2008Annual Report.pdf

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Form 1 Approved
OMB No. 1902.0021
(Expires 2/29/2009)
Form 1-F Approved
OMB No. 1902-0029
(Expires 2/28/2009)
Form 3-Q Approved
OMB No. 1902-0205
(Expires 2/28/2009)
THIS FILING IS
Item 1: 00 An Initial (Original)
Submission
OR 0 Resubmission No.
,.c:i:.,.
~ ?J.-i moui rn
;::i\...NW
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, Secions 3, 4(a), 30 and 309, and
18 CFR 141.1 and 141.40. Failure to report may result in criminal fines, civil penalties and
other sanctions as provide by law. The Federa Energ Regulatory Commission does not
consider these reports to be of confidential nature
Exact Legal Name of Respondent (Company)
PacifiCorp
Year/Period of Report
End of 2008/Q4
FERC FORM No.113-Q (REV. 02-04)
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INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3.0
GENERAL INFORMATION
I. Purpose
FERC Form NO.1 (FERC Form 1) is an annual regulatory requirement for Major electric utilties, licensees and others
(18 C.F.R. § 141.1). FERC Form No. 3-0 ( FERC Form 3.0)is a quarterly regulatory requirement which supplements the
annual financial reporting requirement (18 C.F.R. § 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 utilty, 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.F.R. Part 101),
must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-0 (18 C.F.R. § 141.400).
Note: Major means having, in each of the three previous calendar years, sales or transmission service that
exceds one of the following:
(1) one milion 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).
II. What and Where to Submit
(a) Submit FERC Forms 1 and 3-0 elecronically through the forms submission softare. Retain one copy of each report
for your files. Any electronic submission must be created by using the forms submission sofare provided free by the
Commission at its web site: http://ww.ferc.gov/docs-filing/eforms/form-1/elec-subm-soft.asp. The softre is
used to submit the electronic filing to the Commission via the Internet.
(b) The Corporate Offcer 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 eFilng 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 Certifcation Statement, submit within 30 days after filng 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 Certfication Statement can be
either eFiled or mailed to the Secretary of the Commission at the address above.
FERC FORM 1 & 3.0 (ED. 03-07)
The CPA Certification Staement should:
a) 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 Accuntant's published accounting releases), and
b) 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
C.F.R. §§ 41.10-41.12 for specific qualifications.)
Reference Schedules Pages
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
e) 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 connecion with our regular examination of the financial staements 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 Fedral 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 accunting records and such other auditing produres as we considered necessary in the circumstances.
Based on our review, in our opinion the accopanying 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 Stocholders, and the CPA Certifiction Statement using eFiling.
To further that effort, new selections, "Annual Report to Stocholders," and "CPA Certifcation Statement" have been
added to the dropdown "pick list" from which companies must choose whn eFiling. Further instructions are found on the
Commission's website at http://w.ferc.gov/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://ww.ferc.gov/docs-filing/eforms/form-1/form-1.pdfand
http://ww.ferc.gov/docs-filing/eforms.asP#3Q-gas .
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)ii
............................................
............................................
a) FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and
b) FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. §
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, Ofce of
Management and Budget. Washington, DC 20503 (Attention: Desk Officr 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.S.C. § 3512 (a)).
FERC FORM 1 & 3-Q (ED. 03-07)iii
GENERAL INSTRUCTIONS
i. 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 USofA.
II. Enter in whole numbers (dollars or MWH) only, except where otherwse noted. (Enter cents for averages and
figures per unit where cents are importnt. 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.
II Complete each question fully and accurately, even if it has been answered in a previous report. Enter the
word "None" where it truly and completely states the fact.
iV. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not
Applicable" in column (d) on the list of Schedules, pages 2 and 3.
V. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the
header of each page is to be complete only for reubmissions (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 sofare only. Please explain
the reason for the resubmission in a footnote to the data field.
VII. Do not make references to reports of previous periodslears 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 fiures 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 Accss 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 Accss
Transmission Tariff. For all transactions identified as LFP, provide in a footnote the
FERCFORM 1 & 3-Q (ED. 03-07)iv
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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 reservtion 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.af-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
bther 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 entit or instrumentlity in whose
behalf the report is made.
FERC FORM 1 & 3-Q (ED. 03-07)v
FERC FORM 1 & 3-Q (ED. 03-07)vi
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EXCERPTS FROM THE LAW
Federal Power Act, 16 U.S.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 incorprated 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 corpration;
(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 distrit, 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 direly conneced 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 empowere
(a) To make investigations and to collect and rerd data concerning the utilzation 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 -csts, and relation to markets of power sites; ... to the extent the
Commission may deem necessary or useful for the purposs of this Act."
"Sec. 304. (a) Every Licensee and every public utilit 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 specifc 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, capitaliztion, net investment, and reduction thereof, gross receipts, interest due
and paid, depreciation, and other reserves, cost of project and other facilties, cost of maintenance and operation of the
project and other facilties, 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 speifies". 1 0
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"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 accunting, 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 milion per day per violation of its rules and regulations. See
FPA § 316(a) (2005), 16 U.S.C. § 8250(a).
FERC FORM 1 & 3-Q (ED. 03.07)vii
FERC FORM NO. 1/3-Q:............................................
REPORT OF MAJOR ELECTRIC UTiliTIES LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent 02 YearlPeriod of Report
PacifiCorp End of 2008/Q4
03 Previous Name and Date of Change (if name changed during year)
/ /
04 Address of Principal Ofce at End of Period (Strt, Cit, 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 Corprae Controller
07 Address of Contact Persn (Stet, Cit, State, Zip Coe)
825 N.E. Multnomah, Suit 1900, Portand, OR 97232
08 Telephone of Contact Person,lncluding 09 This Report is 10 Date of Report
Al'a Coe (1) IX An Original (2) 0 A Resubmission (Mo,Da, Yr)
(503) 813-179 03/3112009
ANNUAL CORPORATE OFFICER CERTFICATION
Th undersigned ofr certs that:
I have examined this report and to th best of my knowge, infation, and belie all statement of fact contained in this repo are corrct stant
of the busine afirs of th repondent and the financial stment, and other financial infrmation contained in this report. conform in all material
respect to the Unifrm Syste of Accunts.
-
01 Name 03 Signature ~04 Date Signe
Douglas K. Stuver (Mo,Da, Yr)02Tit P;KSeniorVP & Chief Financial Ofcer 031112
TiU 18, U.S.C. 1001 makes it a cre for any pers to knowngly and willingly to make to any Agncy or Departent of the Unit Stas any
fals, fiitious or frudulent statement as to any mar wiin it juriicon.
FERC FORM No.1/3-Q (REV. 02-04) Page 1
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Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo8/Q4
(2) Fi A Resubmission 03131/2009
LIST OF SCHEDULES (Electric Utilty)
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)
1 General Information 101
2 Control Over Respondent 102
3 Corporations Controlled by Respondent 103
4 Oficers 104
5 Diretors 105
6 Importnt Changes During the Year 108-109
7 Comparative Balance Sheet 110-113
8 Statement of Income for the Year 114-117
9 Statement of Retained Eamings for the Year 118-119
10 Statement of cah Flows 120-121
11 Notes to Financial Statements 122-123
12 Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b)
13 Summary of Utilty Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
14 Nuclear Fuel Materials 202-203 NlA
15 Elecric Plant in Servce 20-207
16 Electric Plant Leased to Others 213 NlA
17 Electric Plant Held for Future Use 214
18 Construction Work in Progress-Elecric 216
19 Accumulated Provision for Depreciation of Elecric Utilty Plant 219
20 Investment of Subsidiary Companies 224-225
21 Materis and Supplies 227
22 Allowances 228-229
23 Exraordnary Property Losses 230 NlA
24 Unrecovered Plant and Regulatory Study Costs 230
25 Transmission Servce and Generation Interconnection Study Costs 231
26 Other Regulator Assets 232
27 Miscellaneous Deferred Debits 233
28 Accumulated Deferred Income Taxes 234
29 Capital Stock 250-251
30 Other Paid-in Capital 253
31 Capita Stock Expense 254
32 Long. Term Debt 256-257
33 Recnciliation of Reported Net Income wih Taxle Inc for Fed Inc Tax 261
34 Taxes Acrued, Prepaid and Charged During the Year 262-263
35 Acumulated Deferred Investment Tax Credits 266-267
36 Other Deferr Credits 269
FERc FORM NO. 1 (ED. 12-9)Page 2
FERC FORM NO.1 (ED. 12-9)Page 3
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Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 0331/20
LI T OF SCHEDULES (Elecri Utilit) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropnate, 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)
37 Accumulated Deferr Income Taxes-Accelerated Amortization Propert 272-273 NlA
38 Accumulated Deerred Income Taxes-Other Propert 274-275
39 Accumulated Deferred Income Taxes-Other 276-277
40 Other Reglatory Liabilities 278
41 Elecric Operang Revenues 300-31
42 Sales of Elecricity by Rate Schedules 30
43 Sales for Resae 310-311
44 Elecric Operation and Maintenae Expnses 320-323
45 Purchased Power 326-327
46 Trasmission of Electricity for Others 328-330
47 Transmission of Elecricity by ISO/RTOs 331 NlA
48 Transmission of Electricity by Others 332
49 Miscellaneous General Exnses-Elecric 33
50 Depreciation and Amortization of Eleric Plant 33-337
51 Regulatory Commission Exenses 350-1
52 Research, Development and Demonstration Acivities 352-353
53 Distribution of Salaries and Wages 354-355
54 Common Utility Plant and Exnses 356 NlA
55 Amounts included in ISO/RTO Setlement Statements 397 NlA
56 Purchase and Sale of Ancilary Services 398
57 Monthly Trasmission System Pea Load 400
58 Monthly ISO/RTO Transmission System Peak Load 40a NlA
59 Elecric Energy Account 401
60 Monthly Peaks and Output 401
61 Steam Electric Generating Plant Statistics 402-43
62 Hydroelecric Generating Plant Statistics 40-47
63 Pumpe Storage Generating Plant Statistics 408-4 NlA
64 Generating Plant Statistics Pages 410-11
65 Transmission Line Statistics Pages .422-423
66 Transmission Lines Added During the Year 424-425
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Name of Respondent
PacifCorp
Year/Period of Report
End of 2008/04
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) riA Resubmission 03131/200
LI T 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 repondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
426427
450
Remarks
(c)
67 Substations
68 Footnote Data
Stockholders' Reports Check appropriate box:
I: Four copies will be submitted
o No annual reprt to stockholders is prepared
FERC FORM NO.1 (ED. 12-9)Page 4
End of 20004
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Name of Respondent
PacifiCorp
This Report Is:
(1) IX An Original
(2) 0 A Resubmission
Date of Report
(Mo,Da, Yr)
03131/209
Year/Period of Report
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.
Douglas K. Stuver, Senior vice President and Chief Financial Officer
825 N.E. MUltna, Suite 1900
Portland, OR 97232-4116
Corporate Books are kept at:
825 N.E. MUltna, Suite 1900
Portlan, 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 tye
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 propert of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took posession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not applicable
4. State the classes or utility and other services furnished by respodent during the year in each State in which
the respondent operated.
PacifiCorp, which includes pacifiCorp an its subsidiaries, is a UDited States reglated electric comanyserving 1.7 million retail customrs, including residential, comrcial, industrial an other customrs
in portions of the states of Utah, Oregon, Wyomng, Washington, Idaho and California. PacifiCorp
delivers electricity to customrs in Utah, wyoming and Idaho under the trade nae Rocky Mountain Power
an to customers in Oregon, Washington and Californa uner the trade na Pacific Power. PacifiCorp's
electric generation, comrcial an energ trad, an coal-mining funtions are operated under the 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) 0 Yes...Enter the date when such independent accountant was initially engaged:
(2) 00 No
FERC FORM No.1 (ED. 12-8 PAGE 101
............................................
Name of Respondent
PacifiCorp
This Report Is:
(1) IX An Original
(2) 0 A Resubmission
Date of Report
(Mo,Da, Yr)
03/31/2009
Year/Period of Report
End of 2008/04
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 controllng 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%) (88.25% controlled by Berkshire Hathaway Inc.)
PPW Holdings LLC (100% controlled by MidAmerican Energy Holdings Company)
PacifiCorp (100% of common stock held by PPW Holdings LLC)
FERC FORM NO.1 (ED. 12-9)Page 102
FERC FORM NO.1 (ED. 12-9)Page 103
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Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ei A Resubmission 03131/200
C RPORATIONS CONTROLLED BY R SPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised wihout 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 betwen two holders, or each part 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 part.
~Kind of Busines Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)1 Mining 100
2 Energy West Mining Company Mining 100
3 Glenrock Coa Company Mining 100
4 Interwest Mining COpay Mining 100
5 Pacific Minerals, Inc.Mining 100
6 Mining 66.67
7 PacifiCorp Environmental Remediation Compay Environmental Servces 100
8 Rain Forest Carbn Credits 100
9 PacifiCorp Investment Management, Inc.Management servces for PERCo 100
10 Mining 21.40
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/31/2009 2008/Q4
FOOTNOTE DATA
¡Schedule Page: 103 Line No.: 1 Column: a
In Ma 200, th assets of Centria Mi Co an were sold to TrasAlta.
Schedule Pa e: 103 Line No.: 6 Column: a
Idaho Power Corp. holds a 33.33% ownership interest in Bndger Coal Company. PacifCorp's interest is held thugh Pacifc
Mineras, Inc.
¡Schedule Page: 103 Line No.: 8 Column: a
Effective July 28, 2008, Canopy Botaicals SRL, a Bolivian Corpration and an indirect subsidiar of PacifCorp Futur Generations,
was dissolved.
¡SChedule Page: 103 Line No.: 10 Column: a
The other joint owners of Trapper Mining, Inc. ar Salt River Project (32.10%), Tn-State Generation and Trasmission Association,
Inc. (26.57%) and Platt River Power Authonty (19.93%).
IFERC FORM NO.1 (ED. 12-87) Page 450.1
FERC FORM NO.1 (ED. 12-9)Page 104
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/20
OFFICERS
1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
Line iitie Name of Oficer fo~a:~rNo.(a ~(c)
1
2 Chairman of the Bord an Chief Executve Oficer
3 Senior Vice President an Chief Financial Oficer 215,499
4 President, Rocky Mountan Power A. Richard Walje 34,00
5 President, Pacific Power R. Patrick Reiten 258,00
6 President, PacifiCorp Energ A. Robert Lasich 230,00
7=n
9 Senior Vice President and Chief Financial Oficer 144,696
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Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/2009 2008/04
FOOTNOTE DATA
¡Schedule Page: 104 Line No.: 1 Column: a
PacifiCorp sets fort the salar information for its "named executive offcers" for the year ended December 31, 2008, consistent with
Item 402 of Regation S-K promulgated by the Securties and Exchage Commssion. Salar inormtion of other offcers will be
provided to the Federal Energy Reguatory Commission (the "FERC") upon request, but the company considers such informtion
ersonal and confidential to such offcers. See 18 CFR 388.107 d ,
SChedule Pa e: 104 Line No.: 2 Column: b
Mr. Abel receives no direct compensation from PacifiCorp. PacifiCorp reimbures MidAerican Energy Holdings Compay
("MEHC") for the cost of Mr. Abel's tie spent on PacifiCorp mattrs, including compensation paid to him by MEHC, pursuat to an
intercompany admnistrtive servces agreement amng MEHC and its subsidiares. Please refer to MEHC's anual report on Form
10-K for the ea ended December 31, 2008 File No. 001-14881 for executive com ation inormtion for Mr. AbeL.
Schedule Pa : 104 Line No.: 3 Column: b
For additional informtion regardig changes in the statu ofPacifiCorp's offcer refer to page 108, Important Chages During the
Year, Item 13, of this Form No. 1. Mr. Stuver was eleced Senior Vice President and Chief Finacial Offcer, effecve March 1,2008.f$hedule Page: 104 Line No.: 8 Column: a I
PacifiCorp sets fort the salar information for its "named executive offcers" for the year ended December 31,2008, consistent with
Item 402 of Regulation S-K promulgated by the Securties and Exchange Commssion. Salar inormtion of other offcers will be
provided to the FERC upon request, but the company considers such informtion persona and confdential to such offcers. See 18
CFR388.107 d,
hedule Pa e: 104 Line No.: 9 Column: b
For additional informtion regarding changes in the statu ofPacifiCorp's offcers refer to page 108, Important Changes During the
Year, Item 13, of this Form No. 1. On Febru 8, 2008, Mr. Mendez resigned as a direcr and executve offcer ofPacifiCorp,
effectve Febr 29, 2008.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
FERC FORM NO.1 (ED. 12-95)Page 105
............................................
Name of Respondent This j!rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 0331/200
DIRECTORS
1. Report below the information called for conceming each director of the respondent who held ofice at any time during the year. Include in column (a), abbreviated
titles of the direors who are offcers of the repondent.
2. Designate members of the Executive Commitee by a triple asterisk and the Chainnan of the Executive Committee by a double asterisk.
IU~g,Name (ançi,lltleJ Of uirector l"nncipal tssiness Aaaress
(a)(b)
1 PacifCorp Board of Direcors as of December 31, 2008:
2 666 Grad Avenue, Suite DM29, Des Moines, Iowa 50309
3 R. Patrick Reiten (President, Pacifc Power)825 NE Multnomah, Suite 200, Portland, Oregon 97232
4 A. Richard Walje (President, Rocky Mountain Power)201 South Main, Suite 230, Salt Lake City, Utah 84140
5 Douglas L. Anderson 302 South 36th Street, Omaha, Nebraka 68131
6 Brent E. Gale (Senior Vice Preident)825 NE Multnomah, Suite 200, Portland, Oregon 97232
7 Patrick J. Gooman 66 Grad Avenue, Suite DM29, Des Moines, Iowa 50309
8 A. Robert Laich (President, PaciCorp Energy)1407 West North Temple, Suite 320, Salt Lake Cit, Utah 84116
9 Mark C. Moench (SVP & General Counsel, PacifiCorp and
10 Rooky Mountain Power)201 Souh Main, Suite 2400, Salt Lae City, Utah 84140
11 Natalie L. Hooken (VP and Genera Counsel, Pacifc Power)825 NE Multnomah, Suite 200, Portlan, Oregon 97232
12
13
14
15 Other Directors in 2008
825 NE Multnomah, Suite 190, Portland, Oregon 97232
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Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 200/04
FOOTNOTE DATA
¡Schedule Page: 105 Line No.: 2 Column: a
Curently there is only one commttee, a Compensation Commtt, of whch the sole member is Mr. AbeL.
¡Schedule Page: 105 Line No.: 16 Column: a
Mr. Mendez resigned as a director and executive offcer ofPacifiCorp effective Febru 29, 2008. For additional infonntion
regading changes in the sttus ofPacifiCorp's offcers refer to page 108, Important Changes During the Year, Item 13, of ths Form
No.1.
IFERC FORM NO.1 (ED. 12w87) Page 450.1
Blank Page
............................................
(Next Page is 108)
............................................
Name of Respondent
PacifiCorp
Date of Report Year/Period of Report
End of 2008/04
This Report Is:
(1) ~ An Original
(2) 0 A Resubmission
1M ORTANT CHANGES DURING THE QUARTERNEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the propert, 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 otherwse, 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 liabilties 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
part or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have
occurred during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affilated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
03/31/2009
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-9)Page 108
IFERC FORM NO.1 (ED. 12-96)Page 109.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/200 2004
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
ITEM 1.
Changes in Franchise Rights
State Effectve Date Expiration Date Fee
(Fee atthed to frchise agrment)
California Ca)
None
Idaho Cb)
Spencer 07/10/2008 07/10/2038 2.0%
Oregon (e)
Merrll 04/03/2008 04/03/2018 5.0%
Coburg 08/19/2008 08/19/2013 5.0%
Utah Cb)
Plymout 01/23/2008 01/23/2033
Providence 01/31/2008 01/31/2033 5.00,4
Naples 04/17/2008 04/17/2018 6.0%
Sunet 04/18/2008 04/18/2018 6.0%
Davis County 07/06/2008 07/06/2023
West Bountiful 09/09/2008 09/09/2018 6.00,4
Washington Cb)
Toppenish 09/15/2008 09/15/2028 8.5%
Columbia County 10/06/2008 10/06/2043
Pasco 10/24/2008 10/24/2018
Wyoming Cd)
Opal 04/23/2008 04/23/2033 1.0%
(a) In Californa, frchise fees ar an expen to PacifiCorp an are embedded in rates.
(b) In Idao, Uta and Washingtn, PacifiCorp collec frchise fees from customers and remits them
directly to the applicable muncipalities.
(c) In Oregon, the first 3.5% of the frchise fees is an expnse to PacifiCorp and is embedded in rates.
Any amount above the 3.5% is collecd from cusmers and rett directy to the applicable
muncipalities.
(d) In Wyomig, the first 1.0% of the franchise fees is an exense to PacifiCorp and is embedded in rates.
Any amount above the 1.0% is collected from customers and remttd directly to the applicable
muncipalities.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp i2) A Resubmission 03131/2009 2008104
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
ITEM 2.
Acquisition of Ownership in Other Companies
On September 15, 2008, afr having received the reuisite reguatory approvals, PacifiCorp acuird from TNA Merchat Project,
Inc., an affliate of Suez Energy North Amenca, Inc., 100% of the equity interests of Chehalis Power Generating, LLC e'Chehalis"), an
entity owning a 520-megawatt ("MW") natul gas-fid generating plant located in Chehalis, Washingtn. The tota cash purchae
pnce wa $308 millon and the estimated fair value of the acquired entity wa pnmaly allocated to the plant, which is included in
account 102, Electc plant purchased or sold. Chehalis was merged into PacifiCorp imediately following the acuisition. The results
of the plant's operations have been included in PacifiCorp's Financial Statements sinc the acquisition date. Commssion
autonzations associated with the acquisition were as follows:
D Federal Trade Commssion - Trancton identification mnnber 20081 103, grted May 9,2008.
D Federa Energy Reguatory Commssion (the "FERC") - Docket No. EC08-82-000 issue July 17, 2008.
D Washingtn Energy Facilty Site Evaluation Council - Order No. 836, effective July 8, 2008.
D Federal Communcations Commssion - File number 0003447617, consent dated May 23,2008.
D Oregon Public Utility Commssion (the "OPUC") - Order No. 08-376, effective July 17,2008, grtig the petition for waiver of
the OPUC's competitive bidding gudelines.
D Uta Public Service Commssion (the "UPSC") - Docket No. 08-035-35, dated Augt 30, 2008, grting the request for approval
to acquie a signficant energy resource.
ITEM 3.
Purchase or Sale of an Operating Unit
On September 14, 2007, PacifiCorp closed the sale of the Upper Beaver Hydroelectc Project FERC Projec No. 814, assets and
water nghts, to the City of Beaver, Uta, for $2 millon. In accordance with 18 CFR Par 4.94 (f) Aricle 6, notification of the trfer
of the license exemption wa filed with the FERC. The Upper Beaver Hydroelectc Project is located in southwestern Uta, on the
Beaver River near the City of Beaver, upon Unite States Forest Servce (''USFS'') lands in the Fish Lake National Forest and
operated under the autonty of a special use pennt with the USFS. The proceeds, net book value and selling cost were trsferred to
account 102, Electic plant purchad or sold. In Apnl 2008, the FERC approved the joural entres called for by the Unifonn System
of Accounts. The sale was approved by the Wyomig Public Servce Commssion (the "WPSC'), the OPUC and the Californa Public
Utilties Commssion (the "CPUC").
For inormtion regarding company acquisitions, refer to Imortt Changes Dung The QurlY ear, Item 2 included in this
FonnNo.l.
IFERC FORM NO.1 (ED. 12-96) Page 109.2
IFERC FORM NO.1 (ED. 12-96) Page 109.3
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp i2) A Resubmission 0331/2009 20004
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
ITEM 4.
Important Leaseholds
Seven Mile Hil Wind Project
In March 2008, PacifiCorp completed the purchase of the nghts to the Seven Mile Hil wid site in Carbon County, Wyoming from
Eurs Wind Power Development LLC. As pa of ths agreement, PacifiCorp wa assigned two real estate leases, one with pnvate
landowner and one with the State of Wyomig. The leae with the pnvate landowners has an initial term of 10 years with an autmatic
extension of 99 years if a ce milesne is met. The milestone ha been met. The leas with the State of Wyoming ha a 25-year
term, with the 25-yea extions avalable at PacifiCorp's option, subjec to ce lease renewa procedurs. The leaes have initial
term rent payments, one-time intalation fees bas on installed megawatt of capacity and anual operating rent payments based
on instaled megawatt of capacity. Both leas also include mimwn leae payment obligations.
Chehalis Gas Lateral
In September 2008, as pa of the acquisition of Chehalis, PacifiCorp asswned a 25.5 yea natul gas tranporttion agrment entered
into durng Augut 2001 with Nortwest Pipeline Corporation (''Nortwest''). The ageement set fort the ter for Nortwest's
provision of natual ga trsportion servces to the Chehalis genera facilty and Nortwest's constron of a natul gas
pipeline and facilties necessar to connec the Chehais generati failty to Nortwes's existing maiine. The estimated monthy
charge includes reimburement for the conscton costs of the pipeline and failties and other executory cost such as monthy
opertion and maintenance costs and propert taes. The monthy chage will be adjusted anually to reflect the act costs incurd
by Nortwes. The agrent is consider a capita leae of the failties resultig in a $4.7 millon capita leae obligation and a
$4.7 milion capit lease asset. The agreeent requis fu miwn lea payments, including executory costs, of approxitely
$1.2 millon per year for the yea endig Decber 31, 2009 thoug December 31,2027 and $0.4 millon for the yea ending
December 31,2028.
High Plains Wind Project
In Septeber 2008, PacifiCorp complete the purchase of the nghts to the High Plains wid site from Gree Wing Pacific Energy
Corporation. The wid site is locte about five miles south of the town of Rock River, in Carbon and Albany counties, Wyoming. As
par of this agreement, PacifiCorp wa assigned two pnvate landowner real estte leases. The leases with the pnvate landowner have
an initial term of 30 yea frm the onginaleas execon date of June 5, 2007 with an available extsion of 30 year acvated by
wrttn notice from PacifiCorp. The leas have miwn ret paymen, one-time constrcton payments based on megawatt of rated
capacity, and royalty payment bas on genertion.
ITEM 5.
Importnt Extension and Reduction of Transmission or Distribution System
For discussion of trsmission lines added durg the year, refer to pages 424-425 of ths Form NO.1. During the year ended
December 31, 2008, PacifiCorp did not signficatly increae or deceas the capacity of its distbution syst.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03131/2009 200/04
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
ITEM 6.
Financing Activities
Short-Term Debt and Revolving Credit Agreements
Reguatory autorities limt PacifiCorp to $1.5 bilion of short-term debt, of whch an aggregate principal amomit of $85 millon was
outstading as of December 31, 2008, with a weighted-average interest rate of 1.0%. In Janua 2009, PacifiCorp repaid its
outstading short-term debt with proceeds from its Janua 2009 long-term debt issuace discussed below. Commssion authorizations
for up to $1.5 bilion outstading at anyone tie in commercial paper and other miseured short-term debt are as follows:
o OPUC - Docket No. UF-4120, Order No. 98-158, dated April 16, 1998.
o Washingn Utilties and Trasporttion Commssion (the "WUC") - Docket No. UE-980404, dated April 8, 1998.
o Idaho Public Utilities Commssion (the "IPUC') - Case No. PAC-E-06-01, Order No. 29999, dated March 14, 2006.
o FERC - Docket No. ES07-61-000, dated November 26,2007, letr order effecve Janua 1,2008.
As of December 31, 2008, PacifiCorp had $1.5 bilion of tota ban commtments mider two misecur revolvig credit failties.
However, PacifiCorp's effective liquidity mider these facilties was reduced by $105 millon to $1.4 bilion due to the Lehm
Brothers Holdings Inc. ("Lehm") bantcy filing in September 2008. Lehm filed for proteon mider Chapter 11 of the Feder
Bantcy Code in the United States Banptc Cour in the Soutern Distrct of New York. Lehman Brothers Ban FSB and
Lehm Commercial Paper, Inc., bot subsidiaries of Lehm have commtments totaing $105 millon in PacifiCorp's $1.5 bilion
misecurd revolving credit facilties. The reduction in available capaity under the credit failties as a reult of the Lehm banptcy
did not have a material adverse impac on PacifiCorp.
Adjusng for the Lehman banptcy, the first crit facilty has $760 millon of tota ban commtments though July 6, 2011. The
commtments reduce over time to $630 millon of remaing availabilty for the year endig July 6, 2013. Adjusting for the Lehm
banptcy, the second credit facilty has $635 millon of total ban commtments though Octobe 23, 2012. Each crt facilty
includes a variable interest rate borrowing option based on the London Interban Offere Rate, plus a magin that wa 0.155% at
Febru 27, 2009 and vares based on PacifiCorp's credit ratings for its senior unsecured long-ter debt securties. These credit
facilties support PacifiCorp's commercial paper program, mienhced vaable-rate ta-exempt bond obligations and other short-term
borrowing needs.
As of December 31, 2008, PacifiCorp had no borrwings outding mider either crit facilty but had lett of crdit mider both
crit agreements totaling $220 millon to support varable-rate ta-exempt bond obligations. In addition, the crit facilties supportd
$85 millon of commercial paper borrowings and $38 millon ofunenhced varable-rate ta-exempt bond obligations outding as
of December 31,2008. The remaining $1. bilion of effective liquidity under the unur revolving crdit facilties wa available as
of Deember 31, 2008.
IFERC FORM NO.1 (ED. 12-96)Page 109.4
IFERC FORM NO.1 (ED. 12-96) Page 109.5
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) K An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 0311/2009 208104
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
Long-Term Debt
In Janua 2008, PacifiCorp received reguatory authority from the OPUC and the IPUC to issue up to an additional $2,0 bilion of
long-ter debt. PacifiCorp must mae a notice filing with the WUC prior to any futue issuace. Also in Janua 2008, PacifiCorp
filed a shelf registrtion statement with the Securties Exchange Commssion coverng futue first mortage bond issuances.
PacifiCorp's long-term debt issuaces in Januar 2009 and during the year ended December 31, 2008 were covered under the
above-noted reguatory autorities and shelf registtion stateent.
In Janua 2009, PacifiCorp issued $350 millon of its 5.50% Fir Mortgage Bonds due Janua 15, 2019 and $650 millon of its
6.00010 First Mortgage Bonds due Janua 15,2039.
In July 2008, PacifiCorp issued $500 millon of its 5.65% First Mortgage Bonds due July 15, 2018 an $300 millon ofits 6.35% First
Mortgage Bonds due July 15,2038.
State commssion autorizations for the issuaces above were as follows:
o OPUC - Doket No. UF-4243, Order No. 08-013, date Janua 14,2008.
o IPUC - Cas No. PAC-E-07-16, Order No. 30489, dated Janua 22, 2008.
In September 2008, PacifiCorp acquired $216 millon of its inur vaable-rate ta-exempt bond obligations due to the signficant
reducton in maket liquidity for inur varable-rate obligations. In Novembe 2008, the associated insurce and related stadby
bond purchase agements were ted and thes varable-ra long-term debt obligations were remaketed with credit
enancement and liquidity support provided by $220 millon of letrs of credit issued under PacifiCorp's two unecured revolvig
credit facilties.
As of December 31, 2008, PacifiCorp had $517 millon of letrs of credit available to provide credit enhancement and liquidity
support for variable-rate ta-exempt bond obligations totaing $504 millon plus interest. These commtted ban arangements were
fuly available at December 31,2008 and expire perodically thoug May 2012.
PacifiCorp may from time to time seek to acquie its outstading securties though cash purhass in the open maet privatly
negotiated trsactions or otherwse. Any debt securties repurchasd by PacifiCorp may be reissued or resold by PacifiCorp from time
to time and will depend on prevailing maket conditions, PacifiCorp's liquidity requiements, contractl restrctons and other faors.
The amounts involved may be mateal.
ITEM 7.
Changes in Aricles of Incorporation or Amendments to Charter
On September 15,2008, PacifiCorp acquied 100% of the ownership interes in Chehalis, and immediately thereafter merged Chehalis
with and into PacifiCorp, with PacifiCorp surivi, such tht the separte existence of Chehalis ceased. The merger was accomplished
by the recordation of Arcles of Merger with the Secretary of State for the state of Oregon, and a Certficate of Merger with the
Secreta of State for the state of Delaware. These documents now appea in the arcles of incorporation records ofPacifiCorp.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifCorp 1(2)A Resubmission 03131/2009 20004
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
ITEM 8.
Estimated Annual Effect of Wage Scale Changes
PacifiCorp's bargaining unit wage scale changes were as follows:
Unions Repeseted % Incrase (a)Effecive Date(s)
Estd Anua
Fincial Impac (b(c)
IBEW 57 Geeraon (l, il & WY
IBEW 57 Power Deliver (l, il & WY
Tota
2.78%
2.78%
1126/2008
1126/2008
$1,026,679
2,197.939
3,224618$
(a) This peceta incrase reesets the incras in waes for all effectve das durg the caenda yea as
compaed to the wae scale of the prior effectve period.
(b) Some amounts may be reimbured by joint owners of generng failties.
(c) The estimed anua impac is bad on the tie peod from the effecve date of the increas to the end of the
caenda year.
ITEM 9.
Legal Proceeings
In addition to the procdings descrbed below, PacifiCorp is curntly par to varous items of litigation or arbitrtion in the norml
coure of business, none of which are reanably exped by PacifiCorp to have a materal adverse effect on its ficial results.
In December 2007, PacifiCorp was served with a complaint filed in the Unite States Distct Cour for the Nortrn Distct of
California by the Klamth Riverkeeper (a local environmental group), individual Kar and Yurok Tnbe members and a resort owner.
The complain alleged that reservoirs behid the hydroelectc dam tht PacifiCorp opertes on the Klamth River provide an
environment for the growt of a blue-green algae known as microcystis aeruginosa, which can generte a toxin called microcystin and
cause substatial endagerment to health and the environment. PacifiCorp believed the claims to be without ment and filed a motion to
dismiss in December 2007. In March 2008, the cour dismisse the complaint following plaintiffs' failure to agree on the cour's
conditions for combini this case with the May 2007 case descnbed below.
In May 2007, PacifiCorp was served with a complaint filed in the Unite States Distict Cour for the Norter Distrct of Californa
by individual Kar and Yurok Tnbe members, a commercial fisherm a resort owner and the Klamth Riverkeeper. The complaint
similarly alleges tht microcysti aeruginosa causes the plaintiff physical, propert and ecnomic har. In March 2008, one of the
Yurok Tnbe members voluntaly dismissed his clai in the case. In Apnl 2008, the cour enterd a stipulation and order dismissing
plaintff Klamth Riverkeeper's claims, with prejudice. In July 2008, commercial fisherm Michael Hudson's claim were dismissed
with prejudice, and PacifiCorp fied motions for sum judgment on all remainig plaintiff for all remg claims. In
August 2008, plaintiff Leaf Hilma Ka Tribe member, volunly dismissed all his personal injur clai with prejudice. In
September 2008, PacifiCorp filed a motion for sum judgment on all of plaintiffs' claims for public nuisance, pnvate nuisance and
negigence. In Octber 2008, the pares negotiated a fi selement in the matt and a stipulation was filed with the cour dismissing
all plaintiff an all remaining claim, with prejudice.
IFERC FORM NO.1 (ED. 12-96) Page 109.6
IFERC FORM NO.1 (ED. 12-96) Page 109.7
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
PacifiCorp (2)A Resubmission 0331/2009 200104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
In Februar 2007, the Sierr Club and the Wyoming Ouoor Council filed a complaint against PacifiCorp in the federal distrct cour
in Cheyenne, Wyoming, alleging violations of the Wyomig state opacity stadads at PacifiCorp's Jim Bridger plant in Wyoming.
Under Wyoming state requirements, which are par of the Jim Bridger plant's Title V permt and are enforceable by private citizens
under the federa Clean Air Act a potential source of pollutats such as a coal-fied generating facilty must meet minimum stadads
for opacity, which is a measurement of light that is obscured in the flue of a generting facilty. The complaint alleges thousands of
violations of asserted six miute compliance perods and seeks an injuncton orderig the Jim Bridger plant's compliance with opacity
limts, civil penalties of $32,500 per day per violation, and the plaintiffs' costs of litigation. The cour grted a motion to bifucate the
tral into separte liabilty and remedy phaes. In Marh 2008, the cour indefinitely postponed the date for the liabilty-phase tral. The
remedy-phase tral has not yet been scheduled. The cour also ha before it a number of motions on which it has not yet rued.
PacifiCorp believes it ha a number of defenes to the clai. PacifiCorp intends to vigorously oppose the lawsuit but canot predict
its outcome at ths tie. PacifiCorp ha aly commtt to invest at leat $812 millon in pollution control equipment at its
generating facilties, including the Jim Bridger plant. Ths commtment is expected to signficantly reduce system-wide emissions,
including emssions at the Jim Bridger plan.
In October 2005, PacifiCorp was added as a defendant to a lawsuit origily filed in Febru 2005 in stte distrct cour in Salt Lae
City, Uta by USA Power, LLC and its affliated companies, USA Power Parers, LLC and Spring Canyon, LLC (collectively, "USA
Power"), against Utah attorney Jody L. Wiliam and the law fi Holme, Rober & Owen, LLP, who represent PacifiCorp on varous
matters from time to time. USA Power wa the developer of a planed generation projec iI Mona Uta called Spring Cayon, whch
PacifiCorp, as par of its resource procurement process, at one tie considered as an alterntive to the Curt Creek plant. USA
Power's complaint alleged that PacifiCorp misappropriate confdenial proprieta informtion in violation of Uta's Uniform Trade
Secet Act and accused PacifiCorp of breach of contr and related claims. USA Power seeks $250 millon in damges, statutory
doubling of damages for its tre secr violaton claim, puntive daes, cost and attrneys' fees. Afr considerg varous
motions for sumary judgment, the cour rued in Ocber 2007 in favor of PacifiCorp on all coun and dismissed the plaintiffs'
claim in their entirety. In Febru 2008, the plaintiff filed a petition requestig consideration of their appeal by the Uta Supreme
Cour. The plaintiffs request wa grted and thy filed a brief in November 2008 with the Uta Supreme Cour. In Janua 2009,
PacifiCorp fied its reply brief. PacifiCorp believes tht its defenses tht prevailed in the tral cour will prevail on appeal. Furermore,
PacifiCorp expects that the outcome of any appeal will not have a marial impact on its finacial results.
In May 2004, PacifiCorp was served with a complaint filed in the Unite States Distrct Cour for the Distrct of Orgon (the "Distrct
Cour") by the Klamath Tribes of Oregon, individua Klamath Tribal members and the Klamath Claims Commttee. The complaint
generally alleges that PacifiCorp and its predecessors afect the Klamth Tribes' federa treaty rights to fish for salmn in the
headwaters of the Klamath River in souter Oregon by building da that blocked the passage of salon upstea to the headwaters
beginng in 191 i. In July 2005, the Distrct Cour dismsse the cae and in September 2005 dened the Klamth Tribes' reuest to
reconsider the dismissaL. In Octber 2005, the Klam Tribe appealed the Distct Cour's decision to the Unite States Cour of
Appeals for the Ninth Circuit (the ''Nin Circuit") and briefing was complet in March 2006. In Febru 2008, the Ninth Circuit
afrmed the Distrct Cour's 2005 decisions dismissing the ca. In May 2008, the plaitiffs fied a petition requestng review by the
United States Supreme Cour. PacifiCorp fied a brief in opposition to the pettion in June 2008. In October 2008, the United States
Supreme Cour denied plaintiff' petition for review.
For fuer informtion regading material developments to legal proceedings pending at December 31, 2007, refer to Note 13 of Note
to Finacial Staments included in ths Form No. i.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2) . A Resubmission 03131/2009 2O4
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
ITEM 10.
Related Party Transactions
None.
ITEM 11.
(Reserved)
ITEM 12.
General Regulation
PacifiCorp is subjec to comprehensive governent regulation that signficantly influences its operating environment, prices charged
to customers, capital strcte, costs and its abilty to recover costs.
Federal Regulation
In addition to the discussion contaned herein, refer to Note 13 of Notes to Financial Stateents included in ths Form No. 1 for fuer
inormtion regarding federa regulatory mattrs.
Wholesale Electrcity and Capacity
The PERC regulates PacifiCorp's rates charged to wholesale customers for electcity, capacity and trsmission services. Most of
PacifiCorp's elecc wholesale sales and purchases tae place under maket-bas rate pricing allowed by the PERC and ar therefore
subject to maket volatilty.
The PERC conduct a trennial review of PacifiCorp's maket-based rate pricing autority in accordance with the filing schedule
established by the FERC in Order No. 697. Each utilty must demonstrte the lack of genertion market power in order to chage
maket-based rates for sales of wholesale electicity and capacity in their respecve balancing authority area. PacifiCorp's next
trennial filing is due in June 2010. Under the PERC's maket~based rules, PacifiCorp must also file a notice of chage in statu upon
the ownership or control of an additional 100 MW of incrmenta generation. Following the fiing by PacifiCorp of a change in status
notice relatig to new generation, the PERC in November 2007 confrmed that PacifiCorp does not have maket power and may
continue to charge maket.based rates. In Ocober 2008, PacifiCorp filed a chage in sttu notice, which is pending, relate to its
acuisition of the 520-MW Chehalis natu gas-fired generating facilty and the expectd commercial operation of several new
PacifiCorp wind-powerd generang facilties. Althoug PacifiCorp submitt sties to support a FERC conclusion consistent with
its precedent tht PacifiCorp continues to lack generation maket power in all relevant maket, it is possible that the FERC could
require PacifiCorp to adopt mitigation measures for a specific maket.
IFERC FORM NO.1 (ED. 12-96) Page 109.8
IFERC FORM NO.1 (ED. 12-96) Page 109.9
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0331/209 200/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
Transmission Investment
In July 2008, PacifiCorp filed a petition for declartory order with the FERC to confirm incentive rate tratment for the Energy
Gateway Tramission Expanion Project. The Energy Gateway Tramission Expansion Project is an investent plan to build
approxitely 2,000 miles of new high-voltage trmission lines primaly in Wyoming, Uta, Idao, Oregon and the desert
Southwest. The plan with an estited cost exceeding $6.1 billon, includes projec tht will address customer load growt, improve
system reliabilty and deliver energy from new wind-power and other renewable generating resources thoughout PacifiCorp's
six-state serce area and the Western Unite States. Cert trmission segments associated with ths plan ar expeced to be placed
in serce beginning 2010, with other segments plac in sece thoug 2018, depndin on sitig, penntting and constrction
schedules. In Octber 2008, the FERC grte a 200-basis-point (two-pecente-point) incentive rate adder to PacifiCorp's base
retu on equity for seven of the eight projec segments subjec to a futu Section 205 rate case filing with the FERC. The FERC did
not preclude PacifiCorp from filing for incetive rate tratment for the remag segment at a fue date.
FERC Orders No. 890 and 890-A and 890-B
In Febru 2007, the FERC adopted a final rue in Order No. 890 designed to stengten the pro form Open Access Tranmission
Tarff ("OATT') by providing greater specificity and incrasing trparency. The most signficant revisions to the pro form OATT
relate to the development of more consistent methodologies for calculatig available trfer capabilty, chages to the transmission
planing process, changes to the pricing of cert genrator and ener imbalance to encourge effcient scheduling behavior and
changes regading long-term point-to-point trssion sece, includg the addition of conditional firm long-term point-to-point
trsmission serice and genertion redispatch. As a trmission provider with an OATT on file with the FERC, PacifiCorp is
required to comply with the reuints of the new rue. PacifiCorp mae its firs compliance filing amending its OATT in July 2007.
Subsequent to ths filing, PacifiCorp was reuied to mae additiona compliance filings to revise its intial filing, all of which were
accepte by the FERC thoug varous orders issued in 2007 and 2008.
In December 2007, the FERC issued Order No. 890-A generlly affrmg th provisions of the fina rue as adopted in Order No. 890
with certin limite clarfications and requirig an additional compliance fiing by trmission providers. In March 2008, PacifiCorp
submitted its Order No. 890-A compliance filing, which wa accepted by the FERC in November 2008. In June 2008, the FERC issued
Order No. 890-B, which generally afrmed the provisions of th final rue as adopted in Order No. 890 and Order No. 890-A with
certin additional limited clarfications, and which requied an additional compliance filing. PacifiCorp fied its Order No. 890-B
compliance filing in September 2008, whch consist of non-substative grtica revisions to its OATT and which was accepted
by the FERC in December 2008. In addition to these filings, PacifiCorp filed other Order No. 890 related compliance filings, including
a December 2007 filing proposing chages to its loca, regona and sub-regional trmission planng process contaned in its OATT.
This filing, which is stil pending before the FERC, is not anticipat to have a signficant impact on PacifiCorp's financial results, but
it could have a signficat impact on its trmission plang fuctons.
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/209 2008104
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
FERC Reliabilty Standards
The FERC has approved 88 reliabilty stadads developed by Nort American Elecc Reliabilty Corporation (the ''NRC'') and
8 regional variations developed by the Western Electrcity Coordintig Council (the "WECC"). Responsibilty for compliance and
enorcement of these stadards ha been given to the WECC. The 88 standards comprise over 600 requirements and sub-requirements
with which PacifiCorp must comply. PacifiCorp expect tht these stadards will change as a result of modifications, gudance and
clarfication followig industr implementtion and ongoing audits and enorcement. In Janua 2008, the FERC approved eight
additional cyber security and crtical infstrct protection stadads proposed by the NERC. The additional stdads became
madatory and enforceable in April 2008. PacifiCorp canot predict the effect that these stadards will have on its finacial results;
however, they will likely requie increased expenditues for cyber securty and other systems for PacifiCorp's critical asset and may
have a signficant impac on trsmission operations and resource planng fuctions. Durg 2007, the WECC audited PacifiCorp's
compliance with several of the approved reliabilty stadards. In April 2008, PacifiCorp received a notice of a prelimar non-public
investigation from the FERC and the NERC to detrme wheter an outage tht occur in PacifiCorp's transmission syste in
Febru 2008 involved any violations of reliabilty standads. In November 2008, PacifiCorp reived prelimina fidings from
the FERC sta regarding its non-public investgation into the Febru 2008 outage. In November 2008, in conjuncton with the
reliabilty stadard review, the FERC took over processing certin aspect of the WECC's 2007 audit. PacifiCorp is anyzing the
prelim results ofthe audit and the prelimi results of the non-public investigation, and at ths time, caot preict the impac of
the audit or the non-public investigation, if any, on its fiancial results.
Hydroelectric Relicensing
PacifiCorp's Klamath hydroelectc syst is the remang hydroelectc generting facilty actvely engaged in the relicensing
process with the FERC. PacifiCorp also has requested the FERC to allow decommssioning of cerin hydroelectc systems. Most of
PacifiCorp's hydroelecc genertig failties are license by the FERC as major systems under the Federal Power Act and cert of
these systems are licensed under the Oregon Hydroelecc Act. Refer to Note 13 of Notes to Finacial Stateent for an update
regading hydroelectc relicensing for PacifiCorp's Klamth, Lewis River an Prospect hydroelectc systems.
Hydroelectric Decommissioning
Power dale Hydroelectrc Facilty ~HoQd River. Oregon
In June 2003, PacifiCorp entered into a settement agreement to remove the 6-MW Powerdale plant rather than purue a new licens,
based on an anlysis of the costs and benefits of relicensing versus decommssioning. Removal of the Powerdale dam and associated
system featus, whch is subject to the FERC and other reguatory approvals, is projecd to cost $6 millon, excluding infation. Plant
shut down and removal was scheduled to commence in 2010. However, in November 2006, flooding damged the Powerdae plant an
rendered its generating capabilties inoperble. In Febru 2007, the FERC gred PacifiCorp's request to cease genertion at the
plan; however, removal is still scheduled for 2010. Also in Febru 2007, PacifiCorp submitted a request to the FERC to allow
PacifiCorp to defer the remaning net book value and any additional removal costs of ths system as a reglatory asset. In May 2007,
the FERC issued an order that approved PacifiCorp's proposed acunting entres, thereby allowig PacifiCorp to reclassifY the net
book value and the estited removal cost to a reguatory asset. PacifiCorp ha received approval from its stte reguatory
commssions to defer and recover these costs.
IFERC FORM NO.1 (ED. 12-96) Page 109.10
Page 109.11
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp (2) . A Resubmission 03131/200 2008/04
IMPORTANT CHANGES DURING THE aUARTERNEAR (Continued)
Condit Hvdroelectrc Facilty - White Salmon River, Washington
In September 1999, a settlement agreement to remove the 14-MW Condit hydroelectc facilty wa signed by PacifiCorp, state and
federal agencies and non-governental organizations. Under the origial settlement ageeent, removal wa expected to begin in
Octber 2006, with a tota cost to decommssion not to exceed $17 milion, excluding inflation. In early Febru 2005, the pares
ageed to modifY the seement agrement so tht removal would not begin until Octber 2008, with a total cost to decommssion not
to exceed $21 millon, excluding ination. The selement ageement is contient upon receiving a FERC surnder order and other
reguatory approvals tht are not mateally inconsistt with the amended settlement agreement. PacifiCorp is in the process of
acquiring all necessar permts with the terms and conditions of the amended setement agrment. Given the ongoing permtting
process and the time needed for systm reoval and to evaluate impact on natul resources, decommssionig is now expected to
begin in Ocber 2010. In Marh 2008, the United States Ary Corps of Engiee requestd PacifiCorp complete an additional study
of expctd decommssioning imact on aquatic resources. The study work is complete and results have been provided to the United
States Ary Corps of Engieers and the Wasgtn Deparnt of Ecology. Abset fuer inormtion requests, the Washingtn
Depaent of Ecology is expect to coinlete the Clean Water Act 401 certfication process durng 2009. Remaing permtting
includes a 404 permt from the United State Ary Corps of Engieers and a surender order from the FERC.
The Bonneville Power Administration Residential Exchange Program
The Northwest Power Act thoug the Residential Exchae Prgr provides access to the benefits of low-cost federal
hydroeleccity to the residential and smal-far cusme of the reon's investr-owned utilities. The progr is adnistred by
the Bonneville Power Admsttion (the "BPA") in acrdace with feder law. Puuat to ageements beteen the BPA and
PacifiCorp, benefits from th BPA ar pased though to PacifiCorp's Orgon, Washigtn and Idaho residential and small-far
customers in the form of eleccity bil crdits.
Severl publicly owned utilities, cooperatives and the BPA's direct-servce indus customer fied lawsuits aginst the BPA with the
Unite States Cour of Appeals for the Ninth Circuit (the ''Nin Circuit") seekig review of cert aspect of the BPA's Residential
Exchage Progr as well as chalengig the level of benefits previously paid to investor-owned utility cusomers. In May 2007, the
Ninth Circuit issued two decisions that resulte in the BPA suspending paymnts to the Pacific Nortwest's six investor-owned
utilties, including PacifiCorp. This resulted in incrases to PacifiCorp's residential and small-fa customers' electc bils in Oregon,
Washingtn and Idaho.
In Febru 2008, the BP A initiate a rate proceg under the Nortest Power Act to rensider the level of benefits for the yeas
2002 though 2006 consistet with th Nin Ciruit's decisions, as well as to re-estblish the level of benefits for years 2007 and 2008
and to set the level of benefits for year 2009 and beyond. The BPA issued its fi records of decision in Septeber 2008 estblishing
rates for the time period of Ocber 2008 thoug Septembe 2009 and adopting a residential purchas and sale agrement for October
2008 though Septembe 2011. In September 2008, the OPUC approved PacifiCorp's reuest to execute the residential purchase and
sale agreement for the payment of Residential Exche Progr benefits from the BP A. In October 2008, the OPUC and WUC
approved PacifiCorp's filing of revised taff shee to resume residential exchange credits, effective November 1, 2008. Because these
credits are passed though to PacifiCorp's custmers, they do not signficantly affec PacifiCorp's fiancial results.
In October 2008, the BPA offered PacifiCorp a long-term residential purchae and sale agrement for Ocber 201 1 thoug
September 2028. In December 2008, the OPUC denied PacifiCorp's request to execut the residential purcha and sale agment for
these years. Also in December 2008, PacifiCorp fied two pettions with the Ninth Circuit for review of the BPA's fial records of
decision. Because these credits ar passed though to PacifiCorp's cuomer, they do not signficantly affec PacifCorp's ficial
results.
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 1(2)A Resubmission 0311/2009 2008/04
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
United States Mine Saety
PacifiCorp's miing operations ar regulated by the federal Mine Safety and Health Admsttion ("MSHA"), which admsters
federal mine safety and health laws, reguations and state regulatory agencies. The Mine Improvement and New Emergency Response
Act of2006 ("MIR Act"), enacte in June 2006, amended previous mine safety and health laws to improve mie.safet and heath
and accident preparedness. PacifiCorp is required to develop a wrtten emergency response plan spcific to each underground mie it
operates. These plans must be reviewed by MSHA every six months. It also requies every mine to have at leas two rescue team
located withn one hour, and it limts the legal liabilty of rescue te members and the companies that employ them. The MIR Act
also increases civil and crnal penalties for violations offederal mie safet stadads and gives MSHA the abilty to insitute a civil
action for relief, including a tempora or perment injuncton, restnin order or other appropnate order agait a mie opertor
who fails to pay the penalties or fines.
I FERC FORM NO.1 (ED. 12-96)Page 109.12
Adjustment Mechanism (1)PacifiCorp has reues approva of an ener cost
adjusent mechaism ("ECAM") to reover the difference
bet bas powe co se durg a gener rate cas and
acua powe cos. The application is cutl peding
before the UPSC.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/209 200/04
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
State Regulation
PacifiCorp is subject to comprehensive reguation by the UPSC, the OPUC, the WPSC, the WUC, the IPUC and the CPUC.
PacifiCorp purues a reguatory progr in all states, with the objectve of keeping rates closely aligned to ongoing costs. The
following table ilustrtes PacifiCorp's recovery mechansm in each state jursdicton in which PacifiCorp operates.
State Regulator
Uta Public Service
Commission
Orgon Public Utility
Commission
Wyoming Public Serce
Commission
Washington Utilities and
Traporttion Commission
Idao Public Utilities
Commission
California Public Utilities
Commission
Base Rate Test Period
Foreasted or historica with
known an measble
chages (2)
Fored
Fore or histrica with
known and meable
changes (2)
Histca with know and
meable chages
Histrica with known and
measurble chages
Forte
Anua trition adjusent mechaism ("TAM"), a
mechasm for anua rate adjusents for foreaste net
vaable po co; no tre-up to acal net vaable power
costs.
Renewle adjustent clause ("RAC") to reover the revenue
reuirent of new reewable resour and assoiate
trsmission tht ar not reflec in gener raes.
Anua SB 408 tre-up of taes autori to be collec in
ra compa to ta paid by PacifiCorp, as defined by
Orgo stte and adinstve rues.
Pow co adjustment mechaism ("PCAM') bas on
fored net po co lat tr-up to ac net powe
co. Subjec to dea bads and custer sharng.
Deer mechanism of coss for up to 24 month of new bas
loa generion reoures that quaify under the stte's
emissions pedonnance stadad and are not reflec in
gener rates.
PacifiCorp ha reues approval of ECAM to recover the
differece be base power costs set durig a gener rate
cas and ac powe costs. The applicaion is curently
pending before the IPUC.
Pos te-yea adjustment mechaism for major capita
additions ("PAM - capita additions"), a mechaism th
allows for rate adjusents outside of the context of a
tritiona rate ca for the revenue reuireent asiated
with caita additions exceing $50 milion on a
tot-cmpa bais. Filed as eligible caita additions ar
plac into sece.
Post test-yea adjusent mechaism for atttion ("PTAM -
attion"), a mechaism that allows for an anua adjusent
to co oter th net varable powe costs tied to the
Coner Prce Index minus a 0.5% producvity offse
Ener co adjusent claus ("ECAC") tht allow for an
anua updte to ac and forased net vaable powe
cost.
(I) Marns eaed on wholese saes for ener and caacity have histcaly bee included as a component of rel cost
of seice upon whch rel rate ar ba.
(2) PacifiCor ha relied on both historica test peod with knwn and meale adjusents and fore te peods.
The WPSC ha not isued a fina ruing on its preerce bet a histrica or forte tes perod.
IFERC FORM NO.1 (ED. 12-96) Page 109.13
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 2008/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
Utah
In December 2007, PacifiCorp filed a gener rate case with the UPSC requesting an anual increase of $161 millon, or an averge
pnce incrase of 1 1 % based on a test penod ended June 2009. The increase wa primaly due to increased capital spending and net
power costs, both of which are dnven by load growt. In March 2008, PacifiCorp fied supplemental testimony reducing the requested
rate increase to $ 1 00 millon. The decrease was pnmarly a result of a UPSC-ordered chage in the test penod to the year ended
December 2008 and reductions associated with recent UPSC orders on depreciation rate changes and two defered accuning
requests. Subsequently, hearngs were held on the revenue requirement portion of the cas and PacifiCorp filed additional testiony. In
Augu 2008, the UPSC issued its revenue requirement order in the cas, increasing rates by $36 milion, or 3%. The new ras became
effecve Augt 13, 2008. In Septembe 2008, PacifiCorp fied a petition for reconsideration of several elements of the order. In
October 2008, the UPSC issued an order on the reconsideration petition allowig PacifiCorp to recver an additiona $3 millon,
bnnging the total rate increase to $39 millon. A setlement tht provides for an equal pecentae increas to all taff customers wa
reached in the rate-design phase of the cae and was approved by the UPSC.
In July 2008, PacifiCorp filed a general rate cae with the UPSC requesting an anua increase of $161 millon, or an average pnce
increase of 11%, pnor to any considertion for the UPSC's order in the December 2007 case descnbed above. In Septeber 2008,
PacifiCorp fied supplemental testimony that reflected then-curnt revenues and other adjusents based on the Aug 2008 order in
the 2007 general rate case. The supplemental fiing reduced PacifiCorp's request to $115 millon. In October 2008, the UPSC issued
an order changing the test period from the twelve months ending June 2009 using end-of-perod rate base to the forecast calenda yea
2009 using average rate base. In December 2008, PacifiCorp updaed its fiing to reflect the chane in the test penod. The updated
filing proposes an increase of $ 1 16 millon, or an avere pnce increas of 8%. The UPSC issued an order resetg the beginng of
the 240-day statutory time penod required to process the case to the date of the September 2008 supplemental fiing. Based on the new
time penod, the new rates, if approved, will become effective in May 2009. In Febru 2009, a settement agreement was reahed
among the paries who had fied testimony in the cost of capital phase of the rate case. A stipulation was fied with the UPSC
requesting that the UPSC set the weighted cost of capita at 8.4% with a retu on equity at 10.6%. The UPSC approved the cost of
capital settlement agreement by bench order in March 2009. Rebuttl testimony wa fied with the UPSC for the 2008 general rate case
in March 2009 which wil support a rate increae of $57 millon, or 4%, which reflec the cost of capital setlement. In March 2009, a
setement agreement was filed with the UPSC resolvig all remaing reenue requirement issues resulting in paries agreeing, among
other settlement terms, on a $45 millon, or 3%, rate increase tht would be effective on May 8, 2009. The UPSC will hold heangs on
Mach 31, 2009 to address the approval of the revenue requirment settlement agrment.
In March 2009, PacifiCorp fied for an energy cost adjustent mechasm with the UPSC. The fiing recommends the UPSC adopt the
energy cost adjustment mechanism to recover the difference beten base power costs set in the next Uta general rate case and ac
power costs.
IFERC FORM NO.1 (ED. 12-96) Page 109.14
Page 109.15
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0311/200 208104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
Oregon
In April 2008, PacifiCorp mae its fi anua renewable adjustmen claus RAC fiing to recver the revenue requiement related to
eligible new renewable resoures and assoiated trssion mider the OREA that are not refleced in general rates. PacifiCorp
requested an anua increase of$39 millon on an Orgon-allocate basis, or an average price increase of 4%. In November 2008, the
OPUC issued an order approving the RAC request with certn modifications. The O~UC excluded Oregon's shar of the costs for the
99-MW Rollng Hills wind-powered generating plant from the request on the basis that PacifiCorp failed to prove the resource was
pruently acquird. The OPUC's finding was priarly based on the conclusion tht the capacity facor was less favorable compared to
other mispecified Wyoming wind-powered generating project PacifiCorp may have been able to acquie. In December 2008 and
Janua 2009, PacifiCorp submittd compliance filings consistent with the OPUC order that togeter reduced the requested increase by
$8 millon to $31 millon, or an average price increase of3%. The OPUC approved $25 millon, or 2%, to go into effect on Janua 1,
2009. The OPUC approved an additional $6 millon, or 1%, to go into effect on Janua 21,2009 for the 99-MW Seven Mile Hill
wind-powered generating plant.
In July 2008, as par of its anua TAM, PacifiCorp filed update fored ne power cost for 2009. PacifiCorp proposed a net
power cost increase of $57 millon on an Orgon-allocate basis, or an avera price increase of 6%. In September 2008, PacifiCorp
fied a stipulation agreement reducing the proposed net powe cost incras to $34 millon on an Oregon-allocated basis, or an average
price increase of 2%. The stipulation ageement was approved by the OPUC in November 2008. The forecasted net power costs were
updated. again in November 2008 for OPUC-ordered chages, chages to the forwd price cure and new wholesale sales and
purchass. In December 2008, PacifiCorp submitted a compliance filing in the TAM proceeding tht reflected fina forecated net
power costs and diect access trition adjustments for 2009. The compliance filing reduced PacifiCorp's request by an additional
$15 millon on an Orgon-allocated basis, which resulted in an increae of $9 millon, or an average price increae of 1%, after
adjusting for load growt. The compliance filing was approved in December 2008 and the new rates becae effective Janua 1, 2009.
For a discussion of SB 408, refer to Note 5 of Notes to Financial Stats included in ths Form NO.1.
Wyoming
In Jmie 2007, PacifiCorp filed a genera rate case with the WPSC requesting an anua increa of $36 millon, or an average price
increae of 8%. In addition, PacifCorp request approval of a new renewable resource recovery mechansm and a magil cost
pricing taff to beter reflect the cost of adding new generation. In Janua 2008, PacifiCorp reached a setement in principle with
paries to the cas. The settlement provided for an anua rate increase of$23 millon, or an avere price increae of 5%. In addition,
the paries also agred to modiry the curent PCAM to use forecasted power costs in the futue and to termnate the PCAM by
April 2011, miless a continuation is specifically applied for by PacifiCorp and approved by the WPSC. PacifiCorp's magil cost
pricing taff proposal will not be implemented, but will be the subjec of a collaborative process to seek a new pricing proposal. Also
as par of the settlement, PacifiCorp agred to withdrw from ths filing its request for a reewable resource recvery mechansm. The
stipulation was approved by the WPSC in Mah 2008. The new rates were effecve May 1, 2008.
IFERC FORM NO.1 (ED. 12-96)
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03131/2009 20004
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
In Februar 2008, PacifiCorp fied its anual PCAM application with the WPSC for costs incured durg the penod December 1,
2006 thoug November 30, 2007. In March 2008, the WPSC approved PacifiCorp's request on an intenm basis effective Aprl 1,
2008, resulting in a rate increase of $31 millon, or an average pnce increase of 8%, to recover deferr power cost over a one-yea
penod. In August 2008, PacifiCorp reached an agrement with pares to the case to adjust the rat increae to $29 millon. In
November 2008, the WPSC issued an order approvig the stipulation agreement. The intenm rates were revised to reflect the
$29 millon increase approved in the stipulation agrment and became effectve Octber 15,2008.
In July 200S, PacifCorp filed a general rate case with the WPSC requesting an anual increase of $34 millon, or an averae pnce
increase of 7%, with an effectve date in May 2009. Power costs have been excluded from the filing and will be addressed separtely in
PacifiCorp'sanual PCAM application in Febru 2009. In October 2008, the gener rate case request was reduced by $5 millon, to
$29 millon, to reflec a change in the in-service date of the High Plain wid-powered generating plant. In March 2009, a settement
ageement was filed with the WPSC requesting an increae in Wyoming rates of$IS millon anually begig May 24, 2009, for an
averae overall increase of 4%. The WPSC held and completed public heargs on the 2008 rate case in March 2009. The WPSC
issued a bench decision approvig the stipulation agreeen and an $18 millon rate increae effective with serce on áDd afr
May 24, 2009.
In Febru 2009, PacifiCorp filed its anual PCAM application with the WPSC. Puuat to taff changes mae in the 2007 general
rate case, the 2009 PCAM application includes a request to recover $27 millon of deferred net power cost dunng the penod
December 1,2007 though November 30,2008 and to establish a new forecast base net power cost using the test penod December 1,
2008 thoug November 30, 2009. The net effect of the deferrd and forecast base net power cost is an increase in Wyoming rates of
$19 millon, or 4%. The taff governg the power cost adjustment mechanism requis an effectve date of Apnl 1,2009. As a result
of the 2008 general rate case settement agrement, PacifiCorp and certin pares agreed to request the WPSC implement an intenm
PCAM increase of $7 millon until the docket is resolved áDd a fial PCAM surcharge increase is detrmned. In Mach 2009, the
WPSC approved PacifiCorp's motion to implement the intenm rate increase of$7 millon effecive Apnl 1,2009.
Washington
In Februar 2008, PacifiCorp fied a genera rate case with the WUC for an anual increase of $35 millon, or an averae pnce
incr of 15%. In August 2008, PacifiCorp fied with the WUC an all-par settlement agreement in whch the paries agree to an
overl rate increase of $20 millon, or 9%. The settement wa approved by the WUC in Octber 200S with the new rates effecive
Octbe 15, 2008. The incrase is composed of an $18 millon increas to base rates, as well as a $2 millon anual surcharge for
approximately thee yea related to recovery of higher power costs incurd in 2005 due to poor hydroelecic conditions. PacifiCorp
ageed to drop the curent proposa for a generation cost adjustment mechasm and fuer commtted not to propose such a
mechansm in the next general rate case.
In Febru 2009, PacifiCorp filed a genera rate case with the WUC for an anua increase of $39 millon, or anaverage pnce
increae of 15%. The expected effectve date for the rate chage is Janua 11,2010. The filing includes a request to begin collecion
of a deferrl for costs associate with the 520-MW Chehalis natul ga-fired generang plant pnor to its inclusion in rate base
beginng in Janua 2010. The associated costs are estimated at $15 millon. PacifiCorp has proposed to recover these costs though
an extension in the hydroelectc deferrl mechasm and thereby not afecting curent customer rates.
IFERC FORM NO.1 (ED. 12-96) Page 109.16
IFERC FORM NO.1 (ED. 12-96) Page 109.17
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 0311/2009 2008/04
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
Idaho
In September 2008, PacifiCorp filed a general rate case with the IPUC for an anual increase of $6 millon, or an average price
increase of 4%. The increase is prily due to increased capita spending and net power costs. If approved, the new rates will become
effective April 18,2009. In Febru 2009, a seement signed by PacifiCorp, the IPUC staff and intervening paries was filed with the
IPUC resolving all issues in the 2008 genera rate cas. The agreement stipulates a $4 milion increase, or 3% averae rate incrase, for
non-contr retal cusmers in Idao. As par of the stipulation, inteening pares acknowledged the following: PacifiCorp's
acquisition of the Chehais, Wasgtn plant was prudent and the investment should be included in PacifiCorp's revenue requiment;
PacifiCorp ha demonstrted tht its demad-side maement program are prudent; and a base level of net power costs is established
for any futue energy cost adjusent mechasm calculations if a mechasm is adopted in Idao. In Febru 2009, paries to the
stipulation filed supportng testimony reommending the IPUC approve the stipulation as fied. Public heargs were held in
March 2009 for the IPUC to hea evidence in support of the selement and associated price incrase. A decision is pending.
In Octber 2008, PacifiCorp filed a reues with the IPUC for approval of an ECAM to defer for later recovery in rats the difference
beee base net power costs set durg a gener ra ca and ac net power cost incurd by PacifiCorp. If approved, PacifiCorp
would file an application with the IPUC anualy to adjus the ECAM surcharge rate to refud or collect the ECAM deferred balance
from the end of the prior calendar year.
California
In 2008, PacifiCorp made filings with the CPUC reuesting rate incres puruat to the post-test year adjusent mechansm and the
energy cost adjustment clause totaling $5 millon, or averae price incr totaing 6%. All reues wee approved by the CPUC and
the rates became effecive varous dates from Augt 23,2008 thug Janua 1,2009.
In Febru 2009, PacifiCorp fied a post test year adjusent mechasm for major capital additions amouning to a rate adjustment of
$1 millon, or 2%. The filing included the addition of four major renewable resources; the 99-MW Seven Mile Hill, the 99-MW
Glenock, the 39-MW Glenrock il and the 99-MW Rolling Hills wid-powerd generating failties. The rates became effecive
March 19, 2009.
Depreciation Rate Changes
For a discussion of PacifiCorp's depreiation rate chages, refer to Note 3 of Notes to Finacial Statements included in ths
FonnNo.I.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 2008/04
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
Environmental Regulation
PacifiCorp is subject to federal, stte and local laws and regulations with regard to air and water quality, renewable portolio stdards
("RPS"), climate change, haardous and solid wate disposal and other envionmentl matter and is subject to zonig and other
reguation by local authorities. These laws and reguations are subject to a rage of interprettion which may ultimately be resolved by
the cour. In addition to imposing continuing compliance obligatons, these laws and reguations authorize the imposition of
substtial penaties for noncompliance including fies, inunctive relief and other sanctions. PacifiCorp believes it is in material
compliance with all laws and reguations. The most signficant envionmenta laws and reguations affectg PacifiCorp include:
o The federal Clean Air Act as well as stte laws and reguations impcting air emssions, includng State Implementation Plan
("SIP") related to existig and new national ambient air quality stadads. Rules issued by the Envionmental Protection Agency
(the "EPA") and certin states require substtial reuctions in sulfu dioxide ("S02") and nitrogen oxide ("NOx") emssions
beginnng in 2009 and extending though 2018. PacifiCorp has already installed cerin emission contol tehnology and is tang
other measmes to comply with required reducons. Refer to "Clea Air Stadads" section below for additiona discussion
regarding ths topic.
o The federal Water Pollution Control Act ("Clean Water Act") and individual state clean water laws reguate coling water intae
stcts and discharges of waswater, includig storm water ruoff PacifiCorp believes tht it curently has, or has initiated the
procs to receive, all requied wate quaity permts. Refer to "Water Qulity Stadards" section below for additional discusion
regarding ths topic.
o The federa Comprehensive Environmental Response, Compenstion and Liabilty Act and similar state laws, whch may requie
any curent or former owners or operators of a disposal site, as well as trsporters or genertors of hazdous substaces set to
such disposal site, to sha in environmental remediation costs. Refer to Note 13 of Notes to Finacial Statement included in this
Form NO.1 for additional informtion regarding environmenta contigencies.
o The FERC oversees the relicensing of existig hydroelectc syste and is also responsible for the oversight and issuace of
liceses for new consction of hydroelecc systems, dam safet inpecions and environmental monitorig. Refer to Note 13 of
Notes to Financial Statements included in this Form No. 1 for additional information regading the relicensing of cert of
PacifiCorp's existing hydroelectc generating facilties.
Clean Air Standards
The Clean Air Act provides a frework for protecting and improving the nation's air quality, and controllng mobile and stationa
sources of air emissions. The major Clea Air Act progrs, which most directly affect PacifiCorp's elecc generting facilties, are
briefly descrbed below. Many of these progr are implemented and admistered by the states, whch can impose additiona, more
strgent requirements.
IFERC FORM NO.1 (ED. 12-96) Page 109.18
IFERC FORM NO.1 (ED. 12-96) Page 109.19
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0311/200 2008/04
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
National Ambient Air Qulity Standards
The EPA implements nationa ambient ai quaity stadas for ozone and fie pariculate matr, as well as for other crteria pollutats
that set the minium level of ai quaity for the United States. Aras that achieve the stadards, as determed by ambient air quality
monitoring, are chacterize as being in attinent, while those tht fail to meet the stadards are designted as being nonattinment
area. Generally, sources of emissions in a nonattent area are required to make emissions reductions. A new, more strigent
stadard for fine pariculate matt became effective in December 2006. This stadad was appealed to the United States Cour of
Appeals for the Distrct of Columbia Circuit ("D.C. Circuit"). On Febru 24, 2009, the D.C. Ciruit ruled that the EPA had failed to
adequaely explai why the anua fine pariculate matter standad set at 15 microgr per cubic metr was sufciently protectve of
public health and reded the rue for fuer review of the stadard. The existing rue will remain in place until the EPA taes
fuer action. Ai quaity modeling and prelimi air quaity monitoring data indicate the counties in Washigton, Orgon, Monta
Wyoming, Colorado, Uta and Arzona where PacifiCorp's major emission soures are located ar in attent of the curnt ambient
air quaity stdads.
In March 2008, the EPA issued fil rues to stngten the national ambient ai quaity stdad for ground level ozone, lowering the
stada to 0.075 par per millon from 0.08 par per millon. Sta have until March 2009 to charrize their attent statu,
and the EPA's determnations regarding non-attnmen will be made by March 2010 with SIPs due in 2013. Until the EPA maes its
fil attinent designtions, the impa of any new stdads on PacifiCorp will not be known.
Regulated Air Pollutants
In 2005, the EPA promulgated the Clea Air Mercur Rule ("CAM") whch would have regulated mercur emissions from coal-fired
generating facilties though the us of a cap-and-trde system begig in 2010, with reductons of approximately 70010 when fuly
implemente in 2018. The CAM wa over by the Unite Stas Cour of Appeals for the Distrct of Columbia Circuit in
Febru 2008. The EPA pettioned the Unite Stas Supreme Cour for reiew of th lower cour's decision in October 2008. On
Febru 6, 2009, the EPA withdr its petion for review before the United States Supreme Cour and on Febru 23, 2009, the
Supreme Cour dismss the petion. The EPA ha indicate it plan to propose a new meur rue tht will requie coal-fired
generating facilties to utilze Maxmum Achievable Control Technology, rather th a cap-and-trde mechaism, to reduce mercur
emssions. As a result, PacifiCorp's coal-fired generatig facilties may be required to instal controls to reduce mercur emissions at
each of its failties rather than mang cost-effectve mercu emssion reductons thug a combination of controls and allowaces.
Depnding on the scope and timng of these reduction requirements, as well as the availabilty and effectveness of controls, the new
rues could impose additional costs on PacifiCorp for control of merur emissions above the costs anticipated under the CAM
The emissions reuctions could be mae more stingent by curnt or fu reguatory and legislative proposas at the federal or stte
levels that would result in signficant reductions of S02, NOx and mercur, as well as cabon dioxide and other gases that may afect
global climte chage.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp . (2) A Resubmission 0331/2009 2008/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
Regional Haze
The EPA has initiated a regional haz progr intended to improve visibilty at speific federaly protecd areas. Some of
PacifiCorp's generating failties meet the theshold applicabilty critea under the Clean Ai Visibilty Rules. In accordance with the
federal requirements, sttes were required to submit SIPs by December 2007 to demonstrte reasonable progress towad achieving
natual visibilty conditions in certin Class I areas by requiring emssion controls, known as best available retofit technology, on
sources with emissions that are anticipated to cause or contrbut to impairment of visibilty. Wyomig ha not yet submitt its SIP
and is continuig to review the planed emission reductions at PacifiCorp's Wyoming generating facilties. Uta submitt its SIP and
suggeste tht the emission reducton project planed by PacifiCorp are sufcient to meet its initial emssion reuction requirements.
In Janua 2009, the EPA made a fiding that 37 states, including Wyoming, had failed to file a SIP tht met some or all of the basic
progr requirements under the regional ha progr. As a result, Wyomi ha two year from Janua 2009 to file and obta EPA
approval of a SIP that meets all of the regional haz progr requirements or the stte will be subject to a federal implementation plan,
with the EPA adstrig the regional hae progr. PacifiCorp believes that its planed emission reduction project will satisfy the
regional haz requirements in Uta and Wyomig; however, it is possible that some additional controls may be required once the
respective SIPs have been submittd or tht the timng of the instalation of planed controls could be chaged.
New Source Review
Under existing New Source Review ("NSR") provisions of the Clean Ai Act any failty that emits reguated pollutts is required to
obtain a permt from the EPA or a state regulatory agency prior to (i) beginng constrcton of a new major stationa source of an
NSR-reguated polluta, or (ii) mang a physical or operational change to an existig stationar source of such pollutts that
increass certn levels of emissions, uness the changes ar exempt under the regulations (including routine maintenace, repair and
replacement of equipment). In genera, projec subject to NSR reguations ar subject to pre-consction review and permttg under
the Prevention of Signficant Deterioration ("PSD") provisions of the Clean Ai Act. Under the PSD progr a projec tht emits
thshold levels of reguated pollutts must undergo a "best available contol technology" anysis and evaluate the most effective
emssions controls. These controls must be installed in order to receive a pert. Violations ofNSR reguations, which may be alleged
by the EPA, sttes and envionmntal groups, among others, potentially subject a utilty to material fies and other sanctons and
remedes, including requiring instllation of enhanced pollution controls and fuding supplemental environmenta project.
As par of an industr-wide investigation to assess compliance with the NSR and PSD provisions, the EPA ha requested frm
numerous utlities inormtion and supporting documentation regading their capital projecs for varous generating facilties. 'Beteen
2001 and 2003, PacifiCorp responded to requests for informtion relating to its capita project at its generating facilties and has been
engaged in perodic discussions with the EPA over severa year regarding PacifiCorp's historica project and their compliance wi
NSR and PSD provisions. An NSR enforcement case against another utilty has ben decided by the United States Supree Cour
holding that an increae in anual emissions of a generating facilty, when combined with a modification (i.e., a physical or operational
change), may trigger NSR permtting. PacfiCorp canot predict the outcome of its discussions with the EPA at this time; however,
PacifiCorp could be required to install additiona emissions controls, and incur additional cost and pelties, in the event it is
detrmed that PacifiCorp's historical project did not meet all reguatory requirements.
Numerous chages have be propose to the NSR rules and reguations over the last several year. These chanes, withdrwas of
proposed changes, differing interprettions by the EPA and the cour, and the reent change in adstrtion, create risk and
uncertinty for regulate entities in complying with NSR requiements when pertting new project and intaling emission contrls at
existing facilties. PacifiCorp monitors these changes and interprettions to ensure permttng activities ar conduc in accordance
with the applicable requiements.
IFERC FORM NO.1 (ED. 12-96) Page 109.20
IFERC FORM NO.1 (ED. 12-96) Page 109.21
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03131/2009 2008104
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
Renewable Portolio Standrds
The RPS described below could signficantly impact PacifiCorp's ficial results. Resources tht meet the qualifYg electcity
requirements under the RPS var frm stte-to-state. Each state's RPS requires some form of compliance reporting and PacifiCorp can
be subject to penalties in the event of non-compliance.
In November 2006, Washin vote approved a ballot intiative establishing a RPS requirment for qualifying electic utlities,
including PacifiCorp. The requiements ar tht 3% of retal sales by Janua 2012 thoug 2015,9% of retal sales by Janua 2016
though 2019 and 15% of reil sales by Janua 2020 be supplied by quaified renewable resources. The WUC has adopted fi
rues to implement the initiative. PacifiCorp exp to be able to recover its costs of complying with the RPS, either though rate caes
or an adjustment mechasm.
In June 2007, the Oregon Renewable Energ Act (the "OREA") wa adopte, providig a comprehensive renewable energy policy for
Oregon. Subjec to cein exemptions and cost limtations established in the OREA, PacifiCorp and other quaifyng electc utilities
must meet minimum qualifying eleccity requiements for electcity sold to retal cutomers of at least 5% in 201 i though 2014,
15% in 2015 though 2019,20010 in 2020 though 2024 and 25% in 2025 and subsequent year. As requied by the OREA, the OPUC
ha approved an automatic adjustment clause to allow an electric utility, including PacifiCorp, to recover prudently incured costs of its
investments in renewable energy generating facilties and associated trmission costs. The OPUC and the Orgon Deparent of
Energy have underten additional ruemg proceedings to fuer implement the intiative. PacifiCorp expects to be able to recover
its costs of complyig with the RPS though the automac adjusent mechansm.
Californa law requires electc utilties to incre their procuren of reewable resources by at leat 1 % of their anual rel
electcity sales per year so tht 20% of their anua eleccity saes are procured frm renewable resources by no later than
December 31,2010. In May 2008, PacifiCorp and otr small multi-jursdictona utilities ("SMJU") received fuer gudance from
the CPUC on the tratment of SMJs in the Californa RPS progr. In Aug 2008, concurent with its anua RPS compliance
filing, PacifiCorp, joined by another SMJ, fied a Joint Motion for Review of the decision, including banng of RPS procuremen
mae whle it awaited fuer gudance from the CPUC on the tratment of SMJUs during the 2004-2006 period. PacifiCorp note
among other thgs on ths filing that its interpretation is consistent with the CPUC gudance and best seres the inteests of its
cuomers by recognzing pas good faith effort to comply with Californa's RPS progr beginng Janua 2004. PacifiCorp is
curently awaiting the CPUC's response to the Joint Motion for Review. Absent fuer direction from the CPUC on treatment of
SMJUs, PacifiCorp canot predict the impac of the Californa RPS on its fiancial results.
In March 2008, Uta's goveror signed Uta Sente Bil 202, Energy Resoure and Carbon Emission Reduction Intiative. Among
other thgs, this law provides that. begining in the year 2025, 20% of adjused reil elecc sales of all Uta utilties be supplied by
renewable energy, if it is cost effecve. Retl elecc saes wil be adjused by deducting the amount of generation from sources tht
produce zero or reduce carbon emssions, and for saes avoided as a result of energy effciency and demad-side management
progrs. Quifying reewable energy sources ca be locate anhere in the WECC areas and reewable energy crits ca be
used. PacifiCorp expec to be able to recover its cost of complying with the law, either though rate cases or adjustent mechansms.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) lÇ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03131/200 20004
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
Climate Change
As a result of increased attntion to global climte change in the United States, there are significant fue environmenta reguations
under consideration to increase the deployment of clean energy technologies and regulate emissions of greenhouse gas at the state,
regional and federal levels. Congress and federal policy maers ar considerig climate change legislation and a varety of national
climte chage policies. President Obama has expressed support for an economy-wide grnhouse gas cap-and-tre progr tht
would reduce emissions 80% below 1990 levels by 2050. Alternatively, or in conjunction with a cap, policy maers have disced the
possibilty of imposing a ta on grenhous ga emissions. Given the strong interest and support in reducing greenouse gas emissions,
PacifiCorp's electc generating facilties are likely to be subject to regulation of greenouse gas emissions within the next several
year.
In addition, nongovernental organtions have become more active in intiating citizen suits under existing envionmtal and other
laws and the EPA issued an advanced notice of proposed ruemakng in 2008 to consider issues associatd with reguating grenouse
ga emissions under the Clea Air Act. The United Staes Supreme Cour has rued that the EPA has the authority under the Clea Air
Act to regulate emissions of greenhouse gass from motor vehicles and that the EPA must mae a deternation relating to the dager
posed by grenhouse gas emissions. Furerore, pending cases tht address the potetial public nuisance from grenhouse ga
emssions from electrcity generators and the EPA's failure to reguate greenhouse gas emissions from new and existing coal-fired
generating facilties ar expected to become active. While debate continues at the national level over the direction of domestic climat
policy, several states have developed state-specific laws or regional legislative initiatives to reduce greenhouse ga emissions that ar
expected to impac PacifiCorp, including:
o The Western Regional Climate Action Initiative ("Wester Climte Initiative"), a comprehensive regional effrt to reduce
greenhouse ga emissions by 15% below 2005 levels by 2020 though a cap-and-trde program tht includes the electcity sectr.
The Western Climate Initiative includes the states of Arzona, California, Monta, New Mexico, Oregon, Uta and Washigtn
and the provinces of British Columbia, Mantoba, Ontao and Quebe. The state and provicial parers have agred to begin
reportg greenhouse gas emissions in 2011 for emissions that occur in 2010. The fi phae of the cap-and-trde progr will
begin in Janua 2012.
o An executive order signed by Californa's governor in June 2005 would reduce greenhous ga emissions in tht state to 2000
levels by 2010, to 1990 levels by 2020 and 80% below 1990 levels by 2050. In addition, Californa has adopt legislation that
imposes a greenhouse gas emission performance stadard to all electrcity generted within the stte or delivere from outside the
state tht is no higher than the grenhouse ga emission levels of a state-of-the-ar combined-ccle natual gas*fied generatig
facilty, as well as legislation that adopts an ecnomy-wide cap on grenhoue ga emissions to 1990 levels by 2020.
o The Washington and Oregon governors enaced legislation in May 2007 and August 2007, respecively, estblishig
economy-wide goals for the reduction of greenhouse gas emissions in their respive states. Washingn's goals seek to (i) by
2020, reduce emssions to 1990 levels; (ii) by 2035, reduce emssions to 25% below 1990 levels; and (ii) by 2050, reduce
emissions to 50% below 1990 levels, or 70010 below Washington's forecasted emissions in 2050. Oregon's goals seek to (i) by
2010, ceas the growt of Oregon greenhouse gas emssions; (ii) by 2020, reduce grenhouse gas levels to 10% below
1990 levels; and (ii) by 2050, reduce greenouse ga levels to at least 75% below 1990 levels. Each state's legislation also calls
for state governent-developed policy recmmendations in th fue to assist in the monitori and achievement of these goals.
The impac of th ena legislation on PacifiCorp canot be deted at ths time.
IFERC FORM NO.1 (ED. 12..96) Page 109.22
Page 109.23
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03131/2009 20/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
In addition to pending legislative proposals to regulate greenhouse gas emissions, in July 2008, the EPA issued an advance notice of
proposed ruemag presenting informtion relevant to, and solicitig public comment on, how to respond to the United States
Supreme Cour's decision in Massachusetts v. EPA, in whch the Unite States Supreme Cour rued tht the Clean Air Act autories
regulation of greenhouses gases because they meet the definition of an air pollutat under the Clean Air Act given the potential
ramfications of a decision to regulate such emissions under the existig Clean Air Act frework.
PacifiCorp is curently subject to specifc greenhouse gas-related requirements, including mandatory grenhouse gas reporting
requirements in California, Washigton and Orgon. Californa, Washigton and Orgon also require the consideration of grenhouse
gas emissions in new resource decisions thoug the establishment of greenhouse gas emissions perfonnce stadards and the
requirement for mitigation of greenous gas emissions in conjuncton with the addition of new emitting resources.
PacifiCorp believes in implementing public policy to addrss climte chage in a maer tht inorm all constituents of cost
rafications and atempts to minize such cost. PacifiCorp believes that research and development must be underten on a large
scale and in a coordinated maer to obta technologies tht reduce caron emssions while still providing reasonably priced energy
and that the development and deployment of low-carbon electcity technologies must precede the imposition of signficant emission
reducton requirements or taes or fees on emssions. PacifiCorp contnues to add reewable and low-caron electric capacity to its
generation portolio in an effort to reduce the cabon intesity of its genering capacity. From 2005 to 2008, though the adition of
lower-carbon and renewable generation resources, PacifiCorp reduced the COi intensity of its electrcity generation portfolio by i 1 %
while increasing the number of megawatt hour ("MW") generated by 17%. In addition PacifiCorp has engaged in several volunta
progr designed to reduce or avoid grnhouse gas emissions, includig the EPA's sulfu hexafluoride reduction progr
refrgerator recycling progrs and the EPA landfll metane outach progr. PacifiCorp is a member of the California Climte
Action Registr and The Climte Registr, under whch it reort and certifies its grenouse gas emissions.
Climte change may cause physical and ficial risk thugh among other thgs, sea level rise, changes in precipitation and exteme
weather events. Energy needs may incr or decreas, bas on overl chages in weather. Availabilty of resoures to generte
electcity, such as wate for hydrelectc producton and coling puroses, may also be imaced by climate chage and could
infuence PacifiCorp's existing and fu eleccity generaion portolio. These issues may have a direct impact on the costs of
electcity producton and increase the price paid by customer for electcity.
Legislative and reguatory responses to climate chae have the potential to create fiancial risk. Adoption of early and strgen limits
on greenhouse ga emissions could significantly adversely impac PacifiCorp's curent and futue fossil-fueled failties, and therefore,
its finacial results. To the extnt that PacifiCorp is not allowed by its reguators or canot otherwse recover the costs incurd to
comply with climate change requiments, these requirements could have a material adverse impact on PacifiCorp's finacial results.
Cost of compliance with environmenta and other reguatory reuirements are historically recovered in rates but risk regulatory lag.
Although PacifiCorp does not mae policy and does not tae a position on the scientfic aspects of climate chane, it supports an
informed dialogue on climte chage and inteds to implement actons to coply with any new legislation or regulation. The impac of
any pending judicial proceedings and any pending or enactd federl and st climte chane legislation and reguation caot be
determned at ths time; however, adoption of stgent limits on grenouse gas emssions could adversely impact PacifiCorp's curent
and futu fossil-fueled generating failties, and, therefore, its fiancial results.
IFERC FORM NO.1 (ED. 12-96)
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp i2) A Resubmission 03131/2009 2008/04
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
Water Quality Standards
The Clean Water Act establishes the frework for maintanig and improvig water quality in the United States throug a program
that reguates, among other things, dischages to and withdrawals from waterwys. The Clean Water Act requires that cooling water
intae strctes reflect the "best technology available for mimiing adverse envionmental impac" to aquaic orgaisms. In
July 2004, the EPA estblished signficant new national technology-based performce stadards for existing elecc generating
facilties that tae in more th 50 millon gallons of water per day. These rues are aimed at minimizig the adverse environmental
impact of cooling water intae strctes by reducing the number of aquatic orgasms lost as a result of water withdrawas. In
response to a legal challenge to the rue, in Janua 2007, the Second Circuit Cour of Appeals remaded almost all aspec of the rue
to the EPA, leaving companies with cooling water intae strcts uncert regarding compliance with these requirements. Pettions
for certora are pending before the United States Supreme Cour regarding the Second Ciruit Cour of Appeals' decision. The Unite
States Supreme Cour will consider wheter Section 316(b) of the Clean Water Act authories the EPA to compare costs with benefits
in detrmng "best technology available for minimizig adverse environmntal impac" of cooling water intae solutions.
Compliance and the potential costs of compliance, therefore, caot be ascertned until such tie as the United States Supreme
Cour's decision is rendered or fuer action is taken by the EPA. Curently, PacifiCorp's Dave Johnton plant exceeds the 50 millon
gallons of water per day intae theshold. In the event that PacifiCorp's existing intae strcts require modification or alterntive
technology required by new rules, expnditues to comply with these requirements could be signficant.
Ash Disposal
In December 2008, an ash impoundment dike at th Tennessee Valley Authority's Kigston power plant collapsed after heavy ran,
releasing a significant amount of fly ash, bottm ash, coal combustion byproducts and water to the surounding ara. In light of ths
incident, federal and state offcials have called for greater reguation of coal combuston storae and disposal. PacifiCorp operates coal
ash impoundments and, in Janua 2008, voluntaly commtted under an industr acton plan to disposal restrctons, monitorig and
reporting of coal combustion product that exceed requirements under curnt law. These ash impoundments could be impactd by
additional regulation and could pose additional costs associated with ash management and disposal acivities at PacifiCorp's coal-fired
generating facilties. The impact of any new reguations on coal combustion product cat be determned at this tie.
Future Generation and Conservation
Integrated Resource Plan
As required by certin state reguations, PacifiCorp uses an Integrd Resoure Plan ("IR") to develop a long-term view of prudent
fue actons required to help ensur that PacifiCorp continues to provide reliable and cost-effective electc servce to its customers.
The IR process identifies the amount and timig of PacifiCorp's expectd fue resource needs and an associated opti futu
resource mix that accounts for planng uncertinty, risks, reliabilty impact and other fars. The IR is a coordinated effort with
steholders in each of the six states where PacifiCorp operates. PacifiCorp fies its IR on a biennial basis.
In May 2007, PacifiCorp released its 2007 IR, which identified a nee for approximtely 3,171 MW of additional reources by
sumer 2016 to satisfY the difference between project retail load obligations and owned or contrct reoures. PacifiCorp plans to
meet ths nee though demad reponse and energy effciency progr; the conscton or purchase of aditional generation,
including cost-effective renewable energy, combined heat and power, and thermal generation; and wholesale electcity trsaons to
mae up for the remining difference between retl load obligations and owned or contrct resources.
In June and Augut 2008, PacifiCorp submittd to the state regulatry commssions a 2007 IR update rert reflecg revised
planing assumptions. The need for additional resources by 2016 wa essentially unchaged at 3,202 MW. Relative to the initial
2007 IR, the planed resources to meet ths need include a heavier reliance on energy effciency measurs. Ths need was reduced by
509 MW due to the September 2008 acquisition of the Chehalis plant. PacifCorp's 2008 IR is scheduled to be filed in Spri 2009,
which will tae into account recent declines in load and growt expcttions.
IFERC FORM NO.1 (ED. 12-96) Page 109.24
IFERCFORM NO.1 (ED. 12-96) Page 109.25
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/209 20004
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
Requests for Proposal
PacifiCorp has issued a series of separte requests for proposa ("RFs"), each of whch focuses on a specific category of resources
consistent with the IR. The IR and th RFPs provide for the identification and staged procurement of resources in futue year to
achieve load/resoure balance. As required by applicable laws and reguations, PacifiCorp ties draf RFPs with the UPSC, the OPUC
and the WUC prior to issuance to the maet.
In Febru 2007, PacifiCorp tied a modified 2012 RFP (the "2012 RFP") in Uta for up to 1,700 MW of additional resources to
become available beginnng in 2012 though 2014. The 2012 RF was approved by the UPSC and issued to the market in April 2007.
In June 2007, proposals from qualifYing bidder were recived by commssion-directd independent evaluators. These bids included
varous strctues, ragig from purchase or lea of coal, natu ga and gether generting facilties to power purchas
agreements. Due to lack of cost effectve bids, the 2012 RF did not result in any new resources.
In Januar 2008, PacifiCorp issued to the maket a reewable reurces RF for resources less than 100 MW, or grat th 100 MW
for a power purchae agrement with a te of less than five year, to become available no later than December 2009. In
September 2008, PacifiCorp execute a power purhae agrement to purcha the entire output of the proposed 99-MW Thre Butts
wid-powered generatig plant locate in Wyomig. The generation of the energy and associated renewable energy credits under ths
agreement are expct to commence in December 2009 and continue for a period of 20 yea.
In Febru 2008, PacifiCorp tied an all-source 2008 RF (the ''2008 RFP") with the UPSC and the OPUC for base-load,
intermediate or thd quar sumer peag product to be delivered into PacifiCorp's system. The 2008 RFP seeks up to 2,000 MW
of resources to become available beginng in 2012 thug 2016. The 2008 RF wa approved by the OPUC and the UPSC and
subsequently issued to the maket in Octber 2008. Proposas wer reived from the maket in December 2008. The proposals were
evaluated and resulted in no cost effve proposas. As a result, the 2008 RF wa suspended and is expecte to be reissued durg
2009.
In April 2008, PacifiCorp filed its dr 2008R-1 renewable resources RF (the ''2008R-1 RFP") with the OPUC. The 2008R-1 RF is
a 500 MW reuest for renewable generation project, with no single resoure grter th 300 MW and on-line dates no later than
Deceber 31,2011. The 2008R-1 RFP wa approved by the OPUC in September 2008. Single renewable resource requests under
300 MW do not require approval from the UPSC. The 2008R-1 RFP wa issued to the maket in Ocber 2008. Proposals were
received from the maket in December 2008 followed by an amendment issued in Janua 2009 to include new and updated proposals
tht were received in Febru 2009 which are being evaluated.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp . (2) A Resubmission 03131/2009 200/04
IMPORTANT CHANGES DURING THE QUARTERl EAR (Continued)
Demand-side Management
PacifiCorp has provided a comprehensive set of demd-side maement progr to its customer since the 1970s. The program
are designed to reduce energy consumption and more effectively maage when energy is used, including management of seasonal peak
loads. Curent program offer servces to customers such as energy engineering audits and informtion on how to improve the
effciency of their homes and businesses. To assist customers in investing in energy effciency, PacifiCorp offers rebates or incentives
encourging the purchase and instalation of high-effciency equipment such as lighting, heating and cooling equipment,
weatherization, motors, process equipment and systems, as well as incentives for effcient constrction. Incentives are also pad to
solicit parcipation in load management progr by residential, business and agrcultual customers though progr such as
PacifiCorp's residential and small commercial air conditioner load control progr and irgation equipment load control progr.
Subjec to radom prudence reviews, state reguations allow for contemporaeous recovery of costs incured for retl customer
demd-side maagement progrs and servces though state-specific energ effciency serce chages paid by all retail electc
customer. In addition to these retil custmer demad-side magement progr, PacifiCorp has load curilment contr with a
number oflarge industral cusmers that deliver up to 342 MW ofload reducton when neeed. Recover for the cost associate with
the large indusal load maagement program is determed though PacifiCorp's genera rate case procss. In 2008, $77 millon was
expended on the demad-side mangement progr in PacifiCorp's six-state servce area, resulting in an estimted 395,000 MWh of
first-year energ savings and 338 MW of peak load maagement. Tota demd-side load available for control in 2008, including bothload magement from the large indusal curlment contrct and rel customer demad-side maemen progr, was
approxitely 680 MW.
Credit Ratings
Debt and prefered securties of PacifiCorp are rated by nationally recognzed credit ratig agencies. Assigned crdit ratings ar based
on each ratig agency's assessment ofPacifiCorp's abilty to, in general, meet the obligations of its issued debt or preferd securties.
The credit ratins are not a recommendation to buy, sell or hold securties, and there is no assurce tht a paricular credit ratig will
continue for any given period of time. PacifiCorp' s credit ratigs at March 31, 2009 were as follows:
Moody's Standard & Poor's
Issuer/Corporate
Senior securd debt
Senior uncured debt
Preferred stock
Commercial paper
Outlook
Baal
A3
Baal
Baa
P-2
Stable
A-
A
A-
BBB
A-2
Stable
PacifCorp has no credit rating-downgre trggers that would accelerte the matuty dates of outding debt and a change in ratigs
is not an event of default under applicable debt instents. PacifiCorp's unecured revolving credit facilties do not require the
maintenance of a mium credit rating level in order to drw upon their availabilty. However, commtment fees and interest rates
under the credit failties are tied to credit ratings and increas or decreae when the ratings chage. A ratings downgre could also
increase the fue cost of commercial paper, short- and long-tenn debt issuances or new credit facilties. Cer authorizations or
exemptions by reguatory commssions for the issuace of securties are valid as long as PacifiCorp maintains investment gre ratigs
on senior seured debt. A downgrde below that level would necessitate new reguatory applications and approvals.
IFERC FORM NO.1 (ED. 12-96) Page 109.26
I FERC FORM NO.1 (ED. 12-96)Page 109.27
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 20004
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
A chae to PacifiCorp's crdit rating could result in the requiement to post cash collateral, letrs of credit or other simlar credit
support under cer agreements related to its procurement or sae of electcity, natl gas, coal and other supplies. In accordance
with industr pratice, PacifiCorp's agrment may either speifically provide bilateral rights to demad cash or other securty if
credit exposures on a net bais exceed cert ratings-dependen theshold levels, or provide the right for counterpares to demad
"adequate assurces" in the event of a marial adverse change in PacifiCorp's creditwortess. As of December 31, 2008,
PacifiCorp's credit ratings frm the thee recognze crdit rating agencies were investent grade; however, if the ratings fell one
ratig below investment gre, PacifiCorp's collate reuirements would incrase by approximately $356 millon. Additiona
collater requiements would be necessar if rating fell fuer th one rating below investment gre. PacifiCorp's collateral
requirements could fluctue considerably due to seasnaity, market price volatility, a loss of key PacifiCorp generating failties or
other related factors.
Sunnyside Power Purchase Agreement
PacifiCorp and Sunyside Cogeneration Assoiates ("SCA") amended their 1987 power purchase agrement, which was approved by
the UPSC in April 2008 and became effecve in May 2008. As a result of the amendment, the agreeent qualifies as a capital lease.
The agreement requires PacifiCorp to purcha up to 53 MW of caity and energy from the SCA's coal-fired generating failty. The
amendment provides a new metod for deterg the avoided energy co paid to SCA by PacifiCorp. The amendment also puts
into place anual floor and ceiling prices tht ar applicable to the engy price. The origi ageement end date remans as Augut
2023 with a renewal option of additiona five-yea peod. Minwn lea payment obligations are based on a miimwn rate pe
megawatt-hour. PacifiCorp's miniwn lease paymnt under ths agrt will be $5 millon for the four year ending December 31,
2012; $5 millon for the four year ending December 31, 2016; $5 millon for the four yeas ending December 31, 2020; and
$5 millon for the three years ending December 31, 2023.
ITEM 13.
Offcer & Director Changes
On Febru 8, 2008, PacifiCorp's Senior Vice Prsiden and Chief Financial Ofcer, David J. Mendez, resigned as a directr and
offcer, effective Febru 29, 2008.
Douglas K. Stuver was electd Senor Vice Prident and Chef Finacial Ofce, effective March 1,2008. Mr. Stuver was serng as
Maaging Director and Division Contller ofPacifiCorp Energy.
ITEM 14.
Not applicable.
............................................
Delo'itte.Deloltt . Touche LLP
Suite 3900
111 SW Fift Avenue
Portand, OR 97204-3642
USA
Tel: [phone]
Fax: + 503 224 2172
www.delolt.com
INDEPENDENT AUDITORS' REPORT
PacifiCorp
Portland, Orgon
We have audited the balance sheet - regulatory basis of PacifiCorp (the "Company") as of Decembe 31,
2008, and the related statements of income - reguatory basis; retaed eags - reguatory bais; cah
flows - reguatory basis, and accumulate other comprehensive income, comprehensive income, and
hedging acvities - reguatory basis for the yea ended December 31, 2008, included on pages 1 10
though 123 of the accompanying Federal Energy Regulatory Commssion Form 1. These ficial
statements ar the responsibility of the Company's magement. Ou responsibilty is to express an
opinon on these fiancial statements based on our audit. .
We conducted our audit in accordace with auditing stada generlly accepted in the United States of
America. Those stadads requie tht we plan and perorm the audit to obta reaonable assurce about
whether the ficial stateents are fre of materal misstatement. An audit includes consideration of
inteal control over fiancial reportng as a basis for designg audit procedures tht are approriate in
the circtaces, but not for the purse of expressing an opinon on the effectiveness of the Company's
interal contrl over financial reprtg. Accordingly, we express no such opinion. An audit also includes
examg, on a test bais, evidence supportng the amounts and disclosurs in the ficial statements,
assessing the accountig principles used and signficant estites mae by maagement, as well as
evaluatig the overl financial stateent presentation. We believe th our audit provides a reaonale
basis for our opinon.
As discussed in Note 2, these ficial statements wer prepar in acordace with the accounting
requirements of the Federa Energy Regulatory Commssion as set for in its applicable Uniform Syste
of Accounts and published accountig releases, which is a comprehensive basis of accountig other th
accountig priciples generly acepte in the Unite States of America.
In our opiniol4 such regutory-basis finacial statements prsent faily, in all mateal respec, the
assets, liabilties, and proprieta capita of the Company as of Deber 31, 2008, and the results of its
opertions and its cash flows for the yea ended Decembe 31, 2008, in accordace with the accountig
requireents of the Federl Energy Regulatory Commssion as set fort in its applicable Uniform Syste
of Accounts and published acountig releaes.
Ths reprt is intended solely for the inortion and use of the board of diectors and maagement of the
Company and for filig with the Federl Energy Reguatory Commssion and is not intened to be and
should not be used by anyone other th these speified pares.
DJ"¥t ~ T~ LLP
Febru 27,2009 (March 31, 200 as to the Rate Matter secon of Note 5)
~ofDe1b ~
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1)IE An Original (Mo,Da, Yr)
(2)0 A Resubmission 03/31/2009 End of 2008/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line Currnt Year Prior Year
Ref.End of OuarterlYear End BalanceNo.Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
1 UTILITY PLAT
2 Utility Plant (101-106, 114)200-201 18,462,953,925 16,637,482,510
3 Construction Worl in Proress (107)200-201 1,208,785,536 941,818,776
4 TOTAL Utilty Plant (Enter Total of lines 2 and 3)19,671,739,461 17,579,301,286
5 (Less) Accm. Provo for Depr. Amort. Depl. (108, 110, 111, 115)200-201 6,848,927,351 6,691,765,903
6 Net Utilty Plant (Enter Total of line 4 less 5)12,822,812,110 10,887,535,383
7 Nuclear Fuel in Pross of Ref., Conv.,Enrich., and Fab. (120.1)202-203 0 0
8 Nuclear Fuel Matenals and Asemblies-Stock Accunt (120.2)0 0
9 Nuclear Fuel Asemblies in Reactor (120.3)0 0
10 Spent Nuclear Fuel (120.4)0 0
11 Nuclear Fuel Under Capital Leases (120.6)0 0
12 (Less) Accm. Provo for Amort. of Nucl. Fuel Asmblies (120.5)202-203 0 0
13 Net Nuclear Fuel (Enter Total oflines 7-11 les 12)0 0
14 Net Utilty Plant (Enter Total of lines 6 and 13)12,822,812,110 10,887,535,383
15 Utilit Plant Adjustments (116)122 0 0
16 Gas Stored Underground - Noncurrnt (117)0 0
17 OTHER PROPERT AND INVESTMENT
18 Nonutlity Propert (121)9,497,834 9,436,375
19 (Less) Accm. Provo for Depr. and Amor. (122)1,455,833 1,396,066
20 Investments in Associated Companies (123)9,031,958 7,637,258
21 Investment in Subsidiary Companies (123.1)224-225 171,510,195 149,005,037
22 (For Cost of Accunt 123.1, See Footnote Page 224, line 42)
23 Noncurrnt Portion of Allowances 228-229 0 0
24 Other Investments (124)85,601,343 87,106,834
25 Sinking Funds (125)0 0
26 Depreciation Fund (126)0 0
27 Amortzation Fund - Federal (127)0 0
28 Other Special Funds (128)8,081,370 9,530,018
29 Special Funds (Non Major Only) (129)0 0
30 Long-Term Portion of Derivative Assets (175)86,579,548 215,055,123
31 Long-Term Portion of Derivative Assets - Hedges (176)0 0
32 TOTAL Other Propert and Investments (Lines 18-21 and 23-31)368,846,4 !f 476,374,579
33 CURRENT AND ACCRUED ASSETS
34 Cash and Worling Funds (Non-major Only) (130)C 0
35 Cash (131)15,725,712 10,512,273
36 Special Deposits (132-134) .2,048,982 6,256,766
37 Worlin9 Fund (135)2,020 2,670
38 Temporry Cash Investments (136)3,937,516 182,317,755
39 Notes Recivable (141)270,949 616,766
40 Customer Accunts Receivable (142)34,007,077 373,257,825
41 Other Accunts Receivable (143)43,610,380 15,687,039
42 (Less) Accm. Provo for Uncolleible Acc.-Creit (144)8,679,145 6,551,765
43 Notes Receivable from Associated Companies (145)20,797,545 25,975,115
44 Accunts Receivable from Assoc. Companies (146)8,447,228 12,144,713
45 Fuel Stoc (151)227 136,802,882 98,334,182
46 Fuel Stoc Exnses Undistributed (152)227 0 0
47 Residuals (Elec) and Exracted Proucts (153)227 °0
48 Plant Matenals and Operating Supplies (154)227 170,075,369 150,050,022
49 Merchandise (155)227 C 0
50 Oter Materials and Supplies (156)227 C 0
51 Nuclear Materials Held for Sale (157)202-203/227 C °
52 Allownces (158.1 and 158.2)228-229 0 0
FERC FORM NO.1 (REV. 12-03)Page 110
............................................
............................................
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1)IX An Original (Mo,Da, Yr)
(2)0 A Resubmission 03/31/2009 End of 2008/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITSJContinued)
Line Currnt Year Prior Year
No.Ref.End of QuarterlYear End Balance
Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
53 (Less) Noncurrnt Portion of Allownces 0 0
54 Stores Expense Undistributed (163)227 C 0
55 Gas Store Underground -Currnt (164.1)0 0
56 Liquefied Natural Gas Store and Held for Procesing (164.2-164.3)C 0
57 Prepayments (165)
58 Advances for Gas (166-167)0 0
59 Interest and Dividends Receivable (171)28,10:-13,245,222
60 Rents Receivable (172)2,172,05C 3,189,547
61 Accrued Utility Revenues (173)210,896,OOC 192,299,000
62 Miscellaneous Currnt and Accrued Assets (174)8,854,407 11,238,653
63 Derivative Instrument Assets (175)260,256,08::357,980,420
64 (Less) Long-Term Portion of Derivative Instrument Assets (175)86,579,54E 215,055,123
65 Derivative Instrment Assets - Hedges (176)C 0
66 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 0 0
67 Total Currnt and Acc Assets (Lines 34 through 66)1,219,442,820 1,311,185,598
68 DEFERRED DEBITS
69 Unamortized Debt Exnses (181)30,017,721 27,166,066
70 Exraordinary Propert Losses (182.1)230 C 0
71 Unrecovered Plant and Regulatory Study Costs (182.2)230 10,439,101 15,589,069
72 Other Regulatory Assets (182.3)232 1,626,353,73C 1,081,739,789
73 Prelim. Survey and Investigation Charges (Electric) (183)1,091,392 0
74 Preliminary Natural Gas Survey and Investigation Charges 183.1)C 0
75 Other Preliminary Survy and Investigation Charges (183.2)0 0
76 Clearing Acunts (184)0 0
77 Temporary Facilties (185)88,82~115,300
78 Miscellaneous Deferrd Debits (186)233 72,806,094 52,116,892
79 Def. Losses frm Disposition of Utilty PIt. (187)0 0
80 Researc, Devel. and Demonstration Expend. (188)352-353 0 0
81 Unamortized Loss on Reaquired Debt (189)16,563,180 20,786,394
82 Accmulated Deferr Income Taxes (190)234 586,940,125 432,328,560
83 Unrecovered Purcased Gas Costs (191)(0
84 Total Deferrd Debits (lines 69 through 83)2,34,300,172 1,629,842,070
85 TOTAL ASSETS (lines 14-16, 32, 67, and 84)16,755,401,51f 14,304,937,630
FERC FORM NO.1 (REV. 12-03) Page 111
IFERC FORM NO.1 (ED. 12,;87) Page 450.1
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0331/200 200/04
FOOTNOTE DATA
............................................
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)0 A Rresubmission 0331/209 end of 2008104
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
line Currnt Year Prior Year
No.Ref.End of Quarter/Year End Balance
Title of Accunt Page No. Baance 12/31
(a)(b)(c)(d)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201)250251 3,417,945,896 3,417,94,896
3 Preferred Stock Issue (20)250251 41,46,30 41,46,30
4 Capital Stock Subscribe (202, 205)252 0 0
5 Stock liabilty for Converion (20, 206)252 C 0
6 Premium on Capital Stock (207)252 C 0
7 Other Paid-In Capital (208-211)253 8n,063,95E 427,06,956
8 Installments Received on capital Stock (212)252 C 0
9 (Less) Discunt on Capital Stock (213)254 0 0
10 (Less) Capital Stock Expense (214)254 41,288,207 41,288,207
11 Retained Earnngs (215, 215.1, 216)118-119 1,687,760,38:1 1,231,878,766
12 Unappropriated Undistributed Subsidiary Earings (216.1)118-119 6,508,77E 7,557,54
13 (Less) Reaquire capitl Stock (217)250251 C °
14 Noncorprate Proprietorship (Non-major only) (218)C °
15 Accumulated Other Comprehensive Income (219)122(a)(b)-2,550,68C -3,516,384
16 Total Proprietary Capital (lines 2 through 15)5,986,903,425 5,081,104,871
17 LONG-TERM DEBT
18 Bonds (221)256-257 5,510,797,OO 5,123,205,00
19 (Less) Reaquired Bonds (222)256257 C °
20 Advances from Associated Companies (22)256-257 C °
21 Other Long-Term Deb (224)256257 C °
22 Unamortized Premium on Long-Term Debt (225)38,281 40,999
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)7,96,911 6,014,592
24 Total Long-Term Debt (lines 18 through 23)5,502,871,37C 5,117,231,407
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capitl Leaes - Noncurr (227)59,390,32E 47,94,276
27 Accumulated Provision for Prope Insurace (228.1)C °
28 Accumulated Provision for Injuries and Damage (228.2)8,501,565 6,054,192
29 Accumulated Provision for Pensions and Benefits (228.3)604,317,22-4 315,188,411
30 Acumulated Miscellaneous Operating Provision (228.4)42,256,56C 38,105,696
31 Accumulated Provision for Rate Refunds (229)C 0
32 Long-Term Portion of Deriative Instrument liabilities 490,202,44~496,92,54
33 Long-Term Portion of Derivative Instrument Liabilities - Hedges C 0
34 Asset Retirement Obligations (230)80,948,143 75,241,936
35 Total Other Noncurrent Liabilties (line 26 through 34)1,285,616,269 979,463,051
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payabe (231)85,000,00 °
38 Accunts Payable (232)744,182,870 449,488,562
39 Notes Payable to Associated Companies (233)0 °
40 Accounts Payable to Asociated Companies (234)17,383,942 11,007,508
41 Customer Depoits (235)21,919,032 21,686,771
42 Taxes Accrued (236)262-26 28,648,482 20,901,699
43 Interest Accrued (237)88,65,332 86,897,114
44 Dividends Declared (238)520,947 520,947
45 Mature Long-Term Debt (239)0 °
FERC FORM NO.1 (rev. 12-03) Page 112
............................................
.............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
PacifiCorp (1 )00 An Original (mo, da, yr)
(2)0 A Rresubmission 0331/2009 end of 2008/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIT(Sntinued)
Line Currnt Year Prior Year
No.Ref.End of QuarterN ear End Balance
Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
46 Matured Interest (240)C 0
47 Tax ColleciOns Payable (241)14,388,66 13,034,927
48 Miscellaneous. Current and Accrued Liabilties (242)67,406,951 76,018,36
49 Obligations Under Capital Leases.current (243)5,768,00 1,428,748
50 Derivative Instrument Liabilties (244)620,548,36 613,992,765
51 (Less) Long-Term Portion of Derivative Instrument Liabilties 490,202,449 496,923,54
52 Derivative Instrument Liabilties - Hedges (245)0 0
53 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 0 0
54 Total Current and Accrued Liabilties (lines 37 through 53)1 ,204,219, 13€798,05,867
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)20,259,57e 17,485,789
57 Accumulated Deferrd Investment Tax Credits (255)266-267 49,828,35€53,767,820
58 Deferred Gains from Dispoition of Utilty Plant (256)C 0
59 Other Deferred Credits (253)269 42,762,022 59,527,962
60 Other Regulatory Liabilties (254)278 76,45,65 71,34,435
61 Unamortized Gain on Reaquired Debt (257)0 0
62 Accum. Deferred Income Taxes-Accel. Amort.(281)272-277 0 0
63 Accum. Deferred Income Taxes.Other Propert (282)2,095,724,933 1,832,890,057
64 Acum. Deferred Income Taxes-Other (283)490,759,775 29,06,371
65 Total Deferred Creits (lines 56 through 64)2,n5,791 ,318 2,329,08,43
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)16,755,401,518 14,30,937,63
FERC FORM NO.1 (rev. 12-03)Page 113
FERC FORM NO. 1/3 (REV. 02-()Page 114
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) 0 A Resubmission 03131/200
STATEMENT OF INCOME
Quarterly
1. Enter in column (d) the balance for the reporting quarter and in column (e) the baance for the same thre month period for the pror year.
2. Report in column (f) the quarter to date amounts for electric utility function; in column (h) the quarter to date amounts for ga utility, and in 0) the
quarter to date amounts for other utilty function for the current year quarter.
3. Report in column (g) the quarter to date amounts for electric utilty function; in column (i) the quarter to date amounts for gas utilty, and in (k) the
quarter to date amounts for other utilty function for the prior year quarter.
4. If additional columns are needed place them in a fotnote.
Annual or Quarterly if applicale
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expes frm Utilty 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 apprte. Include these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utility Operating Incme, in the sae manner as acunts 412 and 413 abve.
8. Report data for lines 8, 10 and 11 for Natural Gas companies using accunts 404.1, 40.2, 404.3, 407.1 and 407.2.
Line Tota Total Current 3 Monhs Prior 3 Month
No.Current Year to Prior Year to Ended Ended
(Ref.)Date Balance fo Date Baanc for Quarterly Only Quarterly Only
Title of Accunt Page No.OuarterNear QuarterNear No 4th Quarter No 4th Quarter
(a)(b)(c) (d) (e) (f)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)30301 ~3 Operating Expense
4 Operation Expnse (401)320-323 2,593,626,077 2,407,885,415
5 Maintenance Expnse (402)320-323
ji '''J1t
378,00,826
6 Deprecation Exnse (403)33337 418,496,84
7 Deprecatin Exns for Ast Retrement Cos (403.1)33337
8 Amort. & Depl. of Utilit Plant (404-405)33337 40,33,443 45,276,103
9 Amort. of Utilit Plant Acq. Adj. (406)33337 5,479,353 5,479,353
10 Amort. Propert Los, Unrecv Plant and Regulatory Study Cos (407)5,107,035 2,452,56
11 Amort. of Converson Expense (407)
12 Regulatory Debits (407.3)7,057,628 10,429,071
13 (Les) Regulatory Creit (407.4)
14 Taxes Oter Than Incme Taxes (40.1)26.263 .101,472,747
15 Incoe Taxes. Federal (409.1)26-263 125,610,768
16 - Other (409.1)262-263 15,623,546
17 Provion for Deferred Income Tax (410.1)234, 272-277 669,322,953 425,06,057
18 (Les) Proviion for Deferre Income Taxesr. (411.1)234, 272-277 356,785,266 36,448,712
19 Invement Tax Credit Adj. - Net (411.4)266 -1,874,204 -5,85,860
20 (Les) Gains frm Dis. of Utlit Plant (411.6)
21 Los from Dis. of Utilit Plant (411.7)
22 (Les) Gains frm Dision of Allowanc (411.8)4,88,027 14,663,498
23 Los from Disos of Allowances (411.9)
24 Acceton Exns (411.10)
25 TOTAL Utili Operating Exnse (Enter Totl of Hnes 4 thru 24)3,769,087,216 3,548,834,222
26 Net Utl Oper Inc (Enter Tot line 2 les 25) carr to Pg117,line 27 725,498,770 694,791,749
.............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A ResubmissÎon 03131/2009
S ATEMENT OF INCOME FOR TH YEAR (Continued)
9. Use page 122 for important notes regarding the statement of income for any account thereof.
10. Give concise explanations conceming unsettled rate prodings 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 respe to power or gas purchaes. State for each year effeced
the gross revenues or cots to which the contingency relates and the tax efecs together wih an explanation of the major factors which affect the rights
of the utilty to retain such revenues or recver 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
proeeding affecing revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expnse accunts.
12. If any notes appering 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 efect on net incoe,
including the basis of alloctions and apprtionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous year'slquarter's figures are diferent from that reported in prior reports.
15. If the columns are insufcient for reporting additional utility departments, supply the appropriate accnt titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(g) (h)
GAS UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(i) 0)
Line
No.
4,889,027 14,66,498
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
2,593,626,on
374,652,182
416,636,387
2,407,885,415
378,009,826
418,496,84
40,332,443
5,479,353
5,107,035
45,276,103
5,479,353
2,452,562
7,057,628 10,429,071
112,424,490
-83,683,183
-8,319,65
66,322,953
356,785,26
-1,874,204
101,472,747
125,610,768
15,623,546
425,065,057
36,448,712
-5,85,86
3,769,087,216
725,498,nO
3,548,83,222
694,791,749
FERC FORM NO.1 (ED. 12-96)Page 115
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) FiA Resubmission 0331/20
STA EMENT OF INCOME FOR THE YEAR (continued)
Une TOTAL (;urrent 3 Montns !"nor 3 Montns
No.Endd Ended
(Ref.)Quarterly Only Quarterly Only
Title of Accunt Page No.Current Year Previous Year No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(f)
27 Net Utilit Oprating Incme (Carred forwrd frm page 114)725,49,770 694,791,749
28 Oter Income and Deductons
29 Oter Income
30 Nonutilt Operang Income
31 Revenues From Mercandisng, Jobbing and Contract Work (415)2,278,244 2,760,357
32 (Les) Cos and Exp. of Mercandisng, Job. & Contrct Work (416)2,44,146 2,946,861
33 Revenues From Nonutilil Operations (417)233,693 239,021
34 (Les) Expnse of Nonutlil Operations (417.1)26,272 25,945
35 Nonoprating Rental Income (418)60,570 63,654
36 Equity in Earnings of Subsiary Companies (418.1)119 -1,905,654 1,716,150
37 Interes and Divdend Income (419)10,637,00 13,913,812
38 Allowance for Oter Funds Use During Constction (419.1)46,616,392 40,90,06
39 Mislaneous Nonoperating Income (421)144,442,511 164,005,754
40 Gain on Dison of Propert (421.1)2,378,68 89,266
41 TOTAL Other Income (Enter Total of lines 31 thru 40)202,271,027 221,522,26
42 Oter Income Deductions
43 Los on Dispoon of Propert (421.2)263,455 4,210,041
44 Misllaneous Amortization (425)340 1,165,477 1,118,623
45 Donations (426.1)340 2,848,144 2,863,061
46 Life Insurance (426.2)-2,259,327 -4,961,276
47 Penahies (426.3)1,560,618 4,184,046
48 Exp. for Certin Civic, Political & Related Activities (426.4)1,265,718 1,147,711
49 Oter Deuctions (426.5)143,419,88 161,982,725
50 TOTAL Oter Income Deductions (Totl of lines 43 thru 49)148,2,96 170,54,931
51 Taxes Applic. to Oter Income and Deucons
52 Tax Oter Than Income Taxes (408.2)26-263 23,746 223,659
53 Income Taxes-Fedra (409.2)26-263 20,014,193 18,941,072
54 Income Taxesher (409.2)26.263 2,719,596 2,573,778
55 Proviion for Deferre Inc. Taxes (410.2)234, 272-277 146,049,815 58,876,813
56 (Les) Proviion for Deferred Income T axesr. (411.2)234, 272-277 146,94,899 59,117,957
57 InvemetTaxCredit Adj.-Net (411.5)
58 (Les) Investment Tax Credit (420)2,065,26 2,06,26
59 TOTAL Taxes on Oter Income and Deuctons (Total of Une 52-58)20,012,191 19,432,105
60 Net Oter Income and Deductons (Totl of Une 41, 50, 59)33,99,871 31,545,232
61 Interes Charges
62 Interes on Long-Term Debt (427)313,572,98 278,731,910
63 Amort. of Debt Disc. and Expns (428)3,072,734 3,012,770
64 Amortization of Los on Reaquired Debt (428.1)4,223,214 4,651,715
65 (Les) Amort. of Premium on Deb-Cred (429)2,718 2,718
66 (Les) Amortzatin of Gain on Reaquire De-Creit (429.1)56,166
67 Inter on Debt to As. Companie (43)340
68 Oter Intere Exnse (431)340 14,625,06 29,764,583
69 (Les) Allonce for Borowd Funds Use During Consruon-er. (43)34,280,545 28,653,980
70 Net Interes Charges (Totl of lines 62 thru 69)301,210,737 287,448,114
71 Incme Before Extraordinary Items (Tot of lines 27, 60 and 70)458,282,90 438,88,867
72 Exraordinar hems
73 Exraordinary Income (434)
74 (Les) Exraordinary Deucton (435)
75 Net Exraordinary Itms (Totl of line 73 les Une 74)
76 Income TaxesFedera an Oter (40.3)262-263
77 Exraordinary Items After Tax Gine 75 less line 76)
78 Net Income (Totl of Une 71 and 77)458,282,90 438,888,867
FERC FORM NO. 113Q (REV. 02-()Page 117
............................................
..............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/31/209 2008/04
FOOTNOTE DATA
¡SChedule Page: 114 Line No.: 6 Column: c
Vehicle depreciation is chaged to functional accounts. The followig table sumzes the vehicle depreiation expene tht was
chaged to the fuctional accounts.
Yeas Ended
Deember 31,2008 2007
Vehicle Depreciation $ 13,465,822 $ 12,494,116
¡SChedule Page: 114 Line No.: 7 Column: c
PacifCorp records the depreciation expense of asset retiement obligations as either a reguatory asset or liabilty.
ISchedule Page: 114 Line No.: 14 Column: c
Payroll taes are charged to fuctional accounts, which is consistent with where labor is charged. The followig table sumzes the
payroll ta expense that was chaged to the fuctional accounts.
Year Ended
December 31,2008 2007
Payroll Tax Expense $ 37,428,777 $ 35,60,794
¡Schedule Page: 114 Line No.: 15 Column: c
The credit balance report in curent ta expense is primay attbutale to a provision-toretu tre-up for th calendar yea ended
December 31, 2007 and to a provision for net operatig loss (ta basis) and tax credit carbacks for the calendar yea ended
December 31, 2008. PacifiCorp's net operatig loss (ta basis) is primly attbutable to accelerate ta depreiation and ta bonus
depreciation taen in excess of book depreciation.
¡Schedule Page: 114 Line No.: 16 Column: c
See footnote line 15, colum C.
¡SChedule Page: 114 Line No.: 24 Column: c
Pacifcorp records the accretion expense of asset retiement obligations as either a reguatory asset or liabilty.
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
I~~
!I - -
236 13,325,103
............................................
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
03131/200
INGS
Year/Period of Report
End of 20004
This~rtls:(1) ~An Oriinal
(2) A Resubmission
STATEMENT OF RETAINED EAR
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 accunt 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 accunt 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 reservd 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.
Line Item~. ~
UNAPPROPRIATED RETAINED EARNINGS (Accunt 216)
1 Balance-Begnning of Period
2 Changes
3 Adjustments to Retained Eamings (Accunt 439)
4 Adoption of FASB Interpretation No. 48
5
6
7
8
9 TOTAL Credits to Retained Eamings (Acc. 439)
10 Adoption of SFAS No. 158 meaurement date provisions, net
11 of tax of ($94,130)
12
13
14
15 TOTAL Debits to Retined Eamings (Acc. 439)
16 Baance Transferred from Incme (Acnt 43 less Acnt 418.1)
17 Appropriations of Retained Eamings (Acc. 43)
18
19
20
21
22 TOTAL Apropritions of Retined Eamings (Acct. 43)
23 Dividends Declared-Preferred Stock (Account 437)
24 Preerred Stock, various series and rates
25
26
27
28
29 TOTAL Dividends Declared-Preferr Stoc (Acc. 437)
30 Dividend Declaredmmon Stoc (Acnt 43)
31
32
33
34
35
36 TOTAL Divideds Dere-Common Stock (Acc. 43)
37 Transfers from Acct 216.1, Unaprop. Undistrib. Subsidiary Eamings
38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
39
40
Contra Primary
ccount Affected
(b)
Current
OuarterN ear
Year to Date
Balance
(c)
Previous
OuarterNear
Year to Date
Balance
(d)
13,325,103
228.3 -1,36,26
-1,36,264
460,188,558 437,172,717
-2,083,790
-856,888
1 ,68,184,571 1,228,30,955
FERC FORM NO. 1/3 (REV. 02-0)Page 118
............................................
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
03131/200
INGS
Year/Period of Report
End of 2008/04
This ~rtls:
(1) ~An Original
(2) A Resubmission
STATEM NT OF RETAINED EAR
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 accunt 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.
Line
No.
41
42
43
44
45 TOTAL Appropriated Retained Eamings (Accunt 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Eamings-Amort. Reserve, Federal (Acct. 215.1)
47 TOTAL Appro. Retained Eamings (Acct. 215, 215.1) (Total 45,46)
48 TOTAL Retained Eamings (Acct. 215, 215.1,216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Ouarterly
49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Eamin9s for Year (Credt) (Account 418.1)
51 (Less) Dividends Received (Debit)
52 Transfers from Unapprop. Retained Eamings (Account 216)
53 Balance-End of Year (TotalUnes 49 thru 52)
Item
(a)
Contra Primary
ccount Affeced
(b)
Currnt
OuarterN ear
Year to DateBace
(c)
Previous
OuarterN ear
Yea to Date
Balance
(d)
3,575,811
3,575,811
1,687,760,382
3,575,811
3,575,811
1,231,878,766
i
-- I -- -- - -- --- --
7,557,54
-1,905,654
5,841,394
1,716,150
856,88
6,508,778 7,557,54
FERC FORM NO.113-Q (REV. 020()Page 119
Name of Respondent This i!rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) n A Resubmission 0331/20
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proceeds or Payment;(b)Bond, debentures and other long-term debt (c) Include comercl par, an (d) Ident seely suh ites as
inveents, fixed assts, intagibles, et.
(2) Infrmation abut noncah Inveting and financing activities must be provided in the Note to the Financal sttements. Also provide a reliation between 'Cash and Cash
Equivalent at End of Period' with rela amount on the Balance Sht.
(3) Operating Actvities - Other: Includ gans and losses pertning to operating activties only. Gains and loss pertining to inveting and financing actvies should be report
in those activities. Show in the Note to th Financials the amounts of interest paid (net of amount caitalized) and income ta paid.
(4) Investng Actvities: Include at Oter (line 31) net cash outfow to acquire other companies. Provide a recncilation of assets acquired with liabilties asum in the Notes to
the Financial Statements. Do not include on this statement th dollar amount of leas caitalized per the USofA General Instructon 20; instead provide a reconciliation of the
dollar amount of leases capitlize wi th plant cot.
Une Description (See Instruction NO.1 for Explantion of Codes)Current Year to Date Previous Year to Date
No.QuarterN ear QuarterN ear
(a)(b)c)
1 Net Cah Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117)458,282,90 438,888,867
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion 43,811,133 431,935,488--iI5 59,141,93 64,755,712-
6
7 Unrealized (Gains)/Losses on Derivative Contracs 61,572 -1,661,541
8 Deferred Income Taxes (Net)311,719,127 45,331,714
9 Investment Tax Credit Adjustment (Net)-3,939,46 -7,920,120
10 Net (Increase) Décreae in Receivables 4,4oo,3n -74,00,726
11 Net (Increase) Decrease in Inventory -57,076,891 -36,421,476
12 Net (Increase) Decrea in Allowa Inveory
13 Net Increae (Derease) in Payables an Acru Exnses 7,685,33 47,887,94
14 Net (Increase) Decreae in Other Regulatory Asets -36,836,116 -18,00,439
15 Net Incree (Decrease) in Other Reulatory Uabilities -2,020 -27,468,274
16 (Less) Allowance for Othèr Funds Used During Construction 46,616,392 40,90,06
17 (Less) Undistributed Eamings from Subsidiary Compaies -1,905,65 1,716,150
18 Amounts Due To/From Affilates, Net -9,84,783 20,506,275
19 Derivative Contract AsetslUabilties, Net -81,90,00 400,00
20 -53,394,167 -14,n5,749
21
22 Net Cash Provided by (Used in) Operating Activiies (Total 2 thru 21)98,39,206 826,823,461
23
24 Cash Flows from Investment Activiies:
25 Construction and Acquisition of Plant (including land):
26 Gro Additions to Utilty Plant (les nuclear fuel)-1,80,989,623 -1 ,525,508,915
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utilit Plant
29 Gross Additions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construion -4,616,392 -4,90,06
31 Acquisitions, Net of Cash Acquire -307,682,572
32
33
34 Cash Outlows for Plant (Total of lines 26 thru 33)-2,067,055,803 -1,484,602,855
35
36 Acquisition of Other Noncurrent Aset (d)
37 Proees from Disposal of Noncurrent Assets (d)3,012,032 2,685,689
38
39 Investments in and Adans to As. and Subsidiar Companies -10,417,00 -22,349,22
40 Contributions and Advances from Assoc. an Subsidiar Compaies
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of Investment Secrities (a)-9,698
45 Proeds from Sales of Investment Securities (a)
FERC FORM NO.1 (ED. 12")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)
03131/200
Year/Period of Report
End of 2008/04
(1) Codes to be used:(a) Net Procees or Payments;(b)Bonds, debentures and other long-term debt; (c) Includ commercial par; and (d) Identify separately such itms as
investmen, fixed assets, intangibles, etc.
(2) Information abut noncah invesing and financing activities must be provided in the Notes to the Financial sttement. Also provi a recnciliation betwn .Cash an Cash
Equivalent at End of Perod' with related amounts on the Balance Sheet.
(3) Operating Activitie - Otr: Include gains and losses pertining to operating activities only. Gains and losss pertining to invsting an financing actvities ShOuld be reported
in those activities. ShOw in th Notes to the Financials the amounts of interest paid (net of amount capitalize) and income taes paid.
(4) Investing Actvities: Include at Other (line 31) net cah outlow to acquire othr companies. Provide a reconcilation of assts acuired wi liabilties asumed in the Notes to
th Financial Statements. Do nat includ on this statement the dollar amount of leases calize per th USofA General Instructon 20; instead prvide a reccilation of the
dollar amunt of les capitlize with th plant cost.
Une
No.
Description (See Instruction NO.1 for Explanation of Codes)
(a)
Current Year to Date
QuarterlY ear
b
Previous Year to Date
QuarterlYear
c
46 Loans Made or Purchased
47 Collections on Lons
48
49 Net (Increase) Derease in Receivables
50 Net (Increase) Decreae in Inventory
51 Net (Increase) Derease in Allowances Held for Speculation
52 Net Increase (Decree) in Payables and Accrued Expenses
53
54
55
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proeeds from Issuance of:
61 Long-Term Debt (b)
62 Preferr Stock
63 Common Stock
64 Equity Contribution
65 Reacquired Bonds
66 Net Increase in Short-Term Debt (c)
67
68
69
70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote):
77 Repyment of Capital Lease Obligations
78 Net Decrease in Short-Term Debt (c)
79 Reacquired Bonds
80 Dividends on Preferred Stock
81 Dividend on Common Stoc
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)
84
85 Net Increase (Decree) in Cash and Cash Equivalnts
86 (Total of lines 22,57 and 83)
87
88 Cash and Cash Equivalents at Beginning of Period
89
90 Cash and Cash Equivalents at End of period
4,988,593 13,017,394
792,126,293 1,193,405,452
450,00,00
216,470,00
84,991,027
200,00,00
3,502,924
1,54,587,320 1,396,908,376
-709,310 -1,254,709
-397,251,666
-216,470,00
-2,083,790 -2,08,790
19,66,248 192,832,698
FERC FORM NO. 1 (ED. 12-9)Page 121
YT YT FERC
121311200 121311200 Account
$ 40,332,443 $ 45,276,103 404
1,165,477 1,118,623 425
5,479,353 5,479,353 405
12,164,663 12,881,633 407/407.3
$ 59,141,936 $ 64,755,712
YT YT FERC
1213112008 121112007 Acct
$ 12,035,196 $ 15,163,499 151
(8,910,812)(6,808,915)151
(2,588,295)893,597 101/108
(2,125,011)(6,385,866)253
(42,626,647)(19,781,800)228
4,813,141 10,602,121 107
(7,488,00)186
(3,04,671)(5,632,346)228/253
(2,357,519)2,125,634 124/186
(1,101,549)(4,951,673)Varous
$(53,394,167)$(14,775,749)
YT YT FERC
12111200 121311007 Account
$ 3,344,372 $ 7,670,035 124/128
26,471 (78,766)185
1,617,750 5,426,125 128/134
$4,988,593 $ 13,017,394
YT YT FERC
1213112008 1213112007 Accunt
$$ 3,502,924 211
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ;K An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 200/04
FOOTNOTE DATA
¡Schedule Page: 120 Line No.: 5 Column: a
Amortzation of Software Development & Oter Intagibles
Amortation of LicensingIydr
Amrtzation of Electrc Plant Acquisition Adjustmnt
Amrtzation of Reguatory Assets
¡Schedule Page: 120 Line No.: 20 Column: a
Coal and Stear Depreciation & Depletion included in Cost of Fuel
PM! Equity Eargs included in Cost of Fuel
(Gai)/Loss on Sale of Prpert
Deferred Credits - Deferr Compnsation
Accumulate Provision for Pension & Benefits
Wnte-Qf of Assets Under Constrtion
BPA Prepaid Trasmission
Accumulate Provision for MiningÆnvinlom
Long-Term Notes Receivable
Other
¡Schedule Page: 120 Line No.: 53 Column: a
Oter InvestmntsSpeial Funds
Temprar Facilties
Restrcted Cash
f§chedule Page: 120 Line No.: 67 Column: a
Tax Benefit of Stock Options Exercised
I$chedule Page: 120 Line No.: 74 Column: c
Represents redemption of preferred stock subject to madatory reemption, which is classifed as Long-term debt on the Balance
Sheet. This represents all remaing outstading shaes ofPacifCorp's $7.48 No Par Senal Prferr Stok senes.
IFERC FORM NO.1 (ED. 12-S7) Page 45.1
............................................
Name of Respondent
PacifiCorp
Date of Report Year/Period of Report
End .of 2008/04
This Report Is:
(1) ~ An Original
(2) 0 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 liabilties existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involvng 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, Utilty Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. see General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 30 disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 30 disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
03/31/2009
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REOUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-9)Page 122
IFERC FORM NO.1 (ED. 12..S) Page 123.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) c An Original (Mo, Da, Yr)PacifiCorp (2) A Resubmission 03131/2009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
PACIFCORP AN SUBSIDIAES
NOTES TO FIANCIA STATEMENTS
(1) Organization and Operations
PacifiCorp, which includes PacifiCorp and its subsidiares, is a United States regulated electc company serving 1.7 millon reil
customers, including residential, commercial, industral and other customers in portons of the states of Uta Oregon, Wyomig,
Washingtn, Idao and Californa. PacifCorp owns, or ha interests in, a number of theral, hydroelectc, wind-powered and
geotherml generting facilties, as well as elecc trsmssion and distrbution assets. PacifiCorp also buys and sells electcity on
the wholesale market with public and private utlities, energy maretg companies and incorporated municipalities. PacifiCorp is
subjec to comprehensive state and feder reguation. PacifiCorp's subsidiares support its elecc utility opertions by providing
coal-mining services. PacifiCorp is an indir subsidiar of MidAercan Energy Holdings Company ("MEHC"), a holding
company based in Des Moines, Iowa, owning subsidiares that are pricipally engaged in energy businesses. MEHC is a consolidated
subsidiar of Berkshire Hathaway Inc. ("Berksh Hathaway").
(2) Summary of Significant Accounting PoUcies
Basis of Presentation
These fiancial sttements ar prepard in acrdace with the reuirments of the Feder Energy Regulatory Commssion (the
"FERC") as set fort in its applicable Uniform Syste of Accunts and published accounting releases, which is a comprehensive
basis of accounting other th acuntig principles generaly accepted in the United States of Amerca ("GAA"). These notes
include disclosures required by GAA adjus to the FERC basis of presentation, and include specific information reuested by the
FERC.
The following ar the signficant differences between the FERC reporting stadads and GAA:
Investment in Subsidiaries
PacifiCorp accounts for cerin investments in subsidiares using the equity metod rather than conslidang the assets,
liabilties, revenues and expenses of the subsidiares as required by GAA. GAA requires that majority-owned subsidiares and
varable-intest entities for which a company is the primar beneficiar be consolidated in accordance with Statement of
Financial Accounting Stadas ("SF AS") No. 94, Consolidaon of All Majority-Owned Subsidiaries, and revised Financial
Accounting Stadards 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 certin subsidiares using the equity
metod rather than the consolidation metod in acrdce with GAA has no effec on net income or retined earings.
Accumulated Removal Costs
The accumulated removal costs for PacifiCorp's reguate proper, plant and equipment that do not mee the defiition of an
asset retirement obligation ("ARO") under SFAS No. 143, Accounting for Asset Retirement Obligations, are classified as a
reguatory liabilty under GAA and as accumulated provision for depreiation under the FERC accounting and reportgstadar.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/31/2009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
Accumulated Deferred Income Taxes
Accumulated deferrd income taes are classified as curent and non-currnt for GAA, by presenting net curt asset and
liabilties separte from net non-curent assets and liabilties on the balance sheet in accordance with SF AS No. 109, Accounting
for Income Taxes. All such amounts are classified as gross non-curnt assets and grss non-curent liabilties under the FERC
accounting and reporting stadards.
Accumulated deferrd income taes are determined for GAA as the difference between the ta basis of an asset or liabilty as
determined in accordace with the recognition and measurment provisions of F ASB Interpretation No. 48, Accounting for
Uncertainty in Income Taxes-an interpretation ofFASB Statement No. /09 ("FIN 48"), and its reportd amount in the financial
stateents. All such amounts are determined for FERC as the difference beteen the ta basis of an asset or liabilty as reflecte
or expected to be reflectd in a ta ret and its reportd amount in the financial statements.
Interest and penalties on income taes for GAA are classified as income ta expense as perssible by FIN 48. All such
amounts are classified as interest income, interest expense and penlties under the FERC reportng stadads.
Unrealized Gains and Losses on Derivative Instrments
The FERC accounting and reporting stadads require that unealizd gais and losses on dervative instrents that ar not
probable of recovery in rates be classified gross in the statement of income in accordance with FERC Order 627, Accounting and
Reporting of Financial Instrments, Comprehensive Income, Derivatives and Hedging Activities. Unreaized gains and losses on
energ contrcts accounted for as derivatives are presented in the Statement of Income as miscellaneous nonoperating income for
unealized gains and as other deductons for unalized losses. For GAA, unealized gans and losses on energy derivatve
contract not held for trading puroses ar presented in the Statement of Income as revenues for saes contrs and as energy
costs and operating expense for purchas contrct.
Reclassifcations
Cerin other reclassifications of balance sheet, income statement and cash flow amounts have been made in order to conform to
the FERC basis of presentation. These reclassifications had no effec on net income.
Use of Estimates in Preparation of Financial Statements
The prepartion of financial statements in conformty with GAA requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilties at the date of the fiancial statements and the reported amounts of revenues and
expenses durng the period. These estimates include, but are not limited to: unbiled revenue; valuation of energy contrct; effect of
reguation; AROs, accounting for contingencies, including environmental, regulatory and income ta mattrs; and cerin
assumptions made in accounting for pension and other postretiement benefits. Actl results may differ frm the estimates used in
preparng the financial statements.
I FERC FORM NO.1 (ED. 12-88)Page 123.2
Cash (131)
Working fuds (135)
Temporar cash investments (136)
Total cash and cash equivalents
$ 16 $ 11
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/3112009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Cash Equivalents and Restricted Cash
Cash equivalents consist of fuds invested in money market accounts and in other investments with a matuty of thee months or
less when purhased. Cash and cash equivalents exclude amounts where availabilty is restrctd by legal requirments, loan
agreements or other contrctual provisions. Restrctd amounts are included in other special fuds and special depsits in the
Compartive Balance Shee. Cash and cash equivalents are as follows (in millons):
Years Ended Deember 31,2008 2007
4
$ 20
182
$ 193
Accountingfor the Effects of Certain Types of Regulation
PacifiCorp prepares its fiancial sttements in accordace with the provisions of SF AS No. 71, Accountingfor the Effects of Certain
Types of Regulation ("SF AS No. 71 "), which differ in certn respec frm the application of GAA by non-regulated businesses.
In general, SFAS No. 71 recognizs tht accountig for ratereguat enterprises should reflect the economic effects of regulation.
As a result, a regulated entity is reuired to defer the regnition of cost or income if it is probable that, though the ratemang
process, there wil be a corresponding incre or decree in fu ra. Accrdgly, PacifiCorp has deferr certin cost and
income that will be reognize in earngs over varous futu peods.
Management contiually evaluates the applicabilty of SF AS No. 71 and asesses wheter its reguatory asse are probable of fue
recovery by considering factors such as a change in the regulator's approach to setting rats from cost-basd ratemaking to another
form of regulation; other regulatry acions; or the impact of competition, which could limt PacifiCorp' s abilty to rever its costs.
Based upon this continual assessment, mangement believes the application of SFAS No. 71 continues to be appropriate and its
existig regulatory assets are probable of recovery. The assessment reflects the curent political and regulatory climate at both the
state and federal levels and is subjec to change in the futue. If it becomes no longer probable that these costs will be recovered, the
reguatory assets and regulatry liabilties would be wrttn off and recgnized in the stement of income.
Allowance for Doubtfl Accounts
The allowance for doubtfl accounts is bas on PaifiCorp's asssment of the collectibilty of payments from its customers. This
assessment requires judgment regarding the abilty of customers to pay the amounts owed to PacifiCorp or the outcome of any
pending disputes. The change in the balance of the allowance for doubtf accounts, which is included in accumulated provision for
uncollectible accounts is sumarzed as follows (in milions):
Years Ended December 31,2008 2007
Beginnng balance $7 $12
Charged to operation expenses, net 14 9
Write-offs, net (2)(14)
Ending balance $9 $7
I FERC r=ORM NO.1 (ED. 12-88)Page 123.3
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp I (2) A Resubmission 03/31/2009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
Derivatives
PacifCorp employs a number of different commodity derivative instrents, including forward contrac, options, swaps and other
agements, to manage its commodity price, for example natu gas and electcity volatilty. Derivative instrents are recorded in
the Compative Balance Sheet as either assets or liabilties and are stted at fair value unless they are designated as normal
purchass or normal sales and qualify for the exemption aforded by GAA. Derivative balances reflec reductions permtted under
master nettng argements with counterparies and cash collateral pad or received under such agreements. For those derivative
contract that are probable of recovery in rates, the unalized gains and losses are recorded as a net reguatory asset or liabilty
pursuatto SF AS No. 71.
Derivative contr for commodities used in norml business operations that are seted by physical delivery, among other crteria,
ar eligible for and may be designated as normal purchases or normal sales pursuant to the exemption. Contr that qualify and are
designate as norml purchases or norml sales ar not marked to market. Recognition of these contrct in operating revenues or
operation expenses in the Stament of Income occur when the contrct sette.
For contrct designated in hedge relationships ("hedge contrct"), PacifiCorp formally assesses, at inception and therafter,
whether the hede contract are highly effective in offsettg changes in cash flows or fai values of the hedged items. PacifiCorp
formally documents hedgig acivity by trsaction type and risk management strtegy.
Chanes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extt effective, are included in the
Statements of Accumulated Comprehensive Income, Comprehensive Income, and Hedging Activities as acumulate other
comprehensive income ("AOCI"), net of ta, until the hedged item is recognized in earings. PacifiCorp discontinues hedge
accounting prospectively when it has detrmned that a derivative no longer qualifies as an effective hedge, or when it is no longer
probable that the hedged forecaste trsaon will occur. When hedge accounting is discontinued because the derivative no longer
qualifies as an effectve hedge, futu changes in the value of the derivative are charged to earings. Gains and losses related to
discontiued hedges that were previously recorded in AOCI will remain in AOCI until the hedged ite is realized, uness it is
probable that the hedged forecasted trsaction wil not occur, at which time associate deferred amounts in AOCI ar immediately
recognized in eaings.
Inventories
Inventories consist mainly of materials and supplies, coal stocks, natual gas and fuel oil, which ar stated at the lower of averae
cost or market.
Propert, Plant and Equipment, Net
General
Prope, plant and equipment is recorded at historical cost. PacifiCorp capitalizes all constrction-related material, direct labor and
contract servces, as well as indi constrction costs, which include allowance for fuds used durng constrcton ("AFUDC").
The cost of major additions and betrments ar capitalized, while costs for replacements, mainteance and reai that do not
improve or extend the lives of the respective assets ar charged to operating expense.
Generally when PacifiCorp retires or sells its regulated propert, plant and equipment, it charges the original cost and any cost of
removal and salvage to accumulated provision for depreciation.
IFERC FORM NO.1 (ED. 12-88) Page 123.4
I FERC FORM NO.1 (ED. 12-88)Page 123.5
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)PaciCorp I (2) A Resubmission 03/3112009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
PacifiCorp records AFC, which represents the estimated costs of debt and equity fuds necessa to finance additions to
proper, plant and equipment. AFUDC is capitalize as a component of propert, plant and equipment, with offseting credits to the
Stateent of Income. Aftr constrction is completed, PacifiCorp is permittd to ear a retu on these costs by their inclusion in
rate base, as well as recover these costs though depreciation expense over the usefu life of the related assets.
The weighte-average agegate ras used for AFC were 8.2% and 8.3% for the year ended December 31,2008 and 2007,
respectively.
Asset Retirement Obligations
The far value of an ARO liabilty is reognze in the period in which it is incur, if a reasnable estiate of fair value can be
made, and is added to the caring amount of the associated asset, which is then depreciated over the remainig usefu life of the
asse. Subsequent to the initial recognition, the ARO liabilty is adjusted for any revisions to the expecd value of the retment
obligation (with corresponding adjustments to propert, plant and equipment) and for accrtion of the ARO liabilty due to the
passage of tie. The difference beteen the ARO liabilty, the corresponding ARO asset included in propert, plant and equipment
and amounts recovered in rates to satisfY such liabilties is reorded as a regulatry asset or liabilty. Estimated removal costs that
PacifiCorp recovers through approved depreiaton rate, but that do not meet the reuiements of a legal ARO, are accumulated in
accumulate provision for depreciation in the Compartive Balance Shee.
Depreciation and Amortation
Depreiation and amortization ar compute by the strght-line group metod either over the life prescrbed by PacifiCorp's varous
reguatory jurisdictions or over the assets' estimted useful lives. Periodic depreciation studies ar perormed to determine the
appropriate group lives, salvage and group depreciation rates. These studies ar reviewed and approved by PacifiCorp's varous
reguatory bodies.
Revenue Recognition
Revenue is recognized as electcity is delivered and includes amounts for serices redered. Revenue recognized includes unbiled
as well as biled, amounts. Unbiled revenues included in customer accounts receivable in the Compartive Balance Sheet were
$211 milion and $192 milion as of December 31, 2008 and 2007, respecvely. Rates charged are subject to federa and state
regulation.
The detrmination of sales to individual customer is based on the reading of the customer's meter, which is performed on a
systematic basis throughout the month. At the end of each month, amounts of energy provided to customer since the date of the last
metr reading are estimated, and the corresponding unbiled revenue is recorded. The estmate is reversed in the followig month
and actal revenue is recorded based on subsequent meter readings.
The monthly unbiled revenues of PacifiCorp are detined by the estimation of unbiled energy provided durng the period, the
assignent of unbiled energy provided to customer classes and the average rate per customer class. Facrs that ca impact the
estimate of unbiled energy provided include, but ar not limted to, seaonal weather patts, customer usage patt, historical
trnds, volumes, line losses, retail rate changes and composition of cutomer classes.
PacifiCorp records sales, frchise and excise taes, which ar collec dirly from customers and remitted directly to the taing
authorities, on a net basis in the Stateent of Income.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 0313112009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Income Taxes
As a result of the sale of PacifiCorp to MEHC on March 21, 2006, Berkshire Hathaway commenced including PacifiCorp in its
United States federl income ta ret. PacifiCorp's provision for income taes has been computd on the basis that it files separte
consolidatd income ta retus. Pror to the sale, PacifiCorp was included in the consolidated United States feder income ta
retu ofPacifiCorp Holdings, Inc., PacifiCorp's former parent company.
Defered ta assets and liabilties are based on differences between the financial statements and ta bases of assets and liabilties
using the estimated ta rates in effect for the year in which the differences are expectd to reverse. Changes in deferr income ta
assets and liabilties that are associated with components of AOCI are charged or credited directly to AOCI. Changes in deferred
income ta assets and liabilties that are associated with income ta benefits related to certin propert-related basis differences and
other varous differences that PacifCorp is required to pass on to its customer in most stte jursdictions ar charged or credited
directly to a regulatory asset or regulatory liabilty. These amounts were reognized as a net reguatory asset of $409 milion and
$423 milion as of December 31,2008 and 2007, respectively, and will be included in rates when the tempora differences reverse.
Oter chages in deferrd income ta assets and liabilties are included as a component of income ta expense.
Investment ta credits are generaly defered and amortze over the estimated usefu lives of the relate propertes or as prescrbe
by varous regulatory jursdictions.
In detrming PacifiCorp's income taes, management is required to interet complex ta laws and regulations. In preparng ta
retus, PacifiCorp is subject to continuous exainations by federl, state and local ta autorities that may give rise to different
interprettions of these complex laws and regulations. Due to the natu of the examnation process, it generly taes yea before
these examnations ar completed and these matters are resolved. The United Staes Internal Revenue Servce has close its
examation of PacifiCorp's income ta retus though the 2000 ta year. In most cases, state jursdictions have closed their
examations ofPacifiCorp's income ta rets though 1993. Although the ultimate resolution ofPacifiCorp's federal and state ta
examations is uncertin, PacifiCorp believes it has made adequate provisions for these ta positions and the agggate amount of
any additional ta liabilties tht may result from these examinations, if any, will not have a mateal adverse effec on PacifiCorp' s
financial results. Assets and liabilties are established for uncertin ta positions taen or positions expectd to be taen in income
ta retus when such positions are judged to not meet the "more-likely-than-not" thshold based on the tehnical merits of the
position. PacifiCorp's uncognzed ta benefits ar priarly included in miscellaneous curent and accrued asset, intest and
dividends receivable and inteest accrued in the Compartive Balance Sheet. PacifiCorp recognizes interest and penlties related to
income taes in interest income, interest expense and penalties in the Statement of Income.
Segment Information
PacifiCorp curently has one segment, which includes the regulated retil and wholesae electc utility opertions.
IFERC FORM NO.1 (ED. 12-88) Page 123.6
IFERC FORM NO.1 (ED. 12-88) Page 123.7
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PaciCorp I (2) A Resubmission 0313112009 2008/04
NOTES TO FINACIAL STATEMENTS (Continued)
New Accounting Pronouncements
In December 2008, the Financial Accounting Stadads Boad (the "FASB") issued F ASB Staff Position ("FSP") No. 132(R)-1,
Employers 'Disclosures about Postretirement Benefit Plan Assets ("FSP F AS 132(R)-1 "). FSP F AS 132(R)-1 is intended to improve
financial reporting about plan assets of defied benefit pension and other postretirement plans by requiring enhanced disclosures to
enable investors to betr understad how investment allocation decisions ar made and the major categories of plan asset. FSP F AS
132(R)-1 also requires disclosure of the inputs and valuation techniques used to measure fair value and the effect of fair value
measurements using signficat unobservable inputs on chages in plan assets. In addition, FSP FAS 132(R)-1 establishes disclosure
requirements for signficant concentrtions of risk within plan aset. FSP F AS 132(R)-1 is effectve for financial statements issued
for fisca years begining afer December 15, 2009, with ealy application permttd. PacifiCorp is curently evaluatig the impact of
adopting FSP F AS 132(R)- on its disclosures included withn Note to Financial Statements.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instrments and Hedging Activities-n amendment
of FASB Statement No. 133 ("SFAS No. 161"). SFAS No. 161 is intended to improve fiancial reportng about derivative
instrents and hedging activities by requirg enhanced disclosurs to enable investors to better undertad how and why an entity
uses derivative instrents and their effect on an entity's financial position, fiancial performance and cash flows. SFAS No. 161 is
effective for fiancial statements issued for fiscal yea and interim periods begiing afer November 15, 2008 with early
application encoured. PacifiCorp is curently evaluating the impact of adopting SF AS No. 161 on its disclosures included withn
Notes to Financial Statements.
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations ("SFAS No. 141(R)"). SFAS No. 141(R) applies to
all trsactions or other events in which an entity obta contrl of one or more businesses. SF AS No. 141 (R) estblishes how the
acquirer of a business should recognize, meaur and disclose in its fiancial statements the identifiable asset and goodwil
acquired, the liabilties assumed and any noncontrolling inte in the acquied business. SFAS No. 141(R) is applied prospetively
for all business combinations with an acquisition date on or afer the begiing of the fist anual reporting period beginning on or
after December 15, 2008, with early application prohibited. SFAS No. 141(R) will not have an impac on PacifCorp's historical
Financial Statements and will be applied to business combinations complete, ifany, on or aftr Januar 1,2009.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/31/2009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
In September 2006, FASB issued SFAS No. 157, Fair Value Measurements ("SFAS No. 157"). SFAS No. 157 defines fair value,
estblishes a frework 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 certn exceptions, to other
accountig pronouncements that either require or permt fair value measurments. Under SF AS No. 157, fair value refers to the price
that would be received to sell an asset or paid to trsfer a liabilty in an orderly transacion between market parcipants in the
pricipal or most advantageous maket. The stadard clarfies that fair value should be based on the assumptions market paricipants
would use when pricing the asset or liabilty. In Februar 2008, the FASB issued FSP No. 157-2, Effective Date of FASB Statement
No. 157, which delays the effective date of SF AS No. 157 for all non-financial assets and liabilties, except those that are recognized
or disclosed at fair value in the consolidated financial statements on a recurng basis, until fiscal year begining afr November 15,
2008. These non-financial items include assets and liabilties such as non-fiancial assets and liabilties assumed in a business
combination, reportng units measurd at fair value in a goodwil impairment test and AROs initially measured at fair value. In
October 2008, the FASB issued FSP No. 157-3, Determining the Fair Value of a Financial Asset When the Marketfor That Asset Is
Not Active ("FSP FAS 157-3"), which clarfies the application of SFAS No. 157 in a market that is not active and provides an
example to ilustrate key consideraions in determining the fair value of a fiancial asset when the market for that fiancial asset is
not active. FSP FAS 157-3 was effectve upon issuace, includig prior periods for which financial stateents had not been issued.
PacifiCorp adopted the provisions of SF AS No. 157 for assets and liabilties recognized at fair value on a recurg basis effecve
January 1, 2008. The parial adoption of SF AS No. 157 did not have a material impact on PacifiCorp's Financial Statements.
In September 2006, the FASB issued SFAS No. 158, Employers' Accountingfor Defined Benefit Pension and Other Postretirement
Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R) ("SFAS No. 158"). PacifiCorp adopte the recognition
provisions of SFAS No. 158 at December 31, 2006. SFAS 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 SFAS No. 87 and SFAS No. 106 to meaure up to
thee month pror to the financial statement date. PacifiCorp adopted the requirement to meaure plan asset and benefit obligations
as of the date ofits fiscal yea-end at December 31,2008. Upon adoption of the measurement date provisions, PacifiCorp recorded a
transitional adjustment of $14 millon, $12 milion of which is considered probable of recovery in rates and was recorded as a
regulatory asset. The remaining $2 millon (pre-ta) is not considered probable of recovery in raes and was recorded as a reducton
in retaned earings.
I FERC FORM NO.1 (ED. 12-8)Page 123.8
I FERC FORM NO.1 (ED. 12*88)Page 123.9
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PaciCorp (2) A Resubmission 03131/2009 2008104
NOTES TO FINACIAL STATEMENTS (Continued)
(3) Propert, Plant and Equipment, Net
Depreciable Lives
The average depreciable lives of prope, plant and equipment curtly in use by category are as follows:
Generation:
Steam plant
Hydroelectc plant
Wind plant
Oter plant
Transmission
Distribution
Intagible plant (1)
Oter
20-57 yea
24-80 yeas
25 year
15 -40 years
25 -75 year
44-52 year
5 -50 yea
5 -29 yea
(I) Computer soft cost inluded in intable plan ar intily asign a depreiable life of 5 to i 0 yea.
Utilty Plant Acquisition
On September 15, 2008, afer having received the requi regulatory approvals, PacifiCorp acquied from lNA Merchant Project,
Inc., an afliate of Suez Energy Nort Amenca, Inc., 100% of the equity interests of Chehais Power Generating, LLC, an entity
owning a 520-megawatt ("MW") natul ga-fired generting plant located in Chehalis, Washigtn. The total cash purchase pnce
was $308 milion and the estimate fa value of the acquired entity was pnmarly allocated to the plant. Chehalis Power
Generating, LLC was merged into PacifiCorp immedately following the acquisition. The results of the plant's operations have been
included in PacifiCorp's Financial Stateents since the acqsition date.
Unallocated Acquisition Adjustments
PacifiCorp has unallocated acquisition adjustments that rereent the excess of costs of the acquired interests in propert, plant and
equipment purchased from the entity that fi devote the assets to utility service over their net book value in those assets. These
unallocated acquisition adjustments included in utility plant ha an onginal cost of$I57 millon as of Decmber 31,2008 and 2007
and accumulated provision for depreciation, amortiztion and depletion of $91 milion and $85 milion as of December 31,2008 and
2007, respectively.
Depreciation Study
In August 2007, PacifiCorp filed applications with the regulatory commissions in Uta, Oregon, Wyoming, Washington and Idaho to
change its rates of depreiation prospectvely based on a new depreciation study. PacifiCorp received approval to change the
depreciation rates effective Januar 1, 2008. The Oregon Public Utility Commssion (the "OPUC") order requid additional
modifications relat to the depreciation lives of coal-fi generting facilties, which were approved in Augst 2008. The revised
deprciation rates generally reflect an extension of the lives of PacifiCorp's asset. The most significant change resulted in an
incrase in the rage of depciable lives for steam plant from 20 -43 yea to 20 - 57 year. The revised depreciation rates resulted
in a benefit to pre-ta income durg the yea ended Deembe 31, 2008 of approximtely $47 millon.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/31/2009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(4) Jointly Owned Utility Facilties
Under joint facilty ownership agreements with other utilties, PacifiCorp, as a tenant in common, ha undivided interts in jointly
owned generation and trsmission facilties. PacifiCorp accounts for its proportonal share of each facilty, and each joint owner has
provided fiancing for its share of each generating facilty or trsmission line. Operating costs of each facilty ar assigned to joint
owners based on ownership percentage or energy purchased, depending on the nature of the cost. Oprating costs and expenses in
the Statement of Income include PacifiCorp's share of the expenses of these facilties.
The amounts shown in the table below represent PacifiCorp's shar in each jointly owned failty as of December 31, 2008
(dollars in milions):
Facilty Accumulated Construction
PacifiCorp in Depreciation!Work in
Share Servce Amorttion Progress
Jim Bridger Nos. 1 - 4 (1)67%$996 $502 $29
Wyodak(l)80 333 177 4
Hunter No. 1 94 305 153 8
Colstrp Nos. 3 and 4 (1)10 244 127 2
Hunter No. 2 60 194 92 10
Hermiston (2)50 173 42
Crag Nos. i and 2 19 168 81
Hayden No. 1 25 45 22 i
Foote Creek 79 37 15
Hayden No. 2 13 28 15
Oter trsmission and distrbution facilties Varous 83 24
Total $ 2,606 $1,250 $55
(1)Includes trsmission lines and substtions.
(2)PacifCorp ha contrd to purhase the remaining 50"10 of the output of the Heristn plant.
I FERC FORM NO.1 (ED. 12-88)Page 123.10
I FERC FORM NO.1 (ED. 12-88)Page 123.11
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03/31/2009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
(5) Regulatory Matters
Regulatory Assets and Liabilties
Regulatory asset rereent cost that ar expec to be reoverd in futu ras. Reguatory liabilties represent inome to be
recognzed or amounts to be reed to cusmer in futu penods. PacifiCorp had reguatory asset not earing a retu on
investment of $1.5 bilion and $945 millon as of Deceber 31, 2008 and 2007, respectively.
Rate Matters
Oregon
In October 2007, PacifiCorp filed its ta rert for 2006 under Oregon Sente Bil408 ("SB 408"), which was enacted in
September 2005. SB 408 requirs that PacifiCorp and other lare reguate investor-owned utilties that provide elecc or natul
gas service to Orgon customers file a rert anually with the OPUC coparg income taes collecd and income taes paid, as
defied by the statute and its adistrive rules. PacifiCorp's fiing indicated that for the 2006 ta year, PacifiCorp paid
$33 milion more in federal, state and local taes than was collec in rates frm its retail customers. PacifiCorp proposed to recover
$27 milion of the deficiency over a one-year perod stag June 1,2008 and to defer any excess into a balancing account for futue
disposition. During the review process, PacifiCorp updte its filing to address the OPUC's starecommendations, which increased
the initial request by $2 millon for a total of $35 milion. In Apnl2oo8, the OPUC approved PacifiCor's revised request with
$27 millon to be recovered over a one-year penod beginng June 1,2008 and the remainder to be defered until a later perod, with
interest to accre at PacifiCorp's authonzed rate of retu. In June 2008, PacifiCorp recorded a $27 milion regulatory asset and
associated revenues representing the amount that PacifiCorp wil collect from its Orgon retil customers over the one-year perod
that began on June 1,2008.
In May 2008, the Industral Customer of Nortwest Utilities ("ICNU") filed a peition with the Cour of Appes of the Stae of
Oregon seekig judicial review of the final order with regar to PacifiCorp's 2006 SB 408 ta report. In December 2008, ICN
filed their opening bnef. In March 2009, a notice of withdrwal of the SB 408 order in judicial review was issued by OPUC. The
notice states that the purose is to reconsider the order in light of the contentions raised on appeal. In the notice, the OPUC proposes
to afrm, modify, or revers the order by May 25,2009. The notice suspeds the proceedings before the Cour of Appeals until the
OPUC issues an order or until the time for issuing an order expirs on May 25, 2009. The order has not been stayed and remains in
lawfl effect. PacifiCorp believes the outcome of these proceeings wil not have a matenal impact on its financial results.
In Octber 2008, PacifiCorp filed its ta report for 2007 under SB 408. PacifiCorp's fiing indicate that for the 2007 ta yea,
PacifiCorp paid $4 milion more in federa, state and local taes than was collected in rates from its retl customers.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) oAn Original (Mo, Da, Yr)
PaciCorp I (2) A Resubmission 03/31/2009 2008104
NOTES TO FINANCIAL STATEMENTS (Continue)
(6) Fair Value Measurements
The caring amounts ofPacifiCorp's cash and cash equivalents, receivables, payables, accred liabilties and short-term borrowings
approximate fai value because of the short-term matuty of these instrents. PacifiCorp has varous fiancial instrents that are
measured at fair value in the Financial Statements, including commodity derivatives. PacifiCorp's fiancial asset and liabilties ar
measured using inputs from the thee levels of the fair value hierchy. A financial asset or liabilty classification withn the
hierachy is determined based on the lowest level input that is signficant to the fair value measurement. The thee levels ar as
follows:
. Level i - Inputs are unadjusted quoted prices in active market for identical assets or liabilties that PacifiCorp has the abilty to
access at the measurement date.
· Level 2 - Inputs include quoted prices for similar asset and liabilties in actve market, quoted prices for identical or similar
assets or liabilties in markets that are not acive, inputs other th quoted prices that ar observable for the asset or liabilty and
inputs that are derived pricipally from or corroborated by observable market data by corrlation or other means (market
corroborated inputs).
. Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market parcipants would use in pricing
the asset or liabilty since limited market dat exists. PacifiCorp develops these inputs based on the best information available,
including PacifiCorp's own data.
The followig table presents PacifiCorp's assets and liabilties recognized in the Comparative Balance Sheet and measured at fai
value on a recurrng basis as of Decmber 31, 2008 (in milions):
Input Levels for Fair Value Measurements
Description Levell Level 2 Level 3 Other (1)Total
Assets:
Commodity derivatives 1.Li $88 $(02)~
Liabilties:
Commodity derivatives $$ (485)$(496)$361 ~
(1) Prmarly represnts netting under ma nettng arements an ca collate requien.
PacifiCorp uses various derivative instrents, including forward contr, options, swaps and other agrements. The fair value of
derivative instrments is determined using unadjusted quoted prices for identical instrents on the applicable exchage in which
PacifiCorp trsacts. When quoted prices for identical instents are not available, PacifiCorp uses forward price curs derived
from market price quotations, when available, or interlly developed and commercial models, with inteal and external
fudaental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direc communcaion
with market paricipants and actl transactions executed by PacifiCorp. Maret price quotations for cern major electcity and
natul gas tring hubs are generally readily obtainable for the first six yea, and therefore, PacifiCorp's forward price cures for
those locations and periods reflect observable market quotes. Market price quotations for other electcity and natul gas trng
hubs are not as readily obtainable for the six years or if the instrent is not actively trded. Given that limited market data exists for
these instrents, PacifiCorp uses forward price cures derived from inteal models based on peeived pricing relationships to
major tring hubs that are bas on signficant unobservable inputs.
I FERC FORM NO.1 (ED. 12..S)Page 123.12
2008 2007
Carrng Fair Carrng Fair
Amount Value Amount Value
Long-tenn debt $ 5,503 $ 5,769 $5,117 $5,350
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PaciCorp (2)A Resubmission 03131/2009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Contrcts with explicit or embedded optionality are valued by separating each contract into its physical and financial forward, swap
and option components. Forward and swap components ar valued agaist the appropriate forward price cure, Options components
are valued using Black-Scholes-tye option models, such as European option, Asian option, spread option and best-of option, with
the appropriate forward price cure and other inputs.
The following table reconciles the beging and ending balance of PacifiCorp's asset and liabilties measured at fair value on a
recurng basis using significant Level 3 inputs (in millons):
Commodity
Derivatives
Balance, January 1,2008
Unrealize gais (losses) included in reguatory asset
Puchases, sales, issuaces and setements
Net transfers into Level 3
Balance, December 31, 2008
$ (311)
(103)
(7)
13
$ (408)
PacifiCorp's long-tenn debt and curent matties of long-te debt ar caed at cost in the Financial Statements. The fai value of
PacifiCorp's long-tenn debt has ben estite baed on quote market prices. The caring amount of varable-rate long-tenn debt
approximtes fair value because of the fruent reprièing of these instents at maket rates. The following table presents the
carring amount and estimated fai value ofPacifiCorp's fied-rate and varable-rate long-tenn debt, including the curent portion as
of December 31 (in millons):
(7) Risk Management and Hedging Activities
PacifiCorp is exposed to the impact of market fluctons in commodity prces, pricipally natu gas and eleccity, Inteest rate
risk exists on varable-rate debt, commerial pape and fue debt issuaces. PacifiCorp employs estblished policies and procedures
to maage its risks associated with these market flucttions using varous commodity instrments, includig forward contr,
options, swaps and other ageements. The risk management process established by PacifiCorp is designed to identitY, assess,
monitor, report mange and mitigate each of the varous types of risk involved in its business. PacifiCorp's portfolio of energy
derivatives is substatially used for non-tradng puroses. As of December 31, 2008 and 2007, PacifiCorp had no financial
derivatives in effect relating to interest rate exposur.
I FERC FORM NO.1 (ED. 12-88)Page 123.13
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/31/2009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table sumarzes the varous derivative mark-to-market positions included in the Comparative Balance Sheet as of
December 31, 2008 (in milions):
Net Regulatory
Net DerivativeAssets (Liabilties)(I~Assets
Assets Liabilties Total (Liabilties)
Commodity $260 $(620)$(360)$442
Curent $174 $(130)$44
Non-curent 86 (490)(404)
Tota $260 $(620)$(360)
(1) Net derivative asse (liabilities) include $82 milion of a net asse for ca collatera.
The following table sumarzes the varous derivative mark-to-market positions included in the Comparative Balance Sheet as of
December 31,2007 (in milions):
Net
Regulatory
Net Derivative Assets (Liabilties)Assets
Assets Liabilties Total (Liabilties)
Commodity $357 $(614)$(257)$257
Foreign curncy 1 1 (1)
$358 $(6)4)$(256)$256
Curent $143 $(117)$26
Non-curnt 215 (497)(282)
Tota $358 $(614)$(256)
The following table sumzes the amount of the pre-ta unealizd gais and losses included within the Statement of Income
associated with changes in the fair value ofPacifiCorp's derivative contr that are not included in rates (in milions):
Years Ended Deember 31,
2008 2007
Oter income:
Miscellaneous nonoperating income (421)
Oter income deductions:
Oter deductons (426.5)
Tota unalized gain (loss) on derivatve contrct
$ (143)$ (163)
143 161$ (2)$
IFERC FORM NO.1 (ED. 12-88) Pag 123.14
IFERC FORM NO.1 (ED. 12-88) Page 123.15
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03/3112009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
Realized and unealized gains and losses on derivative contrct held for trading purpses are presented on a net basis in the
Statement of Income as miscellaneous nonoperating income. Unrealiz gains and losses on electrcity and natul gas derivative
contracts not held for trading puroses are presented in the Statement of Income as miscellaneous nonoperting income for
unealized gains and other deductons for unealized losses. Realized gais and losses on physically seted derivative contrcts not
held for trading puroses are presented in the Statement of Income as operating revenues for sales contrts and as opeation
expenses for purchase contract. Reaize gains and losses on non-physically seted forwar purhase and sale derivative contrct
not held for trding puroses ar presented on a grss basis in the Stateent of Income as operting revenues for gains and operation
expenses for losses. Realizd gai and losses on fiancial swap energy contr ar presente in the Statement of Income as
operation expenses.
Cash Collateral
Amounts reognized for cash collateral received frm other that was offset against net derivative assets totaled $78 milion as of
December 31, 2008 compared to $ i 60 millon of cah collatera provided to others that was offset agaist net derivative liabilties as
of December 31, 2008. The amoun of cah collat recived or provided var priarly based on changes in fair value of the
related positions.
(8) Short-Term Borrowings
Short-Term Debt
As of December 3 I, 2008, PacifiCorp ha outstading short-te debt borrwings of $85 milion consisting of commercial paper at
an average interest rate of I .0%. As of Decembe 31, 2007, PacifiCorp had no outstading short-term debt borrowings.
Revolving Credit Agreements
As of December 3 I, 2008, PacifiCorp had $1.5 bilion of tot ban commtments under two unecurd revolving credit facilties.
However, PacifiCorp's effective liquidity under thes failties was reduced by $105 milion to $1.4 bilion due to the Lehman
Brothers Holdings Inc. ("Lehman") banptcy filing in September 2008. Lehman fied for proteion under Chapter 1 i of the
Federal Banptcy Code in the Unite States Banpt Cour in the Southern Distrct of New York. Lehman Brother Ban, FSB
and Lehman Commercial Paper, Inc., both subsidiares of Lehm, have commtments totaling $105 millon in PacifiCorp's
$1.5 bilion unsecured revolving crt facilties. The reucton in available capacity under the crdit failties as a result of the
Lehman banptcy did not have a marial adver impact on PacifiCorp.
Adjusting for the Lehman banptc, the first credit facilty has $760 millon of total ban commitments though July 6, 2011. The
commtments reduce over time to $630 milion of remaining availabilty for the yea ending July 6, 2013. Adjusting for the Lehman
banptc, the second credit facilty has $635 milion of tota ban commtments though October 23, 2012. Each credit facilty
includes a varable interest rate borrowing option bas on the London Interban Offered Rate, plus a margin that is curently
0.155% and vares based on PacifiCorp's credit ratigs for its senior unsecured long-term debt securties. These credit facilties
support PacifiCorp's commercial paper progr unenhanced varable-rate ta-exempt bond obligations and other short-term
borrowing needs.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PaciCorp I (2) A Resubmission 03/3112009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Còntinued)
As of December 31, 2008, PacifiCorp had no borrowings outstading under either credit facilty but had letrs of cret under both
credit agreements totaling $220 milion to support varable-rate ta-exempt bond obligations. In addition, the credit facilties
supportd $85 millon of commercial paper borrowings and $38 millon of unenhanced varable-rate ta-exempt bond obligations
outstading as of December 31, 2008. The remaining $ 1.1 bilion of effective liquidity under the unecured revolving credit facilties
was available as of December 31,2008.
As of December 31,2007, PacifiCorp had no borrowings outstading under either credit facilty.
PacifiCorp's revolving credit and other financing agrements contain customar covenants and default provisions, including a
covenant not to excee a specified debt-to-capitaization ratio of 0.65 to 1.0. As of Decber 31, 2008, PacifiCorp was in
compliance with the covenants of its revolving credit and other finacing agrements.
IFERC FORM NO.1 (ED. 12-88) Page 123.16
(9)Long-Term Debt and Capital Lease Obligations
PacifiCorp's long-term debt and capital lease obligations were as follows as of December 31 (in millons):
2008 2007
Average Average
Par Interest Interest
Value Amount Rate Amount Rate
Long-ter debt:
First mortgage bonds:
4.3% to 9.2%, due though 2013 $977 $976 6.9%$1,389 6.5%
5.0% to 8.7%, due 2014 to 2018 721 720 5.5 221 5.3
6.7% to 8.5%, due 2021 to 2023 324 324 7.7 324 7.7
6.7% due 2026 100 100 6.7 100 6.7
7.7% due 2031 300 299 7.7 299 7.7
5.3% to 6.4%, due 2034 to 2038 2,350 2,345 6.0 2,046 5.9
Tax-exempt bond obligations:
Varable rates, due 2013(1)(2)41 41 0.8 41 3.8
Varable rates, due 2014 to 2025(2)325 325 1.325 3.5
Varable rates, due 2024(1 )(2)176 176 0.9 176 3.8
3.4% to 5.7%, due 2014 to 2025(1)184 184 4.5 183 4.5
6.2% due 2030 --13 6.2 13 6.2
Tota long-term debt $ 5.5II $5.503 $5 II7
Capital lease obligations:
8.8% to 14.8%, due though 2036 65 65 11.6 49 11.3
Less curnt matuties (6)(6)(I)
Non curnt capita leae obligations $59 $59 $48
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacilCorp (2)A Resubmission 03/31/2009 2008104
NOTES TO FINACIAL STATEMENTS (Continued)
(I) Secured by pledged fi morte bos generly at the sae inst ra, matty date and reempton provisions as
the ta-exempt bond obligaons.
(2) Interet rates fluctte ba on vaous ras, prly on cefica of deit ra, in borrwi ras, prie
rate or other sh-ter maret ras.
Firt mortage bonds of PacifiCorp may be issued in amounts limite by PacifiCorp's propert, eaings and other provisions of
PacifiCorp's mortage. Approximately $17.8 billon of the eligible assets (basd on original cost) ofPacifiCorp were subjec to the
lien of the mortage as of December 31, 2008.
In Janua 2009, PacifiCorp issued $350 millon of its 5.50% First Mortgage Bonds due Januar 15, 2019 an $650 milion of its
6.00% First Mortgage Bonds due Janua 15,2039.
I FERC FORM NO.1 (ED. 12-88)Page 123.17
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 03/31/2009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
In September 2008, PacifiCorp acquird $216 milion of its insured varable-rate ta-exempt bond obligations due to the significant
reduction in market liquidity for insured varable-rate obligations. In November 2008, the associated insurce and related stadby
bond purchase agreements were terminated and these varable-rate long-term debt obligations were rearketed with credit
enhancement and liquidity support provided by $220 milion of lettrs of credit issued under PacifiCorp's two unsecured revolving
credit facilties.
In Januar 2008, PacifiCorp received regulatory authonty from the OPUC and the Idaho Public Utilties Commission to issue up to
an additional $2.0 bilion of long-term debt. PacifiCorp must make a notice filing with the Washington Utilties and Tranporttion
Commssion pnor to any futue issuance. Also in Januar 2008, PacifiCorp fied a shelf registation statement with the United States
Secunties and Exchange Commission covenng futu first mortage bond issuaces. PacifiCorp's long-ter debt issuances in
Januar 2009 and dung the year ended December 31,2008 were coverd under the above-noted regulatory authonties and shelf
registration statement.
As of Deember 31, 2008, $4.3 bilion of firs mortgage bonds were redeemable at PacifiCorp's option at redemption pnces
dependent upon United States Treury yields. As of December 31,2008, $542 milion of varable-rate ta-exempt bond obligations
and $84 milion of fied-rate ta-exempt bond obligations were redeemable at PacifiCorp's option at par. The remaining long-term
debt was not redeemable as of Deember 31,2008.
As of December 31, 2008, PacifiCorp had $517 milion of lettrs of credt available to provide credit enhancement and liquidity
support for varable-rate ta-exempt bond obligations totaling $504 millon plus intest. These committed bank argements were
fully available at December 31, 2008 and expire penodically though May 2012.
In addition, as of December 31, 2008, PacifiCorp had approximately $18 millon of lettrs of creit available to provide crdit
support for cerin trsacions as requested by third pares. These commtt ban arangements were all fully available as of
December 31, 2008 and have provisions that automatically extend the anual expiration dates for an additional yea unless the
issuig ban elect not to renew a letr of credit prior to the expirtion date.
PacifiCorp's lettrs of credit generally contan similar covenats and default provisions to those contained in PacifiCorp's revolvig
credit ageement, including a covenant not to exceed a specified debt-to-capitalization ratio of 0.65 to 1.0. PacifiCorp monitors these
covenants on a regular basis in order to ensure that events of default wil not occur and as of Deceber 31, 2008, PacifiCorp was in
compliance with these covenants.
PacifiCorp has entered into long-term agreement that expire at varous dates though Octber 2036 for trsporttion services,
purchase power agreements, real estte and for the use of certin equipment that qualitY as capital leases. The trporttion serices
agreements included as capital leaes are for the nght to use pipeline facilties to provide natual gas to thee of PacifiCorp's
generating facilties. Net assets accounted for as capital leaes of $65 milion and $49 milion as of Deember 31,2008 and 2007,
respectively, wer included in net utilty plant in the Comparative Balance Sheet.
I FERC FORM NO.1 (ED. 12-88)Page 123.18
Total
$152
23
595
25
273
4,599
5,667
(91)
$5.576
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03/3112009 2008104
NOTES TO FINACIAL STATEMENTS (Continued)
The anual maturities of long-term debt and capital lease obligations for the year beginning Januar 1, 2009 and therer,
excluding unamortzed discounts, are as follows (in millons):
Long-term
Debt
Capital Lease
Obligations (1)
2009
2010
2011
2012
2013
Thereafr
Total
Amounts representing inteest (2)
Total
$13
9
8
8
12
106
156
(91)
65
$139
14
587
17
261
4,493
5,511
$5.511 $
(1) Excluded frm these amounts ar approximtely $4 milion of capita lea executry cost, including taes mateance
an ins.
(2) Inteest expns on caita lea obligaons is rerd as re expns.
(10) Asset Retirement Obligations
PacifiCorp estiates its ARO liabilties baed upon detled engieeng caculatons of the amount and timing of the futu cash
spending for a thrd par to perorm the requied work. Speding estte ar escalated for inflation and then discounted at a
credit-adjusted, risk-free rate. Changes in estimtes could ocur for a number of reasons, including plan revisions, ination and
changes in the amount and timing of the expect work.
PacifiCorp doe not recognze liabilties for AROs for which the fair value canot be renably estimted. Due to the indetermnate
removal date, the fair value of the associated liabilties on certin transmission, distrbution and other assets canot curently be
estimated and no amounts are recognized in the Financial Statements other than those included in the regulatory removal cost
liabilty established via approved depreciation rates.
The change in the balance of the tota ARO liabilty is sumze as follows as of Decembe 31 (in millons):
2008 2007
Balance, Januar 1 $75 $86
Additions 2 1
Retements (4)(6)
Change in estimated costs (1)4 (11)Accrion (2)4 5
Balance, Deember 31 $81 $75
(1) Resuts frm chages in the tiin and amun of es ca flows for cert plant an mine relamon.
(2) PaifiCorp recods the acon expns of as retient obligans as either a regury as or (liability).
I FERC FORM NO, 1 (ED. 12-88)Page 123.19
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifCorp I (2) A Resubmission 03/31/2009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
Certin of PacifiCorp's decommissioning and reclamation obligations relate to jointly owned facilties and mine sites. For
decommissioning, PacifiCorp is commttd to pay a proportionate share of the decommssioning costs based upon its ownership
percentage, or in the case of mine reclamation obligations, PacifiCorp has commttd to pay a proportonate share of mine
reclamation costs based on the amount of coal purchased by PacifiCorp. In the event of default by any of the other joint paricipants,
PacifiCorp potentially may be obligated to absorb, direcly or by paying additional sums to the entity, a proportionate share of the
defaulting par's liabilty. PacifiCorp's estimated share of the decommssioning and reclamation obligations ar priarly recorded
as ARO liabilties.
(11) Employee Benefit Plans
PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees and also provides cern postrrement
health car and life insurance benefits through various plans for eligible retirees. In addition, PacifiCorp sponsors a defined
contrbution 401(k) employee savings plan (the "401(k) Plan"). Non-union employees hired on or aftr Januar 1, 2008 and certin
union new hirs ar not eligible to parcipate in the PacifiCorp Retrement Plan (the "Retirement Plan"). These employees are
eligible to receive enhanced benefits under the 401(k) Plan.
Pension and Other Postretirement Benefit Plans
PacifiCorp's pension plans include a non-contrbutory defined benefit pension plan, the Retirement Plan; the Supplementa
Executive Retirement Plan (the "SERP"); and certin joint trst union plans to which PacifiCorp contrbutes on behalf of cert
bargaining units. Benefits for cern union employees covered under the Retement Plan ar basd on the employee's yea of
service and average monthly pay in the 60 consecutive months of highest payout of the last 120 months, with adjustments to reflec
benefits estimated to be received from social securty. At December 31, 2008, all non-union Retirement Plan paricipants, as well as
cerin unon paricipants, ear benefits basd on a cash balance formula. Refer to the discussion of curlments below.
The cost of other postretrement benefits, including health care and life insurance benefits for eligible retirees, is accred over the
active service period of employees. PacifiCorp fuds these other postretirement benefits though a combination of fuding vehicles.
PacifiCorp also contrbutes to joint trst union plan for postretirement benefits offered to certin bargaining units.
IFERC FORM NO.1 (ED. 12-88) Page 123.20
IFERC FORM NO.1 (ED. 12-88) Page 123.21
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 0313112009 2008/Q4
NOTES TO FINACIAL STATEMENTS (Continue)
Measurement Date Change
PacifiCorp adopted the measurement date provisions of SFAS No. 158 at December 31, 2008, which requires that an employer
measur plan assets and benefit obligations at the end of the employer's fiscal year. Effectve Decembe 31, 2008, PacifiCorp
changed its measurement date from September 30 to December 31 and recorded a $14 millon trsitional adjustment. The
components of the measurement dat change tritional adjustment were as follows on a pre-ta basis (in millons):
Pension Oter Postrrement Total
Serce cost $7 $2 $9
Interest cost 16 8 24
Ex re on plan asse (18)(7)(25)
Net amorttion 2 4 6
Tota $7 $7 $J4
The $14 millon transitional adjustment includes $12 millon rerded as an increase in regulatory asses for the porton considered
probable of recovery in rates and $2 millon rerded as a reduction ($1 millon after-ta) in retned eaings for the porton not
considere probable of recover in rates. The $12 milion increase to reguatory assets wil be amortzed over the to 10 yea based
on agements with varous state reguatory commssions. The recogntion of service cost, interest cost and expecd retur on plan
assets, totaling $8 milion, resulted in an incr in peion and other postetirement liabilties. The $6 millon net amortation
represents recognition of prior serce cost, net trition obligaon and actaral net loss and resulted in a reducton in regulatory
asse.
Curtailments
In Augut 2008, non-unon employee parcipants in the Reirent Plan wer offered the option to continue to recive pay credits in
their curent cash balance formula of the Rement Plan or reeive equivalent fied contrbutions to the 401(k) Plan. The elecion
was effective Janua 1,2009, and resulted in the recgnition of a $38 milion curlment gain. PacifiCorp recrded $36 millon of
the curlment gain as a reduction to regulatory assets as of December 31, 2008, representig the amount to be reed to customers
in rates. The reduction to the regulatory asset wil be amortized over a period of the to 10 year based on agreements with varous
state regulatory commissions.
Effective December 31,2007, Local Union No. 659 of the Inteatonal Brotherood of Eleccal Workers ("Local 659") electd to
cease parcipation in the Retrement Plan and pacipate only in the 401(k) Plan with enhanced benefits. As a result of this elecion,
the Local 659 paricipants' Retireent Plan benefits wer froze as of Deber 31, 2007. This change resulte in a $2 milion
curilment gain that was recorded as a reducton to regulatory asse as of December 31,2008 based on the requirment to re the
amount to customers in rates. It will be amorted over a perod of th to 10 year bas on ageements with varous state
regulatory commissions. Also as a result of ths change, PacifiCorp's pension liabilty and regulatory assets each decreased by
$13 milion.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2) . A Resubmission 03/31/2009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
Change in Benefit Formula
Effective June I, 2007, PacifiCorp switched from a traditional fial-average-pay formula for the Retirement Plan to a cah baance
formula for its non-union employees. As a result of the chage, benefits under the traditional final-average-pay formula were frozen
as of May 31, 2007 for non-union employees, and PacifiCorp's pension liabilty and regulatory assets each decreased by
$ ii 1 millon.
Net Periodic Benefit Cost
For puroses of calculating the expected re on plan asset, a market-relate value is used. The market*related value of plan assets
is calculated by spreading the difference between expected and actal investment returns over a five-year peod begining af the
first year in which they occur. In addition, as differences beeen expected and actal investment retus ar adttd into the
market-related value of plan assets, the corresponding gains or losses are then amortzed and included in the net amortzation
component of net periodic benefit cost.
Net peodic benefit cost for the pension and other postretireent benefit plans included the following components (in millons):
Pension Oter Postretiement
Years Ended December 31,Years Ended December 31,
2008 (2)2007 200 (2)2007
Servce cost (i)$27 $29 $7 $7
Inre cost 67 71 33 33
Expectd retu on plan assets (72)(68)(28)(26)
Net amorttion 7 23 IS 19
Cost of teination benefits 1
Curilment loss (gain)(2)
Net peodic benefit cost $27 $56 $27 $33
(1) Service cost excludes $1 I milion and $10 milion of contrbutons to th joint trt union plan durng the yea ended
December 31. 2008 and 2007, repeively.
(2) Excludes impac of the meaurement date chage and the portion of the curilment gans requird to be reed to custmer
in raes. Refer to "Measurement Date Chae" and "Curlments" above.
I FERC FORM NO.1 (ED. 12-88)Page 123.22
Penson Other Postrtirement
Years Ended Deember 31,Years Ended December 31,
2008 2007 2_2007
Plan asse at fair value, beging of yea $%3 $884 $378 $318
Employer contrbutions 70 80 42 46
Parcipant contrbutions 14 11
Act ret on plan as (224)118 (103)46
Benefits pad (l7)(l9)(47)(43)
Plan as at fai value, end of yea $622 $963 $284 $378
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) õAn Original (Mo, Da, Yr)
PacifCorp · (2) A Resubmission 03/31/2009 2008104
NOTES TO FINANCIAL STATEMENTS (Contnued)
Funded Status
The following table is a rencilation of the fai value of plan assets as of the end of the yea (in millons):
The followig table is a reconcilation of the benefit obligations as of the end of the year (in milions):
Pension Oter Postretirement
Years Ended December 31,Years Ended December 31,
2_2007 2_200
Benefit obligation, begig of yea $I,m $1,333 $536 $566
Service cost (I)34 29 9 7
Intest cost (1 )83 71 41 33
Parcipat contbutions 14 11
Plan amendments (7)(130)(12)
Curilment (13)Actal ga (21)(74)(56)(40)
Benefits paid, ne of Medica subsidy (11)(119)(43)(41)
Cost oftemiination benefits 1
Benefit obligaion, end of yea $1079 $! ! J!$489 $536
Accumulate benefit obligaion, end of yea $1948 $! 961
(1) Included in the pension an othr posttime liabilities in in connecon wi th meurment dat chage in 2008
was additiona sece cost of $7 million and $2 milion and adtion interest co of $16 milion and $8 milion for th
penion and other postment benefit plan, repevely.
IFERC FORM NO.1 (ED. 12-88)Page 123.23
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 0313112009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
The fuded statu of the plans and the amounts recognized in the Comparative Balance Sheet are as follows as of Deember 3 I
(in millons):
Pension
2008 2007
Plan assets at fa value, end of yea $692 $963
Less - Benefit obligation, end of yea 1.070 1 111
Funded sttus (378)(148)Contrbutions af the measent date
but before yea-end
Amoun recognizd in the Compave
Balance Shee $'38)$(48)
Amoun regnd in the Compative
Baance Shee:
Oter cunt liabilities $(4)$(4)Oter long-te liabilities '34)(144)
Amounts regnize $'38)$(J48)
Other Postrtirement2008 2007
$ 378
536
(158)
12
$ (146)
$
(46)
$ (46)
The SERP has no plan asset; however, PacifiCorp has a Rabbi tnst that holds corporate-owned life insurce and other investments
to provide fuding for the fuure cash requirements of the SERP. The cash surender value of all of the policies included in the Rabbi
trst, net of amounts borrowed against the cash surender value, plus the fair market value of other Rabbi tnst investments, was
$38 millon and $40 millon as of December 31,2008 and 2007, respectvely. These asset ar not included in the plan asse in the
above table, but ar reflected in the Compartive Balance Sheet. The porton of the pension plans' projected benefit obligation
related to the SERP was $50 milion and $52 milion as of December 31,2008 and 2007, respectively. The SERP's accumulated
benefit obligation totaled $50 milion and $52 milion as of December 31,2008 and 2007, respectively.
Unrecognized Amounts
The porton of the fuded statu of the plans not yet recognized in net penodic benefit cost is as follows as of Dembe 31 (in
milions):
Pension2008 207 Other Postirement200 2007
Amounts not yet reognized as components
of ne peodic benefi cost:
Net loss
Pror sece cot (credit)
Net trition obligaton
Regatory deferrs (1 )Tot
$508
(68)
$250
(115)
3
$$45
17
60
138
128
1
45
6
180 $122$
(3)
408 $$
(1) Consists of amounts relate to the porton of the curment gans an the meaement da chage tritional adjustment
tht ar considere probale of inclusion in rates.
IFERC FORM NO.1 (ED. 12-88l Page 123.24
IFERC FORM NO.1 (ED. 12-88) Page 123.25
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
A reconcilation of the amounts not yet recognzed as components of net penodic benefit cost for the years ended December 31,
2008 and 2007 is as follows (in millons):
The net loss, pnor service credit, net transition obligation and regulatory defers that wil be amortized in 2009 into net perodic
benefit cost ar estated to be as follows (in millons):
Net Pror Sece Net Tnnsitin Reglatory
Loss Creit Obliation Deferrals Tot
Pension benefits $18 $(8)$$(8)$2
Oter posttient benefits -12 --13
Tota $18 L.$12 L.$15
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03/31/2009 20081Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Plan Assumptions
Assumptions used to determine benefit obligations and net benefit cost were as follows:
Pension
Years Ended December 31.2008 207
Oter Postretirement
Years Ended December 31,2008 200
Befit obligaons as of the
meaurent date:
Discowit rate 6.9010 6.30%6.9010 6.45%
Ra of compensation incras 3.50 4.00 N/A N/A
Net benefit co for the peod ended:
Discwit rate 6.30%5.76%6.45%6.00%
Ex retu on plan assets 7.75 8.00 7.75 8.00
Rate of compensation incr 4.00 4.00 N/A N/A
In establishing its assumption as to the expecte retu on plan assets. PacifiCorp reviews the expected asset allocation and develops
ret assumptions for each asset class basd on historical performance and forward-looking views of the financial markets.
Assumed health care cost trend rates as of the measurement date:
2008 2007
Heath care cost trd rate asumed for next yea - uner 65
Heath car cost trd rate asumed for next yea - over 65
Ra tht th cot trend ra grualy declines to
Yea tht rate rehes the ra it is assumed to reman at - wider 65
Yea tht rate reahes the rate it is assumed to remain at - over 65
8%
6
5
2012
2010
9%
7
5
2012
2010
A one-percentae-point change in assumed health care cost trend rates would have the following effect (in millons):
Increase (Decrese)
One Percentage-Point One Percentage-Point
Increase Derease
Effec on tota seice and intet cost
Effec on other posttireent benefit obligation
$3
31
$(2)
(26)
I FERC FORM NO.1 (ED. 12-88)Page 123.26
Pension Plan Trost VEBATrosts2_2007 Target 2008 2007 Target
Equity seurties 49"10 56%53-57%64%64%63-67%
Debt seurties 40 35 33-37 36 36 33-37
Oter -l -2 8- 12 --..1o ..1o ,1%J.%
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/31/2009 2008/Q4
NOTES TO FINACIAL STATEMENTS (Continued)
Contributions and Benefit Payents
Employer contrbutions to the pension, other postretirment benefit plans and the joint trst unon plans are expected to be
$54 milion, $25 millon and $11 millon, respectively, for 2009. Funding to the established pension trst is based upon the
actuarally determined costs of the plan and the requirement of the Internal Revenue Code, the Employee Retirment Income
Securty Act of 1974 and the Pension Protection Act of 2006, as amended. PacifiCorp's policy is to contrbute to its other
postrirement benefit plan an amount equal to the sum of the net periodic cost and the expectd Medicare subsidy.
The Plan's expecd benefit payments to parcipants for its penion and other postretement benefit plans for 2009 though 2013
and for the five year thereafr ar sumar below (in millons):
Projeet Benefi Payments
Oter Postrtiement
Pension Gros Medicare Subsidy Net of Subsidy
2009 $90 $36 $(3)$33
2010 93 37 (3)34
2011 95 38 (4)34
2012 96 39 (4)35
2013 101 40 (5)35
2014-2018 50 220 (30)190
Investment Policy and Asset Allocation
PacifiCorp's investent policy for its pension and oter postent benefit plans is to balance risk and ret though a
diversified portfolio of equity securties, fied income secties and other alteative investments. Asset allocation for the pension
and other postretirement benefit plans are as indicated in the tables below. Matuties for fied income securties are managed to
tagets consistent with prudent risk toleraces. Suffcient liquidity is maintained to meet nea-term benefit payment obligations. The
plans reta outside investment advisors to manage plan investments within the parameters outlned by PacifiCorp's Pension
Investment Commttee. The weighted-average re on assets assumption is based on historical performance for the types of asset
in which the plans invest.
PacifiCorp's pension plan trst includes a sete accunt that is used to fud benefits for the other postretirement benefit plan. In
addition to ths separate account, the asset for other postrement benefits are held in two Volunta Employees' Beneficiares
Association e'VEBA") Truts, eah of which has its own investment allocaton strtegies. PacifiCorp's asset allocation (percentage
of plan assets) as of Deember 31 was as follows:
PacifiCorp's beefit plan asset allocaions were impac by the highy volatile capital market in the second half of 2008.
IFERC FORM NO.1 (ED. 12-88) Page 123.27
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PaciCorp (2)A Resubmission 03/31/2009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
Defined Contrbution Plan
PacifiCorp's 401(k) Plan covers substatially all employees. PacifiCorp's contrbutions are bad primarly on each paicipant's
level of contrbution and canot exceed the maxmum allowable for ta puroses to the 401(k) Plan. PacifiCorp's contrbutions were
$23 milion and $19 milion durng the yeas ended December 31, 2008 and 2007, respectively.
Severance
PacifiCorp incured $- millon in severance expense during the year ended Deceber 31,2008 and $4 milion durg the year ended
December 31, 2007.
(12) Income Taxes
Income ta expense (benefit) consists of the following (in millons):
Years Ended December 31,
2008 2007
Current:
Federl $(64)$145
State (6)18
Total (70)163
Deferrd:
Federal 276 51
State 36 7
Total 312 58
Investment tax creits (4)(8)
Tota income ta expense $238 $213
I FERC FORM NO.1 (ED. 12-88)Page 123.28
2008 2007
Deferred tax assets:
Employee benefits $246 $139
Derivatve contr 169 107
Regulatory liabilties 42 44
Oter 130 142
587 432
Deferr tax liabilties:
Propert, plant and equipment (1,656)(1,374)
Regulatory assets (880)(688)Oter (50)(65)
(2,586)(2,127)
Net deferred ta liabilty $(J 299)$(J.695)
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PaciCorp ;2) A Resubmission 03/3112009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continue)
A reconcilation of the feder statutory ta ra to the effective ta rate applicable to income before income ta expense is as
follows:
Years Ended December 31,2008 2007
Federal statutory ta rate
State taes, net of federal benefit
Effec of regulatory treatment of
depreciation differnces
Tax reserves
Tax crdits (I)
Oter
Effectve income ta ra
35%
3
35%
3
1 2
(2)
(3)0)
32%
(5)
34%
(1) Prmaly atbutable to the impa of feder renewle eleccity proucon ta credit relate to quaifying wind-power
genertig failities tht extnd 10 yea from the da the failities we plac in sece.
The net deferred tax liabilty consist of the following as of Debe 31 (in millons):
The sale ofPacifiCorp to MEHC on March 21,2006 trggerd cert ta relate events that remain unsetled. PacifiCorp does not
believe that the ta, if any, arsing from the ultimte setement of these events wil have a mateal impac on its fiancial results.
PacifiCorp adopted F ASB Interprettion No. 48, Accounting for Uncertainty in Income Taxes-an interpretation ofF ASB Statement
No. 109, effective Januar 1,2007, resulting in a net increase in its asset for uncertin ta positions of $13 milion, which was offse
by an increase in beginning retined earings in the Compartive Balance Sheet.
As of December 31,2008 and 2007, PacifiCorp had a net asset of$13 milion for uncern ta positions. As of Deember 31,2008
and 2007, the net asset for uncertn ta position included $14 millon and $15 milion, respectvely, of ta positions that, if
recognizd, would have an impac on the effecve ta rate. The reming unecognize ta beefits relate to positions for which
ultimate deductibilty is highly cert but for which ther is unceinty as to the tiing of such deductbilty. Recognition of these
ta benefits, other than applicable interest and penalties, would not afec PacifiCorp's effecive ta rate. The uncertn ta positions
were included in miscellaneous curt and accred asset in the Comparatve Baance Sheet.
IFERC FORM NO.1 (ED. 12-88) Page 123.29
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/2009 2008104
NOTES TO FINACIAL STATEMENTS (Continued)
(13) Commitments and Contingencies
Legal Matters
PacifiCorp is par to a varet of legal acions arsing out of the normal coure of business. Plaintiffs occasionally seek punitive or
exemplar damages. PacifiCorp does not believe that such normal and routine litigation will have a material effec on its fmancial
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 substatial amounts and are descrbed below.
In Februar 2007, the Sierr Club and the Wyoming Outdoor Council fied a complaint agaist PacifiCorp in the federa distrct
cour in Cheyenne, Wyoming, alleging violations of the Wyoming state opacity stadards at PacifiCorp's Jim Bridger plant in
Wyoming. Under Wyoming state requirements, which are par of the Jim Bridger plant's Title V permit and ar enforceable by
private citizens under the federal Clean Air Act, a potential source of pollutats such as a coal-fied generating facilty must mee
minimum stadards for opacity, which is a meaurment of light that is obscurd in the flue of a generting facilty. The complait
alleges thousands of violations of asserd six-minute compliance periods and seeks an injuncton orderg the Jim Bridger plant's
compliance with opacity limits, civil penalties of $32,500 per day per violation, and the plaintiffs' costs of litigation. The cour
grted a motion to bifuate the tral into separte liabilty and remedy phases. In Marh 2008, the court indefinitely postponed the
date for the liabilty-phase tral. The remedy-phase tral has not yet been scheduled. The cour also has before it a number of motions
on which it has not yet ruled. PacifiCorp believes it has a number of defenses to the claims. PacifiCorp intends to vigorously oppose
the lawsuit but canot predict its outcome at this time. PacifiCorp has already committd to invest at least $812 millon in pollution
control equipment at its generatig facilties, including the Jim Bridger plant. Ths commtment is expectd to significatly reduce
system-wide emissions, including emissions at the Jim Bridger plant.
Environmental Regulation
Environmental Matters
PacifiCorp is subjec to federal, state and local laws and regulations regarding air and water quality, hazdous and solid waste
disposal and other environmenta matters that have the potential to impac PacifiCorp's curnt and futue operations. PacifCorp
believes it is in material compliance with curent environmental requirements.
New Source Review
As par of an industr-wide investigation to assess compliance with the New Soure Review ("NSR") and Prvention of Significant
Deterioration ("PSD") provisions, the United States Environmenta Proteion Agency (the "EPA") has requested from numerous
utilties information and supporting documentation regading their capital projec for varous generating facilties. Beteen 2001
and 2003, PacifiCorp responded to requests for information relating to its capital project at its generting facilties and has been
engaged in periodic discussions with the EPA over several year regarding PacifiCorp's historica projec and their compliance with
NSR and PSD provisions. An NSR enforcement case against another utilty has been decided by the United States Supreme Cour
holding that an increae in anual emissions of a generating failty, when combined with a modification (i.e., a physica or
operational change), may trgger NSR permittng. PacifiCorp canot prdict the outcome of its discussions with the EPA at this time;
however, PacifiCorp could be required to install additional emissions controls, and incur additional costs and penalties, in the event it
is determined that PacifiCorp's historical project did not meet all regulatory requirements.
IFERC FORM NO.1 (ED. 12-88) Page 123.30
IFERC FORM NO.1 (ED. 12-88)Page 123.31
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp I (2) A Resubmission 03/31/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Accrued Environmental Costs
PacifiCorp is fully or parly responsible for envionmental reediation at varous containated sites, including sites that are or were
par of PacifiCorp's operations and sites owned by th pares. PacifiCorp accres environmenta remediation expenses when the
expenses are believed to be probable and ca be reasonably estatd. The quantification of environmental exposures is based on
may factors, including changing laws and regulations, advancements in environmenta technologies, the quality of available
site-specific information, site investigation results, expeced remediation or settement timelines, PacifiCorp's proportionate
responsibilty, contrctul indemnities and coverae provided by insurce policies. Remediation costs that are fied and
detrminable have been discounted to their present value using credt-adjusted, risk-free discount rates based on the expect futue
anual borrowing costs of PacifiCorp. The liabilty rerded as of December 31, 2008 and 2007 was $11 milion and $13 millon,
respectively, and is included in other deferr credts in the Compative Balance Sheet. Environmental remediation liabilties that
separtely result from the normal operation of long-lived asse and tht ar associated with the retiment of those asset are
separtely accounted for as AROs. The Deembe 31, 2008 recorded liabilty included $2 milion of discounted liabilties. Had none
of the liabilties included in the $11 millon balance reorded as of Deceber 31, 2008 been discounted, the total would have been
$11 milion.
Hydroelectrc Relicensing
PacifiCorp's hydroelectc portolio consists of 47 generating facilties with an aggregate facilty net owned capacity of 1,158 MW.
The FERC regulates 98% of the net capacity of this portolio though 16 individua licenses, which typically have terms of 30 to
50 year. In April 2008 and June 2008, the FERC issued new licenses for the Prospect and the Lewis River hydroelectc systems,
respectively, as described below. PacifiCorp's Klamath hydrlectc system is the remanig hydroelecc generatig facilty
actvely engaged in the relicensing process with the PERC. Hydroelecc relicening and the related environmental compliance
requirements and litigation ar subject to unceties. PacifiCorp expe tht futue costs relating to these matt will be
significant and will consist priary of additional relicensing costs, as well as ongoing opertions and maintenance expense and
capital expenditus required by its hydroelecc liceses. Eleccity genertion reuctons may result from the additional
environmental requirements. PacifiCorp ha incu $57 millon and $89 millon in costs, included in constrction work in
progress, as of December 31, 2008 and 2007, respevely, for ongoing hydroelectc relicensing. Refer to Hydroelectc
Commitments secton below for a discussion regaring existig capital expnditures commtments related to hydroelectc licenses
under which PacifiCorp is curntly operatig.
Klamath Hydroelectric System - Klamath River. Oregon and CalifOrnia
In Febru 200, PacifiCorp fied with the FERC a final application for a new license to operate the 169*MW Klamth
hydroelectc system in anticipation of the March 2006 expirtion of the existing license. PacifiCorp is curently operatig under an
anua license issued by the FERC and expect to continue operating under anual licenses until the relicensing process is complete.
As par of the relicensing process, the FERC is requir to pedorm an environmenta review and in November 2007, the FERC
issued its final environmental impact statement. The United States Fish and Wildlife Service and the National Marne Fisheries
Service issued final biological opinions in December 2007 analyzig the Klamath hydroelectc system's impact on endagered
species under a new FERC license consistent with the FERC staffs recommended license alterntive and term and conditions
issued by the Unite States Deparents of the Inteor and Commerc. These term and conditions include constrcton of upstrea
and downstram fish passage facilties at the Klamath hydroelecc system's four mainst das. PacifiCorp wil nee to obtan
water quality certifications from Oregon and Californa prior to the FERC issuing a final license. PacifiCorp curntly has water
quality applications pending in Oregon and California.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) . A Resubmission 0313112009 2oo81Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
In November 2008, PacifiCorp signed a non-binding agrment in priciple (the "Al") that lays out a frework for the disposition
of PacifiCorp's Klamath hydroelectc system relicensing process, including a path toward dam trsfer and removal by an entity
other than PacifiCorp no earlier than 2020. Paries to the Al ar PacifiCorp, the United States Deparent of the Intenor, the State
of Oregon and the State of California. Any trsfer of facilties and subsequent removal are contingent on PacifiCorp reaching a
comprehensive final settlement agreeent with the Al signatones and other staeholders. Negotiations on a final agrement have
begu and the Al states that a final agreement is expected no later than June 30, 2009. As provided in the Al, PacifiCorp's support
for a definitive setlement will depend on the inclusion of proteion for PacifiCorp and its customer from da removal costs and
liabilties.
The Al includes provisions to:
· Perorm studies and implement cen measurs designed to benefit aquatic species and their habitat in the Klamath Basin;
· Support and implement legislation in Oregon authonzig a customer surcharge inteded to cover potential da removal; and
· Require paries to support proposed federa legislation introduced to failtate a final agrment.
Assumg a fial agreement is reached, the United States governent will conduct scientific and engineeg studies and consult
with state, local and trbal governents and other staeholders, as appropnate, to determne by Marh 31, 2012 whether the benefits
of da removal will justify the costs.
In addition to signing the AI, PacifiCorp recently provided both the United States Fish and Wildlife Serice and the Nationa
Marne Fisheries Servce an intenm conservation plan aied at providing additional protecons for endangered species in the
Klamath Basin. PacifiCorp is currently collaborating with both agencies to implement the plan.
As of December 31,2008 and 2007, PacifiCorp had $57 milion and $48 millon, respectively, in costs related to the relicensing of
the Klamath hydroelectc system included in constction work in progress in the Comparive Balance Sheet.
Lewis River Hydroelectrc System - Lewis River. Washington
PacifiCorp fied new license applications with the FERC for the 136-MW Merwin and 240-MW Swift No.1 hydroelectc facilties
in April 2004. An application for a new license for the 134-MW Yale hydroelectc facilty was filed with the FERC in Apnl 1999.
However, consideration of the Yale application was delayed pending filing of the Merwin and Swift No. i applicaions so that the
FERC could complete a comprehensive environmental analysis.
In November 2004, PacifiCorp executed a comprehensive setement agreement with 26 other paies, including state and federa
agencies, Native Amencan trbes, conservation groups and local governent and citizen grups, to resolve, among the paries, issues
related to the pending applications for new licenses for PacifiCorp's Merin, Swift No.1 and Yale hydroelectc falities. As par of
this settement agrement, PacifiCorp agreed to implement certn protecon, mitigation and enhancement measures pnor to and
durig a proposed 50-year license penod. In June 2008, the FERC issued new individual licenses for the Mer, Swift No. 1 and
Yale hydroelectc facilties, each for a penod of 50 years, effective June 1, 2008. In July 2008, PacifiCorp filed a motion of request
for clarfication or rehearng on certin items, which were subsequently addrssed by the FERC in its October 2008 order on
reheang. In October 2008, subsequent to the FERC's final order, $36 milion in costs to relicense these facilties were trsfered
from constrction work in progress to utilty plant.
IFERC FORM NO.1 (ED. 12-88) Page 123.32
Total
$3,037
2,605
1,463
893
56
242
$8296
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) cAn Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/3112009 2008/04
NOTES TO FINACIAL STATEMENTS (Continued)
Prospect Hydroelectrc System - Rogu Rier, Oregon
In June 2003, PacifiCorp submittd a final license application to the FERC for the Prospect Nos. 1,2 and 4 hydroelecc facilties,
with tota nameplate ratings of 37 MW. In 2008, the FERC issued a new license for a period of 30 years effective April 1, 2008.
Subsequent to the issuace of the new license, $7 milion of costs incured to relicense the Prospect hydroelectc system were
transferred from constction work in progress to utilty plant.
Hydroelectric Commitments
Some of PacifiCorp's hydroelecc licees conta requiremen for PacifiCorp to mae cen capital expenditus related to its
hydroelectc facilties. PacifiCorp estites it is obligate to mae capita expenditues of approxitely $278 millon over the next
10 yea related to these licenses.
FERClssues
Northwest Refund Case
In June 2003, the FERC teinated its proceeg relating to the possibilty of requirg refuds for wholesale spot-market bilatera
sales in the Pacific Nortwest between December 2000 and June 2001. The FERC concluded that orderig refuds would not be an
appropriate resolution of the matt. In November 2003, the FERC issued its final order denying reheang. Several market
paricipants, excluding PacifiCorp, fied petitions in the Unite States Cour of Apps for the Ninth Circuit (the "Ninth Circuit')
for review of the FERC's fial order. In Augut 2007, the Ninth Ciruit concluded that the FERC failed to adequately explain how it
considered or examined new evidence showig intentiona maket mapulaton in Californa and its potential ties to the Pacific
Nortwest and that the FERC should not have excluded from the Pacific Nortwest refud proceeding purchases of energy mae by
the Californa Energy Resources Scheduling ("CERS") division in the Pacific Nortwest spt market. The Ninth Circuit remanded
the case to the FERC to (i) addrss the new market manpulation evidence in detil and account for it in any futue orders regarding
the award or denial of refuds in the proceengs, (ii) include sales to CERS in its analysis, and (ii) fuer consider its refud
decision in light of related, intervening opinions of the cour. The Ninth Circuit offered no opinion on the FERC's findings based on
the record established by the admistrative law judge and did not rule on the merits of the FERC's November 2003 decision to deny
refuds. Due to the remand, PacifiCorp canot predict the impact of this ruling at this time.
Purchase Obligations
PacifiCorp has the following unconditiona purhas obligaons as of Deember 31,2008 (in millons) that ar not reflec in the
Comparive Balance Sheet:
Payments Due During the Years Ending December 31,2009 2010 2011 2012 2013 Thereafter
Purchased electcity
Fuel
Constrction
Trasmission
Operting leasesOter
Tota commitments
$ 419
519
923
80
5
43
$ i 989
$389 $254 $176 $171
436 259 141 144
392 97 42 7
76 70 63 59
4 4 4 3~-.----um LW LI Lm
$1,628
1,106
2
545
36
126
3443$
IFERCFORM NO.1 (ED. 12-88) Page 123.33
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PaciCorp (2) A Resubmission 0313112009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Purchased Electrcity
As par of its energy resource portfolio, PacifiCorp acquires a portion of its eleccity though long-term purchass and exchange
ageements. PacifiCorp has several power purchase agrements with wind-powered and other generating falities that are. not
included in the table above as the payments are based on the amount of energy generate and there are no minimum payments.
Purchased electcity, including purchases under those contract that ar not included in the above table and purchases of short-term
electcity, were $759 milion and $793 millon for the years ended Dember 31,2008 and 2007, respecively. These amounts are
net of the effect of book outs and tring activities.
Included in the minimum fied anual payments for purchased eleccity above are commitments to purchase electicity from
several hydroelecc systems under long-term argements with public utilty distct. These purchases are made on a
"cost-of-servce" basis for a stated percentage of syste output and for a like percentage of system operting expenses and debt
servce. These costs are included in operation expenses in the Statement of Income. PacifiCorp is reuired to pay its portion of
operatig costs and its portion of the debt service, whether or not any electrcity is produced. These argements accounted for less
than 5% ofPacifiCorp's 2008 and 2007 energy sources.
Fuel
PacifiCorp ha "tae or pay" coal and natual gas contrct that requir miimum payments.
Constrtion
PacifiCorp has an ongoing constrcton program to meet increased electcity usage, customer grwt and syste reliabilty
objecives. As of December 31,2008, PacifiCorp had estated long-term purchase obligations relate to its constrcton progr
pnmaly for new wid-powered generating facilties and for certin segments of the Energy Gateway Trasmission Expanion
Projec. Amounts included in the purchase obligations table above relate to fi commtments. The following discussion descrbes
overall commtments related to those entered into as a result ofMEHC's March 2006 acquisition ofPacifiCorp, as well as the Energy
Gateway Trasmission Expansion Projec. The amounts descnbed below include amounts to which PacifiCorp is not yet firmly
commttd though a purchas order or other agrement.
As par of the Marh 2006 acquisition of PacifiCorp, MEHC and PacifiCorp made a number of commtments to the state regulatory
commssions in all six states in which PacifiCorp has retl customers. These commitments are generally being implemented over
severl yeas following the acquisition and are subject to subsequent regulatory review and approval. Outstading commitments as
of Deember 31,2008 include:
· Approximately $812 millon in investments in emissions reducton technology for PacifiCorp's existig coal-fired generating
facilties. Though December 31, 2008, PacifiCorp had spent a tota of $496 millon, including non-cash equity AFUDC, on
these emissions reduction prjecs and expe to spend in excess of the original commtment due to higher commodity inflaton
expeence on the planed investments.
· Approxiately $520 milion in investments (including both capital and operag expense commitments) in PacifiCorp's
trsmission and distbution syste that would ence reliabilty, faciltate the reeipt of renewable resources and enable
fuer syste optiization. Though December 31, 2008, PacifiCorp had spent a total of $224 milion in capita expenditus,
including non-cash equity AFUDC, in support of this commitment, and has anounced the transmission expansion projec
discussed below.
IFERC FORM NO.1 (ED. 12-88) Page 123.34
Series:
Serial Preferrd, $100 stated
value, 3,500 shares authoried
4.52% to 4.72%
5.00% to 5.40%
6.00%
7.00010
5% Prferred $100 state value,
127 shars authorized
Redemption
Price Per Share
2008
Share Amount
2007
Shares Amount
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/3112009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The Energy Gateway Trasmission Expansion Prjec is an investment plan to build approximately 2,000 miles of new high-voltage
trsmission lines, prily in Wyoming, Uta, Idao, Orgon and the deser Southwest. The plan, with an estimated cost exceedng
$6.1 bilion, includes projec that will addrs cusomer load growt improve system reliabilty and deliver energy from new
wind-powered and other renewable genertig resoures thoughout PacifiCorp's six-state servce area and the Western United
States. Cert transmission segments associate with this plan are expeced to be placed in serice begining in 2010, with other
segments placed in serce though 2018, depending on sitig, perttng and constrction schedules.
Transmission
PacifiCorp has ageements for the right to trsmit eleccity over other entities' trsmission lines to faciltate delivery to
PacifiCorp's customers.
Operating Leases
PacifiCorp leaes offces, certn operating failties, land and equipment under opering leases that expire at varous dates though
the year ending December 31, 2092. Cern leas conta renewal options for varing perods and escalation clauses for adjusting
rent to reflect changes in price indices. These leaes generlly reuir PacifiCorp to pay for insurce, taes and maintenance
applicable to the leaed propert.
Net rent expense was $25 milion and $29 millon durg the yea ended Deceber 31, 2008 and 2007, respectively.
Other
PacifiCorp has purchase obligations relate to equipment maitenace and varous other servce and maintenance agreements.
(14) Preferred Stock
PacifiCorp's preferrd stock, not subjec to madary reemption, wa as follows as of December 31 (shars in thousands, dollar in
millons, except per share amounts):
$102.3 to $103.5
$100.0 to $101.0
Non-reeeable
Non-redeeable
$110.0
157 $15 157 $15
108 10 108 10
6 1 6 1
18 2 18 2
126 -U 126 -U.Æ $41 ..$41
IFERC FORM NO.1 (ED. 12..S) Page 123.35
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03/31/2009 2oo8/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Generaly, preferred stock is redeemable at stipulated prices plus accred dividends, subject to cert restrctions. In the event of
volunta liquidation, all prefered stock is entitled to stated value or a specified preference amount per share plus accrued dividends.
Upon involunta liquidation, all preferred stock is entitled to stated value plus accred dividends. Dividends on all preferred stock
are cumulative. Holders also have the right to elec members to the PacifiCorp board of directors in the event dividends payable ar
in default in an amount equal to four ful quarrly payments.
Dividends declard but unpaid on preferred stock were $1 millon as of December 31, 2008 and 2007.
(15) Common Shareholder's Equity
Appropriated Retained Earnings
In accordance with the requirments of certn hydrelecc relicensing projects, as of December 31, 2008 and 2007, PacifiCorp had
$4 millon in appropriated retined earings - amortization reserve, federaL.
Common Shareholder's Equity
Though PPW Holdings LLC, MEHC is the sole shareholder of PacifiCorp's common stock. The state regulatry orders that
authorize MEHC's March 2006 acquisition ofPacifiCorp contain restrctons on PacifiCorp's abilty to pay dividends to the extnt
that they would reuce PacifiCorp's common stock equity below specified percentages of defied capitalization.
As of December 31, 2008, the most restctive of these commtments prohibits PacifiCorp from makg any distrbution 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 capitaization, excluding short-term debt and curent matuties oflong-term debt. From Januar 1,
2009 though December 31, 2009 the minimum level of common equity required by this commitment is 47.25%. After December 31,
2009, this minimum level of common equity declines anually to 44.0% afer December 31, 2011. The ters of this commitment
treat 50.0% of PacifiCorp's remaining balance of preferred stock in existence prior to MEHC's March 2006 acuisition of
PacifiCorp as common equity. As of December 31,2008, PacifiCorp's acl common stock equity percentage, as calculated under
this measure, was 52.6%, and PacifiCorp had $945 millon available to dividend.
These commitments also restrct PacifiCorp from makng any distrbutions to either PPW Holdings LLC or MEHC if PacifiCorp's
unecured debt rating is BBB- or lower by Stadard & Poor's Rating Services or Fitch Ratings or Baa or lower by Moody's
Investor Serce, as indicated by two of the thee rating services. As of December 31,2008, PacifiCorp's unsecurd debt rating was
A- by Stadad & Poor's Rating Serices, BBB+ by Fitch Ratings and Baal by Mooy's Investor Service.
PacifiCorp is also subjec to maximum debt-to-total capitalization percentage under varous financing agreeents as fuer
discussed in Notes 8 and 9.
I FERC FORM NO.1 lED. 12-88)Page 123.36
IFERC FORM NO.1 (ED. 12-88) Page 123.37
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/31/2009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continue)
(16) Related-Part Transactions
Transactions with MEHC
PacifiCorp has an intercompany adinisttion serices agrment with its indirct parent company, MEHC. Serces provided by
PacifiCorp and charged to affliates relate priarly to adinistive services, fiancial statement prepartion and direct-assigned
employees. These receivables were $1 millon and $- millon as of December 31,2008 and 2007, respectively. Services provided by
affliates and charged to PacifiCorp relate priarly to the administtive services provided under the intercompany adminstrtive
servces agement among MEHC and its afliates. These expenses totaled $9 millon durg each of the years ended December 31,
2008 and 2007. These payables were $1 millon as of December 31, 2008 and 2007.
PacifiCorp engages in varous trsacions with sever of its afliat compaies in the ordinar course of business. Serices
provided by afliates in the ordinar coure of business and charged to PacifiCorp relate prarly to the transporttion of natl
gas and relocation services. These expenes toed $6 millon and $5 milion durng the yea ended December 31,2008 and 2007,
respectively. These payables were $2 millon and $1 millon as of Deember 31,2008 and 2007, respecively.
Berkshir Hathaway, PacifiCorp's ultimte parnt compay, has an ownersp intest in Burlington Nortern Santa Fe Ralway
("BNSF"). PacifiCorp has long-term trporton contr with BNSF. Trasporttion costs under these contrct were
$32 milion and $31 millon durg the year ended Deber 31,2008 and 2007, respeively. As of December 31,2008 and 2007,
PacifiCorp had $2 millon of accounts payable to BNSF outstading under these contr, including indirect payables related to a
jointly owned plant.
PacifiCorp parcipates in a captive insurce program provided by MEHC Insurnce Services Ltd. ("MISL"), a wholly owned
subsidiar ofMEHC. MISL covers all or signficant portons of the proper daage and liabilty insurce deductbles in many of
PacifiCorp's curt policies, as well as overhea distrbuton and trsmission line propert daage. PacifiCorp has no equity
interest in MISL and has no obligation to contrbute equity or loan fuds to MISL. Prium amounts ar established based on a
combination of actal assesments and maet rate to cover loss claims, adsttive expenses and appropriate reserves, but as
a result of regulatory commtments are cappe thugh Deembe 31,2010. Certin cost associate with the progr ar prepaid
and amortze over the policy coverae peod expirig Mah 20, 2009. Prmium expenses were $7 millon durng each of the year
ended December 31,2008 and 2007. Prepayments to MISL wer $2 millon as of December 31,2008 and 2007. Receivables for
claims were $7 milion and $11 milion as of December 31, 2008 and 2007, respecvely.
PacifiCorp is par to a ta-sharg agrment and is par of the Berkshir Hathaway United States federal income ta retu. As of
December 31, 2008 and 2007, prepayments included $42 millon and $22 milion, respectively, of income taes receivable from
MEHC.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/31/2009 2008/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Transactions with Unconsolidated Subsidiaries of PacifCorp
In the ordinar course of business, PacifiCorp engages in various trsactions with its unconsolidated subsidiares. Servces provided
by PacifiCorp and chaged to its subsidiares related priarly to management services, income taes and labor. These reeivables
were $1 millon as of Decmber 31, 2008 and 2007. Services provided by subsidiares and chared to PacifiCorp primarly related to
coal purchases. These payables were $14 milion and $9 milion as of December 31, 2008 and 2007, respectively. Expenes for these
coal purchases were $14 i milion and $ i 02 milion for the years ended December 31, 2008 and 2007, respetively.
PacifiCorp is par to an umbrella loan agreement with one of its unconsolidated subsidiares. Regulatory authorizations permit
PacifiCorp to borrow from its subsidiares (including those that are consolidated) without limitation and to loan each of these
subsidiares up to $30 milion at anyone time, provided that the borrowings bear interest at rates that do not exceed the interest rates
that PacifiCorp would otherwise incur extrnally. As of December 31, 2008 and 2007, afliated notes receivable from unconsolidated
subsidiares were $21 milion and $26 milion. respectively, including interest.
(17) Supplemental Cash Flows Information
The sumar of supplemental cash flows information is as follows (in milions):
Years Ended December 31,2008 2007
Inteest paid, net of amounts capitaize
Income taes (received) paid, net
$
$
280
(52)
$
$
221
152
Supplemental disclosure of non-cash investing and financing activities:
Utilty plant additions in accounts payable $ 398
Utility plant additions acquired under capita leaseobligatons $ 17
$103
$
IFERC FORM NO.1 (ED. 12-88) Page 123.38
FERC FORM NO.1 (NEW 06)Page 122
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) ¡= A Resubmission 0331/200
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, Ar. 0 HEDGING ACTIVITIES
1. Repo in coumns (b),(c),(d) and (e) the amounts of acumulated other comprehensive incme items, on a net-o-tax bais, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of oter ca flow hedges.
3. For each category of hedges that have been accunted for as "fair value hedges., report the acounts affeced and the related amounts in a footnote.
Line Item Unreaized Gains and Minimum Pension Foreign Currency Other
No.Loes on Available-Liabilty adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a)(b)(c)(d)(e)
1 Baance of Account 219 at Beginning of
Preceding Year 9,86 (5,939,253)
2 Preceding QtrNr to Date Reclassifications
from Acct 219 to Net Income
3 Preedng QuarterNear to Date Changes in
Fair Value 31,08 2,381,915
4 Total (lines 2 and 3)31,08 2,381,915
5 Balance of Account 219 at End of
Preceding QuarterNear ~6 Balance of Account 219 at Beinning of
Currnt Year 40,954 (3,557,338)
7 Currnt QtrNr to Date Reclassifications
from Aec 219 to Net Income
8 Current QuarterNearto Date Changes in
Fair Value (171,723)1,137,427
9 Total (lines 7 and 8)(171,723)1,137,427
10 Balance of Account 219 at End of Currt
QuarterlYear -~
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008/04
This ~rtls: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 03131/200
COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, ASTATEMENTS OF ACCUMULATE
Other Cash Flow
Hedges
Interest Rate Swaps
Other Cash Flow
Hedes
(Specify)
Totals for each
category of items
recrded in
Accunt 219
(h)
( 3,882,135)
( 2,047,252)
2,413,003
365,751
3,516,384)
3,516,384)
Line
No.
(f)(g)
1
2
3
4
5
6
7
8
9
10
2,047,252
2,047,252)
2,047,252)
96,704
965,704
2,550,68)
Net Income (Carred
Forwrd from
Page 117, Lie 78)
Total
Comprehensive
Income
(i)0)
FERC FORM NO.1 (NEW 062)Page 122b
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/200 20004
FOOTNOTE DATA
to $40,954.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
............................................
Blank Page
(Next Page is 200)
90,847,520
6,84,927,351
90,847,520
6,848,927,351
............................................
is~ s:
(1) ~An Original
(2) A Resubmission
SUMMA Y OF UTILITY PLANT AND ACCUM LATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETON
Report in Column (c) the amount for electric function, in column (d) the amount for ga function, in column (e), (f), and (g) report other (speif) and in
column (f) common function.
(a)
Total Compay for the
Current Year/Quarter Ended
(b)
Electric
(c)
Line
No.
Classification
Utilty Plant
2 In Service
3 Plant in Servce (Classified)
4 Property Under Capital Leaes
5 Plant Purchased or Sold
6 Completed Construction not Classifed
7 Exprimental Plant Unclassifed
8 Total (3 thru 7)
9 Leaed to Others
10 Held for Future Use
11 Constrution Work in Progress
12 Acquisition Adjustments
13 Total Utilty Plant (8 thru 12)
14 Accum Prov for Der, Amort, & Depl
15 Net Utilit Plant (13 less 14)
16 Detail of Accum Prov for Depr, Amort & Dept
17 In Service:
18 Depreiation
19 Amort & Depl of Proucing Nat Gas Land/Land Right
20 Amort of Underground Storage LandLa Righ
21 Amort of Other Utilty Plant
22 Total In Servce (18 thru 21)
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 Total Leaed to Others (24 & 25)
27 Held for Future Use
28 Dereciation
29 Amortization
30 Totai Held for Future Use (28 & 29)
31 Abandoment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31,32)
17,858,244,918
65,742,757
302,819,070
63,878,843
17,858,244,918
65,742,757
302,819,070
63,878,84
18,290,685,588 18,290,685,588
15,074,557
1,208,785,536
157,193,780
19,671,739,461
6,84,927,351
12,822,812,110
15,074,557
1,208,785,536
157,193,780
19,671,739,461
6,848,927,351
12,822,812,110
FERC FORM NO.1 (ED. 12-89)Page 20
............................................
Name of Respondent
PacifiCorp
Gas
This ~rtls: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 03131/200
SUMMAR F UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Speify) Other (Specif) Other (Specif)
Year/Period of Report
End of 20004
Common
FERC FORM NO.1 (ED. 12-8)Page 201
Tota $6,343,121,197
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)PacifiCorp (2) A Resubmission 03131/2009 2008/04
FOOTNOTE DATA
¡Shedule Page: 200 Line No.: 18 Column: c
Depreciation is comprised of:
Depreiation $6,309,809,795Depletion 33,311.402
I FERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Blank Page
(Next Page is 204)
FERC FORM NO.1 (REV. 12005)Page 20
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 0331/200
ELECTRI PLANT IN SERVICE (Account 101,02, 103 and 106)
1. Report below the original cost of electric plant in service accrding to the prescribed accunts.
2. In addition to Account 101, Elecric Plant in Service (Classified), this page and the next include Accnt 102, Elecric Plant Purchaed or Sold;
Account 103, Experimenta Elecric Plant Unclasified; and Accunt 106, Completed Construction Not ClasifedElecri.
3. Include in column (c) or (d), as appropriate, correions of addition and reirements for the current or preeding year.
4. For revisions to the amount of initial aset retireent cots cataized, incude by primary plant accunt, increaes in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accunts to indicate the negtive effect of such accunts.
6. Classify Account 106 accordng to prescribe accounts, on an esimated bais if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a signifcant amount
of plant retirements which have not ben classified to primary accunts 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 accnt for accumulated depreciation provision. Include als in column (d)
!Line Account ~No.
Ca)
Beginning of Yearb) (c)
1 1. INTANGIBLE PLANT
2 301) Oraanization
3 302) Franchises and Consents 115,670,811 50,216,83
4 (30) Miscellaneous Intagible Plant 555,278,797 30,887,832
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)670,949,608 81,104,66
6 2. PRODUCTION PLANT
7 A. Steam Prouction Plant
8 310) Land and Land Rights 94,677,729 1,168,771
9 (311) Structures and Improvements 803,481,836 18,092,182
10 312\ Boiler Plant Equipment 2,842,150,285 241,428,185
11 313) Engines and Engine-Driven Generators
12 (314) Turbenerator Units 754,869,133 45,948,270
13 (315\ Accessorv Electric EQuipment 340,742,715 22,233,810
14 316) Misc. Power Plant Equipment 25,907,698 33,482
15 317) Asset Retirement Costs for Stea Productio 26,574,784 1,379,350
16 TOTAL Steam Prodction Plant CEnter Tota of lines 8 thru 15)4,888,40,180 33,585,050
17 B. Nuclear Production Plant
18 (320) Land and Land Rights
19 (321) Structures and Improvemens
20 322\ Reactor Plant EQuipment
21 323) Turbenerator Units
22 324) Accessorv Electric Equipment
23 325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Prouction
25 TOTAL Nuclear Production Plan CEnter Total of lines 18 thru 24)
26 C. Hvdraulic Production Plant
27 (330\ Land and Land Rights 19,692,547 288
28 (331) Structures and Improvements 83,912,04 2,812,43
29 (332) Reservoirs, Dams, and Waterwys 279,983,821 16,447,223
30 333\ Water Wheels, Turbines, and Generators 90,548,710 12,670,210
31 33\ Accessorv Electri Equipment 43,143,055 10,213,031
32 335\ Misc. Power Plant Equipment 2,56,625 14,624
33 33) Roads, Railroads, and Bridges 13,940,90 820,767
34 (337) Asset Retirement Costs for HYdraulic Prouction
35 TOTAL HYdraulic Prouction Plant (Enter Total of line 27 thru 34)53,785,702 42,978,573
36 D. Other Prouction Plant
37 C34) Land and Land Rights 21,542,670 247
38 (341) Structures and Improvements 112,490,790 1,295,742
39 (342) Fuel Holders, Proucts, and Accessories 8,976,320 -31,431
40 C343 Prime Movers 892,403,54 778,331,190
41 (34 Generators 223,358,160 24,869
42 C34 Accesso Elecri EQuioment 115,873,753 8,054
43 (34) Misc. Power Plant Equipment 6,66,88
44 (347) Ast Retirement Cots for Other Prouction 1,303,579 735,093
45 TOTAL Other Pro. Plant (Enter Totl of lines 37 thru 44)1,382,613,703 780,36,764
46 TOTAL Pro. Plan (Enter Tot of lines 16, 25, 35, and 45)6,804,803,585 1 ,153,927,387
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 03/31/2009
ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106) (Continued)
distributions of these tentative classifcations 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 Accunts 101 and 106 will avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7. Show in column (f) reclassificaions or transfers within utilty plant accunts. Include also in column (f) the additions or reductions of primary accunt
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 offet to the debits or crdits distributed in column (f) to primary
account classifications.
8. For Accunt 399, state the nature and use of plant included in this accunt and if substantial in amount submit a supplementary statement showing
subaccunt classification of such plant conforming to the reuirement of these pages.
9. For each amount comprising the reported balance and changes in Accunt 102, state the propert purchased or sold, name of vendor or purcase,
and date of transaction. If proposed joumal entries have been filed with the CommiSSion as required by the Uniform System of Accounts, give also dateRetirements Adjustments Transfers Balance at LineEnd fYear No(e .
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
4,080,804
88,317,049
-1,54,526
-16,253,788
11,694,118
958,905
89,688
15,232,091
427,808
308,400
804,355,376
362,445,428
26,460,892
27,254,154
5,111,318,671
495,038
19,692,835
87,066,858
296,190,974
102,877,058
52,221,914
2,377,969
14,727,440
152,650
240,070
458,271
645,786
26,461
34,231
116,409
-488,386
-174,819
121,181
102,180
4,902,973
11,373
164,618
-5,473,946
351,555
-27,612,667
11,850,056
19,327,489
519,133
21,542,917
108,191,405
9,194,264
1,638,219,095
235,221,712
135,04,678
7,184,019
2,038,672
2,156,636,762
7,843,110,481
5,302,325
112,000,358 -699,980
-1,038,380
-2,920,153
20FERC FORM NO.1 (REV. 12-()Page
FERC FORM NO. 1 (REV. 12-05)Page 206
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 0331/20
ELECTRIC PlAT IN SERVICE (Account 101, 102, 1 J3 and 106) (Continued
ILlne Account ~No.Beginning of Year
(a)(b) c
47 3. TRANSMISSION PLANT
48 (350 Land and Land Riohts 88,585,565 6,90,063
49 (352) Structures and Imorovements 63,744,997 709,228
50 353) Station Equioment 1,029,270,485 139,174,258
51 (35) Towers an Rxtures 434,46,188 -99,097
52 355 Poles and Fixtures 532,740,254 38,815,670
53 (356) Overhead Conductors and Devices 703,734,651 31,838,803
54 (357) UndeI'round Conduit 3,2n,612 3,065
55 358) UndeI'round Conductors and Device 7,365,512
56 359) Roads and Trals 11,472,227 62,857
57 359.1) Asset Retirement Costs for Trasmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)2,874,659,491 216,509,847
59 4. DISTRIBUTION PLANT
60 360 Land and Land Riahts 45,675,442 1,217,841
61 361 Structures and Improvements 51,355,986 182,337
62 (362 Station Equioment 683,925,359 60,584,106
63 (363 Storaae Batterv Eauioment 1,457,804
64 364) Poles, Towers, and Fixtures 84,025,721 36,311,658
65 (36 Overhead Conductors and Devices 607,741,213 17,936,500
66 366 Underaround Conduit 270,012,305 10,88,96
67 367 UndeI'round Conducors and Devices 649,509,858 30,452,90
68 (368 Line Transformers 974,00,458 58,669,335
69 369 Services 503,373,333 33,206,213
70 370 Meters 184,941,478 29,272,089
71 371) Installations on Customer Premises 8,86,60 46,571
72 (372) Leased Property on Customer Premises 49,658
73 373 Street Liahtina and Sianal Systems 59,329,699 2,926,943
74 374 Asset Retirement Costs for Distribution Plant 374,403 124,782
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)4,88,637,321 281,815,250
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANTn(38 Land and Land Riohts
78 381 Structures and Imorovements
79 382 Comouter Hardware
80 (383) Comouter Softre
81 (384) Communiction Equipment
82 (385) Miscellaneos RElional Transmission an Market Ooeration Plant
83 (38) Asset Retirement Costs for Reaional Trasmission and Market Oper
84 TOTAL Transmission and Market Ooeration Plan CTotailines n thru 83)
85 6. GENERAL PLANT
86 (389) La and Land Riohts 15,283,942 810,324
87 (390) Structures and Improvements 226,824,150 11,047,415
88 (391) Ofice Fumiture and EQuioment 96,245,673 11,426,06
89 1(392) TransDOrttion EQuioment 95,395,892 7,100,947
90 (393 Stores Equioment 13,453,276 852,926
91 I (39) Tools, Shop an Garage Etluioment 62,541,713 2,751,842
92 (395) Laratorv Equipment 40,187,183 1,271,09
93 I (396) Power Operated Equiomen 122,290,881 10,536,787
94 (397) Communication Eauioment 241,073,068 14,139,432
95 (398) Miscellaneous Equipment 5,930,894 401,068
96 SUBTOTAL (Enter Total of lines 86 thru 95)919,226,672 60,337,894
97 (399) Other Tanaible Propert
98 1 (399.1) Asset Retirement Costs for General Plant 39,748
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98)1,182,26,561 75,261,760
100 TOTAL (Accounts 101 and 106)16,417,316,566~101 1(102) Electric Plant Purchased (See Instr. 8)
102 1 (Less) (102) Elecric Plant Sold (See Instr. 8)-21,858
103 1(103) Exoerimental Plant Unclassifed
104 TOTAL Elecric Plant in Servce (Enter Tota of lines 100 thru 103)16,417,33,424 2,111 ,44,982
.Name of Respondent This ~ort Is:Date of Report Year/Period of Report.PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) A Resubmission 03/31/2009.ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106) (Continued).Adjustments Transfers Balance at Line
(e End tifYear No..47.139,664 4,591 95,350,555 48
87,938 6,330,330 70,696,617 49.13,513,612 -6,066,842 1,148,864,289 50
1,06,887 1,149,788 433,558,992 51.8,726,292 -9,191,373 553,638,259 52.13,052,979 7,746,559 730,267,034 53
2,206 -68,889 3,209,582 54.124,663 7,490,175 55
-81,637 11,453,447 56.57.36,587,578 58
59.366,520 46,526,763 60
52,057 6,868,201 58,354,467 61.5,415,412 -7,307,055 731,786,998 62.1,457,804 63
6,950,928 148,492 873,534,943 64.5,524,254 21,512 620,174,971 65
982,765 279,913,50 66.2,499,032 677463,735 67.9,570,919 17,425 1,023,120,299 68
1,291,443 535,288,103 69.26,871,892 217,056 187,558,731 70
93,326 8,813,849 71.49,658 72.760,50 73
74.60,428,710 75
76.77.78
79.80.81
82.83
84.85.16,094,266 86
8,275,694 -108,486 229,487,385 87.18,931,114 311,386 89,052,008 88
2,927,225 -206,832 99,362,782 89.862,587 200,725 13,64,340 90.3,122,992 589,743 62,760,306 91
2,629,230 144,168 38,973,211 92.6,670,104 315,928 126,473,492 93
14,787,436 1,486,536 241,911,600 94.171,403 196,523 6,357,082 95.2,929,691 924,116,472 96
97.39,748 98
63,126,003 1,197,249,133 99.302,899,080 17,922,123,761 100.302,819,070 101
102.103
302,899,080 -878,869 -61,626 18,224,942,831 104.....FERC FORM NO. 1 (REV. 12-()Page 207
Adjustents Trasfer Balance at End
of Yea
(e)(f)(g)
$-$$2,634,916
52,550,647
40,385,161
12,180,880
3,424,575
391,745 65,527,839
17,699,562
10,652,772
17,001,312
4,695,073
91,872 1,180,419
5,160,806
(391,745)2,117,020
(1,859)615,912
36,839,783
(178,889)426,236
$(178,889)$90,013 $ 273,092,913
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0311/200 200104
FOOTNOTE DATA
¡Schedule Page: 204 Line No.: 97Account Deription
(a)
39921 Lad Owed in Fee
39922 Lad Rights39930 Strctes
39941 SUDac - Plant Equipment
39944 SUDace - Elecc Powe Facilties
39945 Underground - Coa Mine Equipment
39946 Longwl Shields
39947 Longwl Equipment
39948 Manline Extnsion
39949 Secion Exension
39951 Vehicles
39952 Heavy Constction Equipment
39%0 Miscellaneous Geera Equipment
39961 Computer - Manfe
39970 Mine Development and Ro Extsion
399915 Coal Mine As Retreent Obligations
Tota Plan Use in Miing Activities
Column:b
Balance Beginning
of Yea
(b)
$ 2,634,916
52,550,647
39,600,837
11,882,614
3,424,575
58,96,142
17,699,562
10,786,602
16,528,462
3,935,855
1,115,%7
4,842,225
2,233,419
650,464
35,542,729
605,125
$ 263,00,141
Additions
(c)
$
791,47046,60
9,527,336
940,460
922,423
356,891
590,998
38,630
1,297,054
$ 14,929,866
Retireents
(d)
$
(7,146)
(166,338)
(3,357,384)
(13,830)
(467,610)
(163,205)
(27,420)
(38,310)
(315,652)
(71,323)
$(4,748,218)
¡Schedule Page: 204 Line No.: 97 Column: c
See footnote line 97, colum b.
¡Schedule Page: 204 Line No.: 97 Column: d
See footnote line 97, colum b.
¡Schedule Page: 204 Line No.: 97 Column: e
See footnote line 97, colum b.
¡Schedule Page: 204 Line No.: 97 Column: f
See footnote line 97, colum b.
¡Schedule Page: 204 Line No.: 97 Column: g
See footnote line 97, colum b.
¡Schedule Page: 204 Line No.: 101 Column: c
On September 15,2008, aftr having reeived the reui reguatory approvals, PacifiCorp acquired from TNA Merchant Projec,
Inc., an afliate of Suez Energy North Amerca, Inc., 100% of the equity interest of Chehalis Power Generating, LLC, an entity
owning a 520-megawatt ("MW") natul gas-fired generting plant locate in Chehalis, Washington. The tota cash purchase price wa
$308 millon and the estimate fair value of the acuired entity wa primly allocated to the plant. Chehalis Power Generating, LLC
was merged into PacifiCorp immediately followig the acuisition. The results of the plant's opertions have been included in
PacifiCorp's Financial Statements since the acquisition date.
In Febru 2009, PacifiCorp filed with the FERC uner docket number AC09-41-000 a reuest to clea account 102 Electc Plan
Puchas or Sold, for costs incur to a we the 520-MW natu -fired Chehalis eneratin lant.
hedule Pa : 204 Line No.: 102 Column: f
In April 2008, the FERC approved the jour enes called for by the Uniform System of Accounts for the Upper Beaver
Hydroelectic Project which wa sold to the City of Beaver, Uta in Septeber 2007. For fuer informtion, refer to Importt
Changes Durng The QuerlY ear, Ite 3 included in this Form No. 1.
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Blank Page
(Next Page is 214)
FERC FORM NO.1 (ED. 12-9)Page 214
............................................
Name of Respondent This î!rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
End of 20004
(2) Fi A Resubmission 03131/20
ELECTRIC PLANT HELD FOR FUTURE uSE (Accunt 105)
1. Report separately each propert held for future use at end of the year having an original cot of $250,00 or more. Group othr items of property held
for future use.
2. For property having an original cot of $250,000 or more previously used in utilty operations, now held for future use, give in column (a), in addition to
other required information, the date that utilty use of such property wa discontinue, and the date the original cost wa transferred to Account 105.
Line uescni:tlon ana Location ~No.Of profert in is Account in Utilty Service End of Year. (a (b) (c) (d)
1 Land and Rights:
2
3 Oquirr Substation 2005 2009 2,245,898
4 North Hom Mountain Coal Properties 1977_953,014
5 Bames Butte Substation 2007 2010 746,268
6 White Rock Substation 2007 2009 505,024
7 Wild Horse Wind Plant 2007 -6,763,094
8 Twelve Mile Wind Plant 2007 2,160,207
9 Jumbers Point Substation 2008 2012 1,173,276
10
11 Miscellaneous, each under $250,00:-527,776
12
13
14
15
16
17
18
19
20
21 Other Property:
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Total 15,074,557
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/2009 2oo8/Q4
FOOTNOTE DATA
ISchedule Page: 214 Line No.: 4 Column: c
The Nort Horn Mounta Coal Propertes ar neeed to access futue coal ports and federa coal reserves when existig Eat
Mounta coal mies are mied out.
¡Schedule Page: 214 Line No.: 7 Column: c I
Lad purchase for wind far with an estited constrction date of 2016 or before subject to the tig of completion of the Energy
Gateway Transmission Expansion Project.
ISchedule Page: 214 Line No.: 8 Column: c I
Lad purchased for wid far with an estite constrction date of 2016 or before subject to the tig of completion of the Energ
Gateway Transmission Expansion Project.
¡SChedule Page: 214 Line No.: 11 Column: c
Varous dates and plans.
IFERC FORM NO.1 (ED. 12-87) Page 45.1
FERC FORM NO.1 (ED. 12-87)Page 216
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 03/31/20
CONSTRUe ION WORK IN PROGRESS - - ELE( TRIC (Accnt 107)
1. Report below descriptions and balances at end of year of projects in pross of costruction (107)
2. Show items relating to "research, development, and demonstration" proecs last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accunts)
3. Minor projecs (5% of the Balance End of the Year for Accunt 107 or $100,00, whichever is less) may be groupe.
Line Description of Project Construction work in proress -
No.Electric (Account 107)
(a)(b)
1 Intangible:
2 Klamath Relicensing 56,574,157
3 Transmission Scheduling Project KWH 3,46,30
4 CaT TriP II Energy Trading Systems 3,074,257
5 SAP License and Maintenance Enhancents 2,144,405
6
7 Production:
8 Rollng Hils Wind Plant (99 MW)196,499,05
9 High Plains Wind Plant (99 MW)116,484,099
10 Dave Johnston U3 S02 & PM Emission Cotro Upgrades 114,821,152
11 Glenrock II Wind Plan (39 MW)80,03,026
12 Dunlap II Wind Plant 26,341,809
13 Dave Johnston U4 S02 & PM Emission Control Upgrade 25,66,763
14 Dunlap I Wind Plant 2O,n2,737
15 North Umpqua Relicensing Implementation 14,079,56
16 Blundell Project 12,329,80
17 Lewis River Relicensing Implementation 10,219,999
18 Huntington U1 Clean Air - PM 9,758,572
19 Dave Johnston U4 - Boilerrrurbine Controls 7,228,398
20 Dave Johnston U4 " Boiler EconomizerlLow Temp SH Upgrade 6,40,60
21 Hunter U2 Clean Air-PM 5,77,416
22 Hunter U1 Turbine Upgrade HPIIP/LP 4,33,554
23 Huntington Water Efficiency Management 4,266,531
24 Jim Bridger U3 S02 & PM Emission Control Upgdes 3,897,890
25 Dave Johnston U4 - Replace Reheater 3,274,33
26 Jim Bridger U1 S02 & PM Emission Control Upges 3,143,669
27 Dave Johnston U4 NOx 2,416,291
28 Huntington U2 Steam Coil Air Preheaters 2,405,371
29 Jim Bridger Soda Liquor Storage 2,184,437
30 Huntington U1 Turbine Upgrade HPIIP/LP 1,84,881
31 Jim Bridger U1 Turbne Upgrade HPIIP/LP 1,825,985
32 Jim Bridger U2 S02 & PM Emission Contro Upgrades 1,713,133
33 Ashton Dam Seepage Conrol 1,709,799
34 NERC/CIPS Security Remediation 208 1,69,60
35 Jim Bridger U1 Generator Rewind 1,670,273
36 Carbn - Fly Ash Handling System 1,64,761
37 Huntington Security - NERCICIPS Physical Securi 1,627,713
38 Dave Johnston - Install Fire Proecion Pump 1,579,895
39 Hunter U2 Turbne Upgrae HPIIPILP 1,44,273
40 Jim Bridger Fan Bay Road Paving/Regrade 07 1,391,983
41 Currant Crek Block 2 Development 1,282,34
42 Dave Johnston U4 - Replace Air Heater Bakets 1,26,784
43 TOTAL 1,208,785,53
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 03131/200
CONSTRUCTION WORK IN PROGRESS - - ELEC TRIC (Account 107)
1. Report below descriptions and balances at end of year of proects in proess of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demnstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projecs (5% of the Balance End of the Year for Account 107 or $100,00, whichever is less) may be groupe.
Line Description of Projec Construction work in progress.
No.Electric (Account 107)
(a)(b)
1 Jim Briger U2 Reheater Outlet Terminal Tubes 1,181,351
2 Dave Johnston U3 Mercury CEMS 1,065,761
3 Naughton U3 OH Generator Rotor Replacement 1,038,161
4 Dave Johnston. Col Load.lnlripper Washdown System 1,038,029
5 Dave Johnston - Replace/Exand CET Shop 1,00,469
6
7 Transmission:
8 Populus.Terminal: Obi Ckt 345 kV Transmission Line 127,889,642
9 Oquirr New 345-138kV Substation 12,342,33
10 Chappel Crek 230KV Cimarex Energy 10,913,53
11 Camp Wiliams Static VAR Compensator Installation 8,735,215
12 Line 37 Conv to 115kV Bid Nickel Mt Sub 8,65,405
13 Glenrok Wind Interconection 6,521,882
14 Mona-Oquirr Line 6,232,249
15 Dave Johnston Bridger Midpoint 500kV Line 6,001,729
16 Three Peaks Sub: Install 34 kV Sub 5,783,381
17 Wine Country New 230-115kV Sub 5,743,96
18 Copco II Sub Repl Exist 115-69kV Tmsfmr 5,470,516
19 Bridger Mona 500V Une 3,479,20
20 Three Mile Knoll Sub: New 34-138kV Sub 3,43,694
21 Upper Green River Basin - Jonah Field & Paradise SubsUnes 3,26,143
22 Mona Substation Instl New 34kV cap Bank 1,955,45
23 Shute Creek to Mona System Upgrade 1,92,659
24 St George-Red Butte 138kV Line 1,741,682
25 McClelland-Emigration Tap 1.4Mi OH Line 1,550,38
26 Califomia-Orego Intertie Transfer Capilty Incr 1,385,2n
27 Walla Walla Midway 230kV Line 1,130,512
28 Malin Sub CKB RepllTE 500kV CKB491 1,09,550
29 Jim Bridger - Repel RAS A&B Scheme Proect 2,014,56
30
31 Distribution:
32 Yew Avenue - Constuc New Sub (Tetherow)9,516,574
33 Morrson Creek Sub Construct New Substation 3,90,254
34 Snydervile Add 2nd Transformer 3,624,765
35 Gol Rush New 139-12.5kV 30MVA Sub 3,497,467
36 Shoreline New 13812.5kV Sub Transf & Fdrs 2,271,873
37 Northeast Instl2nd 4-12kV Tmsf 4-12kV 2,097,169
38 E layton Install 2nd 30MVA Tmsmr-Dist 1,98,847
39 Casper WY Automated Meter Reading Project 1,325,257
40
41 Genera:
42 Moble Radio Replacent Projec 10,870,n5
43 TOTAL 1,20,785,536
FERC FORM NO.1 (ED. 12..57 Page 216.1
FERC FORM NO.1 (ED. 12-8 Page 216.2
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 0331/20
CONSTRUe ION WORK IN PROGRESS - - ELE TRIC (Accunt 107)
1. Report below descriptions and balances at end of year of projects in proess of construion (107)
2. Show items reating to "research, development, and demontration" proec last, under a caption Researc, Deveopmen, 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 $100,00, whichever is less) may be groupe.
Line Description of Projec Construction work in progress -
No.Electric (Account 107)
(a)(b)
1 Jim Bridger - Repl RAS A&B Scheme Proec 2,014,569
2 SAP Hardware and Databe 2,962,077
3 Energy West-Business System Upgra 1,771,723
4 IP Telephony Project 1,03,215
5
6 171,011,575
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43 TOTAL 1,208,785,53
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0311/2009 2008/Q4
FOOTNOTE DATA
¡Schedule Page: 216.2 Line No.: 6 Column: a
A $1,00,00 reportg theshold was approved for PacifCorp effective with the 1993 reportg year by the Chief
Accountat, Federa Reguatory Commssion in a lettr to the company date August 5, 1993, Docket No. AC93-181-00.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Year/Period of Report
End of 2008/04 ............................................
Name of Respondent
PaciiCorp
This~rtls:
(1) ~An Original
(2) A Resubmission
ACCUMULATED PROVI ION FOR DEPRECIATION OF ELE
1. Exlain in a footnote any important adjustments during year.
2. Explain in a footnote any diference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in servce, pages 204-207, column 9d), excluding retirements of non-depreciable propert.
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.
ine
No.
em
(a)
1 Balance Beginning of Year
2 Depreciation Provisions for Year, Charged to
(403) Depreciation Expense
(403.1) Depreciation Exense for Asset
Retirement Costs
5 (413) Exp. of Elec. PIt. Leas. to Others
Trasportation Expnses-Clearing
Other Clearing Account
Other Accunts (Specify, details in footnote):
Date of Report
(Mo, Da, Yr)
03131/20
RIC UTILITY PLANT (Accunt 108)
44,165,138-~~-TOTAL Depre. Prov for Year (Enter Tota of
lines 3 thru 9)
11 Net Charges for Plant Retired:
Book Cost of Plant Retire
Cost of Removal
Salvage (Credit)
TOTAL Net Chrgs. for Plant Ret. (Enter Totl
of lines 12 thru 14)
Other Deit or Cr. Items (Describe, deails in
footnote):
26,449,n1
45,33,80
8,783,073
30,00,504
Bok Cost or Asset Retirement Costs Retire
Balance End of Year (Enter Totas of lines 1,
10,15, 16, and 18)
6,34,121,197
Steam Prouction
seon B. Balance at End of Year Acrding to Functonal Classification
2,467,561,753 2,467,561,7
2 Hydraulic Proction-enventional
23 Hydraulic Prouction-Pumpe Storage
2 Other Proction
242,183,351
154,698,448
1,097,50,323
1,90,426,138
Regional Trasmission and Maret Opraon
General
TOTAL (Enter Total of lines 20 thru 28)
474,745,184
6,34,121,197
474,745,1
6,34,121,19
FERC FORM NO.1 (REV. 12-G)Page 219
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/2009 2008104
FOOTNOTE DATA
¡Schedule Page: 219 Line No.: 4 Column: b
PacifCorp records the depreciation expense of asset retiment obligations as either a regulatory asset or (liabilty).
¡SChedule Page: 219 Line No.: 8 Column: b
Depreciation of mig assets included in account 151 Fuel Stock
Account 143.3 Joint Owner Receivable - Depreciation expense biled to Joint Owners
Account 182.3 Otr Reguatory Assets
Vehicle Depreciation allocate to O&M based on usage activity
Account 503.1 Blundell Depletion
Account 503 JGC Depreciation and Amrtzation
Tota Oter Accounts
$9,786,263
280,223
1,725,894
13,465,822
185,368
1,085,369
(188)
26,528,751$
¡SChedule Page: 219 Line No.: 16 Column: b
Other items including:
- Recovery frm thd pares for asset relocatons and damged propert
- Insurce recovenes
- Adjustmnts of reserve relate to electrc plant sold
- Reclassifcations from electrc plant
$5,140,119
IFERC FORM NO.1 (ED. 12-87) Page 450.1
FERC FORM NO.1 (ED. 12-8)Page 224
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
End of 2oo8/Q4
(2) Fi A Resubmission 0331/20
INVESTM NTS IN SUBSIDIARY COMPANIES Accunt 123.1)
1.Report below investments in Accounts 123.1, investment in Subsidiary Compaies.
2. Provide a subheading for each company and List there under the information caled for below. Sub - TOTAL by compay and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and desribe each security own. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loas or investment advances which are subjec to repaymen, but which are not subject to
current settlement. With respect to each advnce show whether the advance is a note or open accunt. List each note giving date of issuance, maturity
date, and specifying whether note is a renewaL.
3. Report separately the equity in undistribued subsidiary eamings since acuisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
ine Descnption or Investment Date Acquired Date Of Amount of Invesment at
No.(a)(b)
MBl:frity Beginning of Year
(d)
1 PACIFIC MINERALS, INC 12/31/1991
2 Common Stock 1
3 Capital Contributions 32,46,00
4 Undistributed Eamings 93,410,979
5 SUBTOTAL 125,870,980
6
7 PACIFICORP ENVIRONMENTAL REMEDIATION COMPANY 8/19/1994
8 Common Stock 90,00
9 Capital Contributions 13,719,625
10 Acquisition of Minority Interest 956,88
11 Undistributed Subsidiary Earings 7,567,496
12 SUBTOTAL 23,144,00
13
14 PACIFIC FUTURE GENERATIONS, INC 9/19/1999
15 Undistributed Subsidiary Eamings -9,952
16 SUBTOTAL -9,952
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42 Total Cot of Account 123.1 $62,679,6261 TOTAL 149,005,037
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
End of 2008/04(2) Ei A Resubmission 03131/2009
INVESTMENT IN SUBSIDIARY COMPANIES (Accunt 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 purpe of the pledge.
5. If Commission approval was required for any advance made or security acuired, designate such fact in a footnoe and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment dispoed of during the year, the gain or loss represented by the difference betwee cot of the investment (or
the other amount at which carried in the books of account if diference from cost) and the selling price theref, not including interest adjustment includible
in column (f).
8. Reprt on Line 42, column (a) the TOTAL cost of Accunt 123.1
t:quity in ~uDslalary Hevenues tor Year Amount or investment at l:ain or LOSS trom Investment LineEamin~~)of Year
(f)
Endm)Year DiS~edof No.
1
1 2
3-102,321,791 4
8,910,812 150,281,792 5
6
7
;;8
9
10
-1,905,654 11
-1,905,65 21,238,355 12
13
14
-9,952 15
-9,952 16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
7,005,158 171,510,195 42
FERC FORM NO.1 (ED. 12-8)Page 225
I FERC FORM NO.1 (ED. 12-87)Page 45.1
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0331/2009 2oo8/Q4
FOOTNOTE DATA
¡Schedule Page: 224 Line No.: 3 Column: 11
Reflect $15,500,000 ca ital contrbutons from aren co
Schedule Pa e: 224 Line No.: 4 Coumn: e
As equity earngs on PacifiCorp's investment in Pacific Miners, Inc. ("PMI") represent intercompany profit in Bridger Coal
Company's sales of coal to PacifiCorp, such amoun ar not rerded in acunt 418.1, Equity in Earings of Subsidiar Companies.
Rather, PacifiCorp rerds PMI's earngs before inteest and taes as an offet to fuel inventory, whch is charged to fuel expense as
consumed, and records interest and taes in their respectve line ite. PMI own Bridger Coal Company jointly with a subsidiar of
Idaho Power Company.
¡Schedule Page: 224 Line No.: 8 Column: g
See footnote on line 10, colum g
¡Schedule Page: 224 Line No.: 10 Column: g
PacifiCorp Environmenta Remediation Company ("PERCo") becae a wholly owned subsidiar ofPacifiCorp in April 2007, when
PacifiCorp acquired the outtading 10% miority intest. The acuisition of PER Co's miority interest was allocated to common
stock in the amount of $100,000 and undistrbutd susidi . s in the amount of$856,888.
Schedule Pa e: 224 Line No.: 11 Column:
See footnote on line 10, colum g
............................................
Blank Page
(Next Page is 227)
FERC FORM NO.1 (REV. 12-ÐS)Page 227
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, 08, Yr)2O8IQ4(2) D A Resubmission 03131/20 End of
MATERIALS AND SUPPLIES
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional clasifications as indicated in column (a);
estimates of amounts by function are acceptale. In column (d), designate the department or deprtments which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a fotnote) showing geera clases of material and suppies and the
various accounts (operating expenses, clearing accnts, plant, etc.) afeced debied or credited. Show sepaely debi or creits to stores expnse
clearing, if applicable.
Line Account Baance Balance Department or
No.Beginning of Year End of Year Departments which
Use Material
(a)(b)(c)(d)
1 Fuel Stock (Accunt 151)98,33,182 136,802,88 Electric
2 Fuel Stock Exnses Undistributed (Account 152)
3 Residuals and Extracted Proucts (Account 153)
4 Plant Materias and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)53,387,313 76,746,318 Elecric
6 Assigned to - Operations and Maintenance
7 Prouction Plant (Estimated)74,067,221 71,228,040 Elecric
8 Transmission Plant (Estimated)6,228,512 497,646 Electric
9 Distribution Plant (Estimated 11,90,581 16,n2,938 Elecric
10 Regiona Trasmission and Market Operaio Plant
(Estimated)
11 Asigned to - Other (provide details in footnote)Electric
12 TOTAL Accunt 154 (Enter Total of lines 5 thru 11)150,050,022 170,075,369
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Acnt 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163)
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)248,38,204 30,878,251
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/200 200/04
FOOTNOTE DATA
¡Schedule Page: 227
MigM&S
General Plant M&S
Line No.: 11
$4,314,408
145,987
$4,460,395
Line No.: 11
$4,656,652
173,775
$4,830,427
Column:b
¡Schedule Page: 227
MinigM&S
Genera Plant M&S
Column:c
IFERC FORM NO.1 (ED. 12..7) Page 450.1
............................1................
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 03131/2009
Allowances (Accounts 158.1 and 158.2)
1. Report below the particulars (details) called for concerning allowances.
2. Report all acquisitions of allowances at cost.
3. Report allowancs in accrdance with a weighted average cost allocation method and other accunting as prescribed by General
Instrction No. 21 in the Uniform System of Acunts.
4. Report the allowances transactions by the period they are first eligible for use: the current yeats allowances in columns (b)-(c),
allowances for the three succeding years in columns (d)-(i), starting with the following year, and allowances for the remaining
succeeding years in columns ü)-(k).
5. Report on line 4 the Environmental Protection Agency (EPA) issued allownces. Report withheld portions Lines 36-0.Line Allowances Inventory Currnt Year 2009
No. (Account 158.1)
(a)
1 Balance-Beginning of Year
2
3
4
5
6
7
8 PurchaseslTransfers:
9 Chehalis
10
11
12
13
14
15 Total
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Year/Period of Report
2008/04End of
Acquired During Year:
Issue (Less Withheld Allow)
Retumed by EPA
Relinquished During Year:
Charges to Account 509
Other.
Cost of SaleslTransfers:
DTE Coal Services
Louis Dreyfus
Macquarie
NRG
Sempra
West Valley
Total
BalanceEnd of Year
Sales:
Net Sales Proceeds(Assoc. Co.)
Net Sales Proceds (Other)
Gains
Losses
Allownces Withheld (Acc 158.2)
36 Balance-Beginning of Year
37 Add: Withheld by EPA
38 Deuct: Returned by EPA
39 Cost of Sales
40 BalanceEnd of Year
41
42
43
44
45
46
Sales:
Net Sales Proceeds (Assoc. Co.)
Net Sales Proceeds (Other)
Gains
Losses
FERC FORM NO.1 (ED. 12-95)Page 228
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 03/31/2009
Allownces (Accunts 158.1 and 158.2) (Continued)
6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA's sales of the withheld allowances. Report on Lines
43-46 the net sales proceeds and gains/losses resulting from the EPA's sale or auction of the withheld allowances.
7. Report on Lines 8-14 the names of vendorsltransferors 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 transactons on a separate line under purchaseslransfers and sales/transfers.
10. Report on Lines 32-35 and 43-6 the net sales proceeds and gains or losses from allowance sales.
4.00
2,000.00
12,000.00
1,00.00
1,00.00
5,00.00
1.00
21,001.00
4,639,549.00
FERC FORM NO.1 (ED. 12-9)Page 229
FERC FORM NO.1 (ED. 12-8)Page 230b
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
PaciCorp (1) An Original (Mo, Da, Yr)End of 200Q4
(2) 0 A Resubmission 03131/200
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
Line Description of Unrecovered Plan l'otl Costs WRITIEN OFF DURING YEAR Balance at No.and Regulatory Study Costs (Include Amount Reçisedin the description of cots, the date of of Charges During Year Account Amount End of Year Commission Authorization to use Ace 182.2 Charged
and period of amortization (mo, yr to mo, yr))
(a)(b)(c)(d)(e)(f)
21 Unrecovered Plant: Trojan Nuclear 5,149,185 407 1,670,00 3,479,179
22 Plant located near Portland, OR
23 Date of Retirement: 12/31/1992
24 Date of Commission Authorization:
25 0420/1993
26 Amortization Period: 01/1993
27 hrough 01/2011
28
29 Unrecovere Plant: Powerdale 10,439,884 I~'407 3,437,028 6,959,922
30 Hydro Elecric Plant
31 Date of Retirement: 02/0812007
32 Date of Commission Authorization:
33 05/1412007
34 Amortization Period: OS/207
35 hrough 12/2010
36
37
38
39
40
41
42
43
44
45
46
47
48
49 TOTAL 15,589,069 -42,9 5,107,034 10,43,101
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 200/04
FOOTNOTE DATA
¡Schedule Page: 230 Line No.: 29 Column: c
Represents insurce reimurements.
IFERC FORM NO.1 (ED. 12-87)Page 45.1
FERC FORM NO. 1/1-FJ3 (NEW. 037)Page 231
............................................
Name of Respondent This WOrt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) Fi A Resubmission 031/209
Transmission Servce and Generation Interconnecion Stud Cos
1. Report the particulars (details) called for conceming the costs incurred and the reimbursements reived for penonning transmission servce an
generator interconnection studies.
2. Ust each study separately.
3. In column (a) provide the name of the study.
4. In column (b) report the cost incurred to perfonn the study at the end of period.
5. In column (c) report the accunt charged with the cost of the study.
6. In column (d) report the amounts received for reimbursement of the study cots at end of period.
7. In column (e) report the accont credited with the reimbursement reived for perfonning the study.
Line
Cots Incurr During ljelm!'rsements Account CreditedNo.Received DuringDecriptionPeriodAccunt Charged the Period With Reimbursement
(a)(b)(c)(d)(e)
1 Transmission Studies2.1 3,469 561.6 3,469 456.2
3 Aref 421623,421624 21 561.6 21 456.2
4 Aref 421615,421616,421617 21 561.6 21 456.2
5 Aref 421618,421619,421620 35 561.6 35 456.2
6 Aref 4413,44314 43 561.6 433 456.2
7 Aref 44315, 44316 43 561.6 433 456.2
8 Aref 44, 449 64 561.6 648 456.2
3,657 561.6 3,657 45.2
10 Are 40233, 40235 516 561.6 516 456.2
11 Aref437326 618 561.6 618 456.2
12 Aref 424140,424146 5,43 561.6 5,43 456.2
13 Aref46656 608 561.6 608 456.2
14 Aref 4606, 46 145 561.6 145 456.2
15 Aref475248 897 561.6 897 456.2~4,156 561.6 4,032 456.2
17 Aref 466,46 822 561.6 762 456.2
7,83 561.6 7,838 45.2
19 ~1,66 561.6 1,663 45.2
20 Aref 291675, 292491, 29249 (4,93)561.6
21 Generaion Studies
22 GlOO108 93 561.7 93 456.2
23 GlQO71 2,031 561.7 2,031 45.2
24 GlQO92 14 561.7 14 45.2
25 GIQO80 350 561.7 350 456.2
26 GIQOO89 975 561.7 975 456.2
Z7 GIOO, GIQ001 93 561.7 932 456.2
28 Gl005 2,258 561.7 2,258 456.2
29 GIOO134 2,03 561.7 2,036 45.2
30 GIQQ138 40 561.7 40 45.2
31 GIQQ139 4,477 561.7 4,477 456.2
32 GIQQ119 1,418 561.7 1,418 456.2
33 GIQQ142 1,442 561.7 1,442 456.2
34 GIQQ143 574 561.7 574 456.2
35 GIOO144 449 561.7 449 456.2
36 GIQQ151 5,787 561.7 5,787 456.2
37 GIQQ145, GIQ0146, GIQQ147 11,447 561.7 11,447 456.2
38 GIQQ148 1,050 561.7 1,050 456.2
39 GIQQ150 1,851 561.7 1,851 456.2
40 GIQQ152 1,037 561.7 1,037 456.2
............................................
Name of Respondent
PacifiCorp
This ~rtls: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 03131/2009
Transmission Servce and Generation Interconnection Study Costs
Year/Period of Report
End of 2008/04
(continued)
ne
No.
eim ursementsReceived During
the Period
(d)
Costs Incurrd During
Period Account Charged(~ ~)Account Credited
With Reimbursement
(e)
Description
(a)
1 Transmission Studies
2 Aref 428070
3 Aref 428102
4 Aref 41645
5 Are 445008
6 Aref 44867
7 Aref 462551
8 Are 46209
9 Aref46233, 46235, 46713
10
11 Aref 46721
12 Aref 46745,46754
13 Aref 46874
14 Aref 47007
15 Aref 471741
16 Aref 471743
17 Aref 46551
18 Aref 492327
19 Aref 493092
20 Aref 492326
21 Generation Studie
22 Gia0153
23 GIQ0154
24 GlQ0155
25 GIQ0117, GlQ0118
26 GlQ0128
27
28 GlOO16
29 GlQ0100
30 GlQ0129
31 GIQ0164
32 GlQ0165
33 GlQ0162
34 GIQ0163
35 GlQ0112
36 GlQ0139
37 GIQ0166
38 GlQ0167
39 GIQ0168
40 GlQ0141
42 561.6
62 561.6
83 561.6
21 561.6
873 561.6
569 561.6
442 561.6
474 561.6
1,287 561.6
474 561.6
927 561.6
194 561.6
63 561.6
803 561.6
5,94 561.6
124 561.6
5,392 561.6
689 561.6
68 561.6
1,474 561.7
1,421 561.7
1,049 561.7
14,291 561.7
16,43 561.7
2,878 561.7
231 561.7
10,561 561.7
20,183 561.7
5,412 561.7
293 561.7
8,989 561.7
14 561.7
10,859 561.7
3,470 561.7
1,747 561.7
1,794 561.7
2,33 561.7
5,078 561.7
1,474 45.2
1,223 45.2
1,04 45.2
13,751 45.2
16,438 45.2
2,878 45.2
231 456.2
10,561 456.2
20,183 456.2
5,412 456.2
293 456.2
8,989 456.2
14 456.2
10,859 456.2
3,470 456.2
1,747 456.2
1,794 45.2
2,33 456.2
5,078 45.2
FERC FORM NO. 1I*F/3 (NEW. 03-7)Page 231.1
ne
No.Description
(a)
1 Transmission Studies
2 Aref 468352, 469874
3 Aref 498286
4 Aref 505517
5 Aref 507957
6 Aref 507960
7 Aref 508134
8 Aref 508355
9 Aref 50832
10 Aref 508370
11 Aref 523183
12 Aref 531024
13 Customer Studies Accruls
14 Aref 313369
15 Aref 432138
16 Aref 432141
17 Aref 4472
18 Aref 44730
19 Aref 43138,43141
20 Aref 46058
21 Generaion Studies
22 GlOO93
23 GI00132
24 GlQ0169
25 GlQ0170
26 GlQ0171
27 GlQ0119
28 GI00172
29 GI00173
30 GIQ0138
31 GIQ0130
32 GIQ0135
33 GIQ0136
34 GlQ0137
35 GIQ0174
36 GIQ0175
37 GIQ0144
38 GlQ0143
39 GlQ0142
40 GlQ0178
Costs Incurr DuringPeriod Acunt Charged(b) (c)
eim ursements
Received During
the Period
(d)
Accunt Creed
With Reimbursement
(e)
............................................
Name of Respondent
PacifiCorp
This ~rtls: Date of Report
(1) ~ An Origina (Mo, Da, Yr)
(2) A Resubmission 03131/2009
Transmission Servce and Generation Interconnecio Study Cots (continued)
Year/Period of Report
End of 2008104
248 561.6
2,110 561.6
3,48 561.6
1,283 561.6
4,279 561.6
. 6,93 561.6
2,89 561.6
3,80 561.6
1,159 561.6
372 561.6
50 561.6
20 561.6
194 107
1,786 107
2,45 107
21 107
21 107
3,117 107
29 107---
651 561.7
7,755 561.7
1,799 561.7
405 561.7
11,131 561.7
14,175 561.7
2,65 561.7
2,116 561.7
2,93 561.7
21,717 561.7
17,158 561.7
14,35 561.7
14,199 561.7
4,68 561.7
5,207 561.7
13,292 561.7
14,96 561.7
16,805 561.7
8,188 561.7
651 456.2
7,755 456.2
1,799 456.2
405 456.2
5,281 456.2
14,175 45.2
2,654 456.2
2,116 45.2
2,938 456.2
21,717 456.2
17,158 456.2
14,35 456.2
14,199 456.2
4,539 456.2
4,057 456.2
13,292 456.2
14,96 456.2
16,805 456.2
8,188 45.2
FERc FORM NO. 1/1-FI3 (NEW. 03 Page 231.2
............................................
Name of Respondent
PacifiCorp
This ~ortls: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 03131/209
Transmission Service and Generation Interconnection Study Costs
Year/Period of Report
End of 2oo8/Q4
(continued)
ine
No.
eim ursements
Recived During
the Period
(d)
Accunt Credited
With Reimbursement
(e)
Costs Incurred During
Period Account Charged(b) (c)Description
(a)
Transmission Studies1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 GIQ0190
23 GlQ0187
24 GlQ0188
25 GIQ0177
26 GIQ0148
27 GlQ0176
28 GlQ0189
29 GlQ0128
30 GIQ0154
31 GlQ0192
32 GlQ0151
33 GlQ0191
34 GIQ0194
35 GlQ0193
36 GlQ0153
37 GIQ0145
38 GIQ0166
39 GlQ0152
40 GlQ0150
Aref460548
Aref46514, 46515, 460516
Aref46538
Aref4620
Aref4888
Aref49560
Aref 508324
Aref 50831
Aref 507939
Aref 513817
Aref 516316
1,162 107
298 107
153 107
474 107
866 107
2,671 107
2,227 107
2,130 107
1,647 107
1,36 107
256 107
-
10,695 561.7
24,831 561.7
16,838 561.7
2,230 561.7
38,073 561.7
2,687 561.7
16,140 561.7
15,299 561.7
19,188 561.7
1,111 561.7
7,419 561.7
4,56 561.7
4,84 561.7
26,44 561.7
5,950 561.7
48,213 561.7
5,426 561.7
15,256 561.7
3,219 561.7
10,695 456.2
24,831 45.2
16,838 456.2
2,230 456.2
38,073 456.2
2,687 456.2
16,140 456.2
15,299 456.2
19,188 45.2
1,111 456.2
7,419 456.2
4,566 456.2
4,84 456.2
26,44 456.2
5,950 45.2
48,213 456.2
5,426 456.2
15,256 456.2
3,219 45.2
FERC FORM NO.1/1-F/3 (NEW. 03-7)Page 231.3
ine
No.Description
(a)
Transmission Studies
Cots Incurr DuringPeriod Accnt Charged(b) (c)
eim ursementsReceived During
the Period
(d)
Accnt Creited
With Reimbursement
(e)
............................................
Name of Respondent
PacifiCorp
This ~rtls: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 0331/2009
Trasmission Servce and Generation Intercnnecio Stud Cots (continued)
Year/Period of Report
End of 2008/04
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 GlQ0162
23 GlOO198
24 Gia0199
25 GlOO200
26 GlOO201
27 GlOO195
28 GlOO197
29 GlOO202
30 GIOO20
31 GIOO205
32 GIQ0206
33 GlQ0212
34 GIQ0172
35 GIQ0172
36 GlQ0210
37 GlOO209
38 GlQ0211
39 GlQ0176
40 GlQ0142
--
7,642 561.7
2,502 561.7
2,078 561.7
1,457 561.7
1,723 561.7
7,598 561.7
7,642 561.7
1,54 561.7
4,469 561.7
2,35 561.7
1,757 561.7
1,56 561.7
15,557 561.7
14,85 561.7
5,091 561.7
9,83 561.7
4,620 561.7
4,349 561.7
5,870 561.7
7,642 45.2
2,502 456.2
2,078 456.2
1,457 456.2
1,723 456.2
7,598 456.2
7,642 456.2
1,54 456.2
4,469 456.2
2,364 456.2
1,757 45.2
1,564 45.2
15,557 456.2
14,855 45.2
5,091 456.2
9,83 456.2
4,620 45.2
4,34 45.2
5,870 45.2
FERC FORM NO. 111-F/3 (NEW. 03 Pag 231.4
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2oo8lQ4
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 03131/2009
Transmission Servce and Generation Interconnection Study Costs (continued)
ine
No.
eim ursements
Received During
the Period
(d)
Account Creited
With Reimbursement
(e)
Costs Incurr During
Period Account Charged(b) (c)Description
(a)
Transmission Studies1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generion Studies
22 GIQ0143
23 GlQ0213
24 GlQ0214
25 GlQ0215
26 GlQ0216
27 GlQ0130
28 GIQ0135
29 GIQ0136
30 GlQ0137
31 GlQ0217
32 GIQ0218
33 GlQ0219
34 GIQ022
35 GlQ0148
36 Gl0021
37 GlQ0153
38 GIQ0175
39 GIQ0208
40 GlQ0225
9,912 561.7
9,453 561.7
3,859 561.7
791 561.7
3,768 561.7
7,882 561.7
6,273 561.7
2,407 561.7
5,642 561.7
6,53 561.7
5,849 561.7
4,799 561.7
12,379 561.7
21 ,267 561.7
3,98 561.7
22,949 561.7
15,017 561.7
22,541 561.7
5,493 561.7
9,912 456.2
9,453 456.2
3,859 45.2
791 45.2
3,768 456.2
7,88 456.2
6,273 456.2
2,407 45.2
5,642 456.2
6,534 456.2
5,849 456.2
4,799 45.2
12,379 456.2
21,267 456.2
3,982 456.2
22,949 45.2
15,017 456.2
22,541 456.2
5,493 456.2
FERC FORM NO. 1/1-F13-Q (NEW. 037)Page 231.5
me
No.Description
(a)
Transmission Studies
Costs Incurr DuringPeriod Accunt Charg(b) (c)
eim ursements
Received During
the Period
(d)
Account Creited
With Reimbursement
(e)
............................................
Name of Respondent
PacifiCorp
This ~rtls: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 033112009
Transmission Servce and Generation Interconnecion Stud Costs (continued)
Year/Period of Report
End of 2oo8/Q4
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Genertion Studies
22 GlQ0226
23 GlQ0171
24 GlQ0152
25 GlQ0227
26 GlQO16
27 GlQ0228
28 GlQ0229
29 GlQ0191
30 GlQ0176
31 GIQ0166
32 GlQ0231
33GIQ0234
34 GlQ0178
35 GIQ0154
36 GlQ0172
37 GlQ0173
38 GIQ0236
39 GlQ0198
40 GlQ0199
4,318 561.7
6,593 561.7
18,182 561.7
83,882 561.7
13,185 561.7
1,326 561.7
10,311 561.7
5,39 561.7
6,370 561.7
6,69 561.7
22,022 561.7
3,62 561.7
14,27 561.7
9,705 561.7
6,668 561.7
5,60 561.7
11,474 561.7
6,608 561.7
1,649 561.7
4,318 456.2
6,593 45.2
18,182 45.2
48,432 456.2
13,185 456.2
1,326 456.2
10,311 45.2
5,394 45.2
6,370 45.2
6,693 456.2
22,022 456.2
3,622 456.2
14,277 456.2
9,705 456.2
6,668 456.2
5,606 456.2
11,474 456.2
6,608 45.2
1,649 45.2
FERC FORM NO.1/1-F13-Q (NEW. 03-7)Page 231.6
............................................
Name of Respondent
PacifiCorp
This ~rtls: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 03131/2009
Transmission Service and eneration Interconnecion Study Costs (continued)
Year/Period of Report
End of 2008/04
me
No.Description
(a)
Transmission Studies1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 GlQ0200
23 GlQ0201
24 GlQ0235
25 GIQ0228
26 GlQ0239
27 G1Q0238
28 GI00174
29 GlQ0187
30 GlQ0188
31 GlQ0189
32 GlQ0193
33 GIQ0218A, GlQ0218B
34 GIQ0221A, GI00221B, GIQ0221C
35 GlQ0240
36 GIQ0225
37 GIQ0226
38 GlQ0242
39 GIQ0171
40 GIOO30
Costs Incurred During
Period Account Charged(b) (c)
eim ursementsReceived During
the Period
(d)
Accnt Credted
With Reimbursement
(e)
2,259 561.7
1,455 561.7
10,131 561.7
2,798 561.7
4,407 561.7
1,050 561.7
10,89 561.7
5,941 561.7
3,014 561.7
4,038 561.7
4,218 561.7
6,225 561.7
16,319 561.7
37,676 561.7
5,08 561.7
3,326 561.7
599 561.7
2,00 561.7
4,253 561.7
2,259 456.2
1,455 456.2
10,131 456.2
2,798 456.2
4,407 456.2
1,05 456.2
10,890 456.2
5,941 45.2
3,014 45.2
4,038 45.2
4,218 456.2
6,225 456.2
16,319 456.2
37,676 45.2
4,784 45.2
2,949 45.2
599 456.2
2,00 456.2
4,253 456.2
FERC FORM NO. 1/1-FI3 (NEW. 03-Page 231.7
Name of Respodent
PacifiCorp
This ~rtls: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 03111200
Transmissio Servce and Generation Interconnecion Stud Cots (continued)
Year/Period of Report
End of 2008/04 ............................................
ine
No.Description
(a)
Transmission Studies
Costs Incurr During
Period Account Chared(b) (c)
eim ursementsReceived During
the Period
(d)
Accont Credited
With Reimbursement
(e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generaion Studies
22 GIQ02Q
23 GlQ0241
24 GIQ0234
25 GIQ0217
26 Gia0198
27 GIQ0199
28 GlQ0200
29 GlQ0201
30 GIQ0236
31 GIQ0243
32 GIQ0244
33 GIQ0245
34 GlQ0248
35 GIQ0246
36 GlQ0247
37 GlQ0249
38 GIQ0228
39 GIQ0250
40 GIQ0209
252 561.7
1,219 561.7
918 561.7
217 561.7
28 561.7
3,078 561.7
280 561.7
294 561.7
2,442 561.7
1,256 561.7
80 561.7
704 561.7
49 561.7
450 561.7
1,262 561.7
68 561.7
66 561.7
821 561.7
124 561.7
252 45.2
1,219 456.2
918 456.2
217 456.2
280 456.2
3,078 456.2
280 456.2
294 456.2
2,442 45.2
1,256 456.2
809 456.2
704 45.2
495 456.2
450 456.2
1,262 456.2
68 456.2
662 456.2
821 456.2
124 456.2
FERC FORM NO. 1/1*FI3-Q (NEW. 037)Page 231.8
............................................
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 03131/2009
Transmission Servce and Generation Interconnecion Study Costs
Year/Period of Report
End of 2oo8/Q4
(continued)
ne
No.
eim ursements
Received During
the Period
(d)
Costs Incurred DuringPeriod Accunt Charged(b) (c)
Account Credited
With Reimbursement
(e)
Description
(a)
Transmission Studies1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 GlQ0251
23 GlQ0252
24 GlQ0253
25 GlQ0191
26 Customer Studies Accruals
27 GlQ0122
28 GlQ0125
29 GlQ0122
30 GIQ0179
31 GIQ0180
32 GlQ0181
33 GlQ0182
34 GIQ0183
35 GIQ0184
36 GIQ0185
37 GIQ0186
38 GlQ0232
39 GlQ0203
40 GIQ0184
___w
430 561.7
923 561.7
233 561.7
233 561.7
4,025) 561.7
456 561.7
4,733 561.7
327 561.7
3,097 561.7
1,823 561.7
1,803 561.7
1,618 561.7
2,245 561.7
2,137 561.7
1,915 561.7
1,649 561.7
413 561.7
1,33 561.7
792 561.7
43 456.2
923 456.2
233 456.2
233 456.2
4,025) 456.2
FERC FORM NO. 111-FI3-Q (NEW. 03-7)Page 231.9
ine
No.Description
(a)
Transmission Studies
Costs Incurr During
Period Accunt Charged(b) (c)
eim ursements
Recived During
the Period
(d)
Account Credited
With Reimbursement
(e)
............................................
Name of Respondent
PacifiCorp
This ~rtls: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 0311/20
Tramissio Servce and Generation Intercnnecion Stud Costs (continued)
Year/Period of Report
End of 2008/04
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generion Studies
22 GlQ0185
23 GlQ0186
24 GlQ0125
25 GIQ0122
26 GlQ0126
27 GlQ0123
28 GlQ0124
29 GlQ0203
30 GlQ0207
31 GlQ0179
32 GIQ0180
33 GlQ0181
34 GlQ0182
35 GIQ0183
36 GlQ0222
37 GlQ0223
38 GlQ0224
39 GIQ0184
40 GIQ0185
---
46 561.7
46 561.7
19,409 107
4,558 107
12,222 107
7,36 107
3,66 107
55,164 107
1,518 107
10,96 107
9,026 107
2,09 107
6,098 107
6,38 107
3,36 107
8,817 107
22,012 107
8,880 107
6,90 107
FERC FORM NO. 1/1-FI3-Q (NEW. 037)Page 231.10
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008/04
This ~rt Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 03131/2009
Transmission Service and Generation Interconnection Study Cots (continued)
ine
No.
eim ursments
Recived During
the Period
(d)
Account Credited
With Reimbursement
(e)
Costs Incurred During
Period Account Charged(b) (c)Description
(a)
Transmission Studies1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 GIQ0186
23 GlQ0232
24 GlQ0233
25 GIQ237A, GIQ237B, GIQ237C
26 GlQ0224
27
28
29
30
31
32
33
34
35
36
37
38
39
40
---
3,957 107
62 107
15,86 107
9,048 107
345 107
FERC FORM NO.1/1-FI3-Q (NEW. 03-7)Pag 231.11
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp I (2) A Resubmission 0311/20 200/04
FOOTNOTE DATA
¡Schedule Page: 231 Line No.: 2 Column: a
AJef 412890,412896,412899,412902,412905,413567, 413571, 413576, 413580, 412911
¡Schedule Page: 231 Line No.: 9 Column: a
~f 417112,417114,417116,417118
¡Schedule Page: 231 Line No.: 16 Column: a
~f 484637,484639,484641,484643,484645,484647,484649, 484651, 484653, 484655, 484657, 484659, 484661
¡Schedule Page: 231 Line No.: 19 Column: a
AJef 504111,504113,504115,50117,504121,504123,504125, 504127, 504129, 504131, 504133, 504135, 504137, 504139
¡Schedule Page: 231.1 Line No.: 10 Column: a
AJef 464709,465219,465221,465224,465226
¡Schedule Page: 231.1 Line No.: 27 Column: a
GIQ0102, GIQ0103, GIQ0104, GIQ0105, GIQ0106
... ..........................................
Blank Page
(Next Page is 232)
FERC FORM NO. 113.0 (REV. 02-()Page 232
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008104
(2) D A Resubmission 03131/200
o HER REGULA TORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for conc~ming 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 Bance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beinning of wmien oll uunng wmin oll uunng Currnt CuarterNear
Currnt the CuarterNear thePenod
CuerNear Accunt Charged Amount
(a)(b)(c)(d)(e)(f)
1 California DSM Regulatory Ast (24898 32,217 908 1,078,585 -1,001,355
2 Idaho DSM Regulatory As 4,251,758 4,814,83 90 5,374,86 3,691,734
3 Utah DSM Regulatory As (40,156)34,68,831 431,908 26,66,514 7,622,161
4 Wasington DSM Regulatory As (1,09,675)6,061,769 431,90 5,03,709 -6,615
5 Wyoming DSM Regulatory As (10)282,62 89,69 908 62,260 310,06
6 DSM Regulatory Asts Accruals 3,68,45 1,779,44 5,464,896
7 caif. Altematie Rate For Energy (CARE)1,742,225 89,94 2,640,174
8 Transion Plan - OR (10)10,05,172 930.2 3,89,30 6,161,872
9 200 Transiton Plan - WA (3)1,62,72 920 66,151 955,571
10 200 Transion Plan. 10 (3)1,83,58 920 610,194 1,220,389
11 200 Transion Severance Co . wy (3)4,780,00 920 2,124,44 2,655,556
12 FAS 109 Defe Income Taxes Elecc 4554,491 282 18,80,706 439,741,785
13 SB 1149 Implementatin Cos OR RetH Acc (5)4,49,68 90,89 407.3 4,58,576 2
14 IDAI Cos No. CA Direc Acc (5)30,34 407.3 30,34
15 SC 781 Direc Acc Shopping Incentive 520,471 412,477 407.3 93,793 -85
16 Glenro Mine Exduding Recamation UT (9)2,428,82 930.2 1,30,39 1,126,424
17 Deferre Exce Net Power Cos - OR UE116 149,807 11,824 161,631
18 Deerre Exce Net Power Cos - wy (1)68,619 8,39 555 88,012
19 Deferr Exce Net Power Cos - CA 758 27,09 555 1,26,79 -475,407
20 Defe Exce NPC - WY 207 (1)29,lli,115 4,491,38 555 24,96,142 8,63,35
21 Deerr Exce Net Power Cos - WY 08 24,231,911 24,231,911
22 OR sa 408 Recvery (1)213,05 213,05
23 Environmentl Co (10)7,05,54 1,172,34 925 1,193,011 7,03,873
24 Environmental Co - WA (10)(453,691)75,49 925 169,90 -548,100
25 Re As - Environmental Cos 1,561,95 2,915,35 4,477,314
26 Cholla Plant Transactn Cos (26)10,756,572 557 1,122,424 9,63,148
27 Cholla Plant Transaion Coss - OR (26)(515,709)53,813 -41,896
28 Cholla Plnt Transaction Cos - WA (26)(92,64)97,00 -82,637
29 Cholla Plant Transaction Cos - 10 (26)(315,99 32,974 -283,021
30 Washington Colstnp 1t3 (22)68,62 456 52,188 630,63
31 FAS 133 Denvative Net Regulatory As 256,02,770 186,118,35 442,142,129
32 As Rerement Obligatins Regulatory Diffrence 52,85,40 14,674,73 230 10,245,517 57,282,618
33 FAS 158 Pension/Oter Pos Ret/SERP 22,2,93 36,256821 il 28,65,42 563,859,32
34 RTO Goo West NI Reg As 1,131,721 182.3 1,078,54 53,172
35 Contra Reg Ast - ATO Gnd Wes (1,131,721)1,078,54 -53,172
36 RTO Goo West NIR - OR 87,879 74,46 953,339
37 RTO Goo Wes NIR - WY (3)414,09 90 184,04 230,055
38 RTO Goo West NI - 10 (5)108,64 90 27,163 81,48
39 Deferr UT Independent Evaluator Fee 30,511 760,2 235 1,154,00 -93,250
40 Derr Intervenor Fundng Grnt - 10 28,86 35,180 928 28,86 35,160
41 Derr Intervnor Fundng Grant - OR 56,108 178,73 928 1,00,74a -26,89
42 Deferr Intervenor - CA (1)251,2 928 70,m 180,429
43 Defere Ind Evaluator Fee - OR 1,23,615 1,23,615
44 TOTAL 1,081,739,789 704,214,401 159,60,460 1,626,353,730
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ei A Resubmission 03131/200
o HER REGULATORY ASSETS (Accunt 182.3)
1. Report below the particulars (details) called for con~ming 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 Purpse of Balnce at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beinning of vvniien 011 uunng vvOlen 011 uunng Currnt OuartrNear
Current the QuartNear the Perid
OuarterNear Accunt Charged Amount
(a)(b)(c)(d)(e)(f)
1 BPA Wasington Balancing Accunt 1,94,285 440,442 624,617 1,317,66
2 BPA Oreon Balancing Acnt 29,678 440,442 29,678
3 BPA Idaho Balancing Accnt 1,33,44 590,578 1,926,018
4 OR Renewable Adjustment Clause 1,63,65 11,32,60 12,96,257
5 Reg Ast . Lake Side Damages 1,051,00 1,051,00
6 SB 408 Regulatory Ast - OR (1)27,00,00 142 14,217,240 12,782,760
7 5B 408 Regulatory Aset - MCBIT 169,88 241 191,95 -22,043
8 Deferred Ex NPC. WA Hydro (3)6,35,750 555 33,30 6,017,44
9 Regulator Asts - Recass 2,139,23 254 190,240_
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 1,081,739,789 704,214,401 159,60,46 1,62,353,730
FERC FORM NO. 113-0 (REV. 02-()Page 232.1
$1,001,355
64,615
845
475,407
93,250
266,896
22,043
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2l An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 2oo8/Q4
FOOTNOTE DATA
¡Schedule Page: 232 Line No.: 22 Column: d
Account 440
Account 442
Account 444
¡Schedule Page: 232 Line No.: 33 Column: d
Pensions and benefits are char ed to fuctional accounts, whch is consistent with where labor is cha 00.
SChedule Pa e: 232.1 Line No.: 9 Column: f
The following is a reconcilation of the reguatory asse reclassification account:
Reclassified from Reguatory Asset to Regulatory Liabilties:
Californa DSM Reguatory Asse
Washingtn DSM Reguatory Asset
Sch 781 Diect Acces Shopping Incetive
Deferred Excess Net Power Cos - CA
Deferred UT Indepndent Evaulatr Fee
Deferrd Intervenor Funding Grts - OR
SB 408 Reguatory Asset - Mærr
YTD
December 31,2008
Reclassified from Reguatory Liabilites to Reguatry Asse:
Washington Low Income Progr
$
24,581
1,948,992
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
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(Next Page is 233)
FERC FORM NO.1 (ED. 12-9)Page 233
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ei A Resubmission 0331/20
M SCELLANEOUS DEFFERED DEBITS (Accunt 186)
1.Report below the particulars (details) called for concerning 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.Deferrd Debits Beginning of Year ~çcoun!.Amount End of Year
(a)(b)(c)
cicæed
(e)(f)
1 Joseoh Settlement (20)1,385,256 557 137,380 1,247,876
2
3 Lacomb Irriaation (24)64,890 557 45,720 598,170
4
5 Bogus Creek (42)1,324,400 557 41,280 1,283,120
6
7 Mead Phoenix Availabiltv
8 & Trans Charge (50)14,89,04 56 377,760 14,512,280
9
10 TGS Buvout (23)186,972 557 15,474 171,498
11
12 Hermiston Swa (40)4,907,56 557 171,693 4,735,871
13
14 Deferred Lonowall Costs 572,639 3,44,414 151 2,838,668 1,178,385
15
16 Point to Point Transmission 898,257 917,762 142 66,256 1,155,763
17
18 Deferre Coal Costs - Wyodk
19 Settlement (22)5,02:,727 151 335,182 4,692,545
20
21 Deferr Coal Costs - Arch
22 Settlement (3)7,06,98 151 2,762,514 4,30,468
23
24 Deferred Colstrip Plant Costs 118,061 118,061
25
26 Jim Boyd Hvdro Buvout (11)50,06 557 82,86 421,205
27
28 Credit Aomt Costs (5)2,399,94 431 478,448 1,921,498
29
30 PCRB LOC/SBBPA Costs (5)1,137,801 427 461,747 676,054
31
32 PCRB Mode Conversion Costs (10)518,04 427 128,04 390,00
33
34 '94 Series Restruct. Costs (16)751,985 427 5,961 746,024
35
36 Emission Reduction Creits 40,98 40,980
37
38 LGIA L T Transmission Prepaid 12,303,50 2,071,4,831,728 9,542,974
39
40 Leae Incentives (11)1,33,231 232,385 454.1 145,149 1,425,467
41
42 LT Lease Comm Preod (10)921,200 931 88,39 83,801
43
44 BPA L T Trasm Preoad 2,400,00 7,488,00 9,88,00
45
46 RTO Grid West N/R- WA (5)164,293 90 46,941 117,352
47 Misc. Work in Progress
48 ueterrEK Heguiatory GOm.
Expnses (See oa09 350 - 351)
49 TOTAL 52,116,892 72,80,09
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008104
(2) ri A Resubmission 03131/200
M SCELLANEOUS DEFFERED DEBITS (Accunt 186)
1.Report below the particulars (details) called for concerning 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 Balane at
No.Deferred Debits Beginning of Year 8ccoum,Amount End of Year
(a)(b)(c)
C~aled
(e)(f)
1
2 Lae Side Mant. PreDavment 6,913,029 107 835,498 6,077,531
3
4 PreDaid Outaae Maintenance 15,794,54 107 9,519,953 6,274,592
5
6 Other Deferred Debits with
7 balances less than $50,00 186,083 various 94,508 91,575
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Misc. Woi1 in Progres
48 I Deferred Regulatory COmm.
Expnses (See pages 35.351)
49 TOTAL 52,116,892 72,80,09
FERc FORM NO.1 (ED. 12-9)Page 233.1
IFERC FORM NO.1 (ED. 12..S7) Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 0311/200 20/04
FOOTNOTE DATA
IShedule Page: 233 Line No.: 38 Column: d
Account 107
Account 165
Account 232
Account 419
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03/31/2009
ACCU~ ULATED DEFERRED INCOME TAX S (Accunt 190)
1.Report the information called for below concerning the respondent's accunting for deferred income taxes.
2.At Other (Specify), include deferrals relating to other income and deductions.
Line uescnption ana Location ~No.of Year of Year
(a)(b) c)
1 Electric
2 Employee Benefits 139,413,272 246,078,312
3 FAS 133 Derivatives 106,959,021 168,654,420
4 Regulatory Liabilty 43,693,148 41,530,110
5
6
7 Other 142,263,119 130,677,283
8 TOTAL Electric (Enter Total of lines 2 thru 7)432,328,560 586,940,125
9 Gas
10
11
12
1~
14
1f Other
16 TOTAL Gas (Enter Total oflines 10 thru 15
17 Other (Specify)
18 TOTAL (Aec 190) (Total oflines 8, 16 and 17)432,328,560 586,940,125
Notes
FERC FORM NO.1 (ED. 12-8)Page 234
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 0331/20
CAPITAL STOCKS (Account 201 and 2l4
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filng, a specific reference to report form (I.e., 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.
Une Class and Series of Stock and Number of shares Par or Stated Call Price at
No.Name of Stock Series Auhorized by Charer Value per share End of Year
(a)(b)(c).(d)
1 Common Stock (Account 201)750,00,00
2 PacifiCorp is a wholly
3 owned indirec subsidiary of
4 MidAmerican Energy Holdings Company
5
6 TOTAL COMMON STOCK 750,00,00
7
8
9 Preferred Stock (Accunt 20):
10 5% Cumulative Preferred 126,533 100.00 110.00
11
12
13 Serial Preerred, Cumulative:3,500,00
14 4.52% Series 100.00 103.50
15 7.00% Series 100.00
16 6.00% Series 100.00
17 5.00% Series 100.00 100.00
18 5.40%8eries 100.00 101.00
19 4.72% Series 100.00 103.50
20 4.56% Series 100.00 102.34
21 No Par Serial Preferred 16,00,00
22
23 TOTAL PREFERRED STOCK 19,626,53
24
25
26
27
28
29
30
31i-E32i-33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED. 12-91)Page 25
............................................
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) riA Resubmission 03131/200
CAPITAL STOCKS (Account 201 and 2 14) (Continued)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT Line(Total amount outstanding without reduction AS REACQUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
Sl1ares A~Runt ~l1ares Gpst ~n¡¡res Amount(e)(g)(h)(i)ü)
357,060,915 3,417 ,94,896 1
2
3
4
5
357,060,915 3,417,945,896 6
7
8
9
126,243 12,624,30 10
11
12
13
2,06 20,50 14
18,046 1,804,60 15
5,930 593,00 16
41,908 4,190,80 17
65,959 6,595,90 18
69,890 6,989,00 19
84,592 8,459,200 20
21
22
414,63 41,46,300 23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED. 12-8)Pag 251
IFERC FORM NO.1 (ED. 12-87) Page 45.1
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/209 2004
FOOTNOTE DATA
Column:d
Oregon Public Utility Commssion, Doket No. UF-4228, Order No. 06-417, date July 17, 2006.
Washigton Utiities and Transporttion Commssion, Docket No. UE-060974, Order No.1, date June 28, 2006.
Idao Public Utities Commsion, Cae No. PAC-E-07, Order No. 300, date July 7, 2006.
As of Decmber 31, 2008, 30,00,00 shas authrize; 30,00,00 available.
............................................
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(Next Page is 253)
FERC FORM NO.1 (ED. 12-87)Page 253
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ei A Resubmission 0331/200
OT iER PAID-IN CAPITAL (Accounts 2m 211, inc.)
Report below the balance at the end of the year and the information specified below for the respeve other paid-in caita acounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for recnciliation with baance sheet, Page 112. Add more
columns for any accont if deemed necessary. Explain changes made in any accunt during the year and give the accunting entries efecing such
change.
(a) Donations Received from Stockholders (Accunt 208)-Stte amount and give brief explanation of the origin and purpe of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 20): State amount and give brief explanation of the caital 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 Reacquire Cal Stock (Acunt 210): Reprt balance at beginning of year, credits, debits, and balance at end
of year with a designation of the nature of eac creit an debt idenified by the clas and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Account 211)-Clasif amounts incuded in this acunt according to caions which, together with brief explanations,
disclose the general nature of the trasactions which gave rise to the reported amounts.
i~e ii:r A'Wunto.
1 Account 211 Miscellaneous Paid-in Caital
2 Additional Paid-in Capital
3 Share based payments
4 Tax benefit from stock option exercises
5 Benefit plan separation
6 Capital contributions
7 Gain on sale of Scottish Power stock
8 Qualified production acivity ta deuction
9 Contribution of Intermountain Geothermal
10 Adoption of FASB Interpretation No. 48
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40 TOTAL 8n,06,95
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp (2) A Resubmission 03/31/2009 200/04
FOOTNOTE DATA
¡Schedule Page: 253 Line No.: 3 Column: b
Represents Ù1e income ta deduction attbutable to Ù1e exercise of stok options granted by Scottsh Power pIc, of which $3,502,924
relate to options exercised durg Ù1e year ended December 3 I, 2007. Ths deduction is requi to be recorded though an
aclustment to additional aid-in-ca itaL.
hedule Pa e: 253 Line No.: 4 Column: b
Represents Ù1e income ta deduction attbutable to Ù1e exercise of stock options grante by Scottsh Power pIc. This deducton is
required to be recorded thugh an adjustmnt to additional paid-in-capita.
¡Schedule Page: 253 Line No.: 5 Column: b I
Represents Ù1e effect of trferrg benefit plans to PPM Energy, Inc. as a result of Ù1e sale of PacifCorp by Scotth Power pIc. This
is requied to be recorded thugh an adjustment to additional paid-in-capita.
¡Schedule Page: 253 Line No.: 6 Column: b I
Represents capita contrbutions to PacifCorp (wiÙ1 no shes of stok issued) from its indirect parent MidAerican Energy Holdings
Company ("MEHC"), of which $450,00,00 were made durg Ù1e yea ended Decembr 31, 2008.
Išhedule Page: 253 Line No.: 7 Column: b
Represents a realzed ga on stock relate to separtion of PPM Energy, Inc. parcipants from Ù1e deferred compnsation plan,
required to be recorded in additional paid-in-capita.
¡SChedule Page: 253 Line No.: 8 Column: b
Represents an equity adjustment relate to IRC 199 qualed production activities.
¡SChedule Page: 253 Line No.: 9 Column: b
Represents contrbution of Intermunta GeÙ1erm Company to PacifCorp from MEHC in Marh 200, subseuent to Ù1e sale of
PacifCorp to MEHC. Intermounta GeoÙ1erm Company was merged wiÙ1 and into its direct parnt, PacifCorp, on Augut 31,
200, wiÙ1 PacifCorp surving.
Išhedule Page: 253 Line No.: 10 Column: b I
Represents Ù1e increase in paid-in capita resulting frm Ù1e Januar 1, 2007 adoption ofFASB Interpretation No. 48, "Accountig for
Uncertty in Income Taxes - an interpretation ofFASB Statement No. 109."
IFERC FORM NO.1 (ED. 12-S7) Page 45.1
FERC FORM NO.1 (ED. 12-87)Page 254b
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 03/31/20
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.
I Line liias ana :senes or :stOCk tsaiance at End of Year
No.(a)(b)
1 Common Stock 41,101,062
2
3 Preferred Stock:
4 5.00% Serial 98,049
5 4.52% Serial 9,676
6 4.72% Serial 30,349
7 4.56% Serial 49,071
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22 TOTAL 41,288,207
............................................
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(Next Page is 256)
FERC FORM NO.1 (ED. 12-9)Page 256
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008104
(2) FiA Resubmission 03/31/2009
L )NG- TERM DEBT (Accunt 221, 222, 223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accunts 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 accunts. 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 wih 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 expnses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) rearding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a fotnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accunts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expnse,
No.(For new issue, give commission Authorizaion numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 Bonds: (Accunt 221)
2 First Mortgage Bonds:
3
4 4.300% Series due september 15, 2008 200,000,000 1,322,659
5 288,000 D
6 8.271% Series due October 1, 2010 48,972,000
7 7.978% Series due Ocober 1,2011 4,422,000
8 6.900% Seris due November 15, 2011 500,000,000 3,567,009
9 1,735,000 D
10 8.493% Series due October 1,2012 19,772,000
11 8.797% Series due October 1, 2013 16,203,000
12 5.450% Series due September 15,2013 200,000,000 1,422,659
13 232,000 D
14 4.950% Series due August 15, 2014 200,000,000 1,442,365
15 728,000 D
16 8.734% Series due Ocober 1,2014 28,218,000
17 8.294% Series due October 1,2015 46,946,000
18 8.635% Series due Ocober 1, 2016 18,750,000
19 8.470% Series due October 1, 2017 19,609,000
20 500,000,000 3,007,359
21 905,000 D
22 7.700% Seris due November 15, 2031 300,000,000 2,874,150
23 864,00 D
24 5.900% Series due August 15, 2034 200,000,000 1,892,365
25 722,000 D
26 5.25% Series due June 15, 2035 300,000,000 2,912,055
27 1,080,000 D
28 6.10% Series due August 1, 2036 350,000,000 2,908,372
29 1,141,000 D
30 5.75% Series due April 1, 2037 600,000,000 589,216
31 24,000 D
32
33 TOTAL 6,032,262,000 63,060,499
............................................
Name of Respondent This ì!rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008104
(2) CiA Resubmission 03131/200
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 iong-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 securiies 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 (Total amo~n~t~~~~ging without UneNominal Date Date of Interest for Year No.of Issue Maturity Date From Date To reduction for amounts tìald by Amount
(d)(e)(f)(g)
resPlh'dent)
(i)~2
3
09/151203 09/1512008 09/1512003 09/151200 6,091,667 4
5
041511992 10/01/2010 0415/1992 10/01/2010 9,145,OO 1,007,925 6
04/1511992 10/01/2011 04/15/1992 10/01/2011 1,144,OO 110,715 7
11/1512001 11/15/2011 11/15/201 11115/2011 SO,OO,OO 34,500,000 8
9
0415/1992 10/01/2012 0415/1992 10/01/2012 6,64,OO 649,799 10
041511992 10101/2013 0415/1992 10/01/2013 6,535,00 641,323 11
09/1512003 09/1512013 11/1512001 09/15/2013 20,00,00 10,90,00 12
13
0824120 081512014 08124/200 08115/2014 20,00,00 9,90,00 14
15
04/1511992 10/01/2014 04/15/1992 10101/2014 12,90,00 1,231,079 16
04/1511992 10/01/2015 04/15/1992 10/01/2015 23,30,00 2,081,n3 17
041511992 10/01/2016 0415/1992 10101/2016 10,290,00 94,820 18
041511992 10/01/2017 04/15/1992 1010112017 11,46,00 1,023,261 19
07117/200 07/1512018 07/17/2008 07/15/2018 500,00,00 12,869,44 20
21
11/1512001 11/1512031 11/15/201 11/15/2031 30,00,00 23,100,00 22
23
081241200 08151203 08141200 08115/2034 20,00,00 11,80,00 24
25
06131200 061512035 061312005 0615/2035 30,00,00 15,750,00 26
27
08101200 0801/2036 08110/200 08101/203 350,00,00 21,350,00 28
29
03141207 04/01/2037 031141207 04/01/2037 60,00,00 34,500,00 30
31
32
5,510,797,00 316,04,36 33
FERC FORM NO.1 (ED. 12-9)Pag 25
FERC FORM NO.1 (ED. 12-9)Page 256.1
.............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCor (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 03/31/2009
L JNG- TERM DEBT (Accunt 221, 222, 223 and 224)
1. Report by balance sheet accunt the partculars (details) concerning long-term debt included in Accunts 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 accunts. 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 expnses, premium or discunt should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortzed debt expense, premium or discount associated wih
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 Accunts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issue Premium or Discount
(a)(b)(c)
1 6.25% Series due October 15, 2037 600,000,000 5,127,281
2 750,000 Dt2II300,000,000 2,254,415
4 1,671,000 D
5 6.375% Series H Medium-Ter Notes due May 15, 2008 200,000,000 1,416,179
6 64,000 D
7 7.00% Series H Medium-Term Notes due Jut 15,2009 125,000,000 1,976,904
8 451,250 D
9 9.15% Series C Medium-Term Notes due Aug. 9, 2011 8,000,00 75,327
10 8.95% Series C Medium-Ter Notes due Sept. 1,2011 25,00,000 175,398
11 8.95% Series C Medium-Term Notes due Sept. 1,2011 20,00,000 132,118
12 8.92% Series C Medium-Term Notes due Sept. 1,2011 20,000,000 188,318
13 8.29% Series C Medium-Term Notes due Dec. 30, 2011 3,000,000 23,040
14 8.26% Series C Medium-Term Notes due Jan. 10,2012 1,000,000 7,649
15 8.28% Seris C Medium-Term Notes due Jan. 10,2012 2,000,00 13,297
16 8.25% Series C Medium-Term Notes due Feb. 1,2012 3,000,000 22,946
17 8.13% Series E Medium-Term Notes due Jan. 22, 2013 10,000,000 75,827
18 8.53% Series C Medium-Term Notes due Dec. 16,2021 15,000,000 115,202
19 8.375% Series C Medium-Term Notes due Dec. 31, 2021 5,000,000 38,400
20 8.26% Series C Medium-Term Notes due Jan. 7, 2022 5,000,000 33,243
21 8.27% Series C Medium-Term Notes due Jan. 10,2022 4,000,000 30,594
22 8.05% Series E Medium-Term Notes due Sept. 1,2022 15,000,000 131,471
23 8.07% Series E Medium-Term Notes due Sept. 9, 2022 8,000,000 70,118
24 8.12% Series E Medium-Term Notes due Sept. 9, 2022 50,000,00 438,238
25 8.11 % Series E Medium-Term Notes due Sept. 9, 2022 12,000,000 105,177
26 8.05% Series E Medium-Term Notes due Sept. 14,2022 10,000,000 87,648
27 8.08% Series E Medium-Term Notes due Oct. 14,2022 26,000,000 208,198
28 8.08% Series E Meium-Term Notes due Oct. 14,2022 25,000,000 200,190
29 8.23% Series E Medium-Term Notes due Jan. 20, 2023 5,000,000 37,914
30 8.23% Series E Medium-Term Notes due Jan. 20, 2023 4,000,00 30,331
31 -81,560 P
32 7.26% Series F Medium-Term Notes due July 21, 2023 27,000,000 246,981
33 TOTAL 6,032,262,OOC 63,060,499
............................................
Name of Respondent This i!rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008104
(2) Ei A Resubmission 03131/2009
LONß-TERM DEBT (Account 221,222,22 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortzation 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 U4tstan!J1n8 Line
Nominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reducton for amounts lìeld by Amount
(d)(e)(f)(g)
reslXl;dent)
(i)
10/032007 10/15/2037 1010312007 10/15/207 60,00,00 37,500,00 1
2
07/17/2008 07/1512038 07/17/2008 07/15/2038 30,00,00 8,678,333 3
4
05/1211998 05/1512008 05/1211998 05/15/200 4,781,250 5
6
07/1511997 071512009 07/15/1997 07/151200 125,00,00 8,750,00 7
8
0809/1991 08109/2011 08109/1991 08109/2011 8,00,OO 732,00 9
0811611991 09/01/2011 08116/1991 09/01/2011 25,OO,OO 2,237,500 10
0811611991 09/01/2011 08116/1991 09/01/2011 20,00,00 1,790,000 11
081611991 09/01/2011 0811611991 09/01/2011 20,00,00 1,784,00 12
12131/1991 121302011 12131/1991 12130/2011 3,OO~248,700 13
01/09/1992 01/10/2012 01/09/1992 01110/2012 1,00,00 82,60 14
01/1011992 01/10/2012 01/10/1992 01/10/2012 2,00,00 165,60 15
01/15/1992 02101/2012 01115/1992 02101/2012 3,OO,OO 247,500 16
01/20/1993 01/2212013 01/20/1993 01/222013 10,OO,OO 813,00 17
1211611991 1211612021 1211611991 1211612021 15,OO,OO 1,279,500 18
12131/1991 12131/2021 12/1/1991 12131/2021 5,00,OO 418,750 19
01/0811992 01/07/2022 01/0811992 01/07/2022 5,OO,OO 413,00 20
01/09/1992 01/1012022 01/09/1992 01/10/2022 4,OO,OO 330,80 21
09/1811992 09/01/2022 09/1811992 09/01/2022 15,00,OO 1,207,500 22
09/09/1992 09/09/2022 09/09/1992 09/09/2022 8,OO,OO 64,600 23
09/11/1992 09/09/2022 09/11/1992 09/09/2022 5O,00,OO 4,06,00 24
09/11/1992 09/09/2022 09/11/1992 09/09/2022 12,00~973,200 25
09/1411992 09/1412022 09/14/1992 0911412022 10,OO~00 805,00 26
1011511992 10/1412022 10/15/1992 10/141202 26,00,OO 2,100,80 27
10/1511992 10/1412022 10/1511992 10/1412022 25,00,OO 2,020,00 28
01/2011993 01/2012023 01/20/1993 01/20/2023 5,OO,OO 411,500 29
01/2911993 01/2012023 01/29/1993 01/20/2023 4,OO,OO 329,200 30
31
07/221993 07/2112023 07/221993 07/21/2023 27,OO,OO 1,96,20 32
5,510,797,00 316,049,36 33
FERC FORM NO.1 (ED. 12-9)Page 257.1
FERC FORM NO.1 (ED. 12-9)Page 256.2
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 03/31/2009
L lNG-TERM DEBT (Accunt 221,222,223 and 224)
1. Report by balance sheet accunt the particulars (details) concerning long-term debt included in Accunts 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 accunts. Designate
demand notes as such. Include in column (a) names of associated companies frm 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 wi 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 Accunts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give comission Autriion numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 7.26% Series F Medium-Term Notes due July 21, 2023 11,000,000 100,622
2 7.23% Series F Medium-Term Notes due Aug. 16,2023 15,000,000 137,211
3 7.24% Series F Medium-Term Notes due Aug. 16,2023 30,000,000 274,423
4 6.75% Series F Medium-Term Notes due Sept. 14,2023 5,000,000 38,250
5 6.75% Series F Medium-Term Notes due Sept. 14,2023 2,000,000 15,300
6 6.72% Series F Medium-Term Notes due Sept. 14,2023 2,000,000 15,300
7 6.75% Series F Medium-Term Notes due Oct. 26, 2023 20,000,000 152,326
8 6.75% Series F Medium-Term Notes due Oct. 26, 2023 16,000,000 121,861
9 6.75% Series F Medium-Term Notes due Oct. 26, 2023 12,000,000 91,396
10 6.71% Series G Medium-Term Notes due Jan. 15,2026 100,000,000 90,467
11 Subtotal - First Mortgage Bonds 5,293,892,000 48,205,459
12
13 Pollution Control Obligations - Secured by Pledged First Mortgage Bonds:
14
15 Poll Ct Rev Refunding Bonds, Moffat County, CO, Series 1994 40,655,000 874,159
16 5-518% Poll Ctrt Rev Refunding Bonds, Lincoln County, WY, Series 1993 8,300,000 228,980
17 197,125 D
18 5.65% Poll Ctrl Rev Refunding Bonds, Emery Count, Utah, Seris 1993A 46,500,000 1,624,793
19 5-5/8% Poll Ctr Rev Refunding Bonds, Emery County, Utah, Seris 1993B 16,400,000 625,551
20 389,500 D
21 Poll Ctrt Rev Refunding Bonds, Swetwter County, WY, Series 1994 21,260,000 510,479
22 Poll Ctrt Rev Refnding Bonds, Converse County, WY, Seres 1994 8,190,000 209,777
23 Poll Ctrt Rev Refnding Bonds, Emery Count, UT, Seris 1994 121,940,000 3,274,246
24 Poll Ctrt Rev Refunding Bonds, Carbon County, UT, Series 199 9,365,000 206,519
25 Poll Ctrt Rev Refunding Bonds, Lincoln County, WY, Series 1994 15,060,000 422,858
26 POLL Ctrt Rev Refunding Bonds, Converse County, WY, Series 1988 17,000,000 155,970
27 Poll Ctrt Revenue Bonds, Swetwter Count, WY, Series 1984 15,00,000 122,887
28 105,000 D
29 Poll Ctrt Rev Refunding Bonds, Lincoln Cnty, WY, Seris 1991 45,000,000 771,836
30 Poll Ctrt Revenue Bonds, City of Forsyth, MT, Series 1986 8,500,000 304,824
31 Environ. Imprvnt Rev Bonds, Converse County, WY, Seris 1995 5,300,000 132,043
32 Environ. Imprnt Rev Bonds, Lincoln Count, WY, Series 1995 22,000,000 404,262
33 TOTAL 6,032,262,000 63,060,499
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008104
(2) 0 A Resubmission 03131/2009
LON 3-TERM DEBT (Acount 221,222,22 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD uuisianp~ns LineNominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reuction for amounts held by Amount
(d)(e)(f)(g)
resPlh'dent)
(i)
07/22199 07/21/2023 07/2211993 07/21/2023 11,00,00 798,60 1
081611993 081612023 08116/1993 081612023 15,00,00 1,084,500 2
08/1611993 08/1612023 08/1611993 0811612023 30,00,000 :?,172,00 3
09/1411993 09/14/2023 09/14/1993 09/14/2023 5,00,00 337,500 4
09/1411993 09/1412023 09/1411993 09/14/2023 2,00,00 135,00 5
09/14/1993 09/14/2023 09/14/1993 09/1412023 2,00,00 134,40 6
10/2611993 10/2612023 10/2611993 10/262023 20,000,00 1,350,00 7
10/2611993 10/2612023 10/2611993 10/2612023 16,00,00 1,080,00 8
10/2611993 10/2612023 10/2611993 10/262023 12,00,00 810,00 9
01/2311996 01/15/2026 01/2311996 01/15/2026 100,00,00 6,710,000 10
4,n2,427,00 287,829,339 11
12
13
14
11/17/1994 05/01/2013 11/17/199 05/01/2013 40,655,00 1,639,918 15
11/15/1993 11/01/2021 11/15/1993 11/01/2021 8,300,00 476,83 16
17
11/15/1993 11/01/2023 11/15/1993 11/01/2023 46,500,00 2,683,050 18
11/15/1993 11/01/2023 11/15/1993 11/01/2023 16,40,00 942,180 19
20
11/17/1994 11/01/2024 11/17/1994 11/01/2024 21,260,00 975,021 21
11/171994 11/01/2024 11/17/1994 11/01/2024 8,190,00 376,483 22
11/17/1994 11/01/2024 11/17/199 11/01/2024 121,94,00 5,489,163 23
11/17/1994 11/01/2024 11/17/1994 11/01/2024 9,36,00 373,212 24
11/17/199 11/01/2024 11/17/199 11/01/2024 15,06,00 705,107 25
01/01/1988 01/01/2014 01/01/1988 01/01/2014 17,00,00 680,352 26
12101/1984 12101/2014 12101/1984 12101/2014 15,00,00 600,357 27
28
01/17/1991 01/01/2016 01/17/1991 01/01/2016 45,00,00 1,64,032 29
12101/1986 12101/2016 12101/1986 12101/2016 8,500,00 359,450 30
11/17/1995 11/01/2025 11/17/995 11/01/2025 5,30,00 224,251 31
11/17/1995 11/01/2025 11/17/1995 11/01/2025 22,00,00 952,642 32
5,510,797,00 316,049,36 33
FERC FORM NO.1 (ED. 12-96)Page 257.2
FERC FORM NO.1 (ED. 12-9)Page 25.3
............................................
Name of Respondent This 'ì0rt Is:Date of Report Year/Period òf Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008lQ4
(2) nA Resubmission 03131/2009
L )NG- TERM DEBT (Accunt 221, 222, 223 and 224)
1. Report by balance sheet accunt the particulars (details) concerning long-term debt included in Accunts 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 descrption of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accunts. 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 pnncipal 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 Accunts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expnse,
No.(For new issue, give commission Authorizaion numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 Subtotal Pollution Control Obligations - Secured by Pledged First Mortgage Bonds 400,470,000 10,560,809
2
3
4 Pollution Control Obligations - Unsecured
5
6 Poll Ctrl Rev Refndng Bonds, Swtwter Cnt, WY, Ser. 1992A 9,335,000 167,524
7 Poll Ctrl Rev Refndng Bonds, Swetwter Cnty, WY, Ser. 1992B 6,305,000 151,908
8 Poll Ctrl Rev Refndng Bonds, Convers County, WY, Series 1992 22,485,000 242,163
9 Poll Ctrl Rev Refndng Bonds, Swetwter Cnty, WY, Ser. 1988B 11,500,000 84,822
10 Poll Ctrl Rev Refdng Bonds, Sweetwter County, WY, Ser. 1990A 70,000,000 660,750
11 Poll Ctrl Rev Refng Bonds, Emery County, UT, Series 1991 45,000,000 872,505
12 Poll Ctrl Rev Refndng Bonds, Swetwter Cnty, WY, Ser. 1988A 50,000,000 422,443
13 Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Seris 1988 45,000,00 380,198
14 Poll Ctrl Rev Refndng Bonds, City of Gilette, WY, Ser. 1988 41,200,000 351,905
15 Environ. Imprvmnt Rev Bonds, Sweetwter County, WY, Series 1995 24,400,000 225,000
16 6.150% Environ. Imprvnt Rev Bonds, Emery County, UT, Seris 1996 12,675,000 556,549
17 178,46 D
18
19 Subtotal - Pollution Control Obligations - Unse 337,900,000 4,294,231
20
21
22
23 TOTAL ACCOUNT 221 6,032,262,000 63,060,499
24
25
26
27
28
29 Advances from Asociated Companies: (Accunt 223)
30
31
32
33 TOTAL 6,032,262,OQ 63,060,499
............................................
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ei A Resubmission 03/31/200
LON i-TERM DEBT (Account 221, 222, 22 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Exense, 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 yeàr, (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 u4(Slan~l~LineNominal Date Date of (Total amount outsta ing without Interet for Year No.of Issue Maturity Date From Date To reduction for amounts Iield by Amount
(d)(e)(f)(g)respY~dent)
(i)
40,470,00 18,118,053 1
2
3
4
5
09/2911992 12/01/2020 09/29/1992 12/01/2020 9,335,00 338,272 6
09/29/199 12/01/2020 09/29/1992 12/01/2020 6,305,00 227,027 7
09/29/1992 12/01/2020 09/29/1992 12/01/2020 22,485,00 812,615 8
01/01/1988 01/01/2014 01/01/1988 01/01/2014 11,50,00 301,085 9
07/25/1990 07/01/2015 07/25/199 07/0112015 70,00,00 1,980,549 10
OS/2311991 07/01/2015 OS/2311991 07/01/2015 45,00,00 1,290,742 11
01/01/1988 01/01/2017 01/01/1988 01/01/2017 50,00,00 1,341,954 12
01/01/1988 01/01/2018 01/0111988 01/01/2018 45,00,00 1,181,175 13
01/01/1988 01/01/2018 01/01/198 01/01/2018 41,200,00 1,206,375 14
12/141199 11/01/2025 12/14/1995 11/01/2025 24,40,OOC 642,66 15
09/2411996 09/01/2030 09/2411996 09/01/2030 12,675,00 779,513 16
17
18
337,90,00 10,101,971 19
20
21
22
5,510,797,00 316,049,36 23
24
25
26
27
28
29
30
31
32
5,510,797,00 316,049,36 33
FERC FORM NO.1 (ED. 12-9)Page 257.3
FERC FORM NO.1 (ED. 12-9)Page 25.4
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) riA Resubmission 03131/200
LJNG-TERM DEBT (Accunt 221,222,223 and 224)
1. Report by balance sheet accunt the particulars (details) concerning long-term debt included in Accunts 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 advance on notes and advances on open accunts. 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.
Indicae 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 wih
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 Accunts.
Line Class and Series of Obigation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 Other Long-Term Debt: (Accunt 224)
2
3 TOTAL ACCOUNT 224
4
5
6 ..cu,
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33 TOTAL 6,032,262,000 63,060,499
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ei A Resubmission 03131/200
LON ~-TERM DEBT (Accont 221, 222, 22 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Accunt 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 Asociated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD (Total amo~itt~~~~~ing without Line
Nominal Date Date of Interest for Year No.of Issue Maturity Date From Date To reduction for amounts lìeld by Amount
(d)(e)(f)(g)
resPl~nt)
(i)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
5,510,797,00 316,049,36 33
FERC FORM NO.1 (ED. 12-9)Page 257.4
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp ;2) A Resubmission 03131/2009 200Q4
FOOTNOTE DATA
¡Schedule Page: 256 Line No.: 1 Column: i I
Total interest expens of $316,049,363 does not include $2,476,375 of interest received while PacifiCorp temporaly held certn
pollution control revenue bonds.
For fuer inormation regarding long-term debt, refer to Note 9 of Notes to Financial Stateents included in ths Form No.1.
¡Schedule Page: 256 Line No.: 20 Column: a
In July 2008, PacifiCorp issued $500 millon of its 5.65% Firt Mortge Bonds due July 15,2018. State commssion authorizations
for this issuace were as follows:
Oregon Public Utility Commssion, Docket No. UF-4243, Order No. 08-013, dated Janua 14,2008.
Idao Public Utilty Commssion, Ca No. PAC-E-07-16, Orer No. 30489, dated Janua 22,2008.
¡Schedule Page: 256.1 Line No.: 3 Column: a
In July 2008, PacifiCorp issued $300 millon of its 6.35% Firs Mortage Bonds due July 15,2038. State commssion authoritions
for ths issuace were as follows:
Oregon Public Utility COmmssion, Docket No. UF-4243, Order No. 08-013, dated Janua 14,2008.
Idao Public Utilty Commssion, Cas No. PAC-E-07-16, Order No. 30489, dated Janua 22,2008.
ISchedule Page: 256.3 Line No.: 26 Column: a I
In September 2008, PacifiCorp acquire $216 millon of its inur vaable-rate ta-exempt bond obligations due to the significant
reduction in market liquidity for insured varable-rate obligations. In November 2008, the associated insurce and related stdby
bond purchase agreements were teted and these varable-ra long-te debt obligations were remaketed with crdit
enancement and liquidity support provided by $220 millon of letrs of credit issued under PacifiCorp's two unecurd revolving
credit failties.
¡Schedule Page: 256.4 Line No.: 6 Column: a
For authorization for the issuace of long*term debt ($2.0 bilion authorid; $1.2 bilion available as of Decmber 31, 2008), refer to
page 104, Important Changes During the Year, Item 6, of ths Form No.1.
Autorization to borrow the procs of polluton contrl revenue refuding bonds issued (total of $300,345,000 authorized and
available as of December 31, 2008) by the Counties of Emery, Uta; Caon, Uta; Converse, Wyoming; Lincoln Wyomig;
Sweetwater, Wyoming; and Mofft, Colorao;
Autorization to borrow the proceds of new pollution control revenue bonds issued (total of$150,000,000 authorize and available as
of December 31, 2008) by one or more of the followig counies or muncipalities: Emery, Uta; Converse, Wyomig; Lincoln
Wyomig; Sweeater, Wyoming; City of Gilett, Wyoming; Navajo County, Arna; and Rout County, Colorado is as follows:
Oregon Public Utilty Commssion, Docket No. UF-4250, Order No. 08-382, date July 29, 2008.
Idao Public Utilties Commssion, Case No. PAC-E-08-05, Order No. 30606, dated Augst 4, 2008.
............................................
Blank Page
(Next Page is 261)
-13,859,302
-27,392,44
2,763,498
-24,539,64
-50,009
-540,673
-69,028
18,610
............................................
RECONCILIATION OF REP
Date of Report
(Mo, 08, Yr)0331/20
INCOME FOR F DERAL INCOME TAXES
Year/Period of Report
End of 2008/04
Name of Respondent
PacifiCorp
1. Report the recncilation of reported net incme for the year with taxble income used in coputing Federal income ta acruls and show
computation of such tax accruals. Include in the reconcilation, as far as practicale, the same detail as fumished on Schedule M-1 of the tax retum for
the year. Submit a renciliation even though there is no taxble income for the year. Indicate clearly the nature of each recciling amount.
2. If the utilty is a member of a group which files a consolidaed Federa tax retum, reoncile reported net incoe with tale net income as if a
separate return were to be field, indicating, however, intercmpany amounts to be eliminated in such a consolidated retum. State names of group
member, tax assigned to each group member, and bais of allotion, assignment, or sharing of the consolidated ta among the group members.
3. A substitute page, designed to meet a particular nee of a copany, may be used as Long as the dat is consistent and meets the requirements of
the above instruions. For elecronic reprting purpes complete Line 27 and provide the substitute Page in the context of a footnote.
axble Income Not Reported on Books
1,599,355,018
5,441,058
-39,598,007
Page 261
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/200 200/04
FOOTNOTE DATA
¡SChedule Page: 261 Line No.: 8 Column: a
Paricular (Detls)
Contrbutons in Aid of Constrcton
Reimbursements
Avoided Costs
Deferred Exces Net Power Costs - CA
Deferred Excess Net Power Costs - WY
il MEHC 2006 Trasition Costs
781 Shopping Incentive
Reg liabilty BPA balancing accounts
Reg Liabilty - UT Home Energy Lifeline
Reg Liabilty - W A Low Energy Progr
OR Reg Asset/iabilty Consolidation
Orgon Gai on Sale
Mach 2006 Trasition Plan Costs - W A
Se. 263A Inventory Change - PMI
Accrd Royalties
NW Power Act - WA
SMU Revenue Imputation - UT reg liab
Equity Earings in Subsidiares
Total
Amounts
65,247,545
2,196,309
61,014,506
1,233,703
20,472,760
610,194
521,316
1,281,218
252,482
17,383
470,103
1,239,225
668,151
1,217,884
696,688
624,616
207,540
1.905,654
159,877,277
¡Schedule Page: 261 Line No.: 13 Column: a
Pariculars (Detils)
FedState Tax Expense
% capitalized labor costs for Powert input
Meals & Entertinment
Penalties
Penaties - PMI
Lobbying expenses
Meals & Entertinment - Bridger Coal
MEHC Inurance Serices - Premium
Mining Rescue Training Credit Addback
PMI Fuel Tax Credit
Mining Rescue Traning. PMI
30% capitaized labor costs for Powert input
Book Depreiation
Book Depreciation - PMI
Book Cost Depletion - Addback
Book Depletion - SRC
Book Depletion-Step up basis adjusent
May 2000 Traition Plan Costs - OR
Glenrock Excluding Reclamtion - UT
Reg Asset - F AS 158 Post Ret Liab.
Envionmenta Costs - W A
Cholla PIt Tra Cost - APS Amort
W A Disallowed Colstp #3 - Writeoff
Wyomig PCAM DefNet Power Cost
IDAI Cost - direc access
SB 1149-Related Reguatory Asset
Deferr Intervener Funding Grants
RTO Grd West Note Receivable - Allowace
IFERC FORM NO.1 (ED. 12-87)
Amounts
238,515,739
1,590,858
738,260
510,618
138,682
1,221,209
18,198
6,969,001
36,254
15,978
13,755
6,535,202
485,189,941
13,190,668
2,157,064
206,936
98,385
3,892,299
1,302,399
15,178,614
94,409
938,633
52,188
880,619
305,346
448,454
831,003
1,078,549
Page 450.1
RTO Grid West Notes Receivable - WY
RTO Grid West Notes Receivable - il
Cont Pension Reg Asset MM & CTG - OR
Contr Pension Reg Asset MM & CTG - WY
Reg Asset - Pension MMT - UT
Contr Pension Reg Asset CTG - UT
Contr Pension Reg Asset MM & CTG - CA
Contr Pension Reg Asset CTG - W A
Reg Asset - Post - Ret MM - UT
Unrecoverd Plant - Powerdale
Defered UT Independent Evaluation Fee
Reg Asset balance reclass
Trojan Decomissioning Costs - Reguatory
SB 1149 Costs
Post Merger Loss-Reacq Debt - Addback
Coal Pile Inventory Adjustment
Prepaid Insurance - mEW 157 contgen resee
RTO Grd West Note Receivable - w/o - WA
Deferrd Coal Cost - Arch
TGSBuyout
Laeview Buyout
Joseph Setement
Hermston Swap
F AS 133 Derivatives - Curt
ARO Reg Liabilties
Non-ARO Liabilly - Reg Liabilty
Reg Liabilty - OR Energy Conservation Che
Reg Liabilty - Blue Sky Progr W A
Reg Liabilty - Blue Sky Progr CA
Reg Liabilty - Blue Sky Prgr UT
Reg Liabilty - Blue Sky Progr il
Reg Liabilty - CA Gain on Sae of Asset
Reg Liabilty - UT Gain on Sale of Asset
Reg Liabilty - il Gain on Sale of Asset
Reg Liabilty - WY Gain on Sale of Asse
Self Inured Health Benefit
Vaction Accrl - Cash Basis (2.5 mos)
Severance Accrul - Cash Basis
FAS 133 Derivatives - noncurnt
F AS 143 ARO Liabilty
Bad Debts Allowace - Cas Basis
Bear River Setement Agment
Rogue River - Habitat Enhcement Liabilty
Lewis River Settement Agrement
Misc DefDr - Prop Damge Repai
N. Umpqua Setement Ageement
Umpqua Settement Agreement
Reverse Accrued Final Reclamation
PMI EITF04-6 Pre-Strpping Costs
Injuries and Damges Acc - Cash Basis
FAS 112 Book Reserve
Bridgr Coal Company ARO - Liabilty
Coal Mine Developent - PMI
IFERCFORM NO.1 (ED. 12-87)
184,044
27,162
11,821,555
5,311,868
289,308
16,886,329
1,022,338
3,138,141
284,683
4,365,259
393,761
190,240
1,464,600
4,045,224
4,223,214
2,298,001
15,184
46,941
2,762,514
15,474
43,280
137,381
171,693
65,683,730
97,517
25,093,146
775,874
5,781
12,660
332,106
30,523
45,034
1,019,355
156,434
352,888
708,350
1,893,488
26,539
122,738,278
5,611,655
882,108
468,675
20,017
138,815
34
1,165,477
583,489
778,291
1,300,189
2,377,902
502,513
140,894
7,300,703
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/2009 2004
FOOTNOTE DATA
Page 45.2
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/2009 2oo8lQ4
FOOTNOTE DATA
F AS 115 Mark to Market Accru - Bridger - Reclass
Bridger Coal Company Reclamtion Trut Earng - PMI
Total
¡Schedule Page: 261 Line No.: 18 Column: a
Pariculars (Detils)
MERC Inurance Servces - Receivable
Medicare Subsidy
PMI Overriding Coal Royalty % DepletionAFC
Basis Intgible Difference
GainIoss on Prop. Disposition
Book Gainlss on Land Sales
OR - RCAC Sep-Dec 07 Defered
OR SB 408 Recovery
OR Rate Refuds
Reg Liab - OR Balance Consol
West Valley Lease Reduction - CA
West Valley Lease Reduction - ID
West Valley Lease Reducton - WY
West Valley Lease Reduction - UT
DefReg Asset - Tranmission Srvc Deposit
DefReg Asset - Foote Creek Contr
Deferrd Regulatory Expense
Tenat Lease Allow - PSU Call Cntr
Uneaed Joint Use Pole Contact Revenue
Idao Customer Balancing Account
Bridger Coal Company Gaioss on Assets Disposed
MCI FOG Wire Lease
Redding Contract - Prepaid
Tota
I$hedule Page: 261 Line No.: 25 Column: a
Paricular (Detils)
PPL Pre - 1943 Preferred Stock Div - Deduction
Uta Deferred Comp / COLI
Bridger Coal Company Depletion - PMI
Dividend Received Deduction
Tax Depreciation
Depreciation (Tax Depreciation M-l) - PMI
Capitaize Depreciation
Coal Mine Development
Coal Mine Extension
Removal Costs
Cholla SHL-NOPA (Lease Amortization)
ARO - reclass to ARO liabiles
ARO - reclass to reg assets/iabilty & ARO liabilty
Tax Percentae Depletion - Deduction
DTA 105.154 Section 383 capita loss caorward
Tax Depletion
Fixed Asset - Book!ax
ARO Reg Assets
Reg Asset - F AS 158 Pension Liab Adj.
Envionmenta Clean-up Accrl
DefReg Asset - OR DefNet Power Costs
IFERC FORM NO.1 (ED. 12-87) Page 450.3
CA Deferred Intervenor Funding
Reg Asset - Lake Side Liq.
Contr - RTO Gnd West N/R Allowace
RTO Gnd West Notes Receivable - OR
Reg Asset - Defered OR Independent Evaluator Fees
Deferred Excess Net Power Cost - WY 08
Deferred Excess Net Power Cos - W A Hydro
WY - 2006 Traition Severce Cost
Weatherition
Reguatory Asset - Net F AS 133
Trapper Minng Stock Basis
Prepaid Taxes - OR PUC
Prepaid Taxes - UT PUC
Prpaid Taxes - ID PUC
Oter Prepaid
Prepaid Taxes - Propert Taxes
WY Joint Water Board Reserve - Deducton
Energy trding derivatives - cunt
Energy tring derivatives - nonct
Wasach worker comp resee
CA-Califomia Alterntive Rate for Ene Prgr (CAR)
A&G Credit - W A
A&G Credit - CA
A&G Creit - ID
A&G Credit - WY
Reg Liabilty - Blue Sky Program OR
Reg Liabilty - Blue Sky Program WY
Reg. Liabilty - Deferred Benefit - Arh Setlement
Deferrd Compensation Accral - Cash Basis
Pension / Retirement Accl - Cash Basis
Accred CIC Severace
FAS 158 Pension Liabilty
FAS 158 Post-Retrement Liabilty
FAS 158 SERP Liabilty
Distrbuton O&M Amort ofWriteff
M&S Inventory WriteOff
Amort of Projects - Klamath Engieeng
R & E - Sec.74 Deduction
Oter Environmental Liabilties
Duke/Hennston Contract Renegotiation
BP A Consrvation Rate Credit
Tral Mountain Accrued Liabilties
Misc. Non*Curent Accrued Liabilty
Misc. Curent and Accrued Liabilty
Deerr Revenue - Citiban
West Valley Contr Termaton Fee Accur
PMI Devt Cost Amort
Microsoft Soft License Liabilty
Misc. Defered Credits
Amort NOPAs 99-00 RA
Bridger Coal Company ARO - Reg Asse
Coal Mine Extnsion Costs - PP&E - PMI
Bridger Coal Company Underground Mine Cost Depletion
IFERCFORM NO.1 (ED. 12-87)
(180,429)
(1,051,000)
(1,078,549)
(74,460)
(1,236,614)
(24,231,911)
(6,017,444)
(2,655,556)
(9,547,863)
(186,118,359)
(1,392,041)
(124,784)
(197,014)
(57,134)
(43,034)
(185,449)
(300,000)
(1,258,283)
(983,795)
(297,563)
(897,949)
(428,241)
(41,623)
(225,623)
(34,04)
(181,358)
(3,486)
(1,960,857)
(2,125,011)
(121,895)
(10,308,150)
(30,166,468)
(11,604,974)
(762,000)
(168,548)
(697,985)
(970)
(11,506,537)
(181,464)
(754,839)
(564,504)
(2,355,141)
(3,073,156)
(1,182,500)
(80,595)
(6,601,499)
(3,556,057)
(532,374)
(230,000)
(256,755)
(140,894)
(2,237,229)
(172,447)
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/2009 200/04
FOOTNOTE DATA
Page 45.4
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 0311/2009 2008/04
FOOTNOTE DATA
F AS 115 Unrealized GainIoss
Bridger Coal Company Extction Taxes Payable - PMI
Vacation Accrul - PMI
Total
(16,914,432)
(79,909)
008.413)
(1,599,355,018)
¡Schedule Page: 261 Line No.: 40 Column: b
As a result of the sale ofPacifiCorp to MEHC on March 21, 2006, Berkshire Hathaway commenced including PacifiCorp in its
United States federal income ta retu. PacifiCorp's provision for income taes has been computed on the basis that it files
separte consolidated income ta retu. Pror to the sae, PacifiCorp was included in the consolidated United States feder
income ta ret ofPacifiCorp Holdings, Inc., PacifiCorp's former parent company.
Nam of group members who win tile a conslidate Federal Tax Retum:
UnderMEHC:
PPW Holdings LLC Sub-Group:
PacifiCorp
PPW Holdings LLC
PacifiCor Sub-Group:
Centralia Mining Company
Energy West Minig Company
Glenrock Coal Company
Interwest Mining Company
Pacific Minerals, Inc.
PacifiCorp Environmental Remediation Company
PacifiCorp Futu Generations, Inc.
PacifiCorp Investment Mangement, Inc.
MEHC Sub-Group:
Acaemy of Real Estte, Inc
Allertn Capita, Ltd
America Pacific Finance Company
Amercan Pacific Finance Company II
CalEnerg Company, Inc
CalEnergy Generation Operating Company
CalEnergy Holdings, Inc
CalEnergy Imperial Valley Company, Inc
CalEnergy Interntional Services, Inc
CalEnerg Interntional, Inc
CalEnergy Mineras LLC
CaEnergy Pacific Holdigs Corp
CalEnergy UK Inc
Caitol Intermediar Company
Capitol Lan Exchage, Inc
Capitol Title Company
CBEC Railway, Inc
CBSHome Real Estte Company
CBSHome Real Estate ofIowa Inc
CBSHome Relocation Serces, Inc
CE Admnisttive Servces, Inc
CE Elecc (N, Inc
IFERC FORM NO.1 (ED. 12-87)
CE Electc, Inc
CE Exploration Compan
CE Geothermal, Inc.
CE Indonesia Geothermal, Inc
CE Inteationa Investments, Inc
CE Power, Inc
Champion Realty, Inc
Chancellor Title Servces, Inc
Cimmed Leaing Company
Columbia Title of Florida, Inc
Cordova Funding Corporation
Dakota Dunes Development Company
DCCO,Inc
Edina Financial Servces, Inc
Edina Rety Refer Network
Edina Realty Relocation, Inc
Edina Realty Title, Inc
Edina Realty, Inc
Esslinger- Wooten-Maxell, Inc
E-W-M Referral Serces, Inc.
FFR Inc
Fir Realty, Ltd
Page 450.5
MEHC Sub-Group (continued):
First Reserve Insurce, Inc
For Rent, Inc
HMSV Financial Serces, Inc
HN Real Estae Group N.C., Inc.
HN Real Estate Group, LLC
HN Referr Corporation
HomeServces Fincial Holdings, Inc
HomeServces Financial, LLC
HomeServices Financial-Iowa LLC
HomeServces Inurce, Inc
HomeServces of Alabama, Inc.
HomeServces of AJerica, Inc
HomeServces of California, Inc
HomeServces of Florida, Inc
HomeServces of Iowa, Inc
HomeServices of Kentucky, Inc
HomeServces of Nebraska Inc
HomeServces of Nevada, Inc
HomeServices of the Carolinas, Inc
HomeServices Pacific Nortwest Inc.
HomeServices Relocation, LLC
HSR Equity Funding, Inc
Huf Commercial Group, LLC
Huf-Drees Realty, Inc.
IMO Company, Inc
InterCoast Capital Company
Interoast Energy Company
InterCoast Sierra Power Company
Iowa Realty Company, Inc
Iowa Realty Insurance Agency, Inc
Iowa Title Company
IWGC08
J.S. White Associates, Inc
mRC, Inc.
JD Reece Mortgage Company
Jenny Pritt & Associates
Jim Huff Realty, Inc.
JP&A,Inc
JRW Realty, Inc d//a RealtySouth
Kasas City Title, Inc
Ker River Funding Corpration
KR Holding, LLC
Larabee School of Real Estate & Inurce
MEC Constcton Servces Company
MEHC Insurce Servces Ltd.
MEHC Invesent, Inc
Meto Uniform
MHC Investment Company
MHC,Inc
Mid-AJerica Refer Netork, Inc.
MidAerca Comercial R.E. Servces, Inc
MidAerca Ener Company
MidAercan Energy Holdings Company
MidAerca Serces Company
Midlad Escrow Servce, Inc
Midwest Capita Group, Inc
Midwest Gas Company
MWR Capita, Inc
Nebraska Lad Title & Abstr Company
Nortern Aurora Inc
Nortern Nat Ga Compan
Pickford Escw Compay, Inc
Pickford Real Estate, Inc
Pickford Servce Company, Inc
Prfer Carlinas Realty, Inc
Prfessiona Refer Orgazation, Inc
Qu Cities Energy Company
Real Estate Lin, LLC
Real Estate Refer Network, Inc
Reece & Nichols Allance, Inc
Reece & Nichols Realtors, Inc
Referrl Company of Nort Caolina, Inc
Robe Brothers, Inc
Roy H. Long Realty Company, Inc
Salton Sea Minerals Corpration
San Diego PCRE, Inc
Semoni Realtors, Inc
The Escrow Fir
The Referr Company
Trinity Mortgae Parers, Inc
Two Rivers, Inc
Woods Bros. Realty, Inc
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/200 20004
FOOTNOTE DATA
With Respect to members of the MEHC Sub-Group, MEHC requires all subsidiares to payor receive from MEHC an
amount of ta basd primaly on the stad alone method of allocon. The computation includes all ta beefits from ta
deductons stemmg from cost borne by utility cumers.
Berkshire Hathway Inc. Sub-Group:
21st Communities, Inc.
21 st Mortage Corporation
21st SPC, Inc.
AAS-Lunen, Inc.
Acme Brick Block and Tile, Inc.
Acme Brick DFW, Inc.
Acme Brick Sales Compay
Acme Building Brands, Inc.
Acm Investent Company
Acme Investment Company
IFERC FORM NO.1 (ED. 12-87) Page 450.6
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 2008/Q4
FOOTNOTE DATA
Berkshire Hathway Inc. Sub-Group:
Acme Brick Compy
Acme Management Company
Acme Ochs Brick and Stone, Inc.
Acme Services Company, L.P.
Adalet/Scott Fetz Company
ABG Processing Center No. 58, Inc.
ABG Processing Center No. 35, Inc.
Agile Mfg, Inc.
AJ Warehouse Distrbutors, Inc.
ALflEX Homes, Inc.
Alachua Tung Oil Company
Albecca Inc.
Alexader City Flying Servces, Inc.
All Bilt Uniform
Alpha Cargo Motor Exress, Inc.
American All Risk Inurce Servces, Inc.
American Centennal Insurce Company
America Commercial Claims Admstrtors, Inc.
American Dai Quen Corporation
American Employers Group, Inc.
American Tile Supply, Inc.
Andersn Hardwood Floors, Inc. (fka Shaw-Raor Floors)
Apeks Apparl, Inc.
Applied Group Inurance Holdings, Inc.
Applied Invesgations Inc.
Applied Logisitics, Inc.
Applied Premum Finance, Inc.
Applied Processing Center No. 60, Inc.
Applied Risk Services of New York, Inc.
Applied Risk Services, Inc.
Applied Underwter, Inc.
Ardent Risk Services
AU Captive Risk Assurane Co
AU Captive Risk Assurance Co., Inc.
AU Holding Company, Inc.
AUI Employer Group No. 42, Inc.
Ben Bridge Jeweler, Inc.
Benjamn Moore & Co.
Berkshir Hathaway Credit Corp.
Berkshi Hathaway Finance Corporation
Berkshie Hathaway Inc. (Common Parnt)
Berkshire Hathaway Life Inurce Co. ofNE
Berksire Hathaway Assurance Company
BH Columbia Inc.
BH Fince, Inc.
BH Shoe Holdings, Inc.
BHG Strcted Setlements, Inc.
BNJ Netets, Inc.
Boat U.S. Travel Interntional, Ltd.
BHRInc.
Boat America Corporation
Boat U.S., Inc.
IFERC FORM NO.1 (ED. 12-87)
Blue Chip Staps
Boot Royalty Company
Borsheim Jewelr Company Inc.
BR Agency, Inc.
BHSF,Inc.
Bricker-Mincolla Uniform
Brillant National Servces, Inc.
British Inurance Company of Caym
Brooks Sport, Inc. & Subsidiar
Brookwood Ince Company
Business Wire Caad Inc.
Business Wire, Inc.
C & R Inurce Servces, Inc.
California Employer Group No. 27, Inc.
Californa Inurce Company
Camp Manufactg Company
Campbell Hausfeld/Scott Fetzer Company
Carefr/Scott Fet Company
Centrl States Indemnty Co. of Omah
Centr Staes of Om Companes, Inc.
CG Servce, Inc.
Chippewa Shoe Company
CJE II, Inc.
Claims Services, Inc.
Clayton Commercial Buildings, Inc.
Clayton Homes, In.
CM Capita, Inc.
CM Hodgenville, Inc.
CMH Homes, Inc.
CMH Manufactg West, Inc.
CMH Manufg, Inc.
CMH ofKY, Inc.
CMH Parks, Inc.
CMH Serces, Inc.
CMH Set and Finish, Inc.
Cologne Reinsurance Company of America
Cologne Servces Corporation
Columbia Inurce Company
Combined Claims Servces, Inc.
Command Uniform
Commercial Caslty Inurce Company
Commercial General Indemnty, Inc.
Commonwealth Uniform In.
Complementa Coatings Corporation
Contienta Divide Insurce Co.
Contienta Indemnty Company
Cornusker Casualty Compay
CORT Business Serces Corporation
Covere Dycs Group, Inc.
Criteron Inurce Agency
Cross Crek Apparel, LLC
Crowley Ganent Mf Co Inc.
Page 450.7
Berkshire Hathway Inc. Sub-Group:
Crowley Shirt Mfg Co Inc.
CSI Life Inurce Company
CTB Credit Corp.
CTB International Corp.
CTB IP, Inc.
CTB MN Investments Co. Inc.
CTB, Inc.
Cumberland Asset Manement, Inc.
Cyress Inurce Company
Dairy Queen Corporate Stores, Inc.
Dairy Queen of Georgia, Inc.
Denver Brick Company
Dextr Shoe Company
DQ Funding Corporation
DQ Joint Ventw Stores, Inc.
DQ Manged Store, In.
DQ Wholly-Owed Stores, Inc.
DQF, Inc.
DQG,Inc.
Eastech Chemical, Inc.
Edmonds Material and Equipment Co.
Elm Str Corporation
Employers Insurce Services, Inc.
Eureka Brick and Tile Company
Executive Jet Europe, Inc.
Executive Jet Manement, Inc.
Expertos, SA de C.V.
Faireld Insurance Co.
Fary Capital Limited
Fariors, Inc.
Finial Holdings, Inc.
Final Insurance, Inc.
Finial Reinsurce Company
Firt Berkshie Hathaway Life Insurce Company
FlightSafety Capital Corp.
Flighafet China, Inc.
FlightSafet Development, Inc.
FlightSafet Intertional Inc.
FlightSafet New York, Inc.
FlightSafety Properies, Inc.
FlightSafet Services Corpration
Flighafet Texa, Inc.
Floors Inc.
Footwea Investment Company
Forest River Financial Servces, Inc.
Forest River Housing, Inc.
Forest River Warty Company
Forest River, Inc.
Frace/Scott Fetr Company
Fredom Warehous Corp.
Frut of the Loom Carbbean Inc.
Frut of the Loom Texa, Inc.
Frut of the Loom Trading Company
Frut of the Lom, Inc.
Frut of the Loom, Inc.
FSI Delawa Holding Corp.
FTL Regional Saes Co., Inc.
FT Saes Company, Inc.
Ga Centrl Amerca Corp.
Ga Incorporated
Ga Manufactg Corp
Garan Serices Corp
Gateway Underwters Agency, Inc.
GEICO Casuaty Compay
GEICO Corpration
GEICO Geer Inurce Company
GEICO Indemty Company
GEICO Prduct, Inc.
Ge Re Capita Consultats, Inc. f/a Gener Re
Gen Re Intediares Corporation
Genera Re Assets Investment (I), Inc.
General Re Corporate Fince, Inc.
General Re Corporation
General Re Financial Products Corporation
General Re Funding Corporation
Geeral Re Investment Holdings Corporation
Gener Re New Engand Asse Management
Geer Re Serces Corporation
Geer Reinurce Corporation
Gener Sta Indemnty Company
Generl Sta Management Company
Generl Sta National Inurce Company
Geesis Indemty Insurance Company
Genesis Insurance Company
Genesis Professional Liabilty Underters
Genesis Underwiting Management Company
GenRe Gisboure LLC
Giles Industres, Inc.
GMK Ltd.
Golden Skillet Interntional, Inc.
Goverent Employees Financial Corporation
Governent Employees Insurce Company
GRD Corporation
GRD Global, Inc.
GRD Holdings Corporation
Griffey Uniform
H.H. Brown Shoe Compay,Inc.
H.H. Brown Shoe Technologies, Inc.
H.J. Jus and Sons, Inc.
Halex/Scott Fetzer Company
Hall of Fame Paint Supply Inc.
Hady Fraes, Inc.
Has Uniform
Hason Uniform
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 2008104
FOOTNOTE DATA
IFERC FORM NO.1 (ED. 12-87) Page 450.8
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0311/2009 2008/04
FOOTNOTE DATA
Berkshie Hathaway Inc. Sub-Group:
lIS Redevelopment Corporation
Helzberg's Diamond Shops, Inc.
Henley Holdings, LLC
Hohm & Bard, Inc.
Homefirst Agency, Inc.
Homemaers Plaz, Inc.
Indecr Group Inc. d//a J.C.Licht Company
Inovative Building Product, Inc.
Inurce Counselors of Nevada, Inc.
Insurce Counelors,Inc.
International America Group, Inc.
International America Management Company
International Dairy Queen, Inc.
International Insurce Underwtes, Inc.
Isabela Shoe Corporation
J. S. Justin, Inc.
Janovic/Plaz Inc.
1M Contracing Servces, Inc.
John Manvile China LTD.
John Manville Corporation
John Manville, Inc.
Jordan's Furtue, Inc.
Justin Belt Company, Inc.
Justin Boot Company
Justin Brads, Inc.
Justin Industres, Inc.
Kale Uniform
Kasas Baners Sur Compay
Kaelkorn Shoppe, Inc.
Kay Uniform
Kleberg Holdings, Inc.
LA Termnals, Inc.
Leeburg Yam Mils, Inc.
M & C Products, Inc.
Maco Retaling, Inc.
Mapletee Trasporttion, In.
MarneSafet Interntional, Inc.
Marin Maufacg Company
Marn Mils, Inc.
Marland Ventues, Inc.
McCain Uniform Company Inc.
McCar-Hull Cigar Company, Inc.
McLane Company, Inc.
McLane Eas Inc.
McLae Express, Inc.
McLae Foodserce, Inc.
McLae Mid-Atlantic, Inc.
McLane Midwest, Inc.
McLae Minnesota, Inc.
McLae New Jersy, Inc.
McLane Sout Inc.
McLane Suneast, Inc.
IFERC FORM NO.1 (ED. 12-87)
McLane Western Inc.
Medical Protectve Corpration
Medical Protectve Finance Corporation
Medical Protectve Inurance Services, Inc.
Medical Protective Risk Retention Servces, Inc.
MH Trasport Inc.
Miler Sage, Inc.
MiTek Frangs, Inc.
MiTek Holdings, Inc.
MiTek Industres, Inc.
MiTek, Inc.
MM Corpration
Mobile Disaster Strctus, Inc.
Mossy Oak Apparel Company
Mount Vernon Fire Inurance Company
Mountain View Marketing, Inc.
Mouser Electonics, Inc.
MS Propert Compay
MT Sub, Inc.
Nationa Fire & Marne Inurance Co.
National Indemty Company
National Indemity Company of Mid-Amerca
Natonal Indemnty Company of the Sout
National Liabilty & Fire Inurce Co.
National Reinsurce Corporation
Nationwide Uniform
Nebraska Furtue Mar Inc.
NetJet Aviation Inc.
Netet Eurpe Holdings LLC
NetJets Inc.
NetJets Inteationa Inc.
Netet Lage Aicraft, Inc.
Netets Leasing, Inc.
Netets M E Inc.
NetJets Sales Inc.
Netet Servces Inc.
NetJet U.S., Inc.
NFM of Kasa, Inc.
Nick Bloom Uniforms
NJ Executive Serces Inc.
NJA Jet Inc.
NJE Holdings LLC
Nfl Sales Inc.
Nfl, Inc.
Nocona Boot Company
Nort American Casuaty Co
Nort Sta Reinsurce Corporation
Nort Sta Syndicate, Inc.
Nort States Agency, Inc.
Nortand/Scott Fet Company
Oak River Insurce Company
OBHInc.
Page 450.9
Silver State Uniform
Simon's Incorprate
Simpad Inc.
Soco West, Inc.
som Shoe Company, Inc.
Sol Fra Uniform Inc.
Somerst Servces
Southern Energy Homes of Nort Carolina, Inc.
Southern Energy Homes of Pennylvana, Inc.
Souter Energy Homes Retil Corp.
Souter Energy Homes, Inc.
StaSco Fet Company
Sta Furtu Compy
Stonydge Tru
S1rgic Sta Manment, Inc.
Strck Mexica S.A.
Techncal Coatings Co.
The Ben Bndge Corpration
The BVD Licensin Corp.
The Eagle Company
The Fechheimer Brothers Co.
The Inecor Grup, Inc.
The Kosovich Company, Inc.
The Medcal Proteve Company
The Pam Chef Nort Amenca, Ltd
The Pam Chef, Ltd
The Scott Fet Compan
TM Custom Air Systems, Inc.
Tony Lama Company
Top Five Club, Inc.
TPC - European Holdings, Ltd.
Tranco, Inc.
TTl, Inc.
U.S. Investment Corpration
U.S. Liabilty Insurce Company
U.S. Underwters Insurance Company
Undergaent Fashions, Inc.
Unified Supply Cha Inc.
Uniform of Texa
Union Sales, Inc.
Union Underea Co., Inc.
Unione ltaliana Reinsurce Company of Amenca, Inc.
United Consumer Finacial Serces, Inc.
Unite Dirct Finace Inc.
United States Aviation Underte, Inc.
Univer Uniform
Vanderbilt ABS Corp.
Vanderbilt Mortgage & Finace, Inc.
Vanderbilt Propert & Casuaty Inurce Co., Ltd.
Vanderbilt SPC, Inc.
Vanty Fai Brads, Inc.
Vanty Fai Inc.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/200 20004
FOOTNOTE DATA
Berkshire Hathway Inc. Sub-Group:
OCSAP,Ltd.
Old City Paint & Decrating, Inc.
Orange Julius of Amenca
Pan-Am Shoe Co., Inc.
Pima Uniforms
Pinnacle Paint & Deorating, Inc.
PJR Management Inc
Plaz Financial Servces Co.
Plaz Resources Co.
Ponce Fashions, Inc.
Portand Gold Corp. d//aJ Maine Paint Servce
Precision Brad Produc
Precision Stel Warehous - Chalott
Precision Stel Warehouse - Frain Park
Pnonty One Fincial Serces, Inc.
Pro Installations, Inc.
Professional Dataolutions, Inc.
Promesa Health Inc.
Queen Caret Corporation
R.C.Wiley Home Furshigs
Rabun Apparel, Inc.
Railsplittr Holdings Corporation
Rainbow State Paint & Decoraing In.
Redwood Fir and Casualty Inurce Co.
RENTCO Trailer Corporation
Resolute Management Inc.
Ringwalt & Liesche Co
Robert £ deCastro Inc.
Robert Men's Shop
Runing with Heels (Micro Retling, Inc.)
Russell Brads LLC (f/a Russell Corporation)
Russell Fincial Services, Inc.
Salado Sales, Inc.
Scott Feter Financial Group, Inc.
ScottCare Corporation
Seattle Paint Supply, Inc.
Seaworty Inurce Company
See's Candies, Inc.
See's Candy Shops, Inc.
Seventeenth Street Reaty, Inc.
Shaw Contr Floonng Intalation Servces, Inc.
Shaw Contrct Floonng Servces, Inc.
Shaw Diversified Services, Inc.
Shaw Floors, Inc.
Shaw Funding Company
Shaw Induses Group, Inc.
Shaw Induses, Inc.
Shaw Internationa Servces, Inc. (tk Shaw Finacial Ser)
Shaw Retal Properties, Inc.
Shaw Tranport Inc.
SHX Floorig, Inc.
SHX Leasing, Inc.
IFERC FORM NO. 1 (ED. 12-S7) Page 45.10
.............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0311/2009 200/Q4
FOOTNOTE DATA
Berkshire HathawaY Inc. Sub-Group:
Vanity Fair Ventues, Inc.
Ventas Insurce Group, Inc.
Vessel Assist Association of America, Inc.
Vessel Assist Inurance Servces, Inc.
VFI-Mexico, Inc.
Virginia Paint Co., Inc.
Vision Retaling
Wayne/Scott Feter Company
Waynesburg Shirt Company Inc.
Wenco Financial, Inc.
Wesco Finacial Corporation
Wesco Holdings Midwest Inc.
Wesco-Financial Inurance Co.
West Virginia Uniform
WesteScott Fetzer Company
Wheeler Bnck Compan, Inc.
Whitter, Clark & Danels
Witt Brick & Supply, Inc.
WMCCorp.
Woodperect, Inc.
World Book Encyclopedia, Inc.
World Book, Inc.
World Book/Scott Fetzr Company, Inc.
Worldbook.com Inc.
X-L-CO., Inc.
XLI, Inc.
XT Inc.
XTRA Chassis, Inc.
XTRA Companes, Inc.
XTRA Corporation
XTRA Finace Corporation
XT Intermodal, Inc.
XTRA International Pacific, LTD.
XTRA International, LTD.
XTRA Mexicana, SA de C.V.
Zuckerbergs Uniforms
I FERC FORM NO.1 (ED. 12-87)Page 45.11
FERC FORM NO.1 (ED. 12-9)Page 26
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 208104
(2) DA Resubmission 0331/200
TAXES ACCRUED, PREPAID AND CHA GED DURING YEAR
1. Give particulars (details) of the combined prepad and accrued tax accunts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have ben charged to the accounts to which the taxed materi was charged. If the
actual, or estimated amounts of such taes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxs paid during the year and charg direc to final accounts, (not charged to prepaid or accrued taes.)
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 charg to operations and other accounts through (a) accruals credited to taes accrued,
(b)amounts credited to proportions of prepaid taxes chargble to currt year, and (c) taes paid and charged direct to operations or accounts other
than accrued and prepaid ta accunts.
4. List the aggregate of each kind of ta in such manner tht the tot tax for eah State and subdivision ca readily be ascertained.
!L.ine Kind of Tax BALNCE AT BEGINNING OF YEAR clf~I~Adjust-
No.(See instruction 5)~l"c:~2~ii (inciud:rn~: 165)q.ei~g ~ring mentsear
(a)(b)(c)(d)(e)(f)
1 Federal:
2 Income 31,036,759 -6,66,99 .AI' "11
3 FICA 36,997 40,00 34,359,520 34,250,100
4 Unemployment 11,241 365,656 367,147
5 Unemployment - Energy 129,509 18,43 52,997
6 Unemployment - Interwest 108 1,881 1,815
7 Excise Tax - Coal 84,758 4,253,46 4,248,042
8 Subtotal 591,613 31,076,759 -24,670,03 -7,591,443 -9,171,551
9
10 State:
11
12 Arizona:
13 Propert 9n,160 1,83,63 1,894,975
14 Ince 596,00 -78,1n 9,381
15 Subtotal 9n,160 596,00 1,757,45 1,90,356 -4,90
16
17 Califomia:
18 Propert 2,057,053 2,057,053
19 Unemployment 320 33,341 32,164
20 Franchise-Income 119,942 -224,046 429,481
21 Use 48,788 144,58 186,125
22 Locl Franchise 749,83 1,110,884 997,744
23 Subtota 798,94 119,942 3,121,820 3,702,567 -116,358
24
25 Colorado:
26 Propert 1,760,00 2,102,519 1,942,519
27 Income 172,225 -47,915 -55,9n_
28 Subotal 1,760,00 172,225 2,05,60 1,886,542 -25,580
29
30 Idaho:
31 Propert 1,483,957 2,903,274 2,640,173
32 Income 309,56 -395,66 -85,942
33 KWh 50 24,418 13,00
34 Unemployment 996 26,396 26,550
35 Use 3,84 27,50 2n,983
36 Subtotal 1,489,293 309,568 2,835,929 2,131 ,no -209,331
37
38 Montana:
39 Proert 1,192,357 2,799,337 2,593,503
40 Corprate License-Income 321,413 -49,90 -62,078 .-
41 TOTAL 20,901,699 44,601,542 95,501,425 109,296,502 -14,927,n6
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PaciiCorp (1) An Original (Mo, Da, Yr)End of 2oo8/Q4
(2) Fi A Resubmission 03/3112009
TAXES ACCF UED, PREPAID AND CHARGED DU ING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid ta 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 taes coleced through payroll deductions or otherwse pending
trasmittal of such tas to the taxng authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Acunts 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 utilty departments and
amounts charged to Accunts 408.2 and 409.2. Also shown in column (I) the taxes charg to utilty plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or accunt, state in a footnote the basis (necessity) of apportioning such ta.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Elecric Extraordinary Items AClJustments to Het.Other No.Acco~8l 236)(Inc!. in Account 165)(Accunt 408.1 , 409.1)(Account 409.3)Eamings (Accunt 439)
(h)(i)0)(k)(I)
1
39,022,654 -83,683,183 2
452,938 17,521 3
9,750 4
94,94 5
174 6
90,184 7
647,990 39,040,175 -83,683,183 59,013,150 8
9
10
11
12
917,815 1,835,63 13
638,661 -113,712 ~917,815 638,661 1,721,918 35,535 15
16
17
1,986,441 ~1,497 19
657,111 -325,885 20
7,251 21
862,975 1,110,884 22
871,723 657,111 2,n1,44 350,38 23
24
25
1,920,00 2,101,83 ~138,583 -69,694
1,920,00 138,583 2,032,140 22,46 28
29
30
1,747,058 2,901,326 ~-330,042 -575,509
11,912 24,418 ~842
3,361
1,763,173 -33,042 2,350,23 485,694 36
37
38
1,398,191 2,799,337 39
282,662 -72,590 ~
28,648,482 51,215,626 20,421,655 75,079,nO 41
FERC FORM NO.1 (ED. 12-9)Page 26
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008104 ............................................
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)(2) FiA Resubmission 0331/20
TAXES ACCRUED, PREPAID AND CHAI GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charg to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charge to the accunts to which the taxed material wa charg. If the
actual, or estimated amounts of such taes are know, show the amounts in a foonote an designate whether estimated or actual amounts.
2. Include on this page, taxes pai during the year and chaed direc to fina acunts, (not charged to prepad or acrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not afeced by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taes charg to oprations an other accunts through (a) accruals credited to taxes accrued,
(b)amounts creited to prportions of prepad taxes chargeale to curr yer, and (c) taes paid and charged direct to operations or accounts other
than accrued and prepaid tax acunts.
4. Ust the aggregate of each kind of tax in such manner that the tota ta for ea State and subdivision ca readily be ascertained.
ine Kind of Tax
No. (See instruction 5)
(a)
1 Unemployment
2 Energ Ucense
3 Wholesale Energy
4 Subtotal
5
6 Nebraka:
7 Unemployment
8 Subtotal
9
10 New Mexico:
11 Propert
12 Incme
13 Subtotal
14
15 Orego:
16 Propert
17 Unemployment
18 Wilsonvile Payrol
19 Excise-Income
20 City of Portlan-Income
21 Ofce of Energy
22 Tri-Met
23 Lane Count
24 Franchise
25 Subtotal
26
27 Utah:
28 Propert
29 Income
30 Unemployment
31 Navajo Nation
32 Use
33 Subtota
34
35 Washington:
36 Propert
37 Unemployment
38 Business & Ocupation
39 Public Utility
40 Natura Gas Use Tax
BALANCE AT BEGINNING OF YEARTaxes Accru~ ~repa91 axes(Account 236) (Include in Accunt 165)(b) (c)
c1ix~DuringYear
(d)
62,676
44,657
1,299,690 321,413
657
245,970
175,259
3,171,317
116
116
5,516 10,611
-531
10,0805,516
76
76
4,121
39,86
36
7,88,26 16,553,135
1,33,959
778
-2,467,820
-531
610,437
809,782
2,884
21,80,147
38,651,771
-1,729,013
98,686
285,719
34,260
3,799,889
4,184,508 6,54,656
328,416 37,662,63
-2,715,225
244,29
1,60
3,442,474
38,635,788
6,33,54
14,06
273,558
616,042 6,33,54
4,30,00
3,465
4,862
85,413
6,559,746
86,397
6,829
9,321,317
1,193,104
41 TOTAL 20,901,699 44,601,542 95,501,425 109,29,50 -14,927,776
FERC FORM NO.1 (ED. 12-9)Page 262.1
i~
~~?g
(e)
Adjust-
ments
(f)
519
248,151
176,812
2,956,907 -26,579
116
116
10,821~12,214 -248
17,338,407
1,319,254
949
-2,771
649,436
802,664
2,884
21,541,146
38,700,60 -1,318,153
37,109,196-2,418,682 ~
252,732
1,608
3,299,131
38,243,985 -1,40,233
5,08,892~
80,979
6,523
9,302,730
1,313,713
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 03131/200
TAXES ACCt UED, PREPAID AND CHARGED aU ING YEAR (Continued
5. If any tax (exclude Fedral and State income taxes)- covers more then one year, show the required information separately for each ta year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid ta acunts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries wih respet to deferrd income taxes or taes collected through payroll deductions or otherwse pending
transmittal of such taxes to the taxng 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
pertining to elecric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utilty departents and
amounts charged to Accounts 40.2 and 409.2. Also shown in column (I) the taxes charged to utilty plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the bais (necessit) of apportioning such ta.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED
(Taxes accrued Prepaid Taxes Electric Extrardinary ItemsAcc~nl 236) (Incl. in Account 165) (Account 408.1, 40.1) (Accnt 409.3)tg) (h) (i) (j)
138
60,495
43,104
1,501,928
8,670,415 16,480,86
LineAoiustmemsto Het. ~Other NoEamings (Accnt 439) .(k) (I)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
3,34,647 25
26
27
!56,891,94 33
34
~
245,970
175,259
3,147,976 23,341282,662
5,306 10,611
-774
9,837 ~5,306
1,752
1,752
57,574
198
-3,349,849
-84,414
324,718
-3,589,552
-772
610,437
347,378
4,06,890
4,470,040 5,56,870
21,806,147
35,307,124
881,853 35,691,654
-3,949,4145,225,854
5,63
1,608
416,901
1,304,388 5,225,85 31,743,848
8,553,361
8,883
5,168
875,00
96,129
4,739,533
6,829
9,321,317 39~4O
28,648,482 20,421,655 75,079,77 4151,215,626
FERC FORM NO.1 (ED. 12-96)Page 263.1
116
FERC FORM NO.1 (ED. 12-96)Page 26.2
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 0331/200
TAXES ACCRUED, PREPAID AND CHA GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accunts and show the total taxes char to operation an other acunts during
the year. Do not include gaoline and other sales taes which have been charge to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taes are know, show the amouns in a foonote and designate whether esimated or actual amounts.
2. Include on this page, taxes pad during the year and charged direc to final acunts, (not charge to prpa or accrued taxes.)
Enter the amounts in both columns (d) and (e). The baancing of this page is not afected by the inclusion of these taes.
3. Include in column (d) taxes charged during the year, taes charged to oprations and other accunts through (a) accruals creited to taes accrued,
(b)amounts credited to proportions of prepaid taxes chargeale to currnt year, and (c) taes paid and charged direct to operations or accounts other
than accrued and prepad tax accounts.
4. List the aggregate of eah kind of tax in such manner that the tot tax for ea Stae and subdvision can readily be ascertained.
IUne Kind of Tax BALANCE AT BEGINNING OF YEAR c1~~I~Adjust-No.(See instruction 5)i: axes Accl1~~repaiØ Taxes ~ring ~~?g ments(Account 236)(Include in Accnt 165)ear(a)(b)(c)(d)(e)(f)
1 Use 39,724 588,4n 563,497
2 Retailing 29 29
3 Wholesaling 21,86 1,233
4 Lad Tax 61 61
5 Subtotal 5,20,49 17,77,791 16,353,657 -3,863,245
6
7 Washington D.C.:
8 Frachise-Incoe -3,282 -3,318
9 Subtotal -3,282 -3,318 -3
10
11 Wyoming:
12 Propert 3,665,365 8,672,60 7,986,071
13 Unemployment 3,074 160,112 158,305
14 Frachise 20,30 1,491,310 1,45,110
15 Use n,785 1,03,859 997,260
16 Annual Report 40,323 40,323
17 Subtotal 3,94,524 11,395,20 10,632,069
18
19 State Other -89,368 38,076
20
21 Miscellaneous:
22 Gohute Possessory 27,023
23 Sho-Ban Possessory 132,712 132,712
24 Navajo Possessory 16,873 35,122 34,43
25 Ute Possessory 15,423 15,423
26 Crow Possessory 62,316 62,316
27 Umatila 46,53 46,53
28 Other Taxes 11,04 60,694 71,738
29 Subtotal 27,917 -869,368 762,899 36,156 1,252,44
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 20,901,699 44,601,542 95,501,425 109,29,50 -14,927,n6
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/200
TAXES ACel UED, PREPAID AND CHARGED DU 'lING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the reuired information separately for each ta yea,
identifng the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accunts 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 deferr income taxes or taxes collected through payroll deductions or otherwse pending
transmittal of such taxes to the taxng 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
pertining to electric operations. Report in column (i) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utilty departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utilty 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 ta.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepad Taxes Elecric Extraordnary Items Aoiustments to Het.Other No.
Acco~8J 236)(Incl. in Account 165)(Accunt 408.1 , 409.1)(Account 40.3)Eamings (Accunt 439)
(h)(i)0)(k)(I)
64,704 1
I 2
20,627 3
61 4
10,491,872 14,067,740 3,710,051 5
6
7
-4,826 ~-4,826 1,508 9
10
11
4,351,898 8,662,874 ~4,881 13
241,500 1,491,310 14
111,384 -15
40,323 16
4,709,663 10,194,507 1,200,701 17
18
38,076 19
20
21
27,023 27,023 22
132,712 23
17,561 35,122 24
15,423 25
62,316 26
46,53 27
60,694 28
44,584 762,899 29
30
31
32
33
34
35
36
37
38
39
40
28,64,482 51,215,626 20,421,65 75,079,no 41
FERC FORM NO.1 (ED. 1i.96)Page 263.2
Account
419
421
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp ì2) A Resubmission 03131/2009 200Q4
FOOTNOTE DATA
ISchedulePage: 262 Line No.: 2 Column: f
Interest
Miscellaneous
Federa income ta accrus pursuat to FASB
Interpretation No. 48 ("FI 48")
Reclassifcation of prepaid taes to th par reivable
Tota adjustmnts
Amunt
$ 2,994
152
2,746,106
(11,920,803)
$(9,171,551)
174
143
Line No.: 14 Column: f
Account
State income ta accruals puruant to FASB
Interpretation No. 48 ("FI 48")
Reclassifcation of prepaid taes to th par reeivable
Amunt
$ (15,167)
(29,739)
$ (44,906)
174
143
¡Schedule Page: 262 Line No.: 14 Column: i
State income ta a licable to other income & deductions - 402
Schedule Pa e: 262 Line No.: 18 Column: i
Taxes applicable to other income & deductions
Distrbution rent expense, rents
Tota
Amunt Account
$ 69,738 408.2/409.2874 589
$ 70,612
fScheule Page: 262 Line No.: 19 Column: i
V arous operations and matenance accounts.
fSchedule Page: 262 Line No.: 20 Column: f
State income ta accrus puruat to FASB
Interpretation No. 48 ("FI 48")
Reclassifcation of prepaid taes to th par reeivable
Amunt Account
$ (31,128)
(85,230)
$ (116,358)
174
143
¡Schedule Page: 262 Line No.: 20 Column: i
State income ta a licable to other income & deuctions - 409.2
Schedule Pa e: 262 Line No.: 21 Column: i
Clearg account - 184
fShedule Page: 262 Line No.: 26 Column: i
Taxes applicable to other income & deductions - 408.2, 409.2
IFERC FORM NO.1 (ED. 12-87) Page 45.1
.............................................
.
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 0331/2009 200104
FOOTNOTE DATA
!schedule Page: 262 Line No.: 27 Column: f
Account
State income ta accruals puruat to F ASB
Interpretation No. 48 ("FI 48")
Reclassifcation of prepaid taes to thd par receivable
Amunt
$ (7,353)
(18,227)
$ (25,580)
174
143
¡Schedule Page: 262 Line No.: 27 Column: i
State income ta applicable to other income & deductions - 40 .2
¡Schedule Page: 262 Line No.: 31 Column: i
Taxes ap licable to other income & deductions - 408.2, 409.2
Schedule Pa e: 262 Line No.: 32 Column: f
State income ta accrus puruant to F ASB
Interpretation No. 48 ("FIN 48")
Reclassifcaton of prepaid taes to th par reeivable
Amunt Account
$ (58,816)
(150,515)
$ (209,331)
174
143
Line No.: 40 Column: f
Account
State income ta accruals puruat to FASB
Interpretation No. 48 ("FI 48")
Reclassifcation of prepaid taes to thd par reeivable
State income ta accrs pursuant to FASB
Interpetation No. 48 ("FI 48")
Reclassifcation of prepaid taes to thd pary receivable
Amount
$ (7,594)
(18,985)
$ (26,579)
174
143
Amunt Account
$
$
(46)
(202)
(248)
174
143
\Shedule Page: 262.1 Line No.: 12 Column: i
State inome ta a licable to other income & deductions - 40.2
Schedule Pa : 262.1 Line No.: 16 Column: i
Taxes aplicable to other income & deductions
Distrbution rent expens, rents
Tota
Amount Account
$ 19,734 408.2140.2
52,537 589
$ 72,271
IFERC FORM NO.1 (ED. 12-87) Page 450.2
Amunt Account
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 031/2009 20/04
FOOTNOTE DATA
State income ta accruals puruat to FASB
Interpretation No. 48 ("FI 48")
Reclassifcaton of prepaid taes to thd par reivable
$ (378,859)
(938,789)
$(1,317,648)
174
143
¡Scheule Page: 262.1 Line No.: 19 Column: i
State income ta a licable to other income & deuctions - 409.2
SChedule Pa e: 262.1 Line No.: 20 Column: f
Amunt Account
State income ta accruals puruat to FASB
Interpretation No. 48 ("FI 48")
Reclassifcation of prepaid taes to th par reivale
$
$
(303)
(202)
(505)
174
143
Taxes applicable to other income & deductions
Fuel stock
Distrbution rent expense, rents
Tota
Amunt Account
$ 21,185 408.2/409.2
1,524,407 151
425,387 589
$1,970,979
I$hedule Page: 262.1 Line No.: 29 Column: f
Amunt Account
State income ta accrus pursuant to FASB
Interpretation No. 48 ("FI 48")
Reclassifcation of prepaid taes to thd par receivable
$ (370,066)
(1,034,167)
$(1,404,233)
174
143
Taxes applicable to other income & deductions
IFERC FORM NO.1 (ED. 12-87)
Amunt Account
$ 117,431 408.2/40.2
Page 45.3
............................................
Name of Respondent This Report is:Date of Report Year/Period of Repor
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 2008/04
FOOTNOTE DATA
Constrction
Dìstrbution rent expense, rents
Tota
1,699,373
3,409
$1,820,213
107
589
Line No.: 1 Column: i
Line No.: 3 Column: i
Line No.: 8 Column: f
State ìncoin ta accruals pursuant to FASB
Interpretation No. 48 ("FI 48")
Reclassìfcation of prepaìd taes to thd par reeìvable
Amount Account
$(36)174
143
$ (36)
¡Schedule Page: 262.2 Line No.: 8 Column: i
State ìncome ta a licable to other ìncoin & deductions - 409.2
Schedule Pa e: 262.2 Line No.: 12 Column: i
Taxes applìcable to other ìncome & deductions
Dìstrbution rent expense, rents
Tota
Amunt Account
$ 2,805 408.2/409.2
6,925 589
$ 9,730
¡Schedule Page: 262.2 Line No.: 13 Column: i
Varous 0 rations and matenance accounts.
SCedule Pa e: 262.2 Line No.: 15 Column: i
Clearg account - 184
¡Schedule Page: 262.2 Line No.: 19 Column: f
State ìncoin ta accruals puruant to FI 48 - 174
IFERC FORM NO.1 (ED. 12-87) Page 450.4
FERC FORM NO.1 (ED. 12-8)Page 26
............................................
Name of Respondent ThiS~~IS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, 08, Yr)End of 2008/04
(2) A Resubmission 031/20
ACCUMULA ED DEFERRED INVESTMENT TAX REDITS (Accunt 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utilty and
nonutilty operations. Explain by footnote any correction adjustments to the accunt balance shown in column (g).lnclude in column (i)
the average period over which the tax credits are amortized.
fDne Account
No.SUbdx~sions of Year err for Year Currnt Year's Income Adjustments(b) AccOl NO. Amount ACCU~( NO. ",mount ( )(c) (d) (e) (f) g
1 Elecric Utilty
23%
::4%
4 7%
5 10%40,618,437 ..1,808,76
e 10%10,54,126 1,624,4~
7 Idaho 84,329 411.4 65,43
I:TOTAl
5 Other (Ust separately
and show 3%, 4%, 7%,
10% and TOTAL)
10
11
12
13 10%1,762,928 420 44,8OE
14
15 Total Nonutilty 1,762,928 440,so
1E
17
11:
1S
2C
21
22
2::
24
25
2e
27
2E
3C
31
32
33
34
35
3S
37
3B
3i
4c
41
4~
43~
4E
4E
47
4E
............................................
Name of Respondent ThiS~iortls:Date of Report Year/Period of Report
PacifiCorp (1 )An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/2009
ACCUMULATED D FERRED INVESTMENT TAX CRED S (Accunt 255) lcontinuëcf)
~ADJUSTMENT EXPLANATION Lineof Year of AI ocation No.to Incomeh i f-
1
2
3
4
38,80,669 48.37 5
8,918,674 30 6
77,893 7
48,506,236 8
9
10
11
12
1,322,120 30 13
14
1,322,120 15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO.1 (ED. 12-89)Page 267
IFERC FORM NO.1 (ED. 12-87) Page 45.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifCorp Î2) A Resubmission 0331/2009 200/04
FOOTNOTE DATA
¡Schedule Page: 266 Line No.: 5 Column: e
46(f)2
¡Schedule Page: 266 Line No.: 6 Coumn: e
46(f)
.............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 03131/2009
o HER DEFFERED CREDITS (Accunt 253)
1. Report below the particulars (details) called for conceming I?ther deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $10,00, whichever is greater) may be groupe by clsses.
Line Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
(a)(b)
Accunt
(e)(f)(c)(d)
1
2 Working caital Deposits 2,36,144 473,734 2,841,878
3
4 Reclamation Cots - Trapper Mine 4,037,459 239,153 4,276,612
5
6 Reclamation Costs - Deseret Mine 548,042 131 13,216 534,826
7
8 Reclamation Costs - Trail
9 Mountain Mine 1,131,538 131 4,740 1,126,798
10
11 Deferred Compensation Plans 12,08,380 124 4,207,272 2,082,261 9,961,369
12
13 Transmission Service Depoit 13,155,60 131 21,648,278 12,023,803 3,531,125
14
15 MCI F.O.G. wire lease 558,468 45 3,348,954 3,348,583 558,097
16
17 Redding Contract (20)4,40,06 456 549,996 3,85,072
18
19 Foote Creek Contract (15)980,582 142 137,640 842,942
20
21 Environmental Liabilities 5,873,145 131 1,811,538 1,630,073 5,691,68
22
23 Uneamed Joint Use Pole Contract 3,5n,349 45 8,217,543 8,161,811 3,521,617
24
25 Oregon DSM Loans NPV Uneamed 1,416,49 456,431 699,974 716,516
26
27 Other Deferred Credits - C& T 3,90,913 555 3,073,156 833,757
28
29 Deferred Revenue.
30 DukelHermiston Gas Settlement (5)2,673,387 547,555 754,838 1,918,549
31
32 Trasmission Security Depoits 1,30,00 1,30,00
33
34 Other deferre credits with
35 baances less than $50,00 2,814,397 various 1,558,213 1,256,184
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL 59,527,96 46,025,358 29,259,418 42,762,022
FERC FORM NO.1 (ED. 12-9)Page 26
1,371,109,274 548,099,661 261,436,935
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 0311/2009
ACCUMULATE DEFFERED INCOME TAXES - OT ER PROPERTY (Acunt 82)
1. Report the information called for below concerning the respondent's accunting for deferred income taxes rating to propert not
subject to acclerated amortization
2. For other (Specify),include deferrls relating to other income and deductons.
Line
No.
CHANGES DURING YEARAccuntBalance at
Beginning of Year Amounts Debited
to Accunt 410.1
(c)
Amounts Credited
to Accunt 411.1
(d)(a)(b)
1 Account 282
2 Electric
3 Gas
4 FAS 109 Regulatory Asset
5 TOTAL (Enter Total of lines 2 thru 4)
6 Nonutility
7
8
9 TOTAL Account 282 (Enter Total of lines 5 thru
10 Classification ofTOTAL
11 Federal Income Tax
12 State Income Tax
13 Locallncome Tax
459,165,634
1,830,274,908
2,615,149
548,099,661 261,436,935
1,832,890,057 548,099,661 261,436,935
1,613,625,194
219,26,863
482,531,627
65,568,034
230,161,773
31,275,162
NOTES
FERC FORM NO.1 (ED. 12-9)Page 274
............................................
Name of Respondent
PacifiCorp
Date of Re¡:ort
(Mo, Da, Yr)
Year/Period of Report
End of 2008/04
ACCUMULATED DEFERRED INCO
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Accunt 410.2 to Account 411.2
ADJUSTMEN S
Amount
Balance at Une
End of Year No.
NOTES (Continue)
FERC FORM NO.1 (ED. 12-96)Page 275
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) lÇ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission . 03131/2009 2008/04
FOOTNOTE DATA
¡Schedule Page: 274 Line No.: 2 Coumn: i
Accounts
190
283
¡SChedule Page: 274 Line No.: 4 Coumn: g
Accounts
182
283
............................................
Blank Page
(Next Page is 276)
132,257,166 62,261,412 58,090,266
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Oa, Yr)
(2) A Resubmission 0311/2009
ACCUMU T 0 OEFFEREO INCOME TAXES - THER (Accunt 283)
1. Report the information called for below concerning the respondent's accounting for deferred income taes relating to amounts
recorded in Accunt 283.
2. For other (Specify),include deferrals relating to other income and deductions.
1 Accunt 283
2 Electric
3 Regulatory Asset
4
5 Oeriv. Contracts Reg. Assets
6 Other Deferrd Liabilties
7
8
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
11
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18
19 TOTAL (Acc 283) (Enter Total oflines 9, 17 and 18)
20 Classifcation of TOTAL
21 Federal Income Tax
22 State Income Tax
23 Local Income Tax
Accunt
(a
Line
No.
97,163,581
64,648,624 21,018,003 23,365,553
294,069,371 83,279,415 81,455,819
294,069,371 83,279,415 81,455,819
258,889,416
35,179,955
73,316,870
9,962,545
71,711,427
9,744,392
NOTES
FERC FORM NO.1 (ED. 12-9)Page 276
...................li........................
Name of Respondent
PaciiCorp
Year/Period of Report
End of 2008/04
This ~ort Is: Date of Report
(1) I!An Original (Mo, Da, Yr)
(2) A Resubmission 03131/200
ACCUMULATED EFERRED INCOME AXES - OTHE (Account 283) (Continu
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
ADJUSTMENTS
Une
No.
90,731,161
836,958
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 271
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0331/2009 200/04
FOOTNOTE DATA
!Shedule Page: 276 Line No.: 3 Column: 9
Accounts
190
282
219
............................................
Blank Page
(Next Page is 278)
FERC FORM NO. 113Q (REV 02-()Page 27
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 0331/2009
o HER REGULATORY LIABILITIES (Acnt 254)
1. Report below the particulars (details) called for conceming other regulatory liabilties, 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 Liabilties being amortized, show period of amortization.
Baanc at Begining DEBITS Balance at EndLineDescription and Purpe of of Currt of CurrentNo.Other Regulatory Liabilties QuarterlY ear Accunt Amount Credits QuarterlYearCredited
(a)(b)(c)(d)(e)(f)
1 FAS 109 Regulatry UabUit 2238,21 190 1,013,9 21,373,276
2 FAS 109. WA Flow Through 13,39,03 190 3,605,45 9,793,58
3 OR Gain on Sales of As m,64 1,239,25 1,416,868
4 SMUD Revenue Imputtion (11)25,46.313 440,442 4,729.586 4.937.126 25,669,853
5 Oregon Rate Refund 79.96 142 2 79,9
6 Utah Home Energy Lifeline 147,54 142 2,21,98 2,514,46 400,026
7 BPA Oreon Balancing Accnt 98,54 988,540
8 ARO/ Reg Diffrence. Deer Cree Mine Recmatin 49,m 230 171.503 295.531 621,20
9 AROlReg Diffrence. Trojan Nuclr Plant 86,813 230 191,121 2.69,651 3,373,343
10 Reg Uabilit. CA West VaHey Lease Red (3)54,2 142 29,511 3,525 28,291
11 Reg UabUit. 10 Wes Valley Lea Red (3)65.ns 142 218.92 437,852
12 Reg Liabilit. WY Wes Valley Leas Red. (3)1,45,9 142 39,263 29,28 1,365,919
13 Reg Liailit. UT Wes VaHey Leas Red (1.5)418,170 142 42,473 7.SO
14 Reg Liabilit. A&G Creit - WA (1)42,241 142 43,50 10,264
15 Reg Uabilit . A&G Credit. CA (3)86,93 142 47,268 5,64 45,316
16 Reg Libilit. A&G Creit 10 (3)676,86 142 225.62 451,245
17 Reg Liabilit. A&G Creit WY (3)1,510.795 142 44,8 40,784 1,476,750
18 Wasington Low Income Program (41,96)142 1,03,03 1,05,41 -24,581
19 Reg Liabilit. OR Consoidation (35,45)470,10:117,653
20 Reg Liabilit. Blue Sky . OR 46,671 232 1.151,46 970,106 281,314
21 Reg Libilit. Blue Sky . WA 81,041 232 144.911 150,692 86,822
22 Reg Liabilit. Blue Sky . CA 34.975 232 49,706 62,367 47,63
23 Re Liaili. Blue Sky . UT 58,66 232 1,80,45 2,136,561 921,774
24 Reg Liabilit. Blue Sky . 10 19,9 232 24,09 54,617 50,50
25 Reg Libilit. Blue Sky . WY 104,551 23 162.69 179,207 101,06
26 Reg Liabiit. OR Energy Conser Chrg 232 6,83,798 7,60,672 775,874
27 Reg Liablit. CA Sale Gn 45,03 45,034
28 Reg Liabilit. UT Sale Gn 1.019,355 1,019,355
29 Reg Libilit. 10 Sale Gn 156,43 156,434
30 Reg Liabilit. WY sale Gn 352.88 352,88
31 Reg Liait. Defrr Ben.Ar (3)557.0 2.02,293 5,OO,l~3,53,860
32 Reg Lialit. Reclss 2,139,2 182.3 190,240
33
34
35
36
37
38
39
40
41 TOTAL 71,343,435 27,63,671 32,748,89 76,45,65
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0331/2009 200Q4
FOOTNOTE DATA
ISchedule Page: 278 Line No.: 32 Column: f
The following is a reconcilation of the regulatory liabilty reclassification account:
Reclassified from Regulatory Asset to Reguatory Liabilties:
California DSM Regulatory Asset
Washigton DSM Reguatory Asset
Sch 781 Direct Access Shopping Incentive
Deferred Excess Net Power Costs - CA
Deferred UT Independent Evaulator Fee
Deferd Intervenor Funding Grants - OR
SB 408 Reguatory Asset - MCBIT
YTD
Decmber 31, 2008
$1,001,355
64,615
845
475,407
93,250
266,8%
22,043
Reclassified from Regulatory Liabilties to Reguatory Assets:
Washi~n Low Income ~o~
$
24,581
1,948,992
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) ri A Resubmission 03131/20
E ..CTRIC OPERATING REVENUES ( ccunt 40)
1. The following instctons generally apply to th annual version of th page. Do not report quartriy da in coumns (c), (e), (f), and (g). Unbille revenue an MWH
related to unbiled revenue nee not be report separately as reuire in th annua vesion of th pa.
2. Report below operating revenus for eah prescribe account, and manuftured gas revenue in total.
3. Reprt number of customers, columns (f) and (g), on th basis of meters, in additon to the number of flat rate accunts; exc that whre separa meter readings are added
for biling purposes, one customer shold be counte for each group of meters added. The -average number of customers means the average of twlve figure at the clos ofeach mont.
4. If increases or decrease frm previous period (columns (c),(e), an (g)), are not derived from previously reported figures, explain any inconsistecies in a footnote.
Une Title of Account Operating Revees Year Operating Revnue
No.to Date Quartrly/Annual Previous year (no Quarerl)
Ca)(b (c)
1 Sales of Electricity
2 (440) Residential Sales 1,34,013,66 1,263,790,93
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)1,062,312,561 1,014,421,43
5 Large (or Ind.) (See Instr. 4)998,397,465 914,316,59
6 (44) Public Street and Highway Lighting 19,865,594 18,902,690
7 (445) Other Sales to Public Authorities 18,443,905 17,509,459
8 (44) Sales to Railroads and Railways
9 (44) Interdepartmental Sales
10 TOTAL Sales to Ultimate Coumers 3,44,033,188 3,228,941 ,109
11 (447) Sales for Resale 86,950,758 856,86,831
12 TOTAL Sales of Elecricity 4,30,983,94 4,085,805,94
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provo for Refnds 4,30,98,94 4,085,805,94
15 Other Operating Revenues
16 (450) Forfeited Disconts 7,486,736 6,784,670
17 (451) Miscellaeous Service Revenues 7,079,770 7,215,245
18 (453) Sales of Water and Water Power 26,40 107,480
19 (45) Rent from Electric Propert 20,579,425 18,760,759
20 (455) Interdepartmental Rents
21 (456) Other Elecric Revenues 78,876,459 68,728,424
22 (45.1) Revenues from Transmission of Elecricity of Oters 75,55,244 56,223,453
23 (457.1) Regional Control Servce Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operaing Revenues 189,602,040 157,82,031
27 TOTAL Electric Operating Revenues -4,243,625,971
.
.
FERC FORM NO.1I3Q (REV. 12-()Page 30
............................................
............................................
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 03131/200
E ECTRIC OPERATING REVENUES (Acunt 40)
Year/Period of Report
End of 2008/04
5. Commercial and industrial Sales, Accunt 442, may be classified according to the bais of clasification (Small or Commercial, and Lage or Industrial) regularly used by the
respondent if such bais of clssification is not generally greater th 1000 Kw of demand. (See Accunt 442 of the Uniform System of Accunts. Expain basis of classificatin
in a footnte.)
6. See pages 108-109, Importnt Change During Period, for importnt new territor added and importnt rate increa or dereases.
7. For Line 2,4,5,and 6, see Page 304 for amount relating to unbilled revenue by account.
8. Include unmetered sales. Provide detils of such Sales in a footn.
MEGAWATI HOURS SOLD
Year to Date Quarterl/Annual Amount Previous year (no Quarterly)(d) (e)
AVG.NO. CUSTOMERS PER MONTH Line
Currnt Year (no Quarterly) Previous Year (no Quarterly) No.(f) (g)
16,055,182 15,951,322
21,494,710 20,892,453 5
141,122 136,080 6
449,314 435,395 7
8
54,361,783
12,34,976
66,706,759
13
66,706,759 67,114,33 1,706,127 14
Line 12, column (b) includes $
Line 12, column (d) includes
210,896,00
3,44,267
of unbilled revenues.
MWH relating to unbiled revenues
FERC FORM NO. 113 (REV. 12-05)Page 301
Sales for Resale - Account (447)860,950,758 860,950,758 (b)
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)PacifiCorp I (2) A Resubmission 031/2009 2oo8/Q4
FOOTNOTE DATA
Sales of Elecricity
Residential Sales - Accunt (440)
Commercial and Industral Sales - Account (442)
Smal (Commercial)
Lae (Industral)
Public Street and Highway Lighting - Account (44)
Oter Sales to Public Authorities - Account (445)
Sales to Railrads and Railways - Accunt (446)
Interdeparenta Sales - Account (448)
Page 300 Page 304 Varance
Yea ended Year ende Yea ended
Deber 31,December 31,Dember 31,
2008 2008 2008
$1,345,013,663 $1,345,013,663 $
1,062,312,561 1,062,312,561
998,397,465 998,397,465 -(a)
19,865,594 19,865,594
18,443,905 18,443,905
Tota Sales to Ultiate Consumers 3,44,033,188 3,44,033,188
Tota Sales of Electrciiy 4,304,983,946 3,44,033,188 860,950,758
(less) Provision for Rate Refunds - Account (449.1)
Tota Revenues Net of Provisions for Refunds
Oter Operating Revenues
Fodeite Discounts - Account (450)
Miscellaneous Service Revenues - Accnt (451)
Sales of Water and Water Power - Account (453)
Rent frm Electrc Property - Accunt (454)
Inteeparenta Rents - Account (455)
Other Electrc Revenues - Account (456)
Revenues frm Trasmission of Eleccity of Oters (456.1)
4,304,983,946 3,44,033,188 860,950,758
7,486,736 7,486,736
7,079,770 7,(9,770
26,406 26,406
20,579,425 20,579,425
78,876,459 72,497,824 6,378,635 (c)
75,553,24 75,553,24 (b)
$4,494,585,986 $3,551,703,349 $942,882,637Tota Operati Revenues
(a) The large industral line on page 300 includes acunt 442.2 Industral Sales of $909,975,226 and account 442.3 Irgation Sales of
$88,422,239.
(b) Sales for Resale and Revenues from Trasmission of Eleccity of Oters ar not included on page 304 Sales of Electrcity by Rat
Schedules.
(c) The following difernces ar shown between page 300 Eleccity Opting Revenue and 30 Sales of Eleccity by Rat Schedules:
Page 300 Page 304 Varance
Steam Sales $7,288,382 $$7,288,382
Materials and Supplies Inventory Cost of Sales (909,747)(90,747)
$6,378,635 $$6,378,635
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp (2) A Resubmission 03131/2009 200/04
FOOTNOTE DATA
¡Schedule Page: 300 Line No.: 1 Column: $
The following table is a reconcilation of the unbiled revenue accru at December 31, 2008 and the reversal of the Decmber 31,
2007 unbiled revenue accrual.
Curent year unbiled revenue accru
Pror yea unbiled revenue accrual reversal
December 31,
2008
$ 210,896,00
(192,299,00)
Change In Unbiled Revenue Accrual $18,597,00
¡Schedule Page: 300 Line No.: 1 Column: MWH I
The followig tale is a reconcilation of the unbiled MW accru at Decembr 31, 2008 and the reversal of the Deember 31, 2007
unbiled MW accru.
Curent yea unbiled MWH accru
Pror yea unbiled MWH accr reversal
Decmber 31,
2008
3,440,267
(3,315,584)
124,683Change in MW Accru
IFERC FORM NO.1 (ED. 12-87)Page 450.2
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, 08, Yr)End of 20004
(2) ri A Resubmission 03131/200
SALES OF ELECTRICITY BY RATE S(HEDULES
1. Report below for each rate schedule in effect during the year the MWH of elecricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resae which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribe operating revenue accnt in the sequence followed in "Elecric Operating Revenues," Page
30-301. If the sales under any rate schedule are clasified in more than one revenue accunt, Ust the rate schedule and sales data under each
applicable revenue accunt subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classificaion (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. Th average number of customers should be the number of bills rendere during the year divided by the number of billng periods during the yea (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a foonote the estimated addtional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue acunt subheading.
ine Numoer ano ime 01 Meue scneauie Mvvn ::oia Hevenue Ave~iNumoer ~YV'!.UI 9a1es ~~~~olderNo.(a)(b)(c)ofC omers Per e¡~stomer
(f)
1 RESIDENTIAL SALES
~CALIFORNIA
~06CHCKOOR-CA RES CHECK M
4 06LNXOO102-L1NE EXT 80"k G 51
5 06LNXOO109-REF/NREF ADV +471
6 06NETMT135 - CA RES NET 86 9,234 11 7,811:0.1074
7 O6ALT015R-OUTD AR LGT SR 36 72,707 391 934 0.1992
8 06RESDooD-RES SRVC 205,351 21,756,982 19,041 10,781 0.106
9 06RESDDL06-CA LOW INCOME 107,29 11,273,482 9,126 11,757 0.1051
10 06RESDDM9M-MUL TI FAMILY 2&28,39 E 35,00 0.1014
11 06RESDDS8M-MUL T FAM SBMET 1,4O 111,42S 15 93,33 0.0796
1~ 06UPPLooR-BASE SCH FALL 1
1~ ACQUISITION COMMITMENT-A and 24,92
14 ACQUISITION 15,56
15 SMUD REVENUE IMPUTATIONS 60,135
1E 06RESDOODN - CA RES SRVC -99,59E 10,45,919 7,57E 13,147 0.1050
11 UNBILLED REV - UNCOLLECTIBLE -3,00
H UNBILLED REVENUE 3,96 783,00 0.1976
ü IDAHO
2(07LNX0Q1Q-MNTHL Y 8O%GUAR 1,039
21 07LNXoo35-ADV 8O%MO GUAR 2,95E
22 07NETM135 -ID RESIDENTIAL 1Z 8,16:2 61,00 0.069
2~070ALCOO7-eUST OWN LIGHT 1C 3,687 144 69 0.367
24 070ALT07AR-SECURITY AR LG 116 45,001:39,581 0.3880
25 07RESDOO1-RES SRVC 40,977 35,45,424 0.0876
26 07RESDOO1 "RES SRVC -231 16,576
27 07RESDOO36-RES SRVC-OPTIO 318,449 22,485,523 0.0706
2S 07RESD0-RES SRVC-OPTIO -1
29 BPA BALANCING ACCOUNT 290,84S
3C ACQUISITION COMMITMENT-A and 55,461
31 ACQUISITION 53,821
3: SMUD REVENUE IMPUTATIONS -420,98f
3~UNBILLED REVENUE 3,697 470,OO 0.1271
34 OREGON
3f 01 CHCKOOR-RES CHECK MTR 1
3E 01 COSTOO - 01 RESD0 5,46,592 223,43,16E 0.049
37 01 HABITOO - 01 RESD0 44,79 1,779,422 0.0397
3E 01LNXOO102-L1NE EX 80"k G 5,9O
3S 01LNXOO105-CNTRCT $ MIN G 3l
4C 01LNXOO109REF/NREF ADV +7,36
41 TOTAL Billed 54~'~!3,~1,706,12 31,7!K 0.061
42 Total Unbilled Rev.(See Instr. 6)124,((0.149
43 TOTAL 54,361,7 3,551,703,34 1,706,121 31 ,sa 0.06:3
FERC FORM NO.1 (ED. 12-95)Page 304
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fî A Resubmission 03131/200
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of eletricity 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
30-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule an sales data under each
applicale revenue account subheading.
3. Where the same customers are served under more than one rate schedle in the same revenue account classification (such asa 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 rendere during the year divided by the number of billng periods during the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a foonote the estimated additional revenue biled pursuat thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue account subheading.
ine Numoer ana ime or Male sCneaule Mvvn~oia Hevenue Average I'lumoer ~ vv 11 OJ ~aies ~G~olderNo.(a)(b)(c)ofc~~omers Per ?~stomer
(f)
1 01NETMT135-NET METERING 210,37~4n
2 01NETMT135-NET METERING -3,06~
~ 010ALT014R.OUTD AR LGT RE 2,~384,30e 3,001 894 0.1432
~010AL T014R.OUTD AR LGT RE .1,09i
5 01 PTOUOQ . 01 RESDOO 19,961 816,281 0.04
e 01 RENEWOO - 01 RESD0 183,971 7,204,179 0.0392
7 01 RESDOQ.RES SRVC -2 246,583,035 469,691 .123,291.5175
8 01 RESDOO-RES SRVC -2,717,055
9 01 RESDOOT . RES Time Option 852,63 1,268
10 01 RESDOOT - RES Time Option -10,228
11 01 UPPLOOR-BASE SCH FALL 3
12 BPA BALANCING ACCOUNT -1,157,172
1:3 OR S8408 RECOVERY 10,64,576
14 OR SB 838 RECOVERY 4,429,225
15 SMUD REVENUE IMPUTATIONS 747,414
16 UNBILLED REV . UNCOLLECTIBLE -12,00
17 UN BILLED REVENUE 90,621 8,038,00 0.0887
18 UTAH
19 08BLSKY01 R-BLUESKY ENERGY -:3
2C OSCFROO1-MTH FACILITY S 1,40
21 OSCHCKOOR-UT RES CHECK M
2~08COOLKPRR - Utah Cool Keeper 70,70~
2~08LNXOO1-MTHL Y 80% GUAR 1,500
24 08LNXOO13-8% MNTHLY MIN 21,636
25 08LNXOO108-ANN COST MTHL Y 3,981
26 08MHTP0025-MOBILE HOME &12,00 821,388 11 1,091,636 0.0684
27 08NETMT135 - Net Metering 1,467 121,710 215 6,82:3 0.083
28 080AL TOO7R-SECURITY AR LG 2,923 781,330 3,248 90 0.2673
29 08PTLDOR.POST TOP LIGHT 224 16,849 67 3,34 0.0752
30 08RESDOO1-RES SRVC 6,342,n4 525,723,257 669,82C 9,469 0.0829
31 08RESDOO2-RES SRVC-OPTIO 2,557 208,885 294 8,697 0.0817
32 08RESD()L1FELINE PRGRM 182,65:3 14,918,754 23,358 7,820 0.0817
3S 08UPPLOOR-BASE SCH FALL ~.
34 OSZMERGCR.MERGER CREDITS -21
35 ACQUISITION 125,81.
3E SMUD REVENUE IMPUTATIONS 631,7&1
37 UNBILLED REV - UNCOLLECTIBLE 10,00
38 UNBILLED REVENUE 15,97:3 2,173,00 0.136
39 WASHINGTON
4C 02LNXOO109REF/NREF ADV +58'
41 TOTAL Biled 54~7~ om3'II 1,706,12 31,79 0.061
42 Total Unbiled Rev.(See Instr. 6)124,i i 0.149
43 TOTAL 54,361,7 3,551,703,34 1,706,12 31,~0.06~
FERC FORM NO.1 (ED. 12-95)Page 304.1
Page 30.2
............................................
Name of Respondent This (lrt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo8/Q4
(2) Fi A Resubmission 03131/200
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in efect 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 Rese which is reported on Pages 310-311.
2. Provide a subheading and tot for each prescribe oprating revenue acnt in the sequence follow in "Elecric Opeting 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
scheule and an of peak water heating schedule), the entries in column (d) for the speial schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills redered during the year divided by the number of billng periods during the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a foonote the estimated additional revenue biled pursuat thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
ine Numoer ana ime Of Hate scneauie Mvvn ;:Oiu nevenue lwerai~'\UmDer ~~~n1:foc;:r ~~folderNo.(a)(b)(c)of Cu omers (f)
1 02NETMT135 - WA RES NET 16 1,04 :1 5,33 0.06
2 02NETMT135 - WA RES NET -10
3 020ALTB15R-WA OUTD AR LGT 1,131 150,85 1,22:1 925 0.133
4 020ALTB15R-WA OUTD AR LGT -259
5 02RESD0016-WA RES SRVC 1,55,1~104,82,33 99,024 15,735 0.0673
6 02RESD0016-WA RES SRVC -570,130
.7 02RESDoo17-BILL ASSISTANC 64,105 4,317,85 3,814 16,808 0.0674
8 02RESDoo17-BILL ASSISTANCE -25,90
9 02RESD0018-WA 3 PHASE RES 2,611l 193,707 91l 26,714 0.0740
10 02RESD0018-WA 3 PHASE RES -82
11 O2RESD018X-WA 3 PHASE RES 600 43,731 25 24,12C 0.0725
12 02RESD018X-WA 3 PHASE RES -186
13 02RFNDCENT - CENTRALIA RFND -1
14 02ZMERGCR-MERGER CREDITS 4
15 ACQUISITION COMMITMENT-A and 194
16 BPA BALANCING ACCOUNT -522,412
17 SMUD REVENUE IMPUTATIONS -83,1~
11l UNBILLED REV - UNCOLLECTIBLE 1,00
19 UNBILLED REVENUE -65 271,00 -0.4015
20 WYOMING
21 05LNXOO109-REF/NREF ADV +79C
22 05NETMT135 - EXPERIMENTAL 285 22,313 24 11,875 0.0783
23 050AL T015R-OUTD AR LGT SR 99 154,169 1,14E 86 0.1551
24 05RESOO2-WY OPTIONAL 55,481 3,819,59:1 4,085 13,583 0.068
25 05RESD0-WY RES SRVC 870,219 70,48,991 93,212 9,33 0.0810
26 05RESDO18-RES 3 PHASE SR 11:1 8,191 9 12,556 0.0725
27 05RESD018X-RES 3 PHASE SR 174 12,39E 2 87,00 0.0712
21l OSRFNDCENT-CENTRAIA RFND -il
29 ACQUISITION COMMITMENT-A and 20,85~
30 ACQUISITION 16,09!:
31 SMUD REVENUE IMPUTATIONS 102,34
32 09NETM135 - WY RES NET 491 4
~09RESD002 136 9,972 26 5,231 0.0733
34 UNBILLED REV - UNCOLLECTIBLE -22,00
35 UNBILLED REVENUE 17,186 1,736,00 0.1010
36 05RESDOO2-WY RES SRVC 75,432 6,29,23 8,381 9,00 0.083
31 05RESDOO18-RES 3 PHASE SR 1 130 1 1,00 0.130
31l 05UPPLooR-BASE SCH FALL 1
39 090AL T207R-SECURITY AR LG 87 25,093 101 861 0.288
4C 09NETMT135 - WY RES NET 32 2,109 1 32,00 0.069
41 TOTAL Billed 54;1, 'I "' 3,=1,706,12 31,79C 0.061
42 Total Unbilled Rev.(See Instr. 6)124,68 C C 0.149~
43 TOTAL 54,361,78 3,551,703,1,706,121 31,~0.06:1
FERC FORM NO.1 (ED. 12-95)
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo8/Q4
(2) 0 A Resubmission 03131/200 ---
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effec 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 accont in the sequence followed in "Elecric Operating Revenues," Page
30-301. If the sales under any rate schedule are classified in more than one revenue account, List the rae schedule and sales data under eah
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 pea 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 divide by the number of biling periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a foonote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each appicable revenue account subheading.
ine Numoer ano I me or Hate scneouie Mwn ~oia nevenue l\verage.I'\umUör 'Pet' ?~sfoñl:r iiRtgolderNo.(a)(b)(c)ofc~mers
(f)
1 CUSTOMER COUNT - REGULAR
2 SMUD REVENUE IMPUTATIONS 8,785
:: 05RESOO2-WY OPTIONAL 46 3,15E 5 9,200 0.0687
4 05NETMT135 - EXPERIMENTAL 47 3,411 2 23,500 0.0727
E 09RESOO2 20,563 1,429,oo 741 27,750 0.0695
E 09RESD0 41,54E 3,118,555 3,3&12,292 0.0751
ì UNBILLED REVENUE 27::66,OO 0.2418
E LESS MULTIPLE BILLINGS -92,~
~
1C TOTAL RESIDENTIAL SALES 16,221,455 1,34,013,~1,457,64 11,129 0.0829
11
1~COMMERCIAL SALES
1::CALIFORNIA
14 OSHCKOON-CA NRES CHECK 1
15 OSNSV0025-CA GEN SRVC 65,447 8,242,032 6,912 9,469 0.1259
1 E 06GNSV025F-GEN SRVC-c: 20 94 135,265 9:10,194 0.1427
11 OSNSVOA32-GEN SRVC-20 KW 79,767 8,321,451 87E 90,851 0.1043
1E 06LGSV048T-LRG GENSEAV 71,047 4,n4,991 1C 7,104,700 0.0672
1 ~ 06LGSVOA36-LRG GEN SRVC-O 84,92::7,403,73f 192 442,307 0.0872
2C 06LNX00102-L1NE EXT 80"1 G 12,87f
21 06LNX00105.CNTRCT $ MIN G 4,6O
Z 06lNX00109-REF/NREF ADV +n,~
2::06LNX003O - 80"1 MONTHLY MIN 3,98:
2~06LNX00311 - LINE EXT 8010 7H
25 O6AL T015N-OUTD AR LGT SR 751 151,111 545 1,378 0.2012
26 06RCFL002-AIRWAY & ATHLE 200 30,83 39 5,205 0.1519
27 06WHSV001-COMM WTR HEATI 221 23,83::29 7,621 0.1078
2E 06NMT32135-CA GEN SVC NET 14 1,494 1 14,00 0.1067
29 ACQUISITION COMMITMENT-A and 18,404
3C ACQUISITION 11,490
31 SMUD REVENUE IMPUTATIONS 45,591
3:: 06LNX0011o-REFINREF ADV +5,698
3:UNBILLED REVENUE 936 211,00 0.2254
34 IDAHO
3E 07CISH0019-COMM & IND SPA 8,79E 593,236 191 46,052 0.0674
3E 07GNSVOO-GEN SRVC-LRG P 193,001 11,842,510 935 206,418 0.0614
31 07GNSVOO9-GEN SRVC-HI VO 32,424 1,430,828 1 32,424,00 0.041
38 07GNSV0023-GEN SRVC-SML P 118,264 9,441,262 5,96 19,83 0.0798
39 07GNSV005-GEN SRVCOPTION 64 44,375 ::324,00 0.0685
40 07GNSVOOA-GEN SRVC-LRG P 30,575 1,973,616 21E 141,551 0.06
41 TOTAL Billed 54,237,10( ': i:':':1,706,121 31,79C 0.061
42 Total Unbilled Rev.(See Instr. 6)12~C (0.149~
43 TOTAL 54,361,7 3,551,703,34 1,706,121 31,~0.06::
FERC FORM NO.1 (ED. 12-95)Page 304.3
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ei A Resubmission 03131/200
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Res which is reported on Pages 310-311.
2. Provide a subheading and total for each precribed operating revenue account in the sequence followe in "Elecric Operating Revenues," Page
30-301. 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 sered under more than one rate schedule in the same revenue account classifcaion (such as a genera residential
schedule and an off peak water heating schedule), the entries in column (d) for the speal schedule should denote the duplication in number of reprted
customers.
4. The average number of customers should be the number of bills redere during the year divided by the number of billng periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment claue state in a foote the esimated additiona reveue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for eah apicae reue acunt subheading.
Une Numoer ana I me OJ Haie scneauie Hevenue 7teragerilumoo ~vvn_ OJ ~aies ~~folderNo.(a)(b)(c)of Cfihomers pery~tomer
(f)
1 07GNSV006A-GEN SRVC-LRG P -1
2 07GNSV023A-GEN SRVC-SML P 16,03€1,322,90 1,151 13,93 0.0825
:3 07GNSV023A-GEN SRVC-SML P 241
4 07GNSV023F-GEN SRVC SML P 1~2,687 7 2,714 0.1414
5 07LNXoo010-MNTHL Y 80%GUAR 11,67C
E 07LNXoo03-ADV 8O%MO GUAR 293,307
7 07LNX000-ADV+REFCHG+80%33,53
8 070AL TOO7N-SECURITY AR LG 2~91,36 191 1,325 0.3611
~070ALT07AN-SECURITY AR LG 1~4,867 15 867 0.3744
1C 07LNX00312 - ID UNE EX 1,21
11 07NMT23135 - ID NET MTR -~25 1 3,OO 0.0853
12 07LNX0015-ANNUAL 8OkGUAR 1,16:
13 07LNX00311 - UNE EXT 80%20,323
14 07LNX0020 - ID MONTHLY 611
11:07LNX00300 - 80% MONTHLY MIN 1,54E
1E ACQUISITION COMMITMENT-A and 32,24€
11 ACQUISITION 31,291
1€BPA BALANCING ACCOUNT 161
H SMUD REVENUE IMPUTATIONS -23,~
2C UNBILLED REVENUE -1,59S -67,OO 0.0419
21 OREGON
2~01COSTOO23, OR GEN SRV, COST 997,1~41,26,~0.0414~01COST008 - 01 LGSVOO 760,78£28,737,88~0.0378
2~01COST023F - OR GEN SRV -3,16 139,87£0.042
25 01COSTB023 - OR GEN SRV,91,61::3,931,341 0.0429
26 01COSTL03 - OR LRG GEN SRV,1,055,91E 41,744,837 0.0395
27 01COSTS028, OR GEN SERV,1,973,039 80,323,35S 0.047
2S 01COSTS030 - OR GEN SRV CBS ,.1,09 38,63S 0.032
29 01GNSB0023 - BPA DISC, c: 30 kW -42,190
3(01GNSBOO23, OR GEN SRV, BPA,5,100,20:1 14,494
31 01 GNSB008 - OR GEN SRVC,-71,86
32 01GNSB0028, OR GEN SRV, BPA,2,872,75E 577
3S 01GNSB023T - OR GEN SRV - TOU 26,94 Sf
34 01GNSB023T - OR GEN SRVC,-264
35 01GNSV0023, OR GEN SRV, c: 30 -E 36,744,915 55,18~-6,124.1525
3E 01 GNSV008, OR GEN SRV ,. 30 41,052,982 8,99t
37 01 GNSV023F - OR GEN SRV -9,88~1,207,01 86 11,44 0.1221
3E 01GNSV023M - OR GEN SRV,1€1,49 1 18,00 0.081
31l 01GNSV023T, OR GEN SRV, TOU 161,91 243
4C 01HABT0023, OR HABITAT 2,22 92,877 0.0417
41 TOTAL Billed S4~~1,706,12 31,7AC 0.061
42 Total Unbilled Rev.(See Instr. 6)124,(0.149
43 TOTAL 54,361,78 3,551,703,34T 1,706,12 31,SS 0.06::
FERC FORM NO.1 (ED. 12-9)Page 304.4
............................................
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 03131/200
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue accont in the sequence followed in "Electric Operating Revenues," Page
30-301. 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 accunt subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue accunt classification (such as a general residential
scheduie and an off peak water heating schedule), the entries in column (d) for the speial schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendered during the year divided by the number of billing periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue biled pursuat thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue acunt subheading.
une Numoer ano ime 01 Hate scneauie Myvn ;:010 Mevenue l\verage l'IumOer ~:n?~lo~:r v ~folder
No.(a)(b)(c)ofC~~omers (f)
1 01 HABTB023 - OR HABITAT 168 7,422 0.042
2 01LGSB00, GEN DEL SRV, ~ 200 -26,637
3 01 LGSB000, GEN DEL SRV, ~ 200 882,05~3::
4 01 LGSV0030 - OR LRG GEN SRV,16,60,191 63~
5 01LGSV008-1ooKW AND OVR 7,897,065 95
6 01 LGSV048M-LRG GEN SRVC 1 52,699 2,253,981 1 52,699,00 0.0428
1 01LNX001OO-L1NE EXT 60% G 8,55C
S 01LNX00102-L1NE EXT 80% G 43,328
9 01LNX00103.L1NE EXT 80% G 3,054
10 01LNX00105-eNTRCT $ MIN G 15,347
11 01LNX00109.REF/NREF ADV +1,826,874
12 01 LNX0011 o-REF/NREF ADV +14,221
1::01LNX003oo - LINE EXT 80%76,125
14 01 LNX00311 - LINE EXT 80% G 45,654
15 01LNX00312 - OR IRG LINE EXT -175
1E 01 LPRS047M.PART REO SRVC 3,638 38,293 3 1,212,667 0.105
11 01NMT23135 - OR NET MTR, GEN,27,439 44
1E 010ALT014N-OUTD AR LGT NR 1,674 247,61S 1,196 1,40 0.1479
19 010ALT014N.OUTD AR LGT NR -710
20 01 OAL T015N-OUTD AR LGT NR 6,273 797,251 3,151 1,991 0.1271
21 01PTOU0023, OR GEN SRV, TOU 4,076 165,726 0.047
22 01PTOUB023, OR GEN SRV, TOU 596 24,172 0.04
23 01 RCFLoo54REC FIELD LGT 1,057 92,713 102 10,36 0.0877
24 01 RENW0023, OR RENW USAGE 8,46 357,684 0.0423
25 01 RENWB023 . OR RENEW ABLE 500 26,151 0.0437
26 01 STDAY023 - OR DAY STD OFR,1,87S 116,84 0.0622
27 01STDAY028 - OR DAY STD OFF,3,123 193,459 0.0619
2S 01STDAY030 - OR STD DAY OFF,4,48 275,221 0.0614
29 BPA BALNCING ACCOUNT -6,16C
30 01 LGSB008 - LG GEN SVC ~-1,851
31 01 LGSBOO - LG GEN SVC ~47,471 1
32 01NMT28135 - OR NET MTR, GEN,58,101 12
33 01NMT30135 - OR NET MTR, GEN,3,962 ~
34 01LGSV028M - OR LGSV, ..100 35C 25,06 1 350,00 0.0716
35 01GNSV030M - OR GEN SRV, 200 2,34 124,084 1 2,345,00 0.0529
3€01GNSV0728 - OR GEN SVC DIR 32,08S 2
31 01GNSV0730 -OR GEN SVC DIR 841,47S 37
3E 01GNSV0748 LG GEN SVC DIR 35,863 1
3~ OR SB4 RECOVERY 9,36,575
40 OR SB 838 RECOVERY 3,731,684
41 TOTAL Billed 54,237 ~ k 3'i.'34lr 1,706,12 31,79 0.061
42 Total Unbilled Rev.(See Instr. 6)124,C 0.149
43 TOTAL 54,361 ,7 3,551,703,34 1,706,12 31,86 0.0631
FERC FORM NO.1 (ED. 12-95)Page 304.5
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo8/Q4
(2) ñA Resubmission 031311200
SALES OF ELECTRICITY BY RATE S(HEDULES
1. Report below for each rate schedule in efec during the year the MWH of elecricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resle which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Elecric Operating Revenues," Page
30-301. If the sales under any rae schedule are classified in more than one revenue accunt, Ust the rate schedule and sales data under each
applicable revenue account subheaing.
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 deote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills redere during the year divide by the number of billng periods during the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustmen clause state in a foonoe the estimated adtional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applie revenue acunt subheading.
ine Numoer ana I me OJ Mate scneauie Mvvri ;:ULU Mevenue Average Numoer ~yvi~ui_~_aies ~R~clerNo.(a)(b)(c)of CfJi0mers Per '(tMstomer
(f)
1 SMUD REVENUE IMPUTATIONS 655,031
~UNBILLED REVENUE 13,795 967,OO 0.0701
~UTAH
-4 OSCFRoo051-MTH FAC SRVCHG 44,155
5 OSCFROO52-ANN FAC SVCCHG 2
.6 08CHCKooN-UT NRES CHECK :3
7 08COOLKPRN - A1C DIRECT LOAD 2,285
8 08GNSVOO-GEN SRVC-DISTR 4,754,62:3 30,069,070 11,146 426,5n 0.06
~ OSGNSVOO9-GEN SRVC-HI VO 241,245 10,33,417 1S 13,402,500 0.0428
1C OSGNSV0023-GEN SRVC-DISTR 1,204,527 92,648,53 66,055 18,235 0.0769
11 08GNSVOOA-GEN SRVC-ENERG 196,695 16,66,562 1,700 115,703 0.0847
1~08GNSVOOB-GEN SRVC-DEM&2,920 193,13:12 243,333 0.061
1~08GNSVOOM-MNL DIST VOL TG 3,154 170,815 7 450,571 0.0542
104 08GNSVOOA-GEN SRVC HI VO 25,210 1,202,659 2 12,605,00 O.04n
15 OSGNSVOOM-MANL HIGH VOLT 19,949 83,760 1 19,949,00 0.0418
1E OSGNSV023F-GEN SRVC FIXED 1,42 150,813 121 11,752 0.1061
1i OSGNSV023M-GNSV DIST VOLT 100 8,481 6 18,00 0.0785
U OSGNSV06AM-MNL ENERGY TOO 425 49,11~2 212,500 0.1156
tl OSGNSV06MN-GNSV DIST VOLT 26,731 1,58,28!432 61,8n 0.0593
2(08LNXOO2-MTHL Y 80"1 GUAR 55,67E
21 08LNXOO-ANNUAL SO"lGUAR 79,13
2~08LNXOO-FIXD MTHL Y MIN 14,23i
2~08LNX0014-8Ok MIN MNTHL Y 2,171,~
24 08LNXOO17-ADV/REF&80"IANN 112,144
25 08LNX00158-ANNUALCOST MTH 32,954
2e 08LNXOO - LINE EXT 80"1 PLUS 199,592
27 08LNX00310 - IRR, 80"1 ANNUAL 4,06
2S 08LNX00312 UT IRG LINE EXT 2,557
29 08NMT23135 - UT NET MTR, GEN,239 19,709 1€14,938 0.0825
30 080AL T007N-SECURITY AR LG 9,152 1,980,531 4,7Ol 1,94 0.2164
31 08POLE0075.POLES W/L1GHT 3204 2
ã2 08PRSV031 M-BKUP MNT&SUPPL 14,711 84,96 ~4,903,661 0.0578
3:08PTLDON-POST TOP LIGHT ~4,63 i 8,851 0.0748
34 08TOSS015F-mAFFIC SIG NM 231 18,725 3~7,21~0.0811
3!08TOSS0015-TRAF & OTHER 1,12~94,56 44~2,554 0.083
3E 08MONL0015-MTR OUTDONIGHT 11,~811,oo~291 39,~0.06
37 ACQUISITION 148,02~
3S SMUO REVENUE IMPUTATIONS 716,757
39 08LNX0011 - LINE EXT 8Ok 82,321
4C 08GNSVOO8 - UT GEN SVC TOU :-92,74f 51,526,21S 1~6,99,~0.0554
41 TOTAL Biled ~237'1"".1,706,12 31,79(0.061
42 Totl Unbiled Rev.(See Instr. 6)124,6 ((0.149
43 TOTAL 54,361,7 3,551,703,349f 1,706,12 31,~0.06
FERC FORM NO.1 (ED. 12-9)Page 30.6
............................................
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008lQ4
(2) 0 A Resubmission 03131/200
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricit 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
30-301. If the sales under any rate schedule are clasified 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 classificaion (such as a general residential
schedule and an of 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 billng periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a foonote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue account subheading.
une Numoer ana ime or Hate scneauie Mwn~oio Hevenue Average. Numoer ~!yn~OT_?_~eS ~~RigoÏcerNo.(a)(b)(c)of cqsJiomers Per 9~stomer
(f)
1 08GNSV008M - UT GEN SVC TOU 38,96 2,272,11E 5 7,792,800 0.0583
2 UNBILLED REVENUE -42,172 -1,89,OO 0.048
:3 WASHINGTON
4 02GNSB0024-WA GEN SRVC DO 41,173 3,018,724 3,203 12,855 0.0733
E 02GNS804-WA GEN SRVC DO -12,651
E 02GNSB024F-GEN SRVC DOMIF 215 19,~E 26,875 0.0923
i 02GNS8024F-GEN SRVC DOMIF ~
8 02GNSB24FP-WA GEN SVC 64 123,96 104 6,192 0.1925
E 02GNSB24FP-WA GEN SVC -2(
1C 02GNSV0024-WA GEN SRVC 472,04i 31,457,81E 13,821 34,14C 0.06
11 02GNSV024F-WA GEN SRVC-FL 1,20i 120,541 121 9,975 0.0999
1~02LGS80-LRG GEN SVC IRG 77,13:1 4,256,415 91 847,604 0.0552
1~02LGS80-LRG GENSVC IRG -26,392
14 02LGSVoo36-WA LRG GEN SRV 680,057 38,135,069 80E 841,655 0.0561
H 02LGSV048T-LRG GEN SRVC 1 134,165 6,837,482 25 5,366,6O 0.0510
1E 02LNX00102-L1NE EXT 80"1 G 55,319
17 02LNXOO103-L1NE EXT 80"1 G 2,74E
1E 02LNXOO105-CNTRCT $ MIN G 8~
19 02LNXOO109REF/NREF ADV +210,98::
2(02LNXOO11 Q-REF/NREF ADV +13,94lì
21 02LNXOO112-YR INCURRED CH 66E
22 02LNXOO-L1NE EXT 80"1 G 3,74E
2~02LNX0010 - IRG, 80"1 ANNUAL 2,685
2l 02LNXOO311 - LINE EXT 80"1 14,23E
2E 020ALT015N-WA OUTO AR LGT 1,68E 207,83 87E 1,925 0.1233
2E 020ALTB15N-WA OUTO AR LGT 631 83,45 548 1,151 0.1323
21 020ALTB15N-WA OUTO AR LGT -190
2E 02RCFLOO54-WA REC FIELD L 261 21,082 29 9,OO 0.0808
29 02RFNDCENT - CENTRALIA RFND 7
30 02ZMERGCR-MERGER CREDITS 7
31 02NMT24135, Net metering, WA 2 91 1 2,00 0.045
32 ACQUISITION COMMITMENT-A and 17:3
3:3 SPA BALNCING ACCOUNT -58,012
34 SMUD REVENUE IMPUTATIONS -728,62S
35 UNBILLED REVENUE -5,00 120,OO -0.0236
36 WYOMING
37 05CHCKooN-WY NRES 1
3ll 05NSV005-WY GEN SRVC 1,120,24S 76,659,924 20,821 53,80 0.06
31l 05GNSV02F-GEN SRVC-FL RA 1,00 121,44 191 5,246 0.1212
4C 05LGSVQ0.WY LRG GEN SRV 205,752 10,84,661 11l 10,82,05:0.0527
41 TOTAL Billed 54~~1,706,12 31,79t 0.061
42 Total Unbilled Rev.(See Instr. 6)124,((0.149~
43 TOTAL 54,361,7 3,551,703,349\1,706,12 31,~0.06~
FERC FORM NO.1 (ED. 12-95)Page 304.7
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo8/Q4
(2) Fi A Resubmission 0331/20
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in efect during the yea the MWH of elecricity 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 preribed operating revenue account in the sequence followed in "Elecric Operating Revenues," Page
300-301. If the sales under any rate scheule are classified in more than one revenue accunt, List the rate schedule and sales dat under each
applicae 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 pek 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 reere during the year divided by the number of billng periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnoe the estimated additional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of yer for each apicae revenue acnt subheading.
¡Line Numoer ana I me OJ Maie scneauie Mvvn ::oia Mevenue Average. Numoer ?i:ny~sfJ::r y ~igolderNo.(a)(b)(c)of CfJiomers (f)
1 05LGSV04T-LRG GEN SERV 8,471 437,66 0.0517
:1 05LGSV048T-LRG GENSRV TIM 3,234 251,523 1 3,234,00 0.On8
:: 05LNX001oo-L1NE EXT 60% G 88
4 05LNX00102-L1NE EXT 80% G 758,828
5 05LNX00103-L1NE EXT 80%80a
E 05LNX00105-CNTRCT $ MIN G 5,~
7 05LNX00109-REF/NREF ADV 588,3!Y
e 05LNX00114-TEMP SVC 12MO::-4,821
~ 05NMT25135 - WY NET MTR, GEN,50:41,07C 5 100,40 0.0818
1C 05NMT25135 - WY NET MTR, GEN,3,025 471,17C 1,795 1,685 0.1558
11 05RCFLoo54-WY REC FIELD L 73i 6O,47E 52 14,173 0.0821
12 05RFNDCENT-CENTRALIA RFND ~
1:: 09GNSV0025-GEN SVC-SINGLE 8l 1
14 05LNX003oo - LINE EXT 80%301,471
15 05LNX0011 - LINE EXT 800k 33,92.
1£ ACQUISITION COMMITMENT-A and 28,52E
17 ACQUISITION 22,OH
H SMUD REVENUE IMPUTATIONS 144,89
H UNBILLED REVENUE 2O,02 1,708,OO 0.08
2C 05GNSV0025-WY GEN 9O,66E 6,374,nC 1,72E 52,440 0.0703
21 05GNSV025F-GEN SRVC-FL 1~19,Q9 3C 6,467 0.0984
22 05LNX00102-L1NE EXT 80% G 5,32f
2::05LNX00109-REF/NREF ADV +87,OO
24 05LNX00110-REF/NREF ADV +1,~
25 05LNX00114-TEMP SVC 161
26 09GNSV005-GEN SVC-SINGLE 50,83e 3,214,711 816 62,301 0.062
27 09GNSV025F-GEN SVC-FIXED 3l 3,85€7 5,571 0.0989
2a 09GNSV025M-GEN SVC-MANUAL 2,19€144,98 1 2,196,00 0.06
29 05NMT25135 - WY NET MTR, GEN,105 6,74E 1 105,00 0.062
30 090AL T207N-SECURITY AR LG 26€70,671 144 1,847 0.2657
31 09SLCU2123-MTR OUTOONIGHT 4S 4,60 2 24,00 0.0959
32 05LNXOO - LINE EX 80%5,52€
33 05LNX00311 - LINE EXT 80%2,285
34 SMUD REVENUE IMPUTATIONS 9,22
35 LESS MULTIPLE BILLINGS -25,582
3€
37 TOTAL COMMERCIAL SALES 16,055,18:1 1,062,312,561 210,217 76,374 0.062
3€
39 INDUSTRIAL SALES
4C CALIFORNIA
41 TOTAL Billed 54~'~"m'.1,706,127 31,79C 0.061
42 Total Unbilled Rev.(See Inst. 6)124,68 .C C 0.149:¡
43 TOTAL 54,361,7 3,551,703,1,706,121 31,86 0.06
FERC FORM NO.1 (ED. 12-9)Page 304.8
............................................
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo8/Q4
(2) Ei A Resubmission 03/31/2009
SALES OF ELECTRICITY BY RATE Si HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-11.
2. Provide a subheading an total for each prescribe operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate scheule are classified in more than one revenue account, LIst the rate scheule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served undr more than one rate schedle in the same revenue accunt classification (such as a general residential
schedule and an of 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 bils rendered during the year divided by the number of billng period during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additiona revenue biled pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
ine Numoer ana 1 me or Naie scneaUle Mvvn ::010 Nevenue Average I'lumaer '~"'i.u._'t..ies ~~igolerNo.(a)(b)(c)
of CfJ,0mers Per YiMstomer
(f)
1 06NSV0025-CA GEN SRVC 7~97,725 96 7,84 0.1298
2 06GNSVOA32-GEN SRVC-20 KW 2,10~250,03 2S 75,071 0.1190
:3 06LGSV048T-LRG GEN SERV 48,7OC 3,202,77C 5 9,740,OO 0.068
4 06LGSVOA36-LRG GEN SRVC-O 6,09~584,37~15 406,2O 0.0959
5 06LNX00109-REF/NREF ADV +1,554
E ACQUISITION COMMITMENT-A and 3,935
7 ACQUISITION 2,451
S SMUD REVENUE IMPUTATIONS 8,90~
9 UNBILLED REVENUE 11 27,00 2.4545
1C IDAHO
11 07CFROO1-MTH FACILITY S 2,211
12 07CISH0019-COMM & IND 17(12,111 4 42,500 0.0713
1::07GNSVOO-GEN SRVC-LRG 113,38 5,821,761 11E 96,881 0.0513
14 07GNSV008-GEN SRVC-MEDIU 2,54 140,89A 2 1,272,00 0.0554
15 07GNSV0009-GEN SRVC-HI VO 77,12E 3,462,OO 11 7,011,455 0.049
1€07GNSV0023-GEN SRVC-SML P 11,367 874,25~35~32,201 0.0769
17 07GNSVOO-GEN SRVCOPTION 1,61C 89,87~1 1,610,00 0.0558
1E 07GNSVOOA-GEN SRVC-LRG P 5,2OE 333,54 ~153,11S 0.061
1~07GNSV023A-GEN SRVC-SML P 2,169 198,30(25€8,47::0.0914
2(07GNSV023A-GEN SRVC-SML P 1
21 07GNSV023S-IDAHO TRAFFIC e 1,05C 3 2,667 0.1313
22 07LNX005-ADV 8O%MO GUAR 1,507
2~07LNX00108-ANN COST MTHL Y 1,99
24 07LNX003oo - 80% MONTHLY MIN 3,929
25 070AL T007N-SECURITY AR LG 12 4,57:3 1€750 0.3811
2E 070ALT07AN-SECURITY AR LG 2 847 ::667 0.4235
27 07SPCLOO1 1,339,700 54,483,06 1 1,339,700,00 0.047
2S 07SPCLoo02 107,895 4,188,089 1 107,895,00 0.0388
29 ACQUISITION COMMITMENT-A and 137,90S
30 ACQUISITION 133,815
31 BPA BALANCING ACCOUNT 195
32 SMUD REVENUE IMPUTATIONS -975,241
3:UNBILLED REVENUE -18,48E 51,00 -0.008
34 OREGON
3E 01COSToo23, OR GEN SRV, COST 22,320 923,325 0.0414
3€01 COSTOO - 01 LGSV008 1,506,735 56,236,1n 0.0373
31 01 COST023F - OR GEN SRV -::155 0.0517
3€01COSTB023 - OR GEN SRV,37C 15,86S 0.0429
39 01COSTL030 - OR LRG GEN SRV,225,52:3 8,968,212 0.038
40 01COSTS028, OR GEN SERV,109,351 4,449,902 0.0407
41 TOTAL Biled 54~'~ .~~1,706,12 31,79 0.061
42 Total Unbiled Rev.(See Instr. 6)124,6 (0.149~
43 TOTAL 54,361,78 3,551,703,34 1,706,121 31,86 O.~
FERC FORM NO.1 (ED. 12-95)Page 30.9
Page 304.10
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 0331/20
SALES OF ELECTRICITY BY RATE SC HEDULES
1. Report below for each rate schedule in effec during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding dae for Sales for Resae which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribe operating revenue accunt in the seuence followed in "Elecric Opeting Revenues," Page
30-301. If the sales under any rate schedule are classifie in more than one revenue accnt, Ust the rate schedule and sales data under each
applicable revenue account subheang.
3. Where the same customers are served under more than one rate scedle in the same revenue account classifcation (such as a general residential
schedule and an off pea 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 bils rendere during the year divided by the number of biling periods during the year (12
if all bilings 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 unbiled revenue as of end of year for eac applicae revenue account subheading.
..ina Numoer ana I lle OT Naie scneauie Mvvn;:oio Nevenue Average Numoer ~vvn~OT_~_ales ~GWolerNo.(a)(b)(c)
of CqsJiomers Per ?~stomer
(f)
1 01GNSBO23 - BPA DISC, oe 30 -136
2 01GNSB003, OR GEN SRV, BPA,23,328 6::
3 01 GNSBOO28 - OR GEN SRVC,-284
4 01GNSB008, OR GEN SRV, BPA,21,828 E
5 01GNSV0023, OR GEN SRV, oe 30 8n,482 1,156
6 01 GNSVOO28, OR GEN SRV ~ 30 2,89,417 53E
7 01 GNSV023F - OR GEN SRV -1 754 ::333 0.754
8 01GNSV023M - OR GEN SRV,4 898 1 4,00 0.2245
9 01GNSV023T, OR GEN SRV, TOU 3,169 4
10 01HABTOO23, OR HABITAT 11 502 0.04
11 01LGSVOO30 - OR LRG GEN SRV,5,137,448 1n
12 01LGSVOO8-1OOKW AND OVR 13,65,901 115
13 01 LGSV048M-LRG GEN SRVC 1 522,56 21,40,133 5 104,512,60 0.0410
14 01LNXOO102-L1NE EXT 80% G 2,583
15 01 LNXOO1 05-CNTRCT $ MIN 3,09
16 01 LNXOO109REF/NREF ADV 2,225
17 01 LNXOO300 - LINE EXT 8Ok 12,514
18 01LPRS047M-PART REO 573,261 23,387,391 4 143,315,250 0.0408
19 01NMT28135 - OR NET MTR, GEN,7,438 ~
20 010ALT014N-OUTD AR LGT NR 5 610 5 1,00 0.1220
21 010ALT014N-OUTD AR LGT -2
22 01 OAL T015N-OUT AR LGT 361 44,649 155 2,368 0.1217
23 01PTOUOO23, OR GEN SRV, TOU sa 2,84 0.0418
24 01 RENW0023, OR RENW USAGE 284 11,n4 0.0415
25 01 RENWB023 - OR RENEWABLE 1 56 0.0560
26 BPA BALANCING ACCOUNT -932
27 01STDAY023 - OR DAY STD OFR,32 1,913 0.0598
28 01LGSV028M - OR LGSV, oe1oo 44 2,642 1 44,00 0.06
29 OR SB 408 RECOVERY 6,055,748
30 OR SB 838 RECOVERY 2,4n,400
31 SMUD REVENUE IMPUTATIONS 423,011
32 UNBILLED REVENUE -35,752 -1,727,00 0.0483
33 UTAH
34 OSCFR0051-MTH FAC SRVCHG 16,326
35 08EFOPOO21-ELEC FURNACE 0 1,89 127,35 2 94,00 0.0674
36 08EFOP021 M-ELEC FURNACE 0 1,45 144,44 3 485,00 0.093
37 08GNSVQ0-GEN SRVC-DISTR 762,93 51,857,232 1,309 582,837 0.06
31 08GNSVoo9-GEN SRVC-HI VO 2,459,783 99,732,184 111 22,160,207 0.045
39 08GNSVOO23-GEN SRVC-DISTR 61,031 4,757,736 3,749 16,279 0.0780
40 OSNSVOOA-GEN SRVC-ENERG 47,102 4,56,191 245 192,253 0.0970
41 TOTAL Billed 54,237,10( 3,533,106,34j 1,706,12 31,79C 0.061
42 Total Unbilled Rev.(See Instr. 6)124,~C C 0.149
43 TOTAL 54,361,7 3,551,703,34 1,706,121 31 ,sa 0.063
FERC FORM NO.1 (ED. 12-95)
............................................
Name of Respondent This wort Is: Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/209
SALES OF ELECTRICITY BY RATE S(HEDULES
1. Report below for each rate schedule in effec during the year the MWH of elecricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is repoed on Pages 310-311.
2. Provide a subheading and total for each prescribed oprating revenue account in the sequence followe in "Electric Operating Revenues," Page
30-301. If the sales under any rate schedule are classified in more than one revenue accunt, List the rate schedule and sales data under each
applicale revenue account subheading.
3. Where the same customers are served under more than one rate schele in the same revenue accont classificaion (such as a general residtial
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. Th average number of customers should be the number of bils rendered during the year divided by the number of billng periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a foonote the estimated addtional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue acount subheading.
I Line Numoer ana I ite OT Maie scneauie Mvvn ~oia Hevenue Average_ Numoer ~..'i.ul_ì'_ales 'l ~'Wolder
No.(a)(b)(c)of Cfci0mers Per C(~stomer
(f)
1 OSGNSVOOB-GEN 3,36 250,026 /48,571 0.0743
~ OSGNSVOOM-MNL DIST VOL TG 54S 35,890 1 548,00 0.0655
3 08GNSVOOA-GEN SRVC HI 18,261 1,088,58E E 3,043,500 0.0596
4 OSGNSVOOM-MANL HIGH 1,087,32:2 41,289,769 1~83,640,154 0.0380
5 08GNSV023F.GEN SRVC FIXED 4 1,634 1 4,00 0.4085
6 08GNSV06MN-GNSV DIST VOLT 1,224 81,231 3C 40,80 0.06
7 08GNSV09AM-MAN TOD HIVOL T 1,158 104,996 1 1,158,00 0.097
8 08LNXOO2-MTL Y 80% GUAR 5,815
~ 08LNX0014-% MIN 50,159
1C 08LNXOO17 -ADV /REF&80%ANN 3,61:2
11 08LNX00311 - LINE EXT 80%1,84:2
12 08LNX003O - LINE EXT 80% PLUS 5,745
1~08LNX00310 -IRR, 80% ANNUAL 6,35E
14 080AL T007N-SECURITY AR 1,5OE 296,995 53 2,826 0.196
15 08PRSV031 M-BKUP MNT&SUPPL 5C 26,611 1 50,00 0.5322
1E 08TOSS0015- TRAF & OTHER S ~3,165 ~5,375 0.0736
1¡08MONL0015-MTR OUTDONIGHT 11 2,792 E 1,833 0.2538
H OSSPCL0010SSPCLOO1 56,942 22,311 ,17~1 566,942,00 0.0394
H OSSPCL0002 961,251 27,824,0~1 961,257,00 0.0289
2(OSSPCLOO 673,34 23,196,53C 1 673,34,00 0.03
21 OSSPCLOO5 255,361 9,218,335 1 255,361,00 0.031
22 ACQUISITION 151,63;
2:3 SMUD REVENUE IMPUTATIONS 733,43~
24 08GNSV06AM-MNL ENERGY TOD 135 13,231 1 135,00 0.0980
25 08GNSVOOO8 - UT GEN SVC TOU ;;971,01C 56,115,345 115 8,443,56 0.0578
26 OSGNSVOOM - UT GEN SVC TOU 63,275 3,563,530 8 7,909,375 0.0563
27 UNBILLED REVENUE -25,601 -2n,OO 0.Q08
28 WASHINGTON
29 02GNSBOO24-WA GEN SRVC 2,86:2 201,799 102 28,059 0.0705
30 02GNSBOO24-WA GEN SRVC DO -559
31 02GNSB24FP-WA GEN SVC 1~2,161 1 13,00 0.166
32 02GNSVOO24-WA GEN SRVC 16,4n 1,122,489 36 45,019 0.0681
33 02GNSV024F-WA GEN 33 6,276 4 8,250 0.1902
34 02LGSVoo36WA LRG GEN SRV 133,66 7,679,00 128 1,04,250 0.0575
35 02LGSV04M.WA LRG GEN SRV 26,414 1,698,93~1 26,414,00 0.06
3E 02LGSV04T-LRG GEN SRVC 1 690,52:3 31 ,041 ,80S 33 20,924,939 0.0450
'37 020AL T015N-WA OUTO AR LGT 127 14,nS 4:2,953 0.1164
3S 020ALTB15N-WA OUTO AR LGT 32 4,2~19 1,68 0.133
sg 020AL TB15N-WA OUTO AR LGT -S
40 02PRSV47T-LRG PART REQMT 1,120 81,02E 1 1,120,00 0.0723
41 TOTAL Biled 54'e" 3!i'1'1 1,706,12 31,79C 0.061
42 Total Unbilled Rev.(See Instr. 6)124,((0.149:2
43 TOTAL 54,361,7 3,551,703,34 1,706,12 31,~0.06~
FERC FORM NO.1 (ED. 12-95)Page 30.11
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/20
SALES OF ELECTRICITY BY RATE S(HEDULES
1. Report below for each rate schedule in effect during the year the MWH of elecricity sold, reenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resae which is reported on Pages 310-11.
2. Provide a subheading and total for each prescribe operating revenue account in the sequence followed in "Elecric Operating Revenues," Page
30-31. 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 of peak water heating schedule), the entries in column (d) for the speial schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the numbe of bils rendered during the year divided by the number of billng periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a fonote the esimated additional revenuê billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applice revenue account subheading.
Line I'lumoer ana ime or Mate scneauie Mwn tíoia Mevenue Aveflge Numoer ~wn_or ?aies v ~~oIer
No.(a)(b)(c)of Cfci0mers Per ?~stomer
(f)
1 02LGSBOO36LRG GEN SVC IRG 4,51S 398,42::29 155,828 0.0882
2 02LGSB0036-LRG GENSVC IRG -61S
:3 ACQUISITION COMMITMENT-A and 12S
4 BPA BALNCING ACCOUNT -991
5 SMUD REVENUE -41,72C
6 UNBILLED REVENUE -2,1~-84,OO 0.0396
7 WYOMING
8 05GNSV0025-WY GEN SRVC 298,979 18,461,83 1,641 182,193 0.0617
9 05GNSV025F-GEN SRVC-FL RA 83 8,48 16 5,188 0.1022
10 05GNSV025M - General Servce 717 38,22!:1 717,00 0.053
11 05LGSV006-WY LRG GEN 1,240,88 61,66,865 56 22,158,64 0.0497
12 05LGSV04M-WY LRG GEN 511,54 23,513,93 4 127,885,500 0.04
1:3 05LGSV046T-LRG GEN SERV 34,173 1,676,746 0.0491
14 05LGSV048M-TOU::100 MAN 1,254,294 47,817,925 :3 418,098,00 0.0381
15 05LGSV048T-LRG GENSRV TIM 94,542 36,974,931 9 105,171,33 0.0391
16 05LNX001oo-L1NE EXT 6OÆ. G 18,309
17 05LNX00102-L1NE EXT 80% G 188,43
16 05LNX00105-CNTRCT $ MIN G 42,176
1S 05LNX00109-REF/NREF ADV +165,02
20 050AL T015N-OUTD AR LGT SR 89 12,783 47 1,894 0.1436
21 05PRSV033M-PART SERV REQ 1,106,342 50,429,55 5 221 ,268,400 0.04
22 09GNSV025M-GEN SVC-MANUAL 115 7,176 1 115,00 0.0624
2::ACQUISITION COMMITMENT-A an 127,50
24 ACQUISITION 98,417
25 SMUD REVENUE IMPUTATIONS 652,349
26 05LNX003oo - LINE EXT 80%2,909
21 UNBILLED REVENUE 82,02:3 5,86,00 0.0715
26 05GNSVQ05-WY GEN SRVC 25,327 1,679,03B 254 99,713 0.0663
2S 05NSV025M - General Servce 49 3,30 1 49,00 0.0675
3C 05LGSVOO-WY LRG GEN SRV 26,426 1,416,188 4 6,60,50 0.0536
31 05LGSV04T-LRG GEN SERV 1,224 56,5n 0.042
3.05LGSV048M-TOU::1ooKW MAN 34,769 13,671,34 4 87,442,250 0.0391
3:05LGSV048T-LRG GENSRV 808,93 34,823,514 11 73,539,455 0.040
34 05LNXOO102-L1NE EXT 80% G 1,221,04
35 05LNX00109-REFINREF ADV -27
3€05PRSV033M-PART SERV REQ 9,820 517,96 1 9,820,00 0.0527
37 09NSV0025-GEN 12,332 787,09 301 40,970 0.068
38 09GNSV025M-GEN SVC-MANUAL 4,67 250,942 3 1,559,00 0.0537
39 O9AL T207N-SECURITY AR 5 1,130 3 1,667 0.2260
40 09PRSV033M09PRSV03M 1,197 272,881 1 1,197,00 0.2280
41 TOTAL Billed 54,237,1 DC 3,533,106,34S 1,706,121 31,79C 0.061
42 Tota Unbilled Rev.(See Instr. 6)124'~C (0.1492
43 TOTAL 54,361,7 3,551,703,3491 1,706,121 31,8&0.06:3
FERC FORM NO.1 (ED. 12-9)Pag 30.12
............................................
............................................
Name of Respondent This 'ì0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ei A Resubmission 031311200
SALES OF ELECTRICITY BY RATE sc HEDULES .
1. Report below for each rate schedule in effec 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 310-11.
2. Provide a subheading an total for each prescribed operating revenue account in the sequence followe in "Electric Operating Revenues," Page
30-31. If the sales under any rate schedule are classified in more than one revenue account, List the rate scheule and saes data under each
applicabe revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue accunt classification (such as a general residntial
schedule and an off peak water heating schedule), the entries in column (d) for the speial scheule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendere during the year divied by the number of billng period during the year (12
if all bilings 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 unbiled revenue as of end of year for each applicable reenue account subheading.
tune Numoer ana ime OT Hate sceauie Mvvn '=010 Mevenue AVerag~~'\UmDer ~vvn_or ?aies ~~~okrNo.(a)(b)(c)of Cir omers Per r~stomer
(f)
1 LESS MULTIPLE BILLINGS -1,240
2
3 TOTAL INDUSTRIAL SALES 20,128,17 909,975,22E 11,191 1,798,603 0.042
4
5 IRRIGATION SALES
E CALIFORNIA
7 06APSV0020-AG PMP SRVC 69,21 6,686,37~1,347 51,381 0.09
e 06LNX00102-L1NE EXT 80% G 781
9 06LNX00103-L1NE EXT 80% G 1,921
10 06LNX00110-REFINREF ADV +13,03E
11 06LNX00312 - CA IRG LINE EX 2,37i
12 06USBROO-KLAM IRG ONPRJ 30,82 1,842,81~677 45,524 0.0598
1::06LNX00109-REF/NREF ADV +19!
14 IRRIGATION UNBILLED ~-1,OO 0.33
15 IDAHO
1E 07APSA010L -IRG & Pump BPA -3,47~
17 07APSA010L -IRG & Pump Large 485,95 33,272,601 3,227 150,591 0.0685
1E 07APSA010S -IRG & Pump Small 4,32 379,231 38E 11,205 0.0877
H 07APSAL10X -IRG & PUMP - Large 89,547 6,311,OH 792 113,06 0.0705
2C 07APSAS10X -IRG & PUMP - Small 1,68 161,111 21C 8,04 0.0954
21 07APSVCNLL-LRG LOAD CANAL 34,047 2,100,092 8E 386,898 0.0617
22 07APSVCNLS-SML LOAD CANAL 264 21,18f 1E 14,667 0.0803
2~07BPADEBIT-BPA ADJUST FEE -1,384
2~07LNXOO15-ANNUAL 80%GUAR 5,03E
25 07LNXOOD-ADV+REFCHG+80%141,261
26 07LNX00107-SUBD ADV &1,081
27 07LNX00310 80% ANNUAL 2,47::
28 07LNX00312 -ID LINE EXT 12,721
29 07APSN010L - ID LG IRR & PUMP 3,62 278,84 43 84,372 0.0769
30 07APSN010S - IRRIGATION,431 33,67':11 25,35 0.0781
31 07APSNS10X - IRRIGATION,46 4,36 2 23,00 0.09
32 IRRIGATION BPA BAL ACCT 299,36
33 OREGON
34 01APSV001-AG PMP SRVC BP 1,937,134 4,754
35 01APSV001-AG PMP SRVC BP -2,113
3E 01APSV041L-OR Pumping Serv 2,710,097 1,085
37 01APSV041L-OR Pumping Serv -3,650
3E 01APSV041T - AGR PUMP SRV -E
31; 01APSV041T - AGR PUMP 25,732 5E
4C 01APSV041X-AG PMP SRVC 79,401 23E
41 TOTAL Billed 54.2.1 ~. 3!ì34.1,706,12 31,19 0.061
42 Total Unbille Rev.(See Instr. 6)124,E 0.14~
43 TOTAL 54,361,7 3,551,703,34 1,706,12 31,86 0.06~
FERC FORM NO.1 (ED. 12-95)Page 304.13
Name of Respondent This~rtIS:Date of Report Year/Period of Reprt
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/200
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effec during the year the MWH of elecricit 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 subheaing and total for each prescribe oprating revenue accnt in the sequence followe in "Elecric Opeting Revenues," Page
30-301. If the sales under any rae scheule are classified in more tha one revenue accunt, Ust the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are seived undr more than one rae schedule in the same revenue acount classification (such as a genera residential
schedule and an off peak water heating schedule), the entries in column (d) for the speial schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills redere during the year divided by the number of billng periods during the year (12
if all billng are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a fonote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
Line Numoer ana i lle Oi Mate scneauie Mvvn ::oia Mevenue Average. Numoer 1~;'~'V.IJ0i~~_~es ~w~igorcrNo.(a)(b)(c)
of Cfcl0mers Per '(~$tomer
(f)
1 01 APSV41 XL-OR Pumping Seiv no 135,151 45
201COST001 133,591 5,427,95::0.0406
:3 01 COSTOO - 01 LGSV008 9,84 36,362 0.039
4 01 COSTS028, OR GEN SERV,282 11,531 0.049
5 01 GNSV0028, OR GEN SRV :; 30 8,46 ~
Eì 01 HABIT041 - 01 APSV001 AG ::134 0.047
7 01 LGSB008 - LG GEN SVC :;.23C
8 01 LGSBOO - LG GEN SVC :;74,1M;1
9 01LNX00102-L1NE EX 80% G 16S
1C 01LNX00103-L1NE EXT 80% G 14,022
11 01 LNX001 09-REF/NREF ADV +671
1~01LNX00110-REF/NREF ADV +95,39E
1::01LNX00310-L1NE EXTENSION 1,35
1~01 PTOU0041 - 01 APSV001 AG 64 22,94 0.0356
H 01RENEW041 - 01APSV001 AG 13'5,441 0.0406
1E 01SLXOO5-KLAMATH FALLS 124,65
1i 01SLXOO13-K FALLS IRG MI 7,68
1E 01SLXOO14-K FALLS IRG MI 21C
H 01STDAY041 - Daily Standard Ofer ~1,41f 0.042
2(01USBOF033-KLAMATH BASIN 45,975 823,45 65E 70,084 0.0179
21 01 USBOF03-KLAMATH BASIN -61
22 01USBON033-KLAATH BASIN 55,03 855,24S 1,4(39,198 0.0155
2::01 USBON033-KLAMATH BASIN -4
2.1 01USBGV03IRG TOU W/O BPA 3,31C 32,97E 1C 331,00 0.0100
25 IRRIGATION BPA BAL ACCT -56,919
2E IRRIGATION UNBILLED 42 -8,00 -0.1905
21 01LNXOO312 - OR IRG LINE EX 3,54
2E OR SB48 RECOVERY 500,825
29 OR SB 838 RECOVERY 88,133
3C UTAH
31 08APSV0010-IRR & SOIL DRA 20,370 10,990,020 2,569 77,995 0.0548~08APSV10NS-lrg Soil Drain Pump N 12,386 667,28E 81 152,938 0.0539
3:08LNXOO2-MTHL Y 80% GUAR 88
34 08LNXOO-ANNUAL 8O%GUAR 34,936
35 08LNXOO014-8% MIN MNTHL Y 1,55C
3E 08LNXOO17-ADVlREF&80%ANN 124,147
37 08LNXOO300 - LINE EXT 80% PLUS 227
3E 08LNXOO310 -IRR, 8Ok ANNUAL 2,48:1
3E 08LNX0012 UT IRG LINE EXT 2,991
4C 08NMT10135UT IRR_SOIL DRNG 19 1,124 1 19,00 0.0592
41 TOTAL Biled 54~37'! §_3'~1,706,12 31,79C 0.061
42 Total Unbilled Rev.(See Instr. 6)124,((0.149~
43 TOTAL 54,361,7~ 3,551,703,34 1,706,12.31,86 0.06::
FERC FORM NO.1 (ED. 12-9)Page 30.14
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) ri A Resubmission 03/31/2009
SALES OF ELECTRICITY BY RATE SC HEDULES
1. Report below for each rate schedule in effect during the year the MWH of elecricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resae which is reported on Pages 310-311.
2. Provide a subheading and tota for each prescribed operating revenue account in the sequence followed in "Elecric Operating Revenues," Page
30-301. If the sales under any rate scheule are classified in more than one revenue account, Ust the rate scedule and sales data under each
applicale revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account ctassification (such as a general residential
schedule and an of peak water heating schedule), the entries in column (d) for the special schedule should denoe 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 billng period during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a foonote the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue account subheading.
rune Numoer ana ime or Haie scneauie Mwn tioia Hevenue Ave~ltitumoer ~:n9~s~~:r ~~okierNo.(a)(b)(c)ofC omers
(f)
1 UNBILLED REV -IRRIGATION -177 -10,OO 0.0565
2 WASHINGTON
~ 02APSVOO-WA AG PMP SRVC 145~9,033,284 4,63 31,318 0.0623
~02APSV000-WA AG PMP SRVC -7,33::
5 02APSV040X.WA AG PMP SRVC 21,479 1,337,08 647 33,198 0.0623
6 02LNX00102-L1NE EXT 80"1 G 878
7 02LNX00103-L1NE EXT 80"1 G 4,452
8 02LNX00105-eNTRCT $ MIN G 35
9 02LNX00109-REF/NREF ADV +1,676
1C 02LNX00110-REF/NREF ADV +64,431
11 02LNX00310 -IRG, 80"1 ANNUAL 124
12 02LNX0012 - WA IRG LINE EXT 1,11C
13 02RFNDCENT - CENTRALIA RFND -1
14 02ZMERGCR-MERGER CREDITS -~
15 IRRIGATION BPA BAL ACCT -4,2m
1€ IRRIGATION UNBILLED ::
17 WYOMING
11! 05APSOO-AG PUMPING SVC 15,270 1,106,52E ~26,192 0.0725
1 ~ 05LNX0011 Q-REF/NREF ADV +49,16C
2C 05LNX00103-L1NE EXT 80"1 G 6,625
21 05LNX00310-L1NE EXTENSION 2.:
2~ 05LNX00312 - WY IRG LINE EXT 13f
2:: 05LNX00103-L1NE EXT 80"1 G 4,5H
2~ 05LNX00110-REF/NREF ADV +15,85C
25 09APSV0210-IRR & SOIL DRA 3,244 217,64 59 54,983 0.0671
26 LESS MULTIPLE BILLINGS -650
27
28 TOTAL IRRIGATION SALES 1,36,54 88,422,23S 22,981 59,464 0.067
29
3C PUBLIC STREET&HIGHWAY
31 CALIFORNIA
3~ 06COSL002-CO-OWND STR LG 8 6,36 5 1,60 0.795
3S 06USL053F-SPECIAL CUST 0 1ß5 190,727 12C 13,775 0.1154
34 06USL058F-CUST OWND STR 243 32,251 2::10,565 0.1327
35 06PSV0051-HI PRESSURE SO 673 155,21C 7::9,219 0.2306
3€UNBILLED REVENUE -1
37 IDAHO
3e 07GNSV023S-IDAHO TRAFFIC 161 15,65E 25 6,44 0.0972
3~ 07SLCOO11-STR LGT CO-OWN 127 52,84 3~3,969 0.4161
4C 07SLCU012E-ENGY STR 1~2,241 ::4,667 0.1601
41 TOTAL Billed
"='1" ~~'106i
1,706,12 31,7Q(0.061
42 Total Unbilled Rev.(See Instr. 6)124,68 (0.149.
43 TOTAL 54,361,7 3,551,703,34 1,706,12 31,86 0.063
............................................FERC FORM NO. 1 (ED. 12-95)Page 30.15
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 200Q4
(2) Fi A Resubmission 03/31/200
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in efect during the year the MWH of elecricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Rese which is reported on Pages 310-311.
2. Provide a subheading and total for eah prescribe operating revenue account in the sequence followe in "Elecric Operating Revenues," Page
30-301. If the sales under any rate schedule ar classified in more tha one revenue accunt, 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 scheule in the same revenue acunt classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the speial schedle should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendere during the year divied by the number of biling periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustmen clause state in a foonote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for eah apicae revenue account subheading.
I Line -~lJmDer ana ime or t1ate SCneoule ~evenue ¡.werag~~UmDer ~yyri0r ?aies ~~R'folderNo.(a)(b)(c)ofC~omers Per '(iWtomer
(f)
1 07SLCU012F-FULL MNT STR 1,89E 349,86E 27E 6,87(0.184
2 07SLCU012P-PART MNT STR LGT 202 26,637 1E 12,625 0.1319
::UNBILLED REVENUE æ 20,OO 0.2247
4 OREGON
501COSL0052-STR LGT SRVC C 1,170 136,35 ee 17,206 0.1165
6 01CUSLOO3-CUS-OWNED MTRD 712 48,30 66 10,788 0.0678
7 01CUSL053E-STR LGT SVC 8,173 555,001 165 49,533 0.0679
8 01CUSL053F-STR LGT SRVC C 28 29,83 22 13,136 0.1032
9 01HPSV0051-HI PRESSURE SO 16,958 3,210,86 675 25,123 0.1893
1(01 MVSLOOSD-MERC VAPSTR LG 10,923 1,288,71E 276 39,576 0.1180
11 010ALT014N-OUTD AR LGT NR 1 29E 2 500 0.296
1~010ALT014N-OUTD AR LGT NR -1
1~010AL T015N-OUTD AR LGT NR ~1,244 4 2,250 0.1382
14 OR SB408 RECOVERY 71,44
15 OR SB 838 RECOVERY 21,49E
1E UNBILLED REVENUE -267 -4,OO 0.1498
17 UTAH
1E 08CFR0012-STR LGTS (CONV 54
1~OSCFR0051-MTH FAG SRVCHG 4,52~
2(OSCFR001-U/G AREA LIGHT 121
21 OSCFR002-STREET LIGHTS 7~
2~08HAXOO-L1GHTNG-HAXON ~1
2~080AL T007N-SECURITY AR LG ~1,351 4 1,00 0.3378
2~08TOSS015F-TRAFFIC SIG NM 1,3i 92,091 131 9,992 0.0704
25 OSSLC00011-STR LGT CO-OWN 23,313 6,422,012 1,07E 21,687 0.2755
26 08TOSS0015-TRAF & OTHER S 3,075 273,992 1,541 1,988 0.0891
27 08MONL0015-MTR OUTDONIGHT 1,06 79,290 5::20,075 0.0745
28 OSSLCU012P-STR LGT GUST-o 5,~631,562 211 26,744 0.1119
29 OSSLCU012F-STR LGT CUST-O 3,40 431,60 15~21,421 0.1267
30 OSSLD13ES1-DECOR CUST-OWN 5,700 347,612 8e 71,288 0.0610
31 OSSLCU012E-DECOR GUST-OWN 31,649 1,96,872 277 114,256 0.0620
32 OSSLD13FS1-DECOR COMP-oWN 14E 78,273 E 18,250 0.5361~OSSLD13FS2-DECOR COMP-OWN 17S 112,352 12 14,83 0.6312
34 OSSLD13MS1-DECOR CUST-OWN 521 72,04 2(26,050 0.138
35 OSSLD13MS2-DECOR CUST-OWN 694 106,397 22 31,54 0.1533
3E 08THIKoon-STR LIGHT SPEC 141 17,277 1 141,00 0.1225
37 UNBILLED REVENUE -195 -26,OO 0.1333
3Ê WASHINGTON
3!02CFR0012-STR LGTS (CONV 91
4C 02COSL0052-WA STR LGT SRV ~59,57E H 23,789 0.1318
41 TOTAL Billed 54~'i' "B 1,706,12 31,791 0.061
42 Total Unbilled Rev.(See Instr. 6)124,6-0.149.
43 TOTAL 54,361,7 3,551,703,34 1,706,12 31,86 0.06
FERC FORM NO.1 (ED. 12-9)Page 304.16
............................................
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ei A Resubmission 03131/2009
SALEs OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricit sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Saes for Resae which is reported on Pages 310-11.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Elecric Operating Revenues," Page
30-301. 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 classificaion (such as a general residential
schedule an an off peak water heating schedule), the entries in column (d) for the speial 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 billng periods during the year (12
if all bilings 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 acunt subheading.
Une NumUlr anu ilie Of Maie sCneuule Mvvn ;:010 Mevenue lo\erag~~'lUmDer ~~~~~sfoa::r ~~w~orcrNo.(a)(b)(c)ofc~omers (f)
1 02CUSL053F-WA STR LGT SRV 3,494 221,22C 11 !l 29,610 0.06
2 02CUSL053M-WA STR LGT SRV 1,082 67,791 90 12,022 0.0627
3 02HPSV0051-WA HI PRESSURE 3,024 54,19::144 21,00 0.180
4 02MVSL0057-WA MERC VAPSTR 2,05 227,97C 41 43,702 0.1110
5 UNBILLED REVENUE -30 -4,OO 0.1333
6 WYOMING
7 OSCOSL0057-CO-OWND STR LG 44 91,202 25 17,720 0.2059
!l 05CUSL058F-CUST OWND STR 1,162 n,464 31 31,405 0.067
9 05CUSL058M-CUST OWND STR 74 4,839 1C 7,40 0.0654
1C 05HPSV0051-HI PRESSURE SO 4,420 982,44 15ll 27,799 0.2223
11 05MVSoo053-MERCURY VAPOR 4,052 535,723 274 14,788 0.1322
12 UNBILLED REVENUE -223 -99,00 0.449
1::09SLC00211-STR LGT CO-OWN 1,287 357,975 7ll 16,291 0.2781
14 09SLCU2121-STR LGT CUST-O 87 12,395 1~6,692 0.1425
15 09SLCU2122-TRAF & OTHER S 50 2,745 14 4,28E 0.0458
1E LESS MULTIPLE BILLINGS -2,401
11
18 TOTAL PUBLIC STREET &141,122 19,865,594 4,080 34,589 0.1408
19
20 OTHER SALES TO PUBLIC AUTH
21 UTAH
22 OSGNSVOO-GEN SRVC-DISTR 2,32!l 147,632 4 582,OO 0.06
23 OSGNSV0023-GEN SRVC-DISTR 21l 2,61C 3 9,33::0.0932
24 08GNSV009M-MANL HIGH VOLT 438,494 17,940,369 4 109,623,500 0.04
25 080AL T007N-SECURITY AR LG 11l 4,294 2 9,00 0.2386
26 UNBILLED REVENUE 8,446 349,OO 0.0413
27
2!l TOTAL OTHER SALES TO PUBLIC 449,314 18,443,905 13 34,562,615 0.0410
29
3C FORFEITED DISCOUNTS
31 CALIFORNIA
32 Lae Fees 237,57i
33 IDAHO
34 Lae Fees 458,710
35 OREGON
3E Late Fee 2,n2,734
31 UTAH
31l Lae Fees 2,90,n5
3ll WASHINGTON
40 Late Fees 50,069
41 IOfALBilled 54=leg'l 1,706,12 31,79 0.061
42 Tota Unbiled Rev.(Se Instr.6)124, '0.149
43 TOTAL 54,361,7 3,551,703,3491 1,706,12 31,86 0.063
FERC FORM NO.1 (ED. 12-95)Page 304.17
Page 30.18
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 200/04
(2) Ei A Resubmission 0331/20
SALES OF ELECTRICITY BY RATE S(HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for eah precribe operating revenue account in the sequence followed in "Elecric Operating Revenues," Page
300-301. If the sales under any rate schedle are classified in more than one revenue account, List the rate schedule and saes 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 genera residential
schedule and an off peak water heating schedule), the entries in column (d) for the speial schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendere during the year divided by the number of billng periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause stte in a fooote the esimated additional revenue bille pursuant thereto.
6. Report amount of unbiled revenue as of end of year for ea apicae revenue acnt subheading.
ine Numoer ana i ite or nate SCneoule Mvvn ;:oia nevenue l\verage l'\UmDer ~~~~~fo%e:r ~GfoklrNo.(a)(b)(c)of cfci0mers
(f)
1 WYOMING
2 Late Fees 610,871
S
4 TOTAL FORFEITED DISCOUNTS 7,48,736
5
E MISCELLANEOUS SERVICE REV
1 CALIFORNIA
-e OOFROO3-MTH MAINTENANC 1,45
S OOONN0300CA RECONNECTIO 110,165
1C 06FCBUYOUT 5,247
11 06RCHK030-CA RET CHK CHR 14,387
12 06TAMP0300-CA TAMP & UNAU 2,625
1~06TEMP030CA TEMP SRVC C 5,385
14 06TRBL030-CA TROUBLE CAL 1&
H 06XMTRTAMP-TAMPERING-84S
1 E Home Comfort 1,214
11 Other 12
18 IDAHO
H 07CFROO1-MTH FAC SRVCHG 1,89;;
2C 07CONN0300-iD RECONNECTIO 88,14C
21 07FCBUYOUT - FAC CHG BUYOUT 21,091
2;;07RCHK03-ID RET CHK CHR 33,02C
2~07TAMP030 1,35C
24 07TEMPOO14- TEMP SRVC CONN 14,31C
25 07XMTRTAMP-TAMPERING -92
2€Weatherization Loans ID 1,695
21 Other -2,070
2S OREGON
29 01CFROO01-MTH FACILITY S 61,727
3d 01CFROO3-MTH MAINTENANC 26,017
31 01CFROO-EMRGNCY ST&BY 24,469
3;,01cFROO5-INTERMTNT 41,854
3:01CFROO13-MTH MISC CHRG 2,284
34 01CFROO14-YR MISC CHRG 5
3!01CONN0300-RECONNECTION C 1,153,785
3€ 01 ESSC06 - ESS charges 1,380
37 01 FCBUYOUT-FAC CHG BUYOUT 307,985
3E 01MTRVR30METR VERIF FEE 300
3S 01 RCHK030.RETURNED CHECK 293,44
4C on AMP03 TAMP & UNAUTH 18,30
41 TOTAL Biled 54'23"1 "ll~1,706,12 31,7Q(0.061
42 Total Unbiled Rev.(See Instr. 6)124,68~((0.149.
43 TOTAL 54,361,7~ 3,551,703,34 1,706,12 31,~0.06~
FERC FORM NO.1 (ED. 12-95)
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PaciiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 03131/200
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effec 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
30-301. 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
scedule and an off pek 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 billng period during the year (12
if all bilings 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 unbiled revenue as of end of year for each applicable revenue acunt subheading.
ine Numoer ano ime or Hate scneoUle ivivvii i:0ll.nevenue l\verage Numoer
~:9~slo~:r ~R~olderNo.(a)(b)(c)ofC omers (f)
1 OHEMP0300-TEMP SRVC CHRG 122,210
2 01XMTRTAMP-TAMPERING-5,298
:: Other 11,66
4 UTAH
S OSCFRO13-MTH MISC CHRG 147,885
6 OSCFROO51-MTH FAC SRVCHG 173,88::
i 08CFR002-ANN FAC SVCCHG 424
I: 08CFR0053-MTHLY MAINTFEE 9,807
e 08CFROO-MTH MISC CHARG 3,316
1C 08CFROO-ANN MISC CHARG 6,66
11 08CONN0300-RECONN&DISCONN 384,38
1~08CONTSERV-3RD PARTY OIS 209,209
13 08FCBUYOUT-FAC CHG BUYOUT 288,061
14 OSSRVCHARG-EXCESS FOOTAGE 45
15 08MTRVR300 - Meter Verification F -3
16 08NCON030-UT FEE NRES RE 4,415
17 08RCHK030-UT RET CHK CHR 410,65C
18 08RCONO1-CONNECT FEE 1,496,6O
19 08TAMP030-TAMPERING&UNAU 21,075
20 08TEMP0014-TEMP SRVC CONN 33,62E
21 08XMTRTAMP-TAMPERING -1,33~
22 Energ Finanswer 12,00 1,200
23 Energ Finanswer new Com 49,647
24 Other -23,447
25 08VISIT30 - UT Visit, Servce Ca 275,170
26 Retroit Finanswer 72
21 WASHINGTON
28 02CFROO3-MTH MAINTENANC 1,320
29 02CFR0EMRGNCY ST&BY 5,884
3C 02CFROO5-INTERMTNT SRVC 4,302
31 02CONN030-WA RECONNECTIO 143,85
3~02FCBUYOUT - FAC CHG BUYOUT 15,628
3:02RCHK030-WA RET CHK CHR 55,945
34 02SRVCHARG-EXCESS FOOTAGE -483
3E 02TAMP03O-WA TAMP & UNAU 8,100
36 02TEMP030-WA TEMP SRVC C 30,490
37 02XMTRTAMP-TAMPERING -2,905
sa Energ Finanswer new Com 5,66~
39 Home Comfort 5,751
40 Other -11,811:
41 TOTAL Billed 54,237,1OC 3,53,106,34J 1,706,12 31,79C 0.061
42 Tota Unbilled Rev.(See Instr. 6)124~((0.149~
43 TOTAL 54,361,7 3,551,703,34 1,706,12 31 ,SE 0.06::
FERC FORM NO.1 (ED. 12-95)Page 30.19
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmision 03131/200
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Reprt below for each rate schedule in effect during the year the MWH of elecricity 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 eah prescribe oprating revenue accunt in the sequence followed in "Elecric Opeting Revenues," Page
30.301. If the sales under any rate schedule are classified in more than one revenue accunt, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the sae customers are served under more than one rate schedule in the same revenue accunt classificaion (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 rendere during the year divided by the number of billng periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a foonote the estimated addtional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each aplice revenue acunt subheading.
!Une Numoer ana ime or Hate scneauie Mwn~oia nevenue l\verage_ ,..umlrr P~~'?~sfo%e:r ~W~folderNo.(a)(b)(c)ofC%\omers (f)
1 WYOMING
:2 05CFROO3-MTH MAINTENANC 8,03:
:i 05CFROO-EMRGNCY ST&BY 20,575
4 05CFROO5-INTERMTNT SRVC 10,553
E 05CFR0013-MTH MISC CHRG 3,186
€ OSCONN030WY RECONNECTIO 103,87(
7 05FCBUYOUT. FAC CHG BUYOUT 109,28~
e 05RCHK03O-WY RET CHK CHR 54,03C
6 05SERV03OQWY SRVC CALLS 5,88
1C 05TAMP0300 82f
11 05TEMP03-WY TEMP SRVC C 34,82f
12 05XMTRTAMp.TAMPERING-4E
1:: 09CFROO5-INTERMTNT SRVC 33~
14 05CONN0300.WY RECONNECTIO 19,86
1E 05FCBUYOUT. FAC CHG BUYOUT 248,71l
1 € 05RCHK030-WY RET CHK CHR 7,86(
17 05TAMP030 7f
1E 05XMTRTAMp.TAMPERING.5
1 ~ 05TEMP03OWY TEMP SRVC C 4,25(
2(09FROO1.MTH FAC SRVCHG 4,731
21 09FR0014.YR MISC CHRG ~
22 Energy Finanswer 12,00 G
2::Other 8,12l
24
25 TOTAL MISC SERVICE REV 7,079,77C
26
27 SALES OF WATER AND WTR PWR
28 UTAH 26,40
29 TOTAL WATER AND WATER PWR 26,40
30
31 RENT FROM ELEC PROPERTIES
32 CALIFORNIA
3:OOFROO.MTH RNT AL CHRG 1,710
34 RENT REV-TRANSMISS 110
3S Rent Revenue - Subleases 16,33
36 Joint use 790,780
37 IDAHO
3S 07CFROO9-YR LSE CHRG-EO 794
39 07INVCHGOQINVEST MNT CHG 181
40 07LOOP0014-MTH FEE PRE-AS 2,34
41 TOTAL Bille 54~7.~ "'.-.1,706,12 31,79C 0.061
42 Totl Unbiled Rev.(See Instr. 6)124,6 (0.1492
43 TOTAL 54,361,7 3,551,703,34 1,706,12 31,86:0.06::
FERC FORM NO.1 (ED. 12-95)Page 30.20
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) Fi A Resubmission 03131/200
SALES OF ELECTRICITY BY RATE S(HEDULES
1. Report below for each rate schedule in effec during the year the MWH of elecricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is repoed on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Elecric Operating Revenues," Page
30301. If the sales under any rate schedule are classified in more than one revenue accunt, List the rate schedule and sales data under each
applicale revenue accont subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue accunt classification (such as a genera residential
schedule and an of 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 billng period during the year (12
if all billngs are made monthly).
5. For any rate sChedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereo.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
¡Line Numoer an ime Of Hate scneauie Mvvn ;:010 Hevenue lwerage ,,,umDer ~vvn_oT ~a,es v ~foklr
No.(a)(b)(c)of CfJ,0mers Per y~stomer
(f)
1 07POLEOO75-STEEL POLES US 274
2 07XRNOO13-RNT/LSE L& PRO 103,108
3 RENT REVENUE-HYDRO 13,084
4 RENT REV-DISTRIBUT 500
5 Rent Revenue - Subleaes 2,21€
€ Joint use 203,562
7 OREGON
E 01CFROO-MTH RNTAL CHRG 534,291
5 01XTRNOO13-RNT/LSE L& PRO 29,14C
1C RENTS - COMMON 43,257
11 Rents - Non Common 25
12 MCI FOGWIRE REVENUE 3,34,85C
1~Rent Revenue - Subleases 449,21E
14 RENT REVENUE-HYDRO 52,98€
15 RENT REV-TRANSMISS 218,645
1E RENT REV-DISTRIBUT 16,46
17 RENT REV-GEN(COMM)35,185
1E Joint use 4,40,10E
16 UTAH
2C OSCFROO56-MTH EQUIP RENT 3~
21 OSCFROO58-MTH EQUIP LEAS 748,221
Z 08INVCHGON-INVEST MNT CHG 4,835
2~08INVCHGOR-INVEST MNT CHG 312
24 08LOOP014N-TEMP SERV CONN 14,274
25 08POLEOQPOLE ATT ACHMEN 4,841
2€08POLEOO75-STEEL POLES US 64,736
27 08XTRNOO13-RNT/LSE L& PRO 75,184
28 RENTS - COMMON -16,24:2
25 Rents - No Common 19,051
3C RENT REVENUE-STEAM 105,215
31 RENT REVENUE-HYDRO 121,500
32 RENT REV-TRANSMISS 883,995
~RENT REV-DISTRIBUT 161,241
34 RENT REV-GEN(COMM)56,2n
35 Rent Revenue - Subleaes 2,174,58E
3€Joint use 2,201,26:2
31 WASHINGTON
38 02CFROO1-MTH FACILITY S 2,104
39 02CFROO-MTH RNTAL CHRG 34,53E
40 Rents - Non Common 60
41 TOTAL Biled 54,237,1 3,533,106,345 1,706,12i 31,79C 0.061
42 Tota Unbiled Rev.(See Instr. 6)124,6~((0.149:2
43 TOTAL 54,361,7 ~ 3,551,703,34 1,706,121 31,æ 0.06~
FERC FORM NO.1 (ED. 12-9)Page 30.21
Page 30.22
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo8/Q4
(2) Ei A Resubmission 0331/200
SALES OF ELECTRICITY BY RATE S(HEDULES
1. Report below for each rate schedule in efect during the yea the MWH of elecricity 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 followe in "Elecric Operating Revenues," Page
30-301. If the sales under any rate scedule are classified in more tha one revenue account, List the rate scheule and saes 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 clasificaion (such as a general residential
schedule and an of peak water heating schedule), the entries in column (d) for the special schedule shold denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendere during the year divided by the number of biling periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a foonote the estimated aditional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicae revenue acunt subheading.
Line l'IumOer ano I me OJ nate sCneoule Mvvn ;:il nevenue ¡.\Ve~~~umoer ~YYI!.UI 9Ces ~~igoklrNo.(a)(b)(c)ofC omers Per 1~stomer
(f)
1 RENT REVENUE-HYDRORENT 612,63
2 RENT REV-DISTRIBUT 14,637
3 RENT REV-GEN(COMM)37,800
4 RENT REV-TRANSMISS 1,450
5 Rent Revenue - Subleases 41,90
6 Joint use 1,54,027
7 WYOMING
8 05CFRoo001-MTH FACILITY S 11,524
9 05CFRooQ0MTH RNT AL CHRG 2,94
10 Rents - Non Common 1,55
11 RENT REVENUE-STEAM 57,06
12 RENT REV-TRANSMISS 5,101
13 RENT REV-GEN(COMM)7,224
14 Rent Revenue - Subleases 44,95:2
15 Joint use 348,35
16 09LOOP0214-MTH FEE PRE-AS 180
17 09POLE0075-STEEL POLES US 21,318
18
19 TOTAL RENT FROM ELEC PROP 20,579,425
20
21 OTHER ELECTRIC
22 GENERAL OFFICE
23 OTH ELEC ESTIMATE 590,791
24 GREEN CREDIT SALES 6,151,676
25 NON-WHEELING SYSTEM 10,659,957
26 Other Elec (exclud Wheel)7,679,718
27 CALIFORNIA
28 DSM REV-CA SBC OFF -752,367
29 Fish, Wildlife, Recr 3,701
30 IDAHO
31 DSM REV-ID SBe 4,287,06
32 Other Elec (exclud Wheel)316
33 08XTRN0011.SALE ORDERS (I 650
34 OREGON
35 3RD PARTY TRANS 68,995
36 DSM REVENUE - OREGON ECC 6,83,798
37 Other Elec (excud Wheel)2,9n,60
38 Other Elec DSR carr chrg 801,795
39 M&S INVENTORY REVENUE 2,594
40 08XTRN0011-SALE ORDERS (I 326
41 TOTAL Biled 54=. ~ .. ~.53:¡'~f 1,706,12 31,79C 0.061
42 Tota Unbilled Rev.(See Instr. 6)124,6 (C 0.149:
43 TOTAL 54,361,7B: 3,551,703,34 1,706,12 31,86~0.063
FERC FORM NO.1 (ED. 12-95)
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo8/Q4
(2) Ei A Resubmission 03131/200
SALES OF ELECTRICITY BY RATE S(HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resle which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribe oprating revenue accont in the sequence followed in "Elecric Operating Revenues," Page
30-301. If the sales under any rate schedule are classified in more than one revenue accunt, List the rate schedule and sales data under each
applicable revenue accunt subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classificaion (such as a general residential
schedule and an of pek 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 bils rendered during the year divided by the number of billng period during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a foonote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue account subheading.
ine NumDer ana ime or Mate scneouie Mvvn ;:oio Mevenue l\verag~~'1UmDer ~vyn,oT ~aies ~~igolderNo.(a)(b)(c)
of CLf omers Per y~stomer
(f)
1 JOINT USE REVENUE -5,637
~ UTAH
~ ELEC INC-OTHR 240,200
4 FL YASH SALES 3,397,901
5 DSM REV-UT SBC OFFSET 26,180,373
E 8XTRN0011-SALE ORDERS 1,33E
i M&S INVENTORY REVENUE 968,97C
8 Fish, Wildlife, Recr 1,765
S Other Elec (exclud Wheel)2,nE
1C WASHINGTON
11 Fish, Wildlife, Recr 3,611
12 Wash Colstrip 3 -52,1~
1~WYOMING
14 FL YASH SALES 1,621,634
1 E WY Regulatory Recovery Fee 205,82C
1E Other Elec (exclud Wheel)6,561
1 ¡
H TOTAL OTHER ELEC REVENUE 72,497,824
19
2C
21
22
2~
24
25
26
27
28
29
30
31
32
33
34
35
3€
37
3€
39
4C
41 TOTAL Billed 54~~" ¡~1061 1,706,12 31,79t 0.061
42 Tot Unbilled Rev.(See Instr. 6)124,((0.149.
43 TOTAL 54,361,70: i:i:'¡1,706,12 31,86 0.06~
FERC FORM NO.1 (ED. 12-95)Page 304.23
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) . A Resubmission 03131/2009 200/04
FOOTNOTE DATA
ISchedu/ePage: 304 Line No.: 42 Column: c
For fuer discussion on unbiled revenue refer to page 300, Electrc Operatig Revenues, line 12 colum (b).
............................................
Blank Page
(Next Page is 310)
FERC FORM NO.1 (ED. 12-90)Page 310
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/200
SALES FOR RESALE (Accunt 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 involvng 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 affilation 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 servce is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this servce in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF servce except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm servce. 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU servce except that "intermediate-term" means
Longer than one year but Less than five years.
Une Name of Compay or Public Authority Statistical FERC Rate Averaße Actual Deand (MW)
No.(Footnote Affiliations)Clasif-Schedule or Monthly iIing l\vera~e Aveß
cation Tari Number Demand(MW)Monthly NC Deman Monthly C mane
(a)(b)(c)(d)(e)(f)
1 Requirement Sales
2 Brigham Cit RQ T-12 2~21 20
3 BrighamCity RQ T-6 1i 1E 15
4 Dever, Town of RQ T-4 0.2 0.1 0.1
5 Helper City RQ T-6 O.E 1 0.9
6. Helper City Annex RQ T-6 0.7 O.E 0.6
7 Navajo Tribal Util Auth (Mexican Hat)RQ T-6 O.~O.~0.1
8 Navajo Tribal Util Auth (Red Mesa)RQ T-6 1 1 1
9 Portland General Electric Co.RQ 147 NJI NJI NA
10 Price City RQ T-12 14 1:3 13
11 Price City RQ T-6 12 1:2 11
12 Accrual True-up RQ NA NA NA NA
13
14
Subtotal RQ C 0 0
Subtotal non-RQ C 0 0
Total Cl 0 0
............................................
Name of Respondent ThiSr ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/200
S LES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those servces 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 tye of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling 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 servce, 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 megawatt.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other tyes 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 bils 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 ($)Une
Sold Demand Charg Energ Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
1
66,266 1,135,94::1,320,913 2,456,85E 2
45,949 708,184 800,432 1,508,61E 3
1,00 14,784 18,178 32,96 4
4,314 84,551 76,240 160,791 5
3,758 69,81C 66,509 136,31E 6
1,06 18,718 18,552 37,27C 7
7,94 121,282 138,382 259,66 8
11,296 972'~_978,02E 9
38,942 647,854 772,707 1,451,83 10
36,686 562,867 639,293 ~1,202,160 11
14,83 401,63 12
13
14
232,065 3,36,993 4,824,010 438,124 8,626,127
12,112,911 43,978,820 1,815,026,920 -1,00,681,109 852,324,631
12,344,976 47,342,813 1,819,850,930 -1,00,242,98 86,95,75
FERC FORM NO.1 (ED. 12-9)Page 311
FERc FORM NO.1 (ED. 12-9)Page 310.1
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/20
SALES FOR RESALE (Accunt '"7)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges dunng the year. Do not report exchanges of electricit ( Le., transactions involvng 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 onginal 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 reliabilty of requirements service must
be the same as, or second only to, the supplier's servce to its own ultimate consumers.
LF - for tong-term servce. "Long-term" means five years or Longer and "firm" means that servce cannot be interrupted for economic
reasons and is intended to remain reliable even under advers conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain delivenes 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU servce except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistica FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illng l\vera~e Avera~
cation Tari Number Demand(MW)Monthly NC Deman Monthly CP emanc
(a)(b)(c)(d)(e)(f)
1
2 Nonrequirement Sales
3 Anaheim, Cit of SF WSPP NJI NJl NA
4 Arizona Public Service Co.SF T-12 NJI NJl NA
5 Avista Corp.SF T-13 NJl NJl NA
6 Avista Corp.SF WSPP NJl NJl NA
7 BP Energy Copany WSPP NJl NJl NA
8 BP Energy Company SF WSPP NJl NJl NA
9 Barcays Bank PLC --T-12 NJl NJl NA
10 Barclays Bank PLC SF T-12 NA NA NA
11 Bain Elecric Power Cooperative T-11 NA NA NA
12 Bain Elecric Power Cooperative SF T-11 NA NA NA
13 Basin Elecric Power Cooperative SF WSPP NA NA NA
14 Bear Energy LP SF T-12 NA NA NA
Subtotal RQ C 0 0
Subtotal non-RQ C 0 0
Total II 0 0
............................................
Name of Respondent IhiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/2009
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 tye of-servce 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 bils 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 bils 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 ($)Line
Sold Demand Charges Energ Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(I)en (k)
1
2
30 14,20 14,200 3
313,306 20,515,198 20,515,19S 4
35 ~ii 2,12~5
60,895 3,64,735 3,64,735 6
-431 7
983,513 61,886,09 61,886,091:8
1,012 -71,59C 9
2,168,251 142,441,60 142,441,60 10
4,105 -243,169 11
1,569 86,622 12
29,052 1,902,018 1,902,018 13
50,913 3,773,117 3,773,117 14
232,06 3,363,99 4,824,010 438,124 8,626,127
12,112,911 43,978,820 1 ,815,026,920 -1,00,681,109 852,324,631
12,344,976 47,342,813 1,819,850,93 -1,00,242,98 86,95,758
FERC FORM NO.1 (ED. 12-9)Page 311.1
FERC FORM NO.1 (ED. 12..)Page 310.2
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) i: A Resubmission 0331/20
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 servce as follows:
RQ - for requirements servce. Requirements service is servce which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resourc planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the supplier's servce 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
définition 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 servce is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU servce except that "intermediate-term" means
Longer than one year but Less than five years.
Una Name of Compay or Public Authority Statistical FERC Rate Avera;Actual Demand (MW)
No.(Footnote Affilations)Classif-Schedle or Monthly illng . t'vera~e Avera~
cation Tariff Number Demand (MW) Monthly NC Deman Monthly CP mane
(a)(b)(c)(d)(e)(f)
1 Benton County Public Util Dist NO.1 SF WSPP Nß Nß NA
2 Black Hils Power, Inc..441 5C 5C 49
3 Black Hils Power, Inc.WSPP Nß Nß NA
4 Black Hils Power, Inc.
.
WSPP Nß Nß NA
5 Bonnevile Power Administration T-13 Nß Nß NA
6 Bonneville Power Administration 368 Nß Nß NA
7 Bonneville Power Administration T-11 Nß Nß NA
8 Bonnevile Power Administration T-12 Nß Nß NA
9 Bonnevile Power Administration SF T-11 NA NA NA
10 Bonnevile Power Administration SF T-13 NA NA NA
11 Bonnevile Power Administration SF WSPP NA NA NA
12 British Columbia Transmission Corp.SF T-13 NA NA NA
13 Burbnk, City of SF WSPP NA NA NA
14 Califomia Independent System Oprator T-12 NA NA NA
Subtotal RQ C 0 0
Subtotal non-RQ C 0 0
Totl (I 0 0
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008104
(2)A Resubmission 0331/200
SALES FOR RESALE (Accunt 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 biling 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 (1) must be in megawatt.
Foonote 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 tyes 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 bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQlNon-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 ($)Une
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
4,44 323,745 323,74f 1
36,969 6,156,421 5,415,098 11,571,5H 2
21,739 1,349,947 1,349,941 3
27,84 1,892,358 1,892,35E 4--1 5
2,385 137,5&1 6
3,031 186,19E 7
40,831 1,614,458 1,614,45E 8
72 2,48 9
149 5,9O 10
94,062 6,401,527 6,401,521 11
37 2,4à 12
51,472 2,731,757 2,731,757 13
94 -308,177 14
232,06 3,36,993 4,824,010 43,124 8,626,127
12,112,911 43,978,820 1,815,026,920 -1,00,681,109 852,324,631
12,344,976 47,342,813 1,819,850,930 -1,00,242,98 86,95,758
FERC FORM NO.1 (ED. 12-9)Page 311.2
FERC FORM NO.1 (ED. 12-90)Page 310.3
............................................
Name of Respondent ThiS~iortls:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/20
SALES FOR RESALE (Account 4-7)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involvng 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 affilation 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 servce. Requirements servce is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this servce in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the suppliers service to its own ultimate consumers.
LF - for tong-term servce. "Long-term" means five years or Longer and "firm" means that servce 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 servce). 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 reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU servce except that "intermediate-term" means
Longer than one year but Less than five years.
Une Name of Copany or Public Authority Statistic FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affilations)Clasifi-SCedule or Monthly illng !,vera~e Ave~
cation Tari Number Demand (MW) Monthly NC Deman Monhly C emanc
(a)(b)(c)(d)(e)(f)
1 Califomia Independent System Operator SF T-12 NJI NA NA
2 Cargil Power Markets, LLC .T-12 NJI NA NA
3 Cargil Power Markets, LLC T-12 NJI NJI NA
4 Cargil Power Markets, LLC SF T-11 NJI NA NA
5 Cargill Power Markets, LLC SF T-11 NJI NJI NA
6 Cargil Power Markets, LLC SF T-12 NJI NJI NA
7 Chelan County Public Util Dist No. 1 SF WSPP NJI NJI NA
8 Citigroup Energ, Inc.SF T-11 NJI NJI NA
9 Citigroup Energy, Inc.SF T-12 NJI NJI NA
10 City of Rosevile SF WSPP NA NA NA
11 City of St. George SF WSPP NA NA NA
12 Clatskaie People's Utility District SF WSPP NA NA NA
13 Colorado River Commission of Neva WSPP NA NA NA
14 Colorado Springs Utilities SF WSPP NA NA NA
Subtotal RQ (0 0
Subtotal non-RQ (0 0
Total (0 0
............................................
Name of Respondent This Re iortls:Date of ReP.rt Year/Period of Report
PacifiCorp (1) .~An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/200
S LES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD- for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tarif 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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other tys 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 bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energ Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
246,159 15,826,856 15,826,85E 1
584
4'1
,Ii;
97,00 2
48 4,08 3
34,258 2,071,641 4
12 56e 5
928,534 59,890,888 59,890,ss 6
18,75C 7
50 2,63 8,:/:e:
1,565,802 106,401 ,687 106,401,681 9
63 29,756 29,756 10
305 30,570 30,570 11
4,471 276,998 276,998 12
6 -225 13
1,278 97,423 97,423 14
232,065 3,36,99 4,824,010 43,124 8,626,127
12,112,911 43,978,820 1,815,026,92 .1,00,681,109 852,324,631
12,34,976 47,342,813 1,819,80,93 .1,00,242,985 86,950,758
FERC FORM NO. 1 (ED. 12-9)Page 311.3
FERC FORM NO.1 (ED. 12-90)Page 310.4
............................................
Name of Respondent ThiS~iortls:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 0331/20
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 electricit ( 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 servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this servce in its system resource planning). In addition, the reliabilty 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 servce). 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 on 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU servce except that "intermediate-term" means
Longer than one year but Less than five years.
Une Name of Compay or Public Authority Statisticl FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affiliations)Clasifi-Schedule or Monthly illng l\vera~e Ave~
cation Tari Number Demand (MW)Monthly NC Deman Montly C mane
(a)(b)(c)(d)(e)(f)
1 Cooco Inc.SF T-11 NA NJl NA
2 Conoco Inc.SF T-12 NJl NJl NA
3 Constellation Energ Commodities Group T-12 NJl NJl NA
4 Constellation Energ Commodities Group SF T-11 NJl NJl NA
5 Constellation Energy Commodities Group SF T-11 NJl NJl NA
6 Constellation Energy Commodities Group SF T-12 NJl NJl NA
7 Credt Suisse Energ LLC T-12 NJ NJl NA
8 Credit Suisse Energ LLC SF T-12 NJl NJl NA
9 DB Energy Trading LLC SF T-12 NA NA NA
10 Douglas County Public Util Dist No. 1 SF T-13 NA NA NA
11 Douglas Conty Public Util Dist No. 1 SF WSPP NA NA NA
12 Dyneg Power Marketing SF WSPP NA NA NA
13 EPCOR Energ Marketing (U.S.) Inc.SF WSPP NA NA NA
14 EI Paso Electric Company SF WSPP NA NA NA
Subtotal HO 0 0 0
Subtotal non-RO 0 0 0
Total Q 0 0
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2)A Resubmission 0331/2009
SALES FOR RESALE (Accunt 447) (Continued)
OS - for other servce. 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 tye of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling 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 (1). 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 bils 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 bils 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.
MeaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(j --(k)
3 175 1
481,86 33,106,821 33,106,821 2
1,06 .-82,02~3
21,425 1,317,92E 4
247 14,~5
1,320,102 88,827,748 88,827,74E 6
204 II 14,01~7
66,147 50,682,876 50,682,87E 8
34,696 22,255,189 22,255,1~9
1 .-90 10
360 29,840 29,840 11
75 3,517 3,517 12
5,800 487,240 487,240 13
38,83 2,618,607 2,618,607 14
232,065 3,363,993 4,824,010 438,124 8,626,127
12,112,911 43,978,820 1,815,026,920 -1,00,681,109 852,324,631
12,344,976 47,342,813 1,819,850,930 .1,00,242,985 86,950,758
FERC FORM NO.1 (ED. 12-9)Page 311.4
FERC FORM NO.1 (ED. 12-9)Page 310.5
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCor (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) i" A Resubmission 0331/200
SALES FOR RESALE (Accnt 4 m
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 involvng 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 affilation the respondent has wih 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 servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this servce in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU servce except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Compay or Public Authority Statistica FERC Rate Averaae Acual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedle or Monthly illng . l\vera~e Ave~
cation Tari Number Dean(MW)Monthly NC Deman Monthly C mane
(a)(b)(c)(d)(e)(f)
1 Eugene Water & Electric Board SF T-11 N,l N,l NA
2 Eugene Water & Electric Bord SF WSPP N,l N,l NA
3 FPL Energ Power Marketing, Inc.SF WSPP N,l N,l NA
4 Fortis Energy Marketing & Trading GP WSPP N,l N,l NA
5 Fortis Energ Marketing & Trading GP SF WSPP N,l N,l NA
6 Franklin County Public Util Dist No. 1 SF WSPP N,l N,l NA
7 Gila River Power, L.P.SF WSPP N,l N,l NA
8 Glendale, City of SF WSPP N,l N,l NA
9 Grant County Public Utilty Dist No. 1 SF WSPP NA NA NA
10 Grays Harbr Public Utilty District SF WSPP NA NA NA
11 Highlad Energy LLC SF T-11 NA NA NA
12 Highland Energy LLC SF WSPP NA NA NA
13 Hurricane, City of ..T-12 NA NA NA
14 lberdrola Renewables, Inc.T-11 NA NA NA
Subtotal RQ C 0 0
Subtotal non-RQ C 0 0
Total ~0 0
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03/31/200
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those servces 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 tys 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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of.period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Deman Charges Energ Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(j (k)
40 31,86 1!iLi
21,813 1,362,957 1,362,95i 2
45,205 3,648,785 3,648,78E 3
82 4,305 4
298,4n 20,978,272 20,978,27~5
1 ,no 125,94 125,94C 6
71,397 3,939,812 3,939,812 7
53 3,074 3,07A 8
10,720 603,075 603,on 9
2,582 186,66 186,66Ei 10
4 191 11
33,116 2,04,194 2,04,194 12
153 11,475 11,475 13
-9 -45S 14,"y, "",;
232,065 3,36,993 4,824,010 43,124 8,626,127
12,112,911 43,978,820 1,815,026,920 -1,00,681,109 85,324,631
12,344,976 47,342,813 1 ,819,85,93 -1,00,242,98 86,950,758
FERC FORM NO.1 (ED. 12-9)Page 311.5
FERC FORM NO.1 (ED. 12-90)Page 310.6
............................................
Name of Respondent ThiS~iortls:Date of Report Year/Period of Report
PacifiCorp (1) X An Origina (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 0331/200
SALES FOR RESALE (Accunt 4 7)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affilation 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 servce in its system resource planning). In addition, the reliabilty 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 servce 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 servce. 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term servce from a designated generating unit. The same as LU servce except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Autrity Staisic FERC Rate Avera;Acual Demand (MW)
No.(Footnote Affilations)Clasi-Sched or Montly illng t'vera~e Avera~cation Tari Number Deand(MW)Monhly NC Deman Monhly CP emant
(a)(b)(c)(d)(e)(f)
1 lberdrola Renewables, Inc.T-11 NJI N)NA
2 lberdrola Renewables, Inc.ISF T-11 NJI NJI NA
3 lberdrola Renewables, Inc.ISF T-12 NJI NJI NA
4 Idaho Power Company T-11 NJI NJI NA
5 Idaho Power Company SF T-11 NJI N)NA
6 Idaho Power Compay SF T-11 NJI NJI NA
7 Idaho Power Company SF T-13 NJI NJI NA
8 Idaho Power Company SF WSPP NJI N)NA
9 Integrys Energy Services, Inc.SF T-11 NJI NJI NA
10 Integrys Energy Services, Inc.SF WSPP NA NA NA
11 J. Aro & Company SF T-12 NA NA NA
12 J.P. Morgan Ventures Energy Corpration SF T-12 NA NA NA
13 Lehman Brothers Commodity Servces, Inc SF T-12 NA NA NA
14 Los Angeles Dept. of Water & Power i-301 NA NA NA
Subtotal RQ C 0 0
Subtotal non-RQ C 0 0
Total Il 0 0
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03/31/2009
S LES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tanffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-servce 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 tyes 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 bils 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-penod adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Une
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)~(k)
61 3,~1
17,272 1,014,45'2
393,688 24,470,668 24,470,66E 3
2,029 106,24l 4
6,286 442,62E 5
9 42(6
304 13,501 7
143,33 8,466,149 8,46,1M!8
481 -19,471 9
20,159 1,301,489 1,301,489 10
44,556 31,958,680 31,958,68 11
128,732 9,168,33 9,168,33 12
96,83 6,54,555 6,549,55 13
582,894 25,898,987 25,898,987 14
232,065 3,363,993 4,824,010 438,124 8,626,127
12,112,911 43,978,820 1,815,026,920 -1,00,681,109 852,324,631
12,344,976 47,342,813 1,819,850,930 -1,00,242,98 86,950,758
FERC FOAM NO.1 (ED. 12-9)Page 311.6
FERC FORM NO.1 (ED, 12-9)page 310.7
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmision 03131/200
SALE S FOR RESALE (Accunt 4 7)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the supplier's servce to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF servce 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU servce except that "intermediate-term" means
Longer than one year but Less than five years.
Une Name of Company or Public Autori Staistical FERC Rae Averaße Acual Demand (MW)
No.(Footnote Affiliations)Clasif-SChedle or Monthly illng . ~vera~e Ave~cation Tari Number Deand(MW)Monthly NC Deman Monthly C emanc
(a)(b)(c)(d)(e)(f)
1 Los Angeles Dept. of Water & Power SF WSPP N,I N,I NA
2 Louis Dreyfus Energy Services L.P.SF WSPP N,I N,I NA
3 Macquarie Cook Power Inc.SF WSPP N,I N,I NA
4 Merrll Lynch Commodities, Inc.SF WSPP N,I NJ NA
5 Metropolitan Water District SF WSPP N,I N,I NA
6 Modesto Irrigation District SF WSPP N,I N,I NA
7 Morgan Stanley Capital Group, Inc.T-12 N,I N,I NA
8 Morgan Stanley caital Group, Inc.SF T-11 N,I N,I NA
9 Morgn Stanley caital Group, Inc.SF T-12 N,I N,I NA
10 Municipal Energy Agenc of Nebraka SF T-11 NA NA NA
11 Municipal Energy Agency of Nebraska SF WSPP NA NA NA
12 Nevada Power Company SF T-11 NA NA NA
13 Nevada Power Company SF WSPP NA NA NA
14 NorthWestem Energy SF T-13 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Totl II 0 0
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/2009
Sf LES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements 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 tye 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 megawatt.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Une
Sold Demand Charges Energy Charges Other Chargs (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
176,620 9,280,674 9,280,67~1
1,078 74,60 74,6O 2
1,200 71,60 71,60(3
44,525 3,078,410 3,078,41C 4
2,997 122,88 122,8~5
45,820 3,067,591 3,067,591 6
1,386 62,34~7
9,607 641,921 8
4,713,228 303,595,575 303,624,37!9
14 536 10
6,754 533,969 533,969 11
160 II 7,089 12
160 12,150 12,150 13
3n 24,421 14
232,065 3,36,993 4,824,010 438,124 8,626,127
12,112,911 43,978,820 1 ,815,026,920 -1 ,00,681 ,109 852,324,631
12,34,976 47,342,813 1,819,850,930 -1,00,242,98 86,950,758
FERC FORM NO.1 (ED. 12-9)Page 311.7
FERC FORM NO.1 (ED. 12-9)Page 310.8
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008Q4
(2)A Resubmission 03/31/200
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 servce. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this servce in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF servce 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 servces where the duration of each period of commitment for servce is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU servce except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Compay or Public Authori Staisic FERC Rate Avera;Actual Demand (MW)
No.(Footnote Affiliations)C1asi-Sched or Mothly illn~!\vera~e Ave~9B
cation Tar Number Demand(MW Monthly NC Deman Monthly C emanc
(a)(b)(c)(d)(e)(f)
1 NorthWestem Energy SF WSPP NA NA NA
2 Northem Califomia Power Agency SF WSPP NA NA NA
3 Northpont Energ Solutions Inc.SF WSPP NA NA NA
4 Occidental Power Servces, Inc.SF WSPP NA NA NA
5 PPL EnergyPlus, LLC SF WSPP NA NA NA
6 PPL Montana, LLC SF T-11 NA NA NA
7 Pacific Gas & Electric Company SF WSPP NA NA NA
8 Pacifc NW Generating Coorative SF WSPP NA NA NA
9 Pacific Summit Energ LLC SF T-12 NA NA NA
10 Pasadena, City of SF WSPP NA NA NA
11 Portland General Elecric Co.SF T-11 NA NA NA
12 Portland General Elecric Co.SF T-12 NA NA NA
13 Portland General Elecric Co.SF T-13 NA NA NA
14 Powerex -WSPP NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ri A Resubmission 03131/2009
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 Tarif 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 tye of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling 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 maxmum
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 megawatt.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils 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 coumn (k)
the total charge shown on bils 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)0)(k)
4,787 296,988 296,98E 1
7,44 587,824 587,824 2
8,90 64,674 640,674 3
4,025 275,445 275,445 4
43,390 2,311,628 2,311,62E 5
822 50,gó 6
144,811 11,766,890 11,766,89C 7
17,675 1,257,625 1,257,625 8
61,764 3,352,229 3,352,22~9
480 23,68 23,68 10
74 ~~10')¡4,1~11
38,735 23,910,04 12
332 21,116 13
310 19,91C 14
232,065 3,36,993 4,824,010 43,124 8,626,127
12,112,911 43,978,820 1 ,815,026,920 -1,00,681,109 852,324,631
12,34,976 47,342,813 1,819,850,930 -1,00,242,98 86,95,758
FERC FORM NO.1 (ED. 12-9)Page 311.8
Subtotal RQ
Subtotal non-RQ
o
o
(J
o
o
o
o
o
............................................
This Re iort Is: Date of Report
(1) -IX An Original (Mo, Da, Yr)
(2) L A Resubmission 03131/200
SALES FOR RESALE (Accunt 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 affilation 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 reliabilty 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 servce cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilit and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty 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
Year/Period of Report
End of 2008/04
Line Name of Compay or Public Authority Statistic FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affiliations)Clasif-Schedle or Monthly i1ling t'vera~e Avera~
cation Tari Numbe Demand(MW)Monhly NC Deman Monthly CP emanc
(a)(b)(c)(d)(e)(f)
1 Powerex T-11 NA NA NA
2 Powerex SF T-11 NA NA NA
3 Powerex SF WSPP NA NA NA
4 Public Servce Company of Colorado 320 NA NA NA
5 Public Service Company of Colorad WSPP NA NA NA
6 Public Servce Compay of Colorado 320 141 14E 134
7 Public Service Company of Colorado WSPP NA NA NA
8 Public Service Company of Colorado SF T-11 NA NA NA
9 Public Service Company of Colorado SF WSPP NA NA NA
10 Public Servce Company of New Mexico SF WSPP NA NA NA
11 Puget Sound Energy SF T-13 NA NA NA
12 Puget Sound Energy SF WSPP NA NA NA
13 Rainbow Energ Marketing SF T-11 NA NA NA
14 Rainbow Energy Marketing SF WSPP NA NA NA
Total o
FERC FORM NO.1 (ED. 12-9)Pag 310.9
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004
(2)A Resubmission 03131/200
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 billng 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 servce, 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 megawatt.
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 (j. Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/on-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 ($)Une
Sold Deman Charges Energ Charg Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(k)
14,858 881,87€1
32,575 2,057,7~2
1,120,902 61,237,043 I 61,237,00 3
32 -316,99i 4
127 7,20~5
932,165 18,679,68C 43,289,975 I 61,969,65E 6
940 25,80 25,8O 7
494 -26,72~8
106,188 6,n1,n4 6,n1,n4 9
129,727 8,041,429 8,041,429 10
211 ii 14,144 11
290,738 16,831,94 16,831,~12
6,165 ii 36,43 13
73,132 4,88,326 4,884,326 14
232,06 3,363,993 4,824,010 438,124 8,626,127
12,112,911 43,978,820 1,815,026,920 -1,00,681 ,109 852,324,631
12,344,976 47,342,813 1,819,850,930 -1,00,242,985 86,950,758
FERC FORM NO.1 (ED. 12-9)Page 311.9
FERC FORM NO.1 (ED. 12-9)Page 310.10
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/200
SALES FOR RESALE (Accunt 4 m
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 affilation the respondent has wih 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 servce. Requirements servce is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this servce in its system resource planning). In addition, the reliabilty 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 servce. "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 reliabilty of
servce, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term servce from a designated generating unit. The same as LU servce except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actua Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illng t'ver~Ave~
cation Tari Number Demand (MW) Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Redding, City of SF WSPP NA NA NA
2 SUEZ Energ Marketing NA, Inc.SF WSPP NA NA NA
3 Sacramento Municipal Utility District
i=
250 NA NA NA
4 Sacramento Municipal Utilty District 250 NA NA NA
5 Sacramento Municipal Utiity District WSPP NA NA NA
6 Salt River Projec WSPP NA NA NA
7 Salt River Project WSPP NA NA NA
8 Salt River Project SF WSPP NA NA NA
9 San Diego Gas & Elecric SF WSPP NA NA NA
10 Santa Clara, City of SF WSPP NA NA NA
11 Seattle City Light SF T-13 NA NA NA
12 Seattle City Light SF WSPP NA NA NA
13 Sempra Energy Solutions SF WSPP NA NA NA
14 Sempra Energy Trading LLC T-12 NA NA NA
Subtotal RQ C 0 0
Subtotal non-RQ C 0 0
Totl II 0 0
............................................
Name of Respondent ThiS~iortls:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008104
(2)A Resubmission 03/31/200
S LES FOR RESALE (Account 4471 (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 billng 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 tyes 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 megawatt.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other tyes 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 bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQlon-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 ($)Une
Sold Demand Charges Energ Charges Other Chargs (h+i+j)No.
($)($)($)
(g)(h)(i)u)(k)
21,530 1,182,137 1,182,137 1
12,756 969,632 969,632 2-461,21!l 3
570,608 12,245,248 12,245,24E 4
111,83 7,204,413 7,204,41~5
219,596 14,014,987 14,014,987 6
6,892 575,652 575,65~7
83,737 5,021,962 5,021,962 8
35,417 2,487,761 2,487,761 9
8,827 573,55 573,554 10
3 g ..191 11
54,753 3,329,190 3,329,100 12
600 32,108 ..32,108 13
148 -15,620 14
232,06 3,363,993 4,824,010 438,124 8,626,127
12,112,911 43,978,820 1,815,026,920 -1 ,00,681 ,109 852,324,631
12,34,976 47,342,813 1,819,850,93 -1,00,242,98 86,95,758
FERC FORM NO.1 (ED. 12-9)Page 311.10
FERC FORM NO. 1 (ED. 12-9)Page 310.11
............................................
Name of Respondent This Re ortis:Date of Report Year/Period of Report
PacifiCorp (1) ~An Original (Mo, 08, Yr)End of 2008/04
(2)A Resubmission 0331/200
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 affilation 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 servce which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this servce in its system resourc planning). In addition, the reliabilty 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. IlLong-termll means five years or Longer and "firmll means that servce cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-termll 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-termll means five years or Longer. The availability and reliabilit of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU servce except that Ilintermediate-termll means
Longer than one year but Less than five years.
Une Name of Company or Public Authority Statistical FERC Rate Averaae Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIin~~vera~e Ave~
cation Tariff Number Demand(MW Monthly NC Deman Monhly C mand
(a)(b)(c)(d)(e)(f)
1 Sempra Energy Trading LLC SF T-11 NA NA NA
2 Sempra Energy Trading LLC SF T-12 NA NA NA
3 Sempra Generation SF T-12 NA NA NA
4 Shell Energy North America (US), L.P.WSPP NA NA NA
5 Shell Energ North America (US), L.P.ISF T-11 NA NA NA
6 Shell Energy North America (US), L.P..WSPP NA NA NA
7 Sierra Pacific Power Compay 258 NA NA NA
8 Sierr Pacific Power Company 258 75 75 72
9 Sierra Pacific Power Company T-11 NA NA NA
10 Sierr Pacific Power Company SF T-11 NA NA NA
11 Sierr Pacific Power Company SF T-13 NA NA NA
12 Sierra Pacific Power Company SF WSPP NA NA NA
13 Snohomish Public Utilit District No. 1 SF WSPP NA NA NA
14 Southem Caifomia Edison Company SF T.12 NA NA NA
Subtotal RQ 0 0 0
Subtotl non.RQ 0 0 0
Total ll 0 0
............................................
Name of Respondent This Re ort Is:Date of Report Year/Peri of Report
PacifiCorp (1) .~ An Original (Mo, Da, Yr)End of 2oo8/Q4(2) A Resubmission 03131/200
SALES FOR RESALE (Accunt 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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other tyes 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 bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energ Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)_(k)
90 4,95:1 1
3,542,856 225,132,372 225,132,372 2
3,800 282,720 282,72C 3
.7 n.~.~"525 4
213 12,79:1 5
1,187,655 77,327,85~6
157,38€7
461,337 14,715,00 ,.,_~"34,349,50 8
1,04 61,591 9
14,93 966,315 10
824 45,771 11
3 142 142 12
42,66 2,638,856 2,638,856 13
81,730 6,704,415 6,704,415 14
232,06 3,36,993 4,824,010 43,124 8,62,127
12,112,911 43,978,820 1 ,815,026,920 -1,00,681,109 852,324,631
12,34,976 47,342,813 1 ,819,85,930 -1,00,242,985 86,95,758
FERC FORM NO.1 (ED. 12-9)Pa 311.11
FERC FORM NO.1 (ED. 12-90)Page 310.12
............................................
Name of Respondent Tnis~iortls:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/20
SALES FOR RESALE (Accunt '"7)
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 involvng 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 affilation the respondent has wih 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 servce. Requirements service is servce which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this servce in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm servce. Use this category for all firm servces 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 availabilty and reliabilty of
servce, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU servce except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Compay or Public Authority Statistical FERC Rate Avera;Actual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly illng l\vera~e Ave~
cation Tariff Number Deman (MW) Monthly NC Deman Mohly C emac
(a)(b)(c)(d)(e)(f)
1 Soutwetem Public Service Company SF WSPP NJl NJl NA
2 State of CA Dept of Water Resources SF WSPP NJl NJl NA
3 Tacoma, City of SF WSPP NJl NJ NA
4 The Energy Authority SF WSPP NJl NA NA
5 TransAlta Energy Marketing Inc.T-12 NJl NJl NA
6 TransAlta Energy Marketing Inc.SF T-11 NA NJl NA
7 TransAlta Energy Marketing Inc.SF T-12 NJl NJl NA
8 Tri-State Generation & Transmission SF T-11 NJl NJl NA
9 Tri-5tate Generation & Transmission SF WSPP 0.7 0.1 0.1
10 Tucson Electric Power WSPP NJl NJ NA
11 Tucson Elecric Power SF WSPP NJl NA NA
12 Turlock Irrigation District SF WSPP NJl NA NA
13 UBS Warburg Energy LLC SF T-12 NA NA NA
14 UNS Electric, Inc.SF WSPP NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Totl 0 0 0
............................................
Name of Respondent ThiS~rIS:Date of Report Year/Period of Report
PaCifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) A Resubmission 03131/200
Si LES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and servce 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 servce, as identified in column (b), is provided.
6. For requirements RQ sales and any tye of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling 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 tyes 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 bils 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.
MeaWatt Hours REVENUE Total ($)Une
Sold Demand Charges Energ Charges Other Charges (h+i+j)No.($)($)($)
(g)(h)(i)0)(k)
14,599 1,025,417 1,025,417 1
13,125 784,34 784,34 2
5,03 323,515 323,515 3
21,905 1,406,605 1,40,60 4
826,275 48,56,924 48,56,924 5
2,589 Ii 198,94 6
130,44 7,827,728 7,827,72f 7
68 55,OSE 8
126,80 31,51~9,138,722 9,170,241 9
180 -11,825 10
189,666 12,725,255 12,725,255 11
25,490 1,362,832 1,362,83~12
60,114 40,209,842 40,20,84~13
22,075 845,575 84,575 14
232,06 3,36,993 4,824,010 438,124 8,626,127
12,112,911 43,978,820 1,815,026,920 -1,00,681,109 852,324,631
12,34,976 47,342,813 1,819,850,930 -1,00,242,98 86,950,758
FERC FORM NO.1 (ED. 12-9)Pag 311.12
FERC FORM NO.1 (ED. 12-9)Page 310.13
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, 08, Yr)End of 2008/04
(2) r: A Resubmission 0331/200
SALES FOR RESALE (Accunt 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 involvng 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 affilation 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 servce as follows:
RQ - for requirements service. Requirements service is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this servce in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the supplier's servce to it own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that servce cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm servce. 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 servces 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 reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU servce except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistica FERC Rate Averaae Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illng !\vera~e Ave~caion Tariff Number Demand (MW) Monthly NC Dean Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Utah Assoiated Municipal Power Systems ~WSPP NA NA NA
2 Utah Associated Municipal Power Systems WSPP NA NA NA
3 Utah Municipal Power Agency 43 34 34 34
4 Utah Municipal Power Agency SF T-3 NA NA NA
5 Westem Area Power Administration WSPP NA NA NA
6 Western Area Power Administration SF T-11 NA NA NA
7 Westem Area Power Administration SF T-13 NA NA NA
8 Westém Area Power Administration SF WSPP NA NA NA
9 Bookout Sales AD NA NA NA NA
10 Test Generation lI NA NA NA NA
11 Test Generation NA NA NA NA
12 Trade Sales NA NA NA NA
13 Accrual True-up NA NA NA NA NA
14
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total (l 0 0
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 200Q4
(2)A Resubmission 03131/2009
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 involvng demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling 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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other tyes 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 bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQlNon-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 ($)Line
Sold Demand Charges Energ Charges Other Chargs (h+i+j)No.
($)($)($)
(g)(h)(i)(j (k)
17,565 702,60 702,60 1
4,970 406,90 40,90 2
223,859 4,396,20(5,202,483 9,598,6~3
776 38,253 38,2~4
338 28,980 28,98 5
45 -2,34:1 6
2 157 7
329,292 24,539,597 24,539,597 8
-17,45,425 -886,623,89E 9
-60 32,08 10
-55,89 -3,072,975 11
-127,855,541 12
-2,577 -739,84 13
14
232,06 3,36,993 4,824,010 43,124 8,626,127
12,112,911 43,978,820 1,815,026,920 -1,00,681,109 852,324,631
12,34,976 47,342,813 1,819,850,930 -1,00,242,98 86,95,758
FERC FORM NO.1 (ED. 12-9)Page 311.13
¡SChedule Page: 310 Line No.: 9 Column: j
Settement Adjustment
¡SChedule Page: 310 Line No.: 10 Column: j
Fixed char e for the firt six month of the contract to reover cost.
SChedule Pa e: 310 Line No.: 12 Column:
Represents the diference between actal requirement sales revenues for the period as reflecte on the individual lie items with ths
schedule, and the accruals char ed to account 447 dur the eriod.
Schedule Pa e: 310.1 Line No.: 5 Column:.
Reserve Share
Ilchedule Page: 310.1 Line No.: 7 Column: b
Settement Adjustment
I§hedule Page: 310.1 Line No.: 7 Column: j
Settement Ad~tmnt
¡Schedule Pag: 310.1 Line No.: 9 Column: b
Settement Adjutmnt
¡SChedule Page: 310.1 Line No.: 9 Column: j
Settement Adjutmnt
¡Schedule Page: 310.1 Line No.: 11 Column: b
Basin Electrc Power Company - PEC T -11 (Evergrn Network Trasmission Servce under the Open Access Tranmission Tarff
(S.A. 228 & 233)) - Contract termtion date: 12 month notication.
¡SChedule Page: 310.1 Line No.: 11 Column:j
Transmission Losses
¡SChedule Page: 310.1 Line No.: 12 Column: J
Transmission Losses
¡SChedule Page: 310.2 Line No.: 2 Column: b
Black Hills Power & Li ht Co an - FERC 441 - Contrt termtion date: Deembr 31, 2023.
SChedule Pa e: 310.2 Line No.: 3 Column: b
Second , Econom and/or non-fi sales, includin some hourI fi tractions.
SChedule Pa e: 310.2 Line No.: 5 Column: b
Settlement Ad~tmnt
¡SChedule Pag: 310.2 Line No.: 5 Column: j
Settement Adjustmnt
¡Schedule Page: 310.2 Line No.: 6 Column: b
Bonnevile Power Admistration - FERC 368 rUse of Facilties Agrment for the Mal Traformr under the AC Interte
A eement wt BPA) - Contrct termnation date: U n mutu a eement.
SChedule Pa e: 310.2 Line No.: 6 Column:'
Trasmission Losses
¡Schedule Page: 310.2 Line No.: 7 Column: b
Bonnevile Power Admistrtion - PEC T -11 (point-to-Point Transmission Servce under the Opn Access Tramission Tar
(S.A. 179))- Contrct termation date: Septembr 30, 2025.
Ilchedule Page: 310.2 Line No.: 7 Column: j
Transmission Losses
¡SChedule Page: 310.2 Line No.: 8 Column: b
Bonnevile Power Admistration - FERC T -12 - Contrct termation date: Aprl 22, 2024.
¡SChedule Page: 310.2 Line No.: 9 Column: J
Tranmission Losses
I§hedule Page: 310.2 Line No.: 10 Column: J
Reserve Shae
¡SChedule Page: 310.2 Line No.: 12 Column: j
Reserve Shae
¡SChedUle Page: 310.2 Line No.: 14 Column: b
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0331/209 20004
FOOTNOTE DATA
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/209 2004
FOOTNOTE DATA
Settement Adjutmnt
¡Schedule Page: 310.2 Line No.: 14 Column: I
Settlement Adjustmnt
¡SChedule PaJle: 310.3 Line No.: 2 Column: b
Settlement Ad~tmnt
¡Schedule PaJJ: 310.3 Line No.: 2 Column: j
Settement Adjustment
¡SChedule PaJle: 310.3 Line No.: 3 Column: b
Second , Econom and/or non-firm sales, includin some houri fi trsactions.
SChedule Pa e: 310.3 Line No.: 4 Column:'
Trasmission Losses
¡SChedule Page: 310.3 Line No.: 5 Column: j
Unauthorized use charges
¡SChedule Page: 310.3 Line No.: 7 Column: I
Pond Sale
¡SChedule Page: 310.3 Line No.: 8 Column: I
Transmission Losses
¡Schedule Page: 310.3 Line No.: 13 Column: b
Settement Adjustment
¡Schedule Page: 310.3 Line No.: 13 Column: i
Settemnt Adjustment
¡Schedule Page: 310.4 Line No.: 1 Column: i
Trasmission Losses
¡Schedule Page: 310.4 Line No.: 3 Column: b
Settement Adjistmnt
¡SChedule Page: 310.4 Line No.: 3 Column: i
Settement Adjistmnt
¡Schedule Page: 310.4 Line No.: 4 Column: i
Trasmission Losses
¡SChedule Page: 310.4 Line No.: 5 Column: i
Unauthoried use chages
!Shedule Page: 310.4 Line No.: 7 Column: b
Settement Adjustment
¡SChedule Page: 310.4 Line No.: 7 Column: i
Settement Ad~tmnt
¡SChedule Pag: 310.4 Line No.: 10 Column: i
Reserve Shar
¡SChedule Page: 310.5 Line No.: 1 Column: i
Transmission Losses
¡Schedule Page: 310.5 Line No.: 4 Column: b
Settement Adjistment
!Shedule Page: 310.5 Line No.: 4 Column: i
Settlement Adjustmnt
¡SChedule PaJle: 310.5 Line No.: 11 Column: i
Trasmission Losses
¡SChedule Page: 310.5 Line No.: 13 Column: b
Hurcane, Ci of-PEC T-12 - Contrt tennationdate: Au t 31,2007.
hedule Pa : 310.5 Line No.: 14 Column: b
Settement Adjutmnt
¡SChedule Page: 310.5 Line No.: 14 Column: i
Settement Adjustment
IFERC FORM NO.1 (ED. 12-S7) Page 450.2
Page 450.3
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/200 200/04
FOOTNOTE DATA
¡Schedule Page: 310.6 Line No.: 1 Column: b
Ibrdola Renewables, Inc. - FEC T -11 (point-to-Point Tramission Servce under the Open Access Trasmission Tar (S.A. 279))
- Contract termnation date: A ri130, 2009.
Schedule Pa : 310.6 Line No.: 1 Column:'
Trasmission Losses
¡SChedule Page: 310.6 Line No.: 2 Column: i
Transmission Losses¡Schedule Page: 310.6 Line No.: 4 Column: b I
Idao Power Company - T -11 (Point-to-Point Trasmission Service under the Open Access Trasmission Tar (S.A. 212)) - Contrt
termation date: Ma 31,2009.
SChedule Pa e: 310.6 Line No.: 4 Column:'
Trasmission Losses
¡SChedule Page: 310.6 Line No.: 5 Column: i
Trasmssion Losses
¡Schedule Page: 310.6 Line No.: 6 Column: i
Unauthorize use chages
ISchedule Page: 310.6 Line No.: 7 Column: i
Reserve Shar
¡Shedule Page: 310.6 Line No.: 9 Column: i
Trasmission Losses
!šhedule Page: 310.6 Line No.: 14 Column: b
Los An eles Deparent otWater and Power - FEC 301- Contrt termation date: June 15, 2027.
Schedule Pa : 310.7 Line No.: 7 Column: b
Settement Ad' ustment
SChedule Pa e: 310.7 Line No.: 7 Column:'
Settement Ad~tmnt
¡SChedule Pag: 310.7 Line No.: 8 Column: J
Trasmission Losses
¡SChedule Page: 310.7 Line No.: 9 Column: i
Li uidate Dam es
SChedule Pa e: 310.7 Line No.: 10 Column:'
Transmission Losses
ISchedule Page: 310.7 Line No.: 12 Column: i
Trasmission Losses
¡SChedule Page: 310.7 Line No.: 14 Column: i
Reserve Share
¡SChedule Page: 310.8 Line No.: 6 Column: i
Trasmission Losses
ISchedule Page: 310.8 Line No.: 11 Column: J
Trasmision Losses
ISchedule Page: 310.8 Line No.: 13 Column: i
Reserve Shae
¡SChedule Page: 310.8 Line No.: 14 Column: b
Settlement Ad. ustmnt
SChedule Pa e: 310.8 Line No.: 14 Column: .
Settement Ad .ustment
Schedule Pa e: 310.9 Line No.: 1 Column: b
Powerex - FEC T -11 (Point-to-Point Tramission Servce under the Open Access Trasmission Tar (SA 363)) - Contrct
termation date: September 30, 2012.
ISChedule Page: 310.9 Line No.: 1 Column: i
Tramission Losses
IFERC FORM NO.1 (ED. 12-87)
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 200Q4
FOOTNOTE DATA
Line No.: 2 Column:J
Line No.: 4 Column:b
Line No.: 4 Column:.
Line No.: 5 Column:b
Line No.: 5 Column:J
Line No.: 6 Column:b
fi trsactions.
Line No.: 11 Column:j
Line No.: 13 Column:j
Line No.: 3 Column:b
Line No.: 3 COlumn:j
Line No.: 4 Column: b
Distrct - PERC 250 - Contract termation date: Decmber 31,2014.
fi tranactions.
Line No.: 14 COlumn:b
Line No.: 14 Column:.
Line No.: 1 COlumn:j
Line No.: 4 Column:b
Line No.: 4 Column:.
Line No.: 5 Column:
Line No.: 6 Column:j
Line No.: 7 Column:b
Line No.: 7 Column:j
Line No.: 8 COlumn:b
Page 450.4
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp è2) A Resubmission 03131/2009 2008/04
FOOTNOTE DATA
28,2009.
Line No.: 10 Column: i
Line No.: 11 Column: i
Line No.: 5 Column: b
Inc. - PERC T-12 - Contrct termation date: Deembr 31, 2010.
Line No.: 6 Column:'
Line No.: 8 Column: i
Line No.: 10 Column: b
Line No.: 10 Column:'
fi tractions.
fi trtions.
fi trsactions.
I FERC FORM NO.1 (ED. 12-87)Page 450.5
............................................
Blank Page
(Next Page is 320)
2,681
1,225,169
1,437,284
1,572,617
2,151,781
6,389,532
35,679,549
1,020,921
1,017,895
1,678,495
2,107,860
5,825,171
33,214,241
.............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008/04
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 0331/20
ELE TRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Accont Amount forNo ~~. ~
1
2
3
Am,ount for
Previous Y"ear
(c)
21,838,417
624,912,062
37,487,518
3,371,385
21,506,117
581,178,395
33,767,391
4,84,079
4,303,303
43,572,425
281,381
4,007,896
41,84,589
859,20
Enter Total of Lines 4 thru 12 735,766,491 688,008,670
6,008,903
24,83,108
86,675,457
28,874,080
12,753,101
159,145,649
89,912,140
6,200,007
22,514,293
94,470,112
31,838,666
11,951,367
166,974,43
85,983,105
enses
FERC FORM NO.1 (ED. 12-93)Page 320
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/200
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account ..No.(a)
".. "' P.. "'(b) (c)
60 D. Other Power Generation
61 Operation
62 54) Operation Supervsion and Engineering 218,46 729,753
63 (547 Fuel 466,962,755 325,837,509
64 548 Generation Expnses 17,845,03 22,455,638
65 (549 Miscellaneous Other Power Generation Exenses 10,943,849 5,931,46
66 550) Rents 6,739,843 11,96,686
67 TOTAL Operation (Enter Total of lines 62 thru 66)502,709,949 366,919,052
68 Maintenance
69 551) Maintenance Suoervision and Engineering
70 552) Maintenance of Structures 1,280,348 615,974
71 (553) Maintenance of Generating and Electric Plant 5,911,258 4,630,669
72 554) Maintenance of Miscellaneous Other Power Generation Plant 482,926 396,083
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)7,674,532 5,642,726
74 TOTAL Power Production Expenses-Other Power (Enter Tot of õl & 73)510,384,481 372,561,n8
75 E. Other Power Supplv Expenses
76 I (555) Purchased Power 754,189,849 763,738,961nI (556) System Control and Lod Dispatching 1,997,891 2,535,080
78 557) Other Expnses 56,143,94 60,542,623
79 TOTAL Other Power Supplv Exo (Enter Total of lines 76 thru 78)812,331,684 826,816,66
80 TOTAL Power Prouction Expenses (Total of lines 21,41, 59, 74 & 79)2,253,307,85 2,087,575,788
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Ooration Suoervsion and Engineering 7,808,710 8,207,350
84 (561) Load Dispatching
85 561.1) Load Dispatch-Reliabilit
86 561.2) Load Disoatch-Monitor and Operate Trasmission System 7,114,390 6,33,813
87 (561.3 Load Dispatch-Transmission Service and Scheduling 83,728
88 (561.4 Scheduling, System Control and Disoatch Servces
89 (561.5 Reliabilitv, Plannina and Standards Development
90 (561.6 Transmission Servce Studies 73,289 594,239
91 561.7 Generation Intercnection Studies 1,264,738 958,69
92 561.8) Reliabiltv, Plannina and Standards Develooment Servces
93 562) Station Expnses 1,869,851 1,00,028
94 56) Overhead Lines Expnses 93,337 125,807
95 56 Underground Lines Expses
96 (565 Transmission of Elecricitv bv Others 121,167,183 106,592,111
97 56 Miscellaneous Transmission Expnses 1,795,131 2,751,80
98 567) Rents 822,667 1,356,267
99 TOTAL Operaion (Enter Total of lines 83 thru 98)142,093,024 127,928,113
100 Maintenance
101 (568) Maintenance Supervsion and Engineering 9,822 56,234
102 (569) Maintenance of Strutures 3,284 4,076
103 (569.1 Maintenance of Computer Hardre 290,283 8,331
104 (569.2 Maintenance of Computer Softare 636,171 704,405
105 (569.3 Maintenance of Communication Equipment 3,199,160 2,516,755
106 (569.4) Maintenance of Miscellaneous Reaional Transmission Plant
107 (570 Maintenance of Station Eauipment 11,093,119 9,272,54
108 (571 Maintenance of Overhead Lines 16,204,998 13,323,841
109 (572 Maintenance of Underground Lines
110 (573 Maintenance of Miscellaneous Transmission Plant 480,533 380,572
111 TOTAL Maintenance (Total of lines 101 thru 110)31,917,370 26,266,759
112 TOTAL Transmission Expenses (Total of lines 99 and 111)174,010,394 154,194,872
FERC FORM NO.1 (ED. 12-93)Page 321
FERC FORM NO.1 (ED. 12-9)Page 322
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/2009
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account ..No.urrent ear Previous ear
(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) Trasmission Rights Market Faciltation
118 (575.4) Capacity Market Facilitation
119 (575.5) Ancilary Services Market Faciltation
120 (575.6 Market Monitorino and Compliance
121 (575.7 Market Faciltation, Monitorina and Compliance Servces
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 Hardre
127 (576.3) Maintenance of Computer Sofware
128 (576.4) Maintenance of Communication Eauioment
129 (576.5) Maintenance of Miscellaneos Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Reaional Transmission and Market OP Ex (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervsion and Engineering 20,296,814 19,728,019
135 581) Load Dispatching 12,782,671 12,661,549
136 582) Station Expenses 4,574,167 3,375,957
137 583) Overhead Line Expenses 5,392,347 7,612,638
138 584) Underground Line Expenses 403 230,535
139 (585) Street Lightino and Signal SyStem Exnses 222,030 248,162
140 (586) Meter ExPenses 7,204,688 5,795,418
141 (587) Customer Installations Expnses 11,06,638 9,337,557
142 (588) Miscellaneous Expenses 8,389,281 9,098,859
143 (589) Rents 3,038,169 4,289,931
144 TOTAL Operation (Enter Total of lines 134 thru 143)72,96,208 72,378,625
145 Maintenance
146 (590) Maintenance Supervision and Engineering 6,421,892 6,502,417
147 (591) Maintenance of Structures 2,030,161 1,382,792
148 . (592) Maintenance of Station Eauioment 11,547,226 11,743,862
149 (593) Maintenance of Overhead Lines 85,001,337 91,506,851
150 (594 Maintenance of Underground Lines 23,539,909 22,801,662
151 (595 Maintenance of Line Transformers 1,116,622 744,96
152 (596 Maintenance of Street Liohting and Signal Systems 4,138,856 4,335,96
153 i(597 Maintenance of Meters 5,212,174 5,476,485
154 (598 Maintenance of Miscellaneous Distribution Plan 3,391,891 4,467,250
155 TOTAL Maintenance (Total of lines 146 thru 154)142,400,068 148,962,247
156 TOTAL Distribution Exonses (Total of lines 144 and 155)215,36,276 221,34,872
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 901) Supervision 2,4n,949 2,756,699
160 902) Meter Reading Expenses 25,289,712 28,167,970
161 903) Customer Records and Collecion Exonses 56,637,149 55,607,837
162 (90 Uncollecible Accounts 14,674,714 8,551,037
163 I (905) Miscellaneous Customer Accounts Expnses 229,561 374,243
164 TOTAL Customer Accunts Expenses (Total of lines 159 thru 163)99,30,08 95,457,786
............................................
Name of Respondent
PacifiCorp
This ~rtls: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 03131/200
ELECTRIC OPERATION AND MAINTENANCE E PENSES Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Accunt Amount forNo ~~. ~
Year/Period of Report
End of 200804
PAmountf.orreVlus Year
(c)
247,987
51,82,080
4,101,589
63,857
56,242,513
423,543
42,756,237
3,784,546
5,126
46,969,452
83,301,566
11,n9,729
20,697,804
9,80,219
24,516,013
11,291,287
thru 193)
11,63,262
3,987,182
35,163
18,54,495
6,318,703
142,919,106
10,011,639
5,845,340
257,282
25,310,886
6,292,505
156,017,982
27,125,031
170,04,137
2,968,278,259
24,338,489
180,35,471
2,785,895,241
Page 323FERC FORM NO.1 (ED. 12-93)
2007
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp C2) A Resubmission 03131/209 200/04
FOOTNOTE DATA
¡Schedule Page: 320 Line No.: 187 Column: b
Pensions and benefits are chaged to fuctional accounts, which is consistent with where labor is chaged. The followig tale
sumizes the pension and benefit expense that was charged to the fuctional accounts.
2008
Yeas Ended
Decembr 31,
Pension & Benefits Expense $ 145,242,536 $ 170,449,274
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Blank Page
(Next Page is 326)
FERC FORM NO.1 (ED. 12-9)Page 326
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) D A Resubmission 03/31/2009
PU~C~AJlED POWERJ.Accu~t 5 5)n u ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactons involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's servce to its own ultimate consumers.
LF - for long-term firm servce. "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 servce). This caegory should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transacton identifed as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expec that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servces, where the duration of each period of commitment for service is one
year or less.
LU - for long-term servce from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constrints, must match the availabilty and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. Th same as LU servce expct that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electcity. Use this category for trnsactions invoMng a balancing of debits and credits for energy, capacity, etc.
and any settements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Descibe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statisticl FERC Rate Average Acual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monly Biling Average Average
cation Tari Number Demand (MW Monthly NCP Deman Monthly CP Deand
(a)(b)(c)(d)(e)(f)
1 Power Purchases
2 AES SeaWest, Inc.!NA NA NA
3 AES SeaWest, Inc.NA NA NA
4 Anaheim, City of .NA NA NA
5 Arizona Public Servce Co.NA NA NA
6 Arizona Public Servce Co.NA NA NA
7 Arizona Public Service Co.NA NA NA
8 Arizona Public Service Co.SF NA NA NA
9 Avista Corp.NA NA NA
10 Avista Corp.SF NA NA NA
11 BP Energy Company SF NA NA NA
12 Ballard Hog Farms Inc.LU NA NA NA
13 Bank of America, N.A.SF NA NA NA
14 Barcays Bank PLC -NA NA NA
Total
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ri A Resubmission 03131/200
CCOU~\~gg¿) (continUed)(InCludlnif power exc an )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of servce involving demand charges imposed on a monnthly (or ionger) basis, enter
the monthly average biling 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 maxmum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown On bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Chargs Energ Charges Other Charges Total O+k+l)No.Received Delivere
~l ~t~~fl
of Setlement ($)
(g)(h)(i)(m)
1---271,094 2
156,951 5,568,84E 5,568,84 3
12,665 66,3O 66,300 4
2E -3,911 5
231,531 10,728,200 10,728,296 6
965 65,985 65,985 7
47,19E 2,86,88 2,86,889 8
5C 3,1OC 3,975 9
33,GGE 1,511,1,532,855 10
613,264 33,280,5 37,04,19S 11
7~2,1~.-2,183 12
-290,932 13
625 43,15E 14
11,90,49E 6,43,684 6,569,511 135,972,332 1 ,556,826,34 -93,60,82 754,189,~
FERC FORM NO.1 (ED. 12-9)Page 327
FERC FORM NO.1 (ED. 12-9)Page 32.1
............................................
Name of Respondent This~ortIS:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) FíA Resubmission 031112009
PU~C~&iED POWERJ.Accu~t 5 5)n u ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electicity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements servce. Requirements servce is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes project load for this service in its system resource planning). In addition, the reliabilit of requirement servce must
be the same as, or second only to, the suppliets servce to its ow ultimate cosumers.
LF - for long-term firm service. "Long-term" means fie years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expct that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term servce from a designated generaing unit. "Long-term" means fie years or longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term servce from a designated generating unit.The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of eiectricity. Use this category for transactions involvng a balancing of debits and credits for energy, capacity, etc.
and any settements for imbalanced exchanges.
OS - for other service. Use this category only for those servce which cannot be place in the abovedefined categories, such as all
non-firm service regardless of the Lengt of the contrct and service frm designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Autority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif Scule or Monthly Billng Average AvegecaonTari Number Demand(M Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Barcays Bank PLC SF NA NA NA
2 Bear Energy LP SF NA NA NA
3 Beaver Cit .-NA NA NA
4 Bell Mountain Power NA NA NA
5 Benton County Pub Utilit Dist NO.1 SF NA NA NA
6 Biomass One, L.P.LU 22.5 17.6 15.3
7 Birc Creek Hydro LU NA NA NA
8 Black Hils Power, Inc..NA NA NA
9 Black Hils Powr, Inc.LU NA NA NA
10 Black Hils Powr, Inc.,NA NA NA
11 Black Hils Power, Inc.NA NA NA
12 Black Hils Wyoming, Inc.NA NA NA
13 Black Hils Wyoming, Inc.SF NA NA NA
14 Blanding City .-NA NA NA
Total
.............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ri A Resubmission 03131/200
t"U rilJnA~~~1 cc~ti~ggSi (Continued)nc ud,nci pòwér exc añãè
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-eoincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other tyes of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other tyes of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegWatt Hours POWER EXCHANGES COST/SETrEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Chargs E._"- ~ ~'"- _: T~ ~~No.Received Delivered
~l ~$~ ($) of Settement ($)
(g)(h)(i)k (I) (m)
1,528,20!96,158,7 9O,199,43 1
97,721 6,041,OOa: 3,955,86 2
60 ~~ ~~3
1,OO 48,48E 48,48S 4
13,9O 1,00,1OC 1,009,100 5
127,00.2,399,625 16,826,606 _ II 23,492,500 6
10,1&~"1i 54,~7
-1 33,725 S
1,236 2,189,41E 9
56~6O,Q&60,084 10
87,621 5,243,18E 5,243,1SE 11
91(123,20(123,20 12
32(33,56C 33,56C 13
391 29,34~29,34~14
11,90,49E 6,43,684 6,569,511 135,972,33 1 ,556,826,34 -93,608,829 754,189,841
FERC FORM NO. 1 (ED. 12-9)Page 327.1
FERC FORM NO.1 (ED. 12-9)Pag 326.2
............................................
Name of Respondent This e ortis:Date of Report Year/Period of Report
PacifiCorp (1)X An Original (Mo, Da, Yr)End of 2008/04
(2).. A Resubmission 03131/200
PU~C~ED POWERJ.Accu~t 5 5)n ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electicity (Le., transactons involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Exlain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In coumn (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements servce. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this servce in its system resourc planning). In addition, the reliability of requirement service must
be the same as, or second only to, the suppliets servce to its own ultimate consumers.
LF ~ for long~term firm service. "Long-term" means five years or longer and "firm" means that servce cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm service, where the duration of each period of commitment for servce is one
year or less.
LU - for long-term service from a designated generang unit. "Long-term" means five years or longer. The availabilit and reliabilty of
service, aside from transmission constrints, must match the availabilty and reliabilty of the designated unit.
IU ~ for intermediate-term servce frm a designat generating unit.The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX ~ For exchanges of electricity. Use this category for transactions involving a balancing of debits and crits for energy, capacity, etc.
and any settements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the abovedefined categories, such as all
non-firm service regardless of the Length of the contract and service frm designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Staistical FERC Rate Average Actual Demand (MW)
No.(Footnte Affliations)Classif-SCule or Monthly Billing Average AveragecaonTanf Number Demand (MW Monhly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Bogus Creek LU NA NA NA
2 Bonnevile POlNr Administration .NA NA NA
3 Bonneville POlNr Administration 575 575 497
4 Bonneville Powr Administration NA NA NA
5 Bonneville POlNr Administrtion NA NA NA
6 Bonnevile POlNr Administrtion SF NA NA NA
7 Burbank, City of SF NA NA NA
8 CDM Hydro LU NA NA NA
9 Califomia Independent System Operator ~NA NA NA
10 Califomia Independent System Operator SF NA NA NA
11 Cargill Powr Markets, LLC ..NA NA NA
12 Cargill Powr Markets, LLC NA NA NA
13 Cargil Powr Markets, LLC SF NA NA NA
14 Central Oreon Irrgation District ~NA NA NA
Total
............................................
Name of Respondent This R:;ortis:Date of Report Year/Period of Report
PacifiCorp (1) 2$An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03/31/2009
. ~ '~"~l iiè CCOMR\~8¡l) (vontlnueoJ
udmg' powër e~ an e )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for servce provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of servce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling 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 tyes of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energ Charges Other Charges Total Q+k+l)No.Received Delivere
~l \t~\fl
of Settement ($)
(g)(h)(I)(m)
931 31,71'31,7101 1Jï68,39E 2
47,058,00
14,1.01_
47,058,00 3
1,538,270 4
282,893 5
314,75.14,411,822 6
30,67~1,848,77C 1,848,770 7
28,251 1,50,38E 1,508,38 8
4,68E 291,087 9
267,714 15,001,~15,001,83 10
1,~-108,051 11
18,66 991,19E 991,19E 12
841,937 51,558,96E 51,558,96E 13
-21,951 14
11,90,49S 6,43,684 6,56,511 135,972,33 1,556,826,34 -938,608,829 754,189,8M
FERC FORM NO.1 (ED. 12-9)Page 327.2
FERC FORM NO.1 (ED. 12-9)Page 326.3
............................................
Name of Respondent This F~011 Is:Date of Report Year/Period of Report
PacifiCorp (1)~An Original (Mo, Da, Yr)End of 2008/Q4
(2)A Resubmission 03/31/2009
PU~~ED POWERJACCu~ 5 5)
( ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electcity (Le., transactons involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalance exchanges.
2. Enter the name of the seller or other part in an exchange trnsaction in column (a). Do not abbreviate or trncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the onginal contractual terms and conditions of the service as follows:
RQ - for requirements servce. Requirements service is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resourc planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
ecnomic 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 delivenes of LF service). This category should not be used for long-term firm service firm service .
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm servce.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short*term service.Use this category for all firm services, where the duration of each penod of commitment for service is one
year or less.
LU a for long-term service from a designated generatng unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constrints, must match the availabilit and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expct that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involvng a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this categor only for those servce which cannot be place in the aboveefined categones, such as all
non-firm service regardless of the Length of the contrct and service frm designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Autorty Staisticl FERCRate Average Actual Demand (MW)
No.(Footnote Affliations)C1assif Schule or MOnthIYB=Average AveragecationTari Number Demand (Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f
1 Central Oregon Irrgation District LU 3.3 3.3 2.1
2 Chelan County Pub Utility Dist No. 1 LU NA NA NA
3 Chelan County Pub Utilty Dist No. 1 NA NA NA
4 Chelan County Pub Utility Dist No. 1 ISF NA NA NA
5 Citigroup Energy, Inc.~NA NA NA
6 Citigroup Energy, Inc.SF NA NA NA
7 Cit of Buffalo LU 0.2 0.2 0.2
8 Clatskanie People's Utility District SF NA NA NA
9 Colorado River Commission of Nevada i NA NA NA
10 Commercal Energy Management NA NA NA
11 Conoc Inc.NA NA NA
12 Conoco Inc.ISF NA NA NA
13 Constellation Enery Commodities Group NA NA NA
14 Constellation Energy Commodities Grup NA NA NA
Total
............................................
Name of Respondent This R:,ortis:Date of Report Year/Period of Report
PacifiCorp (1) is An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03/31/200
( nc CCO~\~ggli) (ContlnU90)udinif pOwer exc an )
AD - for out-of-p.eriod adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tarif, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng 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 tyes of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthöurs
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COSTISEnLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Chargs Energ Charges Other Charges Total O+k+l)No.Received Delivered
Wl ~~~\fl
of Settlement ($)
(g)(h)(i)(m)
20,3&1 33,63 1,822,581 2,161,22~1
424,67f 3,831,38 2
2Q 3
22,71E 1,131,5 1,138,54 4
-11 -45 5
1,170,63 73,26,16 75,125,975 6
1,81::27,12::137,75f 164,881 7
1,17C 55,11C .-55,11C 8
51 9,372 9
1,37:i 70,~70,96::10
60 45,25(45,25C 11
352,5~24,852,82E 24,852,82E 12
1,17~75,26!13
4,O7~379,2()379,20f 14
11,909,49€6,43,68 6,569,511 135,972,33 1 ,556,826,34 -93,608,829 754,189,BM
FERC FORM NO.1 (ED. 12-90)Page 327.3
FERC FORM NO.1 (ED. 12-9)Page 32.4
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2)A Resubmission 03/31/200
PU~C~liED POWER hAccou~t 5 5)
n u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electicity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets servce to its ow ultimate cosumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that servce cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transacton identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm servce.The same as LF servce expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term servce.Use this category for all firm servce, 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 availabilit and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service frm a designated generating unit.The same as LU servce expct that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of elecricity. Use this category for transactions involvng a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this categor only for those servce which cannot be place in the above-efined categories, such as all
non-firm service regardless of the Length of the contrct and servce frm designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Stattical FERCRate Average Actual Demand (MW
No.(Footnote Affliations)Classif-Schule or MOnthIYB~Average AveragecaonTari Number Demand (Monhly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Constellation Energy Commodities Group SF 150 NA NA
2 Cowitz County Pub Utility Dist NO.1 ."NA NA NA
3 Credit Suiss Energy LLC NA NA NA
4 Credit Suisse Energy LLC SF NA NA NA
5 Curtiss Livestock LU NA NA NA
6 DB Energ Trading LLC ~NA NA NA
7 DB Energ Trading LLC NA NA NA
8 DR Johnson Lumber Company LU NA NA NA
9 Davis County Waste Management LU NA NA NA
10 Deschutes Valley Water Distrct LU 5.8 4.0 3.0
11 Deseret Power Electric Cooperativ Xi 100 100 99
12 Desert Powr, L.P.LU NA NA NA
13 Deutsch Bank AG SF NA NA NA
14 Douglas County Forest Products IU NA NA NA
Total
............................................
Name of Respondent fhis ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008104
(2) n A Resubmission 03131/200
r-u ivr'''ìlnC(1 cc0Wi~8~S) (i;ontlnUeo)
nc uding' POwér exe n e )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for servce provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng 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 servce, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other typs of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANüES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
~l \~~\fl
of Settlement ($)
(g)(h)(i)(m)
1,154,54,3,832,20 80,121,57 86,891,505 1
-495,391 2
28E 18,601 3
653,581 47,880,241 43,36,208 4
9E 6,37!:..6,375 5
11 5,232 6
309,01~17,455,73'17,45,734 7
65,8~4,275,73(4,275,730 8
45f 24,06.24,062 9
29,10E 567,311 2,939,621 3,506,93 10
817,81.13,486,104 14.06...31,114,155 11
-50,OOC 12
-2,484,519 13
821 44,011 44,018 14
11,90,498 6,43,684 6,56,511 135,972,~1,556,826,34E .938,60,82~754,189,~
FERC FORM NO.1 (ED. 12-9)Pag 327.4
FERC FORM NO.1 (ED. 1MO)Pag 32.5
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008104
(2)A Resubmission 03/31/2009
PU~C~~ED POWER ~Accu~t 5)5n ing power exc anges
1. Report all power purchases made during the year. Also report exchnges of electicity (Le., transactons involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalance exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or trncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements servce is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resourc planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets servce to its own ultmate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and ''frm'' means that service cannot be interrupted for
ecnomic reasons and is intended to remain reliable even under advers conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This caegory should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF servce expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servce, 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 availabilty and reliabilty of
service, aside from transmission constrints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term servce from a designated generating unit. The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those servces which cannot be place in the abovedefined categories, such as all
non-firm servce regardless of the Length of the contct and servce frm designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rae Average Actual Demand (MW)
No.(Footnote Affliations)C1assif Scule or Monthly
=
Average AveragecationTari Numbe Demand Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Douglas County Pub Utilty Dist No. 1 ..NA NA NA
2 Douglas County Pub Utilty Dist No. 1 NA NA NA
3 Douglas County Pub Utiity Dist No. 1 LU NA NA NA
4 Douglas County Pub Utilty Dist No. 1 ..NA NA NA
5 Douglas Count Pub Utilty Dist No. 1 NA NA NA
6 Draper Irrgation Company IU NA NA NA
7 Dry Creek ~NA NA NA
8 Dry Creek -NA NA NA
9 Oynegy Power Marketing NA NA NA
10 Dynegy Powr Marketing SF NA NA NA
11 EPCOR Energy Marketing (U.S.) Inc.SF NA NA NA
12 Eagle Point Irrgation Distrct LU 0.8 0.6 0.4
13 EI Paso Electric Company SF NA NA NA
14 Eugene Water & Electc Board SF NA NA NA
Total
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) i: A Resubmission 03131/200
CCWi~8¡S) (vontlnueoJ(Including power exc nge)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of servce invoMng demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Deand Charges Energ Charges Other Charges Total O+k+l)No.Received Delivered
~l \~~~fl
of Settlement ($)
(g)(h)(i)(m)
-52,263 1
-72,365 2
339,32C 2,66,274 3
52,69~1,011,38 7,465,382 4
23,44~1,483,83 1,485,481 5
29C 15,87a 15,870 6
61 3,591 7
9,83C 488,534 488,534 8
2f 1,594 9
42,98S 3,04,18E 3,04,188 10
22,OO 1,658,57E 1,658,57E 11
2,84::38,55 301,54E 340,101 12
71,52E 4,081,05::--4,090,519 13
122,16E 6,428,24E 6,428,246 14
11,909,498 6,43,68 6,56,511 135,972,33 1,55,826,34 -93,60,829 754,189,849
FERC FORM NO.1 (ED. 12-9)Page 327.5
FERC FORM NO.1 (ED. 12-9)Page 32.6
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03/31/200
PU~C~AJlED POWERJiAccu~t 5 5)n u ing power e~ anges
1. Report all power purchases made during the year. Also report exchanges of elecricity (Le., transactons involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange trnsaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contrctual terms and conditions of the servce as follows:
RQ - for requirements servce. Requirements service is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement servce must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and ''frm'' 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 servce). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF servce expec that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliabilit of
service, aside from transmission constrints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for trnsactions involvng a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those service which cannot be place in the above-defined categories, such as all
non-firm service regardless of the Length of the contact and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Stasticl FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Oassif-Schul or Monthly Billng Average AveragecationTari Number Demand(M Monthly NCP Demaii Monthl CP Demand
(a)(b)(c)(d)(e)(f)
1 Eurus Energy America LU NA NA NA
2 Evergreen BioPower, LLC NA NA NA
3 Evergreen BioPower, LLC LU NA NA NA
4 ExxonMobile Production Company LU NA NA NA
5 FPL Energy Power Marketing, Inc.SF NA NA NA
6 Falls Crek LU 3.0 3.3 2.0
7 Farmers Irrgation District LU 3.8 3.3 2.6
8 Fery, Loyd LU NA NA NA
9 Fillmore Cit
r=
NA NA NA
10 Finley BioEnergy, LLC NA NA NA
11 Finley BioEnergy, LLC NA NA NA
12 Fortis Energy Marketing & Trading GP NA NA NA
13 Fortis Energy Marketing & Trading GP SF NA NA NA
14 Franklin County Pub Utility Dist No. 1 SF NA NA NA
Total
............................................
Name of Respondent This 'O0rt Is:Date of Reiiort Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 03131/20
t"u nvnA~:W1 CCO~\RB~l) (l,ontinued)nc udinci pOwer exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of servce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng 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 tyes of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Tota O+k+l)No.Received Delivered
~l ~~~\fl
of Settlement ($)
(g)(h)(i)(m)
114,45 4,891,891 4,891,89 1-11 2
39,47.2,057,~2,057,O8~3
64,08~32,481,54.32,481,54.4
40,40 2,756,65C 2,756,6&5
15,92E 194,34 1,579,87E 1,774,22f 6
22,79'327,53:2,279,43 2,60,~7
26f 17,11"17,113 8
18.19,68C 19,680 9
10
25,59E 1,649,74E 1,649,745 11
5(3,450 12
182,46,11,497,101 12,908,53:13
8,61(612,47E 612,475 14
11,90,49E 6,43,68 6,56,511 135,972,33 1,55,826,34 -938,60,82~754,189,84'
FERC FORM NO.1 (ED. 12-9)Page 327.6
FERC FORM NO.1 (ED. 12-9)Pag 326.7
............................................
Name of Respondent ThiS~ortis:Date of Reiiort Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008lQ4
(2)A Resubmission 03131/2009
PU~C~~ED POWER J.Accu~t 5 5)n ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involvng a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange trnsaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Sttistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm servce. "Long-term" means five years or longer and ''frm'' 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 servce). This caegory should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transacton identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF servce expe that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term servce.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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term servce from a designated generang unit.The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactons involvng a balancing of debits and credits for energy, capaci, etc.
and any settlements for imbalanced exchanges.
as - for oter servce. Use this category only for those services which cannot be place in the above-efined categories, such as all
non-firm service regardless of the Length of the contract and servce from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or MonthlyB~Average Average
cation Tariff Number Demand (Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Frito Lay NA NA NA
2 Galesville Dam LU 0.6 0.9 0.6
3 Gar1and Canal LU 2.5 1.4 1.2
4 General Chemical Corporation NA NA NA
5 George DeRuyter & Sons Dairy IU NA NA NA
6 Georgetown lnigation Company LU NA NA NA
7 Gila River Power, L.P.NA NA NA
8 Gila River Power, L.P.SF NA NA NA
9 Grand Valley Power II NA NA NA
10 Grant County Pub Utility Dist NO.2 NA NA NA
11 Grant Count Pub Utilty Dist NO.2 14 NA NA
12 Grant County Pub Utilit Dist NO.2 NA NA NA
13 Grant County Pub Utility Dist NO.2 LU NA NA NA
14 Grant County Pub Utility Dist NO.2 NA NA NA
Total
............................................
Name of Respondent This R:.ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 20004(2) ..A Resubmission 0331/200
ccg¡\~ggl) (v ntinueo)( nc uding pówer exc anae )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for servce provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of servce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column G), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energ Charges Other Charges Total O+k+l)No.Received Delivere
~l \~~~ If of Settlement ($)
(g)(h)(i)(m)
612 1
5,45 68,315 616,64~68,95 2
9,72E 151,675 36,781 521,462 3
1,34~20,00 20,00 4
7,441 389,93C 389,930 5
1,81f 94,5~94,593 6
13E 4,55C 4,550 7
173,281 7,879,98C 7,879,980 8
8~13,29E 13,29l 9
-1,409,695 10
87,6O 87,093 6,40,31 6,821,164 11
1,26,25f 11,672,99 24,437,525 12
272,09E 12,514,78€13
4,94 14
11,90,49E 6,43,684 6,569,511 135,972,332 1,55,826,34 -93,608,82S 754,189,84S
FERC FORM NO.1 (ED. 12-9)Page 327.7
FERC FORM NO.1 (ED. 12-9)Page 32.8
...................................'.........
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/2009
PU~C~~ED POWERJAccu~t 5 5)n ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactons involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalance exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any owership interet or affliaton the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements servce. Requirements servce is servce which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resourc planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets servce to its ow ultmate consumers.
LF - for iong-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm servce
which meets the definition of RQ servce. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm servce. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for servce is one
year or less.
LU - for long-term service from a designated generatng unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for trnsactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this categor only for those servce which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and servce from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW
No.(Footnote Affliations)Classif-Schule or Monthly Billing Average Average
cation Tari Numbe Deand (MW Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Grant County Pub Utilty Dist NO.2 SF NA NA NA
2 Grays Harbor Public Utilty District SF NA NA NA
3 i~m_,c~-ii NA NA NA4NANANA-
5 241 241 198
6 Highland Energy LLC SF NA NA NA
7 Hill Air Forc Base il NA NA NA
8 Hurrcane, City of NA NA NA
9 lberdrola Renewables, Inc.NA NA NA
10 lberdrola Renewables, Inc..NA NA NA
11 Idaho Falls, Cit of NA NA NA
12 Idaho Falls, City of LU NA NA NA
13 Idaho Powe Company SF NA NA NA
14 Idaho Power Company SF NA NA NA
Total
............................................
Name of Respondent This ~rt Is: Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) DA Resubmission 03131/2009
~CC~\~8gs~ ivontlnueoJ(InCluding er exc an e )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tarif, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other tyes of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COSVSEnLEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charge Other Charges Total 0+k+1)No.Received Delivered ($1
\~~\'1
of Setlement ($)
(g)(h)(i)0 (m)
19,31S 1,073,51f .RI 1,080,096 1
5,95C 429,28f 429,285 2
5,90S ~~467,076 3
9,961 -4,786 4
1 ,801 ,38C 34,63,139 57,797,92,782,180 5
60,20.4,174,04~4,174,04!l 6
7,71C 34,45f 34,455 7
1,80~135,13f 135,13f 8
16C 2,08C 2,OS 9
410,87E 21,505,1 16,694,151 10
19,242 11
48,16(2,741,428 12
26,31i 1,96,281 13
34,94.1,996,39 2,015,40 14
11,909,498 6,436,68 6,569,511 135,972,33:2 1 ,556,826,34 -938,608,82!l 754,189,84~
FERC FORM NO.1 (ED. 12-90)Pag 32.8
FERC FORM NO.1 (ED. 12-90)Page 32.9
............................................
Name of Respondent This oo0rtIS:Date of Report Year/Period of Report
PacifiCor (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) DA Resubmission 03131/2009
PU~~ED POWERJiAccou~t 555)ing powr ex anges
1. Report all power purchases made during the year. Also report exchnges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or trncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3.ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement servce must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm servce. "Long-term" means five years or longer and "firm" means that servce cannot be interrupted for
economic reasons and is intended to remain reliable even under advers conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF servce). This caegory should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transacton identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expec that "intermediate-term" means longer than one year but less
than five years.
SF - for shortterm 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 genering unit. "Long-term" means five years or longer. The availability and reliabilty of
service, aside from transmission constrints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service frm a designated generang unit. The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for trnsactions involving a balancing of debits and credits for energy, capacity, etc.
and any settements for imbalanced exchanges.
as - for other service. Use this category only for those servces which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and servce from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Autority Statitical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Class-Schule or MonIYB=. Average AveragecaonTariff Number Deman (Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Integrys Energy Service, Inc.SF NA NA NA
2 Intermountain Power Project LU NA NA NA
3 Intemational Paper Company -NA NA NA
4 J. Aron & Company NA NA NA
5 J. Aron & Company SF NA NA NA
6 J.P. Morgan Ventures Energy Corp.SF NA NA NA
7 Kennecott IU NA NA NA
8 Kennecott LU NA NA NA
9 L&M Angus Ranch, LLC LU NA NA NA
10 Lacomb Irrgation LU NA NA NA
11 Lake Siskiyou LU 1.9 2.7 1.3
12 Lehman Brothers Commodit Servces SF NA NA NA
13 Logan City 1M NA NA NA
14 Los Angeles Dept. of Water & Powr NA NA NA
Total
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2O8IQ4
(2) ri A Resubmission 03131/200
cc0'5\~8g¿) lliontinUec)'nñëludïrg' power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other tyes 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.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Chargs Energ Chargs Other Chargs Total O+k+l)No.Received Delivered
~l \~~\fl
of Settement ($)
(g)(h)(i)(m)
7,35C 417,51C 417,51C 1
582,89-25,898,987 25,898,981 2
160,34E 10,632,66 10,63,66 3
-16 4
297,54.'.....0_21,751,323 5
83,9~5,607,031 8,256,547 6
157,65~6,657,6O 6,657,60 7-10,127,010 8
1,72::92,07~92,072 9
4,99 346,n .378,718 10
12,31::178,96 1,296,171 1,475,131 11
159,2OC 11'33'~-12,111,012 12
2E 3,37 3,376 13
14,04 588,47 n5,80::14
11,90,498 6,436,684 6,569,511 135,972,33 1 ,556,826,34 -938,60,82 754,189,84!l
FERC FORM NO.1 (ED. 12-90)Page 327.9
FERC FORM NO.1 (ED. 12-90)Page 32.10
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2)A Resubmission 03/31/2009
PU~C~dlED POWERJiAccu~t 5 5)n u ing powr ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange trnsaction in column (a). Do not abbreviate or trncate the name or use
acronyms. Explain in a footnote any owership interest or affliation th respondent has with the seller.
3. In column (b), enter a Sttistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements servce. Requirements service is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement servce must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm servce. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm servce. The same as LF service expect that "interediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm service, where the duration of each period of commitment for servce is one
year or less.
LU - for long-term servce from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constrints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU servce expct that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for trnsactions involving a balancing of debits and creits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those servces which cannot be place in the above-efined categories, such as all
non-firm service regardless of the Length of the contrct and servce frm designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)C1assif-Schedule or Montly Billng Average AveragecationTariff Number Demand (MW Monthly NCP Deman Monthly CP Demanc
(a)(b)(c)(d)(e)(f)
1 Los Angeles Dept. of Water & Power SF NA NA NA
2 Louis Dreyfus Energy Services L.P.SF NA NA NA
3 Luckey, Paul LU NA NA NA
4 Macquarie Cook Power Inc.SF NA NA NA
5 Magneium Corpration of America IU NA NA NA
6 Magnesium Corporation of America -NA NA NA
7 Marsh Valley Hydro & Electric Company NA NA NA
8 Marsh Valley Hydro & Electric Company LU NA NA NA
9 Merrll Lynch Commodities, Inc.SF NA NA NA
10 Middlefork Irrgation District NA NA NA
11 Middlefork I rrgation District LU NA NA NA
12 Mink Crek Hydro LU NA NA NA
13 Mirant Americas Energy Marketing, L.P.SF NA NA NA
14 Monsanto IU NA NA NA
Total
............................................
Name of Respondent Ihis~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) Ci A Resubmission 03131/200
cco~~8~l~ ((;ontlnueoJ(Includin~i pOwer exc nge)
AD . for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling 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 tyes of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawaUhours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other tyes of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Chargs Other Charges Total Ü+k+l)No.Received Delivere
~l \t~\fl
of Settlement ($)
(g)(h)(i)(m)
25,081 2,452,89l li -2,45,291 1
75 69,75 69,75C 2
28E 31,54.31,542 3
3,60(20,93E 20,936 4
245,72E 14,84,12~14,848,123 5
1,755,36 6
-9 .809 7
3,929 209,209,34 8
68,125 5,055,77 5,669,66 9
-25,873 10
25,17E 1,325,38C 1,325,38 11
9,28E 480,614 480,614 12
17~1,875 1,875 13-15,86,455 14
11,909,49S 6,43,68 6,569,511 135,972,33~1,556,826,34 -93,60,829 754, 189,84~
FERC FORM NO.1 (ED. 12-9)Page 327.10
FERCFORM NO. 1 (ED. 12*90)Page 326.11
............................................
Name of Respondent ThiS~ortis:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/2009
PU~~ED POWERJ.Accu~t 5 5)ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electcity (Le., transactons involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or trncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements servce. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm servce. "Long-term" means fie years or longer and ''frm'' 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 servce). This caegory should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transacton identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expct that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generaing unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constrint, must matc the availabilit and reliabilty of the designated unit.
IU - for intermediate-term service frm a designated generating unit. Th same as LU servce expct that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for trnsactions involvng a balancing of debits and creit for energy, capacity, etc.
and any settements for imbalance exchanges.
as - for other service. Use this category only for those servces which cannot be placed in the aboveefined categories, such as all
non-firm service regardless of the Length of the contract and servce frm designated units of Less than one year. Describe the nature
of the service in a fotnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)C1assif-Schedule or MOnthIYB=Average Average
cation Tari Number Demand (Monthly NCP Deman Monthly CP Demand
(a)--(c)(d)(e)(f)
1 Morgan City NA NA NA
2 Morgan Stanley Capital Group, Inc.NA NA NA
3 Morgan Stanley Capital Group, Inc.NA NA NA
4 Morgan Stanley Capital Group, Inc.SF NA NA NA
5 Mountain Energy, Inc.LU NA NA NA
6 Mountain Wind Power II, LLC LU NA NA NA
7 Mountain Wind Power, LLC LU NA NA NA
8 Municipal Energ Agency of Nebraska SF NA NA NA
9 Nephi City NA NA NA
10 Nevada Power Company SF NA NA NA
11 Nicholson Sunnybar Ranch LU NA NA NA
12 North Fork Sprague LU 0.4 0.5 0.2
13 NorthWestem Enery SF NA NA NA
14 Norlem Califomia Power Agency SF NA NA NA
Total
............................................
Name of Respondent This Re ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ==A Resubmission 03131/200
CCOU~\~8~S) (vontinuec)( nc udinii pOwer exc an e )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COSTISETIEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Deand Charges Energy Charges Other Charges Total Ü+k+l)No.Received Delivered ~l \t~\fl
of Setement ($)
(g)(h)(i)(m)
2f 3,OS;3,081 1
90 II II 38,593 2
329,581 17,743,81-4 17,743,814 3
2,863,63S 191 ,715,36 -194,255,54 4
5E 3,5&3,500 5
57,375 3,057,39~3,057,399 6
77,esE 3,892,94 3,892,94 7
24C 1S,24C 18,24C 8
1-4 1,46f 1,46E 9
23,70!707,34E II .1,628,54 10
1,47~76,19.76,192 11
2,46 38,96 256,1H .-295,082 12
41C 24,90 13
4,04 332,44C 33,440 14
11,90,49E 6,43,684 6,569,511 135,972,332 1,55,82,34 -938,60,829 754, 189,84~
FERC FORM NO.1 (ED. 12-9)Page 327.11
FERC FORM NO.1 (ED. 12-9)Page 326.12
............................................
Name of Respondent ThiS!ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/Q4
(2)A Resubmission 03/31/200
PU~C~dfED POWERJiAccu~t 5 5)n u ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactons involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contrctual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF servce). This caegory should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transacton identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contrct.
IF - for intermediate-term firm service.The same as LF service exp that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliability of
servce, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service frm a designated generating unit.The same as LU servce expct that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electicity. Use this caegory for trnsactions involvng a balancing of debits and creits for energy, capacity, etc.
and any settlements for imbalance exchanges.
OS - for other service. Use this caegory only for those servce which cannot be place in the above-efined categories, such as all
non-firm service regardless of the Length of the contrct and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Une Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Bill~Average AveragecationTariff Number Demand (M Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Nortpoint Energy Solutions Inc.SF NA NA NA
2 Nucor Corporation IF NA NA NA
3 O.J. Powr Company LU NA NA NA
4 Occdental Powr Services, Inc.SF NA NA NA
5 Odll Crek LU 0.05 0.06 0.04
6 Oreon Environmental Industries, LLC LU NA NA NA
7 PPL EnergPlus, LLC ~NA NA NA
8 PPL EnergPlus, LLC NA NA NA
9 Pacic Gas & Electric Company SF NA NA NA
10 Pacifc NW Generating Cooperative SF NA NA NA
11 Pacic Summit Energy LLC SF NA NA NA
12 Pasadena, Cit of NA NA NA
13 Pasadena, City of SF NA NA NA
14 Payson City Corporation -NA NA NA
Total
............................................
Name of Respondent Ihls~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004
(2) i: A Resubmission 03131/2009
CCO~\R8~¿) (liontlnUeO)(Including power exc an e )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for servce provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which servce, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of servce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other tys of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
~/~~~
($/of Settlement ($)
(g)(h)(i)(I (m)
31,47E 2,06,48 2,06,484 1
4,610,4OC 2
67E 32,52'-32,522 3
13,52C 1,265,36C 1,265,36C 4
30 4,472 28,02C 32,492 5
21,8~1,125,84 1,125,84 6
3E 1,44 1,44 7
3,16E 180,34 180,340 8
8,~84,94C 84,940 9
12,75C 6n,68 6n,680 10
137,03(8,551,54 8,551,54 11
5,33~197,75E 197,758 12
1,601 141,19E 141,198 13
e 1,03C 1,03 14
11,90,498 6,43,68 6,569,511 135,972,33 1,556,826,34E -938,608,829 754,189,84~
FERC FORM NO.1 (ED. 12-90)Pag 327.12
FERC FORM NO.1 (ED. 12-9)Page 326.13
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Oriinal (Mo, Da, Yr)End of 2008/04
(2) DA Resubmission 03131/200
PU~~AÆiED POWERJ.ACCU~ 5 5)u ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electicity (Le., transactons involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalance exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or trncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted 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 servce). This caegory should not be used for long-term firm service firm servce
which meets the definition of RQ servce. For all transacton identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servces, 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 availabilty and reliabilty of
service, aside from transmission constraints, must match th availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electicity. Use this category for trnsactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be place in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Staisticl FERC Rate Average Actual Demand (MW
No.(Footnote Affliations)C1assif-Schedule or MonthlYB~Average AveragecationTari Number Demand (Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Pinnacle West Marketing & Trading Co.SF NA NA NA
2 Platte River Power NA NA NA
3 Platte Rive Power SF NA NA NA
4 Portland General Electric Co..NA NA NA
5 Portand General Electric Co.NA NA NA
6 Portand General Electric Co.NA NA NA
7 Portland General Electric Co.SF NA NA NA
8 PO\rex ~NA NA NA
9 Powere NA NA NA
10 Praxair NA NA NA
11 Preston City Hydro ..NA NA NA
12 Provo City NA NA NA
13 Public Servce Company of Colorado NA NA NA
14 Public Servce Company of Colorado SF NA NA NA
Total
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) i: A Resubmission 03131/200
~\88~S) lliontlnueaJ(Including power exc an e )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maXimum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energ Chargs other Charges Total O+k+l)No.Received Delivered
WI \t~WI
of settlement ($)
(g)(h)(i).(m)
7~6,68f 6,68 1
-2f -1,31£2
3,43e 189,491 3
36,06 4
12,024 252,00 5
1,800 6
191,774 9,781,9,812,223 7
38E 20,760 8
571,98E 39,095,21~39,095,215 9i-2,9~10
2,44E 118,6Sf 118,685 11
15E 12,4O 12,4O 12
6C 2,801 13
30,62~1,811,201 1,811,201 14
11,909,49E 6,43,68 6,569,511 135,972,332 1 ,556,826,34 -938,608,82 754,189,84!
FERC FORM NO. 1 (ED. 12-90)Page 327.13
FERC FORM NO.1 (ED. 12-9)Page 326.14
............................................
Name of Respondent ThiS!iortls:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/2009
PU~C~ED POWERJ.Accu~t 5 5)n ing powr ex anges
1. Report all power purchases made during the year. Also report exchanges of electicity (Le., transactons involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalance exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the supplier'S servce to its own ultimate consumers.
LF - for long-term firm serce. "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 servce). This caegory should not be used for long-term firm servce firm service
which meets the definition of RQ service. For all transacton idented as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm servce.The same as LF servce expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term servce.Use this category for all firm service, 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service frm a designated generang unit.Th same as LU servce expct that "intermediate-ter" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for trnsacons involvng a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalance exchanges.
as - for other service. Use this category only for those servce which cannot be place in the above-defined categories, such as all
non-firm service regardless of the Length of the contrct and service from designated units of Less than one year. Descibe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (Wl
No.(Footnote Affliations)Classif-Schedule or MonthlYB~l\verage AveragecationTariff Number Demand (Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Public Serviæ Company of New Mexico -NA NA NA
2 Public Serviæ Company of New Mexico NA NA NA
3 Public Servæ Company of New Mexico SF NA NA NA
4 Pub Utilty Dist NO.1 of Lewis Count II NA NA NA
5 Puget Sound Energy SF NA NA NA
6 Puget Sound Energy SF NA NA NA
7 Quail Mountin, Inc.NA NA NA
8 Rainbow Energ Marketing SF NA NA NA
9 Ralphs Ranch, Inc.LU NA NA NA
10 Redding, City of SF NA NA NA
11 Reliant Energy Serviæs, Inc.SF NA NA NA
12 Riverside, City of ~NA NA NA
13 Riverside, Cit of SF NA NA NA
14 Rocky Mountain Generaion Cooperative ~NA NA NA
Total
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 208104
(2) ri A Resubmission 03131/200
cc~ti~8~S) tvontinueo)iincludii'j;¡ pöwiu exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for servce provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate SChedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which servce, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of servce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling 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 tyes of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column G), energy charges in column (k), and the total of any other tyes of charges, including
out-of-period adjustments, in column (i). Expiain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certin credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+1)No.Received Delivered ~l \~~\fl
of Settlement ($)
(g)(h)(i)(m)
3O!II 18,22E 1
36'26,12f .-26,12E 2
151,35.9,587,41 9,849,888 3
34,82E 34,828 4
110,531 5
122,205 6,60,85 6,64,152 6
10 7
24,461 1,371,33l 1,371,33 8
24C 26,79~26,792 9
1,OO 4O,95~40,952 10
27,5OC 2,48,7OC 2,489,700 11
39,58E 1,455,741 1,455,741 12
4l 2,08E 2,08E 13
13E 6,97f 6,975 14
11,90,49E 6,43,68 6,569,511 135,972,33~1 ,55,826,34 -938,608,829 754, 189,84~
FERC FORM NO.1 (ED. 12-9)Pag 327.14
FERC FORM NO.1 (ED. 12-9)Page 326.15
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr)End of 2008/Q4
(2)A Resubmission 0311/2009
PU~C~AdlED POWER hACCU~ 5 5)
n u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange trnsaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resourc planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its ow ultimate consumers.
LF - for long-term firm servce. "Long-term" means five years or longer and "firm" means that service cannot be interrpted 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 servce). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duraion of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generaing unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constrints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and crits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those servce which cannot be place 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 fotnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Averae Actual Demand (MW
No.(Footnote Affliations)C1assif-Schule or Monly Biling Average AveragecationTari Number Demand (MW Monthly NCP Deman Monthly CP DemaF1
(a)(b)(c)(d)(e)(f)
1 Rocky Mountain Generation Cooperative SF NA NA NA
2 Roseburg Forest Proucts Co.LU NA NA NA
3 Rough & Ready Lumber Company LU NA NA NA
4 Roush Hydro, Inc.LU NA NA NA
5 SUEZ Energy Marketing NA, Inc.SF 525 458 474
6 Sacrmento Municipal Utilit District ~NA NA NA
7 Sacrmento Municipal Utilty District NA NA NA
8 Sacrmento Municipal Utilit District SF NA NA NA
9 Salt River Project NA NA NA
10 Salt River Project SF NA NA NA
11 San Diego Gas & Electric NA NA NA
12 San Diego Gas & Electric SF NA NA NA
13 Santa Clara, City of SF NA NA I'
14 Santiam Water Control District LU 0.2 0.001 0.0
Total
............................................
Name of Respondent This ~iortls:Date of Report Year/Period of Report
PacifiCorp (1)!An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03/31/200
cco~tl~ggS) ((;ontinueo)nc udin¡f DOwer exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tanff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NcP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other tyes of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maxmum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegWatt Hours POWEH EXCHANGES COST/SETTLEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energ Charges Other Charges Total O+k+l)No.Received Delivere
~l \~~~fl
of Setlement ($)
(g)(h)(i)(m)
5,25C 212,06 212,06 1
138,29'7,896,5 7,726,57:3 2
6,331 409,381 409,381 3
27:3 17,681 ll 17,681 4
1,236,24E 11,508,744 79,9n,92C 96,171,741 5
156,389 6
218,86 3,25O,19C 3,25O,19C 7
35,58-2,795,93~2,795,93~8
3,48C 285,36 285,36 9
186,46~11,174,08.-11,1n,211 10
-E -372 11
26,49f 1 ,701 ,16f 1,701,165 12
6,85 447,95C 447,950 13
1,571 13,63~14O,1~153,815 14
11,90,4ge 6,43,68 6,569,511 135,972,33 1,556,826,34 -938,60,829 754,189,~
FERC FORM NO.1 (ED. 12-90)Page 327.15
FERC FORM NO.1 (ED. 12-9)Page 326.16
............................................
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008104
(2)A Resubmission 03131/2009
PU~C~~ED POWERJiAccu~t 5 5)n u ing power e~ anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactons involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchnge transacton in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any owership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement servce must
be the same as, or second only to, the suppliets servce to its own ultimate consumers.
LF - for long-term firm servce. "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 servce). This category should not be used for long-term firm service firm servce
which meets the definition of RQ service. For all transacton identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service exp that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term servce.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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service frm a designated generating unit. The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electcity. Use this categor for trnsactions involvng a balancing of debits and crits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those servces which cannot be place in the above-efined categories, such as all
non-firm service regardless of the Length of the contract and service frm designated units of Less than one year. Describe the nature
of the servce in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (M~
No.(Footnote Affliations)Classif-Schedule or MonthlYB~Average Average
cation Tanff Number Demand (Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Schwendiman Wind Farms Inc.LU NA NA NA
2 Seattle City Light SF NA NA NA
3 Sempr Energy Solutions SF NA NA NA
4 Sempra Energy Trading LLC p NA NA NA
5 Sempra Energy Trading LLC NA NA NA
6 Sempra Generation SF NA NA NA
7 Shell Energy Nort America (US), L.P.g NA NA NA
8 Shell Energy Nort America (US), L.P.NA NA NA
9 Shell Energy Nort America (US), L.P.SF NA NA NA
10 Sierr Pacific Power Company SF NA NA NA
11 Simplot Phosphates, LLC LU 10 12 9
12 Simplot Phosphates, LLC NA NA NA
13 Slate Creek LU 2.4 1.8 0.8
14 Snohomish Pub Utilit Dist No. 1 SF NA NA NA
Total
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PaciiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 031311200
CCOU~\R8g¿~ (Gontinuec)
(Including power exc an )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true.ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of servce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling 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 tyes of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (rn)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Gharges Total O+k+l)No.Received Delivered
~l \~~~fl
of Selement ($)
(g)(h)(i)(m)
-4,462 1
83,7~5,073,461 5,087,26 2
25,86 1,775,34 1,775,347 3
22~12,675 4
1,477,181 96,231,31 94,019,65 5
14,761 995,92 995,926 6
-17E -12,705 7
83~44,5 44,59:2 8
588,22~36,96,36,112,94E 9
46,88E 3,259,48..3,30,431 10
76,47~44,600 3,139,924 3,584,524 11.-8,801 12
8,63f 125,995 80,06~929,051 13
53,96~2,374,311 2,374,311 14
11,909,49E 6,43,68 6,569,511 135,972,33:2 1,556,826,34 -938,60,829 754,189,84~
FERC FORM NO.1 (ED. 12-90)Pag 327.16
FERC FORM NO.1 (ED. 12-9)Page 32.17
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03/31/2009
PU~C!¡JlED POWERJiCCu~ 5 5)n u ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electicity (Le., transactons involving a balancing of
debits and credits for energy, càpacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets servce to its ow ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This caegory should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servce, where the duration of each period of commitment for service is one
year or less.
LU - for long-term servce frm a designated generting unit. "Long-term" means five years or longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involvng a balancing of debits and credits for energy, capaci, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those servce which cannot be place in the above-defined categories, such as all
non-firm service regardless of the Length of the contrct and service frm designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Autority Statistical FERC Rate Average Actual Demand (MW
No.(Footnote Affliations)C1assif Schul or Montly Billng Average Average
cation Tari Number Demand fJ Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Southem Califomia Edison Company p NA NA NA
2 Southem Califomia Edison Company NA NA NA
3 Southwetem Public Service Company SF NA NA NA
4 Spanish Fork City ~NA NA NA
5 Spanish Fork Wind Park 2, LLC NA NA NA
6 Springville City .NA NA NA
7 Springville City NA NA NA
8 State of CA Dept of Water Resourcs SF NA NA NA
9 State of Utah .NA NA NA
10 Straerr Electric Service District NA NA NA
11 Sunnyide Cogeneration Asciates NA NA NA
12 Sunnyside Cogeneration Associates 52.0 53.4 46.7
13 Tacoa, Cit of SF NA NA NA
14 Tesoro Refining and Marketing Company .-NA NA NA
Total
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ri A Resubmission 03131/200
CC~\~~S) (0 ntlnUed)
(inCluding pówer exc an )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for servce provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of servce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other tyes of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawaUhours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other tys of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Deman Charges Energ Charges Other Charges Total O+k+l)No.
Received Delivered ~l \t~\fl
of Settlement ($)
(g)(h)(i)(m)
81,931 2,229,88~2,229,88E 1
114,95~6,669,86E 6,669,86 2
40C 22,OO 22,00 3
4(3,64 3,647 4
23,9O 1,220,10:1 1,220,102 5
~~521 6
3~4,12E 4,129 7
10,4OC 1,057,12E 1,057,128 8
1,219 9
64 4,87~4,875 10
-1,635,49:3 11
414,121 10,361,29:3 16,958,254 27,319,541 12
29,384 1,547,47E Bi .1,551,925 13
180,58~8,768,OH 8,768,019 14
11,909,498 6,436,68 6,569,511 135,972,33 1,556,826,34 -938,60,829 754,189,84E
FERC FORM NO.1 (ED. 12-9)Pag 327.17
FERC FORM NO.1 (ED. 12-9)Page 326.18
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Oa, Yr)End of 2008/04
(2)A Resubmission 03131/2009
PU~C6rJlED POWER hAccu~t 5 5)
n u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electicity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange trnsaction in column (a). Do not abbreviate or trncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contrctual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilit of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transacton identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF servce expct that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servces, where the duration of each period of commitment for servce is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside frm transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expct that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for trnsactons involvng a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchnges.
OS - for other service. Use this category only for those servce which cannot be place in the above-efined categories, such as all
non-firm service regardless of the Length of the contrct and servce from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Autority Statistical FERC Rate Average Actual Demand (MW
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng . Average AveraecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Thayn Hydro LLC LU 0.3 0.4 0.3
2 The Energy Authority SF NA NA NA
3 TransAlta Energy Marketing Inc.l NA NA NA
4 TransAta Energy Marketing Inc.NA NA NA
5 TransAlta Energy Marketing Inc.IF NA NA NA
6 TransAlta Energy Marketing Inc.SF NA NA NA
7 Tri-State Generaion & Transmission NA NA NA
8 Tri-State Generation & Transmission 35 34 29
9 Tri-State Generation & Transmission NA NA NA
10 Tri-State Generation & Transmission SF NA NA NA
11 Tucson Electric Power lE NA NA NA
12 Tucson Electc Powr NA NA NA
13 Tucsn Electc Powr SF NA NA NA
14 Turlock Irrgation Ditrct SF NA NA NA
Total
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 200804
(2) Õ A Resubmission 03131/200
CC~\~8i) (,-ontlnueaJ. .. ''(nClUding power exc an )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which servce, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling 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 tyes of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide expianations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered ~l \t~\fl
of Settement ($)
(g)(h)(i)(m)
2,60 44,455 172,15E 216,611 1
57,92~2,631,69~2,631,692 2
-292,086 3
826,22f 47,531,084 47,531,084 4---420,320 5
181,90f 10,995,091 10,995,098 6-127,690 7
199,5~8,370,60 4,057,911 12,428,511 8
20f 10,37f 10,375 9
51,551 3,273,08C 3,317,890 10
18C 12,001 11
26f 16,12f 16,125 12
81,161 5,302,72~5,302,72:3 13
17,07J 1,026,26.1,026,262 14
11,90,498 6,43,684 6,56,511 135,972,33 1,556,826,34 -938,60,829 754,189,84!3
FERC FORM NO.1 (ED. 12-9)Page 327.18
FERC FORM NO.1 (ED. 12-9)Page 326.19
............................................
Name of Respondent This e ortis:Date of Report Year/Period of Report
PacifiCor (1)X An Original (Mo, Da, Yr)End of 2008/04
(2).. A Resubmission 0311/2009
PU~C~AdfED POWER hAcu~t 5 5)n u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involvng a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements servce. Requirements service is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm servce. "Long-term" means five years or longer and ''frm'' means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expec that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servce, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generaing unit. "Long-term" means five years or longer. The availability and reliabilty of
service, aside from transmission constrints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term servce from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those servce which cannot be place in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and servce frm designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Staistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Class Schule or Montly Billing Average AveragecationTari Number Demand (MW Monthly NCP Deman Monthly CP Demanc
(a)(b)(c)(d)(e)(f)
1 UBS Warburg Energy LLC SF 25 25 25
2 UNS Electric, Inc.SF NA NA NA
3 UT Associated Municipal PO'Nr Systems 77 77 77
4 UT Associated Municipal PO'Nr Systems SF NA NA NA
5 Utah Municipal PO'Nr Agency ..NA NA NA
6 Wadeland South LLC NA NA NA
7 Wadeland South LLC LU 0.02 0.08 0.02
8 Walla Walla, City of LU 2.0 1.6 1.5
9 Warm Springs Forest Proucts t-NA NA NA
10 Warm Springs Forest Prouct NA NA NA
11 Weber County, State of Utah LU NA NA NA
12 Westem Area Powr Administrtion .NA NA NA
13 Westem Area PO'Nr Administration NA NA NA
14 Westem Area PO'Nr Administrtion SF NA NA NA
Total
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/200
CC~\~B~S) (continueo¡, ... "'" '~ì1ìicfudln¡f páwer exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of servce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng 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 tyes 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 coumns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energ Charges Other Charges Total U+k+l)No.Received Delivered
~l \~~WI
of Settlement ($)
(g)(h)(i)(m)
139,11~621,7&10,43,091 --11,095,283 1
5~2,361 2,35(2
109,85~911,619 7,144,821 -8,591,65 3
18S 19,22E 19,225 4
11,43C 576,51.576,512 5--3,n1 6
14E 1,86S 4,73'6,602 7
12,987 138,725 1,662,34 1,801,071 8-321:9
67~15,984 15,98 10
5,89E c=22,081 11
-31 12
1,40 50,6O,8O 13
11 ,67~589,7 60,8n 14
11,909,4ge 6,43,68 6,569,511 135,972,33~1,556,826,34 -938,60,829 754,189,84~
FERC FORM NO.1 (ED. 12-9)Pag 327.19
FERC FORM NO.1 (ED. 12-9)Page 326.20
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCor (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) r: A Resubmission 03/31/2009
PU~C~dfED POWERJ.Accu~t 5 5)n u ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electicity (Le., transactions involvng a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalance exchanges.
2. Enter the name of the seller or other part in an exchange trnsaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the servce as follows:
RQ - for requirements servce. Requirements servce is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resourc planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its ow ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and ''frm'' means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF servce expec that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servce, whre 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this caegory for trnsactions involvng a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this catery only for those servce which canno be place in the aboveefined categories, such as all
non-firm service regardless of the Length of the contrct and servce frm designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Bill~. Average AveragecationTari Number Demand (M Monthly NCP Demam Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Weyerhaeuser Company -l NA NA NA
2 Wolverine Creek Energ LLC NA NA NA
3 Yakima Tieton LU NA NA NA
4 Accal true-up NA NA NA NA
5 Line Loss Retum AD NA NA NA
6 Bookout Purcases AD NA NA NA
7 Potential Liabilty AD NA NA NA
8 Trade Purcases AD NA NA NA
9
10
11
12 Power Exchanges
13 Arizona Public servce Co.EX 306 NA NA NA
14 Avita Corp.EX 55 NA NA NA
Total
............................................
Name of Respondent This R~ortis:Date of Report Year/Period of Report
PacifiCorp (1) 2i An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/200
, .. ".. 1 ccou~i~g~l\ (continued)
nc uding pOwer exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in pnor reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of servce involvng demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other tyes of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maxmum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COSTlSEnLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energ Charges Other Charges Total O+k+l)No.Recived Delivered
~l \~~\fl
of Settlement ($)
(g)(h)(i)(m)
210,68C 13,99,39i 1S,99,397 1
170,26l 9,206,40~9,206,402 2
6,76'339,~339,54~3
-6,203,86 4
-4,585,95~5
-17,46,081 -886,623,89E 6
-1,932,67f 7
-127,855,541 8
9
10
11
12
569,553 569,267 -2,974,14:13
1,770 14
11,909,49 6,436,684 6,569,511 135,972,332 1,556,826,34 -938,60,829 754,189,84~
FERe FORM NO.1 (ED. 12-9)Page 327.20
Name of Respondent This F;J ortis:Date of Report Year/Period of Report
PacifiCorp (1)~An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/2009
PU~C~JlED POWERJACCur 5 5)n u ing powr ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involvng a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has wih the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements servce. Requirements service is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm servce. "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 caegory should not be used for long-term firm service firm service
which meets the definition of RQ servce. For all transacton identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF servce expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for servce is one
year or less.
LU - for long~term service from a designated generaing unit. "Long-term" means five years or longer. The avaiiability and reliabilty of
service, aside from transmission constrints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.Th same as LU servce expec that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other servce. Use this category only for those servces which cannot be placed in the above-defined categories, such as all
non~firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif-SCedule or Monthly
=
Average AveragecationTariff Number Demand Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Basin Electric Powr Cooperative EX T-11 NA NA NA
2 Black Hils Powr, Inc.EX 246 NA NA NA
3 Bonneville Power Administrtion I NA NA NA
4 Bonnevile Powr Administration 237 NA NA NA
5 Bonneville Powr Administration EX 256 NA NA NA
6 Bonnevile Power Administration EX 347 NA NA NA
7 Bonneville Powr Administration EX 368 NA NA NA
8 Bonneville Power Administration EX 554 NA NA NA
9 Bonneville Power Administration EX (16)NA NA NA
10 Bonneville Powr Administration EX T-11 NA NA NA
11 Bonnevile Power Administration EX T-12 NA NA NA
12 Chelan County ~ub Utilty Dist No. 1 EX 55 NA NA NA
13 Chelan County Pub Utiity Dist No. 1 EX T-12 NA NA NA
14 Colockum Transmission Company EX T-12 NA NA NA
Total
FERC FORM NO.1 (ED. 12-9)Page 326.21
............................................
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) i: A Resubmission 0331/200
CCO~\R8~l) (Gontinueo)(inciuding power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of servce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling 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 tyes of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energ Charges Other Charges Total O+k+l)No.Received Delivered
~l \t~\fl
of Settlement ($)
(g)(h)(i)(m)
10,183 10,084 ~71,61.3 1
91 2
.77,970 3
61,488 -9,430 4
53 53 -424 5
1,63,817 1,625,287 615,00 6
222,273 222,273 7
238,349 77,113 8.--4,878,06 9
9,063 6,567 132,449 10
109,074 104,735 551,721 11
16,49 12
83,712 13
267,942 14
11,90,49S 6,43,68 6,569,511 135,972,332 1 ,556,826,34 -938,608,829 754,189,84~
FERC FORM NO. 1 (ED. 12-9)Page 327.21
FERC FORM NO.1 (ED. 12-9)Page 32.22
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/2009
PU~~AdfED POWER ~ACCu~ 5 5)u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involvng a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Sttistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements servce. Requirements servce is servce which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this servce in its system resourc planning). In addition, the reliability of requirement service must
be the same as, or secnd only to, the suppliets servce to its ow ultimate consumers.
LF - for long-term firm servce. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "interrnediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this caegory for all firm servce, where th duration of each period of commitment for servce is one
year or less.
LU - for long-term service from a designated generang unit. "Log-term" means five years or longer. The availabilit and reliabilit of
service, aside from transmission constrints, must match the availabilit and reliabilty of the designated unit.
IU - for intermediate-term service frm a designated generating unit.The same as LU servce expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those servce which cannot be place in the above-defined categories, such as all
non-firm service regardless of the Lengt of the contrct and servce frm designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Sttistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)C1assifi-Scedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Constellation Energy Commodities Group EX T-11 NA NA NA
2 Cowlitz County Pub Utilty Dist No. 1 EX 554 NA NA NA
3 Deseret Power Electric Cooperative NA NA NA
4 Deret Power Electric Cooperative EX 280 NA NA NA
5 Emerald Peoples Utilty Distrct EX 351 NA NA NA
6 Eugene Water & Electc Board EX T-11 NA NA NA
7 Eugene Water & Electc Board EX T-12 NA NA NA
8 Flathead Electnc Cooperative EX T-11 NA NA NA
9 Grant County Pub Utilit Dist NO.2 EX 55 NA NA NA
10 lberdrola Renewables, Inc.EX T-11 NA NA NA
11 Idaho Power Company EX 38 NA NA NA
12 Portand General Electric Co.EX 554 NA NA NA
13 Powerex EX T-11 NA NA NA
14 Public Servce Company of Colorado EX 319 NA NA NA
Total
............................................
Name of Respondent This R~ortis:Date of Report Year/Period of Report
PacifiCorp (1) ~An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/200
cc~ti~8gl) iC;ontlnuea)nc udin~i power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of servce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j, energy charges in column (k), and the total of any other tys of charges, including
out.of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations fOllowing all required data.
MegaWatt Hours POWER EXCHANGES COST/SETIEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered ~l \~~\fl
of settlement ($)
(g)(h)(i)(m)
6,301 2,129 150,345 1
185,517 220,349 2
168 -540 354,82::3
59,059 56,239 -55,691 4
512 -12,791 5
167 260 -7,92€6
20,354 20,215 6,95C 7
9,09 176 530,95 8
12,267 44,241 9
16,247 8,93 36,190 10
288,34 279,69 11
155,718 154,551 12
1,241 803 -30,008 13
5,655 14
11,90,498 6,43,68 6,569,511 135,972,~1,556,82,34 -938,608,829 754,189,84~
FERC FORM NO.1 (ED. 12-90)Page 327.22
FERC FORM NO.1 (ED. 12-90)Page 326.23
.............................................
Name of Respondent ThiSl ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/2009
PU~CJiJlED POWER hAccu~t 5 5)n u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactons involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements servce. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the suppliets servce to it own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term servce.Use this category for all firm service, where the duraon of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generang unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term servce from a designated generating unit.The same as LU service expct that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those servces which cannot be place in the above-efined categories, such as all
non-firm service regardless of the Length of the contrct and servce from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif-Schule or Monthly Billng Average AveragecationTariff Number Demand(MW Montly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Public Servce Company of Colorado EX 320 NA NA NA
2 Public Service Company of Colorado EX T-12 NA NA NA
3 Redding, City of EX 36 NA NA NA
4 SUEZ Energy Marketing NA, Inc.EX T-12 NA NA NA
5 Seattle Cit Light EX 554 NA NA NA
6 Sempra Energy Solutions EX T-11 NA NA NA
7 Tri-State Generation & Transmission NA NA NA
8 Tri-State Generation & Transmission EX 319 NA NA NA
9 UT Associated Municipal Powr Systems ,.-=NA NA NA
10 UT Associated Municipal Powr Systems EX T-11 NA NA NA
11 Utah Municipal Power Agency EX T-11 NA NA NA
12 Warm Springs Power Enterprises EX T-11 NA NA NA
13 Westem Area Power Administration .'.%;.;.;;'C\/. '" .NA NA NA
14 Westem Area Powr Administration EX 262 NA NA NA
Total
............................................
This~rtls:
(1) IlAn Original
(2) A Resubmission
ccountnc udin po er exchan e )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
Name of Respondent
PacifiCorp
YeaúPeriod of Report
End of 2008/04
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng demand in column (d), the average monthly non-coincident peak (NcP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER E~ HANGES
MegaWatt Hours MegaWatt HoursReceived Delivere(h) (i)
219,575 218,853
85,08 83,841
114,387 119,919
COST/SETILEMENT OF POWE
Energy Charges Other Charges($) ($)(k) (i)MegaWatt Hours
Purchased
(g)
Total O+k+l)
of settlement ($)
(m)
Demand Charges
~l
355,599
6,590
372,059
2,672
5,64
-4
127,200
53,790
2,704
2,742
3,288
2
58,621
4,423
5,384
-3,407
11,909,49 135,972,332 1,556,82,-938,608,82 754,189,846,43,684 6,569,511
FERC FORM NO.1 (ED. 12-9)Pag 327.23
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-9)Page 32.24
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/2009
PU~C~~ED POWERJiAcU~ 5 5)n ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactons involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements servce. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resourc planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets servce to its ow ultimate consumers.
LF - for long-term firm servce. "Long-term" means fie years or longer and ''frm'' means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under advers conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transacton identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm servce.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm service, 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 availabilty and reliabilit of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU servce expct that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions invoMng a balancing of debits and crits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and servce from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authori Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Clasif-Schdule or Monthly Billng Average AveragecationTari Number Demand (MI Monhly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Westem Area Power Administration EX LA8-NA NA NA
2
3 System Deviation NA NA NA
4
5
6
7
8
9
10
11
12
13
14
Total
.............................................
Name of Respondent This R!i ortis:Date of Report Year/Period of Report
PacifiCorp (1) ~An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03/31/200
Inc CCO~\g8~Sl (liontlnUeo)
udina páw9r exc an e )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for servce provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any tye of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng 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 tyes of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawaUhours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other tyes of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Chargs En"" "" ~ "" C"__Totl O+k+l)No.Received Delivered
~l ~t~ \'l of Settlement ($)
(g)(h)(i)(m)
48,133 17,974 71,162 1
2
-13,12~3
4
5
6
7
8
9
10
11
12
13
14
11,909,49E 6,436,68 6,569,511 135,972,33~1,556,826,34 -938,60,829 754, 189,84~
FERC FORM NO.1 (ED. 12-9)Page 327.24
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/209 208/04
FOOTNOTE DATA
Line No.: 2 Column: b
Column: i
Coumn:b
Line No.: 5 Column: i
Coumn:b
Column: i
Line No.: 10 Column: i
Line No.: 11 Column: i
Line No.: 13 Column: i
Line No.: 14 Column:b
Line No.: 14 Column: i
Line No.: 1 Column: i
Line No.: 2 Column: i
notication.
Line No.: 8 Column:b
, South Dakota.
Column:b
Line No.: 2 Column: i
Column:b
Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/200 200/04
FOOTNOTE DATA
Column:b
Column: i
Line No.: 6 Column: i
Line No.: 9 Column:b
Line No.: 9 Column: i
Line No.: 11 Column:b
Line No.: 11 Column: i
Column:b
Column:b
Line No.: 14 Column: i
I
I
n.
Line No.: 5 Column:b
Line No.: 5 Column: i
Line No.: 6 Column: i
Line No.: 9 Column:b
Line No.: 9 Column: i
Column:b
Column:b
Line No.: 13 Column: i
Column:b
Column: i
Page 45.2
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 031/20 20004
FOOTNOTE DATA
Column:b
n.
Line No.: 3 Column: i
Line No.: 4 Column: i
Line No.: 6 Column:b
Line No.: 6 Column: i
Column: i
Line No.: 1 Column: b
Line No.: 1 Column: i
Line No.: 2 Column: b
Line No.: 7 Column:b
Line No.: 7 Column: i
Line No.: 9 Column:b
Line No.: 9 Column: i
Line No.: 13 Column: i
Line No.: 2 Column:b
Column: i
Page 45.3
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 2008/04
FOOTNOTE DATA
notication.
Line No.: 12 Column: b
Line No.: 12 Column: i
Line No.: 13 Column: i
Column:b
Column: i
Column:b
Column:b
Column: i I
ILine No.: 1 Column: i
notification.
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 03/31/200 200/04
FOOTNOTE DATA
es and commtt settements.
Column: i
Line No.: 11 Column:b
TO'ect in Idaho Falls, Idaho.
TO' ect in Idaho Fals, Idao.
Line No.: 14 Column: i
Column:b
Column:b
Line No.: 4 Column: i
Line No.: 5 Column: i
Line No.: 6 Column: i
Column: i
Column: i
Line No.: 12 Column: i
Column:b
Column:b
Column: i
Line No.: 1 Column: i
Line No.: 7 Column: b
Line No.: 7 Column: i
Line No.: 9 Column: i
Column:b
Page 450.5
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 2oo8/Q4
FOOTNOTE DATA
Line No.: 10 Column: i
notification.
Line No.: 2 Column: i
Line No.: 4 Column: i
Line No.: 13 Column: i
Line No.: 2 COlumn: i
Column:b
Column:b
notification.
Line No.: 2 Column: i
Line No.: 3 Column: i
Line No.: 4 Column:b
Column: i I
ILine No.: 7 Column: i
Line No.: 8 Column: b
Line No.: 8 COlumn: i
Page 45.6
notication.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 0331/20 200/04
FOOTNOTE DATA
Column:b
Column: i
Line No.: 13 Column: i
Line No.: 1 Column: b
Line No.: 1 Column: i
Column:b
Column: i
Column:b
- Contrct Termation Date: 60 da s wrttn notice.
Column: i
Line No.: 6 Column: i
Line No.: 7 Column: b
Line No.: 7 Column: i
Column:b
Column:b
Column: i
Line No.: 6 Column: i
Line No.: 7 Column: b
Distrct - Contrct Termation Date: Decembr 31, 2014.
Column:b
Column: i
Line No.: 11 Column: b
Line No.: 11 Column: i
Column: i
Page 45.7
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0331/2009 200104
FOOTNOTE DATA
Line No.: 2 Column: i
Line No.: 4 Column:b
Line No.: 4 Column: i
Line No.: 5 Column: i
Line No.: 7 Column:b
Line No.: 7 Column: i
Column:b
Column: i
Line No.: 10 Column: i
Column:b
Column: i
Column:b
notication.
Line No.: 6 Column: i
notication.
Line No.: 11 Column: i
Line No.: 13 Column: i
Column:b
Column:b
Column: i
Column: i
Page 450.8
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp ì2) A Resubmission 031/2009 2oo8/Q4
FOOTNOTE DATA
Line No.: 7 Column: b
Column: i
Line No.: 11 Column: b
Line No.: 11 Column: i
Column:b
Column: i
Column:b
Column:b
Line No.: 6 Column: i
Line No.: 9 Column: b
Line No.: 9 Column: i
Line No.: 12 Column: b
Line No.: 12 Coumn: i
Column:b
Column: i
Column:b
Page 450.9
.............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0331/2009 2oo8/Q4
FOOTNOTE DATA
contracts under EIT Issue No. 02-03.
Line No.: 1 Column: i
Line No.: 3 Column: b
Line No.: 3 Column: i
Line No.: 4 Column: i
Column: i
Column: i
Column: i
Line No.: 3 Column:b
Line No.: 3 Column: i
Line No.: 4 Column: i
Column: i
Column: i
Line No.: 7 Column: i
Line No.: 8 Column: i
Line No.: 10 Column: i
Line No.: 13 Column: i
Column: i
Column: i
Line No.: 3 Column: i
Column: i
Page 450.10
IFERC FORM NO.1 (ED. 12-87)Page 450.11
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0331/200 200/04
FOOTNOTE DATA
Line No.: 5 Column: i
Line No.: 6 Column: i
Line No.: 7 Column:b
Line No.: 7 Column: i
Line No.: 8 Column: i
Line No.: 9 Column:b
Line No.: 9 Column: i
Line No.: 10 Column: i
Line No.: 11 Column: i
Line No.: 12 Column: i
Line No.: 13 Column:b
Line No.: 13 Column: i
Line No.: 1 Column: i
............................................
Blank Page
(Next Page is 328)
Name of Respondent
PacifiCorp
YearlPeriod of Report
End of 2008/04
Inclucin trasacions referred to as 'weein
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilties, cooperatives, other public authorities,
qualifying facilities, non-traditional utiity suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct ty of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authori that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affilation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Servce for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission servce, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission servce, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups. for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
............................................
Une
No.
Payment By
(Company of Public Authori)
(Footnote Affilation)
(a)
1 Bain Elecric Power Cooperative
2 Bain Electric Power Cooperative
3 Basin Electric Power Cooperative
4 Basin Electric Power Cooperative
5 Basin Electric Power Cooperative
6 Bear Energy, LP
7 Black Hils Power & Light Company
8 Black Hils Power & Light Company
9 Black Hils Power & Light Company
10 Black Hils Power & Light Company
11 Black Hils Power & Light Compay
12 Black Hils Power & Light Company
13 Bonnevile Power Administraion
14 Bonneville Power Administration
15 Bonnevile Power Administraion
16 Bonnevile Power Administration
17 Bonnevile Power Administration
18 Bonnevile Power Administration
19 Bonnevile Power Administration
20 Bonneville Power Administration
21 Bonnevile Power Administration
22 Bonnevile Power Administration
23 Bonneville Power Administration
24 Bonneville Power Administration
25 Bonneville Power Administration
26 Bonneville Power Administration
27 Bonneville Power Administraion
28 Bonneville Power Administration
29 Bonneville Power Administration
30 Bonnevile Power Administration
31 Cargill-Alliant, LLC
32 Cargil-Alliant, LLC
33 Cargil-Alliant, LLC
34 CitiGroup Energy inc.
TOTAL
Energy Received From
(Company of Public Authori)
(Footnote Affiliation)
(b)
Wesem Are Powr Adinistraion
Westem Ar Powr Adinistration
Westem Are Power Adinistration
Westem Are Power Administraion
Energ Delivered To
(Company of Public Authority)
(Footnote Affilation)
(c)
Powder River Energy Corp.
Powder River Energy Corp.
Powder River Energy Corp.
Powder River Energy Corp.
Statistical
Classifi-
cation
(d)
FERC FORM NO.1 (ED. 12-9)
PacifiCorp Merchant
PacifCorp Merhant
PacifCorp Merchant
PacifiCorp Mert
Bonneville Powr Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
U. S. Bureu of Reclamation
U. S. Bureau of Reclamation
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Powe Administration
Bonneville Power Administration
Bonneville Powr Administration
Montana-Dakota Utilities
Monta-Dakota Utilties
Black Hils Power & Ught Company
Black Hills Power & Ught Company
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Umpqua Indian Utilit Cooperative
Umpqua Indian Utilit Cooerative
Bonneville Power Administration
Bonneville Power Administration
Boneville Power Administration
Boneville Power Administration
Yakma Power
Yakma Power
Boneville Power Administration
Boneville Power Administration
Page 328
............................................
Name of Respondent ThIS~lOrtls:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 0331/209
i tLt.; I NI~II T FYR I. i NtH.;: j~ ccu~t 45ö)((;ontlnUeO)
(Including transactions reftere to as 'wteelingi,.
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERC Rate Point of Recipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand Megwatt HOUrs MegWatt Hours No.Tari Number Designation)Designation)(MW)REK~Ved DeI~red
(e)(f)(g)(h)
7V11-3&4 Yellowtail Sub Sheridan Sub 1C 85,567 85,56 1
7V11-3&4 Yellowtail Sub Sheridan Sub 7,762 7,7~2
7V11- 3 &4 Yellowtail Sub Sheridan Sub e 54,941 54,941 3
7V11- 3 &4 Yellowtail Sub Sherida Sub 5,m 5,7T 4
7V11- 8 Various Various 35,028 35,021 5
7V11- 8 Variou Various 6
7V11- 8 Various Various 50,993 50,99:7
7V11- 8 Various Various 1,637 1,63 8
7V11 Various Sherian Sub 4C 147,015 147,01!9
7V11 Various Sheridan Sub 6,982 6,98:10
SA 67 Various WyodakSub 5C 244,804 244,80 11
SA 67 Various WyoSub 23,559 23,551 12
SA 237 Various Various 31C 1,474,347 1,474,34 13
SA 237 Various Various 152,55~152,551 14
SA 324 Lost Creek Hydro Various 273,42~273,421 15
SA 324 Lost Creek Hydro Various 20,412 2O,41¡16
7V11- 3 Bonneville Power Adm Galey Substation ~21,774 21,77'17
7V11- 3 Bonneville Power Adm Gazey Substation 2,204 2,20'18
7V11-7 USBR Green Springs Bonneville Power Adm 61,128 61,121 19
7V11-7 USBR Green Springs Bonnevile Power Adm 3,503 3,50:3 20
SA 36 Malin Sub Malin Sub 10"66,863 66,~21
SA 368 Malin Sub Malin Sub 22
7V11-3&4 Bonnevile Power Adm White Swanoppenish 1 35,173 35,17:3 23
7V11- 3 &4 Bonneville Power Adm White SwanI oppenish 3,00:3 3,00:3 24
SA 299 Various Various 211 1,533,152 1,533,15:2 25
S.A.299 Various Various 219,70e 219,70e 26
7V11-8& 11 Various Various 27
7V11- 8 Various Various 720 72C 28
7V11-3&4 Cardell-Merwn ChelatchieNiew 24 112,58C 112,58C 29
7V11- 3 &4 Cardell-Merwn ChelatchieNiew 12,011 12,011 30
7V11-8& 11 Various Various 742,08:2 742,08.31
7V11- 8 Varous Various 12,45E 12,45E 32
7V11-7 Various Variou 132,776 132,77E 33
7V11- 8 Various Various 1,105 1,10f 34
2,38 17,170,08 17,170,08
FERC FORM NO.1 (ED. 12-9)Page 329
Blank Page
............................................
(Next Page is 330)
Date of Report
(Mo, Da, Yr)
03131/200ccunt ntinuIncludin transaction reffered to as 'wIeelin '
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 20004
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERSEnergy Charges (Other Charges)($) ($)(I) (m)Demand Charges
($)
(k)
185,931
187,515
18,
228,819
105
313,279
1,113,750
4,033,635
46,71
4,147,151
651,379
11,119
Total Revenues ($) ne
(k+l+m) No.
(n)
243,717 1
17,141 2
187,515 3
24,757 4
228,819 5
105 6
313,279 7
9,84 8
668,737 9
62,724 10
1,113,750 11
101,250 12
4,101,582 13
370,307 14
286,253 15
26,023 16
178,917 17
39,951 18
400,950 19
36,450 20
246,94 21
22,450 22
186,789 23
38,682 24
2,051,40 25
189,164 26
12,473 27
4,205 28
399,534 29
38,070 30
4,175,709 31
96,481 32
651,379 33
11,119 34
26,628,319 19,473,259 29,451,66 75,553,244
FERC FORM NO.1 (ED. 12-9)Pae 330
Line
No.
Energ Received From
(Copany of Public Auhoriy)
(Footnote Affilation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affilation)
(c)
Statistical
Classifi-
cation
(d)
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008/04
(Includin transctions referr to as 'wheelin
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilties, cooperatives. other public authoriies,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct tye of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affilation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO. Firm Network Servce for Others, FNS - Firm Netwrk Transmission Service for self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission servce, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission servce, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Stateline Wind
Stateline Wind
Uinta
Uinta
Exn Moble
Stateline Wind
Stateline Wind
Uinta
Uinta
Nevadaos Angeles
Nevadalos Angeles
Idaho Power Compay
TOTAL
FERC FORM NO.1 (ED. 12-9)Page 328.1
............................................
Name of Respondent This (grtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 200804
(2) i: A Resubmission 03131/200
~i- y count 45ö)((,ontlnUea)(Including transactions reffered to as 'weeling')
5. In column (e), identity the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billng demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand Megavvau HOUrs Megawatt HOUrs No.Tari Number Designation)Designation)(MW)Received Delivered(e)(f)(g)(h)(i)0)
7V11- 8 Various Various 1 1 1
7V11- 8 Variou Various 58 5~2
7V11- 8 Various Various 329,958 329,95~3
7V11-7 & 11 Various Various 93,104 93,1Oi 4
7V11- 8 Various Various 3,542 3,54~5
SA 234 Swift Unit NO.2 Wooland Sub 6
SA 234 Swi Unit NO.2 Wooland Sub 7
7V11- 8 Various Various 8
7V11-7 Various Various 9
SA 280 Various Various 105 1,579,211 1,579,211 10
SA 280 Various Varius 105 149,101 149,101 11
7V11-5,7,9 Tieton Sub Various 15 5,236 5,231 12
7V11-7 Tieton Sub Various 13
7V11- 8 Various Various 358 351 14
7V11- 8 Various Various 627 62 15
SA 322 TargheeSub Goshen Sub ~16
SA 322 TargheeSub Goshen Sub 17
7V11- 3 Yellowtail Sub Various 1 4,585 4,58!18
7V11- 3 Yellowtail Sub Various 499 49~19
7V11- 8 Various Various 87 8 20
7V11- 8 Various Various 192,108 192,10~21
7V11- 8 Various Various 62,148 62,14~22
7V11- 5,9,11 Various Various 23
7V11- 5 & 9 Various Various 24
7V11- 5,9,11 Various Various 25
7V11-5&9 Various Various 26
7V11-7 Exxon Metering Sta.Harry Allen/Mona Sub 75 137,485 137,485 27
7V11-7 Exxon Metering Sta.Harry Allen/Mona Sub 80,687 80,681 28
7V11-7 Various Various 110,111 110,111 29
7V11-7 Various Various 18,Osi 18,os 30
7V11- 8 Various Various 78,082 78,08~31
7V11- 8 Various Various 1,889 1,88~32
SA 257 Antelope Sub Antelope Sub 33
SA 257 Antelop Sub Antelop Sub 34
2,31K 17,170,08 17,170,08
FERC FORM NO.1 (ED. 12-9)Page 32.1
Blank Page
............................................
(Next Page is 330.1)
(Includin
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and tye of energy or servce
rendered.
10. The total amounts in columns (i) and m must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
............................................
Name of Respondent
PacifiCorp
his ~ortls:
(1) IKAn Original
(2) A Resubmission
Year/Period of Report
End of 2008/04
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energ Charges (Other Charges)($) ($)(I) (m)Demand Charges
($)
(k)
93,951
1,877,1
12,18
987
1,598,297
189,801
26,62,319 19,473,259 29,451,66 75,553,244
FERC FORM NO.1 (ED. 12-9)Page 33.1
Total Revenues ($) ne
(k+l+m) No.
(n)
6 1
818 2
2,028,883 3
953,928 4
32,061 5
93,951 6
8,251 7
631 8
5,022 9
3,288,38 10
163,120 11
126,368 12
30,375 13
21,713 14
3,662 15
138,699 16
12,60 17
39,64 18
3,921 19
987 20
1,598,297 21
421,03 22
83,885 23
43,696 24
198,761 25
101,907 26
1,215,00 27
607,500 28
748,012 29
911,25 30
204,337 31
9,80 32
67,672 33
6,152 34
Includn transactions referred to as 'weelin ~
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilties, cooperatives, other public authorities,
qualifying facilties, non-traditional utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct tye of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the servce as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Servce for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reportng periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of coes.
Name of Respondent
PacifiCorp ............................................
Date of Report
(Mo, Da, Yr)
0331/2009
unt
YearlPeriod of Report
End of 2008/04
Une
No.
Payment By
(Company of Public Authori)
(Footnote Affilation)
(a)
1 Idaho Power Company
2 Idaho Power Company
3 Integrys Energ Services
4 Integrys Energy Services
5 Intermountain Renewable Power LLC
6 Moon Lake Elecric Association
7 Moon Lake Elecric Assoiation
8 Municipal Energy Agency of Nebraka
9 Morgan Stanley Capital Group, Inc.
10 Morgan Stanley Capital Group, Inc.
11 Nevada Power Company
12 Pacific Gas & Electric
13 Pacific Gas & Electric
14 Portland General Electric
15 Portland General Electric
16 Powerex
17 Powerex
18 Powerex
19 Powerex
20 Powerex
21 Powerex
22 Powerex
23 Powerex
24 Powder River Energy Corpration
25 Powder River Energy Corpration
26 PPL Energ Plus
27 PPL Energ Plus
28 Public Service Company of Colorado
29 Public Service Company of Colorao
30 Public Servce Compay of Colora
31 Rainbow Energ Marketing
32 Rainbow Energ Marketing
33 Rainbow Energy Marketing
34 Seattle Cit & Light
TOTAL
Energ Recived Fro
(Company of Public Auhori)
(Footnote Affliation)
(b)
Energ Delivere To
(Company of Public Authority)
(Footnote Affilation)
(c)
Statistical
Classifi-
cation
(d)
Page 328.2FERC FORM NO.1 (ED. 12-9)
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/20
..qr ~L~v I Nlyll T i-YN ~! .~, ....1i'" ccount 4bö)i(.ontlnU90)(Including transacions retfere to as 'wteelin!iÖ)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedle of (Subsatation or Other (Substation or Other Demand Megwatt HOUrs Megwat HOUrs No.Tari Number Designation)Designation)(MW)Recived DeliOred
(e)(f)(g)(h)(i)
SA 20 Jim Bridger Sub Bridger Pump Station 1
SA 203 Jim Briger Sub Bridger Pump Station 2
7V11- 8 Various Various 10,112 10,11;3
7V11- 7 Various Various 1,182 1,18.4
SA 509 Sigurd-34KV bus Mona 11 5
SA 302 Duchesne Duchesne 3 13,827 13,821 6
SA 302 Duchesne Duchesne 3 1,213 1,21::7
7V11- 8 Various Various 321 321 8
7V11- 8 Various Various 243,617 243,611 9
7V11- 8 Various Various 6,44 6,44 10
7V11- 8 Various Various 3,568 3,56S 11
SA 86 Various Various 12
SA 298 Sigurd-Glen Canyon Pinto-Four Corners 13
7V11- 8 Various Various 1,642 1,64~14
7V11- 8 Various Various 15 1E 15
7V11-5,7,9 Tieton Sub Various 15 16
7V11- 5,7,9 Tieton Sub Various 15 38,339 38,33E 17
7V11-7 Bonneville Power Adm Wee Jct. Sub 80 303,793 303,79~18
7V11-7 Bonneville Power Adm Weed Jct. Sub 17,971 17,971 19
7V11- 8 Variou Various 612,137 612,131 20
7V11- 8 Various Various 8,534 8,53 21
7V11-7 Various Various 201,263 201,26~22
7V11-7 Various Various 2,207 2,201 23
SA 59 Various Bufalo Sub 24
SA 59 Various Bufalo Sub 25
7V11- 8 Various Various 17,79€17,79E 26
7V11- 8 Various Various 969 96~27
7V11-7 Various Various 1,20 1,20(28
7V11- 8 Various Various 9,015 9,OH 29
7V11- 8 Various Varius 50 5C 30
7V11-7 Various Varius 69,161 69,161 31
7V11- 8 Various Various 57,597 57,59 32
7V11- 8 Various Various 1,55 1,55C 33
7V11-7 Wallula Sub Mid-C 34
2,38I 17,170,08 17,170,_
FERC FORM NO.1 (ED. 12-9)Pag 329.2
Blank Page
............................................
(Next Page is 330.2)
(Includin
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008/04
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energy Charges (Other Charges)($) ($)(I) (m)Demand Charges
($)
(k)
17,281
1,60
60,75
1,447,875
26,628,319 19,473,29 29,451,66 75,553,244
FERC FORM NO.1 (ED. 12-90)Page 330.2
Total Revenues ($)ine
(k+l+m)No.
(n)
14,927 1
1,357 2
62,130 3
6,568 4
22,275 5
17,281 6
1,60 7
1,939 8
1,678,539 9
50,00 10
44,249 11
20,00,00 12
34,121 13
11,680 14
88 15
60,750 16
33,179 17
1,447,875 18
131,625 19
3,180,32 20
43,012 21
822,549 22
12,363 23
168 24
16 25
104,991 26
5,659 27
4,650 28
39,425 29
292 30
437,651 31
321,169 32
6,792 33
212,625 34
Date of Report
(Mo, Da, Yr)0331/20ccntIncludin trasacions referred to as 'wheelin '
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilties, cooperatives, other public authorities,
qualifying facilties, non-traditional utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct tye of transmission servce involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affilation the respondent has wih the entities listed in columns (a). (b) or (c)
4. In column (d) enter a Statistical Classification coe based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission servce, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of coes.
Name of Respondent
PacifiCorp ............................................
Year/Period of Report
End of 2008/04
Line
No.
Payment By
(Compay of Public Authority)
(Footnote Affilation)
(a)
Seawest Windpower, Inc.
2 Seawest Windpower, Inc.
3 Sempra Energy Trading Corp
4 Sempra Energy Trading Corp
5 Sempra Energ Solutions
6 Sempra Energy Solutions
7 Shell Energy North America
8 Sierra Pacific Power Company
9 Sierra Pacific Power Company
10 Sierra Pacific Power Company
11 Sierra Pacific Power Company
12 Southem Califomia Edison Company
13 State of South Dakota
14 State of South Dakota
15 TransAlta Energy
16 TransAlta Energy
17 Tri.State Generation & Trasmission
18 Tri.State Generaion & Transmission
19 Tri-State Generation & Transmission
20 Tri-State Generation & Transmission
21 Tri.State Generation & Transmission
22 United States Bureau of Reclamation
23 United States Bureau of Reclamation
24 United States Bureau of Reclamation
25 United States Bureu of Reclamation
26 United States Bureu of Reclamation
27 Utah Associated Municipa Power
28 Utah Associated Municipal Power
29 Utah Municipal Power Agenc
30 Utah Municipa Power Agency
31 Warm Springs Power Enterprises
32 Warm Springs Power Enterpes
33 Westem Area Power Administration
34 Westem Area Power Administration
TOTAL
Energ Recived Fro
(Company of Public Authori)
(Footnoe Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affilation)
(c)
Statistical
Classifi-
cation
(d)
Bonneville Power Administraion
Bonnevile Power Administration
Bonneville Power Administraion
Bonneville Power Administraion
Westem Area Powr Administraio
Utah Assocated Municipa Power
Utah Associaed Municipal Power
Utah Municipal Power Agecy
Uth Municipa Powr Age
Warm Spring Enterprises
Warm Springs Enterprise
Westem Area Power Administration
Wesem Area Power Administraion
U.S. Bureau of Reclamation
Croked River Irrigation District
U.S. Bureau of Reclamation
U.S. Bureau of Reclamatio
Weber Basin
Utah Associated Municipal Power
Utah Assoiated Municipal Power
Utah Municipl Power Agency
Utah Municipa Powr Agency
Portlan General Elecric Co.
Portland General Elecric Co.
Various WAPA Customers in PACE
Various WAPA Customers in PACE
Page 328.3FERC FORM NO.1 (ED. 12-90)
............................................
Name of Respondent This Re lOrt Is:Date of Report Year/Period of Report
PacifiCorp (1) ~ An Original (Mo, Da, Yr)End of 20004
(2) A Resubmission 03131/200
i t:Lt: v I_H!t.llyi-YH U.! Ht:H~,l' ccount 4:ltlJlliontlnued)
Clncludino transactions reffered to as 'wteelino')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billng demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY UneSchedule of (Subsatation or Other (Substation or Other Demand Megawatt HOUrs Megawatt HOUrs No.Tari Number Designation)Designation)(MW)Recived Delivered
(e)(f)(g)(h)(i)0)
SA 264 Foote Creek Sub Various 1
SA 264 Foote Crek Sub Various 2
7V11- 8 Various Various 2,00 2,00 3
7V11- 8 Various Various 9,902 9,90~4
7V11- 3 & 4 Bonneville Power Adm Various 11 100,205 100,2()5
7V11- 3 & 4 Bonneville Power Adm Various 8,84 8,84f 6
7V11- 8 Various Various 1,082 1,08~7
7V11- 8 Various Various 189,297 189,291 8
7V11- 8 Various Various 49,20 49,2OC 9
7V11-7 Various Various 89,354 89,35 10
7V11-7 Various Varius 68,99S 68,99S 11
SA 86 Malin Sub Indian Springs 12
7V11-7 Yellowtail Sub WyoakSub 4 16,965 16,96E 13
7V11-7 Yellowtail Sub WyodakSub 1,384 1,38 14
7V11- 8 Various Various 53,508 53,50S 15
7V11.8 Various Various 16
SA 123 Various Various 31 157,189 157,18S 17
SA 123 Various Various 16,43 16,4~18
7V11-7 Various Various 8,942 8,94~19
7V11- 8 Various Various 6,058 6,05S 20
7V11- 8 Various Various 60 6C 21
SA 35 Walla Walla Sub Burbnk Pumps 22
R.S.67 Redmond Substation Croed River Pumps 10,2n 10,27i 23
SA 67 Pasco Sub Dod Road Sub 24
SA 286 Pasco Sub Dodd Road Sub 30,173 3O,m 25
SA 286 Various Various 1,465 1,46 26
SA 297 Variou Various 33S 3,03,988 3,035,98E 27
SA 297 Various Various 290,889 290,88~28
SA 279 Various Various 109 574,223 574,22::29
SA 279 Various Various 52,186 52,18€30
SA 591 Pelton Reregulating Round Bute Sub 16 75,932 75,93~31
SA 591 Pelton Reregulating Round Bute Sub 7,511 7,511 32
SA 262 & 263 Various Various 328 1,534,091 1,534,091 33
SA 262 & 263 Various Various 328 150,370 150,37C 34
2,_17,170,08 17,170,oø
FERC FORM NO.1 (ED. 12-9)Page 32.3
Blank Page
............................................
(Next Page is 330.3)
Date of Report
(Mo, Da, Yr)
03131/2009
ccount
(Includin transactions reffered to as 'wfeelin '
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008/04
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energy Charges (Other Charges)($) ($)(I) (m)Demand Chargs
($)
(k)
137,28
11,541
393,161
207,512
29
2,582,1
26,628,319 19,473,259 29,451,66 75,5,244
FERC FORM NO.1 (ED. 12-9)Page 33.3
Total Revenues ($) ne
(k+i+m) No.
(n)
33,168 1
-37,833 2
11,658 3
48,545 4
158,239 5
13,074 6
8,194 7
90,708 8
110,564 9
393,161 10
253,125 11
34,121 12
89,100 13
8,100 14
207,512 15
29 16
97,576 17
3,559 18
54,84 19
40,991 20
350 21
3,505 22
13,676 23
60 24
30,173 25
1,46 26
7,38,181 27
607,687 28
2,077 ,417 29
180,341 30
109,725 31
9,975 32
2,582,163 33
228,784 34
FERC FORM NO.1 (ED. 12-9)Page 328.4
............................................
Name of Respondent ThiS~iortls:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 031/200
...UI I:LtG I MI~II T r: ccunt 4b.l J
(Including transactions referred to as 'wheeling'f
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilties, cooperatives, other public authorities,
qualifying facilties, non-traditional utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct tye of transmission servce involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the servce as follows:
FNO - Firm Network Service for Others, FNS. Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission servce, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of coes.
Line Payment By Energ Received Fro Energy Delivere To Statistica
No.(Company of Public Authority)(Company of Public Auhori)(Company of Public Authority)Classifi-
(Footnote Affilation)(Footnote Affiliatio)(Footnote Affilation)cation
(a)(b)(c)(d)
1 Western Area Power Administration Westem Are Power Administraion Varius WAPA Customers in PACE
2 Western Area Power Administration Westem Area Power Administration Various WAPA Customers in PACE
3 Westem Area Power Administration Westem Area Power Administration Various WAPA Customers in PACE
4 Westem Area Power Administration Westem Area Power Administration Westem Area Power Administration
5 Westem Area Power Administration Westem Are Power Administration Westem Area Power Administration
6 Accrual True-up
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
TOTAL
............................................
Name of Respondent ThiS~IOrtls:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 20004
(2)A Resubmission 03131/200
i .\~ ccount 456)(lìntlnUetl)(Includino transactions reffered to as 'wIeeliñä:r
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and G) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand Megawatt HOUrs MegaWatt Hours No.Tari Number Designation)Designation)(MW)RiT¡ive Dei~rred(e)(f)(g)(h)
7V11- 8 Various Various 870 87C 1
7V11-7 Various Various 2
7V11- 8 Various Various 1,04S 1,04E 3
7V11 Wyoming Distribution Wyoming Distribution 1 10,085 10,08S 4
7V11 Wyoming Distribution Various 1 1 5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
2,3l 17,170,08 17,170,08
FERC FORM NO.1 (ED. 12-9)Page 329.4
Blank Page
............................................
(Next Page is 330.4)
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 20004
(2) 0 A Resubmission 03131/209
i i-yn '- i Mt:n¡: ..v~ccount ntinuea¡
(Including transactions refere to as 'wIeelinih
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and m must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRNSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energ Charges (Other Charges)Total Revenues ($)Une
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
227,537 227,537 1
6,975 6,975 2
7,265 3
21,7~54,781 4
11,208 5
44,84 6
7
8
9
10
11
12
13
14
15
16
.17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
26,628,319 19,473,259 29,451,66 75,55,244
FERC FORM NO.1 (ED. 12-9)Page 330.4
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0331/20 200/Q4
FOOTNOTE DATA
imalance cha es er Schedules 4 and 9.
n Access Trasmission Tar between varous
n Acces Trasmission Tar between varous
n Access Trasmission Tarff between varous aties and points.
n Access Trasmssion Tar between varous pares and
Column:d
n Access Trasmission Tar (SA 347) termti on Deembr 31,2017.
Column:d
n Access Trasmission Tar SA 347 on Decmbr 31,2017.
Column:m
Page 45.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 200804
FOOTNOTE DATA
on Deember 31, 2023.
on December 31, 2023.
een.
ovemmnt facilties.
Column:m
Column:m
Column:m
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 03131/209 200/04
FOOTNOTE DATA
n Accss Trasmission Tar between varous
n Accss Trasmission Tar between varous
imalce char es er Schedules 4 and 9.
n Acces Transmission Tarff between varous
Page 450.3
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp '2) A Resubmission 03131/20 200/04
FOOTNOTE DATA
n Access Trasmission Tarff between varous
n Access Trasmission Tar between varous
n Access Trasmission Tarff between varous
n Access Transmission Tarff between varous ames and points.
n Access Trasmission Tar between varous
n Access Trasmission Tar between varous
n Access Transmission Tar between varous
IFERC FORM NO.1 (ED. 12..7) Page 450.4
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/20 20/04
FOOTNOTE DATA
n Access Trasmission Tar between varous
n Access Trasmission Tarff between varous
n Access Trasmission Tar between varous
ment.
n Access Transmission Tar between varous
Page 45.5
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) . A Resubmission 03131/2009 200/04
FOOTNOTE DATA
n Access Transmission Tar between varous
n Access Transmission Tarff between varous
n Access Transmission Tar between varous
n Access Transmission Tarff between varous
Page 450.6
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 200/04
FOOTNOTE DATA
Ma 31,200.
n Access Transmission Tar between varous ares and points.
n Accss Trasmission Tarff between varous
n Acces Transmission Tar between varous
cotermous with the IdaholUSDOE Su i Agreement
IFERC FORM NO.1 (ED. 12-S7) Page 450.7
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0311/2009 2O8IQ4
FOOTNOTE DATA
n 12-month wrttn notice.
n Access Trasmission Tar between varous
n Access Trasmission Tar between varous
n Access Trasmission Tarff between varous
I
I
I
Se tember 14,2029.
IFERC FORM NO.1 (ED. 12-S7) Page 450.8
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) i An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/20 200/04
FOOTNOTE DATA
n Accss Tramission Tanff between vanous
n Access Trasmission Tar between vanous
n Access Trasmission Tar between vanous
n Access Trasmission Tanffbetween vanous
IFERC FORM NO.1 (ED. 12-S7) Page 45.9
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 20/04
FOOTNOTE DATA .
n Access Trasmission Tar between varous
n Access Trasmission Tar between varous
IFERC FORM NO.1 (ED.12~87)Page 450.10
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 031/2009 2004
FOOTNOTE DATA
n Access Trasmission Tar between varous
n Access Trasmission Tarff between varous
n Acces Trasmission Tar between varous
n Access Trasmission Tar between varous
n Access Trasmission Tar between varous ares and points.
n Access Trasmission Tar between varous
n Access Trasmission Tar between varous
November 30, 2009.
IFERC FORM NO.1 (ED.12~87)Page 450.11
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0331/2009 200104
FOOTNOTE DATA
n Acces Trasmission Tanbetween varous
n Access Trasmission Tan between varous
Column:m
revenues coveri imbalce cha es r Scheules 4 and 9.
n Access Trasmission Tan between varous
n Acces Trasmission Tanbetween varous
I
I
-I
1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) KAn Original (Mo, Da, Yr)
PacifiCorp I è2) A Resubmission 03131/200 208104
FOOTNOTE DATA
n Access Trasmission Tar between varous
n Access Trasmission Tar between varous
31,200.
31,2009.
n Accss Trasmission Tar between varous
u on wrttn notication.
IFERC FORM NO.1 (ED. 12-87) Page 450.13
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/2009 2008/04
FOOTNOTE DATA
u on wrttn notication.
n Access Trasmission Tar between varous
n Access Trasmission Tar between varous pares and
n Access Trasmission Tarff between varous pares and
Column:m
Column:m
Column:m
Page 45.14
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03111200 200/04
FOOTNOTE DATA
reserve. December 200 Servce.
1,2032.
1,2032.
Column:m
n Access Tramission Tar between varous
n Access Transmission Tarff between varous
n Access Trasmission Tar between varous
IFERC FORM NO.1 (ED. 12-87) Page 450.15
............................................
Blank Page
(Next Page is 332)
FERC FORM NO. 113-Q (REV. 02-()Page 332
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 0331/20
TRANS~ ISSION OF ELECTRICITY BY OTHE 'IS (Accunt 56)
(Including transactions referre to as "wheeing")
1. Report all transmission, Le. wheeling or electricity prôvided by other electric utilties, coperatives, municipalities, other public
authorities, qualifying facilties, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission servce. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the servce as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Tenn Finn Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Tenn Firm Point-to- Point Transmission Reservations, NF - Non-Finn Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission servce.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and tye of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERG'i EXENSES FOR TRNSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical MaCtt-Magawau-!:.emano .Energy ,yirier Total Cost of1l0ulSCtiChrCharrasTrans~ssionAuthority (Footnote Affilations)Clasifcation Recived Delivere ($~(a)(b)(c)(d)(e)(f)
1 Arizona Public Servce 124 124 10,226 16,594
2 Arizona Public Servce 198,712 198,712 973,470 973,470
3 Arizona Public Serce NF 17,717 17,717 55,243 ~55,243
4 Arizona Public Service as 57 57 38,60 65,428
5 Arizona Public Servce SFP 42,90 42,90 154,139 154,139
6 Asland, Cit of FNS 1,874 1,874 18,351 18,351
7 Avista Corp.FNS 56,56 58,790 261,516 261,516
8 Avista Corp.NF 27,614 27,614 91,30 91,30
9 Avista Corp.SFP 4,272 4,272 11,499 11,499
10 Big Hom Rural Elecric as 50,393
11 Bonneville Power Adm.-3,054 -3,054 34,409 -14,734 225,718
12 Bonnevile Power Adm.FNS 523,90 555,116
13 BonnevHle Power Adm.4,522,031 4,522,031 34,284,187 34,680,967
14 Bonneville Power Adm.NF 184,233 ..184,233
15 Bonneville Power Adm.as 5,899,423 6,158,55 35,496,376 55,194 38,077,176
16 Bonneville Power Adm.SFP 35,702 35,702 97,158 45,507 142,66
TOTAL 15,323,501 15,643,84 96,316,66 1,957,46 22,893,52 121,167,183
.............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 03/31/200
TRANSlI ISSION OF ELECTRICITY BY OTHE S (Account 565)
(Including transactions referrd to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity prõvided by other electric utilties, cooperatives, municipalities, other public
authorities, qualifying facilties, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission servce. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affilation with the
transmission servce provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the servce as follows:
FNS - Firm Network Transmission Service for Self, lFP - long-Term Firm Point-to-Point Transmission Reservations. OlF - Other
long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Servce, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and tye of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERG'EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistica Magawatt-Magawan-llemanci £C""' ~ Tol "" oflìoUJlìoursChl¥les T cr T,__Authority (Footnote Affilations)Classifictio Received Delivered
(a)(b)(c)(d)(e)~ h
1 CA. Ind. Sys. Operator -2,458 526,560
2 CA. Ind. Sys. Operator OS 10,953,089
3 CA. Ind. Sys. Operator SFP 471,83 471,83 1,736,38 1,736,385
4 Deret Pw Elec. Coo 4 4 30 30
5 Deset Pwr Elec. Coo NF 5 5 37 37
6 Desret Pwr Ele Coo SFP 191,801 191,801 1,90,220 1,90,220
7 EI Paso Elec. Co.NF 975 975 1,124 1,124
8 EI Pas Elec. Co.SFP 30,818 30,818 51,337 51,337
9 Flathead Elec. Coop.----1,392
10 Flathead Elec. Coop.ii 66,719
11 Flowell Elecric As.25 25 42 42
12 Rowell Elecric As.169 169 289 289
13 Hermison Gen Co., L.P.OS ~1~170,06
14 Idaho Power Compny 29,406 29,40 -39,293 -2,930,283
15 Idaho Power Company FNS 7,901 7,901
16 Idao Power Company NF 706,252 752,011 2,165,435 8,00 2,173,441
TOTAL 15,323,5m 15,643,840 96,316,66 1,957,462 22,893,052 121,167,183
FERC FORM NO. 113-Q (REV. 02-()Page 33.1
FERC FORM NO. 113Q (REV. 02-()Page 33.2
............................................
Name of Respondent This~rtIS:Date of Reiiort Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo8/Q4
(2) EiA Resubmission 0331/200
TRANSr. ISSION OF ELECTRICITY BY OTHE 'lS (Accunt 56)
(Including trasactions referred to as "wheeling")
1. Report all transmission, Le. wheeling or electricity prövided by other electric utilties, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission servce. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, lFP - long-Term Firm Point-to-Point Transmission Reservations. OlF - Other
long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructons for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and tye of energy or servce rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERG'EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Copany or Public Statistical Magawa.Magawan-llliano J;nerg ~Total Cost of
R:f~ed ñours Chr Ch&rpes ChuresAuthority (Footnote Affiliations)Classifcation Delivere Trans~SSion
(a)(b)(c)(d)(e)(f)
1 Idaho Power Company OS 8,917,60
2 Idaho Power Company SFP 391,63 391,63 952,99 952,99
3 Los Ang. Dep WaterlPwr NF 464 46 5,076 5,076
4 Los Ang. Dept WaterlPwr OS 381
5 MAPPCOR OS -1,026
6 Moon Lake Elect. Asc..551
7 Mon Lake Elect. As FNS 124,726
8 Morgan Ci 18 18 100'-100
9 Navajo Tribal Util Auth OS 1,481
10 Nevada Power Company NF 21,541 21,541 64,454 64,454
11 Nevada Power Company OS 11 767,081
12 Nevada Power Company SFP 846,83 846,83 3,922,152 3,922,152
13 NorWesern Enery iI .60,459 -60,459
14 NortWesern Energy NF 30,36 31,191 134,910 134,910
15 NortWesern Energy OS iR 826,027
16 NortWesern Energy SFP 10,39 10,394 45,145 45,145
TOTAL 15,323,50 15,643,840 96,316,66 1,957,46 22,893,052 121,167,183
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 03131/2009
TRANS~ ISS ION OF ELECTRICITY BY OTHE"iS (Account 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, Le. wheeling or electricity pròvided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affilation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, lFP - long-Term Firm Point-to-Point Transmission Reservations. OlF - Other
long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and tye of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERG'EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawan-!:.amana .Fnerg C~rs Total Cost of !l0UJ !lours Chtlf'es Charf'es Trans~ssionAuthority (Footnote Affilations)Clasification Received Delivere ($(a)(b)(c)(d)(e)(f)
1 Platte River Power .1,461 -1,461 118
2 Plate River Power as 12,115
3 Platte River Power SFP 191,08 191,08 96,00 966,00
4 PorUand Gen. Elec NF 234 234 270 270
5 Porand Gen. Eleri as 779,018 780,185 ~143,430
6 Public Servce Co of CO ~111,514 117,122 866,841 .-866,841
7 Public Service Co of NM as 21,349
8 Public Servce Co of NM SFP 115,558 115,558 603,783 603,783
9 SUEZ Energy Mid NA SFP 3,150,700 3,150,700
10 Sail River Projec NF 3,221 3,221 7,485 7,485
11 Seatte Cit Light NF 150 150 450 450
12 Sierra Paciic Power Co NF 16,083 16,08 96,189 96,189
13 Sierr Pacic Power Co as .15,358
14 Supri Valley Elecr.as 9,174
15 Tri.S1te Gen & Transm ..761 .761 1,34 1,815
16 Tri.S1te Gen & Transm 111,832 117,447 866,841 866,841
TOTAL 15,323,501 15,643,840 96,316,66 1,957,46 22,893,052 121,167,183
FERC FORM NO. 113 (REV. 02-()Page 332.3
FERC FORM NO. 1f3 (REV. 02-()Page 332.4
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, 08, Yr)End of 2008/04
(2) Fi A Resubmission 0331/200
TRANSII ISSION OF ELECTRICITY BY OTHE S (Accunt 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity próvided by other electric utilties, cooperatives, municipalities, other public
authorities, qualifying facilties, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, lFP - long-Term Firm Point-to-Point Transmission Reservations. OlF - Other
long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Servce. see General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission servce.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and tye of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERG'EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Pubic Statistical ~tt-Magawari-!l~ari~£;nergy _\-Iner Total Cost oftiourschl¥tes Chl¥tes Chi¥tes Trans~ssionAuthority (Footnote Affilations)Classifiction Recived Delivere
~g)(a)(b)(c)(d)(e)(f)
1 Tri-Stte Gen & Transm NF 18,37 18,637 50,956 50,95
2 Tri-Stte Gen & Transm OS M I 17,760
3 Tucsn Electric Power NF 25 25 163 163
4 Tucsn Elecric Power OS 15
5 Uth As Muni Pwr Sys i-8,050 1,393
6 Uth As Muni Pwr Sys SFP 258,147 258,147 1,293,60 1,306,486
7 Wesrn Are Power Adm..--374 -127
8 Wesern Area Power Adm.FNS 3,735,018 3,735,018
9 Wesern Area Power Adm.178,530 178,530 2,965,00 2,965,000
10 Wesern Are Power Adm.NF 5,06 5,06 22,38 22,38
11 Wesern Area Power Adm.OS ~.378,495
12 Western Are Powr Adm.SFP 150 150 311 7,311
13 Accal True-up -3,152
14
15
16
TOTAL 15,323,50 15,643,84 96,316,66 1,957,462 22,893,052 121,167,183
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/31/2009 2008/04
FOOTNOTE DATA
Line No.: 1 Column: b
Column:g
t 31, 2013, Jan 11,2041 and Ma 31,2047
Column:
Line No.: 11 Column: b
Column:g
Column:
Column:g
Column:b
Line No.: 1 Column:g
Line No.: 2 Column:g
Line No.: 4 Column:b
Line No.: 9 Column:b
Line No.: 9 Column:g
Line No.: 10 Column:g
Line No.: 11 Column:b
ifed costs of cert facilties
Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 0311/2009 2008/04
FOOTNOTE DATA
Line No.: 5 Column:
Line No.: 6 Column:b
Line No.: 6 Column:g
Line No.: 7 Column:g
Line No.: 8 Column:b
Line No.: 9 Column: 9
Line No.: 11 Column:g
Line No.: 13 Column:b
ifed costs of cert facilties
Line No.: 1 Column:g
Line No.: 2 Column:
Line No.: 13 Column:
Line No.: 14 Column: 9
Line No.: 15 Column: b
Line No.: 15 Column: 9
Line No.: 4 Column:
Line No.: 5 Column: b
Line No.: 5 Column: 9
Column:
Page 45.2
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCor (2) A Resubmission 03131/2009 20004
FOOTNOTE DATA
Line No.: 7 Column: b
Line No.: 7 Column:
IFERC FORM NO.1 (ED. 12-87) Page 450.3
FERC FORM NO.1 (ED. 12-9)Page 33
............................................
Name of Respondent This~rtIS:Date af ReP.rt Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 200/04
(2) Fi A Resubmission 0311/200
MISCELLANEOUS GENERAL EXPENSES (Accnt 930.2) (ELECTRIC)
Line DeSCriltion Amount
No.(a (b)
1 Industry Association Dues 645,728
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Exenses
4 Pub & Dist Info to Stkhldrs...expn servicing outstaning Securities
5 Oth Expn =5,00 show purpse, recipient, amount. Group if c: $5,00
6
7 Community and Economic Development:
8 Economic Development Corpration of Utah 124,000
9 Linn-Benton Community College 10,00
10 Newspaper Agency Group 10,00
11 Oregon Cascades West Council of Govemments 10,000
12 Oregon Economic Development Asociation 10,00
13 Port of Columbia 5,00
14 South Coast Development Council 7,500
15 Thermopolis-Hot Springs Cty. Economic Development Co 5,00
16 Utah center for Rural Life 8,00
17 Utah Sports Commission 57,072
18 Wallowa County Chamber of Commerce 5,00
19 Wyoming Business Council 5,380
20 Other 22,35
21
22 Corprate Memberships and Subscriptions:
23 Asiation of Regional Economic Partners, Inc.5,500
24 Consortium for Energy Effciency 13,120
25 Economic Development for Central Oren 7,50
26 E Source Companies LLC 13,220
27 Greenlight Greater Portlan 25,00
28 Idao Mining Association 6,00
29 Intermountain Electrical Assoiation 9,00
30 Laraie Economic Development Corpration 5,00
31 Northem Tier Transmission Group 329,757
32 Northwest Power an Consrvation 15,00
33 Oregon Business Association 11,00
34 Oregon Business Council 30,059
35 Oregon Environmentl Council 5,00
36 Oregon State University 15,00
37 Pacific Northwest Utities Conference Committee 50,302
38 Portland Business Allance 39,250
39 Portland Oregon Sports Authority 5,00
40 Redmond Economic Development 5,00
41 Rocky Mountain Elecrical League 18,00
42 Salt Lake Area Chamber of Commerc 30,555
43 UCA Users Group 5,00
44 Utah Foundation 22,500
45 Utah Hispanic Chamber of Commerce 5,00
46 TOTAL 18,54,495
............................................
Name of Respondent
I This trrtlS:
R~te .Q Rep'ort
I
Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 200/04
(2) Fi A Resubmission 03131/2009
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Une DeSCriltion Amount
No.(a (b)
6 Utah Manufacturers Association 6,000
7 Utah Mining Association 22,915
8 Utah Taxyers Association 20,000
9 West Association 28,511
10 Westem Electricity Coordinating Council 2,885,614
11 Westem Energy Institute 40,000
12 Yakima County Development 5,00
13 Other 127,377
14
15 Directors Fees. Regional Advisory Bords -16
17 Regulatory Asset Amortization:
18 Glenrock Mine Stipulation-UT (Excluding Reclamation)149,625
19 Glenrok Mine 1998 Case-UT (Excluding Reclamation)1,152,774
20 Trasition Plan .3,892,299
21
22 General:
23 MEHC Cross Charge 8,679,610
24 Other 14,342
25
26
27
28
29
30
31 .
32
33 .
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 18,540,495
FERC FORM NO.1 (ED. 12-9)Page 335.1
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 031/209 20004
FOOTNOTE DATA
¡Schedule Page: 335.1 Line No.: 15 Column: b
The ($79,365) prily represents uneaized losses for compensation dermed pursuat to PacifCorp's Deferred Compensation Plan
for Regional Advisory Board members.
............................................
Blank Page
(N ext Page is 336)
FERC FORM NO.1 (REV. 12-()Page 336
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ei A Resubmission 03131/200
DEPRECIATION AND AMORTIZATION OF ELECTRIC P .ANT (Acunt 403, 404, 4)5)
(Except amortization of aquisition adjusents)
1. Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numencally in column (a) each plant subaccount,
account or functional classification, as appropnate, to which a rate is applied. Identify at the bottom of Section C the type of plant
included in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the tye mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortizaion Chargs
Dereation Amortization of
Une D~iation Exnse for Aset UmitedTerm Amortiztion of
No.Functional Classification nse Retireent Costs Eleri Plant Other Elecric Total(Acunt 40)(Acnt 40.1)(Accont 40)Plant (Ac 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 37,623,410 37,623,410
2 Steam Production Plant 113,913,69 113,913,694
~ Nuclear Prouction Plant
4 Hydraulic Production Plant-Conventional 14,977,901 41,34 15,019,246
5 Hydraulic Production Plant-Pumped Storage
€ Other Prouction Plant 53,96,013 115,06 54,081,073
7 Transmission Plant 58,235,144 58,235,144
E Distribution Plant 137,554,06 137,554,06
S Regiona Transmission and Market Operaion
1 C General Plant 37,98,56 2,552,628 40,54,197
11 Common Plant-Electric
12 TOTAL "dd(P("40,332,44 456,96,83C',""""e,,,''''2;6,',',
B. Bais for Amortzation Chargs
The amortization of Umited-Term Electric Plant is baed on straght-line amortization over the life of the asset.
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) Ei A Resubmission 03/31/200
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie i:Silmaieo Nei l\PPlleo MOrnlliY Average
No.Account No.Plant Base Avg. Servce Salvage D~r. rates Curve Remaining1~Ca)(In Th?~rndS)7~r (pergrnt)( er;rnt)Tree 7~f
13 Hunter Plant
14 310.20 UT 24E 60.99 1.29 36.00
15 311.00 UT 205,23C 59.03 -5.97 1.51 34.74
16 312.00 UT 538,44 53.58 -5.86 1.83 32.94
17 314.00 UT 152,75 45.86 -7.47 2.26 31.28
18 315.00 UT 94,53 58.91 -4.93 1.49 35.05
19 316.00 UT 3,641 50.05 -4.79 1.94 27.81
20
21 Jim Bridger Plant
22 310.20WY 281 61.44 1.25 31.00
23 311.OOWY 135,135 56.91 -7.38 1.58 30.06
24 312.OOWY 60,505 48.62 -7.04 2.02 28.72
25 314.OOWY 152,353 43.87 -8.35 2.35 27.46
26 315.OOWY 54,66C 59.17 -6.57 1.49 30.29
27 316.OOWY 3,355 50.58 -5.95 1.95 24.79
28
29 Huntington Plant
30 311.00 UT 111,555 56.44 -6.87 1.77 29.12
31 312.00 UT 376,95E 40.67 -6.67 2.63 27.86
32 314.00 UT 95,71 42.52 -7.67 2.53 26.69
33 315.00 UT 41,7~54.6E -6.0~1.81 29.34
34 316.00 UT 2,05 44.86 -5.99 2.55 24.16
35
36 Cholla Plant
37 310.20AZ 1,16 34.00 2.94
38 311.00 AZ 55,36 57.24 -6.03 1.57 34.70
39 312.ooAZ 318,192 55.30 -5.07 1.50 32.95
40 314.00AZ 63,438 53.18 -6.97 1.71 31.28
41 315.00AZ 64,912 59.39 -4.37 1.29 35.05
42 316.ooAZ 3,163 51.05 -4.44 1.68 27.81
43
44 Dave Johnston Plant
45 310.20WY 10C 54.39 1.77 21.00
46 311.OOWY 52,14 39.65 -8.03 2.77 20.57
47 312.OOWY 302,66E 39.37 -7.85 2.88 19.94
48 314.00WY 80,19~41.17 -8.79 2.87 19.34
49 315.OOWY 16,78E 48.2C -7.42 2.24 20.68
50 316.ooWY 5,245 22.66 -6.94 4.88 18.04
FERC FORM NO.1 (REV. 12-()Page 337
FERC FORM NO. 1 (REV. 12-()Page 337.1
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 0331/20
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Cotinued)
C. Factors Used in Estimating Depreciation Cha
Une uepreciaoie t:siimaiea Nei . l\piiea M?naiiy Average
No.Account No.Plant Bae Avg. Servce Savage D~r. rates Curve Remaining
(a'(In ~~~andS)~l (P~'Jt)( erf"t)Trr 7~l
12 Wyodak Plant
13 310.20WY 165 57.69 1.42 33.00
14 311.OOWY 49,014 58.00 -4.55 1.51 31.94
15 312.OOWY 206,727 51.51 -4.21 1.79 30.43
16 314.ooWY 47,79 51.79 -5.76 1.82 29.02
17 315.ooWY 19,631 59.96 -3.62 1.43 32.20
18 316.OOWY 839 38.84 -3.90 2.63 26.03
19
20 Naughton Plant
21 310.20WY 15 66.50 1.39 23.00
22 311.ooWY 65,63 42.75 -8.56 2.63 22.47
23 312.OOWY 246,96 39.85 -8.01 2.82 21.73
24 314.OOWY 63,020 37.76 -9.13 3.09 21.01
25 315.OOWY 20,60 45.48 -7.63 2.37 22.61
26 316.ooWY 1,351 45.18 -7.38 2.75 19.46
27
28 Costrip Plant
29 311.00 MT 57,36 59.49 -4.4:1.38 38.45
30 312.00 MT 111,182 56.65 -4.11 1.50 36.26
31 314.ooMT 32,12 50.57 -6.1E 1.86 34.23
32 315.00 MT 8,9141 6O.4E -3.22 1.31 38.83
33 316.00 MT 2,20 49.0E -3.7E 1.85 30.06
34
35 Craig Plant
36 311.00 CO 36,02E 53.20 -5.06 2.03 27.24
37 312.00 CO .91,07 44.30 -4.74 2.45 26.14
38 314.00 CO 20,627 48.02 -6.17 2.40 25.10
39 315.00 CO 16,53 54.21 -4.25 1.96 27.43
40 316.00 CO 1,7OC 48.11 -4.34 2.42 22.88
41
42 Gadsby Plant
43 311.00 UT 15,055 40.24 -13.60 1.28 10.89
44 312.00 UT 37,014 39.25 -13.30 1.36 10.72
45 314.00 UT 14,517 42.80 -13.54 1.07 10.56
46 315.00 UT 5,585 43.26 -13.32 0.97 10.92
47 316.00 UT 55 26.42 -12.41 3.08 10.19
48
49
50
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 031311200
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie t:siimatea Net l\ppiiea MOrtality Average
No.Account No.Plant Bae Avg. Servce Salvage ~r. rates Curve Remaining
(In Th?~landS)~r (per~rnt)( ercent)Tree ~l(a\(e)
12 Carbon Plant
13 311.00 UT 14,152 40.18 -8.12 2.55 13.38
14 312.00 UT 61,232 32.01 -7.7E 3.25 13.44
15 314.00 UT 25,572 35.21 -8.2E 3.00 13.27
16 315.00 UT 4,558 42.58 -7.65 2.31 13.86
17 316.00 UT 235 40.25 -7.21 2.58 12.67
18
19 Blundell Plant
20 310.20 UT 40,982 38.12 2.27 27.00
21 311.00 UT 7,405 46.46 -2.25 1.69 26.29
22 312.00 UT 27,34 42.55 -4.90 3.14 25.06
23 314.00 UT 30,801 42.07 -3.7C 2.12 24.29
24 315.00 UT 7,17 47.41 -1.44 1.61 26.47
25 316.00 UT 1,02 42.94 -2.31 1.96 22.22
26
27 Camas Co-Gen Plant
28 311.ooWA 5,734 20.41 -1.17 5.18 9.91
29 312.00WA 5,79S 20.28 -1.5 5.25 9.78
30 314.ooWA 18,61 20.14 -1.61 5.35 9.64
31 315.ooWA 4,30 20.2E -0.93 5.20 9.9:3
32
33 Hayden Plant
34 311.00 CO 6,00 50.19 -5.51 1.94 23.44
35 312.00 CO 51,015 37.67 -5.21 2.72 22.63
36 314.00 CO 6,762 46.89 -6.2E 2.18 21.86
37 315.00 CO 2,491 54.57 -4.82 1.73 23.58
38 316.00 CO 1,10€42.92 -4.75 2.46 20.18
39
40 HYDRAULIC
41 PLANT
42 Swif
43 33O.20WA 6,2n 88.23 1.07 40.00
44 33O.50WA 97 86.50 1.10 40.00
45 331.ooWA 6,739 68.37 -1.63 1.47 38.59
46 332.ooWA 37,681 85.84 -2.36 1.17 38.67
47 333.ooWA 11,505 71.26 -4.32 1.48 38.13
48 334.ooWA 3,941 47.41 -5.20 2.27 36.02
49 33.ooWA 411 78.26 1.30 35.20
50 33.ooWA 3eE 57.95 -2.1S 1.76 38.68
FERC FORM NO.1 (REV. 12-()Page 337.2
FERC FORM NO.1 (REV. 12-Q3)Page 337.3
.............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 0331/20
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Cotinued)
C. Factors Used in Estimating Depreciation Charg
Une uepreciaoie i:siimaieo Nei Appiiea Monany Average
No.Accunt No.Plant Bae Avg. Servce Salvage D~r. rates Curve Remaining
(a)(In Th?~fands)7gr (PeC'Jrnt)( ef;rnt)Tree 7~l
12 Yale
13 33.20WA 76 92.19 1.04 40.00
14 331.ooWA 6,691 66.49 -1.~1.53 38.61
15 332.ooWA 26,56 87.60 -2.36 1.13 38.64
16 33.ooWA 10,561 66.07 -4.3:1 1.61 38.19
17 33.ooWA 3,66:1 50.53 -5.20 2.15 35.96
18 33.ooWA 549 83.18 1.24 35.11
19 336.ooWA 1,396 51.12 -2.18 2.02 38.73
20
21 Merwn
22 33.20WA 301 111.67 0.75 40.00
23 330.50WA 21:1 113.5C 0.74 40.00
24 331.ooWA 28,58 55.Q -1.~1.81 38.69
25 33.ooWA 9,98 87.11 -2.3E 1.10 38.63
26 33.ooWA 7,514 74.0:-4.3:1 1.38 38.09
27 33.ooWA 6,90 46.57 -5.2C 2.29 36.22
28 33.ooWA 134 68.3:1.44 35.39
29 33.ooWA 2,23(57.7C -2.18 1.74 38.67
30
31 Klamath River
32 33.20 CAlOR 68 55.95 1.81 40.00
33 33.40 CAlOR ~76.1E 1.35 40.00
34 331.00 CAlOR 10,78 66.87 -1.61 1.62 38.00
35 33.00 CAlOR 46,04E 73.7:1 -2.3C 1.53 37.66
36 33.00 CAlOR 18,01 55.1f -4.3C 2.01 38.06
37 33.00 CAlOR 14,951 47.7f -5.1~2.36 35.57
38 33.00 CAlOR 2~77.71 1.45 34.08
39 33.00 CAlOR 2,48E 61.98 -2.1~1.76 37.87
40
41 North Umpqua
42 331.00 OR 16,06 55.74 -1.29 2.12 31.11
43 332.00 OR 79,66 66.10 -2.14 1.92 31.08
44 33.00 OR 13,12 61.27 -3.41 2.08 30.81
45 33.00 OR 8,377 46.99 -4.15 2.58 29.31
46 33.00 OR 731 42.37 2.60 29.31
47 33.00 OR 5,64 59.6E -1.72 2.04 31.10
48
49
50
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ei A Resubmission 03131/2009
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Une uepreclaDle t:sumateo Net J:ppiieo MOrtllY Average
No.Accunt No.Plant Base Avg. Servce Salvage Deler. rates Curve Remaining
(In T~~FndS)7~f (pe(rgfnt)( ercent)Tree ~lCa)(e)
12 Cutler
13 330.30 UT 5 97.24 2.27 18.00
14 330.40 UT 91 73.81 2.51 18.00
15 331.00 UT 3,80 37.07 -0.67 3.57 17.67
16 332.00UT 6,669 52.50 -0.97 3.00 17.68
17 333.00 UT 11,67 77.93 -1.79 2.59 17.45
18 334.00 UT 2,478 56.56 -2.22 3.07 16.79
19 335.00 UT 13 40.22 3.51 16.89
20 336.ooUT 57 40.47 -0.90 3.42 17.66
21
22 Prospt #1,2, and 4
23 33.20 OR 4 65.95 2.10 31.00
24 33.40 OR 100.50 1.75 31.00
25 331.00 OR 2,99 52.67 -1.24 2.46 30.28
26 332.00 OR 24,124 39.61 -1.80 2.88 30.34
27 33.00 OR 2,700 60.23 -3.30 2.45 29.93
28 33.00 OR 1,56 44.41 -4.02 2.94 28.55
29 33.00 OR 22 32.00 3.37 26.87
30 33.00 OR 25 59.83 -1.66 2.34 30.19
31
32 Pioneer
33 33.20 UT 133.42 0.93 24.00
34 33.30 UT 111 133.5C 0.93 24.00
35 331.ooUT 42 57.22 -0.94 1.94 23.35
36 33.ooUT 7,905 44.48 -1.35 2.42 23.62
37 33.00 UT 2,135 37.88 -2.49 2.84 23.30
38 334.00 UT 481 42.20 -3.06 2.67 22.21
39 335.00 UT 1 43.50 2.52 22.15
40 336.00 UT 12 51.88 -1.25 2.12 23.38
41
42 Lifon
43 33.2010 2 101.20 1.91 27.00
44 33.3010 24 94.75 1.96 27.00
45 331.00 10 1,244 72.23 -1.07 2.41 26.34
46 33.00 10 7,737 56.19 -1.55 2.71 26.45
47 33.00 10 5,530 32.11 -2.84 3.58 26.25
48 334.00 10 26 51.20 -3.4!l 3.23 25.08
49 335.00 10 56.05 2.62 24.74
50 336.0010 18E 32.72 -1.4:;3.43 26.43
FERC FORM NO.1 (REV. 12-Ð3)Pag 337.4
FERC FORM NO.1 (REV. 12-G3)Page 337.5
............................................
Name of Respondent This (!rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 0331/200
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Coinued)
C. Factors Used in Estimating Deprection Charges
Une uepreciaoie i:siimateo Net Applleo MOrtity -Average
No.Account No.Plant Base Avg. Service Salvage D1tr. rates Curve Remaining
la)(In Th?~tandS)~l (pe(';rnt)( er;rnt)Tri ~l
12 AshtonSt. Anthony
13 33O.201D 2 40.50 2.96 21.00
14 331.00 ID 1,21 43.2E -0.80 2.91 20.56
15 332.00 ID 5,06 40.01 -1.6 3.06 20.63
16 333.00 ID 2,44 39.1S -2.14 3.16 20.44
17 334.00 ID 1,31 39.12 -2.64 3.24 19.90
18 33.00 ID a 47.7C 2.82 19.51
19 33.00 ID 1 109.90 -1.07 1.79 20.40
20
21 Bear River
22 33.201D 6 114.8E 1.40 27.00
23 331.00 ID 3,59 75.5C -1.07 1.85 26.24
24 33.00 ID 19,89 69.33 -1.55 1.96 26.36
25 333.00ID 7,66 55.Q -2.84 2.33 26.10
26 334.00ID 3,26 49.96 -3.48 2.58 24.88
27 335.ooID 11~48.5~2.50 24.85
28 33.00 ID 56 54.24 -1.4~2.28 26.32
29
30 Prospe #3
31 331.00 OR 2~41.~-o.4C 3.69 11.88
32 332.00 OR 4,101 33.71 -0.58 4.17 11.82
33 33.00 OR 1,9~25.44 -1.08 5.00 11.76
34 33.00 OR 475 26.21 -1.35 5.04 11.40
35 33.00 OR 7 28.72 4.69 11.37
36 33.00 OR 5 61.9S -0.54 3.07 11.73
37
38 Condt
39 33.20WA 77.se 9.59 2.00
40 33.40WA ..97.5C 9.31 2.00
41 331.ooWA 1,01 35.92 11.11 2.00
42 332.ooWA 4,31C 40.79 10.77 2.00
43 333.ooWA 1,196 27.30 12.00 2.00
44 334.ooWA 197 29.32 11.74 2.00
45 335.ooWA 4 16.50 14.38 2.00
46 33.ooWA 6(56.09 10.09 2.00
47
48
49
50
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 03131/200
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factor Used in Estimating Depreciation Chargs
Line uepreciaoie i:stimatea Net Appiiea M?rtlny JWetae
No.Accunt No.Plant Base Avg. Servce Salvage D~r. rates Curve Remaining
(a)(In Th~FndS)7~l (Pe('Jtnt)( er;~nt)T'(9 7~l
12 Big Fork
13 331.00 MT 58 74.76 -1.93 0.29 45.37
14 332.00 MT 4,602 59.17 -2.80 1.11 45.29
15 33.ooMT 1,445 57.64 -5.11 1.22 44.47
16 33.00 MT 281 66.50 -6.08 0.46 37.43
17 336.ooMT 212 124.20 -2.57 46.55
18
19 Paris
20 331.00 ID 49 38.67 -0.05 6.11 3.98
21 332.00ID 9 62.19 -0.07 5.19 3.97
22 33.00 ID 73 38.97 -0.12 6.08 3.97
23 33.00 ID 105 28.85 -0.15 6.98 3.93
24 33.00 ID 20.8i 8.25 3.94
25
26 Wallowa Falls
27 331.00 OR 111 28.66 -0.31 3.94 9.8C
28 33.00 OR 90 28.0 -0.45 4.00 9.83
29 33.00 OR 106 51.~-0.84 2.47 9.58
30 33.00 OR 1,391 19.65 -1.05 5.62 9.52
31 336.00 OR 311 21.42 -0.42 5.08 9.84
32
33 Olmsted
34 331.00 UT 17 77.40 -0.31 2.83 9.72
35 334.00 UT 29 17.31 -1.05 6.79 9.59
36 335.ooUT 38.06 4.13 9.35
37 336.ooUT 1 23.35 -0.42 5.39 9.85
38
39 Bend
40 331.00 OR 5E 49.3E -0.05 3.99
41 332.00 OR 14 86.70 -0.07 3.99
42 33.00 OR n 68.78 -0.12 3.99
43 33.00 OR 62 23.70 -0.15 3.98
44 335.00 OR 1 9.48 7.21 3.98
45 33.00 OR 74.49 -0.06 3.99
46
47
48
49
50
FERC FORM NO.1 (REV. 12-Ð3)Pag 337.6
FERC FORM NO.1 (REV. 12-G3)Page U7.7
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) ñ A Resubmission 03131/200
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Chaes
Line uepreciaoie i:siimatea Net Appn Monallty lwerage
No.Account No.Plant Base Avg. Service Salvage D~r. rates Cfrle Remaining
Ca)(In Tti~tandS)Y¿l (perJrnt)( er;rnt)T e 7~l
12 Cline Falls
13 331.00 OR 117 29.56 -0.18 6.96
14 332.00 OR 12 44.61 -0.26 6.96
15 33.00 OR 4 66.57 -0.48 6.94
16 33.00 OR 54 29.16 -0.56 6.86
17 33.00 OR 1 70.46 -0.24 6.96
18
19 Eagle Point
20 33.20 OR 1 68.&0.07 19.00
21 331.00 OR 128 44.73 -0.72 1.17 18.22
22 332.00 OR 1,216 38.85 -1.04 1.65 18.49
23 33.00 OR 252 51.20 -1.91 0.81 17.58
24 33.00 OR 72 47.~-2.36 1.06 16.18
25 33.00 OR 112 29.15 -0.96 2.82 18.60
26
27 Weber
28 331.00 UT 361 44.46 -o.4S 3.29 13.72
29 33.00 UT 1,35 55.5S -0.71 2.92 13.73
30 33.00 UT 874 36.15 -1.32 3.n 13.66
31 334.ooUT 11 42.1:J -1.64 3.57 13.12
32 335.00 UT 2:1 35.38 3.86 13.17
33 33.00 UT 4C 26.01 -o.6€4.60 13.78
34
35 Santa Clara
36 331.00 UT 165 43.37 -0.49 3.24 13.71
37 332.ooUT 97 45.36 -0.71 3.15 13.75
38 333.00 UT 46 34.44 -1.32 3.80 13.66
39 33.00 UT 629 27.36 -1.64 4.54 13.27
40 33.00 UT e 39.0:1 3.55 13.12
41 33.00 UT 2 91.96 -0.66 2.21 13.61
42
43 Stairs
44 331.00 UT 181 50.83 -0.72 2.38 18.55
45 33.00 UT 75 6O.3C -1.04 2.11 18.57
46 33.00 UT 51~37.64 -1.91 3.07 18.49
47 33.00 UT 161 39.4C -2.3E 3.07 17.73
48
49
50
............................................
Name of Respondent This 'l0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/200
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charge
Line uepreclaOle i:stlmatea Net l\ppiiea Monamy l\verage
No.Accnt No.Plant Bae Avg. Servce salvage Depr. rates Curve Remaining
(a)(In Th?~Fnds)~~l (Petgfnt)(pet~fnt)TYKe ~~r
12 Lat Chance
13 331.0010 43 38.76 -0.72 2.98 18.61
14 33.00 10 1,035 38.87 -1.04 2.99 18.66
15 33.00 10 1,11 39.07 -1.91 3.04 18.49
16 33.00 10 24E 28.98 -2.3E 3.92 17.90
17 336.00 10 65 42.09 -0.00 2.81 18.59
18
19 Snake Creek
20 331.00 UT 7C 44.94 -0.49 2.78 13.68
21 332.00 UT 45 45.05 -0.71 2.78 13.72
22 333.00 UT 264 36.67 -1.32 3.30 13.63
23 33.00 UT 15 37.05 -1.64 3.31 13.48
24 33.ooUT 2 33.62 3.56 13.12
25
26 Viva Naughton
27 331.OOWY 38 52.86 -1.37 1.98 33.01
28 332.OOWY 104 52.72 -2.29 2.01 33.01
29 333.OOWY 497 51.8 -3.64 2.10 32.71
30 33.00WY 15 51.26 -4.42 2.20 30.87
31 33.OOWY 21 51.29 2.05 30.79
32
33 Granite
34 331.00 UT 4~61.39 -0.94 2.16 23.39
35 33.ooUT 3,590 33.38 -1.35 3.29 23.58
36 33.00 UT 721 47.35 -2.49 2.60 23.42
37 334.00 UT 18S 43.29 -3.06 2.87 22.27
38 335.00 UT 1 58.17 2.32 22.07
39
40 Fountain Green
41 331.ooUT 3€50.52 -0.05 4.06
42 332.00 UT 316 20.2S -0.07 1.30 3.90
43 333.00 UT 24 76.23 -0.12 4.06
44 33.00 UT 78 22.49 -0.15 0.24 1.91
45 33.ooUT 2 23.17 0.38 2.67
46 33.00 UT 1 78.54 -0.06 4.04
47
48
49
50
FERC FORM NO.1 (REV. 12-03)Page 337.8
FERC FORM NO.1 (REV. 12..)Page 337.9
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 03131/200
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Chargs
Line uepreciaoie t:Stlmatea Net l\ppiiea MOrtainy Average
No.Account No.Plant Bae Avg. Service Salvage D~r. rates Curve Remaining
la)(In Th?~tandS)~~l (periÎrnt)( er~rnt)TrKe 7~l
12 OTHER PRODUCTION
13 Hermiston Plant
14 341.00 OR 12,84 39.66 -2.9:3 2.69 29.95
15 342.00 OR 25 39.63 -2.7E 2.72 29.13
16 34.00 OR 105,794 38.29 -3.20 2.85 29.10
17 34.00 OR 4O,07~39.68 -2.90 2.70 29.82
18 345.00 OR 9,07C 40.40 -2.89 2.65 29.91
19 34.00 OR 491 40.46 -2.90 2.65 29.96
20
21 Little Mountain
22 341.00 UT 261 32.74 -2.41 8.73 3.00
23 342.00 UT 121 39.38 -2.41 8.23 3.00
24 34.00 UT 2,381 17.57 -2.41 11.24 3.00
25 34.00 UT 2,36 8.42 -2.41 16.88 3.00
26 34.00 UT 21E 32.10 -2.41 8.78 3.00
27 34.00 UT 12 39.50 -2.41 8.22 3.00
28
29 Currnt Creek
30 341.00 UT 43,23E 40.42 -3.28 2.57 38.92
31 342.00 UT 3,29 39.02 -3.05 2.66 37.52
32 34.00 UT 181,70 39.00 -3.40 2.67 37.50
33 34.ooUT 75,92~40.21 -3.23 2.58 38.71
34 34.00 UT 40,941 40.35 -3.26 2.57 38.85
35 34.00 UT 2,96 40.42 -3.27 2.57 38.92
36
37 Gadsby Gas Peakers
38 341.00UT 4,1~30.12 -1.4C 3.28 25.97
39 342.00 UT 2,2~29.84 -1.33 3.31 25.34
40 34.00UT 50,n~29.7C -1.55 3.34 25.34
41 34.00 UT 15,87 30.31 -1.38 3.25 25.87
42 345.00 UT 2,951 30.09 -1.56 3.36 25.88
43
44 Chehalis
45 341.00WA 22,41 4O.OC -3.34 2.52 34.75
46 342.00WA 1,591 4O.OC -3.34 2.52 34.75
47 34.00WA 194,18 4O.OC -3.34 2.52 34.75
48 34.00WA 82,234 4O.OC -3.34 2.52 34.75
49 34.00WA 37,68E 40.OC -3.34 2.52 34.75
50 34.00WA 3,211 4O.OC -3.34 2.52 34.75
............................................
Name of Respondent This ~rtIS:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) Ei A Resubmission 03131/200
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Une uepreciaoie i:snmatea Net l\ppiiea Monamy Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
Ca)(In TrngtandS)7~l (p~'Jfnt)(Percent)Tree 7~l(e)
12 Eastside Mobile Gener.
13 34.00 UT 84 20.00 5.00
14
15 SOLAR GENERATING
16 Utah Solar
17 34.00 UT 36 15.00 8.84 SO 3.00
18
19 Oregon Solar
20 34.00 OR 56 15.00 5.73 SO 4.00
21
22 Wyoming Solar
23 34.OOWY 61 15.00 8.98 SO 3.00
24
25 WIND GENERATION
26 Foote Creek
27 341.OOWY 11C 3.84
28 34.OOWY 32,33 26.09 -0.95 3.92 17.59
29 34.OOWY 1,63 26.42 -0.82 3.84 17.92
30 34.OOWY 2,891 26.46 -0.82 3.84 17.96
31
32 Leaning Juniper I
33 341.00 OR 4,911 25.47 -0.52 3.96 24.97
34 343.00 OR 153,40 24.82 -0.71 4.08 24.32
35 34.00 OR 5,14C 3.96
36 34.00 OR 8,39~3.96
37 34.00 OR 8 25.4i -0.52 3.96 24.97
38
39 Marengo I & II
40 341.ooWA 10,18 24.8 -1.00 4.06 24.87
41 34.ooWA 324,805 24.87 -1.00 4.06 24.87
42 34.ooWA 9,221 24.87 -1.00 4.06 24.87
43 34.00WA 18,80:2 24.87 -1.00 4.06 24.87
44 34.ooWA 337 24.87 -1.00 4.06 24.87
45
46
47
48
49
50
FERC FORM NO.1 (REV. 12-()Page 337.10
FERC FORM NO.1 (REV. 12-0)Page 33.11
............................................
Name of Respondent This 'lrtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 0331/200
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depration Charg
Line uepreclaOle i:sIlmateo Net Applleo MoriallY Average
No.Account No.Plant Bae Avg. Servce Salvage D1tr. rates Curve Remaining
la\(In Th?g~andS)~il (P~~nt)( er;fnt)T'te 7~l
12 Goodnoe Hils
13 341.00WA 5,38E 24.87 -1.00 4.06 24.87
14 34.ooWA 165,154 24.87 -1.00 4.06 24.87
15 34.ooWA 4,26€24.87 -1.00 4.06 24.87
16 34.ooWA 8,n.i 24.81 -1.OC 4.06 24.87
17 34.ooWA 171 24.81 -1.OC 4.06 24.87
18
19 GlenrOCk Wind
20 341.OOWY 24.81 -1.00 4.06 24.87
21 342.OOWY 24.87 -1.00 4.06 24.87
22 34.OOWY 199,42 24.87 -1.OC 4.06 24.87
23 34.OOWY 24.87 -1.OC 4.06 24.87
24 345.OOWY 24.87 -1.00 4.06 24.87
25 34.OOWY 24.87 -1.OC 4.06 24.87
26
27 Seven Mile Hil Wind
28 341.OOWY 24.8;-1.OC 4.06 24.87
29 342.OOWY 24.8;-1.OC 4.06 24.87
30 34.00WY 233,91 24.8;-1.OC 4.06 24.87
31 34.OOWY 24.8;-1.OC 4.06 24.87
32 34.00WY 24.8;-1.00 4.06 24.87
33 34.00WY 24.87 -1.00 4.06 24.87
34
35 TRANSMISSION PLANT
36 350.20 63,54 70.00 1.35 R5 45.23
37 352.00 70,64 75.OC -1.OC 1.31 S1 58.51
38 353.00 1,098,36 58.OC -4.OC 1.75 R1.5 45.37
39 353.70 50,7()25.OC 3.78 R2 15.75
40 35.00 43,311 55.DC -7.OC 1.56 R5 42.12
41 355.00 537,891 52.00 -42.00 2.63 R2.5 37.15
42 35.00 695,175 60.00 -42.00 2.25 R4 39.52
43 35.20 20,701 65.00 1.40 S6 33.55
44 357.00 3,21 60.00 1.65 R2 52.87
45 358.00 7,490 60.00 1.64 R2 52.68
46 359.00 11,45 70.00 1.39 R5 54.19
47
48
49
50
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 208104
(2) Fi A Resubmission 03131/200
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line UepreclaUle csumaiea l'\el Appiiea Moriaiiy Average
No.Accunt No.Plant Bae Avg. Service Salvage
oir. rates
Curve Remaining
Ca)
(In Th?~fandS)y¿r (pec';tnt)( er;tnt)Tree 7~l
12 DISTRIBUTION PLANT
13 36.20 OR 3,432 53.DC 1.67 R4 22.94
14 361.00 OR 14,745 65.DC -5.00 1.58 R1.5 53.12
15 362.00 OR 174,608 52.00 -10.00 2.00 R1 39.62
16 362.70 OR 2,97 23.00 3.99 R2.5 11.80
17 36.00 OR 300,229 49.00 -100.00 3.95 R2 35.84
18 365.00 OR 219,47 58.00 -80.00 3.01 R1.5 43.32
19 366.00 OR 79,43 60.00 -6.00 2.61 R2.5 47.80
20 367.00 OR 144,272 58.00 -4.00 2.44 R2.5 45.87
21 36.00 OR 36,484 40.00 -20.00 2.89 R1.5 27.79
22 36.10 OR 67,041 65.00 -25.00 1.88 R2 50.93
23 369.20 OR 138,607 55.00 -20.00 2.14 R4 44.61
24 370.00 OR 60,038 26.00 -2.DC 3.64 R2.5 14.13
25 371.00 OR 2,432 25.00 -4.OC 4.80 S1 9.44
26 373.00 OR 21,35 40.00 -26.00 3.06 R1 29.77
27
28 DISTRIBUTION PLANT
29 360.20WA 227 50.00 1.88 R4 22.03
30 361.00WA 2,239 60.00 -5.00 1.73 R1.5 47.63
31 362.00WA 45,~53.00 -10.00 2.04 R1.5 39.87
32 36.70WA 821 22.00 4.22 R4 8.94
33 36.00WA 84,621 50.00 -110.00 4.14 R1.5 39.26
34 365.00WA 55,519 60.00 -80.00 2.95 R1.5 45.71
35 36.00WA 14,58 40.00 -80.00 4.41 R4 28.07
36 367.00WA 19,452 45.OC -35.00 2.95 R4 33.03
37 36.00WA 89,292 42.00 -25.00 2.90 R2.5 28.10
38 369.10WA 16,113 50.00 -15.00 2.25 R2.5 34.11
39 369.20WA 28,92 55.00 -4.00 2.61 R4 44.34
40 370.00WA 13,846 26.00 -5.00 3.84 R2.5 12.73
41 371.00WA 52 30.00 -15.00 3.70 LO 17.21
42 373.00WA 3,741 40.00 -30.00 3.15 R3 24.74
43
44
45
46
47
48
49
50
FERC FORM NO.1 (REV. 12-()Pag 337.12
FERC FORM NO.1 (REV. 12-()Page 337.13
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 0331/200
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Char
Une uepreciaoie csumatea Net l\Ppileo MOnaJlY Average
No.Account No.Plant Base Avg. Servce salvage ~r. rates Curve Remaining
Ca\(In~gFdS)~l (P~~)( e:~nt)Trr ~~l
12 DISTRIBUTION PLANT
13 36.20WY 3,303 50.00 1.79 R4 27.00
14 361.OOWY 7,09E 55.00 -7.00 1.86 R2 40.24
15 362.OOWY 103,96 50.OC -12.00 2.12 S1 34.94
16 362.70WY 2,101 20.&3.81 R4 6.87
17 364.00WY 97,72~5O.OC -71.OC 3.31 R1 39.43
18 36.OOWY 87,891 55.OC -55.00 2.71 R1 41.67
19 36.OOWY 14,65 42~OC -70.OC 3.85 R3 30.15
20 367.OOWY 43,131 4O.OC -4.OC 3.48 R5 26.12
21 36.ooWY 81,~38.OC -20.OC 3.00 R1 27.27
22 369.10WY 14,3O 6O.0C -15.OC 1.85 R2 46.40
23 369.20WY 27,097 45.00 -38.00 2.94 S5 33.74
24 370.OOWY 15,56a 26.00 -5.00 3.57 R2.5 13.40
25 371.00WY 90 20.00 -6.00 5.97 S-.5 6.59
26 373.OOWY 8,921 50.00 -4.00 2.79 RO.5 38.72
27
28 DISTRIBUTION PLANT
29 360.20CA 914 55.00 2.31 R4 20.10
30 361.ooCA 1,481 55.00 -5.00 2.05 R4 37.62
31 362.00CA 20,25 55.00 -25.00 2.39 R1 41.60
32 362.70CA 21 20.00 7.06 R5 5.47
33 36.ooCA 48,22~50.00 -125.OC 4.72 R1.5 37.94
34 365.ooCA 31,78 65JX -95.OC 3.12 S-.5 51.70
35 366.ooCA 14,91E 50.OC -6.00 3.42 R5 34.58
36 367.ooCA 16,39 45.OC -135.OC 5.65 S6 29.50
37 368.ooCA 44,5O 50.0(-4.00 3.15 R5 32.34
38 369.10 CA 7,92~55.OC -120.OC 4.15 R1 44.37
39 369.20CA 13,631 6O.OC -1OO.OC 3.45 R4 48.69
40 370.ooCA 3,93 26.OC -4.OC 4.60 R2.5 13.24
41 371.ooCA 271 25~-95.00 8.78 LO 13.85
42 373.ooCA 66 35.00 -70.00 5.72 R3 16.36
43
44
45
46
47
48
49
50
.............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/200
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie t:siimaieo Nei l\Ppileo MOrtliy Average
No.Accont No.Plant Base Avg. Servce Salvage D~r. rates Curve Remaining
(In Th7~tands)~~f (pe('Jfnt)( ercent)Tre 7~l(a)(e)
12 DISTRIBUTION PLANT
13 360.20 UT 6,517 50.00 1.86 R4 36.84
14 361.00 UT 31,237 60.00 1.61 R2 50.90
15 362.00 UT 343,011 45.00 -5.00 2.25 S-.5 38.25
16 362.70 UT 11,76 25.00 3.49 R3 15.33
17 36.00 UT 1,393 15.00 6.25 sa 11.50
18 36.70 UT 65 15.00 6.25 sa 11.50
19 36.00 UT 279,64 40.00 -55.OC 3.53 S2 27.88
20 36.00 UT 189,40 42.00 -40.OC 3.15 RO.5 32.98
21 36.00 UT 147,47 60.00 -4.00 2.30 R2 48.48
22 367.00 UT 426,16 50.00 -25.OC 2.35 R2 38.87
23 36.00 UT 370,914 45.00 2.11 RO.5 36.26
24 369.00 UT 194,72 55.00 -5.OC 1.83 S5 45.28
25 370.00 UT 80,052 26.00 -4.00 3.25 R2.5 13.53
26 371.00 UT 4,517 25.00 -70.OC 6.10 LO 16.53
27 372.00 UT 30.00 2.45 LO 13.00
28 373.00 UT 26,22 25.00 -20.OC 4.34 RO.5 16.93
29
30 DISTRIBUTION PLANT
31 36.20ID 95 50.00 1.70 R4 36.84
32 361.00 ID 1,495 60.00 1.54 R2 50.90
33 36.00 ID 25,912 45.00 -7.00 2.20 S-.5 38.25
34 362.70ID 352 25.00 2.93 R3 15.33
35 36.00 ID 57,40!4O.OC -67.00 3.41 S2 V.88
36 36.00ID 33,2OC 42.00 -35.00 2.84 RO.5 32.98
37 366.00 ID 7,13 6O.DC -45.00 2.17 R2 48.48
38 367.00 ID 23,194 5O.DC -15.00 2.02 R2 38.87
39 368.00 ID 63,51~45.OC -10.00 2.20 RO.5 36.26
40 369.00 ID 26,57E 55.OC -15.00 1.90 S5 45.28
41 370.00 ID 13,90 26.00 -3.00 3.22 R2.5 15.23
42 371.00 ID 165 25.00 -45.00 4.58 LO 16.41
43 372.00 ID 30.00 1.49 LO 13.00
44 373.00 ID 59 25.00 -50.DC 4.79 RO.5 16.93
45
46
47
48
49
50
FERC FORM NO.1 (REV. 12-G3)Page 337.14
FERC FORM NO.1 (REV. 12-()Page 337.15
.............................................
Name of Respondent This
Wrt
Is: Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 03131/20
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Deprecation Charges
Une uepreclaDle ~stimatea Net Appiiea Monaiiy -JWerage
No.Account No.Plant Base Avg. Servce Salvage Depr. rates Curve Remaining
(a'(InTh~ndS)~l (P~'Jnt)(Per;rnt)Tree 7~l
12 GENERAL PLANT-OR
13 390.00 OR 60,592 50.00 -10.OC 2.21 R1.5 40.92
14 391.10 OR 3,67A1 5.OC 20.42 L2 2.81
15 392.10 OR 9,65 12JX 10.00 7.63 R3 7.20
16 392.50 OR 9,65 18.OC 10.OC 5.05 S2 12.86
17 392.90 OR 2,82 35.OC 15.OC 2.45 S1 25.44
18 396.30 OR 5,211 9.0(15.00 9.71 R4 4.30
19 396.70 OR 23,81 AI 15.OC 20.00 5.39 L1 10.61
20 397.00 OR 88,627 25.OC 4.06 R2 16.28
21
22 GENERAL PLANT-WA
23 390.ooWA 10,91 30.00 -10.00 3.80 R3 20.37
24 392.10WA 2,193 12J:10.00 7.91 R3 6.98
25 392.50WA 3,45 14.00 10.00 6.66 R3 9.50
26 392.90WA 62 33.00 15.00 2.65 SO.5 24.18
27 396.3OWA 1,26:10.00 10.00 9.69 R4 4.93
28 396.70WA 5,817 13.00 15.00 6.81 L1.5 8.41
29 397.00WA 13,25 20.00 5.24 R2 12.16
30
31 GENERAL PLANT-
32 AZ,CO,MT,NM, ETC.
33 390.00 38 40.00 2.06 R1 26.62
34 392.10 571 13.00 6.42 LO 8.81
35 392.50 234 16.00 15.OC 2.96 R1.5 7.03
36 392.90 3 25.00 2.18 R1.5 10.84
37 396.70 2,38f 25.00 5.OC 2.71 R3 13.68
38 397.00 5,~25.00 -5.OC 3.18 R1.5 14.71
39
40 GENERAL PLANT-ID
41 389.20ID 5 40.00 2.01 R1 20.57
42 390.00 ID 10,525 40.00 -5.00 2.12 R1 29.69
43 392.10ID 2,47 11.00 10.00 6.66 54 5.81
44 392.50ID 2,81S 15.00 15.00 5.22 L2 10.90
45 392.90 ID 85 33.00 lOoe 2.50 L2 23.66
46 396.30ID 1,51 7~10.oe 9.15 R3 2.93
47 396.70ID 6,52 18.oe 25.00 3.87 LO.5 13.43
48 397.00 ID 13,68 25.oe -5.00 3.79 S-.5 17.03
49
50
............................................
Name of Respondent This j!rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/2009
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie t:srimarea Ner l\Ppileo MOnaiiy l\verage
No.Account No.Plant Base Avg. Service Salvage DeFlr. rates Curve Remaining
(al (In Th?~tands)~~l (pecrgtnt)( er;tnt)Tree 7~f
12 GENERAL PLANT-WY
13 389.20WY 74 50.00 2.01 sa 48.63
14 390.OOWY 6,12 40.00 -15.00 3.03 R3 26.52
15 392.10WY 5,06 13.00 10.OC 7.34 S1.5 8.26
16 392.50WY 5,00 14.00 10.00 6.80 S2 9.04
17 392.90WY 2,708 30.00 5.00 3.37 R4 18.71
18 396.3OWY 2,362 9.00 15.00 10.37 R4 4.67
19 396.70WY 25,79 15.00 25.00 5.19 S-.5 10.97
20 397.OOWY 31,90 20.00 -2.00 5.40 L2 12.80
21
22 GENERAL PLANT-CA
23 390.ooCA 1,48 50.00 -20.00 2.38 R3 33.57
24 392.10CA 789 10.00 20.00 7.89 S3 5.79
25 392.50CA 824 15.00 15.00 5.63 L2 10.99
26 392.90CA 34 35.00 5.OC 2.69 R4 22.82
27 396.30CA 875 8.00 15.00 10.34 R4 3.27
28 396.70CA 2,492 15.00 15.00 5.60 R2.5 9.31
29 397.00CA 4,46 25.00 -5.00 4.15 R2 15.47
30
31 GENERAL PLANT oUT
32 38.20UT 35 40.00 2.32 R1 20.3~
33 390.00 UT 85,2~40.OC 10.OC 2.18 R1 28.74
34 392.10 UT 18,35 12.OC 10.00 7.07 R3 6.80
35 392.30 UT 3,~10.00 64.00 3.59 sa 9.50
36 392.50 UT 20,921 16.00 10.00 5.41 L2 10.60
37 392.90 UT 6,291 28.00 25.OC 2.57 S1 17.83
38 396.30UT 3,33 8.OC 10.OC 10.07 R4 3.28
39 396.70UT 45,08 12.OC 15.00 6.84 LO.5 8.22
40 397.00 UT 80,77 25.OC -5.00 4.09 R1 18.38
41
42
43
44
45
46
47
48
49
50
FERC FORM NO.1 (REV. 12-()Page 337.16
FERC FORM NO.1 (REV. 12-()Page 337.17
............................................
Name of Respondent This i!rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) DA Resubmission 0331/200
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depriatio Chaes
Line uepreciaoie t:siimaiea Nei l\ppiiea MC?riiny Average
No.Account No.Plant Bae Avg. Servce Salvage D~r. rates Curve Remaining
la)(In~fandS)~~l (P~i;nt)( er;fnt)Trge ~~l
12 GENERAL PLANT-ALL
13 STATES
14 390.30 12,694 15.00 6.67
15 391.00 26,661 20.00 5.00
16 391.20 57,802 5.00 20.00
17 391.30 90 8.00 12.50
18 393.00 13,64 25.00 4.00
19 394.00 62,69 24.00 4.17
20 395.00 38,92 20.00 5.00
21 397.20 4,164 11.00 9.09
22 398.00 6,35 20.00 5.00
23
24 MINING
25 399.3OUT 16,112 34.64 -0.50 0.81 FCST 12.51
26 399.30UT 24,087 49.30 -5.95 1.86 FCST 34.74
27 399.41 UT 12,181 48.81l -5.95 1.88 FCST 34.74
28 399.4UT 3,42 13.2(7.44 sa 12.70
29 399.45 UT 115,5n 12.00 5.00 4.62 L2 6.26
30 399.51 UT 1,134 14.00 5.00 4.49 S3 8.02
31 39.52 UT 4,991 18.00 5.00 3.08 R5 9.39
32 39.60 UT 2,117 13.00 1.00 4.97 L1.5 7.36
33 399.61 UT 61 8.00 1.76 R4 2.77
34 399.70 UT 36,84 24.45 2.54 FCST 12.51
35I--36I-37
38
39
40
41
42
43
44
45
46
47
48
49
50
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/2009 2008104
FOOTNOTE DATA
Account Estimte Applied Average
No.Avg. Servce Depr. Rate Remag
Life (percent)Life
(a)(c)(e)(g)
STEAM PRODUCTION PLAN
Hunter Plant
310.20 UT 47.99 2.02 23.00
311.00 UT 46.78 2.32 22.49
312.00 UT 42.38 2.64 21.74
314.00 UT 35.61 3.27 21.03
315.00 UT 46.47 2.30 22.61
316.00 UT 41.72 2.78 19.48
Jim Bndger Plant
310.20 WY 49.44 2.03 19.00
311.00 WY 45.50 2.52 18.65
312.00 WY 38.04 3.11 18.14
314.00 WY 34.06 3.58 17.65
315.00 WY 47.62 2.36 18.74
316.00 Wy 42.36 2.86 16.57
Huntigton Plant
311.00 UT 50.76 2.19 23.44
312.00 UT 35.44 3.18 22.63
314.00 UT 37.69 3.08 21.86
315.00 UT 48.90 2.25 23.58
316.00 UT 40.88 2.91 20.18
Cholla Plant
310.20 AZ 20.00 5.00
311.00 AZ 44.07 2.28 21.53
312.00 AZ 43.20 2.33 20.85
314.00 AZ 42.10 2.52 20.20
315.00 AZ 45.99 2.08 21.65
316.00 AZ 42.01 2.49 18.77
Dave Johnston Plant
310.20 WY 50.39 2.18 17.00
311.00 WY 35.80 3.38 16.72
312.00 WY 35.75 3.43 16.32
314.00 WY 37.75 3.35 15.92
IFERC FORM NO.1 (ED. 12-87) Page 45.1
IFERC FORM NO.1 (ED. 12-87)Page 450.2
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03131/2009 20004
FOOTNOTE DATA
315.00 WY 44.31 2.75 16.79
316.00 WY 19.67 5.83 15.05
Wyodak Plant
310.20 WY 44.69 2.34 20.00
311.00 WY 45.67 2.45 19.61
312.00 WY 40.13 2.86 19.05
314.00 WY 41.28 2.87 18.51
315.00 WY 47.47 2.31 19.71
316.00 WY 30.12 3.95 17.31
Naughton Plant
310.20 WY 65.50 1.45 22.00
311.00 WY 41.81 2.65 21.53
312.00 WY 38.97 2.86 20.85
314.00 .WY 36.95 3.10 20.20
315.00 WY 44.52 2.45 21.65
316.00 WY 44.49 2.65 18.77
Colstrp Plant
311.00 MT 46.38 2.08 25.34
312.00 MT 44.79 2.20 24.40
314.00 MT 39.83 2.66 23.49
315.00 MT 47.17 1.99 25.51
316.00 MT 40.58 2.58 21.55
Craig Plant
311.00 CO 45.57 2.81 19.61
312.00 CO 37.21 3.36 19.05
314.00 CO 41.43 3.21 18.51
315.00 CO 46.49 2.72 19.71
316.00 CO 42.54 3.19 17.31
Carbon Plant
311.00 UT 36.71 3.44 9.91
312.00 UT 28.41 4.47 9.78
314.00 UT 31.58 4.10 9.64
315.00 UT 38.65 3.22 9.93
316.00 UT 36.92 3.50 9.34
Hayden Plant
311.00 CO 43.47 2.71 16.72
312.00 CO 31.36 3.76 16.32
314.00 CO 40.95 2.99 15.92
315.00 CO 47.78 2.43 16.79
316.00 CO 37.79 3.29 15.05
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 200/04
FOOTNOTE DATA
FERC Sub Acct
310.20
330.20
330.30
330.40
330.50
350.20
353.70
356.20
360.20
362.70
363.70
369.10
369.20
389.20
390.30
391.0
391.20
391.30
392.10
392.30
392.50
392.90
396.30
396.70
397.20
399.30
399.41
399.44
399.45
399.51
399.52
399.60
399.61
399.70
Description
Lad Rights
Lad Rights
Water Rights
Floo Rights
Land Rights-Fishlildlie
Land Rights
Supervisory Equipment
Cleag & Graing
Land Rights
Supervisory & Alar Equipment
Storae Battery Equipment
Overhead Servces
Undergrund Services
Lad Rights
Ofce Panels
Maiam Computers
Personal Computers
Ofce Equipment
Tranp. Eqt - Light Trucks & Vans
Aicra
Trasp. Eqt - Medum Trucks
Transp. Eqt - Trailers
Light Power Operate Equipment
Heavy Power Oprate Equipment
Mobile Radio Equipment
Strctues & Imrovements
Surace Processing Equip
Surace-Electrc Power Facil
Underground Equipment
Vehicles
Heavy Constrction Equipment
Miscellaneous Equipment
Computer Equipment
Mine Development
IFERC FORM NO.1 (ED. 12-87)Page 45.3
FERC FORM NO.1 (ED. 12-9)Page 350
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ei A Resubmission 0331/200
R GULATORY COMMISSION EXPEN ES
1. Report particuiars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a part.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Line Description Asesse by Expnses Total . ueTerrea.
No.(Fumish name of regulatory commission or boy the Regulatory of Expse for in Account
Commisson Current Year .182.3 ~docket or case number and a description of the cae)Utility (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
1 Before the Public Service Commission of Utah:
2 Annual Fee 3,753,722 3,753,722
3 Other State Regulatory Expnses 2,819 2,819
4
5 Before the Public Utilty Commission of
6 Oregon:
7 Annual Fee 2,877,122 2,877,122
8 Other State Regulatory Expenses 1,009,743 1,009,74::
9
10 Before the Public Serve Commission of
11 Wyoming:
12 Annual Fee 1,09,200 1,099,28C
13 Other State Regulatory Expenses
14
15 Before the Washington Utilties and
16 Transportation Commission:
17 Annual Fee 483,32C 483,32C
18 Other State Regulatory Expnses
19
20 Before the Idaho Public Utilties Commission:
21 Annual Fee 40,139 404,13~
22 Other State Regulatory Expnses 28,86 28,865
23
24 Before the Public Utilties Commission of
25 Califomia:
26 Annual Fee 53€536
27 Other State Regulatory Expenses 70,m 70,m
28
29 Before the Federal Energy Regulatory
30 Commission:
31 Annual Fee 1,716,87E 1,716,878
32 Annual Land Use Fee 183,061 183,061
33
34 Deferred Regulatory Commission Expense 592,97::
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 10,518,058 1,112,204 11,63,262 592,973
............................................
Name of Respondent This (!ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) 0 A Resubmission 03131/200
REGULATORY COMMISSION EXPENSE~(Continued)
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferre to Contra Amount Deferred in LineDepartmentl'c~~m AmOunt Accunt 182.3 Accunt Account 182.3 No.
Cf)(h)(i (j (k)
End ~t)Year
1
Electric 928 3,753,722 2
Electric 928 2,819 3
4
5
6
Electric 928 2,877,122 7
Elecric 928 1,009,743 8
9
10
11
Elecric 928 1,09,280 12
13
14
15
16
Elecric 928 483,320 17
18
19
20
Electric 928 404,13~21
Elecric 928 28,865 22
23
24
25
Electric 928 536 26
Electric 928 70,77 27
28
29
30
Elecric 928 1,716,878 31
Elecric 928 183,061 32
33
Elecric 465,105 928 1,109,385 -51,307 34
35
36
37
38
39
40
41
42
43
44
45
11,630,262 46,10 1,109,38 -51,307 46
FERC FORM NO.1 (ED. 12-9)Page 351
FERC FORM NO.1 (ED. 12-8 Page 352
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 0331/200
RESEAFCH, DEVELOPMENT, AND DEMONS RATION ACTIVITIES
1. Describe and show below costs incurrd and acnts charged during the yea for technological reearch, development, and demonstration (R, D &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored proecs.(ldentif
recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of reseach, development, and demonstration in Uniform System of Accounts).
2. Indicate in column (a) the applicable classification, as shown below:
Clasifications:
A. Elecric R, D & D Performed Internly:a. Overhea
(1) Generation b. Underground
a. hydrolectric (3) Distribution
i. Recreation fish and wildlife (4) Regiona Transmission an Maret Operation
ii Other hydroelecric (5) Enviroment (other tha equipment)
b. Fossil-fuel steam (6) Other (Clasif and include items in excess of $5,00.)
c. Intemal combustion or gas turbine (7) Total Cost Incurre
d. Nuclear B. Electric, R, D & D Performed Exemally:
e. Unconventional generation (1) Research Support to the electrica Research Council or the Elecric
f. Siting and heat rejection Powr Research Institute
(2) Transmission
Line Clasification Description
No.(a)(b)
1
2
3
4 B. Electric R, D & D Perfrmed Extemally
5 (1) Research Support Elecric Power Research Institute
6 (1) Research Support Elecric Power Research Institute
7 (1) Research Support Elecric Power Research Institute
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36 .
37
38
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 03131/20
RESEARCH, DE VELOPMENT, AND DEMONSTRATI(N ACTIVITIES (Continuec)
(2) Research Support to Edison Elecric Institute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Clasif)
(5) Total Cost Incurred
3. Include in column (c) all R, 0 & 0 items performed intemally and in column (d) those items performed outside the company costing $5,00 or more,
briefly describing the specific area of R, 0 & 0 (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.).
Group items under $5,00 by classifcations and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by tye of R, 0 & 0
activity.
4. Show in column (e) the account number chargd with expenses during the year or the account to which amounts were capitalized during the year,
listing Accunt 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e)
5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research,
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6. If costs have not been segregated for R, 0 &0 activities or projecs, submit estimates for columns (c), (d), and (f) with such amounts identified by
"Est."
7. Report separately research and related testing facilties operated by the respondent.
Costs Incurred Internaly Costs Incurred Extemally AMOUNTS CHARGED IN CURRENT YEAR Unamortized Linecurrtc\ Year Current Year Acc~unt Am8ï"t Accumulation No.
Cd)(e (g)
1
2
3
4
234,887 557 234,887 5
30,00 580 30,00 6
40,353 930.2 408,353 7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO.1 (ED. 12-87)Page 35
Year/Period of Report
End of 2008/04 ............................................
Name of Respondent
PacifiCorp
This ~rtls: Date of Report
(1) ~An Original (Mo, 08, Yr)
(2) A Resubmission 0331/20
DISTRIBUTION OF SALARIES AND A ES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utilty Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Line
No.
Classification
(a)
1 Electric
2 Operation
3 Prouction
4 Transmission
5 Regional Market
6 Distribution
7 Customer Accounts
8 Customer Service and Informational
9 Sales
10 Administrative and General
11 TOTAL Operation (Enter Total of lines 3 thru 10)
12 Maintenance
13 Production
14 Transmission
15 Regional Market
16 Distribution
17 Administrative and General
18 TOTAL Maintenance (Total of lines 13 thru 17)
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)
21 Transmission (Enter Total of lines 4 and 14)
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)
24 Customer Accounts (Trascribe from line 7)
25 Customer Service and Informational (Transcribe from line 8)
26 Sales (Transcribe from line 9)
27 AdministraUve and General (Enter Total of lines 10 and 17)
28 TOTAL Oper. and Maint. (Total of lines 20 thru 27)
29 Gas
30 Operation
31 Production-Manufactured Gas
32 Prouction-Nat. Gas (Including Exl. and Dev.)
33 Other Gas Supply
34 Storage, LNG Terminaling and Proessing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Servce and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42 Maintenance
43 Production-Manufactured Gas
44 Prouction-Natural Gas (Including Exloration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Proesing
47 Transmission
FERC FORM NO.1 (ED. 12-8)Page 35
............................................
Name of Respondent
PacifiCorp
This ~ort Is:
(1) ~An Original
(2) A Resubmission
IBUTION OF SALARIES AND WAGDIST
Date of Report
(Mo, Da, Yr)
03/31/200
S (Continued)
Year/Period of Report
End of 2008/04
Line
No.
Classification
10,335,956 10,335,956
a)
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Prouction-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (Including Exl. and Dev.) (Total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Proessing (Total of lines 31 thru
56 Transmission (Lines 35 and 47)
57 Distribution (Lines 36 and 48)
58 Customer Accunts (Line 37)
59 Customer Service and Informational (Line 38)
60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)
63 Other Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64)
66 Utility Plant
67 Construction (By Utilty Departments)
68 Electric Plant
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70)
72 Plant Removal (By Utilty Departments)
73 Electric Plant
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of. lines 73 thru 75)
77 Other Accounts (Specif, provide details in footnote):
78 Fuel Stock
79 Miscellaneous Other Incme Deductions
80 Miscellaneous NonoperatinglNonutilty
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts
96 TOTAL SALARIES AND WAGES
10,335,956 10,335,956
25,30,133
459,80
895,839
25,30,133
459,80
895,839
26,655,776
536,020,637
26,655,776
53,020,637
FERC FORM NO.1 (ED. 12-8)Page 355
FERC FORM NO.1 (New 2-()Page 398
............................................
Name of Respondent This~rtIS:Date 01 Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo8/Q4
(2). n A Resubmission 0311/200
PURCHASES AND SALES OF ANCILLRY SERVICES
Report the amounts for each type of ancilary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related biling determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancilary servces purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other tyes ancilary services purchased or sold during
the year. Include in a footnote and specify the amount for each tye of other ancilary service provided.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Billng Determinant Usage - Related Biling Determinant
Unit of Unit of
UnE Typ of Ancilary Servce Number of Unit Measure Dollars Number of Units Measure Dollars
No (a)(b)(c)(d)(e)(f)(g)
1 Sceduling, Sysem Contrl and Dis 144,444
2 React Supply and Volge
:i Regulation and Frequency Resnse 59,219,15E MWh 9,475,06 62,048,00 MWh 10,117,711
4 Energ Imbalance -146,049 MWh -8,378,412
5 Operating Resrve - Spinning 67,863,33~MWh 24,710,89 70,86,458 MWh 25,562,6n
6 Oprating Resrv - Supplement 67,863,332 MWh 24,710,89 70,491,920 MWh 25,46,38
7 Other 1,38 MWh 24,191
8 T etl (Lines 1 thru 7)194,945,820 58,896,857 203,255,722 52,939,00
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03/31/200
M NTHL Y TRANSMISSION SYSTEM PEAK LOAD
(1) Report the monthly peak load on the respondent's transmission system. II the respondent has two or more power systems which ar not physically
integrated, lumish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c ) and (d) the spcified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through 0) by month the system' monthly maxmum megawatt load by statistical classifications. See Genera Instruction for
the definition of each statistical classifiction.
NAME OF SYSTEM:PacifCorp
Une Monthly Peak Day 01 Hour of Firm Networ Firm Netrk Long-Term Firm Oter Long-Shor. Term Firm Oter
No.Month MW - Total Monthly Monthly Servce for self serv for Point-topoint Term Firm Point-to-pont Se
Peak Peak Others Resrvations Servce Resrvtion
(a)(b)(c)(d)(e)(I)(g)(h)(i)0)
1 Januar 18,31 2~80 8,924 1,035 5,059 3,299
:2 Februa 17,64"4 190 8,270 1,06 5,199 3,107
3 March 17,92~~800 7,848 939 5,199 3,943
4 T otlor Quarr 1 53,891
5 Apl 27,63~1 800 7,785 700 5,327 13,814
6 May 28,514 H 1600 8,427 883 5,242 13,96
7 June 3O,49~3C 1400 9,371 1,021 6,102 14,005
8 Tot for Quar 2 86,64 -.-
9 July 29,72~~1700 9,501 1,06 6,079 13,079
10 Auust 29,05(14 1700 9,39 1,049 6,079 12,526
11 Sepembe 25,93f e 1700 8,080 89 j 6,164 10,801
12 T otlo Quarer 3 84,70 .13 Octbe 25,35~1 1600 7,588 82~6,172 10,779
14 November 24,~f 1800 7,83 742 5,242 10,576
15 Deber 25,83!1f 1800 9,176 89E 5,242 10,525
16 Tot for Quar 4 75,59 .JI
17 Tot Year to
Daea 300,841 102,205 11,114 67,106 120,416
FERC FORM NO.113-Q (NEW. 07-()Page 40
IFERC FORM NO.1 (ED. 12-87) Page 450.1
.............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) . A Resubmission 03131/2009 2008/04
FOOTNOTE DATA
¡Schedule Page: 400 Line No.: 4 Column: e
Reflects actual demads of control area load at ti of Trannssion System Peak.
¡Schedule Page: 400 Line No.: 4 Column: f
Reflects actual demads of contrl ar load at ti of Trasnnssion System Peak
¡Schedule Page: 40 Line No.: 4 Column: g
Reflects reservations in effect at tie of Trannnssion System Pea
¡Schedule Page: 400 Line No.: 4 Column: i
Reflects reservations in effect at tie of Trannnssion System Pea
¡Schedule Page: 400 Line No.: 8 Column: e
Refer to footnote for line 4 colum (e).
¡Schedule Page: 400 Line No.: 8 Column: f
Refer to footnote for line 4 colum (t).
¡Schedule Page: 400 Line No.: 8 Column: g
Refer to footnote for line 4 colum ).
Schedule Pa e: 400 Line No.: 8 Column: i
Refer to footnote for line 4 colum i.
Schedule Pa : 400 Line No.: 12 Column: e
Refer to footnote for line 4 colum e.
Schedule Pa e: 400 Line No.: 12 Column: f
Refer to footnote for line 4 colum (t).
¡Schedule Page: 400 Line No.: 12 Column: g
Refer to footnote for line 4 colum (g).
¡Schedule Page: 400 Line No.: 12 Column: i
Refer to footnote for line 4 colum (i).
¡Schedule Page: 400 Line No.: 16 Column: e
Refer to footnote for line 4 colum (e).
¡Schedule Page: 400 Line No.: 16 Column: f
Refer to footnote for line 4 colum
Schedule Pa e: 400 Line No.: 16 Column:
Refer to footnote for line 4 column (g).
¡Schedule Page: 400 Line No.: 16 Column: i
Refer to footnote for line 4 colum (i).
............................................
Blank Page
(Next Page is 401a)
FERC FORM NO.1 (ED. 12-9)Pag 4018
............................................
Name of Respondent This j!rt Is:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) Ei A Resubmission 0331/200
ELECTRIC ENERGY ACCOUI' T
Report below the information caled for conceming the disposition of elecric energ generated, purcased, exchanged and wheeled during the year.
Une Item MegaWatt Hours Line Item MegaWatt Hours
No.No.
(a)(b)(a)(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to Ultimate Consumers (Including 54,361,783
3 Steam 48,568,501 Interdepartental Saes)
4 Nuclear 23 Requirements Sales for Resale (See 232,065
5 Hydro-Conventional 3,769,9111 instruction 4, page 311.)
6 Hydro-Pumped Storage -3,261 24 Non-Requirements Sales for Resale (See 12,112,911
7 Other 7,540,570 instruction 4, page 311.)
8 Less Energ for Pumping 25 Energy Fumished Without Charge
9 Net Generation (Enter Total of lines 3 59,875,7211 26 Energ Use by the Company (Elecric 121,598
through 8)Dept Only, Excluding Station Use)
10 Purchases 11,909,4911 27 Total Energ Losses 4,503,710
11 Power Exchanges:28 TOTAL (Enter Totl of Unes 22 Through 71,332,067
12 Received 6,43~27) (MUST EQUAL LINE 20)
13 Delivered 6,56,511
14 Net Exchanges (Line 12 minus line 13)-132,827
15 Transmission For Other (Wheeling)
16 Received 17,170,080
17 Delivered 17,170,080
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses -3,33
20 TOTAL (Enter Total of lines 9,10,14,18 71,33,06
and 19)
............................................
Name of Respondent ThiS~)Ortis:Oate of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Oa, Yr)End of 2oo8lQ4
(2)A Resubmission 03131/200
MONTHLY PEAKS ANO OUTPUT
(1) Report the monthly peak load and energ output. If the respondent has two or more power which are not physically integrated, fumish the required
information for each non- integrated system.
(2) Repo on line 2 by month the system's output in Megawatt hours for each month.
(3) Report on line 3 by month the non-requirements sales for ree. Include in the monthly amounts any energy loses associated with the sales.
(4) Report on line 4 by month the system's monthly maxmum megawatt load (60 minute integration) assocated with the system.
(5) Report on lines 5 and 6 the specified information for each monthly peak load reported on line 4.
NAME OF SYSTEM:
Line Monthly Non-Requirments MONTHLY PEAK
No.Sales for Resale &Month Total Monthly Energ Associated Losses Megawatts (See Instr. 4)OayofMonh Hor
(a)(b)(c)(d)(e)(f)~January 6,462,731 974,049 8,941 24 080 PST
3C February 5,731,465 90,66 8,278 5 080 PST
31 March 6,132,2~1,324,170 7,848 5 080 PST
32 April 5,549,787 1,034,184 7,785 1 0800 POT ~May 5,504,926 925,681 8,427 19 160 POT
34 June 5,574,80 742,509 9,371 30 140 POT
35 July 6,420,079 80,181 9,501 9 1700 POT
3E August 6,335,84S 1,06,918 9,396 14 1700 POT
37 September 5,740,575 1,168,029 8,081 8 160 POT
3E Ocober 5,708,09 1,056,84 7,588 1 160 POT
3S November 5,786,144 1,110,255 7,839 5 180 PST
4C Oecember 6,385,37::1,00,421 9,176 15 1800 PST
41 TOTAL 71,33,067 12,112,911
FERC FORM NO.1 (ED. 12-90)Page 401b
FERC FORM NO.1 (REV. 12-03)Page 40
............................................
Name of Respondent This 7!0rtIS:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2oo8/Q4
(2) 0 A Resubmission 03131/200 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (La Plants)
1. Report data for plant in Service only.2. Large plants are steam plants with installed caacity (name plate rating) of 25,00 Kw or more. Report in
this page gas-turbine and intemal combustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a foonote any plant leased or operated
as a joint facilty.4. If net pek demand for 60 minutes is not available, give data which is available, speifing period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm bais report the Btu content or the ga and the quantity of fuel bumed converted to Mct.7. Quantities of fuel bumed (Line 38) and average cost
per unit of fuel bumed (Line 41) must be consistent wih charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is bumed in a plant furnish only the compoite heat rate for all fuels bumed.
Line Item Pla Plant
No.Nae: carb Name:
(a)(b)
1 Kind of Plant (Intemal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdor, Boler, etc)Outdoor Boiler Full Outdor
3 Year Originally Constructed 1954 1981
4 Year Lat Unit was Installed 1957 1981
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)188.60 414.00
6 Net Peak Demand on Plant - MW (60 minutes)174 402
7 Plant Hours Connected to Load 8625 7223
8 Net Continuous Plant Capability (Megawatts)0 0
9 When Not Limited by Condenser Water 172 380
10 When Limited by Condenser Water 0 0
11 Average Number of Employee 70 0
12 Net Generation, Exclusive of Plant Use - KWh 1209820 251059100
13 Cost of Plant: Lad and Lad Righs 956 2415102
14 Structures and Improvements 1415183 55364139
15 Equipment Costs 91596954 44970477
16 Asset Retirement Costs 2951381 390
17 Total Cost 10956711 507523018
18 Cost per KW of Installed Capacit (line 17/5) Including 581.4248 1225.9010
19 Proucion Expnses: Oper, Supv, & Engr 312553 1424208
20 Fuel 18529823 49851156
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expnses 1229297 4623599
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Elecric Expenses 1860316 1566174
26 Misc Steam (or Nuclear) Power Expnses 5188701 3273208
27 Rents 13989 3nO
28 Allowances 0 0
29 Maintenance Supervsion and Engineering 0 2012831
30 Maintenance of Structures 224153 1115728
31 Maintenance of Boiler (or reactor) Plant 2713820 605
32 Maintenance of Elecric Plant 1673829 1611953
33 Maintenance of Misc Steam (or Nuclear) Plant 412789 3533767
34 Total Prouction Expnses 32159270 75080479
35 Expenses per Net KWh 0.0267 0.0299
36 Fuel: Kind (Col, Gas, Oil, or Nuclear)Co .Composite Col Oil Composite
37 Unit (CoI-tonslOil-barreVGas-mcf/Nuclear-indicate)Tons Barrls Tons Barrels
38 Quantity (Units) of Fuel Bumed 5766 3243 0 136249 3084 0
39 Avg Heat Cont - Fuel Bume (btulndicate if nuclear)11951 140 0 96 13009 0
40 Avg Cot of FueVunit, as Delvd f.o.b. during year 31.135 139.133 0.00 35.195 90.420 0.00
41 Average Cost of Fuel per Unit Bumed 31.351 0.00 0.00 36.337 0.00 0.00
42 Average Cost of Fuel Bumed per Millon BTU 1.282 23.662 1.313 1.820 16.521 1.83
43 Average Cost of Fuel Bumed per KWh Net Gen 0.015 0.00 0.015 0.019 0.00 0.019
44 Average BTU per KWh Net Generation 1143.54 15.824 11454.36 104.234 6.723 10439.957
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCOrp (1) An Original (Mo, Da, Yr)2008104
(2) 0 A Resubmission 03131/200 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continue)
9. Items under Cost of Plant are baed on U. S. of A. Accounts. Prodction expenses do not include Purchased Power, System COntrol and Load
Dispatching, and Other Expnses Clasified as Other Power Supply Expnses. 10. For IC and GT plants, report Operating Expnses, Accont Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped wih combinations of fossil fuel steam, nuclear
steam, hydro, intemal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a cobined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear poer generating plant, briefly explain by
footnote (a) accounting metho for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various compoents of fuel cost; and (c) any other informative data conceming plant tye fuel used, fuel enrichment type and quantit for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name:",,,,,,,e,,'j;~l¡~I%~ml~~lt Name:Name: Dave Johnston No.
'ê)","","e,"",e""",~,~(f)-IiSteam Stear Stear 1
Convenional Outdoor Boiler Semi-Outdor 2
1984 1979 1959 3
1986 1980 1972 4
155.60 172.10 816.80 5
153 166 764 6
8782 8784 8784 7
0 0 0 8
148 165 762 9
0 0 0 10
0 0 191 11
12349400 13681090 563 12
1355853 13708 1045108 13
57362857 3626749 5214865 14
1541945 129942322 404891472 15
39236 55971 687441 16
2131n381 166162128 474365621 17
1370.034 96.4975 580.7610 18
17822 271697 765017 19
14142105 1939426 5018n68 20
0 0 0 21
795836 1380265 5679 22
0 0 0 23
0 0 0 24
28900 613813 0 25
264916 70850 1530716 26
2356 0 3134 27
0 0 0 28
227592 59671 0 29
288315 349 1861787 30
1712259 333655 1019032 31
2180 784868 8025256 32307807818143n33
2004758 2824052 87842574 34
0.0165 0.0206 0.0156 35
Coal Oil Composite Coal Oil Compoite COal COmposite 36
Tons Barrels Tons Barrls Tons Barrels 37
79342 671 0 691557 441 0 402487 10941 0 38
8393 1400 0 9933 133998 0 796 140 0 39
16.428 134.845 0.00 28.143 115.09 0.00 12.167 122.86 0.00 40
17.709 0.00 0.00 27.921 0.00 0.00 12.135 0.00 0.00 41
0.986 22.935 0.993 1.363 20.451 1.369 0.756 20.896 0.77 42
0.011 0.00 0.011 0.014 0.00 0.014 0.009 0.00 0.009 43
10788.946 3.197 10792.143 1001.946 1.812 100.758 11375.86 11.409 11387.273 44
FERC FORM NO.1 (REV. 12-G3)Page 403
FERC FORM NO.1 (REV. 12-03)Page 40.1
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, 08, Yr)2008/04(2) 0 A Resubmission 03131/200 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Cotinued)
1. Report data for plant in Service only.2. Large plants are stea plants wih installed capacity (name plate rating) of 25,00 Kw or more. Report in
this page gas-turbine and intemal combustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facilty.4. If net peak demand for 60 minutes is not available, give data which is available, specifing period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If ga is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel bumed converted to Mct.7. Quantities of fuel bumed (Line 38) and average cost
per unit of fuel bumed (Line 41) must be cosistent with charg to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is bumed in a plant furnish only the compoite heat rate for all fuels bumed.
Line Item Plan Plant ¡II"..No.Nae:Name:
(a)
'c"~"'~"""''"'(b ,',","~""' " ,,'e'
1 Kind of Plant (Intemal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor Boiler Outdoor Boiler
3 Year Originally Constructed 1965 1978
4 Year Last Unit was Installed 1976 1978
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)81.30 44.00
6 Net Peak Demand on Plant - MW (60 minutes)79 40
7 Plant Hours Connected to Load 8784 8323
8 Net Continuous Plant Caabilty (Megwatts)0 0
9 When Not Limited by Condenser Water 78 403
10 When Limited by Condenser Water 0 0
11 Average Number of Employee 0 0
12 Net Generation, Exclusive of Plant Use - KWh 6235050 311495700
13 Cost of Plant: Lad and Lad Rights 379735 968975
14 Structures and Improvements 602332 62728682
15 Equipment Cots 61376697 231862809
16 Asset Retirement Costs 208n 1023554
17 Total Cost 677961 30530420
18 Cost per KW of Installed Capacit (line 17/5) Including 833.6979 689.1739
19 Prouction Expenses: Oper, Supv, & Engr 215629 -5903
20 Fuel 118130 39811612
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 1070163 30148
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Elecric Expnses 230705 0
26 Misc Steam (or Nuclear) Power Expenses 417080 2244196
27 Rents 0 29
28 Allowances 0 0
29 Maintenance Supervision and Engineering 219300 0
30 Maintenance of Structures 218128 2206
31 Maintenance of Boiler (or reactor) Plant 1238354 5245970
32 Maintenance of Elecric Plant 158508 11332
33 Maintenance of Misc Stea (or Nuclear) Plant 40135 15n98
34 Total Prouction Expenses 15987042 5387972
35 Expnses per Net KWh 0.0256 0.0173
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Col Oil Composite Col Oil Compoite
37 Unit (Coal-tonslOil-barreVGas-mcf/Nuclear-indicate)Tons Barrels Tons Barels
38 Quantity (Units) of Fuel Bumed 301473 473 0 1485395 3165 0
39 Avg Heat Cont - Fuel Bumed (btulndicte if nuclear)11492 132599 0 1156 140 0
40 Avg Cost of FueVunit, as Delvd f.o.b. during year 36.807 155.123 0.00 0.00 0.00 0.00
41 Average Cost of Fuel per Unit Bumed 38.859 0.00 0.00 26.498 0.00 0.00
42 Average Cost of Fuel Bumed per Milion BTU 1.587 27.859 1.601 1.129 24.291 1.142
43 Average Cost of Fuel Bumed per KWh Net Gen 0.018 0.00 0.018 0.012 0.00 0.012
44 Average BTU per KWh Net Generation 11113.391 4.221 11117.613 11027.839 5.974 11033.813
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2008lQ4(2) 0 A Resubmission 03/31/200 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expnses.10. For IC and GT plants, report Operating Expnses, Accunt Nos.
547 and 549 on Une 25 "Electric Expenses," and Maintenance Accunt Nos. 553 and 554 on Line 32, "Maintenance of Elecric Plant." Indicate plans
designed for peak load service. Designate automatically operated plants.11. For a plant equipped wih combinations of fosil fuel steam, nuclear
stea, hydro, intemal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accunting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various compoents of fuel cost; and (c) any other informative data conceming plant type fuel used, fuel enrichment type and quantity for the
report peri and other physical and operating characteristics of plant.
Plant Plant Plant ~Name:Name:Hunter Unit NO.3 Name:No.:,ecc,,':
(e)~-
Steam Steam Steam 1
Outdor Boiler Outdoor Boiler Outdoor Boiler 2
1980 1983 1978 3
1980 1983 1983 4
285.00 495.60 1223.60 5
261 4n 1126 6
8617 8269 8781 7
0 0 0 8
259 46 1122 9
0 0 0 10
0 0 220 11
2096700 353379700 869172100 12
9688975 10275401 2963351 13
51661298 90839287 205229267 14
154914041 40601688 789378538 15
1023554 102355 30706 16
217287868 504739930 1027331819 17
762.4136 1018.4422 839.5978 18
-5903 -5903 -1n09 19
25535122 4374989 10821723 20
0 0 0 21
3015203 300795 903480 22
0 0 0 23
0 0 0 24
0 0 0 25
-2248468 2740942 273670 26
29 29 87 27
0 0 0 28
0 0 0 29
206150 1839573 6109723 30
523091 78614 18375 31
124733 541738 292535 32
164245 262578 584621 33
35002205 59323255 14813331 34
0.0171 0.0168 0.0170 35
Coal Oil Compoite Coal -Composite Coal Oil Composite 36
Tons Barrls Tons Barrls Tons Barrels 37
952476 750 0 1569283 11091 0 407154 150 0 38
11607 140 0 1154 140 0 11570 14~~0 39
0.00 0.00 0.00 0.00 0.00 0.00 26.252 136.486 0.00 40
26.709 0.00 0.00 26.493 0.00 0.00 26.54 0.00 0.00 41
1.125 21.65 1.129 1.132 23.009 1.172 1.129 23.212 1.150 42
0.012 0.00 0.012 0.012 0.00 0.012 0.012 0.00 0.012 43
10822.880 2.159 10825.039 10249.329 18.45 10267.783 106.301 10.151 10678.452 44
FERC FORM NO.1 (REV. 12-G3)Page 40.1
FERC FORM NO.1 (REV. 12-03)Page 402.2
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, 08, Yr)2008/04
(2) 0 A Resubmission 0311/20 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plats) (Continued)
1. Report data for plant in Service only.2. Large plants are steam plants wih installed capacity (name plate rating) of 25,00 Kw or more. Report in
this page gas-turbine and intemal combustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leaed or operated
as a joint facilty.4. If net peak demand for 60 minutes is not available, give data which is available, specifing period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employee assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the ga and the quantity of fuel bumed converted to Mct.7. Quantities of fuel bumed (Line 38) and average cost
per unit of fuel bumed (Line 41) must be consistent with charges to expnse accnts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is bumed in a plant furnish only the composite heat rate for all fuels bumed.
Line Item Pla ~~
No.Nae: Huntington Name:
(a)(b)
~-""'="'"''
1 Kind of Plant (Intemal Comb, Gas Turb, Nuclear Steam Steam
2 Typeof Constr (Conventional, Outdoor, Boiler, etc)Outdor Boiler Semi-Outdor
3 Year Originally Constructed 1974 1974
4 Year Lat Unit was Installed 1977 1979
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)996.00 1541.10
6 Net Peak Demand On Plant - MW (60 minutes)90 1405
7 Plant Hours Conneced to Load 8770 8784
8 Net Continuous Plant Capability (Megawatts)0 0
9 When Not Limited by Condenser Water 895 1413
10 When Limited by Condenser Water 0 0
11 Average Number of Employee 164 345
12 Net Generation, Exclusive of Plan Use - KWh 71488 101648330
13 Cost of Plant: Lad and Lad Rights 2386782 1161925
14 Structures and Improvements 111555214 135138580
15 Equipment Costs 51645783 814872756
16 Asset Retirement Costs 2351856 66661
17 Total Cost 6327596 95783622
18 Cost per KW of Installed Capacity (line 17/5) Including 635.308 621.5279
19 Prouction Expenses: Oper, Supv, & Engr 15251 18053815
20 Fuel 81271884 149097
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expses 8595373 3610169
23 Steam From Other Sourcs 0 0
24 Steam Transferre (Cr)0 0
25 Elecric Expenses 0 2475
26 Misc Steam (or Nuclear) Power Expenses 1026785 -154153
27 Rents 14493 186164
28 Allowances 0 0
29 Maintenance Supervsion and Engineering 1245563 5008
30 Maintenance of Structures 1550821 1108899
31 Maintenance of Boiler (or reactor) Plant 686869 23148750
32 Maintenance of Elecric Plant 124496 7676159
33 Maintenance of Misc Steam (or Nuclear) Plant 1212918 2726422
34 Total Prouction Expenses 112285991 2082345
35 Expenses per Net KWh 0.0157 0.0197
36 Fuel: Kind (Coa, Gas, Oil, or Nuclear)Co ;'i',Copoite Co Oil Compoite
37 Unit (CoI-tonslOil-barreIlGas-mcf/Nuclear-indicate)Tons Barrls Tons Barrels
38 Quantity (Units) of Fuel Bumed 30101 8288 0 56 18419 0
39 Avg Heat Cont - Fuel Bumed (btulndicte if nuclear)11857 140 0 9249 14~~0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 25.199 126.33 0.00 25.790 119.988 0.00
41 Average Cost of Fuel per Unit Burn 26.705 0.00 0.00 25.816 0.00 0.00
42 Average Cost of Fuel Burn per Milion BTU 1.092 21.486 1.106 1.389 20.406 1.40
43 Average Cost of Fuel Bumed per KWh Net Gen 0.011 0.00 0.011 0.014 0.00 0.014
44 Average BTU per KWh Net Generatio 99.170 6.817 9971.986 10351.518 10.655 10362.172
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2008/04(2) 0 A Resubmission 03/31/200 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expnses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Accunt Nos.
547 and 549 on Line 25 "Electric Exenses," and Maintenance Accunt Nos. 553 and 554 on Line 32, "Maintenance of Elecric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, intemal cobustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit funcions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess cots attributed to research and development; (b) tys of cost units
used for the various components of fuel cost; and (c) any other informative data conceming plant type fuel used, fuel enrihment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name: Naughton Nae:Name:Gadsby Steam Plant No.
(d)e (f)
Steam Steam Steam 1
Outdoor Boiler Conventional Outdoor 2
196 1978 1951 3
1971 1978 1955 4
707.20 289.70 257.60 5
705 280 219 6
8784 84 3079 7
0 0 0 8
700 26 235 9
0 0 0 10
144 69 39 11
51144090 22527990 2320780 12
429826 210526 1252090 13
65636170 49014021 15053 14
33194962 27499749 57668039 15
2650267 613826 587008 16
40518225 324829122 7452501 17
571.9998 1121.2603 289.457 18
46180 20636 78893 19
76503802 19521169 2631622 20
0 0 0 21
7377173 0 0 22
0 0 0 23
0 0 0 24
920 0 0 25
8591754 4112755 346842 26
0 4958 0 27
0 0 0 28
1206951 48 0 29
1139518 356591 246773 30
5974226 55421 1291713 31
1793996 1053128 1221612 32
636100 363 262672 33
103686240 3117008 32850127 34
0.0203 0.0138 0.1415 35
Coal _ComPOite Coal Oil Compoite Gas 36
Tons MCF Tons Barrls MCF 37
2767902 163367 0 1657686 36 0 3124563 0 0 38
9858 1047 0 7821 140 0 1057 0 0 39
27.315 0.00 0.00 11.511 122.186 0.00 0.00 0.00 0.00 40
27.117 8.863 0.00 11.505 0.00 0.00 8.418 0.00 0.00 41
1.374 8.448 1.396 0.736 20.780 0.753 7.961 0.00 0.00 42
0.015 0.00 0.015 0.008 0.00 0.00 0.113 0.00 0.00 43
10670.417 33.514 10703.931 11509.918 9.60 11519.524 14236.623 0.00 0.00 44
FERC FORM NO.1 (REV. 12-()Page 40.2
FERC FORM NO.1 (REV. 12-()Page 402.3
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2008/04
(2) 0 A Resubmission 0331/20 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Cotinued)
1. Report data for plant in Service only.2. Large plants are steam plants with insalled cacit (name plate rating) of 25,00 Kw or more. Report in
this page gas-turbine and intemal combustion plants of 10,00 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facilty.4. If net pek demand for 60 minutes is not available, give data which is available, speifng period.5. If any employees atend
more than one plant, report on line 11 the approximate average number of employee asignable to each plan.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantit of fuel bumed coverted to Mct.7. Quatities of fuel bumed (Line 38) and average cost
per unit of fuel bumed (Line 41) must be consistent with charges to expe acunt 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is bumed in a plant fumish only the composite heat rae for all fues burn.
Line Item Plant Plant ~llill.'liltl\"\l
No.Name: Uttle Mountain Name:
(a)(b)~1 Kind of Plant (Intemal Comb, Ga Turb, Nuclear Gas Turbine
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor Boiler Outdor
3 Year Originally Construted 1972 1996
4 Year Lat Unit was Installed 1972 1996
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)16.00 279.60
6 Net Peak Demand on Plant - MW (60 minutes)17 245
7 Plant Hours Connected to Lod 80 8389
8 Net Continuous Plant Capability (Megawatts)0 0
9 When Not Limited by Condenser Water 14 237
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 6 0
12 Net Generation, Exclusive of Plant Use - KWh 10956 180162500
13 Cost of Plant: Lad and Lad Rights 635 842245
14 Structures and Improvements 267331 1283984
15 Equipment Costs 5092337 15549
16 Asset Retirement Coss 0 214373
17 Total Cost 53630 169357102
18 Cost per KW of Installed Capacity (line 17/5) Including 33.0189 605.7121
19 Prouction Expnses: Oper, Supv, & Engr 0 0
20 Fuel 16n801 5623736
21 Colants and Water (Nuclear Plants Only)0 0
22 Steam Expnses 0 0
23 Steam From Other Sorces 0 0
24 Steam Transferred (Cr)0 0
25 Elecric Expnses 947555 764957
26 Misc Steam (or Nuclear) Power Expnses 0 0
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervsion and Engineering 0 0
30 Mantenance of Structures 0 0
31 Maintenance of Boiler (or reacor) Plat 0 0
32 Maintenance of Elecri Plant 91556 0
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Prouction Expnses 17817202 63882321
35 Expses per Net KWh 0.1626 0.0355
36 Fuel: Kind (Coal, Gas, Oil, or Nucear)Gas Gas
37 Unit (CoI-tonslOil-barrVGas..cf/Nuclear-indicate)MCF MCF
38 Quantity (Units) of Fuel Bumed 2026700 0 0 128969 0 0
39 Avg Heat Cont - Fuel Bumed (btulndicate if nuclear)1058 0 0 1020 0 0
40 Avg Cot of FueVunit, as Delv f.o.b. during year 0.00 0.00 0.00 0.00 0.00 0.00
41 Average Cot of Fuel per Unit Bumed 8.279 0.00 0.00 4.382 0.00 0.00
42 Average Cot of Fuel Bumed per Million BTU 7.827 0.00 0.00 4.301 0.00 0.00
43 Average Cost of Fuel Bumed per KWh Net Gen 0.153 0.00 0.00 0.031 0.00 0.00
44 Average BTU per KWh Net Generation 1956.80 0.00 0.00 7258.235 0.00 0.00
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2008/04(2) 0 A Resubmission 03131/200 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continue)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Prouction expenses do not include Purchased Power, System Control and Load
Dispatching, and Oter Expnses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expnses, Accunt Nos.
547 and 549 on Line 25 "Elecric Expenses,. and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load servce. Designate automatically oprated plants.11. For a plant equipped wih combinations of fossil fuel steam, nuclear
steam, hydro, intemal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functios in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generaed including any excess costs atributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other infrmative data conceming plant type fuel used, fuel enrichment tye and quantity for the
report period and other physical and operating characteristics of plant.
Plant _,ilfl~~'lli¡I'II¡~III.~lfAlê Plant ~~"~~,,
1¡~~l§~¡"Jllll~~l~~;¡~
Plant
Illililili¡lii,i
Line
Name:Name:Name:No.,e,;"~'"
(e)(f)
Steam - Geothermal Steam GaTurbine 1
Indoor Outdoor Boiler Outdoor 2
1984 1996 2002 3
2007 199 2002 4
38.10 61.50 217.00 5
37 46 194 6
838 7267 1757 7
0 0 0 8
34 22 202 9
0 0 0 10
22 0 6 11
25427700 86200 126285 12
41195596 0 0 13
7404973 5733734 0 14
66334256 287168 0 15
1336278 0 0 16
116271103 34505 0 17
3051.7350 56.1714 0.~~18
33075 0 0 19
0 0 1092119 20
0 0 0 21
-234842 0 0 22
3371385 0 0 23
0 0 0 24
0 0 3072 25
2291026 1454 0 26
3024 0 458304 27
0 0 0 28
0 0 0 29
2953 0 166275 30
248805 0 0 31
489274 0 314608 32
63391 6 0 33
656082 14549 190878 34
0.0258 0.0017 0.1510 35
Gas 36
MCF 37
0 0 0 0 0 0 1402458 0 0 38
0 0 0 0 0 0 105 0 0 39
0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 40
0.00 0.00 0.00 0.00 0.00 0.00 7.838 0.00 0.00 41
0.00 0.00 0.00 0.00 0.00 0.00 7.48 0.00 0.00 42
0.00 0.00 0.00 0.00 0.00 0.00 0.087 0.00 0.00 43
0.00 0.00 0.00 0.00 0.00 0.00 11629.156 0.00 0.00 44
FERC FORM NO.1 (REV. 12.(3)Page 40.3
FERC FORM NO.1 (REV. 12-G3)Page 40.4
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2004(2) DA Resubmission 0331/200 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Lae Plats) (Cotinued)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate raing) of 25,00 Kw or more. Report in
this page gas-turbine and internl combustion plants of 10,00 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facilty.4. If net peak demand for 60 minutes is not availabe, give data which is available, speifng period.5. If any employees attend
more than one plant, report on line 11 the aproximate average numbe of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the ga and the quanity of fuel bumed converted to Mct.7. Quantities of fuel bumed (Line 38) and average cost
per unit of fuel bumed (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is bumed in a plant fumish only the compoite heat rate for all fuels bumed.
Line Item Plant Plant
No.Name: Gadsby Gas Peakers Name: Currnt Creek
(a)(b)(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine Combined Cycle
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Outdor Outdor
3 Year Originally Constructed 2002 2005
4 Year Lat Unit wa Installed 2002 200
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)141.00 566.90
6 Net Pea Demand on Plant - MW (60 minutes)124 571
7 Plant Hours Conneced to Lod 4156 7752
8 Net Continuous Plant Capabilty (Megawatt)0 0
9 When Not Limited by Condenser Water 120 540
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 0 21
12 Net Generation, Exclusive of Plant Use - KWh 2505180 2799585000
13 Cost of Plant: Land and Lad Rights 0 3403277
14 Structures and Improvements 412164 4323674
15 Equipment Costs 718891 3084265
16 Asset Retirement Costs 0 134848
17 Total Cost 760233 3516190
18 Cost per KW of Installed Capacity (line 17/5) Including 539.0236 620.2488
19 Prouction Expnses: Oper, Supv, & Engr 0 9234
20 Fuel 23997222 157074310
21 Colants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 15536 2503145
26 Misc Steam (or Nuclear) Power Expenses 0 0
27 Rents 0 120
28 Allowances 0 0
29 Maintenance Supervsion and Engineering 0 0
30 Maintenance of Strutures 11342 405205
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 91594 290153
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 26581975 16298236
35 Expnses per Net KWh 0.1061 0.0582
36 Fuel: Kind (Coal, Gas, Oil, or Nuclea)Gas Gas
37 Unit (Coal-tonslOil-barreVGas-mcf/Nuclear-indicae)MCF MCF
38 Quantity (Units) of Fuel Bumed 2882672 0 0 19384161 0 0
39 Avg Heat Cont - Fuel Bumed (btulndicate if nuclear)1057 0 0 105 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.00 0.00 0.00 0.00 0.00 0.00
41 Average Cost of Fuel per Unit Burn 8.325 0.00 0.00 8.103 0.00 0.00
42 Average Cost of Fuel Bumed per Milion BTU 7.878 0.00 0.00 7.686 0.00 0.00
43 Average Cot of Fuel Bumed per KWh Net Gen 0.096 0.00 0.00 0.056 0.00 0.00
44 Average BTU per KWh Net Generation 12158.823 0.00 0.00 7299.697 0.00 0.00
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2008/04(2) D A Resubmission 03131/200 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Prouction expnses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Elecric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintence of Elecric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, intemal combustion or gas-turbine equipment, reprt each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accunting method for cost of power generated including any excess cots attributed to research and development; (b) types of cost units
used for the varius components of fuel cot; and (c) any other informative data conceming plant type fuel used, fuel enrichment tye and quantiy for the
report period an other physical and operating characteristics of plant.
Plant Plant Plant Line
Name: Lake Side Name:~ll¡liij~'lt¡fLiltll~Name:No.
(d)
,,,,,,",,e"""',,,,,,,,,eêe)'
(f)~Combined Cycle Combined Cycle 1
Outdor Outdoor 2
2007 2003 3
2007 2003 4
548.00 520.00 0.00 5
601 525 0 6
7234 168 0 7
0 0 0 8
548 520 0 9
0 0 0 10
19 17 0 11
2861722000 5884580 0 12
17296760 0 0 13
27057001 0 0 14
305014470 0 0 15
0 0 0 16
349368231 0 0 17
637.5333 0.~~0.~~18
126122 0 0 19
157112030 4228848 0 20
0 0 0 21
0 0 0 22
0 0 0 23
0 0 0 24
2712172 1301982 0 25
0 0 0 26
0 27423 0 27
0 0 0 28
0 0 0 29
58549 9978 0 30
0 0 0 31
165085 515059 0 32
0 0 0 33
162186627 44142850 0 34
0.0567 0.0750 0.~~35
Gas Gas 36
MCF MCF 37
19419993 0 0 418885 0 0 0 0 0 38
1042 0 0 1030 0 0 0 0 0 39
0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.000 0.00 40
8.09 0.00 0.00 10.097 0.00 0.00 0.00 0.00 0.00 41
7.767 0.00 0.00 13.478 0.00 0.00 0.00 0.00 0.00 42
0.055 0.00 0.00 0.072 0.00 0.00 0.00 0.00 0.00 43
706.652 0.00 0.00 5331.917 0.00 0.00 0.00 0.00 0.00 44
FERC FORM NO.1 (REV. 12-GS)Page 40.4
¡Schedule Page: 402 Line No.: .1 Column: c I
Cholla Plant is operated by Arzona Public Servce Company. Respondent owns Unit No.4 plus 37.44% of related common facilties.
Data re ortd re resents res ondent's share. PacifiCo does not have em 10 ees at the Cholla Plant.
Schedule Pa e: 402 Line No.: .1 Column: d
Colstp Plant is operated by PPL Montaa, LLC and is jointly owned. Data reported represents respondent's 10% shae of Colstrp
Plant Units No.3 and No.4. PacifiCo does not have em 10 ee at the Colstr Plant.
Schedule Pa e: 402 Line No.: .1 Column: e
Crag Plant is operate by Tri-State Generation and Tramission Association and is jointly owned. Data reported represents
respondent's 19.28% share of Crag Plant Units No. i and No.2, and 12.86% of common facilties. PacifiCorp does not have
em 10 ees at the Crai Plant.
Schedule Pa e: 402.1 Line No.: .1 Column: b
Hayden Plant is operated by Pulic Sece Company of Colorao and is jointly owned. Data reportd represents respondent's 24.5%
(45 MW share of Hayden Unit No.1, 12.6% (33 MW shae of Hayden Unit No.2, and 17.5% of common failties. PacifiCorp does
not have em 10 ees at the Ha den Plan.
Schedule Pa e: 402.1 Line No.: .1 Column: c
Hunter Plant Unit NO.1 is owned by respondent and Provo City Corporation with undivided interest of93.75% and 6.25%
res 'vel. Data r ortd in colum (c) resents res ndent's sha.
edule Pa e: 402.1 Line No.: .1 Column: d
Hunte Plant Unit NO.2 is owned by respondent, Dese Power Electc Cooperative, and Uta Associat Muncipal Power System,
eah with undivided inteest of 60.31 %, 25.108%, an 14.582% repevely. Data reported in colum (d) represents respondent's
she.
ISchedule Page: 402.1 Line No.: .1 Column: f
Hunter Unit NO.1 is owned by responden and Provo City Corpraon with undivided inteest of93.75% and 6.25% respectively.
Hunte Unit No.2 is owned by repondent, Dese Power Electc Cooperve, and Uta Associate Municipal Power Systems, each
with undivided interest of60.31%, 25.108%, and 14.582% re 'vel. Data in colum re resents res ndent's sha.
Schedule Pa : 402.2 Line No.: .1 Column: c
Jim Bridger Plant is operated by PacifiCorp and colwn (c) repsets the respondent's sha. Owership of the plant is as follows:
PacifiCorp 66 2/30/0. Idaho Power Company 33 1/3%.
!Shedule Page: 402.2 Line No.: .1 Column: e
Wyoda Plant is operated by PacifiCorp and colum (e) represets the respondent's sha. Owerhip of the plant is as follows:
PacifiCo 80%, Black Hills Co ration 20%.
Schedule Pa : 402.3 Line No.: .1 Column: c
Hermton Plant is operated by Hermston Operatig Compay, L.P. an is jointly owned. Data reportd on lines 5 though 43
represent's the responden's 50.()1o sh of the Hermstn Plant. See Page 326.7 Row 14 of ths Form No. i for fuer informtion on
Hermston Generating Compan , L.P.
Schedule Pa e: 402.3 Line No.: .1 Column: d
Blundell
Allor some of the renewble energy attbuts associated with ths generation may be used in fu year to comply with state or
federal renewable portfolio stdads. For fuer inormtion regading the Blundell generating facilty, refer to Page 108, Important
Changes During the Year, Item 2, of ths Form No.1.
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da. Yr)
PacifiCorp (2) . A Resubmission 03131/209 20004
FOOTNOTE DATA
In 2007, PacifiCo added Unit 2, a 10.7 MW bottmi
Schedule Pa : 402.3 Line No.: .1 Column: e
PacifiCorp own the st tubine genertor and associate syst diry relat to the operation of ths unt at Georgia*Pacific
Corporation's Cam, Wasgtn paper mill. Modifications and upgres to the existing Cam paper mill wer necessar to supply
ste to the tubine and to ensur contiued operation of the unt in the event of mill closure. Georga-Pacific retaned ownership of
these modifications. Georgia-Pacific supplies the ful and delivers the ste to PacifiCorp's tubine. PacifiCorp is responsible for
major maintenance costs only on the repai of the tubine genertor and auxliar equipment. None of the facilties ar jointly owned.
Each asset is wholly owned, either by PacifCorp or Georga-Pacific Corpration. PacifiCorp does not have employees at the Camas
Paper Mil. ¡Schedule Page: 402.3 Line No.: .1 Column: f I
In May 2002, PacifiCorp enteed ino a 15-year operatig lease for an electc generation facilty with West Valley Leasing Company,
IFERC FORM NO.1 (ED. 12-87) Page 450.1 I
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp '2) A Resubmission 0311/2009 2008104
FOOTNOTE DATA
LLC ("West Valley"). West Valley is a subsidiar of PPM Energy, Inc. ("PPM"), whch is a direc subsidiar of PHI and an indirect
subsidiary ofScottishPower. The facilty consists of five generation units, each rate at 40 megawatt ("MW"), and is located in Uta
The lease term grted PacifiCorp two independent early ternaion options that provide PacifiCorp the right to termnate the lease
and, at PacifiCorp's fuer option, to purchase the facilty for predetrmned amounts. On May 28, 2004, PacifiCorp exercised its fit
option to termnate the West Valley lease. PacifiCorp subsequently exercised its right to rescind the termation on September 28,
2004 aftr deterning, though a public process, that the resource could not be replaced on a more economic basis and without
increasing risks to system reliabilty. PacifiCorp has a second option to termate the West Valley lease if wrttn notice is provided to
West Valley on or before December 1,2006. PacifiCorp is commtt to future minimum lease payments of$15.0 millon anually for
ears endin March 31, 2005 tho 2008 and $2.5 millon for the ear endin March 31, 2009.
hedule Pa : 402.4 Line No.: .1 Column: e
Chehal
On September 15,2008, afr having received the required reguatory approvals, PacifiCorp acquired from TNA Merchant Prject,
Inc., an affliate of Suez Energy Nort America, Inc., 100% of the equity interests of Chehais Power Generating, LLC, an entity
owning a 520-megawatt ("MW") natu gas-fired generating plan located in Chehalis, Washingn. The total cash purchae price was
$308 millon and the esimate fair value of the acquired entity wa prily allocated to the plant. Chehalis Power Generating, LLC
wa merged into PacifiCorp imediately following the acquisition. The results of the plant's operations have been included in
PacifiCorp's Financial Statements since the acquisition date.
In Febru 2009, PacifiCorp filed with the FERC under docket number AC09-41-000 a requetto clea account 102 Electc Plant
Puchased or Sold, for costs incured to acquir the 520-MW natual gas-fired Chehalis generating plant. The cost of plant on lines 13
thoug 17 on page 403.4 included in this Form No.1 for the Chehalis generating plant is blan as the costs are included in account
102 Electrc Plant Purhased or Sold at Deember 31,2008.
!Schedule Page: 402 Line No.: 36 Column: b2
Carbon
Fuel oil is used for sta-up puses.
¡Schedule Page: 402 Line No.: 36 Column: f2
Dave Johnston
Fuel oil is used for sta*uSchedule Pa e: 402.1 Column: e2
Hunter Plant Unit No.3
Fuel oil is usd for star-uSchedule Pa : 402.2 Column:b2
Huntingn
Fuel oil is used for sta-uchedule Pa : 402.2 Column: d2
Naughton
Natul gas is used for sta-up puroses.
I FERC FORM NO.1 (ED. 12-87)Page 450.2
FERC FORM NO.1 (REV. 12-()Page 40
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, 08, Yr)208104(2) DA Resubmission 0331/200 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,00 Kw or more of instaled cacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed projec, give proec number.
3. If net peak demand for 60 minutes is not available, give that which is avalabe speng period.
4. If a group of employees attends more than one generating plant, rert on line 11 the aproximate average number of employees assignabe to each
plant.
Line Item FERC Licensed Projec No.2082 FERC Licensed Project No.2082
No.Plant Name:Plant Name:
(a)(b)(ere
1 Kind of Plant (Run-of-River or Storage)Run-of-River
2 Plant Construction tye (Conventional or Outdoor)Conventional Conventional
3 Year Originally Constructed 1918 1925
4 Year Lat Unit was Installed 1922 1925
5 Total installed cap (Gen name plate Rating in MW)20.00 27.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)25 30
7 Plant Hours Connec to Load 6,3n 6,145
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions 28 34
10 (b) Under the Most Adverse Oper Conditions 28 34
11 Average Number of Employees 1 2
12 Net Generation, Exclusive of Plant Use - Kwh 97,312,00 120,286,00
13 Cost of Plant
14 Lad and Land Rights 180,375 20,914
15 Structures and Improvements 1,244,99 2,153,7n
16 Reservoirs, Dams, and Waterways 2,64,478 2,95,625
17 Equipment Costs 4,63,50 10,260,704
18 Roads, Railroads, and Bridges 105,442 240,200
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)8,807,799 15,630,220
21 Cost per KW of Installed Capacity (line 20 / 5)44.390 578.8970
22 Prouction Expnses
23 Operation Supervision and Engineering 210,140 263,473
24 Water for Power 1,252 1,691
25 Hydraulic Exenses 498 672
26 Elecric Expenses °0
27 Misc Hydraulic Power Generation Expnses 38,254 527,780
28 Rents -612 -753
29 Maintenance Supervision and Engineering °°
30 Maintenance of Structures 7,068 18,174
31 Maintenance of Reservoirs, Dams, and Waterwys 14,33 76,690
32 Mantenance of Electric Plant 32,660 55,381
33 Maintenance of Misc Hydraulic Plant 15,487 20,907
34 Total Production Expnses (total 23 thru 33)667,085 96,015
35 Exenses per net KWh 0.009 0.0080
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008104
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 03131/209
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accunts. Prouction Exnses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Repor asa separate plant any plant equipped with combinations of steam, hydro, internl combustion engine, or gas turbine equipment.
FERC Licensed Projec No. 1927
Plant Name:
FERC Licensed Project No. 1927
Plant Name:
FERC Licensed Project No. 2420
Plant Name:
Line
No.
Outdoor
1953
1953
15.00
14
8,661
0 0 3,505,129
562,143 1,269,008 3,80,64
4,776,586 10,472,776 6,669,473
1,034,775 1,331,572 14,160,572
39,142 250,151 572,059
°0 °
6,412,64 13,323,507 28,716,878
427.5097 512.4426 957.2293
113,261 209,150 174,052
12,518 21,698 1,879
63,287 109,698 77,526
0 0 0
262,697 422,499 689,34
2,624 4,549 -6
°0 °
14,972 38,448 4,338
17,319 37,024 23,30 31
16,353 53,458 4,796 32
47,409 82,66 266,43 33
550,44 979,184 1,241,623 34
0.0130 0.0226 0.0230 35
FERC FORM NO.1 (REV. 12-()Page 40
FERC FORM NO.1 (REV. 12-()Page 40.1
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)208104(2)o A Resubmission 0331/20 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,00 Kw or more of installed capacity (nae plate ratings)
2. If any plant is leased, operated under a license from the Federa Energy Regulatory Comission, or oprated as a joint facility, indicate such facts in
a footnote. If licensed project, give projec number.
3. If net peak demand for 60 minutes is not available, give that which is availabe spefyng period.
4. If a group of employees atends more than one generating plant, reprt on line 11 the approximate average number of employees assignable to each
plant.
Une Item FERC Ucense Projec No.1927 FERC Licensed Project No.20
No.Plan Nae: Plant Name:
(a)
...
(b)lêf
1 Kind of Plant (Run-of-River or Storage)Storage
2 Plant Construction type (Conventional or Outdoor)Outdor Conventional
3 Year Originally Constructed 1952 1908
4 Year Lat Unit wa Installed 1952 1923
5 Total installed cap (Gen name plate Rating in MW)11.00 33.00
6 Net Peak Demand on Plant-Megwatt (60 minutes)10 31
7 Plant Hours Connec to Load 5,153 7,169
8 Net Plant Capability (in megawatts) ,
9 (a) Under Most Favorable Oper Conditions 10 33
10 (b) Under the Most Adverse Oper Conditions 10 33
11 Average Number of Employees 1 3
12 Net Generation, Exclusive of Plant Use - Kwh 32,54,00 61,371,000
13 Cost of Plant
14 Land and Land Rights °62,169
15 Struures and Improvements 66,878 1,432,117
16 Reservirs, Dams, and Waterways 9,961,50 9,212,586
17 Equipment Costs 1,307,299 4,073,842
18 Roads, Railroads, and Bridges 472,045 65,826
19 Asset Retirement Costs °°
20 TOTAL cot (Tota of 14 thru 19)12,406,726 14,84,540
21 Cost per KW of Installed Cacity (line 20 / 5)1,127.882 449.8952
22 Prouction Expnses
23 Operation Supervsion and Engineering 104,523 165,54
24 Water for Power 9,180 2,06
25 Hydraulic Exnses 46,411 95,567
26 Elecric Expense °°
27 Misc Hydraulic Power Generation Expnses 216,871 1,390,800
28 Rents 1,924 -221
29 Maintenance Supervsion and Engineering °°
30 Maintenance of Structure 11,613 26,490
31 Maintenance of Reservoirs, Dams, and Waterwys 48,104 69,834
32 Maintenance of Elecric Plant 20,736 55,527
33 Maintenance of Misc Hydralic Plant 35,056 92,36
34 Total Proction Exnses (total 23 thru 33)494,418 1,897,976
35 Expenses per net KWh 0.0152 0.0309
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2oo8lQ4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 03131/200
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accunts prescribed by the Uniform System of Accounts. Proction Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of stea, hydro, internl combustion engine, or gas turbine equipment.
FERC Licensed Projec No. 208
Plant Name:
Line
No.
FERC Licensed Project No. 2082
Plant Name:
FERC Licensed Proec No. 1927
Plant Name:
Outdoor Outdoor Outdoor
1962 1958 1955
1962 1958 1955
18.00 97.98 31.99
18 82 32
8,613 7,019 8,59
341,706 26,277 °
4,186,46 2,403,621 781,417
12,950,361 14,538,701 9,63,46
2,212,967 14,98,346 5,93,90
1,076,116 88,710 475,419
°°0
20,767,614 32,841,655 16,824,210
1,153.7563 33.1873 525.92
240,433 468,035 255,452
1,127 6,135 26,697
448 2,440 134,971
°°0
362,073 683,410 55,43
-550 428 5,597
°°0
576,016 73,656 42,628
13,399 40,202 49,716
49,453 27,635 56,64
13,938 107,245 100,693
1,256,337 1,409,186 1,22,83
0.0100 0.0051 0.0082
Page 407.1FERC FORM NO.1 (REV. 12-0)
FERCFORM NO.1 (REV. 12-(3)Page 40.2
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2008/04(2)o A Resubmission 031311200 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed caci (name plate ratings)
2. If any plant is leased, operated under a license from the Fedral Energy Regulatory Commission, or operated as a joint facility, indicate such fact in
a footnote. If licensed project, give projec number.
3. If net peak demand for 60 minutes is not available, give that which is available specifyng period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignale to each
plant.
Line Item FERC Licesed Project No.1927 FERC Liensed Project No.93
No.Pla Name:Plant Name:
(a)(6)(cr~_(R~~1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or OUdoor)Outdor Conventional
3 Year Originally Constructed 1956 1931
4 Year Lat Unit was Installed 1956 1958
5 Tota instaled cap (Gen name plate Rating in MW)33.00 136.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)34 143
7 Plant Hours Connect to Load 8,63 8,784
8 Net Plant Capability (in megwas)
9 (a) Under Most Favorable Oper Conditions 34 151
10 (b) Under the Most Adverse Oper Conditions 34 151
11 Average Number of Employee 1 2
12 Net Generation, Exlusive of Plan Use - Kwh 153,208,00 481 ,775,00
13 Cost of Plant
14 Lad an Lad Rights °1,086,417
15 Strutures and Improvements 1,106,883 28,585,791
16 Reservoirs, Dams, and Waterways 17,780,170 9,988,622
17 Equipment Costs 2,089,025 14,557,771
18 Rods, Ralrods, and Bridges 1,649,779 2,230,484
19 Asset Retirement Costs °°
20 TOTAL cost (Total of 14 thru 19)22,625,857 56,44,085
21 Cost per KW of Instaled Capacity (line 20 / 5)685.6320 415.068
22 Prouction Expenses
23 Operation Supervision and Engineering 247,497 1,08,738
24 Water for Power 27,540 28,594
25 Hydraulic Exnses 139,232 697,709
26 Elecric Expenses °°
27 Misc Hydraulic Power Generation Expnses 54,491 1,108,886
28 Rents 5,773 2,66
29 Maintenance Supervsion and Engineering °°
30 Maintenance of Structure 49,485 11,620
31 Maintenanc of Reservoirs, Dams, and Waterys 51,236 8,932
32 Maintenance of Electric Plant 30,954 69,329
33 Maintenance of Misc Hydraulic Plant 103,616 130,903
34 Total Prouction Exnses (total 23 thru 33)1,201,824 3,144,375
35 Expenses per net KWh 0.0078 0.005
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2oo8lQ4
This ~rtls: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 03131/2009
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accunts prescribed by the Uniform System of Accunts. Producion Expnses
do not include Purchased Power, System control and Load Dispatching, and Other Expnses classified as "Other Power Supply Exenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, intemal combustion engine, or gas turbine equipment.
FERC Licensed Proect No. 1927
Plant Name:
FERC Licensed Projec No. 20
Plant Name:
FERC Licensed Project No. 263
Plant Name:
Line
No.
Conventional
1949
1950
42.50
45
8,415
Storage
Conventiona
1915
1920
30.00
19
8,783
Conventional
1928
1928
32.00
36
8,718
0 36,698 105,168
1,611,84 1,378,703 2,693,034
8,342,707 5,104,685 23,907,861
3,198,682 4,721,36 3,497,552
214,603 495,810 255,486
0 0 0
13,367,838 11,737,261 30,459,101
314.5374 391.2420 951.8469
352,475 149,613 618,34
35,468 1,879 2,00
179,314 86,879 797
0 0 0
652,918 758,142 424,90
7,43 -201 2,63
0 0 0
84,033 14,828 29,198
65,862 2,699 191,894
118,726 83,68 32,350
133,44 57,04 70,547
1,629,675 1,154,565 1,372,678
0.0074 0.033 0.0057
FERC FORM NO.1 (REV. 12-G3)Page 407.2
FERC FORM NO.1 (REV. 12-()Page 40.3
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)20004(2) 0 A Resubmission 0331/200 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Larg Plants)
1.Large plants are hydro plants of 10,00 Kw or more of instaled cacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energ Regulatory Commission, or operated as a joint facilit, indicate such facts in
a footnote. If licensed projec, give projec number.
3. If net peak demand for 60 minutes is not available, give that which is avalabe speng peri.
4. If a group of employees atends more than one generating plant, reprt on line 11 the approximate average number of employees assignable to each
plant.
Une Item FERC Licesed Project No.1927 FERC Licensed Project No.20
No.Plant Name:Plant Name:
(a)Cb)'"
,en,
(c) .
eCCe""',
1 Kind of Plant (Run-of-River or Storage)Run-o-River Storage
2 Plant Construction type (Conventional or Outdor)Outdor Conventional
3 Year Originally Construed 1951 1924
4 Year Lat Unit wa Installed 1951 1924
5 Total installed Cap (Gen name plate Rating in MW)18.00 14.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)18 9
7 Plant Hours Connect to Load 8,636 5,391
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorale Oper Conditions 18 14
10 (b) Under the Most Adverse Oper Conditions 18 14
11 Average Number of Employees 1 2
12 Net Generation, Exclusive of Plan Use - Kwh 89,523,00 14,013,00
13 Cost of Plant
14 La and Land Rights 0 512,94
15 Structures and Improvements 1,696,549 632,785
16 Reservoirs, Das, and Waterwys 5,616,215 5,575,932
17 Equipment Cots 1,341,642 2,237,155
18 Roads, Railrods, and Bridges 16,n8 0
19 Asset Retirement Cots 0 0
20 TOTAL cost (Total of 14 thru 19)8,671,184 8,958,818
21 Cost per KW of Installed Capacit (line 20 / 5)481.7324 639.9156
22 Production Expenses
23 Operation Supervsion and Engineering 140,992 74,041
24 Water for Power 15,022 8n
25 Hydraulic Exnses 75,945 40,54
26 Electric Expenses 0 0
27 Misc Hydraulic Power Generation Expnses 314,954 408,309
28 Rents 3,149 -94
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Struures 22,596 1,170
31 Maintenance of Reservoirs, Dams, and Waterwys 27,486 5,44
32 Maintenance of Elecric Plant 37,251 49,88
33 Maintenance of Misc Hydraulic Plant 56,518 26,027
34 Total Prouction Expnses (total 23 thru 33)693,913 60,202
35 Expnses per net KWh 0.0078 0.04
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2008/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 03131/2009
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accunts or combinations of accounts prescribe by the Uniform System of Accounts. Prouction Exenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expnses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internl combustion engine, or ga turbine equipment.
FERC Licensed Proec No. 2111
Plant Name:
Line
No.
FERC Licensed Project No. 1927
Plant Name:
FERC Licensed Project No. 2071
Plant Name:
e
Storage (Re-Reg)
Outdoor
1952
1952
11.00
12
8,639
Storage
Conventiona
1958
1958
240.00
241
5,385
Storage
Conventional
1953
1953
134.00
163
5,63
°7,813,808 2,n6,917
992,188 6,739,442 6,690,408
12,94,250 37,681,672 26,569,133
2,190,182 15,863,441 14,n1,180
56,124 395,145 1,395,512
°°°
16,178,744 68,493,508 52,203,150
1,470.7949 285.389 38.5757
116,40 1,894,038 1,054,934
9,180 50,461 28,174
46,411 1,401,714 687,44
°°°
287,178 1,349,269 912,601
1,924 90,487 2,759
°°°
34,680 19,588 13,123
41,499 9,206 31,211
10,030 172,917 71,085
34,787 209,628 129,33
582,093 5,197,308 2,930,667
0.0103 0.0088 0.0054
Page 407.3FERC FORM NO.1 (REV. 12-0)
FERC FORM NO.1 (REV. 12-()Page 40.4
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2008/Q4
(2) D A Resubmission 0331/200 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,00 Kw or more of installed capacity (nae plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operted as a joint facility, indicate such facts in
a footnote. If licensed project, give projec number.
3. If net peak demand for 60 minutes is not avalable, give that which is available speifying period.
4. If a group of employees atends more than one generating plant, report on line 11 the approximate average number of employees assignabe to each
plant.
Une Item FERC Licensed Project No.0 FERC Licensed Projec No.0
No.Plan Name:Plant Name:
Cal (6l (cl
1 Kind of Plant (Run-of-River or Storage)Run-of-River
2 Plant Construion type (Conventional or Outdor)Conventional
3 Year Originally Constructed 190
4 Year Lat Unit was Installed 1922
5 Total installed ca (Gen name plate Rating in MW)10.30 0.00
6 Net Peak Demand on Plant-Megawatt (60 minutes)8 0
7 Plant Hours Connect to Load 6,332 0
8 Net Plant Capabilit (in megwatts)
9 (a) Under Most Favorable Oper Conditions 10 0
10 (b) Under the Most Adverse Oper Conditions 10 0
11 Average Number of Employees 4 0
12 Net Generation, Exclusive of Plant Use - Kwh 18,229,00 0
13 Cost of Plant
14 La an Land Rights 0 0
15 Structures and Improvements 267,100 0
16 Reservoirs, Dams, and Waterways 529,217 0
17 Equipment Costs 31,914 0
18 Roads, Railroads, and Bridges 12,641 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)84,872 0
21 Cost per KW of Installed Capacity (line 20 / 5)81.631 0.~~
22 Prouction Expenses
23 Operation Supervsion and Engineering 59,738 0
24 Water for Power 645 0
25 Hydraulic Exnses 26,617 0
26 Elecric Expenses 0 0
27 Misc Hydraulic Power Generation Expenses 316,115 0
28 Rents -22 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 1,451 0
31 Maintenance of Reservirs, Dams, and Waterwys 13,162 0
32 Maintenance of Elecric Plant 63,246 0
33 Maintenance of Misc Hydraulic Plant 91,85 0
34 Total Proction Expnses (total 23 thru 33)572,808 0
35 Expes per net KWh 0.0314 0.~~
............................................
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 03131/200
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accunts or combinations of accunts prescribed by the Uniform System of Accunts. Proion Expenses
do not include Purchased Power, System control and Load Dispaching, and Other Expenses classified as "Other Power Supply Expnses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internl combustion engine, or gas turbine equipment.
Year/Period of Report
End of 2oo8lQ4
FERC Licensed Project No.
Plant Name:
o Line
No.
d
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
o o
(e
0.00
o
o
0.00
o
o
0.00
o
o
FERC FORM NO.1 (REV. 12"(3)
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0.~~0.0000 0.0000
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0.~~0.~~0.~~
Page 407.4
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 200/04
FOOTNOTE DATA
¡Schedule Page: 406 Line No.: -1 Column: b
CopcoNo.l
Al or some of the renewable energy atbutes associated with ths generation may be used in futue yeas to comply with state or
federa renewable portolio stadads.
¡Schedule Page: 406 Line No.: -1 Column: c
CopcNo.2
Al or some of the renewable energy atbutes associat with ths generation may be used in futue year to comply with state or
federal renewable ortolio stadads.
chedule Pa e: 406 Line No.: -1 Column: d
Costs report for ths plant do not include signcant intagible costs due to relicensing and settement which are recorded in FEC
account 302 Frachises and Consents and ar not report on th page. The net book value for relicensing and settement on the
Nort Umpua River system for the followig projects at Deembr 31, 200 was $67,519,056: Lemolo 1, Lemolo 2, Clearater 1,
Clearater 2, Tokete, Fish Crek, Sod S ri s, Slide Creek and the Nort U ua Commn Plant.
Schedule Pa e: 406 Line No.: -1 Column: e
Costs report for th plant do not include signcant intagible costs due to relicensing and settement which are recorded in FERC
account 302 Frachises and Consents and are not report on ths page. The net book value for relicensing and settement on the
Nort Umpqua River system for the followig projects at December 31, 200 was $67,519,056: Lemolo 1, Lemolo 2, Clearater 1,
Clearater 2, Tokete, Fish Creek, Soda S ri s, Slide Creek and the Nort U ua Commn Plat.
Schedule Pa e: 406 Line No.: -1 Column: f
Costs reported for this plant do not include significant intgible costs due to relicensin9 which are charged to FERC
account 302 and are not re rted on this a e. The net bok value for relicensin at December 31, 2003 was $1,473,452.
Schedule Pa e: 406 Line No.: 1 Column: b
Pondage for peaking- - storage, Upper Klamath Lake
I$hedule Page: 406 Line No.: 1 Column: d
Forebay for peaking.
I$hedule Page: 406 Line No.: 1 Column: e
Forebay for peaking.
¡Schedule Page: 406.1 Line No.: -1 Column: b
Costs report for ths plant do not include signcant intagible costs due to relicensing and settement which are recorded in FERC
account 302 Franchises and Consents and are not report on ths page. The net book value for relicensing and settement on the
Nort Umpua River system for the followig projects at December 31, 200 was $67,519,056: Lemolo 1, Lemolo 2, Clearater 1,
Cleaater 2, Toketee, Fish Crek, Soda S ri s, Slide Crek and the Nort U ua Commn Plat.
Schedule Pa e: 406.1 Line No.: -1 Column: c
Costs report for ths plant do not include signcant intagible costs due to relicensing and settement whch ar recorded in FERC
account 302 Frachises and Consents and ar not repor on ths page. The net bok value for relicensing and settement on the Bea
River s stem for the followi ro'ects at Decmbr 31, 200 was $16,940,164: Gre, Cove, Oneida and Sod.
Schedule Pa e: 40.1 Line No.: -1 Column: d
Iron Gate
Allor some of the renewable energy atbutes associate with ths generation may be used in futu yeas to comply with state or
federa renewable rtolio stadads.
chedule Pa e: 40.1 Line No.: -1 Column: e
JCBoyie
Allor some of the renewable energy atbutes associat with upgres to ths generation may be used in futue year to comply with
state or federa renewable ortolio stadads.
Schedule Pa : 406.1 Line No.: -1 Column: f
Costs report for th plant do not include signcant intagible costs due to relicensing and settement which are reorded in FEC
account 302 Frachises and Consents and ar not report on ths page. The net bok value for relicensing and settement on the
Nort Umpua River system for the followig projects at Demb 31, 200 was $67,519,056: Lemolo 1, Lemolo 2, Clearter 1,
Clearater 2, Tokete, Fish Crek, Soda S ri s, Slide Crek and the Nort U ua Commn Plant.
Schedule Pa e: 406.1 Line No.: 1 Column: b
Forebay for peaking.
¡Schedule Page: 406.1 Line No.: 1 Column: d
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/200 208104
FOOTNOTE DATA
Storage for regulation.
¡Schedule Page: 406.1 Line No.: 1 Column: e
Pondage for peaking - stora e, U per Klamath Lake.
Schedule Pa : 406.1 Line No.: 1 Column: f
Stora e, Lemolo Lake.
Schedule Pa e: 406.2 Line No.: -1 Column: b
Costs report for ths plant do not include signcant intagible costs due to relicensing and settement which ar reorded in PERC
account 302 Frachises and Consents and are not reportd on ths page. The net book value for relicensing and settement on the
Nort Umpqua River system for the followig projects at December 31, 200 was $67,519,056: Lemolo 1, Lemolo 2, Clearater 1,
Cleaater 2, Toketee, Fish Crek, Sod S ri s, Slide Creek and the Nort Urn ua Common Plant.
Schedule Pa e: 406.2 Line No.: -1 Column: c
Merwn
Costs reprt for ths plant do not include signifcant intagible costs due to relicensing, and settement which ar reorded in PERC
account 302, Frachises and Consents, and are not reported on ths page. The net book value for relicensing and settement on th
Lewis River s stem for the followi ro'ects at December 31, 2007 was $429 thusand: Merw, Yale, and Swi #1.
Schedule Pa e: 406.2 Line No.: -1 Column: d
Costs report for ths plant do not include signcant intagible costs due to relicensing and settement which ar reorded in PERC
account 302 Franchises and Consents and are not reportd on ths page. The net book value for relicensing and settement on the
Nort Umpqua River system for the following projects at Decembr 31,200 was $67,519,056: Lemolo 1, Lemolo 2, Cleaater 1,
Cleaater 2, Toketee, Fish Creek, Soda S ri s, Slide Crek and the Nort U ua Common Plant.
Schedule Pa e: 406.2 Line No.: -1 Column: e
Costs report for ths plant do not include signicant intagible costs due to relicensing and settement which are reorded in PERC
account 302 Frchises and Consents and are not report on ths page. The net bok value for relicensing and settement on the Bea
River s stem for the followin ro.ects at December 31, 200 was $16,940,164: Grace, Cove, Oneida and Soda.
hedule Pa e: 406.2 Line No.: -1 Column: f
Prospec No.2
Al or some of the renewable energy attbutes assoiated with ths generation may be used in futue yea to comply with state or
federa renewable ortolio stadads.
chedule Pa e: 406.2 Line No.: 1 Column: b
Stora e, Lemolo Lae.
Schedule Pa e: 406.2 Line No.: 1 Column: d
Pondage for peaking - storage, Lemolo Lake.
¡Schedule Page: 40.2 Line No.: 1 Column: f
Forebay for peaking.
¡Schedule Page: 406.3 Line No.: -1 Column: b
Costs report for ths plant do not include signcant intagible costs due to relicensing and settement whch ar reorded in PERC
account 302 Frachises and Consents and ar not report on ths page. The net bok value for relicensing and settement on the
Nort Umpqua River system for the followig projects at December 31, 200 was $67,519,056: Lemolo 1, Lemolo 2, Clearter 1,
Cleaater 2, Toketee, Fish Creek, Sod S rigs, Slide Crek and the Nort U ua Common Plant.
Schedule Pa e: 406.3 Line No.: -1 Column: c
Costs report for ths plant do not include signifcant intagible costs due to relicensing and settement which are recorded in PEC
account 302 Frachises and Consents and are not reported on ths page. The net book value for relicensing and settement on the Bea
River system for the followin ro' ects at Decembr 31, 200 was $16,940,164: Grace, Cove, Oneida and Soda.
Scheule Pa : 406.3 Line No.: -1 Column: d
Costs report for ths plant do not include signifcant intagible costs due to relicensing and settement whch ar recrded in PEC
account 302 Frachises and Consents and are not report on ths page. The net book value for relicensing and settement on the
Nort Umpqua River system for the followig projects at Deember 31, 200 was $67,519,056: Lemolo 1, Lemolo 2, Clearter 1,
Clearater 2, Toketee, Fish Creek, Sod S ri s, Slide Creek and the Nort U ua Commn Plant.
Schedule Pa e: 406.3 Line No.: -1 Column: e
Swi #1
Costs report for ths plant do not include signifcant intagible costs due to relicensing, and settement which ar recorded in PERC
account 302, Frachises and Consents, and ar not report on ths page. The net book value for relicensing and settement on the
Lewis River system for th followig projects at Decembr 31, 2007 was $429 thousand: Merw, Yale, and Swi #1.
(FRC FORM NO.1 (ED. 12-87) Page 450.2
Page 450.3
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0313112009 200/04
FOOTNOTE DATA
¡Schedule Page: 406.3 Line No.: -1 Column: f
Yale
Costs report for ths plant do not include signcant intagible costs due to relicensing, and settement which ar recorded in FERC
account 302, Frachises and Consents, and ar not report on ths page. The net book value for relicensing and settement on the
Lewis River s stem for the followi ro'ects at Deemb 31, 200 was $429 thousand: Merw, Yale, and Swi #1.
Schedule Pa e: 406.4 Line No.: -1 Column: b
Olmstead Plant is owned by the U.S. Bureau of Land Reclamation. PacifiCorp has a 25 year lease beginning in 1990.
The respondent operates the plant and owns the generation.
IFERC FORM NO.1 (ED. 12-87)
.............................................
Blank Page
(Next Page is 410)
Year/Period of Report
End of 20004 ............................................
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) I.An Original (Mo, Da, Yr)
(2) A Resubmission 0331/2009
G NERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25,00 Kw; intemal combustion and ga turbne-plans, conventional hydro plants and pumped
storage plans of less than 10,00 Kw installed capaciy (name plate raing). 2. Designate any plant leased from oters, operated under a licnse fro
the Federal Energy Regulatory Commission, or operated as a joint facilty, and give a concise statement of the facts in a footnote. If licensed projec,
give project number in footnote.
Une Net Generation Cost of PlantName of Plant ExcludingNo.Plant Use
(e)(f)
1917 6.85 8,820,231
1913 1.11 930,840
1910 4.15 7,135,399
1913 1.00 338,868
1913 13.70 15.6,932,747
1957 2.81 2.1,791,40
1924 3.20 3.0 1,976,602
190 2.20 2.0 1,215,36
1922 0.16 0.1 46,080
1896 2.00 1.2 4,957,527
1917 0.75 0.6 63,418
198 1.73 O.2,90,421
1910 0.72 0.7 327,935
1897 5.00 4.0 11,089,922
1923 6.00 725,996
1912 3.76 4.6 96,670
1932 7.20 7.7 6,955,542
194 1.00 0.9 356,987
1926 0.80 0.5 86,63
1910 1.18 1.0 950,757
1895 1.00 1.2 1,609,662
1915 0.50 1,337,279
1920 0.50 0.3 748,404
198 0.74 0.6 1,169,596
1921 1.10 1.0 2,821,770
1911 3.85 2.0 2,791,674
190 0.60 0.6 372,83
7,497,523
5,062,891
13,80,218
1917 -4.50 -3,261 16,508,20-3.0
199 32.62 32.0 36,976,588
20 99.00 199,426,1992094.00 56.0 183,939,586
20 100.50 100.5 172,416,795
207 140.40 140.238,896,531
208 70.20 70.0 125,100,0492099.00 192,90,480
208 19.50 41,391,245
FERC FORM NO.1 (REV. 12-()Page 410
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ri A Resubmission 03131/209
GENERATING PLANT STATISTICS (Small Plants) (Continued
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifing period.5. If any plant is equipped with
combinations of steam, hydro intemal combustion or ga turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilzed in a stea turbne regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset Operatio t'ctlon expenses Fuel Costs (in cents LineRetire. Costs) Per MW Exc'i. Fuel Fuer Maintenance Kind of Fuel (per Milion Btu)
(g)(h)(i)0)(k)(i)
No.
1
1,287,625 407,176 86,715 Water 2
838,595 83,025 83,706 Water 3
1,719,373 356,341 119,167 Water 4
338,868 5,145 780 Water 5
506,04 402,06 59,390 Water 6
637,510 242,493 51,275 Water 7
617,688 142,213 47,054 Water 8
552,43 87,709 49,968 Water 9
2,90,500 19,998 26,377 Water .0
2,478,764 116,63 44,664 Water 11
847,224 63,219 49,216 Water 12
1,676,54 134,876 86,796 Water 13
455,465 48,515 38,861 Water 14
2,217,984 280,862 73,927 Water 15
120,999 203,399 11,385 Water 16
257,891 198,96 88,826 Water 17
96,048 339,131 109,291 Water 18
356,987 79,33 19,898 Water 19
1,075,793 59,178 94,455 Water 2)
805,726 87,182 19,780 Water 21
1,609,662 99,926 14,442 Water 22
2,674,558 64,579 5,112 Water 23
1,496,808 84,06 110,791 Water 24
1,580,535 21,918 14,062 Water 25
2,565,245 84,084 386 Water 26
725,110 208,250 51,910 Water 27
621,392 20,84 18,749 Water 28
4,584 17,274 29
210,717 39,412 30
31
32
33
-3,66,490 236,119 81,447 Water 34
~
36
1,133,556 2,071,010 Wind 37
2,014,40 91,715 Wind 38
1,881,542 Wind 39
1,715,590 3,576,738 Wind 40
1,701,542 4,396,346 Wind 41
1,782,052 1,039,65 Wind 42
1,948,53 52,54 Wind 43
2,122,628 17,86 Wind 44
4!
46
............................................FERC FORM NO.1 (REV. 12-()Page 411
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp i (2) A Resubmission 0313112009 20004
FOOTNOTE DATA
¡Schedule Page: 410 Line No.: 1 Column: a
Common river s stem costs for the 0 eration of these facilties are allocated to each
Schedule Pa : 410 Line No.: 2 Column: a
Ashton
Allor some of the renewable energy attbutes associatd with ths genertion may be (i) used in fue year to comply with state or
federal renewable portolio stadards or other reguatory requirments or (ii) sold to thrd paries in the form of renewable energ
credits or other environmental commodities.
Costs reported for this plan do not include signfica intable co due to relicein which are recorded in FERC account 302,
Franchises and Consents, and ar not ortd on ths e. The ne bok value for relicein at December 31, 2008 was $356,483.
Schedule Pa e: 410 Line No.: 3 Column: a
Bend
Allor some of the renewable energy attbuts associate with ths generation may be (i) us in futue year to comply with state or
federal renewable portolio stdards or other reguatory reuiments or (ii) sold to thrd paries in the form of renewable energy
credits or other environmental commodities.
Costs reported for this plan do not include signficat intable cost due to relicensing whch are recorded in FERC account 302,
Frachises and Consents, and are not l' ortd on ths e. The net bok value for relicensin at December 31,2008 was $230,098.
Schedule Pa e: 410 Line No.: 4 Coumn: a
BigFork
Allor some of the renewable ener attbuts assoiat with ths generion may be (i) used in fu years to comply with state or
federal renewable portolio stdads or other regulatory reuiment or (ii) sold to thrd paries in the form of renewable energy
credits or other environmenta commodities.
Costs report for this plant do not include signfica intagible cost due to reliceing whch are recorded in FERC account 302,
Frachises and Consents, and are not re ortd on ths e. The net book value for relicensin at December 31,2008 was $560,499.
Schedule Pa e: 410 Line No.: 5 Column: a
Cline Fals
Allor some of the renewable energy attbutes associate with this generation may be (i) used in fue year to comply with state or
federal renewable portfolio stdards or other regulatory requirements or (ii) sold to thd paries in the form of renewale energy
credits or other environmenta commodities.
¡Schedule Page: 410 Line No.: 6 Column: a
Condit
In September 1999, a settlement agreeent to remove the 14-MW Condit hydrelecc failty wa signed by PacifiCorp, stte and
federal agencies and non-goverenta orgations. Under th origi selement agreeent, reoval wa expected to begi in
Octber 2006, with a total cost to decmmssion not to exce $17 millon, excluding ination. in early Febru 2005, the paries
agee to modify the settlement agrement so tht reoval would not begi until Octbe 2008, with a total cost to decommssion not
to exced $21 millon, excluding inflation. The selement ageement is contingent upon receiving a FERC surnder order and other
regulatory approvals tht ar not materially inconsistent with the amended settlement ageeent. PacifiCorp is in the process of
acquiring all necessa perts within the ter and conditions of the amended settlement agrement. Given the ongoing permttng
process and the time needed for system removal and to evaluate impac on naturl resources, decommssioning is now expected to
begin in Ocber 2010. in March 2008, the United Sta Ary Corps of Engineers reuesed PacifiCorp complete an additional study
of expected decommssionig impac on aquatic resource. Th stdy work is complet and results have been provided to the Unite
States Ary Corps of Engineers and the Washington Deparent of Ecology. Absent fuer inormtion requests, the Washigton
Deparent of Ecology is expected to complete the Clea Water Act 401 ceification process durng 2009. Remag permtting
includes a 404 ermt from the United States Ar Co s of En ineers and a surnder order from the FERC.
Schedule Pa e: 410 Line No.: 7 Column: a
Eale Point
Allor some of th renewable energy attbuts assoiat with ths generation may be (i) used in futu year to comply with state or
federal renewable portolio stadads or other regulatory requiments or (ii) sold to thd paries in the form of renewable energ
credts or other envronmenta commodities.
¡Schedule Page: 410 Line No.: 8 Column: a
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03131/2009 20004
FOOTNOTE DATA
Eatside
Allor some of the renewable energy atbuts associated with ths generation may be (i) used in fue years to comply with state or
federal renewable portfolio standards or other reguatory requirements or (ii) sold to thd paies in the form of renewable energ
credits or other environmenta commodities.
¡Schedule Page: 410 Line No.: 9 Column: a
Fal Creek
Allor some of the renewable energy attbuts associated with ths generation may be (i) used in futu year to comply with state or
federal renewable portolio stadads or other regulatory requirements or (ii) sold to thrd paries in the form of renewable energ
credits or other environmental commodities.
jShedule Page: 410 Line No.: 10 Column: a
Fountan Green
Allor some of the renewable energy attbutes associated with ths genertion may be (i) used in fu y::ar to comply with state or
federal renewable portolio stadards or other reguatory requirements or (ii) sold to third paries in the form of renewable energy
credits or other environmental commdities.
Costs reported for ths plan do not include signficat intangible cost due to relicensing which are recorded in FERC aecunt 302,
Frachises and Consnts, and are not re ortd on this a e. The net book value for relicensin at December 31, 2008 was $5,182.
Schedule Pa e: 410 Line No.: 11 Column: a
Grante
Allor some of the renewable energy attbuts associatd with ths generation may be (i) used in futue year to comply with state or
federa renewable portfolio stadads or other reguatory reuirements or (ii) sold to thrd paries in the form of renewable energy
crits or other environmenta commodities.
!Schedule Page: 410 Line No.: 12 Column: aGunloc
Allor some of the renewable energy attbutes associated with this generation may be (i) used in fu yea to comply with stte or
federa renewable portolio stadards or other reguatory requirements or (ii) sold to thrd paries in the form of renewable energy
credits or other environmenta commodities.
Costs report for ths plan do not include signficant intagible costs due to relicensing whch are recorded in FERC account 302,
Frachises and Consents, and ar not re ortd on this e. The net book value for relicensin at December 31, 2008 wa $48,556.
Schedule Pa e: 410 Line No.: 13 Column: aLaCbace
Allor some of the reewable energy attbutes associated with this generation may be (i) used in fue year to comply with stte or
federal reewable portolio stadads or other regulatory requiement or (ii) sold to third paries in the form of reewable energy
credits or other envionmental commodities.
¡Schedule Page: 410 Line No.: 14 Column: a
Pari
Allor some of the renewable energy attbuts associated with this generation may be (i) used in fu year to comply with stte or
federal renewable portolio stadads or other regulatory requirents or (ii) sold to thrd paries in the form of renewable energy
credits or other environmenta commodities.
¡Schedule Page: 410 Line No.: 15 Column: a
Pineer
Allor some of the renewable energy attbuts associatd with this generation may be (i) used in fue yc:ar to comply with stte or
feder renewable portolio stadads or other reguatory requiments or (ii) sold to thrd paries in the form of renewable energy
credits or other envonmenta commodities.
Costs report for ths plant do not include significant intable costs due to relicening whch are recorded in FERC account 302,
Frachises and Consent, and are not re ortd on ths e. The net book value for relicensin at Deceber 31, 2008 was $120,435.
chedule Pa e: 410 Line No.: 16 Column: a
Powerde
In Jun 2003, PacifiCorp entered into a selement agreement to remove the 6-MW Powerdale plat rather th purue a new licen,
bas on an anlysis of the costs and benefits of relicensing verus decmmssioning. Removal of the Pow~rdale da and asiated
systm featus, which is subject to the FERC and other reguatry approvals, is project to cost $6 million, excluding infation.
I FERC FORM NO.1 (ED. 12-87) Page 45.2
IFERC FORM NO.1 (ED. 12-87) Page 45.3
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 031/2009 20004
FOOTNOTE DATA
Plant shut down and removal wa scheduled to commence in 2010. However, in November 2006, flooding daged the Powerdale
plant and rendered its generating caabilties inoperble. In Febr 2007, the FERC grted PacifiCorp's request to cease
generation at the plant; however, removal is stll scheduled for 2010. Also in Febru 2007, PacifiCorp submitted a request to the
FERC to allow PacifiCorp to defer the remainig net book value and any additional removal costs of ths system as a reguatory asset.
In May 2007, the FERC issued an order that approved PacifiCorp's proposed accountig entres, thereby allowing PacifiCorp to
reclassify the net book value and the estimated reoval cost to a reguatory asset. PacifiCorp has received approval from its stte
regulatory commssions to defer an reover these costs.
ISchedule Page: 410 Line No.: 17 Column: a
Prspect 1
Allor some of the renewable energy attbutes associated with ths generaton may be (i) used in futu yeas to comply with state or
federal renewable portfolio stadads or other regulatory reuiment or (ii) sold to thrd paries in the form of renewable energy
credits or other environmental commodities.
Costs reported for this plant do not include signfica intable cost due to relicening whch are recorded in FERC account 302,
Franchises and Consents, and are not reportd on ths pae. The net bok value for relicensing at Prospect unts 1,2, and 4 on
December 31,2008 wa $6,631,099.
¡Shedule Page: 410 Line No.: 18 Column: a
Prspect 3
Allor some of the renewable energy atbutes associated with ths genertion may be (i) used in fue year to comply with state or
federal renewable portfolio stadads or other reguatory requiment or (ii) sold to thrd paries in the form of renewble energy
credits or other environmental commodities.
Costs reportd for this plant do not include signfica intable cost due to relicenin whch are recorded in FERC account 302,
Franchises and Consents, and are not reortd on ths page. The net bok value for reliceing at Prospect unt number 3 on December
31,2008 wa $98,015.
¡Schedule Page: 410 Line No.: 19 Column: a
Prospect 4
Allor some of the renewable energy attbuts assoiated with ths generion may be (i) usd in fue yea to comply with state or
federal renewable portfolio stadards or other regulatory requiment or (ii) sold to thrd paries in the form of renewable energy
credits or other environmental commodities.
Costs reportd for this plant do not include significant intagible costs due to relicensing whch are recorded in FERC account 302,
Frachises and Consents, and are not reportd on ths page. The net book value for relicensing at Prospect units 1, 2, and 4 on
Decmber 31, 2008 was $6,631,099.
~hedule Page: 410 Line No.: 20 Column: a
Sad Cove
Allor some of the renewable energy attbutes associated with ths genertion may be (i) used in futue year to comply with state or
federa renewable portolio stadards or other reguatory reuiements or (ii) sold to thrd paries in the form of renewable energy
credits or other environmental commodities.
¡Schedule Page: 410 Line No.: 21 Column: a
Snake Crek
Allor some of the renewable energy attbuts assoiate with this generation may be (i) used in futue years to comply with state or
federl renewable portfolio stadards or other reguatory reuirements or (ii) sold to thd paries in the form of renewable energy
credits or other envionmntal commodities.
~hedule Page: 410 Line No.: 22 Column: a
Stars
Allor some of the renewable energy attbuts assoiat with ths generion may be (i) us in futue year to comply with stte or
federal renewable portolio stadards or other reguatory requirements or (ii) sold to thrd paies in the form of renewble energy
credits or other environmental commodities.
Costs reprtd for ths plan do not include signficant intable cost due to relicening which are recorded in FERC accoun 302,
Frachises and Consents, and ar not reortd on ths page. The net bok value for relicensing at December 31, 2008 was $94,537.
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp (2) . A Resubmission 0311/2009 2004
FOOTNOTE DATA
¡Schedule Page: 410 Line No.: 23 Column: a
St.Anthony
Licensed Project No. 2381 applicable to both Ashton and St. Anthony plants.
Allor some of the renewable energy attbuts associated with this generation may be (i) used in futue yea to comply with state or
federa renewable portolio stdads or other regulatory requirements or (ii) sold to third paes in the form of renewable energy
credits or other environmenta commodities.
¡Schedule Page: 410 Line No.: 24 Column: a
Veyo
All. or some of the renewable energy attbuts associated with this generation may be (i) used in futue yea to comply with stte or
feder renewable portfolio stdads or other regulatory requiremen or (ii) sold to third pares in the form of renewable energy
credits or other envionmenta commodities.
¡Schedule Page: 410 Line No.: 25 Column: a
Viva Naughton
Allor some of the renewable energy attbuts associated with this generation may be (i) used in futu year to comply with stte or
federa renewable portolio stadads or other reguatory requirements or (ii) sold to thd pares in the form of renewable energy
credits or other envionmental commodities.
¡Schedule Page: 410 Line No.: 26 Column: a
Walowa Falls
Allor some of the renewable energy attbutes associated with this generation may be (i) used in futue year to comply with stae or
federl renewable portolio stadards or other reguatory requiements or (ii) sold to third paries in the form of renewable energy
credts or other envionmenta commodities.
¡Schedule Page: 410 Line No.: 27 Column: a
Weber
Allor some of the renewable energy attbutes associated with ths generion DIy be (i) used in futu yea to comply with state or
federal renewable portfolio stadads or other reguatory requirements or (ii) sold to third paies in the form of renewable energy
credits or other envionmental commodities.
Costs reportd for ths plan do not include significat intable costs due to relicensing which are recorded in FERC account 302,
Franchises and Consents, and are not re ortd on this a e. The net book value for relicensin at December 31 2008 was $352,427.
hedule Pa e: 410 Line No.: 28 Column: a
WestSide
Allor some of the renewable energy atbuts associated with this generation may be (i) used in futue year to comply with stte or
federal renewable portolio stadards or other reguatory requirements or (ii) sold to third paries in the form of renewable energy
credts or other envionmental commodities.
¡Schedule Page: 410 Line No.: 29 Column: a
Keno Reguating Dam
Used in reguating the release of water from Klamth Lae an in matanig proper water surce level in the Klamth River between
Klamth Falls and Keno, Oregon.
¡Schedule Page: 410 Line No.: 30 Column: a
Upper Klth Lake
Storage reservoir for six plants on the Klamath River (Copco No.1, Copco No.2, East Side, West Side, John C. Boyle, and Iron
Gate).
¡Schedule Page: 410 Line No.: 31 Column: a
North Umpqua
Common plant in Nort Umpqua Projec. All common roads, employee houses, control equipment, etc. are in ths accoun
Costs report for ths plant do not include signficant intaible cost due to relicensing and seement which are recorded in FERC
account 302, Frachises and Consents, and are not reported on ths page. The net book value for relicensing and seement on the
Nort Umpqua River syst for the followig project at Deember 31, 2008 wa $68,917,344: Lemolo 1, Lemolo 2, Cleater 1,
Cleater 2, Toketee, Fish Creek, Soda S rin s, Slide Crk and the Nort U ua Common PlanL
chedule Pa e: 410 Line No.: 37 Column: a
Foote Crek
IFERCFORM NO.1 (ED. 12-S7) Page 450.4
Page 450.5
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0311/2009 200104
FOOTNOTE DATA
The Foote Creek Wind Far is operted by SeaWest Energy and is jointly owned. Cost reported for this plant represents the
respondents share. Owership of the plant is as follows: PacifiCorp 78.79%, Eugene Water and Electic Board 21.21 %.
Allor some of the renewable energy attbutes associated with ths generation may be (i) used in futue year to comply with state or
federl renewable portolio stadads or other regulatory reuirements or (ii) sold to thd paries in the form of renewable energy
credits or other environmental commodities.
!Shedule Page: 410 Line No.: 38 Column: a
Glenrock
Allor some of the renewble energy attbuts assoiate with ths genertion may be (i) used in fue years to comply with state or
federal renewable portolio stadads or other reguatory reui or (ii) sold to thd paes in the form of renewable energy
credits or other envionmenta commodties.
¡SChedule Page: 410 Line No.: 39 Column: a
Goodnoe Hil
Allor some of the renewable energy attbuts assoiatd with ths generation may be (i) used in futue year to comply with stte or
federa reewable portolio stadads or other reguatory reuiement or (ii) sold to third paies in the form of renewable energy
credits or other envonmenta commodities.¡SChedule Page: 410 Line No.: 39 Column: h I
The credit balance for the Goodnoe Hills wid plant includes both fuds received from the Energy Trust of Oregon to offset operations
and mantenace costs and credits from the BPA for renewble energy.
¡SChedule Page: 410 Line No.: 40 Column: B
Leaning Juniper #1
Allor some of the renewable energy attbut assoiat with ths geeration may be (i) us in futu yea to comply with state or
federa renewable portfolio stdas or other reguatory reuien or (ii) sold to thd paries in the form of renewable energy
credits or other envionmental commodties.
¡SChedule Page: 410 Line No.: 41 Column: a
__Marengo I
Allor some of the renewable energy attbuts associatd with ths generation may be (i) used in futue yea to comply with state or
federal renewable portfolio stadads or other reguatory reuiements or (ii) sold to thrd paries in the form of renewable energy
credits or other environmental commodities.
¡SChedule Page: 410 Line No.: 42 Column: a
Marengo II
Allor some of the renewable energy atbutes assoiat with ths generation may be (i) used in futue yea to comply with stte or
federl renewable portolio stdads or other reguatry reuien or (ii) sold to thd pares in the form of renewable energy
credits or other envionmenta commities.
¡SChedule Page: 410 Line No.: 43 Column: a
Seven Mile Hil
Allor some of the renewable energy attbutes assoiat with ths geeration may be (i) used in futue year to comply with state or
federal reewable portfolio stadads or other reguatory requients or (ii) sold to thd paries in the form of renewable energy
credts or other envionmenta commodities.
¡SChedule Page: 410 Line No.: 44 Column: a
Seven Mile Hi II
Allor some of the renewable energy attbutes associated with ths generation may be (i) used in futue year to comply with state or
federal reewable portfolio stdads or other reguatory requiement or (ii) sold to thd pares in the form of renewable energy
credits or other environmenta commodities.
IFERC FORM NO.1 (ED. 12-87)
............................................
Blank Page
(Next Page is 422)
FERC FORM NO.1 (ED. 12-8 Page 422
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) DA Resubmission 03111200
TRANSMISSION LINE STATIST CS
1. Report information conceming transmission lines, cost of Iines, and expenses for year. List eah trasmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voge.
2. Transmission lines include all lines covere by the definition of transmission system plan as given in the Uniform Sysem of Accunts.Do not report
substation costs and expnses on this page.
3. Report data by individual lines for all voltages if so reuired by a State commission.
4. Exclude from this page any transmission lines for which plant cos are include in Accunt 121, Nonutilty Property.
5. Indicate whether the typ of supporting structure reported in column (e) is: (1) single pole woo or steel; (2) H-frame woo, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of constrution
by the use of brackets and extra lines. Minor portions of a transmission line of a diferent type of construction need not be distinguished fro the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cot of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned struures in coumn (g). In a foote, explain the bais of such occupancy and state whether expenses with
respet to such structures are included in the expnses reported for the line deignated.
LE~GJ'~ ~ie óViles)Line vni
Typ of (Indicae w/ere NumberNo.other th u Wergrounìfiines Of60 cvle 3 ohae)Supporting report circuit miles)
From To I un ~l!Vclure unfA:;li~res CircuitsOperatingDesignedStructureD of.Lln:ed Of'tot er
(a)(b)(c)(e)es'8la ne
(d)(g)(h)
1 Malin, OR Indian Springs, CA 500.OC 500.00 Steel Tower 47.00 1
2 Midpoint, ID Malin, OR 500.OC 500.00 Steel Tower 446.00 1
3 Malin,OR Medord, OR 500.OC 500.00 Steel Tower 84.00 1-Dixonville Sub, OR 500.OC 500.00 Steel Tower 58.00 1
5 Malin, OR Captan Jack, OR 5O.OC 50.00 Stee Tower 7.00 1
6 Meridian, OR 5O.OC 50.00 Stee Tower 74.00 1
7 Switchyar, MT 5O.OC 50.00 Stee Towr 1.00 1
8 Brodvew A, MT 5O.OC 50.00 Stee Tower 112.00 1
9 Broadvew B, MT 500.OC 500.00 Stee Tower 116.00 1
10 Townsend A, MT 500.OC 50.00 Stee Tower 133.00 1-!Townsend B, MT 5OO.OC 500.00 St Tower 133.00 1
12 500 kV expnses
13
14 Subtotal 50 kV 1,211.00 11
15
16 Ben Lomond Sub., UT Bora Substation, ID 345.OC 345.00 Steel- H 133.00 1
17 Ben Lomond Sub., UT Terminal Substation, UT 34.OC 345.00 Steel- 0 94.00 2
18 Spanish Fork Sub., UT Camp Willams Sub., UT 34.OC 345.00 Steel- SP 35.00 1
19 Huntington Plant, UT Sigurd Subsation, UT 345.OC 345.00 Steel. H 95.00 1
20 Huntington Pit. Sub., UT Spanish Fork Sub., UT 345.OC 345.00 Stee- H 78.00 1
21 Terminal Substation, UT Ninety South Sub., UT 34.OC 345.00 Steel- SP 32.00 2
22 Emery Substation, UT Sigurd Subsation, UT 34.OC 345.00 Steel- H 75.00 1
23 Sigurd Substation, UT Camp Wiliams Sub., UT 345.OC 345.00 Steel.H-P 116.00 1
24 Camp Willams Sub., UT Ninety South Sub., UT 345.OC 345.00 Steel-SP 22.00 2
25 Terminal Substation, UT Camp Wiliams Sub., UT 345.OC 345.00 Stee. 0 52.00 2
26 Emery Substation, UT Camp Wiliams Sub., UT 345.OC 345.00 Stl. H 121.00 1
27 Newcatle, UT Utah - Nevada Border 345.OC 345.00 Steel- 0 54.00 1
28 Sigurd Substation, UT Newctle, UT 345.OC 345.00 St. 0 137.00 1
29 Goshen Substation, ID Kinport Substtion, ID 345.OC 345.00 Stee. H 41.00 1
30 Pinto Substation, UT Four Comers Sub., NM 345.OC 345.00 Woo-U 101.00 1
31 Camp Willams Sub., UT Huntington Plant, UT 345.OC 345.00 Woo.U 107.00 1
32 Huntington Plant, UT Pinto Substation, UT 345.OC 345.00 Woo-U 160.00 1
33 Camp Willams Sub., UT Sigurd Subsation, UT 345.OC 345.00 Woo.U 116.00 1
34 Jim Bridger Plant #3, WY Bora Substatio, ID 345.OC 345.00 Stee Tower 240.00 1
35 Jim Briger Plant #2, WY Kinport Substation, ID 345.OC 345.00 Steel Tower 234.00 1
36 TOTAL 16,29.OC 150.00 22
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo8/Q4
(2) Fi A Resubmission 03131/200
RANSMISSION LINE STATISTICS (C ontinued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage Iineš. If two or more transmission line structures support lines of the same voage, report the
poe miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion there for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Leae, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operaion of, fumish a succinct statement explaining the
arrangement an giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, bais of sharing
expnses of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Speif whether lessor, cowner, or
other part is an associated company.
9. Designate any trasmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Bae the plant cost figures called for in columns ü) to (I) on the bok cost at end of year.
I,U::1 INi; (InClude in l,umn UJ Land,
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conor
an Material Land Constrution and Total Cost Operation Maintenance Rents Tot LineOther Costs Expenses Expenses E~nses
(i)ü)(k)(I)(m)(n)(0)(p)No.
.1852 ACSR 134,35E 5,551,720 5,68,076 1
3-1272 ACSR 3,86,4lX 151,289,387 154,375,787 2
3-1272 ACSR 2,907,171 37,830,90 40,738,076 3
3-1272 ACSR 1,468,201 19,534,1~21,002,387 4
272 ACSR 9,23(1,460,04~1,469,272 5
-1272 ACSR 4,769,431 26,243,79!31,013,234 6
95 KCMACSR 34,086 34,086 7
95 KCMACSR 219,551 5,424,681 5,64,23E 8
95 KCMACSR 276,82 7,157,64~7,43,46 9
95 KCMACSR 419,69 6,587,89 7,007,59 10
95 KCMACSR 436,81 6,5oo,71~6,937,53 11
1,054,883 130,93 1,185,81~12
13
13,727,69 267,615,061 281,342,757 1,054,88~130,93 1,185,81~14
15
54 5,229,65 35,379,455 40,60,112 16
272 9,289,09!22,142,78E 31,431,884 17
272 5,503,01'10,158,59f 15,661,öõ 18~343,17 20,O8,7~20,423,955 19
54 977,241 17,68,06 18,66,308 20
272 2,546,471 7,455,160 10,001,631 21
54 32O,31E 13,619,157 13,939,473 22
54 510,49t 25,192,646 25,703,13E 23
272 482,18E 3,895,713 4,377,901 24
272 4,299,09 7,92,490 12,261,583 25
~54 926,251 27,920,816 28,847,06 26
~54 2,320,87,50,681,88 53,002,756 27
54 56,OS 13,60,494 13,661,54 28
95 313,7 2,576,297 2,889,774 29
54 117,66 2,88,58~3,00,244 30
95 893,961 19,899,214 20,793,m 31
95 32
795 179,50 16,63,715 16,814,217 33
272 1,128,22.26,78,1~27,206,361 34
272 1,09,791 27,392,214 28,492,01i 35
87,473,552 1,741,496,237 1,828,96,i~93,33 16,20,99 803,24!17,101,58 36
FERC FORM NO.1 (ED. 12-87)Page 423
FERC FORM NO.1 (ED. 12-8 Page 421
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) 0 A Resubmission 0331/200
TRANSMISSION LINE STATIST CS
1. Report information conceming transmission lines, cot of Iines, and expenses for year. List eah trasmission line having nominal voltage of 132
kilovolts or greater. Report trasmission lines below these voltages in group tots only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform Syem of Accnts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voges if so reuire by a Stae commisson.
4. Exclude from this page any transmission lines for which plant cots are include in Acount 121, Nonutility Propert.
5. Indicate whether the typ of supprting structure reported in column (e) is: (1) single pole woo or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line ha more than one type of supporting structure, indicate the mileage of each tye of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a diferent tye of costruction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each tranmission line. Show in column (f) the pole miles of line on structures the cot of which is
reported for the line designated; conversely, sho in column (g) the pole miles of line on structure the cot of which is reprted for another line. Report
pole miles of line on leased or partly owned structures in coumn (g). In a foe, expain the bais of such ocupancy and state whether expenses with
respect to such structures are included in the expnses reped for the line deigned.
LE~GJiH toie WileS)Line (Indicate vÍ~'(Type of I§t e a~o NumberNo.other than u ergroun lines Of60 cvcle. 3 ohase)Supprting report circuit miles)
From To Operating Designed un ~tricture ull~~CJres CircuitsStructure~.Lineed oot erIllatine(a)(b)(c)(d)(e)(g)(h)
1 Currnt Creek Swtchrd, UT Mona Substation, UT 345.OC 345.00 Steel- SP l.OC 1
2 Camp Wiliams Sub, UT Mona Sub, UT 345.OC 345.00 Woo-SP 8.00 42.00 1
3 34 kV expnses
4
5 Subtotal 345 kV 2,052.00 42.00 26
6
7 Fairvew, OR Isthmus, OR 230.OC 230.00 H Frame Woo 12.00 1
8 Antelope Sub., ID Lost River, ID 230.OC 230.00 Woo-H 20.00 1
9 Wålla Walla, WA Hells Canyon, ID 230.OC 230.00 H Frame Woo 78.00 1
10 Bethel, OR Fry, OR 230.OC 230.00 H Frame Woo 26.00 1
11 Fry, OR Dixonvile, OR 230.OC 230.00 H Frame Woo 45.00 1
12 Alvey, OR Dixonville, OR 230.OC 230.00 H Frame Woo 59.00 1
13 Trotdale, OR Linneman, OR 23.OC 230.00 Steel Tower 6.00 1
14 Troutdale, OR Gresham,OR 23.OC 230.00 Steel Towr 6.00 1
15 McNary, WA Walla Walla, WA 23.OC 230.00 H Frame Woo 56.00 1
16 BPA Heppner, OR Dalree Subsation, OR 230.OC 230.00 H Frame Woo 1.00 1
17 Sigurd Substation, UT Garfield, UT 230.0l 230.00 Woo.U 117.00 1
18 Dixonville, OR Reston, OR 230.0l 230.00 H Frae Woo 17.00 1
19 Yamsey, OR Klamath Falls, OR 230.0l 230.00 H Fra Woo 56.00 1
20 Yamsey, OR Klamath Falls, OR 230.OC 230.00 St Tower 6.00 1
21 Dixonville, OR Lone Pine, OR 230.0(230.00 H Frame Woo 8.00 1
22 Klamath Falls, OR Medrd, OR 230.0(230.00 H Frame Woo 76.00 1
23 Klamath Falls, OR Malin, OR 230.0(230.00 H Frame Woo 35.00 1
24 Table Rock, SW Station, OR Grants Pass, OR 23.0(230.00 H Frame Woo 35.00 1
25 Grats Pas, OR Days Creek, OR 23.0(23.00 H Frame Woo 71.00 1
26 Dixonville, OR Dixonville, OR 23.0(230.00 Woo 1.00 1
27 Sigurd Substation, UT Pavant Substation, UT 230.0(230.00 Woo-U 43.00 1
28 Pavant Substation, UT Nevada - Utah State line 230.0(230.00 Woo.U 98.00 1
29 Bannock Pas, ID Antelope Sub., ID 230.0(230.00 Woo.U 76.00 1
30 Brady Substation, ID Treaureton Sub., ID 230.0(230.00 Woo-U 66.00 1
31 Ben Lomond Sub., UT Naughton Pit. #1, WY 230.0(230.00 Woo.U 88.00 1
32 Sigurd Substation, UT Arizona - Utah State line 230.0(230.00 Woo-U 149.00 1
33 Birch Crek Sub., WY Railrod Substation, WY 23.0(230.00 Woo-HSW 12.00 1
34 Birch Crek Sub., WY Railrod Substation, WY 23.OC 230.00 Woo-HSW 7.00 1
35 Ben Lomond Sub., UT Naughon Pit. #2, WY 230.OC 230.00 Woo-U 59.00 1
36 TOTAL 16,292.OC 150.00 220
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 03131/200
RANSMISSION LINE STATISTICS (C ontinued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote. if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such prort is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other tha a leased line, or portion thereof, for
which the respondent is not the sole ower but which the respondent operaes or shares in the operation of, fumish a sucinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-wner, bais of sharing
expenses of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Speif whether lessor, cor, or
other part is an associated company.
9. Designate any trasmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Bae the plant cost figures caled for in columns ü) to (I) on the boo cot at end of year.
liU:: I ui- LINt: (inciuae in lioiumn U) La,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Coductor
and Material Land Construction an Total Cost Operation Maintenance Rents Total UneOther Costs Expnses Expenses (0)Expenses No.(i)ü)(k)(I)(m)(n)(p)
1,178,479 1,178,479 1
272 9,573,299 9,573,299 2
1,824,21~133,20 1,957,41¿3
4
36,536,53 361,99,994 398,533,530 1,824,21~133,2OC 1,957,41¿5
6
ß5 285,32 1,777,619 2,062,941 7
95 12,921 1,143,095 1,156,024 8
272 64,39 11 ,450,460 11,514,85 9
272 351,98 2,207,541 2,559,52~10
272 4S5,891 4,890,77 5,376,674 11
~54 1,428,24 14,172,177 15,60,424 12
~54 43,671 439,677 13
~54 363,71 577,80l 941,52E 14
272 220,96 3,378,561 3,59,535 15
95 30,39 30,397 16
95 468,99¡7,66,34.8,129,335 17
39,971 1,5oo,88!1,540,85E 18
95 19
95 473,36 4,06,461 4,539,827 20
95 439,56:3,160,501 3,60,0&1 21
95 173,6l 5,665,174 5,83,78.22
272 115,441 1,798,92E 1,914,37E 23
954 191,12 5,220,765 5,411,8~24
272 379,961 11,626,021 12,00,98:25
272 502,47E 502,47E 26
95 41,491 4,375,777 4,417,27E 27
95 28
272 5,10.2,429,20(2,434,30.29
95 72,111 2,193,5SC 2,265,6!l 30
95 426,121 4,485,65.4,911,Tl!31
954 22,64 4,609,03(4,631,67 32
954 165,05'1,29,64,1,464,69E 33
954 181,04 1,520,22(1,701,267 34
272 736,031 5,273,70!6,00,731 35
87,473,55 1 ,741 ,496,237 1 ,828,96,781 93,33 16,204,99 80,249 17,101,58 36
FERC FORM NO.1 (ED. 12-8 Page 423.1
FERC FORM NO.1 (ED. 12-8 Page 422.2
............................................
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) EiA Resubmission 0331/200
TRANSMISSION LINE STATIST CS
1. Report information conceming transmission lines, cot of Iines, and expnses for year. List eah trasmision line having nominal volge of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covere by the definition of trasmission sysem plan as given in the Uniform Sysem of Acunts. Do not report
substation coss and expenses on this page.
3. Report data by individual lines for all voltages if so reuire by a State commission.
4. Exclude from this page any tramission lines for which plant cos are include in Acunt 121, Nonutilit Prorty.
5. Indicate whether the typ of supprting structure reported in coumn (e) is: (1) single poe wo or steel; (2) H-frame woo, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one ty of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a trasmission line of a diferent ty of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each trasmission line. Show in column (f) the poe miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cot of which is reported for another line. Repo
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the bais of such ocupancy and state whether expenses with
respect to such structures are included in the expnses reported for the line designated.
Line
(Indicae Ji~'t Typ of LE~~~ ~e ólileS)NumberNo.
:i~u: nh ~RA\
u ergronìlllnesSuppngreport circuit miles)Of
From To Oprating Deigned o-narn,cture unf~~h~res CircuitsStruureof. Line o not er
(a)(b)(c)(e)Deslllated ne
(d)(g)(h)
1 Ben Lomond Sub., UT Naughton Pit. #2, WY 23Q.(230.00 Woo-U 29.00 1
2 Chappel Creek, WY Naughton Plant, WY 230.0(230.00 Woo Tower 46.00 1
3 Ben Lomond Sub., UT Terminal Substation, UT 230.0(230.00 Steel- D-P 76.00 1
4 Naughton Plant, WY Treasureton Sub., ID 230.0(230.00 Woo-U 79.00 1
5 Naughton Plant, WY Treasureton Sub., ID 230.0(230.00 Woo-U 1JX 1
6 Swif Plant #1, WA Cowlitz Co. Line, WA 230.0(230.00 H Frame Woo 3.00 1
7 Swi Plant #2, WA BPA Wooland, WA 23Q.(230.00 H Frame Woo 23.00 1
8 Union Gap, WA BPA Midwy, WA 23Q.(23.00 H Frame Woo 39.00 1
9 Walla Walla, WA Lewiston, ID 230.0(230.00 H Frame Woo 45.00 1
10 Walla Walla, WA Wanum, WA 23.lX 230.00 H Frame Woo 33.00 1
11 Pomona, WA Wanpum, WA 23.lX 23.00 H Frame Woo 37JX 1
12 Pomona, WA Wanapum, WA 23.lX 230.00 H Frame Woo aJX 1
13 Meridian Sub, OR Lone Pine Sub, OR 23O.lX 230.00 Steel- DC 5.00 1
14 Meridian Sub, OR Lone Pine Sub, OR 23O.lX 230.00 Stee - DC 5.00 1
15 Goose Creek, WY Yellowtail, MT 23O.OC 230.00 H Frame Wood 59.00 1
16 Yellowtil, MT Muddy Ridge, WY 23O.OC 230.00 H Frame Woo 176.00 1
17 Sheridan, WY Decker, MT 23O.OC 230.00 H Frame Woo II 1
18 Dave Johnston Plant, WY Casper, WY 23O.OC 230.00 H Frame Woo 31.00 1
19 Yellowtail, MT Casper, WY 23.lX 230.00 H Frame Woo 149JX 1
20 Rock Springs, WY Kemmerer, WY 23.lX 230.00 H Frame Woo 71.lX 1
21 Rock Springs, WY Atlantic Cit, WY 23O.lX 230.00 H Frame Woo 69.lX 1
22 Thermopis, WY Riverton, WY 23.lX 230.00 H Frame Woo 51.lX 1
23 Casper, WY Riverton, WY 23O.lX 230.00 H Frame Woo 110.00 1
24 Dave Johnston Plan, WY Rock Springs, WY 23O.lX 230.00 H Frame Woo 20.00 1
25 Dave Johnston Plant, WY Spence, WY 23O.lX 23.00 H Frame Woo 31.0(1
26 Riverton, WY Atlantic Cit, WY 23O.lX 230.00 H Frame Woo 50.00 1
2:Rock Springs, WY Flaming Gorge, UT 230.0(230.00 H Frame Woo 41JJj(1
28 Palisades, WY Green River, WY 230.0(230.00 H Frame Woo 5.0(1
29 Bufalo, WY Gillete, WY 23O.lX 230.00 H Frame Woo 69.lX 1
30 Jim Bridger Plant, WY Point of Rocks, WY 23O.lX 230.00 H Frae Woo 4.00 1
31 Jim Bridger Plant, WY Point of Rocks, WY 23O.lX 230.00 H Frame Woo 5.00 1
32 Dave Johnston Plant, WY Yellowce, WY 23O.lX 23.00 H Frame Woo 69.00 1
33 Wyodk, WY Sub. Tie Line, WY 23O.lX 230.00 H Frame Woo 1.00 1
34 Jim Bridger Plant, WY Point of Rocks Ln 2, WY 230.0(230.00 H Frame Woo 8.00 1
35 Blue Rim, WY Sout Trona, WY 23.lX 230.00 H Frame Woo 13JX 1
36 TOTAL 16,292.00 150.00 220
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo8/Q4
(2) Fi A Resubmission 03131/200
RANSMISSION LINE STATISTICS (( ontinued)
7. Do not report the same transmission line strucure twice. Report Lower voltage Unes and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If tw or more transmission line structures support lines of the same voltage, rert the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereo for which the repondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement expaining the
arngement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of cowner, bais of sharing
expnses of the Line, and how the expenses bome by the respondent are accunted for, and accunts affeced. Specif whether lessor, co-ownr, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specif whether lessee is an associated company.
10. Bae the plant cost figures called for in columns u) to (I) on the book cot at end of year.
VUÖL I!\E /Include in voiumn UJ Laa,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Lad rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total ine
Other Costs Expnses Expses (0)Expnses No.(i)u)(k)(I)(m)(n)(p)
272 1,716,425 1,716,429 1
954 170,96 5,949,461 6,120,428 2
272 572,455 10,53,187 11,106,646 3
954 56,491 2,993,30 3,049,807 4
954 56!27,377 27,946 5
954 1,29~326,731 328,024 6
954 103,53~2,530,686 2,63,218 7
272 172,451 1,705,145 1,877,596 8
272 363,08,5,901,659 6,264,741 9
954 235,53,2,387,90 2,623,441 10
780 207,12 2,443,035 2,650,158 11
556.5 11*1,514,165 1,514,334 12
272 2,003,740 2,003,740 13
14
272 2,223,562 2,223,562 15
272 89,84 5,940,815 6,030,660 16
272 17
1795 14,92 1,193,33 1,20,264 18
~271 130,191 10,011,766 10,141,96 19
~271 52,9O 3,415,079 3,467,98S 20
~54 31,855 3,134,024 3,165,8~21
~272 57,11.2,100,040 2,157,152 22
~54 67,85 5,214,00 5,281,86 23
~272 58,10~12,140,358 12,198,460 24
~272 33,oof 2,514,260 2,547,266 25
~271 48,281 3,934,315 3,982,6OC 26
272 30,76!2,66,965 2,69,731 27
272 1"579,14"579,154 28
272 361,351 4,350,955 4,712,31C 29
272 4,80(140,31~145,11~30
272 130,166 130,16E 31
272 294,29C 6,158,1OE 6,452,39 32
272 15,274 15,274 33
272 3,96 441,494 445,461 34
272 88,49~88,493 35
87,473,55.1 ,741,496,237 1,828,96,789 93,33 16,204,99 803,245 17,101,~36
FERc FORM NO.1 (ED. 12-87)Page 423.2
FERC FORM NO.1 (ED. 12-87)Page 42.3
............................................
Name of Respondent This~rtIS:Oate of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Oa, Yr)End of 2008/04
(2) Fi A Resubmission 0331/200
TRANSMISSION LINE STATIST CS
1. Report information conceming transmission lines, cot of Iines, and expenses for year. List each trasmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission sysem plan as given in the Uniform System of Accs.00 not report
substation costs and expnses on this page.
3. Report data by individual lines for all voltages if so reuire by a State commision.
4. Exclude from this page any transmission lines for which plant cos ar includ in Acnt 121, Nonutility Proert.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wo or steel; (2) H-frame woo, or steel poles; (3) tower;
or (4) underground construction If a trasmission line has more than on ty of supprting struure, indicte the mileage of each tye of construion
by the use of brackets and extra lines. Minor portons of a trasmisson line of a dierent type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the poe miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Reprt
pole miles of line on leaed or partly owned structures in column (g). In a fotnote, explain the basis of such occupancy and state whether expnses with
respet to such structure are included in the expnses reported for the line designated.
Line (Indicate wtere Type of LE~GJi~ ~~ie ¿fileS)NumberNo.other tha u 1gergrounlriines
60 cvle 3 Dhae)Supportng report circuit miles)Of
From To Operaing Designed un ~lflClure ug.~lmres CircuitsStruureof. Line oot er
(a)(b)(c)(e)DeI8)ated ne
(d)(g)(h)
1 Monument, WY Exxon Plant, WY 230.OC 230.00 H Fra Woo 13.00 1
2 Firehole, WY Mansface, WY 23O.OC 230.00 Stee Pole 2.00 1
3 Firehole, WY Mansface, WY 230.OC 230.00 H Frame Woo 10.00 1
4 Monuments, WY South Trona, WY 230.OC 230.00 H Frame Woo 4.00 1
5 Spence Sub., WY Jim Briger Plant, WY 230.OC 230.00 H Frame Woo 47.00 1
6 Jim Bridger Plant, WY Mustang Sub., WY 23O.OC 230.00 H Frame Woo 73.00 1
7 Spence Sub., WY Mustag Sub., WY 23O.OC 23.00 H Fra Woo n.oo 1
8 Rock Springs, WY Flaming Gorg, UT 23O.OC 23.00 Stee Tower 7.00 1
9 Line 59, CA Copco II, CA 23O.OC 23.00 H Frame Woo 5.00 1
10 Arizona/Utah State Line Glen Cayon Sub., AZ 23O.OC 23.00 H Frame Woo 10.00 1
11 Miners Sub., WY Foote Creek Sub., WY 23.OC 23.00 Woo-H 29.00 1
12 Monument Sub., WY Craven Creek Sub., WY 23O.OC 23.00 Woo-H 20.00 1
13 Point of Rocks Sub., WY Rock Springs, WY 23O.OC 230.00 Woo-H 27.00 1
14 Craven Creek Substation, WY Pioneer Substation, WY 23O.OC 230.00 Woo-H 3.00 1
15 Chappel Creek Sub., WY Jonah Field, Substation, WY 23O.OC 230.00 Woo-H 35.00 1
16 Marengo Wind, WA Tablot Substation, WA 23O.OC 230.00 Woo-H 4.00 1
17 230 kV expenses
18
19 Subtotal 230 kV 3,347.00 5.00 80
20
21 Montana-Idaho State line Grace Plant, 10 161.0(161.00 Woo-H 57.00 90.00 1
22 Goshen Substation, ID Rigby Substtion, 10 161.161.00 Woo-H 61.00 1
23 Goshen Substation, 10 Antelope Substation, 10 161.161.00 Woo-H 45.00 1
24 Goshen Substation, 10 Sugar Mil Substation, 10 161.161.00 Woo-SP 17.00 1
25 Sugar Mill Sub., 10 Rigby Substtion, 10 161.0(161.00 Woo-SP 17.oe 1
26 Goshen Substation, 10 Bonneville Sub., 10 161.0(161.00 Woo-SP-H 23.oe 1
27 Bilings, MT Yellowtail, MT 161.0(161.00 H Frame Woo 46.oe 1
28 Big Grasy Sub., 10 Idaho Power Line, 10 161.0(161.00 Woo-H toe 1
29 Rigby Sub., 10 Jefferson Roberts, 10 161.0(161.00 Woo-SP 18.oe 1
30 161 kVexpenses
31
32 Subtotal 161 kV 285.oe 90.00 9
33
34 Naughton Plat, WY Evanston Substaion, WY 138.0(138.00 Woo-H 67.OC 1
35 Evanston Substation, WY Anscut Substation, WY 138.0(138.00 Woo-H 6.0(1
36 TOTAL 16,29.00 150.00 220
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) ri A Resubmission 03/31/200
RANSMISSION LINE STATISTICS (( ontinued)
7. Do not report the same transmission line struture twice. Report Lower voltage Unes and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If tw or more transmission line structures supprt lines of the same voltage, report the
pole miles of the primary structure in column (f) and the poe miles of the other line(s) in column (g)
8. Designate any trasmission line or portion thereof for which the respondent is not the sole owner. If such prort is leased from another company,
give name of lessor, date and terms of Leae, and amount of rent for year. For any transmission line other than a leased line, or portion thereo, for
which the respondent is no the sole owner but which the respondent operates or shares in the operaion of, fumish a succinct statement explaining the
arrngement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, bais of sharing
expenses of the Line, and how the expnses bome by the respondent are accounted for, and acnts affeced. Specif whether lessor, co-own, or
other party is an assoiated compay.
9. Designate any transmission line leaed to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns ü) to (I) on the bok cost at end of year.
'"u~ i '" ..uu': (InCluae in GOlumn (j Laa,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Une
Other Costs Expenses Expenses (0)Exenses No.(i)ü)(k)(I)(m)(n)(p)
272 43,839 43,839 1
1272 2
272 2,576,371 2,576,371 3
272 2,720,479 2,720,479 4
272 170,295 170,295 5
1272 4,59 9,77,492 9,776,B:6
272 9,565,742 9,565,742 7
272 4,48 744,631 749,m 8
4,33'820,071 824,41C 9
11,901 451,~463,264 10
4,972,560 4,972,56 11
4,548,527 4,548,527 12
5,939,085 5,93,08E 13
272 ACSR 837,44E 837,44E 14
272 ACSR 11,524,191 11,524,191 15
95 KCMACSR 1,827,482 1,827,482 16
4,927 3,241,691 140,659 3,387,2Ti 17
18
10,333,37 271,190,39E 281,523,775 4,92'3,241,691 140,655 3,387,2Ti 19
20
397.5 18,97 1,758,724 1,777,702 21
397.5 27,521 822,5B:850,10~22
397.5 8,85 2,688,332 2,697,189 23
397.5 48,221 1,473,oa 1,521,31C 24
ß97.5 27,53E 1,210,17 1,237,m 25
~54 362,27~2,845,761 3,208,041 26
556.5 2,274,~2,274~27
556.5 12,194 12,194 28
556.5 76,~1,273,485 1,349,791 29
207,256 1,862 209,111 30
31
569,7~14,35,67~14,928,375 207,255 1,862 209,11 i 32
33
95 146,64!4,056,391 4,203,04.34
95 129,12!498,59C 627,ii!35
87,473,55.1,741,496,237 1,828,96,781 93,33 16,204,99 80,24~17,101,58 36
FERC FORM NO.1 (ED. 12-87)Page 423.3
FERC FORM NO.1 (ED. 12-8 Page 422.4
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, 08, Yr)End of 20004
(2) Ei A Resubmission 0331/2009
TRANSMISSION LINE STATIST CS
1. Report information conceming transmission lines, cot of Iines, and expnses for year. Ust each tramision line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for eah voltage.
2. Trasmission lines include all lines covered by the definition of transmission system plant as given in the Unifor System of Accunts. Do not report
substation cots and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant cos are included in Acunt 121, Nonutility Propert.
5. Indicte whether the ty of supporting structure reported in column (e) is: (1) single poe wo or steel; (2) H-frame woo, or steel poles; (3) tower;
or (4) underground construction If a transmission line ha mor than one ty of suporting struure, indicate the mileage of each type of costruction
by the use of brackets and extra lines. Minor portions of a transmisson line of a dierent ty of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of eah tramision line. Sho in coumn (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in coumn (g) the poe miles of line on struures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a fooe, expain the bais of such ocupancy and state whether expenses with
respe to such structures are included in the expenses reported for the line deignated.
Une
(Indicate .J~'(Type of LE~GJi~ ~gie ólileS)NumberNo.other than u ¡§ergronìlllnes Of60 cvcle 3 Dhae)Supporting report circit miles)
From To Opraing Deigned un qlriciure urif~~o1~res CircuitsStruureoJi~i~ed o oot erine
(a)(b)(c)(d)(e)(9)(h)
1 Evanston Substation, WY Anschutz Subsion, WY 138.IX 138.00 Woo.H 15.00 1
2 Naughton Plant, WY Carter Cre Sub., WY 138.IX 138.00 Woo.H 36.00 1
3 Railroad Sub., WY Carter Creek Sub., WY 138.IX 138.00 Woo.H 17.00 1
4 Painter Substation, WY Natura Gas Sub., WY 138.IX 138.00 Woo.H 5.00 1
5 Grace Plant, 10 Termnl. Sub., UT (103-104)138.IX 138.00 Stee. S 42.00 2
6 Grace Point, 10 Termn!. Sub., UT (103-104)138.IX 13800 Woo-H 211.00 2
7 Grace Plant, 10 Terminal Sub., UT (105)138.IX 138.00 Wood-H 143.00 2
8 Grace Plant, 10 Soda Plant, 10 138.IX 138.00 Woo.H 8.00 4.00 2
9 Oneida Plant, 10 Ovid Substation, 10 138.IX 138.00 Woo.H 23.00 1
10 Antelope Substation, 10 Scoville Sub., 10 138.IX 138.00 Woo.H 1.00 1
11 Soda Plant, Idao Monsanto Sub., 10 138.IX 138.00 Woo.H 14.00 1
12 Three Mile Knoll Sub., 10 Grace Plant, 10 138.IX 138.00 Woo-H 18.00 1
13 Three Mile Knoll Sub., 10 Becker Substation, 10 138.IX 138.00 Woo.H 4.00 1
14 Treasureton Sub., 10 Franklin Sub., 10 138.IX 138.00 Woo.H&S 10.00 1
15 Franklin Substation, 10 Smithield Sub., UT 138.IX 138.00 Woo-H 25.00 1
16 Midvalley Substtion, UT Thirt Souh Sub., UT 138.IX 138.00 Woo.H 1.00 1
17 Angel Substation, UT Smith's UT 138.IX 138.00 Woo-H 1.00 1
18 Terminal Substation, UT 30 South Switch Rack, UT 138.IX 138.00 Stee. S 7.00 1
19 Jordan, UT Terminal Substation, UT 138.0(138.00 Woo.H 6.00 1
20 Wheelon Substation, UT American Falls Sub., UT 138.IX 138.00 Woo-H 82.00 1
21 Cutler Plant, UT Wheelon Substation, UT 138.0(138.00 Woo.H 1.00 1
22 Terminal Substation, UT Helper Substation, UT 138.0(138.00 Woo.H 116.00 1
23 Hale Plant, UT Nebo Substation, UT 138.IX 138.00 Woo.H 54.00 1
24 Carn Plant, UT Helper Substation, UT 138.IX 138.00 Woo-H 2.00 1
25 Termina Substation, UT Tooele Substation, UT 138.IX 138.00 Woo-H 42.00 1
26 Wheelon Substation, UT Smithield Sub., UT 138.IX 138.00 Woo.H 19.00 1.00 2
27 Helper Substation, UT Moab Substation, UT 138.IX 138.00 Woo.H 118.00 1
28 Ninetieth South Sub, UT Carbn Plant, UT 138.IX 138.00 Woo.H 75.00 2
29 Terminal Substation, UT Ninetieth South Sub, UT 138.IX 138.00 Woo-H 16.00 2
30 30 South Switch Rack, UT McClelland Sub., UT 138.IX 138.00 Woo.SP 6.00 1
31 Moab Substation, UT Pinto Substation, UT 138.1l 138.00 Woo-H 68.00 1
32 Pinto Substation, UT Abajo, UT 138.1l 138;00 Woo.H 45.00 1
33 Carbn Plant, UT Ashley Substation, UT 138.1l 138.00 Woo.H 92.00 1
34 McClelland Sub., UT Cottonwo Sub., UT 138.1l 138.00 Woo.SP 6.00 1
35 Ashley Substation, UT Vemal Substation, UT 138.1l 138.00 Woo.H 12.00 1
36 TOTAL 16,292.00 150.00 22
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 03131/200
RANSMISSION LINE STATISTICS (C ontinued)
7. Do not report the same transmissio line structure twce. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary strucure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is leased from another compay,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the repondent opertes or shares in the operation of, fumish a succinct statement explaining the
arrngement and giving particulars (details) of such matters as percent ownership by respodent in the line, name of cownr, bais of sharing
expenses of the Line, and how the expenses bome by the respondent are accounted for; and accounts affeced. Speif whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leaed to another copany and give name of Lesse, date and terms of lease, annual rent for year, and how
deterined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (i) on the bo cost at end of year.
COST OF LINt: iinciuoe in lAlumn UJ Laa,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Lad rihts, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses
(0)
Expenses No.(i)0)(k)(I)(m)(n)(p)
95 3,381 290,80 29,184 1
95 41,411 3,571,596 3,619,007 2
95 72,622 3,889,75S 3,962,381 3
95 -12,42~-278,83 -291,26C 4
95 765,18!13,281,713 14,046,95E 5
95 6
~50 132,96 16,104,165 16,237,125 7
1795 3,29C 226,715 230,005 8
ß3 4,81 942,031 94,84E 9
ß97.5 14~41 19C 10
ß97.5 2,55E 295,902 298,457 11
95 30,33 420,88 727,22E 12
ß97.5 14,42~145,941 160,36 13
95 39,101 54,247 579,348 14
197.5 47,61~1,09,ao 1,141,421 15
192,647 192,647 16
20,22 2O,22S 17
00 1,83 1,256,746 1,258,583 18
661,44 2,06,141 2,725,588 19
50 118,18C 6,20,333 6,318,513 20
50 69,072 69,072 21
50 458,791 11,901,681 12,36,480 22
397.5 27,54 4,628,06 4,655,60l 23
54 781 150,403 151,18S 24
197.5 9,461 8,416,071 8,425,531 25
197.5 188,01E 1,140,352 1,328,370 26
197.5 33,ga 3,135,741 3,169,700 27
95 345,83E 5,628,56 5,974,401 28
272 426,29E 1,227,204 1,65,400 29
95 58,03C 1,56,521 1,621,551 30
97.5 40,1H 1,103,562 1,143,6n 31
397.5 1oo,~2,113,63 2,213,~32
97.5 80,861 1,717,92E 1,798,787 33
95 13,7~1,490,422 1,504,155 34
~97.5 5,54E 325,98C 331,52E 35
87,473,552 1,741 ,496,237 1 ,828,96,78!93,337 16,204,99 803,249 17,101,581 36
FERC FORM NO.1 (ED. 12-87)Page 423.4
FERC FORM NO.1 (ED. 12-8 Page 422.5
............................................
Name of Respondent This ~rtIS:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 200Q4
(2) 0 A Resubmission 0331/200
TRANSMISSION LINE STATIST CS
1. Report information conceming transmission lines, cost of Iines, and expenses for year. List each trasmission line having noinal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Trasmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accnts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so reuire by a State commission.
4. Exclude from this page any transmission lines for which plant cos are included in Account 121, Nonutilty Property.
5. Indicate whether the typ of supporting structure reported in column (e) is: (1) single pole woo or steel; (2) H-frame wod, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one tye of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a diferent tye of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structure the cot of which is
reported for the line designated; conversely, show in coumn (g) the pole miles of line on structures the cot of which is reported for another line. Report
pole miles of line on leaed or partly owned structures in column (g). In a foonoe, explain the bais of such ocupancy and state whether expnses with
respect to such structures are included in the expnses reprted for the line deignated.
Line
(Indcae vJ~;:Type of LE~Gl~ ~~ie Jliies)NumberNo.òterthn u ~ergrounìllines Of60 cvcle 3 oh se)Supporting report circuit miles)
From To Operating Designed I un ~(!V~!ure IU~f~~~res CircuitsStructureDe'if'ed Of'1l)ot erine(a)(b)(c)(d)(e)(g)(h)
1 Sigurd Substation, UT West Cedar Substation, U 138.!138.00 Woo.H 120.00 1
2 Ben Lomond Sub., UT EI Monte Substation, UT 138.!138.00 Woo.HSub 19.0(1
3 Cottonwood Sub., UT Ninetieth South Sub, UT 138.0(138.00 Woo-SP 11.00 1
4 Terminal Substation, UT Rowley Substation, UT 138.0(138.00 Woo.H 56.00 1
5 Huntington Plant, UT McFaddn Substation, UT 138.0(138.00 Woo-H 7.00 1
6 Ben Lomond Sub., UT EI Monte Substaio, UT 138.0(138.00 Woo.H 13.00 1
7 Cottonwood Sub., UT Silvercreek Sub., UT 138.0(138.00 Woo-SP 37.00 1
8 Ninetieth South Sub, UT Taylorsville Sub., UT 138.0(138.00 Woo.SP 9.00 1
9 Gadsby Plant, UT McClelland Sub., UT 138.0(138.00 Woo.SP 4.00 1
10 Ninetieth South Sub, UT Oquirrh Substation, UT 138.0(138.00 Woo.SP 10.00 2
11 Neb, UT Jerusalem, UT 138.0(138.00 Woo Tower 26.00 1
12 Ben Lomond Sub., UT Westem Zircn Sub., UT 138.0(138.00 Woo.H 14.0(1
13 Toole Substation, UT Oquirrh Substation, UT 138.0(138.00 Wood-SP 21.0(1
14 Wheelon Substation, UT Nucor Steel Sub., UT 138.0(138.00 Woo.H 14.00 4.00 1
15 Nebo Substation, UT Martin-Maretta Sub., UT 138.0(138.00 Woo.H 30.0(1
16 West Cedr Sub., UT Middleton Substation., U 138.0(138.00 Woo.H 69.00 1
17 Gadsby Plant, UT Terminal Substation, UT 138.0(138.00 Woo-H 6.00 1
18 Oquirr Substation, UT Kennec Sub., UT 138.0(138.00 Woo.H 4.0(1
19 Oquirrh Substation, UT Bamey Substation, UT 138.0l 138.00 Woo.HS 7.0(2
20 West Cedr Sub., UT Pepcn Substation, UT 138.OC 138.00 Woo.SP 13.00 1
21 Taylorsville Substation, UT Mid-Valley Substation, U 138.OC 138.00 Steel- SP 5.00 1
22 Warrn Substation, UT Kimberly Clark Sub., UT 138.OC 138.00 Woo-HP 1.00 1
23 Honeyvlle, UT Promontory, UT 138.OC 138.00 Woo Tower 22.00 1
24 Ninetieth South Sub, UT Hale Plant, UT 138.OC 138.00 Wood Tower 51.00 1
25 Dumas, UT Bimple, UT 138.OC 138.00 Woo Tower 4.00 1
26 Columbia Sub, UT Sunnysde Co. Gen., UT 138.OC 138.00 Woo Tower 2.00 1
27 Syracuse Sub, UT Ben Lomond Sub, UT 138.OC 138.00 St- D.P 26.1
28 Hale Plant, UT Midway Sub, UT 138.OC 138.00 Woo-H 19.1
29 Jordn 138 kV, UT Fifth West 138 kV, UT 138.0(138.00 Steel Tower 1.1
30 Gadsby 138 kV, UT Jordn 138 kV, UT 138.0(138.00 Stee Tower 1.00 1
31 Panther, UT Willow Crek, UT 138.OC 138.00 Stl Towr 1.00 1
32 Hammer Substation, UT Butlerville Substaion, UT 138.OC 138.00 Stee Tower 5.00 1
33 Miday Substation, UT Silver Creek Sub, UT 138.0(138.00 Stee Tower 14.00 1
34 Midway Substation, UT Cotonwo Sub, UT 138.0(138.00 Stee Tower 10.00 1
35 McFadden Substation, UT Blackawk Subsation, UT 138.0(138.00 Woo-H 11.00 1
36 TOTAL 16,292.OC 150.00 22
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 03131/2009
RANSMISSION LINE STATISTICS (C ontinued)
7. Do not report the same transmission line structure twce. Report Lower voltge Unes and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If tw or more transmission line struures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the poe miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereo for which the respondent is not the sole owner. If such propert is leased from anher company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement explaining the
arrngement and giving particulars (details) of such matters as percnt ownership by respondent in the line, name of co-oer, bais of sharing
expnses of the Line, and how the expenses bome by the respondent are accunted for, and accunts affected. Specif whether lessor, co-ownr, or
other party is an assoiated company.
9. Designate any transmission line leaed to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cot figures called for in columns 0) to (I) on the bo cost at en of year.
IJU;: I IN"' (InclUde in Column UJ Laa,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construion and Total Cost Operation Maintenance Rents Total ina
Other Costs Expenses Expnses Expnses
(i)(j)(k)(I)(m)(n)(0)(p)No.
ß97.5 62,15 3,545,91~3,60,074 1
95 18,84 853,7~872,57E 2
95 549,00 2,246,411 2,795,475 3
95 222,281 2,430,157 2,652,44~4
~7.5 26 238,86 239,1~5
95 24,901 1,023,94C 1,048,841 6
ß97.5 177,82'6,188,3!6,36,22 7
95 5,17 2,551,86 2,557,04.8
95 56,75 920,61E 977,37,9
95 243,44!3,569,52.3,812,96E 10
ß97.5 253,53!2,258,38 2,511,927 11
1'50 96,45,995,21!1,091,67,12
95 252,891 3,138,911 3,391,802 13
95 46,94,909,121 956,067 14
~7.5 66,45,1,80,241 1,875,69.15
~97.5 25,141 2,178,96 2,204,11.16
~272 668,77 810,472 1,479,24.17
1795 4,055,791 256,181 4,311,981 18
1795 16,66 457,31 474,10 19
95 43,59C 1,272,26E 1,315,85E 20
~272 33,46E 2,500,07.2,53,538 21
b97.5 197,97E 1,555,3!1,753,013 22
~7.5 475,68.2,874,162 3,349,84 23
197.5 145,80 7,83,69 7,981,498 24
197.5 2,940,561 2,940,561 25
97.5 -41 2 -39 26
272 353,104 353,104 27
197.5 246,50~4,038,881 4,285,38 28
272 1 1,104,840 1,104,857 29
272 75!381,90 382,655 30
97.5 40,89 40,890 31
188,391 3,36,794 3,553,185 32
2,770,39 2,770,39E 33
690,02!5,581,57~6,271,59E 34
1,747,452 1,747,45.35
87,473,552 1 ,741,496,237 1,828,969,71*93,331 16,204,99 803,249 17,101,58 36
FERC FORM NO.1 (ED. 12-87)Page 42.5
FERC FORM NO.1 (ED. 12-8 Page 422.6
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) Fi A Resubmission 0331/2009
TRNSMISSION LINE STATIST CS
1. Report information concemin9 trasmission lines, cost of Iines, and expenses for year. List each tramission line having nominal voltage of 132
kilovolts or greater. Report trasmission lines below these voltages in group totas only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Unifor Sysem of Accunts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltges if so require by a State comission.
4. Exclude from this page any transmission lines for which plant coss are included in Accunt 121, Nonutility Propert.
5. Indicate whether the type of supporting structure reorted in column (e) is: (1) single pole wod or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a trasmission line has more than one type of supporting structure, indicate the mileage of each type of constructon
by the use of brackets and extra lines. Minor portions of a transmission line of a diferent ty of construction nee not be distinguished fro the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cot of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a foote, explain the basis of such ocupancy and state whether expenses with
respet to such structures are included in the expnses repoed for the line deignated.
Line (Indicate wtere Typ of LE~GJi~ ~~e óli1eS)NumberNo.other than u ~ergroun~lines Of60 cvcle 3 ohae)Supporting report circuit miles)
Fro To Oprating Designed un ~1!Vciure ugf~W:ps CircuitsStructureof. Line Dèslllated ne(a)(b)(c)(d)(e)(g)(h)
1 West Valley Sub., UT Keams Substation, UT 138.(138.00 Wood.SP 2.00 1
2 Syracuse Substation, UT Clearfield Souh Sub., UT 138.01 138.00 Woo.SP 1.00 1
3 Farmington Substation, UT Parrsh Substation, UT 138.01 138.00 Stee- DC 5.00 1
4 Midvalley Substation, UT Cottonwo Substion, UT 138.01 138.00 Woo. DC 5.00 1
5 Taylorsville Substation, UT West Valley Substion, UT 138.01 138.00 Steel. DC 3.00 3.00 1
6 Dynamo Sub, UT Tri-City Sub, UT 138.01 138.00 Woo.SP 2.OC 2
7 Oqruirr Sub, UT Tri-eity Sub, UT 138.01 138.00 Woo.SP 22.OC 2
8 Bridgerland Sub, UT Green Canyon Sub, UT 138.01 138.00 Woo-SP 16.00 1
9 Bonanza Substation, UT AnadarkolChapita, UT 138.01 138.00 Woo.SP 7.OC 1
10 138 kV expenses
11
12 Subtotal 138 kV 2,140.00 12.00 92
13
14
15 All 115 kV lines 115.01 115.00 Woo & Steel 1,58.00
16 All 69 kV lines 69.01 69.00 Woo & Stee 2,96.OC 1.00
17 All 57 kV lines 57.01 57.00 Woo & Stee 113.OC
18 All 46 kV lines 46.01 46.00 Woo & Stee 2,576.OC
19
20
21 Unclassified Plant at 12/31
22 Pleaant Grove Tap Unclassified Plant 138.0(
23 Herrman-Oquirr Unclassified Plant 138.0(
24 Three Mile Knoll Unclaified Plant 138.0(
25 Meridian-Malin Unclassified Plant 500.0(
26 Walla Walla-Hells Canyon Unclasified Plant 23.
27 Glenrok Wind Plant, WY Windstar 230.230.00 Steel.SP 13.00 1
28 Marengo 2 Wind Plant, WA Marengo 230.230.00 Woo.H 4.00 1
29 Unclassifed Plant (Under $1,00,00 Projects)
30
31
32
33
34
35
36 TOTAL 16,292.OC 150.00 22
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 03131/200
RANSMISSION LINE STATISTICS (( :Ontinued)
7. Do not report the same transmission line structure twce. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expnses of the Line, and how the expenses bome by the respodent are accounted for, and accounts affeced. Specif whether lessor, co-ownr, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Speify whether lessee is an associated company.
10. Base the plant cost figures called for in coumns (j) to (I) on the book cost at end of year.
vv;: i vi- LINt: \include in Column OJ Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-o-way)
Conductor
and Material Lad Construction and Total Cost Opertion Maintenance Rents Total Line
(i)(j)
Other Costs Exenses Expnses (0)Expenses No.(k)(I)(m)(n)(p)
268,234 268,234 1
677,37E 677,376 2
897,031 897,031 3
4,655,525 4,655,525 4
2,OO2,98C 2,00,98(5
-795 9,152,872 9,152,872 6
557 41,06,702 41,06,702 7
272 9,298,221 9,29,221 8
95 KCMACSR 44,95E 44,951 9
1 ,981 ,47E 13,807 1,99,28E 10
11
13,133,561 242,239,001 255,372,561 1,981,47E 13,807 1,99,28E 12
13
14
3,622,801 136,362,125 139,984,92E 1.2,703,404 213,29 2,916,711 15
3,38,191 212,710,64 216,09,84 5,06 2,805,142 117,09 2,927,30!16
41,23'8,722,621 8,763,862 E 44,392 19 44,51*17
6,122,431 192,919,34!199,041,785 83,32~2,342,53E 52,11*2,478,061 18
19
20
21
2,261,m 2,261,775 22
2,987,27(2,987,270 23
3,976,854 3,976,854 24
1,510,366 1,510,36 25
1,542,409 1,542,409 26
272 ACSR 5,233,054 5,233,054 27
95 ACSR 1,505,708 1,505,708 28
14,363,931 14,36,931 29
30
31
32
33
34
35
87,473,552 1,741 ,496,237 1,828,96,71*93,337 16,20,99 803,245 17,101,58 36
FERC FORM NO.1 (ED. 12-87)Page 423.6
Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 031/200 2008/04
FOOTNOTE DATA
¡SChedule Page: 422 Line No.: 4 Column: a
The Alvey - Dixonvile 500kV line is jointly owned by the repondent and the Bonneville Power Administration ("the BPA").
Owership of the line is as follows: PacifiCorp 50.0%, the BPA 50.0%. Cost reported for ths line reflect the respondent's 50.0%
share. Operation and maintenance costs ar shared betee the two paes and responsibilty is as follows: PacifiCorp 58.0% and the
BPA42.0%.
!Shedule Page: 422 Line No.: 6 Column: a
The Dixonville - Meridian 500kV line is jointly owned by the resondent an the Bonnevile Power Admnistrtion ("the BP A").
Owership of the line is as follows: PacifiCorp 50.0%, the BPA 50.0%. Cost reportd for ths line reflects the respondent's 50.0%
shae. Opetion and maintenance costs are shared between the two pares an responsibilty is as follows: PacifiCorp 58.0% and the
BPA42.0%.
¡SChedule Page: 422 Line No.: 7 Column: a
The Colstrp 4 - Switchyard 500kV line is jointly owned by the respondent, NortWeste Corporation, Puet Sound Power & Light,
Washigtn Water Power Company and Portand General Elecc. Owerp of the line is as follows: PacifiCorp 6.8%, all others
93.2%. Plant cost and operation and matece costs rertd for ths line reflec th respondent's shae.
¡SChedule Page: 422 Line No.: 8 Column: a
The Colstrp - Broadview A 500kV line is jointy owned by the respndent, NortWest Corpraon, Puget Sound Power & Light,
Washingtn Water Power Company and Portand Generl Elecc. Owerhip of the line is as follows: PacifiCorp 6.8%, all others
93.2%. Plant cost and operation and maintee cost rert for ths line reflec th respondent's share.
¡SChedule Page: 422 Line No.: 9 Coumn: a
The Colstrp - Broadview B 500kV line is jointly owned by th respondent, NortWestrn Corpration, Puet Sound Power & Light,
Washigton Water Power Company and Portand General Elecc. Owerhip of the line is as follows: PacifiCorp 6.8%, all others
93.2%. Plant cost and operation and maintenance cost reportd for ths line reflects th respondent's share.
¡Shedule Page: 422 Line No.: 10 Column: a
The Broadview - Townsend A 500kV line is jointly owned by the reondent, NortWestern Corporation, Puget Sound Power &
Light, Washington Water Power Compay and Portand Geera Electc. Owerhip of the line is as follows: PacifiCorp 8.1%, all
others 91.9"10. Plant cost and operation and maintnance cost report for ths line reflect the respondent's shar.
¡Schedule Page: 422 Line No.: 11 Column: a
The Broadview- Townsend B 500kV line is jointy owned by the respondent, NortWestern Corporation, Puget Sound Power &
Light, Washington Water Power Compay and Portand Gener Electc. Owerhip of the line is as follows: PacifiCorp 8.1%, all
others 91.9"10. Plant cost and operation and mainteance costs reported for this line reflect the respndent's shar.
¡SChedule Page: 422.2 Line No.: 17 Column: f
The Sherida - Decker 230kV line wa sold durg 2008.
IFERC FORM NO.1 (ED. 12-87)
............................................
Blank Page
(Next Page is 424)
FERC FORM NO.1 (REV. 12-03)Page 424
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 0331/200
RANSMISSION LINES ADDED DUR NG YEAR
1. Report below the information called for concerning T.ransmission lines added or altered during the year.It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (I) to (0), it is pennissible to report in these columns the
Line LINE L~~9th PE R til
No.From To in Type N~;;''b:lPer Present UltimateMilesMiles
(a)(b)(c)(d)(e)(f)(g)
1 Ninetieth Souh Sub., UT Hale Plant, UT 4.00 WooSP 14.00 1 1
2 Three Mile Knoll Sub., ID Grace #1, ID 2.00 WooSP 14.00 1 1
3 Three Mile Knoll Sub., ID Grace #2, ID 2.00 WooSP 14.OC 1 1
4 Soda Plant, ID Monsanto 1 Sub., ID 2.00 WooSP 14.OC 1 1
5 Soda Plant, ID Monsanto 2 Sub., ID 2.00 WooSP 14.OC 1 1
6 Glenrock Wind Plant, WY Windstar Substion, WY 13.00 Stee- SP 11.OC 1 1
7 Marengo Wind Plant, WA Marengo, WA 4.00 Woo- H 8.OC 1 1
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 29.OC 89.00 7 i
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 20004
(2) Ei A Resubmission 03131/200
TRAN MISSION LINES ADDED DURING Y AR (Continued
costs. Designate, however, if estimated amounts are r~ported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (i) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
JHö Voltage Line
Size Speification Conf~uration KV Lad and Poles, Towers Conductors Asset Total No.
(h)
and pacing (OP1kiting)Land(~i9hts and Fixtures and ?~viCes Retirlöfosts
(D)(i)Q)(m)
1272 ACSR Vertical 10' 138 1,264,oo 1,480,174 2,745,078 1
1272 ACSR Vertical 10' 138 310,071 310,073 620,147 2
1272 ACSR Vertical 10' 138 321,10!321,108 642,217 3
1272 ACSR Vertical 10' 138 278,2(278,620 557,240 4
1272 ACSR Vertcal 10' 138 276,771 276,774 553,548 5
1272 ACSR Verical10'230 2,616,52 2,616,527 5,233,054 6
795 ACSR Vertical 10' 230 752,851 752,854 1,505,708 7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
5,820,86,6,03,130 11,85,99 44
FERC FORM NO.1 (REV. 120()Page 425
I FERC FORM NO.1 (ED. 12-87)Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) . A Resubmission 0331/209 200/04
FOOTNOTE DATA
¡Schedule Page: 424 Line No.: 1 Column: c
The Ninetieth South to Hale Plant line was converted frm an existig 46kV line to a 138kV line.
............................................
Blank Page
(Next Page is 426)
FERC FORM NO.1 (ED. 12-9)Page 42
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr)End of 200Q4
(2)A Resubmission 0331/200
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
Name and Location of Substation Charcter of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Califomia
2 BELMONT SUB DISTRIBUTION-UNATTEN 69.00 12.47
3 BIG SPRINGS SUB DISTRIBUTION-UNATTEN 69.00 12.47
4 CANBY#2 DISTRIBUTION-UNATTEN 69.OC 2.40
5 CASTELLA SUB DISTRIBUION-UNATTEN 69.OC 2.40
6 CLEAR LAKE SUB DISTRIBUTION-UNATTEN 69.OC 12.47
7 CRESCENT CITY SUB DISTRIBUTION-UNATTEN 12.41 4.16
8 DOG CREEK SUB DISTRIBUTION-UNATTEN 69.OC 2.40
9 DORRIS SUB DISTRIBUTION-UNATTEN 69.00 12.47
10 FORT JONES SUB DISTRIBUTION-UNATTEN 69.00 12.47
11 GASaUETSUB DISTRIBUTION-UNATTEN 115.00 12.47
12 GREENHORN SUB DISTRIBUTION-UNATTEN 69.00 12.47
13 HAMBURG SUB DISTRIBUTION-UNATTEN 69.00 2.40
14 HAPPY CAMP SUB DISTRIBUTION-UNATTEN 69.00 12.47
15 HORNBROOK SUB DISTRIBUTION-UNATTEN 69.00 12.47
16 INTERNATIONAL PAPER SUB DISTRIBUTON-UNATTEN 69.00 2.40
17 LAKE EARL SUB DISTRIBUTION-UNATTEN 69.00 12.47
18 LITTLE SHASTA SUB DISTRIBUTON-UNATTEN 69.00 7.20
19 LUCERNE SUB DISTRIBUTION-UNATTN 69.00 12.47
20 MACDOEL SUB DISTRIBUTION-UNATTEN 69.00 20.80
21 MCCLOUD SUB DISTRIBUTION-UNATTEN 69.00 12.47
22 MILLER REDWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 MONTAGUE SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 MOUNT SHASTA SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 NEWELL SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 NORTH DUNSMUIR SUB DISTRIBUTION-UNATTEN 69.00 12.47
27 NORTHCREST SUB DISTRIBUTION-UNATTEN 69.00 12.47
28 NUTGLADE SUB DISTRIBUTION-UNATTEN 69.00 2.40
29 PATRICKS CREEK SUB DISTRIBUTION-UNATTEN 115.00 7.20
30 PEREZ SUB DISTRIBUION-UNATTEN 69.00 12.47
31 REDWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 SCOTT BAR SUB DISTRIBUTION-UNATTEN 69.00 12.47
33 SEIAD SUB DISTRIBUTION-UNATTEN 69.00 12.47
34 SHASTINA SUB DISTRIBUTION-UNATTEN 69.00 20.80
35 SHOTGUN CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 SIMONSON SUB DISTRIBUTION-UNATTEN 69.00 12.47
37 SMITH RIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 SNOW BRUSH SUB DISTRIBUTION-UNATTEN 69.00 7.20
39 SOUTH DUNSMUIR SUB DISTRIBUION-UNATTEN 69.00 4.16
40 TULELAKE SUB DISTRIBUTION-UNATTEN 69.00 12.47
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo8/Q4
(2) ñ A Resubmission 03131/200
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownrship or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting betwen the parties, and state amounts and accounts
affected in respondent's books of account. . Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Servce) (In MVa)Transformers Spare Type of Equipment Total Capcity No.In Servce Transformers Number of Units
(In MVa)(f (a)(h)(i)(j (k)
1
25 1 2
6 1 3
1 3 4
2 3 5
4 3 6
3 6 7
1 8
8 3 9
6 1 10
9 1 11
13 1 12
1 1 13
8 3 14
4 3 15
9 3 16
13 1 17
2 3 18
4 1 19
31 2 20
6 1 21
4 3 22
6 1 23
16 4 24
8 3 25
6 6 26
20 4 27
2 3 28
1 1 29
2 3 30
9 3 31
2 3 32
2 3 33
18 3 34
1 1 35
5 3 36
6 3 37
3 38
2 3 39
20 1 40
FERC FORM NO.1 (ED. 12-9)Page 427
FERC FORM NO.1 (ED. 12-9)Page 426.1
............................................
Name of Respondent ThiS~ortis:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 0331/200
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those servng customers with energy for resle, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
Name and Location of Substation Charaer of SubsttionNo.Primary Secondry Tertiary
(a)(b)(c)(d)(e)
1 TUNNEL SUB DISTRIBUTON-UNATTEN 69.00 12.47
2 TURKEY HILL SUB DISTRIBUTION-UNATTEN 69.00 12.47
3 WALKER BRYAN SUB DISTRIBUTION-UNATTEN 69.00 12.47
4 WEED SUB DISTRIBUTION-UNATTEN 115.00 12.47
5 YUBA SUB DISTRIBUTION-UNATTEN 69.00 12.47
6 YUROKSUB DISTRIBUTION-UNATTEN 69.00 12.47
7 Total 3186.47 48.96
8 Number of Substations- 45
9
10 ALTURAS TID-UNATTENDED 115.00 12.47 69.00
11 FALL CREEK HYDRO/SUB TIDUNATTENDED 69.00 2.30
12 YREKA SUB TID-UNATTENDED 115.00 12.47 69.00
13 Total 29.00 27.24 138.00
14 Number of Substations- 3
15
16 AGERSUB TRANSMISSION-ATTEND 115.00 69.00
17 COPCO #1 HYDRO PLANT TRANSMISSION-ATTEND 69.OC 2.30
18 COPCO #2 230 SUB TRANSMISSION-ATTEND 230.00 115.00
19 COPCO #2 HYDRO PLANT TRANSMISSION-ATTEND 69.OC 6.60
20 COPCO #2 SUB TRANSMISSION-ATTEND 69.OC 12.47
21 CRAG VIEW SUB TRANSMISSION-UNATTEN 115.00 69.00
22 DEL NORTE SUB TRANSMISSION-UNATTEN 115.OC 69.00
23 IRON GATE HYDRO PLANT TRANSMISSION-UNATTEN 69.00 6.60
24 WEED JUNCTION SUB TRANSMISSION-UNATTEN 115.00 69.00
25 Total 96.00 418.97
26 Number of Substations- 9
27
28 Idaho
29 ALEXNDER DISTRIBUTION-UNATTEN 46.00 12.47
30 AMMON DISTRIBUTION-UNATTEN 69.00 12.47
31 ANDERSON DISTRIBUTION-UNATTEN 69.00 12.47
32 ARCO DISTRIBUTION-UNATTEN 69.00 12.47
33 ARIMO DISTRIBUTION-UNATTEN 46.00 12.47
34 BANCROFT SUB DISTRIBUTION-UNATTEN 46.00 12.47
35 BELSON SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 BERENICE SUB DISTRIBUTION-UNATTEN 69.00 12.47
37 CAMAS SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 CANYON CREEK SUB DISTRIBUTION-UNATTEN 69.00 24.90
39 CHESTERFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 CINDER BUTTE SUB DISTRIBUnON-UNATTEN 161.00 12.47
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 0331/200
SUBSTATIONS (Continued)
5. Show in columns (I), G), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner .or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Servce) (In MVa)Transformers Spare Type of Equipment Total Capcity No.In Service Transformers Number of Units
(f (a)(h)(j)(i (in:ia)
6 6 1
13 3 2
7 1 3
25 1 4
4 3 5
4 3 6
34 113 7
8
9
31 4 10
3 3 11
95 2 12
129 9 13
14
15
5 3 16
28 6 2 17
375 2 18
60 3 1 19
2 3 20
19 3 21
150 2 22
19 1 23
38 3 24
696 26 3 25
26
27
28
4 1 29
14 1 30
20 1 31
6 1 32
8 1 33
4 1 34
13 1 35
11 1 36
14 1 37
20 1 38
5 1 39
30 1 1 40
FERC FORM NO.1 (ED. 12-9)Page 427.1
FERC FORM NO.1 (ED. 12-9)Page 426.2
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) D A Resubmission 0331/2009
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resle, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Loction of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 CLEMENTS SUB DISTRIBUTION-UNATTEN 69.00 12.47
2 CLIFTON SUB DISTRIBUTION-UNATTEN 46.OC 12.47
3 COVE SUB DISTRIBUTION-UNATTEN 46.OC 6.60
4 DOWNEY SUB DISTRIBUTION-UNATTEN 46.00 12.47
5 DUBOIS SUB DISTRIBUTION-UNATTEN 69.00 12.47
6 EASTMONT SUB DISTRIBUTION-UNATTEN 69.00 12.47
7 EGINSUB DISTRIBUTION-UNATTEN 69.00 12.47
8 EIGHT MILE SUB DISTRIBUTION-UNATTEN 46.00 12.47
9 GEORGETOWN SUB DISTRIBUTION-UNATTEN 69.00 12.47
10 GRACE CITY SUBSTATION DISTRIBUTION-UNATTEN 46.00 12.47
11 HAMER SUB DISTRIBUTION-UNATTEN 69.00 12.47
12 HAYES SUB DISTRIBUTION-UNATTEN 69.00 12.47
13 HENRY SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 HOLBROOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
15 HOOPES SUB DISTRIBUTION-UNATTEN 69.00 12.47
16 HORSLEY SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 IDAHO FALLS SUB DISTRIBUTION-UNATTEN 46.00 12.47
18 INDIAN CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 JEFFCOSUB DISTRIBUTION-UNATTEN 69.00 24.90
20 KETLE SUB DISTRIBUTION-UNATTEN 69.00 24.90
21 LAVA SUB DISTRIBUTION-UNATTEN 46.00 12.47
22 LUND SUB DISTRIBUTION-UNATTEN 46.00 12.47
23 MCCAMMON SUB DISTRIBUTION-UNATTEN 46.00 12.47
24 MENAN SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 MERRILL SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 MILLER SUB DISTRIBUION-UNATTEN 69.00 12.47
27 MONTPELIER SUB DISTRIBUTION-UNATTEN 69.00 12.47
28 MOODY SUB DISTRIBUTION-UNATTEN 69.00 24.90
29 NEWDALE SUB DISTRIBUTION-UNATTEN 69.OC 12.47
30 OSGOOD SUB DISTRIBUTION-UNATTEN 69.0C 12.47
31 PRESTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
32 RAYMOND SUB DISTRIBUTION-UNATTEN 69.00 12.47
33 RENO SUB DISTRIBUTION-UNATTEN 69.00 12.47
34 REXURG SUB DISTRIBUTION-UNATTEN 69.00 12.47
35 RIRIE SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 ROBERTS SUB DISTRIBUTION-UNATTEN 69.00 12.47
37 RUDY SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 SAND CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
39 SANDUNESUB DISTRIBUTION-UNATTEN 69.00 24.90
40 SHELLEY SUB DISTRIBUTION-UNATTEN 46.00 12.47
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) Õ A Resubmission 03/31/200
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capcity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Una
(In Service) (In MVa)Transormers Spare Type of Equipment Total Capcity No.In Servce Transformers Number of Units
(In MVa)
(f)(g)(h)(i (0 (k)
5 1 1
4 1 2
21 4 3
5 1 4
13 1 5
14 1 6
14 1 7
3 1 8
6 1 9
5 1 10
14 1 11
9 1 12
3 1 13
6 1 14
9 1 15
4 1 16
20 1 17
3 1 18
22 1 19
14 1 20
3 1 21
5 1 22
3 1 23
11 1 24
20 1 25
5 1 26
8 1 27
14 1 28
20 1 29
20 1 30
13 1 31
2 1 32
20 1 33
33 2 34
9 1 35
8 1 36
7 1 37
40 2 38
20 1 39
20 1 40
FERC FORM NO.1 (ED. 12-9)Page 427.2
FERC FORM NO. 1 (ED. 12-9)Page 426.3
............................................
Name of Respondent This ~rtIS:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 208fQ4
(2) 0 A Resubmission 0331/200
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those servng customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Chaer of Substion
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 SMITH SUB DISTRIBUTION-UNATTEN 69.00 12.47
2 SODASUB DISTRIBUTION-UNATTEN 138.00 7.20
3 SOUTH FORK SUB DISTRIBUTION-UNATTEN 69.00 12.47
4 SPUD SUB DISTRIBUTION-UNATTEN 46.00 12.47
5 ST. CHARLES SUB DISTRIBUTION-UNATTEN 69.00 12.47
6 SUGAR CITY SUB D1STRIBUTION-UNATTEN 69.00 12.47
7 SUNNYDELL SUB DISTRIBUTION-UNATTEN 69.OC 12.47
8 TANNER SUB DISTRIBUTION.UNATTEN 46.00 12.47
9 TARGHEE SUB DISTRIBUTION-UNATTEN 46.00 12.47
10 THORNTON SUB DISTRIBUTION-UNATTEN 69.OC 12.47
11 UCONSUB DISTRIBUTION.UNATTEN 69.OC 12.47
12 WATKINS SUB DISTRIBUION-UNATTEN 69.00 12.47
13 WEBSTER SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 WESTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
15 WINDSPER SUB DISTRIBUTION-UNATTEN 69.00 24.90
16 Total 4301.00 898.93
17 Number of Substations- 67
18
19 MALAD SUB TID-UNATTENDED 138.00 46.00 12.47
20 MUD LAKE SUB TIDUNATTENDED 69.00 12.47
21 RIGBY SUB TIDUNATTNDED 161.00 12.47 69.00
22 SAINT ANTHONY SUB TID-UNATTENDED 69.OC 46.00 12.47
23 Totl 437.OC 116.94 93.94
24 Number of Substations- 4
25
26 GRACE HYDRO TRANSMISSION-ATTEND 138.00 46.00 6.60
27 AMPS SUB TRASMISSION-UNATTEN 230.00 69.00
28 ANTELOPE SUB TRSMISSION-UNATTEN 230.00 161.00
29 ASHTON PLANT TRSMISSION-UNATTEN 46.00 2.40
30 BIG GRASSY SUB TRASMISSION-UNATTEN 161.00 69.00
31 BONNEVILLE SUB TRASMISSION-UNATTEN 161.00 69.00
32 CARIBOU SUB TRASMISSION-UNATTEN 138.00 46.00
33 CONDASUB TRASMISSION-UNATTEN 138.00 46.00
34 FISH CREEK SUB TRASMISSION-UNATTEN 161.OC 46.00
35 FRANKLIN SUB TRANSMISSION-UNATTEN 138.OC 46.00
36 GOSHEN SUB TRANSMISSION-UNATTEN 34.OC 161.00 46.00
37 JEFFERSON SUB TRASMISSION-UNATTEN 161.OC 69.00
38 LIFTON HYDRO TRANSMISSION-UNATTEN 69.0(2.30
39 ONEIDA SUB TRASMISSION-UNATTEN 138.OC 12.50
40 OVID SUB TRASMISSION-UNATTEN 138.OC 69.00
............................................
Name of Respondent ThisWrtlS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 20004
(2) i: A Resubmission 03131/2009
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Servce) (In MVa)Transformers Spare Typ of Equipment Total Capcity No.In Servce Transformers Number of Units
(f (a)(h)(i CD
(In (~~a)
20 1 1
22 1 2
14 1 3
8 1 4
5 1 5
13 1 6
13 1 7
4 1 8
4 1 9
7 1 10
7 1 11
14 1 12
20 1 13
4 1 14
20 1 15
799 72 1 16
17
18
71 4 1 19
14 1 20
189 4 21
40 2 22
314 11 1 23
24
25
115 4 26
75 2 1 27
250 1 28
25 3 29
67 1 30
67 1 31
27 1 32
67 1 33
25 3 34
75 1 35
763 8 1 36
233 3 37
6 2 38
40 2 39
30 1 40
FERC FORM NO.1 (ED. 12-9)Page 427.3
FERC FORM NO.1 (ED. 12-9)Pag 42.4
............................................
Name of Respondent This '(rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo8lQ4
(2) i: A Resubmission 0331/20
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resle, may be grouped accrding
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
Name and Location of Substation Chaer of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 SCOVILLE SUB TRASMISSION-UNATIEN 138.00 69.00 46.00
2 SUGARMILL SUB TRASMISSION-UNATIEN 161.00 46.00 69.00
3 THREEMILE KNOLL SUB TRANSMISSION-UNATIEN 34.00 138.00 46.00
4 TREASURETON SUB TRANSMISSION-UNATIEN 230.00 138.00
5 Total 326.00 1305.20 213.60
6 Number of Substations- 19
7
8 Oregon
9 26TH STREET DISmIBUTION-UNATIEN 20.80 4.16
10 35TH STREET DISTRIBUTION-UNATIEN 20.80 2.40
11 AGNESS AVE DISTRIBUTION-UNATIEN 115.00 12.47
12 ALDERWOOD DISTRIBUTION-UNATIEN 69.00 12.47
13 ARLINGTON DISTRIBUION-UNATIEN 69.00 12.47
14 ATHENA DISTRIBUION-UNATIEN 69.00 12.47
15 BANDON TIE SUB DISTRIBUTION-UNATIEN 20.&12.47
16 BEACON SUB DISTRIBUTION-UNATIEN 69.00 12.47
17 BEALL LANE SUB DISTRIBUTION-UNATIEN 115.OC 12.47
18 BEATISUB DISTRIBUTION-UNATIEN 69.OC 12.47
19 BELKNAP DISTRIBUTION-UNATIEN 69.00 12.47
20 BLALOCK SUB DISTRIBUTION-UNATIEN 69.OC 12.47
21 BLOSS SUB DISTRIBUTION-UNATIEN 115.00 12.47
22 BLYSUB DISTRIBUTION-UNATIEN 69.OC 12.47
23 BOISE CASCADE SUB DISmIBUTION-UNATIEN 69.OC 11.00
24 BONANZA SUB DISmIBUTION.UNATIEN 69.OC 12.47
25 BOND STREET SUB DISmIBUTION-UNATIEN 69.00 12.50
26 BROOKHURST SUB DISTRIBUTION-UNATIEN 115.00 12.47
27 BROWNSVILLE SUB DISmIBUTION-UNATIEN 69.00 20.80
28 BRYANT SUB DISTRIBUTION-UNATIEN 69.00 12.47
29 BUCHANAN SUB DISTRIBUTION-UNATIEN 115.00 20.80
30 BUCKAROO SUB DISTRIBUTION-UNATIEN 69.00 12.47
31 CAMPBELL SUB DISTRIBUTION-UNATIEN 115.00 12.47
32 CANNON BEACH SUB DISTRIBUTION-UNATIEN 115.00 12.47
33 CARNES SUB DISTRIBUTION-UNATIEN 69.00 12.47
34 CASEBEER SUB DISTRIBUTION-UNATIEN 69.00 20.80
35 CAVEMAN SUB DISTRIBUTION-UNATIEN 115.00 12.47
36 CHERRY LANE SUB DISTRIBUTION.UNATIEN 69.00 12.47
37 CHILOQUIN MARKET SUB DISTRIBUTION-UNATIEN 69.00 12.47
38 CHINA HAT SUB DISTRIBUTION-UNATIEN 69.00 12.47
39 CIRCLE BLVD SUB DISTRIBUTION-UNATIEN 115.00 20.80
40 CLEVELAND AVE SUB DISTRIBUTION-UNATIEN 69.00 12.47
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 200804
(2) ri A Resubmission 03/31/200
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capcity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)(f (a)(h)(i)en (k)
76 2 1
168 3 2
700 1 3
533 2 4
332 42 2 5
6
7
8
5 1 9
30 6 10
25 1 11
25 1 12
5 1 13
9 1 14
8 3 1 15
11 3 16
25 1 17
6 1 18
40 2 19
2 3 20
32 2 21
8 3 22
3 1 23
8 3 24
25 1 25
50 2 26
13 1 27
34 2 28
40 2 29
34 2 30
20 1 31
13 1 32
9 3 33
20 1 34
45 2 35
25 1 36
5 3 37
25 1 38
80 2 39
45 2 40
FERC FORM NO.1 (ED. 12-9)Page 42.4
FERC FORM NO.1 (ED. 12-9)Page 426.5
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 0331/200
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substion Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 CLINE FALLS HYDRO DISTRIBUTION-UNATTEN 12.47 2.40
2 CLOAKESUB DISTRIBUTION-UNATTEN 69.00 20.80
3 COBURG SUB DISTRIBUTION-UNATTEN 69.00 20.80
4 COLISEUM SUB DISTRIBUTION-UNATTEN 20.80 4.16
5 COLUMBIA SUB DISTRIBUTION-UNATTEN 115.00 12.47 57.00
6 COOS RIVER SUB DISTRIBUION-UNATTEN 115.00 20.80
7 COQUILLE SUB DISTRIBUTON-UNATTEN 115.00 20.80
8 CREEK SUB DISTRIBUTION-UNATTEN 69.00 34.50
9 CROOKED RIVER RANCH SUB DISTRIBUTON-UNATTEN 69.00 20.80
10 CROWFOOT SUB DISTRIBUTION-UNATTEN 115.00 12.47
11 CULLY SUB DISTRIBUTION-UNATTEN 115.00 12.47
12 CULVER SUB DISTRIBUTION-UNATTEN 69.00 12.47
13 CUTLER CITY SUB DISTRIBUTION-UNATTEN 20.80 4.16
14 DAIRY SUB DISTRIBUTION-UNATTEN 69.00 12.47
15 DALLAS SUB DISTRIBUTION-UNATTEN 115.00 20.80
16 DALREEDSUB DISTRIBUTION-UNATTEN 230.00 34.50
17 DESCHUTES SUB DISTRIBUTION-UNATTEN 69.00 12.47
18 DEVILS LAKE SUB DISTRIBUTION-UNATTEN 115.OC 20.80
19 DIXON SUB DISTRIBUTION-UNATTEN 115.00 4.16
20 DODGE BRIDGE SUB DISTRIBUTION-UNATTEN 69.00 20.80
21 EAST VALLEY SUB DISTRIBUTION-UNATTEN 115.00 12.47
22 EMPIRE SUB DISTRIBUTION-UNATTEN 115.OC 20.80
23 ENTERPRISE SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 FERN HILL SUB DISTRIBUTION-UNATTEN 115.00 12.47
25 FIELDER CREEK SUB DISTRIBUTION-UNATTEN 115.00 20.80
26 FOOTHILLS SUB DISTRIBUTION-UNATTEN 69.00 12.47
27 FRALEY SUB DISTRIBUTION-UNATTEN 69.00 12.47
28 GARDEN VALLEY SUB DISTRIBUTION-UNATTEN 69.00 20.80
29 GAZLEY SUB DISTRIBUTION-UNATTEN 69.00 12.47
30 GLENDALE SUB DISTRIBUTION-UNATTEN 230.00 12.47
31 GLENEDEN SUB DISTRIBUTION-UNATTEN 20.80 4.16
32 GLIDE SUB DISTRIBUTON-UNATTEN 115.00 12.47
33 GOLD HILL SUB DISTRIBUnON-UNATTEN 69.00 12.47
34 GORDON HOLLOW SUB DISTRIBUTION-UNATTEN 69.00 12.47
35 GOSHEN SUB DISTRIBUTION-UNATTEN 115.00 20.80
36 GRANT STREET SUB DISTRIBUTION-UNATTEN 115.00 20.80
37 GRASS VALLEY SUB DISTRIBUTION-UNATTEN 20.80 4.16
38 GREEN SUB DISTRIBUTION-UNATTEN 69.00 12.47
39 GRIFFIN CREEK SUB DISTRIBUnON-UNATTEN 115.00 12.47
40 HAMAKER SUB DISTRIBUTON-UNATTEN 69.00 12.47
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) i: A Resubmission 03131/200
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)Transformers Spae Type of Equipment Total Capacity No.In Service Transformers Number of Units
(f (g)(h)(i)0)
(In (~~a)
1 3 1
20 1 2
1 3 3
9 2 4
55 2 1 5
20 1 6
40 2 7
5 1 8
25 2 9
20 1 10
25 1 11
13 1 12
2 3 13
25 1 14
50 2 15
75 3 16
13 1 17
50 2 18
7 1 19
13 1 20
45 2 21
20 1 22
19 2 23
13 1 24
25 1 25
21 4 26
5 3 27
20 1 28
8 3 29
25 2 30
5 1 31
13 1 32
11 3 33
6 1 34
20 1 35
45 2 36
1 4 37
25 1 38
20 1 39
8 3 40
FERC FORM NO.1 (ED. 12-9)Page 427.5
FERC FORM NO.1 (ED. 12-9)Page 426.6
............................................
Name of Respondent Thls~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) Õ A Resubmission 0331/2009
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substaion
Primary Secondar Tertiary
(a)(b)(c)(d)(e)
1 HARRISBURG SUB DISTRIBUTION-UNATIEN 69.00 20.80
2 HENLEY SUB DISTRIBUTION-UNATIEN 69.00 12.47
3 HERMISTON SUB DISTRIBUTION-UNATIEN 69.00 12.47
4 HILLVIEW SUB DISTRIBUTION-UNATIEN 115.00 20.80
5 HINKLE SUB DISTRIBUTION-UNATIEN 69.00 12.47
6 HOLLADAY SUB DISTRIBUTION-UNATIEN 115.00 12.47
7 HOLLYWOOD SUB DISTRIBUTION-UNATIEN 115.00 12.47
8 HOOD RIVER SUB DISTRIBUTION-UNATIEN 69.00 12.47
9 HORNET SUB DISTRIBUTION-UNATIEN 69.00 12.47
10 INDEPENDENCE SUB DISTRIBUTION-UNATIEN 69.00 20.80
11 JACKSONVILLE SUB DISTRIBUTION-UNATIEN 115.00 12.47 69.00
12 JEFFERSON SUB DISTRIBUTION-UNATIEN 69.00 20.80
13 JEROME PRAIRIE SUB DISTRIBUTION-UNATIEN 115.00 12.47
14 JORDAN POINT SUB DISTRIBUTION-UNATIEN 115.00 12.47
15 JOSEPH SUB DISTRIBUTION-UNATIEN 20.80 12.47
16 JUNCTION CITY SUB DISTRIBUTON-UNATIEN 69.00 20.80
17 KENWOOD SUB DISTRIBUTION-UNATTN 69.00 12.47
18 KILLINGWORTH SUB DISTRIBUTION-UNATIEN 69.00 12.47
19 KNAPPA SVENSEN SUB DISTRIBUnON-UNATIEN 115.00 12.47
20 LAKEPORT SUB DISTRIBUTION-UNATIEN 69.00 12.47
21 LAKEVIEW SUB DISTRIBUTION-UNATIEN 69.00 12.47
22 LANCASTER SUB DISTRIBUTION-UNATIEN 69.00 20.80
23 LEBANON SUB DISTRIBUTION-UNATIEN 115.00 20.80
24 LINCOLN SUB DISTRIBUTION-UNATIEN 115.00 12.47
25 LOCKHART SUB DISTRIBUTION-UNATIEN 115.00 20.80
26 LYONS SUB DISTRIBUTION-UNATIEN 69.00 20.80
27 MADRAS SUB DISTRIBUTION-UNATIEN 69.00 12.47
28 MALLORY SUB DISTRIBUTION-UNATIEN 115.00 12.47
29 MARYS RIVER SUB DISTRIBUION-UNATIEN 115.00 20.80
30 MEDCOSUB DISTRIBUTION-UNATIEN 115.00 12.47
31 MEDFORD DISTRIBUTION-UNATIEN 69.00 12.47
32 MERLIN SUB DISTRIBUTION-UNATIEN 115.00 12.47
33 MERRILL SUB DISTRIBUTION-UNATIEN 69.00 12.47
34 MINAMSUB DISTRIBUTION-UNATIEN 69.00 12.47
35 MODOC SUB DISTRIBUTION-UNATIEN 69.00 12.47
36 MOROSUB DISTRIBUTION-UNATIEN 20.80 2.40
37 MURDER CREEK SUB DISTRIBUTION-UNATIEN 115.00 20.80
38 MYRTLE CREEK SUB DISTRIBUTION-UNATIEN 69.00 12.47
39 MYRTLE POINT SUB DISTRIBUTION-UNATTEN 115.00 20.80
40 NELSCOTISUB DISTRIBUTION-UNATIEN 20.80 4.16
............................................
Name of Respondent ThiS~!Ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/200
SUBSTATIONS (Continued)
5. Show in columns (I), (j, and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Servce) (In MVa)Transformers Spare Type of Equipment Total Capcity No.In Servce Transformers Number of Units
(f)(g)(hl (i (j (In (~va)
13 1 1
6 3 2
40 2 3
45 2 4
20 1 5
75 3 6
50 2 7
40 2 8
20 1 9
20 1 10
75 2 11
13 1 12
20 1 13
20 1 14
6 1 1 15
25 2 16
3 3 17
40 2 18
6 1 19
50 2 20
9 3 21
13 3 22
40 2 23
105 3 24
40 2 25
9 1 26
25 2 27
25 1 28
20 1 29
20 1 30
79 14 31
45 2 32
17 6 33
1 34
6 3 35
2 3 36
100 4 37
14 1 38
9 1 39
4 1 40
I
FERC FORM NO.1 (ED. 12-9)Page 427.6
FERC FORM NO.1 (ED. 12-9)Pag 426.7
............................................
Name of Respondent This ~~ortis:Date of Report Year/Period of Report
PacifiCorp (1)~An Original (Mo, Da, Yr)End of 2004
(2)A Resubmission 03131/200
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those servng customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Loction of Substation Character of Substation Primary Secndary Tertiary
(a)(b)(c)(d)(e)
1 NEW O'BRIEN SUB DISTRIBUTION-UNATTEN 115.00 12.47
2 OAK KNOLL SUB DISTRIBUTION-UNATTEN 115.00 12.47
3 OAKLAND SUB DISTRIBUTION-UNATTEN 115.00 12.47
4 ORCHARD STREET SUB DISTRIBUTION-UNATTEN 12.41 4.16
5 OVERPASS SUB DISTRIBUTION-UNATTEN 69.00 12.47
6 PALLETTE SUB DISTRIBUTION-UNATTEN 69.00 20.80
7 PARK STREET SUB DISTRIBUTION-UNATTEN 115.00 12.47
8 PARKROSE SUB DISTRIBUTION-UNATTEN 57.00 12.47
9 PENDLETON SUB DISTRIBUTION-UNATTEN 69.00 12.47
10 PILOT ROCK SUB DISTRIBUTION-UNATTEN 69.00 12.47
11 POWELL BUTTE SUB DISTRIBUTION-UNATTEN 115.00 12.47
12 PRINEVILLE SUB DISTRIBUTION-UNATTEN 115.00 12.47
13 PROVOLTSUB DISTRIBUTION-UNATTEN 69.DC 12.47
14 QUEEN AVE SUB DISTRIBUTION-UNATTEN 69.DC 20.80
15 RED BLANKET SUB DISTRIBUTON-UNATTEN 59.DC 4.16
16 REDMOND SUB DISTRIBUTION-NATTEN 115.DC 12.47
17 RICH MANUFACTURING SUB DISTRIBUTION-UNATTEN 57.DC 12.47
18 RIDDLE SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 RIDDLE VENEER SUB DISTRIBUTION-UNATTEN 69.00 12.47
20 ROGUE RIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47
21 ROSEBURG SUB DISTRIBUTION-UNATTEN 115.00 20.80
22 ROSS AVE SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 ROXY ANN SUB DISTRIBUTION-UNATTEN 115.00 12.50
24 RUCH SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 RUNNING Y SUB DISTRIBUTION-UNATTEN 69.00 20.80
26 RUSSELLVILLE SUB DISTRIBUTION-UNATTEN 115.00 12.47
27 SAGE ROAD SUB DISTRIBUTION-UNATTEN 115.00 12.47
28 SCENIC SUB DISTRIBUTION-UNATTEN 115.00 12.47 69.00
29 SCIOSUB DISTRIBUTION-UNATTEN 69.00 12.47
30 SEASIDE SUB DISTRIBUTION-UNATTEN 115.00 12.47
31 SELMA SUB DISTRIBUTION-UNATTEN 115.00 12.47
32 SHASTA WAY SUB DISTRIBUTION-UNATTEN 12.47 4.16
33 SHEVLIN PARK DISTRIBUTION-UNATTEN 69.00 12.50
34 SIMTAG BOOSTER PUMP DISTRIBUION-UNATTN 34.50 4.16
35 SOUTH DUNES SUB DISTRIBUION-UNATTEN 115.00 12.47
36 SOUTHGATE SUB DISTRIBUTION-UNATTEN 69.00 20.80
37 SPRAGUE RIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 STATE STREET SUB DISTRIBUTION-UNATTEN 115.00 20.80
39 STAYTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
40 STEAMBOAT SUB DISTRIBUTION-UNATTEN 115.00 7.20
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ri A Resubmission 03/31/200
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Typ of Equipment Total Capacity No.In Service Transformers Number of Units
If (0)(h)(i)0)
(In (~~a)
9 1 1
45 2 2
8 1 3
2 3 4
45 2 5
1 1 1 6
40 2 7
39 2 8
46 7 1 9
22 2 10
6 1 11
50 2 12
11 3 13
50 2 14
2 3 15
50 2 16
8 1 17
14 1 18
25 1 19
.25 2 20
50 2 21
9 3 22
25 1 23
9 1 24
9 1 25
45 2 26
40 2 27
70 3 28
8 1 29
40 2 30
9 1 31
2 3 32
25 1 33
19 2 34
9 1 35
20 1 36
7 3 37
40 2 38
55 2 39
1 40
FERC FORM NO.1 (ED. 12-9)Page 427.7
FERC FORM NO.1 (ED. 12-9)Page 42.8
.................1...........................
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
PacifiCor (1) X An Original (Mo, Da, Yr)End of 208104
(2) Õ A Resubmission 0331/200
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Charater of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 STEVENS ROAD SUB DISTRIBUTION-UNATTEN 115.00 20.80
2 SUTHERLIN SUB DISTRIBUTION-UNATTEN 115.00 12.00
3 SWEET HOME SUB DISTRIBUTION-UNATTEN 115.00 20.80
4 TAKELMA SUB DISTRIBUTION-UNATTEN 115.00 20.80
5 TALENT SUB DISTRIBUTION-UNATTEN 69.00 12.47
6 TEXUMSUB DISTRIBUTION-UNATTEN 69.00 12.47
7 TILLER SUB DISTRIBUTION-UNATTEN 115.00 12.47
8 TOLOSUB DISTRIBUTION-UNATTEN 69.00 12.47
9 UMAPINE SUB DISTRIBUTION-UNATTEN 69.00 12.47
10 UMATILLA SUB DISTRIBUTION-UNATTEN 69.00 12.47
11 US PLYWOOD SUB DISTRIBUTION-UNATTEN 20.80 4.16
12 VERNON SUB DISTRIBUTION-UNATTN 69.00 12.47
13 VILAS SUB DISTRIBUTION-UNATTEN 115.00 12.47
14 VILLAGE GREEN SUB DISTRIBUTION-UNATTEN 115.00 20.80
15 VINE STREET SUB DISTRIBUTION-UNATTEN 69.00 20.80
16 WALLOWA SUB DISTRIBUTION-UNATTEN 69.00 12.47
17 WARM SPRINGS SUB DISTRIBUTION-UNATTEN 69.00 20.80
18 WARRENTON SUB DISTRIBUTION-UNATTEN 115.00 12.47
19 WASCO SUB DISTRIBUTION-UNATTEN 20.80 4.16
20 WECOMA BEACH SUB DISTRIBUTION-UNATTEN 20.80 4.16
21 WESTERN KRAFT SUB DISTRIBUTION-UNATTEN 115.00 12.47
22 WESTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 WESTSIDE HYDRO/SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 WEYERHAUSER SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 WHITE CITY DISTRIBUTION-UNATTEN 115.00 12.47
26 WILLOW COVE SUB DISTRIBUTION-UNATTEN 34.5C 4.16
27 WINSTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
28 YEW AVENUE SUB DISTRIBUTION-UNATTEN 115.OC 12.50
29 YOUNGS BAY SUB DISTRIBUTION-UNATTEN 115.00 12.47
30 Total 15141.81 2480.71 195.00
31 Number of Subsations- 181
32
33 ALBINA SUB T/D-NATTENDED 115.00 12.47 69.00
34 APPLEGATE SUB TID-UNATTENDED 115.00 69.00 12.47
35 ASHLAD MTN AVE SUB TID-UNATTENDED 115.00 69.00 12.47
36 BEND PLANT TID-UNATTNDED 69.00 4.16 12.47
37 CAVE JUNCTION SUB TID.UNATTENDED 115.00 12.47 69.00
38 HAZELWOOD SUB TIDUNATTENDED 115.00 69.00 12.47
39 KNOTT SUB TIDUNATTENDED 115.00 12.47 57.00
40 MILE HI SUB TIDUNATTENDED 115.00 69.00 12.47
............................................
Name of Respondent This Re ortis:Date of Report Year/Period of Report
PacifiCorp (1) ~An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/2009
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Servce) (In MVa)Transformers Spare Typ of Equipment Total Capcity No.In Service Transformers Number of Units
If (g)(h)(i)(j (In (~~a)
25 1 1
25 1 2
42 2 3
13 1 4
50 2 5
17 6 6
1 1 7
11 1 8
13 1 9
25 2 10
13 2 11
50 2 12
25 1 13
40 2 14
22 4 15
7 1 16
13 3 17
25 2 18
3 3 19
3 1 20
50 2 21
22 2 22
23 9 23
40 2 24
60 3 25
28 3 26
23 3 27
25 1 28
37 2 29
448 363 5 30
31
32
1n 9 33
65 2 34
70 2 35
23 3 36
70 2 37
132 4 38
187 8 39
39 4 40
FERC FORM NO.1 (ED. 12-9)Page 427.8
FERc FORM NO.1 (ED. 12-9)Page 426.9
............................................
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2O8IQ4
(2) ñ A Resubmission 0331/20
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summanze according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Chaer of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 PILOT BUTTE SUB TID-UNATTENDED 230.00 69.00 12.47
2 WINCHESTER SUB TIDUNATTENDED 115.00 12.47 69.00
3 Total 1219.00 399.04 338.82
4 Number of Substations. 10
5
6 CLEARWATER #1 HYDRO PLANT TRANSMISSION.ATTEND 138.00 6.90
7 CLEARWATER #2 HYDRO PLANT TRANSMISSION.ATTEND 138.00 12.00
8 FISH CREEK HYDRO TRASMISSION.ATTEND 115.00 6.90
9 JC BOYLE HYDRO TRNSMISSION.ATTND 230.00 11.00
10 LEMOLO #1 HYDRO TRANSMISSION-ATTEND 115.00 12.47
11 LEMOLO #2 HYDRO TRASMISSION.ATTEND 115.00 12.00
12 PROSPECT 1 HYDRO TRANSMISSION.ATTEND 69.00 2.30
13 PROSPECT 2 HYDRO TRANSMISSION.ATTEND 69.00 6.60
14 PROSPECT 3 HYDRO TRANSMISSION.A TTEND 69.00 12.47
15 TOKETEE HYDRO TRANSMISSION.ATTEND 115.00 6.90
16 BEND PLANT TRASMISSION.UNATTEN 4.16 2.40
17 CALAPOOYA SUB TRANSMISSION.UNATTEN 230.00 69.00
18 CHILOQUIN SUB TRASMISSION-UNATTEN 230.00 115.00 69.00
19 COLD SPRINGS SUB TRASMISSION-UNATTEN 230.00 69.00
20 COVE SUB TRASMISSION-UNATTEN 230.00 69.00
21 DAYS CREEK SUB TRASMISSION-UNATTEN 115.00 69.00
22 DIAMOND HILL SUB TRANSMISSION-UNA TTEN 230.00 69.00
23 DIXONVILLE 115/230 SUB TRANSMISSION-UNATTEN 230.00 115.00 69.0024_11:1'1 500.00 230.00
25 EAGLE POINT HYDRO TRANSMISSION-UNATTEN 115.00 2.40
26 EAST SIDE HYDRO TRANSMISSION-UNATTEN 46.00 12.47
27 FISH HOLE SUB TRANSMISSION-UNATTEN 115.00 69.00
28 FRY SUB TRASMISSION-UNATTN 230.00 115.00
29 GRANTS PASS SUB TRASMISSION-UNATTEN 230.00 115.00 69.00
30 GREEN SPRINGS PLANTISUB TRASMISSION-UNATTEN 115.00 69.00
31 HURRICANE SUB TRANSMISSION-UNATTEN 230.00 69.00 2.40
32 ISTHMUS SUB TRASMISSION-UNATTEN 230.00 115.00
33 KENNEDY SUB TRASMISSION-UNATTEN 69.00 57.00
34 KLAMATH FALLS SUB TRASMISSION-UNATTEN 230.00 69.00
35 LONE PINE SUB TRANSMISSION-UNA TTEN 230.00 115.00 69.00
: I MONPAC SUB 11:1'1 500.00 230.00
TRANSMISSION-UNATTEN 115.00 69.00
38 PONDEROSA SUB TRASMISSION-UNATTEN 230.00 115.00
39 POWERDALE PLANT TRSMISSION.UNATTEN 69.00 7.20
40 PROSPECT CENTRAL SUB TRANSMISSION-UNATTEN 115.00 69.00
............................................
Name of Respondent This ~rtl~:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) i: A Resubmission 03131/2009
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacit of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Seivice) (In MVa)Trasformers Spare Typ of Equipment Total Capaci No.In Servce Transformers Number of Units
(f (11)(h)(j (j (In (~~a)
400 4 1
75 5 2
1238 43 3
4
5
17 3 6
31 3 7
13 3 8
89 2 1 9
48 7 1 10
40 4 11
5 3 12
40 6 1 13
10 6 14
50 9 15
3 3 16
75 1 17
119 4 18
60 1 19
67 3 20
50 1 21
75 1 22
34 6 23
650 3 1 24
3 1 25
3 3 26
7 3 27
500 2 28
458 4 29
19 3 30
29 2 31
250 1 32
33 1 33
251 6 1 34
733 10 35
130 6 1 36
50 1 37
250 1 38
8 3 1 39
47 4 40
FERe FORM NO.1 (ED. 12-9)Page 427.9
FERC FORM NO.1 (ED. 12-9)Page 42.10
............................................
Name of Respondent ThIS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004
(2)A Resubmission 0331/200
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industnal or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distnbution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Charer of Substation
Primary Secndry Tertiary
(a)(b)(c)(d)(e)
1 ROBERTS CREEK SUB TRANSMISSION-UNATTEN 115.00 69.00
2 SLIDE CREEK HYDRO TRANSMISSION-UNA TTEN 115.00 7.00
3 SODA SPRINGS HYDRO TRASMISSION-UNA TTEN 115.00 7.00
4 TROUTDALE SUB TRASMISSION-UNATTEN 230.00 115.00 69.00
5 TUCKER SUB TRASMISSION-UNATTEN 115.00 69.00
6 WALLOWA FALLS HYDRO TRANSMISSION-UNATTEN 20.80
7 Total 6751.96 2462.01 347.40
8 Number of Substations- 41
9
10 Utah
11 106TH SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.50
12 118TH SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.47
13 70TH SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.47
14 ALTAVIEW DISTRIBUTION-UNATTEN 46.00 12.47
15 AMALGA DISTRIBUTON-UNATTEN 46.00 12.47
16 AMERICAN FORK DISTRIBUION-UNATTEN 138.00 12.47
17 ARAGONITE DISTRIBUTION-UNATTEN 46.00 7.20
18 AURORA SUB DISTRIBUTION-UNATTEN 46.00 12.47
19 BANGERTER SUB DISTRIBUTION-UNATTN 138.00 12.47
20 BEAR RIVER SUB DISTRIBUTION-UNATTEN 46.00 12.47
21 BENJAMIN SUB DISTRIBUTION-UNATTEN 46.00 12.47
22 BINGHAM SUB DISTRIBUTION-UNATTEN 46.00 12.47
23 BLUE CREEK DISTRIBUTION-UNATTEN 46.00 12.47
24 BLUFF SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 BLUFFDALE SUB DISTRIBUTION-UNATTEN 46.00 12.47
26 BOTHWELL SUB DISTRIBUTION-UNATTEN 46.00 12.47
27 BOX ELDER SUB DISTRIBUTION-UNATTEN 46.OC 12.47
28 BRIAN HEAD SUB DISTRIBUTION-UNATTEN 46.OC 12.47
29 BRICKYARD SUB DISTRIBUTION-UNATTEN 46.OC 12.47
30 BRIGHTON SUB DISTRIBUTION-UNATTEN 46.OC 24.90
31 BROOKLAWN SUB DISTRIBUTION-UNATTEN 46.00 12.47
32 BRUNSWICK SUB DISTRIBUTION-UNATTEN 46.00 12.47
33 BURTON SUB DISTRIBUTION-UNATTEN 34.50 12.47
34 BUSH SUB DISTRIBUTION-UNATTEN 46.00 12.47
35 CANNON SUB DISTRIBUTION-UNATTEN 46.00 12.47
36 CANYONLANDS SUB DISTRIBUTION-UNATTEN 69.00 12.47
37 CAPITOL SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 CARBIDE SUB DISTRIBUTION-UNATTEN 46.00 7.20
39 CARBONVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 CARLISLE SUB DISTRIBUTION-UNATTEN 138.00 12.50
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03/31/2009
SUBSTATIONS (Continued)
5. Show in columns (i), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting betwen the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Typ of Equipment Total Capcity No.In Service Transformers Number of Units
(In MVa)if)(a)(h)(i)0)(k)
50 1 1
21 3 2
13 3 3
500 3 4
100 2 5
2 3 6
6413 135 7 7
8
9
10
30 1 11
30 1 12
30 1 13
45 2 14
11 1 15
30 1 16
1 1 17
3 1 18
50 1 19
17 2 20
2 1 21
11 1 22
2 3 23
1 3 24
9 1 25
4 1 26
14 1 27
14 1 28
9 1 29
26 2 30
6 1 31
60 3 32
11 3 33
9 1 34
13 1 35
1 1 36
20 1 37
3 1 38
6 1 39
30 1 40
FERC FORM NO.1 (ED. 12-9)Page 427.10
FERC FORM NO.1 (ED. 12-9)Pl!ge 42.11
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 0331/200
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secndar Tertiary
(a)(b)(c)(d)(e)
1 CASTO SUBSTATION DISTRIBUTION-UNATIEN 46.00 12.47
2 CENTENNIAL SUB DISTRIBUTION-UNATIEN 138.00 12.47
3 CENTERVILLE SUB DISTRIBUTION-UNATIEN 46.00 12.47
4 CENTRAL SUB DISTRIBUTION-UNATIEN 46.00 12.47
5 CHAPEL HILL SUB DISTRIBUTION-UNATIEN 138.00 12.47
6 CHERRYWOOD SUB DISTRIBUTION-UNATIEN 138.00 12.47
7 CIRCLEVILLE SUB DISTRIBUTION-UNATIEN 69.DC 12.47
8 CLEAR CREEK SUB DISTRIBUTION-UNATIEN 46.00 12.47
9 CLEAR LAKE SUB DISTRIBUTION-UNATIEN 46.DC 12.47
10 CLEARFIELD SOUTH DISTRIBUTION-UNATIEN 138.DC 12.47
11 CLINTON SUB DISTRIBUTION-UNATIEN 138.DC 12.47
12 CLIVE SUB DISTRIBUTION-UNATIEN 46.00 12.47
13 COALVILLE SUB DISTRIBUTION-UNATIEN 46.00 12.47
14 COlD WATER CANYON SUB DISTRIBUTION-UNATTN 138.00 12.47
15 COLEMAN SUB DISTRIBUION-UNATIEN 138.00 69.00 12.47
16 COL TON WELL SUB DISTRIBUTION-UNATIEN 46.00 12.47
17 COMMERCE SUB DISTRIBUTION-UNATIEN 138.00 12.50
18 CORINNE SUB DISTRIBUTION-UNATIEN 46.00 12.47
19 COVE FORT SUB DISTRIBUTION-UNATIEN 46.00 12.47
20 COZVDALE SUB DISTRIBUTION-UNATIEN 138.00 12.50
21 CRESCENT JUNCTION SUB DISTRIBUTION-UNATIEN 46.00 7.20
22 CROSS HOLLOW SUB DISTRIBUTION-UNATIEN 138.00 12.47
23 CUDAHY SUB DISTRIBUTION-UNATIEN 138.00 12.47
24 DAMMERON VALLEY SUB DISTRIBUTION-UNATIEN 34.50 12.47
25 DECKER LAKE SUB DISTRIBUION.UNATIEN 138.00 12.47
26 DELLE SUB DISTRIBUTION-UNATIEN 46.00 12.47
27 DELTA SUB DISTRIBUTION-UNATIEN 46.00 69.00
28 DESERETSUB DISTRIBUTION-UNATTN 46.00 4.16
29 DEWEYVILLE SUB DISTRIBUTION-UNATIEN 46.00 12.47
30 DIMPLE DELL SUB DISTRIBUTION-UNATIEN 138.00 12.47
31 DIXIE DEER SUB DISTRIBUTION-UNATIEN 34.50 12.47
32 DRAPER SUB DISTRIBUTION-UNATIEN 46.00 12.47
33 DUMAS SUB DISTRIBUTION-UNATIEN 138.00 12.47
34 EAST BENCH SUB DISTRIBUTION-UNATIEN 138.00 12.47
35 EAST HYRUM SUB DISTRIBUION-UNATIEN 46.00 12.47
36 EAST LAYTON SUB DISTRIBUTION-UNATIEN 138.00 12.47
37 EAST MillCREEK SUB DISTRIBUTION-UNATIEN 46.00 12.47
38 EDEN SUB DISTRIBUTION-UNATIEN 46.00 12.47
39 ELBERTA SUB DISTRIBUTION-UNATIEN 46.00 12.47
40 ELK MEADOWS SUB DISTRIBUTION-UNATIEN 46.00 12.47
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/200
SUBSTATIONS (Continued\
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated underlease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capcity No.In Servce Transformers Number of Units
(f (0)(h)(i)0)
(In (~;,a)
25 1 1
40 2 2
22 1 3
2 1 4
30 1 5
25 1 6
3 1 7
4 1 8
3 9
60 2 10
50 2 11
4 1 12
20 2 13
30 1 14
106 4 15
1 3 16
30 1 17
3 1 18
2 3 19
30 1 20
1 1 21
22 1 22
30 1 23
42 1 24
55 2 25
6 1 26
48 3 27
2 1 28
4 1 29
60 2 30
2 1 31
23 2 32
60 2 33
30 1 34
6 1 35
30 1 36
20 1 37
12 2 38
5 1 39
3 1 40
FERC FORM NO.1 (ED. 12-9)Page 427.11
FERC FORM NO.1 (ED. 12-9)Page 42.12
.............................................
Name of Respondent ThiS~iortls:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, 08, Yr)End of 20Q4
(2)A Resubmission 0331/2009
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those servng customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize accrding to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secndary Tertiary
(a)(b)(c)(d)(e)
1 ELSINORE SUB DISTRIBUTION-UNATTEN 46.00 12.47
2 EMERY CITY SUB DISTRIBUTION.UNATTEN 69.00 12.47
3 EMIGRATION SUB DISTRIBUTION-UNATTEN 46.00 12.47
4 ENOCH SUB DISTRIBUTION-UNATTEN 138.00 12.47
5 ENTERPRISE VALLEY SUB DISTRIBUTION-UNATTEN 138.00 12.47
6 EUREKA SUB DISTRIBUION-UNATTEN 46.00 12.47
7 FARMINGTON SUB DISTRIBUTION-UNATTEN 138.00 12.47
8 FAYETE SUB DISTRIBUTION-UNATTEN 46.00 12.47
9 FERRON SUB DISTRIBUTION-UNATTEN 46.00 12.47
10 FIELDING SUB DISTRIBUTION-UNATTEN 46.00 12.00
11 FIFTH WEST SUB DISTRIBUTION-UNATTEN 138.00 12.47
12 FLUX SUB DISTRIBUTION-UNATTEN 46.00 12.47
13 FOOL CREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 FOUNTAIN GREEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
15 FREEDOM SUBSTATION DISTRIBUTION-UNATTEN 46.00 7.20
16 FRUIT HEIGHTS SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 GARDEN CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47
18 GATEWAY SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 GORDON AVENUE SUB DISTRIBUTION-UNATTEN 138.00 12.50
20 GOSHEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
21 GRANGER SUB DISTRIBUTION-UNATTEN 46.00 12.47
22 GRANTSVILLE SUB DISTRIBUTION-UNATTEN 46.OC 12.47
23 GREEN RIVER SUB DISTRIBUTION-UNATTEN 46.OC 12.47
24 GROW SUB DISTRIBUTION-UNATTEN 138.OC 12.47 46.00
25 GUNLOCK HYDRO DISTRIBUTION-UNATTEN 34.5C 2.30
26 GUNNISON SUB DISTRIBUTION-UNATTEN 46.OC 12.47
27 HAMIL TON SUB DISTRIBUTION-UNATTEN 34.50 12.47
28 HAMMER SUB DISTRIBUTION-UNATTEN 138.00 12.47
29 HAVASU SUB DISTRIBUTION-UNATTEN 69.00 12.47
30 HELPER CITY SUB DISTRIBUTION-UNATTEN 46.00 4.16
31 HENEFER SUB DISTRIBUTION-UNATTEN 46.00 12.47
32 HERRIMAN SUB DISTRIBUTION-UNATTEN 138.00 12.47
33 HIAWATHA SUB DISTRIBUTION.UNATTEN 46.00 4.16
34 HIGHLAND DIST SUB DISTRIBUION-UNATTEN 46.00 12.47
35 HOGGARD SUB DISTRIBUTION-UNATTEN 138.00 12.47
36 HOGLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 HOLDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 HOLLDAY SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 HUNTER SUB DISTRIBUION.UNATTEN 46.00 12.47
40 HUNTINGTON CITY SUB DISTRIBUTON-UNATTEN 69.00 12.47
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Reprt
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) i: A Resubmission 03131/200
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation otequipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expnses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Una
(In Service) (In MVa)
Transformers Spare Typ of Equipment Totl Capacity No.In Service Transormers Number of Units
(f)(a)(h)(i (j (In (~~a)
2 1 1
3 3 2
25 1 3
14 1 4
10 1 5
3 1 6
30 1 7
1 2 8
5 1 9
6 1 10
30 1 11
4 1 12
2 1 13
2 1 14
1 15
22 1 16
13 1 17
28 2 1 18
30 1 19
2 1 20
43 2 21
24 1 22
5 2 23
72 3 24
1 1 25
11 1 26
1 3 27
60 2 28
3 1 29
3 3 30
4 1 31
30 1 32
1 3 33
25 1 34
50 2 35
22 1 36
4 1 37
32 2 38
22 1 39
13 2 40
FERC FORM NO.1 (ED. 12-9)Page 427.12
FERC FORM NO.1 (ED. 12-9)Page 426.13
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 208104
(2)A Resubmission 0331/20
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Loction of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 HURRICANE FIELDS SUB DISTRIBUTION-UNATTEN 34.50 12.47
2 IRON MOUNTAIN SUB DISTRIBUTION-UNATTEN 34.50 7.20
3 IRON SPRINGS SUB DISTRIBUTION-UNATTEN 34.50 12.47
4 IRONTON SUB DISTRIBUTION-UNATTN 46.00 12.47
5 IVINS SUB DISTRIBUTION-UNATTEN 34.50 12.47
6 JORDAN NARROWS SUB DISTRIBUTION-UNATTEN 46.00 2.40
7 JORDAN PARK SUB DISTRIBUTION-UNATTEN 138.00 12.47
8 JORDANELLE SUB DISTRIBUTION-UNATTEN 138.00 12.47
9 JUAB SUB DISTRIBUTION-UNATTEN 46.00 12.47
10 JUNCTION SUB DISTRIBUTION.UNATTEN 69.00 12.47
11 KAIBABSUB DISTRIBUTION-UNATTEN 69.00 12.47
12 KAMAS SUB DISTRIBUTION-UNATTEN 46.00 12.47
13 KANARRAVILLE SUB DISTRIBUION-UNATTEN 34.50 12.47
14 KEARNS SUB DISTRIBUON-UNATTEN 138.00 12.47
15 KENSINGTON SUB DISTRIBUTION-UNATTEN 46.00 4.16
16 LAKE PARK SUB DISTRIBUTION.UNATTN 138.00 12.47
17 LARK SUB DISTRIBUTION.UNATTEN 46.00 12.47
18 LAYTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
19 LEGRANDE SUB DISTRIBUTION.UNATTEN 46.00 12.47
20 LEWISTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
21 LINCOLN SUB DISTRIBUTION.UNATTEN 46.00 12.47
22 LINDON SUB DISTRIBUTION.UNATTEN 46.00 12.47
23 LISBON SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 LITTLE MOUNTAIN SUB DISTRIBUTION-UNATTEN 46.00 12.47
25 LOAFER SUB DISTRIBUTION-UNATTEN 46.00 12.47
26 LOGAN CANYON SUB DISTRIBUTION-UNATTEN 46.00 7.20
27 LONE TREE SUB DISTRIBUTION-UNATTEN 34.5C 12.47
28 LOWER BEAVER SUB DISTRIBUION-UNATTEN 46.OC 6.60
29 LYNNDYL SUB DISTRIBUTION.UNATTEN 46.00 12.47
30 MAESERSUB DISTRIBUTION-UNATTEN 69.00 12.47
31 MAGNA SUB DISTRIBUTION.UNATTEN 138.00 12.47
32 MANILA SUB DISTRIBUTION-UNATTEN 46.00 12.47
33 MANTUA SUB DISTRIBUTION-UNATTEN 46.00 12.47
34 MAPLETON SUB DISTRIBUTION-UNATTEN 46.00 12.47
35 MARRIOTT SUB DISTRIBUTION-UNATTEN 46.00 12.47
36 MARYSVALE SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 MATHIS SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 MCCORNICK SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 MCKAY SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 MEADOWBROOK SUB DISTRIBUTION-UNATTEN 138.00 12.47 46.00
................................'........l,....
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) r" A Resubmission 03131/2009
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Servce Transformers Number of Units
(f (a)(h)(i)0)
(In (~~a)
1 3 1
1 1 2
5 3 3
2 1 4
22 1 5
13 2 6
30 1 7
30 1 8
2 3 9
3 1 10
5 1 11
7 1 12
1 3 13
60 2 14
7 1 15
53 2 16
6 1 17
40 2 18
2 1 19
14 1 20
20 1 21
20 1 22
4 1 23
20 1 24
1 25
1 26
20 1 27
1 3 28
4 1 29
13 1 30
30 1 31
22 1 32
2 1 33
14 1 34
20 1 35
2 3 36
9 1 37
6 1 38
20 1 39
42 2 40
FERC FORM NO.1 (ED. 12-9)Page 427.13
FERC FORM NO.1 (ED. 12-96)Page 42.14
...........................................
.1
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 20004
(2) Õ A Resubmission 03131/200
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those servng customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secndary Tertiary
(a)(b)(c)(d)(e)
1 MEDICAL SUB DISTRIBUION-UNATIEN 46.00 12.47
2 MELLING SUB DISTRIBUTION-UNATIEN 34.50 4.16
3 MIDLAND SUB DISTRIBUTION-UNATIEN 138.00 12.47
4 MIDVALE SUB DISTRIBUTION-UNATIEN 46.00 12.47
5 MILFORD SUB DISTRIBUTION-UNATIEN 46.00 12.47
6 MILFORD TV SUB DISTRIBUTION-UNATIEN 46.00 7.20
7 MILLVILLE SUB DISTRIBUTION-UNATIEN 46.00 12.47
8 MINERSVILLE SUB DISTRIBUTION-UNATIEN 46.00 12.47
9 MOAB CITY SUB DISTRIBUTION-UNATIEN 69.00 12.47
10 MONTEZUMA SUB DISTRIBUTION-UNATIEN 69.00 12.47
11 MOORE SUB DISTRIBUTION-UNATIEN 69.00 12.47
12 MORGAN SUB DISTRIBUTION-UNATIEN 46.00 4.16
13 MORONI SUB DISTRIBUTION-UNATIEN 46.00 12.47
14 MORTON COURT SUB DISTRIBUTION-UNATIEN 138.00 12.47
15 MOSS JUNCTION SUB DISTRIBUTION-UNATIEN 46.OC 12.47
16 MOUNTAIN DELL SUB DISTRIBUTION-UNATIEN 46.OC 12.47
17 MOUNTAIN GREEN SUB DISTRIBUTION-UNATIEN 46.OC 12.47
18 MYTON SUB DISTRIBUTION.UNATIEN 69.OC 12.47
19 NEW HARMONY SUB DISTRIBUTION-UNATIEN 69.OC 12.47
20 NEWGATESUB DISTRIBUTION-UNATIEN 46.OC 12.47
21 NEWTON SUB DISTRIBUTION-UNATIEN 46.OC 12.47
22 NIBLEYSUB DISTRIBUTION-UNATIEN 46.00 24.90
23 NORTH BENCH SUB DISTRIBUTION-UNATIEN 46.00 12.47
24 NORTH CEDAR SUB DISTRIBUTION-UNATIEN 34.50 4.16
25 NORTH FIELDS SUB DISTRIBUTION.UNATIEN 46.00 12.47
26 NORTH LOGAN SUB DISTRIBUION-UNATIEN 46.00 12.47
27 NORTH OGDEN SUB DISTRIBUTION-UNATIEN 46.00 12.47
28 NORTH SALT LAKE SUB DISTRIBUTION-UNATIEN 46.00 12.47
29 NORTHEAST SUB DISTRIBUTION-UNATIEN 46.00 12.47
30 NORTHRIDGE SUB DISTRIBUTION-UNATIEN 46.00 12.47
31 OAKLAND AVE SUB DISTRIBUTION-UNATIEN 46.00 12.47
32 OAKLEY SUB DISTRIBUTION-UNATIEN 46.00 12.47
33 OGDEN DEFENSE DEPOT SUB DISTRIBUTION-UNATIEN 46.00 12.47
34 OLYMPUS SUB DISTRIBUTION-UNATIEN 46.00 12.47
35 OPHIR SUB DISTRIBUTION-UNATIEN 46.00 12.47
36 ORANGE SUB DISTRIBUTION-UNATIEN 46.00 12.47
37 ORANGEVILLE SUB DISTRIBUTION-UNATTN 69.00 12.47
38 OREMSUB DISTRIBUTION-UNATIEN 46.00 12.47
39 OREMETSUB DISTRIBUTION-UNATIEN 115.00 12.47
40 PACK CREEK RESERVOIR DISTRIBUTION-UNATIEN 46.00 12.47
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03/31/200
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expnses or other accounting betwen the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPËCIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Typ of Equipment Total Capacit No.In Servce Transformers Number of Units
(f)(a)(h)(i)CD
(In (~~a)
58 4 1
5 1 2
30 1 3
25 1 4
14 1 5
1 1 6
13 1 7
2 1 8
19 2 9
13 1 10
3 1 11
3 1 12
6 1 13
25 1 14
6 3 15
5 1 16
6 1 17
6 1 18
7 1 19
20 1 20
5 1 21
14 1 22
25 1 23
5 1 24
2 1 25
25 1 26
22 1 27
13 1 28
45 10 29
14 1 30
24 2 31
6 1 32
11 5 3 33
22 1 34
3 1 35
20 1 36
14 1 37
48 2 38
55 2 39
4 1 40
FERC FORM NO.1 (ED. 12-9)Pag 427.14
FERC FORM NO.1 (ED. 12-9)Page 42.15
............................................
Name of Respondent ThiS!ortis:Date of Report YearlPeriod of Report
PacifiCorp (1)An Original (Mo, Da, Yr)End of 20004
(2)A Resubmission 0331/209
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Loction of Substation Charaer of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 PANGUITCH SUB DISTRIBUTION-UNATTEN 69.00 12.47
2 PARlETTE SUBSTATION DISTRIBUTION-UNATTEN 69.00 24.90
3 PARK CITY SUB DISTRIBUTION-UNATTEN 46.00 12.47
4 PARKWAY SUB DISTRIBUTION-UNATTEN 138.00 12.47
5 PARLEYS SUB DISTRIBUTION-UNATTEN 46.00 12.47
6 PELICAN POINT SUB DISTRIBUnON-UNATTEN 46.00 12.47
7 PINE CANYON SUB DISTRIBUTION-UNATTEN 138.00 12.47
8 PINE CREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47
9 PINNACLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
10 PLAIN CITY SUB DISTRIBUTION-UNATTEN 138.00 12.47
11 PLEASANT GROVE SUB DISTRIBUTION-UNATTEN 46.00 12.47
12 PLEASAN VIEW SUB DISTRIBUTION-UNATTEN 46.00 12.47
13 PORTER ROCKWELL SUB DISTRIBUTION-UNATTEN 138.00 12.47
14 PROMONTORY SUB DISTRIBUTION-UNATTEN 46.OC 12.47
15 QUAIL CREEK SUB DISTRIBUTION-UNATTEN 34.5C 12.47
16 QUARRY SUB DISTRIBUTION-UNATTEN 138.OC 12.47
17 QUITCHAPA SUB DISTRIBUTION-UNATTEN 34.5C 12.47
18 RAINS SUB DISTRIBUTION-UNATTEN 46.00 7.20
19 RANDOLPH SUB DISTRIBUTION-UNATTEN 46.00 12.47
20 RASMUSON SUB DISTRIBUTION-UNATTEN 46.00 12.47
21 RATTLESNAKE SUB DISTRIBUTION-UNATTEN 69.00 24.90
22 RED MOUNTAIN SUB DISTRIBUTION-UNATTEN 69.00 34.50
23 RED ROCK SUB DISTRIBUTION-UNATTEN 69.00 4.16
24 REDWOOD SUB DISTRIBUION-UNATTEN 46.00 12.47
25 RESEARCH PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
26 RICH SUB DISTRIBUTION-UNATTEN 69.00 12.47
27 RICHFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 RICHMOND SUB DISTRIBUTION-UNATTEN 46.00 12.47
29 RIDGELAND SUB DISTRIBUTION-UNATTEN 138.00 12.47
30 RITER SUB DISTRIBUTION-UNATTEN 46.00 12.47
31 ROCK CANYON SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 ROCKVILLE SUB DISTRIBUTION-UNATTEN 34.50 12.47
33 ROCKY POINT DISTRIBUTION-UNATTEN 138.00 13.20
34 ROSE PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
35 ROYAL SUB DISTRIBUTION-UNATTEN.46.00 4.16
36 SALINA SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 SANDY SUB DISTRIBUTIQN-UNATTEN 138.00 12.47
38 SARATOGA SUB DISTRIBUTION-UNATTEN 138.00 12.47
39 SCIPIO SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 SCOFIELD RESERVOIR SUB DISTRIBUTION-UNATTEN 46.00 7.20
............................................
Name of Respondent This ~ortIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008104
(2) ri A Resubmission 03/31/200
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwse than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment óperated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expnses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Servce) (In MVa)Transformers Spare Type of Equipment Total Capcity No.In Service Transformers Number of Units
(f (g)(h)(i)ü)
(In (~~a)
5 1 1
4 3 2
35 2 3
50 2 4
16 2 5
6 1 6
20 1 7
2 1 8
14 1 9
22 1 10
25 1 11
14 1 12
30 1 13
2 1 14
4 1 15
60 2 16
4 1 17
15 1 18
2 1 19
1 3 20
14 1 21
13 1 22
3 1 23
45 2 24
45 2 25
5 1 26
22 2 27
11 1 28
40 2 29
20 1 30
5 1 31
4 1 32
30 1 33
24 3 34
3 35
11 1 36
60 2 37
30 1 38
1 3 39
1 40
FERC FORM NO.1 (ED. 12-9)Page 42.15
FERC FORM NO.1 (ED. 12-9)Page 426.16
............................................
Name of Respondent ThiS~ortis:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 0331/200
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industnal or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those servng customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summanze according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Chaer of Substation
Primary Secndary Tertiary
(a)(b)(c)(d)(e)
1 SCOFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47
2 SECOND STREET SUB DISTRIBUTION-UNATTEN 46.00 12.47
3 SEVEN MILE SUB DISTRIBUTION-UNATTEN 46.00 12.47
4 SHARON SUB DISTRIBUTION-UNATTEN 46.00 12.47
5 SHIVWITS SUB DISTRIBUTION-UNATTEN 34.50 4.16
6 SIXTH SOUTH SUB DISTRIBUTION-UNATTEN 46.00 12.47
7 SKULL POINT SUB DISTRIBUTION-UNATTEN 46.00 12.47
8 SNARR SUB DISTRIBUTION-UNATTN 46.00 12.47
9 SNOWVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47
10 SNYDERVILLE SUB DISTRIBUTION-UNATTEN 138.00 12.47
11 SOLDIER SUMMIT SUB DISTRIBUTION-UNATTEN 69.00 12.47
12 SOUTH JORDAN SUB DISTRIBUTION-UNATTEN 138.OC 12.47
13 SOUTH MILFORD SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 SOUT MOUNTAIN SUB DISTRIBUTION-UNATTEN 138.00 12.47
15 SOUTH OGDEN SUB DISTRIBUTION.UNATTEN 46.00 12.47
16 SOUTH PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 SOUTH WEBER SUB DISTRIBUTION-UNATTEN 138.00 12.47
18 SOUTHEAST SUB DISTRIBUTION.UNATTEN 138.00 12.47 46.00
19 SOUTHWEST SUB DISTRIBUTION-UNATTEN 46.00 12.47
20 SPANISH VALLEY SUB DISTRIBUTION-UNATTN 69.00 12.47
21 SPRINGDALE SUB DISTRIBUTION-UNATTEN 34.50 12.47
22 ST. JOHNS SUB DISTRIBUTION-UNATTEN 46.00 12.47
23 STAIRS SUB DISTRIBUTION-UNATTEN 12.47 2.40
24 STANSBURY SUB DISTRIBUTION-UNATTEN 46.00 12.47
25 SUMMIT CREEK SUB DISTRIBUTION-UNATTEN 138.00 12.47
26 SUMMIT PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
27 SUNRISE SUB DISTRIBUTION-UNATTEN 138.00 12.47
28 SUPERIOR SUB DISTRIBUTION-UNATTEN 69.00 12.47
29 SUTHERLAND SUB DISTRIBUTION-UNATTEN 46.00 12.47
30 TAYLOR SUB DISTRIBUTION-UNATTEN 46.00 12.47
31 THIEF CREEK SUB DISTRIBUTION-UNATTEN 138.00 24.90
32 THIRD WEST SUB DISTRIBUTION.UNATTEN 46.00 12.47
33 THIRTEENTH SOUTH SUB DISTRIBUTION-UNATTEN 46.00 12.47
34 THOMPSON SUB DISTRIBUTION-UNATTEN 46.00 4.16
35 TOOELE DEPOT SUB DISTRIBUTION-UNATTEN 46.00 12.50
36 TOQUERVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47 34.50
37 TRICITYSUB DISTRIBUTION-UNATTEN 138.00 12.47
38 TWENTHIRD STREET SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 UINTAH SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 UNION SUB DISTRIBUTION-UNATTEN 46.00 12.47
............................................
Name of Respondent ThiS~ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/200
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)Transormers Spare Type of Equipment Number of Units Total Capcity No.In Service Transformers (In (~;,a)(1)(g)(hl Ii ü)
1 3 1
13 2 2
5 3 3
20 1 4
6 1 5
20 1 6
2 1 7
40 2 8
5 1 9
30 1 10
13 1 11
30 1 12
20 2 13
60 2 14
25 1 15
14 1 16
50 1 17
50 2 18
22 2 19
6 1 20
4 1 21
4 1 22
2 1 23
20 1 24
14 1 25
7 1 26
30 1 27
8 1 28
6 1 29
14 1 30
14 1 31
40 2 32
24 3 33
2 1 34
25 1 35
34 2 36
30 1 37
13 1 38
39 2 39
50 2 40
FERC FORM NO.1 (ED. 12-9)Page 42.16
FERC FORM NO.1 (ED. 12-9)Pag 426.17
............................................
Name of Respondent This F~iortls:Date of Report Year/Period of Report
PacifiCorp (1)~An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 0331/200
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those servng customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Loction of Substation Character of Substation Primar Seconda Tertiary
(a)(b)(c)(d)(e)
1 UNIVERSITY SUB DISTRIBUTION-UNATTEN 46.00 4.16
2 VALLEY CENTER SUB DISTRIBUTION-UNATTEN 46.00 12.47
3 VERMILLION SUB DISTRIBUTION-UNATTEN 46.00 12.47
4 VERNAL SUB DISTRIBUTION-UNATTEN 69.00 12.47
5 VEYOHYDRO DISTRIBUTION-UNATTEN 34.50 2.40
6 VICKERS SUB DISTRIBUTION-UNATTEN 46.00 12.47
7 VINEYARD SUB DISTRIBUTION-UNATTEN 46.00 12.47
8 WALLSBURG SUB DISTRIBUTION-UNATTEN 138.00 12.47
9 WALNUT GROVE SUB DISTRIBUTION-UNATTEN 138.00 12.50
10 WARREN SUB DISTRIBUTION-UNATTEN 138.00 12.47
11 WASATCH STATE PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
12 WASHAKIE SUB DISTRIBUTION-UNATTEN 138.00 4.16
13 WELBY SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 WELFARE SUB DISTRIBUTION-UNATTEN 46.OC 12.47
15 WELLINGTON SUB DISTRIBUTION-UNATTEN 46.OC 12.47
16 WEST COMMERCIAL SUB DISTRIBUTION-UNATTEN 46.OC 12.47
17 WEST JORDAN SUB DISTRIBUTION-UNATTEN 138.00 12.47
18 WEST OGDEN SUB DISTRIBUnON-UNATTEN 138.00 12.47
19 WEST ROY SUB DISTRIBUTION-UNATTEN 46.00 12.47
20 WEST TEMPLE SUB DISTRIBUTION-UNATTEN 46.00 4.16
21 WESTFIELD SUB DISTRIBUTION-UNATTEN 138.00 12.47
22 WESTWATER SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 WHITE MESA SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 WILLOW CREEK SUB DISTRIBUTIQN-UNATTEN 46.00 12.47
25 WILLOWRIDGE SUB DISTRIBUTION-UNATTEN 46.00 12.47
26 WINCHESTER HILLS SUB DISTRIBUTION-UNATTN 34.50 12.47
27 WINKLEMAN SUB DISTRIBUTION-UNATTEN 46.00 7.20
28 WOLF CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
29 WOOD CROSS SUB DISTRIBUION-UNATTEN 46.00 12.47
30 WOODRUFF SUB DISTRIBUTION-UNATTEN 46.00 12.47
31 Tota 20275.47 3723.42 184.97
32 Number of Substations- 300
33
34 ANGEL SUB TIDUNATTENDED 138.00 12.47 46.00
35 BOO SUBSTATION TID-UNATTENDED 138.00 12.47
36 BUTERVILLE SUB TID-UNATTENDED 138.00 46.00 12.47
37 COTTONWOOD SUB TID-UNATTENDED 138.00 12.47 46.00
38 EMMA PARK SUBSTATION TID-UNATTENDED 138.00 12.47
39 HALE SUB TIDUNATTNDED 138.00 46.00 12.47
40 HIGHLAND SUB TID-UNATTNDED 138.00 12.47 46.00
............................................
Name of Respondent ThiS~ortis:Date of Repo Year/Period of Report
PaciiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03/31/2009
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting betwen the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacit of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Servce) (In MVa)Transformers Spare Type of Equipment Number of Units Tota Capcity No.In Service Transformers
(f)(a)(h)(i (j (In (~~a)
48 4 1
22 1 2
3 1 3
33 2 4
2 3 5
2 1 6
25 1 7
13 1 8
30 1 9
30 1 10
2 3 11
14 1 12
22 1 13
5 1 14
4 1 15
22 1 16
28 1 17
30 1 18
25 1 19
60 3 20
20 1 21
1 3 22
14 1 23
6 1 24
14 1 25
4 1 26
1 27
6 1 28
20 1 29
2 1 30
5354 435 4 31
32
33
135 3 34
30 1 35
175 3 36
289 7 37
8 1 38
114 2 39
97 2 40
FERC FORM NO.1 (ED. 12-9)Page 427.17
FERC FORM NO.1 (ED. 12-9)Page 42.18
............................................
Name of Respondent ThiS~ortis:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, 08, Yr)End of 208104
(2)A Resubmission 0331/200
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those servng customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 JORDAN SUB TIDUNATTENDED 138.00 46.00 12.47
2 JUDGE SUB TIDUNATTENDED 46.OC 12.47
3 MCCLELLAND SUB TID-UNATTENDED 138.00 46.00 12.47
4 OQUIRRH SUB TIDUNATTENDED 138.00 46.00 12.47
5 PARRISH SUB TIDUNATTENDED 138.OC 12.47 46.00
6 PIONEER PLANT TIDUNATTENDED 138.00 2.30 46.00
7 RIVERDALE SUB TID-UNATTENDED 138.OC 46.00 12.47
8 SEVIER SUB TID-UNATTENDED 138.0C 46.00 12.47
9 SILVER CREEK SUB TID-UNATTENDED 138.OC 12.47 46.00
10 SPHINX SUB TID-UNATTENDED 46.00 12.47
11 SYRACUSE SUB TID-UNATTENDED 138.00 46.00 12.47
12 TAYLORSVILLE SUB T/D-NA TTNDED 138.00 46.00 12.47
13 TERMINAL TIDUNATTNDED 34.00 12.47 46.00
14 TIMPSUB TIDUNATTNDED 138.00 46.00 12.47
15 TOOELE SUB TIDUNATTNDED 138.00 46.00 12.47
16 WEST VALLEY SUB TID-UNATTENDED 138.00 12.47
17 Total 3197.00 64.47 459.17
18 Number of Substations- 23
19
20 BLUNDELL PLANT TRANSMISSION-ATTEND 46.00 12.47
21 CARBON PLANT TRANSMISSION-ATTEND 138.00 13.80
22 EMERY SUB TRANSMISSION-ATTND 138.00 6.90 69.00
23 GADSBY PLANT TRASMISSION-ATTEND 138.00 13.80 46.00
24 GADSBY SUB TRASMISSION-ATTEND 138.00 46.00
25 HUNTER PLANT TRASMISSION-ATTEND 34.00 23.00
26 HUNTINGTON PLANT TRASMISSION-ATTEND 34.00 23.00
27 90TH SOUTH SUB TRANSMISSION-UNA TTEN 34.00 138.00
28 ABAJOSUB TRASMISSION.UNATTEN 138.00 69.00
29 ASHLEY SUB TRANSMISSION-UNATTEN 138.00 46.00
30 BARNEY SUB TRANSMISSION-UNATTEN 138.00 46.00
31 BEN LOMOND SUB TRANSMISSION-UNATTEN 34.00 230.00 138.00
32 BLACKHAWK SUB TRANSMISSION-UNATTEN 138.00 69.00 46.00
33 BOOKCLIFFS SUB TRASMISSION-UNATTEN 69.00 46.00
34 CAMERON SUB TRANSMISSION-UNATTEN 138.00 46.00
35 CAMP WILLIAMS SUB TRANSMISSION-UNATTEN 34.00 138.00 12.47
36 CARBON SUB TRANSMISSION-UNATTN 46.00 2.40
37 COLUMBIA SUB TRASMISSION-UNATTEN 138.00 46.00
38 CRANER FLAT SUB TRASMISSIONUNATTEN 138.00 12.47
39 CUTLER SUB TRASMISSION-UNATTEN 138.00 46.00
40 ELMONTESUB TRANSMISSION-UNATTEN 138.00 46.00
............................................
Name of Respondent ThiS~iortls:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03131/2009
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Typ of Equipment Total Capacity No.In Service Transformers Number of Units
if (a)(hI en (j (In (~~a)
164 2 1
22 1 2
34 4 3
135 3 4
97 2 5
51 7 6
180 3 7
34 4 8
100 2 9
3 4 3 10
60 5 11
358 4 12
1108 6 2 13
130 2 14
158 3 15
30 1 16
4358 72 5 17
18
19
25 1 20
225 5 21
783 13 1 22
568 17 23
318 2 24
1513 5 1 25
981 4 26
1538 6 1 27
67 1 28
133 2 29
100 1 30
1813 5 31
100 2 32
6 3 1 33
25 3 34
169 2 35
8 1 36
33 1 37
40 2 38
70 2 39
313 3 40
FERC FORM NO.1 (ED. 12-9)Page 427.18
FERC FORM NO.1 (ED. 12-96)Page 42.19
............................................
Name of Respondent ThiS~!Ortis:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, 08, Yr)End of 2008/04
(2)A Resubmission 03131/200
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Loction of Substation Charer of Substation Primary Secndary Tertiary
(a)(b)(c)(d)(e)
1 GARKANE SUB TRASMISSION-UNATIEN 69.00 46.00
2 GREEN CANYON SUB TRANSMISSION-UNATIEN 138.00 46.00
3 GRINDING SUB TRANSMISSION-UNATIEN 138.00 13.80
4 HELPER SUB TRANSMISSION-UNATIEN 138.00 46.00
5 HONEYVILLE SUB TRASMISSION-UNATIEN 138.00 46.00
6 HORSESHOE SUB TRANSMISSION-UNATIEN 138.00 46.00 12.47
7 HUNTINGTON SUB TRANSMISSION-UNATIEN 34.00 138.00 69.00
8 JERUSALEM SUB TRANSMISSION-UNATIEN 138.00 46.00
9 LAMPO SUB TRASMISSION-UNATIEN 138.00 46.00
10 MCFADDEN SUB TRASMISSION-UNATIEN 138.OC 46.00
11 MIDDLETON SUB TRSMISSION.UNATIEN 138.OC 69.00 34.50
12 MIDVALLEY SUB TRANSMISSION-UNATIEN 34.OC 138.00
13 MIDWAY CITY SUB TRANSMISSION-UNATIEN 138.00 46.00
14 MINERAL PRODUCTS SUB TRNSMISSION-UNATIEN 69.00 46.00
15 MOAB SUB TRANSMISSION-UNATIEN 138.00 69.00
16 NEBOSUB TRASMISSION-UNATIEN 138.00 46.00
17 OLMSTED SUB TRANSMISSION-UNATIEN 46.00 2.40
18 PAROWAN VALLEY SUB TRANSMISSION-UNA TIEN 230.00 138.00 34.50
19 PAVANT SUB TRANSMISSION-UNATIEN 230.00 46.00
20 PINTO SUB TRANSMISSION-UNATIEN 34.00 138.00 69.00
21 REDBUTESUB TRANSMISSION-UNATIEN 230.00 138.00
22 SAND COVE HYDRO TRANSMISSION-UNATIEN 34.50 2.40
23 SIGURD SUB TRASMISSION-UNATIEN 34.00 230.00 138.00
24 SMITHFIELD SUB TRANSMISSION-UNATIEN 138.00 46.00 12.47
25 SPANISH FORK SUB TRASMISSION-UNATIEN 34.00 138.00 46.00
26 ST GEORGE SUB TRANSMISSION-UNATIEN 138.00 16.50
27 WEBER PLANT/SUB TRANSMISSION-UNATIEN 46.00 2.30
28 WEST CEDAR SUB TRANSMISSION-UNATIEN 230.00 138.00 34.50
29 Total 8521.50 3089.24 761.91
30 Number of Substations- 49
31
32 Washington
33 ATIALIASUB DISTRIBUTION-UNATIEN 69.00 12.47
34 BOWMAN SUB DISTRIBUTION-UNATTN 69.00 12.47
35 CASCADE KRAFT SUB DISTRIBUTION-UNATIEN 69.00 12.47 4.16
36 CLINTON SUB DISTRIBUTION-UNATIEN 115.00 12.47
37 DAYTON SUB DISTRIBUTION-UNATIEN 69.00 12.47
38 DODD ROAD SUB DISTRIBUTION-UNATIEN 69.00 20.80
39 GRANDVIEW SUB DISTRIBUTION-UNATIEN 115.00 12.47 69.00
40 HOPLAND SUB DISTRIBUTION-UNATIEN 115.00 12.47
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) Õ A Resubmission 03131/20
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Una
(In Service) (In MVa)Transformers Spare Type of Equipment Total Caacity No.In Servce Transformers Number of Units
(f)(a)(h)(i)0)
(In (~~a)
33 1 1
67 2 2
225 3 3
142 2 4
35 1 5
80 2 6
270 4 7
67 1 8
75 1 9
45 1 10
141 4 11
90 2 12
67 1 13
13 1 14
67 1 15
68 2 16
15 1 17
138 2 18
133 2 19
258 3 20
40 1 21
1 22
1124 6 23
63 2 24
1017 5 25
100 3 1 26
7 1 27
131 2 28
14509 139 5 29
30
31
32
25 1 33
45 2 34
117 6 35
25 1 36
23 2 37
25 4 38
56 2 39
50 2 40
FERC FORM NO.1 (ED. 12-9)Page 427.19
FERC FORM NO.1 (ED. 12-9)Page 426.2
............................................
Name of Respondent ThiS~IOrtls:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 20Q4
(2)A Resubmission 03131/200
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Loction of Substaion Cher of Substaion Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 MILL CREEK SUB DISTRIBUTION.UNATTEN 69.00 12.47
2 NACHES HYDRO DISTRIBUTION-UNATTEN 115.00 12.47
3 NOB HILL SUB DISTRIBUTION-UNATTEN 115.00 12.47
4 NORTH PARK SUB DISTRIBUTION-UNATTEN 115.00 12.47
5 ORCHARD SUB DISTRIBUTION-UNATTEN 115.00 12.47
6 PACIFIC SUB DISTRIBUTION-UNATTEN 115.00 12.47
7 POMEROY SUB DISTRIBUTION-UNATTEN 69.00 12.47
8 PROSPECT POINT SUB DISTRIBUTION-UNATTEN 69.00 12.47
9 PUNKIN CENTER SUB DISTRIBUTION-UNATTEN 115.00 12.47
10 RIVER ROAD SUB DISTRIBUTION-UNATTEN 115.00 12.47
11 SELAH SUB DISTRIBUION-UNATTN 115.00 12.47
12 SULPHUR CREEK SUB DISTRIBUTION-UNATTEN 115.00 12.47
13 SUNNYSIDE SUB DISTRIBUTION-UNATTEN 115.00 12.47
14 TIETON SUB DISTRIBUTION-UNATTEN 115.00 12.47 34.50
15 TOPPENISH SUB DISTRIBUTION-UNATTEN 115.00 12.47
16 TOUCHET SUB DISTRIBUTION-UNATTEN 69.00 12.47
17 VOELKER SUB DISTRIBUTION-UNATTEN 115.00 12.47
18 WAITSBURG SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 WAPATO SUB DISTRIBUTION-UNATTEN 115.00 12.47
20 WENASSUB DISTRIBUTION-UNATTEN 115.00 12.47
21 WHITE SWAN SUB DISTRIBUTION-UNATTEN 115.00 12.47
22 WILEY SUB DISTRIBUTION-UNATTEN 115.00 12.47
23 Total 2990.00 382.43 107.66
24 Number of Substations- 30
25
26 CENTRAL SUB TID-UNATTENDED 69.00 12.47
27 UNION GAP SUB TID-UNATTENDED 230.00 115.00 12.47
28 Totl 299.00 127.47 12.47
29 Number of Substations- 2
30
31 CONDIT PLANT TRANSMISSION-ATTEND 69.00 2.30
32 MERWIN PLAT TRASMISSION-ATTEND 115.00 13.20
33 YALE PLANT TRANSMISSION-ATTEND 230.00 13.80
34 OUTLOOK SUB TRASMISSION-UNATTEN 230.00 115.00
35 PASCO SUB TRSMISSION-UNATTEN 115.00 69.00 7.20
36 POMONA HEIGHTS SUB TRANSMISSION-UNATTEN 230.00 115.00
37 SWIFT 1 PLANT TRANSMISSION-UNATTEN 230.00 13.00
38 WALLA WALL 230KV SUB TRANSMISSION-UNATTEN 23.00 69.00
39 WALLULA SUB TRANSMISSION-UNATTEN 230.00 69.00
40 Total 1679.00 479.30 7.20
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) r: A Resubmission 03131/200
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
penod of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or othér accounting betwen the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Serice) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Servce Trasformers Number of Units
(In ~~a)(f (a)(h)(I)(i)(k
45 2 1
20 1 2
42 2 3
45 2 4
50 2 5
28 3 6
9 1 7
40 2 8
20 2 9
51 4 10
45 2 11
25 1 12
45 2 13
29 2 14
50 2 15
6 1 16
25 1 17
9 1 18
45 2 19
25 2 20
22 2 21
45 2 22
1087 61 23
24
25
14 1 26
348 5 27
362 6 28
29
30
13 6 1 31
183 9 1 32
144 3 1 33
125 1 34
39 9 35
30 2 36
261 3 .1 37
30 2 38
120 2 39
1485 37 4 40
FERC FORM NO.1 (ED. 12-9)Page 427.2
FERC FORM NO.1 (ED. 12-9)Page 426.21
............................................
Name of Respondent ThiS~!Ortis:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 20004
(2)A Resubmission 0331/200
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Lotion of Substatio Chaer of SUbstation Primary Secndary Tertiary
(a)(b)(c)(d)(e)
1 Number of Substations- 9
2
3 Wyoming
4 AIR BASE DISTRIBUnON-UNATTEN 12.4f 2.40
5 ANTELOPE MINE DISTRIBUTION.UNATTEN 230.00 34.50
6 ASTLE STREET DISTRIBUTION-UNATTEN 34.50 13.20
7 BAILEY DOME SUB DISTRIBUTION.UNATTEN 57.00 12.47
8 BAR X SUB DISTRIBUTION-UNATTEN 230.00 34.50
9 BID MUDDY SUB DISTRIBUTION-UNATTEN 69.00 12.47
10 BIG PINEY SUB DISTRIBUTION.UNATTN 69.00 24.90
11 BLACKS FORK DISTRIBUTION.UNATTN 230.00 34.50
12 BRIDGER PUMP SUB DISTRIBUTION-UNATTEN 230.00 34.50 13.20
13 BRYAN SUB DISTRIBUTION-UNATTEN 115.00 12.47
14 BUFFALO TOWN SUB DISTRIBUTION.UNATTEN 20.00 4.16
15 BYRON SUB DISTRIBUTION.UNATTEN 34.5C 4.16
16 CASSASUB DISTRIBUTION.UNATTEN 57.00 20.80
17 CENTER STREET SUB DISTRIBUTION-UNATTEN 115.OC 4.16
18 CHAPMAN SUBSTATION DISTRIBUTION-UNATTEN 46.OC 12.47
19 CHATHAM SUB DISTRIBUTION-UNATTEN 34.5C 4.16
20 CHUKARSUB DISTRIBUTION-UNATTEN 12.47 4.16
21 CHURCH AND DWIGHT SUB DISTRIBUTION-UNATTEN 34.50 0.48
22 COKEVILLE SUB DISTRIBUTION-UNATTEN 46.00 24.90
23 COLUMBIA-GENEVA SUB DISTRIBUTION-UNATTEN 230.00 13.80
24 COMMUNITY PARK SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 CROOKS GAP SUB DISTRIBUTION.UNATTEN 34.50 12.47
26 DEER CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
27 DJ COAL MINE SUB DISTRIBUTION.UNATTEN 69.00 34.50
28 DOUGLAS SUB DISTRIBUTION-UNATTEN 57.00 2.30
29 DRY FORK SUB DISTRIBUION-UNATTEN 69.00 4.16
30 ELK BASIN SUB DISTRIBUION-NATTEN 34.50 7.20
31 ELKHORN SUB DISTRIBUTION-UNATTN 115.00 12.50
32 EMIGRANT SUB DISTRIBUTION.UNATTEN 115.00 12.47
33 EVANS SUB DISTRIBUTION-UNATTEN 69.00 12.47
34 EVANSTON SUB DISTRIBUTION-UNATTN 138.00 12.47
35 FARMERS UNION SUB DISTRIBUTION-UNATTEN 34.50 4.16
36 FIREHOLE SUB DISTRIBUTION-UNATTEN 230.00 34.50
37 FORT CASPER SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 FORT SANDERS SUB DISTRIBUTION.UNATTEN 115.00 13.20
39 FRANNIE SUB DISTRIBUTION-UNATTEN 230.00 34.50
40 FRONTIER SUB DISTRIBUION.UNATTEN 69.00 4.16
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) t= A Resubmission 03131/200
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting betwen the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capcity No.In Service Transformers Number of Units
(f (a)(h)en (j (In (Wa)
1
2
3
1 3 4
25 1 5
13 1 6
2 1 7
25 1 8
7 1 9
8 1 10
150 2 11
73 4 12
25 1 13
2 3 14
2 3 15
2 6 1 16
13 1 17
4 1 18
3 19
1 3 20
3 2 21
4 1 22
45 2 23
40 2 24
5 3 25
9 1 26
13 1 27
6 3 28
9 1 29
5 1 30
25 1 31
13 1 32
9 1 33
40 2 34
2 3 35
50 2 36
25 1 37
20 1 38
50 2 39
6 1 40
FERC FORM NO.1 (ED. 12-9)Page 427.21
FERC FORM NO. 1 (ED. 12-9)Page 426.22
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, 08, Yr)End of 208104
(2) 0 A Resubmission 03131/20
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Loction of Substation Chacter of Subsion Primary Secndary Tertiary
(a)(b)(c)(d)(e)
1 GARLAND SUB DISTRIBUTION-UNATTEN 230.00 34.50
2 GLENDO SUB DISTRIBUTION-UNATTEN 57.00 4.16
3 GRASS CREEK SUB DISTRIBUTION-UNATTEN 230.00 34.50
4 GREAT DIVIDE SUB DISTRIBUTION-UNATTEN 115.00 34.50
5 GREYBULL SUB DISTRIBUTION-UNATTEN 34.50 4.16
6 HANNA SUB DISTRIBUTION-UNATTEN 34.50 12.47
7 JACKALOPE SUB DISTRIBUTION-UNATTEN 115.00 12.47
8 KEMMERER SUB DISTRIBUTION-UNATTEN 69.00 24.90
9 KIRBY CREEK PUMPING STATION DISTRIBUTION-UNATTEN 34.50 2.40
10 KIRBY CREEK SUB DISTRIBUTION-UNATTEN 34.50 4.16
11 LANDER SUB DISTRIBUTION-UNATTEN 34.50 12.47
12 LARAMIE SUB DISTRIBUION-UNATTEN 115.00 13.20
13 LATHAM SUB DISTRIBUTION-UNATTEN 230.00 34.50
14 LINCH SUB DISTRIBUTION-UNATTEN 69.00 13.80
15 LITTLE MOUNTAIN SUB DISTRIBUTION-UNATTEN 230.00 34.50
16 LOVELL SUB DISTRIBUTION-UNATTEN 34.50 4.16
17 MANDERSON SUB DISTRIBUTION-UNATTEN 34.5C 4.16
18 MILL IRON SUB DISTRIBUTION-UNATTEN 34.5C 13.80
19 MILLS SUB DISTRIBUTION-UNATTEN 12.47 4.16
20 MURPHY DOME SUB DISTRIBUTION-UNATTEN 34.50 13.20
21 NUGGETTSUB DISTRIBUTION-UNATTEN 69.00 7.20
22 OPAL SUB DISTRIBUTION-UNATTEN 46.00 24.90
23 ORIN SUB DISTRIBUTION-UNATTN 57.00 12.47
24 ORPHASUB DISTRIBUTION-UNATTN 57.00 7.20
25 PARCO SUB DISTRIBUTION-UNATTEN 34.50 12.47
26 PINEDALE SUB DISTRIBUTION-UNATTEN 69.00 24.90
27 PITCHFORK SUB DISTRIBUTION-UNATTEN 69.00 24.90
28 POINT OF ROCKS SUB DISTRIBUTION-UNATTEN 230.00 34.50
29 POISON SPIDER SUB DISTRIBUTION-UNATTEN 69.00 2.40
30 POLECAT SUB DISTRIBUTION-UNATTEN 34.50 12.47
31 RAINBOW SUB DISTRIBUTION-UNATTEN 34.50 13.20
32 RAVEN SUB DISTRIBUTION-UNATTEN 230.00 34.50
33 RED BUTTE SUB DISTRIBUTION-UNATTEN 69.00 12.47
34 REFINERY SUB DISTRIBUTION-UNATTEN 115.00 12.47
35 SAGE HILL SUB DISTRIBUTION-UNATTEN 34.50 13.20
36 SHOSHONI SUB DISTRIBUTION-UNATTEN 34.50 2.40
37 SLATE CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 SOUTH CODY SUB DISTRIBUTION-UNATTEN 69.00 24.90
39 SOUTH ELK BASIN SUB DISTRIBUTION-UNATTEN 34.50 4.16
40 SOUTH TRONA SUB DISTRIBUTION-UNATTEN 230.00 34.50
............................................
Name of Respondent This 'O0rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ¡= A Resubmission 03131/2009
SUBSTATIONS (Continued)
5. Show in columns (I), G), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwse than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expnses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Typ of Equipment Total Capacity No.In Service Transformers Number of Units
(f (a)(h)(i)0)
(In ~~a)
45 2 1
3 4 2
25 1 3
20 1 4
3 1 5
6 1 6
25 1 7
10 1 8
3 3 9
2 3 .10
25 2 11
50 2 12
25 1 13
13 1 14
20 1 15
4 3 16
1 3 17
13 1 1 18
1 3 19
5 1 20
1 21
8 1 22
2 3 23
3 3 24
5 1 25
8 1 26
17 9 2 27
25 1 28
3 1 29
2 3 30
13 1 31
20 2 32
20 1 33
45 2 34
6 1 35
2 3 36
1 1 37
14 3 1 38
2 6 39
150 2 40
FERC FORM NO.1 (ED. 12-9)Pag 427.22
FERC FORM NO.1 (ED. 12-9)Page 426.23
............................................
Name of Respondent This ~~!Ortis:Date of Report Year/Period of Report
PacifiCorp (1)~An Original (Mo, 08, Yr)End of 2008/04
(2)A Resubmission 0331/20
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Loction of Substation Charaer of Substatio Primary Secnd Tertiary
(a)(b)(c)(d)(e)
1 SPRING CREEK SUB DISTRIBUTION-UNATIEN 115.00 13.20
2 SVILARSUB DISTRIBUTION-UNATIEN 34.50 4.16
3 TEN MILE STEP DOWN SUB DISTRIBUTION-UNATIEN 34.50 12.50
4 TEN MILE SUB DISTRIBUTION-UNATIEN 69.00 34.50
5 THERMOPOLIS TOWN SUB DISTRIBUTION-UNATIEN 34.50 4.16
6 THUNDER CREEK SUB DISTRIBUTION.UNATIEN 57.00 12.47
7 VETERANS SUB DISTRIBUTION-UNATIEN 34.50 13.20
8 WELCH SUB DISTRIBUTON-UNATIEN 57.00 2.40
9 WERTZ-SINCLAIR SUB DISTRIBUTION-UNATIEN 57.00 4.16 12.50
10 WEST ADAMS SUB DISTRIBUTION.UNATIEN 34.50 4.16
11 WESTERN CLAY SUB DISTRIBUTION-UNATIEN 34.50 0.48
12 WESTVACO SUB DISTRIBUTION-UNATIEN 230.00 34.50
13 WORLAND TOWN SUB DISTRIBUTION-UNATIEN 34.50 4.16
14 WYOPOSUB DISTRIBUTION-UNATTN 230.00 34.50
15 WYUTASUB DISTRIBUTION-UNATIEN 46.00 12.47
16 Total 8034.71 1382.50 25.70
17 Number of Substations- 92
18
19 BUFFALO SUB TIDUNATIENDED 230.00 20.80
20 HILLTOP SUB T/D-UNATIENDED 115.00 34.50 20.80
21 LABARGE SUB TIDUNATIENDED 69.00 24.90
22 RIVERTON 230 SUB TIDUNATIENDED 230.00 12.47 34.50
23 YELLOWCAKE SUB TID.UNATIENDED 230.00 34.50
24 Total 874.00 127.17 55.30
25 Number of Substations- 5
26
27 DAVE JOHNSTON PLANT/SUB TRANSMISSION.ATIEND 23.OC 115.00 69.00
28 Ii:NU 34.OC 230.00 34.50
29 JIM UNITS 1-4 TRANSMISSION-ATIEND 34.OC 22.00
30 NAUGHTON SUB TRANSMISSION-ATIEND 230.00 69.00
31 WYODAK 230KV SUB TRASMISSION-ATIEND 230.00 69.00
32 WYODAK PLANT TRASMISSION-ATIEND 230.00 22.00
33 BAIROIL SUB TRASMISSION-UNATIEN 115.00 34.50 57.00
34 CASPER SUB TRANSMISSION-UNATIEN 230.00 115.00 69.00
35 CHAPPELL CREEK SUB TRANSMISSION-UNATIEN 230.00 69.00
36 FOOTE CREEK WIND FARM TRANSMISSION-UNATIEN 230.00 34.50
37 GLENDO AUTO SUB TRANSMISSION-UNATIEN 69.00 57.00
38 MANSFACE SUB TRASMISSION-UNATIEN 230.00 34.50
39 MIDWEST SUB TRASMISSION-UNATIEN 230.00 69.00 34.50
40 MINERS SUB TRASMISSION-UNATIEN 230.00 115.00 34.50
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 0331/200
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Una
(In Servce) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(f)(a)(h)(i)(j (In (~~a)
25 1 1
2 3 2
5 1 3
13 1 4
5 1 5
9 1 6
25 2 7
.3 3 8
2 6 9
3 1 10
1 1 11
25 1 12
5 1 13
20 1 1 14
1 15
1700 175 6 16
17
18
20 1 19
45 2 1 20
8 6 21
50 3 22
25 1 23
148 13 1 24
25
26
1358 17 27
1084 22 28
1122 2 29
1232 15 1 30
60 1 31
503 3 1 32
53 3 33
517 6 34
67 1 35
196 2 36
15 2 37
20 1 38
91 4 39
58 4 1 40
FERC FORM NO.1 (ED. 12-9)Page 427.2
FERc FORM NO.1 (ED. 12-9)Page 42.24
............................................
Name of Respondent ThiS~ortis:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 0331/2009
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Location of Substatio Chaer of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 MUSTANG SUB TRANSMISSION-UNATTEN 230.00 115.00
2 OREGON BASIN SUB TRANSMISSION-UNA TTEN 230.00 34.50 69.00
3 PLATTE SUB TRANSMISSION-UNATTEN 230.00 115.00 34.50
4 RAILROAD SUB TRANSMISSION-UNATTEN 230.00 138.00
5 ROCK SPRINGS 230 SUB TRANSMISSION-UNATTEN 230.00 34.50
6 SAGE SUB TRASMISSION-UNATTEN 69.00 46.00
7 THERMOPOLIS SUB TRANSMISSION-UNATTEN 230.00 115.00
8 YELLOWTAIL SUB TRSMISSION-UNATTEN 230.00 161.00
9 Total 4853.00 1814.50 402.00
10 Number of Substations- 22
11
12 CALIFORNIA
13 Distribution - 45
14 TID -3
15 Transmission - 9
16
17 IDAHO
18 Distribution - 67
19 TID-4
20 Transmission - 19
21
22 OREGON
23 Distribution - 181
24 TID -10
25 Transmission - 41
26
27 UTAH
28 Distriution - 30
29 TID - 23
30 Transmission - 49
31
32 WASHINGTON
33 Distribution - 30
34 TID-2
35 Trasmissio - 9
36
37 WYOMING
38 Distribution - 92
39 TID-5
40 Trasmission - 22
............................................
Name of Respondent ThiS~iortls:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 03/311200
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expnses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Servce) (In MVa)Transformers Spae Typ of Equipment Total Capcity No.In Servce Transformers Number of Units (In ~a)
(f)(g)(h)(i)CD
200 2 1
65 2 2
165 4 3
40 1 4
50 2 5
22 1 6
175 2 7
100 1 8
7553 98 3 9
10
11
12
34 13
129 14
696 15
16
17
799 18
314 19
332 20
21
22
448 23
1238 24
6413 25
26
27
5354 28
4358 29
14509 30
31
32
1087 33
362 34
1485 35
36
37
1700 38
148 39
7553 40
FERC FORM NO.1 (ED. 12-9)Page 427.24
FERC FORM NO.1 (ED. 12-9)Page 42.25
............................................
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 208104
(2) j" A Resubmission 0331/200
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Lotion of Substation Chaer of Substaion Primary Secondry Tertiary
(a)(b)(c)(d)(e)
1
2 ALLSTATES
3 Distribution -715
4 TID-47
5 Trasmission -149
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
............................................
Name of Respondent i his oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ci A Resubmission 03131/2009
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of Sharing expenses or other accounting between the parties, and state amounts and aocounts
affeced in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Servce) (In MVa)Transformers Spare Type of Equipment Total Capty No.In Service Transformers Number of Units
(f (a)(h)(i ü)
(In (~~a)
1
2
13722 3
6549 4
33998 5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO.1 (ED. 12-9)Page 427.25
Page 45.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 031/209 20004
FOOTNOTE DATA
ISchedule Page: 426.9 Line No.: 24 Column: a
The Dixonvie 500kV Substation is jointly owned by th repondent and the Bonneville Power Admistrtion ("the BPA").
Ownership of the substation is as follows: PacifCorp 50.0%, the BPA 50.0%. Opration and matenance costs ar shared between
the two pares and responsibilty is as follows: PacifCorp 58.0%, an the BPA 42.0%.
ISchedule Page: 426.9 Une No.: 36 Column: a I
The Meridian 500kV Substation is jointly owned by the respondent and the Bonnevile Power Admitrtion ("the BPA"). Ownership
of the substation is as follows: PacifCorp 50.0%, the BPA 50.0%. Operation and matenance costs are shaed between the two
pares and responsibilty is as follows: PacifCorp 58.0%, and the BPA 42.0%.
¡SchedUle Page: 426.23 Une No.: 28 Column: a
The Jim Bridger 345kV Substation is jointly owned by th repondent and Idao Power Company. Ownership of the substation is as
follow: PacifCorp 66.7%, Idao Power Company 33.3%. Option and matace costs ar sha between the two pares and
responsibilty is as follow: PacifCorp 66.7%. and Idaho Power Company 33.3%.
I FERC FORM NO.1 (ED. 12-87)
.............................................
INDEX
Schedule Page No.
Accrued and prepaid taxes ........................................................................ 262-263
Accumulated Deferred Income Taxes .................................................................... 234
272-277
Accumulated provisions for depreciation of
common utility plant ............................................................................. 356
utility plant .................................................................................... 219
utility plant (summary) ...................................................................... 200-201
Advances
from associated companies .................................................................... 256-257
Allowances ....................................................................................... 228-229
Amortization
miscellaneous .................................................................................... 340
of nuclear fuel .............................................................................. 202-203
Appropriations of Retained Earnings .............................................................. 118-119
Associated Companies
advances from ................................................................................ 256-257
corporations controlled by respondent ............................................................ 103
control over respondent .......................................................................... 102
interest on debt to .......................................................................... .256-257
Attestation ............................................................................................ i
Balance sheet
comparative .................................................................................. 110-113
notes to ..................................................................................... 122-123
Bonds ............................................................................................ 256-257
Capital Stock ........................................................................................ 251
expense .......................................................................................... 254
premiums ......................................................................................... 252
reacquired ....................................................................................... 251
subscribed ....................................................................................... 252
Cash flows, statement of ......................................................................... 120-121
Changes
important during year ........................................................................ 108-109
Construction
work in progress - common utility plant .......................................................... 356
work in progress - electric ...................................................................... 216
work in progress - other utility departments ................................................. 200-201
Control
corporations controlled by respondent ............................................................ 103
over respondent .................................................................................. 102
Corporation
controlled by .................................................................................... 103
incorporated ..................................................................................... 101
CPA, background information on ....................................................................... 101
CPA Certification, this report form ................................................................. i-ii
FERC FORM NO.1 (ED. 12-9)Indx 1
INDEX (continued)
Page No.Schedule
Deferred
credits, other ................................................................................... 269
debits, miscellaneous ............................................................................ 233
income taxes accumulated - accelerated
amortization property ........................................................................ 272-273
income taxes accumulated - other property .................................................... 274-275
income taxes accumulated - other ............................................................. 276-277
income taxes accumulated - pollution control facilities .......................................... 234
Definitions, this report form ........................................................................ iii
Depreciation and amortization
of common utility plant .......................................................................... 356
of electric plant ................................................................................ 219
336-337
Directors ............................................................................................ ios
Discount - premium on long-term debt ............................................................. 256-257
Distribution of salaries and wages ............................................................... 354-355
Dividend appropriations .......................................................................... 118-119
Earnings, Retained ............................................................................... 118-119
Electric energy account .............................................................................. 401
Expenses
electric operation and maintenance ........................................................... 320-323
electric operation and maintenance, summry ...................................................... 323
unamortized debt ................................................................................. 256
Extraordinary property losses ........................................................................ 230
Filing requirements, this report form
General information .................................................................................. 101
Instructions for filing the FERC Form 1 ............................................................. i-iv
Generating plant statistics
hydroelectric (large) ................................;....................................... 406-407
pumped storage (large) ....................................................................... 408-409
small plants ................................................................................. 410-411
steam-electric (large) ....................................................................... 402-403
Hydro-electric generating plant statistics ....................................................... 406-407
Identification ....................................................................................... 101
Important changes during year .................................................................... 108-109
Income
statement of, by departments................................................................. 114-117
statement of, for the year (see also revenues) ............................................... 114-117
deductions, miscellaneous amortization ........................................................... 340
deductions, other income deduction ............................................................... 340
deductions, other interest charges ............................................................... 340
incorporation informtion ............................................................................ 101
FERC FORM NO.1 (ED. 12-9)Indx 2
............................................
.............................................
INDEX (continued)
Schedule Page No.
Interest
charges, paid on long-term debt, advances, etc ............................................... 256-257
Investments
nonutility property .............................................................................. 221
subsidiary companies ......................................................................... 224-225
Investment tax credits, accumulated deferred ..................................................... 266-267
Law, excerpts applicable to this report form.......................................................... iv
List of schedules, this report form .................................................................. 2-4
Long-term debt ................................................................................... 256~257
Losses-Extraordinary property ........................................................................ 230
Materials and supplies ............................................................................... 227
Miscellaneous general expenses ....................................................................... 335
Notes
to balance sheet ............................................................................. 122-123
to statement of changes in financial position ................................................ 122-123
to statement of income ....................................................................... 122-123
to statement of retained earnings ............................................................ 122-123
Nonutility property .................................................................................. 221
Nuclear fuel materials ........................................................................... 202-203
Nuclear generating plant, statistics ............................................................. 402-403
Officers and officers i salaries ...................................................................... 104
Operating
expenses-electric ............................................................................ 320-323
expenses-electric (summary) ...................................................................... 323
Other
paid-in capital .................................................................................. 253
donations received from stockholders ............................................................. 253
gains on resale or cancellation of reacquired
capital stock .................................................................................... 253
miscellaneous paid-in capital .................................................................... 253
reduction in par or stated value of capital stock ................................................ 253
regulatory assets ................................................................................ 232
regulatory liabilities ........................................................................... 278
Peaks, monthly, and output ........................................................................... 401
Plant, Common utility
accumulated provision for depreciation ........................................................... 356
acquisition adjustments .......................................................................... 356
allocated to utility departmets ................................................................. 356
completed construction not classified ............................................................ 356
construction work in progress ...... ~ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 356
expenses ......................................................................................... 356
held for future use .............................................................................. 356
in service ....................................................................................... 356
leased to others ................................................................................. 356
Plant data .................................................................................. .336-337
401-429
FERC FORM NO.1 (ED. 12-95)Index 3
INDEX (continued)
Schedule Page No.
Plant - electric
accumulated provision for depreciation ........................................................... 219
construction work in progress .................................................................... 216
held for future use .............................................................................. 214
in service ................................................................................... 204-207
leased to others ................................................................................. 213
Plant - utility and accumulated provisions for depreciation
amortization and depletion (surmry) ............................................................. 201
Pollution control facilities, accumulated deferred
income taxes ..................................................................................... 234
Power Exchanges .................................................................................. 326-327
Premium and discount on long-term debt ............................................................... 256
Premium on capital stock ............................................................................. 251
Prepaid taxes ..................................................................................... 262-263
Property - losses, extraordinary ..................................................................... 230
Pumped storage generating plant statistics ....................................................... 408-409
Purchased power (including power exchanges) ...................................................... 326-327
Reacquired capital stock ............................................................................. 250
~eacquired long-term debt ........................................................................ 256-257
Receivers i certificates .......................................................................... 256-257
Reconciliation of reported net income with taxable income
from Federal income taxes ...................................................................... 261
Regulatory conuission expenses deferred .............................................................. 233
Regulatory commission expenses for year .......................................................... 350-351
Research, development and demonstration activities ............................................... 352-353
Retained Earnings
amortization reserve Federal ..................................................................... 119
appropriated ................................................................................. 118-119
statement of, for the year ................................................................... 118-119
unappropriated ............................................................................... 118-119
Revenues - electric operating .................................................................... 300-301
Salaries and wages
directors fees ................................................................................... ios
distribution of .............................................................................. 354-355
officers i ........................................................................................ 104
Sales of electricity by rate schedules ............................................................... 304
Sales - for resale ............................................................................... 310-311
Salvage - nuclear fuel ........................................................................... 202-203
Schedules, this report form .......................................................................... 2-4
Securities
exchange registration ........................................................................ 250-251
Statement of Cash Flows .......................................................................... 120-121
Statement of income for the year ................................................................. 114-117
Statement of retained earnings for the year ...................................................... 118-119
Steam-electric generating plant statistics ....................................................... 402-403
Substations .......................................................................................... 426
Supplies - materials and ............................................................................. 227
FERC FORM NO.1 (ED. 12-9)Index 4
............................................
............................................
INDEX (continued)
Schedule
Taxes
accrued and prepaid
charged during year
on income. deferred
Page No.
262-263
262-263
and accumulated ............................................................. 234
272-277
reconciliation of net income with taxable income for ............................................ 261
Transformers. line - electric ....................................................................... 429
Transmission
lines added during year ..................................................................... 424-425
lines statistics ............................................................................ 422-423
of electricity for others ................................................................... 328-330
of electricity by others ........................................................................ 332
Unamortized
debt discount ............................................................................... 256-257
debt expense ................................................................................ 256-257
premium on debt ............................................................................. 256-257
Unrecovered Plant and Regulatory Study Costs ........................................................ 230
FERC FORM NO.1 (ED. 12-90)Index 5
Page
Number
1
2
3 - 6
7
8
9
10
11 - 12
13
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM NO.1
FOR
MULTI-STATE ELECTRIC COMPANIES
INDEX
Title
Statement of Operating Income for the Year
Electric Operating Revenues
Electric Operation and Maintenance Expenses
Depreciation and Amortization of Electric Plant
Taxes, Other Than Income Taxes
Non-Utility Property
Summary of Utilty Plant and Accumulated Provisions
Electric Plant in Service
Materials and Supplies
M 559 (11000) (12/96)Paçiei
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) L An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) _A resubmission May 12, 2009 Dec. 31, 2008
STATE OF IDAHO STATEMENT OF OPERATING INCOME FOR THE YEAR
ELECTRIC UTILITY
Une ACCOUNT (Ref)
No.Page
No.Current Year Previous Year
(a)(b)(e)(d)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)2 255,576,999 245,796,394
3 Operating Expenses
4 Operation Expenses (401)3-6 157,693,957 154,454,090
5 Maintenance Expenses (402)3-6 20,302,529 21,753,903
6 Depreciation Expenses (403)7 22,141,858 24,741,880
7 Amort. & Depl. of Utility Plant (404-405)7 2,155,279 2,634,326
8 Amort. of Utiltv Plant Acq. Adj (4061 318,186 350,390
Amort. of Propert Losses, Unrecovered
9 Plant and Regulatory Study Costs (407)336,221 200,703
10 Amort. of Conversion Expenses (407)--
11 Taxes other Than Income Taxes (408.1)8 4,904,875 4,657,065
12 Income Taxes - Federal (409.1)(4,773,615 4,093,241
13 -Other (409.1)(417,772 604,267
14 Provision for Deferred Income Taxes (410.1)30,632,497 7,037,972
15 Provision for Deferred Income Taxes - Cr. (411.1)(14,829,314)(14,120,792)
16 InvestmentTax Credit Adj. - Net (411.4)(219,739)(744,909)
17 (Gains) from Disp. of Utility Plant (411.61 --
18 Losses from Disp. of Utilty Plant (411.7)--
19 (Gains1 from Emission Allowances (315,306)(965,806)
20 (Gains) Loss on Sale of Utility Plant (103,876)239,008
21 TOTAL Utilty Operating Expenses
(Enter Total of Lines 4 thru 20)217,825,780 214,935,338
22 Net Utilty Operating Income (Enter Total of
line 2 less 21)37,751,219 30,861,056
IDAHO SUPPLEMENT PaQ1
~o
CIci:i:rms:m
~
i:~CDI\
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) ~ An Original
(2) _ A resubmission
Date of Report
(Mo, Da, Yr)
May 12, 2009
1. Report below operating revenues for each
prescribed account, and manufactured gas revenues in
total.
2. Report number of customers, columns (f) and (g),
on the basis of meters, in addition to the number of flat rate
accunts; 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
ELECTRIC OPERATING REVENUES (Account 400)
at the close of each month.
3. 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.
4. 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 o.un'
footnote5. See p 8.1
Changes During P
and important rate
6. For lines 2,4,5,E
No. 1 for amounts
accounts.
7. Include unmetei
sales in a footnote
OPERATING REVENUES MEGAWATT HOURS SOLD AVG.!'
Line Title of Account Amount for Amount for Numbi
No.Amount for Year Previous Year Amount for Year Previous Year Ye,
(a)(a)(c)(d)(e)(~
1 Sales of Electrcity
2 (440) Residential Sales 58,451,721 49,527,597 727,371 710,522
3 (442) Commercial and Industrial Sales
4 Small (or Commercial) (See Instr. 4)26,869,031 26,011,840 398,426 398,113
5 Laroe (or Industral) (See Instr. 4)111,954,918 108,417,305 2,262,639 2,364,422
6 (444) Public Street and Highway Liohtino 467,242 243,091 2,488 2,215
7 (445) Other Sales to Public Authorities ----
8 (446) Sales to Railroads and Railwavs ---.
9 1(448) Interdepartmental Sales ----
10 TOTAL Sales to Ultimate Consumers 197,742,912 184,199,833 3,390,924 3,475,272
11 (447) Sales for Resale 49,491,559 54,281,131 ia)(a)(~
12 TOTAL Sales of Electricity 247,234,471 238,480,964 3,390,924 3,475,272 .13 Less) (449.1) Provision for Rate Refunds -.--
14 TOTAL Revenue Net of Provo For Refunds 247,234,471 238,480,964 3,390,924 3,475,272
15 Other Operating Revenues (a) For a complete list of the nu.mber 9f custome
16 (450) Forfeited Discounts 458,582 368,639 310-311 of the FERC Form No.1. Sales for Resa!
17 451) Miscellaneous Service Revenues 161,100 142,972
18 (453) Sale of Water and Water Power 1,533 6,873
19 454) Rent from Electric Propert 808,980 713,252
20 (455) Interdepartmental Rents --
21 456) Other Electric Revenues 6,912,333 6,083,694
22
23 TOTAL Other Operating Revenues 8,342,528 7,315,430
24 TOTAL Electric Operating Revenues 255,576,999 245,796,394
.
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) i An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) _ A resubmission May 12, 2009 Dec. 31, 2008
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES -IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Une Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and EnQineerinQ 1,266,099 1,367,905
5 (501) Fuel 40,122,749 37,994,894
6 (502) Steam Expenses 2,170,220 2,147,813
7 (503) Steam from Other Sources 217,429 319,119
8 (Less) (504) Steam Transferred - Cr.--
9 (505) Electric Expenses 247,630 248,882
10 (506) Miscellaneous Steam Power Expenses 2,525,521 2,666,853
11 (507) Rents 16,334 54,292
12 TOTAL Operation (Enter Total of lines 4 thru 11)46,565,982 44,799,758
13 Maintenance
14 (510) Maintenance Supervision and Engineering 346,029 386,44
15 (511) Maintenance of Structures 1,440,505 1,434,887
16 (512) Maintenance of Boiler Plant 5,024,482 6,018,680
17 (513) Maintenance of Electric Plant 1,674,389 2,031,525
18 514) Maintenance of Miscellaneous Steam Plant 735,467 749,911
19 TOTAL Maintenance (Enter Total of lines 14 thru 18)9,220,872 10,621,447
20 TOTAL Power Production Expenses - Steam Power (Enter Total of lines 12 & 19)55,786,854 55,421,205
21 B. Nuclear Power Generation
22 Operation
23 1(517) Operation Supervision and Enaineering --
24 1(518) Fuel --
25 (519) Coolants and Water -
26 1(520) Steam Ëxpenses --
27 (521) Steam from Other Sources --
28 Less) (522) Steam Transferred - Cr.--
29 (523) Electric Expenses --
30 524) Miscellaneous Nuclear Power Expenses --
31 525) Rents --
32 TOTAL Operation (Enter Total of lines 23 thru 31)--
33 Maintenance
34 (528) Maintenance Supervision and EnQineering
--
35 (529) Maintenance of Structures --
36 (530) Maintenance of Reactor Plant Equipment --
37 (531) Maintenance of Electric Plant --
38 (532) Maintenance of Miscellaneous Nuclear Plant --
39 TOTAL Maintenance (Enter Total of lines 34 thru 38)--
40 TOTAL Power Production Expenses - Nuclear Power (Enter Total of lines 32 & 39)--
41 C. Hydraulic Power Generation
42 Operation
43 (535) Operation Supervision and EnQineerinQ 512,537 538,980
44 (536) Water for Power 17,502 13,863
45 (537) Hvdraulic Expenses 237,533 300,934
46 1/538) Electric Expenses --
47 (539) Miscellaneous Hydraulic Power Generation Expenses 1,036,304 968,006
48 (540) Rents 8,202 2,905
49 TOTAL Operation (Enter Total of lines 43 thru 48)1,812,078 1,824,688
IDAHO SUPPLEMENT Page 3
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) .l An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) _ A resubmission May 12, 2009 Dec. 31, 2008
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
50 C. Hvdraulic Power Generation (Continuedl
51 Maintenance
52 541 Maintenance Suoervision and Enaineering 156 -
53 542 Maintenance of Structures 71,146 65,285
54 543 Maintenance of Reservoirs, Dams, and Waterways 83,463 65,092
55 544 Maintenance of Electric Plant 91,322 107,335
56 545) Maintenance of Miscellaneous Hvdraúlic Plant 124,953 134,793
57 TOTAL Maintenance (Enter Total of lines 52 thru 56)371,040 372,505
58 TOTAL Power Production Exoenses - Hvdraulic Power (Enter Total of lines 49 & 57)2,183,118 2,197,193
59 D. Other Power Generation
60 Ooeration
61 546 Operation Supervision and Enaineerino 12,686 46,666
62 547 Fuel .30,518,527 22,205,955
63 548 Generation Exoenses 1,053,278 1,540,082
64 549 Miscellaneous Other Power Generation Expenses 635,509 379,302
65 550) Rents 408,480 872,554
66 TOTAL Ooeration (Enter Total of lines 61 thru 65)32,628,480 25,044,559
67 Maintenance
68 551 Maintenance Suoervision and Engineerina --
69 552 Maintenance of Structures 75,393 42,092
70 553 Maintenance of Generation and Electric Plant 346,580 308,564
71 5541 Maintenance of Miscellaneous Other Power Generation Plant 29,322 28,095
72 TOTAL Maintenance (Enter Total of lines 68 thru 711 451,295 378,751
73 TOTAL Power Production Exoenses - Other Power (Enter Total of lines 66 & 721 33,079,775 25,423,310
74 E. Other Power Supply Expenses
75 1(555) Purchased Power 45,333,059 45,203,486
76 115561 Svstem Control and Load Disaatchina 116,018 162,112
77 5571 Other Expenses 11\7,644,461 9,345,032
78 TOTAL Other Power Suoplv Exoenses (Enter Total of lines 75 thru 77\53,093,538 54,710,630
79 TOTAL Power Production Exoenses - (Enter Total of lines 20, 40, 58, 73 and 78)-- 144;143,285 -137,752,338
80 2. TRANSMISSION EXPENSES
81 Ooeration
82 (560) Operation SUPervision ¡md Enaineerina 453,452 524,839
83 561 Load Dispatching 495,694 504,465
84 562 Station Expenses 108,582 64,333
85 563 Overhead Line Exoenses 5,420 8,045
86 564 Underaround Line Exoenses --
87 565 Transmission of Electricitv bv Others 7,060,389 6,819,746
88 566) Miscellaneous Transmission Exoenses 104,244 175,971
89 56ilRents 47,772 86,730
90 TOTAL Operation (Enter Total of lines 82 thru 891 8,275,553 8,184,129
91 Maintenance
92 568 Maintenance Supervision and Engineering 570 3,596
93 569 Maintenance of Structures 239,765 206,778
94 (570 Maintenance of Station Eauioment 644,177 .592,955
95 571 Maintenance of Overhead Lines 941,024 852,025
96 572 Maintenance of Underaround Lines --
97 5731 Maintenance of Miscellaneous Transmission Plant 27,906 24,336
98 TOTAL Maintenance (Enter Total of lines 92 thru 97)1,853,442 1,679,690
99 TOTAL Transmission Expenses (Enter Total of lines 90 and 981 10,128,995 9,863,819
100 3. DISTRIBUTION EXPENSES
101 Operation
102 5801 OPeration Suoervision and Enaineerina 894,939 862,041
103 (581) Load Dispatching 595,952 583,812
(1) The Idaho amounts in FERC account 557 are $3,238,393 for Current Year and $3,851,417 for Previous Year.
However, these amounts have been increased by $4,406,068 for Current Year and $5,493,615 for Previous Year
because of the embedded cost differentials on Idaho results.
IDAHO SUPPLEMENT Page 4
Name of Respondent This Report Is: Date of Report Year of Report
PacifCorp (1) i An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) _A resubmission May 12, 2009 Dec. 31, 2008
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
104 3. DISTRIBUTION EXPENSES (Continued)
105 582) Station Expenses 255,140 174,616
106 (583) Overhead Line Expenses 162,592 197,205
107 (584) Underground Line Expenses --
108 (585) Street Lighting and Signal System Expenses 10,351 11,443
109 (586) Meter Expenses 397,340 318,915
110 587) Customer Installations Expenses 709,324 635,356
111 588) Miscellaneous Distribution Expenses 370,170 500,303
112 (589) Rents 27,195 66,016
113 TOTAL Operation (Enter Total of lines 102 thru 112)3,423,003 3,349,707
114 Maintenance
115 596) Maintenance Supervision and Enaineering 302,779 297,707
116 591) Maintenance of Structures 118,918 96,189
117 (592) Maintenance of Station Equipment 664,135 435,314
118 (593) Maintenance of Overhead Lines 4,533,920 5,039,022
119 1(594) Maintenance of Underaround Lines 646,670 750,325
120 (595) Maintenance of Line Transformers 52,059 31,551
121 1(596) Maintenance of Street Lighting and Signal Systems 163,040 165,812
122 (597) Maintenance of Meters 317,714 354,660
123 (598) Maintenance of Miscellaneous Distribution Plant 86,051 84,548
124 TOTAL Maintenance (Enter Total of lines 115 thru 123)6,885,286 7,255,128
125 TOTAL Distribution Expenses (Enter Total oflines 113 and 124)10,308,289 10,604,835
126 4. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
127 Operation
128 (901) Supervision 92,212 112,029
129 902) Meter Reading Expenses 1,807,158 1,611,031
13(j ---903)Gt,stomer Recordsand Collection Expenses 2,155,564 2,226,795
131 (904) Uncollectible Accounts 303,856 308,510
132 905) Miscellaneous Customer Accounts Expenses 8,556 15,055
133 TOTAL Customer Accounts Expenses (Enter Total of lines 128 thru 132)4,367,346 4,273,420
134 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
135 Operation
136 (907) Supervision 9,619 17,212
137 908) Customer Assistance Expenses 1,565,402 3,710,798
138 1'909) Informational and Instructional Expenses - 154,192 139,899
139 (91 D)-Miscellaneous Customer Service and Informational Expenses 2,476 751
140 TOTAL Cust. Service and Informational Exp. (Enter Total of lines 136 thru 139)1,731,689 3,86,660
141 6. SALES EXPENSES
142 Ooeration
143 1(911) Supervision --
144 (912) Demonstrating and Sellna Expenses --
145 (913) Advertising Expenses --
146 (916) Miscellaneous Sales Exoenses --
147 TOTAL Sales Expenses (Enter Total of lines 143 thru 146)--
148 7. ADMINISTRATIVE AND GENERAL EXPENSES
149 Operation
150 (920) Administrative and General Salaries 1,953,895 4,938,066
151 (921) Offce Supplies and Expense 700,062 758,491
152 (Less) (922) Administrative Expenses Transferred - Cr.(1 ,208,446)-(1,232,157)
153 923) Outside Services Employee 667,017 580,987
154 (924) Property Insurance 1,788,804 1,459,458
155 (925) Injuries and Damaaes 531,614 672,179
156 926) Emplovee Pensions and Benefis --
157
IDAHO SUPPLEMENT Page 5
Name of Respondent This Report Is: Date of Report Year of Report
PacifiCorp (1) i An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) _ Aresubmission May 12, 2009 Dec. 31, 2008
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) -IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
157 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
158 (927) Franchise Reauirements --
159 (928) Regulatorv Commission Exoenses 543,491 451,722
160 929) Duplicate Charges - Cr.(223,706)(347,978)
161 (930.1) General Advertising Exoenses --
162 (930.2) Miscellaneous General Expenses 741,466 796,911
163 (931) Rents 302,091 320,860
164 TOTAL Operation (Enter Total of lines 150 thru 163)5,796,288 8,398,539
165 Maintenance
166 (935) Maintenance of General Plant 1,520,594 1,446,382
167 TOTAL Administrative and General Expenses (Enter Total of lines 164 & 166)7,316,882 9,844,921
168 TOTAL Electric Operation and Maintenance Expenses (Enter Total of lines 79, 99,125,
133,140,147, and 167)177 ,996,486 176,207,993
SUMMARY OF ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
Line Functional Classifications Operation Maintenance Total
No.(a)(b)(c)(d)
169 Power Production Expenses
170 Electric Generation:
171 Steam Power 46,565,982 9,220,872 55,786,854
172 Nuclear Power --.
173 Hydraulic -Conventional 1,812,078 371,040 2,183,118
174 Other Power Generation ...32,628,480 451,295 33,079,775
175 Other Power Supply Expenses 53,093,538 53,093,538
176 Total Power Production Expenses 134,100,078 10,043,207 144,143,285
177 Transmission Expenses 8,275,553 1,853,442 10,128,995
178 Distribution Expenses 3,423,003 6,885,286 10,308,289
179 Customer Accounts Expenses 4,367,346 4,367,346
180 Customer Service and Informational Expenses 1,731,689 1,731,689
181 Sales Expenses --
182 Adm. and General Expenses 5,796,288 1,520,594 7,316,882
183 Total Electric Operation and Maintenance Expenses 157,693,957 20,302,529 177,996,486
IDAHO SUPPLEMENT Page 6
Name of Respondent This Report Is: Date of Report Year of Report
PacifiCorp (1) 2 An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) _ A resubmission May 12, 2009 Dec. 31, 2008
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Accounts 403,404,405)
(Except amortization of acquisition adjustments)
A. Summary of Depreciation and Amortization Charges
Line Depreciation Amortization of Amortization of
No.Functional Classification Expense Limited-Term Electric Other Electric Total
(Account 403)Plant (Acct. 404)Plant (Acct. 405)
(a)(b)(c)(d)(e)
1 Intancible Plant 2,075,078 2,075,078
2 Steam Production Plant 6,088,251 6,088,251
3 Nuclear Production Plant .
4 Hydraulic Production Plant - Conventional 869,767 869,767
5 Hydraulic Production Plant - Pumped Storage .
6 Other Production Plant 3,144,487 9,512 3,153,999
7 Transmission Plant 3,381,714 3,381,714
8 Distribution Plant 6,441,986 6,441,986
9 General Plant 2,215,653 70,689 2,286,342
10 Common Plant - Electric .
11 TOTAL 22,141,858 2,155,279 -24,297,137
STATE OF IDAHO - ALLOCATED
IDAHO SUPPLEMENT Page 7
Name of Respondent This Report Is:Date of Repo Year of Report
PacifiCorp (1) i An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) _ A resubmission May 12, 2009 Dec. 31, 2008
KIND OF TAX AMOUNT
1 Propert 4,349,885
2 Other 554,990
3
4 .
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20 Total ( Must agree with page 1, line 11.)4,904,875
STATE OF IDAHO . ALLOCATED
TAXES, OTHER THAN INCOME TAXES
ACCOUNT 408 1
IDAHO SUPPLEMENT Page 8
~:io(jC"'"'r-mš:mz-l
Name of Respondent This Repor Is:Date of Report
,&
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) _A resubmission May 12, 2009 31
dba Rocky Mountain Power
NON.UTILITILY PROPERTY (ACCOUNT 121)
"'~CD
co
i ljeginning ljalance Acquistion Keuremem iran
Location Description Description (c)(d)(e)(I
1 IDAHO FALLS POLE TREATING PLANT Fee Land 54,317
2 MALAD PLANT SITE AND WATER RIGHTS Land Rii:hts 33
3 GEORGETOWN PLANT LAND (121)Fee Land 110
4 LAVA DEVELOPMENT (121)Land Rii:hts 1,274
5 MENAN SUBSTATION SITE (121)Fee Land 55
6 UCON SITE (121) - CATERCORNER TO UCON SUBSTAT Fee Land 27
7 OLD DUBOIS SUBSTATION SITE Fee Land 75
8 EAST RIVER SUBSTATION SITE (121)Fee Land 13,742
9 NORTH MONTEVIEW SUBSTATION SITE (121)Fee Land 328
10 MONTEVIEW SUBSTATION SITE (121)Fee Land 618
11 MUD LAKE SERVICE CENTER Fee Land 17,915
12 ARCO TRANSMISSION SUBSTATION AND OFFICE Fee Land 1,740 -
13 ARCO TRANSMISSION SUBSTATION AND OFFICE Structures 38,071 (2,418)
14 THREEMILE KNOLL SUBSTATION Fee Land 26,058
15 Total Non-Utilty Propert 154,363 -(2,418).
.
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) i An Original (Mo, Da, Yr)
:lba Rocky Mountain Power (2) _ A resubmission May 12, 2009 Dec. 31, 2008
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
1 UTILITY PLANT
2 In Service
3 Plant In Service (Classified)955,902,116 937,383,729
4 Propert Under Capital Lease (1)--
5 Plant Purchased or Sold --
6 Completed Construction not Classified 12,044,596 2,474,213
7 Experimental Plant Unclassified --
8 Total (Enter Total of Lines 3 throuah 7)967,946,712 939,857,942
9 Leased To Others --
10 Held for Future Use 750,560 458,401
11 Construction Work In Process 67,820,539 56,067,228
12 Acquisition Adjustments 9,128,243 10.052,135
13 Total Utilty Plant (Enter Total of Lines 8 through 12)1,045,646,054 1,006,435,706
14 Accumulated Provision for Depreciation, Amortization & Depletion 389,746,293 401,323.912
15 Net Utilty Plant (Enter Total of Line 13 less Line 14)655,899,761 605,111,794
DETAIL OF ACCUMULATED PROVISION FOR DEPRECIATION, AMORTIZATION AND
16 DEPLETION
17 In Service
18 Depreciation 363,401,052 374,363,449
19 AmorlzationlDepletion of Producing Natural Gas Land And Land Rights --
20 Amortization of Unden:round Storage Land and Land Riahts --
21 Amortization of Other Utility Plant 21,228,818 21,676,585
22 Total In Service (Enter Total of Lines 18 throuah 21)384,629,870 396,040,034
23 Leased To Others
24 Depreciation --
25 Amortization And Depletion --
26 Total Leased to Others (Enter Total of Lines 24 and 25)--
27 Held for Future Use
28 Depreciation --
29 Amortization --
30 Total Held for Future Use (Enter Total of Lines 28 and 29)--
31 Abandonment of Leases (Natural Gas)--
32 Accumulated Provision for Asset Acauisition Adiustment 5,116,423 5,283,878
Total Accumulated Provisions (Should Agree With Line 14 above) (Enter Total of Lines
33 22, 26, 30, 31 and 32)389,746,293 401,323,912
34
(1) Capital leases are not included in rate base; they are charged to operating expense.
IDAHO SUPPLEMENT Page 10
ELECTRIC PLANT IN SERVICE - STATE OF IDAHO (ALLOCATED)
(In addition to Account 101, Electric Plant In Service (Classified), this schedule includes Account 102, Electric Plant
Purchased or Sold, Account 103, Experimental Electric Plant Unclassified and
Account 106, Completed Construction Not Classified-Electric.)
1 . Report below the original cost of electric plant in 3. Credit adjustments of plant accounts should be
service according to prescribed accounts.enclosed in parentheses to indicate the negative effec
of such amounts.
2. Do not include as adjustments, corrections of
additions and retirements for the current or the
preceding year.
Line Balance at End of
No.Account Beginning Balance Year
(a)(b)(g)
1 1. INTANGIBLE PLANT
2 (301) Organization --
3 (302) Franchises and Consents 5,943,718 7,254,241
4 (303) Miscellaneous Intanaible Plant 31,740,826 29,779,555
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)37,684,544 37,033,796
6 2. PRODUCTION PLANT
7 A Steam Production Plant
8 (310) Land and Land Rights 5,619,834 5,428,705
9 (311) Structures and Improvements 50,322,784 46,937,258
10 312) Boiler Plant Ecuipment 178,106,232 168,618,554
11 (313) EnQines and Engine Driven Generators --
12 314 Turbogenerator Units 47,429,029 45,180,197
13 (315 Accessory Electric Equipment 21,324,879 20,390,793
14 316 Misc. Power Plant Equioment 1,703,496 1,515,785
15 TOTAL Steam Production Plant (Enter Total of lines 8 thru 14)304,506,254 288,071,292
16 B. Nuclear Production Plant
17 320) Land and Land Rights --
18 I (321 Structures and Improvements --
19 (322) Reactor Plant Equipment --
20 1(323) TurboQenerator Units --
21 (324) Accssory Electric Equipment --
22 1(325) Misc. Power Plant Equioment --
23 TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 22)----
24 C. Hydraulic Production Plant
25 (330) Land and Land Rights 1,256,223 1,143,555
26 (331) Structures and Improvements 5,314,359 4,958,440
27 (332) Reservoirs, Dams, and Waterways 18,099,144 16,727,953
28 (333) Water Wheels, Turbines, and Generators 5,709,495 5,616,447
29 (334) Accessory Electric Equipment 2;708,895 2,768,451
30 (335) Misc. Power Plant Equipment 164,450 143,508
31 (336) Roads, Railroads, and Bridges 882,435 829,230
32 TOTAL Hydraulic Production Plant (Enter Total of lines 25 thru 31)34,135,001 32,187,584
33 D. Other Production Plant
34 (340) Land and Land RiQhts 1,377,583 1,250,990
35 (341) Structures and Improvements 5,222,382 6,419,904
36 (342) Fuel Holders, Products, and Accessories 1,249,415 536,054
37 343) Prime Movers 46,456,479 73,560,400
38 (344) Generators 11,304,452 13,374,080
39 345) Accessory Electric Equipment 4,834,781 7,296,653
40 (346) Misc. Power Plant Equipment 332,069 402,103
41 TOTAL Other Production Plant (Enter Total of lines 34 thru 40)70,777,161 102,840,184
42 i U I AL Production Plant (Enter i otai or lines 10, ;¿;;, ;;;¿, ana 41)409,418,416 423,099,060
IDAHO SUPPLEMENT Page 11
ELECTRIC PLANT IN SERVICE (Continued) STATE OF IDAHO (ALLOCATED)
Line Balance End ofNo.Account Beginning Balance Year
(a)(b)(g)
43 3. TRANSMISSION PLANT
44 (350) Land and Land Rights 5,940,329 5,478,889
45 352) Structures and Imorovements 3,804,817 3,901,893
46 353) Station Equipment 63,622,797 63,172,280
47 354) Towers and Fixtures 25,748,909 24,823,566
48 (355) Poles and Fixtures 33,174,956 30,966,465
49 1(356) Overhead Conductors and Devices 43,393,835 41,007,286
50 357) Underi:round Conduit 209,581 188,356
51 (358) Underground Conductors and Devices 468,101 431,335
52 (359) Roads and Trails 734,332 665,647
53 TOTAL Transmission Plant (Enter Total of lines 44 thru 52)177,097,657 170,635,717
54 4. DISTRIBUTION PLANT
55 (360) Land and Land Rii:hts 1,253,969 1,255,542
56 (361) Structures and Improvements 797,057 1,151,317
57 (362) Station Equipment 22,780,426 26,123,899
58 (363 Storai:e Battery Equipment --
59 364 Poles, Towers, and Fixtures 53,860,274 56,159,120
60 (365 Overhead Conductors and Devices 32,451,572 32,973,127
61 (366) Underground Conduit 6,531,868 6,942,477
62 (367) Underground Conductors and Devices 21,443,864 22,642,301
63 (368) Line Transformers 59,350,458 62,062,240
64 (369) Services 23,816,753 25,683,819
65 (370) Meters 13,732,238 13,817,534
66 371) Installations on Customer Pr.emises 159,686 162,607
67 (372) Leased Properl on Customer Premises 4,873 2,437
68 373) Street Liohtino and Signal Systems 570,172 592,483
69 TOTAL Distribution Plant (Enter Total of lines 55 thru 68)236,753,210 249,568,903
70 5. GENERAL PLANT
71 (389) Land and Land Rights 576,855 555,588
72 390) Structures and Improvements 16,687,646 16,306,746
73 391) Ofce Furniture and Equipment 5,950,035 5,217,332
74 (392) Transportation Equipment 6,445,558 6,437,195
75 393) Stores Equipment 905,091 867,042
._--76 (394) Tools, Shop and Garaae Equioment --- ---_.:-:-3,526,756 3,430,881
77 395) Laboratory Equipment 2,069,457 2,041,070
78 (396) Power Operated Equipment 8,696,096 8,750,317
79 (397) Communication Equipment 14,267,752 14,367,405
80 (398) Miscellaneous Equipment 331,588 339,52
81 SUBTOTAL (Enter Total of lines 71 thru 80)59,456,834 58,313,118
82 (399) Other Tangible Property 16,973,068 17,251,522
83 TOTAL General Plant (Enter Total of lines 81 thru 82)76,429,902 75,564,640
84 TOTAL (Accounts 101)937,383,729 955,902,116
85 (102) Electric Plant Purchased --
86 Plant Sold --
87 (103) Experimental Electric Plant Unclassified --
88 106 Plant Unclassified 2,474,213 12,044,596
89 TOTAL Electric Plant in Service 939,857,942 967,946,712
IDAHO SUPPLEMENT Page 12
Name of Respondent
PaCfiCorp
dba Rocky Mountain Power
STATE OF IDAHO --ALLOCATED
This Report Is: Date of Report
(1) i An Original (Mo, Da, Yr)
(2) A resubmission May 12, 2009
Year of Report
Dec. 31, 2008
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 (on a supplemental page) showing general
classes of material and supplies and the various
accounts (operating expense, clearing acunts, plant,
etc.) affcted - debited or credited. Show separately
debits or credits to stores expense clearing, if
applicable.
Line
No,
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Balance
Beginning of
Year
(b)
ACCOUNT
(a)
Fuel Stock (Account 151)
Fuel Stock Expenses Undistributed (Account 152)
Residuals and Extracted Products (Account 153)
Plant Materials and Operatin Supplies (Account 154
Assigned to - Construction (Estimated)
Assigned to - Operations and Maintenance
Production Plant (Estimated)
Transmission Plant (Estimated)
Distribution Plant (Estimated)
Assi ned to - Other
TOTAL Account 154 (Enter Total of lines 5 thru 10)
Merchandise (Account 155
Other Materials and Supplies (Account 156)
Nuclear Materials Held for Sale (Account 157) (Not applicable to Ga
Utilties)
Stores Expense Undistributed (Account 163)15
16
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)
IDAHO SUPPLEMENT Page 13
Balance
End of Year
(c)
7,402,116
Department or
Departments
Which Use Material
(d)
Electric
4,755,711
136,982
4,429,074
1,589
9,323,356
Electric
Electric
Electric
Electric
16,725,472