/2007
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND 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)
( 7 989,643)
(f)
(g)
78,321)
321)
067 964)
067,964)
416,499)
602,328
185 829
882 135)
047 252
047 252
FERC FORM NO.1 (NEW 06-02)Page 122b
Net Income (Carried
Forward from
Page 117, Line 78)
Total
Comprehensive
Income
(i)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 .2006/04
FOOTNOTE DATA
~hedule Page: 12~1f!?1 , Line No.Column:- b
Unrealized gain on available-for-sale securities of$I 487 476 less tax of$564 513 netting to $922 963.
ISchedule Page: 122(a)(b) Line No.Column:
inimum pension liability adjustment of ($14 489 872) less tax of $5 498 945 netting to ($8 990 927).
~chedule Page: 122(a)(b) Line No.10 Column: b
Unrealized gain on available-for-sale securities of$15 900 less tax of $6 034 netting to $9 866.
~chedule Page: 122(a)(b) Line No.10 Column:
SF AS No. 158 - Defined Benefit Pension and Other Postretirement Plans adjustment of ($9 571 706) less tax of $3 632 453 netting to
($5 939,253).
ISchedule Page: 122(a)(b) Line No.10 Column: g
Unrealized gain on cash flow hedges of $3 299 410 less tax of$I 250 158 netting to $2 047 252.
--.J
For a further discussion on cash flow hedging, refer to Page 122 Notes to the Financial Statements Note 8 - Risk Management of this
Fonn No. 1.
IFERC FORM NO.1 (ED. 12-87)Page 450,
Blank Page
(Next Page is: 200)
End of
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (f) common function.
(a)
Total Company for the
Current Year/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 (18thru 21)
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others (24 & 25)
27 Held for Future Use
15,284,762,208 284,762 208
49,253,139 49,253,139
340,315 32,340,315
15,366,355,662 15,366,355,662
361,997 361 997
734,457,063 734,457,063
157,193,780 157,193,780
261 ,368,502 16,261 368,502
6,408,699,464 6,408,699,464
852,669,038 852,669,038
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,32)
79,888,814
6,408,699,464
79,888,814
6,408,699,464
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 05/17/2007
SUMMARY OF UTILITY PLANT AND ACCUMU TED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Specify) Other (Specify) Other (Specify)
Year/Period of Report
End of 2006/04
Name of Respondent
PacifiCorp
Common
(d)(e)
(g)
(h)
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 (2)A Re!;iubmission 05/17/2007 2006/04
FOOTNOTE DATA
!Schedule Page: 200 Line No.
Depreciation is comprised of:
Depreciation
Depletion
Column:
902 280 246
290 236
Total 945 570 482
IFERC FORM NO.1 (ED. 12-87) Page 450.
Blank Page
(Next Page is: 204)
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04
(2) EJA Resubmission 05/17/2007
ELECTRI(PLANT IN SERVICE (Account 101 102 103 and 106)
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101 , Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account
103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Ukewise, 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)
Une Account
No.Beginning of Year
(a)(b) (c)
1. INTANGIBLE PLANT
(301) Organization 16,787 669
(302) Franchises and Consents 117,555 186 712,577
(303) Miscellaneous Intangible Plant 537 849,411 32,878,783
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)672 192 266 33,591 ,360
2. PRODUCTION PLANT
A. Steam Production Plant
(310) Land and Land Rights 81,496,795 869,528
9 (311) Structures and Improvements 770,111,431 10,363,231
(312) Boiler Plant Equipment 553,758,822 252,557,209
(313) Engines and Engine-Driven Generators
(314) Turbogenerator Units 712,601 048 38,825,333
(315) Accessory Electric Equipment 329,362 786 683,232
(316) Misc. Power Plant Equipment 25,059,970 317 935
(317) Asset Retirement Costs for Steam Production 29,462 296 1,420 377
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)501 853,148 322,036,845
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 681 130
(331) Structures and Improvements 011 168 775,347
(332) Reservoirs, Dams, and Waterways 280,231 813 546,757
(333) Water Wheels, Turbines, and Generators 86,077 183 719,600
(334) Accessory Electric Equipment 40,431,916 768,921
(335) Misc. Power Plant Equipment 189,506 907
(336) Roads, Railroads, and Bridges 13,230,084 328,328
(337) Asset Retirement Costs for Hydraulic Production 531 361 936,050
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)528,384 161 15,071,096
D. Other Production Plant
(340) Land and Land Rights 21,502 064 40,126
(341) Structures and Improvements 660,586 424,117
(342) Fuel Holders, Products
, ,
and Accessories 738 839 23,695 238
(343) Prime Movers 262 722 609 293,496,468
(344) Generators 83,479,920 383,034
(345) Accessory Electric Equipment 34,080,559 63,139
(346) Misc. Power Plant Equipment 640 805
(347) Asset Retirement Costs for Other Production 755,214 293,561
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)456 580,596 360,395,683
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)486,817 905 697,503,624
FERC FORM NO.1 (REV. 12-05)Page 204
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 05/17/2007
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 (I) 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 of
Une
End ~f Year No.ro
16,787,669
118,267 763
732,417 384,249 559,380,026
28,520,086 384,249 677,647,789
760 155,907 91,208,656
1 ,362,407 85,412 779,197,667
757,743 328,279 781 886 567
205,291 832 833 738 388 257
391 ,296 087,477 332 567 245
70,938 23,182 28,330,149
30,882,673
38,789,435 639,344 782,461,214
548 83,864 596,718
106,914 757 293 82,436,894
548,987 150,023 286,079,560
855,218 82,907 88,024,472
406,984 803,241 597 094
134 597 791 578,674
103 131,545 13,657 854
467,411
959,888 943,308 540,438,677
21,542,190
011 500,918 582 610
25,138 29,408,939
475,240 813,935 545,929 902
535,937 10,390 125,337,407
333 100,365
000 720,805
048,775
057,521 247,765 810,670,993
48,806,844 943 801 133,570 884
FERC FORM NO.1 (REV. 12-05)Page 205
Name of Respondent This R
l!Jort Is:
Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04
(2) EjA Resubmission 05/17/2007
ELECTRIC PLA ~T IN SERVICE (Account 101, 102, 103 and 106) (Continued)
I ...10 e Account
No.Beginning of Year
(a)(b) (c)
3. TRANSMISSION PLANT
(350) Land and Land Rights 88,432,329 660,595
(352) Structures and Improvements 256,626 1 ,293,978
(353) Station Equipment 900,197 240 842 324
(354) Towers and Fixtures 372 507,097 596,975
(355) Poles and Fixtures 504,706,180 259,303
(356) Overhead Conductors and Devices 643,527 588 19,856,676
(357) Underground Conduit 369,500 907,688
(358) Underground Conductors and Devices 944 256 765,681
(359) Roads and Trails 11,376,682 117 840
(359.1) Asset Retirement Costs for Transmission Plant
TOTAL Transmission Plant (Enter Total of lines 48 thru 57)578,317,498 121 301,060
4. DISTRIBUTION PLANT
(360) Land and Land Rights 36,656,799 029,208
(361) Structures and Improvements 40,844,880 261 223
(362) Station Equipment 630,494,507 26,970,489
(363) Storage Battery Equipment 285,571 54,286
(364) Poles, Towers, and Fixtures 774 914,028 369,193
(365) Overhead Conductors and Devices 577,399,999 15,750,461
66 . (366) Underground Conduit 247 157,475 499,179
(367) Underground Conductors and Devices 581,320,885 631,610
(368) Line Transformers 882 647,097 48,365,397
(369) Services 421 954,840 42,793,938
(370) Meters 187,239,341 257,950
(371) Installations on Customer Premises 927 034 857
(372) Leased Property on Customer Premises 49,658
(373) Street Liahtina and Signal Svstems 55,449,346 269,247
(374) Asset Retirement Costs for Distribution Plant 225,168
TOTAL Distribution Plant (Enter Total of lines 60thru 74)446,341,460 238 519,206
5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
(380) Land and Land Rights
(381) Structures and Improvements
(382) Computer Hardware
(383) Computer Software
(384) Communication Equipment
(385) Miscellaneous Regional Transmission and Market Operation Plant
(386) Asset Retirement Costs for Regional Transmission and Market Oper
TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
6. GENERAL PLANT
(389) Land and Land Rights 15,003,144 187,929
(390) Structures and Improvements 220,743,339 334 433
(391) Office Fumiture and Equipment 118,744 458 422,532
(392) Transportation Equipment 86,849,740 15,451 912
(393) Stores Equipment 13,608,770 053,957
(394) Tools, Shop and Garage Equipment 60,329,825 3,462,210
(395) Laboratory Equipment 37,200,813 245,034
(396) Power Operated Equipment 114 707 566 14,161 346
(397) Communication Equipment 236,321,233 13,722,022
(398) Miscellaneous Equipment 773 191 313,351
SUBTOTAL (Enter Total of lines 86 thru 95)909,282,079 69,354 726
(399) Other Tangible Property
~.' ,,',.
m'
(399.1) Asset Retirement Costs for General Plant 42,454
TOTAL General Plant (Enter Total of lines 96, 97 and 98)152 127,599 81,459,679
100 TOTAL (Accounts 101 and 106)14,335,796 728 172,374,929
101 (102) Electric Plant Purchased (See Instr. 8)
102 (Less) (102) Electric Plant Sold (See Instr. 8)
103 (103) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)335 796,728 172 248,755
FERC FORM NO.1 (REV. 12-05)Page 206
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04
(2) (JA Resubmission 05/17/2007
ELECTRIC PLANT IN SERVICE (Account 101 , 102, 103 and 106) (Continued)
Line
End ~f Year No.
38,929 614 953 439 042
127 352 836,982 55,260,234
327 630 377,373 963,334,561
522 837 797 068 381 378,303
951,400 011,100 511 002 983
144,474 137,331 663 377 121
277,188
435 279 274,658
11 ,494 522
547,901 232,045 688 838,612
063 -41,600 44,640,344
180,418 156,912 082,597
794 630 386,754 647 283,612
117,947 1,457 804
567 105 239,888 809,956 004
836,232 268,485 590,582,713
014 257 380 257 642 017
299,006 085 611,654,574
060,625 16,079 922,967 948
978,065 463,770,713
081 005 189,416,286
99,636 869,255
49,658
687 914 57,030,679
225,168
34,602,956 371 662 652,629 372
160 770 15,030,303
712 606 368,180 224 733,346
19,442 275 402 178 104,322,537
643,286 16,577 96,674,943
525,244 627 13,140,110
138,384 110,064 763,715
108,487 230,126 567,486
9,472,008 781,602 122 178,506
15,899,310 029,879 232,114 066
727 515 28,305 387 332
68,669,115 944,654 911 912,344
";rtl
-. ~, ';;". ,....
42,454
68,530 652 640,760 164,415,866
190 008,439 060,695 317 102,523 100
101
126 174 102
103
189,882 265 060,695 15,317 102 523 104
FERC FORM NO.1 (REV. 12-05)Page 207
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 05/17/2007 2006/04
FOOTNOTE DATA
~chedule Page: 204 Line No.Column: b
Balance at Balance at
Beginning End of
Account Description of Year Additions Retirements Transfers Year
(a)(b)(c)(d)(e)(f)
(g)
39921 LAND OWNED IN FEE 634 916 634 916
39922 LAND RIGHTS 452 647 600 472 247
39930 STRUCTURES 275 271 328 (20 372)328 227
39941 SURFACE - PLANT EQUIPMENT 639,1 75 155 183 794 358
39944 SURF ACE - ELECTRIC POWER FACILITIES 566,476 181,747 (566 476)181 747
39945 UNDERGROUND - COAL MINE EQUIPMENT 786 437 469 139 154 558)(742 791)358 227
39946 LONGW ALL SHIELDS 678 600 962 699 562
39947 LONGW ALL EQUIPMENT 762 131 931 (63 460)786 602
39948 MAINLINE EXTENSION 584 135 385 029 (427 150)711 643 253 657
39949 SECTION EXTENSION 828 109 462 358 3,290,467
39951 VEHICLES 037 811 656 (59 999)683 098,151
39952 HEAVY CONSTRUCTION EQUIPMENT 510 169 001 043 024 690)486 584
39960 MISCELLANEOUS GENERAL EQUIPMENT 082 025 162 200 (137 041)217 114 401
39961 COMPUTERS - NUUNFRAME 578 123 341 600 464
39970 MINE DEVELOPMENT AND ROAD EXTENSTION 429,495 270 775 700 270
399915 Coal Mine ARO 661 188 661 188
TOTAL PLANT USED IN MINING ACTIVITIES $242 845 520 $12 062 499 $138 463 $ (2 585 414)$252,461 068
~chedule Page: 204 Line No.97 Column:
ee footnote line 97, column b.
~chedule Page: 204 Line No.97 Column: d
See footnote line 97, column b.
~chedule Page: 204 Line No.97 Column:
See footnote line 97, column b.
~chedule Page: 204 Line No.97 Column: g
See footnote line 97, column b.
~chedule Page: 204 Line No.: 102 ~olumn:
In July 2006, PacifiCorp completed the sale of a three-mile 230-kV transmission line and related facilities, associated easements and
right-of-way located near Centralia, Washington to TransAlta Centralia Generation LLC, with proceeds totaling $117 024. The FERC
authorized the sale of the facilities in Docket No. EC06-59-000. Approval to clear account 102 was approved in Docket AC07-35-000
on December 14 2006.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 214)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 05/17/2007
EL CTRIC PLANT HELD FOR FUTURE USE (Account 105)
1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held
for future use.
2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line uescnptlon and Location I Date On~mally IncluDed I Date Expected to De used Balance at
No.Of pro
ferty
in T is Account in Utility Service End of Year(b) (c)(d)
1 Land and Rights:
3 Oquirrh Substation 2005
' .
245,898
4 North Horn Mountain Coal Properties 1977 953,014
9 Miscellaneous, each under $250 000 163,085
Other Property:
Miscellaneous, each under $250,000:
Total 361 997
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
(~)
A Resubmission 05/17/2007 2006/Q4
FOOTNOTE DATA
'Schedule Page: 214 Line No.: 3 Column:
roperty for future 345/138 kV substation to be built in 2009.
~chedule Page: 214 Line No.: 4 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.
~chedule Page: 214 Line No.: 9 Column:
Various dates and plans.
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 2006/04(2) DA Resubmission 05/17/2007
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 42,084,337
Yale Relicensing (Lewis River)12,433,652
Merwin Relicensing (Lewis River)505,341
Swift Relicensing (Lewis River)037 292
Prospect 1 , 2 & 4 Relicensing (Rogue River)909,264
Hayden Plant - Routt County Road Improvements - Coal Haul 098,492
Production:
Lake Side Generating Plant (Natural Gas-Fired)264,939,669
Marengo Wind Plant 49,602 609
Goodnoe Hills East & West Wind Plant 44,722,843
Cholla Unit 4: CAI Environmental Projects 33,296,234
North Umpqua Relicensing Implementation 6,420,825
Huntington Water Efficiency Management 819,573
Blundell Bottoming Cycle 268,520
Lewis River Relicensing Implementation 234,274
Hunter Unit 3 Main Controls System Upgrade 110,777
Dave Johnston Unit 4 - Boiler ControlsfTurbine Controls 675,922
Hunter Unit 3 NOx 539 389
Hunter Unit 3 Reheater Replacements 532,569
Lake Side Capitalized Spare Parts 1.,464,372
Hunter Unit 3 Turbine L-O Bucket Replacements 442,521
Hunter Unit 3 Turbine HP Nozzle Box 210,647
Copco 2 Electrical Overhaul 205,816
Cholla Unit 4 D Mill Overhaul 097,243
Jim Bridger Refurbish Generator Field for Unit 3 040,323
Transmission:
Summit-Vineyard (Lake Side) Transmission Project 893,416
Camp Williams-Mona 345 kV No 4 Line 20,745,329
Cache Valley Add. Bridgerland Switching Station Phase 1 800,283
Summit-Vineyard (Lake Side) Interconnect 6,423,094
Line 1 Convert to 115kV, Line 14 Cap Relief 711,109
Marengo Wind-Install Switch Station 297 170
Craven Creek 230kV Svc Enterprise Pd Pioneer 438,568
Marquam 115kV Line Relocation for N Macadam Dev 322,181
Quail Creek Sub - convert to 69kV, Install Transformer 771,466
Hunter 4 Emery-Mona-Qquirrh Mona Cap 279,908
Midpoint-Summer Lake 500 kV Replace Relays 182 162
Oakley-Kamas New 46kV Line 169,191
TOTAL 734,457 063
FERC FORM NO.1 (ED. 12-87)Page 216
Name of Respondent This (!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) OA Resubmission 05/17/2007
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)
Distribution:
Latham Install 230-34 5kV 25MVA Sub 933,469
Bond Street - Construct New 69-12.5 Sub 853,876
Yew Avenue - Construct New Sub (Tetherow)641,394
Business Depot Ogden - Build 138-12.5kV Sub & Line 30MV A 303,474
Porter Rockwell New 138-12.5kV Sub 263,389
UDOT 10400 S to 11700 S Redwood Rd 037 039
General:
IP Telephony Project 856,206
Mainframe & Open Systems Storage 363,566
116,478,269
, ,:, ", '
TOTAL 734,457,063
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 (2)A Resubmission 05/17/2007 . 2006/04
FOOTNOTE DATA
~chedule Page: 216.Lin~ No.13 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
PacifiCorp
This ~ort Is:(1) ~An Original(2) A Resubmission
ACCUMULATED PROVI ION FOR DEPRECIATION OF ELEC
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.
Date of Report Year/Period of Report
(Mo, Da, Yr) End of 2006/04
05/17/2007
RIC UTILITY PLANT (Account 108)
Ine
No.(a)
1 Balance Beginning of Year
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense
4 (403.1) Depreciation Expense for Asset
, Retirement Costs
5 (413) Exp. of Elec. PIt. Leas. to Others
6 Transportation Expenses-Clearing
Other Clearing Accounts
Other Accounts (Specify, details in footnote):29,856,680
420,801 886 420,801,8861 TOTAL Depree. Prov for Year (Enter Total of
lines 3 thru 9)
11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired
13 Cost of Removal
14 Salvage (Credit)
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total of
lines 12 thru 14)
16 Other Debit or Cr. Items (Describe, details in
footnote):
, "" , ""'" "; ,; ,,' , '' " ,' ,' ,,""
i"'
" ". ,'.,.; , ,"';' ".., ".. "" ,,, ". ,," ", /, """".." "' ', ,, "' .'. ,.. ", '
158,186,488
41 ,566,452
371,817
192,381,123
158,186,488
566,452
371 817
192,381,123
26,604,001
945 570,482 945,570,482
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1
10,16, and 18)
Section B. Balances at End of Year According to Functional Classification
20 Steam Production
21 Nuclear Production
22 Hydraulic Production-Conventional
23 Hydraulic Production-Pumped Storage
24 Other Production
392 612,597 392,612 597
236,407 265 236,407,265
747,587 747 587
022,242,292 1 ,022,242,292
759,774,576 759,774.576
456,786,165 456,786,165
945,570,482 945,570,482
25 Transmission
26 Distribution
27 Regional Transmission and Market Operation
28 General
29 TOTAL (Enter Total of lines 20 thru 28)
FERC FORM NO.1 (REV. 12-05)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 05/17/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 219 Line No.Column: b
PacifiCo records the de reciation expense of asset retirement obligations as either a regulatory asset or (liability).
Schedule Page: 219 Line No.Column: b
Depreciation of mining assets included in 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 usage activity
Account 503.1 Blundell Depletion
Account 503 IGC Depreciation and Amortization
Total Other Accounts
903,462
231 586
048 583
268 419
116 724
287 906
$ 29,856 680
~chedule Page: 219 Line No.16 Column: b
Other items including:
Recovery from third parties for asset relocations and damaged property
Insurance recoveries
Adjustments of reserve related to electric plant sold
Reclassifications from electric plant
IGC Acquisition
$ 26 604 001
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 05/17/2007
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.
Ine Description of Investment Date Acquired Date Of Amount OT Investment at
No.(a)(b)l~rity
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
Capital Contributions
Undistributed Eamings 75,332 655
SUBTOTAL 75,332,656
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 677 807
SUBTOTAL 522,226
PACIFIC FUTURE GENERATIONS, INC 9/19/1999
Undistributed Subsidiary Eamings 581
SUBTOTAL -4,581
IITotal Cost of Account 123.1 $508 5261 TOTAL 84,853,402
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 2006/04(2) riA Resubmission 05/17/2007
INVESTMENTs 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 Subsidiary Revenues tor Year Amount of Investment at ""G"aln orToss from Investment LineEamin
~~ff Year
End ~f Year DiS
p?~rd of No.(t)
-100
100
86,602 065
11,269,410 100,762 066
900,000
608,526
826,786 851 021
826,786 359,547
046 627
046 627
9,437,578 113,111,986 100
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 (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
~chedule Page: 224 Line No.Column: g
Centralia Mining Company is a wholly owned subsidiary ofPacifiCorp and supports the electric utility operations. PacifiCorp
consolidates Centralia Mining Company for fmancial statement presentation in the accompanying fmancial statements included in this
Fonn No. I.
ISchedule Page: 224 Line No.10 Column: g
Energy West Mining Company is a wholly owned subsidiary ofPacifiCorp and supports the electric utility operations. PacifiCorp
consolidates Energy West Mining Company for financial statement presentation in the accompanying fmancial statements included in
this Fonn No. I.
~chedule Page: 224 ne No.15 Column:
Reflects $14 160 000 capital contribution from arent com any in 2006.
chedule Pa e: 224 Line No.16 Column:
Equity earnings from Pacific Minerals, Inc. (PMI) consist of inter-company profit on coal ot PacifiCorp from Bridger Coal Company,
that PMI jointly owns with Idaho Power Company, and are not recorded in account 418., Equity in Earnings of Subsidiary
Companies. In order to eliminate the inter-company profit on the coal sales, PacifiCorp records PMl's earnings as an offset to fuel
ex ense.
Schedule Page: 224 Line No.20 Column: g
Glenrock Coal Company is a wholly owned subsidiary ofPacifiCorp and supports the electric utility operations. PacifiCorp
consolidates Glenrock Coal Company for fmancial statement presentation in the accompanying financial statements included in this
onn No.
~chedule Page: 224 Line No.24 Column: g
Interwest Mining Company is a wholly owned subsidiary ofPacifiCorp and supports the electric utility operations. PacifiCorp
consolidates Interwest Mining Company for financial statement presentation in the accompanying fmancial statements included in this
Fonn No.
IFERC FORM NO.1 (ED. 12-87)Page 450,
Blank Page
(Next Page is: 227)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2006/04(2) DA Resubmission 05/17/2007 End of
MATERIALS AND SUPPLIES
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various
accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if
applicable.
Line Account Balance Balance Department or
No.Beginning of Year End of Year Departments which
Use Material
(a)(b)(c)(d)
Fuel Stock (Account 151)631 067 82,230 862 Electric
2 Fuel Stock Expenses Undistributed (Account 152)
Residuals and Extracted Products (Account 153)
Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)48,271 ,495 48,572,876 Electric
6 Assigned to - Operations and Maintenance
Production Plant (Estimated)180 564 636 918 Electric
8 Transmission Plant (Estimated)915,364 250,120 Electric
Distribution Plant (Estimated)815,760 330,981 Electric
Regional Transmission and Market Operation Plant
(Estimated)
Assigned to - Other (provide details in footnote)Electric
TOTAL Account 154 (Enter Total of lines 5 thru 11)117,959,772 129,731,866
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)174 590,839 211 962,728
FERC FORM NO.1 (REV. 12-05)Page 227
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
hedule Pa e: 227 Line No.Column: b
2006
Mining M&S 624 940
General Plant M&S 151.649
776 589
Schedule Page: 227 Line No.Column:
2005
Mining M&S 408 500
General Plant M&S 532.471
940 971
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)2006/04(2)DA Resubmission 05/17/2007 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 m-(k).
5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
Une Allowances Inventory Current Year 2007
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
............
PurchasesITransfers:
Total
Relinquished During Year:
Charges to Account 509 103,584.
Other:
Cost of SaleslTransfers:
P. Morgan 10,000.
Total 10,000.
Balance-End of Year 731.100,352.
Sales:
Net Sales Proceeds(Assoc. Co.
Net Sales Proceeds (Other)
Gains
Losses
Allowances Withheld (Acct 158.
Balance-Beginning of Year 259.259.
Add: Withheld by EPA
Deduct: Retumed by EPA
Cost of Sales 259.
Balance-End of Year 259.
Sales:
Net Sales Proceeds (Assoc. Co.
Net Sales Proceeds (Other)
Gains
Losses
FERC FORM NO.1 (ED. 12-95)Page 228
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2006/04(2) DA Resubmission 05/17/2007 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.
2008 2009 Future Years Totals Line
No.AmI.No.AmI.No.Amt.No.AmI.No.
(f)
(g)
(h)(i)(k)(I)(m)
156,643.0 156,643.00
103,584.
000.
10,000.
259.00 2,259.00 110 921.00 119,957.00
528.528.
269.528.
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 2006/04
(2) CiA Resubmission 05/17/2007
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.
Line Description of Unrecovered Plant Total Costs WRITTEN OFF DURING YEAR Balance atNo.and Regulatory Study Costs (Include Amount Recognised
in the description of costs, the date of of Charges During Year Account Amount End of Year
Commission Authorization to use Acc 182.Charged
and period of amortization (mo, yr to mo, yr)J
(a)(b)(c)(d)(e)(f)
Unrecovered Plant: Trojan Nuclear 513,886 407 674,864 839 022
Plant located near Portland, OR
Date of Retirement: 12/31/1992
Date of Commission Authorization:
04/20/1993
Amortization Period: 01/1993
hrough 01/2011
Unrecovered Plant: Trail Mountain 1 ,326,026 151 1 ,326,026
Date of Retirement: 03/15/2001
Date of Commission Authorization:
~/O4/2002 - UT
~5/20/2002 - OR
~/26/2oo1 - WY
~/2612001 - ID
Amortization Period: 04/2001
hrough 0312006
TOTAL 839,912 000,890 839,022
FERC FORM NO.1 (ED. 12-88)Page 230b
Blank Page
(Next Page is: 231)
Name of Respondent
PacifiCorp
This ~ort Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/04
Transmission Service and Generation Interconnection Study Costs
1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. In column (a) provide the name of the study.
4. In column (b) report the cost incurred to perform the study at the end of period.
5. In column (c) report the account charged with the cost of the study.
6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
7. In column (e) report the account credited with the reimbursement received for performing the study.
No.Description
(a)
Transmission Studies
2 00106
3 00069
4 00106/00107
5 00247-00255
6 00226/0227
7 00220
8 00296
9 00317
10 Aref 355217
11 Aref 314945
12 Aref 367339
13 Various Customer Studies
21 Generation Studies
37 Aref 316762
Costs Incurred During
Period
(b)
Account Charged
(c)
elm ursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
547 561.
506 561.
168 561.
985 561.
190 561.
450 561.
155 561.6
899 561.
809 561.
381 561.
369 561.
839,486 107 561.
547 456.
506 456.
22,168 456.
985 456.
190 456.
450 456.
155 456.
899 456.
809 456.
285 456.
369 456.
GIOOO59, LGIOOO59
GIOOO60, GIOOO63/64
GI0OO6O/61
OFlOO51
GIOOO56, OFIOOO56
----
160,469 561.
43,435 561.
597 561.7
26,170 561.
587 561.
22,708 561.
18,811 561.
16,724 561.
16,037 561.
15,911 561.
12,929 561.
12,367 561.
083 561.
774 561.
69,557 561.
13,470 107
150,765 456.
868 456.
26,645 456.
26,170 456.
24,587 456.
22,081 456.
097 456.
13,634 456.
12,663 456.
15,911 456.
929 456.
565 456.
11,977 456.
36,459 456.
GIOOO80, GI00089
GIOOO73
GI00091
GIOOO54, OFIOOO54
GIOOO72
GIOOO74
GI00090, GIOOO96
Misc Studies (-::1 Ok)
Misc Studies-Not Reimbursed
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07)Page 231
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006104
FOOTNOTE DATA
'Schedule Page: 231 ldne1.Jo.: 27 Column:
Generation Studies: GIQOO71, GlQOO87, GIQOO88 GIQOO92, SGIQOO71
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 2006/04(2) nA Resubmission 05/17/2007
0 HER REGULATORY ASSETS (Account 182.
1. Report below the particulars (details) called for conc~rning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $50,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of vvnuen 011 uunng vvnnen 011 uunng Current OuarterlYear
Current the OuarterlYear the Period
OuarterlYear Account Charged Amount
(a)(b)(c)(d)(e)(1)
Deferred Intervenor Funding Grants 529,353 332 179 861,532
Calffomia DSM Regulatory Asset 271 984)271 912 908 221,452 221,524
Idaho DSM Regulatory Asset 188,034 530 049 908 462,146 255,937
Utah DSM Regulatory Asset 093,204 523 94-29,924,162 692 991
Washington DSM Regulatory Asset ( 1 570 984)888 516 431, 908 109,276 791 744
Wyoming DSM Regulatory Asset (10)372,976 39,575 9OB 83,498 329,053
Transition Plan - OR (10)17,838,770 930.892 299 13,946,471
FAS 109 Deferred Income Taxes Electric 465,147 154 282 21,049892 464,097 262
SB 1149 Implementation Costs OR Retail Access (5)15,306 830 077014 407.825,579 11,558,265
Y2K Expense 98-00 OR (7)59,381 930.381
98 Earty Retirement OR (4)353 893 930.676,947 676,946
Glenrock Mine Excluding Reclamation UT (9)033,621 930.302 399 731,222
Deferred Excess Net Power Costs OR UE116 126 803 10,913 137,716
Environmental Costs (10)120 116 452,488 925 527,588 045,016
Environmental Costs - WA (10)367,157)13,942 353,215
Deferred Cost ofTOU Guarantee 804 930.804
IDAI Costs No. CA Direct Access (5)971,556 407.333,105 638,451
Cholla Plant Transaction Costs (26)13,001,422 557 122 425 878 997
Cholla Plant Transaction Costs OR (26)623,335)53,813 569,522
Cholla Plant Transaction Costs WA (26)123,655)006 026 649
Cholla Plant Transaction Costs ID (26)381 941)32,973 348,968
Washington Colstrip #3 (22)787 199 456 52,188 735,011
Trail Mountain Mine Closure Costs 663,410 151 663,410
Trail Mountain Mine - Deseret Settlement 132,782)132,782
FAS133 Derivative Net Regulatory Asset 229,837 168 229,837 168
FAS 87/88 Pension UT (7)318 028 930.159014 159 014
'Z7 Noell Kempf CAP UT 757 930.757
P&M Strike Amort UT (3)199 ,634 930.199,634
Energy Trust of Oregon SB1149 19,686 111 143 19,686 111
Retail Access Project INC.995,562 120,973 182.960000 156,535
Asset Retirement Obligations Regulatory Difference 28,284 094 30,772,979 230 176,143 860,930
DSM Regulatory Assets - Accruals 524 830 232 761,289 763,541
Regulatory Assets - Reclass 1,299,592 791,038
Sch 781 Direct Access Shopping Incentive 840,807 596290 407.537 839 899,258
FAS 158 Pension/Other Post Ret./SERP 280 655 740 285,273,451 Various 565,929,191
RTO Grid West N/R Reg Asset 131,721 131 721
Contra Reg Asset. RTO Grid West 904 131 721 131 721
RTO Grid West N/R - OR 810,234 810,234
RTO Grid West N/R - WY 414 098 414 098
RTO Grid West N/R - ID 135 811 135,811
Deferred Excess Net Power Costs - WY 554,006 554 006
OR SB 408 Recovery 760,000 254 2,454610 305,390
Reg Asset - Enrionmental Costs 080 491 080,491
TOTAL 885,243,418 605,126,212 709,244 395,660,386
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 05/17/2007
0 HER REGULATORY ASSETS (Account 182.
1. Report below the particulars (details) called for conc~rning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $50,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of Written oft LJunng Written 011 uunng Current QuarterlYear
Current the QuarterlYear the Period
QuarterlYear Account Charged Amount
(a)(b)(c)(d)(e)(I)
Cain. A~emative Rate for Energy (CARE)389,730 389,730
TOTAL 885,243,418 605 126,212 709 244 395 660 386
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)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 232 Line No.Column: d
Account 431
ccount 908
!Schedule Page: 232 Line No.33 Column:
The following is a reconciliation of the regulatory asset reclassification account:
Reclassified from Regulatory Assets to Regulatory Liabilities:
California DSM Regulatory Asset
Washington DSM Regulatory Asset
221 524
791 744
874
486
090 628
Reclassified from Regulatory Liabilities to Regulatory Assets:
Washington Low Income Program
Utah Home Energy Lifeline (11)
IFERC FORM NO.1 (ED. 12-87)Page 450,
Blank Page
(Next Page is: 233)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04
(2) CiA Resubmission 05/17/2007
MISCELLANEOUS DEFFERED DEBITS (Account 186)
Report below the particulars (details) called for conc~rning miscellaneous deferred debits.
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 ~~coum Amount End of YearChar~ed
(a)(b)(c)(e)(1)
Joseph Settlement (20)660,018 557 137,381 522 637
Lacomb Irrigation (24)735,330 557 720 689,610
Facilities and Properties 847 219,121 303,968
Bogus Creek (42)1 ,406,960 557 280 365,680
Intangible Pension Asset:
SERP Plan 935,007 219,228 935,007
Pension Intangible Asset 102 000 102 000
Mead Phoenix Availability
& Trans Charge (50)645,560 565 377,760 15,267 800
Lakeview Buyout (13)133 445 557 279 90,166
TGS Buyout (20)217,918 557 15,473 202 445
Hermiston Swap (20)710,478 557 539,573 170 905
Deferred Longwall Costs 577 345 2,421,423 151 230,216 768 552
Other Deferred Debits with
Amounts less than $50,000 287,928 530,741 151 505,309 313,360
Point to Point Transmission 099,267 981 090 521 356 559,001
Deferred Costs Wyodak
Settlement (22)698 090 151 335,181 362,909
Jim Boyd Hydro Buyout (11)669 785 557 860 586 925
Deferred Shelf ReQistration 279 320 218 283,538
Credit Agmt Costs (5)2,411,433 312 239 431 510 139 213 533
PCRB LOC/SBBPA Cost (5)1 ,372 867 222 484 427 344,476 250,875
Unamortized PCRB Mode Conv Cost 774,123 427 128,039 646,084
Deferred Chrgs-Water Rights 725,776 506 725,776
Emission Reduction Credits 406,980 406 980
Misc. Work in Progress
ueferred Regulatory Comm.
Expenses (See pages 350 - 351)
TOTAL 65,950,331 976,248
FERC FORM NO.1 (ED. 12-94)Page 233
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 05/17/2007
MISCELLANEOUS DEFFERED DEBITS (Account 186)
1. Report below the particulars (details) called for conc~rning miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $50 000, whichever is less) may be grouped by
classes.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~c;coum Amount End of YearChar~ed
(a)(b)(c)(e)(I)
Mine Depreciation Clearing 15,854 151 15,854
Non-Current Fed/State Inc Tax 741 862 12,741 862
LGIA L T Transmission Prepaid 898 901 898,901
WA Environmental Cost-Utah Mtls 290,803 290 803
Financing Costs Deferred 872 573 181 186 861 386 11,187
Property Damaae Repairs 711 228 64,184 28,527
Misc. Work in Progress
ueterred Hegulatory Comm.
Expenses (See pages 350 - 351)
TOTAL 65,950,331 57,976,248
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 (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
Line No.!Schedule Page: 233
Account 182
Account 219
Account 228
!Schedule Page: 233
Account 142
Account 419
Account 557
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 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
ACCUMULATED DEFERRED INCOME TAXES (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.
ocatlon
(a)
Electric
Regulatory Liabilities
Employee Benefits
4 FAS 133 Derivatives
5 PMI Deferred Assets
8 TOTAL Electric (Enter Total of lines 2 thru 7)
9 Gas
315,652,418
181 198,165
45,748,981
319,921 216
294 345 786
102,310,588
514 736
Other
TOTAL Gas (Enter Total of lines 10 thru 15
Other (Specify)
TOTAL (Acct190) (Total of lines 8,16 and 17)687 255,514 819,687,478
Notes
FERC FORM NO.1 (ED. 12-88)Page 234
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
~chedule Page: 234 Line No.Column:
Description
DTA FAS 143 ARO Liability
DT A Reg Liabilities
DT A Distribution O&M Amort of Writeoff
DTA M&S Inventory Write-Off
DTA 205.200 M&S Inventory Write-off
DT A Bad Debts Allowance - Cash Basis
DTA 425.225 Duke Contract Novation
DTA Unearned Joint Use Pole Contract Rev.
DTA 425.380 Idaho Customer Balancing Account
DT A Centralia Sale
DTA U ofWY Contract Amort - Prepaid
DTA DefReg Asset - Transmission Service Deposit
DT A Dei Reg Asset - Foote Creek Contract
DT A Redding Contract - Prepaid
DTA 110.100 Book Depletion
DTA 505.125 Accrued Royalties
DTA Final Reclamation - Cash Basis
DT A Trail Mountain Accrued Liabilities
DT A Montana Sale Accrual
DTA 715.050 Microsoft Lic Liability
DT A Purchase Card Trans Provision
DT A Misc. Current and Accrued Liability
DT A Injuries & Damages Accrual - Cash Basis
DT A Wasatch Workers Comp Reserve
DTA 920.150 FAS 112 Book Reserve
DT A Bogus Creek Settlement
DTA 425.120 Bear River Settlmt Agrmt
DTA 425.320, N. Umpqua Settlemt Agreemt
DT A Legal Reserve
DTA 610.010 NOPA 10399-00 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 8899-00 RAR
DTA 61O.020N NOPA's 72, 73 91 99-00 RAR
DTA 610.100N Amort NOPA's 99-00 RAR
DTA 610.020N NOPA's 110, III , & 13099-00 RAR
DTA 61O.100N Amortization NOPA's 99-00 RAR
DTA Weather Derivatives
DTA Amort of Debt Disc & Exp
DT A Defer MagCorp Revenues
DTADeferred Comp Accrual- Cash Basis
DTA Special Assessment - DOE
DT A Amortization Overburden
DTA Merger Cost Amort
DTA Amort of Projects - Klamath Engineering
DT A 425.110 Tennant Lease Allow-PSU Call Center
DTA 210.000, Prepaid Ins. Cont. Reserve
IFERC FORM NO.1 (ED. 12-87)
Balance at
Beginning of Balance at
Year End of Year
964 767 665 893
443 493
616 889 749 975
812 892
611 872
160 247 726 876
301 046
616 105 335 983
49,715 001 027
947 073 938 878
165 555 212 024
660 145 619 340
515 789 424 377
243 873 878 599
111 099
762 599
938 996
723 026 180 167
220 116 129 792
404 083
363 219
429 391 698 533
975 748 688 805
131 460 907 154
459,220 702 405
782
134 346 143 503
682 408
759 020
415 599
496 680
116 253
101 623
861 497
355
631 392
128 665
330 685
252 773
561 315
749 905 590
077 710
174 795
507 091
137 477
072 806
152 298 136 014
(195 931)
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 05/17/2007 2006/04
FOOTNOTE DATA
DTA 610.120 Trail Mountain
DT A 605.200 WY Jt Water Rd
DTA 505.115 Sales & Use Tax
DTA 505.160 Cal PUC Fee
DTA 425.295 BPA Rate Credits
DTA 425.300 Mead Phoenix Avail & Trans Charge
DT A Idaho ITC Carryforward
DT A - BETC Purchased Credits
DTA 920.160 Stock Incentive Plan
DTA 920.170 Exec Stock Option Plan
227 768
569 289 370 022
718
108
162 716
286 727
498 675
892 824 977 769
079 927
748 855
144,655.950 $96,595,152Total
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 05/17/2007
CAPITAL STOCKS (Account 201 and 204)
Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (Le., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line Class and Series of Stock and Number of shares Par or Stated Call Price at
No.Name of Stock Series Authorized by Charter Value per share End of Year
(a)(b)(c)(d)
Common Stock (Account 201)750,OOO OOO
PacifiCorp is a wholly
owned indirect subsidiary of
MidAmerican Energy Holdings Company
6 TOTAL COMMON STOCK 750,000,000
10 5% Cumulative Preferred 126,533 100.110.
(American Stock Exchange)
Serial Preferred, Cumulative:500 000
52% Series 100.103.
00% Series 100.
00% Series 100.
00% Series 100.100.
40% Series 100.101.
72% Series 100.103.
56% Series 100.102.
TOTAL PREFERRED STOCK 626,533
31~~
"'" .\" ~,",
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 2006/Q4(2) fiA Resubmission 05/17/2007
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 Une
(Total amount outstanding without reduction AS REACQUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
Sl1ares Amount Shares cost Sh~res Amount
(e)(f)
(g)
(h)(i)
357 060,915 3,417 945,896
357,060,915 3,417,945,896
126,243 624,300
065 206,500
18,046 1 ,804,600
930 593,000
41,908 190,800
65,959 595,900
890 989 000
84,592 459,200
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 05/17/2007 2006/04
FOOTNOTE DATA
~chedule Page: 250 Line No.: 1 Column: d
his class of stock is not redeemable.
!schedule Page: 250 Line No.: 9 Column:
Exce t as s ecifically noted, all preferred stock series trade as unlisted securities.
Schedule Page: 250 Line No.: 15 Column: d
This series of referred stock is not redeemable.
chedule Page: 250 Line No.: 16 Column: d
This series of preferred stock is not redeemable.
ISchedule Page: 250 Line No.: 31 Column:
Authorizations for the issuance of common stock by PacifiCorp to its immediate corporate parent, PPW Holdings LLC are as follows:
---,-------
Utah Public Service Commission, Docket No. 06-035-, Report and Order, dated July 10 2006.
Oregon Public Utility Commission, Docket No. UF-4228, Order No. 06-417, dated July 17 2006.
Washington Utilities and Transportation Commission, Docket No. UE-060974, Order No., dated June 28, 2006.
Idaho Public Utilities Commission, Case No. P AC-06- 7, Order No. 30099, dated July 7, 2006.
As of December 31 , 2006 30 000 000 shares authorized; 30 000 000 available.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 253)
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 05/17/2007
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.
1~l l~r
"?g)
unt
Account 211 Miscellaneous Paid-in Capital
Additional Paid-in Capital
3 Share based payments
Tax effect of stock options
Benefit plan separation
Capital contributions
7 Gain on sale of Scottish Power stock
Qualified production activity tax deduction
Contribution of Intermountain Geothermal
TOTAL 223,285,229
FERC FORM NO.1 (ED. 12-87)Page 253
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S, An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/Q4
FOOTNOTE DATA
ISchedule 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 0 tions became full vested in Ma 2005.
Schedule Pa e: 253 Line No.Column: b
This represents the income tax deduction attributable to the exercise of stock options granted by ScottishPower. This deduction is
re uired to be recorded throu an ad'ustment to additional aid-in-ca ita!.
Schedule Pa e: 253 Line No.Column: b
This represents the effect oftransfening benefit plans to PPM Energy as a result of the sale ofPacifiCorp by ScottishPower. This is
required to be recorded through an adjustment to additional paid-in-capita!.
ISchedule Page: 253 Line No.Column: b
Ca ital contributions to PacifiCo with no shares of stock issued uom its immediate co
chedule Pa e: 253 Line No.Column: b
Represents a realized gain on sale of stock for PPM Energy participants in the deferred compensation plan, required to be recorded in
additional aid-in-ca ita!.
Schedule Page: 253 Line No.Column: b
Re resents an e uity adjustment related to the transfer ofPPM Energy s IRC 199
chedule Pa e: 253 Line No.Column: b
Contribution of Intermountain Geothermal Company ("IGC") to PacifiCorp uom MERC. For additional information regarding IGC
refer to page 108 Important Changes During the Year ITEM 2, of this Form No.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ~ort Is:Dale of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) riA Resubmission 05/17/2007
CAPITAL STOCK EXPENSE (Account 214)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line Class and Senes of Stock Balance at ~na ot Year
No.(a)(b)
1 Common Stock 101 062
Preferred Stock:
00% Serial 98,049
52% Serial 676
72% Serial 30,349
7 4.56% Serial 49,071
22 TOTAL 288,207
FERC FORM NO.1 (ED. 12-87)Page 254b
Blank Page
(Next Page is: 256)
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 05/17/2007
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221 , Bonds, 222
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
In column (a), for new issues, give Commission authorization numbers and dates.
For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
In column (b) show the principal amount of bonds or other long-term debt originally issued.
In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission s authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
Bonds: (Account 221)
First Mortgage Bonds:
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 4,422 000
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 1,422 659
232,000 D
950% Series due August 15, 2014 200,000,000 442 365
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 18,750 000
470% Series due October 1, 2017 19,609,000
700% Series due November 15, 2031 300,000 000 874,150
864,000 D
900% Series due August 15, 2034 200,000 000 892,365
722 000 D
25% Series due June 15, 2035 300 000,000 912,021
080,000, D
350,000,000 767 726
141 000 D
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
TOTAL 521,486,000 58,967,468
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 2006/04(2) DA Resubmission 05/17/2007
LONG-TERM DEBT (Account 221 222 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD Ul!tstan~:lIn 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)(I)
(g)
resPyt';)dent)(i)
11/06/1998 11/01/2006 11/06/1998 11/01/2006 9,416,667
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 16,945,000 616,091
04/15/1992 1 0/01 /2011 04/15/1992 10/01/2011 770,000 157 905
11/15/2001 11/15/2011 11/15/2001 11/15/2011 500,000,000 34,500,000
04/15/1992 10/01/2012 04/15/1992 10/01/2012 230,000 856,838
04/15/1992 10/01/2013 04/15/1992 10/01/2013 8,467,000 800,923
09/15/2003 09/15/2013 11/15/2001 09/15/2013 200 000 000 900 000
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 15,952 000 1,481 155
04/15/1992 10/01/2015 04/15/1992 10/01/2015 27,903,000 440,986
04/15/1992 10/01/2016 04/15/1992 10/01/2016 11,959,000 080,325
04/15/1992 10/01/2017 04/15/1992 10/01/2017 13,052,000 150,226
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 11,800,000
06/13/2005 06/15/2035 06/13/2005 06/15/2035 300,000,000 15,750,000
08/10/2006 08/01/2036 08/10/2006 08/01/2036 350,000,000 362,083
01/22/1996 01/15/2006 01/22/1996 01/15/2006 238,000
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
086,372,000 245,313,780
FERC FORM NO.1 (ED. 12-96)Page 257
Name of Respondent This
0ort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04
(2) riA Resubmission 05/17/2007
LONG-TERM DEBT (Account 221 , 222, 223 and 224)
Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221 , Bonds, 222
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
In column (a), for new issues, give Commission authorization numbers and dates.
For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
In column (b) show the principal amount of bonds or other long-term debt originally issued.
In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission s authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
43% Series E Medium-Term Notes due Sept. 11 2007 000,000 15,530
22% Series E Medium-Term Notes due Sept. 18 2007 500,000 19,412
27% Series E Medium-Term Notes due Sept. 24, 2007 000,000 31,059
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 000,000 327
95% Series C Medium-Term Notes due Sept. 1, 2011 000,000 175,398
95% Series C Medium-Term Notes due Sept. 1 2011 20,000,000 132,118
92% Series C Medium-Term Notes due Sept. 1, 2011 20,000,000 188,318
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 13,297
25% Series C Medium-Term Notes due Feb. 1, 2012 000,000 22 , 946
13% Series E Medium-Term Notes due Jan. 22, 2013 10,000,000 827
53% Series C Medium-Term Notes due Dec. 16 2021 15,000,000 115 202
375% Series C Medium-Term Notes due Dec. 31,2021 000,000 38,400
826% 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 30,594
05% Series E Medium-Term Notes due Sept. 1,2022 15,000,000 131,471
07% Series E Medium-Term Notes due Sept. 9, 2022 000,000 70,118
12% Series E Medium-Term Notes due Sept. 9, 2022 50,000,000 438,238
11% Series E Medium-Term Notes due Sept. 9, 2022 000,000 105,177
05% Series E Medium-Term Notes due Sept. 14,2022 10,000,000 87,648
8.08% Series E Medium-Term Notes due Oct. 14, 2022 26,000,000 208,198
08% Series E Medium-Term Notes due Oct. 14 2022 000,000 200,190
23% Series E Medium-Term Notes due Jan. 20, 2023 000,000 37,914
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 000,000 100,622
TOTAL 521,486,000 58,967,468
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 2006/04(2) riA Resubmission 05/17/2007
LONG-TERM DEBT (Account 221 , 222, 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD uutstanaln Line
Nominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)
(g)
resp\(~dent)
(i)
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
09/2211992 09/24/2007 09/22/1992 09/24/2007 000,000 290,800
05/12/1998 05/15/2008 05/12/1998 05/15/2008 200,000,000 12,750,000
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 25,000,000 237 500
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 82,600
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 01/2212013 000,000 813,000
12/16/1991 12/16/2021 12/16/1991 12/16/2021 15,000,000 279 500
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 50,000,000 060,000
09/11/1992 09/09/2022 09/11/1992 09/09/2022 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,ooO,OOC 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
01/29/1993 01/20/2023 01/29/1993 01/20/2023 000,000 329 200
07/2211993 07/21/2023 07/2211993 07/21/2023 000,000 960 200
07/22/1993 07/21/2023 07/22/1993 07/21/2023 11,000,000 798,600
086,372,000 245 313,780
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 2006/04(2) riA Resubmission 05/17/2007
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)
723% Series F Medium-Term Notes due Aug. 16, 2023 000,000 137,211
24% Series F Medium-Term Notes due Aug. 16,2023 30,000,000 274,423
75% Series F Medium-Term Notes due Sept. 14,2023 000,000 38,250
75% Series F Medium-Term Notes due Sept. 14,2023 000,000 15,300
72% Series F Medium-Term Notes due Sept. 14 2023 000 000 15,300
75% Series F Medium-Term Notes due Oct. 26, 2023 20,000,000 152,326
75% Series F Medium-Term Notes due Oct. 26, 2023 16,000,000 121,861
75% Series F Medium-Term Notes due Oct. 26, 2023 000,000 91,396
71% Series G Medium-Term Notes due Jan. 15, 2026 100 000,000 904,467
Subtotal - First Mortgage Bonds 708,116 000 271 995
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 Ctrl Rev Refunding Bonds, Emery County, UT, Series 1994 121,940,000 274,246
Poll Ctrl Rev Refunding Bonds, Carbon County, UT, Series 1994 365,000 206,519
Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1994 15,060,000 422,858
Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1988 000 000 155,970
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 45,000,000 771 ,836
Poll Ctrl Revenue Bonds, City of Forsyth, MT, Series 1986 500,000 304,824
Environ. Imprvmnt Rev Bonds, Converse County, WY, Series 1995 300,000 132 043
Environ. Imprvmnt Rev Bonds, Lincoln County, WY, Series 1995 22,000,000 404,262
Pollution Control Revenue Bonds:
TOTAL 521,486 000 58,967 468
FERC FORM NO.1 (ED. 12-96)Page 256.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PaciliCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 05/17/2007
LONG-TERM DEBT (Account 221 , 222, 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD Ul!ISlanQIn 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)(I)
(g)
res~R)dent)(i)
08116/1993 08116/2023 08/16/1993 08/16/2023 15,000,000 084,500
08/16/1993 08116/2023 08116/1993 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 20,000,000 350,000
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
310,502 000 211 003 080
11/17/1994 05/01/2013 11/17/1994 05/01/2013 655,000 510,788
11/15/1993 11/01/2021 11/15/1993 11/01/2021 300,000 476,836
11/15/1993 11/01/2023 11/15/1993 11/01/2023 46,500,000 683,053
11/15/1993 11/01/2023 11/15/1993 11/01/2023 16,400,000 942,182
11/17/1994 11/01/2024 11/17/1994 11/01/2024 260,000 787 087
11/17/1994 11/01/2024 11/17/1994 11/01/2024 190,000 303,210
11/17/1994 11/01/2024 11/17/1994 11/01/2024 121 940 000 736,241
11/17/1994 11/01/2024 11/17/1994 11/01/2024 365 000 348,015
11/17/1994 11/01/2024 11/17/1994 11/01/2024 15,060,000 572,987
01/01/1988 01/01/2014 01/01/1988 01/01/2014 17,000,000 680,353
12/01/1984 12/01/2014 12/01/1984 12/01/2014 15,000,000 600 358
01/17/1991 01/01/2016 01/17/1991 01/01/2016 45,000,000 1 ,638,402
12/01/1986 12/01/2016 12/01/1986 12/01/2016 500 000 359,451
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 000,000 951,207
086,372,000 245,313 780
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 2006/04(2) riA Resubmission 05/17/2007
LONG-TERM DEBT (Account 221 , 222, 223 and 224)
Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221 , Bonds, 222
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
In column (a), for new issues, give Commission authorization numbers and dates.
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.
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)
Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992A 335,000 167,524
Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992B 305,000 151 908
Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 22,485 000 242,163
Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988B 11,500,000 84,822
Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Ser. 1990A 70,000,000 660,750
Poll Ctrl Rev Refunding Bonds, Emery County, UT, Series 1991 45,000,000 872 505
Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988A 000,000 422 443
Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Series 1988 000 000 380,198
Poll Ctrl Rev Refndng Bonds, City of Gillette, WY, Ser. 1988 200,000 351 905
Environ. Imprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 24,400,000 225,000
150% Emery County, Utah, Series due September 1 , 2030 675,000 556 549
178,464 D
Subtotal - Pollution Control Revenue Bonds 738 370 000 14,855,040
TOTAL ACCOUNT 221 446,486 000 58,127,035
Reacquired Bonds: (Account 222)
Advances from Associated Companies: (Account 223)
Other Long-Term Debt: (Account 224)
-", -; .'..""',')"'*"~ '
75,000,000 840,433
" "
~" '(o. - -
TOTAL ACCOUNT 224 000,000 840,433
TOTAL 521,486,000 58,967,468
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 2006/04
(2) CiA Resubmission 05/17/2007
LON ;;-TERM DEBT (Account 221 222,223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD v~ISlanlJln Line
Nominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)
(g)
res~~dent)(i)
09/29/1992 12/01/2020 09/29/1992 12/01/2020 335,000 360 221
09/29/1992 12/01/2020 09/29/1992 12/01/2020 305,000 243,299
09/29/1992 12/01/2020 09/29/1992 12/01/2020 485,000 867 657
01/01/1988 01/01/2014 01/01/1988 01/01/2014 11,500,000 480,969
07/25/1990 07/01/2015 07/25/1990 07/01/2015 70,000,000 966,840
OS/23/1991 07/01/2015 OS/23/1991 07/01/2015 45,000,000 949,456
01/01/1988 01/01/2017 01/01/1988 01/01/2017 50,000,000 131,467
01/01/1988 01/01/2018 01/01/1988 01/01/2018 000 000 897,488
01/01/1988 01/01/2018 01/01/1988 01/01/2018 200 000 767,407
12/14/1995 11/01/2025 12/14/1995 11/01/2025 24,400 000 044,462
09/24/1996 09/01/2030 09/24/1996 09/01/2030 12,675,000 779,513
738,370,000 303,200
048 872,000 242 306,280
06/11/1992 06/15/2007 07/01/2003 06/15/2007 37,500,000 007 500
500,000 007,500
086,372 000 245,313,780
FERC FORM NO.1 (ED. 12-96)Page 257.
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04
(2) FiA Resubmission 05/17/2007
LONG-TERM DEBT (Account 221 , 222, 223 and 224)
Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221 , Bonds, 222
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
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.
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.
Une 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)
TOTAL 521,486,000 58,967,468
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 (Me, Da, Yr)End of 2006/04(2) nA Resubmission 05/17/2007
LONG-TERM DEBT (Account 221 , 222, 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: '(a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD uulslanOln 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)
res
P'(t7)dent)(i)
086,372,000 245 313 780
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 05/17/2007 2006/04
FOOTNOTE DATA
!Schedule Page: 2~Tine No.27 Column:
On August 10 2006, PacifiCorp issued $350.0 million of its 6.10% Series of First Mortgage Bonds due August 1 2036. PacifiCorp
used the proceeds for general corporate purposes, including the reduction of short-term debt. State Commission authorizations for this
issuance were as follows:
Utah Public Service Commission, Docket No. 06-035-43, Report and Order dated May 3, 2006, amended May 18 2006.
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 June 14 2006.
daho Public Utilities Commission, Case No. PAC-05-, Order No. 29787, dated May 17 2005.
!Schedule Page: 256.Line No.30 Column:
As of December 31 , 2006, there were 375 000 shares outstanding ($100 stated value per share) on the $7.48 series subject to the
followin mandatory redemption re uirements: all shares outstanding on June 15 2007 subject to mandatory redemption on that date.
chedule Page: 256.4 Line No.Column:
For authorization for the issuance ofJong-term debt ($1 000 000 000 authorized; $ 350 000 000 available as of December 31, 2006),
refer to page 104 Important Changes During the Year ITEM 6, of this Form No.
Authorization for the issuance of pollution control revenue bonds ($125 000 000 authorized; $79 225 000 available as of December
, 2006) 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.
For additional information regarding long-term debt, refer to page 104 Important Changes During the Year ITEM 6, of this Form No.
IFERC FORM NO.1 (ED. 12-87) Page 450.
Blank Page
(Next Page is: 261)
This ~ort Is: Date 01 Report YearlPeriod 01 Report(1) ~An Original (Mo, Da, Yr) End 01 2006/04
(2) A Resubmission 05/17/2007
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
1. Report the reconciliation 01 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 lumished on Schedule M-1 of the tax return for the year.
Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
2. II the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate
return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated retum. 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 01 a company, may be used as Long as the data is consistent and meets the requirements 01 the
above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Name 01 Respondent
PacifiCorp
Ine
No.
1 Net Income forthe Year (Page 117)
axable Income Not Reported on Books
mount
(b)
307,934,288
19 Deductions on Retum Not Charged Against Book Income
25 -;; '0'-.
26 State Tax Deductions
27 Federal Tax Net Income
28 Show Computation of Tax:
30 Federal Income Tax at 35.00%
31 Federal Accrual to Retum Adjustments
32 ax ReserVe Changes
33 Stock Options to APIC
34 Wind Credits
35 Excess Loss
36 Misc. Reclass
933,650,459
13,207,381
367 267,158
128,543,505
13,047,764
723,981
721 304
14,562 839
-4,013,753
390,395
38 Federal Income Tax Accrual
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 (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
~chedule Page: i61---Line No.Column:
Particulars (Details)
Contributions in Aid of Construction
Highway Relocation
F AS 133 Derivatives - Current
W A Rate Refund
Oregon Gain on Sale
Oregon Share of Hennis ton
F AS 133 Derivatives - Book Unrealized Gain/Loss
Unearned Joint Use Pole Contact Revenue
MCI FOG Wire Lease
FAS 115 Unrealized Gain/Loss
Equity Earnings in Subsidiaries
Total
Amount
878 131
225 228
881 869
862
104 292
192 764
241 334 773
896 864
558 678
206 175
1.831.832
429, II 9 468
~chedule Page: 261 Line No.13 Column:
Particulars (Details)
FederaVState Income Tax
Other AIR Bad Debt Write-offs
Mandatory Redeemable PrefelTed Stock - F AS 150
Meals & Entertainment
Penalties
Penalties - PMI
Lobbying Expenses
Meals & Entertainment - Bridger Coal
MEHC Insurance Services - Premium
Non-deductible Executive Compl Excise Tax
Non-deductible Parachute Payment - 280G
PMI Fuel Tax Cr
Scottish Power UK Management Fee
Excess Loss Account Triggers - PPW
30% Capitalized Labor Costs for Powertax Input
Book Depreciation
Book Amortization - Abandoned Proj. - Lease Rights
Book Amort. - Abandoned Proj. - Lease Rental
Tax vs Book Depreciation - PMI
AFUDC - Equity
A voided Costs
Acquisition Adjustment Amort
ADR Repair Allowance 3115
Chona SHL (APS Tax Lease)
Book Cost Depletion - Addback
May 2000 Transition Plan Costs - OR
May 2000 Transition Plan Costs - ID
May 2000 Transition Plan Costs - UT
May 2000 Transition Plan Costs - WYE
May 2000 Transition Plan Costs - WYW
Glenrock Excluding Reclamation - UT
FAS 87/88 Pension Write-off - UT rate order
98 Early Retirement - OR rate order
Environmental Costs - W A
Amount
157 319 375
229 804
652 930
522 263
233 819
221
820 552
325
744 651
603 395
783 014
374
645 089
013 268
903 699
413 750 864
492 336
008
149 565
794 500
39,978 480
479 360
000
570 327
419 022
872 283
462,486
147 630
291 432
228 514
279,199
528 274
434 657
352 276
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/Q4
FOOTNOTE DATA
Cholla Pit Transact Costs - APS Amort
W A Disallowed Colstrip #3 - Write-off
DefReg Asset - OR DefNet Power Costs
IDAI Costs - direct access
P&M Strike Amortization - UT
Contra - RTO Grid West NIR Allowance
Contra RTO Grid West NIR wlo - W A
Weatherization
Trojan Decommissioning Costs - Regulatory
Income Tax Audit Pymt
SB 1149 - Related Regulatory Assets
Post Merger Loss - Reacq Debt - Addback
Y2K Expense - OR
Noell Kempf CAP - UT
Trail Mountain Mine Closure
Trail Mountain Unrecovered Inventory
Prepaid Insurance - IBEW 157 Contingency Reserve
Prepaid Taxes - OR PUC
Prepaid Taxes - WY PSC
Pollution Control Facility (Book v. Tax Amort)
TGS Buyout
Lakeview Buyout
Joseph Settlement
Henniston Swap
Energy Trading Derivatives - Current
SPI Investment
W A State Transition Costs
Fifth Cogen Settlement
ARO Reg Liabilities
Non-ARO Liability - Reg Liability
Reg Liability BP A Balancing Accounts
Reg Liab - OR Balance Consol
OR Reg AssetJLiability Consolidation
Property Insurance
West Valley Lease Reduction - W A
West Valley Lease Reduction - CA
West Valley Lease Reduction - ID
West Valley Lease Reduction - WY
West Valley Lease Reduction - UT
A&G Credit - W A
A&G Credit - CA
A&G Credit - ID
A&G Credit - WY
Vacation Accrual - Cash Basis (2.5 mos)
Accrued Retention Bonus
F AS 106 Accruals - Cash Basis
Pension / Retirement Accrual - Cash Basis
SERP Accrual - Cash Basis
Accrued CIC Severance
Steam Rights Blundell Geothennal
FAS 143 ARO Liability
Distribution O&M Amort of Write-off
M&S Inventory Write-off
IFERC FORM NO.1 (ED. 12-87)
642 607
329
585 063
582 933
424 221
131 721
211 234
516 818
601 223
512 123
701 526
141 678
247 842
256
687 988
304 104
318 873
768 829
226 079
572 556
079
740
240 416
944 252
982 762
575 454
657 375
333 060
505 868
726 702
458 870
656 883
115 622
397 429
342 758
145
274 125
608 494
364 461
385 804
125 169
277 319
619 940
549 767
256,794
509 967
162 032
194 743
375 997
956 450
512 140
261
551 230
Page 450.2 '
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
R & E - Sec. 174 Deduction
Bear River Settlement Agreement
Other Environmental Liabilities
DukelHenniston Contract Renegotiation
BP A Conservation Rate Credit
N. Umpqua Settlement Agreement
Umpqua Settlement Agreement
Idaho Customer Balancing Account
Trail Mountain Accrued Liabilities
Misc. Current and Accrued Liability
California Public Utility Commission Fee
Reverse Accrued Final Reclamation
PMI Devt Cost Amort
Microsoft Software License Liability
Aquila Weather Hedge
F AS 112 Book Reserve
Centralia Sale
L TIP Performance Share Awards
Bridger Coal Company Reclamation Trust Earnings - PMI
Vacation Accrual- PMI
Merger Credits - OR
Total
892 694
929,518
254,402
3,428 226
428 752
739 756
027 734
776 638
204 560
398 062
999
384
152
064 748
370 090
275 761
993 949
527 413
953 110
870
36.452
021 472 373
ISchedule Page: 261 Line No.18 Column:
Particulars (Details)
Utah Deferred Comp / COLl
MEHC Insurance Services - Receivable
Tax Exempt Interest (No AMT)
Bridger Coal Tax Exempt Interest Income
Dividend Received Deduction
PMI Overriding Royalty
Regulatory Asset - Net F AS 133
RTO Grid West Note Receivable - w/o - W A
Centralia Gain Give Back - OR
OR Rate Refunds
CA - California Alternative Rate for Energy Program (CARE)
FAS 158 Pension Liability
FAS 158 Post-Retirement Liability
Accrued Royalties
Centralia Give Back - W A
SMUD Revenue Imputation - UT Reg Liab
FAS 115 Mark to Market Accrual- Bridger - Reclass
CA Refund
Total
Amount
111 632
148 582
551
399 037
831 437
937
322 133 246
211 234
843 043
527
389 730
600 000
256
292 692
968 141
018 525
206 175
199.386
444 401 131
~chedule Page: 261 Line No.25 CoTumn:a--
Particulars (Details)
Non Deductible Expenses
Tax Percentage Depletion - Deduction
PPL Pre - 1943 Preferred Stock Div - Deduction
IFERC FORM NO.1 (ED. 12-87)
Amount
Page 450.
692 027
113 599
428 810
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
Trapper Mine Dividend Deduction
SPI 404(k) Contribution
2004 JCA - Qualified Production Activities Deduction (3%)
Medicare Subsidy
Bridger Coal Company Depletion - PMI
Tax Depreciation
Depreciation (Tax Depreciaiton M-
Capitalized Depreciation
AFUDC - Debt
AFUDC
Basis Intangible Difference
Gain / (Loss) on Prop. Disposition
Coal Mine Development
Coal Mine Extension
Removal Costs
Coal Mine Development - 30% Amortization
Cholla SHL - GE Lease (Tax Int. - Tax Rent)
Malin SHL (Tax Int. - Tax Rent)
ARO - rec1ass to ARO liabilities
ARO - rec1ass to reg assets/liability & ARO liability
Book Gain/Loss on Land Sales
Tax Percentage Depletion - Deduction
Ptax NOPAs
ARO Reg Assets
Environmental Clean-up Accrual
Wyoming PCAM DefNet Power Costs
SB 1149 Costs
Deferred Intervener Funding Grants
781 Shopping Incentive
Trail Mountain
Coal Pile Inventory Adjustment
Prepaid Taxes - UT PUC
Prepaid Taxes - ill PUC
Other Prepaid
Prepaid Taxes - Property Taxes
Sales & Use Tax Accrual
WY Joint Water Board Reserve - Deduction
Wasach Workers Comp Reserve
Roll (not Ptax) 99-00 RAR
Reg Liability - UT Home Energy Lifeline
Reg Lability - W A Low Energy Program
A&G Credit - OR
Oregon UE 134 Power Cost
Bonus Liability - Electric - Cash Basis (2.5 mos)
Deferred Compensation Accrual - Cash Basis
Pension / Retirement Accrual - Cash Basis
SERP Accrual - Cash Basis
Severance Accrual - Cash Basis
Executive Trust Comp Reduction Plan - SPI Stock
Steam Rights Blundell Geothermal Tax Depreciation Deduction
Sec. 263A Inventory Change - PMl
Bad Debts Allowance - Cash Basis
Amort of Projects - Klamath Engineering
077 170
594 149
375 720
099 000
165 000
476 305 618
719 787
136 178
873 557
652 231
023 039
789,551
362 699
256 004
39,777 026
361 641
014 244
360 254
820 790
726 702
148 892
985 138
397 852
197 218
223 182
554 006
076 559
507 754
747 938
600 163
246 225
886 715
441
654 992
623 060
133 639
525 000
591 043
405 226
039 592
228 442
305 390
885 080
313 224
924 079
068 795
268 921
621 675
575,454
679 916
257 404
27,492 096
11 ,240
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo , Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
DefReg Asset - Transmission Srvc Deposit
DefReg Asset - Foote Creek Contract
Min. Pension Liability Adjustment
Deferred Regulatory Expense
Tenant Lease Allow - PSU Call Cntr
Misc DefDr - Prop Damage Repairs
Amort of Debt Disc & Exp
Special Assessment - DOE
Oregon LIC Bid Liability Reserve
Purchase Card Trans Provision
Misc. Deferred Credits
NW Power Act - W A
Redding Contract - Prepaid
Legal Reserve
Injuries and Damages Accrual - Cash Basis
Amort NOPAs 99-00 RAR
Coal Mine Development - PMI
Bridger Coal Company Underground Mine Cost Depletion
Bridger Coal Company Extraction Taxes Payable - PMI
Bonus Accrual - PMI
U of WY Contract Amort - Prepaid
Reg Assets/Reg Liabilities - Total
Bogus Creek Settlement
PacifiCorp Stock Incentive Plan
PacifiCorp Executive Stock Option Plan
Total
~chedule Page: 261 Line No.38 Column: b
107 528
240 870
168
938
907
527
148 205
594
238 000
957 074
971 794
727 530
962 493
002 640
764 572
343 582
804 395
694
774 504
334
071 211
120 636
118 000
694 777
17.401.339
933 650 459
On March 21, 2006, MidAmerican Energy Holdings Company ("MEHC") completed its purchase of all ofPacifiCorp
outstanding common stock from PacifiCorp Holdings, Inc. ("PHI"), a subsidiary of Scottish Power pIc ("ScottishPower
PacifiCorp s common stock was directly acquired by a subsidiary ofMEHC, PPW Holdings LLC. As a result of this
transaction, MEHC controls the significant majority ofPacifiCorp s voting securities. MEHC, a global energy company
based in Des Moines, Iowa, is a majority-owned subsidiary of Berkshire Hathaway Inc.
At December 31 , 2005, PacifiCorp kept its accounting records on a fiscal-year basis for the Securities and Exchange
Commission (the "SEC") fmancial reporting purposes. The fiscal year end was March 31. Annual fiscal year end tax
adjustments were performed in March. In May 2006, the PacifiCorp Board of Directors elected to change PacifiCorp s fiscal
year-end from March 31 to December 31.
Names of group members who will file a consolidated Federal Tax Return:
Under ScottishPower:
PacifiCorp Holdings, Inc. (Common US Parent)
PacifiCorp Holdings. Inc. Sub-Group:
Pacific Klamath Energy, Inc.
PacifiCorp
PacifiCorp Group Holdings Company
PPM Energy, Inc.
Scottish Power Finance (US), Inc.
PacifiCorp Sub-Group:
Centralia Mining Company
Energy West Mining Company
Glenrock Coal Company
Interwest Mining Company
Pacific Minerals, Inc.
PacifiCorp Environmental Remediation Company
PacifiCorp Future Generations, Inc.
PacifiCorp Investment Management, Inc.
PacifiCorp Group Holdings Company Sub-Group:
Leblon Sales Corporation
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 05/17/2007 2006/04
FOOTNOTE DATA
New Energy Holdings I, Inc.
PACE Group, Inc.
PacifiCorp Development Company
PacifiCorp Energy Ventures, Inc.
PacifiCorp Financial Services
PacifiCorp International Group Holdings Company
PacifiCorp Trans, Inc.
PFI International, Inc.
PacifiCorp Financial Services. Inc. Sub-Group:
Birmingham Syn Fuel I, Inc.
Hillsborough Leasing Services, Inc.
Pacific Devlopment (Property), Inc.
Pacific Harbor Capital, Inc.
FCC Holdings, Inc.
PHC Properties Corporation
PPM Energy. Inc. Sub-Group:
Atlantic Renewable Energy Corporation
Enstor, Inc.
PPM Colorado Wind Ventures, Inc.
With respect to members of the PHI Sub-Group, PHI required all subsidiaries to pay to or receive from PHI an amount of tax
based primarily on the stand-alone method of allocation. The computation includes all tax benefits from tax deductions
stemming from cost borne by utility customers.
Under MEHC:
PPW Holdings LLC Sub-Group:
PacifiCorp
PacifiCorp Sub-Group:
Centralia Mining Company
Energy West Mining Company
Glenrock Coal Company
Intermountain Geothermal Company
Interwest Mining Company
Pacific Minerals, Inc.
PacifiCorp Environmental Remediation Company
PacifiCorp Future Generations, Inc.
PacifiCorp Investment Management, Inc.
Steam Reserve Corporation
MEHC Sub-Group:
Academy of Real Estate, Inc.
Alaska Gas Transmission Company, LLC
Allerton Capital, Ltd.
American Pacific Finance Co.
American Pacific Finance Co. II
Arizona Home Services, LLC
BG Energy Holding Co., LLC
BG Energy, LLC
CalEnergy Company, Inc.
CalEnergy Generation Operating Company
CalEnergy Holdings Inc.
CalEnergy Imperial Valley Co., Inc.
CalEnergy International Services, Inc.
CalEnergy International, Inc.
CalEnergy Minerals Development LLC
CalEnergy Minerals LLC
CalEnergy Pacific Holdings Corp.
CalEnergy UK, Inc.
IFERC FORM NO.1 (ED. 12-87)
Capitol Intermediary Company
Capitol Land Exchange, Inc.
Capitol Title Company
CBEC Railway, Inc.
CBS Home Real Estate Company
CBS Home Relocation Services, Inc.
CBSHOME Real Estate ofIowa, Inc.
CE Administrative Services, Inc.
CE Electric (NY), Inc.
CE Electric, Inc.
CE Exploration Co.
CE Geothermal, Inc.
CE Geothermal, LLC
CE Indonesia Geothermal, Inc.
CE International Investments, Inc.
CE Obsidian Energy LLC
CE Obsidian Holding LLC
CE Power, Inc.
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 05/17/2007 2006/04
FOOTNOTE DATA
MEHC Sub-Group (continued):
CE Power, LLC
CE Resources, LLC
CElT A LLC
Champion Realty, Inc.
Chancellor Insurance Services, Inc.
Cimmred Leasing Company
Community Diversified Investments, Inc.
Cordova Funding Corporation
Dakota Dunes Development Company
DCCO, Inc.
Edina Financial Services, Inc.
Edina Realty Referral Network, Inc.
Edina Realty Relocation, Inc.
Edina Realty Title, Inc.
Edina Realty, Inc.
Esslinger-Wooten-Maxwell, Inc.
FFR, Inc.
First Realty, Ltd.
First Reserve Insurance, Inc.
For Rent, Inc.
HMSV Financial Services, Inc.
HN Heritage Title Holdings, LLC
HN Insurance Holdings, LLC
HN Mortgage, LLC
HN Real Estate Group, LLC
HN Real Estate Group, N., Inc.
HN Referral Corporation
HomeServices Financial Holdings, Inc.
HomeServices Financial- Iowa, LLC
HomeServices Financial, LLC
HomeServices of Alabama, Inc.
HomeServices of America, Inc.
HomeServices of California, Inc.
HomeServices of Florida, Inc.
HomeServices of Iowa, Inc.
HomeServices of Kentucky, Inc.
HomeServices of Nebraska, Inc.
HomeServices of Nevada, Inc.
HomeServices of the Carolinas, Inc.
HomeServices Pacific Northwest, Inc.
HomeServices Relocation, LLC
HSR Equity Funding, Inc.
Huff Commercial Group, LLC
Huff Insurance Group, LLC
Huff, Jim Realty, Inc.
Huff-Drees Realty, Inc.
IMO Company, Inc.
InterCoast Capital Company
InterCoast Energy Company
InterCoast Power Company
InterCoast Sierra Power Company
Intermountain Geothennal Co.
Iowa Realty Company, Inc.
Iowa Realty Insurance Agency, Inc.
Iowa Title Company, Inc.
IWG Co. 8
D. Reece Mortgage Company
S. White Associates, Inc.
JBRC, Inc.
Jenny Pruitt & Associates
JP & A, Inc.
JRHBW Realty, Inc.
Kansas City Title, Inc.
Kentucky Residential Referral Services, LLC
Kern River Funding Corporation
Kern River Gas Transmission Company
KR Acquisition I, LLC
KR Acquisition 2, LLC
KR Holding, LLC
Larabee School of Real Estate & Insurance, Inc.
M & M Ranch Acquisition Company, LLC
M & M Ranch Holding Company, LLC
Magma Generating Co. I
Magma Generating Co. II
MEC Construction Services Co.
MEHC Alaska Holding 1 , LLC
MEHC Alaska Holding 2, LLC
MEHC Insurance Services, Ltd.
MEHC Investment, Inc.
MHC Investment Company
MHC, Inc.
Mid-America Referral Network, Inc.
MidAmerican Commercial Real Estate Services, Inc.
MidAmerican Energy Company
MidAmerican Energy Holdings Company
MidAmerican Energy Machining Services, LLC
MidAmerican Funding LLC
MidAmerican Services Company
MidAmerican Transmission, LLC
Midland Escrow Services, Inc.
Midwest Capital Group, Inc.
Midwest Gas Company (inactive)
Mortgage South, LLC
MWR Capital, Inc.
Nebraska Land Title & Abstract Co
NNGC Acquistion, LLC
Northern Aurora, Inc.
Northern Natural Gas Company
Pickford Escrow Company, Inc.
Pickford Golden State Member, LLC
Pickford Holdings, LLC
Pickford Real Estate, Inc
Pickford Services Company, Inc.
Plaza Financial Services, LLC
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
MEHC Sub-Group (continued):
Plaza Mortgage Services, LLC
PPW Holding LLC
Preferred Carolinas Realty, Inc.
Preferred Carolinas Title Agency, LLC
Professional Refemal Organization, Inc.
Quad Cities Energy Company
Real Estate Links, LLC
Real Estate Referral Network, Inc.
Reece & Nichols Alliance, Inc.
Reece & Nichols Realtors, Inc.
Referral Company of North Carolina, Inc.
RHL Referral Company, LLC
Roberts Holding Company, Inc.
Roy H. Long Realty Company, Inc.
Salton Sea Minerals Corp
San Diego PCRE, Inc.
Semonin Realtors, Inc.
Southwest Relocation, LLC
The Escrow Finn
The Referral Company
Title South, LLC
Trinity Mortgage Partners, Inc
TTP, Inc. of South Dakota
Two Rivers, Inc.
United Settlement Services, LLC
Woods Bros. Realty, Inc.
With respect to members of the MEHC Sub-Group, MEHC requires all subsidiaries to pay to or receive from MEHC an
amount of tax based primarily on the stand-alone method of allocation. The computation includes all tax benefits from tax
deductions stemming from cost borne by utility customers.
Berkshire Hathaway Inc. Sub-Group:
Berkshire Hathaway Inc. (Common Parent)
21st Communities, Inc.
21st Mortgage Corporation
21st SPC, Inc.
AAS-Lunken, Inc.
Acme Brick Block and Tile, Inc.
Acme Brick Company
Acme Brick DFW, Inc.
Acme Brick Sales Company
Acme Building Brands, Inc.
Acme Investment Company
Acme Management Company
Adalet/Scott Fetzer Company
Agile Mfg, Inc.
Aiken Paint & Decorating Inc. d/b/a Park Avenue Paints
AJF Warehouse Distributors, Inc.
Alachua Tung Oil Company
Albecca Inc.
All Bilt Unifonns
Allegheny Unifonns
Alpha Cargo Motor Exress, Inc.
American Dairy Queen Corporation
American Tile Supply, Inc.
Ardent Risk Services
Ben Bridge Corporation
IFERC FORM NO.1 (ED. 12-87)
Ben Bridge Jeweler, Inc.
Benjamin Moore & Co.
Berkshire Hathaway Credit Corp.
Berkshire Hathaway Finance Corporation
Berkshire Hathaway Life Insurance Co. ofNE
BH Columbia Inc.
BH Shoe Holdings, Inc.
BHG Life Insurance Company
BHG Structured Settlements, Inc.
BHR Inc.
BHSF, Inc.
Binningham Paint Corporation d/b/a! Rainbow Paint & Decorating
Blue Chip Stamps
BNJ NetJets, Inc.
Boot Royalty Company
Borsheim Jewelry Company Inc.
Bricker-Mincolla Unifonns
Broker Market Agency, Inc.
Brookwood Insurance Company
Camp Manufacturing Company
Campbell Bausfeld/Scott Fetzer Company
Carefree/Scott Fetzer Company
Central States Indemnity Co. of Omaha
Central States of Omaha Companies, Inc.
CG Service, Inc.
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 05/17/2007 2006/04
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group:
Chippewa Shoe Company
Claims Services, Inc.
Clayton Commercial Buildings, Inc.
Clayton Homes, Inc.
CMH Capital, Inc.
CMH Hodgenville, Inc.
CMH Homes, Inc.
CMH Insurance Agency, Inc.
CMH Manufacturing West, Inc.
CMH Manufacturing, Inc.
CMH ofKY, Inc.
CMH Parks, Inc.
CMH Services, Inc.
CMH Set and Finish, Inc.
Cologne Services Corporation
Columbia Insurance Company
Command Uniforms
Commonwealth Uniforms Inc.
Continental Divide Insurance Co.
Comhusker Casualty Company
CaRT Business Services Corporation
Crescent Paint & Decorating Inc.
Criterion Insurance Agency
Crowley Garment Mfg Co Inc.
Crowley Shirt Mfg Co Inc.
CSI Life Insurance Company
CTB Credit Corp.
CTB International Corp.
CTB IP, Inc.
crn MN Investments Co. Inc.
CTB, Inc.
Cypress Insurance Company
Dairy Queen Corporate Stores, Inc.
Dairy Queen of Georgia, Inc.
Denver Brick Company
Dexter Shoe Company
DQ Funding Corporation (formerly DQ Overseas Corp.
DQ Joint Venture Stores, Inc.
DQ Managed Stores, Inc.
DQ Wholly-Owned Stores, Inc.
DQF, Inc.
DQGC, Inc.
Edmonds Material and Equipment Co.
Elm Street Corporation
Eureka Brick and Tile Company
Executive Jet Europe, Inc.
Executive Jet Management, Inc.
Expertos en Administracion, S.A. de c.v.
Fairfield Insurance Co.
Faraday Capital Limited
Farriors, Inc.
Fayette Cotton Mill, Inc.
IFERC FORM NO.(ED. 12-87)
Financial Services Plus, Inc.
First Berkshire Hathaway Life Insurance Company
FlightSafety Capital Corp.
FlightSafety China, Inc.
FlightSafety Development, Inc.
FlightSafety International Inc.
FlightSafety New York, Inc.
FlightSafety Properties, Inc.
FlightSafety Services Corporation
FlightSafety Texas, Inc.
Floors Inc.
Footwear Investment Company
Forest River Housing, Inc.
Forest River Warranty Company
Forest River, Inc.
France/Scott Fetzer Company
Freedom Warehouse Corp.
Fruit of the Loom Caribbean, Inc.
Fruit of the Loom Texas, Inc.
Fruit of the Loom Trading Company
Fruit ofthe Loom, Inc.
Fruit of the Loom, Inc.
FSI Delaware Holding Corp.
FTL Regional Sales Co., Inc.
FTL Sales Company, Inc.
Fulton Manufacturing Company
Garan Central America Corp.
Garan Incorporated
Garan Manufacturing Corp
Garan Services Corp
Gateway Underwriters Agency, Inc.
GEICO Casualty Company
GEl CO Corporation
GEICO General Insurance Company
GEl CO Indemnity Company
GEl CO Products, Inc.
Gen Plus Managers, Inc.
Gen Re Intermediaries
General Re Assets Investment (I), Inc.
General Re Assets Investment (II), Inc.
General Re Assets Investment (III), Inc.
General Re Bannockburn, Inc.
General Re Corporate Finance, Inc.
General Re Corporation
General Re Financial Products Corporation
General Re Financial Products Japan, Inc.
General Re Funding Corporation
General Re Investment Holdings Corporation
General Re New England Asset Management
General Re Securities Corporation
General Re Services Corporation
General Re Strategic Solutions
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 05/17/2007 2006/04
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group:
General Reinsurance Corporation
General Star Indemnity Company
General Star Management, Company
General Star National Insurance Company
Genesis Indemnity Insurance Company
Genesis Insurance Company
Genesis Professional Liability Underwriters
Genesis Underwriting Management Company
GenRe Gisbourne LLC
GMK, Ltd.
Golden Skillet International, Inc.
Government Employees Financial Corporation
Government Employees Insurance Company
GRD Corporation
GRD Global, Inc.
GRD Holdings Corporation
Griffey Uniforms
Brown Shoe Company, Inc.
Brown Shoe Technologies, Inc.
H.J. Justin and Sons, Inc.
Halex/Scott Fetzer Company
Hall of Fame Paint Supply Inc.
Hardy Frames, Inc.
Harris Uniforms
Harrison Uniforms
HDS Redevelopment Corporation
Helzberg s Diamond Shops, Inc.
Henley Holdings, LLC
HomefIrst Agency, Inc.
Homemakers Plaza, Inc.
Income Trust No I
Income Trust No 2
Indecor Group Inc. d/b/a lC.Licht Company
Innovative Building Products, Inc.
Insurance Counselors of Kentucky, Inc.
Insurance Counselors of Nevada, Inc.
Insurance Counselors ofTexas Inc.
Insurance Counselors Inc.
Insurance Management Services, Inc.
International Dairy Queen, Inc.
International Insurance Underwriters Inc.
Isabela Shoe Corporation
J. S. Justin, Inc.
JanoviclPlaza Inc.
Johns Manville
Johns Manville China, LTD.
Johns Manville Contracting Services, Inc.
Johns Manville Corporation
Jordan s Furniture, Inc.
Justin Belt Company, Inc.
Justin Boot Company
Justin Brands, Inc.
Justin Industries, Inc.
Kale Uniforms
Kansas Bankers Surety Company
Karmelkorn Shoppes, Inc.
Kay Uniforms
Kleberg Holdings, Inc.
Leesburg Knitting Mills, Inc.
Leesburg Yam Mills, Inc.
M & C Products, Inc.
Macro Retailing, Inc.
Mapletree Transportation, Inc.
MarineSafety International, Inc.
Martin Manufacturing Company
Martin Mills, Inc.
Maryland Ventures, Inc.
McCain Uniform Company Inc.
McLane Company, Inc.
McLane Eastern, Inc.
McLane Express, Inc.
McLane Foodservice, Inc.
McLane Mid-Atlantic, Inc.
McLane Midwest, Inc.
McLane Minnesota, Inc.
McLane New Jersey, Inc.
McLane Southern, Inc.
McLane Suneast, Inc.
McLane Western, Inc.
Medical Protective Corporation
Medical Protective Finance Corporation
Medical Protective Insurance Services, Inc.
Merit Distribution Services, Inc.
Metro Uniforms
Micro Retailing, Inc.
MiTek Framings, Inc.
MiTek Holdings, Inc.
MiTek Industries, Inc.
MiTek, Inc.
MMX Corporation
Moore s Investment Corp.
Mount Vernon Fire Insurance Company
Mountain View Marketing, Inc.
MS Property Company
MT Sub, Inc.
National Fire & Marine Insurance Co.
National Indemnity Company
National Indemnity Company of Mid-America
National Indemnity Company ofthe South
National Liability & Fire Insurance Co.
National Re Corporation
National Reinsurance Corporation
Nationwide Uniforms
Nebraska Furniture Mart, Inc.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group:
NetJets Aviation Inc.
NetJets Inc.
NetJets International Inc.
NetJets Large Aircraft, Inc.
NetJets Leasing, Inc.
NetJets M E Inc.
NetJets Sales Inc.
NetJets Services Inc.
NetJets U., Inc.
NFM of Kansas, Inc.
Nick Bloom Unifonns
NJ Executive Services Inc.
NJA Jets Inc.
NJI Sales Inc.
NJI, Inc.
Nocona Boot Company
North Star Reinsurance Corporation
North Star Syndicate, Inc.
Northern States Agency, Inc.
Northland/Scott Fetzer Company
Oak River Insurance Company
OBH Inc.
OCSAP, Ltd.
OMS Retail Services, Inc.
Opis Realty Co.
Orange Julius of America
Paint & Decorating Depot Inc.
Paint Rental Associates Inc.
Paint Town Inc.
Pima Unifonns
Pinnacle Paint & Decorating, Inc.
Plaza Financial Services Company
Plaza Investment Managers, Inc.
Plaza Paint & Decorating Centers Inc.
Plaza Resources Company
Portland Gold Corp. d/bla! Maine Paint Service
Precision Brand Products, Inc.
Precision Steel W /h-Charlotte SIC
Precision Steel Warehouse, Inc.
Pro Installations, Inc.
Professional Datasolutions, Inc.
Queen Carpet Corporation
c.Willey Home Furnishings
Rabun Apparel, Inc.
Rainbow State Paint & Decorating Inc.
Redwood Fire and Casualty Insurance Co.
Rentco Trailer Corporation
Republic Insurance Company
Resolute Management Inc.
Ringwalt & Liesche Co
Riverside Paint & Decorating, Inc.
Robert f. deCastro Inc.
Roberts Men s Shop
Safe Driver Motor Club, Inc.
Salado Sales, Inc.
Sandy Paint & Decorating Inc.
Scott Fetzer Company
Scott Fetzer Financial Group, Inc.
ScottCare Corporation
Seattle Paint Supply, Inc.
See s Candies, Inc.
See s Candy Shops, Inc.
Seventeenth Street Realty, Inc.
Shaw Contract Flooring Installation Services, Inc.
Shaw Contract Flooring Services, Inc.
Shaw Contract Properties, Inc.
Shaw Diversified Services, Inc.
Shaw Financial Services, Inc.
Shaw Floors, Inc.
Shaw Funding Company
Shaw Industries Group, Inc.(fonnerly Shaw Industries, Inc.
Shaw Industries, Inc.
Shaw Retail Properties, Inc.
Shaw Transport, Inc.
SHX Flooring, Inc.
SHX Leasing, Inc.
Silver State Unifonns
Simon s Incorporated
Sofft Shoe Company, Inc. (Fonnerly Lowell Shoe, Inc.
Sol Frank Unifonns Inc.
Somerset Acres
Southwest Paint & Decorating Inc.
Stahl/Scott Fetzer Company
Star Furniture Company
Stonyridge Trust
Strick Mexicana, S.
Technical Coatings Co.
Tekmax, Inc.
The B.D. Licensing Corp.
The Eagle Company
The Fechheimer Brothers Co.
The Indecor Group, Inc.
The Koskovich Company, Inc.
The Medical Protective Company
The Pampered Chef, Ltd.
The Village Paint Shoppe Inc.
Tony Lama Company
Top Five Club, Inc.
TPC European Holdings, Ltd.
TPC North America, Ltd.
Transco, Inc.
TTI, Inc.
S. Investment Corporation
S. Underwriters Insurance Company
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 05/17/2007 2006/04
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group:
Unified Supply Chain, Inc.
Unifonns of Texas
Union Sales, Inc.
Union Underwear Company, Inc.
Unione Italiana Reinsurance Co.of America, Inc.
United Consumer Financial Service Company
United Direct Finance Inc.
United States Aviation Underwriters, Inc.
United States Liability Insurance Company
Universal Unifonns
Vanderbilt ABS Corp.
Vanderbilt Mortgage & Finance, Inc.
Vanderbilt Property & Casualty Insurance Co., Ltd.
Vanderbilt SPC, Inc.
Virginia Paint Co., Inc.
Visilinx, Inc.
Vision Retailing
Wayne/Scott Fetzer Company
Waynesburg Shirt Company Inc.
Wesco Financial Corporation
Wesco Holdings Midwest, Inc.
Wesco-Financial Insurance Co.
West Virginia Uniforms
Western/Scott Fetzer Company
Wheeler Brick Company, Inc.
Winfield Yarn Mill, Inc. (fonnerly 2556 Industries, Inc.
Witt Brick & Supply, Inc.
WMC Corp. f/k/a Woodmarc Corporation
World Book Encyclopedia, Inc.
World Book, Inc.
World Book/Scott Fetzer Company, Inc.
Worldbook.com Inc.
CO., Inc.
XLI, inc.
XTR, Inc.
XTRA Chassis, Inc.
XTRA Companies, Inc.
XTRA Corporation
XTRA Intennodal, Inc.
XTRA International Pacific, LTD.
XTRA International, LTD.
XTRA Lease, Inc.
XTRA Mexicana, SA de C.
XTRA, Inc.
Zuckerbergs Unifonns
IFERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 262)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 05/17/2007
TAXES ACCRUED, PREPAID AND CHARGED 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 of Tax BALANCE AT BEGINNING OF YEAR ~~es ~'ff Adjust-C argedNo.(See instruction 5)Taxes Accru~9 F'repai.d Taxes ~nng ~ring ments(Account 236)(Include In Account 165)ear ear(a)(b)(c)(d)(e)(1)
Federal:
Income 123,864 131 621 605 194 825,942 35,379 254
FICA 33,180 366 852 795
Unemployment 322 764 371,812 693,404
Unemployment - Energy 390 209,531 179,073
Unemployment - Interwest 22,633 029 405
Excise Tax - Coal 232,466 149 827 249,803
8 Subtotal 528,611 169 535,170 232,825,422 35,379,254
State:
Arizona:
Property 952,458 890,336 897,626
Income 739 173,216 465,832 152,366
Subtotal 882,719 063,552 363,458 152,366
Califomia:
Property 678,556 678,556
Unemployment 23,511 22,119
Franchise-Income 750,490 469,688 722,179 -413,151
Regulatory Commission 257 47,257
Use 297 241 136 204 054
Local Franchise 637 179 881 314 841,362
Subtotal 398,966 341 ,462 515,527 413 151
Colorado:
Property 230 000 1,486 605 964,605
Income 69,035 102,941 258,280 550
Subtotal 160,965 589,546 222,885 90,550
Idaho:
Property 723,609 521 336 775,979
Income 103 914 897 924 380,624 789,840
KWh 500 733 25,733
Unemployment 43,254 353
Regulatory Commission 310,524 310,524
Use 825 186 878 162 717
Subtotal 829 848 985,649 696,930 789,840
TOTAL 310,489 683,453 303,689,962 378,439,907 24,450,391
FERC FORM NO.1 (ED. 12-96)Page 262
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 05/17/2007
TAXES ACCRUED, PREPAID AND CHARGED DURING 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 409.1 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 AajUstments to He!.Other No.
ACCO
~m 236)
(lncl. in Account 165)(Account 408., 409.(AccQunt409.Earnings (Account 439)
(h)(i)
(j)
(k)(I)
38,948,947 106,778 946
352,142 571
172
848
257
132,490
533 909 38,973,518 106,778,946 62,756,224
945,168 890 336
514,721 126,354
945 168 514 721 016,690 46,862
653,010
392
84,848 342,619
, .
379
677,131 881 314
726,902 848 876,943 464,519
752 000 1,485 919
314 924 75,092
752,000 314,924 561,011 28,535
1,468,966 519,236
168 626 655 001
500 25,733
901
' ,
25,986
1,497 353 168,626 199,970 785,679
123,323 795 841 216,903 727 86,786,235
FERC FORM NO.1 (ED. 12-96)Page 263
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) riA Resubmission 05/17/2007
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Ine Kind ofTax BALANCE AT BEGINNING OF YEAR ~1~es Adjust-C argedNo.(See instruction 5)\axesAcc~~t-:repato I axes ~nng ~ring ments(Account 236)(Include In Account 165)ear ear
(a)(b)(c)(d)(e)(I)
3 Montana:
Property 166,308 522,165 2,425,273
Corporate License-Income 128,683 121 608 186 981 106,970
Energy License 60,583 220,218 222 342
Wholesale Energy 132 152,507 153,960
8 Subtotal 140,340 016,498 988,556 106,970
Nevada:
Unemployment
Subtotal
New Mexico:
Property 534 10,794 931
Subtotal 534 10,794 931
Oregon:
Property 7,486,422 620,763 16,245 391
Unemployment 083,279 054,269
Wilsonville Payroll 513 864
Regulatory Commission 375,865 375,865
Excise-Income 141,030 226,681 11,823,403 -4,591 ,174
City of Portland-Income 178,191 84,549 290.001 372
Office of Energy 197,031 400,600 407 138
Tri-Met 189.592 828,256
Lane County 087 087
Franchise 765,697 175,609 18,135,906
Subtotal 15,084,918 683,453 162,538 165,180 -4,665,546
Texas:
Unemployment
Subtotal
Utah:
Property 237,460 33,372,117 33,320.984
Income 3,473,553 385,074 292,943 710,440
Unemployment 496,271 478,603
Regulatory Commission 236,595 236,595
Navajo Nation 034 034
TOTAL 310,489 683,453 303,689 962 378,439,907 24,450 391
FERC FORM NO.1 (ED. 12-96)Page 262.
Name of Respondent This R~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) riA Resubmission 05/17/2007
TAXES ACCRUED, PREPAID AND CHARGED DURING 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 409.1 pertaining
to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and amounts charged
to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items AdjUstments to "ReI.Other No.
ACCO
~m 236)
(Incl. in Account 165)(Account 408., 409.(Account 409.EamlOgs (Account 439)
(h)(i)(k)(I)
263,200 522 165
301 026 708
58,459 220,218
40,679 152,507
1 ,362,338 301 026 983 598 900
397 10,794
397 794
111 050 15,533,930
29,010
649
953,134 812,660
101 633 61,675
' ,
203,569 400,600
361 336
805 400 18,175,609
196 395 7,463,118 984,474 178 064
288,593 30,921,751
144 756 928,201
668
034
123,323 795,841 216,903,727 86,786,235
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 2006/04
(2) riA Resubmission 05/17/2007
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Ine Kind of Tax BALANCE AT BEGINNING OF YEAR ~11fes
~~S Adjust-C argedNo.(See instruction 5)Taxes AccruE:!9 prepai,d Taxes ~nng
~~~g
ments(Account 236)(Include In Account 165)ear
(a)(b) (c)(d)(e)(I)
Use 312,327 091 048 106 084
Gross Receipts 2,476 174 962,307 973,679
3 Subtotal 6,499,514 50,545,446 53,410,922 710,440
5 Washington:
Property 518,835 160,339 329,174
Unemployment 79,306 77,350
Business & Occupation 077 390 20,395
Public Utility 538,837 327 238 145,849
Regulatory Commission 410,193 410,193
Use 104,603 734,281 598,067
Retailing 167 167
Land Tax
Subtotal 955 175 12,732,969 581 250
Washington D.
Unemployment 117 117
Subtotal 117 117
Wyoming:
Property 3,489,468 648,619 555,846
Property - Glenrock 58,024 58,024
Unemployment 138 603 136 155
Other Payroll Taxes -429 -429
Regulatory Commission 874 005 874 005
Franchise 171 900 256,486 240,586
Use 93,152 437,643 391,123
Annual Report 35,352 35,352
Subtotal 812 544 11,390,279 11 ,290,662
Miscellaneous:
Goshute Possessory 297 297
Sho-Ban Possessory 133,242 133,242
Navajo Possessory 15,909 32,905 32,362
Ute Possessory 543 543
Crow Possessory 25,627 294 82,921
Umatilla 53,423 53,423
Misc. Sales & Use Tax Provo 041 023,191 051 232
Subtotal 69,577 315,895 369,020
TOTAL 27,310,489 683 453 303,689,962 378,439,907 24,450,391
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 2006/04
(2) EjA Resubmission 05/17/2007
TAXES ACCRUED, PREPAID AND CHARGED DURING 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 409.1 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 AOI-on~ to Hot,
ACCO
~m 236)
(Incl. in Account 165)(Account408.409.(Account 409.EamIOgs (Account 439) t er
(h)(i)
(j)
(k) (I)
297,291
464,802 962 307
068,354 144 756 38,814 293 731 153
350 000 031,880
956
072 21,390
720,226 327 238
31,611
167
106,894 380,730 352 239
117
582 241 644,795
448
-429
187,800 256,486
139,672
35,352
912,161 936,204 2,454 075
297
133,242
16,452 905
543
294
53,423
370
'" '' "
16,452 360 074 955,821
123,323 795 841 216,903,727 86,786 235
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 05/17/2007 2006/04
FOOTNOTE DATA
~chedule Page: 262 Line No.Column:!
ederal Income Tax - Other Income & Deductions - 409.
~chedule Page: 262 Line No.Column: I
Taxes a licable to Other Income & Deductions - 408.2 & 409.2
Schedule Pa e: 262 Line No.Column: I
Various Operations and Maintenance Accounts.
ISchedule Page: 262 Line No.Column: I
Various Operations and Maintenance Accounts.
~chedule Page: 262 Line No.Column: I
Various 0 erations and Maintenance Accounts.
chedule Page: 262 Line No.Column: I
Fuel Invento - 151
chedule Pa e: 262 Line No.14 Column: I
tate Income Tax - Other Income & Deductions - 409.2
~chedule Page: 262 Line No.18 Column: I
Account
Taxes applicable to Other Income & Deduction - 408.2 & 409.2
Distribution Rent Expense, Rents - 589
Total
Amount
$ 23 796
750
$ 25 546
~chedule Page: 262 Line No.19 Column: I
Various 0 erations and Maintenance Accounts.
chedule Pa e: 262 Line No.20 Column: I
State Income Tax - Other Income & Deductions - 409.
~chedule Page: 262 Line No.21 Column: IRe latory Commission E ense Account - 928.
chedule Page: 262 Line No.22 Column: I
learing Account - 184.
~chedule Page: 262 Line No.27 Column: I
axes applicable to Other Income & Deductions - 408.2 & 409.
~chedule Page: 262 Line No.28 Column: I
State Income Tax - Other Income & Deductions - 409.2
~chedule Page: 262 Line No.32 Column: I
axes applicable to Other Income & Deductions - 408.2 & 409.
~chedule Page: 262 Line No.33 Column: I
tate Income Tax - Other Income & Deductions - 409.2
~chedule Page: 262 Line No.35 Column: I
Various 0 erations and Maintenance Accounts.
chedule Pa e: 262 Line No.36 Column: I
Regulatory Commission Expense Account - 928.2
~chedule Page: 262 Line No.37 Column: I
Clearing Account - 184.
ISchedule Page: 262.Line No.Column: I
tate Income Tax - Other Income & Deductions - 409.
~chedule Page: 262.Line No.11 Column: I
Various 0 erations and Maintenance Accounts.
chedule Pa e: 262.Line No.19 Column: I
Account
Taxes applicable to Other Income & Deduction - 408.2 & 409.
Distribution Rent Expense, Rents - 589
Total
IFERC FORM NO.1 (ED. 12-87)
Amount
$ 38 102
731
$ 86 833
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 05/17/2007 2006/04
FOOTNOTE DATA
rschedule Page: 262.Line No.20 Column: I
Various Operations and Maintenance Accounts.
ISchedule Page: 262.Line No.21 Column: I
arious Operations and Maintenance Accounts.
~chedule Page: 262.1Line No.22 Column: I
Regulatory Commission Ex ense Account - 928.2
chedule Page: 262.Line No.23 Column: I
State Income Tax - Other Income & Deductions - 409.2
~chedule Page: 262.Line No.24 Column: I
tate Income Tax - Other Income & Deductions - 409.
~chedule Page: 262.Line No.26 Column: I
Various 0 erations and Maintenance Accounts.
Schedule Pa e: 262.Line No.27 Column: I
Various 0 erations and Maintenance Accounts.
chedule Page: 262.Line No.32 Column: I
Various 0 erations and Maintenance Accounts.
Schedule Page: 262.Line No.36 Column: I
Account
Taxes applicable to Other Income & Deduction - 408.2 & 409.
Construction - 107
Total
Amount
$ 14 400
2.435.966
$ 2 450 366
~chedule Page: 262.Line No.37 Column: I
tate Income Tax - Other Income & Deductions - 409.2
~chedule Page: 262.Line No.38 Column: I
Various erations and Maintenance Accounts.
chedule Page: 262.Line No.39 Column: I
erations and Maintenance Ex ense - 401 & 402.
chedule Page: 262.Line No.Column: I
Clearing Account - 184.
~chedule Page: 262.Line No.Column: I
Account
Taxes applicable to Other Income & Deduction - 408.2 & 409.2
Distribution Rent Expense, Rents - 589
Total
Amount
$ 125 329
130
$ 128 459
~chedule Page: 262.Line No.Column: I
Various 0 erations and Maintenance Accounts.
Schedule Page: 262.Line No.10 Column: I
Regulatory Commission Expense Account - 928.2
~chedule Page: 262.Line No.11 Column: I
Clearin Account - 184.
Schedule Page: 262.Line No.17 Column: I
Various Operations and Maintenance Accounts.
~chedule Page: 26?~
~__
jpe No..;.~L_~olumn: I
Account
Taxes applicable to Other Income & Deduction - 408.2 & 409.2
Distribution Rent Expense, Rents - 589
Total
Amount
240
584$ 3 824
~urepa-.~~~I~f!.!L~~~=fi)lu mn:
IFERC FORM NO.1 (ED. 12-87)
--,------"'~-----,
.---J
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 05/17/2007 2006/04
FOOTNOTE DATA
Various Operations and Maintenance Accounts.
~chedule Page: 262.Line No.25 Column:
egulatory Commission Expense Account - 928.
~chedule Page: 262.Line No.27 Column:
learing Account - 184.
~chedule Page: 262.Line No.38 Column:
Various Operations and Maintenance Accounts.
IFERC FORM NO.1 (ED. 12-87) Page 450.
Blank Page
(Next Page is: 266)
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 05/17/2007
ACCUMULA ED DEFERRED INVESTMENT TAX CREDITS (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.
Ine Account
No.Subd
l~~sions
of Year Deferred for Year Current Year s Income Adjustments(b) ACCOUI)! 1'110. p\moum ACCOUl)t NO. Amount
( )
(c) (d) (e) (I)
1 Electric Utility
23%
34%
47%
510%52,197 285 411.4 789,42~
7 Idaho 974,201 411.4 65,43€
8 TOTAL 53,171 ,486 854,86C
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10%436,574 420 O65,26C
Total Nonutility 16,436,574 O65,26C
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) riA Resubmission 05/17/2007
ACCUMULATED D FERRED INVESTMENT TAX CREDI S (Account 255) (continuea)
ADJUSTMENT EXPLANATION Lineof Year of AI ocatlon No.to Income
46,407,861
908,765
47,316,626
14,371,314
371 314
FERC FORM NO.1 (ED. 12-89)Page 267
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 05/17/2007
0 HER DEFFERED CREDITS (Account 253)
1. Report below the particulars (details) called for conceming o~her 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)(1)
Cogeneration Bonds - Sunnyside 413,417 413,417
Working Capital Deposit DG&T 159,359 93,938 253,297
Working Capital and Coal Pile
Deposits from Provo City 273,000 273,000
Working capital deposit from UAMPS 433,000 143 188,000 245,000
Reclamation Costs - Trapper Mine 533,600 232,882 766,482
Reclamation Costs - Deseret Mine 744,697 131 190,054 554,643
Reclamation Costs - Trail
Mountain Mine 146,738 146,738
Deferred Compensation - PPL 241,153 124 761 547 2,479,606
Transmission Service Deposit 563,098 68,850 631 948
Def. Credits - Pricing Dispute 972 498 447 589 968 309 189
MCI F.G. wire lease 837,603 454 278,925 558,678
Redding Contract 500,060 456 549,996 950,064
Foote Creek Contract 1 ,255 862 142 137 640 118,222
Environmental Liabilities -
Centralia Plant 483,942 401 402 329,112 154,830
Environmental Liabilities -
Centralia Mine 160,578 66,670 227 248
Wyoming Joint Powers Water
Board Settlement 275,000 232 300,000 975,000
Compensation Reduction 10,428,974 563,665 15,992,639
Uneamed Joint Use Pole Contract 759,453 454 239 170 520,283
Oregon DSM Loans NPV Unearned 017 823 456, 431 328,868 688,955
Exec Trust Comp Reduction Plan -
SPI Stock 069,938 123 124 069,938
TOTAL 591,991 17,759,489 17,959,011 791 513
FERC FORM NO.1 (ED. 12-94)Page 269
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 05/17/2007
0 HER DEFFERED CREDITS (Account 253)
1. Report below the particulars (details) called for conceming o~her 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.
Une 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)
Miscellaneous Security Deposits 300 712 012
Environmental Liabilities -
Non-Current 766,274 865,476 631,750
Deseret Power Security Deposits 511 328 397 535,725
Deferred Revenue -
Lease Incentives 421 151 931 62,756 358,395
Other Deferred Credits - C& T 623,145 555 883,400 739,745
Software License Payments 064,748 064,748
Deferred Revenue -
Duke/Hermiston Gas Sale 547 471 774 900 000 3,428,226
Other Deferred Credits 55,673 55,673
TOTAL 61,591,991 17,759,489 17,959,011 61,791,513
FERC FORM NO.1 (ED. 12-94)Page 269.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED A ORTIZATION PROPERTY (Account 281)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to amortizable
property.
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line
No.
Account Balance at
Beginning of Year
(a)
1 Accelerated Amortization (Account 281
2 Electric
(b)
Amounts Debited
to Account 410.
(c)
Amounts Credited
to Account 411.
(d)
3 Defense Facilities
4 Pollution Control Facilities
634,485 334,312
5 Other (provide details in footnote):
8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
634,485 334,312
10 Defense Facilities
11 Pollution Control Facilities
12 Other (provide details in footnote):
15 TOTAL Gas (Enter Total of lines 10 thru 14)
17 TOTAL (Acct 281) (Total of 8,15 and 16)
18 Classification of TOTAL
19 Federal Income Tax
634,485 334,312
20 State Income Tax
21 Local Income Tax
558,580
905
294,318
39,994
NOTES
FERC FORM NO.1 (ED. 12-96)Page 272
This ~rt Is: Date of Report YearlPeriod of Report
(1) ~An Original (Mo, Da, Yr) End of 2006/04(2) A Resubmission 05/17/2007
ACCUMULATED DEFERRED INCOME TAXES ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued)
3. Use footnotes as required.
Name of Respondent
PacifiCorp
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.Debits
300,173
300,173
300,173
264,262
911
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 273
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
ACCUMULATE DEFFERED INCOME TAXES - OTH R PROPERTY (Account 282)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to property not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line
No.
Account Balance at
Beginning of Year
(a)(b)
Amounts Debited
to Account 410.
(c)
Amounts Credited
to Account 411.
(d)
1 Account 282
2 Electric 504,205,263 320,378,764 334,809,374
3 Gas
4 FAS 109
5 TOTAL (Enter Total of lines 2 thru 4)
6 Nonutility
485,147 153
989 352,416
7,497 530
320,378,764 334 809 374
220,604
9 TOTAL Account 282 (Enter Total of lines 5 thru 8)
10 Classification of TOTAL
11 Federal Income Tax
981,854,886 320,378,764 335,029,978
744,769,666 282 052 512 294 951 031
237 085 220 38,326,252 40,078,94712 State Income Tax
13 Local Income Tax
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.Debits
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 275
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
ACCUMU TED DEFFERED INCOME TAXES - THER (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 2006/04
Name of Respondent
PacifiCorp
(a)
Balance at
Beginning of Year
(b)
Line
No.
Account
1 Account 283
2 Electric
3 Regulatory Assets 162 604 656 23,008 044 39,705,422
5 Derivative Contracts
6 PMI Deferred Liabilities 400,396
167 897,026
60,001 551
76,989,611
587 176
782,496
881,334
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
17 TOTAL Gas (Total of lines 11 thru16)
19 TOTAL (Acct 283) (Enter Total of lines 9,17 and 18)
20 Classification of TOTAL
21 Federal Income Tax
330 902 078 159,999.206 199,956,428
291 315 901 140,858,830 176,036,052
586 177 19,140,376 23,920 37622 State Income Tax
23 Local Income Tax
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/04
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.
114 801,855
464 900
218,156,606
29,643 859
427 515,994
376,372,094
51,143,900
118,179,801 59,789,767 169,619,361
104,042,195 52,637,240 149,328,146
137 606 152 527 20,291 215
247,800,465
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 Res\.lbmission 05/17/2007 2006/Q4
FOOTNOTE DATA
~chedule Page: 276
Other Deferred Liabilities:
Line No.
DTL 205.100 Coal Pile Inventory Adj.
DTL 205.200 Coal M&S Inventory Write-Off
DTL 110.100 Book Depletion
DTL 425.250 TGS Buyout
DTL 425.260 Lakeview Buyout
DTL 425.280 Joseph Settlement
DTL 425.340 Firth Cogen Settlement
DTL 425.320 Umpqua Settlement Agreement
DTL 910.240 Legal Reserve
DTL 210.100 Prepaid Taxes - OR PUC
DTL 210.120 Prepaid Taxes - UT PUC
DTL 210.130 Prepaid Taxes - ID PUC
DTL 210.140 Prepaid Taxes - WY PSC
DTL 210.160 Prepaid Taxes - OR Property
DTL 210.180 Prepaid Membership Fees-
EEI WSCC
DTL 210.200 Prepaid Property Taxes
DTL 210.000 Prepaid Ins. Cont Reserve
DTL 740.100 Post Merger Loss-Reacq. Debt
DTL 320.210 R & E - Sec.174 Deduction
DTL 720.600 FASI 15 Mark to Mark Accrual
DTL 425.360 Henniston Swap
DTL 730.150 Weather Derivatives
DTL 730.180 Aquila Weather Hedge
DTL 61O.150N NOPA 98 99-00 RAR
DTL 61O.065N NOPA 11999-00 RAR
DTL 6 1O.005N SEC 17494-98 & 99-00 RAR
DTL 610.095 N Roll (not Ptax) 99-00 RAR
DTL 425.310 Hydro Relicensing Obligation
DTL 605.710 Reverse Accrued Final Reclass
DTL 605.710 Reverse Accrued Final Reclamation
DTL 135.300 Deferred Comp - ExSop
DTL 415.637 Min. Pension Liability Adj.
DTL 720.900 Min SERP Liab. OCI
DTL 425.300 Mead Phoenix Availability&T
DTL 330, 100 PollutionControlFacility(Bk
DTL 605.200 WY Joint Water Board Reserve
DTL 920.120 Investment in SPI
DTL 705.190 Oregon Share of Henniston
DTL 425.380 Idaho Customer Balancing Ac
DTL Flowthrough Partnership Income
DTL 505.115 Sales & Use Tax Accrual
DTL 105.4143/165 Basis Diff-Intangibles
DTL 415,803 RTO Grid West NIR-W/O-
DTL 425.205 Misc DefDr-Prop Damage Repairs
DTL 730.110 FAS 133 Derivatives
Total
/Schedule Page: 276
Account 219
Account 236
Account 282
Account 190
Line No.
Column:
Balance At Amounts Amounts Amounts Amounts Adjustment Balance at End
Beginning of Debited to Credited to Debited to Credited to Amounts of Year
Year Account41O.1 Account411.l Account41O.2 Account411.2
459 937 $353,489 $142 $
- $- $- $
782 284
833 587 004 652 838 239
952 313 952 313
107 277 830
962 743 219
669 096 240 577 856
126 399 126 399
017 017
002 002
896,7 10 826 939 498 233 225,416
277 643 438 323 101 806 614,160
155 39,848 080 923
800 144 462 230 262
1,437 274 1,437 274
628 086 628 086
712,590 195 302 907 892
126 778 864 914
178 566 469 355 9,709 211
146 366 2,466 478 649 723 963 121
903 273 234 380 666 811 082
320 763 358 352 962 411
339 339
698 839 698 839
427 427
877 041 877 041
124 544 124 544
283 152 333,461 338 071 278 542
364 679 364 679
067 991 914 010 982 001
910 693 910 693
194 841 194 841
146 951 710 396 710 396 9,146 951
298 135 596 269 (298 134)
045,169 045 169
147 237 217 287 929 950
464 900 464 900
874 961 197 237 311 994 760 204
156 156
793 515 793 515
058 884 058 884
302,116 302 116
351 087 351 087
165 165
826 826
502 868 502 868
$ 167 897 026 $989 611 $ 78 881,334 $464 900 $462 070 $513,101 $67,495 032
Column: g
IFERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 278)
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) nOriginal (Mo, Da, Yr)End of 2006/04
(2) CiA Resubmission 05/17/2007
0 HER REGULATORY LIABILITIES (Account 254)
1. Report below the particulars (details) called for conc~rning other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $50 000 which ever is less),may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining DEBITS Balance at End
Line Description and Purpose of of Current of Current
No.Other Regulatory Liabilities OuarterNear ~ccount Amount Credits OuarterNearCredited
(a)(b)(c)(d)(e)(f)
FAS 109 Regulatory Liability 701 959 190 157 334 25,544 625
OR Gain on Sale of Assets 126,839 36,929 163,768
Property Insurance Reserve 551 611 228, 924 317 199 998 702 233,114
SMUD Revenue Imputation 904,888 440, 442 449,056 570 914 28,026,746
Oregon Rate Refund 79,969 79,971
Utah Home Energy Lneline 743,760 142 584396 832 150 -8,486
BPA Washington Balancing Account 386,383 440,442 189,701 132,673 329,355
BPA Oregon Balancing Account 963521 440, 442 792,086 678 756 13,850,191
BPA Idaho Balancing Account 622,244 291,336 913,580
ARO/Reg Dilf - Deer Creek Mine Reclamation 394400 230 802 166 852 461 450
ARO/Reg Dilf - Trojan Nuclear Plant 947,308 230 113 521 833,787
FAS 109 - WA Flow Through 959 445 381.770 22,341,215
West Valley Lease Reduction - WA 342758 342 758
West Valley Lease Reduction - OR 182.083,689 083,689
West Valley Lease Reduction - CA 145 145
West Valley Lease Reduction -274 125 274,125
West Valley Lease Reduction - WY 608,494 608,494
West Valley Lease Reduction - UT 182.85,095 449,556 364,461
A& G Credit - WA 385,804 385,804
A&GCred~-370,920 370 920
A& G Cred~.125,169 125,169
A & G Credn-lD 277319 277,319
A& G Cred~- WY 619,940 619,940
Regulatory Liability - Reclass 299592 791,
Washington Low Income Program 146 064 142 805,414 590,476 68,874
FAS 133 - Derivative Net Reg Liability 92,296,078 182.3, 175 92,296,078
Reg Liability - OR Consolidated 196,540 456 080,916 115,624
TOTAL 198,320,601 116,425,207 087 516 109,982,910
FERC FORM NO. 1/3-(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 (2)A Resubmi&sion 05/17/2007 2006/Q4
FOOTNOTE DATA
!schedule Page: 278 Line No.24 Column:
The following is a reconciliation of the regulatory liability reclassification account:
Reclassified from Regulatory Assets to Regulatory Liabilities:
California DSM Regulatory Asset
Washington DSM Regulatory Asset
221 525
791 744
874
486
090 629
Reclassified from Regulatory Liabilities to Regulatory Assets:
Washington Low Income Program
Utah Home Energy Lifeline (11)
IFERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
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 footnote.
Year/Period of Report
End of 2006/04
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no Quarterly)
(c)
Une
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
917,467,966
828,823,262
18,427 832
16,659,617
858,409,269
775,094 563
17,038,050
17,353,876
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
847,007,472
750 904,692
597,912,164
636 741 080
616 037,278
252,778,358
597,912,164 252,778,358
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
910,738
288,827
15,228
535,245
681 519
19,392,877 29,072 161
22 (456.1) Revenues from Transmission of Electricity of Others
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
514,879
41,246,494
143 884,805
26 TOTAL Other Operating Revenues
Z7 TOTAL Electric Operating Revenues
149,369,043 186,173,730
438,952 088
FERC FORM NO. 1/3-Q (REV. 12-05)Page 300
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/Q4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
E ECTRIC OPERATING REVENUES (Account 400)
5. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by
the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of
classification in a footnote.
6. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
7. For lines 2,4,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
8. Include unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)(d) (e)
AVG.NO. CUSTOMERS PER MONTH Line
Current Year (no Quarterly) Previous Year (no Quarterly) No.(I)
(g)
15,397,126 768,597 199,474 194,933
20,471 544 19,601,466 34,099 34,235
149,401 165,692 258 271
444 665 460 326
797 337 646,202 649,447 613,112
13,656,537 13,274 441
65,453,874 62,920,643 649,447 613,112
65,453,874 920,643 649,447 613,112
Line 12, column (b) includes $
Line 12, column (d) includes
177,642,000
217 145
of unbilled revenues.
MWH relating to unbilled revenues
FERC FORM NO. 1/3-(REV. 12-05)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 05/17/2007 2006/04
FOOTNOTE DATA
Page 300 Page 304 Variance
Year ended Year ended Year ended
December 31 December 31 December 31
2006 2006 2006
$ 1 065 628 795 $ 1 065 628 795
917,467 966 917,467 966
828 823 262 828 823 262 (a)
18,427 832 427 832
659 617 659 617
Sales of Electricity
Residential Sales - Account (440)
Commercial and Industrial Sales - Account (442)
Small (Commercial)
Large (Industrial)
Public Street and Highway Lighting - Account (444)
Other Sales to Public Authorities - Account (445)
Sales to Railroads and Railways - Account (446)
Interdepartmental Sales - Account (448)
Total Sales to Ultimate Consumers 847 007 472 847 007 472
750 904 692 750 904 692 (b)
597 912 164 847 007 472 750 904 692
Sales for Resale - Account (447)
Total Sales of Electricity
(less) Provision for Rate Refunds - Account (449.1)
Total Revenues Net of Provisions for Refunds 597 912 164 847 007,472
910 738 910 738
288 827 288 827
228 228
392 877 392 877
514 879 71,465,755
246 494 246,494
$ 3 747 281 207 $ 2 991 327 391
750 904 692
Other Operating Revenues
Forfeited Discounts - Account (450)
Miscellaneous Service Revenues - Account (451)
Sales of Water and Water Power - Account (453)
Rent from Electric Property - Account (454)
Interdepartmental Rents - Account (455)
Other Electric Revenues - Account (456)
Revenues from Transmission of Electricity of Others (456.
049 124 (c)
(0)
$ 755 953 816Total Operating Revenues
(a) The large industrial line on page 300 includes account 442.2 Industrial Sales of $770 600 712 and account 442.3 lITigation Sales of $58 222 550.
(b) Sales for Resale are not included on page 304 Revenue by Rate Schedule.
(c) Other Electric Revenues on page 300 includes steam sales of$5 049 124 not included on page 304 Revenue by Rate Schedule.
~chedule Page: 300 Line No.Column:
The following table is a reconcilation of the unbilled revenue accrual ar December 31, 2006 and the reversal of the December 31 , 2005
unbilled revenue accrual.
Cun-ent year unbilled revenue accrual
Prior year unbilled revenue accrual reversal
December 31
2006
177 642 000
(169 648,000)
Change In Unbilled Revenue Accrual 994 000
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/Q4
FOOTNOTE DATA
~chedu'e Page: 300 Line No.Column: MWH
The following table is a reconcilation of the unbilled MWH accrual ar December 31 , 2006 and the reversal of the December 31, 2005
unbilled MWH accrual.
Current year unbilled MWH accrual
Prior year unbilled MWH accrual reversal
December 3 1
2006
217 145
108 165)
Change in MWH Accrual 108 980
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2006/Q4(2) nA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC-IEDULES
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.
1L.lne NUmDer ana (me OJ Hate scneaUie Mwn ~ola Hevenue Average Numcer rswn: OTS'aIes ~6~~krNo.(a)(b)(c)of cu(~omers Per y::,stomer
(f)
1 Residential Sales
2 CA
3 06CHCKoooR-CA RES CHECK M
4 06LNX00102-LlNE EXT 80% G
5 06LNXOO109-REF/NREF ADV +769
6 06NETMT135 - CA RES NET 556 10,500 0882
7 060AL T015R-OUTD AR LGT SR 381 774 406 938 1753
06RESDOOOD-RES SRVC 210,880 18,096,870 20,077 10,504 0858
06RESDDC7A-CA RES CLEAN A -425 36,186 0851
06RESDDL06-CA LOW INCOME 83,492 183,110 481 161 0741
06RESDDM9M-MUL TI FAMILY 407 32,800 33,917 0806
06RESDDS8M-MUL TI FAM SBMET 396 105,453 250 0755
1::ACQUISITION COMMITMENT-A and 63,957
ACQUISITION 38,737
CAALT RATE FOR ENERGY 538,151
SMUD REVENUE IMPUTATIONS 83,134
06RESDooDN - CA RES SRVC -102,853 721 246 633 13,475 0848
UNBILLED REV - UNCOLLECTIBLE 000
UNBILLED REVENUE 338 000 0575
07LNX00010-MNTHL Y 8O%GUAR 976
07LNX00035-ADV 8O%MO GUAR 762
07LNXOO107-SUBDIV ADV+AIC 094
07NETMT135 - ID RESIDENTIAL 735 14,000 0525
07NETMT135 -ID RES NET 261
070ALCO007-CUST OWN LIGHT 054 10,000 2054
070AL T007R-SECURITY AR LG 970 647 2700
070ALT07AR-SECURITY AR LG 115 26,093 148 777 2269
070AL T07 AR-SECURITY AR LG 216
07RESD0001-RES SRVC 368,703 30,941 591 176 918 0839
07RESDOOO1-RES SRVC 084,935
07RESDO036-RES SRVC-OPTIO 313 097 21,208,470 16,295 19,214 0677
07RESD0036-RES SRVC-OPTIO 016,464
BPA BALANCING ACCOUNT 711 847
UNBILLED REV - UNCOLLECTIBLE 000
ACQUISITION COMMITMENT-A and 65,980
ACQUISITION 63,051
UNBILLED REVENUE -4,411 274 000 0621
01CHCKOOOR-RES CHECK MTR
TOTAL Billed 51,688,35 2,983,333,391 0577
Total Unbilled Rev.(See Instr. 6)
~~~::~~
073-4
TOTAL 057E
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 2006/Q4(2) riA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC-IEDULES
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.
Ine I'lumoer ana Ime OJ Male scneaUle IVIVVII tiOIO Hevenue Average I'liumoer 'S,wn OT :;sales ~6~~krNo.(a)(b)(c)of cu(~omers Per 9~stomer
(f)
1 01 COSTOOO4 - 01 RESDOOO4 395,788 194,299 986 0360
2 01 HABITOO4 - 01 RESDOOO4 367 095 727 0349
3 01LNXO0102-LlNE EXT 80% G 029
4 01LNX00105-CNTRCT $ MIN G
5 01LNX00109-REF/NREF ADV +576
6 01NETMT135-NET METERING 105,730 249
01NETMT135-NET METERING 25,422
010ALT014R-OUTD AR LGT RE 092 383 712 157 979 1241
9 010ALT014R-0UTD AR LGT RE 28,782
01 PTOUooO4 - 01 RESDOOO4 18,613 667,455 0359
01 RENEWOO4 - 01 RESDOOO4 127 079 374 225 0344
01 RESDOOO4-RES SRVC 235,476,494 459 742 871.6646
01 RESD0004-RES SRVC 189,350
01 RESD004T - RES Time Option 780,362 186
01 RESDOO4T - RES Time Option 173,449
01 UPPLOOOR-BASE SCH FALL
01ZZMERGCR-MERGER CREDITS
ACQUISITION COMMITMENT-A and 551 819
ACQUISITION -422 382
BPA BALANCING ACCOUNT 834 153
OR SB408 RECOVERY 767 157
SMUD REVENUE IMPUTATIONS 017,435
UNBILLED REV - UNCOLLECTIBLE 46,000
UNBILLED REVENUE 22,435 1,416 000 0631
08BLSKY01 R-BLUESKY ENERGY
08CFROOO01-MTH FACILITY S 1 ,409
08CHCKOOOR-UT RES CHECK M
08COOLKPRR - Utah Cool Keeper 60,181
08LNXOOOO1-MTHL Y 80% GUAR 107
08LNXOOO05-MTHL Y MIN GUAR 240
08LNXOO013-80% MNTHL Y MIN 631
08LNXOOO16 - 80% annual guarantee 044
08LNX00108-ANN COST MTHL Y 921
08MHTPO025-MOBILE HOME &11,189 671 125 017,182 0600
08NETMT135 - Net Metering 505 36,773 645 0728
080AL T007R-SECURITY AR LG 985 704 242 425 872 2359
08PTLDOooR-POST TOP LIGHT 224 16,802 394 0750
08RESDO001-RES SRVC 922.745 442,343 598 643,905 198 0747
08RESDO002-RES SRVC-OPTIO 2,464 180,980 293 8,410 0734
TOTAL Billed 688 35 2 983,333,391 057/
Total Unbilled Rev.(See Instr. 6)108 0734
TOTAL 797 33 2,991,327,391 0578
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 2006/Q4(2) nA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Ine Numoer ano Ime or Hate scneaUie Mvvn ~ola Hevenue Average"Numcer KWnot ~ales ~6~~rderNo.(a)(b)(c)of Cu
fchomers
Per 9:f,stomer
(I)
1 08RESDOOO3-LlFELINE PRGRM 180,986 13,296,086 23,761 617 0735
2 08RFND1999-UTAH RATE RFND
3 08UPPLOooR-BASE SCH FALL
4 08ZZMERGCR-MERGER CREDITS
5 ACQUISITION 372,273
6 SMUD REVENUE IMPUTATIONS 015,270
7 UNBILLED REV - UNCOLLECTIBLE 32,OOC
8 UNBILLED REVENUE 18,199 692,000 0930
02LNX00109-REF/NREF ADV +1 ,421
020AL T013R-W A oum AR LGT 881 110,253 292 682 1251
020AL T013R-W A OUTD AR LGT 947
020ALT015R-WA OUTD AR LGT
020AL TB15R-WA oum AR LGT 322 151 283 251 1247
020ALTB15R-WA OUTD AR LGT 296
02RESD0016-WA RES SRVC 557,092 97,485,553 98,637 15,786 0626
02RESD0016-WA RES SRVC 16,945,045
02RESD0017 -BILL ASSIST ANC 39,531 2,498,991 027 19,502 0632
02RESDO017-BILL ASSISTANCE -428,615
02RESD0018-WA 3 PHASE RES 805 193,979 101 27,772 0692
02RESD0018-WA 3 PHASE RES 30,672
02RESD018X-WA 3 PHASE RES 761 52,118 28,185 0685
02RESD018X-WA 3 PHASE RES 348
02RFNDCENT - CENTRALIA RFND
02ZZMERGCR-MERGER CREDITS
ACQUISITION COMMITMENT-A and 146,504
ACQUISITION 126,011
BPA BALANCING ACCOUNT 148,662
UNBILLED REV - UNCOLLECTIBLE 10,000
UNBILLED REVENUE 050 -435,000 0861
05NETMT135 - EXPERIMENTAL 397 3,400 0822
050AL T015R-OUTD AR LGT SR 146 151,231 206 950 1320
05RESOOOO2-WY OPTIONAL 51,197 596,489 115 10,009 0702
05RESDoo02-WY RES SRVC 749,899 55,873,765 645 655 0745
05RESD0003-WY OPTIONAL RE 022 663,611 134 302 0631
05RESD0018-RES 3 PHASE SR 159 11,523 875 0725
05RESD0135 - Experimental Partial 377 000 0689
05RESD018X-RES 3 PHASE SR 155 11,135 51,667 0718
05RFNDCENT-CENTRALIA RFND
TOTAL Billed 688'057i
Total Unbilled Rev.(See Instr. 6)108,98 073l
TOTAL 797 33 2 991,327,391 057e
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2OO6/Q4(2) DA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC;EDULES
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 I'liumoer anu ,me or Male scneuule Mwn ::;ola Mevenue Average I'liumoer ~vvn or ;:,ales ~6~~rdNo.(a)(b)(c)of Cu
&Qomers
Per 9~stomer
(f)
1 09LNXO0108-ANN COST MTHL Y 336
2 09RESD0201-RES SRVC 644 235 0696
3 ACQUISITION COMMITMENT-A and 70,806
4 ACQUISITION 300
5 SMUD REVENUE IMPUTATIONS 128,500
6 09NETMT135 - WY RES NET 329 500 0782
7 09RESDO002 167 350 350 0740
8 UNBILLED REV - UNCOLLECTIBLE 000
UNBILLED REVENUE 035 298,000 0270
05RESDOOO2-WY RES SRVC 580 084 923 0743
05RESDO003-WY OPTIONAL RE 172 12,750 0622
05RESD0018-RES 3 PHASE SR 403 000 1008
05UPPLOOOR-BASE SCH FALL
09INVCHGOR-INVEST MNT CHG
O9OAL T207R-SECURITY AR LG 30,181 103 913 3211
09RESD0201-RES SRVC 16,129 144 121 372 721 0709
09RESD0205-RES SRVC ALL E 967 633,915 238 4,454 0636
09NETMT135 - WY RES NET 672 25,000 0669
SMUD REVENUE IMPUTATIONS 21,455
05RESOOOO2-WY OPTIONAL 243 11,750 0690
09RESOOOO2 30,768 143,666 224 13,835 0697
09RESDO002 62,033 794,430 527 511 0773
09RESDOOO3 -235 16,452 0700
UNBILLED REVENUE 393 60,000 1527
Less Multiple Billings 98,796
Total Residential 15,334,601 065,628,795 1,411,602 10,863 0695
COMMERCIAL SALES
06CHCKOooN-CA NRES CHECK
06GNSV0025-CA GEN SRVC 63,690 893,599 740 9,450 1082
06GNSV025F-GEN SRVC-o::: 20 974 120,543 10,587 1238
06GNSVOA32-GEN SRVC-20 KW 77,582 850,059 863 89,898 0883
06LGSVO48T-LRG GEN SERV 541 895,453 154,100 0545
06LGSVOA36-LRG GEN SRVC-137 116,547 196 424 168 0736
06LNX00102-LlNE EXT 80% G 704
06LNX001 05-CNTRCT $ MIN G 092
06LNX00109-REF/NREF ADV +87,063
06LNX003oo - 80% MONTHLY MIN 057
TOTAL Billed 51,688,35 2 983 333,391 057/
Total Unbilled Rev.(See Instr. 6)108'0.07311
TOTAL 51,797,33 2,991 327 391 057f
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This (!Jort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2006/Q4
(2) riA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC -IEDULES
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.
une NumDer ana Ime or Hate scneaUie Mwn ~ola Hevenue Average Number Kwn ot ~ales ~6~eNo.(a)(b)(c)of cu(~omers Per 9~stomer
(f)
1 060ALT015N-OUTD AR LGT SR 765 135,315 557 373 1769
2 06RCFL0042-AIRWAY & ATHLE 199 236 103 1318
3 06WHSV0031-GOMM WTR HEATI 250 22,072 065 0883
ACQUISITION COMMITMENT-A and -47 218
ACQUISITION 28,598
CAALT RATE FOR ENERGY 399,872
SMUD REVENUE IMPUTATIONS 807
06LNX00103-LlNE EXT 80% G
9 06LNX00110-REF/NREF ADV +991
UNBILLED REVENUE 632 -469,000 0833
07CISH0019-COMM & IND SPA 10,186 722,751 301 33,841 0710
07GNSVOOO6-GEN SRVC-LRG P 209,666 440,410 909 230 656 0593
07GNSV0009-GEN SRVC-HI VO 272 365 675 272 000 0437
07GNSV0023-GEN SRVC-SML P 107 882 617 981 5,424 19,890 0799
07GNSV0035-GEN SRVCOPTION 830 740 915,000 0518
07GNSVOO6A-GEN SRVC-LRG P 24,319 636,674 199 122,206 0673
07GNSVOO6A-GEN SRVC-LRG P -467 316
07GNSV023A-GEN SRVC-SML P 779 257 011 089 13,571 0851
07GNSV023A-GEN SRVC-SML P 284 372
07GNSV023F-GEN SRVC SML P 591 571 1439
07LNX0001 O-MNTHL Y 80%GUAR 743
07LNXoo035-ADV 8O%MO GUAR 187,597
07LNXOOO4Q-AD V + R EFCHG +80%233
070AL T007N-SECURITY AR LG 262 52,415 201 303 2001
070ALT07AN-SECURITY AR LG 334 667 2334
070ALT07AN-SECURITY AR LG 190
07LNX00312 -ID LINE EXT 593
07LNXOOO15-ANNUAL 80%GUAR 12C
07LNX00311 - LINE EXT 80%529
07LNX00020 - ID MONTHLY 573
07LNX003oo - 80% MONTHLY MIN 905
ACQUISITION COMMITMENT-A and 38,359
ACQUISITION 36,657
BPA BALANCING ACCOUNT 318,119
UNBILLED REVENUE 481 29,000 0603
01COST0023, OR GEN SRV, COST 979,702 35,355,701 0361
01 COST0048 - 01 LGSV0048 707,417 23,748,484 0336
01COST023F - OR GEN SRV -237 125,166 0387
TOTAL Billed 51'688'057/
Total Unbilled Rev.(See Instr. 6)108,98(
, ,
07~
TOTAL 51,797,33 2,991,327,391 0578
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 2006/04(2) nA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
,LIne Numoer ana IlIIe or Hale scneoUie Mvvn :::'010 Hevenue Average"Number KWnot ::;ales w.6't3~krNo.(a)(b)(c)of c(~omers Per 9~stomer
(f)
1 01 COSTB023 - OR GEN SRV 98,304 685,949 0375
2 01COSTL028, OR LRG SRV, COST 755 58,018 0331
3 01COSTLO30 - OR LRG GEN SRV 989,349 34,612,807 0350
4 01COSTS028, OR GEN SERV,945,045 68,034,305 0350
5 01COSTSO30 - OR GEN SRV CBS:;.144 40,384 0353
01GNSB0023 - BPA DISC, -c: 30 998 833
7 01GNSBOO23, OR GEN SRV, BPA, -c:265 134 14,812
8 01 GNSB0028 - OR GEN SRVC 568 281
01GNSB0028, OR GEN SRV, BPA,
:;'
3,497,961 637
01GNSB023T - OR GEN SRV - TOU 63,149 104
01GNSB023T - OR GEN SRVC,15,135
01GNSV0023, OR GEN SRV, -c: 30 35,142 814 531 35,142.8140
01GNSVO028, OR GEN SRV:;. 30 654,362 521
01GNSV023F - OR GEN SRV - FLAT 525 155,979 901 791 1003
01GNSV023M - OR GEN SRV,965 64 ,000 0620
01GNSV023T, OR GEN SRV, TOU 147,522 221
01HABT0023, OR HABITAT 590 862 0370
01HABTBO23 - OR HABITAT 147 689 0387
01LGSBO030, GEN DEL SRV :;' 200 -460 888
01LGSBO030, GEN DEL SRV,:;' 200 712,202
01 LGSV0028, OR LRG GEN SRV -c:147 204
01LGSVoo30 - OR LRG GEN SRV,
:;'
16,072,012 609
01 LGSV0048-1 oooKW AND OVA 612 697
01 LGSVO48M-LRG GEN SRVC 1 50,54'1 987,098 50,544,000 0393
01 LNX001 OQ-LlNE EXT 60% G 840
01LNXO0102-LlNE EXT 80% G 380,116
01LNX00103-LlNE EXT 80% G 615
01 LNXO01 05-CNTRCT $ MIN G 950
01LNXO0109-REF/NREF ADV +1,473 690
01LNXO0110-REF/NREF ADV +12,411
01 LNXOO120 - Line Extension 60% G 10,837
01 LNX00300 - LINE EXT 80%915
01 LNXO0311 - LINE EXT 80% G 800
3.:1 01 LPRSO47M-PART REO SRVC 831 545,021 610,333 0696
01NMT23135 - OR NET MTR, GEN 102
010ALT014N-OUTD AR LGT NR 917 242,004 249 535 1262
010ALT014N-OUTD AR LGT NR 17,656
010ALT015N-OUTD AR LGT NR 332 778,283 237 265 1061
01 PTOUO023, OR GEN SRV, TOU 748 132,754 0354
01PTOUB023, OR GEN SRV, TOU 505 52,772 0351
TOTAL Billed 688.0577
Total Unbilled Rev.(See Instr. 6)108,98
. ,;
073.:1
TOTAL 797 33 2 991,327 391 057E
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 2006/Q4(2) fiA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1....lne Numoer ana ,me OJ Hale scneaUie Mvvn ~ola Hevenue Average 'Number KWnot :sales v n
of cuMomers
Per 9~stomer h odNo.(a)(b)(c)(I)
1 01 RCFLOO54-REC FIELD LGT 898 75,551 102 804 0841
01 RENWOO23, OR RENW USAGE 029 185,927 0370
01 RENWBO23 - OR RENEW ABLE 531 20,302 0382
01STDAY023 - OR DAY STD OFR 660 89,709 0540
5 01STDAY028 - OR DAY STD OFF,261 173 273 0531
6 01STDAY030 - OR STD DAY OFF 329 234,876 0543
01ZZMERGCR-MERGER CREDITS
8 ACQUISITION COMMITMENT-A and -474 162
9 ACQUISITION 362,941
BPA BALANCING ACCOUNT 464
01 LGSB0048 - LG GEN SVC;:.33,244
01 LGSB0048 - LG GEN SVC;:.12,375
01NMT28135 - OR NET MTR, GEN,709
01LGSV028M - OR LGSV, -::1000 395 25,310 395,000 0641
01GNSV030M - OR GEN SRV, 200 050 99,263 050,000 0 . 0484
01GNSV0728 - OR GEN SVC DIR 48,769
01GNSV0730 -OR GEN SVC DIR 919,863
01GNSV0748 LG GEN SVC DIR 034
OR SB408 RECOVERY 606,074
SMUD REVENUE IMPUTATIONS 885,936
UNBILLED REVENUE 717 244 000 0792
08BLSKY01 M - BLUE SKY
08CFR00051-MTH FAC SRVCHG 65,202
08CFR00052-ANN FAC SVCCHG
08CHCKoooN-UT NRES CHECK
08COOLKPRN - AIC DIRECT LOAD 280 866
08GNSVOOO6-GEN SRVC-DISTR 501,299 261,463,158 10,614 424 091 0581
08GNSVooo9-GEN SRVC-HI VO 223,627 736,798 12,423,722 0391
08GNSV0023-GEN SRVC-DISTR 129 553 78,549,340 60,203 18,762 0695
08GNSVOOGA-GEN SRVC-ENERG 175,721 13,507,286 539 114,179 0769
08GNSV006B-GEN SRVC-DEM&2,480 139 215 248,000 0561
08GNSVO06M-MNL DIST VOL TG 253 234,453 850,600 0551
08GNSV009A-GEN SRVC HI VO 21,640 924,885 10,820,000 0427
08GNSV009M-MANL HIGH VOLT 25,964 962,437 25,964,000 0371
08GNSV023F-GEN SRVC FIXED 383 128,531 116 922 0929
08GNSV023M-GNSV DIST VOLT 235 968 29,375 0679
08GNSV06AM-MNL ENERGY TOD 421 46,779 210,500 1111
08GNSV06MN-GNSV DIST VOLT 25,440 293 794 372 68,387 0509
08GNSV09AM-MAN TOD HIVOL T 420 19,194 420,000 0457
TOTAL Billed 51 '688,35 057/
Total Unbilled Rev.(See Instr. 6)108,98 07~
TOTAL 797 33 2,991,327,391 057E
FERC FORM NO.1 (ED. 12-95)Page 304.
Name 01 Respondent This ~rt Is:Date 01 Report Year/Period 01 Report
PacifiCorp (1) An Original (Mo, Da, Yr)End 01 2006/Q4(2) nA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC iEDULES
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. II 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 Numoer ana IlIIe OJ Hate scneoUie Mvvn ;::,010 Hevenue Average I'liumaer
'P~vr'~~sr;:~r ~6~~krNo.(a)(b)(c)of cu(~omers
(I)
1 08GNSV09LM-GEN TOO LAGOON 546 66,771 546,000 0432
2 08LNXoo002-MTHL Y 80% GUAR 353,032
3 08LNXooOO4-ANNUAL 80%GUAR 75,720
4 08LNXOOOO6-FIXD MTHL Y MIN 13,082
5 08LNXoo014-80% MIN MNTHLY 1 ,460,943
6 08LNXOO017 -ADV /REF&80%ANN 61,010
7 08LNX00150-AGR MTH GUAR M 945
8 08LNX00151-AGR MTH+ADV+BT 736
9 08LNX00158-ANNUALCOST MTH 33,793
08LNX003oo - LINE EXT 80% PLUS 184,833
08LNX00312 UT IRG LINE EXT 444
08NMT23135 - UT NET MTR, GEN,552 000 0862
080AL T007N-SECURITY AR LG 349 790,265 882 915 1915
08POLE0075-POLES W /LiGHT 246
08PRSV031 M-BKUP MNT&SUPPL 16,559 855,073 519,667 0516
08PTLDOOON-POST TOP LIGHT 868 125 0749
08SLC1202F-TRAFFIC giG NM 219 638 844 0668
08SLCU1202-TRAF & OTHER S 179 84,094 380 103 0713
08SLCU1203-MTR OUTDONIGHT 9,428 661 920 256 36,828 0702
OSZZMERGCR-MERGER CREDITS 101
ACQUISITION -437,994
SMUD REVENUE IMPUTATIONS 199,407
08LNX00311 - LINE EXT 80%881
08GNSV0008 - UT GEN SVC TOU ;;.839,026 41,849,775 118 110,390 0499
08GNSV008M - UT GEN SVC TOU ;;.755 059,153 625,833 0530
UNBILLED REVENUE 31,657 081,000 0657
02GNSB0024-WA GEN SRVC DO 11,257 782,604 290 3,422 0695
02GNSB0024-WA GEN SRVC DO 113,342
02GNSB024F-GEN SRVC DOMIF 658 500 0870
02GNSB024F-GEN SRVC DOM/F
02GNSB24FP-WA GEN SVC 45,462 111 171 3927
02GNSB24FP-WA GEN SVC 202
02GNSV0024-WA GEN SRVC 458,489 29,105,254 13,185 34,774 0635
02GNSV0025-WA GEN SRVC DO 32,367 228,779 289 841 0689
02GNSV0025-W A GEN SRVC DO 364,139
02GNSV024F-WA GEN SRVG-200 111 714 122 836 0931
02GNSV025F-GEN SRVC DOMIF 192 16,787 19,200 0874
02GNSV025F-GEN SRVC DOMIF 307
02GNSV24FP-GNSV SEASONAL 234 39,679 113 071 1696
TOTAL Billed 688,35 2,983 333,391 0577
Total Unbilled Rev.(See Instr. 6)108'0734
TOTAL 797 33 2,991,327 391 057S
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006lQ4
(2) FiA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues " Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Ine Numoer ana Ime or Hate scneaUie Mvvn ;::'010 Hevenue Average"Number KWn 01 ::iales ~G~~lderNo.(a)(b)(c)of cu
(ihomers
Per 9~stomer
(f)
1 02GNSV24FP-GNSV Seasonal 629
2 02LGSB0036-LRG GEN SVC IRG 26,078 305,042 266,102 0500
3 02LGSBoo36-LRG GENSVC IRG 266,006
4 02LGSVoo35-WA LRG GEN SRV 53,073 788,036 552,844 0525
5 02LGSV0035-WA LRG GEN SRV 597 070
6 02LGSV0036-W A LRG GEN SRV 668,945 34,992,635 791 845 695 0523
02LGSV048T-LRG GEN SAVe 1 153,167 215,122 5,470,250 0471
02LNX00102-LlNE EXT 80"'" G 622
9 02LNX00103-LlNE EXT 80% G 436
02LNX00105-CNTRCT $ MIN G 287
02LNX00109-REF/NREF ADV +158,344
02LNX00110-REF/NREF ADV +221
02LNX00112- YR INCURRED CH 669
02LNX0030D-LINE EXT 80% G 17,266
020AL T013N-W A OUTD AR LGT 501 62,128 594 843 1240
020AL T013N-W A OUTO AR LGT 6513
020AL T015N-W A OUTO AR LGT 740 200,406 879 980 1152
020AL TB15N-WA aUTO AR LGT 177 887 584 303 1237
020ALTB15N-WA OUTD AR LGT 808
02RCFLoo54-WA REC FIELD L 241 18,534 310 0769
02RFNDCENT - CENTRALIA RFND 140
02ZZMERGCR-MERGER CREDITS
02NMT24135, Net metering, W A 410 000 0820
ACQUISITION COMMITMENT-A and 130,273
ACQUISITION 112,051
21:BPA BALANCING ACCOUNT 60,564
UNBILLED REVENUE 357 468,000 0636
05CHCKOOON-WY NRES CHECK
05GNSVO025-WY GEN SRVC 017,759 66,446,025 094 50,650 0653
05GNSV025F-GEN SRVG-FL RA 098 121,886 195 631 1110
05LGSVO46M-WY LRG GEN SRV 208 90,358 208,000 0409
05LGSV046T-LRG GEN SERV 209,610 748,480 032 105 0465
05LNXO0100-LlNE EXT 60% G 239
05LNX00102-LlNE EXT 80% G 431,630
05LNX00105-CNTRCT $ MIN G 369
05LNXO0109-REF/NREF ADV +365,461
05LNX00110-REF/NREF ADV +280
05LNXO0114-TEMP SVC 12MO;;.541
05NMT25135 - WY NET MTR, GEN 363 709 181 500 0874
TOTAL Billed 6"'057i
Total Unbilled Rev.(See Instr. 6)108,98 07~
TOTAL 51,797,33 2,991,327 391 057f
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 2006/Q4(2) DA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC -iEDULES
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 Numoer ana Ime or Hale scneaUie Mvvn ~ola Hevenue Average Numoer ~vvn oT ;;:.ales ~6'$~r;rNo.(a)(b)(c)of cu
MJomers
Per '(~stomer
(f)
1 050AL T015N-OUTD AR LGT SR 3,483 457 526 856 877 1314
2 05RCFLoo54-WY REC FIELD L 683 003 648 0761
3 05RFNDCENT-CENTRALIA RFND
4 09GNSV0025-GEN SVC-SINGLE 214 000 2140
5 09GNSV0206-GEN SRVC-SINGL
6 05LNXoo300 - LINE EXT 80%275,366
05LNX00311 - LINE EXT 80%782
8 ACQUISITION COMMITMENT-A and 96,863
9 ACQUISITION 068
SMUD REVENUE IMPUTATIONS 148,091
UNBILLED REVENUE 322 434,000 3478
05GNSV0025-WY GEN SRVC 317 104,088 20,905 0790
OSGNSV025F-GEN SRVC-FL RA 121 740 903 0970
05LNXOO102-LlNE EXT 80% G 776
05LNX00103-LlNE EXT 130% G 610
05LNX00109-REF/NREF ADV +62,808
05LNXOO11D-REF/NREF ADV +852
09GNSVOO25-GEN SVC-SINGLE 101,969 663,782 293 44,470 0654
09GNSV0206-GEN SRVC-SINGL 22,773 384,209 276 10,006 0608
09GNSV025F-GEN SVC-FIXED 107 808 643 0823
09GNSV025M-GEN SVC-MANUAL 003 126 040 667 667 0629
09GNSV206F-GEN SRVC-FIXED 070 077 0969
09GNSV206M-GENSERV MANUAL 456 26,557 152 000 0582
090AL T207N-SECURITY AR LG 298 784 146 041 3114
09SLCU2123-MTR OUTOONIGHT 365 500 0716
05LNXOO300 - LINE EXT 80%984
05LNXO0311 - LINE EXT 80%265
SMUD REVENUE IMPUTATIONS 868
UNBILLED REVENUE 040 213 000 0701
Less Muhiple Billings 104
COMMERCIAL SALES TOTAL 15,397 126 917,467 966 199,474 77,189 0596
INDUSTRIAL SALES
06GNSVOO25-CA GEN SRVC 940 103,400 104 038 1100
06GNSVOA32-GEN SRVC-20 KW 805 194 099 82,045 1075
06LGSVO48T-LRG GEN SERV 50,607 703,501 651 750 0534
06LGSVOA36-LRG GEN SRVC-195 717 944 574,688 0781
06LNX00109-REF/NREF ADV +603
TOTAL Billed ".35 057i
Total Unbilled Rev.(See Instr. 6)108,0734
TOTAL 51,797 33 2,991 327 391 0578
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This (!prt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4
(2) riA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold , revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of un billed revenue as of end of year for each applicable revenue account subheading.
I Line Numoer ana Ime or Hate scneoUie Mvvn ::soia Hevenue Average NumDer IS,vvn- or ::sales ~6~~lderNo.(a)(b)(c)of c~~omers Per 9~stomer
(f)
1 ACQUISITION COMMITMENT-A and 095
2 ACQUISITION 114
CA AL T RATE FOR ENERGY 027
SMUD REVENUE IMPUTATIONS 13,524
5 UNBILLED REVENUE 323 19,000 0588
61D
7 07CFROOOO1-MTH FACILITY S 145
07CISH0019-COMM & IND SPA 167 12,716 23,857 0761
07GNSVOOO6-GEN SRVC-LRG P 272 593,576 111 786,234 0526
07GNSV0008-GEN SRVC-MEDIU 433 134 135 216 500 0551
07GNSVO009-GEN SAVe-HI VO 88,103 895 575 009,364 0442
07GNSV0023-GEN SRVC-SML P 11 ,464 885,4OC 356 202 0772
07GNSVOO6A-GEN SRVe-LRG P 723 367 669 150,605 0642
07GNSVOO6A-GEN SRVC-LRG P 109,977
07GNSV023A-GEN SRVe-SML P 368 219 871 267 869 0929
07GNSV023A-GEN SRVe-SML P -45,502
07LNX00035-ADV 8O%MO GUAR 567
07LNX00108-ANN COST MTHL Y 996
070AL T007N-SECURITY AR LG 3,421 842 2138
070ALT07AN-SECURITY AR LG 333 500 3330
070ALT07AN-SECURITY AR LG
07SLCU1201-TRAF SIGNAL SY 935 667 1169
07SPCL0001 357 700 324 896 357 700,000 0304
07SPCLOOO2 119,309 200,978 119,309,000 0352
ACQUISITION COMMITMENT-A and 164,045
ACQUISITION 156 764
BPA BALANCING ACCOUNT 53,529
UNBILLED REVENUE 15,432 254 000 0165
01COST0023, OR GEN SRV, COST 22,902 828,527 0362
01COSTOO48 - 01LGSV0048 744,412 717 910 0331
01COST023F - OR GEN SRV -135 0450
01COST8023 - OR GEN SRV,375 13,994 0373
01COSTL028, OR LRG SRV, COST 134 -4,544 0339
01COSTLO3O - OR LRG GEN SRV 280,248 834,982 0351
01COSTS028, OR GEN SERV 119,893 189,381 0349
01GNSB0023 - BPA DISC ,;: 30 kW 770
01GNSBO023, OR GEN SRV, BPA
, ..;:
24,820
01GNSB0028 - OR GEN SRVC,911
01GNSBO028, OR GEN SRV, BPA
;:'
16,591
TOTAL Billed 688,35 2,983,333,391 057
Total Unbilled Rev.(See Instr. 6)108'0734
TOTAL 797 33 2,991,327,391 057E
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 2006/Q4
(2) fiA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues,. Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
NumDer ana I me or Hate scneaUie Mwn ;:;ola Hevenue Average NUmDer lSWf!:. oTSates v n /derNo.of cu(~omers Per 1~stomer h od
(a)(b)(c)(I)
1 01GNSV0023, OR GEN SRV, -:: 30 878,260 180
2 01GNSVO028, OR GEN SRV,. 30 296,817 564
01GNSV023F - OR GEN SRV - FLAT 645
4 01GNSV023M - OR GEN SRV,849 000 2830
5 01GNSV023T, OR GEN SRV, TOU 868
6 01HABT0023, OR HABITAT 317 0342
01LGSBoo30, GEN DEL SRV " 200 33,094
8 01 LGSBOO30, GEN DEL SRV, ,. 200 55,395
9 01 LGSV0028, OR LRG GEN SRV -::155
01 LGSV0030 - OR LRG GEN SRV, ,.878,292 193
01LGSVOO48-1oo0KW AND OVA 15,684,615 120
01 LGSVO48M-LRG GEN SRVC 1 584 281 21,724,445 116,856,200 0372
01 LNX00105-CNTRCT $ MIN G 090
01LNX00109-REF/NREF ADV +18,705
01 LNXoo300 - LINE EXT 80%7,478
01 LPRSO47M-PART REQ SRVC 492,488 276,273 123,122,000 0371
01NMT28135 - OR NET MTR, GEN 290
010ALT014N-OUTD AR LGT NR 177 000 1308
010ALT014N-OUTD AR LGT NR
010ALT015N-OUTD AR LGT NR 466 46.841 164 841 1005
001PTOUOO23, OR GEN SRV, TOU 199 0364
01 RENW0023, OR RENW USAGE 184 838 0372
01RENWB023 - OR RENEWABLE 0290
01ZZMERGCR-MERGER CREDITS
ACQUISITION COMMITMENT-A and 304,575
ACQUISITION 233,132
BPA BALANCING ACCOUNT
01STDAYO23 - OR DAY STD OFR 807 0531
01LGSV028M - OR LGSV, -::1000 109 9,489 109,000 0871
OR S8408 RECOVERY 15,963
SMUD REVENUE IMPUTATIONS 562,184
UNBILLED REVENUE 776 368,000 0473
08CFROO051-MTH FAC SRVCHG 16,329
08EFOPO021-ELEC FURNACE 0 1,427 840 713,500 0616
08EFOP021 M-ELEC FURNACE 0 075 208,738 691 667 1006
08GNSVO0Q6-GEN SRVC-DISTR 767,828 078,876 351 568,340 0613
08GNSVO009-GEN SRVC-HI VO 372,252 86,022,843 109 21,763,780 0363
08GNSVOO23-GEN SRVC-DISTR 247 340,442 884 15,769 0709
08GNSVOO6A-GEN SRVC-ENERG 58,066 721 381 229 253,563 0813
TOTAL Billed 688,35 2 983,333,391 0571
Total Unbilled Rev.(See Instr. 6)108'073/
TOTAL 51,797,33~ 2 991 327 391 057S
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 2006/Q4
(2) EjA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC -IEDULES
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.
...lne Numoer ana Ime or Hale scneaUie Mvvn ~ola Hevenue Average Numoer ~vvn or ~ales ~~lB~~lderNo.(a)(b)(c)of Cu(~omers Per r:tJstomer
(f)
1 08GNSVOO6B-GEN SRVC-DEM&070 220,945 511 667 0720
2 08GNSVOO6M-MNL DIST VOL TG 364 142 364,000 0566
3 08GNSV009A-GEN SRVC HI VO 543 923,660 923,833 0527
4 08GNSV009M-MANL HIGH VOLT 691,420 24,266 072 62,856,364 0351
5 08GNSV023F-GEN SRVC FIXED 316 000 3290
08GNSV06MN-GNSV DIST VOLT 952 49,657 000 0522
7 08GNSV09AM-MAN TOD HIVOL T 245 107,947 1 ,245 000 0867
8 08LNXOOOO2-MTHL Y 80% GUAR 899
9 08LNXOOOQ4-ANNUAL 8O%GUAR 757
08LNX00014-80% MIN MNTHL Y 031
08LNX00017 -ADV /REF&80%ANN 233
08LNX001SQ-AGR MTH GUAR M 728
08LNX003oo - LINE EXT 80% PLUS 094
080AL T007N-SECURITY AR LG 544 272 802 555 782 1767
08PRSV031 M-BKUP MNT&SUPPL 112 598 112,000 0500
08SLCU1202-TRAF & OTHER S 851 500 0 . 0648
08SLCU12O3-MTR OUTDONIGHT 775 833 2523
08SPCL0001 589,057 835,146 589,057 000 0303
08SPCL0002 767 211 21,183,374 767,211 000 0276
OBSPCL0003 654,937 405,451 654,937 000 0327
08SPCL0005 224,635 664,316 224 635,000 0341
OBSPCL0011 20,342 1 ,432,698 20,342,000 0704
OSZZMERGCR-MERGER CREDITS
ACQUISITION -448,687
SMUD REVENUE IMPUTATIONS 244 511
08GNSV06AM-MNL ENERGY TOD 653 000 0951
08GNSV0008 - UT GEN SVC TOU:;.968,189 49,621,388 108 964,713 0513
08GNSV008M - UT GEN SVC TOU :;.69,750 551 180 718 750 0509
UNBILLED REVENUE 37,578 394 000 0371
02GNSB0024-WA GEN SRVC DO 841 56,256 114 377 0669
02GNSB0024-WA GEN SRVC DO 751
02GNSB24FP-WA GEN SVC 614
02GNSB24FP-WA GEN SVC
02GNSVO024-WA GEN SRVC 19,097 219,613 381 123 0639
02GNSV0025-WA GEN SRVC DO 890 133,122 117 16,154 0704
02GNSV0025-WA GEN SRVC DO 21,267
02GNSV024F-WA GEN SRVC-441 250 1649
02GNSV24FP-GNSV SEASONAL 623 000 6230
02GNSV24FP-GNSV Seasonal
TOTAL Billed 51,688,35 2 983,333,391 057i
Total Unbilled Rev.(See Instr. 6)108'0734
TOTAL 797 33 2 991 327,391 057
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 2006/Q4
(2) CiA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC-IEDULES
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.
,-JOe NumDer ana Ime or Hale scneaUie Mvvn ~ola Hevenue Average ."umoer ~wn ol :;sales v R~lder
No.(a)(b)(c)of cu(~omers Per 1~stomer
(f)
1 02LGSV0035-WA LRG GEN SRV 214 206 527 000 0933
2 02LGSV0035-W A LRG GEN SRV 24,902
3 02LGSV0036-WA LRG GEN SRV 145,564 741 178 133 1 ,094,466 0532
02LGSVO48M-W A LRG GEN SRV 72,852 301,774 852,000 0453
5 02LGSV048T-LRG GEN SRVC 1 710 265 29,878 654 20,293,286 0421
6 02LNX00102-LlNE ExT 80% G 57,,-
7 02LNX00109-REF/NREF ADV +800
8 020AL T013N-W A OUTO AR LGT 031 200 1263
9 020AL T013N-W A aUTO AR LGT 275
020AL T015N-W A OUTD AR LGT 120 13,249 727 1104
020AL TB15N-WA OUTO AR LGT 040 421 1300
020ALTB15N-WA aUTO AR LGT
02PRSV47TM-LRG PART REQMT 107 959 919 10,553,500 0929
02RFNDCENT - CENTRALIA RFND
02ZZMERGCR-MERGER CREDITS
02LGS80036-LRG GEN SVC IRG 698 117 282 58,552 0691
02LGS80036-LRG GENSVC IRG 720
02LGSB048T - WA GEN SRVC, BPA 29,804
02LGSB048T - W A GEN SRVC, NO 896 139 107 896 000 0480
ACQUISITION COMMITMENT-A and 205
ACQUISITION 83,608
BPA BALANCING ACCOUNT 267
UNBILLED REVENUE 567 484,000 0418
05GNSV0025-WY GEN SRVC 291,300 16,624 168 670 174 431 0571
05GNSV025F-GEN SRVC-FL RA 344 188 1005
05GNSV025M - General Service 659 104,029 829,500 0627
05LGS45025-LRG GEN SRVC 149 70,408 0613
05LGSV046M-WY LRG GEN SRV 578,058 128,614 115,611,600 0417
05LGSV046T-LRG GEN SERV 282 552 146,414 112,966 0438
OSLGSV048M- TOU::- 1 OOOKW MAN 127 170 638,246 375,723,333 0334
05LGSVO48T-LRG GENSRV TIM 766,163 26,043,840 109,451 857 0340
05LNX001oo-LiNE EXT 60% G 13,176
05LNXO0102-LlNE EXT 80% G 138,359
05LNXO0105-CNTRCT $ MIN G 48,357
05LNXO0109-REF/NREF ADV +248,676
050AL T015N-OUTO AR LGT SR 100 11,910 174 1191
05PRSV033M-PART SERV REQ 055,188 037,495 211 037 600 0398
ACQUISITION COMMITMENT-A and -432 964
ACQUISITION -411,530
TOTAL Billed 688,35 2,983 333,391 0577
Total Unbilled Rev.(See Instr. 6)108'0734
TOTAL 797,33 2 991 327 391 057f
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 2006/04(2) DA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC -fEDULES
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 Numcer ana Ime or Hale scneaUie Mvvn ~ola Hevenue Average Numcer ~vvn or ~ales ~~~~krNo.(a)(b)(c)of cu
(a)omers
Per 9~stomer
(f)
1 SMUD REVENUE IMPUTATIONS 902,270
05LNXoo300 - LINE EXT 80"10 11 ,384
UNBILLED REVENUE 43,663 449,000 0561
4 05GNSV0025-WY GEN SRVC 033 65,876 46,955 0638
5 05GNSV025M - General Service 184 000 0920
05LGSV046M-WY LRG GEN SRV 021 210,213 021,000 0523
05LGSV046T-LRG GEN SERV 444 360,070 444 000 0426
8 05LGSVO48M-TOU::-1oooKW MAN 290,657 10,117,380 48,442,833 0348
05LGSV048T-LRG GENSRV TIM 249,179 821,161 41.529,833 0354
05LNX00109-REF/NREF ADV +075
05PRSVO33M-PART SERV REO 340 167,416 340,000 0.4924
. 12 09GNSVOO25-GEN SVC-SINGLE 36,367 216,903 374 238 0610
09GNSV0206-GEN SRVC-SINGL 919 469 120 392 20,202 0592
09GNSV0217-LRG POWER SRVC 540 033,013 17,508 000 0346
09GNSV025M-GEN SVC-MANUAL 894 193,724 298,000 0497
09GNSV206M-GENSERV MANUAL 932 020 233,000 0472
09GNSV217M-LRG POWER SRVC 95,916 281 938 15,986,000 0342
O9OAL T207N-SECURITY AR LG 921 750 2744
09PRSVO33M 269 193,520 269,000 1525
09PRSV218M-BKUP,MNT SUPPL 119 74,390 59,500 6251
SMUD REVENUE IMPUTATIONS 137 663
UNBILLED REVENUE 469 406,000 0628
Less Multiple Billings 681
INDUSTRIALSALES TOTAL 19,200 105 770,600,712 492 670,737 0401
IRRIGATION SALES
06APSVOO2D-AG PMP SRVC 60,021 771,069 306 45,958 0795
06LNX00102-LlNE EXT 80"k 404
06LNX00103-LlNE EXT 80"k 124
06LNX0011D-REF/NREF ADV +11,491
06SLXOOOO1-KLAM FALLS MIN 729
06UKRBOO35-KLAM OFF PROJ
06USBROO40-KLAM IRG ONPRJ 570 719,365 659 46,388 0562
06USBR033T USBR 069 989 141 140 0038
06LNX00109-REF/NREF ADV +663
IRRIGATION UNBILLED 240
07APSA010L - IRG & Pump BPA 16,893,211
TOTAL Billed 688,35 2,983 333,391 0577
Total Unbilled Rev.(See Instr. 6)108'0734
TOTAL 51,797 33 2 991,327,391 057E
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 2006/04
(2) fiA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC-IEDULES
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.
1L.lne Numcer ana Ime or Hare scneaUie Mwn :SOld Hevenue Average Number fS,Wn oT :sales rw.w~~ellrNo.(a)(b)(c)of Cu(~omers Per ~~stomer (f)
1 07APSA010L - IRG & Pump Large 535,348 33,946,924 3,479 153,880 0634
2 07APSA010S - IRG & Pump BPA 165,147
3 07APSA010S - IRG & Pump Small 235 403 138 390 13,423 0770
4 07APSAL10X -IRG & PUMP - Large I 36,408 452,764 511 71,249 0674
5 07APSAS10X - IRG & PUMP - Small 157 108,616 214 407 0939
07APSC010L - IRG PUMP Srv BPA 835
7 07APSC010L - IRG PUMP Srv Large 721 0947
07APSC010S - IRG PUMP SRV
9 07APSCL10X - was 07APSC10LX 522 39,319 0753
07APSCS10X - was 07APSC10SX 965 2183
07APSVCNLL-LRG LOAD 899 861 502 310,396 0578
07APSVCNLL-LRG LOAD CANAL -447 737
07APSVCNLS-SML LOAD CANAL 440 556 08B8
07APSVCNLS-SML LOAD CANAL 318
07BPADEBIT-BPAADJUST FEE 6BO 253
07LNXoo015-ANNUAL BO"loGUAR 634
07LNXOOO4Q-AD V +R E FCH G+80"lo 153,885
07LNX00107-SUBD ADV & AIC 097
07LNXOO310 80% ANNUAL 398
07LNX00312 - ID LINE EXT 615
07APSN010L -ID LG IRR & PUMP 1,404 103,772 87,750 0739
07APSN010L - ID LG, IRR, 3 PH, BP -44,294
07APSN010S - IRR, SMALL, 3 PH,-4,665
07APSN010S - IRRIGATION,148 299 143 0763
07APSNS10X - IRRIGATION 762 15,500 OB91
IRRIGATION BPA BAL ACCT 215,940
2'1 UNBILLED REV - IRRIGATION 195 213,000 0970
01APSV0041-AG PMP SRVC BP 833,049 796
01APSV0041-AG PMP SRVC BP -47B,545
01APSVO41L-OR Pumping Serv 2,496 434 003
01APSVO41L-OR Pumping Serv BPA 755,719
01 APSVO41T - AGR PUMP SRV 426
01 APSVO41T - AGR PUMP 26,791
01APSVO41X-AG PMP SRVC 74,667 222
01APSV41XL-OR Pumping Serv no 119,323
01 BPADEBIT-BPA ADJUST FEE 43,927
01COST0041 124,422 4,474 936 0360
01COSTS028, OR GEN SERV 254 948 0352
01GNSV0028, OR GEN SRV;,. 30 591
TOTAL Billed 688 057/
Total Unbilled Rev.(See Instr. 6)10B,98(07~
TOTAL 51,797,33 2 991,327 391 057E
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 2006/04(2) DA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
I LIne Numoer ana ,me or Male scneaUie Mvvn ;:,010 Mevenue Average I'lumoer ~vvn or ~ales ~6~~lderNo.(a)(b)(c)of cu(~omers Per '(:f)stomer
(1)
1 01LGSV0030-3P DEMAND,VAR,SEC
01LNX00102-LlNE EXT 80% G 163
3 01LNX00103-LlNE EXT 80% G 18,168
4 01LNX00109-REF/NREF ADV +372
5 01LNX00110-REF/NREF ADV +105,328
6 01NMT41135 - NETMTR AG PMP
01 PTOU0041 - 01 APSVOO41 AG 629 19,211 0305
8 01RENEWO41 - 01 APSV0041 AG 347 0360
9 01SLXOOOO5-KLAMATH FALLS 207,475
01SLXOOO13-K FALLS IRG MI 14,686
01SLX00014-K FALLS IRG MI 624
01STDAYO41 - Daily Standard Offer 111 0222
01 UKRBOO35-KLAMA TH BASIN 48,932 484 149 679 065 0099
01UKRBOO35.KLAMATH BASIN 276 747
01USBROO4O-KLAMATH BASIN 416 466,649 403 40,924 0081
01USBROO4O-KLAMATH BASIN 536,346
01USBR33TX-IR TOU W/O BPA 327 202 532 700 0 . 0044
01ZZMERGCR-MERGER CREDITS
IRRIGATION BPA BAL ACCT 601
IRRIGATION UNBILLED 22 ,000 2529
OR ENRGY COST RECOV AMORT 944,606
OR Irrigation - BPA adjustment 18,135
01LNX00310-LiNE EXTENSION 222
01LNX00312 - OR IRG LINE EXT 905
OR SB408 RECOVERY 973
08APSVO010-IRR & SOIL DRA 158,827 084,591 405 040 0509
08APSV10NS. Irg Soil Drain Pump N 12,142 602 022 181 224 0496
08LNXOOOO2.MTHL Y 80% GUAR 852
08LNXQ0004.ANNUAL 80%GUAR 68,433
08LNX00014-80% MIN MNTHL Y 526
08LNX00017 -ADV /REF&80%ANN 104,243
08LNX00152-AGR ANN GUAR M 105
08LNX00153-AGR ANN+ADV+BT 970
08LNXO0310. IRR, 80% ANNUAL 440
08LNX00312 UT IRG LINE EXT 886
08NMT10135.UT IRR SOIL DRNG 347 000 0578
UNBILLED REV - IRRIGATION 000 0800
02APSV0040-W A AG PMP SRVC 136 211 050,954 663 29,211 0591
TOTAL Billed 51 '6B8'0577
Total Unbilled Rev.(See Instr. 6)108,0734
TOTAL 51,797 33 2 991 327,391 0578
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 2006/04(2) OA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC -iEDULES
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.
Ine Numcer ano Ime or Hare scneaUie Mvvn ;:1010 Hevenue Average I'liumoer ~vvn or ,-,ales w.6'!3~rlrNo.(a)(b)(c)of c~~omers Per 9~stomer
(I)
1 02APSV0040-WA AG PMP SRVC 527,858
2 02APSVO40X-W A AG PMP SRVC 104 067 940 575 485 0590
3 02BPADEBIT-BPA ADJUST FEE 050
02LNX00102-LlNE EXT 80% G 086
5 02LNX00103-LlNE EXT 80% G 012
6 02LNX00105-CNTRCT $ MIN G
7 02LNX00109-REF/NREF ADV +835
02LNX0011D-REF/NREF ADV +50,756
9 02RFNDCENT - CENTRALIA RFND 11::
02ZZMERGCR-MERGER CREDITS
IRRIGATION BPA BAL ACCT 338
IRRIGATION UNBILLED 187 000 2246
05APSOOO4D-AG PUMPING SVC 17,992 308,343 553 32,535 0727
05LNX00110-REF/NREF ADV +37,126
OSLNX00103-LlNE EXT 80% G 603
OSLNX00105-CNTRCT $ MIN G
05LNX00310-LlNE EXTENSION 121
IRRIGATION UNBILLED 000 1039
OSAPSOOO4O-AG PUMPING SVC 855 12,000 0713
OSLNX00103-LlNE EXT 80% G 019
05LNX00110-REF/NREF ADV +339
09APSV0210-IRR & SOIL DRA 592 162 958 61,714 0629
Less Multiple Billings -608
IRRIGATION SALES TOTAL 271,439 58,222,550 607 56,241 0458
PUBLIC STREET&HIGHWAY LIGHT
06COSL0052-CO-OWND STR LG 667 600 7084
06CUSL053F-SPECIAL GUST 0 1 ,424 136 943 123 577 0962
06CUSL058F-CUST OWND STR 243 341 720 1125
06HPSV0051-HI PRESSURE SO 711 145,797 355 2051
UNBILLED REVENUE -41 000 1220
07SLCO0011-STR LGT CO-OWN 131 506 226 2329
07SLCU1201-TRAF SIGNAL SY 182 15,620 280 0858
07SLCU1203-STR LGT CUST-293
07SLCU122A-STR LGT CUST-181 581 12,929 0529
07SLCU122B-STR LGT CUST-824 195,537 258 070 1072
TOTAL Billed 688.0577
Total Unbilled Rev.(See Instr. 6)108,98( 0734
TOTAL 797 33 2 991,327 391 057E
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 2006/04(2) DA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC-tEDULES
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.
L-Ine Numoer ana Ilile or Hale scneaUie Mvvn ::Iola Hevenue Average Numoer ~vvn OT ~ales ~~~~~~er
No.(a)(b)(c)of Cu(~omers Per 9~stomer
(f)
1 UNBILLED REVENUE
20R
3 01 COSL0052-STR LGT SRVC C 980 211 836 101 19,604 1070
01 GUSL0053-CUS-OWNED MTRD 692 44,403 13,308 0642
5 01 CUSL053E-STR LGT SVC
6 01GUSL053F-STR LGT SRVC C 357 501 ,643 175 53,469 0536
7 01 HPSVO051-HI PRESSURE SO 283 753,505 668 873 1593
01 MVSL005Q-MERC VAPSTR LG 784 235,926 315 37,410 1049
9 01 OAL T014N-QUTD AR LGT NR
010ALT014N-OUTD AR LGT NR
010ALT015N-OUTD AR LGT NR 440 500 1467
OR SB408 RECOVERY 832
UNBILLED REVENUE -48 75,000 5625
08CFR00012-STR LGTS (CONV
08CFR00051-MTH FAC SRVCHG.529
08CFR00061-U/G AREA LIGHT 127
08CFR00062-STREET LIGHTS
08HAXTOO6O-LiG HTNG -HAXTO N
080AL TOO7N-SECURITY AR LG 994 3,400 1761
08SLC1202F-TRAFFIC giG NM 211 75,422 130 315 0623
08SLCOO011-STR LGT GO-OWN 086 613,141 156 836 2330
08SLCU1202-TRAF & OTHER S 749 280,368 536 441 0748
08SLGU1203-MTR OUTDONIGHT 002 516 22,267 0724
08SLCU121A-STR LGT CUST-13,019 087,435 359 265 0835
08SLCU121B-STR LGT CUST-195 856,466 .206 636 0931
08SLD13ES1-DECOR CUST-OWN 744 289,552 119,667 0504
08SLD13ES2-DECOR CUST-OWN 17,736 896,147 354,720 0505
08SLD13FS1-DECOR CaMP-OWN 34,252 16,250 5270
08SLD13FS2-DECOR CaMP-OWN 206 113,242 15,846 5497
08SLD13MS1-DECOR CUST-OWN 527 65,193 40,538 1237
08SLD13MS2-DECOR CUST-OWN 991 123,374 158 1245
08THIKOO77-STR LIGHT SPEC 141 277 141 000 1225
UN BILLED REVENUE 310 437 000 1320
02CFR00012-STR LGTS (CONV
02COSL0052-W A STR LGT SRV 458 55,757 615 1217
02CUSL053F-WA STR LGT SRV 3,420 204,416 183 18,689 0598
02CUSL053M-W A STR LGT SRV 966 090 500 0591
02HPSV0051-WA HI PRESSURE 815 479,328 160 17,594 1703
TOTAL Billed 51,688,35 2 983,333.391 0577
Total Unbilled Rev.(See Instr. 6)108'0734
TOTAL 797 33 2,991,327,391 057f
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~rt Is:Date of Report YearlPeriod of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2006/04
(2) fiA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, Ust 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 Numoer ana Ime or Hate scneaUie Mwn :SOlei Hevenue Average Numoer ISwnor :sales ~6'$~lderNo.(a)(b)(c)of cu
lRJomers
Per 9~stomer
(f)
1 RENT REV-GEN(COMM)525
2 Rent Revenue - Subleases 42,171
3 Joint use 558,630
09LOOP0214-MTH FEE PRE-229
5 09POLEO075-STEEL POLES US 713
RENT REVENUE-STEAM 338
7 Joint use 167 059
9 Total RENT FROM ELEC 19,392,877
MISCELLANEOUS SERVICE REV
ALL BLUE SKY RES 122
ALL NON-RES BLUE SKY 394
ALL BLUE SKY RES 89,693
ALL NON-RES BLUE SKY 086
ALL BLUE SKY RES 79,676
ALL NON-RES BLUE SKY 16,594
ALL BLUE SKY RES 856,434
ALL NON-RES BLUE SKY 221 314
01XTRNBSKY - Blue Sky 322
ALL BLUE SKY RES 256,390
ALL NON-RES BLUE SKY 358,536
ALL BLUE SKY RES 29,778
ALL NON-RES BLUE SKY 650
ALL BLUE SKY RES 34,273
ALL NON-RES BLUE SKY 018
WHEELING ESTIMATE 307
OTH ELEC ESTIMATE 215,075
GREEN CREDIT SALES 011,684
NON-WHEELING SYSTEM 875,451
Other Elec (exclud Wheel)539 580
Post Merg Firm Wheeling 478,498
OTH ELEC REV - TRANS ANC 354 735
Inter-Co Other Elec Revenues 88,317
TOTAL Billed 51.688,35 057/
Total Unbilled Rev.(See Instr. 6)108 98( . '
. .
0734
TOTAL 51,797,33 2 991,327 391 057E
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 2006/04
(2) CiA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC-IEDULES
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.
LJne NumDer ana Ime Of Hate scneaUie Mvvn ::;010 Hevenue Average NumDer ~:n
9~s?~~r ~6~~tderNo.(a)(b)(c)of cu(~omers (f)
1 CA
2 Fish, Wildlife, Recr 546
310
4 DSM REV-ID SBC 374,343
5 Other Elec (exclud Wheel)224
60R
7 01CFROOOO1-MTH FACILITY S 41,490
8 01 CFROOOO4-EMRGNCY ST&BY 15,660
9 01CFROOOO5-INTERMTNT SRVC 29,874
ELEC INC-OTHR 148
3RD PARTY TRANS 494 314
INTERCO FIRM WHEEL 899,737
Non-Firm Wheeling 122,478
Other Elec (exclud Wheel)593,944
Other Elec DSR carry chrg 461 865
Post Merg Firm Wheeling 432 013
Pre Merg Firm Wheel PPL 163,777
Pre Merg Firm Wheel UPL 668,802
Short-term Firm Wheeling 200,736
Inter-Co Other Elec Revenues 030
INTERCOShort-Term WHEEL 471,992
08CFROOO53-MTHL Y MAINTFEE 241
08XTRNOO16-QUTBIL SVC REN 152 808
ELEC INC-OTHR 321,515
FLYASH SALES 348,302
DSM REV-UT SBC OFFSET 29,115,718
Fish, Wildlife, Recr 995
2!J Other Elec (exclud Wheel)863,124
02CFROOOO4-EMRGNCY ST&BY 943
02CFROOOO5-INTERMTNT SRVC 924
Fish, Wildlife, Recr 306
Other Elec (exclud Wheel)-422,363
Wash Colstrip 3 188
05CFROOQ04-EMRGNCY ST&BY 14,084
05CFROOOO5-INTERMTNT SRVC 163
09CFROOOO5-INTERMTNT SRVC 226
ELEC INC-OTHR 355
TOTAL Billed 688,35 2,983,333,391 0577
Total Unbilled Rev.(See Instr. 6)108'0734
TOTAL 797,33 2 991,327 391 057IJ
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 2006/04(2) DA Resubmission 05/17/2007
SALES OF ELECTRICITY BY RATE SC iEDULES
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 me or Hale scneoUie Mwn ::;010 Hevenue Average, Numoer ~~n
9~sr;:~r "W~~'S~rderNo.(a)(b)(c)of c~~omers (f)
1 FLY ASH SALES 507 145
2 WY Regulatory Recovery Fee 172 202
FLY ASH SALES 753
5 OTHER ELECTRIC REVENUE 71,465,755
OTHER ELECTRIC REVENUE
8 WHEELING ESTIMATE 826,170
OTH ELEC REV - TRANS ANC 820,738
ANCILLARY SERVICES REVENUE 071,318
Non-Arm Wheeling 139,748
Post Merg Firm Wheeling 100,160
1.11 Pre Merg Firm Wheel PPL 611,571
Pre Merg Firm Wheel UPL 673,914
Short-term Firm Wheeling 629,915
USE OF FACILITY-REVENUE 025,300
Total Revenues from Transmission 246,494
TOTAL Billed 688,35 2 983,333,391 0577
Total Unbilled Rev.(See Instr. 6)108'0734
TOTAL 797,33 2 991,327 391 057€
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
~chedule Page: 304 Lin No.42 Column:
For a further discussion on unbilled revenue refer to page 300 Electric Operating Revenues, line 12 column (b).
IFERC FORM NO.1 (ED. 12-87)Page 450,
Blank Page
(Next Page is: 310)
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2006/04
(2) CiA Resubmission 05/17/2007
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:
RO - 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 IF service). This category should not be used for long-term firm service which meets the
definition of RQ service. For all transactions identified as IF, 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 IF 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.
Une Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing lWer Averali5cationTariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
Brigham City
Deaver, Town of T-4
Helper City T-6
Helper City Annex T-6
Navajo Tribal Utility Authority -
(Mexican Hat)
Navajo Tribal Utility Authority -
(Red Mesa)
Portland General Electric Co.147
Price City
Accrual True-up
American Electric Power WSPP
Anaheim, City of WSPP
Arizona Public Service Co.
,,--
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 05/17/2007
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the length of the contract and service from designated units of less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
Total" in column (a) as the last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
G. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (GO-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (GO-minute
integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-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)
(j)
(k)
110,660 754 614 927 702 682 316
028 768 18,535 33,303
132 110,354 108,559 218,913
786 976 025 139,001
139 500 19,840 340
960 110,419 121 155 233,764
11,048 921 365 921,365
75,365 158,002 313,689 2,471,691
805
279,800 13,410,074 432,974
360 16,615 16,615
96 ,600 835,020 835,020
216 028 241,633 4,497 870 615 738 888
13,440,509 56,231 133 042,326,068 355,391 397 743,165,804
13,656,537 59,472,766 046,823,938 355,392,012 750 904 692
FERC FORM NO.1 (ED. 12-90)Page 311
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006/04
(2) (JA Resubmission 05/17/2007
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote
any ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of IF service). This category should not be used for long-term firm service which meets the
definition of RQ service. For all transactions identified as IF, 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 IF 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.
Une Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera
pie Avera
cation Tariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Arizona Public Service Co.
2 Arizona Public Service Co.
3 Avista Corp.WSPP
4 Avista Corp.
5 Avista Corp.
6 Avista Corp.WSPP
7 Avista Energy, Inc.WSPP
8 Avista Energy, Inc.
9 Avista Energy, Inc.WSPP
BP Energy Company WSPP
Barclays Bank PLC
Basin Electric Power Cooperative
Basin Electric Power Cooperative WSPP
Basin Electric Power Cooperative
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
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.
G. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (GO-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (GO-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 iine 24.
10. Footnote entries as required and provide explanations following all required data.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/04
MegaWatt Hours
Sold
(g)
REVENUE
Energy Charges
($)
(i)
Other Charges
($)(j)
Total ($)
(h+i+j)
(k)
Demand Charges
($)
(h)
118
649,724
323,482
805,112
323,482
31,805 112
125
2,476
445,048
13,610
178
32,628,496
132,572 030
556,060
232,922
25,995
028
120 365
220
736,674
320 761
246,423
084
426
216,028
440,509
241,633
56,231,133
4,497,870
042,326,068
615
355,391,397
738 888
743,165,804
13.656,537 59.472,766 046,823 938 355 392 012 750,904 692
FERC FORM NO.1 (ED. 12-90)Page 311.
Line
No.
This ~ort Is:(1) ~An Original
(2) A Resubmission
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:
RO - 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 suppliers service to its own ultimate consumers.
lF - for tong-term service. "long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of lF service). This category should not be used for long-term firm service which meets the
definition of RQ service. For all transactions identified as lF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as lF service except that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
lU - for long-term service from a designated generating unit. "long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as lU service except that "intermediate-term" means
Longer than one year but less than five years.
Name of Respondent
PacifiCorp
Une
No.
Name of Company or Public Authority
(Footnote Affiliations)
Statistical
Classifi-cation
(b)(a)
1 Basin Electric Power Cooperative
2 Bear Energy LP
3 Benton County PUD No.
4 Black Hills Power, Inc.
5 Black Hills Power, Inc.
6 Black Hills Power, Inc.
7 Blanding City
8 Blanding City
9 Bonneville Power Administration
10 Bonneville Power Administration
11 Bonneville Power Administration
12 Bonneville Power Administration
13 Bonneville Power Administration
14 Bonneville Power Administration
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)
FERC Rate
Schedule orTariff Number
(c)
WSPP
WSPP
441
WSPP
WSPP
543
370
Page 310.
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006104
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)verage Averag,eMonthly NCP Deman Monthly CPTIemand(e) (f)
This ~rt Is: Date of Report(1) l!.IAn Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
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 averagemonthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2006/04
Name of Respondent
PacifiCorp
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
31,204 787 447 787 447
155 109,210 109,210
870 309,176 309,176
364,826 112 239 022,898 10,135,
400 19,600 600
102 486 379,052 379,052
648
12,857 176,199 333,008 509,207
82,733
589
353.629 14,498,789 14,498,789
368 085,655 085 655
330 82,617
942 135,971
216,028
13,440,509
241 633
56,231 133
4,497,870
042,326,068
-615
355 391,397
738 888
743 165.804
656,537 59,472,766 046,823,938 -1,355,392,012 750,904,692
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~rt Is:Date of Report YeauPeriod m Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 05/17/2007
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote
any ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
lF - for tong-term service. "long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of lF service). This category should not be used for long-term firm service which meets the
definition of RO service. For all transactions identified as lF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as lF service except that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for long-term service from a designated generating unit. "long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as lU service except that "intermediate-term" means
longer than one year but less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Aver
cwe Avera
cation Tariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
Bonneville Power Administration
Bonneville Power Administration WSPP
British Columbia Transmission Corp.
4 Burbank, City WSPP
5 CaJifomia Independent System Operator
6 Califomia Independent System Operator
Cargill Power Markets, LLC
Cargill Power Markets, LLC
9 Cargill Power Markets, LLC
Chelan County PUD No.WSPP
Citigroup Energy, Inc.
City of Roseville WSPP
Clark Public Utilities
Clark Public Utilities
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~rt Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
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 averagemonthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 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 2006/04
Name of Respondent
PacifiCorp
MegaWatt Hours REVENUE LineTotal ($)
Sold Demand Charges Energy Charges (h+i+j)No.
($)($)(g)
(h)(i)(k)
107
273 760 146,585 146,585
619
137,756 983 194 983,194
368 129,923
215,534 940,487 940,487
859 085,832
8,463 392,676 392 676
291 ,087 65,768,500 65,768,500
056 56,480 56,480
973,161 271,370 59,271 370
511 665 665
131 801
789,135 296,826 33,589,326 35,886,152
216 028
13,440,509
241 ,633
56,231,133
4,497,870
042,326,068
615
355,391 397
738,888
743,165,804
13,656,537 59,472,766 046.823,938 355,392 012 750,904 692
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)
End of 2006/04(2) nA Resubmission 05/17/2007
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.
Une Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Aver Avera
cation Tariff Number Demand (MW)Monthly NC Deman!Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Clatskanie People s Utility District WSPP
Colorado River Commission of Nevada WSPP
Colorado Springs Utilities WSPP
Colorado Springs Utilities WSPP
Conoco Inc.
Constellation Energy Commodities Group
7 Coral Power
8 Coral Power WSPP
Credit Suisse Energy LLC
DB Energy Trading LLC
Douglas County PUD No.WSPP
Duke Energy Trading & Marketing, LLC
ENMAX Energy Marketing Inc.WSPP
EPCOR Merchant and Capita/Inc.WSPP
Subtotal RO
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 2006/04(2) DA Resubmission 05/17/2007
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the length of the contract and service from designated units of less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
Total" in column (a) as the last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
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 (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (D. Explain in a footnote all components of the amount shown in column OJ. 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)
(j)
(k)
615 348 025 348,025
34,065 180,220 180,220
709 113,376 113,376
865 160,529 160,529
219,777 536,020 536,020
521,505 058,939 84,058,939
159
661,806 92,700,646 700,646
108,000 833,304 833,304
245,155 854,127 12,854 127
005 149,760 149,760
19,519 083,147 083,147
567 436 436
15,354 773 157 773,157
216,028 241 633 4,497,870 615 738,888
13,440,509 56,231 133 042,326,068 355,391 397 743,165,804
13,656,537 59,472 766 046 823,938 355,392,012 750 904,692
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 05/17/2007
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote
any ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of IF service). This category should not be used for long-term firm service which meets the
definition of RO service. For all transactions identified as IF, 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 IF 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 Aver
cwe Avera
!f5cationTariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 EI Paso Electric Company WSPP
2 EI Paso Electric Company WSPP
3 Eugene Water & Electric Board
4 Eugene Water & Electric Board WSPP
5 Eugene Water & Electric Board
6 Eugene Water & Electric Board WSPP
7 FPL Energy Power Marketing, Inc.WSPP
8 Flathead Electric Cooperative
9 Flathead Electric Cooperative
Fortis Energy Marketing & Trading GP WSPP
Franklin County PUD No.WSPP
Gila River Power, loP.WSPP
Glendale, City of WSPP
Grant County PUD No.WSPP
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~rt Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
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 averagemonthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2006/04
Name of Respondent
PacifiCorp
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)
(j)
(k)
670 37,355 38,330
108,419 5,472,023 5,472,023
138
109,571 109,571
531 21,447
27,539 1,457 371
20,270 099,190
759
111 496 618,376 569,376
90,200 645,189 645,189
446 168,879 168,879
128,800 947,131 947 131
2,450 2,450
45,055 098,514 098,514
216,028
13,440,509
241,633
56,231,133
4,497 870
042,326,068
615
355 391 397
738,888
743,165,804
13,656,537 59,472 766 046 823,938 355 392 012 750 904 692
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 2006/04
(2) CiA Resubmission 05/17/2007
SALES FOR RESALE (Account 447)
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:
RO - 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 IF service). This category should not be used for long-term firm service which meets the
definition of RQ service. For all transactions identified as IF, provide in a footnote the tennination 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 IF 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.
Una Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Avera Avera
!J5cationTariff Number Demand (MW)Monthly NC Demam Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Grays Harbor Public Utility District WSPP
Hurricane, City of
3 Idaho Power Company
..-.
WSPP
Idaho Power Company
5 Idaho Power Company WSPP
6 Idaho Power Company
Idaho Power Company
8 Idaho Power Company WSPP
9 J. Aron & Company
J. Aron & Company
P. Morgan Ventures Energy Corporation
Lehman Brothers Commodity Services, Inc
Los Angeles Dept. of Water & Power 301
Los Angeles Dept. of Water & Power WSPP
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
SALES FOR RESALE (Account 447 (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the length of the contract and service from designated units of less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
Total" in column (a) as the last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-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 2006/04
Name of Respondent
PacifiCorp
MegaWatt Hours REVENUE Total ($)Une
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
865 267 100 267 100
431 628,068 628,068
550
123 89,108
13,035
643 446,000
279 12,273
223,331 10,235,106 10,235,106
446 22,476
124,800 48,688,520 688,520
246,184 210,116 14,210,116
111,625 575,854 575 854
593,481 25,128,957 25,128,
381 148,835 148,835
216,028
13,440,509
241 ,633
56,231,133
4,497,870
042,326,068
615
355,391 397
738,888
743,165,804
13,656 537 59,472 766 046,823,938 355,392 012 750,904,692
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PaciliCorp
(1) X An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 05/17/2007
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote
any ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
lF - for tong-term service. "long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of lF service). This category should not be used for long-term firm service which meets the
definition of RO service. For all transactions identified as lF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as lF service except that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for long-term service from a designated generating unit. "long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as lU service except that "intermediate-term" means
longer than one year but less than five years.
Une Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Aver
cwe Avera
cation Tariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(I)
Los Angeles Dept. of Water & Power WSPP
Merrill Lynch Commodities, Inc.WSPP
Modesto Irrigation District WSPP
Morgan Stanley Capital Group, Inc.
Morgan Stanley Capital Group, Inc.
Morgan Stanley Capital Group, Inc.
Morgan Stanley Capital Group, Inc.
Municipal Energy Agency of Nebraska WSPP
Municipal Energy Agency of Nebraska WSPP
Nevada Power Company WSPP
NorthWestem Energy NJI
Northem Calilomia Power Agency WSPP
Northpoint Energy Solutions Inc.WSPP
Occidental Power Services, Inc.WSPP
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 05/17/2007
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the length of the contract and service from designated units of less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE LineTotal ($)
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)
(j)
(k)
219,212 11,844,495 11,844,495
199,470 423,970 10,423 970
25,320 1 ,406,596 1,406,596
96 ,600 836,095 836,095
400 22,000 22 ,000
864 224,797
464,319 383,725,629 383,725,629
510 21,150 21,150
14,557 803,155 803,155
387,084 23,444,867 23,444 867
579 31,768
110,353 998,796 998,796
23,200 089,320 089,320
12,393 700,935 700,935
216,028 241 633 4,497 870 615 738,888
13,440,509 56,231 133 042,326,068 355,391 397 743,165,804
656,537 59,472 766 046 823 938 355,392 012 750,904 692
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006/04
(2) FiA Resubmission 05/17/2007
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 IF service). This category should not be used for long-term firm service which meets the
definition of RQ service. For all transactions identified as IF, 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 IF 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.
Une Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(1)
1 PPL Energy Plus, LLC WSPP
PPL Montana, LLC WSPP
PPL Montana, LLC
PPL Montana, LLC WSPP
5 PPM Energy, Inc.
6 PPM Energy, Inc.
7 PPM Energy, Inc.
8 PPM Energy, Inc.WSPP N.ii
Pacific Gas & Electric Company WSPP
Pacific Northwest Gen. Cooperative WSPP
Pasadena, City of WSPP
Pinnacle West Capital Corporation
Portland General Electric Co.
Portland General Electric Co.
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~ort Is: Date of Report
(1) l2UAn Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
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 averagemonthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (6D-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-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.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/04
MegaWatt Hours REVENUE Total ($)Une
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)
(j)
(k)
23,800 301 550 301,550
625 88,095 88,575
972 90,116
53,653 645,411 645,411
350 233,424
17,051 770,164
11,821 546,975
290,846 13,503 947 13,454,815
353 981,011 981,011
10,715 528,945 528,945
174 267,590 267,590
315,425 24,865,948 865,948
428 968
831
216,028
13,440,509
241 633
56,231,133
4,497 870
042,326,068
615
355,391,397
738,888
743,165,804
13,656,537 59,472 766 046,823,938 355,392 012 750,904,692
FERC FORM NO.1 (ED. 12-90)Page 311.
This ~ort Is:(1) I!.JAn Original(2) A Resubmission
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:
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 IF service). This category should not be used for long-term firm service which meets the
definition of RO service. For all transactions identified as IF, 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 IF 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.
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/04
Name of Respondent
PacifiCorp
Une Name of Company or Public Authority Statistical FERC Rate Avera
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing
cation Tariff Number Demand (MW)
(a)(b)(c)(d)
1 Portland General Electric Co.
2 Portland General Electric Co.
Powerex WSPP
Powerex
Powerex
Powerex WSPP
Powerex WSPP
Public Service Company of Colorado 320 170
Public Service Company of Colorado
Public Service Company of Colorado WSPP
Public Service Company of Colorado WSPP
Public Service Company of New Mexico WSPP
Public Service Company of New Mexico WSPP
Puget Sound Energy
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~rt Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 05/17/2007
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the length of the contract and service from designated units of less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2006/04
Name of Respondent
PacifiCorp
MegaWatt Hours REVENUE Total ($)Une
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)
(j)
(k)
494,283 27,890,206 27,890,206
738
325
13,611 620 187
958 596,617
689 20,608 20,608
521 624 042 094 042,094
150,736 28,110,720 372 880 59,483,600
380 136,817
607 234,920 234,920
570,727 28,980,419 28,980,419
665 132,475 136,175
443 900 21,972,895 972,895
933
216,028
13,440,509
241,633
56,231,133
4,497 870
042,326,068
615
355,391,397
738,888
743,165,804
13,656,537 59,472,766 046,823 938 355,392 012 750,904,692
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006/04
(2) rJA Resubmission 05117/2007
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote
any ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the suppliers service to its own ultimate consumers.
LF - for tong-term service. "long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of lF service). This category should not be used for long-term firm -service which meets the
definition of RQ service. For all transactions identified as lF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as lF service except that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for long-term service from a designated generating unit. "long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as lU service except that "intermediate-term" means
Longer than one year but less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Puget Sound Energy WSPP
Rainbow Energy Marketing
3 Rainbow Energy Marketing WSPP
Redding, City of WSPP
5 SUEZ Energy Marketing NA, Inc.WSPP
6 Sacramento Municipal Utility District 250
7 Sacramento Municipal Utility District 250
8 Sacramento Municipal Utility District WSPP
9 Salt River Project WSPP
Salt River Project WSPP Nfl
Salt River Project WSPP Nfl
San Diego Gas & Electric WSPP Nfl
Santa Clara, City of WSPP Nfl
Seattle City Light'Nfl
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
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 averagemonthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (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 ROINon-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 2006/04
Name of Respondent
PacifiCorp
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)
(j)
(k)
352,469 16,785,494 16,785,494
593 70,006
21,200 1 ,040,840 1 ,040,840
675 39,374 39,374
118 151 998,357 998,357
288,137
530,157 797,301 797,301
77,932 598,561 598,561
73,200 354,126 354 126
650 429,185 429,185
503,277 26,618,878 26,618,878
161 310,095 310,095
41,476 363,416 363,416
287
216,028
13,440,509
241 633
56,231,133
4,497 870
042,326,068
615
355,391 397
738,888
743,165,804
13,656,537 59,472,766 046,823,938 355 392 012 750,904,692
FERC FORM NO.1 (ED. 12-90)Page 311.
This ~ort Is:(1) ~An Original
(2) A Resubmission
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote
any ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
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 IF service). This category should not be used for long-term firm service which meets the
definition of RQ service. For all transactions identified as IF, 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 IF 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.
Date of Report
(Mo, Da, Yr)
05/17/2007
YearlPeriod of Report
End of 2006/04
Name of Respondent
PacifiCorp
Une Name of Company or Public Authority Statistical FERC Rate Avera
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing
cation Tariff Number Demand (MW)
(a)(b)(c)(d)
1 Seattle City Ught WSPP
2 Sempra Energy Solutions WSPP
3 Sempra Energy Trading Corp.
4 Sempra Energy Trading Corp.
5 Sempra Generation
6 Sierra Pacific Power Company 258
7 Sierra Pacific Power Company 267
8 Sierra Pacific Power Company
9 Sierra Pacific Power Company
10 Sierra Pacific Power Company 258
11 Sierra Pacific Power Company 267
12 Sierra Pacific Power Company
13 Sierra Pacific Power Company WSPP
14 Sierra Pacific Power Company
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~rt Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
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 averagemonthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2006/04
Name of Respondent
PacifiCorp
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
001 522,216 522,216
920 091 394 091 394
271 404,481
164,107 254,640,684 254 640,684
000 746,400 746,400
720 900
832 26,304
918
483
459 900 15,102 000 16,432,227 534,227
132 982 982
790 36,691
958 262,738
243 305 181
216,028
440,509
241,633
56,231 133
4,497,870
042,326,068
615
355,391 397
738,888
743,165,804
13,656,537 59,472,766 046,823,938 355,392 012 750,904,692
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 05/17/2007
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote
any ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
lF - for tong-term service. "long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of IF service). This category should not be used for long-term firm service which meets the
definition of RO service. For all transactions identified as IF, 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 IF 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.
Une Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Aver Avera
cation Tariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
Sierra Pacific Power Company
Sierra Pacific Power Company WSPP
Snohomish Public Utility District No.WSPP
Southem Califomia Edison Company 248
Southem Califomia Edison Company
Southwestem Public Service Company WSPP
State of Califomia Department of WSPP
Water Resources
Tacoma, City of WSPP
The Cincinnati Gas & Electric Company WSPP
TransAlta Energy Marketing Inc.
TransAlta Energy Marketing Inc.WSPP
Tri-State Generation & Transmission WSPP
Tri-State Generation & Transmission
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~rt Is: Date of Report
(1) I!UAn Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
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 averagemonthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (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 ROINon-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 2006/04
MegaWatt Hours
Sold
(g)
REVENUE
Energy Charges
($)
(i)
445
25,966,951
1,487,325
44,160,000
661,470
848,118
202,792
Demand Charges
($)
(h)
Other Charges
($)
Total ($)
(h+i+j)
(k)
479 260
30,825
736 000
770
11 ,638
18,400
25,966,951
1,487,325
160,000
661,470
848 118
202,792
580
320
636,690
458
655
132,931
551 550
132,931
551,550
507
34,054,450
290,463
28,413
029,950
290,463
216 028
13,440,509
241,633
56,231,133
4,497 870
042,326,068
615
355,391,397
738,888
743,165 804
13,656,537 59,472,766 046,823,938 355,392 012 750,904,692
FERC FORM NO.1 (ED. 12-90)Page 311.
Line
No.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 05/17/2007
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 suppliers service to its own ultimate consumers.
lF - for tong-term service. "long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of IF service). This category should not be used for long-term firm service which meets the
definition of RQ service. For all transactions identified as IF, 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 IF 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.
Une Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Avera Averall5cationTariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Tri-State Generation & Transmission WSPP
Tucson Electric Power WSPP
Tucson Electric Power WSPP
Turlock Irrigation District WSPP
5 UBS Warburg Energy LLC
6 Utah Associated Municipal Power Systems WSPP
7 Utah Associated Municipal Power Systems WSPP
8 Utah Associated Municipal Power Systems
9 Utah Associated Municipal Power systems WSPP
Utah Municipal Power Agency 433
Utah Municipal Power Agency
Westem Area Power Administration
Westem Area Power Administration WSPP
Westem Area Power Administration
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~rt Is: Date of Report(1) l!.JAn Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the length of the contract and service from designated units of less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
Total" in column (a) as the last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-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.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/04
MegaWatt Hours REVENUE Line
Sold Demand Charges Energy Charges Other Charges Total ($)
No.
($)($)($)
(h+i+j)
(g)
(h)(i)
(j)
(k)
186,490 36,949 10,328,929 10,365,878
532 30,003 30,
79,130 598 164 598,164
20,225 085 884 085,884
410,504 84,977,271 84,977 271
17,509 665,342 665,342
495 815 22,815
473
344 687 970 687,970
218,884 396,200 086,864 9,483,064
149 227 349 227 349
905
302 362,057 362,057
292
216,028
13,440,509
241 633
56,231,133
4,497 870
042,326,068
615
355,391,397
738,888
743 165,804
13,656,537 59,472,766 046 823,938 355,392,012 750 904 692
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
0ort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo. Da, Yr)End of 2006/04(2) riA Resubmission 05/17/2007
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., 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.
Une Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing AVera Avera
cation Tariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(I)
1 Westem Area Power Administration WSPP
2 Weyerhaeuser
3 Bookout Sales
4 Bookout Sales
5 Test Generation
6 Trade Sales
7 Trade Sales
8 Accrual True-up NJI NJ!
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
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 (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-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.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/04
MegaWatt Hours
Sold
(g)
REVENUE
Energy Charges
($)
(i)
Other Charges
($)
Total ($)
(h+i+j)
(k)
Demand Charges
($)
(h)
138,173
019
632
277 378
238,660
041 381 041 381
135 743
241 757
004 967,209
125 197
1 ,400
363,399,842
16,988,282122,531
216,028
13,440,509
241 633
56,231 133
4,497 870
042 326 068
615
355,391.397
738,888
743,165,804
13,656 537 59,472 766 046 823 938 355,392,012 750,904 692
FERC FORM NO.1 (ED. 12-90)Page 311.
Une
No.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
!schedule Page: 310 Line No.Column:
ettlement Adjustment
!schedule Page: 310 Line No.11 Column:j
ccrual True-up
Ischedule Page: 310 Line No.12 Column:
Li uidated Damages
chedule Page: 310 Line No.14 Column: b
Arizona Public Service Co. - FERC - T-I2 - Contract terminination date: December 31 2006.
Ischedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-fIrm sales, including some hourly firm transactions.
ISchedule Page: 310.Line No.Column: b
econdary, Economy and/or non-fIrm sales, including some hourly firm transactions.
Ischedule Page: 310.Line No.Column:
perating Reserves
Ischedule Page: 310.Line No.Column:
ransmission Losses
Ischedule Page: 310.Line No.Column:
eserve Share
Ischedule Page: 310.Line No.Column: b
econdary, Economy and/or fIrm sales, including some hourly firm transactions.
Ischedule Page: 310.Line No.Column:
perating Reserves
Ischedule Page: 310.Line No.Column:
ransmission Losses
Ischedule Page: 310.Line No.12 Column: b
Basin Electric Power Company - FERC - T -11 (Evergreen Network Transmission Service under the Open Access Transmission Tariff
A. 228 & 233)) - Contract termination date: 12 months notification.
Ischedule Page: 310.Line No.12 Column:
Transmission Losses
ISchedule Page: 310.Line No.13 Column: b
Secondary, Economy and/or non-firm sales, including some hourly fIrm transactions.
!schedule Page: 310.Line No.14 Column:
ransmission Losses
Ischedule Page: 310.Line No.Column: b
Black Hills Power & Light Company - FERC 236 - Contract termination date: December 31 , 2023.
Ischedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-fIrm sales, including some hourly fIrm transactions.
ISchedule Page: 310.Line No.Column: b
Settlement Adjustment.
Ischedule Page: 310.Line No.Column:
Settlement Ad'ustment
chedule Pa e: 310.Line No.Column: b
Blanding City - FERC T-12 -Contract termination date: March 1 2007.
ISchedule Page: 310.2 Liire-~o.Column: b
Settlement Ad'ustment.
Schedule Page: 310.Line No.Column:
Settlement Adjustment
!Schedule Page: 310.Line No.: 10 Column: b
Settlement Adjustment.
Schedule Page: 310.LTneNo.: 10 Column:
.-------
, _~.._.._n_'__-
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
ettlement Adjustment
!schedule Page: 310.Line No.11 Column: b
onneville Power Administration - FERC 543 - Contract termination date: September 30, 2006.
!schedule Page: 310.Line No.12 Column: b
Bonneville Power Administration - FERC T-12 - Contract termination date: A ri122, 2024.
chedule Page: 310.Line No.13 Column: b
Secondary, Economy and/or non-fIrm sales, includin some hourly firm transactions.
chedule Pa e: 310.Line No.13 Column:
Transmission Losses
ISchedule Page: 310.Line No.14 Column: b
econdary, Economy and/or non-fIrm sales, including some hourly firm transactions.
!schedule Page: 310.Line No.14 Column:
Transmission Losses
'Schedule Page: 310.Line No.Column:
ransmission Losses
!schedule Page: 310.Line No.Column:
eserve Share
!schedule Page: 310.Line No.Column: b
ettlement Adjustment.
!schedule Page: 310.Line No.Column:
Settlement Adjustment
!schedule Page: 310.Line No.Column: b
econdary, Economy and/or non-fIrm sales, including some hourly fIrm transactions.
!schedule Page: 310.Line No.Column:
Transmission Losses
!schedule Page: 310.Line No.Column: b
econdary, Economy and/or non-firm sales, including some hourly firm transactions.
!schedule Page: 310.Line No.13 Column: b
ettlement Adjustment.
!schedule Page: 310.Line No.13 Column:
ettlement Adjustment
!schedule Page: 310.Line No.14 Column: b
lark County PUD #1 - FERC T-12 - Contract termination date: December 12 2007.
!schedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-fIrm sales, including some hourly fIrm transactions.
!Schedule Page: 310.4 Line No.Column:
ransmission Losses
!schedule Page: 310.Line No.Column: b
econdary, Economy and/or non-fIrm sales, including some hourly firm transactions.
chedule Page: 310.Line No.Column:
Operating Reserves
ISchedule Page: 310.Line No.Column: b
econdary, Economy and/or non-fIrm sales, including some hourly firm transactions.
!schedule Page: 310.Line No.Column:
ransmission Losses
!schedule Page: 310.Line No.Column: b
econdary, Economy and/or non-fIrm sales, including some hourly firm transactions.
~chedule Page: 310.Line No.Column:
Transmission Losses
ISchedule Page: 310 Line No.Column: b
Settlement Adjustment.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
~chedu7e Page: 310.Line No.Colu~n
ettlement Adjustment
~chedule Page: 310.Line No.Column: b
Flathead Electric Coo erative, Inc. - FERC T-12 - Contract tennination date: Se tember 30, 2006.
chedule Page: 310.Line No.Column: j
Unauthorized Use Charge
ISchedule Page: 310.Line No.Column: b
urricane, City of - FERC T-12 - Contract tennination date: August 31, 2007.
~chedule Page: 310.Line No.Column: b
Settlement Ad'ustment.
chedule Page: 310.Line No.Column: j
ettlement Adjustment
~chedule Page: 310.Line No.Column: b
Idaho Power Company - FERC - T-ll (Point-to-Point Transmission Service under the Open Access Transmission Tariff(SA 212))-
ontract tennination date: May 31, 2009.
~chedule Page: 310.Line No.Column: j
ransmission Losses
~chedule Page: 310.Line No.Column: b
econdary, Economy and/or non-fInD sales, including some hourly finn transactions.
~chedule Page: 310.Line No.Column: j
perating Reserves
~chedule Page: 310.Line No.Column: j
ransmission Losses
~chedule Page: 310.Line No.Column: j
Reserve Share
~chedule Page: 310.Line No.Column: j
ransmission Losses
~chedule Page: 310.Line No.13 Column: b
os Angeles Department of Water and Power - FERC 301 - Contract tennination date: June 15 2027.
~chedule Page: 310.Line No.14 Column: b
econdary, Economy and/or non-firm sales, including some hourly firm transactions.
~chedule Page: 310.Line No.Column: b
organ Stanley Capital Group, Inc. - FERC - T-12 - Contract tenninination date: December 31, 2006.
~chedule Page: 310.Line No.Column: b
econdary, Economy and/or non-firm sales, including some hourly finn transactions.
~chedule Page: 310.Line No.Column: j
Transmission Losses
!Schedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-fInD sales, including some hourly fInD transactions.
Schedule Page: 310.Line No.11 Column: j
Reserve Share
~chedule Page: 310.Line No.Column: b
econdary, Economy and/or non-firm sales, includin some hourly fInD transactions.
~chedule Page: 310.Line No.Column: j
perating Reserves
~chedule Page: 310.Line No.Column: j
ransmission Losses
~chedule Pa e: 310.
~-
Line No.Column: b
Settlement Adjustment and PPM Energy was an affiliate of the respondent through March 20, 2006.
'Schedule Page: 31!i
~=-
Line No.ColumnL-
,-----
Settlement Adjustment
IFERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
~chedule Page: 31~iine No.Column: b
PPM Energy - FERC - T-II (Point-to-Point Transmission Service under the Open Access Transmission Tariff (S.A. 279)) - Contract
rmination date: 12 months written notification. PPM Energy was an affiliate of the respondent through March 20 2006.
~chedule Page: 31ifB Line No.Column:
ransmission Losses and Unauthorized Use Charge
~chedule Page: 310.Line No.Column: b
PPM Energy was an affiliate of the res ondent through March 20, 2006.
chedule Page: 310.Line No.Column:
Transmission Losses
~chedule Page: 310.Line No.Column: b
PM Energy was an affiliate of the respondent through March 20, 2006.
~chedule Page: 310.Line No.Column:
Li uidated Damages
chedule Pa e: 310.Line No.13 Column: b
econdary, Economy and/or non-fmn sales, including some hourly firm transactions.
~chedule Page: 310.Line No.13 Column:j
erating Reserves
chedule Page: 310.Line No.14 Column:
ransmission Losses
~chedule Page: 310.Line No.Column:
eserve Share
~chedule Page: 310.Line No.Column: b
ettlement Adjustment.
~chedule Page: 310.Line No.Column:
ettlement Adjustment
~chedule Page: 310.Line No.Column: b
PowerEX - FERC - T -II (Point-to-Point Transmission Service under the Open Access Transmission Tariff (SA 169)) - Contract
termination date: Se tember 30 2007.
chedule Pa e: 310.Line No.Column:
ransmission Losses
~chedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-firm sales, including some hourly finD transactions.
~chedule Page: 310.Line No.Column:
Transmission Losses
~chedule Page: 310.Line No.Column: b
econdary, Economy and/or non-firm sales, including some hourly fmn transactions.
!schedule Page: 310.Line No.Column: b
blic Service Company of Colorado - FERC 320 - Contract tennination date: December 31 , 2011.
~chedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-firm sales, including some hourly fInD transactions.
~chedule Page: 310.Line No.Column:
Transmission Losses
~chedule Page: 31g.9Line No.: 10 Column: b
econdary, Economy and/or non-fmn sales, including some hourly finD transactions.
~chedule Page: 310
~___
!!,!e No.12 Column: b
Secondary, Economy and/or non-fmn sales, including some hourly finD transactions.
~chedule Page:~!QJr~line No.12 Column:j
____-
Operating Reserves
~chedule Page
!!-
Line No.14 Column:
Reserve Share
ISchedule Page: ~1Q 1JJ~ine No.Column:j
-~,...
IFERC FORM NO.1 (ED. 12-87)Page 450.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da , Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
Transmission Losses
~chedule Page: 310.10 Line No.Column: b
Settlement Adjustment.
ISchedule Page: 310.10 Line No.Column: j
ettlement Adjustment
~chedule Page: 310.10 Line No.Column: b
Sacramento Munici al Utility District - FERC 250 - Contract termination date: December 31 , 2014.
chedule Page: 310.10 Line No.Column: b
alt River Project - WSPP - Contract termination date: December 31 , 2009.
~chedule Page: 310.10 Line No.: 10 Column: b
econdary, Economy and/or non-firm sales, including some hourly fmn transactions.
~chedule Page: 310.10 Line No.14 Column: j
eserve Share
~chedule Page: 310.11 Line No.Column: b
econdary, Economy and/or non-fmn sales, including some hourly fmn transactions.
~chedule Page: 310.11 Line No.Column: j
ransmission Losses
~chedule Page: 310.11 Line No.Column: b
ettlement Adjustment.
~chedule Page: 310.11 Line No.Column: i
ettlement Adjustment
~chedule Page: 310.11 Line No.Column: b
ettlement Adjustment.
~chedule Page: 310.11 Line No.Column: j
ettlement Adjustment
~chedule Page: 310.11 Line No.Column: b
Settlement Adjustment.
~chedule Page: 310.11 Line No.Column: j
ettlement Adjustment
~chedule Page: 310.11 Line No.Column: b
ettlement Adjustment.
~chedule Page: 310.11 Line No.Column: j
Settlement Ad'ustment
chedule Pa e: 310.11 Line No.: 10 Column: b
SieITa Pacific Power Com any - FERC 258 - Contract termination date: February 28, 2009.
Schedule Page: 310.11 Line No.11 Column: b
SieITa Pacific Power Com any - FERC 267 - Contract termination date: A ril 30, 2021.
chedule Page: 310.11 Line No.12 Column: b
SieITa Pacific Power Company - FERC - T -11 (Pavant Capacitor Ownership, Operation and Maintenance Letter Agreement dated
November 9 2000) - Contract termination date: 90 days notification.
~chedule Page: 310.11 Line No.12 Column:j
ransmission Losses
~chedule Page: 310.11 Line No.13 Column: b
econdary, Economy and/or non-firm sales, including some hourly fmn transactions.
~chedule Page: 31~ Line No.14 Column: j
Transmission Losses
ISchedu/Page: 310.Line No.Column: j
eserve Share
~chedule Page: 310.12 Line No.Column: b
Southern California Edison Company - FERC 248 - Contract termination date: Se tember 30, 2006.
ISchedule Page:l1Q~
!'~~
jne No.11 Column: j
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
ransmission Losses
~chedule Page: 310.12 Line No.12 Column:
Li uidated Damages
chedule Page: 31 12 Line No.13 Column: b
Secondary, Economy and/or non-finD sales, including some hourly finD transactions.
ISchedule Page: 310.12 Line No.14 Column:
ransmission Losses
~chedule Page: 310.13 Line No.Column: b
Secondary, Economy and/or non-fmn sales, including some hourly fmn transactions.
ISchedule Page: 310.13 Line No.Column: b
econdary, Economy and/or non-fmn sales, including some hourly fmn transactions.
~chedule Page: 310.13 Line No.Column:
ransmission Losses
~chedule Page: 310.13 Line No.10 Column: b
Utah Municipal Power Agency - FERC 433 - Contract tennination date: June 30 2017.
~chedule Page: 310.13 Line No.12 Column: b
Western Area Power Administration - FERC -ll (Evergreen Network Transmission Service under Transmission Service and
eratin A eement for network service in PACE) - Contract tennination date: 90 days notification.
chedulePage:310.13 LineNo.:12 Column:j
ransmission Losses
~chedule Page: 310.13 Line No.13 Column: b
econdary, Economy and/or non-fmn sales, including some hourly fmn transactions.
~chedule Page: 310.13 Line No.14 Column:
ransmission Losses
~chedule Page: 310.14 Line No.Column: b
Weyerhaeuser - FERC - T-ll (point-to-Point Transmission Service under the Open Access Transmission Tariff (S.A. 320)) - Contract
tennination date: December 31 , 2006.
~chedule Page: 310.14 Line No.Column:
ransmission Losses
~chedule Page: 310.14 Line No.Column: b
Settlement Ad' ustment.
chedule Pa e: 310.14 Line No.: 3 Column:
ettlement Adjustment
~chedule Page: 310.14 Line No.: 4 Column:
ecognition and reporting of gains and losses on bookouts under EITF Issue No. 03-
~chedule Page: 310.14 Line No.: 5 Column: b
econdary, Economy and/or non-finD sales, including some hourly finD transactions.
~chedule Page: 310.14 Line No.Column:
The negative revenue reported on this line reflects test energy generated at the Current Creek and Leaning Juniper power plants that
were transferred to construction. Energy generated during testing was delivered to PacifiCorp s electric system for sale, as required by
the guidance in 18 CFR Electric Plant Instructions 18(a), is a component of construction and is the fair value of the energy delivered.
~chedule Page: 310.14 Line No.Column: b
ettlement Adjustment.
~chedule Page: 310.14 Line No.Column:
Settlement Adjustment
ISchedule Page: 310.14 Line No.Colu'!'n:
Reco ition and reporting of gains and losses on energy trading contracts under EITF Issue No. 02-03.
Schedule Pa e: 14 Line No.Column:
Accrual True-up
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) riA Resubmission 05/17/2007
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account
IIiiIIIiiiI
mount for AmountJorCurrent Year PrevIous Year
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering 22 686,191 24,017,1245 (501) Fuel 485 079,578 460,560,6016 (502) Steam Expenses 32,320,388 34,694,6137 (503) Steam from Other Sources 3 110 724 4 211,469
8 (Less) (504) Steam Transferred-Cr.
9 (505) Electric Expenses
10 (506) Miscellaneous Steam Power Expenses
11 (507) Rents
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12)
14 Maintenance
15 (510) Maintenance Supervision and Engineering
16 (511) Maintenance of Structures
17 (512) Maintenance of Boiler Plant
18 (513) Maintenance of Electric Plant
19 (514) Maintenance of Miscellaneous Steam Plant
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering
25 (518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr.
30 (523) Electric Expenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
34 Maintenance
35 (528) Maintenance Supervision and Engineering
36 (529) Maintenance of Structures
37 (530) Maintenance of Reactor Plant Equipment
38 (531) Maintenance of Electric Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering
45 (536) Water for Power
46 (537) Hydraulic Expenses
47 (538) Electric Expenses
48 (539) Miscellaneous Hvdraulic Power Generation Expenses
49 (540) Rents
50 TOTAL Operation (Enter Total of Lines 44 thru 49)
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering
54 (542) Maintenance of Structures
55 (543) Maintenance of Reservoirs, Dams, and Waterways
56 (544) Maintenance of Electric Plant
57 (545) Maintenance of Miscellaneous Hydraulic Plant
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)
215,404
30,690,672
173,471
028,397
17,294,691
880,309
579,276,428 545,687,204
604,360
19,475,953
90,246,837
32,506,692
11,617,137
161,450,979
740,727,407
374,328
16,716,514
88,150 437
30,895,424
9,458,599
152,595,302
698,282,506
448,958
241,545
629,403
787
15,883,249
94,633
28,301 575
448,802
155,594
376,778
20,996
17,237,689
175,519
26,415,378
072,249
435,262
948,267
543 440
999,218
34,300 793
088,138
919,845
537 342
582,641
127 966
34,543,344
FERC FORM NO.1 (ED. 12-93)Page 320
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/04
(2) FjA Resubmission 05/17/2007
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (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)
D. Other Power Generation
Operation
(546) Operation Supervision and Engineering 1 ,170,218 586,268
(547) Fuel 129,693,593 461 763
(548) Generation Expenses 12,202,052 10,263,205
(549) Miscellaneous Other Power Generation Expenses 930,812 1,473,786
(550) Rents 13,642,417 17,319,501
TOTAL Operation (Enter Total of lines 62 thru 66)159,639,092 104,523
Maintenance
(551) Maintenance Supervision and Engineering
(552) Maintenance of Structures 239,024 191 273
(553) Maintenance of Generating and Electric Plant 562 314 1 ,424,850
(554) Maintenance of Miscellaneous Other Power Generation Plant 436,088 249,513
TOTAL Maintenance (Enter Total of lines 69 thru 72)237,426 1 ,865,636
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)162 876,518 92;970,159
E. Other Power Supply Expenses
(555) Purchased Power 707,454,156 674,794 888
(556) System Control and Load Dispatching 484,435 451 461
(557) Other Expenses 54,585,469 46,131,142
TOTAL Other Power Supply ExD (Enter Total of lines 76 thru 78)764 524 060 722,377,491
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79)702,428,778 548,173,500
2. TRANSMISSION EXPENSES
Operation
(560) Operation Supervision and Engineering 758,555 6,457 151
(561) Load Dispatching 087,335 512,428
(561.1) Load Dispatch-Reliability
(561.2) Load Dispatch-Monitor and Operate Transmission System 161.724
(561.3) Load Dispatch-Transmission Service and Scheduling
(561.4) Scheduling, System Control and Dispatch Services
(561.5) Reliability, Planning and Standards Development
(561.6) Transmission Service Studies 805,928
(561.7) Generation Interconnection Studies 507 258
(561.8) Reliability, Plannina and Standards Development Services
(562) Station Expenses 320,015 569 390
(563) Ovemead Lines Expenses 320,087 188,772
(564) Underaround Lines Expenses
(565) Transmission of Electricity bv Others 110,633 360,299
(566) Miscellaneous Transmission Expenses 938,870 191 619
(567) Rents 343,348 028,958
TOTAL Operation (Enter Total of lines 83 thru 98)113,353,753 99,308,617
100 Maintenance
101 (568) Maintenance Supervision and Engineering 19,767 11,686
102 (569) Maintenance of Structures 318
103 (569.1) Maintenance of Computer Hardware
104 (569.2) Maintenance of Computer Software 132,256
105 (569.3) Maintenance of Communication Equipment 820,947
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment 10,062 229 520,157
108 (571) Maintenance of Ovemead Lines 10,812,758 587,820
109 (572) Maintenance of Underground Lines 599
110 (573) Maintenance of Miscellaneous Transmission Plant 723,453 847 821
111 TOTAL Maintenance (Total of lines 101 thru 110)576,728 15,974 180
112 TOTAL Transmission Expenses (Total of lines 99 and 111)136,930,481 115,282,797
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) riA Resubmission 05/17/2007
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account
.........
No.urrent ear Previous Year
(a)(b) (c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Day-Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Rights Market Facilitation
118 (575.4) Capacitv Market Facilitation
119 (575.5) Ancillary Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Facilitation, Monitoring and Compliance Services
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)
124 Maintenance
125 (576.1) Maintenance of Structures and Improvements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Software
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Reaional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Enaineering 25,372 966 25,226,709
135 (581) Load Dispatchina 12,310,097 786,336
136 (582) Station Expenses 155,806 301,836
137 (583) Overhead Line Expenses 17,529,369 18,348,654
138 (584) Underaround Line Expenses 527,073 514 228
139 (585) Street Lightina and Signal System Expenses 149 307 192 851
140 (586) Meter Expenses 126,900 033,168
141 (587) Customer Installations Expenses 640
142 (588) Miscellaneous Expenses 14,857,820 20,626,608
143 (589) Rents 324 851 168,615
144 TOTAL Operation (Enter Total of lines 134 thru 143)83,354,189 216,645
145 Maintenance
146 (590) Maintenance Supervision and Enaineerina 510,144 711,039
147 (591) Maintenance of Structures 312,953 101 838
148 (592) Maintenance of Station Equipment 12,350,005 10,416,491
149 (593) Maintenance of Overhead Lines 581,466 54,444 188
150 (594) Maintenance of Underground Lines 275,933 20,517 510
151 (595) Maintenance of Line Transformers 634 175,108
152 (596) Maintenance of Street Liahtina and Sianal Svstems 115,843 454,472
153 (597) Maintenance of Meters 100,036 279,992
154 (598) Maintenance of Miscellaneous Distribution Plant 183,218 17,281 723
155 TOTAL Maintenance (Total of lines 146 thru 154)135,466,232 114 382,361
156 TOTAL Distribution Expenses (Total of lines 144 and 155)218,820,421 201 ,599,006
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 10,719,527 940,111
160 (902) Meter Reading Expenses 828,346 23,835,530
161 (903) Customer Records and Collection Expenses 52,949,192 51,082 123
162 (904) Uncollectible Accounts 093,297 232 503
163 (905) Miscellaneous Customer Accounts Expenses 1 ,273,970 134,759
164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163)107,864,332 91,225,026
FERC FORM NO.1 (ED. 12-93)Page 322
This ~rt Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 05/17/2007
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount for
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision
168 (908) Customer Assistance Expenses
169 (909) Informational and Instructional Expenses
170 (910) Miscellaneous Customer Service and Informational Expenses
171 TOTAL Customer Service and Information Expenses (Total 167 thru 170)
172 7. SALES EXPENSES
173 Operation
174 (911 Supervision
175 (912) Demonstratin and Sellin Expenses
176 (913) Advertising Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries
182 (921) Office Supplies and Expenses
183 (Less) (922) Administrative Expenses Transferred-Credit
184 (923) Outside Services Emplo ed
185 (924) Prope Insurance
186 (925) Injuries and Damages
187 (926) Emplo ee Pensions and Benefits
188 (927) Franchise Requirements
189 (928) Regulatory Commission Expenses
190 (929) (Less) Duplicate Char es-Cr.
191 (930.1) General Advertising Expenses
192 (930.2) Miscellaneous General Expenses
193 (931) Rents
194 TOTAL Operation (Enter Total of lines 181 thru 193)
195 Maintenance
196 (935) Maintenance of General Plant
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196)
198 TOTAL Elec Op and Maint Expns (Total 80,112,131,156 164,171 178,197)
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/04
Amoun!JorPrevious Year
(c)
301 ,809
710,915
620,675
105,971
739,370
932,798
44,489,026
614,258
262 985
48,299,067
142,943,825 137 354,536
10,053,431 087,468
23,386,081 28,826,830
18,460,427 876,349
23,392 399 20,388,933
10,053,945 10,918,589
435,094 756,397
571 778 15,441,595
693,669 796,122
25,696,241 35,008,141
197 293 853,508
215,968,465 217 739,875
22,676,043 18,968,997
238,644,508 236,708,872
2,457,427,890 241,288,268
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 05/17/2007 2006/04
FOOTNOTE DATA
'Schedule Page: 320 Line No.187 Column: b
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 Ending
December 31
2006
Twelve Months Ending
December 31
2005
Pension & Benefits Expense 172 724 970 150 348,149
~chedule Page: 320 Line No.187 Column:
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.
IFERC FORM NO.1 (ED. 12-87)Page 450.