2007Annual Report.pdf

...........
II.:................................
OR 0 Resubmission No.
Form 1 Approved
OMS No. 1902-0021
(Expires 7/3112008) ,
Form 1-F Approved
OMS No. 1902-0029
(Expires 6130/2007)
Form 3-0 Approved
OMS No. 1902-0205
(Expires 6/30/2007)
'THIS FILING IS
&AC--E
FERCFINANCIAlREPORT
FERCFORMNo.1 : Annual ReRortof
. Majof.ElectricUtitities, licensees
and Others andSuRPlemental
form3.Q: Quarterly financilIReport
. Exact Legal Name of Re$pondent (Company)
PacifiCorp
'FERC FORM No.1f3(REV. 02-6)
~ ~k MOUTAIN RECEIVE.O~ A DIVISION OF PACIACORP S 9
'30
April 29, 2008
\0.
VI OVERNIGHT DELiVF"P\.Ji
201 South Main, Suite 2300
Salt Lake City, Utah 84111
Idao Public Utilities Commssion
472 West Washington
Boise, ID 83702-5983
Attention:Jean D. Jewell
Commssion Secreta
RE: FERC Form 1
PacifiCorp (d.b.a. Rocky Mountain Power) submits for filing one copy of PacifiCorp's anual
FERC Form i report for the year ended December 31, 2007.
PacifiCorp respectfully requests that all data requests regarding this matter be addressed to:
By email (preferred):dataequest(Çacificorp.com
By regular mail:Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
By fax:[phone]
Please direct any informal questions to Ted Weston, Regulatory Manager, at [phone].
Sincerely,
Jir t:. 4-J'
Jeffey K. Larsen
Vice President, Reguation
Enclosure
............................................
INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q
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-Q ( FERC Form 3-Q)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 utilties, licensees and others subject to the junsdiction 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 Utilties 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-Q (18 C.F.R. § 141.400).
Note: Major means having, in each of the three previous calendar years, sales or transmission service that
exceeds one of the following:
(1) one 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 (delivenes plus losses).
III. What and Where to Submit
(a) Submit FERC Forms 1 and 3-Q electronically through the forms submission software. Retain one copy of each report
for your files. Any electronic submission must be created by using the forms submission software provided free by the
Commission at its web site: http://ww.ferc.gov/docs-filnqleforms/form-1/elec-subm-soft.asp. The software is
used to submit the electronic filng to the Commission via the Internet.
(b) The Corporate Officer Certification must be submited electronically as part of the FERC Forms 1 and 3- filngs.
(c) Submit immediately upon publication, by either eFilng 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 Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not
applicable to filers classified as Class C or Class D pnor to January 1,1984). The CPA Certification Statement can be
either eFiled or mailed to the Secretary of the Commission at the address above.
FERC FORM 1 & 3-Q (ED. 03-07)
FERC FORM 1 & 3-Q (ED. 03-7)ii
............................................
The CPA Certification Statement 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 Accountant'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
Sttement of Income
Statement of Retaine 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 connection with our regular examination of the financial statements of _ for the year ended on which we have
reported separately under date of , we have also reviewed schedules
of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for
conformity in all material respets with the requirements of the Federal Energy Regulatory Commission as set forth in its
applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such
tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph
(except as noted below) conform in all matenal 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 Reprt to Stockholders, and the CPA Certification Statement using eFilng.
To further that effort, new selections, "Annual Report to Stockholders," and "CPA Certification Statemenl have been
added to the dropdown "pick lisl from which companies must chooe when eFilng. Further instructions are found on the
Commission's website at http://ww.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.pdf and
http://ww.ferc.gov/docs-filng/eforms.asp#3Q-gas .
IV. When to Submit:
FERC Forms 1 and 3-Q must be filed by the following schedule:
............................................
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 aspet of these collections of information, including
suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC
20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of
Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory
Commission). No person shall be subject to any penalt if any collection of information does not display a valid control
number (44 U.S.C. § 3512 (a)).
FERC FORM 1 & 3-Q (ED. 037)ii
FERC FORM 1 & 3-Q (ED. 03-07)iv
............................................
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 otherwise noted. (Enter cents for averages and
figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements
where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the
statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance
sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the
current year's year to date amounts.
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 completed only for resubmissions (see VII. below).
Vi. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must
be reported as positive. Numbers having a sign that is diferent from the expected sign must be reported by enclosing the
numbers in parentheses.
VII For any resubmissions, submit the electronic filng using the form submission softare only. Please explain
the reason for the resubmission in a footnote to the data field.
VIII. Do not make references to reports of previous penodlyears or to other reports in lieu of required entries,
except as specifically authonzed.
IX. Wherever (scheule) pages refer to figures from a previous penod/year, the figures reported must be based
upon those shown by the report of the previous penodlyear, or an appropnate explanation given as to why the diferent
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
descnbed in Order No. 888 and the Open Access Transmission Tanf. "Self" means the respondent.
FNO ~ Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions. -Network Service" is Network Transmission Service as
described in Order No. 888 and the Open Access Transmission Tanff.
LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and" firm"
means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse
conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access
Transmission Tarif. For all transactions identified as LFP, provide in a footnote the
-...........................................
termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.
OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the
terms of the Open Access Transmission Tanff. "Long-Term" means one year or longer and "firm" means that service
cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all
transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either
buyer or seller can unilaterally get out of the contract.
SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point
transmission reservations, where the duration of each period of reservation is less than one-year.
NF- Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions.
OS - Other Transmission Service. Use this classification only for those services which can not be placed in the
above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC Form.
Describe the type of service in a footnote for each entry.
AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior
reporting periods. Provide an explanation in a footnote for each adjustment.
DEFINITIONS
Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any
other Commission. Name the commission whose authorization was obtained and give date of the authonzation.
II. Respondent -- The person, corporation, licensee, agency, authonty, or other Legal entity or instrumentality 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
............................................
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 incorporated or not, or a receiver or receivers, trustee or trustees of any of the
foregoing. It shall not include 'municipalities, as hereinafter defined;
(4) 'Person' means an individual or a corporation;
(5) 'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act,
and any assignee or successor in interest thereof;
(7) 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or
agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or
distributing power; ......
(11) "project' means. a complete unit of improvement or development, consisting of a power house, all water
conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and
all storage, diverting, or fore bay reservoirs direcly conneted therewith, the primary line or lines transmitting power there
from to the point of junction with the distnbution system or with the interconneced primary transmission system, all
miscellaneous structures used and useful in connecion 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 herebyauthonzed and empowered
(a) To make investigations and to collect and record data concerning the utilzation of the water 'resources of any region to
be developed, the water-power industry and its relation to other industnes and to interstate or foreign commerce, and
concerning the location, capacit, development -costs, and relation to markets of power sites; ... to the extent the
Commission may deem necessary or useful for the purposes of this Act."
"Sec. 304. (a) Every Licensee and every public utilit shall file with the Commission such annual and other periodic or
speial* reports as the Commission may be rules and regulations or other prescnbe as necessary or appropnate to assist
the Commission in the -proper administration of this Act. The Commission may prescribe the manner and FERC Form in
which such reports salt be made, and require from such persons specific answers to all questions upon which the
Commission may nee information. The Commission may require that such reports shall include, among other things, full
information as to assets and Liabilties, capitalization, net investment, and reduction thereof, gross receipts, interest due
and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the
project and other facilities, cost of renewals and replacement of the project works and other facilties, depreciation,
generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such
person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under
oath unless the Commission otherwise specifies*.1 0
............................................
"Sec. 309. The Commission shall have power to perform any and all acts, and to prescnbe, issue, make, and rescind such
orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other
things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribe
the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be fied with the Commission,
the information which they shall contain, and the time within which they shall be field..."
General Penalties
The Commssion may assess up to $1 millon 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. 03-7)vii
FERC FORM No.1/3-Q (REV. 02-04)Page 1
............................................
..
IDENTIFICATION
01 Exact Legal Name of Respondent 02 Year/Period of Report
PacifiCorp End of 2007/Q4
03 Previous Name and Date of Change (if name changed during year)
1 1
04 Address of Pnncipal Offce at End of Period (Street, City, State, Zip Code)
825 N.E. Multnomah, Suite 1900, Portland, OR 97232
05 Name of Contact Person 06 Title of Contact Person
Henry E. Lay Corporate Controller
07 Address of Contact Person (Street, City, State, Zip Code)
825N.E. Multnomah, Suite 1900, Portland, OR 97232
08 Telephone of Contact Person,lncluding 09 This Report Is 10 Date of Report
Area Code (1) IX An Original (2) 0 A Resubmission (Mo,Da, Yr)
[phone] 04/04/2008
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned offcer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affirs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accunts.
01 Name 03 s~"at"Ð-+ K.~04 Date SignedDouglas K. Stuver (Mo,Da, Yr)
02 Title
Senior VP & Chief Financial Ofcer Douglas K. Stuver 04/0412008
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willngly to make to any Agency or Department ofthe United States any
false, fictitious or fraudulent statements as to any matter wihin its jurisdiction.
FERC FORM NO. 1/3-Q:
REPORT OF MAJOR ELECTRIC UTILITIES LICENSEES AND OTHER
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) DA Resubmission 04/03/2008
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 Tite of Schedule Reference Remrks
No.Page No.
(a)(b)(c)
1 General Information 101
2 Cotrol Over Respondent 102
3 Corprations Controlled by Respondent 103
4 Oficers 104
5 Directors 105
6 Important Changes During the Year 108-109
7 Comparative Balance Sheet 110-113
8 Statement of Incme for the Year 114-117
9 Statement of Retained Earnings for the Year 118-119
10 Statement of Cash Flows 120-121
11 Notes to Financial Sttements 122-123
12 Statement of Acum Comp Income, Camp Income, and Hedging Activities 122(a)(b)
13 Summar of Utilty Plant & Accumulated Provions for Dep, Amort & Dep 200-201
14 Nuclear Fuel Materials 202-203 N/A '.
15 Elecric Plant in Service 204-207
16 Elecric Plant Leased to Others 213 NlA
17 Elecric Plant Held for Future Use 214
18 Construction Work in Progres-Electric 216
19 Accumulated Provision for Depreciation of Electric Utilit Plat 219
20 Investment of Subsidiary Companies 224-225
21 Material and Supplies 227
22 Allowances 228-229
23 Exraordinary Propert Losses 23 NlA
24 Unrecovered Plant and Regulatory Study Costs 230
25 Transmissio Service and Generation Interconnection Stud Cots 231
26 Other Regulatory Assets 232
27 Miscellaneous Deferred Debits 233
28 Acumulated Deferred Incoe Taxes 234
29 Capital Stock 250-251
30 Other Paid-in Capital 253
31 Capitl Stock Expense 254
32 Long-Term Debt 256-257
33 Reconcilation of Reported Net Income with Taxe Inc for Fed Inc Tax 261
34 Taxes Accrued, Prepaid and Charged During the Year 262-263
35 Acumulated Deferred Investment Tax Credits 26267
36 Other Deferred Credits 269
FERC FORM NO.1 (ED. 12-96)Page 2
FERC FORM NO.1 (ED. 12-9)Page 3
............................................
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04032008
LI T OF SCHEDULES (Elecric Utiit) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
37 Accumulated Deferred Income Taxes-Accelerated Amorization Propert 272-273
38 Accumulated Deferred Income Taxes-Other Propert 274-275
39 Accumulated Deferred Ince Taxes-Other 276-277
40 Otr Regulatory Liabilties 278
41 Elecric Operating Revenues 30-301
42 Sales of Elecricity by Rate Schedles 30
43 Sales for Resale 310-311
44 Electric Operation an Maintenance Exnses 320-323
45 Purcased Power 326-327
46 Transmission of Elecricit for Others 328-330
47 Transmission of Electricity by ISOIATOs 331 N/A
48 Transmissio of Elecriity by Others 332
49 Miscellaneous Genral Expenses-Elecri 33
50 Depreiatio and Amortizaion of Elecric Plant 33337
51 Regulatory Commission Exnses 35351
52 Research, Development an Demontraion Act 352-353
53 Distribution of Salaries and Wages 35355
54 Common Utilit Plant and Exes 356 NlA
55 Amounts included in ISOIRTO Settlement Statements 397 NIA
56 Purchase and Sale of Ancillary Service 398
57 Monthly Transmission System Peak Load 400
58 Monthly ISOIATO Trasmission System Peak Load 40a NIA
59 Elecric Energy Acount 401
60 Monthly Peaks and Outpu 401
61 Steam Becric Genrating Pl Sttistics 402-43
62 Hydroelectric Generating Pl Sttistics 4007
63 Pumpe Storage Generating Plt Sttistics 40 N/A
64 Generating Plant Statistics Pages 410-411
65 Transmissio Line Statistics Pages 422-423
66 Transmission Lines Added During the Year 424-425
............................................
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) CIA Resubmission 04/03/2008
LI T OF SCHEDULES (Electric Utilty) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no informtion or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Year/Period of Report
End of 2oo7/Q4
Line
No.
Title of Schedule Remarks
67 Substations
68 Footnote Data
Stockholders' Reports Check appropriate box:
i! Four copies wil be submited
o No annual reprt to stockholders is prepared
Reference
Page No.
(b)
426-427
450
(c)(a)
FERC FORM NO.1 (ED. 12-96)Page 4
Name of Respondent
PacifCorp
This Report Is:
(1) IX An Original
(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
040312008
Year/Period of Report
2007/04End of
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 Pinancial Officer
825 N.E. Multnom, Suite 1900
Portland, OR 97232-4116
corporate Books are kept at:
825 N.E. Multnom, Suite 1900
Portland, OR 97232-4116
2. Provide the name of the State under the laws of which respodent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
Incorporated on August 11, 1987 in the State of Oregon
3. If at any time during the year the propert of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not applicable
4. State the classes or utilty and other services furnished by respondent during the year in each State in which
the respondent operated.
The Company is a reglated electric comany operating in portions of the states of Utah, Oregon,
Wyomng, Washington, Idaho and Californa. The Comany conducts its retail electric utility business as
Pacific Power and Rocky Mountain Power, and engages in electricity production end sales on a wholesale
basis under the trade n~ 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. 12-87)PAGE 101
............................................
............................................
Name of Respondent
PacifiCorp
This Report Is:
(1) IX An Original
(2) D A Resubmission
Date of Report
(Mo, Da, Yr)
04/03/2008
Year/Period of Report
2007/Q4End of
CONTROL OVER RESPONDENT
1. If any corpration, 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%) (88.2% controlled by Berkshire Hathaway Inc.)
PPW Holdings LLC (100% controlled by MidAmerican Energy Holdings Company)
PacifiCOrp (99.78% controlled by PPW Holdings LLC)
FERC FORM NO.1 (ED. 12-96)Page 102
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04032008
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 intermdiaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Year/Period of Report
End of 2007/04
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Diret control is that which is exercised wihout interpsition of an intermiary.
3. Indirect control is that which is exercised by the interpsition of an intermiary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each 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.
Line
No.
Miing
Mining
Mining
Mining
Mining
Percet Voting
Stock Owed
(c)
100
100
100
100
100
66.67
100
100
100
21.40
Name of Company Controlled Kind of Business Footnote
Ref.
(d)(a)(b)
2 Energy West Mining Company
3 Glenrock Co Copany
4 Interwest Mining Compay
5 Pacific Minerals, Inc.
Environmenta Servics
Rain Forest Carbn Credits
Management Services for PERCo
Mining
Stea Delivery Serv
Steam Delivery service
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO.1 (ED. 12-96)Page 103
............................................
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
!Schedule Page: 103 Line No.: 1 Column: a
In May 200, the assets of Centrala Minin Com any were sold to TransAlta.
Schedule Pa e: 103 Line No.: 6 Column: a
Idaho Power Corp. holds a 33.33% ownership interest in Bndger Coal Company. PacifiCorp's interest is held though Pacific
Minerals, Inc.
I$chedule Page: 103 Line No.: 7 Column: a
PacifiCorp Environmenta Remediation Company ("PERCo") became a wholly owned subsidiar of PacifiCorp in Apnl 2007, when
PacifiCorp acquied the outstading 10% minority interest in PERCo from CH2M HllL. For additional information refer to Page 108,
1m ortant Changes Durin the Yèar, Item 2, of ths Form No.1.
chedule Pa e: 103 Line No.: 8 Column: a
PacifiCorp Future Generations owns an interest in Canopy Botanicals, Inc., which holds an interest in Caopy Botaicals, SRL relating
to rain forest carbon emissions credits.
¡Schedule Page: 103 Line No.: 10 Column: a
The other joint owners of Trapper Mining, Inc. are Salt River Project (32.10%), Tn-State Generation and Transmission Association,
Inc. (26.57%) and Platte River Power Authon (19.93%).
chedule Pa e: 103 Line No.: 11 Column: a
Intermountan Geothermal Company was merged with and into its direct parent, PacifCorp, on August 31, 2007, with PacifiCorp
survin . For additional information refer to Pa e 108, 1m ortan! Chan es Durin the Year, Item 2, of ths Form No.1.
chedule Pa e: 103 Line No.: 12 Column: a
Steam Reserve Corporation was merged with and into its diect parent, Intermountan Geotherm Company, on August 30,2007, with
Intermountan Geothrm Company suriving. For additional informtion refer to Page 108, Important Changes During the Year,
Item 2, of ths Form No.1.
IFERC FORI\ NO.1 (ED. 12-S7) Page 450.1
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04200
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.
Une Title Name of Oficer :-saj:ry
No.(a)(b)
forexrar
1
2 Chairman of the Bord and Chief Executive Oficer ""
3 Senior Vice President and Chief Financial Ofcer 214,200
4 President, Rocky Mountain Power A. Richard Walje 335,811
5 President, Pacific Power R. Patrik Reiten 250,00
6 President, PacifiCorp Energy 173,580
7
8
9 President, PacifCorp Energy 521,431
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
FERC FORM NO.1 (ED. 12-96)Page 104
............................................
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
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, 2007, consistent with
Item 402 of Regulation S- K promulgated by the Securities and Exchange Commssion. Salar information of other offcers will be
provided to the Federal Energy Regulatory Commssion (th "PERC") upon request, but the company considers such informtion
rsonal and confidential to such offcers. See 18 CP 388.107(d), ( .
chedule Pa e: 104 Line No.: 2 Column: b
Mr. Abel receives no direct compensation from PacifiCorp. PacifiCorp reimburses MidAmerican Energy Holdings Company
("MEHC") for the cost of Mr. Abel's time spent on PacifiCorp matters, including compensation paid to hi by MERC, pursuant to an
intercompany administrative services agreement among MEHC and its subsidiares. Please refer to MEHC's annual report on Form
IO-K for the ear ended December 31,2007 (File No. 001-14881) for executive com nsation informtion for Mr. AbeL.
chedule Pa : 104 Line No.: 3 Column: b
For additional information regarding chages in the status ofPacifiCorp's offcers refer to page 108, Importnt Changes During the
Year, Item 13, of ths Form NO.1. On Februar 8, 2008, Mr. Mendez resigned as a director and executive offcer of PacifiCorp
effective Febru 29, 2008.
I$chedule Page: 104 Line No.: 6 Column: b
For additional informtion regarding changes in the status of PacifiCorp's offcers refer to page 108, Important Changes During the
Year, Item 13, of ths Form NO.1.
¡Schedule Page: 104 Line No.: 8 Column: a
PacifiCorp sets fort the salar information for its "named executive offcers" for the year ended December 31, 2007, consistent with
Item 402 of Regulation S- K promulgated by the Securties and Exchange Commssion. Salar informtion of other offcers wil be
provided to the PERC upon request, but the company considers such informtion personal and confdential to such offcers. See 18
CFR 388.107(d), (t).
I$hedule Page: 104 Line No.: 9 Column: b
For additional information regarding changes in the status of PacifiCorp's offcers refer to page 108, Important Changes During the
Year, Item 13, of ths Form NO.1. Mr. Fehran resigned as a director and executive offcer of PacifiCorp on August 30, 2007.
!FERC FORM NO.1 (ED. 12-87l Page 450.1
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 040312008
DIRECTORS
1. Report below the information called for cocerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated
titles of the directors who are officers of the respondent.
2. Designate members of the Executive Commitee by a triple asterik and the Chairman a1the Executive Commitee by a doble asterisk.
.U,!g.Name (anÇl.1 itie) or Ulrecor pnncipal I:usiness Address
(a)(b)
I 12 66 Grand Avenue, Suite DM29, Des Moines, Iowa 50309
3 Patrick Reiten (President, Pacific Power) 825 NE Multnomah, Suite 200, Portland, Oregon 97232
4 A. Richard Walje (President, Rocky Mountain Power)201 South Main, Suite 2400, Salt Lake Cit, Utah 84140
5 Douglas L. Anderson 302 South 36th Street, Omaha, Nebraka 68131
6 Brent E. Gale 825 NE Multomah, Suite 200, Portlan, Oregon 97232
7 Patrik J. Goodman 66 Grand Avenue, Suite DM2, Des Moines, Iowa 50309
8 A. R. Laich (President, PacifiCorp Energy)1407 West North Temple, Suite 320, Salt Lae City, Utah 841169 Mark C. Moench 201 Sout Main, Suite 240, Salt Lake City, Uta 84140
825 NE Multomah, Suite 200, Portland, Oregon 9723211 825 NE Muitnomah, Suite 190, Portand, Oregon 97232
12
13
14
15 Other Directors in 2007_'40wemNo.hT_~'_32'S8la~'_84'1617 4695 South 190 West #3, Roy, Uta 847
18 825 NE Multnomah, Suite 200, Portlan, Oregon 97232
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
48
FERC FORM NO.1 (ED. 12-95)Page 105
............................................
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) lÇ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/03/2008 2007/Q4
FOOTNOTE DATA
!Schedule Page: 105 Line No.: 2 Column: a
CurenU there is only one commttee, a Com ensation Commttee, of which the sole member is Mr. AbeL.
chedule Pa e: 105 Line No.: 10 Column: a
Ms. Hocken was elected August 30, 2007. For additional informtion regarding Ms. Hocken refer to Page 108, Important Chages
During the Year, Item 13, of ths Form No.1.
!Schedule Page: 105 Line No.: 11 Column: a
Mr. Mendez was elected August 30,2007. For additional informtion regarding Mr. Mendez refer to Page 108, Important Changes
During the Year, Item 13, ohhis Form No.1.
'§chedule Page: 105' Line No.: 16 Column: a
Mr. Fehrn resigned as a director on August 30,2007. For additional informtion regarding Mr. Fehrn refer to Page 108,
1m ortant Changes During the Year, Item 13, of ths Form No.1.
chedule Pa e: 105 Line No.: 17 Column: a
Mr. Kaas resigned as a director effective July 25, 2007. For additional informtion regarding Mr. Ka refer to Page 108,
1m ortant Cha es Durin the Year, Item 13, of ths Form No.1.
hedule Pa e: 105 Line No.: 18 Column: a
Mr. Watters resigned as a director effective March 16,2007. For additiona information regarding Mr. Watters refer to Page 108,
Important Changes During the Year, Item 13, of ths Form No.1.
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Blank Page
............................................
(N ext Page is 108)
............................................
Name of Respondent
PacifiCorp
This Report Is:
(1) (2 An Original
(2) D A Resubmission
IMPORTANT CHANGES DURING THE QUARTERIEAR
Date of Report Year/Period of Report
End of 2007/Q404/03/2008
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accrdance 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 importnt 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. ImPortnt leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: . Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of 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 authori,ztion, 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
proeedings 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 assoiate 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 securi 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.
PAGE 1 08 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-9)Page 108
IFERCFORM NO.1 (ED. 12-96) Page 109.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 0410312008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
ITEM 1.
Changes in Franchise Rights
State Effective Date Expiration Date Fee
(F attche to frnchise agrment)Californa (a)
None
Idaho (b)
Arco 0811012007 08/1012011 3.0%
Oregon (c)
Bend 0813112007 08/3112017 5.0%
Corvallis 09119/2007 09119/2017 5.0%
Enterpnse 09/1012007 06130/2017 7.0%
Halsey 1211112007 1211112027 3.5%Harsburg 07/0112007 0710112027 (e)Helix 0312312007 03123/2027 7.0%
Laeview 07/01/2007 06012017 (t)Maywood Park 07/0512007 0710512017 5.0%
Medford 04/0112007 08/0512022 7.0%
Myrle Creek 051291200 OS/29/2017 7.0%
Portand 04/0712007 04/07/2027 5.0%
Redmond 07/26/2007 07126/2012 7.0%
Utah (b)
Brian Head 12/07/2007 12/0712032 6.0%
Circlevile 0711612007 0711612032
Cottonwood Heights 08/07/2007 08/0712017
Kaysvile 10/02/2007 Indefinte
Midvale 10/08/2007 10/08/2057 6.0%
Provo 1213112007 0613012013 6.0%
Rockvile 09117/2007 09117/2037
Sandy 061912007 0113012016 6.0%
Washington (b)
Benton County 04/0212007 02129/2012
Mabton 04110/2007 04110/2027 6.0%
Union Gap 07117/2007 07117/2027 6.0%
Wapato 04/2012007 04/2012027 6.0%
Wyomig (d)
Kiby 0911712007 09117/2032 2.0%
Lander 041121007 041121032 4.0%
Pinedale 0612112007 0612112032 2.0%
(a) In California, franchise fees are an expense to PacifiCorp and are embedded in rates.
(b) In Idaho, Uta and Washington, PacifiCorp collects franchise fees from customers and remits them
directly to the applicable municipalities.
(c) In Oregon, the first 3.5% of the franchise fee is an expense to PacifiCorp and is embedded in rates.
Any amount above the 3.5% is collecte from customers and remitted directly to the applicable
municipalities.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
(d) In Wyoming, the first 1.0% of the franchise fees is an expense to PacifiCorp and is embedded in rates.
Any amount above the 1.0% is collected from customers and remittd directly to the applicable
municipalities.
(e) 4.5% from 7/0112007 though 6130/2009; 5.5% from 7/01/2009 though 7/0112027.
(f) 5.0% from 7/01/2007 though 6/30/2012; 7.0% from 7/0112012 though 613012017.
ITEM 2.
Acquisition of Ownership in Other Companes
PacifCorp Environmental Remediation Company
PacifiCorp Envionmenta Remediation Company ("PERCo") became a wholly owned subsidiar of PacifiCorp in April 200, when
PacifiCorp acquired the outstanding 10% minority interest in PERCo for $150,00. No commssion approval was required.
Intermuntain Getherm and Stem Reserve Corpration
Steam Reserve Corporation was merged with and into its direct parent, Intermountain Geothermal Company, on August 30,2007, with
Intermountan Geothermal Company suriving. Subsequently, Intermountan Geotherm Company was merged with and into its direct
parent, PacifiCorp, on August 31,200, with PacifiCorp suriving. As a result, effective September 1,2007, all assets and liabilities of
Steam Reserve Corporation and Intermountan Geothermal Company reside at PacifiCorp. No commssion approval was required.
ITEM 3.
Purchas or Sale of an Operating Unit
On September 14, 2007, PacifiCorp closed the sale of the Upper Beaver Hydroelectrc Project, Federa Energy Regulatory
Commssion ("FERC") Project No. 814, assets and water rights, to the City of Beaver, Uta, for $2 millon. In accordance with
18 CFR Par 4.94 (f) Arcle 6, notification of the transfer of the license exemption was fied with the FEC. The Upper Beaver
Hydroelectrc Project is located in southwestern Uta, on the Beaver River near the City of Beaver, upon United States Forest Servce
("USFS") lands in the Fish Lae National Forest, and operated under the authority of a special use permt with the USPS. The
proceds, net book value, and sellng costs were tranferred to account 102, Electrc plant purchased or sold. In March 2008,
PacifiCorp filed with th FERC the joural entres caled for by the Uniform System of Accounts. The sale was approved by the
Wyoming, Oregon and Californa state commssions.
ITM 4.
Importnt Leeholds
Godnoe Hils Win Project
In April 2007, PacifiCorp concluded the purchase of the 94.0-megawatt ("MW") Goodnoe Hils Wind Project from Nortwest Wind
Parners, LLC ("Nortwest"), currently under constrction near Goldendae, Washington. As a result of the acquisition, PacifiCorp was
assigned and assumed five 25-year real estate leases from Nortwest with private land owners. The leases have one 25-year extension
available at PacifiCorp's option. Th leases have annual initial term rent payments; one-time installation fees based on the installed
megawatt capacity; and four of the leases have operating rent payments with minimum leas payment obligations based on installed
megawatt of capacity. The remaining lease has operating rent payments based on a millage rate per kilowatt hour determned by a
percentage of an adjusted Powerdex Mid-Columbia weighted-average hourly index and subject to a cap.
I FERC 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) XAn Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/03/2008 2007/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
Marengo n Wind Project
In September 2007, PacifiCorp announced the purchase of the 70.2-MW Marengo II wind project from Blue Sky Wind, LLC,
curently under constrction near Dayton, Washington. As a result of ths acquisition, PacifiCorp was assigned and assumed one
35-year and one 30-year wind energy ground leases and transmission access easements from Blue Sky Wind, LLC, for use of the
underlying land for the project. Both leases are with private land owners and have extensions available though 2055 and 2056 at
PacifiCorp's option. Both leases call for the payment of one-time instalation fees based on the installed megawatt capacity and
monthy production payments based on a millage rate per kiowatt hour of energy generated. Monthly production paymnts are subject
to annua inflationar increases. Both leas call for annua floor minium payments based on the greater of: (1) th monthy
production payments; (2) a fixed annua amount; or (3) a fied amount per instaled megawatt capacity.
ITMS.
Importnt Extension and Reduction of Transmision or Distribution System
For a discussion of transmission lines added during the yea, refer to pages 424-425 of ths Form No.1. Durng th yea ended
December 31, 2007, PacifiCorp did not significantly increase or decrease its distrbution system.
ITEM 6.
Financing Activities
Short- Term Debt
PacifiCorp had no short-term debt outstading at December 31,2007. Authorizations durng the year ended December 31, 2007 for up
to $1.5 bilion outstading at anyone time in commercial paper and other unsecur short-term debt were as follows:
· Utah Public Service Commssion (the "UPSC") - Docket No. 06-035-027, Report and Order date March 17, 200
· Oregon Public Utility Commssion (the "OPUC") - Docket No. UF-4120 and Order No. 98-158 date April 16, 1998
· Washington Utilities and Trasporttion Commssion (the "WUTe') - Doket No. UE-980404 dated April 8, 1998
· Idao Public Utilities Commssion (the "IPUC") - Ca No. PAC-E-0Ol and Order No. 2999 dated March 14,2006
· United States Securties and Exchange Commssion (the "SEC") - Release No. 35-27851 dated May 28, 200; filed with the
FERC on Februar 6, 2006, pursuant to 18 CFR 366.6(b)
Long- Term Debt
In Janua 2008, PacifiCorp received regulatory authority from the OPUC and the IPUC to issue up to an additional $2.0 billion of
long-term debt. PacifiCorp must make a notice filing with the WUC prior to any futue issuance. Also in Januar 2008, PacifiCorp
filed a shelf registration statement with the SEC covering future firt mortgage bond issuances. In May 2007, PacifiCorp was granted
an exemption from obtaning wrtten approval from the UPSC prior to the issuance of securities. The exemption generally remains in
effect as long as PacifiCorp's senior seur debt mantans investment grade ratings.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
In October 2007, PacifiCorp issued $600 million of its 6.25% First Mortgage Bonds due October 15, 2037. State commssion
authorizations for ths issuance were as follows:
· OPUC - Docket No. UF-4237 and Order No. 07-085 dated March 5, 2007
· IPUC - Case No. PAC-E-07-02 and Order No. 30258 dated Febru 27, 2007
In March 2007, PacifiCorp issued $600 millon ofits 5.75% Firt Mortgage Bonds due April 1, 2037. State commssion authorizations
for ths issuance were as follows:
· UPSC - Docket No. 07-035-05, Report and Order dated March 2, 2007
· OPUC - Docket No. UF-4237 and Order No. 07-085 dated March 5,2007
· WUC - Docket No. UE-070450 and Order No. 1 dated Marh 7, 2007
· IPUC - Case No. PAC-E-07-2 and Order No. 30258 date Februar 27, 2007
Revolving Creit and Other Fincing Arrangements
At December 31, 2007, PacifiCorp had $1.5 bilion available under its unsecured revolving credit facilties. Durng th year ended
December 31, 2007, PacifCorp entered into an unsecured revolving credit facilty with tota bank commtments of $700 millon
available though October 23, 2012. Under PacifiCorp's existing unsecured revolving credt facility, $800 millon is available though
July 6, 2011 and $760 millon is available from July 7, 2011 though July 6, 2012. The ban facilities support PacifiCorp's
commercial paper program and include a varable interest rate borrowing option basd on the London Interbank Offered Rate
(ULmOR"), plus a magin that is curently 0.195%, and vares based on PacifiCorp's credt ratings for its senior unsecured long-term
debt securties. At December 31, 200, PacifiCorp did not have any borrowings outstanding under either credit facilty.
At December 31,2007, PacifiCorp had $518 millon of stadby letters of credit and stadby bond purhase agreements available to
provide credit enhancement and liquidity support for varable-rate pollution-control revenue bond obligations. These commtted bank
arangements were fully available at December 31, 2007 and expire periodically though May 2012.
In addition, at.December 31,2007, PacifiCorp had approximately $18 millon of stadby lettrs of credit available to provide credit
support for certn transactions as reuested by thrd pares. Thse commtted bank arangements were all fully available at
December 31,2007 and have provisions that automatically extend the annual expiration dates for an additional year uness the issuing
bank elects not to renew a letter of credit prior to the expiration date.
PacifiCorp's revolving credit and other financing agreements contan customar covenants and default provisions, including a
covenant not to excee a specified debt-to-capitaization ratio of 0.65 to 1.0. At December 31,2007, PacifiCorp was in compliance
with the covenants of its revolving credit and other financing agreements.
ITEM 7.
Changes in Articles of Incorporation or Amendments to Charter
None.
IFERC FORM NO.1 (ED. 12-96) Page 109.4
IBEW 57 Power Delivery (UT, ID & WY)
IBEW 127 (W)
IBEW 57 Generation (UT, ID & WY)
2.78%
2.82%
2.79%
1126/200
3/2612007 & 9/26/200
11261007
$2,127,00
1,107,00
978,00
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 040312008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
ITEMS.
Estimated Annual Effect of Wage Scale Changes
PacifCorp's bargaining unit wage scale changes were as foUows:
Unions Represented % Incras (a)Effective Date(s)
Estimate Anual
Financial Impact (b)(c)
Tota $4,212,00
(a) This percntage increase represents the increase in wages for al effective dates during the caenda yea as compar
to the wage scale of the prior effective period.
(b) Some amounts may be reimbursed by joint owners of steam generang facilties.
(c) The estimate anual impact is basd on the time period from the effective date of the increase to the end of the
calenda yea.
ITEM 9.
Legal Procedings
In addition to the proceedings described below, PacifiCorp is curntly par to varous items of litigation or arbitration in the norml
course of business, none of which are reasonably expected by PacifiCorp to have a material adverse effect on its financial results.
In December 2007, PacifiCorp was served with a complaint fied in the United States Distrct Cour for th Northern District of
Californa by the Klamath Riverkeeper (a local environmnta group); Leaf Hilman (a Kar Tribe member); Howard McConnell
and Robert Attbery (Yurok Tribe members); and Blyt Reis (a resort owner). The complaint alleged that reservoirs behind the
hydroelectrc da that PacifiCorp operates on the Klamath River provide an envionment for the growth of a blue-green algae
known as microcystis aeruginosa, which can generate a toxin called microcystin. The complaint alleged tht such algae is a "solid
waste" under the federal Resource Conservation and Recovery Act. tht PacifiCorp "generates" and "stores" such algae in its
reservoirs, that PacifiCorp "disposes" of such algae when it passes though the da, an tht such "generation," "storage" and
"disposal" causes or theatens to cause an immnent and substatial endagerment to health and the environment. PacifiCorp believed
the claims to be without merit and filed a motion to dismiss in Decmber 2007. In Februar 2008, a cour order was issued
conditionally allowing the consolidation of the December 2007 blue-green algae case with the May 2007 blue-green algae cas
described below, provided that plaintiffs agree to pay PacifiCorp for certn delay costs caused by the consolidation. Plaintiffs did not
agree to pay PacifiCorp's delay costs and the court subsequently issued an order to dismiss the lawsuit in March 2008.
lFERC FORM NO.1 (ED. 12-96) Page 109.5
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Onginal (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/03/2008 2007/Q4
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
In May 2007, PacifiCorp was served with a complaint fied in the United States District Court for the Nortern District of California
by Leaf Hillman and Terance J. Supahan (Kak Tribe members); Frankie Joe Myers, Howard McConnell and Robert Attebery
(Yurok Tribe members); Michael T. Hudson (a commercial fisherman); Blythe Reis (a resort owner); and the Klamath Riverkeeper (a
local environmental group) alleging that toxic algae "introduced" by PacifiCorp into Klamath hydroelectrc project reservoirs is
releas by PacifiCorp to the river downstream of the project, and caused or will cause the plaintiffs physical, property, and economic
har. Plaintiffs allege seven causes of action based on nuisance, trespass, negligence, and unlawfl business practices, all under
California law. Elevated concentrations of microcystis aeruginosa (blue-green algae) have been identified in Klamath River
hydroelectrc project reservoirs, and now farher downstream on the Klamath River. The algae occur naturally across Oregon,
California, and thoughout the world. Elevated concentrations tend to appear in areas of slack water that is relatively war. It has
been identified for year on Klamth Lake. Plaintiffs seek unspecified damages and injunctive relief; however, in an order filed by the
cour in August 2007, the cour dismissed plaintiffs' claims for injunctive relief based on federal preemption under the Federal Power
Act. Additionally, in March 2008, plaintiff Robert Attbery voluntaly dismissed his claims in the case, and on April 2, 2008, the
court entered a stipulation and order dismissing plaintiff Klamath Riverkeeper's claims, with prejudice. PacifiCorp denies the
allegations and is vigorously defending the case, which is curently in the discovery phase.
In Februar 2007, the Sierra Club and the Wyoming Outdoor Council fied a compliant against PacifiCorp in the federal distrct cour
in Cheyenne, Wyoming, alleging violations of Wyoming state opacity standards at PacifiCorp's Jim Bridger plant in Wyoming.
Under Wyomig state requirements, which are par of the Jim Bridger plant's Title V permt and are enforceable by private citizens
under the federal Clean Air Act, a potential SOurce of pollutats such as a coal-frred generating facilty must meet mimum standads
for opacity, which is a measurement of light that is obscured in the flue of a generating facilty. The complaint alleges thousands of
violations of asserted six-minute compliance periods and seeks an injunction ordering 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 court granted a motion to
bifucate the trial into separate liabilty and remedy phases. A five-day tral on the liabilty phase is scheduled to begin in April 2008.
The remedy-phase tral has not yet been set. The cour is considering several sum judgment motions filed by the pares, but has
not yet ruled on any of them. PacifiCorp believes it has a number of defenses to the claims. PacifiCorp intends to vigorously oppose
the lawsuit but canot predict its outcome at ths time. PacifiCorp has aleady commtted to invest at least $812 millon in pollution
control equipment at its generating facilties, including the Jim Bridger plant. Ths commtment is expected to significantly reduce
system-wide emissions, including emissions at the Jim Bridger plant.
In October 2005, PacifiCorp was added as a defendant to a lawsuit originally filed in Februar 2005 in state distrct cour in Salt Lake
City, Utah by USA Power, LLC and its afliated companies, USA Power Parners, LLC and Spring Canyon, LLC (collectively,
"USA Power"), against Utah attorney Jody L. Wiliams and the law firm Holme, Roberts & Owen, LLP, who represent PacifiCorp on
varous matters from time to time. USA Power is the developer of a planned generation project in Mona, Utah called Spring Canyon,
which PacifiCorp, as par of its resource procurement process, at one time considered as an alternative to the Curant Creek plant.
USA Power's complaint alleged that PacifiCorp misappropriated confidential proprieta information in violation of Uta's Uniform
Trade Secrets Act and accused PacifiCorp of breach of contract and related claims. USA Power seeks $250 millon in damages,
statutory doubling of dages for its trade secrets violation claim, punitive damages, costs and attorneys' fees. Afer considering
various motions for summar judgment, the cour ruled in October 2007 in favor of PacifiCorp on all counts and dismissed the
plaintiffs' claims in their entirety. Plaintiffs are expected to appeal ths decision and PacifiCorp believes that its defenses that
prevailed in the tral cour wil prevail on appeaL. Furtermore, PacifiCorp expects that the outcome of any appeal will not have a
material impact on its financial results.
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 04/03/2008 2007/04
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
In May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the Distrct of Oregon by the
Klamath Tribes of Oregon, individual Klamath Tribal members and the Klamath Claims Commttee. The complaint generally alleges
that PacifiCorp and its predecessors affecte the Klamath Tribes' federal treaty rights to fish for salmon in the headwaters of the
Klamath River in southern Oregon by building dam that blocked the passage of salmon upstream to the headwaters beginning in
1911. In September 200, the Klamath Tribes filed thir fist amended complaint adding claims of damage to their treaty rights to fish
for sucker and steelhead in the headwaters of th Klamth River. The complaint seeks in excess of $1.0 bilion in compensatory and
punitive damages. In July 2005, th Distrct Cour dismissed the case and in September 2005 denied the Klamath Tribes' request to
reconsider the dismissal. In October 2005, the Klamath Tribes appealed the Distrct Court's decision to the Ninth Circuit and briefing
was completed in March 2006. In Februar 2008, the Ninth Circuit afed the Distrct Cour's decision. The plaintiffs in the cas
may seek reheang before a larger panel on the Ninth Circuit or appeal to the U.S. Supreme Court. PacifiCorp believes the outcome
of ths proceeding will not have a material impact on its financial results.
ITM 10.
None.
ITM 11.
(Reserved)
ITEM 12.
Federal Reglatory Mattrs
For a discussion of Californa and Nortwest Refu cass, refer to Note 11 of Notes to Financial Statements included in ths Form 1.
The Bonneville Power Administration Residential Exchange Program
The Nortwest Power Act, though the Residential Exchange Program, provides access to th benefits of low-cost federal
hydroelectricity to the residential and small-far customers of the region's investor-owned utilities. The program is administered by
the Bonneville Power Administration (the "BPA") in accordance with federal law. Pusuat to agreements between the BPA and
PacifCorp, benefits from the BPA are passed though to PacifiCorp's Oregon, Washington and Idaho residential and smal-far
customers in the form of electcity bil credits. In October 200, PacifiCorp entere into a settlement agreement with the BPA that
provided Residential Exchage Program benefits to PacifiCorp's customers from October 2001 through September 200. In
May 2001, PacifiCorp entered into a load reduction ageement with the BPA tht eliminate the BPA's obligation to deliver power to
PacifiCorp from October 2001 though September 200 in exchange for cah paymnts. Ths agreement also contaned a "reduction of
risk discount" provision, which provided that the BPA would reduce the cash payments to PacifiCorp if by December 1, 2001,
PacifiCorp and other utilities were able to negotiate an enter into settlement agreements with the publicly owned utilties and other of
the BPA's preference customers dismissing certn lawsuits. If these pares did not reach settement by the specified date, the clause
would expire and the BPA would make cash payments to PacifiCorp based on the original rate for the October 2002 though
September 2006 period. Settement was not reached and the clause expired, obligating the BPA to make the full cash payment to
PacifiCorp. In May 200, PacifiCorp, the BPA and other pares execute an additional agreement, which modified both the
October 200 and May 200 1 agreements, which provides for a guaranted range of benefits to customers from October 2006 though
September 2011.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/03/2008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
Several publicly owned utilties, cooperatives and the BPA's dirt-service industry customers filed lawsuits against the BPA with the
United States Cour of Appeals for the Ninth Circuit (the "Ninth Circuit") seeking review of certin aspects of the BPA's Residential
Exchange Program, as well as challenging the level of benefits previously paid to investor-owned utility customers. In May 2007, the
Ninth Circuit issued two decisions. The fist decision sets aside the October 2000 Residential Exchange Program settlement
agreement as being inconsistent with the BPA's settement authority. The second decision holds, among other thngs, that the BPA
acted contrar to law when it allocated to its preference customers, which include public utilties, cooperatives and federal agencies,
par of the costs of the October 2000 settement the BPA reached with its investor-owned utility customers. As a result of the ruling,
in May 2007, the BPA notified the Pacific Northwest's six utilities, including PacifiCorp, that it was immediately. suspending
payments. Ths has resulted in increases to PacifiCorp's residential and small-far customers' electrc bils in Oregon, Washington
and Idaho. In October 2007, the Ninth Circuit issued one published decision and thee unpublished decisions. The publishe decision
remanded the May 2004 agreement modifying the October 200 and May 2001 agreements to the BPA for fuer action consistent
with the Ninth Circuit's May 2007 decisions. The other thee unpublished decisions dismiss cass in which the publicly owned
utilities sought review of the BPA's decision to implement th reduction of risk discount provision and make the full cash payment to
PacifiCorp. In Februar 2008, the BPA initiated a rate proceeng under section 7(i) of the Nortwest Power Act to reconsider the
level of benefits for the years 2002 though 2006 consistent with the Ninth Circuit's decisions, to re-establish the level of benefits for
yeas 2007 and 2008 and to set the level of benefits for years 2009 and beyond. Because the benefit paymnts from th BPA are
passed through toPacifiCorp's customers, the outcome of ths matter is not expected to have a significant effect onPacifiCorp's
financial results.
FERC Market Oversight
FERC Order No. 693
In March 2007, the FEC issued Order No. 693, Mandatory Reliabilty Standards for the Bulk-Power System, which imposes
penalties of up to $1 millon per day per violation for failure to comply with new electrc reliabilty standards. The FERC approved
83 reliability standads developed by the Nort American Electrc Reliabilty Corporation (the "NERC"). Responsibilty for
compliance and enforcement of these standards has been given to the WECC. The 83 stadards comprise over 60 requiements and
sub-requirements with which PacifiCorp must comply. On June 18, 2007, the stadards became mandatory and enforceable under
federal law. PacifiCorp expects that the existing standards will change as a result of modifications, guidance and clarfication following
industr implementation and ongoing audits and enforcement. On Januar 18, 2008, the FERC approved eight additional cyber
securty and critical infrastrcture protection standards proposed by the NERC. The additional standards will beome effective on
April 7,2008. PacifiCorp cannot predict the effect that these standards wil have on its financial results; however, they will likely have
a signicant impact on transmission operations and resource planning functions. Also durng 2007, the WECC audited PacifiCorp's
compliance with several of the reliabilty standads approved by the FERC. PacifiCorp is analyzing the preliminar results of the audit
and, at ths time, cannot predict the impact of potential penalties, if any, on its financial results.
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) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
FERC Orders No. 890 and 890-A
In Februar 2007, the FERC adopted a final rule in Order No. 890 designed to strengthen the pro forma OAIT by providing greater
specificity and increasing transparency. The most signficant revisions to the pro forma OAIT relate to the development of more
consistent methodologies for calculating available trsfer capability, changes to the transmission planning process, changes to the
pricing of certin generator and energy imbalances to encourage effcient scheduling behavior and to exempt intefOttent generators,
and changes regarding long-term point-to-point transmission service, including the addition of conditional firm long-term
point-to-point transmission servce, and generation re-dispateh. As a trnsmission provider with an open-access transmission taff on
fie with the FERC, PacifiCoip is requied to comply with th reuiments of the new rule. The first compliance filing, which amends
the OAIT, was fied in July 2007. Certn detals related to the preise methodology tht will be used to calculate available transfer
capabilty were fied with the FERC in September 2007. A number of pares to the proceeding, including PacifiCoip, have requested
rehearng or clarification of various portons of the final rule. In December 2007, the FERC issued Orer No. 890-A generally
affng the provisions of the final rule as adopted in Order No. 890 with certn limited clarfications. Although PacifiCoip has
requested a limited clarfication of Order No. 890-A, the final rule as revised is not anticipated to have a significant impact on
PacifiCoip's financial results, but it will likely have a signficant impact on its transmission operations, planng and wholesale
marketing functions.
Energy Policy Act of 2005
On August 8,2005, the Energy Policy Act was sign into law and ha significantly impacted the energy industr. In parcular, the
law expanded the FERC's regulatory authority in areas such as electrc system reliabilty, electrc transmission expansion and pricing,
regulation of utility holding companes, and enforcement authority to issue civil penalties of up to $1 millon per day. Whle the
FERC ha now issued rules and decisions on multiple aspects of the Energy Policy Act, the full impact of those decisions remains
uncertn.
Th Energy Policy Act also gives the FERC "backstop" trmission siting authority and dirts the FERC to oversee th
establishment of mandatory trsmission reliabilty standards as discussed above. The Energy Policy Act also extended the federal
production tax credit for new renewable electrcity generation projects though December 31, 2007, with subsequent legislation
extending the credit to December 31, 2008. Parly as a result of that porton of the law, PacifiCoip began development effort for
additional wind plants.
Transmission Settlement
In Janua 2007, the FERC approved a settement with PacifiCoip regarng PacifiCoip's use of its transmission system while
conducting wholesale power transactions with thd pares. PacifiCoip discovered possible violations of its FERC-approved taff
durng an internal investigation of its compliance with certn FERC regulations shorty before MidAerican Energy Holdings
Coiporation's ("MEHC") acquisition of PacifiCoip. Upon completion of the acquisition, PacifiCoip self-reported the potential
violations to the FERC. The potential violations primarily related to the way PacifiCoip used its own transmission system to transmit
energy using "network service" instead of "point-to-point" servce as the FERC believes is requir by PacifiCoip's taff. This use of
transmission service neither enrched PacifiCoip's shareholders nor hared its retal customers. As par of the settement, PacifiCoip
voluntaly refunded $1 millon to other transmission customers in April 200 and paid a $10 millon fine to the United States
Treasur in Januar 2007.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp (2) A Resubmission 04/03/2008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
Wholesale Electricity and Capacity
The PERC regulates PacifiCorp's rates charged to wholesale customers for electrcity, capacity and trnsmission services. Most of
PacifiCorp's electrc wholesale sales and purchases tae place under market-based rate pricing allowed by the PERC and are
therefore subject to market volatility. A December 2006 decision of the Ninth Circuit changed the interpretation of the relevant
standad that the PERC should apply when reviewing wholesale contracts for electrcity or capacity from a strngent "public policy"
stadard to a broader "just and reasonable" stadard makng contracts more vulnerable to challenge. The decision raises some
concerns regarding the finality of contract prices, parcularly from the sellers' side of the transactions. The United States Supreme
Cour is reviewing th case on appeal and the outcome of its ruling cannot be predicted at ths time. All sellers subject to the PERC's
jurisdiction, including PacifiCorp, are currently subject to increase risk as a result of ths decision.
The PERC conducts a trennial review of PacifiCor' s market-based rate pricing authority. Each utility must demonstrte the lack of
generation market power in order to chage maket-based rates for sales of wholesale electrcity and capacity in their respetive
balancing authority areas. Under the PERC's market-based rules, PacifiCorp must file a notice of change in status when 100 MW of
incrementa generation becomes operational. Following separate filings by PacifiCorp of a change in status notice relating to new
generation, the PEC in February and November 2007 confied tht PacifiCorp does not have market power and may continue to
charge market-based rates. In accordance with the filing schedule established by the PERC in Orer No. 697, PacifiCorp's next
triennal review will occur in 2010 or earlier if requied.
Hydroelectrc Relicensing
Several of PacifiCorp's hydroelectrc plants are in some stage of the relicensing process with the PERC. PacifiCorp also has
requested the PERC to allow decommssioning of certn hydroelectrc projects. The following summzes the status of certn of
these projects.
Klamath Hydroelectrc Project - (Klamath River, Oregon an California)
In Februar 200, PacifiCorp filed with the PERC a final application for a new license to operate the 169-MW (namplate rating)
Klamath hydroelectrc project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is curently operating
under an annual license granted by the PERC and expects to continue to operate under annua licenses until the new operating license
is issued. As par of the relicensing process, the United States Deparents of Interior and Commerce fied proposed licensing term
and conditions with the PERC in March 2006, which proposed that PacifiCorp constrct upstram and downstrea fish passage
facilties at the Klamth hydroelectric project's four manstem dams. In April 2006, PacifiCorp filed alternatives to the federal
agencies' proposal and requested an administrtive hearng to challenge some of the federal agencies' factual assumptions supportng
their proposal for the constrction of th fish passage facilities. A hearng was held in August 200 before an administrative law
judge. The administrative law judge issued a ruling in September 2006 generally supportng the federal agencies' factual assumptions.
In Januar 2007, the United States Deparents of Interior and Commerce fied modified term and conditions consistent with
March 200 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to' meet and implement the federal
agencies' term and conditions as par of the project's relicensing. However, PacifiCorp expects to continue in settlement discussions
with varous pares in the Klamath Basin area who have intervened with the PERC licensing proceeding to tr to achieve a mutually
acceptable outcome for the project.
IFERC FORM NO.1 (ED. 12-96) Page 109.10
IFERC FORM NO.1 (ED. 12-96)Page 109.11
............................................
Name of Respondent This Report is:Date of Report Year/Penod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 041032008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Cotinued)
Also, as par of the re1icensing process, the FERC is required to pedorm an environmental review. In September 200, the FERC
issued its draft environmental impact statement on the Klamath hydroelectrc project license. PacifiCorp filed comments on the draft
statement by th close of the public comment period on Deember 1,2006. Subsequently, in November 2007, the FERC issued its
final environmental impact statement. The United States Fish and Wildlife Service and the National Marine Fisheries Service issued
final biological opinions in December 2007 analyzing the hydroelectrc project's impact on endagered species under the proposed
new FERC license. The United States Fish and Wildlife Service asserts the hydroelectrc project is curently not .covered by
previously issued biological opinions, and that consultation under the Endangered Species Act is required by the issuance of annual
license renewals. PacifiCorp disputes these assertons, and believes federal case law is clear that consultation on annual FERC
licenses is not requir. PacifiCorp will need to obtan water quality certfications from Oregon and California prior to the FERC
issuing a final license. PacifiCorp curntly has applications pending before each state.
Lewis River Hydroelectric Projects - (Leis River, Washington)
PacifiCorp filed new license applications for th 136-MW (nameplate rating) Merwn and 240-MW (nameplate rating) Swift No. i
hydroelectrc projects in April 200. An application for a new license for the 134-MW (nameplate rating) Yale hydroelectrc project
was filed with the FERC in April 1999. However, consideration of the Yale application was delayed pending filing of the Merwin and
Swift No. 1 applications so that the FERC could complete a comprehensive environmental analysis.
In November 200, PacifiCorp execute a comprehensive settement agrment with 25 other pares including state and federal
agencies, Native American trbes, conservation groups, and local government and citizen groups to resolve, among the pares, issues
related to the pending applications for new licenses for PacifiCorp's Merwn, Swift No. i and Yale hydroelectrc projects. As pa of
this settement agreement, PacifiCorp agreed to implement certn protetion, mitigation and enhancement meaures prior to and
durng a proposed 50-year license period. However, these commtments are contingent on ultimately receiving licenses from the
FERC and other required permts that are consistent with the settlement agreement. PacifiCorp has received water quality certficates
from the Washington Deparent of Ecology and biological opinions from th United States Fish and Wildlife Service and th
National Marne Fisheries Service. Regulatory documents needed to licens the projects have been submitted to the FERC and
PacifiCorp is awaiting the issuance of new FERC licenses.
Prospect Hydroelectric Project- (Rogue River, Oregon)
In June2oo3, PacifiCorp submittd a final license application to the FERC for the Prospect Nos. 1, 2 and 4 hydroelectric projects,
whose nameplate ratings tota 37 MW. The Orgon Deparent of Envionmenta Quality issued a 401 Water Quality certficate for
the project in April 2007, which effectively concluded the license process. The FERC is expected to issue a new license before th
end of May 2008.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/03/2008 2007/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
Hydroelectric Decommissioning
Power dale Hydroelectric Project- (Hood River, Oregon)
In June 2003, PacifiCorp entered into a settlement agreement to remove the 6-MW (nameplate rating) Powerdale plant rathr than
pursue a new license, based on an analysis of the costs and benefits of relicensing versus decommssioning. Removal of the
Powerdale da and associated project featues, which is subject to the FERC and other regulatory approvals, is projected to cost
$6 millon excluding inflation. Removal was scheduled to commence in 2010. However, in November 2006, flooding damaged the
Powerdae plant and rendered its generating capabilties inoperable. In Februar 2007, the FERC granted PacifiCorp's request to
cease generation at the project until decommssioning activities begin. Also in Februar 2007, PacifiCorp submitted a request to the
FERC to allow the company to defer the remaining net book value and any additional removal costs of ths project as a. regulatory
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 removal costs to a regulatory asset. PacifiCorp has received approval from its state
commssions to defer and recover these costs.
Condit Hydroelectric Project - (White Salmon River, Washington)
In September 1999, a settlement agreement to remove the iD-MW (namplate rating) Condit hydroelectc project was signed by
PacifiCorp, state and federal agencies and non-governenta organizations. Under the original settement agrment, removal was
expected to begin in October 200, with a tota cost to decommssion not to exceed $17 millon, excluding inflation. In early
Februar 2005, the pares agreed to modif the settlement agreement so that removal wil not begin until October 2008 for a tota
cost to decommssion not to exceed $21 millon, excluding inflation. The settlement agreement is contingent upon receiving a FERC
surender order and other regulatory approvals that are not materially inconsistent with the amended settement agreement. PacifiCorp
is in the process of acquirng all necessary permts, withn the terms and conditions of the amended settement agreement. If th
permttng process continues into the seond quaer of 2008, the decommssioning will not begin until October 200.
Cove Hydroelectric Project - (Bear River, Idaho)
In May 200, the PERC approved PacifiCorp's application to amend the Bear River license and authorize the removal of the 8-MW
(nameplate rating) Cove hydroelectrc plant and facilities. Decommssioning of the Cove facilties has been completed in accordance
with th license amendment and the approved removal plan. The removal of the dam, flowline and all facilties, with the exception of
the powerhouse that has been designated a historical landmak, was completed in November 2006. As of December 31, 200,
$3 millon had been spent for the decommssioning of the Cove hydroelectrc project.
American Fork Hydroelectrc Project - (American Fork Creek, Utah)
In August 200, the PERC authorized the removal of the I-MW (nameplate rating) American Fork hydroelecc plant and facilties.
Decommssioning of the American Fork facilties has been completed in accordance with the approved removal plan. The removal of
the dam, flowline and all facilities, with the exception of the powerhouse tht has been designated a historical. landmark, was
completed in December 2007. As of December 31, 2007, $4 millon had been spent for th decommssioning of the American Fork
hydroelectrc project.
IFERC FORM NO.1 (ED. 12-96) Page 109.12
I FERC 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 I (2) A Resubmission 0410312008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
United States Mine Safety
Mining operations are regulated by th federal Mine Safety and Health Administration ("MSHA"), which administers federal mine
safety and health laws, regulations and state regulatory agencies. The Mine Improvement and New Emergency Response Act of 2006
(''MINR Act"), enacted in June 2006, amended previous mine safety and health laws to improve mine safety and health and accident
preparedness. The MINR Act, portons of which are not yet fully implemented, requires operators of underground coal mines to
develop a wrtten emergency response plan specific to each mie they operate. These plans must be reviewed by MSHA every
six months. It also requires every mine to have at leat two rescue team located withn one hour, and it lits the legal liabilty of
rescue team members and the companes that employ them. The MIR Act also increas civil and criminal penalties for violations
of federal mine safety standads and givesMSHA th abilty to institute a civil action for relief, including a temporar or permanent
injunction, restraining order or other appropriate order against a mine operator who fails to pay the penalties or fines.
State Regulatory Actions
PacifiCorp is currently pursuing a regulator program in all states, with the objective of keeping rates closely aligned to ongoing
costs. The following discussion provides a state-by-state update.
Utah
In December 2007, PacifiCorp fied a general rate case with the UPSC reuesting an annual increase of $ 161 millon, or an average
prce increase of 11%. The increase is priarly due to increased capita spending and net power costs, both of which ar driven by
load growt. In Febru 200S, the UPSC issued an order determning that the proper test period should end December 200S. In
March 200S, PacifiCorp filed supplementa testiony reducing the reuested rate increase to $100 millon. Th six month change in
the test period accounts for $40 millon of th reduction. The supplemental filing also reflects an additional $21 millon of reuctions
associated with recent UPSC orders on depreciation rates and two deferred accounting requests that were pending when the original
case was filed. Hearngs on the revenue requirement porton of the case are scheduled for June 200S, with the rate-design phase
scheduled for October 200S. PacifiCorp expets that initial rates, if approved, will become effective no later than August 200S.
In December 2006, the UPSC approved a stipulation setting PacifiCorp's general rate case fied in March 2006 related to increased
investments in Uta due to growing demand for electricity. The stipulation called for an annual increase of $115 millon, or an
average price increase of 10%, with $S5 millon of the increase effective December 11,200 and the remaning $30 millon increase
effective June 1,2007.
Oregon
In April 200S, PacifiCorp fied its net power costs for 200 in the company's Transition Adjustment Mechanism (the ''TAM'') and
revenue requirement for 2009 for new renewable resources in the Renewable Adjustment Clause (the "RAC"). The TAM and the
RAC filings propose a combined rate increase of $SO millon, or 9%, effective Januar 1,200. The combined increae is 7% to
residential customers and 12% to industral customers. Although PacifiCorp wil mae two separate filings, it is expecte that the
filings will be consolidated into one proceeding. The filings are complementar in tht if the fixed costs of an eligible resource are
included in the RAC or otherwse in rates, then the varable costs and cost offsets of the resource are included in the TAM. Both
mechanisms are designed to produce a commssion decision by November 200S.
In August 2007, PacifiCorp filed a renewable cost adjustment clause that will allow for timely recovery between rate cases of the
costs of eligible renewable resources and associated transmission under the renewable portolio standads ("RPS"). The RPS required
the OPUC to approve an automatic adjustment clause for timely recovery of these costs by Janua 1, 200S. In December 2007, the
OPUC approved a settlement stipulation filed by the pares to the proeeings tht established the RAC mechansm, with an effective
date of Januar 1, 200S. Under the RAC mechanism, PacifiCorp will submit a filing on April 1 of each year, with rates to become
effective Januar 1 of the following year, to recover the revenue requirement of new renewable resources and associated transmission
that are not reflected in general rates. As par of the RAC mechanism, the OPUC authrized PacifiCorp to defer eligible costs not yet
included in rates until the next annua RAC filing.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
In July 2007, as par of PacifiCorp's annual compliance filing with the OPUC to update forecasted net power costs, PacifiCorp
requested an increase of approximately $30 million, or an average price increase of 3%, to tae effect Januar 1, 2008. The annual
filing, called the transition adjustment mechanism (''TAM''), was adjusted for new contracts though October 2007 and for other
changes to forecasted net power costs, such as coal and natural gas prices, though November 2007. In October 2007, the OPUC
issued an order that approved the TAM increase subject to PacifiCorp updating its net power cost forecast to reflect changes adopted
in the decision. In November 2007, PacifiCorp submitted a compliance filing with an updated net power cost forecast, which reflected
a $22 millon increase, or an average price increase of 2%. In December 2007, the OPUC approved the TAM with rates effective
Januar 1, 2008.
In September 200, the OPUCapproved a settlement agrement resolving PacifiCorp's Februar 2006 general rate case request
relate to investments in generation, transmission and distrbution infrtrcture and increases in fuel and general operating expenses,
including the mantenance of low-cost but aging power plants. Pursuant to the settlement agreement, PacifiCorp received an annual
increase for non-power cost items of $33 millon effective January 1, 2007. Also on Januar 1, 2007, PacifiCorp received a
$10 millon increase for power costs though its annual TAM.
For a discussion of Oregon Senate Bil 408, refer to Note 3 of Notes to Financial Statements included in ths Form 1.
Wyoming
In June 2007, PacifiCorp fied a general rate case with the Wyoming Public Service Commssion (the "WPSC") requesting an annual
increae of $36 millon, or an average price increase of 8%. In addition, PacifiCorp requested approval of a new renewable resource
recovery mechanism and a marginal cost pricing taff to bettr reflect the cost of adding new generation. In Januar 2008, PacifiCorp
reached a settlement in principle with pares to the case, subject to entering into a final stipulation and approval by the WPSc. The
settement provides for an annual rate increase of $23 millon, or an average price increase of 5%. In addition, the pares also agreed
to a forecast power cost mechanism and discontinuation of the curent power cost adjustment mechaism ("PCAM") by April 2011,
unless a continuation is specifically applied for by PacifiCorp and approved by the WPSC. PacifiCorp's marginal cost pricing taff
proposal will not be implemented, but wil be the subject of a collaborative process to seek a new pricing proposal. Also as par of the
settement, PacifiCorp agreed to withdraw from ths filing its request for a renewable resource recovery mechansm. The stipulation
was executed and fied with the WPSC in Januar 2008 and was the subject of a hearng for approval in March 2008 where it was
approved. The new rates will become effective May 1,2008.
In Februar 2008, PacifiCorp filed its annual deferred net power cost adjustment application with the WPSC in the amount of
$31 millon for costs incured durng the period December 1, 2006 through November 30, 2007.
In Februar 2007, PacifiCorp fied its fist annual deferred net power cost adjustment application with the WPSC in th amount of
$3 millon for costs incured during the period July 1, 2006 though November 30, 2006. In March 2007, PacifiCorp received
approval from the WPSC to implement interim rates effective April 1, 2007, in the amount of $3 millon. In May 2007, PacifiCorp
fied a stipulation and agreement with the WPSC that resolved all issues in the application and reduced the deferred net power cost
adjustment to $2 millon. The revised rates were effective July 1,2007.
IFERC FORM NO.1 (ED.12~96)Page 109.14
IFERCFORM NO.1 (ED. 12-96) 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 041032008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
Washington
In Februar 2008, PacifiCorp fied a general rate case with the WUC for an annual increase of $35 millon, or an average price
increase of 15%, with an effective date no later than Janua 2009.
In OCtober 2006, PacifiCorp fied a general rate case with the WUC for an annual increase of $23 millon, or an average price
incree of 10%. As part of the fiing, PacifiCorp proposed a Washington-only cost-allocation methodology, which is based on
PacifiCorp's western resources. The rate case included a five-year pilot period on the proposed allocation methodology and a PCAM.
In June 2007, the WUC issued an order approving a rate increas of $14 millon, or an average price increa of 6%, effectve
June 27, 2007, and accepted PacifiCorp's proposed western balancing authority area cost-allocation methodology for a five-year pilot .d
period. The WUC found tht PacifiCorp demonstrate the nee for a PCAM, but it did not approve the design of the proposal in ths
case. The order authorize PacifiCorp to file a revise PCAM proposa, with or without a request to file power cost-only rate cases,
outside the context of a general rate case withn 12 month of the order.
Idaho
In June 2007, PacifiCorp filed a general rate case with the IPUC for an annual increas of $ I 8 millon, or an average price increase of
10%, with a request for an effective date of Januar 1, 2008. In November 2007, an all-pary stipulation was reached on all issues in
the general rate case, resulting in an annual increase of $12 millon, or an average price increase of 6%. The IPUC approved th
settement stipulation in December 2007, with new rates effective Janua 1, 2008. The settement also provides for rate increases
effective Janua I, 200 and 2010 for PacifiCorp's two special contract industral customers and no additional rate changes for those
two special contract customers effective prior to Januar 1,201 1. Additional rate increases for the remaining customer classes may be
requested if needed to maintan cost of service coverage.
California
In October 2007, PacifiCorp fied two advice lettrs requesting authority to implement components of the post test-year adjustment
mechanism ("PTAM"), a mechanism that allows for annual rate adjustments for changes in operating costs and plant additions outside
of the context of a trditional rate case. The combined requested increase totaed $2 millon, or an average price increase of 2%. The
Caifornia Public Utilities Commssion (the "CPUC") approved th increase in November 2007. In Decmber 2001, PacifiCorp
revised the increase based on updted capital additions, and the CPUC issued a revised order for a $ i millon increase, or an average
price increase of 1% effective Januar 1,2008.
In August 2007, PacifiCorp filed an energy cost adjustment clause application with the CPUC to update actual and forecasted net
variable power costs, requesting a rate incree of $6 millon, or an average price increase of 8%, with an effective date of Januar i,
2008. In December 2007, the CPUC issued an order for a $5 millon increase, or an average price increase of 7%, with an effective
date of Januar 1,2008.
Depreciation Rate Changes
In August 2007, PacifiCorp filed applications with the regulatory commssions in Uta, Oregon, Wyoming, Washington and Idaho to
change the rates of depreciation and extend the depreciable lives of certn assets, based on a new depreciation study. Agreements
have been reached in each of these states and are in various stages of approval. When approved by the state commssions, the
agreements will make the new depreciation rates effective Januar i, 2008. For further discussion on depreciation rate changes, refer
to Note 2 of the Notes to Financial Statements included in this Form 1.
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/03/2008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
Environmenta Regation
PacifiCorp is subject to federal, state and local laws and regulations with regard to ai and water qualty, RPS, climate change,
hazardous and solid waste disposal and other environmental matters and is subject to zoning and other regulation by local authonties.
In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substatial
penalties for noncompliance including fines, injunctive relief and other sanctions. PacifiCorp believes it is in material compliance
with all laws and regulations. The most significant environmental laws and regulations affecting PacifiCorp include:
· The federal Clea Air Act, as well as state laws and regulations impacting ai emissions, including State Implementation
Plans related to existing and new nationa ambient air qualty standards. Rules issued by the Environmenta Protection
Agency ("EPA") and certin states requie substantial reductions in sulfur dioxide and nitrogen oxide emissions beginning in
2009 and extending though 2018. PacifiCorp has aleady installed certin emission control technology and is tang other
measures to comply with required reductions. Refer to "Clean Air Standards" below for additional discussion regarding ths
topic.
· The federal Water Pollution Control Act ("Clean Water Act") and individual state clean water laws regulate cooling water
intae strctures and discharges of wastewater, including storm water runoff. PacifiCorp believes tht it curently has, or has
initiated the process to receive, all required water quality permts. Refer to "Water Quality Stadards" below for additiona
discussion regarding ths topic.
· The federal Comprehensive Environmental Response, Compensation and Liabilty Act and simlar state laws, whch may
require any curnt or former owners or operators of a disposal site, as well as transporters or generators of hazardous
substaces sent to such disposal site, to share in envionmenta remediation costs. Refer to Note 11 of Notes to Financial
Statements included in this Form 1 for additional informtion regarding environmental contingencies.
· The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational,
reclamation and closur stadards that must be met dunng and upon completion of mining activities.
· The FERC oversees the relicensing of existing hydroelectrc projects and is also responsible for the oversight and issuance of
licenses for new constrction of hydroelectrc projects, dam safety inspetions and environmenta monitonng. Refer to
Note 11 of Notes to Financial Statements included in ths Form 1 for additional information regaring the relicensing of
certn of PacifiCorp' s existing hydroelectrc facilties.
PacifiCorp is subject to federal, state and local laws and regulations with regard to air and water qualty, RPS, climate change,
hazdous and solid waste disposal and other environmenta matters. The cost of complying with applicable environmenta laws,
regulations and rules is expected to be matenal to PacifiCorp. In paricular, futue mandates may impact the operation ofPacifiCorp's
generating facilties and may require PacifiCorp to reduce emissions at its generating facilties though the instalation of additional
emission control equipment or to purchase additional ennssion allowances or offsets in the futue. PacifiCorp is not aware of any
established technology tht reduces the carbon dioxide ennssion at coal-fied facilties and PacifiCorp is uncertn when, or if, such
technology will be commercially available.
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 (2)A Resubmission 04/0312008 2007/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
Expenditures for compliance-related items such as pollution control technologies, replacement generation, mine reclamation,
hydroelectric relicensing, hydroelectrc decommssioning and associate operating costs are generally incorporated into the routine
cost strcture ofPacifiCorp. An inabilty to recover these costs from PacifiCorp's customers, either though regulated rates, long-term
arangements or market prices, could adversely affect PacifiCorp's futue financial results.
Clean Air Standrds
The Clean Air Act provides a framework for protecting and improving the nation's ai quality and controllng mobile and stationar
sources of ai emissions. The major Clean Ai Act program, which most directly affect PacifiCorp's electrc generating facilties, are
briefly described below. Many of these program are implemented and administered by the states, which can impose additional, more
strngent requiements.
In connection with the March 2006 acquisition of PacifiCorp by MEHC, PacifiCorp commtt to state regulators to spend
approximately $812 millon over several years to reduce emissions at PacifiCorp's generating facilities to address existing and future
ai quality requirements. These costs and any additional expenditues necessitate by ai quality regulations are expecte to be
reovered in rates and, as a result, would not have a material adverse impact on PacifiCorp's results of operations. As of December 31,2007, PacifiCorp had incurrd $205 milion in capita expenditures puruant to ths commtment.
National Ambient Air Quality Standards
The EPA implements national ambient ai quality standards for ozone and fine parculate matter, as well as for other criteria pollutants
that set the minimum level of air quality for the United States. Areas that achieve th standards, as determned by ambient ai quality
monitoring, are characterize as being in attnment, while those tht fail to meet the stadards are designated as being nonattnmnt
areas. Generaly, sources of emissions in a nonattnment area ar requied to mae emissions reductions. The counties in Washington,
Oregon, Montaa, Wyoming, Colorado, Uta and Arzona where PacifiCorp's major emission sources ar locate are in attnment of
the current ambient ai quality standas. A new, more strngent stadad for fine parculate mattr became effective on December 18,
200, but is under legal chalenge in the United States Cour of Appes for the Distrct of Columbia Circuit. Ai quaity modeling and
preliminar ai quality monitoring data indicate tht portons of the states in which PacifiCorp has major emission sources may not
meet the new standads. Until thee yeas of data are collec and atnmnt designations under the new fine parculate standard are
made, the impact of these new stadars on PacifiCorp will not be known.
On March 12,2008, the EPA issued a rule to strengten the ambient air quaity standards for ground-level ozone, settng the prima
and secondar 8-hour ozone stadards to 0.075 par per millon. States wil have until June 200 to characterize their attnment
status, with the EPA's determnations regarding non-attnment made by June 2010 and state implementation plans due in 2013. Until
the EPA makes its final determnation on the revised stadards and attnment designations are made, the impact of any new standards
on PacifiCorp will not be known. However, based on the new stadard, the EPA projects that there may be five counties in Uta tht
do not meet new standads for ozone.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
Regulated Air Pollutants
In March 2005, the EPA released the final Clean Air Mercury Rule ("CAMR"), a two-phase program that utilizes a market-based cap
and trade mechanism to reduce mercur emíssions from coal-buring power plants from the 1999 nationwíde level of 48 tons to
15 tons. The CAMR required initial reductions of mercur emíssions in 2010 and an overall reduction in mercury emíssions from
coal-burning power plants of 70% by 2018. The individual states in which PacífiCorp operates facilties regulated under the CAMR
submítted state implementation plans reflecting their regulations relating to state mercury control program. On Februar 8, 2008, the
United States Court of Appeals for the District of Columbia Circuit held that the EPA improperly removed electricity generating units
from Section 112 of the Clean Air Act and, thus, that the CAMR was improperly promulgated under Section 111 of th Clean Ai
Act. The cour vacated the CAMR's new source performance stadards and remanded the mattr to the EPA for reconsideration. On
March 24, 2008, the EPA filed a petition with the United States Cour of Appeals for the Distrct of Columbia Circuit for review en
bane of th Febru 8, 2008 decísion. In light of ths decision, it is not known the extent to which future mercury rules may impact
PacífiCorp's current plans to reduce mercury emíssions at its coal-fid facilties.
Regional Haze
The EPA has initiated a regional haz program intended to improve visibilty at specífic federally protected aras. Some of
PacifiCorp's plants meet the thshold applicabilty criteria under the Clean Ai Visibilty Rules. In accordance wíth the federal
requirements, states were required to submít state implementation plans by Deember 2007 to demonstrate reasonable progress toward
achieving natural visibility conditions in certn Class I areas by requiring emíssion controls, known as best available retrofit
tehnology, on sources with emíssions that are anticípated to cause or contrbute to impairmnt of visibilty. Wyomíng has not yet
submítted its state implementation plan and is continuing to review the results of analyses relating to planned emíssion reductions at
PacífiCorp's Wyomíng generating plants. Uta has not yet submítted its state implementation plan, but expects to do so in the near
term. PacífiCorp believes that its planed emíssion reduction projects wil satisfy the regional haz requirements in Uta an
Wyomíng; however, it is possible that some additional controls may be required once the respective state implementation plans have
been submíttd.
New Source Review
Under existing New Source Review ("NSR") provisions of the Clean Ai Act, any facilty that emíts regulated pollutants is required to
obtain a permt from the EPA or a state regulatory agency prior to (i) beginning constrction of a new major stationar source of an
NSR-regulated pollutant, or (ii) mang a physical or operational change to an existing stationar source of such pollutats that
increases certn levels of emíssions, unless the changes are exempt under the regulations (including routine mantenance, repair and
replacement of equipment). In general, projects subject to NSR regulations are subject to pre-constrction review and permtting
under the Prevention of Significant Deterioration ("PSD") provisions of the Clean Ai Act. Under the PSD program, a project that
emíts theshold levels of regulated pollutants must undergo a "best available control technology" analysis and evaluate the most
effective emíssions controls. These controls must be instaled in order to receive a permt. Violations of NSR regulations, which may
be alleged by the EPA, states and environmenta groups, among others, potentially subject a utility to material expenses for fines and
other sanctions and remedies including requirng installation of enhanced pollution controls and funding supplementa environmenta
projects.
IFERC FORM NO.1 (ED. 12-96) Page 109.18
I FERC 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 04/0312008 2007/04
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
As part of an industr-wide investigation to assess compliance with the NSR and PSD provisions, th EPA has requested from
numerous utilities information and supportng documentation regarding their capital projects for varous generating plants. Between
2001 and 2003, PacifiCorp responded to requests for informtion relating to its capital projects at its generating plants and has been
engaged in periodic discussions with the EPA over several year regaring ths matter. An NSR enforcement case against another
utility has been decided by the United States Supreme Court, holding that an increase in annual emissions of a facilty, when
combined with a modification (i.e., a physical or operational change), may trigger NSR permttng. PacifiCorp cannot predict the
outcome of the EPA's review of the data it has submitted at ths time.
In 2002 and 2003, the EPA proposed varous changes to its NSR rules that clarfy what constitutes routine repair, mantenance and
replacement for puroses of trggering NSR requirements. These chages have been subject to legal chalenge, and in March 200, a
panel of the United States Cour of Appeals for the Distrct of Columbia Circuit invalidated portons of the EPA's new NSR rules,
holding that they conflicted with the wording of the statute. However, the EPA ha asked the United States Supreme Court to review
portons of the case. Unti such time as the legal challenges are resolved and the revised rues are effective, PacifCorp will continue
to manage projects at its generating plants in accordance with the rules in effect prior to 2002, except for pollution-control projects,
which are now subject to permttng under the PSD program. In 2005, the EPA proposed a rule tht would change or clarfy how
emission increases are to be calculate for puroses of determning the applicabilty of the NSR permtting program for existing
power plants. The EPA also proposed additional changes to the NSR rules in September 2006 that are intended to simplify the
permttng process and allow facilties to underte activities tht improve their safety, reliabilty and effciency without trggering
NSR requirements. In April 2007, the EPA issued a supplementa notice of proposed rulemang to determne emissions increases for
electrc generating units, proposing to use both hourly and annua emissions tests to determne whether utilities trgger the NSR
permttng program when an existing power plant maes a physical or operational change. The supplementa proposal was issued
thee weeks afer the United States Supreme Cour issued a unanmous opinion in Environmental Defense v. Duke Energy that the
EPA was correct in applying an annual emissions test to determne NSR compliance.
Renewable Portolio Standards
The RPS described below could significantly impact PacifiCorp's financial results. Resources that meet the qualifyng electrcity
requiements under the RPS var from state-to-state. Each state's RPS requires some form of compliance reportng and PacifiCorp
can be subject to penalties in the event of non-compliance.
In November 2006, Washington voters approved a ballot initiative establishing a RPS reuirement for qualifying electrc utilities,
including PacifiCorp. The requirements are 3% of retal sales by Janua 1,2012 though 2015,9% ofretal sales by Januar 1,2016
though 2019 and 15% of retal sales by Januar 1, 2020. Th WUC has adopted final rules to implement the initiative. PacifiCorp
expects to be able to recover its costs of complying with the RPS, eithr though rate cases or an adjustment mechansm.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) lÇ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
In June 2007, the Oregon Renewable Energy Act (the "Act") was adopted, providing a comprehensive renewable energy policy for
Oregon. Subject to certain exemptions and cost limitations established in the Act, PacifiCorp and other qualifying electric utilities
must meet minimum qualifying electrcity requirements for electrcity sold to retal customers of at least 5% in 2011 though 2014,
15% in 2015 through 2019,20% in 2020 though 2024, and 25% in 2025 and subsequent years. As required by the Act, the OPUC
has approved an automatic adjustment clause to allow an electrc utilty, including PacifiCorp, to recover prudently incurred costs of
its investments in renewable energy facilities and associated transmission costs. The OPUC and the Orgon Deparent of Energy
have underten additional rulemakng proceedings to fuer implement the initiative. PacifiCorp expects to be able to recover its
costs of complying with the RPS though the automatic adjustment mechansm. For furter discussion of the automatic adjustment
mechansm. refer to "State Regulatory Actions - Oregon" above.
Californa law requires electrc utilities to increase their procurement of renewable resources by at least 1 % of their annual retal
electrcity sales per year so that 20% of their annua electricity sales are procured from renewable resources by no later than
December 31, 2010. However, PacifiCorp and other small multi-jurisdictional utilities ("SMJU") are curently awaiting furter
guidance from the CPUC on the treatment of SMJUs in the Caifornia RPS program. PacifiCorp has filed comments requestig SMJU
rues for flexible compliance with annual tagets. PacifiCorp expects rues governng the treatment of SMJUs and any specific flexible
compliance mechanisms to be released by CPUC sta for public review in early 2008. Absent fuer direction from the CPUC on
treatment of SMJUs, PacifiCorp cannot predict the impact of the Californa RPS on its financial results.
In March 2008, Uta Governor Huntsman signed Senate Bil 202 ("SB 202"), the Uta "Energy Resource an Carbon Reduction
Initiative" bil. SB 202 amends existing law to pemnt constrction of wind projects smaller thn 300 megawatts outside the Senate Bil
26 procurement process. It also establishes a target of 20% for PacifiCorp's and other qualifyng utilities adjusted retal electrc sales in
the year 2025 be derived from renewable energy resources, if the renewable resources are detemnned to be "cost effective". Retal
sales will also adjusted by subtracting the non-carbon sources of energy and future carbon sequestration from the tota retal sales. The
20% taget would then apply to the "carbon" component of PacifCorp's portolio. The law also requires: 1) plans and report
concernng progress in acquirng renewable energy and 2) varous state agencies to mae rues concernng carbon capture and
geological storage of captued carbon ellssions.
In addition to its portfolio of generating plants, PacifiCorp purchass electrcity in the wholesale markets to meet its retal load and
long-term wholesae obligations, for system balancing requirements and to enhance the effcient use of its generating capacity over the
long term. All or some of the renewable energy attbutes associated with ths generation may be used in future year to comply with
state or federal renewable portolio stadards. For a complete listing of PacifiCorp's purchased electrcity, refer to pages 326-327 of
ths Form No.1.
Climate Change
As a result of increased attntion to global climate change in the United States, numerous bils have been introduced in th curnt
session of the United States Congress that would reduce greenhous gas emissions in the United States. Congressional leadership has
made climate chage legislation a priority, and many congressional obserers expect to see the passage of climate change legislation
within the next several years. The Lieberman-Warer Climate Securty Act of 2007 (S. 2191) was passed by the United States Senate
Environment and Public Works Commttee on December 5,2007. The bil would impose an economy-wide cap on greenhouse gas
emissions to reduce emissions 70% from 2005 levels by 2050. Included withn the bill's definition of a covered facility is any facilty
that uses more than 5,000 tons of coal in a calendar year, which includes all of PacifiCorp's coal-fired generating plants. In addition,
nongovernmenta organizations have become more active in initiating citizen suits under existing environmenta an other laws. In
April 2007, a United States Supreme Cour decision concluded that the EPA has the authority under the Clean Ai Act to regulate
emissions of greenhouse gases from motor vehicles. Furermore, pending cases that address the potential public nuisance from
greenhouse gas emissions from electricity generators and the EPA's failure to regulate greenhouse gas ellssions from new and
existing coal~fired plants are expected to become active. Whle debate continues at the national level over th direction of domestic
climate policy, several states have developed state-specifc laws or regional legislative initiatives to reduce greenhouse gas emissions,
including:
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) 2S An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/032008 2007/04
IMPORTANT CHANGES DURING THE QUARTERNEAR (Contnued)
· In Februar 2007, the governors of Caifornia. Arzona, New Mexico, Oregon and Washington signed the Western Regional
Climate Action Initiative (th "Western Climate Initiative") that directed their respective states to develop a regional target
for reducing greenhouse gases by August 2007. Uta joined the Western Climate Intiative in May 2007. The states in the
Western Climate Initiative announced a taget ofreducing greenhouse gas emissions by 15% below 2005 levels by 2020,
with Uta establishing its reduction goal by August 2008. By August 2008, they are expected to devise a maket-based
program, such as a load-based cap-and-trade program for the electncity sector, to reach the regional taget. The Western
Climate Initiative paricipants also have agreed to parcipate in a multi-state registr to track and manage greenhouse gas
emissions in the region.
· An executive order signed by Californa's governor in June 2005 would reduce greenhouse gas 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 adopted
legislation tht imposes a greenhouse gas emission pedormance standad to all electncity generated withn the state or
delivered from outside the state that is no higher than the greenhouse gas emission levels of a state-of-the-ar combined-cycle
natual gas generation facilty, as well as legislation that adopts an economy-wide cap on grenhouse gas emissions to 1990
levels by 2020.
· The Washington and Orgon governors enacte legislation in May 2007 and August 2007, respectively, establishing
economy-wide goals for the reduction of greenhouse gas emissions in their respective states. Washington's goals seek to
(i) by 2020, reduce emissions to 1990 levels; (ii) by 2035, reduce emissions to 25% below 1990 levels; and (ii) by 2050,
reduce emissions to 50% below 1990 levels, or 70% below Washington's forecasted emissions in 2050. Oregon's goals seek
to (i) by 2010, cease the growt of Oregon greenhouse gas emissions; (ii) by 2020, reduce greenhouse gas levels to 10%
below 1990 levels; and (üi) by 2050, reduce greenhouse gas levels to at leat 75% below 1990 levels. Each state's legislation
also calls for state governent-developed policy recommendations in the futue to assist in the monitoring and achievement
of these goals. The impact of the enacted legislation on PacifiCorp canot be determned at ths tie.
PacifiCorp continues to add renewable electnc capacity to its generation portolio. In addition, PacifiCorp has engaged in volunta
program designed to either reuce or avoid greenhouse gas emissions, including the EPA's sulfu hexafuoride reduction program and
refrgerator recycling program. PacifiCorp is a member of the Calforna Climate Action Registr and The Climate Registr, under
which it report and certfies its greenhouse gas emissions.
The impact of any pending judicial proceedings and any pending or enacte federal and state climate change legislation and regulation
cannot be determned at ths tie; however, adoption of stnngent limits on greenhouse gas emissions could significantly impact
PacifiCorp's curent and.futue fossil-fueled facilties, and, therefore, its financial results.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 0410312008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
Water Quality Standards
The Clean Water Act establishes the framework for maintaining and improving water quality in the United States through a program
that regulates, among other thngs, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water
intake strctures reflect th "best technology available for minimizing adverse environmental impact" to aquatic organisms. In
July 200, the EPA established significant new national technology-based performance standards for existing electrc generating
facilties that take in more than 50 millon gallons of water a day. These rules are aimed at minimizing the adverse environmental
impacts of cooling water intae strctures by reducing the number of aquatic organisms lost as a result of water withdrawals. In
response to a legal challenge to the rule, in Januar 2007, the Second Circuit Cour of Appeals remanded almost all aspects of the rule
to the EPA, leaving companies with cooling water intake strctues uncertn regarding compliance with these requiments. Petitions
for certoran are pending before the United States Supreme Court regarding the Second Circuit's decision. Compliance and the
potential costs of compliance therefore cannot be ascertned until such time as furter action is taken by the EPA. Curently,
PacifiCorp's Dave Johnston plant exceeds the 50 millon gallons of water per day in-tae theshold. In the event tht PacifiCorp's
existing intae strctures require modification or alternative technology is required by new rules, expenditures to comply with these
requirements could be significant.
Integrate Resurce Plans
As required by certn state regulations, PacifiCorp uses an Integrated Resource Plan ("IR") to develop a long~term view of prudent
futue actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electrc service to its customers.
The IRP process identifies the amount and timing of PacifiCorp's expected future resource needs and an associated optimal future
resource mix that accounts for planning uncertinty, risks, reliabilty impacts and othr factors. The IRP is a coordinated effort with
staeholders in each of the six states where PacifiCorp operates. When the IR is fùed, each state commssion with IR adequacy
rules judges whether the IR reasonably meets its standards and guidelines. PacifiCorp requests "acknowledgement" of its IRP fùing
from the UPSC, the OPUC, the IPUC and the WUC puruant to those states' IR adequacy rules. The IR can be used as evidence
by pares in rate-mang or other regulatory proceedings. PacifiCorp files its IRP on a biennial basis.
In May 2007, PacifiCorp released its 2007 IRP. The 2007 IRP identified a need for approximately 3,171 MW of additional resources
by summer 2016 to satisfy the difference between projected retal load obligations and available resources. PacifiCorp plans to meet
ths nee though demand response and energy effciency programs; the constrction or purchae of additional generation, including
cost-effective renewable energy, combined heat and power, and thermal generation; and wholesale electricity transactions to make up
for the remaning difference between retal load obligations and available resources. PacifiCorp is curently seeking acknowledgement
of its 2007 IR from state regulators and expects the acknowledgement process to be complete in 2008.
Requests for Proposa
PacifiCorp has issued a series of separate requests for proposal ("RF"), each of which focuses on a specific category of resources as
provided in the IRP. The IR and the RF provide for the identification and staged procurement of resources in future year to
achieve load/resource balance. As required by applicable laws and regulations, PacifiCorp files draf RF with the UPSC, the OPUC
and the WUC prior to issuance to the maket.
IFERC FORM NO.1 (ED. 12-96) Page 109.22
IFERC FORM NO.1 (ED. 12-96) Page 109.23
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Onginal (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
In Februar 2007, PacifiCorp fied a modified 2012 RF in Uta for up to 1,700 MW of additional resources to become available
beginning in 2012 though 2014. The RF was approved by the UPSC and issued to the maket in April 2007. In June 2007,
proposals from qualifying bidders were received by commssion-directed independent evaluators. These bids included various
strctures, ranging from purchase or lease of coal, natual gas, and geothermal power plants to power purchase agreements.
PacifiCorp initiated negotiations with short-listed bidders in Janua 2008.
In Januar 2008, PacifiCorp issued to the maket a 2008 renewable RF for less than 100 MW, or greater than 100 MW for power
purchae agreements with a term ofless than five yea, to become available prior to Deembe 2009.
In Februar 2008, PacifiCorp filed an all source 2008 RF with the UPSC, the OPUC and th WUC for base load, intermediate or
thd quarr sumer peakng products delivered into PacifiCorp's system. Theall source 2008 RF seeks up to 2,00 MW of
resources to become available beginning in 2012 though 2016.
In addition to new generation resources, substatial transmission investments are expecte to be required to deliver energy to
PacifiCorp's growing customer base and to enhance system reliabilty. The actu investment requirement wil depend on the location
and other characteristics of the new generation resources.
ITEM 13.
Otcer & Director Changes
On March 12, 2007, PacifiCorp's Senior Vice President, Staley K. Watters, resigned as a dictor and offcer, effective March 16,
2007.
On May 31, 2007, PacifiCorp's Senior Vice President and General Counsel, Mark C. Moench, was elected to the additional offce of
PacifiCorp Secreta.
On July 25, 2007, Nolan E. Kaas resigned as a director ofPacifiCor, effective imediately.
On August 30,2007, Wiliam J. Fehr resigned as Prsident of PacifiCorp Energy, a division of PacifiCorp, and as a director of
PacifiCorp and A. Robert Lasich was elected President of PacifiCorp Energy. Mr. Laich was serving as Vice President and General
Counsel of PacifiCorp Energy and continues to serve as a director of PacifiCorp.
On Augut 30, 2007, Nataie L. HockeD, Vice President and General Counsel of Pacific Power, and David J. Mendez, Senior Vice
President and Chief Financial Offcer, were electe dictors ofPacifiCorp.
On Febru 8, 2008, PacifiCorp's Senior Vice Prsident and Chief Financial Ofcer, David J; Mendez, resigned as a diector and
offcer, effective Februar 29, 2008.
On Febru 19,2008, Douglas K. Stuver was appointed Senior Vice President and Chief Financial Offcer, effective March 1,2008.
Mr. Stuver was serving as Managing Director and Division Controller ofPacifiCorp Energy.
ITEM 14.
None.
............................................
Deloitte~Deloitte 8. Touche LLP
Suite 3900
111 SW Fifth Avenue
Portland, OR 972Q43642
USA
Tel: [phone]
Fax: [phone]
ww.deloitte.com
INDEPENDENT AUDITORS' REPORT
PacifiCoip
Portland, Oregon
We have audited the balance sheet - regulatory basis of PacifiCoip (the "Company") as of December 31,
2007, and the related statements of income - reguatory basis; retained eargs - reguatory basis; cash
flows - reguatory basis, and accumulated comprehensive income, comprehensive income, and hedgig
activities - regulatory basis for the year ended December 31, 2007, included on pages 110 through 123
of the accompanying Federal Energy Regulatory Commssion Form 1. These financial statements are the
responsibilty of the Company's management. Our responsibility is to express an opinion on these
fmancial statements based on our audit.
We conducted our audit in accordance with auditing standads generally accepted in the United States of
America. Those standards require that we plan and pedorm the audit to obtain reasonable assurance a.bout
whether the financial statements are free of material misstatement. An audit includes consideration of
internal control over fmancial reporting as a basis for designing audit procedures that are appropriate in
the circumstances, but not for the purose of expressing an opinon on the effectiveness of the Company's
internal control over fmancial reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our audit provides a reasonable
basis for our opinion.
As discussed in Note 2, these financial statements were prepared in accordance with the accounting
requirements of the Federa Energy Regulatory Commssion as set forth in its applicable Uniform System
of Accounts and published accounting releases, which is a comprehensive basis of accounting other than
accounting principles generally accepted in the United States of America.
In our opinion, such regulatory-basis financial statements present fairly, in all material respects, the
assets, liabilties, and proprietary capital of PacifiCorp as of December 31, 2007, and the results of its
operations and its cash flows for the year ended December 31, 2007, in accordance with the accounting
requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System
of Accounts and published accounting releases.
This report is intended solely for the inormation and use of the board of directors and management of
PacifiCoip and for filing with the Federal Energy Regulatory Commission and is not intended to be and
should not be used by anyone other than these specified parties.
~.T~ C-L.('
Februar 27,2008
Member of
Deloitt Touche Tohmatu
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 04103120 End of 2007/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line Current Year Prior Year
Ref.End of OuarterlYear End BalanceNo.Title of Account Page No. Balance 12/31
(a)(b)(c)(d)
1 UTILIT PLANT
2 Utilty Plant(101-106, 114)200-201 16,637,482,51C 15,526,911,439
3 Construction Work in Proress (107)200-201 941,818,n6 734,457,063
4 TOTAL Utilty Plant (Enter Total of lines 2 and 3)17,579,301,286 16,261,368,502
5 (Less) Accum. Provo for Depr. Amort. Depl. (108,110,111,115)200-201 6,691,765,903 6,40,699,46
6 Net Utilty Plant (Enter Total of line 4 les 5)10,887,535,383 9,852,669,038
7 Nucar Fuel in Proess of Ref., Cov.,Enri., and Fab. (120.1)202-203 C °
8 Nuclear Fuel Matenals an Assemblie-Stoc Accnt (120.2)(J °
9 Nucler Fuel Assemblie in Reactor (120.3)C °
10 Spent Nuclear Fuel (120.4)°°
11 Nucear Fuel Undr Caital Leses (120.6)°°
12 (Less) Accum. Provo for Amort. of Nucl. Fuel Assemblies (120.5)202-203 C °
13 Net Nuclear Fuel (Enter Total of lines 7-11 less 12)C °
14 Net Utilit Plant (Enter Totl of line 6 and 13)10,887,535,383 9,852,669,038
15 Utilit Plant Adjustments (116)122 C °
16 Gas Stored Underground - Noncurrent (117) C °
17 OTHER PROPERTY AND INVESENT
18 Nonutilty Propert (121)9,43,375 8,945,604
19 (Less) Accum. Provo for Depr. and Amor. (122)1,396,06 1,231,40
20 Investments in Associated Copanies (123)7,637,258 7,695,513
21 Investment in Subsidiary Companies (123.1)224-225 149,005,037 113,111,986
22 (For Cost of Account 123.1 , See Footnote Page 224, line 42)
23 Noncurrent Porton of Allowances 228-229 C °
24 Other Investments (124)87,106,834 93,958,194
25 Sinking Funds (125)(J °
26 Depreciation Fund (126)C °
27 Amortization Fund - Fedra (127)°°
28 Oter Special Funds (128)9,53O,01S 7,847,422
29 Special Funds (Non Major Only) (129)(J °
30 Long-Term Portion of Denvative Asets (175)215,055,123 234,925,374
31 Long-Term Portion of Denvative Asts - Hedges (176)(J °
32 TOTAL Other Propert an Investment (Lines 18-21 and 23-31)476,374,579 46,252,693
33 CURRENT AND ACCRUED ASETS
34 Cash and Working Fund (Non-major Only) (130)(J °
35 Cash (131)10,512,273 9,559,447
36 Speial Deposits (132-134)6,256,766 13,969,784
37 Working Fund (135)2,670 2,920
38 Temporary Cash Investments (136)182,317,755 14,54,66
39 Notes Recivable (141)616,766 893,754
40 Customer Accounts Receivable (142)373,257,825 324,627,813
41 Other Accounts Receivable (143)15,687,039 22,216,920
42 (Less) Accum. Proo for Uncollecible Acct.-Credit (144)6,551,765 11,879,64
43 Notes Receivable from Associaed Compaies (145)25,975,11~22,866,308
44 Acounts Receivable from Assoc. Copanies (146)12,144,71~9,933,523
45 Fuel Stock (151)227 98,33,182 82,230,862
46 Fuel Stock Expenses Undistnbuted (152)227 C °
47 Residuals (Elec) and Extracted Proucts (153)227 C °
48 Plant Matenals and Operating Supplies (154)227 150,050,022 129,731,866
49 Merchandise (155)227 C 0
50 Oter Matenals and SUppies (156)227 0 °
51 Nuclear Materials Held for Sale (157)202-2031227 0 0
52 Allowances (158.1 and 158.2)228-229 C °
FERC FORM NO.1 (REV. 12-Q3) Page 110
............................................
............................................
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifCorp (1 )ix An Original (Mo, Da, Yr)
(2)0 A Resubmission 04/03/200 End of 2007/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITStntinued)
Line Current Year PnorYear
No.Ref.End of OuarterlYear End Balance
Title of Account Page No.Balance 12/1
(a)(b)(c)(d)
53 (Less) Noncurrent Portion of Allowances 0 0
54 Stores Expense Undistributed (163)227 0 0
55 Gas Stored Undergrond - Current (164.1)0 0
56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)0 0
57 Prepayments (165)
58 Advances for Gas (166167)iJ 0
59 Interest and Dividends Receivable (171)13,245,222 112,488
60 Rents Receivable (172)3,189,547 1,266,047
61 Acrued Utilty Revenues (173)192,29,00 1n,642,OO
62 Miscellaneous Current and Accrued Asets (174)11,238,6~0
63 Derivative Instrument Assets (175)357,980,420 381,369,990
64 (Less) Long-Term Portion of Denvative Instrument Assets (175)215,055,12::234,925,374
65 Derivative Instrument Assets - Hedges (176)C 4,48,761
66 (Less) Long-Term Portion of Denvative Instrument Assets - Hedges (176 0 0
67 Total Current and Accrued Assets (Lines 34 through 66)1,311,185,598 1,032,986,086
68 DEFERRED DEBIT
69 Unamortized Deb Expnses (181)27,166,06 23,745,172
70 Exraordinary Propert Losses (182.1)230 0 0
71 Unrecovered Plant and Regulatory Study Cots (182.2)230 15,589,069 6,839,022
72 Other Regulatory Asets (182.3)232 1,081,739,789 1,395,66,386
73 Prelim. Survey and Investigation Charges (Electn) (183)0 3,727,385
74 Preliminary Natural Gas Survey and Investigation Charges 183.1)0 0
75 Other Preliminary Survey and Investigation Charges (183.2)C 0
76 Cleanng Acounts (184)C 0nTemporary Facilities (185)115,30 36,534
78 Miscellaneous Deferred Debits (186)233 52,116,892 57,976,248
79 Def. Losses from Dispoition of Utlity PIt. (187)0 0
80 Research, Devel. and Demonstration Exped. (188)352-353 0 0
81 Unamortized Loss on Reaquired Debt (189)20,786,394 25,438,109
82 Accumulated Deferred Income Taxes (190)234 819,687,478
83 Unrecovered Purchased Gas Cots (191)0 0
84 Total Deferred Debits (lines 69 through 83)1,629,842,070 2,33,110,33
85 TOTAL ASSETS (lines 14-16, 32, 67. and 84)14,30,937,63 13,68,018,151
FERC FORM NO.1 (REV. 12..3) Page 111
IFERC FORM NO.1 (ED. 12-87) Page 450.1
......i..i....................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2. An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
FOOTNOTE DATA
¡Schedule Page: 110 Line No.: 57 Column:
At December 31, 2007, account 165 Prepayments included $22.2 millon in income taes receivable due from PPW Holdings LLC,
PacifiCorp's direct parent company.
¡Schedule Page: 110 Line No.: 57 Column:
At December 31, 2006, account 165 Prepayments included $43.5 millon in income taes receivable due from PPW Holdings LLC,
PacifiCo's direct arent com any.
chedule Pa e: 110 Line No.: 82 Column:
Deferred ta assets of $268 millon related to accrued removal costs were netted against deferred ta .liabiltieson propert, plant and
equipment in account 282 at December 3 i, 2007. At December 31, 200, deferred ta assets of $265 millon related to accrued
removal costs were included in account 190.
.............................................
Blank Page
(Next Page is 112)
Name of Respondent This Report is:Date of Report Year/Period of Report
PacifiCorp (1 )Ii An Original (rna, da, yr)
(2)0 A Rresubmission 0403008 end of 2007/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prir Year
No.Ret.End of QuarterlYear End Balance
Title of Accunt Page No. Balance 12/31
(a)(b)(c)(d)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201)250-251 3,417,945,896 3,417,94,896
3 Preferred Stock Issued (20)250-251 41,463,30C 41,463,300
4 Capital Stock Subscribed (202, 205)252 °°
5 Stock Liabilty for Conversion (203, 206)252 °°
6 Premium on Capital Stock (207)252 0 °
7 Other Paid-In capitl (208-211)253 427,063,95€223,285,229
8 Installments Received on Capitl Stoc (212)252 °0
9 (Less) Discount on Cata Stock (213)254 °°
10 (Less) Capita Stock Exns (214)254 41,288,201 41,288,207
11 Retained Eamings (215, 215.1, 216)118-119 1,231,878,76E 783,464,736
12 Unappropriated Undistributed Subsidiary Eamings (216.1)118-119 7,557,54 5,841,394
13 (les) Reaquired capital Stoc (217)250251 °°
14 Noncorprate Proprietorship (Non-major only) (218)°°
15 Accumulated Other Comprehensive Income (219)122(a)(b)-3,516,38 -3,882,135
16 Total Proprietary Capitl (lines 2 through 15)5,081,104,871 4,426,83,213
17 LONG-TERM DEBT
18 Bonds (221)256-257 5,123.205,OO 4,048,872,00
19 (Less) Reauire Bonds (222)256-257 °°
20 Advances from Asocated Companies (223)256-257 C 0
21 Other Long-Term Debt (224)256-257 0 37,500,00
22 Unamortized Premium on Long-Term Debt (225)40,999 43,717
23 (Less) Unamorted Disunt on Long-Term Debt-Debit (22)6,014,592 5,85,708
24 Total Log-Term Debt (lines 18 throgh 23)5,117,231,407 4,080,562,00
25 OTHER NONCURRENT LIABILITIES
26 Obligatios Under Capitl Leaes - Noncurrent (227)47,949,27€49,399,03
27 Accumulated Provision for Property Insurance (228.1)0 1,418,669
28 Accmulated Provision for Injuries and Damages (228.2)6,054,192 3,289,637
29 Accumulated Provision for Pensions and Benefits (228.3)315,188,411 690,86,211
30 Accumulated Miscellaneous Operating Provisions (228.4)38,105,69E 47,586,470
31 Accumulated Provision for Rate Refunds (229)(0
32 Long-Term Portion of Derivative Instrument Liabilties 496,923,54 50,511,387
33 Long-Term Porton of Deriative Instrument Liilties - Hedges (°
34 Aset Retirement Obligations (230)75,241,93 85,797,248
35 Total Other Noncurrent Liilities (lines 26 through 34)979,46,051 1,382,871,652
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payale (231)0 399,000,00
38 Accunts Payable (232)449,488,562 396,650,693
39 Notes Payable to Associated Companies (233)0 °
40 Acconts Payable to Associated Companies (234)11,007,5OB 9,548,784
41 Customer Deposits (235)21,68,n1 23,526,476
42 Taxes Accrued (236)262-263 20,901,699 21,123,323
43 Interest Accrued (237)86,897,114 56,736,30
44 Dividend Declared (238)520,947 520,947
45 Matured Long-Term Debt (239)C °
FERC FORM NO. 1 (rev. 12..)Page 112
............................................
.............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
PacifiCorp (1 )IX An Original (rna, da, yr)
(2)0 A Rresubmission 04/032008 end of 2oo7/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDllSi)itinued)
Line Current Year Prior Year
No.Ref.End of QuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
46 Matured Interest (240)0 0
47 Tax Collecions Payable (241)13,034,927 13,982,472
48 Miscellaneous Current and Accrued Liabilities (242)76,018,36 84,647,611
49 Obligations Under Capital Leases-Current (243)1,428,748 1,233,704
50 Deriative Instrument Liabilities (244)613,992,765 612,857,273
51 (Less) Long-Term Portion of Derivative Instrument Liablities 496,923,54 504,511,387
52 Derivative Instrument Liabilities - Hedges (245)0 1,186,351
53 (Less) Long-Term Portion of Derivative Instrument Libilities-Hedges 0 0
54 Total Current and Accrued Liabilities (lines 37 through 53)798,053,867 1,116,502,553
55 DEFERRED CREDITS
56 Customer Advances for Constrction (252)17,485,789 10,34,762
57 Accumulated Deferred Investment Tax Credits (255)266-267 53,767,82C 61,687,94
58 Deferred Gains from Disposition of Utilty Plant (256)è 0
59 Other Deferred Credits (253)269 59,527,962 61,791,513
60 Other Regulatory Libilties (254)278 71,343,43 109,982,910
61 Unamortized Gain on Reaquired Debt (257)0 56,166
62 Acum. Deferred Incoe Taxes-Acce!. Amrt.(281)272-277 0 30,173
63 Acum. Deferred Incme Taxes-Other Propert (282)2,00,573,266
64 Accum. Deferred Income Taxes-Oher (283)294,069,371 427,515,99
65 Total Deferred Credits (lines 56 through 64)2,329,08,434 2,677,251,724
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)14,30,937,63C 13,684,018,151
FERC FORM NO.1 (rev. 12..3)Page 113
IFEFlCFORM 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 04/0312008 2007/Q4
FOOTNOTE DATA
'¡chedule Page: 112 Line No.: 63 Column:
Deferred ta assets of $268 millon related to accrued removal costs were netted against deferred ta liabilties on property, plant and
equipment in account 282 at December 31, 2007. At December 31, 2006, deferred tax assets of $265 millon related to accrued
removal costs were included in account 190.
............................................
Blank Page
(Next Page is 114)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) riA Resubmission 04/02008
STATEMENT OF INCOME
Quarterly
1. Enter in column (d) the bace for the reporting quarter and in column (e) the balance for the same three month period for the prior year.
2. Report in column (f) the quarter to date amounts for elecric utilit function; in coumn (h) the quarter to date amount for ga utilit, and in ü) the
quarter to date amounts for other utility function for the current year quarter.
3. Report in column (g) the quarter to date amounts for electric utlit function; in column (i) the quarter to date amounts for gas utilit, and in (k) the
quarter to date amounts for other utilit function for the prior year quarter.
4. If additional columns are neeed place them in a footnote.
Annual or Quarterly if applicble
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utilit Plant Leased to Others, in another utiity columnin a similar manner to
a utilty department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utilit Operating Incoe, in the same manner as accounts 412 and 413 above.
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.
.
Une Tot Totl Currnt 3 Mos Prior 3 Mos
No.Currt Year to Prir Year to End End
(Ref.)Date Bala for Date Baance for Qurterlyony Quarterly Only
Title of Acunt PagaNo.QuarterNear QurterNear No 4th Quartr No 4th Quarter
(a)(b)(c) (d) (e) (f)
1 UTILITY OPERATING INCOE
2 Opraing Revenues (40)30301 ~3 Operang Expense
4 Opration Expese (401)320323 2,407,88,415 2,105,021,26
5 Maintenance Expens (402)320-323
:
Ii
352,40,62
6 Deprecation Expense (40)33337 39,945,206
7 Deprection Exns for Ast Retirement Co (403.1)33337
8 Amor. & Depl. of Utlit Plant (40-405)33337 45,276,103 47,633,759
9 Amort. of Utilit Plant Ac. Adj. (40)33 5,479,353 5,479,353
10 Amort. Prort Lo, Unre Pl and Reglator Stdy Co (407)2,4556 1,674,863
11 Amort. of Coverson Ex (407)
12 Regulatory Debits (407.3)10,429,071 7,69,523
13 (Less) Regulatory Creit (407.4)
14 Taxes Oter Than Ince Taxes (408.1)262-263 101,03,471
15 Income Taxes - Federal (409.1)262.263 125,610,768 106,ns,946
16 . Other (409.1)262.263 15,623,54 9,09,310
17 Provision for Deerrd Income Taxes (410.1)234, 272.277 425,06,057 813,769,788
18 (Les) Provision for Defer Incoe Taxes-Cr. (411.)23, 272.27 36,44,712 753,579,201
19 Invesment Tax Cr Adj. . Net (411.4)266 -5,854,86 -5,85,86
20 (Les) Gains fr Disp. of Utlit Plant (411.6)
21 Losse from Disp. of UtHit Plant (411.7)
22 (Les) Gains fro Dispoon of Alowance (411.8)14,66,498 15,619,25
23 Los fro DiSPDsion of Allowance (411.9)
24 Accretion Exse (411. 0)
25 TOTAL Utlit Oprating Exns (Enter Totl of lines 4 thru 24)3,548,83,222 3,166,477,798
26 Net Util Opr Inc (Enter Tot line 2 less 25) Carr to Pg117,Iine 27 694,791,749 580,803,409
FERC FORM NO. 1/3-Q (REV. 02-()Page 114
............................................
............................................
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/03/2008
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for importnt notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists sUCh that refunds of a material amount may need to be
made to the utilty's customers or which may result in material refund to the utilty with respet to power or gas purchases. State for each year efected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utilit to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning signifcant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expnse accounts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only thoe changes in acnting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar efect of such changes.
14. Explain in a footnote if the previous year's/quarter's figures are diferent from that reported in prior reports.
15. If the columns are insufcient for reprting additional utilty departments, supply the appropriate accunt titles report the information in a footnote to
this schedule.
Year/Period of Report
End of 20071Q4
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) (j)
Line
No.
2,407,885,415
378,009,826
418,496,84
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
2,105,021 ,264
352,406,626
390,945,206
45,276,103
5,479,353
2,452,562
47,63,759
5,479,353
1,674,86
10,429,071 7,696,523
101,472,747
125,610,768
15,623,546
425,06,057
36,448,712
-5,854,86
101,034,471
106,778,94
9,09,310
813,769,788
753,579,201
-5,85,86
14,663,498 15,619,250
3,548,834,222
694,791,749
3,166,477,798
580,803,409
FERC FORM NO.1 (ED. 12-9)Page 115
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04/03
STA EMENT OF INCOME FOR THE YEAR (continued)
Line TOTAL Current 3 Months Pnor 3 Moths
No.Ended Ende
(Ref.)Quarterly Only Quarterly Only
Title of Account Page No.Current Year Previous Year No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(f)
27 Net Utilit Operating Incoe (Carr forwrd fr page 114)694,791,749 58,803,409
28 Other Income and Deuctons
29 Other Incoe
30 Nonutlt Oprating Income
31 Reenues From Merchndising, Jobina and Cotract Work (415)2,760,357 3,443,913
32 (Les) Cots and Ex. of Merchandising, Job. & Cotract Work (416)2,946,861 3,554,683
33 Revenues From Nonutilit Opions (417)239,021 156,069
34 (Les) Expese of NDnutili Operations (417.1)25,945 23,117
35 Nonoprating Rental Income (418)63.65 60,059
36 Equit in Eaming of Subsdiary Copanie (418.1)119 1,716,150 -1,831,832
37 Intere and Dividend Incoe (419)13,913,812 7,426,781
38 Allowance for Otr Funds Used During Coructon (419.1)40,90,06 23,612,825
39 Misclaneous Nonoperang Inco (421)164,00,754 48,231,577
40 Gain Dn Dipoion of Pro (421.1)89,266 162,550
41 TOTAL Oter Income (Enter Total of lines 31 thru 40)221,522,26 509,68,142
42 Ot Inco Deions
43 Los on Dispiton of Propert (421.2)4,210,041 342,567
44 Miscellaneous Amrtzation (425)34 1,118,623 1,099,117
45 Donatons (426.1)34 2,86,061 2,144,714
46 Life Insurance (426.2)-4,961,276 -7,657,632
47 Penales (426.3)4,184,04 10,058,546
48 Exp. for Certain Civi, Politicl & Reated Activities (426.4)1,147,711 1,163,251
49 Otr Deducons (426.5)161,982,725 530,547,357
50 TOTAL Oter Income Dedcton (Totl of lines 43 thru 49)170,54,931 53,697,92
51 Taxes Aplic. to Oter Incoe and Deucion
52 Taxes Other Thn Income Taxes (40.2)26-26 223,65 497,588
53 Inco Taxes-Federa (409.2)262.263 18,941,072 24,842,659
54 Incoe Taxes-Oter (409.2)262-263 2,573,77 3,371,372
55 Provision for Deerred Inc. Taxes (410.2)234, 272-277 58,876,813 95,532,620
56 (Less) Provision for Deferr Incoe Taxes-er. (411.2)234, 272-277 59,117,957 134.566,999
57 Invesment Tax Credit Adj.-Net (411.5)
58 (Les) Investment Tax Creit (420)2,06.26 2,065,26
59 TOTAL Taxes on Other Incme and Deucon (TDtal of Hnes 52-58)19,43,105 -12,388,02
60 Net Otr Incoe and Deucions (Total of Hnes 41, 50, 59)31,545,232 -15,625,758
61 Interes Charg
62 Interest Dn Long.Teno Debt (427)278,731,910 245,313,780
63 Amo. of Debt Dic. and Expese (428)3,012,770 3,779,288
64 Amortization of Los on Reaquire Det (428.1)4,651,715 4,847,826
65 (Les) AmDrt. of Preium on Debt-Cr (429)2,718 2,718
66 (Les) Amortzati of Gain on Reaquire De-ere (429.1)56,166 84,249
67 Intere on Debt to As Companie (43)34 25,95
68 Other Interest Exens (431)340 29,764,58 26,043,69
69 (Les) Allowanc for Borrwed Funds Usd During Coruction-Cr. (43)28,65,98 22,68,215
70 Net Interest Chargs (Total of Hnes 62 thru 69)287,448,114 257,243,36
71 Income Before Exrardinary Items (Tot of lines 27, 60 and 70)438,888,867 307,934,288
72 ExDrdnary Items
73 Exraorinry Incoe (434)
74 (Less) Extraordnary Deio (435)
75 Net Exraornary Items (Total of line 73 less line 74)
76 Incoe TaxesFedral and Other (40.3)262-26
77 ExraDrdinary Item After Taxes (line 75 les line 76)
78 Net Incom (Total of line 71 and 77)438,88,867 30,934,288
FERC FORM NO. 113-0 (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 04/03/2008 20071Q4
FOOTNOTE DATA
¡Schedule Page: 114 Line No.: 6 Column: c
Vehicle depreciation is charged to functional accounts. The following table summarizes the vehicle depreciation expense that was
charged to the functional accounts.
Twelve Months Ending
December 31,2007 2006
Vehicle Depreciation $ 12,494,116 $ 12,268,419
asset or liabil .
Twelve Month Ending
December 31,2007 200
Payroll Tax Expense $ 35,600,794 $ 36,613,788
!schedule Page: 114 Line No.: 24 Column: c
PacifiCorp records the accretion expense of asset retirement obligations as eithr a regulatory asset or liabilty.
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report(1) ~An Onginal (Mo, Da, Yr)
(2) A Resubmission 04031200
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings accunt in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpse and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Eamings, reflecting adjustments to the opening balanc 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.
Year/Period of Report
End of 2007/04
Une ItemNo. (a)
UNAPPROPRIATED RETAINED EARNINGS (Accnt 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retaned Earnings (Account 439)
4 FIN 48 Adoption
5
6
7
8
9 TOTAL Creits to Retane Eamings (Acc. 439)
10
11
12
13
14
15 TOTAL Debits to Retaned Eamings (Acc!. 439)
16 Balance Transferred from Incme (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Ac. 43)
18
19
20
21
22 TOTAL Approriations of Retained Earnngs (Acc. 43)
23 Dividnds DeclaredPreferred Stock (Account 437)
24 Preferred Stock - Various series and rates
25
26
27
28
29 TOTAL Divideds Deared-Preferred Stock (Ac. 437)
30 Dividend Declared-Common Stock (Account 43)
31 Common stock
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Ace!. 438)
37 Transfers from Acct 216.1, Unarop. Undistrib. Subsidiary Eamings
38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
39
Current
OuarterlYear
Year to Date
Balane
(c)
Previous
OuarterlYea
Year to Date
Balance
13,325,103
437,172,717 30,766,120
238 -2,083,790 2,08,79)
238
16,n3,669)
1 ,228,302,955 n9,8B8,925
FERC FORM NO. 113.Q (REV. 02-()Page 118
............................................
............................................
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 040312008
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effec 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.
Year/Period of Report
End of 2007/Q4
Une
No.
40
41
42
43
44
45 TOTAL Aproprited Retained Earning (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acc. 215.1)
47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Accunt
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debi or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52
53 Balance-End of Year (Total lines 49 thru 52)
Cotra Primary
ccunt Afeced
(b)
Current
QuarterlYea
Year to Date
Balance
(c)
Prevous
QuaerlYear
Year to Date
Balance
(d)
Item
(a)
5,841,394
1,716,150
7,673,226
1,831,832)
7,557,54 5,841,394
FERC FORM NO. 113-Q (REV. 02.04)Page 119
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 0403/2008 2007/Q4
FOOTNOTE DATA
¡Schedule Page: 118 Line No.: 4 Column: c
For a discussion regarding PacifiCorp's adoption ofFASB Interpretation No. 48, "Accounting for Uncertnty in Income Taxes-an
interpretation ofFASB Statement No. 109" ("FI 48") refer to Note 2 of Notes to Financial Statements included in ths Form 1.
............................................
Blank Page
(Next Page is 120)
Name of Respondent
PacifiCorp
This~rtls:
(1) ~AnOriginal
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)042008
Year/Period of Report
End of 2007/04
(1) Codes to be used:(a) Net Proceeds or Payments;(b)BDnds, debentures and Dther long-term debt; (c) Include commercial paper; and (d) Identify seprately such itms as
investments, fixed assets, intangibles. etc.
(2) Information about noncash investing and financing actvities must be provided in the Notes to the Financial statement. Also provide a reconcillatiDn betwen 'Cash and
Cash Equivalents at End of PeriDd with related amonts Dn the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertining tD operating acts only. Gains and losses pertining to investing and financing activities should be
repDrted in those activities. Show in the NDtes to the Financlals the amounts of interest paid (net of amount caitlized) and incme taes paid.
(4) Investing Actiities: Include at Other (line 31) net cash outfow to acquire othr companies. Prode a recncilation of assets acquired wit liabilties assumed in the
Notes to the Financial Statements. Do nDt include Dn this statement the dollar amount Df leass caitlize per the USofA General Insruction 20; instead provide a
reconciliation of the dDllar amount of leases capitlized wit the plant cot.
Une
No.
Description (See Instruction NO.1 for Exlanation of Cod)Current Year to Date
OuarterlYear
(b)
Previous Year to Date
OuaerlYear
(c)(a)
1 Net Cash Flow from Operating Activties:
2 Net Income (Une 78(c) on page 117)
3 Nonch Charges (Credits) to Income:
4 Depreciation and Depletio
5
6
7 Unrealize (Gains)/Losses on Deriative Contracts
8 Deferred Income Taxes (Net)
9 Investment Tax Credit Adjustment (Net)
10 Net (Increase) Decrea in Recivabes
11 Net (Increase) Decrease in Inventor
12 Net (Increase) Decreas in Allowan Invenory
13 Net Increae (Decrease) in Payables and Acrued Exnses
14 Net (Increae) Decreae in Other Regulatory Assets
15 Net Increase (Decrease) in Other Regulatory Uabiliies
16 (Less) Allowance for Other Funds Used During Construction
17 (Less) Undistributed Earnings from Subsidiary Companies
18 Amounts Due to/Fro Afliates, Net
19
20
21
22 Net Cash Providd by (Used in) Operating Activities (Totl 2 thru 21)
23
24 Cah Flows from Investment Acvitie:
25 Contru an Acquisiton of Plant (including land):
26 Gros Additions to Utilit Plant (less nuclear fuel)
27 Gross Addions to Nuclear Fuel
28 Gross Addtions to Common Utilty Plant
29 Gros Addtions to Nonutilty Plant
30 (Less) Allowance for Other Funds Used During Costructio
31 Other (provide details in fonote):
32
33
34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Oter Noncurrent Asets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
38
39 Investments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of Investments in (and Advances to)
42 Asiated and Subsidiary Companies
43
-1,661,541
45,331,714
-7,920,120
-70,90,726
-36,421,476
51,066,157
21,156,209
-7,920,120
-82,84,925
-37,371,890
45,187,94
-18,00,439
-27,46,274
40,906,06
1,716,150
20,50,275
-14,775,749
116,66,014
14,522,86
-3,472,833
23,612,825
-1,831,83
-52,647,09
-36,872,203
826,823,461 735,752,886
-1 ,525,508,915 -1,339,383,764
-4,90,06 -23,612,825
-1,484,60,855 -1,315,770,939- -- I ---
2,685,689 309,662
-22,349,232 -38,211,124
44 Purchase of Investment Securiies (a)
45 Proceeds from Sales of Investment Securiies (a)
FERC FORM NO.1 (ED. 12-96)Page 120
............................................
............................................
Name of Respondent
PacifiCorp
This ~ort Is:
(1) ~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/0312008
Year/Period of Report
End of 2007/04
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and Dther long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments. fixed assets, intangibles, etc.
(2) InfDrmation about nDncash investing and financing activities must be provided in the NDtes to the Financial statements. Also provide a reconcilation between 'Cash and
Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertining tD operating activities only. Gains and losses pertaining to investing and financing activities should be
reportd in those activities. Show in the Notes tD the Financials the amDunts of interest paid (net of amDunt capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. PrOvide a reconcilation Df assets acquired with liabilties asumed in the
Notes to the Rnancial Statements. Do not include on this statement the dollar amount of leases capitalized per the USDfA General Instrction 20; instead provide areconcilation of the dollar amount of leases capitalize with the plant cost.
Line
No.
Description (See Instruction NO.1 for Explanatio of Codes)
(a)
Current Year to Date
OuarterlYear
(b)
Previous Year to Date
OuarterlYear
(c)
46 Loans Made or Purchased
47 Collecons on Loans
48
49 Net (Increase) Decrease in Receivables
50 Net (Increae) Decrease in Inventory
51 Net (Increase) Decreae in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accrued Exenses
53
54
55
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55)
58
59 Cash Flows from Finacing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Equity Contribution
65
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 Intercompany Borrowings
n Repayment of Capital Leas Obligations
78 Net Derease in Short-Term Debt (c)
79
80 Dividends on Preferrd Stock
81 Dividends on Comon Stoc
82 Net Cash Proed by (Used in) Financing Activties
83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
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
13,017,394 -7,854,64
1,193,40,452 348,33,528
200,00,000
109,722,222
214,950,00
3,502,924
182,63,96
1,816,8n
1,396,908,376 857,457,592
-1,254,709
-397,251,66
-1,595,907
-547,822
-2,083,790 -2,083,790
-16,773,669
192,832,698 24,107,030
FERC FORM NO.1 (ED. 12-96)Page 121
!Schedule Page: 120 Line No.: 19 Column: a
YT YT PERC
1213112007 121311200 Account
$45,276,103 $47,633,759 404
1,118,623 1,099,117 425
5,479,353 5,479,353 406
12,881,633 9,371,386 407/407.3
$64,755,712 $63,583,615
YT YTD PERC
1213112007 12/311200 Account
$15,163,499 $13,481,495 151
(6,808,915)(11,269,409)501
893,597 (127,201)254/411.6/411.7
(6,385,866)(1,232,359)253.4
(19,781,800)(33,547,909)228
10,602,121 1,598,165 107
(1,275,241)211
(5,632,346)(7,075,262)228/253
(2,826,039)2,575,518 Varous
$(14,775,749)$(36,872,203)
YT YT PERC
121112007 1213112006 Account
$7,670,035 $(256,759)124/128
(78,766)97,548 185
5,426,125 (2,521,393)128/134
(5,174,041)101
$13,017,394 $(7,854,645)
YT YT PERC
1213112007 12131/200 Account
$$2,330,669 211
3,502,924 211
(513,792)211
$ 3,502,924 $1,816,877
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
I$chedule Page: 120 Line No.: 5 Column: a
Amortzation of Software Development & Other Intagibles
Amortzation of Licensinglydro
Amortzation of Electrc Plant Acquisition Adjustment
Amortzation of Regulatory Assets
Coal Depreciation & Depletion included in Cost of Fuel
PMI Equity Earngs eliminate in Cost of Fuel
(Gain)/Lss on Sale of Propert
Deferr Credits - Deferrd Compensation
Accumulated Provision for Pension & Benefits
Write-Off of Assets Under Constrction
IRC Section 199 Tax Deduction
Accum Provision for Mininglnvironlecom
Other
¡Schedule Page: 120 Line No.: 53 Column: a
Othr Investments/Special Funds
Temporar Facilities
Restricted Cash
Business Acquisition of Steam Reserve Corpration
!Schedule Page: 120 Line No.: 67 Column: a
Contrbution Received from MEHC from the Acquisition of IGC
Tax Benefit of Stock Options Exercised
Oter Equity Adjustments
Net Additional Paid-In Capital
/Shedule Page: 120 Line No.: 74 Column: b
Represents redemption of preferred stock subject to mandatory reemption, which is classified as Long-term debt on the Balance
Sheet. Ths represents all remaning outstading shares of PacifiCorp's $7.48 No Par Serial Preferred Stock series.
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Name of Respondent
PacifiCorp
This Report Is:
(1) I! An Original
(2) D A Resubmission
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utilty. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accunts 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 eamings restrictions and state the amount of retained eamings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes suficient 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
omited.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have ocurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recntly
completed year in such items as: accunting 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.
Date of Report Year/Period of Report
End of 2007/Q404/03/2008
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 122
IFERC FORM NO.1 (ED. 12-88) Page 123.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 0410312008 2007/04
NOTES TO FINANCIAL STATEMENTS (Continued)
PACIFCORP
NOTES TO TH FINANCIA STATEMENTS
(1) Organization and Operations
PacifiCorp (wluch includes PacifiCorp and its subsidiares) is a United States regulated electrcity company serving 1.7 milion retal
customers, including residential, commercial, industrial and other customers in portons of the states of Utah, Oregon, Wyoming,
Waslungton, Idao and Californa. PacifiCorp owns, or ha interests in, a number of thermal, hydroelectrc and wind-powered
generating plants, as well as electrc transmission and distrbution assets. PacifiCorp also buys and sells electricity on the wholesale
market with public and private utilties, energy marketing companes and incorporated municipalities. The reguatory commssion in
each state approves rates for retal electrc sales withn that state. PacifiCorp's consolidated subsidiares support its electrc utilty
operations by providing coal-minig facilities and servces.
On March 21, 2006, a wholly owned subsidiar of MidArican Energy Holdings Company ("MEHC") acquied 100% of the
common stock of PacifiCorp from a wholly owned subsidiar of Scottsh Power pIc ("ScottishPower"). As a result of ths acquisition,
MEHC controls substantially all ofPacifiCorp's voting securties, whch include both common and preferred stock. MEHC, a holding
company basd in Des Moines, Iowa, owning subsidiares that are principally engaged in energy businesses, is a consolidated
subsidiar of Berkshie Hathway Inc. ("Berkshie Hathaway").
(2) Summry of Signcant Accounting Policies
Basis of Prentation
These financial statements are prepared in accordace with the reuiments of the Federal Energy Regulatory Commssion ("the
FERC") as set fort in its applicable Uniform System of Accounts and publishe accounting releases, wluch is a comprehensive basis
of accounting other than accounting principles generally accepte in th Unite States of America ("GAA"). These notes include
disclosures required by GAA adjusted to the FERC basis of presentation, and include specific informtion requested by the FERC.
The following are the signifiant differences between the FERC reportng stadards and GAA:
Investments in Subsidiaries
PacifiCorp accounts for certin investments in subsidiares using the equity method rather than consolidating the assets, liabilties,
revenues and expenses of the subsidiaries as required by GAA. GAA requirs that majority-owned subsidiares and
varable-interest entities for which a company is the prima beneficiar be consolidated in accordance with Statement of
Financial Accounting Stadards ("SFAS") No.94, Consolidtin of All Majority-Owed Subsidiaries and revised Financial
Accounting Standads Board (th "FASB") Interptation No. 46, Consolidtion of Variable-Interest Entities, an interpretatin of
Accounting Research Bulletin No. 51. In genera, the accounting for investments in these certn subsidiares using the equity
method rather than the consolidation method in accordance with GAA has no effect on net income or retaned earngs.
Accumulated Removal Costs
The accumulated removal costs for PacifiCorp's regulated propert, plant and equipment that do not meet the definition of an
asset retiement obligation under SFAS No. 143, Accounting for Asset Retirement Obligations, are classified as a regulatory
liability under GAA and as accumulated provision for depreciation under the FERC reportng standards.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Accumulated Deferred Income Taxes
Accumulated deferrd income taxes are classified as curent and non-current for GAA, by presenting net curent assets and
liabilties separate from net non-curent assets and liabilties on the balance sheet in accordance with SFAS No. 109, Accounting
for Income Taxes. All such amounts are classified as gross non-curnt assets and gross non-curent liabilities for the FERC
reportng standards.
Accumulated deferred income taes are determned for GAAP as the difference between the tax basis of an asset or liabilty as
determned in accordance with the recognition and measurement provisions of FASB Interpretation No. 48, Accounting for
Uncertainty in Income Taxes-an interpretation of FASB Statement No. /09 ("FI 48"), and its" report amunt in the finacial
statements. All such amounts are determned for FERC as the difference between the ta basis of an asset or liabilty as reflected
or expected to be reflecte in a ta retu and its reportd amount in the financial statements.
Interest and penalties on income taes for GAA are classified as income ta expense as permssab1e by FI 48. All such amounts
are classified as interest income, interest expense and penalties for FERC on the Statement of Income.
Unrealized Gains and Losses on Derivative Instruments
The FERC accounting stadards requi tht unralze gains and losses on denvative instrments that are not probable of
recovery in rates be classified gross on the income statement in accordance with FERC Order 627, Accounting and Reportng of
Financial Instrments, Comprehensive Income, Derivatives and Hedging Activities. Unrealized gains and losses on energy
contracts accounted for as denvatives are presente in the Statement of Income as Miscellaneous nonoperating income for
unrealized gains and as Other deductions for unrealized losses. For GAA, unrealized gains and losses on energy denvative
contracts not held for trading purposes are presented on the Statements of Income as revenues for sales contracts and as energy
costs and operatig expense for purchase contracts.
Reclasifcations
Certn other reclassifications of balance sheet, income statement and cash flow amounts have ben made in order to conform to
the FERC basis of presentation. These reclassifications had no effect on net income.
Change in Fisal Year
On May 10, 2006, the PacifiCorp Board of Directors elected to chage PacifiCorp's fiscal year-end from March 31 to December 31.
See PacifiCorp's Secunties and Exchange Commssion (the "SEC") Transition Report on Form 10-K for the nine-month penod ended
December 31, 200 for consolidated financial statements and complete footnotes prepared in accordance with GAA.
Use of Estimate in Preparation of Financial Statements
The preparation of financial statements in conformty with GAA reuires management to mae estimates and assumptions that afect
the reported amounts of assets and liabilties at the date of the financial statements and the reportd amounts of revenues and expenses
during the penod. These estimates include, but are not limited to: unbiled recivables; valuation of energy contracts; the effects of
regulation; the accounting for contingencies, including environmntal, regulatory and income ta mattrs; and certn assumptions
made in accounting for pension and other postretiement benefits. Actual results may differ from the estiates used in preparing the
financial statements.
IFERC FORM NO. 1 (ED. 12-SS) Page 123.2
Cash (131)$11 $10
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) li An Original (Mo, Da, Yr)PacifiCorp (2) A Resubmission 0410312008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Cash Equivalents
Cash equivalents consist of funds investe in money market fuds and in other investments with a maturty of thee months or less
when purchaed.
(Milions of dollars)
December 31,
2007
December 31,
200
Workig funds (135)
Temporar cash investments (136)182 14
Tota cash and cash equivalents $193 $24
Accountig for the Effects of Cert Type of Regation
PacifiCorp prepares its financial statements in accordace with the provisions of SFAS No. 71, Accountìng for the Effects of Certain
Types of Regulation ("SF AS No. 71 "), which differs in certn respects from the application of GAA by non-regulated businesses. In
general, SFAS No. 71 recognzes that accounting for rate-regulated enterpnses should reflect the economic effects of regulation. As a
result, a regulated entity is requied to defer th reogntion of costs or income if it is probable tht, though the rate-makng process,
there wil be a corresponding increase or decrease in future rates. Accordingly, PacifiCorp has deferred certn costs and income that
will be recognized in earnings over varous futue penods.
Management continually evaluates th applicabilty of SFAS No. 71 and assesses whether its regulatory assets are probable of future
recovery by considenng factors such as a change in the regulator's approach to settng rates from cost-based rate-makng to anothr
form of regulation; other regulatory actions; or the impact of competition, which could limt PacifiCorp's abilty to recover its costs.
Based upon ths continual assessment, management believes the application of SFAS No. 71 continues to be appropnate and its
existing regulatory assets are probable of recovery. The assessment reflects the curent political and regulatory climate at both the
state and federal levels and is subject to change in the future. If it becomes probable tht these costs wil not be recoverd, the assets
and liabilties would be wrttn off and recognzed in the statement of income.
AUowance for Doubtful Accounts
The allowance for doubtfl accounts is based on PacifiCorp's assessment of th collectibilty of payments from its customers. Ths
assessment requires judgment regarding the abilty of customers to pay the amounts owed to PacifiCorp and the outcome of pending
disputes and arbitrations. At December 31,2007 and 200, the allowance for doubtful accounts totaled $7 millon and $12 millon,
respetively.
Derivatives
PacifiCorp employs a number of different derivative instrments in connection with its electrc, natural gas and foreign curency
exchange rate activities, including forward purchases and sales, swaps and options. Derivative instrments are recorded in the
Comparative Balance Sheet at fair value as either assets or liabilties unless they are designated and qualify for the normal purchases
and normal sales exemption aforded by GAA. Contracts that qualify as normal purchases or normal sales are not marked to market.
Derivative contracts for commodities used in normal business operations that are settled by physical delivery, among other criteria,
are eligible for and may be designated as normal purchases and normal sales pursuant to the exemption. Recogntion of these
contracts in revenues or Operation expenses in the Statement of Income occurs when the contracts settle.
I FERC FORM NO.1 (ED. 12-88)Page 123.3
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ß An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
For contracts. designated in hedge relationships ("hedge contract"), PacifiCorp maintans formal documentation of the hedge. In
addition, at inception and on a quarerly basis, PacifiCorp formally assesses whether hedge contracts are highly effective in offsettng
changes in cash flows of the hedged items. PacifiCorp documents hedging activity by transaction type and risk management strategy.
Changes in th fai value of a derivative designated and qualifying as a cash flow hedge, to the extent effective, are included in the
Statements of Accumulated Comprehensive Income, Comprehensive Income and Hedging Activities, as Accumulate othr
comprehensive income, net of ta, until the hedged item is recognized in earings. PacifiCorp discontinues hedge accounting
prospectively when it has determned that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that
the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an
effective hedge, futue changes in the value of the derivative are charged to earings. Gains and losses related to discontinued hedges
that were previously recorded in Accumulated other comprehensive income will remain in Accumulated other comprehensive income
until the hedged item is realized, unless it is probable that the hedged forecasted transaction will not occur, at which time associate
deferred amounts in Accumulated other comprehensive income are immediately recognized in curent eangs.
Certn derivative contracts utilized by PacifiCorp are recoverable though rates. Accordingly, unrealize changes in fair value of
these contracts are deferred as net regulatory assets or liabilties pursuant to SFAS No. 71.
When available, quoted maket prices or prices obtaned though external sources are used to measure a contract's fai value. For
contracts without available quoted maket prices, fair value is determned based on internally developed modeled prices. The fair
value of these instruments is a function of underlying forward commodity prices, related volatility, counterpar creditwortness and
duration of the contracts.
Inventories
Inventories consist mainly of materials and supplies, coal stocks, natual gas and fuel oil, which are valued at the lower of average
cost or market.
Propert, Plant and Equipment, Net
General
Propert, plant and equipment are recorded at historical cost. PacifiCorp capitaizes all constrction-related material, direct labor
costs and contract services, as well as indirct constrction costs, which include allowance for funds used during constrction. The
cost of major additions and betterments are capitaized, while costs for replacements, maintenance and repais tht do not improve or
extend the lives of the respective assets are charged to operating expense.
Generally when PacifiCorp reties its regulated propert, plant and equipment, it charges the original cost and any cost of removal and
salvage to accumulated provision for depreciation. Generally when PacifiCorp sells its regulated propert, plant and equipment, the
cost is removed from the propert accounts and the related accumulated provision for depreciation and amortzation accounts ar
reduced and any residual gain or loss is amortzed though future depreciation expense.
PacifiCorp records an allowance for funds used during constrction, which represents the estimated cost of debt and equity costs of
capital funds necessary to finance construction of plants. Allowance for funds used durng constrction is capitaized as a component
of propert, plant and equipment, with offsettng credits to the Statement of Income. Aftr construction is completed, PacifiCorp is
permtt to earn a return on these costs by their inclusion in rate base, as well as recover these costs though depreciation expense
over the useful life of the related assets.
IFERC FORM NO.1 (ED. 12-88) Page 123.4
IFERC FORM NO. 1 (ED. 12-SS) Page 123.5
............................................
Name of Respondent This Report is:Date of Report Year/Penod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The weighted-average aggregate rates used for the allowance for funds used during construction were 8.3% for the yea ended
December 31, 2007 and 7.7% for the year ended December 31, 2006.
Intagible plant consists primarly of computer software costs that are originally recorded at cost. Accumulated amortzation on
intagible plant was $378 millon at Deember 31, 2007 and $358 millon at December 31,200. Amortzation expense on intagible
plant was $44 millon durng th year ended December 31, 2007 and $46 millon during the year ended December 31, 2006. The
estimated aggregate amortzation on intagible plant for the yea ending from Deember 31, 2008 though 2012 is $39 millon in
2008, $31 millon in 2009, $27 millon in 2010, $26 millon in 2011 and $24 millon in 2012. Unamortzed computer software costs
were $149 millon at December 31, 2007 and $177 millon at December 31, 2006.
PacifiCorp has unallocated acquisition adjustments that represent the excess of costs of the acquied interests in property, plant and
equipment purchased from other regulated utilities over their net book value in those assets. These unallocate acquisition
adjustments had an origina cost of $157 millon at December 31, 2007 and 2006, and accumulated provision for depreciation of
$85 millon and $80 millon at December 31, 2007 and 2006, respectively.
Asset Retirement Obligations
PacifiCorp recognzes legal asset retiment obligations, manly relate to the final reclamtion of leased coal-mining propert. The
fair value of a liabilty for a legal asset retiement obligation is recogned in the period in which it is incured, if a reasonable
estimate of fai value can be made. The fai value of th liabilty is added to the carng amount of the associated asset, which is then
depreciated over the remaining useful life of the asset. Subseuent to the initial recognition, the liabilty is adjusted for any revisions
to the expected value of the retiement obligation (with corresponding adjustments to propert, plant and equipment) and for accretion
of the liabilty due to the passage of time. The difference between the asset retiement obligations liabilty, the corresponding asset
retiement obligations asset included in propert, plant and equipment and amounts recovered in rates to satisfy such liabilties is
recorded as a regulatory asset or liabilty. Estimated removal costs tht PacifiCorp reovers though approved depreciation rates but
that do not meet the requirements of legal asset retiement obligations ar accumulated in accumulated provision for depreciation in
the Comparative Balance Sheet.
Depreciation and Amortization
Depreciation and amortzation ar compute by th straight-line group method eith over the life prescribed by PacifiCorp's varous
regulatory jurisdictions for regulate assets or over th assets' estimated usfu lives. The composite depreciation rate of average
depreciable assets on utility propert, plant and equipment was 3% for the yeas ended December 31, 2007 and 2006.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The average depreciable lives of propert, plant and equipment currently in use by category are as follows:
Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.
Generation
Steam plant
Hydroelectric plant
Wind plant
Other plant
Trasmission
Distrbution
Intagible plant
Other
20-43 years
14- 85 years
25 year
15 -35 years
20-70 year
44-50 year
5 -50 years
5 - 30 years
In August 2007, PacifiCorp filed applications with the regulatory commssions in Utah, Oregon, Wyoming, Washington and Idao to
change the rates of depreciation. Agreements have been reached in each of these states and are in varous stages of approvaL. Based
on the new depreciation study, PacifiCorp expects th depreciable lives of its propert, plant and equipment generally to be extended
beyond the lives assumed as of December 31, 2007. The most signicant change is expected to result in increasing the range of
depreciable lives for steam plant from 20 - 43 years to 20 - 57 years. When approved by the state commssions, the agrements wil
mae the new depreciation rates effective Janua 1,2008.
Revenue Recogntion
Revenue from customers is recognized as electrcity is delivered and includes amounts for services rendere. Revenue recognize
includes unbiled, as well as biled, amounts. Rates charged are subject to federal and state regulation.
Electricity sales to retal customers are determned based on meter readings taken thoughout the month. PacifiCorp accrues an
estimate of unbiled revenues, which are eared but not yet biled, net of estimated line losses, each month for electrc servce
provided afr the meter reading date to the end of the month. The process of calculating the unbiled revenue estimate consists of
thee components: quantifying PacifiCorp's tota electrcity delivered during the month, assigning unbiled revenues to customer type
and valuing the unbiled energy. Factors involved in the estimation of consumption and line losses relate to weather conditions,
amount of natual light, historical trends, economic impacts and customer tye. Valuation of unbiled energy is based on estimating
the average price for the month for each customer type.
PacifiCorp records sales, franchise and excise taes, which are collected directly from PacifiCorp's customers and remitted directly to
taing authorities, on a net basis in the Statement ofIncome.
Income Taxes
As a result of the sale of PacifiCorp to MEHC on March 21, 200, Berkshie Hathaway Inc. commenced including PacifiCorp in its
United States federal income ta return. PacifiCorp's provision for income taes has been computed on th basis that it files separate
consolidated income tax returns. Prior to the sale, PacifiCorp was included in the consolidated United States federal income ta retu
for PacifiCorp Holdings Inc. ("PHI").
IFERC FORM NO.1 (ED. 12-SS) Page 123.6
IFERCFORM NO.1 (ED. 12-SS) Page 123.7
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Cotinued)
Deferred ta assets and liabilties are based on differences between the financial statements and tax bases of assets and liabilties
using the estimated ta rates in effect for the year in which the differences ar expected to reverse. Changes in deferred income ta
assets and liabilties. that are associated with components of Other comprehensive income are charged or credited directly to Oter
comprehensive income. Changes in deferred income ta assets and liabilities that are associated with income ta benefits related to
certn property-related basis differences and other varous differences that PacifiCorp is required to pass on to its customers in most
state jurisdictions are charged or credited directly to a regulatory asset or regulatory liability. These amounts were recognized as a net
regulatory asset of $423 ßUllon at December 31,2007, and will be included in rates when the temporar differences reverse. Othr
changes in deferred income ta assets and liabilties are included as a component of income ta expense.
Investment tax credits are generally deferred and amortze over the estited useful lives of the related propertes or as prescribed
by varous regulatory jurisdictions.
In determning PacifiCorp's ta liabilties, management is reuir to interpret complex ta laws and regulations. In preparing ta
returs, PacifiCorp is subject to continuous examnations by federal, state and local ta authorities that may give rise to different
interpretations of these complex laws and regulations. Due to the natur of the examnation process, it generally taes year before
these examnations are completed and these mattrs ar resolved. The Internal Revenue Service has closed its examnation of
PacifiCorp's income ta retus though the 2000 ta year. In addition, open ta years related to a number of state jurisdictions
remain subject to examnation. Although the ultimate resolution of PacifiCorp's federal and state ta examnations is uncertn,
PacifiCorp believes it has made adequate provisions for thse ta positions and the aggregate amount of any additional ta liabilties
that may result from these examnations, if any, will not have a material adverse effect on PacifiCorp's financial condition, results of
operations or cash flows.
Segment Inormtion
PacifiCorp curently has one segment, whch includes the regulate reta and wholesale electrc utility operations.
New Accounting Pronouncements
FIN 48
In July 2006, the FASB issued FI 48. PacifiCorp adopted th provisions of FI 48 on Janua 1, 2007. Under FI 48, ta benefits
are recognized only for tax positions that are more likely than not to be sustaned upon examnation by ta authorities. The amount
recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon ultimate settement.
Unrecognized ta benefits are ta benefits claimed in PacifiCorp's ta retus that do not meet these recogntion and measurements
stadads. In May 2007, the PERC issued gudace under Docket No. AI07-2-00 ("AI07-2"), tht clarfies the PERC's view on the
financial statement presentation of certn items impacted by FI 48. PacifiCorp adopted the reuirements of AI07-2 as of December
31,2007. Refer to Note 8 for additiona discussion.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
SFAS No. U1(R)
In December 2007, th FASB issued SFAS No. 141(R), Business Combinations ("SFAS No. 141(R)"). SFAS No. 14l(R) applies to all
transactions or other events in which an entity obtains control of one or more businesses. SFAS No. 141(R) establishes how the
acquirer of a business should recognize,. measure and disclose in its financial statements the identifiable assets and goodwil acquied,
the liabilities assumed and any noncontrollng interest in the acquired business. SFAS No. 141(R) is applied prospetively for all
business combinations with an acquisition date on or after the beginning of the first annual reportng period beginning on or afer
December 15, 2008, with early application prohibited. SFAS No. 141(R) wil not have an impact on PacifiCorp's historical financial
statements and will be applied to business combinations completed, if any, on or after Januar 1, 200.
SFASNo.160
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements-an amendment
of ARB No. 51 ("SFAS No. 160"). SFAS No. 160 establishes accounting and reportng standards for the noncontrollng interest in a
subsidiar and for the deconsolidation of a subsidiar. SFAS No. 160 reuies entities to report noncontrollng interests as a separate
component of shareholders' equity in the consolidated financial statements. The amount of earngs attbutable to the parent and to
th noncontrollng interests should be clearly identified and presented on the face of the consolidate statements of operations.
Additionally, SFAS No. 160 requires any changes in a parent's ownership interest of its subsidiar, while retaning its control, to be
accounted for as equity transactions. SFAS No. 160 is effective for fiscal year beginning on or after December 15,2008 and interim
periods withn those fiscal year. PacifiCorp is currently evaluating the impact of adopting SFAS No. 160 on its financial position and
results of operations.
SFASNo.161
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instrments an Hedging Activities - an amendment
of FASB Statement No. 133 ("SFAS No. 161"). SFAS No. 161 revises and enhances the disclosure requiements for derivative
instrments and related hedging items as defined under SFAS No. 133, Accounting for Derivative Instrments and Hedging
Activities. The amended disclosures include tabular quantitative disclosures about the fair value of dervative instrents and the
related gains and losses on those instrments during the reportng period. Additionally, SFAS No. 161 requires qualitative disclosures
about the objectives and strategies for using derivative and hedging instrnts and the underlying risk exposures of those items.
SFAS No. 161 is effective for fiscal years beginning afer November 15, 2008 and interim periods withn those fiscal years.
PacifiCorp is currently evaluating the impact of adopting SFAS No. 161.
SFASNo.159
In Februar 2007, the FASB issued SFAS No. 159, The Fair Value Option for Finacial AsSets and Financial Liabilties-Includingan Amendment to SFAS No. 115 ("SFAS No. 159"). SFAS No. 159 permts entities to elect to measure many financial instrments
and certn other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that
exist at the adoption date. Subsequent to the initial adoption, the election of the fai value option should only be made at initial
recognition of the asset or liabilty or upon a remeasurement event that gives rise to new-basis accounting. The decision about
whether to elect the fair value option is applied on an instrment-by-instrment basis, is irevocable and is applied only to an enti
instrment and not only to specified risks, cash flows or portons of that instrument. SFAS No. 159 does not affect any existing
accounting standards that require certin assets and liabilities to be cared at fair value nor does it eliminate disclosure requirements
included in other accounting stadards. SFAS No. 159 is effective for fiscal year beginning afer November 15, 2007. PacifiCorp
does not anticipate electing the fair value option for any existing eligible items. However, PacifiCorp will continue to evaluate items
on a case-by-case basis for consideration under the fair value option.
IFERC FORM NO.1 (ED. 12-SS) Page 123.8
IFERC 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)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
SFASNo.I57
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements ("SFAS No. 15?"). SPAS No. 157 defines fair value,
establishes a framework for measuring fair value and expands disclosures about fai value measurements. SPAS No. 157 does not
impose fair value measurements on items not already accounted for at fai value; rather, it applies, wìth certn exceptions, to other
accounting pronouncements that either require or permt fair value measurements. SFAS No. 157 is effective for fiscal years
beginning after November 15, 2007 and interi periods wìthn those fiscal yea. PacifiCorp is currently evaluating th impact of
adopting SFAS No. 157 on its financial position or results of operations.
SFASNo.I58
In September 200, the EASB issued SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement
Plans-an amendment of FASB Statements No. 87, 88,106, and I32(R) ("SFAS No. 158"). PacifiCorp adopted the recognition and
relate disclosure provisions of SFAS No. 158 as of December 31,2006. SFAS No. 158 also requires tht 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
measure up to thee months prior to the financial statement date. Th requirement to measure plan assets and benefit obligations as of
the date of the employer's fiscal year-end is not required until fiscal year ending afr December 15,2008. As of Deember 31,2007,
PacifCor had not yet adopted the measurement date provisions of the statement. Upon adoption of the measurement date provisions,
PacifiCorp wil be required to record a transitional adjustmnt to retaned earngs or to a regulatory asset depending on whether the
amount is considered probable of being recovere in rates.
(3) Reglatory Mattrs
Regulatory Assets and Liabilties
PacifiCorp is subject to the jurisdiction of public utility reguatory authorities of the states in which it conducts retal electrc
operations with respect to prices, servces, accounting, issuance of securties and other matters. At present,PacifiCorp is subject to
cost-based rate-makig for its business. PacifiCorp is a "licensee" and a "public utility" as those terms are used in the Feeral Power
Act and is therefore subject to regulation by the PERC as to accounting policies and practices, certn prices and other matters
PacifiCorp had regulatory assets not earing a retur on investment of $945 millon at December 31, 2007.
Rate Matters
In October 2007, PacifiCorp filed its 200 ta report undr Oregon Senate Bil 408 ("SB 408"), which was enacted in
September 2005. SB 408 requires that PacifiCorp and other large regulated, investor-owned utilities tht provide electrc or natual
gas service to Oregon customers file an annual ta report wìth the Orgon Public Utility Commssion (the "OPUC"). PacifiCorp's
filing indicates that in 2006, PacifiCorp paid $33 millon more in federal, state and local taxes than was collected in rates from its
retal customers. PacifiCorp proposes to amortze $27 millon of the surchage over a one-year period, which would result in an
average price increas of 3%. If the OPUC issues an order providing for recovery in excess of $27 millon and allows th deferral of
the excess, the porton not yet recovered wil be tracked in a balancing account accruing interest at PacifiCorp's weighted cost of
capita. The deferrd amount, if any, would be addressed in a subseuent SB 408 filing. The 200 ta report is currently being
challenged durng the I80-day procedural schedule that follows the date of the filing, with rates potentially effective June 2008. As
par of the review procss, PacifiCorp update its filing for OPUC sta reommendations which increased the initial request by $2
millon for a tota of $35 millon. PacifiCorp expets to file its 2007 ta report under SB 408 durng the fourt quarer of 2008.
PacifiCorp has not recorded any amounts related to eithr the 200 ta report or the 2007 expeted filing.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp (2) A Resubmission 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(4) Short-Term Borrowings
Short- Term Debt
At December 31,2007, PacifiCorp did not have any outstading short-term debt borrowings. At December 31,200, PacifiCorp's
outstading short-term borrowings consisted of commercial paper arangements of $399 millon at an average interest rate of 5.3%.
Revolving Credit Agrements
At Deember 31,2007, PacifiCorp had $1.5 bilion available under its unsecured revolving credit facilties. Durng the year ended
December 31, 2007, PacifiCorp entered into an unsecured revolving credit facility with tota ban commtments of $700 millon
available though October 23,2012. Under PacifiCorp's existing unsecured revolving credit facility, $800 millon is avaiable though
July 6,2011 and $760 millon is available from July 7, 2011 through July 6, 2012. Each credit facility includes a varable interest rate
borrowing option based on the London Interbank Offered Rate plus a magin that is curently 0.195% that vares based on
PacifiCorp's credit ratings for its senior unsecured long-term debt securities and support PacifCorp's commercial paper program. At
December 31, 2007 and 200, PacifiCorp had no borrowings outstanding under either credit facility.
PacifiCorp's revolving credit and other financing agreements contan customar covenants and default provisions, including a
covenant not to excee a specified debt-to-capitalization ratio of 0.65 to 1.0. At December 31, 2007, PacifiCor was in compliance
with the covenants of its revolving credit and other financing agreements.
IFERC FORM NO.1 (ED. 12-88) Page 123.10
December 31, 2007 December 31, 2006
Average Average
Interet Interest
Amunt Rate Amount Rate
$1,169 6.6%$1,295 6.6%
442 5.5 442 5.5
175 8.1 175 8.1
249 7.0 249 7.0
300 7.7 300 7.7
2,050 5.9 850 5.8
(5)(5)
41 3.8 41 4.0
325 3.5 325 3.9
176 3.8 176 4.0
184 4.5 184 4.5
13 6.2 13 6.2
(1)0)
$5,118 $4,04
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0410312008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(5) Long- Term Debt, Preferred Stock Subject to Mandatory Redemption and Capital Lease Obligations
PacifiCorp's long-term debt, preferred stock subject to mandatory redemption and capital lease obligations were as follows
(in nullons):
Firt mortgage bonds:
4.3% to 9.2%, due though 2012
5.0% to 8.8%, due 2013 to 2017
8.1% to 8.5%, due 2018 to 2022
6.7% to 8.2%, due 2023 to 2026
7.7% due 2031
5.3% to 6.3%, due 2034 to 2037
Unamortzed discount
Pollution-eontrol revenue obligations:
Varable rates, due 2013 (a) (b)
Variable rates, due 2014 to 2025 (b)
Varable rates, due 2024 (a) (b)
3.4% to 5.7%, due 2014 to 2025 (a)
6.2% due 2030
Unamortzed discount
Total long-term debt
Other long-term debt:
Preferred stock subject to mandatory
redemption, due 2007
Capital lease obligations:
10.4% to 14.8%, due thugh 2036
Total
Less current maUnties
Total
$$38
49 11.3 50 11.7
5,167 4,132
(1)(1)
$5.166 $4.131
(a) Secured by pledged fist mortgage bonds generally at the same interest rates, maturty dates and
redemption provisions as the pollution-control revenue bond obligations.
(b) Interest rates fluctuate based on various rates, primarly on certficate of deposit rates, interbank
borrowing rates, prime rates or other short-term maket rates.
First mortgage bonds of PacifiCorp may be issued in amounts linute by PacifiCorp's property, earngs and other provisions of
PacifiCorp's mortgage. Approximately $16 billon of the eligible assets (based on original cost) ofPacifiCorp were subject to the lien
of the mortgage at December 31, 2007.
In October 2007, PacifiCorp issued $600 nullon of its 6.25% Firt Mortgage Bonds due October 15, 2037. In March 2007,
PacifiCorp issued $600 nullon of it 5.75% Firt Mortgage Bonds due April 1,2037.
IFERC FORM NO.1 (ED. 12-SS) 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 04/0312008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
As of December 31, 2007, $3.9 bilion of first mortgage bonds were redeemable at PacifiCorp's option at redemption prices
dependent upon United States Treasur yields. As of December 31, 2007, $542 millon of varable-rate pollution-control revenue
bond obligations were redeemable at PacifiCorp'soption at par.
As of December 31, 2007, $71 millon of fixed-rate pollution-control revenue bond obligations were redeemable at PacifiCorp's
option at par and another $13 millon at 101% of par. The remaining long-term debt was not redeemable at December 31,2007.
At December 31, 2007, PacifiCorp had $518 millon of stadby letters of creit and standby bond purchase agrements available to
provide credit enhancement and liquidity support for varable-rate pollution-control revenue bond obligations. These commtt ban
arangements were all fully available at December 31, 2007 and expire periodically though May 2012.
In addition, at December 31,2007, PacifiCorp had approximately $18 millon of standby letters of credit available to provide credit
support for certn transactions as requested by thrd pares. These commtted bank arangements were all fully available at
December 31, 2007 and have provisions that automatically extend the annual expiration dates for an additional year unless.the issuing
bank elects not to renew a lettr of credit prior to the expiration date.
PacifiCorp's stadby letters of credit and stadby bond purchase agreements generally contan similar covenants and default
provisions to those contained in PacifiCorp's revolving credit agreement, including a covenant not to excee a speified
debt-to-capitazation ratio of 0.65 to 1.0. PacifiCorp monitors these covenants on a regular basis in order to ensure tht events of
default will not occur and at December 31, 2007, PacifiCorp was in compliance with these covenants.
PacifiCorp has entered into long-term agreements that expire at varous dates though October 2036 for transporttion services, rel
estate and for the use of certn equipment which qualify as capital leases. The transporttion services agreements included as capita
leases are for the right to use newly constrcte pipeline facilties to provide natural gas to two of PacifiCorp's power plants. There
were no non-cash capita leas additions to propert, plant and equipment during the year ended December 31, 2007. Non-cash
capital lease additions to propert, plant and equipment were $13 millon durng the yea ended December 31, 200. Assets
accounted for as capital leases of $49 millon as of December 31, 2007 and 2006 were included in Utility plant in the Comparative
Balance Sheet.
In June 2007, PacifiCorp redeemed $38 millon of outstanding preferred stock subject to madatöry redemption, representing all
remaning outstanding shares of PacifiCorp's $7.48 No Par Serial Preferred Stock Series. At December 31, 200, PacifiCorp had
375,00 No Par Serial Preferred shares outstading with a $100 stated value, totaing $38 millon. Durng the year ended
December 31, 200, PacifiCorp redeemed $8 millon of preferred stock subject to mandatory and optional redemption.
I FERC FORM NO.1 (ED. 12-88)Page 123.12
Long-term Capita Le
Debt Obligations Total
2008 $412 $7 $4192001397146
2010 15 7 22
2011 587 7 594
2012 17 7 24
Threafter 3,954 85 4,039
Tota 5,124 120 5,244
Unamortzed discount (6)(6)
Amounts representing interest (a)(71)(71)
Tota $5.118 $49 $5.167
(a) Interest expense on capita lease obligations is recorded as rent expense.
(6)Ast Retirenint Obligations
..................................'..........
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Onginal (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Cotinued)
The annual maturities of long-term debt and capita leas obligations for the years ending December 31 are (in millons):
PacifiCorp records asset retirement obligation liabilties for long-lived physical assets that qualify as legal obligations. PacifiCorp
estimates its asset retiement obligation liabilties based upon detaled engineering calculations of the amount and ting of the futue
cash spending for a thd par to perform the requied work Spending estimates are escalate for inflation and then discounted at a
credit-adjusted, risk-free rate. PacifiCorp then reords an asset retiement obligation asset associated with the liabilty. The asset
retirement obligation assets are depreiated over their expeted lives and th asset retiement obligation liabilties are accreted to the
projected spending date. Changes in estites could ocur due to plan revisions, changes in estimated costs and changes in timing of
the performance of reclamtion activities.
PacifiCorp does not recognize liabilties for asset retiment obligations for which the fai value cannot be reasonably estimated. Due
to the indetermnate removal date, the fai value of the associated liabilities on certn transmission and distrbution and other assets
cannot curently be estimated and no amounts are recognized in the financial statements other than those included in the accumulated
provision for depreciation as established in approved depreciation rates.
IFERC 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 (2)A Resubmission 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table describes the changes to PacifiCorp's asset retiement obligation liabilty for the years ended December 31, 2007
and 2006 (in millons):
December 31, 2007 December 31, 2006
Liabilty recognized at beginning of period
Liabilties incured
Liabilties setted
Revisions in cash flow (a)
Accretion expense (b)
$$62
29
(5)
(4)
4
86
i
(6)
(11)
5
Asset retiement obligation $$8675
(a) Results from changes in the timing and amounts of estimated cash flows for certn plant
reclamation.
(b) PacifiCorp records the accretion expense of asset retiement obligations as either a regulatory asset
or (liabilty).
(7) Rik Management and Hedgin Activities
PacifiCorp is exposed to the impact of market fluctuations in commodity prices, principally natural gas and electricity. Interest rate
risk exists on varable rate debt, commercial paper and futue debt issuances. PacifiCorp employs established policies and procedures
to maage its risks associated with these market fluctuations using varous commodity and financial derivative instrnts, including
forward contracts, swaps and options. The risk management process established by PacifiCorp is designed to identify, assess, monitor,
report, manage and mitigate each of the varous tys of risk involved in its business. PacifiCorp's portolio of energy derivatives is
substantially use for non-trading puroses. As of December 31, 2007 and 2006, PacifiCorp had no financial derivatives in effect
relating to interest rate exposure.
The following table summarizes the varous derivative mak-to-maket positions included in the Comparative Balance Sheet as .of
December 31,2007 (in millons):
Commodity
Foreign currncy
Accuulate
Other
Net Reglatory Comprehensive
Derivative Net Asts (Liability)Asts (Iome)
Asets Liabilties Tota (Liabilities)Los (a)
$357 $(614)$(257)$257 $
1 1 (l
$358 $(614)$(26)$256 $
$143 $(117 $26
215 (497)(282)
$358 $(614)$(256)
Currnt
Non-curnt
Tot
(a) Before income taes.
IFERC FORM NO.1 (ED. 12-SS) Page 123.14
Page 123.15
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) XAn Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/0312008 2007/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table summarizes the varous derivative mark-to-maket positions included in the Comparative Balance Sheet as of
December 31,200 (in ßUllons):
Commoity
Forign currency
Acculate
Other
Net Regulatory Comprehensive
Derivative Net Asts (Liabilty)Asts (Income)
Asts Liabilties Totl (Liabilties)Lo (a)
$383 $(614)$(231)$233 $(3)
3 3 (3)
$386 $(614)$(228)$230 $(3
$151 $(110)$41
235 (504)(269)
$386 $(614)$(228)
Curt
NDn'"urnt
Tota
(a) Before income taes.
Commodity Pnce Risk
PacifiCorp is exposed to market risk due to the variations in the price of fuel used for generation and the price of wholesale electrcity
to be purchas or sold. To manage ths commodity price risk, as well as to optißUze the utilization of power generation assets and
related contracts, PacifiCorp enters into forward purchas and saes. Such energy purchase and sales activities are governed by
PacifiCorp's risk management policy.
PacifiCorp makes continuing projections of futu reta and whlesale loads and futue resource availabilty to meet these loads
basd on a number of criteria, including historical load and forward maket prices and other econoßUc information and experience.
Basd on these projections, PacifiCorp purchaes and sells electrcity on a forward yearly, quaerly, monthly, daly and hourly basis
to match actual resources to actu energy requirments. Ths proess involves hedging transactions, which include the purchase and
sale of firm energy under long-term contracts, forward physical contracts or financial contracts for the purchas and sale of a specified
amount of energy at a specified price over a given period of time.
PacifiCorp manages its exposur to increases in natul gas supply costs through forward commtments for the purchase of physical
natual gas at fixed prices and financial swap energy contracts tht sette in cash based on the difference between a fixed price that
PacifiCorp pays and a floating market-based price that PacifiCorp receives.
Denvative Intruments
Forward physical and financial swap energy contracts tht do not quafy for the exemptions afforded by GAA are accounte for as
derivatives and are recorded in the Comparative Balance Shet as assets or liabilties measured at estimated fair value. Where
PacifiCorp's derivative instments are subject to a mater nettng agrment and the criteria of FI 39, Offsetting of Amounts
Related to Certain Contracts -An Interpretation of APB Opinion No. 10 and FASB Statement No. 105, are met, PacifiCorp presents
its derivative assets and liabilties, as well as accompanying receivables and payables, on a net basis in the Comparative Balance
Sheet. For those energy contracts that are probable of recovery in rates, the unrealized gains and losses on derivative instrments are
recorded as a net regulatory asset or liability.
IFERC FORM NO.1 (ED. 12-SS)
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Realized gains and losses on contracts that qualify as normal purchases and normal sales under GAA (and therefore exempted from
fair value accounting) are reflected in the Statement of Income at the contract settlement date.
Unrealized gains and losses on derivative contracts held for trading puroses are presented on a net basis in the Statement of Income
as Miscellaneous nonoperating income. Unrealized gains and losses on electricity and natural gas derivative contracts not held for
trading purposes are presented in the Statement of Income as Miscellaneous nonoperating income for unrealize gains and Othe
deductions for unrealized losses. Realized gains and losses on derivative contracts held for trading purposes are presented on a net
basis in th Statement of Income as Revenue. Realized gains and losses on physically setted derivative contracts not held for trading
puroses are presented in the Statement of Income as revenues for sales contracts and as Operation expenses for purchas contracts.
Realized gains and losses on non-physically settled forward purchase and sale derivative contracts not held for trading puroses are
presented on a gross basis in the Statement of Income as Revenues for gains and Operation expenses for losses. Realize gains and
losses on financial swap energy contracts are presented in the Statement of Income as Operation expenses.
Cash Flow Hedging
In order to reduce the impact of fluctutions in forward prices of electrcity and natual gas on PacifiCorp's results of operations,
PacifiCorp initiate cash flow hedging in April 2006 for a porton of its derivative contracts, primarly electricity sales and natural gas
purchas contracts. Changes in the fai value of derivative contracts designated as cash flow hedges are recorded as Accumulated
other comprehensive income to the extent the hedges ar effective in offsettng changes in futue cash flows for forecasted electrcity
and natural gas purchas and sales transactions. Amounts included in Accuiulated other comprehensive income are reclassified to the
Statement of Income when the forecasted sale or purchas transaction is recognzed in earngs, or when it is probable that th
forecasted transaction will not occur. Hedge ineffectiveness and reclassifications from Accumulated othr comprehensive income to
earngs are presented in Miscellaneous nonoperating income and Other deductions.
Summary of Activity
Th following table sumzes the amount of the pre-ta unealized gais and losses included withn the Statement of Income
associated with chages in th fai value ofPacifCorp's derivative contracts that are not included in rates (in millons):
Years Ended December 31,2007 200 (a)
Other income:
Miscellaneous nonoperating income (421)
Other income deductions:
Other deductions (426.5)
$$(163)(476)
161 527
Tota unrealized (gain) loss on derivative contracts $$(2)51
IFERC FORM NO.1 (ED. 12-SS) Page 123.16
(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 (2)A Resubmission 04/0312008 2oo7/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(a) During the year ended December 31,2006; PacifiCorp reached a new general rate case stipulation
with several pares in Utah and received approval from the OPUC for a new general rate case
settlement in Oregon. Utah and Oregon together account for approximately 70% of PacifiCorp's
retal electrc operating revenues. Based on management's consideration of the two new rate
settlements, as well as the power cost recovery adjustment mechanisms approved in Wyoming and
California earlier in 2006, PacifiCorp chaged its estimate of the contracts reciving recovery in
rates. Effective July 21,2006, PacifiCorp reorded a $40 millon decreas in net regulatory assets
for previously reorded net unze gains relate to contracts that it detennned were probable
of being recovered in rates with a corrsponding pre-ta chage to net income of $44 millon and a
pre-ta increase to Accumulated other comprehensive income of $4 millon.
Fair Value Calculations
PacifiCorp bases its forward price cures upon market price quotations when available and bases them on internally developed and
commercial models, with internal and external fundamental data inputs, when maket quotations are unavailable. Market quotes are
obtaned from independent energy brokers, as well as direct information received from thd-par offers and actual transactions
executed by PacifiCorp. Price quotations for certn major electrcity trading hubs are generally readily obtaable for the first six
years and therefore PacifiCorp's forward price cures for those locations and periods reflect observable maket quotes. However, in
the later years or for locations that are not actively trded, forward price cures must be developed. For short-term contracts at less
actively traded locations, prices ar modeled based on observed historical price relationships with actively traded locations. For
long-term contracts extending beyond six year, the forward price cure (beyond the fist six yeas) is base upon th use of a
fundamentals model (cost-to-build approach) due to th limite informtion avaiable. The fundamentas model is updated as
waranted, at least quarrly, to reflect chages in the market. such as long-term natural gas prices and expeted inflation rates.
Short-term contracts, without explicit or embedded optionality, are valued based upon the relevant porton of the forwar price cure.
Contracts 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 are valued against the appropriate forward price curve. Options components
are valued using Black-Scholes-ty option models, such as European option, Asian option, spread option and best-of option, with the
appropriate forward price curve and other inputs.
Foreign Currency Derivatives
PacifiCorp has entered into an agrment with a turbine supplier related to a wind plant under constrction that requires PacifiCorp to
mae certn payments in Euros. To mitigate the related exposure to fluctuations in foreign curency exchange rates, PacifiCorp
entered into forward contracts to purchas Euros at a fixed price of United States Dollars. Thre is one remang settlement date of
Marh 31,2008 tht corresponds to the final payment to be made in Euros under the supply agreement. The forward contracts quaif
as derivative instrments. As the cost of the associated wind plant is expected to be recovered in rates, the unrealized gain on ths
contract was recorded as a net regulatory asset. Th unrealized gain was $1 millon and $3 millon at December 31, 2007 and 200,
respectively.
Weather Derivatives
PacifiCorp had a non-exchange-traded streamow weather derivative contract to reduce PacifiCorp's exposure to varabilty in
weather conditions that affect hydroelectrc generation. The contract expire on September 30, 200. PacifiCorp paid an annua
premium in retu for the right to mae or recive payments if streamfow levels were above or below certn thesholds. PacifiCorp
recognized a loss of $12 millon durng the year ended December 31,2006. PacifiCorp curently has no streamow or other weather
derivative contracts.
-...........................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(8) Income Taxes
Income ta expense (benefit) consists of the following (in millons):
Years ended December 31,2007 200
Curent:
Federal
State
Total
$145
18
163
$132
12
144
Deferred:
Federal
State
Tota
51
7
58
20
1
21
Investment ta credits
Tota income tax expense $
(8)
213 $
(8)
157
A reconciliation of the federal statutory ta rate to the effective ta rate applicable to income before income ta expense follows:
Years ended December 31,2007 200
Federal statutory rate
State taes, net of federal benefit
Effect of regulatory treatment of
depreciation differences
Tax reserves
Tax credits
Oter
Effective income ta rate
35%
3
35%
3
2
(2)
(3)
(3)
32%
4
(2)
(4)
(2)
34%
IFERC FORM NO.1 (ED. 12-88) Page 123.18
Deferred ta asets:
Employee benefits
Derivative contracts
Regulatory liabilty
Other deferred ta assets
139
107
44
142
432
294
102
320
104
820
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Onginal (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Cotinued)
The net deferred ta liabilty consists of the following (in millons):
December 31, 2007 December 31, 200
Deferre ta liabilties:
Propert, plant and equipment
Regulatory assets
Derivative contrct regulatory assets
Other deferred ta liabilties
Net deferred ta liabilty
(1,374)
(591)
(97)
(65)
(2,127)
0'695)
(1,510)
(727)
(87)
(10)
(2.434)
(1.614)$$
As of December 31, 200 and Deember 31, 200, PacifiCorp had no federal or state net operatig loss carorwards.
The sale of PacifiCorp to MEHC on March 21, 200 trggered the recogntion of a deferrd intecompany gain or loss for ta
puroses. The recognition of the ta effects of ths item is considere to have occurr imediately prior to the closing of the sale of
PacifiCorp while it was par of the PHI consolidate group. However, no adjustments have been recorded as PacifiCorp is not yet
able to estimate the amount of the ta effect, if any, or determne a rage of th potential ta effect. As the transaction was deemed to
be with shareholders and as a result of form agreements among PacifiCorp, MEHC, PHI and ScottshPower, PacifiCorp does not
believe any adjustments resulting from the ta effect of a deferr intercompany gain or loss will have a material impact on its
financial results,
PacifiCorp adopted FI 48 effective Januar 1, 2007, resulting in a net increase in its asset for uncertn ta positions of $13 millon,
which was offset by an increase in beginning retaned earngs in the Comparative Balance Sheet.
PacifiCorp had a net asset of $9 millon for uncertn ta positions at December 31, 2007 that, if recognzed, would have an impact
on the effective ta rate.
IFERC 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)
PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(9) Preferred Stock
PacifiCorp's preferred stock, not subject to mandatory redemption, was as follows (shares in thousands, dollar in millons, except per
share amounts):
Redemption
Price Per Share
Series:
Serial Preferred,
$100 stated value,
3,500 shares authorized
4.52%
4.56
4.72
5.00
5.40
6.00
7.00
5% Preferred, $100 stated
value,127 shares
authorized
$ 103.5
102.3
103.5
100.0
101.0
Non-redeemable
Non-redeemable
110.0
December 31, 2007
Share Amount
December 31, 200
Share Amount
2 $2 $
85 8 85 8
70 7 70 7
42 4 42 4
66 6 66 6
6 1 6 1
18 2 18 2
126 13 126 13
415 $41 415 $41
Generally, preferred stock is redeemable at stipulate prices plus accrued dividends, subject to certn restrctions. In th event of
volunta liquidation, all preferred 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 accrued dividends. Dividends on all preferred stock
are cumulative. Holders also have the right to elect members to the PacifiCorp board of directors in the event dividends payable are in
default in an amount equal to four full quarrly payments.
Dividends declared but unpaid on preferred stock were $1 millon at December 31,2007 and 200.
(10) Commn Shareholder's Equity
Appropriate Retained Earnngs
In accordance with the requirements of certn hydroelectrc relicensing projects, at December 31, 200, PacifiCorp had $4 millon in
Appropriated retained earngs - amortzation reserve, federal.
Conuon Shareholder's Equity
Through PPW Holdings LLC, MEHC is the sole shareholder of PacifiCorp's common stock. The state regulatory orders that
authorized the acquisition ofPacifiCorp by MEHC contan restrictions on PacifiCorp's abilty to pay dividends to the extent that they
would reduce PacifiCorp's common stock equity below speified percentages of defined capitaization.
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 (2) A Resubmission 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
As of December 31, 2007, the most restrictive of these commtments prohibits PacifiCorp from makng 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 capitalization, excluding short-term debt and curent maturities of long-term debt. After
December 31, 2008, ths minimum level of common equity declines annually to 44.0% aftr December 31, 2011. The terms of ths
commtment treat 50.0% of PacifiCorp's remaining balance of preferred stock in existence prior to the acquisition of PacifiCorp by
MEHC as common equity. As of December 31,2007, PacifiCorp's actual common stock equity percentage, as calculated under ths
measure, exceeded the minimum theshold.
These commtments also restrct PacifiCorp from mang any distrbutions to either PPW Holdings LLC or MEHC if PacifiCorp's
unsecured debt rating is BBB- or lower by Stadad & Poor's Rating Servces or Fitch Ratings or Baa3 or lower by Moody's Investor
Service, as indicate by two of the th rating servces. At Decmber 31,2007, PacifiCorp's unsecured debt rating was BBB+ by
Stadard & Poor's Rating Services and Fitch Ratings and Baal by Moody's Investor Service.
PacifiCorp is also subjectto maximum debt-to-tota1 capitalization percentage under various financing agreements as fuer discussed
in Notes 4 and 5.
(11) Contingencies
Legal Matters
PacifiCorp is par to a varety of legal actions arsing out of the norm cour of business. Plaintiffs occasionally seek punitive or
exemplar damages. PacifiCorp does not believe that such norm and routine litigation will have a material effect on its financial
results. PacifiCorp is also involved in other kinds of legal actions, some of whch assert or may assert claims or seek to impose fines
and penalties in substantial amounts and are described below.
In Februar 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint agaist PacifiCorp in the federal distrct cour
in Cheyenne, Wyoming, alleging violations of the Wyoming 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 federal Clean Ai Act, a potential sour of pollutats such as a coal-fired generating facilty must met minimum standads
for opacity, which is a measurement of light that is obscured in the flue of a generating facilty. The complaint alleges thousands of
violations of six-minute compliance periods and seks an injunction ordering the Jim Bridger plant's compliance with opacity limts,
civil penalties of $32,500 per day per violation, and th plaintiffs' costs of litigation. The court granted a motion to bifurcate the tral
into separate liabilty and remedy phaes. A five-day tral on the liabilty phae is scheduled to begin on April 21, 2008. Theremey-phase tral has not yet ben se. PacifiCorp believes it ha a number of defenses to the claims. PacifiCorp intends to
vigorously oppose the lawsuit but cannot predict its outcome at ths tie. PacifiCorp has already commtted to invest at least
$812 millon in pollution control equipment at its generating facilties, including th Jim Bridger plant. This commtment is expected
to significantly reduce system-wide emissions, including emissions at the Jim Bridger plant.
-...........................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Environmental Matters
PacifiCorp is subject to numerous environmental laws, including the federal Clean Air Act, related air quality standards promulgated
by the Environmental Protection Agency and various state air quality laws; the Endangered Species Act, parcularly as it relates to
certn endangered species of fish; the Comprehensive Environmenta Response, Compensation and Liability Act, and simlar state
laws relating to environmental cleanups; the Resource Conservation and Recovery Act and similar state laws relating to the storage
and handling of hazardous materials; and the Clean Water Act, and simlar state laws relating to water quality. These laws have the
potential for impacting PacifiCorp's operations. Speifically, th Clean Air Act wil likely continue to impact th operations of
PacifiCorp's generating facilties and will likely require PacifiCorp to reduce emissions from those facilties though the instaation
of additional or improved emission controls, the purchase of additional emission allowances, or some combination thereof. As of
December 31, 2007, PacifiCorp's environmental contingencies principally consist of air qualty mattrs. Pending or proposed air
regulations would, if enacted, requie PacifiCorp to reduce its electrcity plant emissions of sulfur dioxide, nitrogen oxide and other
pollutats at its generating plants below curnt levels. PacifCorp believes it is in material compliance with curent environmenta
requirements.
PacifiCorp's policy is to accre environmental cleanup-related costs of a non-capital natue when those costs are believed tobe
probable and can be reasonably estimated. The quantification of environmenta exposures is bas on assessments of may factors,
including changing laws and regulations, advancements in environmental technologies, the quality of information available related to
specific sites, the assessment stage of each site investigation, prelimnar findings and the lengt of time involved in remediation or
settement, PacifiCorp's proportonate share and any coverage provided by insurance policies. Remediation costs that are fixed and
determnable have been discounted to their present value using credit-adjusted, risk-free discount rates based on the expecte future
annual borrowing costs of PacifiCorp. The liability recorded was $ 1 3 millon at December 31, 2007 and $20 millon at December 31,
200 and is included in Deferred credits in the Compartive Balance Sheet. The December 31, 2007 recorded liabilty included
$3 millon of discounted liabilties. Had none of the liabilties included in the $ 1 3 millon balance reorded at December 3 i, 2007
been discounted, the total would have ben $ 14 millon. The expected undiscounted payments for each of the years ending
Deember 31,2008 though 2012 and thereafter ar as follows: $2 millon in 2008, $- millon in 200, $1 millon in 2010, $- millon
in 2011, $- millon in 2012 and $11 milion thereafter.
It is possible that futue findings or changes in estimates could require that additional amounts be accrued. Should curent
circumstances change, it is possible tht PacifiCorp could incur an additional undiscounted obligation of up to approximately
$3 millon relating to existing sites. However, management believes that completion or resolution of these matters will have no
material adverse effect on PacifiCorp's financial position, results of operations or cash flows.
Hydroelectric Relicensing
PacifiCorp's hydroelectric portolio consists of 47 plants with an aggregate plant net owned capacity of 1,158 MW. The FERC
regulates 98% of the net capacity of ths portolio though 16 individual licenses. Several ofPacifiCorp's hydroelectrc projects are in
some stage of relicensing with the PERC. Hydroelectrc relicensing and the related environmenta compliance requiements and
litigation are subject to uncertinties. PacifiCorp expects that future costs relating to thse matters may be significant and wil consist
primaly of additional relicensing costs, operations and maintenance expense, and capita expenditures. Electrcity generation
reductions may result from the additional environmenta requirements. PacifiCorp had incured $89 millon and $79 millon in costs
as of Deember 31, 2007 and 2006, respectively, for ongoing hydroelectrc relicensing, which are reflected in Constrction
work-in-progress in the Comparative Balance Sheet.
IFERC FORM NO.1 (ED. 12-SS) Page 123.22
Page 123.23
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 040312008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
In Februar 200, PacifiCorp fied with the PERC a final application for a new license to operate the 169-MW (nameplate rating)
Klamath hydroelectrc project in anticipation of the March 200 expiration of the existing license. PacifiCorp is currently operating
under an annual license issued by the PERC and expects to continue to operate under annual licenses until the new operating license
is issued. As par of the relicensing process, the Unite States Deparents of Interior and Commerce filed proposed licensing terms
and conditions with the PERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage
facilties at the Klamth hydroelectric project's four manstem dams. In April 2006, PacifiCorp filed alternatives to the federal
agencies' proposal and requested an administrative hearing to challenge some ofthe federal agencies' factual assumptions supportng
their proposal for the constrction of the fish passage facilities. A hearng was held in August 200 before an administrative law
judge. The administrative law judge issued a ruling in September 200 generally supportng th federal agencies' factual assumptions.
In Januar 2007, the United States Deparents of Interior and Commerc filed modified term and conditions consistent with the
March 2006 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to met and implement the federal
agencies' terms and conditions as par of th project's relicensing. However, PacifiCorpexpets to continue in settlement discussions
with varous pares in the Klamth Basin area who have intervened with th PERC licensing proceeing to tr to achieve a mutually
acceptable outcome for the project.
Also, as par of the relicensing process, the PERC is required to penorm an envionmenta review. In September 200, the PERC
issued its draft environmental impact statement on the Klamth hydroelectrc project license. PacifiCorp filed comments on the draft
statement by the close of the public comment period on December 1,200. Subsequently, in November 2007, the PERC issued its
final environmental impact statement. The United States Fish and Wildlife Service and th National Marne Fisheries Service issued
final biological opinions in December 2007 analyzing the hydroelectrc project's impact on endagered species under the proposed
new PERC licens. The United States Fish and Wildlie Service assert the hydroelectrc project is currently not covered by
previously issued biological opinions, and tht consultation under the Endagered Speies Act is required by the issuance of annual
license renewals. PacifiCorp disputes these assertons, and believes federal case law is clear that consultation on annual PERC
licenses is not requied. PacifiCorp will need to obtan water quality certfications from Oregon and Californa prior to the PERC
issuing a final license. PacifiCorp curntly ha applications pending before each state.
In the relicensing of the Klamth hydroelectrc project, PacifiCorp had incured $48 millon and $42 millon in costs at December 31,
2007 and 200, respectively, which ar reflected in Constrction work-in-progrss in the Comparative Balance Sheet. Whle the costs
of implementing new license provisions cannot be detennned until such tie as a new license is issued, such costs could be materiaL.
IFERC FORM NO.1 (ED. 12-S8)
..............................................
Name of Respondent This Report is:Date of Report YearlPenod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERCIsues
California Refund Case
In June 2007, the PERC approved PacifiCorp's settement and release of claims agreement ("Settlement") with Pacific Gas and
Electrc Company, Southern Californa Edison Company, San Diego Gas & Electrc Company, the People of the State of Caifornia,
ex reI. Edmund G. Brown Jr., Attorney General, the Californa Electricity Oversight Board, and the Californa Public Utilities
Commssion (collectively, the "California Pares"), certn of which purchased energy in the California Independent System Operator
("ISO") and the California Power Exchange ("PX") markets durng past penods of high energy pnces in 200 and 2001. The
Settlement, which was execute by PacifiCorp in Apnl 2007, settes claims brought by the Caiforna Pares against PacifiCorp for
refunds and remedies in numerous related proceedings (together, the "PERC Proceedings"), as well as certain potential civil claims,
arsing from events and transactions in Western United States energy makets durng the penod Janua 200 through June 2001 (the
"Refund Penod"). Under the Settlement, PacifiCorp made cash payments to escrows controlled by the Californa Pares in the
amount of $ 1 6 millon in April 2007, and upon PERC approval of the agreement in June 2007, PacifiCorp allowed thePX to release
an additional $12 millon to such escrows, which represente PacifiCorp's estimated unpaid receivable from the transactions in th
PX and ISO markets durng the Refund Penod, plus interest. The monies held in escrow ar for distrbution to buyers from th ISO
and PX markets that purchased power during the Refund Period. The agreement provides for the release of claims by the Californa
Pares (as well as additional pares that join in the Settement) against PacifiCorp for refunds, disgorgement of profits, or other
moneta or non-moneta remedies in the PERC Proceedings, and provides a mutual release of claims for civil dages and
equitable relief.
Northwest Refund Case
In June 2003, the PERC termnated its proceeding relating to the possibilty of requinng refunds for wholesale spot-market bilateral
sales in the Pacific Nortwest between December 200 and June 2001. The PERC concluded tht ordering refunds would not be an
appropnate resolution of the matter. In November 2003, th PERC issued its final order denying reheanng. Several market
parcipants fied petitions in the United States Cour of Appeals for the Ninth Circuit (the "Ninth Circuit") for review of the PERC's
final order. In August 2007, the Ninth Circuit issued its order on ths appeal, concluding that the PERC failed to adequately explain
how it considered or examned new evidence showing intentional market manipulation in Californa and its potential ties to the
Pacific Northwest and that the PERC should not have excluded from the Pacific Nortwest refund proceeding purchases of energy
made by the Californa Energy Resources Schedulng ("CERS") division in the Pacific Nortwest spot market. The Ninth Circuit
remaded the case to the PERC to (i) address the new maket manipulation evidence in detal and account for it in any futue orders
regarding the award or denial of refunds in the proceedings, (ii) include sales to CERS in its analysis, and (ii) fuher consider its
refund decision in light of related, intervening opinions of the cour. The Ninth Circuit offered no opinion on the PERC's findings
based on the record established by the administrative law judge and did not rule on the ments of the PERC's November 2003 decision
to deny refunds. Due to the remand, PacifiCorp cannot predict the impact of ths ruling at ths time.
(12) Guarante and Other Commtments
Guarantee
PacifiCorp is generally required to obtan state regulatory commssion approval pnor to guaranteeing debt or obligations of othr
pares. The following represent the indemnfication obligations of PacifiCorp at December 3 i, 2007.
IFERC FORM NO.1 (ED. 12-88) Page 123.24
Pants Du Du th Year Endin Dember 31,20 20 2010 2011 2012 Therter
CDnstction $342 $6 $1 $$$
Operating leaes 9 4 4 3 3 35
Purchase elecmcity 734 487 414 256 182 1,874
Transmission 61 64 60 54 47 404
Fuel 607 531 445 276 118 1,104
Other ~----102 -.830
Total commtments ~~1J L.~$4247
Construction
Tota
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 25 An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 04103208 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
PacifiCorp has made certin commtments related to the decommssioning or reclamation of certn jointly owned facilties and mine
sites. The decommssioning commtments require PacifiCorp to pay a proportonate share of the decommssioning costs based upon
percentage of ownership. The mine reclamation commtments requie PacifiCorp to pay the mining entity a proportonate share of the
mine's reclamtion costs based on the amount of coal purchasd by PacifiCorp. In the event of default by any of the other joint
parcipants, PacifiCorp potentially may be obligate to absorb, directly or by paying additional sums to the entity, a proportonate
share of the defaulting par's liability. PacifiCorp ha reorded its estimated shae of the decommssioning and reclamation
commtments.
In connection with the sale of PacifiCorp's Montaa service terrtory, PacifiCorp entered into a purchase and sale agreement with
Flathead Electric Cooperative in October 1998. Under the agreement, PacifiCorp agreed to indemnify Flathead Electrc Cooperative
for losses, if any, occurng afer the closing date and arsing as a result of certn breaches of waranty or covenants. The
indemnification has a cap of $10 millon until October 2008 and a cap of $5 millon thereaftr (less expended costs to date). Two
indemnity claims relating to environmenta issues have been tendered, but remediation costs for these claims, if any, are not expected
to be materiaL.
Unconditional Purcha Obligations (in milions)
$ 349
58
3,947
690
3,081
1.25~
PacifiCorp has an ongoing constrction progr to met incred eleccity usage, customer growt and system reliabilty
objectives. At December 31,2007, PacifCorp had estimated long-term unconditional purchas obligations relate to the constrction
of five new wind plants.
Operating Leases
PacifiCorp leases offces, certin operating facilties, land and equipment under operating leases that expire at varous dates though
the year ending December 31, 2092. Certain leases conta renewal options for varing periods and escalation clauses for adjusting
rent to reflect changes in price indices. These leases generally require PacifiCorp to pay for insurance, taes and maintenance
applicable to the leased propert. Excluded from the operating leas payments above are any power purchase agreements that meet
the definition of an operating lease.
Net rent expense, including that relate to obligations accounted for as capita leases for balance sheet presentation, was $29 millon
during the year ended December 31, 2007 and $26 millon during the year ended December 31, 200.
Minimum non-cancelable sublease rent payments expected to be received though the year ended December 31, 2018 total
$21 millon.
IFERC FORM NO. 1 (EO. 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 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Purchased Electricity
As par of its energy resource portfolio, PacifiCorp acquires a portion of its electrcity through long-term purchases and/or exchange
agreements. Included in the purchased electrcity payments above are any power purchase agreements that meet th definition of an
operating lease.
Included in th minimum fixed annual payments for purchased electricity above are commtments to purhase electrcity from several
hydroelectrc projects under long-term arangements with public utility distrcts. These purchaes are made on a "cost-of~service"
basis for a stated percentage of project output and for a like percentage of project operating expenses and debt service. These costs
are included in Operation expenses in the Statement of Income. PacifiCorp is required to pay its porton of operating costs and its
porton of the debt service, whether or not any electrcity is produced.
At Deember 31,200, PacifiCorp's share oflong-term arangements with public utility distrcts was as follows (in millons):
Year
Contract
Expires
Nameplate
(MW)
Percentage
of Output
Annual
Costs (a)
Generating Facìlty:
Wanapum
Rocky Reach
Prest Rapids
Wells
Tota
200
2011
2045
2018
194
69
63
53
379
19%
5
7
7
$ 10
4
3
3
$ 20
(a) Includes debt servce totang $11 millon.
PacifiCorp's minimum debt service and estiated operating obligations included in purchased electrcity above for the years ending
December 31 are as follows (in millons):
Minimum
Debt Servce
Operating
Obligations
2008 $11
2009 11
2010 5
2011 5
2012 3
Thereafter 64
$99
$12
12
6
6
4
122
162$
IFERC FORM NO.1 (ED. 12-88) Page 123.26
IFERC FORM NO.1 (ED. 12-SS) Page 123.27
............................................
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 04/0312008 2oo7/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
PacifiCorp has a 4% entitlement to the generation of the Intermountain Power Project, located in central Utah, though a power
purchase agreement. PacifiCorp and the City of Los Angeles have agreed that the City of Los Angeles wil purchase capacity and
energy from PacifiCorp's 4% entitlement of the Intermountain Power Project at a pnce equivalent to 4% of the expenses and debt
servce of the project.
Fuel
PacifiCorp has "tae or pay" coal and natu gas contrcts tht requie minimum payments.
Other
Unconditional purchase obligations, as defined by accounting stadads, are those long-term commtments tht are non-cancelable or
cancelable only under certn conditions. PacifiCorp has such commtmnts related to legal or contractual asset retirement obligations,
envionmenta obligations, hydroelectrc obligations, equipment maintenance and varous other service and maintenance agreements.
Also included are contributions expected to be made to the PacifiCorp Retiement Plan dunng the year ending December 31, 2008 as
disclosed in Note 13 below.
(13) Employee Beneft Plans
PacifiCorp sponsors defined benefit pension plans tht cover th majonty of its employees and also provides certn postretiment
health care and life insurance benefits though varous plans for eligible retiees. In addition, PacifiCorp sponsors an employee
savings plan.
As a result of the sale of PacifiCorp to MERC, plan parcipants that were employees or retiees of certn ScottishPower affliates
and a former PacifiCorp mining subsidiary ceased to parcipate in PacifiCorp's plans. Ths separation resulted in a net $4 millon
reduction in Other paid-in capita durng the year ended December 31, 2006.
Pension and Other Posretirement Plans
PacifiCorp's pension plans include a non-eontrbutory defined benefit pension plan, the PacifiCorp Retiement Plan (the "Retiement
Plan"); the Supplementa Executive Retiement Plan (the "SERP"); and certn multi-employer and joint trst union plans to which
PacifiCorp contrbutes on behaf of certn bargaining unts. Benefits for union employees covered under the Retiement Plan are
based on the employee's yea of servce and average monthy pay in the 60 conseutive months of highest payout öf the last
120 months, with adjustments to reflect benefits estimate to be received from social seunty.
Effective June 1, 2007, PacifiCorp switched from a traditional final average pay formula for the Retiement Plan to a cash balance
formula for its non-union employees. As a result of the change, 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 $111 millon.
Non-union employees hired on or after Januar 1, 2008 will not be eligible to parcipate in PacifiCorp's Retiement Plan. These
non~union employees will be eligible to receive enhanced benefits under PacifiCorp's defined contrbution plan.
Effective December 31, 2007, Local Union No. 659 of the International Brotherhoo of Electrcal Workers ("Local 659") elected to
cease parcipation in the Retiement Plan and parcipate only in PacifiCorp's defined contrbution plan with enhanced benefits. As a
result of ths election, the Local 659 parcipants' benefits were frozen as of Dember 31,2007.
.............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The cost of other postretirement benefits, including health care and life insurance benefits for eligible retirees, is accrued over the
active service period of employees. PacifiCorp funds these other postretirement benefits though a combination of funding vehicles.
PacifiCorp also contrbutes to joint trust union plans for postretiement benefits offered to certin bargaining units.
Plan assets and benefit obligations are measurd thee months prior to PacifiCorp's fiscal year end. Accordingly, plan assets and
benefit obligations were measured as of September 30. The market-related value of plan assets, among other factors, is used to
determne expected retur on plan assets. The maket-related value of plan assets is calculated by spreading the difference between
expected and actual investment returs over a five-year period beginning aftr the first year in which they ocur. As differences
between expected and actual investment retus are recognized, they are included in the Amortzation of prior year loss component of
Net periodic benefit cost.
The following disclosures were generally taen directly from PacifiCorp's Form 100K filed with the SEC in Februar 2008. Net
periodic benefit cost for the pension, including the SERP, and other postretiement benefit plans included the fòllowing
components (in nnllons):
Pension
Yea Ended
Deber 31.
2007
Nine.Month
Period Ended
December 31,
200
Yea Ended
Deember 31,
2007
Other Postrtiret
Nine.Month
Period Ended
Dember 31,20
Service cost (a)$29 $22
mteret cot 71 56
Expected rern on plan assets (68)(54)
Net amDrtzation 23 23
Cost Dr ternation benefits 1 2
Curtlment loss 1
Net periodic benefit cost (b)$56 $50
$7
33
(26)
19
$7
25
(19)
15
$33 $28
(a) Service cost excludes $10 nnllon of contrbutions to th multi-employer and joint trst union
plans durng the year ended December 31, 2007, $6 nnllon during the nine-month period ended
December 31, 2006 and $ 1 nnllon durng the year ended March 31, 2006.
(b) Net periodic benefit cost for the thee months ended March 31, 2006 was $17 nnllon for the
pension plans and $7 milion for the other postrtiement plans, resulting in total net periodic
benefit cost for the year ended December 31, 2006 of $67 nnllon for the pension plans and $35
nnllon for the other postretirement plans.
I FERC FORM NO.1 (ED. 12-88)Page 123.28
Pla asses at fai value, beginnng of peod
Employe contnbutions
Parcipant contributions
Actual re DO plan asses
Benefits paid
$884
80
$825
79
$318
46
11
46
(43)
$292
30
7
19
(30)
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ß An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/032008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table is a reconcilation of the fai value of plan assets as of the end of the period (in millons):
Pension
Year Ended
Dember 31,
200
Nine.Month
Period Ended
December 31,
2006
Year Ended
Deember 31,
2007
Other Postrtirement
Nine-Month
Period Ended
Decmber 31,
200
118
(19)
56
(6)
Pla assets at fair value, end of peod $963 $884 $378 $318
The SERP has no plan assets; however, PacifCorp has a Rabbi trst tht holds corporate-owned life insurance and other investments
to provide funding for the futue cash requirements of the SERP. The cash surnder value of all of the policies included in the Rabbi
trst, net of amounts borrowed against the cash surender value, plus th fai maket value of other Rabbi trst investments, was
$40 millon and $39 millon at December 31, 2007 and 200, respetively. These assets ar not included in the plan assets in the
above table. The porton of the pension plans' projected benefit obligation, included in the table below, related to the SERP was
$52 millon and $54 millon at December 31,2007 and 200, respetively.
The following table is a reconcilation of the benefit obligations at the end of the perod (in millons):
The SERP's accumulated benefit obligation totaled $52 millon and $53 millon at December 31, 2007 and 200, respetively.
IFERC FORM NO.1 (ED. 12-88) Page 123.29
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ß An Original (Mo, Da, Yr)
PacifiCorp . (2) A Resubmission 04103/2008 2oo7/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The funded status of the plans and the amounts recognized in the Comparative Balance Sheet are as follows (in millons):
Pension Other Postrtirement
Dember 31,Decber 31,Dember 31,Decmber 31,
207 2006 200 200
Pla assets at fair value, end of peod $963 $884 $378 $318
Les - Benefit obligation, end of penod 1.iii 1.333 536 566
Funded sttus (148)(449)(158)(248)
Contnbutions afer the meurement date
but before ye-end 12 27
Amunts reognze in the CompativeBalce She $(J48)$(4)$(46)$(21)
Aiounts reogniz in th Copartive
Balace She:
Oter currnt liabilties $(4)$(4)$$
Pension and oter pot employmnt
liabilties (44)(445)(46)(221)
Aiounts reognize $(J48)$(44)$(146)$(221)
AiDunts nDt yet recogize as components
of net penodic beefit cost:
Net loss $250 $400 $45 $109
Pror service CDst (crit)(115)9 17 20
Net trsition obligation 3 5 60 72
Tota $138 $414 $122 $201
A reconcilation of the amounts not yet recognized as components of net periodic benefit cost for th year ended December 31, 2007
is as follows (in millons):
Accuulate
Oter
Regultory ComprehensiveAstInme
Pension
Balance, beginning of yea $405 $9
PrDr service cot ansing dunng th yea (129)(I)
Net gain ansing dunng the yea (121)(2)
Net amortization (23)
TDtai (273)ß)
Balance, end of ye $132 $6
Deerr
Regulatory IncomeAsTaxes
Oter Postrrement
Balance, beginning of yea $161 $40
Net gain ansing durng the yea (47)(13)
Net amrtization (9)
Tota (66)(1)
Balance, end of yea $95 $27
Tota
$414
(130)
(123)
(23)
(276)
$138
Tot
$201
(60)(9)
(79)
$122
IFERC FORM NO.1 (ED. 12-SS) Page 123.30
Pension benefits
Other postrment benefits
Net Pror Servce Net Transition
Loss Cost Obligation Total
$17 $(13)$3 $7
3 12 15
$17 $(Jm $15 $22
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) XAn Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 0410312008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The net loss, prior service cost and net transition obligation that will be amortzed in 2008 into net periodic benefit cost are estimated
to be as follows (in millons):
Tota
Plan Assumptions
Assumptions used to determne benefit obligations and net benefit cost were as follows:
Pension
Yea Ended
Dember 31,
2007
Nine-Month
Period Ended
Deber 31,20
Year Ended
December 31,
2007
Other Postretient
Nine-Month
Period Ended
Dember 31,20
Benefit Dbligations as of the
meurement date:
Discount rate
Rate of compensation inc
6.30%
4.00
5.85%
4.00
6.45%
N/A
6.00%
N/A
Net benefit cost for the peod
ended:
Discount rate
Expeced retur on pla asses
Rate of compensation incr
5.76%
8.00
4.00
5.75%
8.50
4.00
6.00%
8.00
N/A
5.75%
8.50
N/A
Assumed health care cost trnd rates as of the measurement date:
Year Ended
Decmber 31,
200
Nine-Month
Period Ended
Deber 31,
200
Heath car cost trnd rate assume for next yea - unde 65
Health ca cost trd rate assume for next yea - over 65
Rate that the cost trnd rate grduay declines to
Yea th rate reches the rate it is assumed to reman at - unde 65
Yea that rae reches the rate it is assumed to reman at - over 65
9%
7
5
2012
2010
10%
8
5
2012
2010
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)
PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Assumed health care cost trnd rates have a signficant effect on the amounts reported for the health care plans. A
one-percentage-point change in assumed health care cost trend rates would have the following effects (in millions):
Increa (Dcrease) in Expens
One Percentage-Point One Percentae-PointIncrea Decree
Effect on totl service and interest CDst
Effect on otr postrrement benefit Dbligation
$$3
40
(2)
(33)
Contributions and Benefit Payments
Employer contrbutions to the pension and other postretiement benefit plans are expected to be approximately $70 millon and
$27 millon, respetively, for 2008. Also durng 2008, PacifiCorp expects to contribute approxitely $11 millon to the joint trust
union plans.
Retirement Plan costs are funded annually by at least the miimum required amount but by no more than the mamum amount tht
can be deducted for federal income ta purposes. The Pension Protetion Act of 2006 changes funding rules beginning in 2008 and
may have the effect of making mimum pension funding requirements more volatile than they have been histoncally. Accordingly,
PacifiCorp continually evaluates its funding strategies. PacifiCorp's policy is to contrbute to its other postretiement benefit plan an
amount equal to the net periodic cost.
PacifiCorp's expecte benefit payments to parcipants for its pension and other postretiement plans for 2008 though 2012 and for
the five years thereafer are summarized below (in millons):
Proje Benefit Paymnts
Other Poretirement
Pension Gro Medicare Subsidy Net of Subsidy
2008 $89 $38 $3 $35
2009 86 39 4 35
2010 91 40 4 36
2011 92 42 4 38
2012 99 42 5 37
2013- 2017 535 232 31 201
IFERC FORM NO.1 (ED. 12-88) Page 123.32
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp (2) A Resubmission 04/03/2008 2007/04
NOTES TO FINANCIAL STATEMENTS (Continued\...
Invesment Policy and Asset Alocation
The Retirement Plan and other postretirement plan assets are managed and invested in accordance with all applicable requirements,
including the Employee Retirement Income Securty Act and the Internal Revenue Code. PacifiCorp employs an investment approach
that pnmarily uses a mix of equities and fixed-income investmnts to maxze the long-term retu of plan assets at a prudent level
of nsk. Risk tolerance is established though consideration of plan liabilties, plan funded status, and corporate financial condition.
The investment portolio contans a diversified blend of pnmly equity, fixed-income and other alternative investments as shown in
the table below. Equity investments ar diversified across Unite States and foreign stocks, as well as growt and value companies,
and small and large maket capitazations. Fixed-income investments are diversified across United States and foreign bonds. Other
assets, such as pnvate equity investments, are use to enhance long-term retus while improving portolio diversification. PacifiCorp
pnmarly minimizes the nsk of large losses though diversification but also monitors and manages other aspects of risk though
quaerly investment portolio reviews, annual liability meaurements and penodic assetliabilty studies.
The assets for other postretiement benefits are composed of three different trst accounts. The 401(h) account is invested in the same
manner as the assets of the Retirement Plan. Each of the two Volunta Employees' Beneficiares Association Trusts has its own
investment allocation strategies.
PacifiCorp's asset allocation was as follows:
Volunta Emloyee'
Beneciries Asation Tms
Dember 31, Deember 31,207 2006 Taret
Pens & Oter Postiment
Deember 31, Debe 31,207 2006 Target
PacifiCorp's employee savings plan qualifies as a ta-deferred arangement under th Internal Revenue Code and covers substatially
all employees. PacifiCorp's contrbutions to the employee savings plan were $19 millon dunng the year ended December 31, 2007
and $21 millon durng the year ended December 31, 200.
Severance
PacifiCorp has underten a review of its organzation and workforce. As a result of the review, PacifiCorp incured severance
expense of $4 millon durng the year ended December 31, 2007 and $43 millon durng the year ended December 31,200.
I FERC FORM NO.1 (ED. 12-88)Page 123.33
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp i2) A Resubmission 04103/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(14) Fair Value of Financial Instruments
The caring amounts of cash and cash equivalents, receivables, payables, accrued liabilties and short-term borrwings approximate
fair value because of the short-term maturity of these instruments. Derivative instrments are recorded at their fair values, which ar
based upon published maket indexes as adjusted for other market factors such as location pricing differences or internally develope
models. Substatially all investments are cared at their fai values, which are based on quoted market prices.
The fai value. of PacifiCorp' s fixed-rate long-term debt, current matuties of long-term debt and preferred stock subject to mandatory
redemption has been estimated based on quote maket prices. The caring amount of variable-rate long-term debt approximates fai
value because of the frequent repricing of these instrments at maket rates. The following table presents the carng amount and
estimated fair value of PacifiCorp's long-term debt and preferred stock subject to mandatory redemption, including the currnt
porton (in millons):
December 31, 2007Ca~ng FairAmunt Value
December 31, 2006Carring FairAmount Value
Long-term debt
Preferred stock subject to
mandatory redemption
$ 5,118 $ 5,350 $ 4,04 $ 4,243
38 38
(15) Relate-Part Tranctions
Transactions while owned by MEHC
As discussed in Note 1, PacifiCorp was acquired by a subsidiar ofMEHC on March 21, 2006. The following describes PacifiCorp's
transactions and balances with unconsolidated related pares while owned by MEHC.
In the ordinar course of business, PacifiCorp engages in varous transactions with several of its afliated companies. Services
provided by PacifiCorp and charged to affiiates related prmarly to the administrative services, financial statement preparation and
direct-assigned employees. These receivables were $- millon at December 31,2007 and $1 millon at December 31,200. Services
provided by afliates and charged to PacifiCorp related primaly to the transport of natural gas, relocation services, and
administrative servces provided under the intercompany administrative servces agreement among MEHC and its affliates. These
payables were $2 millon at December 31,2007 and $1 millon at December 31,2006. These expenses totaled $14 millon during the
year ended December 31, 2007 and $8 millon during the year ended December 31, 200.
PacifiCorp has long-term tranporttion contracts with the Burlington Nortern Santa Fe Railway ("BNSF'), in which PacifiCorp's
ultimate parent company, Berkshie Hathaway, acquired a 17% ownership interest dunng 2007. At December 31,2007, PacifiCorp
had $2 millon of accounts payable to BNSF outstanding under these contracts, including indirt payables related to a jointly owned
plant. Transporttion costs under these contracts were $31 millon during the year ended December 31, 2007.
IFERC FORM NO.1 (ED. 12-88) Page 123.34
IFERC FORM NO.1 (ED. 12-88) 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 04/03/2008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Effective March 21,200, PacifiCorp began parcipating in a captive insurance program provided by MEHC Insurance Services Ltd.
("MISL"), a wholly owned subsidiar of MEHC. MISL covers all or significant portions of the propert damage and liabilty
insurance deductibles in many of PacifiCorp's current policies, as well as overhead distribution and transmission line property
damage. PacifiCorp has no equity interest in MISL and has no obligation to contrbute equity or loan funds to MISL. Premium
amounts are established based on a combination of actuaral assessments and market rates to cover loss claims, administrative
expenses and appropriate reserves, but as a result of regulatory commtments are capped though December 31, 2010. Certn costs
associated with the program are prepaid and amortized over the policy coverage period expiring March 20, 2008. Prepayments to
MISL were $2 millon at Deember 31, 2007 and $2 millon at December 31, 200. Receivables for claims were $11 millon at
December 31,2007 and $8 millon at December 31,200. Premium expenses were $7 millon during the year ended December 31,
2007 and $6 millon during the year ended December 31, 200.
PacifiCorp is par to a ta-sharng agreement and is par of the Berkshi Hathaway consolidated ta retu. As of December 31,
2007 and 2006, Prepayments included $22 millon and $4 millon, respetively, of income taes receivable from PacifiCorp's parent
company.
Tranctins with Unconslidate Subsidiaries of PacifCorp
In the ordinar course of business, PacifiCorp engages in varous transactions with its unconsolidate subsidiares. Servces provided
by PacifiCorp and charged to its subsidiares related primarly to management services, income taes and labor. These receivables
were $1 milion at December 31, 2007 and 200. Services provided by subsidiares and charged to PacifiCorp primaly related to coal
purchases. These payables were $9 millon at December 31, 2007 and 2006. Expenses for these coal purchases were $102 millon for
the year ended December 31, 2007 and $94 millon for the year ended Deember 31, 200.
PacifiCorp is par to an umbrella loan agreement with one of its unconsolidated subsidiares. Regulatory authorizations permt
PacifiCorp to borrow from its subsidiares (including those tht ar consolidate) without limitation and to loan each of these
subsidiares up to $30 millon at anyone ti, prvided that the borrowings bear interest at rates tht do not exceed the interest rates
that PacifiCorp would otherwse incur externally. As of Deember 31, 2007 and 200, afliated notes receivable from unconsolidated
subsidiares were $26 millon and $23 millon, respetively, including interest.
Transctions whie owned by ScotthPower
Under ScottshPower ownership, PacifCorp engaged in varous transactions with several of its formr afliated companies pursuant
to ScottishPower's afliated interest cross-charge policy. Revenues from these former afliates related primaily to wheeling services
and totaled $2 millon for the year ended Deember 31, 200. Services provided by PacifiCorp and recharged to these former
afliates relate priily to administrative servces, costs associate with retention agrements and severance benefits reimbured by
ScottshPower, and payroll costs and related benefits of PacifiCorp employees working on international assignent in the United
Kingdom. These charges totaed $2 millon for the year ended Deember 31, 200. Services provided by former affliates and
recharged to PacifiCorp related primaly to leas payments, captive insurce, administrtive services and payroll costs and related
benefits of ScottishPower employees working on international assignment in the United States. These expenses totaled $10 millon for
the year ended December 31, 200.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(16) Jointly Owned Utilty Plants
Under joint plant ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly
owned generation and transmission plants. PacifiCorp accounts for its proportonal shae of each plant. Operating costs of each plant
are assigned to joint owners based on ownership percentage or energy purchased, depending on the nature of the cost. Operating
expenses in the Statement of Income include PacifiCorp' s share of the expenses of these units.
The amounts shown in the table below represent PacifiCorp's share in each jointly owned plant at December 31, 2007
(dollar in millons):
Plat Accumulate Constmction
PacifCorp in DepreciatioD!Work-in-
Share Service Amrtiztion Progre
Jim Bridger Nos. 1 - 4 (a)67%$965 $505 $13
Wyod(a)80 329 173 1
Hunter No. 1 94 304 148 1
Colstrp Nos. 3 and 4 (a)10 243 123 1
Hunter No. 2 60 192 88 1
Hermston (b)50 170 38 2
Crag Nos. 1 and 2 19 167 78 1
Hayden No. 1 25 44 21 i
Foote Creek 79 37 13
Hayden No. 2 13 27 14
Other transmission and distrbution
plants Varous 80 24 2
Total $2.558 $1.225 $23
(a)Includes transmission lines and substations.
(b)Additionally, PacifiCorp ha contrcted to purchase the remaning 50% of the output of the Hermston
plant.
Under the joint ownership agreements, each parcipating utility is responsible for financing its shae of constrction, operating an
leasing costs. PacifiCorp's portion is recorded in its applicable constrction work-in-progrss, operations, mantenance and ta
accounts, which is consistent with wholly owned plants.
(17) Supplemental Cah Flow Informtion
A summar of supplemental cash flow information is presente in the following table (in millons):
Year Ended
December 31,
2007
Year Ended
December 31,
200
Income taxes paid
Interest paid, net of amounts capitaized
$
$
$
$
178
245
152
251
IFERC FORM NO.1 (ED. 12-88) Page 123.36
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) DA Resubmission 04/031008
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMP =lEHENSIVE INCOME, AN) HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-ta basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
Une Item Unrealize Gains and Minimum Pension Foreign Currency Other
No.Losses on Available-Uabilty adiustment Hedges Adiustments
for-sale Securies (net amount)
(a)(b)(c)(d)(e)
1 Balance of Account 219 at Beginning of
Preceding Year 92,96 (8,99,927)
2 Preceding OtrNr to Date Reclassifcations
from Act 219 to Net Incme (1,416,499)
3 Preceding OuarterNear to Date Changes in
Fair Value 503,402 8,990,927 (5,939,253)
4 Total (lines 2 and 3)(913,097)8,990,927 (5,939,253)
5 Baance of Accunt 219 at End of Precedng
OuarterNear
6 Balance of Account 219 at Beinning of
Current Year 9,86 (5,939,253)
7 Current OtrNr to Date Reclasifications
from Acc 219 to Net Incme
8 Current OuarterNear to Date Change in
Fair Value 31,08 2,381,915
9 Total (lines 7 an 8)31,088 2,381,915
10 Balance of Account 219 at End of Current
OuarterNea
FERC FORM NO.1 (NEW 06)Page 122a
............................................
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2oo7/Q4
This ~ort Is:
(1) ~An Original
(2) A Resubmission
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMP
Date of Report
(Mo, Da, Yr)
04/031208
EHENSIVE INCOME, AN HEDGING ACTIVITIES
Line
No.
Other Cash Flow
Hedges
Interest Rate Swaps
Other Cash Flow
Hedges
Deriative Contracts - EleCtrcity
and Natural Gas
(f)
1
2
3
4
5
6
7
8
9
10
2,047,252
2,047,252
Totals for each
categry of items
recrded in
Acunt 219
(h)
( 8,067,96)
( 1 ,416,499)
5,602,328
4,185,829
3,882,135)
3,882,135)
2,047,252)
2,413,003
365,751
3,516,384)
Net Income (carried
Forward from
Page 117, Line 78)
Total
Comprehensive
Income
(i)0)
FERC FORM NO.1 (NEW 062)Page 122b
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 04/0312008 2007/Q4
FOOTNOTE DATA
ISchedule Page: 122(a)(b) Line No.: 5 Column: b
Unrealized ain on available-for-sale securties of $15,900 less ta of $6,034 nettin to $9,866.
chedule Pa e: 122 a)(b) Line No.: 5 Column: e
Adjustment to initially apply SFAS No. 158 (pension and other postretiement plans) of ($9,571,706) less ta of ($3,632,453) nettng
to ($5,939,253).
f$chedule Page: 122(a)(b) Line No.: 5 Column: g
Unrealize gain on cash flow hedges of $3,299,410 less ta of $1,252,158 nettng to $2,047,252.
For a fuer discussion on cash flow hedging, refer to Page 122, Notes to the Financial Statements - Note 7 ~ Risk Management of ths
Form No. 1.
ISchedule Page: 122(a)(b) Line No.: 10 Column: b
Unrealized gain on available-for-sale securities of $66,003 less ta of $25,049 nettng to $40,954.
ISchedule Page: 122(a)(b) Line No.: 10 Column: e
Unrecognized amounts on retirement benefits of ($5,733,112) less ta of ($2,175,774) nettn to ($3,557,338).
chedule Pa : 122 a b Line No.: 10 Column:
For a fuer discussion on cash flow hedging, refer to Page 122, Notes to the Financial Statements - Note 7 - Risk Management of this
Form No. 1.
............................................
Blank Page
(Next Page is 200)
ae 0 epa
(Mo, Da, Yr)04/038
SUMMA Y OF UTILITY PLANT AND ACCUM LATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for elecric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specif) and in
column (f) common function.
Line
No.
Classification Total Company for the
Current YearlQuarter Ended
(b)
Electric
(c)(a)
Utilty Plant
2 In Service
3 Plant in Service (Classified)
4 Prort Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7)
9 Leased to Others
10 Held for Future Use
11 Construion Work in Proress
12 Acquisition Adjustments
13 Total Utilit Plant (8 thru 12)
14 Acum Prov for Depr, Amort, & Depl
15 Net Utiity Plant (1.3 less 14)
16 Detail of Accum Prov for Depr, Amort & Depl
17 In Service:
18 Depreciation
19 Amort & Depl of Producing Nat Gas Ladlnd Right
20 Amort of Undrground Storage La Rights
21 Amort of Other Utilit Plant
22 Total In Service (18 thru 21)
23 Leased to Others
24 Depreciation
25 Amortiztion and Depletion
26 Tota Leased to Others (24 & 25)
27 Hed for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31,32)
16,361,058,390
49,253,139
21,858
56,258,176
16,361,058,390
49,253,139
21,858
56,258,176
16,46,591,563 16,46,591,563
13,697,167
941,818,n6
157,193,780
17,579,301 ,286
6,691,765,90
10,887,535,383
13,697,167
941,818,776
157,193,780
17,579,301,286
6,691,765,903
10,887,535,383
85,36,167
6,691,765,90
85,368,167
6,691,765,903
FERC FORM NO.1 (ED. 12-89)Page 200
............................................
-...........................................
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 0403/2008
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Specif) Other (Specif) Other (Specif)
Year/Period of Report
End of 2007/Q4
Gas Common Line
No.
FERC FORM NO.1 (ED. 12-8)Page 201
¡Schedule Page: 200 Line No.: 18 Column: c
Depreciation is comprised of:
Depreciation
Depletion
$6,168,852,765
30,968,679
......i......................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp (2) A Resubmission 0410312008 2007/Q4
FOOTNOTE DATA
Total $6,199,821,44
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Blank Page
(Next Page is 204)
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 0403100
ELECTRI PLANT IN SERVICE (Account 101. 102, 103 an 106)
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Elecric Plant Unclassified; and Account 106, Completed Construction Not Classifed-Elecric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, includd by primary plant account, increases in column (c) additions and
redctions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indcae th negtie efect of such accunts.
6. Classif Account 106 accrding to presribed accounts, on an estimated bais if neary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prir ye reprted in comn (b). Ukewise, if the respondent has a significant amount
of plant retirements which have not been classified to primary accunt at th en of the yer, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the acunt for acumulated depreciation provision. Include also in column (d)
une Account ~No.la)Beinning of Year(b (c)
1 1. INTANGIBLE PLANT
2 301 Oraanization
3 (302 Frachises and Consents 118,267,763 50,028
4 11303 Miscellaneous Intangible Plant 559,380,026 17,245,176
5 TOTAL Intanoible Plant (Enter Total of lines 2, 3, and 4)6n,647,789 17,749,204
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 310) Lad and La Riohts 91,208,65 3,471,496
9 311) Structures an Improvements n9,197,667 14,484,117
10 312) Boiler Plant Eauipment 2,781,88,567 129,704,587
11 313 Enaines and Enaine-Driven Generators
12 314 Turbaenerator Unit 738,388,257 28,167,842
13 315 Accesorv Elecric Eauipment 332,567,245 2,80,658
14 316 Misc. Power Plant Eauipment 28,33,149 44,315
15 317) Asset Retirement Costs for Steam Production 30,882,673 6,46,093
16 TOTAL Steam Prouction Plant (Enter Total of lines 8 thru 15)4,782,461,214 185,550,108
17 B. Nuclear Producton Plant
18 320 Lad and Land Riahts
19 (321 Strutures and Improvements
20 322 Reactor Plant Eauipment
21 323) Turbaenerator Units
22 324) Accessorv Elecric Eauipment
23 325) Misc. Power Plant Eauipment
24 326) Aset Retirement Costs for Nuclear Prouction
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. Hvdraulic Production Plnt
27 330\ Land and Land Rights 19,596,718 97,661
28 331 Structures and Improvements 82,43,894 2,336,240
29 332 Reservoirs, Dams, and Waterways 286,079,56 8,829,245
30 333 Water Wheels, Turbines, and Generators 88,024,472 4,219~
31 334 Accessorv Electric Eauipment 41,597,094 3,071,144
32 335 Misc. Power Plant Eauipment 2,578,674 21,526
33 336) Roads. Railroads, and Briaes 13,657,854 242,05234(337) Asset Retirement Costs for Hvdraulic Production 6,467,411
35 TOTAL Hvdraulic Production Plant (Enter Total of lines 27 thru 34)540,438,6n 18,817,428
36 D. Other Prodion Plant
37 '340\ Land and Land Riahts 21,542,190 48038(341) Structures and Improvements 49,582,610 245,417
39 (342) Fuel Holders, Products, and Accssories 29,40,939
40 34) Prime Movers 54,929,902 585,327,485
41 34) Generators 125,337,407 -1,314,978
42 (345) Accessory Elecric Eauipment 34,100,365 903,67243(34) Misc. Power Plant Eauipment 3,720,805
44 (347) Asset Retirement Costs for Other Production 1,048,n5 488,314
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)'810,670,993 585,65,390
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)6,133,570,88 790,017,926
FERC FORM NO.1 (REV. 12-0)Page 204
............................................
............................................
Year/Period of Report
End of 2oo7/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/03/2008
ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. careful observance of the above instructions and the texts of Accounts 101 and 106 wil avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utilty plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Acount 102, state the propert purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed wih the Commission as required by the Uniform System of Accounts, give also dateRetirements Adjustments Transfers Balance at LineEnd liyear No.
Name of Respondent
PacifiCorp
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
2,423
1,102,068
47,798,637
10,902,120
-21 ,642,232
94,677,729
803,481,836
2,842,150,285
11,931,246
64,99
309,317
244,280
6,018,80
-2,561,449
754,869,133
34,742,715
25,907,698
26,574,784
4,888,40,180
1,832
1,027,632
14,157,968
1,695,322
1,289,075
39,031
66,154
1,321,994
19,599,008
166,538
-767,016
19,692,547
83,912,040
279,983,821
90,54,710
43,143,055
2,564,625
13,940,90
-236,108
3,456
107,152
4,287,062
27,169
62,662,763
-20,432,619
-234,566,780
99,362,90
80,869,716
2,94,081
21,542,670
112,490,790
8,976,320
892,403,545
223,358,160
115,873,753
6,66,886
1,303,579
1,382,613,703
6,80,803,585
4,314,231
85,705,924
-233,510
-233,510
-16,154,909
-9,159,939
-16,924,392
FERC FORM NO.1 (REV. 12-05)Page 205
Page
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) OA Resubmission 04/032008
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106) (Continued)
ine Account ~No.Beginning of Year
(a)b) (c)
47 3. TRANSMISSION PLANT
48 350 Land and Land Riahts 92,439,042 985,860
49 352 Structures and Improvements 55,260,234 1,574,793
50 353 Station Eauioment 96,334,561 62,435,219
51 354) Towers and Fixtures 381 ,378,303 53,145,900
52 355) Poles and Fixtures 511,002,983 23,556,843
53 356) Overhead Conducors and Devices 663,377,121 41,779,674
54 357) Underaround Conduit 3,277,188 615
55 358) Underground Conductors and Devics 7,274,658 90,85
56 359) Roads and Trals 11,494,522
57 359.1) Asset Retirement Costs for Trasmission Plat
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)2,68,838,612 183,569,758
59 4. DISTRIBUTION PLANT
60 1(360 Land and Land Riahts 44,64,34 1,123,743
61 1(361 Structures and Improvements 47,082,597 689,998
62 (362 Station Eauipment 647,283,612 43,091,471
63 363 Storaae Batterv Equipment 1,457,804
64 36 Poles, Towers, and Fixtures 809,956,00 40,417,072
65 36 Overhead Conductor and Devices 590,582,713 20,493,66
66 36 Underaround Conduit 257,642,017 12,947,842
67 (36 Underaround Couctors and Device 611 ,65,574 39,123,488
68 368 Line Trasformers 922,967,94 59,329,64
69 369 Services 46,770,713 40,324,721
70 370 Meters 189,416,286 22,360,645
71 (371 Installations on Customer Premises 8,869,255 48,733
72 372 Leaed Prooert on Customer Premises 49,658
73 373) Street Liahtina and Sianal SYStems 57,030,679 2,787,534
74 374) Aset Retirement Costs for Distribution Plant 225,168 149,235
75 TOTAL Distribuion Plat (Enter Total of lines 60 thru 74)4,652,629,372 282,887,782
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 380) Land an Land Riahts
78 381) Structures and Improvements
79 382) Computer Hardware
80 (383 Computer Softre
81 384 Communication Equipment
82 38 Miscellaneous Reaional Trasmission and Market Ooratin Plan
83 (386 Asset Retirement Costs for Regioal Tramision an Market Ooer
84 TOTAL Transmission and Market Operation Plant lTotalline 77 thru 83)
85 6. GENERAL PLANT
86 (389 Land and Land Riahts 15,030,303 291,125
87 !(390 Structures and Improvements 224,733,346 5,514,568
88 (391 Ofce Furniture and Eauipment 104,322,537 11,048,250
89 (392 TransoorttionEauipment 96,674,94 4,156,332
90 (393 Stores Eauioment 13,140,110 290,324
91 (394) Tools, Shop an Garaae Equipment 60,763,715 2,938,399
92 (395 Laboratorv Equipment 37,567,486 3,131,390
93 396 Power Ooerated Equipment 122,178,506 15,708,612
94 397 Communication Equipment 232,114,06 11,461,421
95 398 Miscellaneous Eauipment 5,387,332 417,212
96 SUBTOTAL (Enter Total of lines 86 thru 95)
97 399)Other Tanaible Propert
98 (399.1) Asset Retirement Cots for General Plant 42,454
99 TOTAL Genera Plant (Enter Total of lines 96, 97 and 98)1,164,415,86 71,731,727
100 TOTAL (Accounts 101 and 106)15,317,102,523 1 ,34,956,397
101 102) Electric Plant Purchased (See Instr. 8)
102 Less) (102) Elecric Plant Sold (See Instr. 8)
103 103, Exrimental Plant Unclassified
104 TOTAL Elecric Plant in Service (Enter Total of lines 100 thru 103)15,317,102,523 1,345,978,255
FERC FORM NO.1 (REV. 12-0)206
-...........................................
Year/Period of Report
End of 2oo7/Q4
Name of Respondent
PacifiCorp
Retirements
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/031008
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)Adjustments Transfers BalancE! at
End lg)Year
105,143
103,867
3,546,741
56,015
1,819,572
1,422,654
191
-4,734,194
7,013,837
7,047,446
88,585,565
63,744,997
1,029,270,485
434,468,188
532,740,254
703,734,651
3,2n,612
7,36,512
11,472,227
510
22,295
7,076,478 9,327,599 2,874,659,491
-510
-5,031
45,675,442
51,355,986
683,925,359
1,457,80
84,025,721
607,741,213
270,012,305
649,509,858
974,00,45
503,373,33
184,941 ,478
8,860,60
49,658
59,329,699
374,403
4,88,637,321
6,347,355
3,33,650
572,523
1,268,204
8,279,043
722,101
26,835,453
57,384
-14,087
488,514
37,486
3,452,512
19,080,807
4,626,589
71,854
1,206,651
737,004
15,860,420
5,249,729
120,230
50,44,282
28,748
-4,307
-808,794
94,696
46,250
225,311
264,183
2,747,310
246,580
2,799,9n
15,283,942
226,824,150
96,245,673
95,395,892
13,453,276
62,541,713
40,187,183
122,290,881
241,073,068
5,930,894
919,226,672
-2,706
-58,769
-16,213,678
2,699,206
-22,925
39,748
1,182,266,561
16,17,316,566
56,521,469
229,505,751
-21,858
229,505,751 -16,213,678 -22,925 16,417,338,424
FERC FORM NO.1 (REV. 12-0)Page 207
Line
No.
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76n
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
I$chedule Page: 204 Line No.: 97 Column:b
Balance at
Beginig
Account Decription of Yea Additions Retiments Adjustments Trasfers
(a)(b)(c)(d)(e)(t)
39921 LAND OWND IN FE $2,634,916 $$$$
39922 LAN RIGHTS 52,472,247 78,00
39930 STRUCTUS 37,328,227 2,341,876 69,266
39941 SURFAæ - PLAN EQUIPME 11,794,358 88,256
39944 SURACE - ELCTRIC POWER FACILITIE 3,181,747 242,828
39945 UNERGROUND - COAL MIN EQUIPMENT 55,358,227 7,780,011 4, 172,Ô96
39946 LONGW Al SHIS 17,699,562
39947 LONGW Al EQUIPMENT 10,786,602
39948 MAININ EXTNSION 15,253,657 2,593,869 1,319,06
39949 SECTON EXTENSION 3,290,467 645,388
39951 VEIDCLES 1,098,151 183,720 201,724 35,820
39952 HEAVY CONSTRUCTION EQUIPMENT 3,486,584 1,584,054 91,822 (136,591)3996 MISælLOUS GENERAL EQUIPME 2,114,401 336,436 217,418
39961 COMPUTRS - MAIAM 60,46 56,797 6,797
39970 MIN DEVEOPMENT AN ROAD EXTENSION 34,700,270 842,459
399915 Coa Mine ARO 661,188 (56.063)
TOTAL PLA USED IN MINING ACTIITS $252,461,068 $16,774,094 $6,078,187 $(56,063)$(100,771)
......i.
Balance at .
End ofYea .
)
$2,634,91
52,550,647
39,600,83.
11,882,611i
3,424,57_
58,966,14_
17,699,56_
10,786,60_
16,528,46_
3,935,85..
1,115,96
4,842,22_
2,233,41650,~
35,542,72~605,12.
$263,000,14Ti..i.i..i.I.i...................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
I$chedule Page: 204 Line No.: 97 Column: c
See footnote line 97, column b.
ISchedUle Page: 204 Line No.: 97 Column: d
See footnote line 97, column b.
!sChedule Page: 20 Line No.: 97 Column: e
See footnote line 97, colum b.
I$chedule Page: 204 Line No.: 97 Column: f
See footnote line 97, column b.
¡Shedule Page: 204 Line No.: 97 Column: g
See footnote line 97, column b.
¡Schedule Page: 204 Line No.: 102 Column: c
Refer to pages 108- 109 Importnt Chages During the Year.
I FERCFORM NO.1 (ED. 12-S7) Page 450.1
............................................
Blank Page
(Next Page is 214)
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
End of 2O7/Q4(2) FiA Resubmission 0403100
EL CTRIC PLANT HELD FOR FUTURE USE (Accnt 105)
1. Report separately each propert held for future use at end of the year having an original cost of $250,00 or more. Group other items of propert held
for future use.
2. For propert having an original cost of $250,00 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other required information, the date that utilty use of such property was discntinued, and the date the original cost was transferred to Account 105.
Une Descniition arncation ~No.Of Prolerty in is Account in tilty Service End of Year
(a (b) (cl (d)
1 Land and Rights:
2
3 Oquirrh Substation 205..2,245,898
4 North Hom Mountain Col Properties 19n 953,014
5 Barnes Bute Substation 2007 2009 746,26
6 White Rock Substation 2007 2009 505,024
7 Wild Horse Wind Plant 207 2010 6,863,094
8 Twelve Mile Wind Plant 2007 2010 2,058,839
9
10 Miscellaneous, each under $250,00 325,030
11
12
13
14
15
16
17
18
19
20
21 Oter Propert:
22
23
24
25
26
27 Miscellaneous, each under $250,00:
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Total 13,697,167
FEAC FORM NO.1 (ED. 12-96)Page 214
............................................
.............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE OAT A
I$chedule Page: 214 Line No.: 4 Column: c
The North Hom Mountan Coal Properties are needed to access future coal ports and federal coal reserves when existing East
Mountan coal mines are mined out.
¡Schedule Page: 214 Line No.: 10 Column: c
Various dates and plans.
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This~rtIS:Date of Report Year/Period of Reprt
PacifCorp (1) An Origina (Mo, Da, Yr)End of 2007/04
(2) EiA Resubmission 04/03208
CONSTRUCTION WORK IN PROGRESS - - EL8 TRIC (Accunt 107)
1. Report below descriptions and balances at end of year of proects in proces of construction (107)
2. Show items relating to "research, development, and demonstration" proiects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accunts)
3. Minor projects (5% of the Balance End of the Year for Accunt 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construction work in prQ9ress -
No.Elecric (Account 107)
(a)(b)
1 Intagible:
2 Klmath Relicensing 48,278,400
3 Yale Relicensing (Lewis River)13,54,949
4 Merwin Relicensing (Lewis River)10,384,818
5 Swi Relicensing (Lewis River)9,847,042
6 Propet 1, 2 & 4 Relicensing (Roge River)6,56,429
7
8 Prouction:
9 Goonoe Hils Wind Plant 168,750,742
10 Cholla Unit #4 -CAl Environmental Projes 115,431,568
11 Mango II Wind Plant 96,048,595
12 Seven Mile Hill Wind Plan 57,553,129
13 Glenrock Wind Plant 57,099,009
14 Rolling Hils Wind Plant 55,573,522
15 Nort Umpqua Relicensing Impleenti 14,767,43
16 Huntington Water Effciency Magemen 10,248,167
17 Copc 2 Elecrial Overhaul 7,369,007
18 Lewis River Relicensing Implemention 7,339,997
19 Dave Johnston Unit #4 - Boiler/Turbine Cotrols 4,815,791
20 Cutler #2 Runner 3,99,917
21 Cholla - Coal Unloading & Handing 2,323,44
22 ChollR - 135 Car Rail Sidng 1,712,449
23 Hermiston Purchase 1 st & 2nd Stage Buckets 1,464,829
24 Cholla Unit #4 - Exciter & AVR Replacement 1,44,087
25 Cholla Unit #4 - Economizer Replacement 1,175,317
26 Hydro Faclities Fall Protecion 1,052,808
27 Carn - Fly Ash Handling System 1,04,822
28
29 Transmission:
30 Three Mile Knoll - New 345-138kV Substation 19,266,598
31 Line 1 Convert to 115kV, Line 14 Cap Relief 11,745,674
32 Populus-Terminal: Dbl Ckt 345 kV Transmission Line 11,262,090
33 Herrman Purch Sub Prop & Trans ROW 3,400,216
34 Craner Flat Substation - Install 138 kV 2,802,868
35 Copco 2 Install 230/115 Transformer & Breaker 2,171,271
36 Path 18 Reliability Improements 2,436,32
37 Transmission Relay Replacement Zone 3 Setting 1,90,622
38 Mona-Oquirr Line 1,714,504
39 Yakima Transmission ROW Renewal Project 1,424,987
40 Shute Creek to Mona System Upgrade 1,338,071
41 Copco II Sub Repl Exist 115-69kV Transformer 1,205,268
42 Line 37 Conv to 115kV Bid Nickel Mt Substation 1,072,94
43 TOTAL 941,818,176
.
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 2007/04
(2) ñA Resubmission 04/03/2008
CONSTRUCTION WORK IN PROGRESS - . ELE TRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor proiects (5% of the Balance End of the Year for Accont 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Accont 107)
(a)(b)
1 Upper Green River Basin -
2 Jonah Field & Paradise SubsLines 1,069,167
3
4 Distribution:
5 Yew Avenue. Constuct New Substation (Tetherow)5,953,979
6 Elk Hom Install 115-12.5kV Two Fdr Substation 5,527,744
7 Wastch Front Automated Meter Reading 4,154,846
8 Cozyle Build New 138-12.5kV Subsation 3,714,847
9 Pleasant Grove Sub Cov to 138kV 2,979,550
10 Campbel Sub Increase Capacit 2,938,65
11 Cedr Indust Pk New 138-12.5kV Substation Site 1,30,077
12 Jumbers Point New 138-12.5kV Substation Site 1,170,198
13
14 General:
15 Mobile Radio Replacement Projec 6,94,084
16 IVRAAR Agent Access Rtr 3,402,849
17 IP Telephony Project 1,770,745
18 Jim Bridger - Replacement RAS MB Scheme Projec 1,64,766
19 Deer Cree -Roof Bolter 1,158,181
20
137,913,30
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43 TOTAL 941,818,776
FERC FORM NO.1 (ED. 12-87)Page 216.1
......
!Schedule Page: 216.1 Line No.: 21 Column: a I .
A $1,00,000 reportng theshold was approved for PacifiCorp effective with the 1993 reportng year by the Chief Accountant, Federal .
Regulatory Commssion in a letter to the company dated August 5,1993, Docket No. AC93-181-oo0. .................................
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 04/0312008 2007/Q4
FOOTNOTE DATA
............................................
Blank Page
(Next Page is 219)
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 040300
ACCUMULATED PROVI ION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable 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 depreation accunting.
Year/Period of Report
End of 2oo7/Q4
ne
No.
em
(a)
1 Baance Beginning of Year
2 Depreciation Provisions for Year, Charged to
(40) Depreciation Expense
(403.1) Depreciation Expense for Asset
Retirement Costs
449,354,224 449,35,224~-~-
200,410,311
44,136,30
9,429,174
235,117,44
200,410,311
44,136,
9,429,174
235,117,
6,199,821,44 6,199,821,44
Secion B. Balance at End of Year Acrding to Functional Claificion
2,46,739,015 2,469,739,015Steam Prouction
21 Nuclear Prouction
22 Hydraulic Production-Conventional
23 Hydraulic Production-Pumped Storage
24 Other Prouction
231,109,912
105,487,03
1,On,851,432
1 ,84,588,160
25 Transmission
26 Distribution
2 Regional Transmission and Market Operation
2 General
29 TOTAL (Enter Total of lines 20 thru 28)
471 ,045,889
6,199,821 ,44
FERC FORM NO.1 (REV. 12-05)Page 219
............................................
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
FOOTNOTE DATA
¡Schedule Page: 219 Line No.: 4 Column: b
PacifiCo records the depreciation expense of asset retirement obli ations as either a re
chedule Pa e: 219 Line No.: 8 Column: b
Depreciation of mining assets included in account 151 Fuel Stock
Account 143.3 Joint Owner Receivable - Depreciation expense biled to Joint Owners
Account 182.3 Other Regulatory Assets
Vehicle Depreciation allocated to O&M based on usage activity
Account 503.1 Blundell Depletion
Account 503 IGC Depreciation and Amortzation
Total Other Accounts
asset or (liabil ).
$ 13,939,854
266,558
2,505,420
12,494,116
640,038
1,011,394
$ 30,857,380
¡Schediiie Page: 219 Line No.: 16 Column: b
Oter items including:
-Recovery from thd pares for asset relocations and damaged propert
-Insurance recoveries
-Adjustments of reserve related to electrc plant sold
-Reclassifications from electric plant
$ 40,014,183
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Page 224
............................................
Name of Respondent This 7!rt Is:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)
End of 2007/Q4(2) FiA Resubmission 04/031008
INVESTM NTS IN SUBSIDIARY COMPANIES (Account 123.1)
1. Report below investments in Acounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and Ust there under the information calle for below. Sub - TOTAL by company and give a TOTAL in
columns (e) ,(f) ,(g) and (h)
(a) Investment in Securities - List and describe each securi owne. For bonds give also principa amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advanes which are subiec to repayment, but which are not subject to
current settlement. With respe to each advance show whether the advane is a note or open account. List each note giving date of issuance, maturity
date, and specifyng whether note is a renewaL.
3. Report separately the equity in undistributed subsidiary eamings since acquisiton. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
Une Descnptiön of Investment Date Acquired Date Of Amount of Investment at
No.(a)(b)
M~:frity Beginning of Year
(d)
1 PACIFIC MINERALS, INC 12/31/1991
2 Common Stock 1
3 Capital Contributions 14,160,000
4 Undistributed Eamings 86,602,065
5 SUBTOTAL 100,762,06
6
7 PACIFICORP ENVIRONMENTAL REMEDIATION COMPANY 8119/199
8 Common Stock 90,00
9 Capital Contributions 5,608,526
10 Acquisition of Minority Interest
11 Undistributed Subsidiary Eamings 5,851,021
12 SUBTOTAL 12,359,547
13
14 PACIFIC FUTURE GENERATIONS, INC -9119/1999
15 Undistriuted Subsidary Eaming -9,627
16 SUBTOTAL -9,627
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 IITotal Cot of Account 123.1 $48,036,5141 TOTAL 113,111,98
FERC FORM NO. 1 (ED. 12-89)
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
End of 2007/04(2) riA Resubmission 04/03/2008
INVESTMENT IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
4. For any securiies, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpse of the pledge.
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the yer.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the diference between cost of the investment (or
the other amount at which carred in the books of account if diference from cost) and the sellng price thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Acunt 123.1
Equity in Subsidiary Hevenues tor Year Amount or investment at üain or LOSS trom Investment LineEamin~i;)f Year
(f)
End lg)Year DiS'1fied of No.
1
1 2
3
93,410,979 4
6,808,914 125,870,980 5
6
7
90,00 8
9
956,888 10
1,716,475 7,567,496 11
1,716,475 23,144,009 12
13
14
-325 -9,952 15
-325 -9,952 16
17
18
19
20
21
22
23
24
25
26
Zl
28
29
30
31
32
33
34
35
36
37
38
39
40
41
8,525,06 149,00,037 42
FERC FORM NO.1 (ED. 12-8)Page 225
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
......i -........-.....-...........-..........
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
I$chedule Page: 224 Line No.: 3 Column: g
Reflects $18,300,000 ca ita1 contrbution from parent com an in 2007.
hedule Pa e: 224 Line No.: 4 Column: e
Equity earngs from Pacific Minerals, Inc. (PMI) consist of inter-company profit on coal to PacifiCorp from Bridger Coal Company,
that PMIjointly owns with Idao Power Company, and are not recorded in account 418.1, Equity in Eaings of Subsidiar
Companies. PacifiCorp records PMI's earngs before interest and taes as an offset to fuel expense, and records interest and taes to
their respective line items.
¡Schedule Page: 224 Line No.: 9 Column: g
Reflects $8,111,099 of deferred ta assets assumed from parnt company in 2007.
............................................
Blank Page
(Next Page is 227)
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) An Origina (Mo, Da, Yr)2oo7/Q4(2)DA Resubmission 04038 End of
MATERIALS AND SUPPLIES
1. For Accunt 154, report the amount of plant materials and operating supplies under the primary functional classifcatio as indicated in coumn (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affeced debied or credited. Show separately debit or credits to stores expese
clearing, if applicale.
Une Acunt Bace Balance Department or
No.Benning of Year End of Year Departments which
Use Material(a)(b)(c)(d)
1 Fuel saock (Accnt 151)82,230,862 98,334,182 Electric
2 Fuel Stock Expenses Undistributed (Accunt 152)
3 Residuals and Exracted Products (Account 153)
4 Plant Materials an Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)48,572,876 53,387,313 Elecric
6 Asigned to - Operations and Mantenace
7 Producion Plant (Estimated)64,63,918 74,067,221 Electric
8 Transmission Plant (Estimated 4,250,120 6,228,512 Electric
9 Distribuion Plant (Estimated)8,33,981 11,90,581 Electric
10 Regionl Transmissio an Market Operatin Plant
(Estimated
11 Asgned to - Other (proide deils in footne)Elecri
12 TOTAL Account 154 (Enter Total of lines 5 thru 11)129,731,86 150,050,022
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15 Nucler Materials Held for Sale (Accnt 157) (Not
applic to Gas Uti!)
16 Stores Expense Undistributed (Acnt 163)
17
18
19
20 TOTAL Materials and Supplies (Per Bance Sheet)211,96,728 248,384,20
FERC FORM NO.1 (REV. 12-()Page 227
............................................
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
¡Schedule Page: 227
MiningM&S
General Plant M&S
Line No.: 11
$3,408,500
532,471
$3,940,971
Line No.: 11
$4,314,408
145,987
$4,460,395
Column:b
fschedule Page: 227
MiningM&S
General Plant M&S
Column:c
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 0403008
Alloances (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 allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General
Instruction No. 21 in the Uniform System of Accounts.
4. Report the allowances transactions by the period they are first eligible for use: the current year's allowances in columns (b)-(c),
allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining
succeeding years in columns (j-(k).
5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.Line Allowances Inventory 200
No. (Account 158.1)
(a)
1 Balance-Beginning of Year
2
3
4
5
6
7
8 PurchasesIransfers:
9
10
11
12
13
14
15 Total
16
17
18
19
20
21
22
23
24
25
26
27
28 Total
29 Balance-End of Year
30
31
32
33
34
35
Year/Period of Report
End of 20710
Acquired During Year:
Issued (Less Withheld Allow)
Returned by EPA
Relinquished During Year:
Charges to Account 509
Other:
Cost of SalesIransfers:
Saracen Energy
Louis Dreyfs
Alpha Energy
Fortis Energy
Dte Coa Servs
Sales:
Net Sales Proceeds(Assoc. Co.)
Net Sales Procs (Other)
Gains
Losses
Allowances Witheld (Acct 158.2)
36 Balance-Beginning of Year
37 Add: Withheld by EPA
38 Deduc: Returned by EPA
39 Cost of Sales
40 Balane-End of Year
41
42
43
44
45
46
Sales:
Net Sales Proceed (Assoc. Co.)
Net Sales Procee (Other)
Gains
Losses
FERC FORM NO.1 (ED. 12-95)Page 228
............................................
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmission 04/03/2008
Allowances (Accounts 158.1 and 158.2) (Continued)
6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA's sales of the withheld allowances. Report on Lines
43-46 the net sales proceeds and gains/losses resulting from the EPA's sale or auction of the withheld allowances.
7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated
company" under "Definitions" in the Uniform System of Accounts).
8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies.
9. Report the net costs and benefits of hedging transactions on a separate line under purchasesltransfers and saleslransfers.
10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
Year/Penod of Report
2007/04End of
Amt.
(i)
Future YearsNo. Amt.ü) (k)
4,03,432.00
Une
No.
FERC FORM NO.1 (ED. 12-95)Page 229
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 0403
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
Line Description of Unrecovered Plant rotal Costs WRITTEN OFF DURING YEAR Balane at No.and Regulatory Study Costs (Include Amount Recognisedin the description of costs, the date of of Charges During Year Account Amount End of Year Commission Authorization to use Ace 182.2 Charged
and period of amortization (mo, yr to mo, yr))
(a)(b)(c)(d)(e)(f)
21 Unrecovere Plant: Trojan Nuclear 6,839,022 407 1,672,435 5,149,185
22 Plant located near Portland, OR
23 Date of Retirement: 12/31/1992
24 Date of Commission Authorization:
25 04/20/1993
26 Amortization Period: 01/1993
27 hrough 01/2011
28
29 Unrecvered Plant: Powerdale
30 Hydro Elecri Plant 11,220,011 407 780,12ì 10,439,884
31 Date of Retirement: 02/0812007
32 Date of Commission Auhorization:
33 PSl14/207
34 ~mortization Peri: 05007
35 hrough 12/2010
36
37
38
39
40
41
42
43
44
45
46
47
48
49 TOTAL 6,839,02 11,202,60 2,452,562 15,589,069
FERC FORM NO. 1 (ED. 12-8)Page 23b
............................................
-...........................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
!Schedule Page: 230 Line No.: 21 Column: c
Represents the sale of a porton of the Trojan plant switchyard assets.
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
This ~rt Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/0312008
Transmission Service an Generation Interconnection Study Cots
1. Report the particulars (details) called for conceming the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. In column (a) provide the name of the study.
4. In column (b) report the cost incurred to perform the study at the end of period.
5. In column (c) report the accunt charged with the cost of the study.
6. In column (d) report the amounts received for reimbursement of the study cos at end of period.
7. In column (e) report the account credited with the reimbursement recived for performing the study.
ine
No.Description
(a)
Transmission Studies
Costs Incurred DuringPerid
(b)
Account Charged
(c)
eim ursementsReceived During
the Period
(d)
Accunt Credited
With Reimbursement
(e)
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2007/04
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17 Aref 417614,417702
18 Aref421625,421626
19 Are 417581
20 Aref 421623, 421624
21 Generation Studies
22 GI00053
23 Gl000
24 GIOO63, GIQ0
25 GlOO71
26 GI00074
27
28 GI00081
29 Gl001
30 G1003, GI0006
31 GIOoo90
32 GlOO59
33 GIOOO
34 GIOO80
35 GlQ0093
36 GI00071
37 GI00092
38 GIOO94
39 GIOOO95
40 Gl008
Aref 235776, 256959, 34975
Aref 314945
Aref367339
Aref401968
Aref404233
Aref404235
Aref 412890, 413567, 413571
Aref412893
39 561.6
53,813 561.6
3,137 561.6
66 561.6
471 561.6
471 561.6
461 561.6
358 561.6
422 561.6
10 561.6
525 561.6
10 561.6
510 561.6
1,151 561.6
852 561.6
8 561.6
439 561.6
439 561.6
439 561.6
39 456.2
59,90 456.2
3,137 456.2
66 456.2
471 456.2
471 45.2
461 456.2
358 456.2
422 456.2
10 456.2
525 456.2
10 456.2
510 456.2
1,151 456.2
268 456.2
8 456.2
439 456.2
439 456.2
439 456.2--
1,299) 561.7
1,286 561.7
428 561.7
169) 561.7
1,252 561.7
3,33 561.7
561.7
2,223 561.7
1,661 561.7
16,531 561.7
47,651 561.7
4,46 561.7
16,054 561.7
2,181 561.7
332 561.7
1,956 561.7
8,142 561.7
26,011 561.7
1,584) 561.7
1,299) 456.2
1,286 45.2
428 456.2
169) 456.2
1,252 456.2
3,730 456.2
88 456.2
5,597 456.2
21,884 456.2
16,584 456.2
57,356 456.2
19,417 456.2
16,464 456.2
2,586 456.2
636 456.2
2,376 45.2
8,195 456.2
26,06 456.2
1,260) 456.2
FERC FORM NO. 1I.FI3-Q (NEW. 03-67)Page 231
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2007/Q4
This ~rt Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 0410312008
Transmission Service and Generation Interconnection Study Costs (continued)
ine
No.
eim ursements
Received Duringthe Peri
(d)
Account Credited
With Reimbursement
(e)
Costs Incurred During
Period
(b)
Description
(a)
Transmission Studies
Accunt Charged
(c)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15 Aref 421618,421619,421620
16 IRP
17 Aref 291675, 292491 , 292494
18 Aref 317351
19 Aref 301557
20 Aref 30176
21 Generation Studies
22 GIQoo96
23 GIQ0097
24 GlQO99
25 GIQ0100
26 GIQ0101
27 GIQ0089
28 GIQ0102
29 GlQO73
30 GlOO108
31 GIQ0109
32 GlOO110
33 GIQ0071
34 GlQ0115
35 GIQ0111
36 GIQ0116
37 GIQ0112
38 GIQ0113
39 GIQ0114
40 GIQ0119
Aref421599
Aref 421621,421622
Aref 421615, 421616, 421617
Aref417622
Aref 421618,421619,421620
439 561.6
439 561.6
439 561.6
459 561.6
439 561.6
482 561.6
482 561.6
121 561.6
82 561.6
82 561.6
86 561.6
20 561.6
680 561.6
19 561.6
4,450 561.6
73,869 561.6
113,745 561.6
91,721 561.6
110,797 561.6
439 456.2
439 456.2
439 456.2
459 456.2
439 45.2
482 456.2
482 456.2
121 456.2
82 4562
82 456.2
86 456.2
20 456.2
680 456.2
19 45.2
--
40,64 561.7
3,458 561.7
3,09 561.7
7,20 561.7
4,659 561.7
22,521 561.7
2,94 561.7
22,110 561.7
2,415 561.7
2,131 561.7
6,070 561.7
37,343 561.7
8,673 561.7
1,763 561.7
500 561.7
26,771 561.7
4,512 561.7
62 561.7
7,457 561.7
40,696 456.2
3,530 456.2
4,894 456.2
7,755 456.2
5,116 456.2
22,826 45.2
3,694 4562
25,201 456.2
2,486 456.2
2,184 456.2
6,158 456.2
37,413 456.2
8,673 456.2
1,851 456.2
50 456.2
26,874 45.2
4,512 456.2
62 456.2
7,457 456.2
FERC FORM NO. 1N-FI3-Q (NEW. 03-07)Page 231.1
ine
No.Description
(a)
1 Transmission Studies
2 Aref 345779
3 Aref 371619
4 Aref 374355
5 Aref 378464
6 Aref 381927
7 Aref 379612
8 Aref 38428
9 Aref 384190
10 Aref 38329
11 TCA
12 Aref 39373
13 Aref 39655
14 Aref 381927
15 Aref 384190
16 Aref 384328
17 Are 384329
18 Aref 412872
19 Aref 414741
20 Aref 384190
21 Generaion Studies
22 GlQ0117
23 GI00120
24 GIOO90
25 GI00121
26 GlOO92
27 GI0000
28 GI0007
29 GI00127
30 GlQ0128
31 GlOO89
32 GIOOO
33 GI00129
34 GIOO
35 GI00100
36 GI00130
37 GlOO82
38 GI00102
39 GI00101
40 GIOO96
Cots Incurred DuringPeno
(b)
Accunt Charged
(c)
eim ursementsReceived During
the Period
(d)
Accunt Credited
With Reimbursement
(e)
............................................
Name of Respondent
PacifCorp
This ~rt Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 040312008
Transmission Service and Generation Interconnecion Study Cots
Year/Period of Report
End of 2007/04
(continued)
22,398 561.6
412 561.6
721 561.6
105 561.6
9,48 561.6
10,28 561.6
5,66 561.6
5,355 561.6
5,43 561.6
1,648 561.6
2,60 561.6
6,491 561.6
2,299 561.6
2,58 561.6
2,249 561.6
5,523 561.6
1,09 561.6
488 561.6
536 561.6
24,566 561.7
3,681 561.7
50,825 561.7
3,614 561.7
4,556 561.7
14,801 561.7
13,624 561.7
3,387 561.7
6,661 561.7
15,210 561.7
7,63 561.7
5,798 561.7
18,695 561.7
45,34 561.7
2,862 561.7
16,002 561.7
22,401 561.7
3,552 561.7
13,747 561.7
24,566 456.2
3,681 456.2
50,825 456.2
3,614 456.2
4,556 456.2
14,801 456.2
13,624 456.2
3,387 456.2
6,661 456.2
15,210 456.2
7,63 456.2
5,798 456.2
18,695 456.2
45,34 456.2
2,862 456.2
16,002 456.2
22,401 456.2
3,552 456.2
13,747 456.2
FERC FORM NO. 1/1-FI3-Q (NEW. 03-07)Page 231.2
-...........................................
Name of Respondent
PacifiCorp
This F30rt Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/03/2008
Transmission Servce and Generation Interconnection Study Costs
Year/Period of Report
End of 2007/04
(continued)
ine
No.
eim ursementsReceived During
the Period
(d)
Costs Incurred During
Period
(b)
Account Credited
With Reimbursement
(e)
Description
(a)
1 Transmission Studies
2 Aref 38428
3 Aref 428071
4 Aref 428070
5 Aref 41645
6 Aref 34778
7 Aref 36367
8 Aref 36231
9 Customer Stuies Accruals
10 Aref 313369
11 Aref 301356,301357
12 Aref 3942
13 Aref 394947
14 Aref 394952
15 Aref 40007
16 Aref 40817
17 Aref 402411
18 Aref 422102
19 Aref 425384
20 Aref 41645
21 Generation Studies
22 Gl005
23 Gi00132
24 G100134
25 G100135
26 GI00138
27 GI00139
28 Gi00140
29 Gi00141
30 GI00119
31 GI00142
32 Gi00143
33 GI00144
34 Gi00149
35 Gi00151
36 GI00145
37 GI00148
38 Gi00149
39 G100136
40 GI00137
Accunt Charged
(c)
676 561.6
268 561.6
268 561.6
680 561.6
26,598 561.6
1,217 561.6
16,544 561.6
451) 561.6
49,092 107
57,420 107
814 107
64 107
2,682 107
132 107
59 107
2,356 107
337 107
70 107
20 107 -
20,357 561.7
22,355 561.7
22,715 561.7
4,819 561.7
5,476 561.7
11,323 561.7
948 561.7
5,368 561.7
20,747 561.7
2,961 561.7
1,158 561.7
5,879 561.7
913 561.7
4,087 561.7
3,517 561.7
6,34 561.7
2,034 561.7
1,556 561.7
1,394 561.7
20,357 456.2
22,355 456.2
22,715 456.2
4,819 45.2
5,476 456.2
11,323 456.2
948 456.2
5,368 456.2
20,747 456.2
2,961 456.2
1,158 456.2
5,879 456.2
913 456.2
4,087 456.2
3,517 456.2
6,343 456.2
2,034 456.2
1,556 456.2
1,394 456.2
FERC FORM NO. 1/1-FI3Q (NEW. 03-07)Page 231.3
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/020
Transmission Service and Generation Interconnecio Study Costs
Year/Period of Report
End of 2oo7/Q4 ............................................
(continued)
ne
No.Desripton
(a)
1 Transmission Studies
2 Aref 432138
3 Aref 432141
4 Aref 432805
5 Aref 4390
6 Aref 442184
7 Aref 44572
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
22
23
24
25
26
27
28
29 GlQ0161
30 GIQ0100
31 GIQ0129
32 GIQ0162
33 GIQ0163
34 GIQ0164
35 GIQ0165
36 GIQ0112
37 GIQ0139
38 GIQ0166
39 GlQ0167
40 GIQ0168
Costs Incurred DuringPeri Acunt Charged(b) (c)
eim ursementsReceived Duringthe Pério
(d)
Account Credited
With Reimbursement
(e)
80 107
80 107
2,080 107
20 107
20 107
20 107
GIQ0152
GIQ0153
GIQ0154
GIQ0155
GIQ0117
GIQ0128
1,938 561.7
2,391 561.7
2,747 561.7
2,68 561.7
14,122 561.7
7,358 561.7
14,827 561.7
1,388 561.7
22,439 561.7
8,474 561.7
96 561.7
30 561.7
55 561.7
618 561.7
6,176 561.7
7,54 561.7
1,462 561.7
992 561.7
394 561.7
1,938 456.2
2,391 456.2
2,747 456.2
2,684 456.2
14,122 456.2
7,358 45.2
14,827 456.2
1,388 456.2
22,439 456.2
8,474 456.2
96 456.2
304 456.2
554 456.2
618 456.2
6,176 456.2
7,540 456.2
1,462 456.2
992 456.2
394 456.2
FERC FORM NO. 1/1.FI3Q (NEW. 03-7)Page 231.4
............................................
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/03/2008
Transmission Service and Generation Interconnecion Study Costs
Year/Period of Report
End of 2007/04
(continued)
ine
No.
eim ursements
Received During
the Period
(d)
Accont CreditedWith Reimbursment
(e)
Costs Incurred During
Period
(b)
Description
(a)
Transmission Studies
Account Charged
(c)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 GIQ0141
23 GlQ03
24 GIQ0132
25 GlQ0169
26 GIQ0170
27 GIQ0171
28 GIQ0119
29 GlQ0172
30 GIQ0173
31 GIQ0138
32 GIQ0174
33 GIQ0175
34 GIQ0130
35 GIQ0135
36 GIQ0136
37 GIQ0137
38 Customer Studies Acruals
39 Aref 316762
40 Aref 316764
4,745 561.7
264 561.7
1,426 561.7
127 561.7
127 561.7
395 561.7
942 561.7
590 561.7
127 561.7
165 561.7
273 561.7
75 561.7
155 561.7
409 561.7
285 561.7
285 561.7
5,80 561.7
608 561.7
152 561.7
4,745 456.2
264 45.2
1,426 456.2
127 456.2
127 456.2
395 45.2
942 456.2
590 456.2
127 456.2
165 456.2
273 456.2
75 45.2
155 456.2
409 456.2
285 456.2
285 456.2
5,80 45.2
FERC FORM NO. 1N.FI3-Q (NEW. 037)Page 231.5
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/0320
Transmission Service and Generation Interconnection Stud Cots
Year/Period of Report
End of 2007/04 ............................................
(continued)
ine
No.Description
(a)
Transmission Studies
Costs Incurred DuringPeriod A~oom C~~ed(b) (c)
eim ursements
Received During
th Period
(d)
Account 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 Generation Studies
22 Aref 316762
23 Aref 316260
24 Aref 316764
25 GI00107
26 GlOO75
27 GI00122
28 GI00123
29 GI00124
30 GlQ0125
31 GI00126
32 GI00131
33 GIQ0122
34 GI00131
35 Aref 431343
36 Aref 431345
37 Aref431347
38 Aref 431348
39 Aref 431350
40 GI00126
4,03 561.7
647 561.7
7,631 561.7
4,712 561.7
607 561.7
19,375 561.7
3,936 561.7
5,189 561.7
13,254 561.7
19,409 561.7
721 561.7
3,509 561.7
5,651 561.7
46 107
46 107
46 107
46 107
112 107
2,931 107
FERC FORM NO. 1I-FI3-Q (NEW. 03-7)Page 231.6
............................................
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 04/0312008 2007/Q4
FOOTNOTE DATA
!Schedule Page: 231 Line No.: 10 Column: a
Transmission Studies: Aref 412896,412899,412890,412905,412908
lSchedule Page: 231 Line No.: 15 Column: a
Transmission Studies: Aref 417712,417714,417716,417718
!Schedule Page: 231 Line No.: 16 Column: a
Transmission Studies: Aref 417471,417474,417476,417478,417480
¡Schedule Page: 231 Line No.: 27 Column: a
Labor, e ui ment and admnistration fees associated with h dro ro.ect in Idao Falls, Idaho.
chedule Pa e: 231.1 Line No.: 7 Column: a
Transmission Studies: Aref 424565,424568,424571,424573,424576
lSchedule Page: 231.1 Line No.: 12 Column: a
Transmission Studies: Aref 412890,412896,412899,412902,412905,413567,413571, 413576, 413580, 412911
!Schedule Page: 231.1 Line No.: 14 Column: a
Transmission Studies: Aref 417471,417474,417476,417478,417480
ISchedule Page: 231.4 Line No.: 28 Column: a
Generation Studies: GIQ0102, GIQOI03, GIQOI04, GIQOI05, GIQOI06
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
FERC FORM NO. 113-Q (REV. 02-()Page 232
............................................
Name of Respondent This~rtIS:Date of Report YearlPerid of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 0403/
o HER REGULATORY 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 Purpe of Baance at Debits CREDITS Balance at end ofNo.Other Regulatory Asets Beinning of wnten ot uunng wntten on uunng Current OuarterlYearCurrthe QuarerlY ear the Peri
QuarterlY ear Accunt Chargd Amount
(a)(b)(c)(d)(e)(1)
1 Califrnia oSM Regatory Asset (221,524)215,72 908 242,935 -248,987
2 Idao OSM Reglatory Aset 5,25,937 2.131,64 90 3,135,82 4,251,758
3 Uth OSM Regulatorv Ast 69,991 25,599,94 431,908 26,693,091 -4,156
4 Washington oSM Regultory As (1,791,744)5.38,987 431,90 4,892.918 -1,09,67
5 Wyoming oSM Reglator As (10)32.05 26,2 90 72,852 282,627
6 oSM Reguor As- Acruals 2,763,51 921,915 3,68,456
7 Calif. Altere Rate For Ene (CARE)1,38,73 1.87.781 142 1,35,2 1,742,22
8 Transion Plan - OR (10)13.94,471 93.2 3,69,29 10,05,172
9 FAS 109 Deferrd Incoe Taxes Electric 46,097,2 282 5.551,77 45,54,491
10 SB 1149 Impementation Co OR Retail Ac (5)11,55,285 1,811,58 407.3 8,876,169 4,493,68
11 Energy Trust of Oregon SB1149 1.111 143 1,111
12 RetaH Acc Pro Inc. (Various)1.156,535 251.5'-1,40.058
13 10AI Cos No. CA Direc Acce (5)63,451 407.3 33,105 305,346
14 Scl 781 Dire Acc Shopng Inceve 899,28 55,92 407.3 932.713 520,471
15 98 Eany Retireent OR (4)3,676,94 93.2 3,676,946
16 Glnroc Mine Exduding Reclamation UT (9)3,731,2 93.2 1,302,39 2,428,823
17 Derred Exce Net Power Co - OR UE116 137,716 12,091 149,807
18 Deferred Exce Net Powe Co - WY (1)2,5,00 123,53 55 1.79.921 880,619
19 Deferred Exce Net Power Co - CA 75,2 758,296
20 Deerr Exce Ne Power Cos - WY 207 29.108.115 29,108,115
21 OR SB 40 Recery (1)2,305.39 108,66'-2,21.005 213,053
22 Enviromental Co (10)6,04,016 2.141,79 925 1,131,27 7,05,54
23 Enviromeal Cos - WA (10)(35,215)56,507 925 158,98 -453,691
24 Reg As - Enviromeal Cos 8,08,491 1,230,36 253 7,748.89 1,561,958
25 Cholla Plant Transction Co (26)11,878,997 557 1,12242 10,756,572
26 Cholla Plant Transacton Costs - OR (26)(56,52)53,813 -515,709
27 Chla Plant Tracton Co - WA (26)(1.02,64)97.00 -92,643
28 Cholla Plant Transacton Co - 10 (26)(34)3297 -315,99
29 Washington Colstrip #3 (22)73.011 45 52,188 682,823
30 FAS 133 Derivatie Net Reglatory As 22.87,188 26,186,802 25,023,nO
31 FAS 87/8 Penon UT (7 3,159,014 930.2 3,159,014
32 Ast Retreent Obligations Regulatory Dierce 54,860,93 20,2,50 23 22,244,031 52,853,403
33 FAS 158 PensionOter Post Ret.lSERP 56,929,191 12,38,1~35.060,40 22,252,933
34 RTO Grid West NIR Reg Aset 1.131,721 1,131,721
35 Cora Re Aset - RTO Grid Wes (1,131,721)-1,131,721
36 RTO Grid West NI - OR 810,23 88,64 878,879
37 RTO Grid West NlR . WY 414,098 414,09
38 RTO Gri Wes NlR - 10 (5)135,811 90 27,162 108,64
39 Deferred UT Indpent Evaluator Fee 30,511 30,511
40 Deferr Intervenr Fundng Grant (1)861,53 28,92 928.2 555,48 592,973
41 200 Transion Plan - WA (3)1.98,160 920 35,43 1,62,72
42 BPA Washington Balancing Account 1,942,28 1,942,28
43 BPA Oreon Balancing Accunt 29,678 292,678
44 TOTAL 1,395,66,386 140,832,88 45,753,48 1,081,739,789
-...........................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Me, Da, Yr)End of 2007/04
(2) DA Resubmission 04/031200
0 HER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for conc~rning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $50,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balanc at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beinning of wnnen on uunng wrien on uunng Curret Quarterl ear
Curret the QuarterNear th Period
QuarterNear Accont Chargd Amount
(a)(b)(c)(d)(e)(f)
1 BPA Idaho Balancing Acnt 1,33.440 1,33,44
2 200 Transitn Plan. 10 (3)1,83,58 1,83,583
3 OR RCAC 1,63,653 1,63,653
4 Regulatory Asts. Relass 2,09.83 48,60
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 TOTAL 1,395,66,38 140,83,88 454,753,48 1,081,739,789
FERC FORM NO. 1I3Q(REV. 02-94)Page 232.1
$ 248,987
1,095,675
400,156
......
i ·.i.....I...............................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2i An Original (Mo, Da, Yr)PacifiCorp (2) A Resubmission 04/03/2008 2007/Q4
FOOTNOTE DATA
!Schedule Page: 232 Line No.: 12 Column: d
Account 182.3
Account 407.3
¡Schedule Page: 232 Line No.: 21 Column: d
Account 440
Account 442
Account 44
!Schedule Page: 232 Line No.: 33 Column: d
Account 228
V arous Labor Accounts
!ßchedule Page: 232.1 Line No.: 4 Column: f
The following is a reconcilation of th regulatory asset reclassification account:
Reclassified from Regulatory Assets to Regulatory Liabilties:
Caifornia DSM Regulatory Asset
Washington DSM Regulatory Asset
Uta DSM Regulatory Asset
YTD
December 31, 2007
Reclassified from Regulatory Liabilties to Regulatory Assets:
Washington Low Income Program
Regulatory Liabilty Oregon Consolidated
41,964
352,450
$ 2,139,232
IFERC FORM NO.1 (ED.12-S7) Page 450.1
............................................
Blank Page
(Next Page is 233)
FERC FORM NO.1 (ED. 12-94)Page 233
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) An Original (Me, Da, Yr)End of 2007/04
(2) FiA Resubmission 04208
MISCELLANEOUS 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.
Une Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beinning of Year ~unt:Amnt End of Year
(a)(b)(c)C~
(e)(f)
1 Joseoh Settlement (20)1,522,637 557 137,381 1,385,256
2
3 Lacomb Irrgation (24)689,610 557 45,720 64,8904
5 Facilities and Proorties 303,968 118,018 403,672 18,314
6
7 Beaus Creek (42)1,365,680 557 41,280 1,324,40
8
9 Med Phoenix Availabiltv
10 & Trans Chame (50)15,267,80 565 3n,760 14,890,04
11
12 LaéView BuYOt (21 )90,166 557 43,280 46,886
13
14 TGS Buyout (23)20,44 557 15,473 186,972
15
16 Hermiston Swao (35)5,170,90 557 263,341 4,907,56
17
18 Deferrlonawall Costs 1,768,552 1,408,523 151 2,60,43 572,639
19
20 Other Deferred Debits wih
21 Amounts less than $50,00 313,360 30,022 151 320,302 23,08
22
23 Point to Point Transmission 559,001 6Z,8 288,643 898,2724
25 Deferred Costs Wvoak
26 Setlement (22)5,36,90 151 33,182 5,027,72727
28 JimBO Hvcro Buyout (11)586,925 557 82,86 50,06
29
30 Deferred Shelf Reaistration 283,538 247,227 181 43,363 96,402
31
32 Credit Aamt Costs (5)2,213,533 64,09 431 456,681 2,399,946
33
34 PCRB LOC/SBBPA Cot (5)1,250,875 211,607 427 324,681 1,137,801
35
36 Unamortized PCRB Mode Conv Cost 64,084 427 128,04 518,04
37
38 Emission Reducion Credits 406,980 40,98039
40 Non-Current FecState Inc Tax 12,741,86 10,729,23,471,510
41
42 LGIA L T Transmission Preoaid 6,89,901 8,108,86 2,704,260 12,303,50443
44 WA Environmental Cost-Utah Mts 290,80 182.3 290,803
45
46 Financina Costs Deferred 11,187 2,028,126 2,037,946 1,367
47 Misc. Work in Progres
48 ¡Deerec Heguiatory GOmm.
I Exenses (See paces 35 - 351)
49 TOTAL 57,976,248 52,116,892
-...........................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2007/Q4
(2) rïA Resubmission 04/03/2008
M SCELLANEOUS DEFFERED DEBITS (Account 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 $50,000, whichever is less) may be groupéd by
classes.
Line Descnption of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~çcoum.Amount End of Year Chad~ed
(a)(b)(c)(d (e)(f
1
2 Properl Damaae Reoaim 28,527 122,39 150,891 34
3
4 Lease Incentives (11)1,371,847 454.1 33,616 1,338,231
5
6 LT Lease Comm Preoaid (10l 928,200 931 7,000 921,200
7
8 BPA L T Transm Preoaid 2,40,OO 2,400,00
9
10 RTO Goo West N/R- WA (5)211,234 90 46,941 184,293
11
12 Contra RTO Gnd West NlR - WA -211,234 211,234
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Misc. Work in Proress
48 I Deferred Regulatory Comm.
Exenses (See oaaes 350 - 351 )
49 TOTAL 57,976,248 52,116,892
FERC FORM NO.1 (ED. 12-94)Page 233.1
......i...I..i......I..,.........................
Name of Respondent This Report is:Date of Report YeadPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
I$chedule Page: 233 Line No.: 5 Column: d
Account 102
Account 107
Account 539
ISchedule Page: 233 Line No.: 23 Column: d
Account 142
Account 232
Account 557
I$chedule Page: 233 Line No.: 40 Column: d
Account 165
Account 241
Account 282.1
Account 409.1
I$chedule Page: 233 Line No.: 42 Column: d
Account 165
Account 232
'Schedule Page: 233 Line No.: 46 Column: d
Account 181
Account 186
Account 923
I$chedule Page: 233.1 Line No.: 2 Column: d
Account 228
Account 143
I FERC 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 2oo7/Q4
(2) DA Resubmission 04/0312008
ACCUMULATED DEFERRED INCOME TAXE S (Account 190)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
Line Descnption and Location ~No.of Year of Year
(a)(b) c)
1 Electnc
2 Employee Benefts 294,34,786 139,413,272
3 FAS 133 Denvatives 102,310,588 106,959,021
4 Regulatory Uabilty 319,921,216 43,693,148
5
6
7 Other 103,109,88 142,263,119
8 TOTAL Electnc (Enter Total of lines 2 thru 7)819,687,478 432.328,56
9 Gas
10
11
12
13
14
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15
17 Other (Speify)
18 TOTAL (Acct 190) (Total of lines 8,16 and 17)819,687,478 432,328,56
Notes
FERC FORM NO.1 (ED. 12-88)Page 234
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 040312008
CAPITAL STOCKS (Account 201 and 204)
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filng, a specific reference to report form (Le., year and
company title) may be reported in column (a) provided the fiscl 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 incorpration 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 Authorized by Charter Value per share End of Year
(a)(b)(c)(d)
1 Common Stock (Accunt 201)750,00,00
2 PacifiCorp is a wholly
3 own indirect subsidiary of
4 MidAmerican Energ Holdings Company
5
6 TOTAL COMMON STOCK 750,00,00
7
8
10 5% Cumulative Preferred 126,53 100.00 110.00
11 (American Stock Exchange)
12
13 Serial Preferred, Cumulative:3,50,00
14 4.52% Series 100.00 103.50
15 7.()k Series 100.00
16 6.00% Series 100.00
17 5.00% Series 100.00 100.00
18 5.40% Series 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 19,626,533
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED. 12-91)Page 250
............................................
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) ¡=A Resubmission 04/03/200
CAPITAL STOCKS (Account 201 and 2)4) (Continued)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commissionwhich 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)
~l1ares Amount Sl1ares 1~t ~h!ireS Amount(e)(f)(g)(i)(j
357,060,915 3,417,94,896 1
2
3
4
5
357,06,915 3,417,94,896 6
7
8
9
126,243 12,624,300 10
11
12
13
2,065 206,500 14
18,04 1,804,60 15
5,930 593,00 16
41,90 4,190,800 17
65,959 6,595,90 18
69,890 6,989,00 19
84,592 8,459,200 20
21
22
414,633 41,46,30 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)Page 251
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 040312008 2007/Q4
FOOTNOTE DATA
Column:d
Oregon Public Utility Commssion, Docket No. UF-4228, Order No. 06-4 I 7, date July 17, 2006.
Washington Utilities and Transporttion Commssion, Doket No. UE0674, Order No. I, dated June 28, 2006.
Idaho Public Utilities Commssion, Case No. PAC-E-ü7, Order No. 3009, dated July 7, 2006.
As of December 31,200730,00,00 shares authorized; 30,00,00 available.
............................................
Blank Page
(Next Page is 253)
Name of Respondent This ~ort Is:Date of Report Year/Penod of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04031200
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
Report below the balance at the end of the year and the infonnation speifed below for the respetive other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as tota of all accounts for recncilation with balance sheet, Page 112. Add more
columns for any account if deemed necessary. Exlain changes made in any accunt dunng the year and give the accounting entries effecting such
change.
(a) Donations Received from Stockholders (Account 208)-State amount and give bnef explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give bne explanation of the caital change which gave nse to
amounts reported under this caption including identificaion wih the clas and senes of stock to which related.
(c) Gain on Resle or Cancellation of Reacquire Capit Stoc (Acunt 210): Report bace at beinning of year, credits, debits, and balance at end
of year with a designation of the nature of eah credit and debi identif by the cl and senes of stock to which related.
(d) Miscellaneous Paid-in capital (Accunt 211)-Clasif amounts include in this accnt accrding to captions which, together with brief explanations,
disclose the general nature of the trasations whic gave nse to th reported amounts.
.~(e 'i:r A"(unto.
1 Accunt 211 Miscellaneous Pai-in Capit
2 Additional Pai-i Capital
3 Share baed payments
4 Tax benefi fro stock opion exercises
5 Benefit plan sepration
6 Capit contnbutions
7 Gain on sae of ScttishPower stock
8 Qualifed proucon ac ta deducion
9 Cotnbution of Intennountain Geothennal
10 Adotion 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 427,06,95
FERC FORM NO.1 (ED. 12-87)Page 253
............................................
-...........................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Onginal (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
FOOTNOTE DATA
I$chedule Page: 253 Line No.: 3 Column: b
Represents the fair value of stock options granted by Scottish Power pIc for which certn performance measures were met in March
2005. These 0 tions became fully vested in May 2005.
chedule Pa e: 253 Line No.: 4 Column: b
Represents the income tax deduction attibutable to the exercise of stock options granted by Scottsh Power pIc, of which $3,502,924
related to options exercised during the year ended December 31, 2007 . Ths deduction is required to be recorded through an
ad.ustment to additional aid-in-ca ital.
chedule Pa : 253 Line No.: 5 Column: b
Represents the effect of transferrng benefit plans to PPM Energy as a result of the sale of PacifiCorp by Scottsh Power pIc. Ths is
required to be recorded though an adjustment to additional paid-in-capita.
ISchedule Page: 253 Line No.: 6 Column: bRepresents capita contrbutions to PacifiCorp (with no shares of stock issued) from its immediate corporate parent PPW Holdings
LLC, of which $200,00,00 were made durn the ear ended Deember 31, 2007.
chedule Pa e: 253 Line No.: 7 Column: b
Represents a realized gain on stock related to separation of PPM Energy, Inc. paricipants from the deferred compensation pla,
r uired to be recorded in additional aid-in-capita.
chedule Pa e: 253 Line No.: 8 Column: b
Represents an e uity adjustment related to IRC 199 ualified roduction activities.
hedule Pa : 253 Line No.: 9 Column: b
Represents contrbution of Intermountan Geotherm Company to PacifiCorp from MidAerican Energy Holdings Company
("MEHC") in March 2006, subse uent to the sale of PacifiCo to MEHC.Schedule Pa e: 253 Line No.: 10 Column: b
Represents the increase in paid-in capita resulting from the Januar 1,2007 adoption ofFASB Interpretation No. 48, "Accounting for
Uncertnty in Income Taxes - an interpretation ofFASB Statement No. 109."
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) EiA Resubmission 0403120
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 accunt charged.
IUne Class and Senes of StOCk Balance at EM of Year
No.(a)(b)
1 Common Stock 41,101,062
2
3 Preferred Stock:
4 5.00% Seril 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
FERC FORM NO.1 (ED. 12-87)Page 254b
............................................
............................................
Blank Page
(N ext Page is 256)
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04/031200
LONG-TERM DEBT (Account 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 accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respec to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expnses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount wih a notation, such as (P) or (D). The expnses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expnse, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Une Class and Series of Obligation, Copon Rate Principa Amount Tot expense,No.(For new issue, give commission Authotion numbers and eles)Of Debt issued Premium or Discount
(a)(b)(c)
1 Bonds: (Account 221)
2 First Mortgage Bo:
3
4 4.300% Series due September 15, 200 200,00,00 1,322,659
5 288,00 D
6 8.271 % Sees due October 1 , 2010 48,972,00
7 7.978% Series due October 1 , 2011 4,422,00
8 6.9OÆi Series due Noember 15, 2011 500,00,00 3,567,009
9 1,735,00 D
10 8.493% Series due Octobr 1, 2012 19,n2,00
11 8.797% Series due October 1 , 2013 16,203,00
12 5.450% Series due September 15, 2013 200,00,00 1,422,659
13 232,00 D
14 4.950% Series due August 15,2014 200,00,00 1,442,365
15 728,00 D
16 8.734% Series due Ocober 1,2014 28,218,00
17 8.29% Series due Ocober 1, 2015 46,94,00
18 8.635% Seri due Ocober 1,2016 18,750,00
19 8.470% Series due October 1,2017 19,60,00
20 7.700% Series due November 15, 2031 30,00,00 2,874,150
21 86,00 D
22 5.900% Series due August 15, 2034 200,00,00 1,892,365
23 722,00 D
24 5.25% Series due June 15, 20 300,00,00 2,912,055
25 1,080,00 D
26 6.10% Series due Augut 1 , 203 35,00,00 2,908,372
1,141,000 D
60,00,00 588,610
29 24,00 D30' ,60,00,000 5,091,953
31 750,00 D
32 7.67% Series C Medium-Term Notes due Jan. 10, 2007 5,724,00 36,625
33 TOTAL 5,421,486,00 57,859,191
FERC FORM NO.1 (ED. 12-96)Page 256
............................................
............................................
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) DA Resubmission 04/0312008
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpse 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 Accunt 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 -uulsianalnSï UneNominal Date Date of (Total amount outtan 'ng wihout Interest for Year No,of Issue Maturity Date From Date To reduction for amounts tieJd by Amount
(d)(e)(1)(g)resp?fòdent)
(i)
1
2
3
09/15/200 09/15/2008 09/1512003 09/151200 200,00,00 8,60,00 4
5
0415/1992 10101/2010 0411511992 10101/2010 13,2OO,OO 1,324,084 6
04/1511992 10101/2011 0411511992 10/01/2011 1,469,000 135,207 7
11/1512001 11/15/2011 11/1512001 11/15/2011 500,00,000 34,500,00 8
9
04/15/1992 101011212 04/15/1992 10/01/2012 7,988,OO 757,533 10
0415/1992 10101/2013 04115/1992 10101/2013 7,542,OO 724,499 11
09/15/203 09/1512013 11115/2001 09/15/2013 200,00,00 10,90,00 12
13
081241200 08115/2014 08124/200 08115/2014 2OO,OO,OO 9,90,00 14
15
041511992 10101/2014 04/15/1992 1010112014 14,492,00 1,361,369 16
0415/1992 10101/2015 041511992 10101/2015 25,697,00 2,268,53 17
04/15/1992 10/01/2016 0415/1992 10101/2016 11,159,OO 1,015,390 18
04/15/1992 10/01/2017 0411511992 10/01/2017 12,288,OO 1,089,327 19
11/1512001 11/15/2031 11/15/201 11/15/2031 3OO,00,OO 23,100,00 20
21
0814/200 08115/203 08124100 0811512034 2OO,00,OOC 11,875,00 22
23
06/1312005 06/15/2035 061312005 0615/2035 30,00,00 15,750,00 24
25
08/10/200 08011036 08101200 080112036 350,00,00 21,350,00 26
27
03114/2007 04/01/2037 0311412007 0401/2037 6O,00,OOC 27,504,166 28
29
10131007 10/1512037 1010312007 10/15/207 6O,OO,OO 9,166,666 30
31
01/10/1992 01/10/2007 01/10/1992 01/10/2007 10,976 32
5,123,205,00 278,731,910 33
FERC FORM NO.1 (ED. 12-96)Page 257
FERC FORM NO.1 (ED. 12-9)Page 256.1
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2007/Q4
(2) riA Resubmission 04032008
L NG. TERM DEBT (Account 221, 222, 223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in 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 accounts. Designate
demand notes as such. Include in column (a) names of assiated 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 respe 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. Fumish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authörization of treatment other than as
specified by the Uniform System of Accounts.
Line Class an Senes of Obligaion, Copo Rate Pnncpal Amount Total expense,
No.(For new issue, give comission Authonztion numbe and daes)Of Debt issued Premium or Discount
(a)(b)(c)
1 6.625% Senes G Medum-Tenn Notes due June 1, 207 100,00,00 1,267,428
2 630,00 0
3 7.43% Series E Medium- Tenn Notes due Sept. 11, 207 2,00,00 .15,530
4 7.22% Senes E Meium.Tenn Notes due Sept. 18,2007 2,500,00 19,412
5 7.27% Senes E Meum-Tenn Notes due Sept. 24, 207 4,00,00 31,059
6 6.375% Senes H Meium-Tenn Notes due May 15, 2008 200,00,00 1,416,179
7 64,00 0
8 7.00% Senes H Meium-Tenn Notes due Jul. 15,2009 125,00,00 1,976,90
9 451,2500
10 9.15% Senes C Medium-Tenn Notes du Aug. 9, 2011 8,00,00 75,327
11 8.95% Series C Medium- Tenn Notes due Sept. 1, 2011 25,00,00 175,398
12 8.95% Senes C Medum- Tenn Notes due 8e. 1, 2011 20,00,00 132,118
13 8.92% Series C Meium-Tenn Notes due Sept. 1,2011 20,00,00 188,318
14 8.29% Senes C Medium-Tenn Notes due Dec. 30, 2011 3,000,00 23,04
15 8.26% Senes C Medium-Tenn Notes due Jan. 10,2012 1,00,00 7,649
16 8.28% Senes C Medium.Tenn Notes due Jan. 10,2012 2,00,000 13,297
17 8.25% Series C Medium-Tenn Notes due Feb. 1,2012 3,00,000 22,94
18 8.13% Senes E Medium- Tenn Notes due Jan. 22, 2013 10,00,00 75,827
19 8.53% Series C Medium-Tenn Notes due Dec. 16,2021 15,00,00 115,202
20 8.375% Senes C Medium-Tenn Notes cle Dec. 31, 2021 5,000,00 38,400
21 8.26% Senes C Meium-Tenn'Notes due Jan. 7, 2022 5,00,00 33,243
22 8.27"Æi Senes C Medium-Tenn Notes cle Jan. 10,2022 4,00,00 30,594
23 8.05% Senes E Medium-Tenn Notes due Set. 1, 20 15,00,000 131,471
24 8.07% Senes E Medium-Tenn Notes cle Sept. 9, 2022 8,00,00 70,118
25 8.12% Senes E Medium-Ter Notes due Sept. 9, 2022 50,00,00 438,238
26 8.11% Senes E Medium-Tenn Notes cle Sept. 9, 2022 12,000,00 105,1n
27 8.05% Senes E Medium-Tenn Notes due Sept. 14, 2022 10,00,000 87,648
28 8.08% Senes E Medium-Tenn Notes due Oc. 14,2022 26,00,00 208,198
29 8.08% Senes E Medium-Tenn Notes due Oct. 14,2022 25,00,00 200,190
30 8.23% Senes E Medium-Tenn Notes due Jan. 20, 2023 5,00,000 37,914
31 8.23% Series E Meium- Tenn Notes due Jan. 20, 2023 4,000,00 30,331
32 -81,560 P
33 TOTAL 5,421,486,00 57,859,191
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) EiA Resubmission 04/03/2008
LONG-TERM DEBT (Account 221,222,223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any diference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD v~tsIan~UneNominal Date Date of (Total amount oust ing witou Interest for Year No.of Issue Maturiy Date From Date To reduction for amounts Iield by Amount
(d)(e)(f)(g)
reSPlh'dent)
(i)
0609/1995 0601/2007 0609/1995 0601/2007 2,760,417 1
2
09/11/1992 09/11/2007 09111/1992 09/1112007 103,194 3
09/1811992 09/1812007 09/18/1992 09/1812007 128,857 4
09/2211992 09/24/2007 09/2211992 09/24/2007 212,44 5
05/1211998 05/1512008 05/1211998 05115/2008 200,00,00 12,750,00 6
7
07/15/1997 01/15/200 07/15/1997 07/151209 125,00,000 8,750,00 8
9
0809/1991 08109/2011 08109/1991 08109/2011 8,00,00 732,00 10
0811611991 09101/2011 081611991 09/01/2011 25,00,00 2,237,500 11
0811611991 09/0112011 08/16/1991 09/01/2011 20,00,00 1,790,00 12
08116/1991 09/01/2011 08/1611991 09/01/2011 20,000,00 1,784,00 13
12131/1991 121012011 12131/1991 12l2011 3,00,000 248,700 14
01/09/1992 01/10/2012 01/09/1992 01/10/2012 1,00,000 82,600 15
01/10/1992 01/1012012 01/10/1992 01/10/2012 2,00,00 165.600 16
01/1511992 02101/2012 01/15/1992 02101/2012 3,00,00 247,500 17
0112011993 0112212013 01/20/1993 01/2212013 10,00,00 813,00 18
1211611991 12116/2021 12116/1991 121161021 15,00,00 1,279,50 19
12131/1991 12131/2021 12131/1991 12131/2021 5,00,00 418,750 20
0110811992 01/07/2022 01/0811992 01/07/2022 5,00,000 413,00 21
01/09/1992 01/10/2022 01/09/1992 01/10/2022 4,00,000 33,800 22
09/1811992 09/01/2022 09/1811992 09/01/2022 15,00,00 1,207,50 23
09/0911992 09/09/2022 09/09/199 09/09/2022 8,00,00 645,60 24
09/11/1992 09/09/2022 09/11/1992 09/09/2022 50,00,00 4,06,00 25
09/11/1992 09/09/2022 09111/1992 09/09/2022 12,00,00 973,20 26
09/1411992 09/14/2022 09/14/1992 09/14/2022 10,00,00 805,00 27
10/1511992 10/14/2022 10/15/1992 10/14/2022 26,00,00 2,100,800 28
10/15/1992 10/14/2022 10/15/1992 10/1412022 25,000,00 2,020,00 29
01/20/1993 01/20/2023 01/20/1993 01/20/2023 5,00,00 411,500 30
01/29/1993 01/20/2023 01/2911993 01/20/2023 4,000,00 329,200 31
32
5,123,205,00 278,731,910 33
FERC FORM NO.1 (ED. 12-96)Page 257.1
FERC FORM NO.1 (ED. 12-96)Page 256.2
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) ñA Resubmission 0403008
L NG-TERM DEBT (Accunt 221, 22, 223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2.In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respec 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 wih a notation, such as (P) or (D). The expenses, premium or discunt should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expnse, premium or discunt associated with
issues redeemed during the year. Also, give in a footnte the date of the Commission's authorization of treatment other than as
speified by the Uniform System of Accunts.
Line Class and Series of Obligation, Copon Rate Principal Amount Tota expnse,
No.(For new issue, give commission Authorition numbers and dates)Of Deb issued Premium or Discunt
(a)(b)(c)
1 7.26% Series F Meium-Term Notes due July 21, 2023 27,00,00 246,981
2 7.26% Series F Meium-Term Notes due July 21,2023 11,00,00 100,622
3 7.23% Series F Medum-Term Notes due Aug. 16,202 15,00,00 137,211
4 7.24% Series F Medium-Term Notes due Aug. 16,2023 30,00,00 274,423
5 6.75% Series F Medium-Term Notes due Sept. 14,20 5,00,00 38,250
6 6.75% Series F Medum-Term Notes du Sept. 14,202 2,00,00 15,30
7 6.72% Series F Meium-Term Notes due Sept. 14,2023 2,00,00 15,30
8 6.75% Series F Medium-Term Notes due Oct. 26, 203 20,00,00 152,326
9 6.75% Series F Medium-Term Notes due Oct. 26, 2023 16,00,00 121,861
10 6.75% Series F Medium-Term Notes due OCt. 26, 2023 12,00,00 91,396
11 6.71% Series G Medium-Term Notes due Jan. 15,2026 100,00,00 90,467
12 Subtotal- First Mortgage Bonds 4,608,116,00 42,331,805
13
14 Pollution Control Obligations - Secured by Pleged First Mortgage Bods:
15
16 POLL Ctrl Rev Refunding Bond, Mot County, CO, Series 199 40,655,00 874,159
17 5-5/8% Poll Ctrl Rev Refnding Bods, Lincoln Cont, WY, Seri 1993 8,300,00 228,980
18 197,125 D
19 5.65% Poll Ctrl Rev Refunding Bonds, Emery County, Utah, Series 199A 46,500,000 1,624,793
20 5-5/8% Poll Ctrl Rev Refunding Bonds, Emery County, Utah, Series 1993B 16,400,00 625,551
21 389,50 D
22 Poll Ctrl Rev Refunding Bonds, Sweetwater Conty, WY, Series 1994 21,260,000 510,479
23 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1994 8,190,00 209,77
24 POLL Ctrl Rev Refunding Bonds, Emery County, UT, Series 1994 121,940,00 3,274,246
25 Poll Ctrl Rev Refunding Bonds, carbon County, UT, Series 1994 9,365,00 20,519
26 Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1994 15,06,00 422,858
27 POLL Ctrl Rev Refunding Bonds, Converse Cont, WY, Series 1988 17,00,00 155,970
28 POLL Ctrl Revenue Bond, Sweetwater County, WY, Seri 1984 15,00,00 122,887
29 105,00 D
30 Poll Ctrl Rev Refunding Bonds, Lincoln Cnty, WY, Series 1991 45,00,00 n1,83
31 Poll Ctrl Revenue Bonds, Cit of Forsyth, MT, Series 1986 8,500,000 304,824
32 Environ.lmprvmnt Rev Bonds, Converse County, WY, Series 1995 5,30,000 132,04
33 TOTAL 5,421,486,00 57,859,191
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) CiA Resubmission 04/0312008
LONG-TERM DEBT (Account 221, 222, 22 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expnse 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 vl!lS¡an!JlnSi UneNominal Date Date of (Total amount oustan 'ng without Interest for YElr No.of Issue Maturiy Date From Date To reduction for amounts field by Amount
(d)(e)(f)(g)
respWdent)
(i)
07/2211993 07/21/2023 07/2211993 07/21/2023 27,00,00 1,96,2 1
07/2211993 07/21/2023 07/221993 07/21/2023 11,00,00 798,GO 2
08/1611993 081612023 081611993 081612023 15,00,00 1,08,500 3
08116/1993 08161023 08/16/1993 0811612023 30,000,00 2,172,00 4
09/14/1993 09/14/2023 09/14/1993 09/14/2023 5,00,00 337,50 5
09/14/1993 09/14/2023 09/14/1993 09/14/2023 2,00,00 135,00 6
09/14/1993 09/14/2023 09/14/1993 09/14/2023 2,00,00 134,400 7
10/26/1993 10/2612023 10/2611993 10/2612023 20,00,00 1,350,00 8
10/2611993 10/2612023 10/26/1993 10/2612023 16,00,000 1,080,00 9
10/2611993 10/26/2023 10/2611993 10/261023 12,00,00 810,000 10
01/2311996 01/1512026 01/231199 01/15/2026 100,00,00 6,710,000 11
4,384,835,00 245,705,614 12
13
14
15
11/17/1994 05/01/2013 11/17/1994 05/01/2013 40,655,00 1,58,074 16
11/15/1993 11101/2021 11/15/1993 11/01/2021 8,30,00 46,54 17
18
11/15/1993 1110112023 11/15/1993 11/011223 46,500,00 2,636,594 19
11/15/1993 11/01/2023 11/15/1993 11/01/2023 16,400,00 925,796 20
21
11/17/1994 11/01/2024 11/1711994 11/01/2024 21,260,00 833,632 22
11/17/1994 11101/2024 11/17/1994 11101/2024 8,190,00 316,422 23
11/17/1994 11/01/2024 11/17/1994 11/01/2024 121,94,00 4,981,354 24
11/17/1994 11/01/2024 11/17/199 11/01/2024 9,365,00 369,84 25
11/17/1994 11/01/2024 11/17/1994 11/01/2024 15,060,00 60,459 26
01/01/1988 01/01/2014 01/01/1988 01/01/2014 17,00,00 680,43 27
121011984 12101/2014 12101/1984 12101/2014 15,00,00 600,430 28
29
01/17/1991 01/01/2016 01/17/1991 01/01/2016 45,00,00 1,639,795 30
12101/1986 121112016 12101/1986 12101/2016 8,500,00 359,492 31
11/17/1995 11/01/2025 11/17/1995 11/01/2025 5,30,00 224,278 32
5,123,205,00 278,731,910 33
FERC FORM NO.1 (ED. 12-9)Page 257.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) EiA Resubmission 04/03008
LONG-TERM DEBT (Account 221,222, 223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certifcates 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 discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expnse, premium or discunt 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 Acunts.
Une Class and Series of Obligatio, Coupo Rate Principal Amount Total expense,
No.(For new Issue, give commiSion Authorization numbers an dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 Environ.lmprnt Rev Bonds, Uncoln County, WY, Series 1995 22,00,00 40,262
2 Subtotal Pollution Control Obligations - Secured by Pleded First Mortgage Bo 40,470,00 10,560,809
3
4
5 POllution Control Obligations - Unsecure
6
7 POLL Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992A 9,33,000 167,524
8 Poll Ctrl Rev Refdng Bonds, Sweetwater Cnt, WY, Ser. 1992B 6,305,00 151,908
9 POLL Ctrl Rev Refndng Bonds, Coverse County, WY, Series 1992 22,485,00 242,163
10 POLL Ctrl Rev Refnng Bonds, SweeaterCnty, WY, Ser.1988B 11,500,00 84,822
11 Poll Ctrl Rev Refndng Bonds, Sweetwater Count, WY, Ser. 1990A 70,00,00 660,750
12 Poll Ctrl Rev Refndg Bond, Emery County, UT, Series 1991 45,00,00 872,505
13 Poll Ctrl Rev Refndng Bond, Sweetwater Cnty, WY, Ser. 1988A 50,00,00 422,43
14 Poll Ctrl Rev Refdng Bo, City of Forsyt, MT, Series 1988 45,00,00 380,198
15 Poll Ctrl Rev Refndng Bo, Cit of Gillette, WY, Ser. 1988 41,200,00 351,905
16 Environ. Imprvmnt Rev Bods, Sweetwater Conty, WY, Series 199 24,400,00 225,00
17 6.150% Enviro.lmprvmnt Rev Bond, Emery Co, UT, Seri 1996 12,675,00 556,549
18 178,46 D
19
20 Subtotal - POllution Cotrol Obligations - Unsecured 337,90,00 4,294,231
21
22
23
24 TOTAL ACCOUNT 221 5,346,486,00 57,186,84
25
26
27 Reacquired Bonds: (Accunt 22)
28
29
30 Advances from Asociated Companie: (Account 223)
31
32
33 TOTAL 5,421,486,000 57,859,191
FERC FORM NO.1 (ED. 12-96)Page 256.3
............................................
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04/0312008
LON -TERM DEBT (Account 221, 222, 223 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and arè nominally outstanding at ènd of
year, describe such securities in a footnote.
15. If interest expnse was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expnse 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 O~tstn!lins UneNominal Date Date of (Total amount outsta ing without Interet for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)
res~ent)
(i)
11/17/1995 11/01/2025 11/17/1995 11/01/2025 22,00,00 952,183 1
4O,470,OO 17,180,331 2
3
4
5
6
09/29/1992 12/0112020 09129/1992 12/01/2020 9,335,OO 376,057 7
09/29/1992 12/0112020 09/29/1992 12/0112020 6,305,OO 253,995 8
09/29/1992 12/01/2020 09/29/199 12/01/200 22,485,00 907,984 9
01/01/1988 01/01/2014 01/01/1988 01/01/2014 11,500,00 499,655 10
07125/1990 07/01/2015 07/2511990 07/01/2015 70,00,00 3,042,320 11
OS/231991 07/01/2015 OS/2311991 07/01/2015 45,00,OO 1,968,893 12
01/01/1988 01/01/2017 01101/1988 01/01/2017 50,000,OO 2,179,830 13
01/01/1988 01101/2018 01101/1988 01/01/2018 45,00,OO 1,950,96 14
01/01/1988 01/01/2018 01101/1988 01/011218 41,20,00 1,797,53 15
12/14/1995 11/01/2025 12/14/1995 11/01/2025 24,40,00 1,076,726 16
09/24/1996 09/011230 09/2411996 09/01/2030 12,675,00 n9,512 17
18
19
337,90,00 14,833,46 20
21
22
23
5,123,205,00 2n,719,410 24
25
26
27
28
29
30
31
32
5,123,205,00 278,731,910 33
FERC FORM NO.1 (ED. 12-96)Page 257.3
FERC FORM NO.1 (ED. 12-96)Page 256.4
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 04208
LONG-TERM DEBT (Acount 221,222,223 an 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 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 discunt 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 expnse, premium or discunt 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.
Une Class and Series of Obligtion, Coupon Rate Pripal Amount Total expense,
No.(For new isue, give commissio Auhorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1
2 Other Long-Term Debt: (Acnt 224)
75,00,00 672,346
4
5 TOTAL ACCOUNT 224 75,00,00 672,34
6
7
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 5,421,48,00 57,859,191
............................................
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifiCorp (1) An Onginal (Mo, Da. Yr)End of 2007/Q4
(2) DA Resubmission 040312008
LONG-TERM DEBT (Account 221,222,223 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to 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). Exlain 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 _~,!sian()ins LineNominal Date Date of (Total amount outstan ing withot Interest for Year No.of Issue Matunty Date Fro Date To reduction for amounts Iield by Amount
(d)(e)(f)(g)
reSPlh\dent)
(i)
1
2
0611/1992 0615/2007 07/0112003 0615/207 1,012,50 3
-4
1.012,500 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
5,123,20.00 278,731,910 33
FERC FORM NO.1 (ED. 12-96)Page 257.4
\shedule Page: 256.4 Line No.: 3 Column: a I
As of Decmber 31,2007, there were no shares outstading. On June 15,2007 the remaining 375,000 shares outstanding ($100 state
value er share on the $7.48 senes were redeemed in accordace with the mandato rede tion re uirements.
hedule Pa e: 256.4 Line No.: 8 Column: a
For authonzation for the issuance of long-term debt ($1.5 billon authonzed; $300 millon available as of December 31, 2(07), refer to
page 104, Important Changes During the Year, Item 6, of ths Form No.1.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
ISchedule Page: 256 Line No.: 28 Column: a
On March 14,2007, PacifiCorp issued $600 millon of its 5.75% Senes of First Mortgage Bonds due April 1, 2037. PacifiCorp usedthe proceeds for general corporate purposes, including the reduction of short-term debt. State commssion authonzations for ths
issuance were as follows:
Uta Public Service Commssion, Docket No. 07-035-05, Report and Order dated March 2,2007.
Oregon Public Utility Commssion, Docket No. UF-4237, Order No. 07-085, dad Marh 5, 2007.
Washington Utilities and Transporttion Commssion, Doket No. UE-070450, Orer No.1, date March 7,2007.
Idaho Public Utilities Commssion, Cae No. PAC-E-07-2, Order No. 30258, date Febru 27,2007.
!Schedule Page: 256 Line No.: 30 Column: a
On October 3, 2007, PacifiCorp issued $600 millon of its 6.25% Senes of Firt Mortgage Bonds due October 15, 2037. PacifiCorp
intends to use the proceeds for general corporate purposes, includng the reduction of short-term debt. State commssion authorizations
for this issuance were as follows:
Oregon Public Utility Commssion, Docket No. UF-4237, Orer No. 07-085, date March 5, 2007.
Idao Public Utilities Commssion, Ca No. PAC-E-0-2, Order No. 30258, dated Februar 27,2007.
Authonzation for the issuance of pollution control revenue bonds ($125 millon authonzed; $79 millon available as of December 31,
2(07) is as follows:
Oregon Public Utility Commssion, Docket No. UF-4128, Orer No. 95-518, date May 25, 1995.
Washington Utilties and Transporttion Commssion, Doket No. UE-950490, date May 24, 1995.
Idaho Public Utilities Commssion, Docket No. PAC-S-95-2, Order No. 26039, dated June 13, 1995.
For additional information regarding long-term debt, refer to page 104, Important Changes During the Year, ITM 6, of ths Form No.
1.
lFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Blank Page
(Next Page is 261)
Name of Respondent
PacifCorp
RECONCILIATION OF REP
Date of Report
(Me, Da, Yr)040318
INCOME FOR FEDERAL INCOME TAXES
Year/Period of Report
End of 2007/Q4
1. Report the reconcilation of reported net incoe for the year with taxe income used in computing Federal income tax accruals and show
computation of such ta accruals. Include in the reconciliation, as far as practicable, the sae detail as furnished on Schedule M-1 of the ta return for
the year. Submit a reconcilation even though there is no table ince for the yer. Indicate clearly the nature of each reconcilng amount.
2. If the utility is a member of a group which files a consolidated Fed ta return, recncile reported net income with taable net income as if a
separate return were to be field, indicating, however, intercmpay amounts to be eliminated in such a cosoidated return. State names of group
member, tax assigned to each group member, and bais of alloti, asignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particlar nee of a company, may be used as Long as the data is consistent and meets the requirements of
the above instructions. For electronic reprting purpses complete Une 27 and provide the substitute Page in the context of a footnote.
et Ince for the Year (Page 117)
axble Income Not Reported on Boks
1,027,196,502
16,09,307
452,407,699
158,342,695
5,203,656
5,649,016
3,083,876
-10,145,039
-4,485
-6,013,353
-11,522,396
-130
39
40 Federa Income Tax Accrual
41
42
43
44
FERC FORM NO.1 (ED. 12-9)Page 261
.............................................
.............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp (2) A Resubmission 04/03/2008 2007/Q4
FOOTNOTE DATA
¡Schedule Page: 261 Line No.: 8 Column: a
Parculars (Detals)
Contrbutions in Aid of Constrction
Highway Relocation
Hermston Swap
Uneared Joint Use Pole Contract Revenue
Accrued Royalties
FAS 115 Unrealized GainIoss
Bridger Coal Company Reclamation Trust Earngs PMI
Equity Eangs in SubsidiaresTota
I,chedule Page: 261 Line No.: 13 Column: a
Parculars (Detals)
FedState Tax Expense
% capitazed labor costs for Powert input
Mandatory Redeemable Prferred Stock - FAS 150
Meals & Entertnment
Penalties
Penalties- PMI
Lobbying expenses
Meals & Entertnment - Bridger Coal
MEHC Insurance Services - Premium
Mining Rescue Training Credit Addback
Non-deductble Parachute Payment -280G
Deferred Revenue - SRC
PMI Fuel Tax Cr
Interest Accual on FIT - Cash Basis
Mining Rescue Training Credit Addback
30% capitalized labor costs for Powert input
Book Depreciation
Tax vs Book Depreciation - PMI
Avoided Costs
ARO - reclass to ARO liabilties
Book GainIoss on Lad Sales
Book Cost Depletion - Addback
BookDepletion -SRC
Book Depletion-Step up basis adjustment
Fixed Asset -Bookfax
Book Amort-Bandoned Proj-Lease Rights
Book Amort-Bandoned Proj-Lease Rental
May 200 Transition Plan Costs-OR
Glenrock Excluding Reclamtion-UT
FAS 87/88 Pension Writeoff - UT rate order
98 Early Retiement-OR rate order
Reg Asset - PAS 158 Pension Liab Adj.
Reg Asset - FAS 158 Post Ret. Liab.
Environmental Clean-up Accrual
Environmenta Costs - W A
ChoIIa PIt Transact Costs-APS Amort
W A DisaIIowed Colstrp #3- Write-off
Wyoming PCAM DefNet Power Costs
I FERC FORM NO.1 (ED. 12-81)
i
Amounts
219,340,007
2,990,60
1,096,543
655,934
4,182,180
18,407
1,101,453
22,597
7,057,172
28,527
1,623,557
119,015
17,957
464,179
17,958
3,835,385
495,661,102
11,171,996
56,119,565
5,075,961
11,491,995
2,046,969
215,634
156,365
545,06
505,367
20,825
3,892,299
1,302,399
3,159,014
3,676,946
23,767,760
19,311,911
4,852,132
100,476
938,633
52,188
1,673,388
Page 450.1
IDAl Costs - direct access
SB 1149-Related Regulatory Assets
Deferred Intervener Funding Grants
RTO Grid West Notes Receivable - ID
OR SB 408 Recovery
Weatherization
Trojan Decomissioning Costs - Regulatory
781 Shopping Incentive
SB 1149 Costs
Post Merger Loss-Reacq Debt - Addback
Trapper Mining Stock Basis
Prepaid Insurance - IBEW 157 contingency reserve
Prepaid Taxes - Propert Taxes
RTO Grid West Note Receivable - w/o - W A
TGSBuyout
Laeview Buyout
Joseph Settement
FAS 133 Derivatives - Curent
Energy trding derivatives -noncurrent
ARO Reg Liabilties
Non-ARO Liabilly - Reg Liabilty
Reg Liabilty - UT Home Energy Lifeline
Reg Liabilty - WA Low Energy Progr
Reg Liab - OR Balance Consol
Oregon Gain on Sale
West Valley Lease Reduction - ID
West Valley Lease Reduction - WY
A&G Credit - W A
A&G Credit - ID
A&G Credit - WY
Reg Liability-Blue Sky Program OR
Reg Liabilty-Blue Sky Program W A
Reg Liabilty-Blue Sky Program CA
Reg Liabilty-Blue Sky Program UT
Reg Liabilty-Blue Sky Program ID
Reg Liabilty-Blue Sky Prgram WY
FAS 158 SERP Liabilty
FAS 133 Derivatives - noncurrent
Distrbution O&M Amort of Writeoff
Sec. 263A Inventory Chnge - PMI
Def Reg Asset-Transmission Srvc Deposit
Bear River Settlement Agreement
Misc Def Dr-Prop Damage Repais
BPA Conservation Rate Credit
N. Umpqua Settlement Agreement
Umpqua Settlement Agreement
Trail Mountan Accrued Liabilities
Purchase Card Trans Povision
WV Contract Termnation Fee Accural
Bridger Coal Company GainIoss on Assets Disposed
Misc. Deferred Credits
Injuries and Damages Accru - Cash Basis
FAS 112 Book Reserve
I FERC FORM NO.1 (ED. 12-87)
333,105
8,017,105
269,486
27,162
2,092,338
504,628
1,532,586
378,787
1,184,975
4,651,715
256,060
182,213
1,400,646
46,941
15,474
43,280
137,381
12,242,658
33,891
4,912,316
8,763,878
156,028
26,90
48,602
13,875
382,653
848,461
42,438
399,549
890,855
462,671
81,041
34,975
589,668
19,977
104,551
42,00
12,248,513
45,384
532,054
11,523,653
491,262
28,493
827,852
1,118,623
638,092
416,%7
1,005,134
6,601,499
3,839,523
225,811
1,415,357
103,076
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)PacifCorp (2) A Resubmission 040312008 2oo7/Q4
FOOTNOTE DATA
Page 450.2
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/03/2008 2007/Q4
FOOTNOTE DATA
Bridger Coal Company ARO - Asset
Bridger Coal Company Extraction Taxes Payable - PMI
Vacation Accrual - PMI
7,132,809
654,468
106,520
988,435,434
¡Schedule Page: 261 Line No.: 18 Column: a
Parcular (Detals)
Uta Deferred Comp / COLI
MERC Insurance Services - Receivable
Medcare Subsidy
Bridger Coal Tax Exempt Interest Income
Dividend Received Deduction
SMUD Revenue Imputation-UT reg liab
!$hedule Page: 261 Line No.: 25 Column: a
Parculars (Detals)
PPL Pre - 1943 Preferred Stock Div - Deduction
Tax Exempt Interest ( No AMT)
200 JCA - Qualified Production Activities Deduction (6%)
200 JCA - Qualified Production Activities Deduction (6%) PMI
Bridger Coal Company Depletion - PMI
PMI Overrding Coal Royalty % Depletion
Tax Depreciation
Depreciation (Tax Depreciation M-l)
Capitaized DepreciationAFC
Basis Intagible Difference
Gain / (Loss) on Prop. Disposition
Coal Mine Development
Coal Mine Extension
Removal Costs
Coa Mine Development- 30% Amortzation
ARO - reclass to reg assets/liabilty & ARO liability
Tax Percentage Depletion - Deduction
Tax Depletion
Book!ax Gain on Disposal
ARO Reg Assets
Def Reg Asset-OR Def Net Power Costs
Contra RTO Grid West NIR w/o - WA
RTO Grid West Notes Receivable - OR
Unrecovered Plant-Powerdale
Deferred Excess Net Power Costs-CA
Deferred Excess Net Power Costs-WY
Deferred UT Independent Evaluation Fee
ID MERC 2006 Transition Costs
OR _RCAC Sep-Dec 07 Deferred
Regulatory asset - Net FAS 133
Coal Pile Inventory Adjustment
Prepaid Taxes - OR PUC
Prepaid Taxes - UT PUC
Prepaid Taxes - ID PUC
IFERC FORM NO.1 (ED. 12-87) Page 450.3
Other Prepaid
WY Joint Water Board Reserve - Deduction
Wasatch workers comp reserve
Reg liabilty BPA balancing accounts
OR Rate Refunds
OR Reg Assetliabilty Consolidation
Propert Insurance(same as Injuries & Damages)
West Valley Lease Reduction - W A
West Valley Lease Reduction - CA
West Valley Lease Reduction - UT
CA-Californa Alternative Rate for Energy Program (CAR)
A&G Creit - CA
March 2006 Transition Plan Costs _ W A
Self Insured Health Benefit
Vacation Accrual- Cash Basis (2.5 mos)
Accred Retention Bonus
Deferred Compensation Accrual - Cash Basis
Pension I Retiement Accrual - Cash Basis
Severance Accrual - Cash Basis
Accrued CIC Severance
FAS 158 Pension Liabilty
FAS 158 Post-Retiement Liabilty
FAS 143 ARO Liabilty
Scottsh Power Long Term Incentive Plan
M&S Inventory Write-Off
Bad Debts Allowance - Cash Basis
Amort of Projects- Klamath Engineering
R & E - Sec. 174 Deduction
Def Reg Asset-Foote Creek Contract
Deferred Regulatory Expense
Tenant Lease Allow - PSU Call Cntr
Other Environmental Liabilties
Amort of Debt Disc & Exp
DukelHermston Contract Renegotiaton
Idaho Customer Balancing Account
Special Assessment - DOE
Misc. Curent and Accrued Liabilty
Reverse Accrued Final Reclamation
PMI Devt Cost Amort
PMI EIT04-6 Pre-Strpping Costs
Microsoft Software License Liabilty
MCI FOG Wire Lease
NW Power Act-WA
Redding Contract - Prepaid
Amort NOPAs 99~00 RA
Bridger Coal Company ARO - Liabilty
Bridger Coal Company ARO - Reg Asset
Coal Mine Extension Costs-PP&E - PMI
Coal Mine Developent-PMI
Bridger Coal Company Underground Mine Cost Depletion
PacifiCorp Stock Incentive Plan
PacifiCorp Executive Stock Option Plan
Scottsh Power Long Term Incentive Plan
I FERC FORM NO.1 (ED. 12-87)
(611,442)
(300,000)
(186,471)
(14,142,869)
(5)
(468,072)
(2,233,114)
(342,758)
(23,868)
(946,291)
(352,495)
(38,231)
(1,623,722)
(121,587)
(839,899)
(58,333)
(6,385,866)
(153,688)
(174,639)
(13,418,126)
(39,487,083)
(9,176,369)
(8,417,002)
(2,324,715)
(127,937)
(4,973,203)
(6,423)
(6,782,736)
(137,640)
(927)
(62,756)
(7,140,683)
(56,166)
(754,839)
(9,249,021)
(38,625)
(10,119,572)
(700,335)
(1,152,215)
(1,093,541)
(532,374)
(210)
(4,271,640)
(549,996)
(41,311)
(3,030,408)
(4,102,401)
(462,425)
(775,310)
(175,792)
(3,865,252)
(938,127)
(4,426,742)
.............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Onginal (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
Page 450.4
.............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 0403/2008 2007/Q4
FOOTNOTE DATA
Total (1,027,196,502)
¡Schedule Page: 261 Line No.: 40 Column: b
On March 21,2006, a wholly owned subsidiar of MidAmerican Energy Holdings Company ("MEHC") acquired 100% of the
common stock of PacifiCorp from a wholly owned subsidiar of Scottish Power pIc ("ScottshPower"). As a result of this acquisition,
MEHC controls substatially all of PacifiCorp's voting securities, which include both common and preferred stock. MEHC, a
holding company based in Des Moines, Iowa, ownng subsidiaries that are principally engaged in energy businesses, is a consolidated
subsidiar of Berkshire Hathaway Inc. ("Berkshire Hathaway").
Names of group members who wil me a conslidate Federal Tax Return:
UnderMEHC:
PPW Holdings LLC Sub~Group;
PacifiCorp
PacifiCorp Sub~Group:
Centralia Mining Company
Energy West Mining Company
Glenrock Coal Company
Intermountan Geothermal Company
Interwest Mining Company
Pacific Minerals, Inc.
PacifiCorp Environmental Remediation Company
PacifiCorp Future Generations, Inc.
PacifiCorp Investment Management, Inc.
Steam Reserve Corporation
MEHC Sub~Group:
Academy of Real Estate, Inc
Allerton Capital, Ltd
American Pacific Finance Company
American Pacific Finance Company II
CalEnergy Company, Inc
CalEnergy Generation Operating Company
Calnergy Holdings, Inc
CalEnergy Imperial Valley Company, Inc
CalEnergy International Services, Inc
Calnergy International, Inc
CalEnergy Minerals LLC
CalEnergy Pacific Holdings Corp
CalEnergy UK Inc
Capitol Intermediar Company
Capitol Land Exchange, Inc
Capitol Title Company
CBEC Railway, Inc
CBSHome Real Estate Company
CBSHome Real Estate of Iowa, Inc
CBSHome Relocation Servces, Inc
CE Administrative Services, Inc
CE Electrc (N), Inc
CE Electrc, Inc
CE Exploration Company
CE Geothermal, Inc.
CE Indonesia Geothermal, Inc
CE International Investments, Inc
CE Power, Inc
Champion Realty, Inc
Chancellor Insurance Services, Inc
Chancellor Title Services, Inc
Cimmed Leasing Company
Columbia Title of Florida. Inc
Community Diversified Investments, Inc
Cordova Funding Corporation
Dakota Dunes Development Company
DCCO,Inc
Edina Financial Services, Inc
Edina Realty Referral Network
Edina Realty Relocation, Inc
Edina Realty Title, Inc
Edina Realty, Inc
Esslinger-Wooten-Maxwell, Inc
E-W-M Referral Services, Inc.
FF, Inc
Firt Realty, Ltd
IFERC FORM NO.1 (ED. 12-87) Page 450.5
MEHC Sub-Group (continued):
First Reserve Insurance, Inc
For Rent, Inc
HMSV Financial Services, Inc
HN Real Estate Group N.C., Inc.
HN Real Estate Group, LLC
HN Referral Corporation
Home Real Estate, Inc
HomeServices Financial Holdings, Inc
HomeServices Financial, LLC
HomeServices Financial-Iowa, LLC
HomeServices Insurance, Inc
HomeServices of Alabam, Inc.
HomeServIces of America. Inc
HomeServices of Calfornia, Inc
HomeServices of Florida, Inc
HomeServIces of Iowa, Inc
HomeServices of Kentucky, Inc
HomeServices of Nebraska, Inc
HomeServices of Nevada. Inc
HomeServices of the Carolinas, Inc
HomeServices Pacific Nortwest, Inc.
HomeServices Relocation, LLC
HSR Equity Funding, Inc
Huff Commercial Group, LLC
Huff-Drees Reaty, Inc.
IMO Company, Inc
InterCoast Capita Company
InterCoast Energy Company
InterCoast Power Company
InterCoast Sierra Power Company
Iowa Realty Company, Inc
Iowa Realty Insurance Agency, Inc
Iowa Title Company
IWGCo8
J.S. Whte Associates, Inc
JBRC,Inc.
JD Reee Mortgage Company
Jenny Prtt & Associates
Jim Huff Realty, Inc.
JP &A, Inc
JRHW Realty, Inc d//a RealtySouth
Kasas City Title, Inc
Kern River Funding Corporation
KR Holding, LLC
Laabee School of Real Estate & Insurance
MEC Constrction Services Company
MEHC Insurance Services Ltd.
MEHC Investment, Inc
MHC Investmnt Company
MHC,Inc
Mid-America Referral Network, Inc.
MidArican Comercial R.E. Services, Inc
MidAerican Energy Company
MidArican Energy Holdings Company
MidArican Services Company
Midland Escow Servces, Inc
Midwest Caita Group, Inc
Midwest Gas Company
MW Capital, Inc
Nebraska Land Title & Abstract Company
Nortern Aurora Inc
Nortern Natural Gas Company
Pickford Escow Company, Inc
Pickford Rea Estate, Inc
Pickford Servces Company, Inc
Prferred Caolina Realty, Inc
Professional Referr Organzation, Inc
Qu Cites Energy Company
Real Estate Link, LLC
Real Estate Referral Network, inc
Reee & Nichols Alliance, Inc
Reece & Nichols Realtors, Inc
Referral Company of North Carolina. Inc
Robert Brothers, Inc
Robert Holding Company, Inc
Roy H. Long Realty Company, Inc
Salton Sea Mineras Corpration
San Diego PCRE, Inc
Semonin Reators, Inc
Th Escrow Fir
The Referral Company
Trinity Mortgage Parers, inc
TI, Inc of South Dakota
Two Rivers, Inc
Woos Bros. Realty, Inc
............................................
Name of Respondent This Report is:Date of Report Year/Penod of Report
(1) !ÇAn Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
With Respect to members of the MEHC Sub-Group,. MEHC requires all subsidiaries to payor receive from MEHC an
amount of ta based primarily on the stand alone method of allocation. The computation includes all ta benefits from ta
deductions stemmng from cost borne by utity customers.
Berkshire Hathaway Inc. Sub-Group:
21st Communities, Inc.
21st Mortgage Corpration
21st SPC, Inc.
(FERC FORM NO.1 (ED. 12-87)
AAS-Lunken, Inc.
Acme Brick Block and Tile, Inc.
Acme Brick Company
Page 450.6
............................................
Name of Respondent This Report is:Date of Report Year/Penod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub.Group:
Acme Brick DFW, Inc.
Acme Brick Sales Company
Acme Building Brands, Inc.
Acme Investment Company
Acme Management Company
Acme Services Company, L.P.
AdaletlScott Fetzer Company
ABG Processing Center No. 58, Inc.
ABG Processing Center No. 35, Inc.
Agile Mfg, Inc.
AJ Warehouse Distrbutors, Inc.
AUX Homes, Inc.
Alachua Tung Oil Company
Albecca Inc.
Alexander City Flying Services, Inc.
Al Bilt Uniforms
Alpha Cargo Motor Exress, Inc.
American All Risk Insurance Services, Inc.
American Commercial Claims Administrators, Inc.
Amrican Dair Queen Corporation
American Employers Group, Inc.
American Tile Supply, Inc.
Anderson Hardwood Floors, Inc. (fk Shaw-Razor Floors)
Apeks Apparel, Inc.
Appalachian Engineered Floors, Inc.
Applied Group Insurance Holdings, Inc.
Applied Investigations Inc.
Applied Logisitics, Inc.
Applied Premium Finance, Inc.
Applied Processing Center No. 60, Inc.
Applied Risk Services of New York, Inc.
Applied Risk Services, Inc.
Applied Underwriters, Inc.
Ardent Risk Services
AR Holding, LLC
AU Captive Risk Assurance Co
AU Captive Risk Assurance Co., Inc.
AU Holding Company, Inc.
AU! Employer Group No. 42, Inc.
Ben Bridge Jeweler, Inc.
Benjamn Moore & Co.
Berkshire Hathaway Credit Corp.
Berkshi Hathaway Finance Corporation
Berkshire Hathaway Inc. (Common Parent)
Berkshire Hathaway Life Insurance Co. of NE
Berksire Hathaway Assurance Company
BH Columbia Inc.
BH Shoe Holdings, Inc.
BHG Strctued Settlements, Inc.
BHRlnc.
BHSF, Inc.
Blue Chip Staps
I FERC FORM NO.1 (ED. 12-87)
BNJ NeÜets, Inc.
Boar U.S. Travel International, Ltd.
Boat America Corporation
Boat U.S" Inc.
Boot Royalty Company
Borsheim Jewelry Company Inc.
BR Agency, Inc.
Bricker-Mincolla Uniform
Brillant National Services, Inc.
Brooks Sport, Inc. & Subsidiar
Brookwood Insurance Company
Business Wire Canada Inc.
Business Wire, Inc.
C & R Insurance Services, Inc.
Californa Employer Group No. 27, Inc.
California Insurnce Company
Camp Manufactung Company
Campbell Hausfeld/Scott Fetzr Company
Carefree/Scott Fetzr Company
Central States Indemnty Co. of Omah
Central States of Omaa Companes, Inc.
CG Service, Inc.
Chippewa Shoe Company
er II, Inc.
Claims Servces, Inc.
Clayton Commercial Buildings, Inc.
Clayton Homes, Inc.
CMH Capita, Inc.
CMH Hodgenvile, Inc.
CMH Homes, Inc.
CMH Manufacturng West, Inc.
CMH Manufacturng, Inc.
CMH of KY, Inc.
CMH Parks, Inc.
CMH Services, Inc.
CMH Set and Finish, Inc.
Cologne Services Corpration
Columbia Insurance Company
Combined Claims Servces, Inc.
Commnd Uniform
Commercial General Indemnty, Inc.
Commonwealth Uniform Inc.
Continental Divide Insurance Co.
Continenta Indemnity Company
Cornhusker Casualty Company
CORT Business Services Corporation
Coverage Dynamics Group, Inc.
Cresent Paint & Decorating Inc.
Criterion Insurance Agency
Cross Creek Apparel, LLC
Cross Creek Holdings, Inc
Crowley Garent Mfg Co Inc.
Page 450.7
Berkshire Hathaway Inc. Sub-Group:
Crowley Shirt Mfg Co Inc.
CSI Life Insurance Company
CTB Credit Corp.
CT International Corp.
CTB IP, Inc.
CTB MN Investments Co. Inc.
CTB,lnc.
Cumberland Asset Management, Inc.
Cypress Insurance Company
Dairy Queen Corporate Stores, Inc.
Dai Queen of Georgia, Inc.
Delta Veneer Investors, LLC
Denver Brick Company
Dexter Shoe Company
DQ Funding Corporation
DQ Joint Venture Stores, Inc.
DQ Managed Stores, Inc.
DQ Wholly-Owned Stores, Inc.
DQF,lnc.
DQGC, Inc.
Eatech Chemical
Edonds Material and Equipment Co.
Elm Street Corporation
Employers Insurance Services, Inc.
Eureka Brick and Tile Company
Executive Jet Europe, Inc.
Executive Jet Management, Inc.
Expertos, S.A. de C.V.
Faield Insurance Co.
Faraday Capital Limited
Farors, Inc.
Fayett Cotton Mil, Inc.
Finial Holdings, Inc.
Finial Insurance, Inc.
Finial Reinsurance Company
First Berkshire Hathaway Life Insurace Company
FlightSafety Capital Corp.
FlightSafety China, Inc.
FlghtSafet Development, Inc.
FlightSafety International Inc.
FlightSafety New York, Inc.
FlightSafety Propertes, Inc.
FlightSafety Services Corpration
FlightSafety Texas, Inc.
Floors Inc.
Footwear Investment Company
Forest River Financial Services, Inc.
Forest River Housing, Inc.
Forest River Warnty Company
Forest River, Inc.
France/Scott Fetzr Company
Freedom Warehouse Corp.
I FERC FORM NO.1 (ED. 12-87)
Fruit of the Loom Carbbean, Inc.
Frut of the Loom Texas, Inc.
Fruit of the Loom Trading Company
Frut of th Loom, Inc.
Fruit of the Loom, Inc.
FSI Delaware Holding Corp.
FT Regional Sales Co., Inc.
FT Sales Company, Inc.
Garn Central America Corp.
Garan Incorporated
Garn Manufactung Corp
Gar Services Corp
Gateway Underwiters Agency,Inc.
GEICO Casuaty Company
GEICO Corporation
GEICO General Insurance Company
GEICO Indemnty Company
GEICO Products, Inc.
Gen Re Caita Consultats, Inc. fIa General Re
Gen Re Intermiares Corporation
Genera Re Assets Investment (I), Inc.
Genera Re Corporate Finance, Inc.
General Re Corpration
Gener Re Financial Products Corpration
General Re Funding Corporation
General Re Investmnt Holdings Corporation
Genera Re New England Asset Management
General Re Services Corpration
General Reinsurance Corpration
Genera Sta Indemnty Company
General Sta Management Company
Genera Sta Nationa Insurance Company
Genesis Indemnty Insurance Company
Genesis Inurce Company
Genesis Prfessiona Liabilty Underwters
Genesis Underwting Management Company
GenRe Gisboure LLC
Giles Industres, Inc.
GMK, Ltd.
Golden Skillet International, Inc.
Governent Employees Financial Corporation
Governnt Employees Insurance Company
GRD Corporation
GRD Global, Inc.
GRD Holdings Corpration
Griffey Uniform
H.H.Brown Shoe Company,Inc.
H.H.Brown Shoe Technologies,lnc.
H.J. Justin and Sons, Inc.
HalexlScott Fetzer Company
Hall of Fame Paint Supply Inc.
Hardy Frames, Inc.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 04/0312008 2oo7/Q4
FOOTNOTE DATA
Page 450.8
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group:
Hars Uniform
Harson Uniform
HDS Redevelopment Corporation
Helzberg's Diamond Shops, Inc.
Henley Holdings, LLC
Homefirst Agency, Inc.
Homemakers Plaza, Inc.
Indecor Group Inc. dl/a J.C.Licht Company
Innovative Building Products, Inc.
Insurance Counselors of Nevada, Inc.
Insurance Counselors,Inc.
International Dairy Queen, Inc.
International Insurance Underwters,Inc.
Isabela Shoe Corporation
J. S. Justin, Inc.
JanoviclPlaz Inc.
JM Contracting Services, Inc.
Johns Manvile China, LTD.
Johns Manvile Corporation
Johns Manvile, Inc.
Jorda's Furnitue, Inc.
Justin Belt Company, Inc.
Justi Boot Company
Justin Brands, Inc.
Justin Industres, Inc.
Justin Royalty BV
Kae Uniform
Kasas Baners Surety Company
Kae1korn Shoppes, Inc.
Kay Uniform
Kleberg Holdings, Inc.
LA Termnals
Lesburg Yam Mils, Inc.
M & C Products, Inc.
Macro Retaling, Inc
Mapletree Transporttion, Inc.
MarneSafety International, Inc.
Marin Manufacturing Company
Marin Mils, Inc.
Marland Ventures, Inc
McCain Uniform Company Inc.
McCar-Hull Cigar Company, Inc.
McLane Company, Inc.
McLane Eastern, Inc.
McLane Express, Inc.
McLane Foodservice, Inc.
McLane Mid-Atlantic, Inc.
McLane Minnesota, Inc.
McLae New Jersey, Inc.
McLae Southern, Inc.
McLae Suneast, Inc.
McLane Western, Inc.
McLane Midwest, Inc.
Medical Protective Corporation
Medical Protective Finance Corporation
Medical Protective Insurance Services, Inc.
Metro Uniforms
MH Transport, Inc.
MiTek Framngs, Inc.
MiTek Holdings, Inc.
MiTek Industres, Inc.
MiTek, Inc.
MM Corporation
Mobile Disaster Strctues, Inc.
Mossy Oak Apparel Company
Mount Vernon Fire Insurance Company
Mountan View Marketing, Inc.
Mouser Electronics, Inc.
MS Propert Company
MTSub,Inc.
National Fire & Marne Inurce Co.
National Indemnty Company
National Indemnty Company of Mid-America
National Indemnty Company of the South
National Liabilty & Fire Insurance Co.
National Reinsurance Corporation
Nationwide Uniform
Nebraska Furnitu Mar, Inc.
NetJets Aviation Inc.
NetJets Europe Holdings u.C
NetJets Inc.
NetJets International Inc.
NetJets Lage Aicraf, Inc.
NetJets Leasing, Inc.
NetJets M E Inc.
NetJets Sales Inc.
NetJets Services Inc.
NetJets U.S., Inc.
NF of Kasas, Inc.
Nick Bloom Uniform
NJ Executive Services Inc.
NJA Jets Inc.
NJE Holdings u.C
NJI Sales Inc.
NJI, Inc.
Nocona Boot Company
Nort American Casuaty Co
Nort Sta Reinsurance Corporation
Nort Sta Syndicate, Inc.
Northern States Agency, Inc.
Northland/Scott Fetzer Company
Oak River Insurance Company
OBHInc.
OCSAP,Ltd.
I FERC FORM NO.1 (ED. 12-87)Page 450.9
Berkshire Hathaway Inc. Sub-Group:
Old City Paint & Decorating, Inc.
Orange Julius of America
Paint Rental Associates Inc.
Pan-Am Shoe Co., Inc.
Pennsylvania Reinsurance Company
Pima Uniform
Pinnacle Paint & Decoratig, Inc.
Plaza Financial Services Co.
Plaza Paint & Decorating Centers Inc.
Plaza Resources Co.
Ponce Fashions, Inc.
Portand Gold Corp. d//a! Maine Paint Service
Precision Brand Products
Precision Steel Warehouse - Chalott
Precision Steel Warehouse - Frain Park
Pnority One Financial Services, Inc.
Pro Instalations, Inc.
Professional Datasolutions, Inc.
Promesa Health, Inc.
Queen Caet Corpration
R.C.Wiley Home Furnishings
Rabun Apparel, Inc.
Rainbow State Paint & Decorating Inc.
Redwood Fire and Casualty Insurance Co.
RENTCD Trailer Corporation
Republic Insurance Company
Resolute Management Inc.
Richline Group, Inc.
Ringwalt & Liesche Co
Rintel Propertes, Inc.
Robert f. deCastro Inc.
Roberts Men's Shop
Running with Heels
Russell Asset Management, Inc.
Russell Corporation
Russell Financial Services, Inc.
Russell Servicing Company, Inc.
Salado Sales, Inc.
Salt Lae Paint
Scott Fetzer Financial Group, Inc.
Scottare Corporation
Seattle Paint Supply, Inc.
Seaworty Insurance Company
See's Candies, Inc.
See's Candy Shops, Inc.
Seventeenth Street Realty, Inc.
Shaw Contract Flooring Installation Servces, Inc.
Shaw Contract Flooring Services, Inc.
Shaw Diversified Services, Inc.
Shaw Floors, Inc.
Shaw Funding Company
Shaw Industres Group, Inc.
Shaw Industres, Inc.
Shaw International Services, Inc. (fka Shaw Financial)
Shaw Retal Propertes, Inc.
Shaw Transport, Inc.
SHX Flooring, Inc.
SHX Leasing, Inc.
Silver State Uniform
Simon's Incorprated
SocoWest
Soff Shoe Company, Inc.
Sol Fran Uniform Inc.
Somerset Servces
Southern Energy Homes of Nort Carolina, Inc.
Southrn Energy Homes of Pennsylvania, Inc.
Southrn Energy Homes Retal Corp.
Southern Energy Homes, Inc.
Soutwest Paint & Decorating Inc.
StaScott Fetzr Company
Stadard Plywoods, Inc.
Sta Furtue Company
Stonyrdge Trust
Strategic Staff Management, Inc.
Strck Mexicana, S.A.
Techncal Coatings Co.
The Ben Bridge Corpration
The BVD Licensing Corp.
1b Eagle Company
The Fechhimer Brothers Co.
The Indecor Group, Inc.
The Koskovich Company, Inc.
The Medical Protective Company
The Pampered Chef Nort America, Ltd
The Pampered Chef, Ltd
The Scott Fetzer Company
Tony La Company
Top Five Club, Inc.
TP - European Holdings, Ltd.
Transco, Inc.
lT, Inc.
lT, Inc.
U.S. Investment Corporation
U.S. Liabilty Insurance Company
U.S. Underwiters Insurance Company
Undergarnt Fashions, Inc.
Unified Supply Chain, Inc.
Uniform of Texas
Union Sales, Inc.
Union Underwear Co., Inc.
Unione Itaian Reinsurance Company of America, Inc.
United Consumer Financial Servces, Inc.
Unite Dirt Finance Inc.
United States Aviation Underwrters, Inc.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) XAn Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 0410312008 2007/Q4
FOOTNOTE DATA
IFERC FORM NO.1 (ED. 12-S7) Page 450.10
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group:
Universal Uniform
Vanderbilt ABS Corp.
Vanderbilt Mortgage & Finance, Inc.
Vanderbilt Propert & Casualty Insurance Co., Ltd.
Vanderbilt SPC, Inc.
Vanity Fair Brands, Inc.
Vanty Fai Inc.
Vanity Fai Ventues, Inc.
Veritas Insurance Group, Inc.
Vessel Assist Association of America, Inc.
Vessel Assist Insurance Services, Inc.
VF Credit Corporation
VF-Mexico, Inc.
Virginia Paint Co., Inc.
Vision Retaling
Walterboro Veneer Company, Inc.
Wayne/Scott Fetzr Company
Waynesburg Shi Company Inc.
Wenco Financial, Inc.
Wesco Financial Corporation
Wesco Holdings Midwest, Inc.
Wesco-Financial Insurance Co.
West Virginia Uniforms
WesternScott Fetzer Company
Wheeler Brick Company, Inc.
Whttaker, Clark & Daniels
Witt Brick & Supply, Inc.
WMCCorp.
Woodperfect, Inc.
World Book Encyclopedia, Inc.
World Book, Inc.
World Book/Scott Fetzr Company, Inc.
Worldbook.com Inc.
X-L-CO., Inc.
XLI, inc.
XTR,Inc.
XT Chassis, Inc.
XT Companies, Inc.
XTRA Corporation
XT Finance Corporation
XT Intermodal, Inc.
XTRA International Pacific, LTD.
XT International, LTD.
XT Mexicana, S.A. de C.V.
Zuckerbergs Uniforms
IFERC FORM NO.1 (ED. 12-S7) Page 450.11
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 04031
TAXES ACCRUED, PREPAID AND CHAF GED DURING YEAR
1. Give particulars (details) of the cobined prepaid and accrued tax acunts an show the total taxes charged to operations and other accunts dunng
the year. Do not include gasoline and other sales taxes which have been charged to the accunts to which the taed matenal was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote an designate whther estimated or actual amounts.
2. Include on this page, taxes paid dunng the year and charged dire to final accnts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not afeced by the inclusion of these taes.
3. Include in column (d) taxes charged dunng the year, taes charg to opra and oter accunts through (a) accals credited to taes accrued,
(b)amounts credited to proportions of prepaid taes chargeable to current year, an (c) taes paid and charged direct to operations or accounts other
than accrued and prepaid tax accunts.
4. List the aggregte of each kind of ta in such manner that the tota ta for each Slae and subdivision can readily be ascertained.
ILine Kind of Tax BALANCE AT BEGINNING OF YEAR chi:~~T~'l Adjust-No.(See instructon 5)Taxes Accn,eØ i:repai.d Taxes . ~nng ~i?g ments(Account 236)(Include in Accunt 165)ear(a)(b)(c)(d)(e)(1)
1 Federal:
2 Incme 38,948,947 144,551,84 132,785,09 3,854,556
3 FICA 352,142 24,571 32,848,762 32,850,336
4 Unemployment 1,172 371,625 361,55
5 Unemployment - Energ 47,84 182,451 100,790
6 Unemployment - Interwest 257 1,721 1,870
7 Excise Tax - Col 132,49 4,070,04 4,117,778
8 Subtotal 533,90 38,973,518 182,026,44 170,217,426 3,854,556
9
10 State:
11
12 Anzon:
13 Propert 94,168 1,954,321 1,922,32
14 Income 514,721 317,480 378,905 19,86
15 Subtotal 945,168 514,721 2,271,801 2,301,23 19,863
16
17 Califoria:
18 Propert 1,85,687 1,850,687
19 Unemployment 1,392 23,536 24,608
20 Franchise-Income -84,84 651,561 815,585 40,766
21 Regulatory Commission 4,84 4,84
22 Use 48,379 199,695 199,286
23 Lol Franchise 677,131 978,96 90,262
24 Subtot 726,90 -84,84 3,709,288 3,801,271 40,766
25
26 Colorado:
27 Propert 1,752,00 1,776,603 1,768,603
28 Incoe 314,924 153,909 1,581 9,629
29 Subtotal 1,752,00 314,924 1,930,512 1,770,184 9,629
30
31 Idaho:
32 Propert 1,468,96 2,470,100 2,455,109
33 Income 168,626 1,231,112 1,295,026 77,028
34 KWh 500 20,960 20,96
35 Unemployment 1,901 34,007 34,912
36 Regulatory Commission 347,005 347,005
37 Use 25,986 217,289 239,435
38 Subtotal 1,497,353 168,626 4,320,473 4,392,447 77,028
39
40 Montana:
41 TOTAL 21,123,323 51,795,841 320,614,257 309,517,839 4,123,743
FERC FORM NO.1 (ED. 12-96)Pag 26
............................................
............................................
Name of Respondent This '00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2oo7/Q4
(2) DA Resubmission 04/0312008
TAXES ACCRUED, 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,
identifyng the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (1) 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 collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (i) how the taxes were distributed. Report in column (I) only the amounts charged to Acnts 408.1 and 40.1
pertining to electric operations. Report in column (i) the amounts charged to Accunts 408.1 and 109.1 pertaining to other utility departents and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taes charged to utility plant or other balance sheet accounts.
9. For any ta apportioned to more than one utilty department or account, state in a footnote the basis (necessity) of apprtioning such ta.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Elecric Exraordinary Items . AOjustments to ~~i.Other No.
ACCO~SJ 236)(Inc!. in Account 165)(Acount 408.1. 40.1)(Account 409.3)Earnings (Accunt 439)
(h)(i)(j)(k)(I)
1
31,036,759 125,610,768 2
365,997 40,00 3
11,241 4
129,509 5
108 6
84,758 7
591,613 31,076,759 125,610,768 56,415.6n 8
9
10
11
12
9n,160 1,954,321 13
596,00 272.5n ~9n,160 596,009 2,226,898 44,90315
16
17
1,825,141 18
320 19
119,942 559,40 ".20
21
48.788 22
749,835 978,96 23
798.94 119,942 3.363.513 34.n5 24
25
26
1,760,00 1,n5,929 ~172.225 132,141
1,760,00 172,225 1,908.070 22,42 29
30
31
1,483,957 2,467,20 32
309,568 1,056,987 33
500 20,960 34
996 35
36
3,840 37
1,489,293 309,568 3.545,153 n5,320 38
39
40
20,901.699 44.601,542 242,707,061 n,907,196 41
FERC FORM NO. 1 (ED. 12-96)Page 26
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) EjA Resubmission 04/03
TAXES ACCRUED, PREPAID AND CHAI GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accunts an show the total taxes charged to operations and other acconts during
the year. Do not include gasoline and other sales taxes which have ben charged to the accunts to which the taed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote an designate whether estimated or actual amounts.
2. Include on this page, taes paid during the year and charged dire to final accunt, (not chaed to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balaning of this page is not affeced by the inclusion of these taes.
3. Include in column (d) taes charged during the year, taes charged to operations and other accunts through (a) accrus credited to taxes accrued,
(b)amounts credited to proportions of prepaid taes chrgble to currnt yer, an (c) taes pad and charged direct to operations or acconts other
than accrued and prepaid tax accounts.
4. Ust the aggregate of each kind of tax in such manner that the tota ta for each State and subdivision ca readily be ascertained.
ine Kind of Tax BALNCE AT BEGINNING OF YEAR
:;1i¡es i~~Adust-C argedNo.(See instructon 5)l axes AÇcruep ~repa~CJ_! axes
~tfli?g ~~?g ments(Account 236)(Include in Account 165)(a)(b)(c)(d)(e)(f)
1 Propert 1,263,200 2,387,678 2,458,521
2 Corprate Ucense-Incme 301,026 158,956 169,397 9,94
3 Energy Ucense 58,459 231,921 227,704
4 Wholesale Energy 40,679 166,221 162,243
5 Subtotal 1,362,33 301,02 2,94,n6 3,017,86 9,94
6
7
8 New Mexio:
9 Propert 5,397 11,031 10,912
10 Income 96 982 60
11 Subtota 5,397 11,997 11,894 60
12
13 Oregon:
14 Propert 8,111,05 15,956,889 15,730,982
15 Unemployment 29,010 96,978 957,119
16 Wilsonvlle Payrll 649 1,117 1,397
17 Regulatory Commission 2,502,769 2,502,769
18 Excie.lncome -95,134 7,930,158 6,658,111 496,168
19 Cit of Portland-Income 101,63 6,34 3,00 39720Ofce of Energy 20,569 489,288 571,43
21 Tri-Met 361,336 791,30 812,38
22 Lane Coty 3,081 3,081
23 Frahise 2,805,400 20,426,637 19,432,148
24 Subtotal 3,196,395 7,46,118 49,075,565 46,672,425 496,565
25
26
27 Utah:
28 Propert 288,593 34,140,315 34,100,492
29 Income 4,144,756 7,746,091 9,450,228 484,651
30 Unemployment 17,66 35,330 353,930
31 Regulatory Commission 3,556,709 3,556,709
32 Navajo Nation 7,34 7,34
33 Use 297,291 3,332,673 3,356,406
34 Gros Receipts 2,46,802 2,464,802
35 Subtotal 3,068,354 4,144,756 49,133,46 53,289,912 484,651
36
37 Washington:
38 Property 3,350,00 4,258,589 3,30,589
39 Unemployment 1,956 72,796 71,287
40 Business & Ocupation 3,072 9,174 7,384
41 TOTAL 21,123,323 51,795,841 320,614,257 309,517,839 4,123,743
FERC FORM NO.1 (ED. 12-96)Page 262.1
............................................
............................................
Name of Respondent This f!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 0403/2008
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 ta year,
identifng the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taes or taes collected through payrll deductions or otherwise pending
transmittal of such taes to the taing 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 Acounts 408.1 and 109.1 pertaining to other utiity departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (i) the taes charged to utilty plant or other balance sheet account.
9. For any tax apportioned to more than one utilty department or account, state in a footnote the bais (necessity) of apportioning such ta.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Exraordinary Items Adiustments to Het.Other No.AccO~m236)(Inc!. in Account 165)(Account 408.1, 409.1)(Account 409.3)Earnings (Account 439)
(h)(i)ul (k)(i)
1,192,357 2,387,678 1
321,413 136,474 ~62,676 231,921 3
44,657 166,221 4
1,299,690 321,413 2,922,294 22.482 5
6
7
8
5,516 11,031 9
76 828 ~5,516 76 11,859 138 11
12
13
4,121 7,889,26 15,862,312 14
39,869 15
369 16
17
-1,729,013 6,808,539 18
98,68 5,447 19
285,719 489,288 20
340,260 21
22
3,799,889 20,426,637 23
4,184,508 6,54,656 43,592,223 5,48,342 24
25
26
27
328,416 31,081,518 28
6,33,544 6,650,506 29
14,06 30
31
7,345 32
273,558 33
34
616,042 6,33,54 37,739,369 11,394,09 35
36
37
4,30,000 4,146,198 ~3.465 39
4,862 9,174 40
20,901,699 44,601,542 242,707,061 n,907,196 41
FERC FORM NO.1 (ED. 12-9)Page 263.1
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) CiA Resubmission 04031208
TAXES ACCRUED, PREPAID AND CHAI GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accunts and show the tota taxes charged to operations an other accounts during
the year. Do not include gasoline and other sales taes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accunts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the totl tax for each State an subdision can readily be ascertained.
ILlne Kind of Tax BANCE AT BEGINNING OF YEAR ~ires i~r¡Adjust-C argècNo.(See instruction 5)l=~~~re.ci Taxes ~nng ~~?g ments(Incude in Acunt 165)ear(a)(b)(c)(d)(e)(1)
1 Public Utilty 720,226 8,666,551 8,530,36
2 Regulatory Commission 430,44 43,44
3 Use 31,611 614,373 606,260
4 Retailng 29 156 156
5 Land Tax 58 58
6 Subtotal 4,106,894 14,052,140 12,954,541
7
8 Washington D.C.:
9 Unemplyment
10 Franchise-Income 747 -2,582 47
11 Subtotal 747 -2,582 47
12
13 Wyoming:
14 Proprty 3,582,241 7,326,653 7,243,529
15 Propert - Glenrock
16 Unemployment 2,448 134,398 133,n2
17 Other Payroll Taxes 141 141
18 Regulatory Commission 891,463 891,463
19 Franchise 187,80 1,34,369 1,33,869
20 Use 139,672 1,126,859 1,188,746
21 Annual Report 35,319 35,319
22 Subtota 3,912,161 10,858,202 10,823,839
23
24 State Other -869,368
25
26 Miscellaneous:
27 Goshute Possessory
28 Sho-Ban Possesory 131,599 131,599
29 Navaj Possessory 16,452 33,746 33,325
30 Ute Posesry 9,54 9,543
31 Crow Possessory 59,130 59,130
32 Umatila 50,615 50,615
33 Other Taxes -5,785 -16,829
34 Subtotal 16,452 278,848 267,383 -869,36
35
36
37
38
39
40
41 TOTAL 21,123,323 51,795,841 320,614,257 309,517,839 4,123,743
FERC FORM NO.1 (ED. 12-,)Page 262.2
............................................
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04/0312008
TAXES ACCRUED, PREPAID AND CHARGED DU ING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the reuired information separately for each tax year,
identifing the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittl of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (i) only the amounts charge to Acunts 408.1 and 409.1
pertaining to elecri operations. Report in column (I) the amounts charged to Accunts 408.1 and 109.1 pertaining to other utilit departents and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taes charged to utlit plant or other balance sheet accunts.
9. For any ta apportioned to more than one utilty department or account, state in a footnote the basis (necessity) of apprtioning such ta.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Exraordinary Items . AO)Ustments to Hat.Oter No.Aco~SJ 236)(Incl. in Account 165)(Account 408.1, 409.1)(Account 409.3)Eamings (Acunt 439)
(h)(i)(j)(k)(i)
856,413 8,666,551 1~39,724
29 156 4
58 5
5,204,493 12,822,137 1,230,003 6
7
8
9
-3,282 641 ~-3,282 641 106 11
12
13
3,665,365 7,306,459 14
15
3,074 16
141 17
18
200,300 1,343,369 19
77,785 20
35,319 21
3,946,524 8,685,288 2,172.914 22
23
-869,368 24
25
26
27
131,599 28
16.873 33,746 29
9,543 30
59,130 31
50,615 32
11,04 -5,785 33
27,917 -869,368 278,848 34
35
36
37
38
39
40
20,901,699 44,601,542 242,707,061 77,907,196 41
FERC FORM NO.1 (ED. 12-96)Page 263.2
......i.i......I.i.i....I.i.i.......................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 040312008 2007/04
FOOTNOTE DATA
Account
Taxes Applicable to Oter Income and Deductions- 408.2,409.2 $ 45,121Distribution Rent Expense, Rents - 589 49,456Total $ 94,577
Išhedule Page: 262.1 Line No.: 15 Column: i
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 04/0312008 2007/Q4
FOOTNOTE DATA
V arious Operations and Maintenance Accounts.
~chedule Page: 262.1 Line No.: 16 Column: i
Varous 0 erations and Maintenance Accounts.
chedule Pa e: 262.1 Line No.: 17 Column: I
Re ulatory Commssion Ex ense Account - 928
chedule Pa e: 262.1 Line No.: 18 Column: i
State Income Tax - Other Income & Deductions - 409.2
~chedule Page: 262.1 Line No.: 19 Column: I
State Income Tax - Other Income & Deductions - 409.2
!Sheule Page: 262.1 Line No.: 21 Column: i
Varous Operations and Maintenance Accounts.
¡Schedule Page: 262.1 Line No.: 22 Column: i
V arious Operations and Maintenance Accounts.
i,chedule Page: 262.1 Line No.: 28 Column: i
14,400
1,984,418
83,054
976,925
$ 3,058,797
Line No.: 38 Column: i
Account
Taxes Applicable to Other Income and Deductions- 408.2,409.2
Distrbution Rent Expense, Rents - 589
Total
~chedule Page: 262.1 Line No.: 39 Column: i
Varous Operations and Maintenance Accounts.
\Shedule Page: 262.2 Line No.: 2 Column: i
Regulatory Commssion Ex ense Account - 928
chedule Pa e: 262.2 Line No.: 3 Column: i
Clearng Account - 184
/Šchedule Page: 262.2 Line No.: 10 Column: i
State Income Tax - Other Income & Deductions - 409.2
!ShedUle Page: 262.2 Line No.: 14 Column: i
$ 109,130
3,261
$ 112,391
Taxes Applicable to Other Income and Deductions- 408.2,409.2
Distribution Rent Expense, Rents - 589
Tota
~chedule Page: 262.2 Line No.: 16 Column: i
Varous Oprations and Maintenance Accounts.
¡Schedule Page: 262.2 Line No.: 18 Column: i
Re ulatory Commssion Ex ense Account - 928
chedule Pa e: 262.2 Line No.: 20 Column: i
Clearng Account - 184
IFERC FORM NO.1 (ED. 12-87)
Account
$ 16,610
3.584
$ 20,194
Page 450.2
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04031200
ACCUMULA ED DEFERRED INVESTMENT TAX REDITS (Acnt 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utilty and
nonutilityoperations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i)
the average period over which the tax credits are amortized.
ine S bCd~o.u~t a ancgf~earginning Deferred for YearNo. u nv(sions (b) ccoun o. oun~ ~ ~
Year/Period of Report
End of 2O7/Q4
1 Electric Utilty
23%
34%
47"10
14,371,314 420
14,371,314 -12,167,578
FERC FORM NO.1 (ED. 12-89)Page 266
............................................
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) nA Resubmission 0403/2008
ACCUMULATED D FERRED INVESTMENT TAX CRED TS (Account 255) (continued)
~ADJUSTMENT EXPLANATION Uneof Year of AI ocation No.to Incomeh i i-
1
2
3
4
40,618,437 30/35 5
10,543,126 6
843,329 7
52,00,892 8
9
10
11
12
1,762,928 32 13
14
1,762,928 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
......i.i..I.,..................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
!Schedule Page: 266 Line No.: 5 Column: e
46(t)2
!Schedule Page: 266 Line No.: 6 Column: e46(t)
!Schedule Page: 266 Line No.: 6 Column: g
Reclass from Non-Utility
ISchedule Page: 266 Line No.: 13 Column: g
Reclass to Utility
IFEAC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Blank Page
(Next Page is 269)
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 040318
o HER DEFFERED CREDITS (Account 253)
1. Report below the particulars (detals) called for conceming '?ther deferred credits.
2. For any deferred credit being amortzed, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Acount 253 or amounts les than $10,00, whichever is greater) may be groped by clases.
Line Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beinning of Year Contra Amount Credits End of Year
(b)
Acunt(a)(c)(d)(e)(1)
1 Cogeneration Bonds - Sunnyside 413,417 413,417
2
3 Working Capital Deposit DG&T 1,253,297 290,847 1,54,144
4
5 Workng Cata and Coal Pile
6 Deposits from Provo City 273,00 273,00
7
8 Working capital depoit from UAMPS 245,00 306,00 551,000
9
10 Recamation Costs - Traper Mine 3,766,482 270,9n 4,037,459
11
12 Reclamation Costs - Deseret Mine 55,643 131 6,601 548,042
13
14 Reclamation Costs - Trail
15 Mountin Mine 1,146,738 131 15,200 1,131,53
16
17 Deferred Copensation - PPL 2,479,60 124 748,537 118,824 1,849,893
18
19 Transmision Servce Depit 1,631,94 33,94 11,859,60 13,155,60
20
21 Def. Credits - Rights of Way 4,189 56 4,189 230,00 230,00
22
23 MCI F.O.G. wire lease 558,678 45 3,351,021 3,350,811 558,468
24
25 Reding Contract (20)4,95,06 456 549,99 4,40,06
26
27 Foote Creek Contract (15)1,118,222 142 137,64 980,582
28
29 Environmental Liabilities -
30 Centralia Plant 154,830 506 117,571 61,058 98,317
31
32 Enviromental Liabilties -
33 Centralia Mine 3,22,248 50.3 4,143 102,550 3,32,655
34
35 Wyoming Joint Powers Water
36 Board Settlement (7)975,00 232 30,00 675,00
37
38
39 Unearned Joint Use Pole Cotract 3,520,283 45 8,58,662 8,641,728 3,5n,349
40
41 Oregon DSM Loans NPV Uneamed 1,688,955 456 272,465 1,416,490
42
43 Exec Trust Comp Reduction Plan 15,992,639 124 7,1n,250 1,421,098 10,23,48
44
45 Miscellaneous Securiy Deposits 23,012 23,012
46
47 TOTAL 61,791,513 37,332,379 35,068,828 59,527,96
FEHC FORM NO.1 (ED. 12-94)Page 269
............................................
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 04/03/2008
0 HER DEFFERED CREDITS (Account 253)
1. Report below the particulars (details) called for concerning ?ther deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $10,000, whichever is greater) may be groupe by classes.
Une Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
(a)(b)Account
(e)(c)(d)(1)
1 Environmenta Uabilties -
2 Non-Curren 9,631,750 182.3 8,502,461 1,319,884 2,449,173
3
4 Deseret Power Security Deposits 535,725 24,530 560,255
5
6 Deferred Revenue -
7 Lease Incentives (10)358,395 931 62,756 295,639
8
9 Other Deferred Credits - C& T 2,739,745 4,1n,961 5,34,129 3,90,913
10
11
12 Softare Ucense Payments 1,064,748 560 532,374 532,374
13
14 Deferred Revenue -
15 Duke/Hermiston Gas Settlement (5)3,428,226 754,839 2,673,387
16
17 Other Deferred Credits 55,673 557 194,565 163,392 24,50
18
19 Emission Allowance Sales Procees 411.8 1,502,200 1,503,60 1,400
20
21 Mil Fork Lease Bonus Payment 58,800 58,80
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 61,791,513 37,332,379 35,06,828 59,527,962
FERC FORM NO. 1 (ED. 12-9)Page 269.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0403/2008 2007/Q4
FOOTNOTE DATA
¡Schedule Page: 269 Line No.: 19 Column: c
Accounts
252
555
!Schedule Page: 269.1 Line No.: 9 Column: c
Accounts
555
242
!Schedule Page: 269.1 Line No.: 15 Column: c .
Accounts
547
555
I FERC FORM NO.1 (ED. 12-87) Page 450.1
-...........................................
Blank Page
(Next Page is 272)
Name of Respondent
PacifCorp
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmision 040312008
ACCUMULATED DEFERRED INCOME TAXES. ACCELERATED AMORTIZATION PROPERTY (Account 281)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to amortizable
propert.
2. For other (Specify),include deferrals relating to other income and deductions.
Year/Period of Report
End of 2007/04
Line
No.
CHANGES DURING YEARAccountBalance at
Beginning of Year Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Account 411.1
(d)(a)
1 Aclerated Amortization (Accunt 281)
2 Electric
3 Defense Facilties
4 Polluion Cotrol Facilities
5 Other (provide detals in footnote):
6
7
8 TOTAL Elecri (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilities
11 Pollution Control Facilities
12 Other (provide details in footnote):
13
14
15 TOTAL Gas (Enter Totl of lines 10 thru 14)
16
17 TOTAL (Acct 281) (Totl of 8,15 and 16)
18 Classifcation of TOTAL
19 Federallncme Tax
20 State Income Tax
21 Loc Income Tax
(b)
30,173 300,173
30,173 30,173
30,173 300,173
264,262
35,911
264,262
35,911
NOTES
FERC FORM NO.1 (ED. 12-9)Page 272
............................................
-...........................................
Name of Respondent
PacifiCorp
ACCUMULATED DEFERRED INCO
3. Use footnotes as required.
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/0312008
E TAXES _ ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued)
Year/Period of Report
End of 2oo7/Q4
CHANGES DURING YEAR
Amounts Debied Amounts Credited
to Accunt 410.2 to Account 411.2
ADJUSTMENTS
Debits Balance at
End of Year
Line
No.Amount
NOTES (Continued
FERC FORM NO.1 (ED. 12-96)Page 273
Name of Respondent
PacifiCorp
This ~rt Is: Date of Reprt
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 0403208
ACCUMULATE DEFFERED INCOME TAXES - OT ER PROPERTY (Acount 282)
1. Report the information called for below concerning the respondent's accounting for deferred income taes rating to propert not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
Year/Period of Report
End of 2007/04
Line
No.
CHANGES DURING YEARAccountBaance at
Beginning of Year Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Account 411.1
(d)(a)(b)
1 Account 282
2 Elecric
3 Gas
4 FAS 109 Regulatory Asset
5 TOTAL (Enter Total of lines 2 thru 4)
6 Nonutilty
7
8
9 TOTAL Account 282 (Enter Total of lines 5 thru
10 Classification of TOTAL
11 Federal Income Tax
12 State Income Tax
13 Loca Incoe Tax
1,548,668,566 321,698,216 264,607,293
46,097,261
2,012,765,827
-7,192,561
620,143
322,318,359 264,607,293
2,005,573,266 322,318,359 264,607,293
1,765,650,665
239,922,601
283,760,077
38,558,282
232,952,867
31,65,426
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
............................................
-...........................................
Name of Respondent
PacifCorp
ACCUMULATED DEFERRED INCO
3. Use footnotes as required.
This ~rt Is: Date of Report(1) ~An Onginal (Mo, Da. Yr)
(2) A Resubmission 04/03/2008
E TAXES - OTHER PROPERTY (Account 282) (Continued)
Year/Penod of Report
End of 2007/Q4
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.2 to Account 411.2
ADJUSTMENTS
Debits Balance at Line
End of Year No.Amount
4
5
6
7
NOTES (Contnued)
FERC FORM NO.1 (ED. 12-96)Page 275
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
......i....i..................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 0410312008 2007104
FOOTNOTE DATA
¡Schedule Page: 274 Line No.: 2 Column: g
Accounts
190
186
283
282
¡Schedule Page: 274 Line No.: 2 Column: i
Accounts
190
283
186
101
............................................
Blank Page
(Next Page is 276)
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report(1) ~An Onginal (Mo, Da, Vr)
(2) A Resubmission 04312008
ACCUMU TED DEFFERED INCOME TAXES - OTHER (Accnt 283)
1. Report the informtion called for below concerning the respondent's accunting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
Vear/Penod of Report
End of 2007/Q4
Line
No.
Account
(a)
1 Account 283
2 Elenc
3 Regulatory Assets
4
5 Dem. Contracts Reg. Asets
6
257,08,452 23,381,893 33,687,074
102,93,510
7 Other Deferred Lialities
8
9 TOTAL Elecnc (Tota 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 of lines 9,17 and 18)
20 Classification of TOTAL
21 Federal Income Tax
22 Stte Income Tax
23 Local Incme Tax
67,495,03 30,409,325
427,515,99 34,131,617 64,09,399
376,372,09
51,143,90
30,048,522
4,083,09
56,428,679
7,667,720
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
............................................
-...........................................
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/0312008
ACCUMULATED DEFERRED INCOME TAXES - OTHE (Account 283) (Continued
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
Year/Period of Report
End of 2oo7/Q4
ADJUSTMENTS Balance at Une
End of Year No.
(k)
**************36,938,524 274,856,06 167,33,519 294,069,371
**************32,519,64 241,975,602 147,316,635 258,889,416
**************4,418,880 32.880,46 20,017,88 35,179,955
NOTES (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 27
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 04/03/2008 2007/Q4
FOOTNOTE DATA
'ichedule Page: 276 Line No.: 7 Column: g
Accounts
219
236
282
190
'ichedule Page: 276 Line No.: 7 Column: i
Accounts
190
186
283
............................................
Blank Page
(Next Page is 278)
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 0403
o HER REGULATORY LIABILITIES (Accunt 254)
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $50,00 which ever is less),may be grouped
by classes.
3. For Regulatory Liabilties being amortized, show period of amortization.
Ba at Beining DEBITS Balance at EndUneDescription and Purpose of of Currt of CurrentNo.Other Regulatory Liabilties OuarterlYear Accunt Amount Credits OuarterlYearCredited
(a)(b)(c)(d)(e)(1)
1 FAS 109 Regulatory Liabilit 25,54,625 190 3,157,40 22,387,221
2 FAS 109. WA Flow Throgh 22,341,215 190 8,942,178 13,399,037
3 OR Gain on Sales of Asets 163,768 13,875 17,643
4 Prort Insurance Resrve 2.2.114 228,924 2,233,114
5 SMUO Revenue Imutti (11)2802,746 44,442 4,898,04 2,33,6~25,462,313
6 Oregon Rate Refnd 79,971 142 5 79,966
7 Utah Hoe Ener Lifeline (8.46)142 2.,46 2,451,498 147,54
8 BPA Washington Balancig Accnt 2,32,3 44,44 3,35,48 1.02,133
9 BPA Oregon Balancing Accnt 13.85,191 44,442 14.30.592 45,401
10 BPA Idaho Balancing Accont 7,913,58 44,442 9,047,35 1,133.77
11 ARO/ Reg Dierence. Deer Cree Mine Reamation 461.45 230 167,611 20,33 497,177
12 AROlRea Dieren - Trojan Nucear Plant 833,787 230 117.057 149,083 86,813
13 Re Liablity. WA Wes VaHey Lea Reduction 342,758 44,442,431 576,383 23,62
14 Reg Liabilit. CA West Valley Lese Red (3)78,145 44,442 29.510 5,64 54,277
15 Reg Liabilit. 10 West Valley Lease Red (3)274,125 382,653 656,778
16 Reg Liabilit. WY Wes Valley Lea Redon 60,494 84.46 1,456,954
17 Reg Liailit. UT Wes Valley Lease Red (1.5)1,3,461 44,442 1,021,134 74,84 418,170
18 Reg Liabilit - A&G Crit. WA (1)38,80 44,442 251,99 29,43 428,241
19 Reg Liabilit. A&G Credit - CA (3)125,169 44,442 47,2 9,037 86,938
20 Reg Liabilit. A&G Cre 10 (3)27.319 399,54~676,86
21 Reg Libilit - A&G Cre WY 619.94 89,85 1,510,795
22 Washinaton Low Income Proram (68,874)142 769,010 795,2C .41,96
23 Reg Liabilit. OR Coidation 115,624 456 468,074 -352,450
24 Reg Liability - Blue Sk . OR 46,671 462,671
25 Reg Liability. Blue Sky . WA 81,041 81,041
26 Reg Liabilit. Blue Sky . CA 34,97f 34,975
27 Reg Liability. Blue Sky . UT 589,66 589,66
28 Reg Liabilit - Blue Sky . 10 23 11,85 31,831 19,977
29 Reg Liabilit. Blue Sky . WY 104.551 104,551
30 Re Liabilit. 10 Irngation 142 45,00 45~
31 Reg Liabilit. Reclass 2,09,62 46,
32
33
34
35
36
37
38
39
40
41 TOTAL 109,982,910 52,148,54 13,50,074 71,34,435
FERC FORM NO. 113Q (REV 02-()Page 278
............................................
-...........................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
¡Schedule Page: 278 Line No.: 31 Column: f
The following is a reconcilation of the regulatory liabilty reclassification account:
Reclassified from Regulatory Assets to Regulatory Liabilties:
Californa DSM Regulatory Asset
Washington DSM Regulatory Asset
Uta DSM Regulatory Asset
YTD
Decmber 31, 2007
$ 248,987
1,095,675
400,156
Reclassified from Regulatory Liabilties to Regulatory Assets:
Washington Low Income Program
Regulatory Liabilty Oregon Consolidated
41,964
352,450
$ 2,139,232
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respöndent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) CiA Resubmission 040300
E ECTRIC OPERATING REVENUES (Account 40)
1. The fOIlDwing instructions generally apply to the annual version 01 these pages. Do not report quarterly data in columns (c). (e), (f), and (g). Unbilled revenues and MWH
related to unbilled revenues ned not be repDrted separately as required In the annual version Df these pages.
2. Report below Dperating revenues fDr each prescribed accunt. and manufactred gas revenues in tDtal.
3. Report number of customers. columns (f) and (g). on the basis Df meters, in additon to the number 01 flt rate accunts; except that where separate meter readings are
added for billing purpDses, one customer should be counted fDr each group of meters adde. Th -average number of customers means the average of twelve figures at the
close of each month.
4. If increases or decreases from previous period (coumns (c),(e), and (g)), are not derived from previously repoed figures, explain any incDnsistencies in a footnote.
Une Title of Account Oprating Reenues Year Oprating RevenuesNo.to Date Quarterly/Annual Preious year (no Quartrly)(a)b c
1 Sales of Electricity
2 (44) Residential Sales 1,263,790,93 1,065,628,795
3 (442) Commercial and Industrial Sale
4 Small (or Comm.) (See Instr. 4)1,014,421,43 917,467,966
5 Large (or Ind.) (See Instr. 4)914,316,590 828,823,262
6 (44) Public Street and Highway Ught 18,902,690 18,427,832
7 (44) Other Sales to Public Authorities 17,509,459 16,659,617
8 (44) Sales to Railrods an Railways
9 (44) Interdepartmental Sales
10 TOTAL Saes to Ultmate Consumers 3,228,941,109 2,847,007,472
11 (447) Sales for Rese 856,86,831 750,90,692
12 TOTAL Sales of Electricity 4,08,805,940 3,597,912,164
13 (Less) (449.1) Provision for Rate Refund
14 TOTAL Revenues Net of Prov. for Refnds 4,08,805,94 3,597,912,164
15 Other Operating Revenues
16 (45) Forfeited Discounts 6,784,670 5,910,738
17 (451) Miscellaneos Service Revenues 7,215,245 6,288,827
18 (453) sales of Water and Water Power 107,480 15,228
19 (454) Rent from Elecric Propert 18,760,759 19,392,8n
20 (45) Interdpartmentl Rents
21 (456) Other Elecric Revenues 68,728,424 76,514,879
22 (456.1) Revenues from Transmission of Elecricit of Others 56,223,45 41,246,494
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneus Revenues
25
26 TOTAL Other Operating Revenues 157,820,031 149,369,043
27 TOTAL Elecric Operating Revenues -3,747,281,207
FERC FORM NO. 113-Q (REV. 12-()Page 300
............................................
............................................
Name of Respondent
PacifiCorp
This~rtls:
(1) ~An Original
(2) A Resubmission
E ECTRIC OPERATING REVENUES (
Date of Report
(Mo, Da, Yr)
04/0312008
ccount4oo)
Year/Period of Report
End of 2007/04
5. Commercial and industral Sales, Account 442, may be classified according tD the basis of classification (Small or CDmmercial. and Large or Industrial) regularly used by
the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of
classification in a fODtnote.)
6. See pages 108-109, ImpDrtnt Changes During Period, fDr importnt new territory added and important rate increase or decreases.
7. For Wnes 2.4,5,and 6. see Page 304 for amounts relating to unbilled revenue by accounts.
8. Include unmetred sales. Provide details of such Sales in a foonoe.
MEGAWATT HOURS SOLD
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)(d) (e)
AVG.NO. CUSTOMERS PER MONTH Line
Current Year (no Quarterly) Previous Year (no Quarterly) No.(f) (g)
15,951,322 15,397,126
20,892,453 20,471,54 5
136,080 149,401 4,23 6
435,395 44,66 13 7
8
9
53,390,478
13,723,856
67,114,334
67,114,33 65,45,874 1,683,619 14
Line 12, column (b) includes $
Line 12, column (d) includes
192,299,00
3,315,584
of unbiled revenues.
MWH relating to unbilled revenues
FERC FORM NO. 113-Q (REV. 12-05)Page 301
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp ì2) A Resubmission 040312008 2oo7/Q4
FOOTNOTE DATA
Page 300 Page 304 Varance
Year ended Year ended Year ended
Decmber 31,December 31,Deember 31,
2007 2007 2007
Sales of Eledricity
Residential Sales. Account (44)$ 1,263,790,936 $ 1,263,790,936 $
Commercial and Industnal Sales - Account (442)
Smal (Commrcial)1,014,421,434 1,014,421,434
Lage (lndustnal)914,316,590 914,316,590 -(a)Public Stret and Highway Lighting - Account (44)18,902,690 18,902,690
Other Sales to Public Authonties - Account (445)17,509,459 17,509,459
Sales to Railroads and Railways - Account (446)
Interdepaenta Sales - Account (44)
Tota Sales to Ultimate Consumers 3,228,941,109 3,228,941,109
Sales for Resale - Account (447)856,864,831 856,864,831 (b)
Total Sales of Electncity 4,085,805,940 3,228,941,109 856,864,831
(less) Provision for Rate Refunds - Account (449.1)
Total Revenues Net of Provisions for Refunds 4,085,805,940 3,228,941,109 856,864,831
Oter Operating Revenues
Fodeited Discounts - Account (450)6,784,670 6,784,670
Miscllaneous Service Revenues - Accunt (451)7,215,245 7,215,245
Sales of Water and Water Power - Account (453)107,480 107,480
Rent from Electnc Propert - Account (454)18,760,759 18,760,759
Interdeparmenta Rents - Accunt (455)
Other Elecc Revenues - Account (456)68,728,424 65,399,708 3,328,716 (c)
Revenues frm Trasmission of Electncity of Others (456. I)56,223,453 56,223,453 (b)
Tota Operating Revenues $ 4,243,625,971 $ 3,327,208,971 $916,417,00
(a) The large industnalline on page 300 includes account 442.2 Industnal Sales of $826,933,127 and accunt 442.3 Irgation Sales of
$87,383,463.. .
(b) Sales for Resale and Revenues from Tramission of Electcity of Others ar not included on page 304 Revenue by Rate Schedule.
(c) Steam sales totaing $4,322,329 and matenals and supplies inventory cost of sales totang ($993,613) are not included on page 304
Revenue by Rate Schedule.
¡Schedule Page: 300 Line No.: 1 Column: $
The following table is a reconcilation of the unbiled revenue accal at December 31, 200 and the reversal of the December 31,
200 unbiled revenue accr.
Curent year unbiled revenue accrual
Pror year unbiled revenue accrual reversal
December 31,
2007
$ 192,299,00
(177,642,00)
Change In Unbiled Revenue Accrul
IFERC FORM NO.1 (ED. 12-S7)
$ 14,657,000
Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2SAn Original (Mo, Da, Yr)
PacifiCorp i2) A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
ISchedule Page: 300 Line No.: 1 Column: MWH I
The following table is a reconcilation of the unbiled MW accrual at December 31, 2007 and the reversal of the December 31, 200
unbiled MW accrual.
Curent year unbiled MWH accral
Pror year unbiled MWH accrual reversal
December 31,
2007
3,315,584
(3,217,145)
Change in MW Accrual 98,439
IFERC FORM NO. 1 (EO. 12-87) Page 450.2
Name of Respondent This~rtIS:Date of Report Year/Period of Reprt
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 041031208
SALES OF ELECTRICITY BY RATE SCHEDULES
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 Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue accunt in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
aplicable 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 special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills renre during th ye div 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 fooote th estimaed aditiol revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of yer for each apicle revenue acnt subhng.
Line ~lJmoer ana i me or Naie scneauie Mvvn :;Nevenue Average Numoer pè~'?~s~:r ~~~'S~lderNo.(a)(b)(c)of Cfclomers
(f)
1 Residential Sales
:; CALIFORNIA
. ~ 06CHCKOOR- RES CHECK M 1
4 06LNX00102-L1NE EX 80"1 G 32
5 06LNX00109REF/NREF ADV +41g
6 06NETMT135 - RES NET METR 87 8,34 8 10,875 0.099
7 O6ALT015R-QUTD AR LGT SR 3n 70,541 401 94 0.1871
8 06RESOOD-RES SRVC 213,729 2O,48,86 19,935 10,721 0.095
. g 06RESDDL06-LOW INCOME 86,911 8,04,337 7,623 11,401 0.0926
1C 06RESDDM9M-MULTI FAMILY 331 30,155 9 36,na 0.0911
11 06RESDDS8M-MUL TI FAM SBMET 1,4O 97,535 16 88,06 0.0692
12 ACQUISITION COMMITMENT 24,~
12 ACQUISITION COMMITMENT 15,56
14 AL T RATE FOR ENERGY (CARE)203,00
15 SMUD REVENUE IMPUTATIONS 56,40
16 06RESDODN - RES SRVC - DEL 104,324 9,90,532 8,011 13,023 0.099
17 UNBILLED REV - UNCOLLECTIBLE -2,00
18 UNBILLED REVENUE 2,19C 522,OO 0.238
19 IDAHO
2(07LNX001 ()MNTHL Y 80"lGUAR 1,02(
21 07LNX0035-ADV 8O"IMO GUAR 3,55E
22 07NETMT135 -RESIDENTIAL NET 65 3,99 -4 16,2&0.0615
2~07NETMT135 -RES NET -so
24 070ALC0007-CUST OWN LIGHT 1C 2,05 1 10,00 0.2054
25 070ALT07AR-SECURITY AR LG 115 26,66 154 747 0.2319
2t 070ALT07AR-SECURITY AR LG -870
27 07RESOO1-RES SRVC 390,817 32,802,269 38,599 10,125 0.089
28 07RESOO1-RES SRVC -3,469,745
29 07RESDoo36-RES SRVe-OPTIO 314,163 21,206,989 16,39€19,159 0.0675
3C 07RESD006-RES SRVC-QPTO -3,054,365
31 BPA BALANCING ACCOUNT 1,826,57~
32 UNBILLED REV - UNCOLLECTIBLE -3,OO
33 ACQUISITION COMMITMENT -87,9n
34 ACQUISITION COMMITMENT -84,06g
35 UNBILLED REVENUE 5,351 355,OO 0.063
36 OREGON
37 01 CHCKooR-RES CHECK MTR 1
38 01 COSTOO - 01 RESDOO 5,408,166 211,066,50 0.0390
39 01 FXRENEWR-Fixed Renewable -1
4C 01 HABITOO4 - 01 RESDOOO 38,947 1,476,275 0.0379
41 TOTAL Billed 53~.~1,683,6H 31,65 0.062~
42 Total Unbiled Rev.(See Instr. 6)98,43 ((0.148~43 TOTAL 53,390,47 3,327,208,971 1,683,619 31,71"0.0623
FERC FORM NO.1 (ED. 12-95)Page 304
............................................
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) nA Resubmission 04/0312008
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in efec during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, Ust the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are sered 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 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 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 biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue account subheading.
I Line NumDer ana I me OT Hate scneauie Mvvn i:la Revenue Average NumDer es -~C'è~erNo.(a)(b)(c)ofC~~omers Per r~stomer
(f)
1 01 LNX001 02-L1NE EX 80% G 2,706
2 01 LNXOO1 05-CNTRCT $ MIN G 21
3 01 LNX001 09REFINREF ADV +8,291
4 01NETMT135-NET METERING 148,15C 35
5 01NET135-NET METERING -15,207
6 010ALT014R-OUTD AR LGT RE 2,79C 394,749 3,084 905 0.1415
7 010ALT014R-OUTD AR LGT RE -11,94
8 01 PTOUOO - 01 RESDOO 18,749 732,264 0.0391
9 01 RENEWOO - 01 RESD0 155,919 5,820,584 0.0373
10 01 RESDOORES SRVC 244,22,970 46,687
11 01 RESD0-RES SRVC -25,489,193
12 01 RESD0T - RES Time Option 80,607 1,189
13 01 RESDOOT - RES Time Option -78,229
14 01UPPLooR-BASE SCH FALL :i
15 MERGER CREDITS is
1€BPA BALANCING ACCOUNT 13,244,429
17 S6408 RECOVERY -86,405
18 SB838 RECOVERY 664,142
19 SMUD REVENUE IMPUTATIONS 66,989
2C UNBILLED REV - UNCOLLECTIBLE -8,OO
21 UNBILLED REVENUE 19,282 3,280,00 0.1701
22 UTAH
2:J 08BLSKY01 R-BLUESKY ENERGY -3
24 08CFROO1-MTH FACILITY S 1,40
25 08CHCKOOOR-RES CHECK M 1
26 08COOLKPRR - Utah Col Keeper -20 67,059
27 08LNXOO1-MTHL Y 80% GUAR 1,851
28 08LNXOO-MTHLY MIN GUAR 60
29 08LNXoo13-80% MNTHL Y MIN 18,011
30 08LNXOO16 - 800k annual 343
31 08LNX00108-ANN COST MTHL Y 4,861
32 08MHTP0025-MOBILE HOME 11,754 779,781 11 1,068,54 0.06
3:08NETMT135 - Net Metering 764 61,932 131 5,577 0.0811
34 080AL TOO7R-SECURITY AR LG 2,991 781,03~3,331 898 0.2611
35 08PTLDOOR-POST TOP LIGHT 224 16,851 66 3,394 0.0752
36 08RESDO01-RES SRVC 6,356,131 520,034,533 661,369 9,611 0.0818
31 08RESD002-RES SRVC-OPTIO 2,585 208,616 290 8,914 0.0807
38 08RESD003-L1FELlNE PRGRM 183,053 14,676,696 23,490 7,793 0.0802
39 08RESD0150-RES ALL E NOT5 2~
4C 08RFND1999-RATE RFND 2
41 TOTAL Biled 53~'1-1,683,6H 31,65 0.062~
42 Total Unbiled Rev.(See Instr. 6)98,43 C (O.148~
43 TOTAL 53,390,47 3,327,208,971 1,683,619 31,7~0.062~
FERC FORM NO.1 (ED. 12-95)Page 304.1
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 04312008
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effec dunng the year the MWH of elecncit sold, revenue, average number of customer, average Kwh per
customer, and average reenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescnbed operating revenue accunt in the sequence followed in "Elecnc Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account clasifcation (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 number of bils rendered dunng the year divided by the number of billng penods dunng the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustmnt clause state in a footnote the estimated additioal revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applice revenue accunt subheading.
Line NlImoer ana Iitie or Hate scneauie MW~la Hevenue AVerage NumDe ~YYILUI ",aies ~~~'èUjerNo.(a)(b)(c)of cqscb0mers Per Y:fstomer
(f)
1 OSEAMINOO-SEASNL ANN MIN 4E
2 08UPPLOOR-BASE SCH FALL 2
3 MERGER CREDITS 5
~ ACQUISITION 301,949
5 SMUD REVENUE IMPUTATIONS 692,975
€ UNBILLED REV - UNCOLLECTIBLE -5,OO
7 UNBILLED REVENUE 3,471 2,628,00 0.7571
8 WASHINGTON
9 02LNX00109-REF/NREF ADV +62S
10 BLUESKY ENERGY -1
11 020AL TB15R-OUTD AR LGT RES 1,172 151,o0 1,264 927 0.1288
12 020ALTB15R-OUT AR LGT RES -5,00
1~ 02RESDO16-RES SRVC 1,579,34 101,03,OS 99,275 15,90 0.06
1~ 02RESDO16-RES SRVC -7,261,5~
15 02RESD0017-BILL ASSISTANC 45,842 2,93,97E 2,506 18,293 0.061
16 02RESDO17-BILL ASSISTANCE -237,54
17 02RESD0018 3 PHASE RES 2,745 193,926 98 28,010 0.0706
18 02RESDO18 3 PHASE RES -11,8SS
19 02RESD018X 3 PHASE RES 710 49,34 26 27,308 0.0695
20 02RESOO18X 3 PHASE RES -3,23C
21 CENTRALIA RFND -7
22 ACQUISITION COMMITMENT -97,Ø .
¿~ACQUISITION 129,98
2~BPA BALNCING ACCOUNT 3,619,33
25 UNBILLED REV - UNCOLLECTIBLE 3,OO
26 UNBILLED REVENUE -3,08 30,00 -0.0989
27 WYOMING
28 05LNX00109-REF/NREF ADV+15::
29 05NETMT135 - EXPERIMENTAL 113 8,391 10 11,30 0.0743
3C 050ALT015R-OUTD AR LGT SR 1,018 154,330 1,175 866 0.1516
31 05RESOO02-QPTIONAL 109,378 7,633,131 5,10~21,43 0.0698
32 05RESOO2-RES SRVC 787,26.60,512,874 88,22 8,924 0.0769
3:05RESD0018-RES 3 PHASE SR 31E 25,585 9 35,33 0.0805
34 05RESD018X.RES 3 PHASE SR 455 32,32~4 113,750 0.0711
35 05RFNDCENT-CENTRALIA RFND -1~
36 09LNX00108-ANN COST MTHLY 19E
37 ACQUISITION COMMITMENT -94,40
38 ACQUISITION -89,734
39 SMUD REVENUE IMPUTATIONS 87,54
40 09NETMT135 - RES NET 18 1,494 3 6,000 0.083
41 TOTAL Biled 5S~.~1,683,61~31,65 0.062
42 Total Unbiled Rev.(See Instr. 6)98,43 .t (0.148
43 TOTAL 53,390,47 3,327,208,971 1,683,6H 31,71~0.062
FERC FORM NO.1 (ED. 12-95)Page 30.2
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04/03/2008
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of elecriity 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 prescribe operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, LIst the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the speial 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 footnote the estimated adcitional revenue billed pursuat thereto.
6. Reprt amount of unbiled revenue as of end of year for each applicae revenue account subheading.
!Une Number ana i me OJ Haie scneauie Mwn ;:öl Hevenue Average Numoer ~:~~sr~:r ~is~lderNo.(a)(b)(c)of CfJi0mers
(f)1 09RESD0 220 16,650 2~9,565 0.0757
2 UNBILLED REV - UNCOLLECTIBLE 2,00
~ UNBILLED REVENUE -2,380 -180,00 0.0756
4 05RESD0002-RES SRVC 683 52,84E 80 8,538 0.On4
5 05RESDO18-RES 3 PHASE SR 4 395 1 4,00 0.0988
6 05UPPLooR-BASE SCH FALL 1
7 090AL T207R-SECURITY AR LG 89 31,905 103 86 0.3585
8 09NETMT135 - RES NET 71 4,697 1 71,00 0.062
9 SMUD REVENUE IMPUTATIONS 12,928
10 05RESO2-oPTIONAL 102 7,050 4 25,500 0.0691
11 09RESOO2 40,675 2,875,487 2,222 18,306 0.0707
12 09RESD002 85,727 6,627,874 9,884 8,6n 0.On3
13 UNBILLED REVENUE 39 6,00 0.1538
14 Less Multiple Billings -87,560
15
16 Total Residential 15.975,22E 1,263,790,936 1,44,688 11,08e 0.0791
17
18 COMMERCIAL SALES
H CALIFORNIA
20 06CHCKooN-NRES CHECK :2
21 06NSVOO5-GEN SRVC 65,240 7,537,405 6,851 9,523 0.1155
2~06GNSV025F-GEN SRVC--= 20 950 124,951 92 10,326 0.1315
2~06NSV0A32-GEN SRVC-20KW 81,765 7,707,217 86 94,417 0.094
24 06LGSV048T-LRG GEN SERV 73,690 4,299,11.1 e 8,187,n8 0.058
25 06LGSVOA3LRG GEN SRVC-O 85,850 6,726,982 194 442,526 0.0784
26 06LNX00102-L1NE EX 80% G 8,13!J
27 06LNX00105-CNTRCT $ MIN G 3,606
28 06LNX00109-REF/NREF ADV +n,294
29 06LNX003oo - 80% MONTHLY MIN 2,74:
30 O6AL T015N-oUTD AR LGT SR 766 143,835 551 1,390 0.1878
31 06RCFL002-AIRWAY & ATHLE 184 26,381 38 4,842 0.1434
32 06WHSV0031-COMM WTR 246 23,976 30 8,20 0.0975
33 ACQUISITION COMMITMENT HEAT .18,40.
34 ACQUISITION 11,490
35 SMUD REVENUE IMPUTATIONS 42,142
36 06LNX00103-L1NE EX 80% G 30
3ì 06LNXOO110-REF/NREF ADV +7,197
38 UNBILLED REVENUE 1,48S 193,00 0.1297
39 IDAHO
4C 07CISH0019-COMM & IND SPA 9,657 691,401 299 32,298 0.0716
41 TOTAL Biled 53~~1,683,61!31,~0.06~
42 Total Unbilled Rev.(See Instr. 6)98,43 ((0.148(
43 TOTAL 53,390,47 3,327,208,971 1,68,6H 31,7~0.062;:
FERC FORM NO.1 (ED. 12-95)Page 30.3
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 04l0200
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect dunng the year the MWH of elecncity 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 prescnbe operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a genera residential
schedule and an off peak water heating schedule), the entnes 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 dunng the year divided by the number of biling perids dunng the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the esmated additional revenue biled pursuant thereto.
6. Reprt amount of unbiled revenue as of end of year for each aplice reenue acnt subheading.
Line l'umoer ana i me OJ Hate scneauie Hevenue AVe~¡~UmDer iswaOJ ~aies i:~'S~lderNo.(a)(b)(c)ofC omers Per ?~stomer
(f)
1 07GNSVOO-GEN SRVC-LRG P 195,911 11,744,55 911 215,057 0.0599
2 07GNSVoo9-GEN SRVC-HI VO 33,1Ol 1,45,531 1 33,108,00 0.048
:: 07GNSV0023-GEN SRVC-SML P 114,881 9,142,533 5,657 20,308 0.0796
4 07GNSVOO-GEN SRVCOPTION 902 43,775 '2 451,00 0.045
5 07GNSVOOA-GEN SRVC-LRG P 30,272 1,987,196 214 141,458 0.0656
6 07GNSV006A-GEN SRVC-LRG P -487,83
7 07GNSV023A-GEN SRVC-SML P 15,697 1,33,25f 1,135 13,83 0.0849
8 07GNSV023A-GEN SRVC-SML P -145,390
5 07GNSV023F-GEN SRVC SML P 16 2,39 7 2,286 0.1494
1C 07LNX0010-MNTHL Y 80%GUAR 15,19E
11 07LNXoo35ADV 8OMO GUAR 25,88
12 07LNX~ADV+REFCHG~k 30,46
1S 070AL T007N-SECURITY AR LG 26:l 52,110 19B 1,323 0.1989
14 070ALT07AN-SECURITY AR LG 13 3,03 16 813 0.233
15 070AL T07AN-SECURITY AR LG -98
16 07LNX00312 -LINE EX 5,57::
17 07LNX0015-ANNUAL 80%GUAR 2,41:1
1å 07LNX00311 - LINE EXT 80%9,SO
19 07LNX00020 -MONTHLY 661
20 07LNXOO0 - 80% MONTHLY MIN 2,243
21 ACQUISITION COMMITMENT -51,14E
22 ACQUISITION -4,876
23 BPA BALANCING ACCOUNT 105,158
2~UNBILLEO REVENUE -2,61::-127,OO 0.046
25 OREGON
26 01COST0023,GEN SRV,CST BASE 993,76::39,290,675 0.0395
27 01 COST004-01 LGSV008 727,288 26,320,594 0.032
28 01 COST023F -GEN SRV -3,271 138,536 0.0424
29 01COSTB023-GEN SRV, CST-BSO 90,915 3,738,986 0.0411
30 01COSTL03LRG GEN SRV, CST 1,050,776 39,747,00 0.0378
31 01COSTS028, GEN SERV, COST ~1,956,597 76,061,301:0.0389
3~01 COSTS030-GEN SRV CBS ~20 1,14~40,55C 0.0353
3:01GNSBOO23 -BPA DISC,o:3OW -420,423
34 01 GNSBO23,GEN SRV,BPA,o:3O 5,116,66 14,468
35 01GNSB0028-GEN SRVC,BPA,~-6,210
3E 01GNSBO28,GEN SRV,BPA,:-3,015,04 569
37 01GNSB023T-GEN SRV-TOU-B 35,453 62
31:01GNSB023T-GEN SRVC,TOU,BP -4,133
39 01GNSV0023,GEN SRV,o: 30KW 36,608,361 54,053
4c 01GNSV008,GEN SRV ~30kW 42,207,448 8,814
41 TOTAL Biled ;s='~1,683,61!31,65 O.06Z
42 Total Unbiled Rev.(See Instr. 6)98,43 ((O.148~
43 TOTAL 53,390,47 3,327,208,971 1,683,61!31,71:1 0.062:
FERC FORM NO.1 (ED. 12.95)Page 304.4
............................................
............................................
Name of Respondnt This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) DA Resubmission 04/0312008
SALES OF ELECTRICITY BY RATE SCHEDULES
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 "Elecric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divid 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 thereto.
6. Report amount of unbiled revenue as of end of yer for each applicale revenue accunt subheading.
une Numoer ana Ilte OJ Hate scneauie Mvvn ;:010 "evenue l\vera~~"umoer ~~~n?~sf~:r ~'S~rderNo.(a)(b)(c)of CI omers (f)
1 01GNSV023F-GEN SRV-FLAT RA 10,203 1,235,130 873 11,687 0.1211
2 01GNSV023M-GEN SRV,MANUAL B 78 4,953 1 78.00 0.0635
3 01GNSV023T,GEN SRV,TOU Optio 166,n3 250
4 01 HABT0023,HABITAT BLENDED 1,780 71,831 0.0404
5 01HABTB023-HABITAT BLENDED 150 6,365 0.0424
6 01 LGSBO3O,GEN DEL SRV,::2oo -231,119
7 01 LGSBO3O,GEN DEL SRV,::2oo 864,953 31
8 01LGSV0028,LRG GEN SRV..100 -42,414
9 01LGSVoo30LRG GEN SRV,::10 17,421,842 635
10 01LGSV008-100KW AND OVR 8,163,733 90
11 01 LGSV048M-LRG GEN SRVC 1 51,625 2,167,84 1 51,625,00 0.0420
12 01 LNX001 oo-L1NE EXT 60% G 8,269
13 01LNX00102-L1NE EXT 80% G 383,54
14 01 LNX001 03-L1NE EX 80Q/o G 12,703
15 01LNXOO105-CNTRCT $ MIN G 15,098
16 01LNXOO109-REF/NREF ADV +1,249,175
17 01LNX00110-REF/NREF ADV +10,912
18 01 LNX00120-Line Exension 60% G 5,96
19 01 LNX003QOL1NE EX 80%13,038
20 01 LNX00311-L1NE EXT 80% G 27,214
21 01LNX00312-IRG LINE EXT 175
22 01 LPRS047M-PART REO SRVC 5,118 442,03 3 1,706,00 0.086
23 01 NMT2313-NET MTR, GEN, .. 3 13,174 28
24 010AL T014N-OUTD AR LGT NR 1,701 248,56 1,210 1,40 0.1461
25 010ALT014N-OUTD AR LGT NR -7,295
26 010ALT015N-OUTD AR LGT NR 6,371 80,101 3,195 1,99 0.1262
27 01PTOU0023,GEN SRV, TOU ENG 4,119 160,856 0.0391
28 01 PTOUB023,GEN SRV, TOU SPL Y n5 29,422 0.0380
29 01 RCFLOO54-REC FIELD LGT 925 82,107 102 9,069 0.0888
3C 01 RENW0023,RENW USAGE SPL Y 6,64€269,610 0.04
31 01RENWB023 -RENEWABLE 62€26,128 0.0416
32 01 STDAY02 -DAY STD OFR, SCH 1,n2 94,215 0.0532
33 01STDAY028-DAY STD OFF, SCH 3,305 174,302 0.0527
34 01STDAY030-STD DAY OFF, SCH 4,480 235,582 0.0526
35 MERGER CREDITS 22
36 BPA BALANCING ACCOUNT 688,651
37 01 LGSB008-LG GEN -16,097
38 01 LGSB008-LG GEN 41,828 1
39 01NMT28135-NET MTR, GEN,::3 36,499 9
40 01LGSV028M-LGSV,..1oo kW, M 471 30,499 1 471,000 0.068
41 TOTAL Biled 53'29'~1,683,6H 31,65 O.06Z
42 Total Unbilled Rev.(See Instr. 6)98,43 ((0.148~
43 TOTAL 53,390,47 3,327,208,971 1,683,6H 31 ,71~0.062~
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 2007/Q4
(2) FiA Resubmission 04208
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effec during the year the MWH of elecriity 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 prescribe operating revenue account in the sequence followed in "Eletric Operating Revenues," Page
300-301. If the sales under any rate schedule are classifed in more than 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 schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendered 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 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 applicble revenue account subheading.
Line . Numoer ana ime Of Hate scneauie Mwn::oia Revenue Average NumDer iswn_of :;ies _~1derNo.(a)(b)(c)of CfJ,0mers Per r~stomer
(1)
101 GNSV03OM-GEN SRV,200W,5,44~29,00 1 5,449,00 0.0532
2 01GNSV0728-GEN SVC DIR 32,40 2
~ 01GNSV0730GEN SVC DIR 95,676 sa
~ 01GNSV0748 LG GEN SVC DIR 41,16e 1
5 SB4 RECOVERY -80,44
-t SB838 RECOVERY 559,549
J SMUD REVENUE IMPUTATIONS 5n,36e
8 UNBILLED REVENUE 13,437 1,758,OO 0.1308
~ UTAH
1ë 08CFR001-MTH FAC SRVCHG 66,600
11 08CFR002-ANN FAC SVCCHG :1
12 08CHCKOOON-NRES CHECK S
13 08COOLKPRN - AlC DIRECT LOAD 2,942
14 08GNSVOOGEN SRVC-DISTR 4,719,37i 295,99,725 10,982 429,737 0.0627
15 08GNSVOO-GEN SRVe-HI VO 241,80 10,126,176 19 12,726,421 0.0419
1E 08GNSVOO23-GEN SRVC-DISTR 1,190,08 89,235,279 62,766 18,961 0.0750
17 08GNSVOO6A-GEN SRVC-ENERG 191,892 15,916,282 1,623 118,233 0.0829
18 08GNSVOOB-GEN SRVC-DEM&2,699 170,44 10 269,90 0.0632
1e 08GNSVOOM-MNL DIST VOL TG 8,300 415,374 i 1,198,571 0.0495
2e 08GNSVOO9A-GEN SRVC HI VO 27,272 1,250,91S 2 13,636,00 0.049
21 OBGNSV009M-MANL HIGH VOLT 20,55C 841,166 1 20,550,00 0.049
22 08GNSV023F-GEN SRVC FIXED 1,434 148,595 116 12,362 0.1036~08GNSV023M-GNSV DIST VOLT 109 8,411 6 18,167 0.on2
24 08GNSV06AM-MNL ENERGY TOD 76e 69,64e 2 384,500 0.0906
25 08GNSV06MN-GNSV DIST VOLT 28,185 1,58,43 405 69,593 0.0564
26 08GNSV09AM-MA TOD HIVOL T 16S 9,601 1 168,000 0.0571
27 08LNXOO2-MTHL Y 80% GUAR 44,142
28 08LNX00004-ANNUAL 80%GUAR 90,384
2S 08LNXOO,FIXD MTHL Y MIN 13,926
30 08LNX0014-80% MIN MNTHL Y 1,619,165
31 08LNX0017 -ADVlREF&80"kANN 137,752
32 08LNX00150-AGR MTH GUAR M 852
3:08LNX00158-ANNUALCOST MTH 34,60S
34 08LNXoo30-L1NE EXT 80% PLUS 199,988
35 08LNX00310-IRR 80% ANNUAL MIN 512
"3t 08LNXOO312 IRG LINE EXT 1,06
3i 08NMT23135-NET MT,GEN,," 2 7E 6,41C 7 10,857 0.084
3S 080AL TOO7N-SECURITY AR LG 9,283 1,96,186 4:B 1,926 0.2116
39 08POLE0075-POLES W/L1GHT 1,221 ,
40 08PRSV031 M-BKUP MNT&SUPPL 14,447 849,317 3 4,815,667 0.0588
41 TOTAL Biled 53~~1,683,6H 31,65~O.06Z
42 Total Unbiled Rev.(See Instr. 6)98,43 ((0.148~43 TOTAL 53,390,47 3,327,208,971 1,683,6H 31,71~0.062~
FERC FORM NO.1 (ED. 12-95)Page 30.6
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) EjA Resubmission 04/03/2008
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect dunng the year the MWH of electncity 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 prescnbed operating revenue account in the sequence followed in "Electnc Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate scedule in the same revenue accunt classifcation (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 number of bills rendered dunng the year divided by the number of biling penods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicale revenue accunt subheading.
I Line Numoer ana ime or Hate scneauie Mvvn ;:010 Nevenue Aver~i~umDer ~vvn_or_~-!es '"~irolerNo.(a)(b)(c)ofC omers Per r~stomer
(f)
1 08PTLDOON-PQST TOP LIGHT 65 4,872 8 8,125 0.0750
2 08SLC1202F-TRAFFIC SIG NM 206 15,841 32 6,438 0.0769
3 08SLCU1202-TRAF & OTHER S 1,098 88,695 416 2,639 0.088
4 08SLCU1203-MTR OUTDONIGHT 9,n4 689,942 265 36,883 0.0706
5 MERGER CREDITS -7
6 ACQUISITION 355,253
7 SMUD REVENUE IMPUTATIONS 797,86
8 08LNX00311-L1NE EXT 80%60,765
9 08GNSVOO8-GEN SVC TOU::1oo 925,190 50,078,176 132 7,009,015 0.0541
10 08GNSV008M-GEN SVC TOU::1oo 46,855 2,704,857 6 7,809,167 0.05n
11 UNBILLED REVENUE 24,901 3,216,QO 0.1292
12 WASHINGTON
13 02GNSBO24-GEN SRVC DO 41,717 2,929,486 3,180 13,119 0,0702
14 02GNSBO24-GEN SRVC DO -172,018
15 02GNSB024F-GEN SRVC DOMIF 228 20,255 9 25,333 0.0888
1E 02GNSB024F-GEN SRVC DOMIF -156
17 02GNSB24FP-GEN SVC 40 99,741 101 3,785 0.2463
18 02GNSB24FP-GEN SVC -3,011
19 02GNSV0024-GEN SRVC 46,956 29,838,106 13,523 34,~0.062
2C 02GNSV024F-GEN SRVC-FL 1,211 115,54 122 9,926 0.0954
21 02LGSBO36-LRG GEN SVC IRG 86,232 4,506,151 95 907,705 0.052~
22 02LGSBO36-LRG GENSVC IRG -36,637
23 02LGSVoo36-LRG GEN SRV 674,915 36,048,841 811 832,201 0.0534
24 02LGSV048T-LRG GEN SRVC 1 153,00 7,333,94 27 5,668,259 0.0479
25 02LNX00102-L1NE EX 8010 G 55,619
26 02LNX00103-L1NE EX 80% G 4,132
27 02LNX00105-CNTRCT $ MIN G 692
28 02LNX00109-REF/NREF ADV +162,752
29 02LNX00110-REF/NREF ADV +12,557
30 02LNX00112- YR INCURRED CH 669
31 02LNXOOL1NE EXT 80% G 4,665
32 02LNX0011- LINE EX 80%1,647
33 020AL T015N-OUTD AR LGT 1,700 201,867 891 1,908 0.1187
34 020ALTB15N-OUTD AR LGT NR 6SC 82,850 563 1,155 0.1275
35 020AL TB15N-OUTD AR LGT NR -2,782
36 02RCFLoo54-REC FIELD L 227 18,033 28 8,107 0.0794
37 CENTRALIA RFND -141
3E MERGER CREDITS 1E
3~02NMT24135, Net metenng 5 454 1 5,000 0.090
40 ACQUISITION COMMITMENT -86,849
41 TOTAL Biled 53,292,03~ 3,312,551,971 1,683,61~31,65 O.06Z
42 Tota Unbilled Rev.(See Instr. 6)98,~~C (0.1481
43 TOTAL 53,390,47 3,327,208,971 1,683,61~31,71~0.06:
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 2007/04
(2) FiA Resubmission 0403208
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of elerici 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 acunt in the sequence followed in "Elecric Operating Revenues," Page
300-301. If the sales under any rate schedule are classifed in more than on revenue accnt, 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 sae revenue accunt classifcation (such as a general 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 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 billngs 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 accunt subheading.
Line Nurnoer ana i me or Hate sceauie Mvvn ::010 Hevenue Average Numoer IS vv nßT :;ie ~~lderNo.(a)(b)(c)of cìjJ,0mers Per '(~stomer
(f)1 ACQUISITION COMMITMENT 115,58
2 BPA BALANCING ACCOUNT 32,616
3 UNBILLED REVENUE -6,500 -99,00 0.0152
4 WYOMING
5 05CHCKOON-NRES CHECK 1
6 05GNSVOO25-GEN SRVC 1,070,43!J 70,447,298 20,440 52,370 0.068
7 05GNSV025F-GEN SRVC-FL RA 1,031 122,571 194 5,314 0.1189
l! OSLGSV04M-LRG GEN SRV 971:46,061 1 976,00 0.0472
9 05LGSV04T-LRG GEN SERV 213,878 10,330,523 19 11,256,737 0.0483
10 05LNXOO1OQL1NE EX 6010 G 17C
11 OSLNXOO102.L1NE EX 80% G 550,26
12 05LNXOO1OS-CNTRCT $ MIN G 5,373
-i 05LNXOO109-REF/NREF ADV +43,575
14 05LNXOO114- TEMP SVC 12MO::3,6Zi
15 05NMT25135-NET MTR,GEN,.: 2 45 37,80 :3 152,667 0.0825
16 OSOALT015N-OUTD AR LGT SR 3,081 46,09 1,822 1,691 0.1519
17 05RCFLOO54REC FIELD L 652 51,422 52 12,538 0.0789
1S CENTRALIA RFND 18
19 09GNSVOO25.GEN SVC-SINGLE 1 261 1 1,OO 0.2610
20 05LNXOO30L1NE EX 80%68,64
21 05LNXOO310-L1NE EXT 80%20,921
22 ACQUISITION COMMITMENT -129,151
2~ACQUISITION COMMITMENT -122,757
24 SMUD REVENUE IMPUTATIONS 125,61!J
25 UNBILLED REVENUE -8,52C -6,OO 0.0739
26 05GNSVOO25-GEN SRVC 1,359 120,21 48 28,313 0.0885
27 05GNSV025F.GEN SRVC.FL RA 211 20,542 32 6,594 0.0974
28 05LNXOO102-L1NE EX 80% G 5,74!J
29 05LNXOO109-REFINREF ADV +67,450
3C 05LNXOO110-REF/NREF ADV +2,213
31 05LNXOO114-TEMP SVC 12MO::55
32 09GNSVOO25.GEN SVC-SINGLE 129,484 8,507,479 2,383 54,337 0.067
33 09GNSV025F.GEN SVC-FIXED 44 4,270 7 6,286 0.0970
34 09GNSV025M-GEN SVC.MANUAL 2,362 149,232 2 1,181,00 0.0632
35 090AL T207N-SECURITY AR LG 279 93,553 145 1,924 0.3353
3e 09SLCU2123-MTR OUTDONIGHT 52 3,57C 2 26,00 0.0687
37 OSLNXOO300-L1NE EXT 80%2,821
38 05LNXOO311-L1NE EXT 80%1,337
39 SMUD REVENUE IMPUTATIONS 13,920
40 UN BILLED REVENUE 1,057 72,00 0.061
41 TOTAL Biled æ~.~1,683,611 31,65 0.06242Total Unbilled Rev.(See Instr. 6)98,43 C (0.148!J43TOTAL53,390,47 3,327,208,971 1,68,6Ú 31,71~0.06~
FERC FORM NO.1 (ED. 12-95)Page 30.8
............................................
-...........................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04/0312008
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh,excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicale revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account claifcation (such as a general residential
schedule and an off peak water heating schedule), the entries in coumn (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 billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote th estimated additional revenue biled pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
IUne Numoer ana Ille OT Hate seleauie Mwn::oia Hevenue Aver~~~umDer ~wnßT::ales n~lder
No.(a)(b)(c)ofC omers per?~tomer
(f)
1 Less Multiple Billngs -26,021 '.
2
3 COMMERCIAL SALES TOTAL 15,951,322 1,014,421,43 204,569 n,975 0.0636
4
5 INDUSTRIAL SALES
6 CALIFORNIA
7 06GNSV0025-GEN SRVC 1,020 118,162 101 10,091 0.1158
E 06GNSV0A3-GEN SRVC-20 KW 1,94S 213,743 2~84,69t 0.1097
~ 06LGSV04T-LRG GEN SERV 50,284 2,895,055 5 10,056,ao 0.0576
1(06LGSV0A3-LRG GEN SRVe-o 7,069 601,035 15 471,27 0.08
11 06LNXoo109-REF/NREF ADV +1,51E
12 ACQUISITION COMMITMENT 3,935
13 ACQUISITION 2,457
14 SMUD REVENUE IMPUTATIONS 8,841
15 UNBILLED REVENUE 867 82,00 0.0946
16 IDAHO
17 07CFROO1-MTH FACILITY S 2,217
1 S 07CISH0019-COMM & IND SPA 175 13,192 7 25,OO 0.0754
19 07GNSVOO-GEN SRVe-LRG P 107,449 5,60,08 117 918,36 0.0522
20 07GNSV008-GEN SRVC-MEDIU 2,473 136,299 2 1,236$0.0551
21 07GNSV009-GEN SRVC-HI VO 84,460 3,761,075 11 7,678,182 0.04
22 07GNSV0023-GEN SRVC-SML P 10,562 816,7m 35 29,66~0.on3
2:3 07GNSVOO35-GEN SRVCOPTION 1,427 69,36 1 1,427,00 0.0486
24 07GNSVOOA-GEN SRVC-LRG P 5,146 324,561 34 151,353 0.0631
25 07GNSVOOA-GEN SRVC-LRG P -39,107
26 07GNSV023A-GEN SRVC-SML P 2,30S 213,702 26C 8,8n 0.0926
27 07GNSV023A-GËN SRVC-SML P -19,153
28 07GNSV023S-TRAFFIC SIGNALS 3 505 3 1,00 0.1683
29 07LNXoo35-ADV 800/MO GUAR 1,501
30 07LNXoo108-ANN COST MTHL Y 1,99
31 07LNX0030D-800/ MONTHLY MIN 295
32 070ALT007N-SECURITY AR LG 12 2,592 1E 750 0.2160
33 070AL T07 AN.SECURITY AR LG 2 437 3 667 0.2185
34 070ALT07AN-SECURITY AR LG -12
35 07SLCU1201-TRAF SIGNAL SY 2 3H ~667 0.1595
3E 07SPCLoo1 1,320,60 48,229,649 1 1 ,320,60,00 0.0365
3i 07SPCLOO2 98,95E 3,657,795 1 98,958,000 0.0370
38 ACQUISITION COMMITMENT -218,727
39 ACQUISITION -209,019
40 BPA BALANCING ACCOUNT 20,646
41 TOTAL Biled 53m.~1,683,6H 31,65 O.06Z
42 Total Unbiled Rev.(See Instr. 6)98,43 ((O.148~
43 TOTAL 53,390,47 3,327,208,971 1,683,6H 31,711 0.062~
FERC FORM NO.1 (ED. 12-95)Page 30.9
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 0403/8
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate scedule 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 tota for each prescribed operating reenue accont in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are clasifed in more th one revenue accunt, 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 schedle in the same revenue accunt classifcation (such as a general 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 rendered during the year divided by the number of billng peris during the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a foonote th estimated additional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicale revenue account subheading.
rune "Number ana i me OT HaTe scneauie Mvvn~oia Hevenue lo\e~i~umoer ~VVI!.UI 9C\es ~~isilderNo.(a)(b)(c)ofC omers Per ~~stomer
(f)
1 UNBILLED REVENUE 33,573 1,286,OO 0.0383
2 OREGON
~ 01 COST0023,GEN SRV,COSTBASE 22,67C 896,33 0.0395
4 01 COSTOO -01 LGSVOO 1,690,18:6O,26,60~0.0357
5 01 COST023F-GEN SRV COST BA 3 14e 0.0493
6 01COSTB23-GEN SRV,CST-BSD 325 13,615 0.0419
7 01COSTL030LRG GEN SRV, CST 258,66 9,834,304 0.0380
8 01COSTS028,GEN SERV, COST;:115A4 4,48,583 0.0389
9 01GNSBO23-BPA DISC, e: 30 kW -1,46C
10 01GNSBO23,GEN SRV, BPA,e:30 22,535 65
11 01GNSB08-GEN SRVC, BPA,;:-2,831
12 01GNSB0028,GEN SRV,BPA,;:0 23,46 7
13 01GNSV0023,GEN SRV,e:30KW 894,14:2 1,165
14 01GNSV0028,GEN SRV;:3OW 3,142,20 54
1E 01GNSV023F-GEN SRV-FLATRT aSs 3
16 01GNSV023M -GEN SRV, MANUAL 2 65:2 1 2,00 0.3260
17 01GNSV023T GEN SRV, TOU Optio 3,4S 4
18 01 HABT0023,HABITAT BLEND 76 2,780 0.0366
11 01 LGSB0,GEN DELSRV;:2oo -9,316
20 01 LGSB0,GEN DELSRV;:2O 36,95~1
21 01 LGSB008-LG GEN SVC;:10oo -8s(
22 01 LGSB008-LG GEN 5,193 1
23 01 LGSV0030-LRG GEN SRV;:10 5,823,183 189
24 01 LGSVOO8-100 AND OVR 16,274,8O 11E
25 01 LGSV04M-LRG GEN SRVC 1 592,157 20,051,48 5 100,431,40 0.0399
26 01 LNX00102-L1NE EXT 80% G 2,243
27 01 LNX00105-CNTRCT $ MIN G 3,1n
28 01 LNXoo109-REFINREF ADV +1,53
29 01 LNX003OO-L1NE EX 80%705
30 01 LPRS07M-PART REO SRVC 593,056 23,652,895 4 148,264,00 0.0399
31 01 NMT28135-NET MTR, GEN, ;: 3 4,517 1
32 01 OAL T014N-QUTD AR LGT NR 5 742 6 83 0.1484
3~010ALT014N-OUTD AR LGT NR -21
34 01 OAL T015N-QUTD AR LGT NR 38:46,151 159 2,409 0.120
3f 001 PTOU0023,GEN SRV, TOU ENG 76 3,OSE 0.042
3€01 RENW0023,RENW USAGE SPL Y 224 9,184 0.0410
37 01 RENWB023 -RENEWABLE 1 4C 0.04
38 BPA BALANCING ACCOUNT 7,88
39 01 STDAY023-DAY STD OFR,SCH 43 2,22 0.0516
40 01 LGSV028M -LGSV,e:100 55 4,482 1 55,OO 0.0815
41 TOTAL Biled os,m,l-1,683,6H 31,65:0.062~
42 Total Unbiled Rev.(See Instr. 6)98,43 '(0.148(
43 TOTAL 53,390,47 3,327,208,971 1,683,6H 31,71 0.062::
FERC FORM NO.1 (ED. 12-9)Page 304.10
............................................
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 04/03/2008
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating scheule), the entries in column (d) for the special schedule should denote the dupliction in number of repoed
customers.
4. The average number of customers should be the number of bill rendered during the year divided by the number of biling perios during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adiustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line Numoer ana Ille OT Hate sef Mwn::oia Hevenue Average Numoer IS wa or :;aies ~is~rNo.(a)(b)(c)ofC~~omers Per y~stomer
(f)
1 S8408 RECOVERY -506,730
2 SB838 RECOVERY 371,475
3 SMUD REVENUE IMPUTATIONS 388,213
'4 UNBILLED REVENUE 8,602 782,00 0.09
5 UTAH
6 08CFR0051-MTH FAC SRVCHG 16,329
i 08EFOP0021-ELEC FURNACE 0 1,8H 130,330 2 907~0.0718
8 08EFOP021 M-ELEC FURNACE 0 1,612 153,229 ~537,333 0.0951
9 08GNSVOO-GEN SRVC-DISTR 800,317 52,623,648 1,337 598,592 0.068
10 08GNSV009-GEN SRVC-HI VO 2,491,833 98,373,226 11C 22,653,027 0.0395
11 08GNSV0023-GEN SRVC-DISTR 62,439 4,752,017 3,799 16,436 0.0761
12 08GNSVOOA-GEN SRVC-ENERG 49,613 4,668,949 241 205,863 0.091
13 08GNSVOOB-GEN SRVC-DEM&3,045 22,021 6 507,500 0.0729
14 08GNSVOOM-MNL DIST VOL TG 3,06 164,52 1 3,06,00 0.0536
15 08GNSV009A-GEN SRVC HI VO 18,466 1,049,447 6 3,077,667 0.05ee
16 OSGNSV009M-MANL HIGH VOLT 791,582 29,908,098 11 71,962,00 0.0378
17 08GNSV023F-GEN SRVC FIXED 4 1,830 2 2,00 0.4575
18 OSGNSV06MN-GNSV DIST VOLT 1,117 73,49 27 41,370 0.068
19 08GNSV09AM-MAN TOO HIVOL T 1,578 121,856 1 1,578,00 0.0772
2C 08LNXOOO2-MTHL Y 80% GUAR 28,676
21 08LNXOO-ANNUAL 8O%GUAR 362
22 OSLNX0014-80% MIN MNTHL Y 56-:
~08LNX00017-ADV/REF&80%ANN 3,056
24 OSLNX00150-AGR MTH GUAR M 864
25 08LNX003oo - LINE EXT 80% PLUS 5,015
26 08LNX00958-L1NE EXT CNTRC -4,663
27 080AL T007N-SECURITY AR LG 1,468 289,686 545 2,694 0.1973
28 08PRSV031 M-BKUP MNT&SUPPL 975 309,054 1 975,00 0.3170
2~08SLCU1202-TRAF & OTHER S 43 3,12!l 9 4,778 0.0728
30 08SLCU1203-MTR OUTDONIGHT 12 2,937 6 2,000 0.244
31 08SPCLO1 591,691 21,985,~1 591,691,00 0.0372
32 OSSPCL002 859,186 24,291,917 1 859,186,00 0.028~OSSPCL003 628,031 20,791,684 1 628,031,00 0.0331
34 OSSPCLoo05 257,89f 8,595,536 1 257,898,00 0.0333
35 08SPCL0011 6,33C 445,704 0.0704
36 MERGER CREDITS 4
37 ACQUISITION 363,932
38 SMUD REVENUE IMPUTATIONS 823,543
39 08GNSV06AM-MNL ENERGY TOO 96 10,009 1 96,00 0.104
40 08GNSV008-GEN SVC TOU~1oo 974,230 54,86,938 112 8,698,482 0.0563
41 TOTAL Biled 53m.~1,683,6H 31,65~0.062
42 Total Unbiled Rev.(See Instr. 6)98,43 (C 0.1481
43 TOTAL 53,390,47 3,327,208,971 1,683,6H 31,71:0.062
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 2oo7/Q4
(2) EiA Resubmission 04031
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of elecrici 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 accnt in the sequence followed in "Electri Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue accunt, Ust the rate schedule and saes data under each
applicable revenue account subheading.
3. Where the same customers are served under more thn one rate schedule in the same reenue acnt clasification (such as a general residential
schedule and an of peak water heating schedule), the entries in coumn (d) for th spel schedule should deote the duplicaion in number of repoed
customers.
4. The average number of customers should be the number of bils reere during the yer divide by the number of billng perios 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 addtional revenue biled pursuant thereo.
6. Report amount Of unbilled revenue as of end of year for each applicble revenue account subheading.
-'is1,lderUne"NUmoèr ana IlIe aT Maie scneauie Mwn Sold Mevenue Average Number iswn_oT t;aies
No.(a)(b)(c)of Cfcb0mers Per r~stomer
(f)
1 08GNSV008M-GEN SVC TOU ~ 100 66,399 3,634,22 8 8,299,875 0.057
2 UNBILLD REVENUE -8,856 175,OO -0.0198
3 WASHINGTON
4 02GNSB0024-GEN SRVC DO 3,254 215,281 105 30,99 0.062
5 02GNSBO24-GEN SRVC DO -10,52E
6 02GNSB24FP-GEN SVC i 1,97::1 7,00 0.2819
i 02GNSB24FP-GEN SVC -2(
e 02GNSV0024-GEN SRVC 18,00 1,159,53 376 47,888 0.06
9 02GNSV024F- GEN SRVG-FL ~5,79€4 8,250 0.1756
1C 02LGSVOOLRG GEN SRV 136,630 7,424,663 128 1,06,422 0.053
11 ()2LGSV04M-LRG GEN SRV 25,831 1,639,796 1 25,831,00 0.0635
12 02LGSV048T-LRG GEN SRVC 1 674,725 29,173,22 34 19,84,853 0.042
13 020AL T015N-OUTD AR LGT 127 14,25C 43 2,953 0.1122
14 020ALTB15N-OUTD AR LGT NR 32 4,114 19 1,68 0.1286
15 020ALTB15N-QUTD AR LGT NR -14:2
16 02PRSV47TM-LRG PART REQMT 1,54 148,32 1 1,54,00 0.09
17 CENTRALIA RFND 4S
18 MERGER CREDITS -€
19 02LGSB003LRG GEN SVC IRG 3,87E 347,66 2i 143,556 0.0897
2C 02LGSBO36-LRG GENSVC IRG -4,950
21 02LGSB08T - GEN SRVC, NO BPA 1
22 ACQUISITION COMMITMENT -64,803
23 ACQUISITION 86,241
24 BPA BALANCING ACCOUNT 8,941
25 UNBILLED REVENUE -5,04 -132,00 0.0262
2€WYOMING
27 05GNSV0025-GEN SRVC 296,66 17,237,724 1,65!l 178,823 0.0581
28 05GNSV025F-GEN SRVG-FL RA s:8,42(16 5,188 0.1014
29 05GNSV025M-GEN SRVC Manu 1,63 82,20€1 1,632,00 0.05
30 05LGSV04M-LRG GEN SRV 48,96 20,541,214 4 121,741,50 0.0422
31 05LGSV04T-LRG GEN SERV 1,25,496 57,547,14:57 22,04,789 0.0458
32 05LGSV048M-TOU~1OOKW MAN 1,199,937 40,829,34 ::399,979,OO 0.03
33 05LGSV04T-LRG GENSRV TIM 878,n6 30,762,317 9 97,641,n8 0.0350
34 05LNX001oo-L1NEEX 60"1 G 17,38f
35 05LNX00102-L1NE EXT 80"1 G 162,89~
36 05LNX00105-CNTRCT $ MIN G 46,748
37 05LNX001 09-REF/NREF ADV +187,54
38 050AL T015N-QUTD AR LGT SR 89 12,452 47 1,894 0.1399
3g 05PRSV033M-PART SERV REQ 1,082,268 44,181,740 5 216,453,600 0.0408
4C ACQUISITION COMMITMENT -5n,286
41 TOTAL Biled 53.29.~1,683,611 31,65 0.062~
42 Total Unbiled Rev.(8e Instr. 6)98,43 ((0.148~
43 TOTAL 53,390,47 3,327,208,971 1,683,61\31,71~,0.062~
FERC FORM NO.1 (ED. 12-9)Page 30.12
............................................
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) DA Resubmission 0403/2008
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
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
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 rendere during the year divided by the number of biling peri during the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adiustment clause state in a fooote the estimated additionl revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accont subheading.
.une Numoer ana ime or Hate scneauie MvvnoOla Hevenue Average. Numoer l!~s '"~~'SlderNo.(a)(b)(c)of cfch0mers Per C(~stomer
(f)
1 ACQUISITION -548,707
2 SMUD REVENUE IMPUTATIONS 518,781
3 O5LNX003O-L1NE EXT 80%-8,662
4 UN BILLED REVENUE 27,931 1,321,00 0.0473
5 05GNSV0025-GEN SRVC 798 41,279 7 114,00 0.0517
6 05LGSV04T-LRG GEN SERV 25,00 1.217,90~4 6,251,50 0.0487
7 05LGSV048M-TOU;:1ooKW MAN 393,521 13,765,368 E 65,586,833 0.0350
8 05LGSV048T-LRG GENSRV TIM 351,721 12,616,18~7 50,245,857 0.039
9 O5LNX00102-L1NE EXT 80% G 534,272
10 05LNX00109-REF/NREF ADV +1,701
11 05PRSV033M-PART SERV REQ 106,236 1
12 09GNSV0025-GEN SVC-SINGLE 41,545 2,54,122 38 109,329 0.0612
13 09GNSV025M-GEN SVC-MANUAL 4,849 244,206 :1 1,616,333 0.0504
14 090AL T207N-SECURITY AR LG 6 1,766 3 2,00 0.2943
15 09PRSV033M 1,308 187,140 1 1,308,00 0.1431
1E SMUD REVENUE IMPUTATIONS 84,9O
1i UNBILLED REVENUE 90 192,OO 0.2119
18 Less Multiple Bilings -1,08E
19
20 INDUSTRIALSALES TOTAL 19,433,821 826,933,127 11,329 1,715,405 0.0426
21
22 IRRIGATION SALES
2~CALIFORNIA
24 06APSV0020-AG PMP SRVC 68,604 6,013,64 1,331 51,54 0.0877
25 06LNXOO102-L1NE EXT 80% G 916
26 06LNXOO103-L1NE EX 80% G 1,476
27 06LNX00110-REFINREF ADV +9,489
28 06LNXOO312-IRG LINE EX 719
29 06SLX00001-KLAM FALLS MIN 21
30 06USBROOKLAM IRG ONPRJ 33,153 1,246,121 673 49,262 0.0376
31 06LNXOO1 09REF/NREF ADV +180
32 IRRIGATION UNBILLED -17 -3,00 0.1765
33 IDAHO
34 07APSA010L IRG & Pump BPA -8,929,856
~07APSA010L IRG & Pump Large 558,368 36,026,822 3,386 164,90 0.065
36 07APSA010S IRG & Pump BPA -83,650
37 07APSA010S IRG & Pump Small 5,280 421,842 39:1 13,43 0.0799
38 07APSAL 1 OX IRG & PUMP - Large I 86,732 5,883,079 629 137,889 0.0678
39 07APSAS10X IRG & PUMP - Small I 1,413 127,393 195 7,246 0.092
4(07APSC010L IRG PUMP Srv BPA -1,615
41 TOTAL Biled 53,29'1-1,68,61~31,65:1 0.062
42 Total Unbiled Rev.(See Instr. 6)98,43 .((0.148E
43 TOTAL 53,390,47 3,327,208,971 1,683,6H 31,71:1 0.062~
FERC FORM NO.1 (ED. 12-95)Page 304.13
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) An Origina (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04/031008
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in efec 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 subheading and totl for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are clasified in more th one revenue accunt, 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 sae revenue accnt clasiftion (such as a general residential
schedule and an off peak water heating schedule), th,e entries in colun (d) for the speal schedule should deote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rere during the yer divide by the number of billng peris during the yer (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a fooe the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of yer for each applic reenue acnt subheading.
Line -Number ana i me OT l1aie scneauie Mvvn ~oia 'Revenue Average Numoer ~ VY I !-UI_ ,?_aies _~~er
No.(a)(b)(c)of cfch0mers Per y~stomer
(f)
1 07APSC010L IRG PUMP Srv Large 41 -31~-0.0076
2 07APSVCNLL-LRG LOAD 41,5&2,425,104 74 561,892 0.0583
3 07APSVCNLL-LRG LOAD CANAL -68,261
4 07APSVCNLS-SML LOAD CANAL 234 18,06 14 16,714 0.On2
5 07APSVCNLS-SML LOAD CANAL -3,80
6 07BPADEBIT-BPA ADJUST FEE 2,115,00
7 07LNXOO15-ANNUAL 80%GUAR 10,690
8 07LNXOOo-ADV+REFCHG+SOk 128,757
9 07LNXoo107-SUBD ADV & AIC 1,097
1C 07LNX00310 80% ANNUAL 4,131
11 07LNX00312-L1NE EX 8,891
12 07APSN010L-LG IRR & PUMP 3,37E 237,075 31 108,903 0.0702
13 07APSN010L-LG, IRR, 3 PH, BP -50,067
14 07APSN010S-IRR, SMALL, 3 PH,-3,345
15 07APSN010S.IRRIGATION, SMALL,2~15,811 11 18,455 0.On9
16 07APSNS10X-IRRIGATION, SMALL,411 4,270 ::16,33 0.0871
17 IRRIGATION BPA SAL ACCT 7,462,1 Be
1S IRRIGATION LOAD CNTRL CR -4,OO
ill UNBILLED REV - IRRIGATION -¿
20 OREGON
21 01APSV001-AG PMP SRVC BP 1,96,93 4,759
22 01APSV001-AG PMP SRVC BP -96,73i
23 01APSV041L-Pumping Serv:0KW 2,84,204 1,057
24 01 APSV041 L-Pumping Serv BPA ::3 -167,551
25 01APSV041T-AGR PUMP SRV TOU -1,025
2€01APSV041T-AGR PUMP SRV-TOU 26,978 59
27 01APSV041X-AG PMP SRVC n,230 223
28 01 APSV41 XL-Pumping Serv no BPA 114,455 42
29 01 BPADEBIT-BPA ADJUST FEE 28,202
30 01 COST001-01 APSV001-01 APSV 136,279 5,299,60 0.0389
31 01COSTOO8-1 LGSVOO 9,35 33,310 0.0355
32 01 COSTS028,GEN SERV COST :: 3 286 11,190 0.0391
33 01GNSV0028,GEN SRV::SO kW 8,19C 2
34 01 HABIT041-01 APSV001AG PMP 1 28 0.0280
35 01 LGSB0048-LG GEN -23,823
36 01LGSB0048-LG GEN SVC::100 97,6O 2
3i 01LNXoo102-L1NE EX 80% G 184
Sf 01 LNX001 03-L1NE EXT 80% G 1S,31C
3E 01LNXoo109-REF/NREF ADV +806
4C 01LNXoo110-REFINREF ADV +79,224
41 TOTAL Billed ~:=.~1,683,6H 31,65 0.062~
42 Total Unbilled Rev.(See Il1tr. 6)98,3 .((0,1486
43 TOTAL 53,390,47 3,327,208,971 1,683,619 31,71~0.062~
FERC FORM NO.1 (ED. 12-95)Page 304.14
............................................
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) riA Resubmission 04/03/2008
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Reprt 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 "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 served under more than one rate schedule in the same revenue accunt classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendered during the year divded 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 applicle revenue accunt subheading.
IUne NumDer ana I me or Hate scneouie Mvvn ::010 Hevenue Average Numoer ~vvn~OT_~.!es v ~'flder
No.(a)(b)(c)of cqlhomers Per C(~stomer
(f)
1 01PTOU0041-01APSV001 AG PMP 64 21,201 0.0330
2 01RENEW041-01APSV001 AG 100 3,911 0.0391
3 01SLXOO-KLAMATH FALLS 116,28C
4 01 SLX0013-K FALLS IRG MI 4,366
5 01SLX0014-K FALLS IRG MI -2€
6 01 STDA Y041-Daily Standard Ofer 8 30 0.0375
7 01USBGV033-KLAMATH IRG TOU -6
8 01USBOF033-KLAMATH BASIN 51,901 691,180 662 78,400 0.0133
9 01USBOF03-KLAMATH BASIN -63,96E
10 01 USBON033-KLAMATH BASIN 59,nE 673,17E 1,410 42,39€0.0113
11 01USBON033- KLAMATH BASIN -72,63!
1;¡01 USBGV033-IRG TOU WIO BPA 2,812 19,10~10 281,2OC 0.0068
1::MERGER CREDITS -4
14 BPA BALANCING ACCOUNT 384,565
15 IRRIGATION UNBILLED -41 -9,00 0.2191:
1€Irrigation - BPA adjustment 5,92~
17 01LNX0012 - IRG LINE EX 2,521
18 S8408 RECOVERY -23,366
19 SB838 RECOVERY 13,215
2C UTAH
21 08APSV0010-IRR & SOIL DRA 200,303 10,702,821 2,493 80,34 0.0534
22 08APSV10NS-lrg Soil Drain Pump N 14,313 757,46E 75 190,84 0.0529
23 08LNX0002-MTHL Y 80% GUAR 656
24 08LNXoo04-ANNUAL 80%GUAR 57,549
25 08LNX0014-80% MIN MNTHL Y 530
26 08LNX0017-ADVIREF&80%ANN 108,202
27 08LNX00152-AGR ANN GUAR M 84
28 08LNX003OO-L1NE EXT 80% PLUS 28
29 08LNX0010-IRR, 80% ANNUAL 3,023
3C 08LNX0012 IRG LINE EXT 3,369
31 08NMT10135-IRR~SOIL DRNG NET 11 831 1 11,00 0.0755
32 08RFND 1999-RATE REFUND 1
33 UNBILLED REVENUE 104 7,00 0.0673
34 WASHINGTON
35 02APSVOO-AG PMP SRVC 143,928 8,647,963 4,66 30,86 0.061
36 02APSVOO-AG PMP SRVC -361,732
37 02APSV040X-AG PMP SRVC 20,255 1,204,250 587 34,506 0.0595
38 02BPADEBIT-BPA ADJUST FEE 9,370
39 02LNX00102-L1NE EX 80% G 957
40 02LNX00103-L1NE EXT 80% G 5,651
41 TOTAL Billed 53~.~1,68,619 31,6~0.062;¡
42 Total Unbilled Rev.(See Instr. 6)98,3 C C 0.148~
43 TOTAL 53,390,47 3,327,208,971 1,683,6H 31 ,71~0.062~
FERC FORM NO.1 (ED. 12-95)Page 304.15
Page 304.16
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) nA Resubmission 04031
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of elecriit sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reprted on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue accunt in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classifed in more than one revenue accunt, 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 residentil
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 rendered during the year divide by the number of billng perods 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 aditionl revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applice revenue acount subheading.
I Line NumDer ana llte or Hate sCneoule Mvvn 0:010 Revenue Ave~ititumDer ~vvll OT ;;aies ~olerNo.(a)(b)(c)ofC omers Per C(~stomer
(f)
1 02LNX00105-CNTRCT $ MIN G 3C
2 02LNX001 09-REF/NREF ADV +1,951
3 02LNX00110-REFINREF ADV +55,64i
4 02LNX00310-iRG 80% ANNUAL 42E
5 02LNX0012-IRG LINE EX 145
e CENTRALIA RFND 10
7 MERGER CREDITS 9
8 BPA BALANCING ACCOUNT 338,962
i; UNBILLED REVENUE -20 -59,00 0.2823
1C WYOMING
11 05APSOOo-AG PUMPING SVC 16,704 1,238,994 sa 29,670 0.0742
12 05LNX0011Q-REF/NREF ADV +35,28
13 05LNX00103-L1NE EXT 80% G 5,757
14 05LNX00310-L1NE EXENSION 27~
15 05LNX0012-IRG LINE EXT ~
16 UNBILLED REVENUE -7 -1,OO 0.1429
17 05APSOOAG PUMPING SVC -~1
18 O5LNX00103-L1NE EXT 80% G 4,76~
19 O5LNX00110-REFINREF ADV +4,093
2C 09APSV0210-IRR & SOIL ORA 3,095 196,037 50 61,900 0.06
21 Less Multiple Billngs -609
22
2:3 IRRIGATION SALES TOTAL 1,458,632 87,38,~22,79C 64,003 0.0599
24
25 PUBLIC STREET&HIGHWAY LIGHT
26 CALIFORNIA
27 06COSL0052-eO-OWND STR LG 8 6,104 5 1,600 0.763
28 OGUSL053F-SPECIAL CUST 0 1,46 156,620 12C 12,217 0.106
29 06CUSL058F-CUST OWND STR 251 30,524 23 10,913 0.1216
30 06HPSV001-HI PRESSURE SO 681 147,184 75 9,080 0.2161
31 UNBILLED REVENUE -9
32 IDAHO
33 07GNSV023S-TRAFFIC SIGNALS 94 9,107 26 3,615 0.099
3A 07SLCOO11-STR LGT CO-OWN 126 29,961 31 4,065 0.2378
35 07SLCU012E-ENGY STR LGT 146 1
3€07SLCU012F-FULL MNT STR LGT 1,052 112,941 275 3,825 0.1074
3i 07SCLU012P-PART MNT STR LGT 10~5,79~16 6,375 0.056
3e 07SLCU1201-TRAF SIGNAL SY 8:1 6,71€26 3,154 0.0819
39 07SLCU1203-STR LGT CUST-o 122 1
4C 07SLCU122A-STR LGT CUST-O 7e 4,312 15 5,200 0.0553
41 TOTAL Billed 53~92.~1,683,61!31,65 O.06Z
42 Total Unbiled Rev.(See Instr. 6)98,43 ((0.148E
43 TOTAL 53,390,47 3,327,208,971 1,683,61E 31,71:1 0.062~
fERC fORM NO.1 (ED. 12-95)
-...........................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 041031208
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue accunt in the sequence followed in UElectric Operating Revenues," Page
30301. If the sales under any rate schedule are classifed 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 seived under more than one rate schedule in the same revenue account classifcation (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 bils rendered during the year divide by the number of biling perids during the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a fooote the estimated additional revenue biled pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
'Line 'Numper ana i me oJ Maie sCneauie "Revenue Average Numoer ~VVIJ aT i?aies h~lderNo.(a)(b)(c)of cfd\omers Per r~stomer
(f)
1 07SLCU122B-STR LGT CUST-O 789 84,989 271 2,911 0.10n
2 UNBILLED REVENUE -10e -11,OO 0.1019
~ OREGON
4 01 COSL0052-STR LGT SRVC C 1,517 187,186 82 18,500 0.1234
5 01 CUSL0053-CUS-OWND MTRD 749 50,469 63 11,889 0.0674
6 01 CUSL053E-STR LGT SVC 4,685 317,175 97 48,299 O.06n
'1 01 CUSL053F-STR LGT SRVC C 3,459 245,159 86 40,221 0.0709
8 01 HPSVOO51-HI PRESSURE SO 16,161 3,022,033 672 24,049 0.1870
9 01 MVSL005O-MERC VAPSTR LG 10,78i 1,255,946 30 35,957 0.1164
10 010ALT014N-OUTD AR LGT NR 139 1
11 010AL T014N-OUTD AR LGT NR -2
12 010ALT015N-oUTD AR LGT NR 5 898 2 2,500 0.1796
13 S8408 RECOVERY -6,06
14 S8838 RECOVERY 3,223
15 UNBILLED REVENUE 25€51,00 0.19n
16 UTAH
17 08CFRoo12-STR LGTS (CONV 54
18 08CFR00051-MTH FAC SRVCHG.4,529
19 08CFR001-U/G AREA LIGHT 138
20 08CFR002-STREET LIGHTS n
21 08HAXOO-L1GHTNG-HAXON 93 1
22 080AL TOO7N-SECURITY AR LG 1 22~2 500 0.223C
23 08SLC1202F-TRAFFIC SIG NM 1,1~81,275 130 9,100 0.0687
24 OBLCOOO11-STR LGT CO-OWN 22,274 6,165,682 1,130 19,712 0.2768
25 08SLCU1202-TRAF & OTHER S 3,074 266,728 1,54 1,986 0.088
26 08SLCU1203-MTR OUTDONIGHT 954 71,048 45 21,20 0.0745
27 08SLCU121A-STR LGT CUST-O 7,244 732,852 240 30,183 0.1012
28 08SLCU121 B-STR LGT CUST-O 3,274 425,827 186 17,602 0.1301
29 OBSLD13ES1-DECOR CUST-OWN 6,160 367,371 62 99,355 0.0596
30 08SLD13ES2-DECOR CUST-OWN 27,879 1,688,262 198 140,803 0.06
31 OBSLD13FS1-DECOR COMP-OWN 91 51,158 7 13,857 0.5274
32 08SLD13FS2-DECOR COMP-oWN 184 112,520 12 15,333 0.6115
33 08SLD13MS1-DECOR CUST-OWN 572 n,92E 17 33,647 0.1362
34 08SLD13MS2-DECOR CUST -OWN 80 122,06 21 38,476 0.1511
35 08THIKoon-STR LIGHT SPEC 141 17,2n 1 141,00 0.1225
36 UNBILLED REVENUE -1,38 -167,00 0.1205
37 WASHINGTON
38 02CFROO12-STR LGTS (CONV 91
3~02COSLOO52-STR LGT SRV 452 58,017 22 20,54 0.1284
40 02CUSL053F-STR LGT SRV 3,43~209,990 189 18,164 0.0612
41 TOTAL Billed 53~92.~1,683,6H 31,65~0.06
42 Total Unbilled Rev.(See Instr. 6)98,43 (t 0.148
43 TOTAL 53,390,47 3,327,208,971 1,683,611;31,71~0.062~
FERC FORM NO.1 (ED. 12-95)Page 304.17
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) nA Resubmission 04208
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate scheule in efec 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 subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, Ust the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are seived under more than one rate schedule in the same revenue account classifcation (such as a general residential
schedule and an oft peak water heating schedule), the entries in column (d) for the speia schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendere during th year divde by the number of billng periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a ful adjustment clause state in a fooote the estimated additonal reenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of yea for eah applicle revenue account subheading.
Une Number ana Titie or Maie Scneauie Mevenue -Average NulToer iswn_OIò;les ~~R~UíerNo.(a)(b)(c)of CfJ,0mers Per l~stomer
(1)
1 02CUSL053M-STR LGT SRV 1,018 61,485 86 11,837 0.06
2 02HPSV0051-HI PRESSURE 2,933 511,622 159 18,447 0.1744
3 02MVSL0057-MERC VAPSTR 2,059 218,907 51 40,373 0.1063
4 UNBILLED REVENUE -2f -1,00 0.0357
5 WYOMING
6 OSCOSL0Q7-CO-oWND STR LG 514 101,96 27 19,037 0.1984
7 05CUSL058F-CUST OWND STR 1,158 73,67f sa 30,474 0.06
8 05CUSL058M-CUST OWND STR n 4,84~9 8,556 0.0629
.~ 05HPSV0051-HI PRESSURE SO 4,27 919,91E 161 26,255 0.2176
1C OSMVSO53-MERCURY VAPOR 4,137 53,291 268 15,379 0.1282
11 09SLC00211-STR LGT CO-OWN 1 15~1 1,00 0.1520
12 09SLCU2122-TRAF & OTHER S 2 65 2 1,00 0.0325
13 UNBILLED REVENUE -91 -14,00 0.1538
1~09SLC00211-STR LGT CO-OWN 1,36 485,190 93 14,6n 0.3555
15 09SLCU2121-STR LGT CUST-o 9C 16,310 1~6,429 0.1812
1E 09SLCU2122-TRAF & OTHER S 64 2,375 14 4,571 0.0371
17 UNBILLED REVENUE -2:3 -6,OO 0.2609
18 Less Multiple Bilings -2,693
19
2C Total PUBLIC STREET&HIGHWAY 136,080 18,90,69 4,230 32,170 0.1389
21
22 OTHER SALES TO PUBLIC AUTH
2~UTAH
24 08GNSVOO-GEN SRVC-DISTR 2,336 143,8~4 584,00 0.0616
25 08GNSV0023-GEN SRVC-DISTR 27 2,319 2 13,50 0.0859
2€08GNSVOOM.MANL HIGH VOLT 439,112 17,480,811 4 109,n8,00 0.0398
27 080AL T007N-SECURITY AR LG 19 4,495 3 6,333 0.236
2E UNBILLED REVENUE -6,000 -122,00 0.0200
29
30 Total Other Sales to Public Auth 435,395 17,509,459 1:3 33,491,923 0.042
31
32 FORFEITED DISCOUNTS
33 CALIFORNIA
34 Late Fees 20,9n
35 IDAHO
36 Late Fee 368,66
3i OREGON
38 Late Fee 2,479,920
39 UTAH
4C Late Fees 2,744,745
41 TOTAL Biled S3=.~1,683,61~31,65 0.06242Total Unbille Rev.(See Instr. 6)98,43 ((0.148£
43 TOTAL 53,390,47 3,327,208,971 1,683,61£31,71~0.062~
FERC FORM NO.1 (ED. 12-95)Page 304.18
............................................
-...........................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 04/03/2008
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
3DO301. If the sales under any rate schedule are classifid in more than one revenue accunt, 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 scedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billng perio 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 pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue acunt subheading.
Une Numoer ana I me OT Hate scneauie Hevenue Average Numoer ~~nr~sroa::r ~'SikrNo.(a)(b)(c)of circiomers
(1)
1 WASHINGTON
2 Late Fees 48,516
3 WYOMING
4 Late Fees 430,589
5 Late Fees 70,257
6
7 Total FORFEITED 6,784,670
8
II OTHER ELECTRIC REVENUE
1C CALIFORNIA
11 06CFROO3-MTH MAINTENANC 1,454
1;;06CONN03DORECONNECTION 102,787
13 06METR030FEE MTR TES 200
14 06FCBUYOUT 4,757
15 06RCHK03OO-RET CHK CHR 9,965
1€06TAMPæOO~AMP & UNAU 2,325
17 06TEMPO~~EMP SRVC C 7,99
H!06TRBL03 TROUBLE CAL 30
19 06SVRCHARG- EXCESS FOOTAGE -2,018
2C 06XMTRTAMP- TAMPERING-UNAU 38/
21 Home Comfort 2,262
22 Industrial Finanswer 771
23 Irrigation Finanswer 992
24 Other 7,054
25 IDAHO
26 07CFROO1-MTH FAC SRVCHG 2,100
27 07CONN03DORECONNECTION 83,820
28 07RCHK03-RET CHK CHR 23,620
211 07TAMP0300 2,40
30 07TEMPOO14- TEMP SRVC CONN 27,205
31 07XMTRTAMP-TAMPËRING -511
32 Weatherization Loans 2,014
33 Other 1,085
34 OREGON
35 01CFROO1-MTH FACILITY S 62,082
36 01 CFROO3-MTH MAINTENANC 26,061
37 01 CFROOO04EMRGNCY ST&BY 24,748
38 01 CFROOOO-INTEAMTNT SRVC 43,458
39 01 CFROO13-MTH MISC CHRG 2,284
40 01CFROOO14-YR MISC CHRG 5
41 TOTAL Bille 53,2.~1,683,61 31,65 0.062:
42 Total Unbilled Rev.(See Instr. 6)98,43 (0.148(
43 TOTAL 53,390,47 3,327,208,971 1,683,61 31,7~0.062~
FERC FORM NO.1 (ED. 12-95)Page 30.19
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04/031200
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of elecncity 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 prescnbe operating revenue accnt in th sequence followed in "Elecnc Operating Revenues," Page
300-301. If the sales under any rate schedule are classifed in more than one revenue accnt, 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 accunt classification (such as a general residential
schedule and an of peak water heating schedule), the entries in column (d) for the spec 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 divi by the number of billing penods 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 pursuant thereto.
6. Report amount of unbiled revenue as of end of yer for each applicable revenue acnt subheading.
ine Numoer ana I me Of Hate scneouie Mvvn tiOlO Hevenue Average NumDer i:vvnßT_t;les R'tlderNo.(a)(b)(c)of CfJ,0mers Per y~stomer
(f)
1 01CONN0300-RECONNECTION C 1,04,32
2 01 ESSC06 -ESS charges 1,420
:3 01 FCBUYOUT-FAC CHG BUYOUT 72,36
4 01 RCHK03O-RETURNED CHECK 221,35
5 01TAMP03OQ TAMP & UNAUTH 18,90
6 01TEMP030 TEMP SRVC CHRG 248,795
ì 01XMTRTAMP-TAMPERING-3,271
8 Otr 22,891
e Retroit Finanswer 1,017
1e Misc Serv-Acet Serv Charge 411,681
11 UTAH
12 08CFROO13-MTH MISC CHRG 147,88
13 08GNSVOO-GEN-SRVC-DISTR 15.66
14 08CFROO51-MT FAC SRVCHG 173,62
15 08CFROO52-ANN FAC SVCCHG 424
16 08CFROO53-MTHL Y MAINTFEE 9,OG
1i 08CFROO-MTH MISC CHARG 3,301
18 08CFROO-ANN MISC CHARG 6,66
1e 08CONN030-RECONN&DISCONN 517,3O
20 08CONTSERV-3RD PARTY O/S 207,351
21 08FCBUYOUT-FAC CHG BUYOUT 97,038
22 08MTRVR30 -Meter Veriication F 51C
23 08NCON0300-FEE NRES RE3072 4,042
24 08RCHK030-RET CHK CHR 327,79!
25 08RCONOO1-CONNECT FEE 1,688,160
21:08TAMP0300- TAMPERING&UNAU 27,37f
27 08TEMP0014-TEMP SRVC CONN 724,57C
28 08XMTRTAMP- TAMPERING -4,902
29 08INFOO-CUSTI3RD P REO 38
3t Energy Finanswer 12,00 1,509
31 Energy Finanswer new Com 69,711:
32 Other -4,402
33 08VISIT30 - Visit, Service Ca 323,665
34 Retroft Finanswer 478
35 WASHINGTON
3E 02CFROO-MTH MAINTENANC 1,32
37 02CFROO-EMRGNCY ST&BY 5,9O
38 02CFROO5-INTERMTNT SRVC 4,302
39 02CONN03-RECONNECTION 136,450
4C 02FCBUYOUT - FAC CHG BUYOUT 23,551
41 TOTAL Biled 53~~1,683,6H 31,65 0.062~
42 Total Unbilled Rev.(See Instr. 6)98,43 :(0.14~
43 TOTAL 53,390,47 3,327,208,971 1,683,61~31,71 0.062~
FERC FORM NO.1 (ED. 12-95)Page 304.20
............................................
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifiCorp (1) An Original (Mo. Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04/03/2008
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect dunng 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 prescnbed 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
schedule and an of peak water heating schedule), the entnes 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 penods dunng the year (12 if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote th estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each appicable revenue account subheading.
Line CNumoer ana Ille OT Nate sctieae Mvvn ::010 Nevenue AVerage"Numoer ~:nC(~s~e:r Ris~krNo.(a)(b)(c)of cllch0mers
(f)
1 02RCHK030-RET CHK CHR 40,405 .
2 02TAMP0300-TAMP & UNAU 7,80
3 02TEMP03QO TEMP SRVC C 41,765
4 02XMTRTAMP-TAMPERING-2,141
5 Other -1,718
6 Weatherization Loans 106
7 Energy Finanswer New Com 7,092
.~ Home Comfort 6,826
9 WYOMING
1C 05CFROO-MTH MAINTENANC 8,032
11 05CFROO-EMRGNCY ST&BY 20,576
12 05CFRoo05-INTERMTNT SRVC 10,554
13 05CFRoo13-MT MISC CHRG 3,186
14 05CONN030-RECONNECTIO 78,470
15 05FCBUYOUT-FAC CHG BUYOUT 142,224
16 05RCHK030RET CHK CHR 44,700
17 05SERV0300-SRVC CALLS 6,480
1f 05TEMP0300-TEMP SRVC 49,995
H 09CFROO005-INTERMTNT SRVC 339
20 05LONGFORM-BILL PRINT 40
21 05CONN0300-RECONNECTION 10,180
22 05FCBUYOUT - FAC CHG BUYOUT 111:0
23 05RCHK0300-RET CHK CHR 6,30
24 05SERV0300-SRVC CALLS 84
25 05TAMP030 1,200
26 OSTEMP03- TEMP SRVC 6,035
27 OSXMTRTAMP- TAMPERING-UNAU 151
28 09CFROO1-MTH FAC SRVCHG 5,36€
29 09CFRoo14-YR MISC CHRG 2
3C Energy Finanswer 12,00 493
31 Other 1,509
32
33 MISC. SERVICE REV TOTAL 7,215,245
34
35 WATER & WATER PWR SALES
3€UTAH 44,831
37 WYOMING 62,649
38
39 Total WATER & WATER PWR 107,480
40
41 TOTAL Biled 53.~1-1,683,61 31,65 0.0622
42 Total Unbilled Rev.(See Instr. 6)98,43 "(0.1485
43 TOTAL 53,390,47 3,327,208,971 1,683,61 31,71~0.062~
............................................FERC FORM NO.1 (ED. 12-95)Page 30.21
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) EiA Resubmission 0410
SALES OF ELECTRICITY BY RATE SCHEDULES
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 accunt in the sequence followed in "Electri Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue acunt, 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 schedle in the sae reenue accnt classifcation (such as a general residential
schedule and an of peak water heating schedule), the enri 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 rere during the yer divid 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 fonote the estimated addional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each apicable revenue accnt subheading.
I Line Numoer ana I me OT Hate scneauie Mevenue l\verage l'umoer ~ vv n~ OT ;;aies R'gir;rNo.(a)(b)(c)of CfJ,0mers Per rl\stomer
(f)
1 RENT FROM ELEC PROPERTIES
2 CALIFORNIA
:: 06CFROOMTH RNTAL CHRG 1,710
4 RENT REVENUE-HYDRO 4O,OO
5 Rent Revenue - Sublease 14,56
6 Joint use 33,nE
7 IDAHO
8 07CFROO9-YR LSE CHRG-EO 794
9 07INVCHGoo-INVEST MNT CHG 181
10 07LOOP0014-MTH FEE PRE-AS 2,247
11 07POLE0075-STEEL POLES US 283
12 07XTRN0013-RNT/LSE L& PRO 103,10S
13 RENT REVENUE-HYDRO 5,450
14 Joint use 228,521
15 Rents- Non common 30
1 E Rent Revenue - Subleases ~
1/ OREGON
H RENTS - COMMON 34,O4~
19 Rents - Non Common 3,181
2C MCI FOGWIRE REVENUE 3,351,12E
21 RENT REVENUE-HYDRO -37,1OC
22 RENT REV-TRANSMISS 204,919
2:3 RENT REV-DISTRIBUT 6,951
24 RENT REV-GEN(COMM)45,521
25 01CFROO-MTH RNTAL CHRG 515,702
26 01XTRN0013-RNT/LSE L&PRO 13,993
27 Rent Revenue - Subleases 478,34
28 Joint use 4,707,985
29 UTAH
30 08CFRoo056-MTH EOUIP RENT 3:
31 08CFROO58-MTH EOUIP LEAS 729,2B:
32 08INVCHGON-INVEST MNT CHG 4,837
33 08INVCHGOR-INVEST MNT CHG 328
34 08LOOP014N-TEMP SERV CONN 15,28S
35 08POLE~POLE ATTACH MEN 5,190
36 08POLE0075-STEEL POLES US n,151
37 08XTRN0013-RNTILSE L& PRO 75,184
38 RENTS - COMMON -74,902
39 Rents - Non Common 4,95C
4C RENT REVENUE-STEAM 36,280
41 TOTAL Biled "-'l-1,68,61~31,65~0.062
42 Total Unbiled Rev.(8e Instr. 6)98,3 C C 0.148
43 TOTAL 53,390,47 3,327,20,971 1,68,6H 31,71~0.06
FERC FORM NO.1 (ED. 12-95)Page 304.22
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Peri of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04/0312008
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicble revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entris 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 biling period 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 billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicae revenue account subheading.
fLìne l'moer ana i me OT Hate scneClule Hevenue AVerage Number ~"'!.UJ~les ~isikrNo.(a)(b)(c)ofC omers Per e¡~stomer
(f)
1 RENT REVENUE-HYDRO 144,596
2 RENT REV-TRANSMISS 819,706
:: RENT REV-DISTRIBUT 83,34
4 RENT REV-GEN(COMM)550,012
E Rent Revenue - Subleases 1,959,100
6 Joint use 2,160,77C
7 WASHINGTON
8 02CFROO1-MTH FACILITY S 2,070
5 02CFROO-MT RNTAL CHRG 35,57~
10 RENT REVENUE-HYDRO 665,811
11 RENT REV-DISTRIBUT 14,190
1"RENT REV-GEN(COMM)30,649
13 RENT REV-TRANSMISS 250
14 Rent Revenue - Subleaes 35,60
15 Joint use 46,474
16 WYOMING
17 05CFROO1-MTH FACILITY S 11,524
1e 05CFROO-MTH RNTAL CHRG 2,94
19 RENT REVENUE~TEAM 38,377
20 RENT REV-GEN(COMM)13,893
21 Rent Revenue - Subleases 51,647
22 Joint use 390,815
23 09LOOP0214-MTH FEE PRE-AS 159
24 09POLE0075-STEEL POLES US 22,44
25 RENT REVENUE-STEAM 5,388
26 Joint use 16,633
27
2E Total RENT FROM ELEC 18,760,759
25
3C OTHER ELECTRIC REVENUE
31 WYOMING
32 ALL BLUE SKY RES 36,149
3:3 ALL NON-RES BLUE SKY 4,798
34 ALL BLUE SKY RES 4,423
35 ALL NON-RES BLUE SKY 164
36 WASHINGTON
37 ALL BLUE SKY RES 37,0~
38 ALL NON-RES BLUE SKY 11,442
39 UTAH
40 ALL BLUE SKY RES 757,332
41 TOTAL Biled 5Ø=~1,683,61 31.65~0.062~
42 Total Unbiled Rev.(See Instr. 6)98,43 (0.148~
43 TOTAL 53,390,47 3,327,208,971 1,683,61 31,71~0.062~
FERC FORM NO. 1 (ED. 12-95)Page 30.23
Name of Respondent This~rtIS:Date of Reprt Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) EiA Resubmission 04103100
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of elecrity 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 "Elecric Oprating Revenues," Page
300-301. If the sales under any rate schedle are classified in more than one revenue accnt, 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 scedule in the same revenue account classifcation (such as a general residential
schedule and an of peak water heating schedule), the entries in column (d) for the specal 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 biling peris during the year (12
if all billngs are made mothly).
5. For any rate schedule having a fuel adjustment clause state in a foonote the estimated additional revenue biled pursuan thereto.
6. Report amount of unbiled revenue as of end of yer for each applicable revenue account subheading.
!üOe Number anci Tite ot Haie scneaUle MWh ~oici Hevenue Averaiil-Jumoer isWh_ot :;eiies .c'Sil1rNo.(a)(b)(c)ofC~s omers Per y:tstomer
(f)
1 ALL NON-RES BLUE SKY 193,265 .
2 OREGON
3 ALL BLUE SKY RES 123,149
4 ALL NON-RES BLUE SKY 148,589
5 IDAHO
6 ALL BLUE SKY RES 13,316
7 ALL NON-RES BLUE SKY 67
8 CALIFORNIA
9 ALL BLUE SKY RES 13,856
10 ALL NON-RES BLUE SKY 359
11 OTH ELEC ESTIMATE -119,418
12 GREEN CREDIT SALES 3,727,113
1:3 NON-WHEELING SYSTEM REV 9,44,36
14 ELEC INC- OTHR 16,310
15 Other Ete 14,497;92:
16 DSM REV- CA sse OFF -27,46
17 Joint Use Cust Accm 66,90
1S CALIFORNIA
19 Fish,Wildle. Recr 3,899
20 IDAHO
21 DSM REV-ID SBC 2,04,020
22 Oter Elec 1,682
2~OREGON
2~3RD PARTY TRANS 441,08
25 M&S INVENTORY REVENUE 12,100
26 01XTRNO11- SALE ORDERS 22,851
27 Jont Use Cust Ac 610,99
28 Other Elec 3,074,56:
29 Other Elec DSR carr chrg 414,110
3C UTAH
31 ELEC INC-QTHR 230,oo
32 FL YASH SALES 309,94
33 M&S INVENTORY REVENUE 981,96
34 Joint Use Cust Accm 574
35 DSM REV-UT SBC OFFSET 25,396,52f--Fish, Wildlife, Recr 1,96
37 Other Elec 67,18E
38 WASHINGTON
39 02XTRN0011-SALES ORDER INV 257
4CJ Fish, Wildlife, Recr 53,553
41 TOTAL Biled 53'~~1,683,611 31,65 0.062
42 Total Unbiled Rev.(See Instr. 6)98,3 ((0.14~
43 TOTAL 53,390,47 3,327,208,971 1,683,611 31,71~0.06~
FERC FORM NO.1 (ED. 12-95)Page 304.24
............................................
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 04/0312008
SALES OF ELECTRICITY BY RATE SCHEDULES
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 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 "Elecric Operating Revenues," Page
300301. 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 undr 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 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 billing peri during the year (12
if all billngs are made monthly).
5. For any rate scheule having a fuel adiustment 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 account subheading.
Line NUmoer ana ime OT Hate scneauie Mwn~ia Hevenue Average. Numoer ~~nr~s=:r C~ol;rNo.(a)(b)(c)ofcq~omers
(f)
1 Joint Use Cust Accom 97,043
2 Wash Costri 3 -52,18l
3 WYOMING
4 Joint Use Cust Accom 8,878
5 ELEC ING-THR 463
6 FL YASH SALES 2,534,613
7 Regulatory Recovery Fee 176,496
E FLYASH SALES ...'11,765 ........... ............
~
10 OTHER ELECTRIC REVENUE 65,399,708
11
12
1~
14
15
16
17
18
19
2C
21
22
23
24
25
26
27
28
29
3C
31
32
33
34
35
36
37
38
39
40
41 TOTAL Biled 53,292,03!ô 3,312,551,971 1,683,6H 31,65 0.062
42 Total Unbilled Rev.(See Instr. 6)98,~((0.148~
43 TOTAL 53,390,47 3,327,208,971 1,683,61~31 ,71~0.06~
FERC FORM NO.1 (ED. 12-95)Page 304.25
/FERC FORM NO.1 (ED. 12-S7) Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) XAn Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 040312008 2007/Q4
FOOTNOTE DATA
¡Schedule Page: 304 Line No.: 42 Column: c
For furter discussion on unbiled revenue refer to page 300, Electrc Operating Revenues, line 12 colum (b).
............................................
Blank Page
(Next Page is 310)
Name of Respondent ThiS~ort Is:Date of Reprt Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2)A Resubmission 0403120
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 imbalance exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projeced 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 suppliers service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termnation 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 servic excpt that "intermdiate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm servics 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.
Une Name of Company or Public Autori Stl FERC Rae Averaße Actual Demand (MW)
No.(Footnote Affliatins)Claif-Scedle or Moly ¡Iling Avera~Avera~catio Tari Number Deman(MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Requirement Sales
2 Brigham City RQ T-6 20 20 18
3 Deaver, Town of RQ T-4 .2 .1 .1
4 Helper City RQ T-6 1 1 .9
5 Helper City Annex RQ T-6 .6 .7 .6
6 Navajo Tribal Util Auth (Mx Hat)RQ T-6 .2 .2 .2
7 Navajo Tribal UtU Auth (Red Mesa)RQ T-6 1 1 1
8 Portland General Electric Co.RQ 147 W NP NA
9 Price City RQ T-6 1:3 12 12
10 Accrual True-up RQ NA NA NA NA
11
12 Nonrequirement Sales
13 Anaheim, Cit of SF WSPP NA NJl NA
14 Ariza Elecri Power Coperative T-12 NA NP NA
Subtotal RQ (0 0
Subtotal non-RQ (0 0
Total C 0 0
FERC FORM NO.1 (ED. 12-90)Page 310
............................................
............................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Me, Da, Yr)End of 2oo7/Q4
(2) DA Resubmission 04/03/2008
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 - RO"
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 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 (GOminute
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-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 ($)Une
Sold Deman Charges Energy Charges Other Charge (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
1
116,855 1,881,51~2,035,617 3,917,130 2
1,072 14,317 19,305 33,622 3
6,243 117,594 110,465 .228,059 4
3,794 72,89S 67,155 140,053 5
1,06 19,782 18,579 38,361 6
7,711 119,782 134,321 254,100 7
11,148 929,33 934,195 8
76,735 1,176,411 1,337,567 2,513,984 9
-14,929 -4,219 10
11
12
8,491 458,34 458,34 13
-12,195 14
209,695 3,402,303 4,652,34 -4,359 7,616,288
13,514,160 51,06,933 2,54,114,007 -1,745,930,397 849,248,543
13,723,855 54,467,236 2,54,766,351 -1,746,368,756 85,86,831
FERC FORM NO.1 (ED. 12-90)Page 311
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04/031008
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 dunng the year. Do not report exchanges of electncit ( 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 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 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 intermdiate-term firm servic. The same as LF servic excpt that "intermiate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm servs where the duration of each penod 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
service, aside from transmission constraints, must match the availabilit 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.
Une Nare of Company or Publc Auhori St FERC Rae Averaar Actual Deand (MW)
No.(Footnote Affliation)Claif-Sc or Moly lling . !,vera¡§e Avera~cation Tar Number Demand(MW)Monthly NC Deman Monthly CP emac
(a)(b)(c)(d)(e)(1)
1 Arizona Public Service Co.T-12 NA NA NA
2 Arizona Publi Service Co.T-12 NA NA NA
3 Arizona Public Service Co.T-12 NA NA NA
4. Arina Public Service Co.SF T-12 NA NJl NA
5 Avista Corp.SF T-13 NA NJl NA
6 Avista Corp.SF WSPP N,l NJl NA
7 Avista Energy, Inc.SF WSPP NA NJl NA
8 BP Energy Company SF WSPP NA NJl NA
9 BarclaysBank PLC SF T-12 NA NA NA
10 Basin Elecric Power Cooperative T-11 NA NA NA
11 Basin Electric Power Cooperatie SF T-11 NA NA NA
12 Bain Eleric Power Coperative SF WSPP NA NJl NA
13 Bear Energy LP SF T-12 NA NJl NA
14 Benton County Public Utilty Dist No. 1 SF WSPP NA NJl NA
Subtotal RO (J 0 0
Subtotal non-RO (J 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.1
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) riA Resubmission 04103/2008
S LES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of.service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly 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 (SO-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (SO-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/on-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 Tot ($)üne
Sold Demand Charges Energy Charges ~(h+i+j)No.
($)($)($)
(g)(h)(I)')(k)
139 1
25 993 993 2
1,8n 102,128 102,12f 3
222,722 13,078,701 13,078,701 4
56 2,792 5
42,995 2,30,125 2,309,125 6
88,129 4,30,46 4,30,46 7
1,929,254 122,854,492 122,85,492 8
2,54,522 147,527,015 147,527,01E 9
3,84 210,491 10
897 45,329 11
32,553 2,047,405 2,047,405 12
561,767 33,722,09 33,722,094 13
5,597 255,874 255,874 14
209,695 3,402,303 4,652,34 -48,359 7,616,288
13,514,160 51,06,933 2,54,114,007 -1,745,930,397 849,248,543
13,723,855 54,467,236 2,548,766,351 -1,746,368,756 856,86,831
FERC FORM NO.1 (ED. 12-90)Page 311.1
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2007/04
(2) nA Resubmission 04208
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 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 reliability of requirements service mustbe the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 servic 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 reliability of
service, aside from transmission constraints, must match the availabilit and reliabilit of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Une Name of Copay or Public Auhon Statistica FERC Rate Averaar Acual Demand (MW)
No.(Footnote Affliations)Cia Scheule or Montly lUng l\vera~e Avera95cationTar Number Demand(MW)Monthly NC Deman Mothly CP emand
(a)--(c)(d)(e)(f)
1 Black Hils Power,lnc.441 5C 50 43
2 Black Hils Power, Inc.WSPP NA NA NA
3 Black Hils Power, Inc.SF WSpp NA NA NA
4 Black Hils Wyoming, Inc.SF WSPP NA NA NA
5 Blanding City T-12 1.5 NJ!NA
6 Bonnevile Power Administration T-12 NA NJ!NA
7 Bonnevile Power Administration 368 NA NJ!NA
8 Bonneville Power Administration T-11 NA NA NA
9 Bonneville Power Administration T-12 NA NA NA
10 Bonnevile Power Administration SF T-11 NA NA NA
11 Bonneville Power Administration SF T-13 NA NA NA
12 Bonnevile Power Administration SF WSPP NA NA NA
13 Bntish Columbia Transmission Corp.SF T-13 NA NA NA
14 Burbank, City of SF WSPP NA NA NA
SubtotalRO 0 0 0
Subtotai non-RO 0 0 0
Total (0 0
FERC FORM NO.1 (ED. 12-9)Page 310.2
............................................
-...........................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) tiA Resubmission 04/03/2008
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Usting. 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 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 (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on 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 (j. 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-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - ROil amount in column (g) must be reported as Requirements sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE
Totl ($)Une
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.($)($)($)
(g)(h)(i)(j (k)
36,449 6,156,660 4,708,324 10,864,984 1
975 60,255 60,255 2
40,53 2,381,058 2,381,05e 3
30 1,325 1,325 4
3,167 44,OH 82,038 126,04E 5
29,065 6
5,053 86,28 7
2,887 133,365 8
36,316 1,452,277 1,452,2n 9
177 12,88E 10
130 6,84e 11
142,145 7,835,520 7,825,321 12
231 13,700 13
89,507 4,824,520 4,824,52C 14
209,695 3,402,303 4,652,34 -48,359 7,616,288
13,514,160 51,06,933 2,54,114,007 -1,745,930,397 849,248,543
13,723,855 54,467,236 2,548,766,351 -1,746,368,756 856,864,831
FERC FORM NO.1 (ED. 12-90)Page 311.2
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) ñA Resubmission 04208
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 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" mens 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 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 servic except that "intermdiate-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
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.
Une Name of Compay or Public Auhority Statica FERCRae Averaae Actual Demand(MW)
No.(Footnote Affilations)Classif-Scle or Mothly illing Avera~e Avera~cation Tari Number Demand(MW)Montly NC Deman Monthly CP eman
(a)(b)(c).(d)(e)(f)
1 California Independent System Operator T-12 NA NJI NA
2 California Indepedent System Operator SF T-12 NA NJI NA
3 Cargil Power Markets, LLC T-12 NA NJI NA
4 Cargll Power Markets, LLC T-12 NA NJI NA
5 Cargil Power Markets, LLC SF T-11 NA NJI NA
6 Cargil Power Markets, LLC SF T-12 N)i NJI NA
7 Chelan County Public Utility Dist No. 1 SF WSPP NJI NJI NA
8 CitigrOlP Energy, Inc.SF T-11 NJI NJI NA
9 Citigrop Energy, Inc.SF T-12 N)i NJI NA
10 City of Rosevile SF WSPP NA NA NA
11 Clark Public Utilities T-12 NA NA NA
12 Clatskaie People's Utility Distri SF WSPP NA NA NA
13 Colorado River Commission of Nevada SF WSPP NA NA NA
14 Colorado Springs Utiities SF WSPP NA NJI NA
Subtotal RO C 0 0
Subtotal non-RO C 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.3
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FîA Resubmission 04/0312008
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 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 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 (6o-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 (j). 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,iine24.
10. Footnote entries as reuired 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)0)(k)
-200 -33,81*1
233,982 11,532,545 11,532,54 2
253 14,38€3
47 1,551 1,551 4
31,387 1,685,773 5
2,299,753 136,879,828 136,879,828 6
1,80 89,00 9O,2OC 7
65 4,82E 8
1,731,458 107,176,758 107,176,758 9
261 17,505 17,505 10
384,00 853,237 14,64,120 15,496,357 11
1,56 69,851 69,851 12
24,607 983,556 983,556 13
381 24,081 24,081 14
209,695 3,402,303 4,652,34 -438,359 7,616,288
13,514,160 51,06,933 2,54,114,007 -1,745,930,397 849,248,54
13,723,85 54,467,236 2,548,766,351 -1,746,36,756 856,86,831
FERC FORM NO.1 (ED. 12-90)Page 311.3
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) ñA Resubmission 0403/
SALES FOR RESALE (Accounf4 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 electncity ( 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 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 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 intermiate-term firm service. The same as LF service excpt that "intermdiate-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 penod 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 reliabilit of designated unit.
IU - for intermediate-term servce from a designated generating unit. The same as LU service except that "intermdiate-term" means
Longer than one year but Less than five years.
Une Name of Company or Public Authori Sttistil FERCRate Averar Actual Deman (MW)Claif-Scedle or Monthly 11ing Avera~e Avera~No.(Footnote Affliations)cation Tar Number Dema(MW)Mothly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Conoco Inc.SF T-11 NA NA NA
2 Conoco Inc.SF T-12 NA NA NA
3 Constellation Energy Commodities Group T-12 NA NA NA
4 Constellation Energy Commodities Group SF T-12 NA NA NA
5 Coral Power SF T-11 NA NA NA
6 Cora Power SF WSPP NA NA NA
7 Creit Suisse Energy LLC SF T-12 NA NA NA
8 DB Energy Trading LLC SF T-12 NA NA NA
9 Douglas County Public Utilty Dist No.1 SF WSPP NA NA NA
10 Dyngy Power Marketing SF WSPP NA NA NA
11 EPCOR Energ Marketing (U.S.) inc.SF WSPP NA NA NA
12 EI Paso Elecric Compay SF WSPP NA NA NA
13 Eugene Water & Elecric Board SF T-11 NA NA NA
14 Eugene Water & Electric Bord SF WSPP NA NA NA
Subtota RO (0 0
Subtotl non-RO (0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.4
............................................
............................................
Name of Respondent i his oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) DA Resubmission 04/0312008
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 tarifs 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 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 serve, 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 (6o-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). Exlain 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 RQlNon-RQ grouping (see instruction 4), and then totled 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
Totl ($)Une
Sold Demand Charges Energy Charge ~(h+i+j)No.
($)($)($)
(g)(h)(i)')(k)
15 76~1
271,526 16,238,987 16,238,981 2
865 48,065 48,06E 3
2,63,708 151,745,995 151,745,995 4
32 1,59E 5
1,855,013 104,388,787 104,388,787 6
833,465 57,062,588 57,062,58 7
560.22 35,229,471 35,229,471 8
150 7,620 7,620 9
20 854 85 10
36,622 2,139,762 2,139,762 11
82,933 4,530,202 4,53,202 12
2,454 ,120,991 13
7,499 388,139 388,139 14
209,695 3,402,303 4,652,34 -438,359 7,616,288
13,514,160 51,06,933 2,54,114,007 -1,745,930,397 849,248,54
13,723,855 54,467,236 2,548,766,351 -1,746,368,756 856,864,831
FERC FORM NO.1 (ED. 12-9)Page 311.4
Name of Respondent This wort Is:Date of Reprt Year/Period of Report
PacifiCorp (1) X An Origina (Mo, Da, Yr)End of 2007/04
(2) ñA Resubmission 04031208
SALES FOR RESALE (Accounf4 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 ( 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 service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in it system resourc planning). In addition, the reliabilty of requirements service must
be the same as, or secnd only to, the suppliers service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" mens 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 reliabilty of
service, aside from transmission constraints, must match the availabilit and reliabilit of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermdiate-term" means
Longer thn one year but Less than five years.
Une Name of Company or Public Authori Sttistical FERC Rate Averaß¡e Actual Demand (MW)
No.(Footnote Affilations)Clasifi-Scedle or Monthly lling Aver,e Avera~cation Tari Number Demand (MW) Monly NC Deman Moly CP emand
(a)(b)(c)(d)(e)(1)
1 FPL Energy Power Mareting, Inc.SF WSPP NA NA NA
2 Flathead Elecric Coperative T-12 NA NA NA
3 Fortis Energy Marketing & Trading GP SF WSPP NA NA NA
4 Fraklin Cty Publ Utilities Dist No. 1 SF WSPP NA NA NA
5 Gila River Power, L.P.SF WSPP NA NA NA
6 Glendle, City of SF WSPP NA NA NA
7 Grant County Public Utility Dist NO.2 SF WSPP NA NA NA
8 Grays Harbr Public Utilit District SF WSPP NA NA N~
9 Highland Energy LLC SF WSPP NA NA NA
10 Hurrcane, Cit of T-12 NA NA NA
11 Idaho Power Company T-11 NA NA NA
12 Idaho Power Compay SF T-11 NA NA NA
13 Idaho Power Company SF T-13 NA NA NA
14 Idaho Power Compay SF WSPP NA NA NA
Subtotal RQ C 0 0
Subtotl non-RQ C 0 0
Totl (0 0
FERC FORM NO.1 (ED. 12-9)Pag 310.5
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) FîA Resubmission 04/03/2008
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identiied 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 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 tys of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on 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 ROlNon-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 Tota ($)Une
Sod Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(i)(k)
39,461 2,107,098 2,107,09l 1
-1,115 2
611,531 36,840,410 36,840,41C 3
1,823 88,550 88,550 4
142,559 6,984,114 6,984,114 5
45 2,025 2,025 6
29,239 1,808,831 1,808,831 7
4,n2 247,042 247,042 8
2,800 180,80 180,800 9
12,799 359,970 359,970 10
1,102 79,03 11
26,983 1,539,080 12
820 40,862 13
494,763 27,709,225 27,709,225 14
209,695 3,402,303 4,652,34 -438,359 7,616,288
13,514,160 51,06,93 2,54,114,007 -1,745,930,397 849,248,54
13,723,855 54,467,236 2,548,766,351 -1,746,36,756 85,86,831
FERC FORM NO.1 (ED. 12-90)Page 311.5
Name of Respondent This~rtls;Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) DA Resubmission 04032008
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 dunng the year. Do not report exchanges of electncity ( 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 projeced 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 suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" mens that service cannot be interrpted 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 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 availabilty 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 service except that "intermediate-term" means
Longer than one year but Less than five years.
Une Name of Compay or Pubic Auor Sttitic FERCRate Averaßl Actal Demand (MW)
No.(Footnote Affliations)Classif-Schedle or Mothly lling . !'verair Avera~cation Tari Number Demand (MW) Monthly NC Deman Montly CP emanc
(a)(b)(c)(d)(e)(1)
1 Integry Energy Services, Inc.SF WSPP NA NA NA
2 J. Aron & Compay SF T-12 NA NA NA
3 J.P. Morgan Venture Energy Corpration T-12 NA NA NA
4 J.P. Morgn Ventures Energy Corpration SF T-11 NA NA NA
5 J.P. Morgan Ventures Energy Corpration SF T-12 NA NA NA
6 Lehman Brothers Commodit Servic, Inc SF T-12 NA NJ!NA
7 Los Angeles Dept. of Water & Poer WSPP NA NJI NA
8 Los Angeles Dept. of Water & Power 301 NA NJI NA
9 Los Angeles Dept. of Water & Power SF WSPP NA NA NA
10 Merrll Lynch Comodities, inc.SF WSPP NA NA NA
11 Modesto Irrigation District SF WSPP NA NA NA
12 Morgan Stanley Capital Group, Inc.T-12 NA NA NA
13 Morgan Stanley Capital Group, Inc.SF T-11 NJI NA NA
14 Morga Stanley Capital Group, Inc.SF T-12 NJI NA NA
Subtotal RO 0 0 0
Subtotal non-RO C 0 0
Total 0 0 0
fERC fORM NO.1 (ED. 12-90)Page 310.6
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) riA Resubmission 04/0312008
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly 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 typs of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maimum
metered hourly (6o-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (6o-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). Exlain 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 ROlNon-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.
MegWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charge Other Charges (h+i+j)No.
($)($)($)
(g)(h)(I)(i)(k)
31,181 1,882,86 1,882,800 1
1,431,692 74,871,392 74,871,392 2
78 12,1':l~402 3
22 4
198,098 12,271,337 5
441,500 26'511'950i-26,511,950 6
-49,750 7
583,94 25,976,563 25,976,56:3 8
94,392 4,709,722 4,709,722 9
251,986 15,548,914 15,548,914 10
56,497 3,211,43 3,211,430 11
647 39,130 12
4,645 234,53 13
8,809,871 479,594,598 479,594,598 14
209,695 3,402,30 4,652,34 -48,359 7,616,288
13,514,160 51,06,933 2,54,114,007 -1,745,930,397 849,248,543
13,723,855 54,467,236 2,54,766,351 -1,746,368,756 856,864,831
FERC FORM NO.1 (ED. 12-90)Page 311.6
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 040312008
SALES FOR RESALE (Account 41 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:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the 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 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 tht "intermiate-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 availabilit 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.
Une Name of Company or Public Auhori Sttis FERC Rate Averaai Acual Dend (MW)
No.(Footnote Affliations)Clasif-Scule or Moly 11ing Avera,§e Avera~caion Tar Number De(MW)Moly NC Deman Monthly CP eman
(a)(b)(c)(d)(e)(f)
1 Municipal Energy Agency of Nebraka WSPP NJ!NA NA
2 Municipal Energy Agency of Nebraska SF T-11 NJ!NA NA
3 Municipal Energy Agency of Nebraka SF WSPP NJ!NA NA
4 Nevada Power Compay SF WSPP NJ!N¡l NA
5 NorthWestern Energy SF T-13 NJ!N¡l NA
6 Norter California Power Agency WSPP NJ!N¡l NA
7 Northern california Power Agency SF WSPP NJ!NJ!NA
8 Northpoint Energy Solutions Inc.SF WSPP NJ!NJ!NA
9 Occidental Power Services, Inc.SF WSPP NA NA NA
10 PPL EnergyPlus, LLC SF WSPP NA NA NA
11 PPL Montana, LLC SF T-11 NA NA NA
12 PPL Montana, LLC SF WSPP NA NA NA
13 PPM Energy, Inc.T-11 NA NA NA
14 PPM Energy, Inc.T-11 NJ!NA NA
Subtotal RO 0 0 0
Subtotal no-RO 0 0 0
Total lJ 0 0
FERC FORM NO.1 (ED. 12-9)Page 310.7
............................................
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2007/Q4
(2) ñA Resubmission 04/03/2008
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-eoincident 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 tys of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in coumn 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 ($)Una
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.($)($)($)
(g)(h)(i)(j (k)
110 3,09 3,090 1
50 881'43J-2,272 2
13,433 881,43 3
125 5.=..5,OO 4
785 41,999 5
4 6
125,648 8,891,256 8,891,25E 7
2,521 144,20 144,200 8
16,700 753,280 753,2&9
400 20,80 20,800 10
1,105 56,701 11
36,752 1,746,721 1,746,721 12
-9,765 -452,409 13
59 629 14
209,695 3,402,303 4,652,34 -48,359 7,616,288
13,514,160 51,06,933 2,54,114,007 -1,745,930,397 849,248,543
13,723,855 54,46,236 2,548,766,351 -1,746,368,756 856,86,831
FERC FORM NO.1 (ED. 12-9)Page 311.7
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) riA Resubmission 0403200
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 electricit ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settements 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 secnd 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 categry should not be use 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 reliabilit of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Une Name of Company or Public Authority Statistical FERC Rate Averaße Acual Demand (MW)
No.(Footnote Affiliations)Clasifi-Schedule or Monthly illng Avera~e Avera~cation Tar Number Demand(MW)Monthly NC Demanc Monthly CP emanc
(a)(b)(c)(d)(e)(f)
1 PPM Energ, inc.SF T-11 NA NJl NA
2 PPM Energ, Inc.SF WSPP NJl NJl NA
3 Pacific Gas & Elecri Company SF WSPP NJl NJl NA
4 Pacifc NW Generating Coerative SF WSPP NJl NJl NA
5 Pacific Summit Energy LLC SF T-12 NJl NJl NA
6 Pasdena, City of SF WSPP NJl NA NJl
7 Pinnacle West Marketing & Trading Co.SF T-12 NJl NJl NA
8 Portlan General Electric Co.T-12 NJl NJl NA
9 Portland Geneml Elecric Co.SF T-11 NA NA NA
10 Portla Genera Electric Co.SF T-12 NA NA NA
11 Portland General Elecric Co.SF T-13 NA NA NA
12 Powerex T-11 NA NJl NA
13 Powerex WSPP NA N,I NA
14 Powerex SF T-11 NA NA NA
Subtotal RO C 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.8
............................................
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 04/03/2008
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
S. For requirements RO 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 (t). For all other tyes of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in meawatts.
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 demnd 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). Exlain 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 RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all require data.
MegaWatt Hours REVENUE Total ($)Lie
Sold Demand Charges Energy Chargs ~(h+i+j)No.
($)($)($)
(g)(h)(i)(k)
23,052 978,8~1
679,04 35,897,506 35,897,5()2
137,068 7,510,073 7,510,073 3
11,168 566,990 56,990 4
388,559 21,134,175 21,134,175 5
10,080 516,440 516,44 6
96,85 6,693,45 6,693,45 7
55 3,025 3,025 8
156 6,69.9
507,887 30,392,216 30,392,216 10
240 13,567 11
12,30 611,872 12
10,00 645,00 645,00 13
23,105 1,185,313 14
209,695 3,402,303 4,652,34 -438,359 7,616,288
13,514,160 51,06,933 2,54,114,007 -1,745,930,397 849,248,54
13,723,855 54,467,236 2,54,766,351 -1,746,36,756 856,864,831
FERC FORM NO.1 (ED. 12-9)Page 311.8
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 040312008
SALS FOR RESALE (Account 447T
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 acronym. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the 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 mets 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 service except that "intermediate-term" means
Longer than one year but Less than five years.
Une Name of Compay or Public Aut Sttitil FERCRate Averaar Actual Demand (MW)
No.(Footnote Affliations)C1asif-SCule or Moly ilUng Aver,e Avera~cati Tar Number Deman(MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Powerex SF WSPP N,l N,l NA
2 Public Service Company of Colorado .320 N,l N,l NA
3 Public Service Company of Colorado WSPP .'N~N,l NA
4 Public Service Company of Colorado 320 176 17€170
5 Public Service Company of Colorado T-11 NA N,l NA
6 Public Service Copany of Corado Ií WSPP N,l NA NA
7 Public Service Company of New Mexio WSPP N~N,l NA
8 . Public Service Company of New Mexico SF WSPP N,l NA NA
9 Puget Sound Energy SF T-13 NA NA NA
10 Puget Sound Energy SF WSPP N,l N,l NA
11 Rainbow Energy Marketing SF T-11 NA NA NA
12 Rainbow Energy Marketing SF WSPP N,l N,l NA
13 Redding, City of SF WSPP NA NA NA
14 Riverside, Cit of SF WSPP N,l NA NA
Subtotal RO (J 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.9
............................................
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) DA Resubmission 04/0312008
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal- RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Usting. Enter
"Total" in column (a) as the Last Une 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 Unes, Ust 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 biling demand in column (d), the average monthly non-eincident 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 hourty (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on 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 (j). 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 ROIon-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.
MeaWatt Hours REVENUE
Total ($) Une
Sold Demand Charges Energy Charg Other Charges (h++j)No.
($)($)($)
(g)(h)(i)(j (k)
1,795,086 93,450,260 93,45,26C 1
13,575 2
44 30,299 3
1,158,105 24,858,240 44,285,935 69,144,175 4
2,408 124,876 5
339,458 17,n5,428 17,175,42S 6
280 12,750 12,750 7
54,03 32,659,186 32,659,186 8
341 17,63 9
207,102 11,661,197 11,661,197 10
2,920 147,287 11
20,448 1,049,296 1,049,296 12
42,682 3,269,667 3,269,667 13
6,40 367,050 367,050 14
209,695 3,402,303 4,652,34 -438,359 7,616,288
13,514,160 51,06,933 2,54,114,007 -1,745,930,397 849,248,54
13,723,855 54,467,236 2,548,766,351 -1,746,368,756 856,86,831
FERC FORM NO.1 (ED. 12-9)Page 311.9
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) DA Resubmission 0403
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 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 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. "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 servic. 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 availabilit and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermiate-term" means
Longer than one year but Less than five years.
Une Name of Company or Public Authority Statistical FERC Rate Averaßf Actual Demand (MW)
Classifi-Schedule or Monthly iIing Averape Avera~No.(Footnote Affliations)cation Tari Number Demand(MW)Monthly NC Demal1 Monthly CP emanc
(a)(b)(c)(d)(e)(f)
1 SUEZ Energy Marketing NA, Inc.SF WSPP Nil NA NA
2 Sacramento Municipal Utilit Dirict 250 Nil NA NA
38acraento Municipa Utilty Distri 250 Nil NA NA
4 Sacramento Municipal Utilit Distri SF WSPP Nil NA NA
5 Salt River Projec WSPP Nil NJI NA
6 Salt River Proec SF WSPP NP NJl NA
7 Sa Dieg Gas & Electric SF WSPP NP NJI NA
8 Santa Clara, Cit of SF WSPP NP NJl NA
9 Seatt City Ught SF T-13 NA NA NA
10 Seattle City Ught SF WSPP NA NA NA
11 8empra Energy Soutions SF WSPP NA NA NA
12 Sempr Energy Trading LLC T.12 NA NA NA
13 Sempra Energy Trading LLC SF T-11 NA NA NA
14 Sempra Energy Trading LLC SF T-12 NP NA NA
Subtotal RO 0 0 0
Subtotal non-RO C 0 0
Total 0 0 0
FERC FOR NO.1 (ED. 12-90)Page 310.10
..........'..................................
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 04/0312008
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any ty 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 (t). Monthly NCP demand is the maximum
metered hourly (6o-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 (1). 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 ROlNon-RO grouping (se 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 expanations following all required data.
MegaWatt Hours REVENUE Tota ($)Une
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(I)(i)(k)
82,769 4,382,616 4,382,616 1
816,442 2
569,40 11,90,279 11,90,279 3
180,597 8,691,353 8,691,353 4
219,000 11,761,320 11,761,32C 5
233,470 12,137,047 12,137,047 6
5,395 290,123 290,123 7
37,859 2,161,763 2,161,76S 8
39 1'382'975~1,684 9
28,442 1,382,975 10
44,625 =~..2,273,78S 11
151 8,80 12
1,724 95,392 13
4,400,984 268,076,061 268,076,061 14
209,695 3,402,303 4,652,34 -48,359 7,616,288
13,514,160 51,06,933 2,54,114,007 -1,745,930,397 849,248,543
13,723,855 54,467,236 2,54,766,351 -1,746,368,756 856,86,831
FERC FORM NO.1 (ED. 12-90)Page 311.10
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) L?An Original (Me, Da, Yr)
(2) riA Resubmission 040312008
SALES FOR RESALE (Acount 447\
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capaCity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system 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. "Long-term" means five years or Longer and "firm" mens 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 availabilit 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 service except that "intermediate-term" means
Longer than one year but Less than five years.
Year/Period of Report
End of 2oo7/Q4
Line Name of Company or Public Authori Statistical FERC Rate Averaße Acual Demand (MW)
Clasifi-Schedule or Monthly illng Avera~e Avera~No.(Footnote Affliations)caion Tari Number Demand (MW) Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(I)
1 5empra Generation SF T-12 NA NA NA
2 Sierra Pacifc Power Company 258 NA Nfl NA
3 Sierra Pacific Power Company 25 75 75 72
4 Sierr Pacific Power Company T-11 NA Nfl NA
5 Sierra Pacifc Power Compay SF T-11 Nfl Nfl N,I
6 Sierra Pacific Power Company SF T-13 Nfl Nfl NA
7 Sierr Pacific Power Copany SF WSPP Nfl Nfl NA
8 Snohomish Public Utilit District No. 1 SF WSPP Nfl NJl NA
9 Southern California Edison Company SF T-12 NJl NA NA
10 Sothwestern Public Service Company SF WSPP NA NA NA
11 State of CA Dept of Water Resurces SF WSPP NA NA NA
12 Tacoma, City of SF WSPP NA NA NA
13 The Energy Authori SF WSPP NA Nfl NA
14 TransAla Energy Marketing Inc.T-12 NA NJl NA
Subtotal RQ
Subtotal non-RQ
(o
o
o
o
Total c
FERC FORM NO.1 (ED. 12-90)Page 310.11
o
o
o
............................................
............................................
Name of Respondent i his oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) ÕA Resubmission 04/03/2008
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 expianation 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 Usting. Enter
"Total" in column (a) as the Last Une 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 Unes, Ust 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 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 (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on 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 (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 ROlNon-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The .Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Chargs Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(j (k)
39,498 1,805,04 1,805,04 1
-1,635,525 2
46,297 15,057,OO 16,566,089 31,623,089 3
1,021 51,589 4
40,241 2,381,839 5
154 8,86 6
152,617 9,735,84 9,735,84 7
45,095 2,427,490 2,427,49C 8
31,085 1,926,887 1,926,887 9
22,483 1,117,470 1,117,470 10
13,400 809,856 809,856 11
1,735 78,490 78,490 12
400 14,400 14,400 13
552,125 31,094,951 31,094,951 14
209,695 3,402,303 4,652,34 -48,359 7,616,288
13,514,160 51,06,933 2,54,114,007 -1,745,930,397 849,248,543
13,723,855 54,467,236 2,548,766,351 -1,746,368,756 856,86,831
FERC FORM NO.1 (ED. 12-9)Page 311.11
Name of Respondent ThiS~lOrt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2)A Resubmission 04/03120
SALES FOR RESALE (Account 4-7)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the 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 excpt 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 reliabilit of
service, aside from transmission constraints, must match the availabilit and reliabilit of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Une Name of Company or Public Auori Sttisical FERC Rae AverRl Actual Dean (MW)
No.(Footnote Affiation)Clasi-Sc or Moth illng Avera¡§e Avera~caio Tari Number Dean(MW)Mothly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(1)
1 TranAlta Energy Marketing Inc.SF T-12 NA NA NA
2 TransAIt Energy Marketing Inc.SF WSPP NA NA NA
3 Tri-State Generation & Transmission WSPP NA NA NA
4 Tri-State Generation & Trasmission SF T-11 NA NA NA
5 Tri-State Generation & Transmission SF WSPP 0.7 0.7 0.1
6 Tucson Electric Power SF WSPP NA NA NA
7 Tunock Irrigation District SF WSPP NA NA NA
8 HBS Warbrg Energy LLC T-12 NA NA NA
9 UBS Warburg Energy LLC SF T-12 NA NA NA
10 Utah Associated Municipal Power Systems WSPP NA NA NA
11 Utah Asociated Municipa Power Systems WSPP NA NA NA
12 Uta Assoiated Municpal Power Systems SF WSPP NA NA NA
13 Utah Municipal Power Agency 43 31 31 31
14 Utah Municipal Power Agency SF T-3 NA NA NA
Subtotal RO 0 0 0
Subtotal non-RO (0 0
Total (0 0
FERC FORM NO.1 (ED. 12-9)Page 310.12
............................................
-...........................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 0403/2008
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-eefined 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 _ ROil
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 Numbr. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
S. For requirements RO 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 (1). For all other tyes of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (SO-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (SO-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 RO/on-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 ($)UnaSolDemand Charges Energy Chargs Other Charges (h+i+j)No.($)($)($)
(g)(h)(i)(j (k)
93,765 5,173,138 5,173,138 1
84,638 4,523,988 4,523,988 2
25 1,70C 3
1,595 76,797 4
109.162 33,611 6,537,437 6,571,00 5
266,957 16,941,386 16,941,386 6
6,200 343,80 343,SO 7
-3 8
1,170,471 71,731,652 71,731,652 9
14,575 553,850 553,850 10
2,935 117,475 117,415 11
5,662 442,552 442,552 12
203,705 4,062,175 4,73,104 8,796,279 13
8,54 516,670 516.67C 14
209,695 3,402,303 4,652,34 -438,359 1,616,288
13,514,160 51,06,933 2,54,114,007 -1,745,930,397 849,248,543
13,723,855 54,467,236 2,548,766,351 -1,746,368,756 856,864,831
FERC FORM NO.1 (ED. 12-90)Page 311.12
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) DA Resubmission 040318
SALES FOR RESALE (Account 4-7)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilit 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 use 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 unilateraiiy get out of the contract.
IF - for intermdiate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five yers.
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" mens five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilit and reliabilit of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU servic except that "intermeiate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authonty Statistical FERC Rate Average Acual Demand (MW)
No.(Footnote Affilations)Classif-Scheule or Monthly illng . ~veraiYe Avera95cationTari Number Derand(MW)Monthly NC Deman Monthly CP emand
(a)~(c)(d)(e)(f)
1 Wester Area Power Administrtion WSPP NJI NJI NA
2 Western Area Power Administration SF T.11 NJI Nil NA
3 Westem Area Power Administration ë WSPP NJI NJI NA
4 Bookouts NA NJI NJI NA
5 Bookouts SF NA Nil NJI NA
6 Test Generation NA NJI NJI NA
7 Trading SF NA NJI NA NA
8 Accrul True-up NA NA NJI NJI NA
9
10
11
12
13
14
Subtotal RO 0 0 0
Subtotal non-RO C 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.13
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2oo7/Q4
(2) DA Resubmission 04/03/2008
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups. for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly 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.
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/on-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
Totl ($)Line
Sold Demand Charges Energy Charges Other Charge (h+i+j)No.
($)($)($)
(g)(h)(i)en (k)
20 760 760 1
257 12,88~2
174,244 11,414,883 11,414,88 3
-731 -76,13E 4
-32,163,253 -1,424,201,264 5
-241,471 -14,638,049 6
-315,04,007 7
17,610 -4,555 8
9
10
11
12
13
14
209,695 3,402,303 4,652,34 -48,359 7,616,288
13,514,160 51,064,933 2,54,114,007 -1,745,93,397 849,248,543
13,723,855 54,467,236 2,548,766,351 -1,746,368,756 856,8,831
FERC FORM NO.1 (ED. 12-90)Page 311.13
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 20071Q4
FOOTNOTE DATA
Line No.: 8 Column: i
Line No.: 14 Column: J
Line No.: 1 Column: b
Line No.: 1 Column:'
fi tranactions.
Line No.: 11 Column: J
Line No.: 6 Column:'
Column:j
Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
FOOTNOTE DATA
Reserve Share
IGchedule Page: 310.2 Line No.: 12 Column: j
Li uidated Damages
chedule Page: 310.2 Line No.: 13 Column: j
Reserve Share
¡Schedule Page: 310.3 Line No.: 1 Column: b
Settement Ad ustment
chedule Pa e: 310.3 Line No.: 1 Column: j
Settlement Adjustment
¡Shedule Page: 310.3 Line No.: 3 Column: b
Settlement Adjustment
¡Schedule Page: 310.3 Line No.: 3 Column: j
Settlement Adjustment
!Shedule Page: 310.3 Line No.: 4 Column: b
Secondar, Economy and/or non-fi sales, including some hourly fi transactions.
¡Schedule Page: 310.3 Line No.: 5 Column: i
Transmission Losses
IGchedule Page: 310.3 Line No.: 7 Column:j
Pond Sale
rschedule Page: 310.3 Line No.: 8 Column: i
Transmission Losses
IGchedule Page: 310.3 Line No.: 11 Column: b
Clark Coun Pun #1 - FERC T -12 - Contract termnation date: December 12, 2007.
chedule Pa e: 310.4 Line No.: 1 Column: .
Transmission Losses
¡Schedule Page: 310.4 Line No.: 3 Column: b
Secondar, Economy and/or non-firm sales, including some hourly fi transactions.
¡Schedule Page: 310.4 Line No.: 5 Column: i
Transmission Losses
IGcheduie Page: 310.4 Line No.: 13 Column: j
Transmission Losses
IGchedule Page: 310.5 Line No.: 2 Column: b
Settement Adjastment.
IGchedule PaJ/e: 310.5 Line No.: 2 Column:j
Settlement Adjustment
¡Schedule Page: 310.5 Line No.: 10 Column: b
Hurcane, Ci of - FERC T-12 - Contract termnation date: Au ust 31, 2007.
Schedule Pa e: 310.5 Line No.: 11 Column: b
Idaho Power Company - FERC T-ll (Point-to-Point Transmission Service under the Open Access Transmission Tarff (S.A. 212)) -
Contract termnation date: May 31, 2009.
!Scheule Page: 310.5 Line No.: 11 Column: i
Transmission Losses
IGchedule Page: 310.5 Line No.: 12 Column: i
Transmission Losses
IGchedule Page: 310.5 Line No.: 13 Column: j
Reserve Share
IGchedule Page: 310.6 Line No.: 3 Column: b
Settlement Adjastment.
¡SChedule PaJ/e: 310.6 Line No.: 3 Column: i
Settement Adjustment
IGchedule Page: 310.6 Line No.: 4 Column: i
Transmission Losses
IFERC FORM NO.1 (ED. 12-S7)
==
I
I
I
1
I
I
Page 450.2
................i..I.I.i.I: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 04/0312008 2007/Q4
FOOTNOTE DATA
Line No.: 7 Column: b
Line No.: 7 Column:'
Line No.: 12 Column:j
Line No.: 13 Column:j
fi trctons.
UneNo.:5 Column:j
Line No.: 6 Column:b
Line No.: 6 Column:j
Line No.: 11 Column:j
Line No.: 13 Column:b
Line No.: 13 Column:j
Column:j
Line No.: 1 Column: j
fi transactions.
Line No.: 11 Column: j
Column:j
firm transactions.
Line No.: 2 Column: b
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 04/03/2008 2007/Q4
FOOTNOTE DATA
Line No.: 2 Column: i
Line No.: 3 Column: b
Line No.: 3 Column: i
fi transactions.
Line No.: 11 Column: i
Line No.: 2 Column: b
Line No.: 2 Column: i
Line No.: 12 Column: b
Line No.: 12 Column: i
Line No.: 13 Column:.
Line No.: 2 Column: b
Line No.: 2 Column: j
28,200.
Line No.: 5 Column: j
Line No.: 6 Column: j
Line No.: 14 Column: b
Inc. - FERC T-12 - Contracttermnation date: Deember 31,2010.
Line No.: 3 Column: b
Column:j
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 04/0312008 2007/Q4
FOOTNOTE DATA
Line No.: 4 Column: j
Line No.: 8 Column: b
Line No.: 8 Column: j
fi trsations.
Line No.: 4 Column: b
Line No.: 4 Column:'
IFERC FORM NO.1 (ED. 12-87) Page 450.5
............................................
Blank Page
(Next Page is 320)
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/0300
ELE TRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.Une Account Amount forNo Current Year. ~
Year/Period of Report
End of 207/04
AmpunUorPrevious Year
(c)
21,506,117
581 ,178,395
33,767,391
4,845,079
22,68,191
485,079,578
32,320,388
3,110,724
4,007,896
41,84,589
859,203
4,215,404
30,690,672
1,173,471
13,992,399
45,426
27,389,070
7,448,958
241,545
4,629,40
3,787
15,883,249
94,633
28,301,575
1,020,921
1,017,895
1,678,495
2,107,860
5,825,171
33,214,241
1,072,249
1,435,262
948,267
2,543,440
5,999,218
34,30,793
FERC FORM NO.1 (ED. 12-93)Page 320
............................................
............................................
Name of Respondent This i!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2O7/Q4
(2) FiA Resubmission 04/03/2008
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)
""""' ea, _.. "'(b) (c)
60 D. Other Power Generation
61 Ooeration
62 546 Operation Supervision and Engineerina 729,753 1,170,218
63 547 Fuel 325,837,509 129,693,593
64 548 Generation Expenses 22,455,63 12,202,052
65 549) Miscellaneous Other Power Generation Expenses 5,931,466 2,930,812
66 550 Rents 11,964,68 13,642,417
67 TOTAL Ooeration (Enter Total of lines 62 thru 66\36,919,052 159,639,092
68 Maintenance
69 1(551\ Maintenance Supervision and Engineering
70 I (552) Maintenance of Structures 615,974 239,024
71 I (553) Maintenance of Generating and Electric Plant 4,63,669 2,562,314
72 (55) Maintenance of Miscellaneous Other Power Generation Plat 396,083 436,088
73 TOTAL Maintenance (Enter Total of lines 69 thru 721 5,642,726 3,237,426
74 TOTAL Power Prouction Exoenses-Other Power (Enter Tot of 67 & 73)372,561,778 162,876,518
75 E. Other Power Suoolv Expenses
76 . (555) Purchaed Power 763,738,961 707,454,156
77 (556\ SYStem Control and Load Dispatching 2,535,080 2,484,435
78 (557) Other Exenses 60,542,623 54,585,469
79 TOTAL Other Power Suoolv Exo (Enter Total of lines 76 thru 78\826,816,664 764,524,06
80 TOTAL Power Prouction Exoenses (Total of lines 21,41,59,74 & 79)2,087,575,788 1,702,428,778
81 2. TRANSMISSION EXPENSES
82 Ooeration
83 (560\ Ooeration Supervision and Engineering 8,207,350 7,758,555
84 (561) Load Disoatching 1,087,33
85 (561.1) Load Disoatch-Reliabiltv
86 (561.2) Load Disoatch-Monitor and Operate Transmission SYStem 6,335,813 4,161,724
87 /561.3\ Load Dispatch-Transmission Serve and Scheduling
88 /561.4 .Scheduling, SYStem Control and Disoatch Services
89 561.5 Reliabilitv, Planning and Standard Development
90 561.6 Transmission Service Studies 594,239 805,928
91 561.7 Generation Interconnection Studies 958,694 507,258
92 (561.8 Reliabilitv, Planning and Standard Develooment Services
93 562\ Station Exoenses 1,00,028 320,015
94 56\ Overhead Lines Expenses 125,807 2,320,087
95 564 Underground Lines Expenses
96 565 Transmission of Electricitv bv Others 106,592,111 94,110,633
97 566) Miscellaneous Transmissio Exoenses 2,751,804 938,870
98 567\ Rents 1,35,267 1,343,348
99 TOTAL Ooeration (Enter Total of lines 83 thru 98)127,928,113 113,353,753
100 Mantenace
101 568) Maintenance Supervision and Engineerina 56,234 19,767
102 569) Maintenance of Struures 4,076 5,318
103 569.1\ Maintenance of Comouter Hardware 8,331
104 569.2\ Maintenance of Computer Softare 704,405 132,256
105 (569.3) Maintenance of Communication Eauipment 2,516,755 1,820,947
106 569.4) Maintenance of Miscellaneous Reaional Transmission Plant
107 570 Maintenance of Station Eauipment 9,272,545 10,06,229
108 571 Maintenance of Overhead Lines 13,323,841 10,812,758
109 (572 Maintenance of Underground Lines
110 1(573) Maintenance of Miscellaneous Transmission Plant 380,572 723,453
111 TOTAL Maintenance (Total of lines 101 thru 110\26,266,759 23,576,728
112 TOTAL Trasmission Expenses (Total of lines 99 and 111)154,194,872 136,930,481
.
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04/038
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Cotinued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account ..No.urrent ear Previous Year
(a)(b) (c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Dav-Ahead and Real-Time Market Facilittion
117 (575.3) Transmission Rights Market Facilitation
118 575.4) Capacitv Market Faciltation
119 575.5) Ancilarv Services Market Faciltation
120 575.6) Market Monitorina and Copliance
121 (575.7) Market Facilittion, Monitoring and Comoliance Services
122 (575.8 Rents
123 Total Ooeration (Lines 115 thru 122)
124 Maintenance
125 576.1 Maintenanc of Structures and Improvements
126 576.2 Maintenance of Computer Hardare
127 576.3 Maintenance of Computer Softare
128 576.4 Maintenance of Communication Equipment
129 I (576.5) Maintenance of Miscllaneous Market Ooeration Plant
130 Total Mantenance (Lines 125 thru 129)
131 TOTAL Reaional Transmission and Market Op Exns (Tot 123 an 130)
132 4. DISTRIBUTION EXPENSES
133 Ooeration
134 580 Operation Supervision and Engineering 19,728,019 25,372,96
135 581 Load Disoatching 12,661,549 12,310,097
136 582 Station Exoenses 3,375,957 3,155,806
137 583) Overhead Line Exoenses 7,612,638 17,529,369
138 (584 Underaround Line Expnses 230,535 1,527,073
139 1(585 Street Lighting and Signal SYStem Expenses 248,162 149,307
140 (586 Meter Exoenses 5,795,418 5,126,90
141 . (587) Customer Installations Exoenses 9,337,557
142 (588) Miscellaneous Expenses 9,09,859 14,857,820
143 (589) Rents 4,289,931 3,324,851
144 TOTAL Ooeration (Enter Total of lines 134 thru 143)72,378,625 83,354,189
145 Maintenance
146 590 Maintenance Supervision and Engineering 6,502,417 2,510,144
147 591 Maintenance of Structures 1,382,792 2,312,953
148 592 Maintenance of Station Equipment 11,743,862 12,350,005
149 593 Maintenance of Overhead Lines 91,506,851 85,581,466
150 594 Maintenance of Underaround Line 22,801,662 22,275,933
151 595) Maintenance of Line Transfonners 744,96 36,63
152 (596 Maintenance of Street Lighting and Signal SYStems 4,33,96 4,115,84
153 597 Maintenance of Meters 5,476,485 5,100,03
154 598 Maintenance of Miscellaneous Distribution Plant 4,467,250 1,183,218
155 TOTAL Maintenance (Total of lines 146 thru 154)148,962,247 135,46,232
156 TOTAL Distribution Exoenses (Total of lines 144 and 155)221,34,872 218,820,421
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Ooeration
159 901 Supervision 2,756,699 10,719,527
160 902 Meter Readina Expenses 28,167,970 26,828,346
161 903 Customer Records and Collecion Expenses 55,607,837 52,949,192
162 '904) Uncollectible Accunts 8,551,037 16,093,297
163 (905) Miscellaneous Customer Accounts Expenses 374,243 1,273,970
164 TOTAL Customer Accounts Exenses (Total of lines 159 thru 163)95,457,786 107,864,332
FERC FORM NO.1 (ED. 12-93)Page 322
.............................................
-...........................................
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/03/2008
ELECTRIC OPERATION AND MAINTENANCE PENSES Continued
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount forNo ~~. M
423,54
42,756,237
3,784,54
5,126
46,969,452
Year/Penod of Report
End of 2007/Q4
Am,OuntJorPrevious Year
(c)
1,301,809
47,710,915
3,620,675
105,971
52,739,370
83,301,566
11,n9,729
20,697,80
9,800,219
24,516,013
11,291,287
142,94,825
10,053,431
23,386,081
18,460,427
23,392,399
10,053,945
thru 193
10,011,639
5,845,340
257,282
25,310,886
6,292,505
156,017,982
8,435,094
9,571,n8
1,693,669
25,696,241
8,197,293
215,968,465
24,338,489
180,356,471
2,785,895,241
22,676,04
238,64,508
2,457,427,890
FERC FORM NO.1 (ED. 12-93)Page 323
2006
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0410312008 2007/Q4
FOOTNOTE DATA
¡Schedule Page: 320 Line No.: 187 Column: b
Pensions and benefits are charged to functional accounts, which is consistent to where labor is charged. The following table
summzes the pension and benefit expense that was chaged to the fuctional accounts.
2007
Twelve Months Ending
December 31,
Pension & Benefits Expense $ 170,449,274 $ 172,724,970
IFERCFORM NO.1 (ED. 12-S7) Page 450.1
............................................
Blank Page
(Next Page is 326)
Name of Respondent This~rtIS:Date of RElrt Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 04200
PU~C~~ED POWER hAccou~t 5 5)nc 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, capacit, 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 affilation 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 servce 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
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 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 unilateraiiy get out of the contract.
IF - for intermediate-term firm service. The same as LF service exp that "intermiate-term" mens 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 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 elecricity. Use this category for transactions involing 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-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.
Una Name of Company or Public Authori Statistica FERC Rate Average Actuai Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly Billng Average AveragecationTari Number Demand (MW) Monthly NCP Deman Monthly CP DemarK
(a)(b)(c)(d)(e)(1)
1 Power Purchases
2 3Degrees SF NA NA NA
3 AES SeaWest, Inc.NA NA NA
4 AES SeaWest, Inc.LU NA NA NA
5 Alberta Power Pool SF NA NA NA
6 American Elecric Power SF NA NA NA
7 Anaheim, Cit of NA NA NA
8 Anaheim, City of SF NA NA NA
9 Arizona Electric Power Corative SF NA NA NA
10 Arizona Public Service Co.IF NA NA NA
11 Arzona Public Service Co.NA NA NA
12 Arizona Public Service Co.SF NA NA NA
13 Avista Corp.NA NA NA
14 Avista Corp.SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-9)Page 326
...............................;.........
lI...
............................................
Name of Respondent This lË0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) ¡=A Resubmission 04/03/2008
CCOU~\~g~~) (continUed)nneluding pòwer 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 appropnate
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 (t). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on 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 expnses, 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/SETLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered ($/
~~~\'/
of Settlement ($)
(g)(h)(I)(j (m)
1
437,5O 2
-549,100 3
140,90~4,999,23 4,99,238 4
1H 6,010 5
4€2,16C 2,160 6
5,43S 121,7Sf 121,785 7
9,771 403,70:403,705 8
4~2,01C 2,010 9
227,85C 14,785,121 14,785,127 10
174,34C 5,868,56E 5,868,566 11
64,676 3,148,01C 3,148,010 12
5,500 13
42,57f 2,217,94 2,242,762 14
13,186,772 9,64,44 8,978,36 121,80,550 2,308,732,360 -1 ,66,801,949 763,738,961
FERC FORM NO.1 (ED. 12-90)Page 327
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2O7/Q4
(2) FiA Resubmission 04/03100
PU~C~A&ED POWER hAccou~t 555)nc u ing power exc anges
1. Report all power purchases made dunng the year. Also report exchanges of electncity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation 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 projecs 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 supplier's service to its own ultimate consumers.
LF - for long-term firm servic. "Long-term" means five years or longer and "firm" mens 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 service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each penod of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five yers or longer. The availabilit and reliabilty of
service, aside from transmission constraints, must match the availabilit and reliabilit 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 electncity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categones, 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.
Une Name of Company or Public Auhority Sttistil FERC Rate Average Actual ~and (NN)
No.(Footnote Afliati)
Clif-Scle or Montly Billing Average AveragecaTar Numbe Demand (NN)Mohly NCP Deman Montly CP Demand
(a)(b)(c)(d)(e)(f)
1 Avista Energy, Inc.~NA NA NA
2 Avista Energy, inc.SF NA NA N,l
3 BP Energy Company SF NA NA NA
4 Ballard Hog Farms Inc.LU NA NA NA
5 Barclays Bank PLC SF NA NA NA
6 Ber Energy LP SF NA NA NA
7 Bever City NA NA NA
8 Bel Mountain Power LU NA NA NA
9 Benton County Pub Utilty Dist No. 1 SF NA NA NA
10 Biomass One, L.P.LU 22.5 17.7 15.1
11 Birch Creek Hydro LU NA NA NA
12 Black Hils Power, Inc.fl NA NA NA
13 Black Hils Power, Inc.NA NA NA
14 Black Hils Power, Inc.-NA NA NA
Total
FERCFORM NO.1 (ED. 12-9)Page 326.1
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PaeifCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) Fî A Resubmission 04/0312008
ecougt 55~l¡ (0 ntinued)(Ineludinii power exe 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, tarifs 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 (t). 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 settlellnt
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/SElEMENT OF POWER Una
Purchased MeWatt Hours MegaWatt Hours Demand Chage Energy Charges Other Chargs Tota O+k+l)No.
Received Delivered ~l \~~\fl
of Setement ($)
(g)(h)(I)(m)
2,200 1
112,58!5,578,631 5,518,631 2
1,376,94 82,578,83,381,69t 3
!13 138 4
1,962,03 111,420,97 112,014,75:5
664,95:37,543,28 39,012,612 6
6:5,2n 5,279 7
1,09t 52,02i 52,021 8
11,67~615,53~615,53~9
127,00:2,399,625 16,482,85 23,543,75E 10
11,93E 625,95 625,95C 11
-~83,287 12
4,331 1,221,10€13
E 40(40 14
13,186,112 9,64,44 8,978,368 121 ,808,55C 2,308,732,36 -1 ,66,801,949 163,738,961
FERC FORM NO.1 (ED. 12-9)Page 321.1
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) nA Resubmission 043/2008
PU~CHAJlED POWER hAccou~t 555)
(ncu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 affilation 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 secnd 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 categry 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 "intermiate-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 reliabilit of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designted unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service exp that "intermiate-term" means
longer than one year but less than five years.
EX.. For exchanges of elecricity. Use this category for transactons involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-efined 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.
Une Name of Compay or Public Authori Sttistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Clasif-Schele or Montly B::. Average AveragecaionTari Number Dem ( )Monthly NCP Deman Monthl CP Demam
(a)(b)(c)(d)(e)(1)
1 Black Hils Power, Inc.SF NA NA NA
2 Black Hils Wyoming, Inc.SF NA NA NA
3 Blanding City NA NA NA
4 Bogus Creek NA NA NA
5 Bogus Creek LU NA NA NA
6 Bonnevile Power Administration NA NA NA
7 Bonnevile Power Administration 575 575 523
8 Bonneville Power Administratio NA NA NA
9 Bonnevile Power Administration NA NA NA
10 Bonnevile Power Administration SF NA NA NA
11 Bonnevile Power Administration SF NA NA NA
12 Briish Columbia Trasmission Corp.SF NA NA NA
13 Burbank, City of NA NA NA
14 Burbank, City of SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-9)Page 326.2
............................................
............................................
Name of Respondent This oo0rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) DA Resubmission 04/03/2008
~ccouHt_~s~i) (v ntinueo¡(Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any 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-eincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). 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.
MegaWatt Hours POWER EXCHANGES COST/SETEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charge Other Charges Total O+k+l)No.Received Delivered
~l ~t~\fl
of Settement ($)
(g)(h)(I)(m)
82,2H 5,211,62(5,211,620 1
6,66(289,495 289,495 2
26e 20,O6 20,06 3
111 3,610 4
1,14e 38,08 38,088 5
-53,216 6
47,058,00 47,058,00 7
1,46,83 8
1,018,608 9
18,180 10
681,90 27,569,09 27,835,130 11
157 1,99 12
-f -206 13
54,53(3,274,45f 3,274,468 14
13,186,712 9,646,44 8,978,36 121,80,550 2,308,732,36 -1,66,801 ,949 763,738,961
FERC FORM NO.1 (ED. 12-9)Page 327.2
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 048
PU~C~AJlED POWER hAccou3t 555)
n u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalance exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the 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 service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyr or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF servic 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 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 intermiate-term service from a designated generating unit. The same as LU service expec that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactons 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-efined 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.
Une Name of Compay or Public Authori Statistical FERC Rate Average Acual Demand (MW)
No.(Footnote Affilations)Classifi-Schedule or Monthly Biling Average AveraecationTar Number Demand (MW) Monthly NCP Deman Mothly CP Demanc
(a)(b)(c)(d)(e)(f)
1 COM Hydro LU NA NA NA
2 California Independent System Operator NA NA NA
3 California Independent System Operator =NA NA NA
4 Cargil Power Markets, LLC NA NA NA
5 Cargil Power Markets, LLC SF NA NA NA
6 Central Oregon Irrigation Distric ë 4.2 4.1 2.2
7 Chelan County Pub Utilit Dist No 1 NA NA NA
8 Chelan County Pub Utilit Dist No 1 LU NA NA NA
9 Chela County Pub Utilit Dist No 1 NA NA NA
10 Chelan County Pub Utilty Dist No 1 SF NA NA NA
11 Citigroup Energy, Inc.SF NA NA NA
12 City of Bufalo LU 0.2 0.2 0.2
13 Clatskanie People's Utilty District SF NA NA NA
14 Colorado River Commission of Nevada SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.3
............................................
-...........................................
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PaeifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
.(2) nA Resubmission 04/0312008
t"u eeouHU¡§~~i (Continued)-niiCludlriò. påwer exe 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), identiy 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 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 meawatthours
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 Woe
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+I)No.Received Delivered
~l ~~~\fl
of Setement ($)
(g)(h)(i)(m)
20.72~1,081,7&1,081,700 1
-B 1,65~2
389,90f ro=.~20,295,35S 3
63~34,395 4
2.712,32~165,381,21 .165,381,213 5
25,10.433,44 2,186,361 2,619,805 6
161,558 7
389,371 3,809,68 8
400 9
51 ,78~2,321,7 2,331,36 10
1,697,60'97,616,47 97,776,148 11
1,59f 26,125 111 ,83~137,957 12
2,48C 131,69C 131,690 13
51,10 2,805,14f 2,80,148 14
13,186,772 9,64,44 8,978,368 121,808,550 2,308,732,36 -1,66,801,949 763,738,961
FERC FORM NO.1 (ED. 12-9)Page 327.3
Name of Respondent This~rtls;Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) DA Resubmission 042008
PU~C~~ED POWER hAccou~t 5 5)
nc ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalance exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation 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 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 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 ge out of the contract.
IF - for intermediate-term firm service. The same as LF servic exp that "intermiate-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 - 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 availabilit 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" mens
longer than one year but less than five years.
EX . For exchanges of elecncity. 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 servics which cannot be place in the above-efined categones, such as all
non-firm service regardless of the Length of the contract and service from designated unit of Less than one year. Descnbe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTari Number Demand(MW)Montly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Colorado Springs Utilties SF NA NA NA
2 Columbia Storage Power Exchange NA NA NA
3 Commercial Energy Management LU NA NA NA
4 Conoco inc.NA NA NA
5 Conoco Inc.SF NA NA NA
6 Constellation Energy Commodities Group NA NA NA
7 Constellation Energy Commodities Group SF NA NA NA
8 Coral Power NA NA NA
9 Coral Power SF NA NA NA
10 Cowlitz County Pub Utilty Dist No 1 NA NA NA
11 Credit Suisse Energy LLC SF NA NA NA
12 Curtiss Livestock LU NA NA NA
13 DB Energy Trading LLC SF NA NA NA
14 DR Johnson Lumber Company LU NA NA NA
Total
FERC FORM NO.1 (ED. 12-9)Page 326.4
............................................
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04/03/2008
v -Y,iltiwé'ccouHt 55~~) (Gontlnuec). Oiicludin po er exc anaè
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 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
dunng 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 tyes of charges, incuding
out-of-penod 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 energ. 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 entnes as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charge Oter Charges Total O+k+l)No.Received Delivered
~l \i~\fl
of Selemet ($)
(g)(h)(i)(m)
5~3,40(3,4O 1
-2,597 2
1,841 94,43 94,43 3
230,48E 16,658,275 16,658,275 4
311,65 20,021,98E 20,021,986 5
43E 25,965 25,965 6
1,627,73 96,472,331 97,352,084 7
17,030 8
1,130,12~61,725,24 62,627,47€9
-138,791 10
88,31E 56,397,1 56,114,894 11
12~6,79(6,79C 12
217,23'11,322,83E 11,32,83E 13
66,63 3,673,301 3,673,30 14
13,186,772 9,646,44 8,978,368 121,808,550 2,308,732,36C -1 ,66,801,949 763,738,961
FERC FORM NO.1 (ED. 12-90)Page 327.4
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) DA Resubmission 04031008
PU~C~A~ED POWER hAccount 555)
( nc u ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation 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 service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
thn 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 availabilit 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 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 servics which cannot be place in the above-efined categories, such as all
non-firm service regardless of the Length of the contract and servic 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 Authori Statistical FERCRae Average Acual Demand (MW)
No.(Footnote Affilations)Classif-Schedule or Monthly Biling Average AveragecationTari Number Demnd(MW)Monthly NCP Dema Monthly CP Demanc
(a)(b)(c)(d)(e)(f)
1 Davis County Waste Management i-NA NA NA
2 Davis County Waste Management NA NA NA
3 Deschutes Valley Water District ~5.7 4.0 2.9
4 Deseret Power Elecric Cooperative 100 100 92
5 Deutsche Bak AG SF NA NA NA
6 Douglas County Forest Product =NA NA NA
7 Douglas County Pub Utility Dist No 1 NA NA NA
8 Douglas County Pub Utilty Dist No 1 LU NA NA NA
9 Dougla County Pub Utilit Dist No 1 NA NA NA
10 Douglas County Pub Utilty Dist No 1 SF NA NA NA
11 Draper Irrigation Company IU NA NA NA
12 Dry Creek LU NA NA NA
13 Dynegy Power Marketing SF NA NA NA
14 EPCOR Energy Marketig (U.S.) Inc.SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.5
............................................
............................................
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04/0312008
_.ccou~t SS~~) lL" ntinueo¡'llnëudin~j põwer exc angè )
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 impsed on a monnthly (or longer) basis, enter
the monthly average billng demand in column (d), the average monthly non-eincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (1). 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 recived 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 certin credits or charges covere 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 COSTÆ8TLEMENT OF POWER Line
Purcased MegWatt Hours MegaWatt Hours Demand Charges _~a-~T~Ü~~No.Received Delivere
~l ~$~ ($) of Settlement ($)
(g)(h)(i)k ro ~
7::1
6S(28,3 28,38 2
24,74€711,148 2,483,72 3,194,871 3
747,23E 13,12S,162 12,S04,29,108,916 4
281,974 5
89G 43,79 43,797 6
-151,015 7
257,836 2,572,782 8
68,69;,1,282,1,282,88C 9
16,41(797,68 8oo,65€10
~1,ng 1,n9 11
8,46 405,2SG 405,25G 12
26,08f 1,782,99E 1,782,998 13
52,31E 2,513,97:2 2,513,97:2 14
13,186,n2 9,64,44 8,978,368 121,808,55 2,30,732,36 -1,66,801 ,94G 763,738,961
FERC FORM NO.1 (ED. 12-90)Page 327.5
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) riA Resubmission 0431208
PU~C~AdfED POWER hAccou~t 555)nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 affilation 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 bethe 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 advers 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 identifie as LF, provie 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 intermdiate-term firm service. The same as LF service expec that "intermiate-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 reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermdiate-term service from a designated generating unit. The same as LU service exp that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricit. Use this category for transactions involving a balancing of debit and credits for energy, cacity, 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.
Une Name of Company or Public Authority Sttistical FERC Rate Average Actual Dem (MW)
No.(Foonote Affilations)C1assif-Schedule or Monthly Billng Average AveragecationTari Numbr Demand (MW) Monthly NCP Deman Monthly CP Demanc
(a)(b)(c)(d)(e)(f)
1 Eagle Point Irrati District LU 0.8 0.5 0.4
2 EI Paso Elecric Company SF NA NA NA
3 Eugne Water & Elecric Bord SF NA NA NA
4 Eurus Energy Ameria LU NA NA NA
5 Evergreen BioPower, LLC LU NA NA NA
6 Exergy Development Group, LLC ..NA NA NA
7 ExonMobile Prouction Company NA NA NA
8 FPL Energy Power Marketing, Inc.SF NA NA NA
9 Falls Creek LU 3.2 3.4 1.1
10 Farmers Irrigation District LU 3.2 3.1 2.4
11 Fery, Loyd LU NA NA NA
12 Fillmore City NA NA NA
13 Finley BioEnerg, LLC LU NA NA NA
14 Fortis Energy Marketing & Trading GP SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-9)Page 326.6
............................................
-...........................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) nA Resubmission 04/0312008
CCOU~\~g~) (Continued)
-micludmö- 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, tarifs 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 (SO-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (SO-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.
S. 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 settlemnt
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.
MegaWått Hours POWER EXCHANGES COST/SETLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charge Tot 0+k+1)No.Received Delivered ~l \~l \fl
of Settlement ($)
(g)(h)(i)(m)
3,31~45,365 342,79E 388,161 1
38,04 2,104,07_2,12O,86 2
107,97~6,264,781 6,264,781 3
117,18C 4,088,41S 4,088,418 4
6,531 34,975 345,975 5
118,750 6
668,08~31,607,6!K 31,607,69C 7
35,45~2,219,81f 2,219,815 8
14,~201,257 1,437,27C 1,63,527 9
21,48E 279,720 2,088,351 2,368,074 10
270 15,00 15,00 11
18~19,68C 19,680 12
1,4&:84,29E 84,29S 13
587,ß3 33,483,13 33,20,02 14
13,186,n2 9,646,44 8,978,368 121,808,55C 2,30,732,36 -1,66,801,949 763,738,961
FERC FORM NO. 1 (ED. 12-90)Page 327.6
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) DA Resubmission 04008
PU~C~~ED POWER ~ccou~t 555)nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 affilation 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 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
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 transactn 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 expct that "intermdiate-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 the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expec that "intermediate-term" means
longer than one year but less than five years.
EX - For eXChanges of elecricit. 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 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.
Une Name of Compay or Public Authori Statistical FERCRate Average Actua Demand (MW)
No.(Footnote Affliation)Classifi-Schedule or Monthly Biling Average AveragecationTari Number Demand (MW) Mohly NCP Deman Monthly CP Demanc
(a)(b)(c)(d)(e)(f)
1 Franklin County Pub Utilty Dist No. 1 SF NA NA NA
2 Galesville Dam LU 0.6 0.8 0.6
3 Garland Canal LU 2.7 0.3 0.1
4 General Chemical Corpration ~NA NA NA
5 George DeRuyter & Sons Dairy NA NA NA
6 Georgetown Irrigation Company ~NA NA NA
7 Gila River Power, L.P.NA NA NA
8 Gila River Power, L.P.SF NA NA NA
9 Glendale, City of II NA NA NA
10 Grad Valley Power NA NA NA
11 Grant County Pub Utilty Dist No 2 NA NA NA
12 Grant County Pub Utiit Dist No 2 14 NA NA
13 Grant County Pub Utiit Dist No 2 LU NA NA NA
14 Grant County Pub Utilty Dist No 2 LU NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.7
............................................
............................................
Name of Respondent i his ÏË0rt Is:Date of Report Year/Period of Report
PaeifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) DA Resubmission 04/0312008
11i ;II d'-g pôwi: eeougt 551¿) (i;ontlnUeo¡ne u in 0 er exe 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 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
dunng 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 megwatthours
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 amouht (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 Recived on Page 401, line 12.
The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entnes as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Deman Charge Energy Charge Other Charge Totl O+k+I)No.Received Delivered ~l ~~~\fl
of settement ($)
(g)(h)(i)(m)
5,654 298,184 298,184 1
4,87e 63,553 537,015 600,56 2
8,90~133,411 329,oa 462,491 3
1,87~27,901 27,901 4
5,781 323,14e 323,148 5
1,311 67,031 67,031 6
8,075 574,51C 574,510 7
379,700 21,36,589 21,36,589 8
5 37:3 37:3 9
8C 12,28:12,283 10
-557,374 11
87,60 85,193 6,405,4 6,823,968 12
741,59f 12,520,9 21,725,766 13
931,53E 9,698,148 14
13,186,n2 9,646,44 8,978,368 121,808,550 2,308,732,36 -1,66,801 ,949 763,738,961
FEC FORM NO.1 (ED. 12-9)Page 327.7
Name of Respondent
PacifCorp
This~rtls:
(1) I!An Original
(2) A Resubmission
PUR( CH1IASED POWER (Account 555)llnc tJng power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Coe based on the original contractual term and conditions of the service as follows:
Date of Report
(Mo, Da, Yr)04/03208
Year/Period of Report
End of 2O7/Q4
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 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 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 "intermiate-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 reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilit of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expec that "intermdiate-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.
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 servic 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 AuorityNo. (Footnote Affilations)
(a)
1 Grant County Pub Utility Dist No 2
2 Grant County Pub Utilit Dist No 2
3 Grays Harbr Public Utilty Distri
4 Heber Ught & Power Copay
5
6
7 Highland Energy LLC
8 Hil Air Force Bae
9 Hil Air Force Bae
10 Hurricane, City of
11 Idao Falls, City of
12 Idaho Falls, City of
13 Idaho Falls, City of
14 Idaho Power Company
Statistical
Classif.
cation
(b)
Average
Monthly Biling
Demand (MW)
(d)
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Demand(e) (1)
FERC Rate
Schedule or
Tari Number
(c)
NA
NA
NA
NA
NA
241
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
241
NA
NA
NA
NA
NA
NA
NA
NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.8
NA
N
NA
NA
NA
216
NA
NA
NA
NA
NA
NA
NA
NA
............................................
............................................
This ~ort Is:
(1) IlAn Onginal
(2) A Resubmission
ccountnc udin po er exchange)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2007/Q4
4. In column (c), identify the FERC Rate Schedule Number or Tanff, or, for non-FERC junsdictional 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-eoincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on 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 reeipt 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.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt HoursReceived Delivered(h) (i)Demand Charges
~l
Line
No.
34,303,979
13,186,n2 9,646,44 8,978,368 2,308,732,360 763,738,961121,808,55
FERC FORM NO.1 (ED. 12-90)Page 327.8
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) EiA Resubmission 0403200
PU~C~AdfED POWER hAccou~t 555)nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation 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 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
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 cotract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermdiate-term firm service.The same as LF service expect that "intermdiate-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 availabilit and reliabilty of
service, aside from transmission constraints, must match the availabilit and reliabilit of the designated unit.
IU - for intermediate-term servce from a designated generating unit. The same as LU service expect that "intermediate-term" mens
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 category only for those servs which cannot be placed in the above-efined 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 Copany or Public Authority Sttitica FERC Rate Average Acual Demand (MW)
No.(Footnote Affilatios)
Clasif-Schedle or Montly Billng Average AveragecatinTar Number Demand(MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Idaho Power Company SF NA NA NA
2 Integry Energy Services, Inc.SF NA NA NA
3 Intennountain Power Projec LU NA NA NA
4 J. Aron & Copany SF NA NA NJI
5 J.P. Morgan Ventures Energy Corp.NA NA NA
6 J.P. Morgan Ventures Energy Corp.SF NA NA NA
7 Kennectt IU NA NA NA
8 Kennecott LU NA NA NA
9 Kennecott NA NA NA
10 L&M Angus Ranch, LLC LU NA NA NJI
11 Lacomb Irrgation LU NA NA NA
12 Lake Siskiou LU 2.7 2.6 1.0
13 Leman Brothers Commodit Services SF NA NA NA
14 Los Angeles Det. of Water & Power NA NA NA
Total
FERC FORM NO.1 (EO. 12-90)Page 326.9
............................................
............................................
Name of Respondent
PacifiCorp
his~rtls:
(1) llAn Onginal
(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.
Year/Penod of Report
End of 207/04
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropnate
designation for the contract. On separate lines, list all FERC rate schedules, tanffs 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
dunng 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-penod 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 chargs 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 entnes as reuired and provide explanations following all required data.
POWER EXCHANGES
MegaWatt Hours MegaWatt HoursReceived Delivered(h) (i)
COST/SETLEMENT OF POWER
Energy Charges Oter Charges($) ($)(k) (I)Demand Charges
~l
763,738,961
254,
9,646,44 8,978,36 121,808,55 2,308,732,36 -1,66,801,949
FERC FORM NO.1 (ED. 12-9)Page 327.9
Une
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) t=A Resubmission 0431
PU~C~AJlED POWER hAccou~t 555)( nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 affilation 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 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
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 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 intermeiate-term firm service. The same as LF servic expec that "intermiate-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 reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of the designated unit.
IU - for intermdiate-term service from a designated generating unit. The same as LU servic expect that "intermdiate-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 servics 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.
Una Nae of Company or Public Authori Statisticl FERC Rate Average Acual Demand (MW)
No.(Footnote Affliations)Classifi-SCheule or Monthly Billng . Average AveragecationTari Number Demand(MW)Monthly NCP Deman Mothly CP Demand
(a)(b)(c)(d)(e)(f)
1 Los Angeles Dept. of Water & Power SF NA NA NA
2 Luckey, Paul LU NA NA NA
3 Magnesium Corporation of America IU NA NA NA
4 Magnesium Corpration of America NA NA NA
5 Marsh Valley Hydo & Elecric Compay LU NA NA NA
6 Merrill Lynch Commodities, Inc.SF NA NA NA
7 Middlefork I rrgatin District LU NA NA NA
8 Mink Creek Hydro LU NA NA NA
9 Mirant Americas Energy Marketing, LP.SF NA NA NA
10 Moesto Irrgation District SF NA NA NA
11 Monsanto IU NA NA NA
12 Morgan City lI NA NA NA
13 Morgan Stnley Capitl Group, Inc.NA NA NA
14 Morgan Stanley capital Group, Inc.50 50 50
Total
FERC FORM NO.1 (ED. 12-90)Page 326.10
............................................
-...........................................
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) IlAn Original (Mo. Da, Yr)
(2) nA Resubmission 04/0312008
. "'lV' ,A::i:U d.i:~' ::~.~\~ ccount 555) ') (e ontinued)lInclu iny pOwer exchanaes)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
Year/Period of Report
End of 2oo7/Q4
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-eincident 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 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 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.
COST/SETLEMENT OF POWER .
EnergyChargæ ~ T~ O'+k+I)
($) ($) of Settlement ($)(k) (i) . (m)4,138,38 4,199,54128,95 28,954
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt HoursReceived Delivered(h) (í)
Demand Charges
~l
10,84,413
1,755,360
235,167
29,715,390
1,381,498
426.556
25,587
3.sg
13,011,421
3,115
40,555
31,497,680
763.738,961
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
62,5OE
28!
214,849 10,84,41=
235.16
~.~.101
1.381,49E
426,55€
25,581
3,394
4,47.1
483.39t
25,2H
8,4M
81~
7f
~
62E
504.80(
3.11
468.00 31.029,6&
13,186,n2 121,80,550 -1,66.801,9499,64,44 8.978,368 2,308,732,360
FERC FORM NO.1 (ED. 12-90)Page 327.10
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) nA Resubmission 048
PU~C~~ED POWER ~Accou~t 555)
( nc ng power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 affilation 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 mustbe
the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service exp that "intermiate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servics, 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 availabilit and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU . for intermdiate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX . For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services whic 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 Acual Demand (MW)
No.(Footnote Affiliations)Classif-SChedule or Monthly Biling Average AveragecationTari Number Demand (MW) Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Morgan Stnley Capial Group, Inc.SF NA NA NA
2 Mountn Energy, Inc.LU NA NA NA
3 Municipal Energy Agency of Nebraka SF NA NA NA
4 NephiCity NA NA NA
5 Nevada Power Company NA NA NA
6 Nevada Power Compay SF NA NA NA
7 Nicholson Sunnybr Ranch LU NA NA NA
8 Nort Fork Sprague LU 0.4 0.6 0.2
9 NorthWestern Energy SF NA NA NA
10 Northern California Power Agency SF NA NA NA
11 Northpoint Energy Solutions Inc.SF NA NA NA
12 Nucor Corporation IF NA NA NA
13 O.J. Power Company LU NA NA NA
14 Occidental Power Services, Inc.SF NA NA NA
Total
FERCFORM NO.1 (ED. 12-90)Page 326.11
............................................
-...........................................
Name of Respondent This oo0rt Is:Date of Report Year/Penod of Report
PacifiCorp (1) X An OnginaJ (Mo, Da, Yr)End of 2oo7/Q4
(2) EjA Resubmission 04032008
PI CCOUR\~8~~~ (U ntlnueoJ
.- '~liñèuding 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 biling demand in column (d), the average monthly non-eincident 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 (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the meawatthours
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.
MeaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges
""~ W Tmm ~~)
No.Received Delivered
~l \$l ($) of Settlement ($)(g)(h)(i)k (I) (m)
5,832,56¡322,n2,61 323,086,862 1
1 94S 94S 2
4,48C 203,12C 203,120 3
1 1,67~1,673 4
55C 25,95 25,950 5
28,83€1'00'3~1,925,331 6
1,65"85,55 85,557 7
2,25€42,575 22~271,813 8
56~29,609 9
33,86e 1,828,1,828,63 10
12,00 848'4~848,488 11
4,610,400 12
78E 37,61e 37,61S 13
24,8OC 1,818,64 1,818,648 14
13,186,n2 9,64,44 8,978,368 121,80,550 2,308,732,36C -1,666,801,949 763,738,961
FERC FORM NO.1 (ED. 12-90)Page 327.11
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) ¡=A Resubmission 04032008
PU~~~ED POWER hAccou~t 555)ng power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 affilation 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 resourc 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 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 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 servic exp that "intermdiate-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 reliabilty of
service, aside from transmission constraints, 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 expect that "intermdiate-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 creits 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-efined categories, such as all
non-firm service regardless of the Length of the contract and servic from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Una Name of Company or Public Auhoriy Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average AveragecationTari Number Deman(MW)Monthly NCP Deman Monthly CP Demanc
(a)(b)(c)(d)(e)(1)
1 Odell Creek LU 0.04 0.06 0.Q
2 Oregon Environmental Industries, LLC LU NA NA NA
3 PPL EnergyPlus, LLC SF NA NA NA
4 PPL Montana, LLC SF NA NA NA
5 PPM Energy, Inc.NA NA NA
6 PPM Energy, Inc.SF NA NA NA
7 Pacifc Gas & Electric Compay SF NA NA NA
8 Pacific NW Generating Cooperative SF NA NA NA
9 Pacific Summit Energy LLC Ji NA NA NA
10 Pacific Summit Energy LLC NA NA NA
11 Pasadena, City of =NA NA NA
12 Paysn City Corporation NA NA NA
13 Pinnacle West Marketing & Trading Co.SF NA NA NA
14 Platte River Power NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.12
............................................
-...........................................
Name of Respondent This
Wrt
Is: Date of Report Year/Period of Report
PaeifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) ñA Resubmission 04/0312008
CCOUR\~~l ~ (Continued)
(Ineludmii pòwër exe 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 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 m6nthly 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 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 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 COSTISEnEMENT OF POWER üne
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Recived Delivered
~l ~~~~fl
of Setlement ($)
(g)(h)(i)(m)
25'3,537 22,48~26,026 1
12,021 64,471 64,471 2
2,76C 13(38 134,38(J 3
22,21E 1,091,17A 1,091,174 4
.~68,912 5
684,990 34,748,58 35,228,729 6
32,391 2,258,851 2,258,851 7
25,385 1,259,24C 1,259,240 8
80(49~6O 49,60 9
674,81!38,678,50:38,678,502 10
10,91f 687,401 687,4~11
1(1,15f 1,155 12
5,71,435,73E 435,736 13
-f -176 14
13,186,172 9,64,44 8,978,368 121,80,550 2,308,732,36 -1,66,801,949 763,738,961
FERC FORM NO.1 (ED. 12-90)Page 327.12
Name of Respondent This~rtIS:Date of Reirt Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) DA Resubmission 04/032008
PU~C~~ED POWER hAccou~t 555)
nc ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is servic 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 service. "Long-term" mens five yers or loger and "firm" mens 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 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 expt that "intermdiate-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 generating unit. "Long-term" means five yers or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermdiate-term service from a designated generating unit. The same as LU servic expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of elecricit. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalance exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Une Name of Company or Public Authori Statistical FERC Rate Average Acual Deman (MW)
No.(Foonote Affliatis)
Classifi-Schule or Monthly Billing Average AveragecationTar Number Demand(MW)Mothly NCP Deman Monthly CP Demanc
(a)(b)(c)(d)(e)(f)
1 Platte River Power SF NA NA NA
2 Portlad General Eleric Co.NA NA NA
3 Portland General Elecric Co.NA NA NA
4 Portland General Elecric Co.NA NA NA
5 Portland General Elecric Co.NA NA NA
6 Portland General Electri Co.SF NA NA NA
7 Powerex SF NA NA NA
8 Preston City Hydro LU NA NA NA
9 ProvoCit Ji NA NA NA
10 Public Servce Copany of Colorado NA NA NA
11 Public Service Company of New Mexico C NA NA NA
12 Public Service Company of New Mexico NA NA NA
13 Puget Sound Energy NA NA NA
14 Puget Sound Energy SF NA NA NA
Total
FERCFORM NO.1 (ED. 12-90)Page 326.13
............................................
............................................
This~rtls:
(1) I2An Original
(2) A Resubmission
ccounterexChan 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
Year/Period of Report
End of 2007/Q4
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 impsed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-eincident 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 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 expnses, 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
Purchased
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt HoursReceived Delivered(h) (i)
COST/SETLEMENT OF POWER
Energ Charges Other Charges~~l \fl UneTotal (j+k+l) N
of Setlement ($) o.
(m)
179,595 1
118,75 2
40,54 3
137,00 4
5
6
7
8
9
10
11
12
13
14
Demand Charges
~I
5
28,38,31
89,214,51
119,61
13,07
10,654,27
403,30
22,388,8
13,186,n2 763,738,9619,64,44 121,808,5 2,308,732,368,978,368
FERC FORM NO.1 (ED. 12-90)Page 327.13
Name of Respondent This~rtIS:Date of Reprt Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) DA Resubmission 04208
PU~C~~ED POWER hAccou~t 555)nc ing poer exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation 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 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 ofRQ 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 servic exp that "intermiate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servics, 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
service, aside from transmission constraints, must match the availabilit and reliabilit of the designated unit.
IU - for intermediate-term service from a designated generating unit. Thé same as LUservice expect that "intermdiate-term" means
longer than one year but less than five years.
EX - For exchanges of electicity. Use this category for transactions involvng 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 servics which cannot be place in the above-defined categories, such as all
non-firm service regardless of the Lengt of the contract and servce from designated units of Less than one year. Describe the nature
of the servic in a footnote for each adjustment.
Une Name of Company or Public Authority Statistical FERC Rate Average Acual Demand (MW)
No.(Footnote Affiliations)Clasifi-Schedule or Monthly Billing Average AveragecationTari Number Demand(MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Puget Sound Energy SF NA NA NA
2 Ouail Mountain, Inc.LU NA NA NA
3 Rainbow Energy Marketing NA NA NA
4 Rainbow Energy Marketing SF NA NA NA
5 Ralphs Ranch, Inc.LU NA NA NA
6 Reding, City of SF NA NA NA
7 Reliant Energy Services, Inc.SF NA NA NA
8 Riverside, City of NA NA NA
9 Riverside, City of SF NA NA NA
10 Rocky Mountain Generation Coperative SF NA NA NA
11 Roseburg Forest Products Co.LU NA NA NA
12 Roush Hydro, Inc.NA NA NA
13 Roush Hydro, Inc.LU NA NA NA
14 SUEZ Energy Marketing NA, Inc.SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-9)Page 326.14
............................................
............................................
Name of Respondent This e ort Is:Date of Report Year/Period of Report
PacifiCorp (1 )~ An Original (Mo, Da, Yr)End of 2007/Q4
(2)A Resubmission 04/0312008
"""' .r_¡ccouHt 55~il (continued)nc udinò- pòwer 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-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 (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on 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. Réport 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 COSVSEnEMENT OF POWER Une
Purchased MegaWatt Hours MegaWatt Hours Demand Charges
'-"- m T~ fj~
No.Received Delivered
~l \$~ ($) of Setlement ($)(g)(h)(i)k (I)' (m)
136,86 7,015,3 7,059,145 1
51 3,001 3,001 2
32C 43,2OC 43,200 3
34,1 Of 1,744,OB 1,744,060 4
250 25,39~25,392 5
45 25,06 25,06 6
37,OOf 3,025,86f 3,025,865 7
10,27C 239,47C 239,47C 8
63f 14,09S 14,095 9
5,58E 225,137 225,137 10
151,58~8,640,57 8,624,731:11
3 12
26'14,49 14,497 13
168,94(9,148,021 9,148,021 14
13,186,772 9,64,44 8,978,368 121,808,550 2,308,732,36 -1,66,801,949 763,738,961
FERC FORM NO.1 (ED. 12-90)Page 327.14
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) rÎA Resubmission 043/8
PU~C~AJiED POWER hAccou~t 555)( nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricit (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation 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 resourc 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 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 service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction idel'tified 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 intermiate-term firm service. The same as LF service expt that "intermdiate-term" means ionger 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 reliabilty of
service, aside from transmission constraints, must match the availabilit and reliabilit of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermdiate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Auhority Statistic FERC Rate Average Acual Demand (MW)
No.(Footnote Affliations)Claif-Sced or Mohly Billing Average AveragecatiTari Number Deand(MW)Monthly NCP Demani Monhly CP Demanc
(a)(b)(c)(d)(e)(f)
1 Sacramento Municipa Utilty District NA NA NA
2 Sacraento Municipa Utilit Ditrict NA NA NA
3 sacramento Municipal Utility District SF NA NA NA
4 Salt River Project NA NA NA
5 salt River Project NA NA NA
6 sail River Project SF NA NA NA
7 san Diego Gas & Elecric SF NA NA NA
8 Santa Clara, Cit of SF NA NA NA
9 Santiam Water Control Distri LU 02 0.2 0.1
10 Schweniman Wind Farms Inc.LU NA NA NA
11 Seaboard Foo ~NA NA NA
12 Seattle City Light NA NA NA
13 Sempra Energy Solutions .-NA NA NA
14 Sempra Energy Trading LLC NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.15
............................................
-...........................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PaeifiCorp (1) X An.Original (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 04/03/2008
oum 199g) (Continued)
"niiudlñò' power exe anãe )
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-cincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other typs of service, enter NA in columns (d), (e) and (f). MonthlyNCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (6o-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 creits 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.
MegWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges _~ ~. Tdm a~~1 No.Receied Delivered ~l ~$~ ($) of Settement ($)
(g)(h)(i)k (I) (m)
64,189 1
179,75 2,568,72 2,568,72É 2
23,941
"~~ii
1,445,815 3
538 4
90 5
276,5El 15,725,151 15,727,265 6
37,364 2,316,44E 2,316,448 7
6,254 357,83C 357,83C 8
1,5El 13,632 136,2~149,661 9
.71,234 10
1,495 11
168,011 8,081,70 8,096,714 12
67,961 4,247,46 4,247,465 13
2,250 14
13,186,772 9,646,44 8,978,368 121,808,550 2,308,732,36C -1 ,66,801 ,94~763,738,961
FERC FORM NO.1 (ED. 12-9)Page 327.15
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) tiA Resubmission 04/0312008
PU~C~AdlED POWER hAccou7t 555)nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 affilation 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 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" mens that service cannot be interrpted 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 categry should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction 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 expt that "intermdiate-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 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 transactions involving a balancing of debits and credits for energy, capacit, etc.
and any settlements for imbalancd exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Une Name of Copay or Public Authori Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-SChedule or Monthly Billng Average .
Averge cation Tari Number Deman (MW) Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Sempra Ener Trading LlC ~NA NA NA
2 Sempra Energy Trading LLC NA NA NA
3 Sempra Generation SF NA NA NA
4 Sierr Pacific Power Company NA NA NA
5 Sierra Pacifc Power Copany SF NA NA NA
6 Simplot Phosphates, LLC .0 NA NA NA
7 Simplot Phosphates, LLC LU 10 13 9
8 Simp/ot Phosphates, LLC NA NA NA
9 Slate Creek NA NA NA
10 Slate Creek LU 2.0 1.4 0.3
11 Snohoish Pub Utlit District No. 1 ii NA NA NA
12 Southem California Edison Company NA NA NA
13 Southern California Ediso Company SF NA NA NA
14 Southwestern Public Servce Copany SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.16
............................................
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PaeifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) DA Resubmission 04/03/2008
ecouHti~8~l) (l'ontinued)~ ,~... 'U"ciuding power exe 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 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 (t). For all other tyes of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (6o-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on 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 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/SETLEMENT OF POWER Una
Purchased MegaWatt Hours MegaWatt Hours Demand Chargs Energy Charges Other Charges Totl O+k+l)No.Received Delivered
~l \~~\fl
of Settlement ($)
(9)(h)(i)(m)
1,02C 47,61C 47,610 1
1,696,041 110,552,41 111,503,313 2
29,47E 1,858,1,858,380 3
e 288 4
37,851 1,812,00 1,851,438 5
3,766 6
82,08g 152,981 3,33,68 3,485,66 7
28,720 8
78,158 9
5,385 86,388 485,701 572,089 10
134,98E 5,355,94E 5,355,94 11
45C 10,25C 10,250 12
270,271 16,993,25~16,993,252 13
54E 11,71C 11,710 14
13,186,772 9,646,44 8,978,368 121,808,550 2,308,732,36 -1,66,801 ,949 763,738,961
FERC fORM NO.1 (ED. 12-90)Page 327.16
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) ¡=A Resubmision 04/03008
PU~C~AJlED POWER hAccou~t 555)nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricit (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the n.ame or use
acronyms. Explain in a footnote any ownership interest or affilation 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 resourc 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 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 intermdiate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" mens five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilit and reliabilit ofthe designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be place in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and servic from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.-
Une Name of Compay or Public Auhori Statiical FERC Rae Average Actual Demand (MW)
No.(Footnote Affliations)Claif-SChee or Monthly Billing Average AveragecationTari Number Demand(MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(1)
1 Spaish Fork City NA NA NA
2 Springvile City NA NA NA
3 Stte of CA Dept of Water Resources r=NA NA NA
4 Strawberry Electri Service Distri NA NA NA
5 Sunnyside Cogeneraon Associates LU 48.6 50.1 48.4
6 Swiss Re Financial Prod Corpratin SF NA NA NA
7 Sys Intermountain Foos NA NA NA
8 Sysco Intermountan Foos NA NA NA
9 Tacma, City of SF NA NA NA
10 Tesoro Refning and Marketing Copay NA NA NA
11 Thayn Hydro LLC LU 0.3 0.4 0.3
12 The Energy Autority ..NA NA NA
13 TransAlta Energy Marketing Inc.NA NA NJ
14 TransAia Energy Marketing Inc.IF NA NA NA
Total
FERC FORM NO.1 (ED. 12-9)Page 326.17
............................................
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2007/Q4
(2) riA Resubmission 04/0312008
couHt 55~~) (0 ntlnuec)ìlñeiudIÌl~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 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 rendere 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 reportd
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.
MeWatt Hours POWER EXCHANGES COsT/SETLEMENT OF POWER Una
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered ~l \~l ~fl
of Settlement ($)
(g)(h)(i)(m)
4ï 4,22~4,229 1
3E 4,39 4,391 2
20,80 1,369,07€1,36,O7€3
81 6,00 6,00 4
404,201 9,625,588 17,625,3OC 27,250,88 5
93,903 6
44 7
2,135 8
25,011 1,308,39 1,314,20 9
41,54~1,892,541 1,892,541 10
2,57~38,43 141,99 180,424 11
2,56.130,061 130,061 12
-534 13
552,12E 3O,404,79f 30,404,795 14
13,186,772 9,64,44 8,978,36 121,808,550 2,308,732,36 -1,66,801,949 763,738,961
FERC FORM NO.1 (ED. 12-9)Page 327.17
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 207/04
(2) nA Resubmission 04/031200
PU~C~AdfED POWER hAccou7t 555)nc u ing power exc anges
1. Report all power purchases made dunng the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 affilation 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 seNice as follows:
RQ - for requirements seNice. 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 seNice. "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 deliveries of LF seNice). 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 "intermiate-term" means longer than one year but less
than five years.
SF - for short-term seNice.Use this category for all firm seNices, where the duration of each penod 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 service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for thse seNics which cannot be place in the above-defined categones, such as all
non-firm service regardless of the Length of the contract and servic from designated unit of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Una Name of Company or Public Authori Statistic FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Mothly Billing Average AveragecationTari Number Demand(MW)Monthly NCP Deman Monthly CP Demanc
(a)(b)(c)(d)(e)(1)
1 TransAlta Energ Marketing Inc.i;NA NA NA
2 TransAIt Energy Marketing Inc.NA NA NA
3 Tri-State Generation & Transmission 41 41 39
4 Tri-State Generaion & Transmission NA NA NA
5 Tri-State Generation & Transmission SF NA NA NA
6 Tri-State Generaion & Transmision ii NA NA NA
7 Tucson Electric Power NA NA NA
8 Tucson Electric Power SF NA NA NA
9 Turloc Irrigation District SF NA NA NA
10 UBS Warburg Energy LLC IF NA NA NA
11 UBS Warburg Energy LLC SF NA NA NA
12 UT Associated Municipal Power Systems NA NA NA
13 UT Associated Municipal Power Systems NA NA NA
14 UT Asociated Municipal Power Systems 81 81 74
Total
FERC FORM NO.1 (ED. 12-90)Page 326.18
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PaeifiCorp (1) X An Original (Mo, Da, Yr)End of 2O07/Q4
(2) nA Resubmission 04/0312008
, v '"ìlnct eeouHt 19~~) (continued)neluding power exe anãè
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, tanffs 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 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 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-penod 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 entnes as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Une
Purchaed MegaWatt Hours MegaWatt Hours Demand Charges "-~~Tmæü*~No.Received Delivered
~l \$~ ($) of Settement ($)(9)(h)(i)k (i) (m)
1,667,74E 53,751,27 53,00,035 1
238,58 13,987,OSC 13,987,OS 2
228,23E 8,461,050 4,575,67C 13,03,720 3
H 57C 570 4
954,54 5
23,41 1,017,82 1,041,83 6
73f 32,24C 32,240 7
227,58~13,34,49~13,343,49~8
2,60(135,30 135,30 9
91,03~6,310,32~6,310,329 10
932,594 54,808,82E 54,80,828 11
27C 12,087 12
328,985 13
452,09 3,659,976 15,949,071 21,526,931 14
13,186,n2 9,64,44 8,978,368 121 ,808,550 2,308,732,36 -1,66,801 ,94~763,738,961
fERC FORM NO.1 (ED. 12-90)Page 327.18
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) ñA Resubmission 0403208
PU~C~AJlED POWER hAccou~t 555)nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 affilation 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 servic to its own ultimate consumers.
IF - 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 IF 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 IF, provide in a footnote the termination date of the contract
defined as th 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 "intermiate-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 reliabilty of
service, aside from transmission constraints, must match the availability and reliabilit of the designated unit.
iU - for intermediate-term service from a designated generating unit. The same as LU service 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, capacit, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those servic which cannot be place in the above-defined categories. such as all
non-firm service regardless of the Length of the contract and servic from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Compay or Public Auont Statisl FERC Rate Averge Actual Demand (MW)
No.(Footnote Affilatis)
Claslf-Schedule or Mothly Billng Average AveragecationTari Number Demand(MW)Mohly NCP Dean Mohly CP Demand
(a)(b)(c)(d)(e)(f)
1 UT Asiated Municipal Power Systems SF NA NA NA
2 Utah Municipal Power Agency NA NA NA
3 Utah Municipal Power Agency SF NA NA NA
4 Wadeland Soh LLC NA NA NA
5 Wadeland South LLC LU 0.04 0.08 0.04
6 Walla Walla, City of LU 1.9 1.6 1.5
7 Warm Springs Forest Products LU NA NA NA
8 Weber County, State of Utah pi NA NA NA
9 Weber County, State of Utah NA NA NA
10 Western Area Power Administration ~NA NA NA
11 Westem Area Power Administration NA NA NA
12 Westem Area Power Administration NA NA NA
13 Weyerheuser NA NA NA
14 Whitney, A. C.LU NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.19
............................................
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) A Resubmission 04/03/2008
ccouHt ""'" If"ntinued)Oneludliò'Dower exc anaesl
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 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/SETTLEMENT OF POWER Li
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Chargs Other Charges Total O+k+l)No.Received Delivered
~I \tl \fl
of Settlement ($)
(g)(h)(I)(m)
30 10,74~10,749 1
4,701 240,12E 240,12€2
8(3,200 3,2OC 3
-4 -1,971 4
32 40 11,47~11,512 5
12,31~135,747 1,529,08t 1,66,83:6
390 8,281 8,281 7
-2.-729 8
2,39~84,84,460 9
1E 9Ó 10
2,16E 87,2 661,151 11
31,50t 1,392,83 1,43,136 12
379,12,21,263,32f 21,263,328 13
14
13,186,n~9,64,44 8,978,36 121,808,55C 2,308,732,36 -1,66,801,949 763,738,961
FERC FORM NO.1 (ED. 12-9)Page 327.19
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 207/04
(2) DA Resubmission 040312008
PU~C~AdlED POWER hAccou~t 555)nc u ing power exc anges
1. Report all power purchases made dunng the year. Also report exchanges of electncity (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 affilation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system 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 "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 delivenes of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermiate-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" mens five yers or longer. The availabilty and reliabilit of
service, aside from transmission constraints, must match the availabilit and reliabilit of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expec that "intermdiate-term" means
longer than one year but less than five years.
EX - For exchanges of electncity. 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 servics 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. Descnbe 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.(Footnoe Affliations)Classif-SCule or Mohly Billing Average AveragecatiTar Numbe Demand(MW)Monthly NCP Deman Monthly CP Deanc
(a)(b)(c)(d)(e)(f)
1 Wolverine Creek Energy LLC LU NA NA NA
2 Yakma Tieton LU NA NA NA
3 Accrual true-up NA NA NA NA
4 Line Loss Return AD NA NA NA
5 Bookouts NA NA NA
6 Boouts AD NA NA NA
7 Accrual for disputed amounts AD NA NA NA
8 Trading AD NA NA NA
9
10 Power Exchange
11 Arizona Public Service Co.EX 30 NA NA NA
12 Avista Corp.EX 554 NA NA NA
13 Basin Electric Power Cooperative EX T-11 NA NA NA
14 Black Hils Power,lnc.~246 NA NA NA
Total
FERC FORM NO.1 (ED. 12-9)Page 326.20
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04/03/2008
, ..'Y,cl r:iWfccouHt ~g~§i (v ntinueà). (Includin po 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 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 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 MegWatt Hours Demand Charges Energy Charges Other Charges Tot 0+k+1)No.Received Delivered
~l \~~\fl
of Setlement ($)
(g)(h)(i)(m)
148,9~7,979,814 7,979,814 1
6,91 372,14 372,149 2
-27,818,841 3
3,146,781 4
-82::-76,136 5
-583,94C -1,424,201,26:3 6
2,324,553 7
-31 ,579,09~-315,04,007 8
9
==10
571,186 571,305 -530,812 11
1,930 12
19,259 6,673 28,90 13
2 14
13,186,n2 9,646,44 8,978,36 121,808,55C 2,308,732,36 -1,66,801 ,94!l 763,738,961
FERC FORM NO.1 (ED. 12-9)Page 327.20
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) DA Resubmission 040312008
PU~C~~ED POWER hAccou~t 5 5)
nc ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation 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 service to its own ultimate consumers.
LF . for long-term firm service. "Long-term" means five years or longer and "firm" mens 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 transaction identified as LF, provide in a footnote the termination date 0,1 the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermeiate-term firm service. The same as LF service expec that "intermiate-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 yers or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilit and reliabilit of th designated unit.
IU - for intermediate-term servic 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.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Une Name of Company or Public Authori Statistcal FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Clasif-SCule or Mohly Billing Average AveragecationTari Numbe De(MW)Moly NCP Deman Montly CP Demanc
(a)(b)(c)(d)(e)(f)
1 Black Hils Power, Inc.EX 246 NA NA NA
2 Bonevile Power Administratio 237 NA NA NA
3 Bonevile Power Administration 256 NA NA NA
4 Bonnevile Power Administration 347 NA NA NA
5 Bonnevile Power Administration EX 237 NA NA NA
6 Bonnevile Power Administration EX 256 NA NA NA
7 Bonnevile Power Administratio EX 347 NA NA NA
8 Bonnevile Power Administration EX 36 NA NA NA
9 Bonneville Power Administration EX 55 NA NA NA
10 Bonnevile Power Administration EX (16)NA NA NA
11 Bonevile Power Administration EX T-11 NA NA NA
12 Bonnevile Power Administration EX T-12 NA NA NA
13 Chelan County Pub Utiity Dist No. 1 EX 55 NA NA NA
14 Clark Public Utilties ~417 NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.21
............................................
............................................
This ~ort Is:
(1) ~AnOriginal
(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.
Year/Period of Report
End of 2007/Q4
Name of Respondent
PacifiCorp
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any 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 (t). For all other tys of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (SO-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (SO-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
S. 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). Exlain 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 Recived 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
Purcased
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt HoursReceived Delivered(h) (i)
316
COST/SETEMENT OF POWER
Energy Charges Other Charges~~l \fl Total '+k+l)
of settlement ($)
(m)
Line
No.Demand Chargs
~l
1
2
3
4
5
6
7
8
9
10
11
12
13
14
2,824
93,954
16,875
4,225
96,125
-974
13,186,n2 2,308,732,360 -1,66,801,949 76,738,9619,64,44 8,978,368 121,808,550
FERC FORM NO.1 (ED. 12-90)Page 327.21
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04208
PU~C~~ED POWER hAccount 555)
( nc ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of elecricity (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 affilation 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 service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projecs 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 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 deliveries of LF service). This category should not be used for long-term firm service firm servic
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 exp that "intermiate-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 reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermdiate-term service from a designated generating unit. The same as LU service expec that "intermiate-term" means
longer than one year but less than five years.
EX - For exchanges of electricit. Use this category for transactions involvng a balancing of debits and credits for energy, capaCity, etc.
and any settlements for imbalance exchanges.
OS - for other service. Use this category only for those servces 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.
Une Name of Copany or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affilations)Classif-Schedule or Mothly Billng Average AveragecationTari Number Demand(MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Clark Public Utilties EX 417 NA NA N,4
2 Cokum Transmission Company EX T-12 NA NA NA
3 Cowlitz County Pub Utilit Dist No. 1 EX 55 NA NA NA
4 Deseret Power Elecri Coperative EX 280 NA NA NA
5 Emerad Peoples Utility District 351 NA NA NA
6 Emeral Peoples Utilty District EX 351 NA NA NA
7 Eugene Water & Elecric Bord EX T-11 NA NA NA
8 Eugene Water & Electric Board EX T-12 NA NA NA
9 Flathead Electric Coperative EX T-11 NA NA NA
10 Grat County Pub Utilit Dist No.2 EX 554 NA NA NA
11 Idaho Power Company EX 380 NA NA NA
12 PPM Energy, Inc.EX T-11 NA NA NA
13 Portland General Elecric Co.EX 554 NA NA NA
14 Public Service Company of Colorado EX 319 NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.22
............................................
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) DA Resubmlssion 04/03/2008
or 511 di;ã ;wÊ ccouHt ~Õ~) (ContinUed)nc u in po er 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 expianation 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 tyes of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (SO-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (SO-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.
S. 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 exchnge.
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 expnses, 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 Une
Purchased MegaWatt Hours MegaWatt Hours Deand Charges EM~~ ~.. T~ ~No.Received Delivered ~l \$l ($) of Setement ($)(g)(h)(I)k (I) (m)
530,707 28,285,778 1
267,50 2
198,156 219,58 3
77,418 40,691 1,396,716 4
14 -341 5
475 -11,868 6
1,355 1,688 -10,738 7
18,105 17,970 10,560 8
9,095 132 454,212 9
11,254 44,373 10
315,721 236,96 --11
16,295 9,717 210,00 12
157,007 155,831 13
5,735 14
13,186,77::9,646,44 8,978,36 121,808,550 2,308,732,36 -1 ,66,801 ,949 763,738,961
FERC FORM NO.1 (ED. 12-90)Page 327.2
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 04/0008
PU~C~AdfED POWER hAccount 5 5)( nc u ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of elecricity (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 transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation 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 (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 servic to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must-attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expec that "intermiate-term" mens longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servics, 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 availabilit and reliabilty of the designated unit.
IU - for intermiate-term service from a designated generating unit. The same as LU service expect that "intermdiate-term" means
longer than one year but less than five years.
EX - For exchanges of electricit. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services whic cannot be place in the above-efined categories, such as all
non-firm service regardless of the Length of the contract and servic 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 Authont Statistil FERC Rate Average Actual Demand (MW)
No.(Footnoe Afflitions)C1assif-Schedule or Moly Billing Average AveragecationTari Number Demd (MW) Monthly NCP Demaii Monthly CP Demand
(a)(b)(c)(d)(e)(1)
1 Public Service COmpany of Colorado EX T-12 NA NA NA
2 Redding, Cit of EX 36 NA NA NA
3 Seattle Cit Light EX 554 NA NA NA
4 sempra Energy Solutions EX T-11 NA NA NA
5 Tri-State Generation & Transmission 319 NA NA NA
6 Tri-State Generation & Trasmission EX 319 NA NA NA
7 UT Associated Municipal Power Systems T-11 NA NA NA
8 UT Associated Municipal Power Systems EX T-11 NA NA NA
9 Utah Municipal Power Ageny T-11 NA NA NA
10 Uta Municipal Power Agency EX T-11 NA NA NA
11 Warm Springs Power Enterprises T-11 NA NA NA
12 Warm Springs Power Enterprises EX T-11 NA NA NA
13 Westem Area Power Administration T-11 NA NA NA
14 Western Area Power Administration EX 262 NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.23
............................................
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2007/Q4
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 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 meawatthours
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.
MeWatt Hours
Purchaed
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt HoursReceived Delivered(h) (i)Demand Charges
~l
Une
oi~=ie:tll$) No.
(m)
302,75 1
-639,23 2
794,863 3
43,765 4
6,52 5
106,n8 6
-730,140 7
1,897,216 8
9
1,986,551 10
39,912 11
-309,874 12
666,153 13
14
763,738,961
COST/SETEMENT OF POWER
Energy Charges Other Charges~~~ \fl
71,753
110,721
337,571
5,036
67,965
123,097
329,40
2,998
80,566
21,737
115,41
-16,754
63,36
24,236
7,89248,954
1,895
5,882
16,764
7,764
169
13,186,n2 9,64,44 8,978,368 121,808,55 2,308,732,36 -1,66,801,949
FERC FORM NO.1 (ED. 12-9)Page 327.23
Name of Respondent ThiS~lOrt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Origina (Mo, Da, Yr)End of 2007/Q4
(2)A Resubmision 04/031208
PU~CH~ED POWER hAccou~t 555)(nclu ing poer 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 transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affilation 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 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 servic 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 servic. 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 exp that "intermiate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servics, 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 reliabilit of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service exp that "intermiate-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 category only for those services which cannot be placed in the above-efined 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.
Une Name of Company or Public Authori Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Afilations)C1assifi-Schedle or Monthly Billing Average AveragecationTari Number Demand(MW)Monthly NCP Demani Monthly CP Demanc
(a)(b)(c)(d)(e)(f)
1 Western Area Power Administration EX T-11 NA NA NA
2
3 System Deviation NA NA NA
4
5
6
7
8
9
10
11
12
13
14
Total
FERC FORM NO.1 (ED. 12-90)Page 326.24
.............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PaeifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) ñA Resubmission 04/0312008
ru ''"' "''inCfI ecouR\~~~~) (Continued)
ne udina Dower exe 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 billng demand in column (d), the average monthly non-eincident 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 covere 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 Woo
Purchased MegaWatt Hours MegaWatt Hours Demand Chargs ~~~~.T~~~No.Recived Delivered ~l ~$~ ($) of Selement ($)
(g)(h)(i)k (i) (m)
26,551 12,957 1,60,537 1
2
-3,88E 3
4
5
6
7
8
9
10
11
12
13
14
13,186,772 9,646,44 8,978,368 121,808,55C 2,308,732,36 -1,66,801,949 763,738,961
FERC FORM NO. 1 (ED. 12-90)Page 327.24
.....................I.I...I.I...........I.i.......
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
Line No.: 2 Column: i
Line No.: 3 Column: b
Column: i
Column: i
Column:b
Column: i
Line No.: 14 Column: i
Column:b
Column: i
Line No.: 3 Column: i
Line No.: 5 Column: i
Line No.: 6 Column: i
n timely notification.
Line No.: 12 Column:b
Line No.: 4 Column: i
Line No.: 6 Column: b
Line No.: 6 Column: i
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 04/03/2008 2007/Q4
FOOTNOTE DATA
Column:b
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.: 2 Column:b
Line No.: 2 Column: i
Line No.: 4 Column:b
Line No.: 4 Column: i
Line No.: 7 Column: b
Line No.: 11 Column: i
Line No.: 2 Column: b
Line No.: 2 Column: i
Column:b
Column:b
Column: i
Page 450.2
......................................
.1.....
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
Column:b
Column: i
Line No.: 9 Column: i
Column:b
Line No.: 1 Column: b
Line No.: 1 Column: i
Line No.: 7 Column: b
Column: i
Line No.: 2 Column: i
Line No.: 6 Column: b
Line No.: 6 Column: i
notification.
Column:b
Column:b
IFERC FORM NO. 1 (ED. 12-87) 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 04/0312008 2007/Q4
FOOTNOTE DATA
located on the Lewis River in the state of Washington.
Line No.: 4 Column: b
eeinnt subject to termnation u on tily notication.
the Hermiston Plant, which is jointly owned.
page 402.3 column (c) of this Form No. 1 for
charges and commtt settements.
the Hermiston Plant, which is jointly owned.
page 402.3 column (c) of this Form No. 1 for
Line No.: 8 Column: i
ro. ect in Idaho Falls, Idaho.
Column: i
Line No.: 1 Column: i
Line No.: 4 Column: i
IFERC FORM NO.1 (ED. 12-07) 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 040312008 2007/Q4
FOOTNOTE DATA
Line No.: 5 Column: b
Line No.: 5 Column: i
Line No.: 6 Column: i
Column: i
Column:b
Column: i
Line No.: 13 Column: i
Column:b
Column: i I
Line No.: 1 Column: i I
I
Line No.: 13 Column: i
Line No.: 1 Column: i
Column: I
Line No.: 9 Column: i
Line No.: 12 Column: i
Line No.: 5 Column: b
Column: i
Column: i
IFERC FORM NO.1 (ED. 12-87) Page 450.5
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
Column:b
notification.
Line No.: 14 Column: i
Line No.: 1 Column: i
Line No.: 2 Column: b
Line No.: 2 Column: i
Line No.: 3 Column: b
Column: i
Line No.: 6 Column: i
notification.
Column: i
Line No.: 12 Column: i
Column:b
on.
Line No.: 1 Column: i
Column:b
Column: b
Column: i
Page 450.6
Availabilt re uIrement shortfall.
Schedule Pa e: 326.14 Line No.: 12 Column: b
Settement adjustment.
¡Schedule Page: 326.14 Line No.: 12 Column: i
Settlement adjustment.
¡Schedule Page: 326.15 Line No.: 1 Column: b
Settlement adjustmnt.
¡Schedule Page: 326.15 Line No.: 1 Column: i
Settlement adjustment.
f$chedule Page: 326.15 Line No.: 2 Column: b
Sacramento Municipal Utility Distrct - Contract Termnation Date: December 31,2014.
!Schedule Page: 326.15 Line No.: 4 Column: b
Settlement adjustment.
IGchedule Page: 326.15 Line No.: 4 Column: i
Line loss.
¡Schedule Page: 326.15 Line No.: 5 Column: b
Seconda, economy and/or non-firm.
fShedule Paae: 326.15 Line No.: 5 Column: i
Oprating reserves.
rSchedule Page: 326.15 Line No.: 6 Column: i
Line loss.
!Schedule Page: 326.15 Line No.: 10 Column: i
Damages for non-delivery of eneration.
Schedule Pa e: 326.15 Line No.: 11 Column: b
Secon ,econom and/or non-fi.
Schedule Pa e: 326.15 Line No.: 11 Column: i
Load curtilment.
¡Schedule Page: 326.15 Line No.: 12 Column: i
Reserve Share.
!Schedule Page: 326.15 Line No.: 14 Column: b
Settlement adjustment.
!Schedule Page: 326.15 Line No.: 14 Column: i
Settlement adjustment.
!Schedule Page: 326.16 Line No.: 1 Column: b
Seconda, econom and/or non-firm.
chedule Page: 326.16 Line No.: 2 Column: i
Financial Swap.
!Schedule Page: 326.16 Line No.: 4 Column: b
Settement ad. ustment.
chedule Pa e: 326.16 Line No.: 4 Column: i
Settement adjustment.
!Schedule Page: 326.16 Line No.: 5 Column: i
Reserve share and line loss.
!Schedule Page: 326.16 Line No.: 6 Column: b
Settlement adjustmnt.
¡Schedule Page: 326.16 Line No.: 6 Column: i
Load curlment.
¡Schedule Page: 326.16 Line No.: 8 Column: b
Second , economy and/or non-firm.
Schedule Pa e: 326.16 Line No.: 8 Column: i
Load curlment.
I
I
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 0410312008 2007/Q4
FOOTNOTE DATA
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 04/0312008 2007/Q4
FOOTNOTE OAT A
Line No.: 9 Column: b
Line No.: 9 Column: i
Column:b
notification.
Line No.: 7 Column: b
Line No.: 7 Column: i
Column:b
Column: i
Line No.: 9 Column: i
Column:b
Column:b
Column: i
Column:b
Column:b
Column: i
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 040312008 2007/Q4
FOOTNOTE DATA
Column:b
Column:b
Line No.: 4 Column: I
Line No.: 8 Column: b
Line No.: 8 Column: i
Line No.: 10 Column: b
Line No.: 10 Column: i
Column:b
Column:b
Line No.: 13 Column: i
Line No.: 14 Column: b
Line No.: 2 Column: b
Line No.: 2 Column: i
IFERC FORM NO.1 (EO. 12-87) Page 450.9
-...........................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 20071Q4
FOOTNOTE DATA
Line No.: 3 Column: b
Column: i
Column:b
Line No.: 5 Column: i
Column: i
Column: i
Line No.: 12 Column: i
Line No.: 14 Column: b
Line No.: 5 Column:b
Column: i
Column: i
Column: i
Line No.: 8 Column: i
Line No.: 9 Column: i
Line No.: 12 Column: i
Line No.: 1 Column: i
Line No.: 2 Column: i
Line No.: 3 Column: i
lFERC FORM NO.1 (ED. 12-87) Page 450.10
............................................
Name of Respondent This Report is:Date of Report Year/Penod of Report
(1) X An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 04032008 2oo7/Q4
FOOTNOTE DATA
!Schedule Page: 326.23 Line No.: 4 Column: i
Imbalance energy.
¡Schedule Page: 326.23 Line No.: 5 Column: b
Settement adjustment.
¡Schedule Page: 326.23 Line No.: 5 Column: i
Imbalance ener .
chedule Pa e: 326.23 Line No.: 6 Column: i
Exchan e ener ex nse and imbalance energy.
chedule Pa e: 326.23 Line No.: 7 Column: b
Settement adttment.
ISchedule P,- e: 326.23 Line No.: 7 Column: i
Imbalance ene:.
!Schedule Pa~: 326.23 Line No.: 8 Column: I
Imbalance ener .
Schedule Pa e: 326.23 Line No.: 9 Column: b
Settement adjustment.
¡Schedule Page: 326.23 Line No.: 10 Column: i
Imbalance ene~.
¡Schedule Pa=: 326.23 Line No.: 11 Column: b
Settlement adjustment.
¡Schedule Page: 326.23 Line No.: 11 Column: i
Imbalance ener y.
chedule Pa e: 326.23 Line No.: 12 Column: i
Imbalance ene~.
ISchedule Pay: 326.23 Line No.: 13 Column: b
Settement adjustment.
¡Schedule Page: 326.23 Line No.: 13 Column: i
Imbalance ene~y.
/schedule Pa e: 326.24 Line No.: 1 Column: i
Imbalance ene~y.
/Shedule Pa=e: 326.24 Line No.: 3 Column: b
Not applicable: adjustment for inadvertent interchange.
IFERC FORM NO.1 (ED. 12-S7) Page 450.11
............................................
Blank Page
(Next Page is 328)
Date of Report
(Mo, Da, Yr)
04/03120
ccount4 .Includin transactions referred to as 'wheelin ')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, 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 authorit 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 coe based on the original contractual terms and coditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Name of Respondent
PacifiCorp
Year/Perio of Report
End of 2007/Q4
Line
No.
Payment By
(Company of Public Authori)
(Footnote Affiliation)
(a)
1 Basin Elecric Power Corative
2 Bain Electric Power Coperatie
3 Basin Elecric Power Coperative
4 Bain Electric Power Cooperative
5 Bain Elecric Power Coperative
6 Basin Elecric Power Coperative
7 Bear Energy, LP
8 Black Hils Power & Light Copay
9 Black Hils Power & Light Company
10 Black Hils Power & Light Compay
11 Black Hils Power & Light Company
12 Black Hils Power & Liht Compay
13 Black Hills Power & Liht Compay
14 Black Hils Power & Light Compay
15 Bonnevile Power Administration
16 Bonnevile Power Administration
17 Bonnevile Power Administratin
18 Bonneville Power Administration
19 Bonnevile Power Administration
20 Bonnevile Power Administration
21 Bonneville Power Administration
22 Bonnevile Power Administration
23 Bonnevile Power Administration
24 Bonneville Power Administration
25 Bonnevile Power Administration
26 Bonneville Power Administratio
27 Bonevile Power Administration
28 Bonneville Power Administration
29 Bonnevile Power Administration
Energy Recived From
(Company of Public Authori)(Fooe Aflition)
(b)
Westem Ar Power Admini
Wester Ar Power Admini
Westem Are Power Admini
Western Area Power Admini
PaciCorp Merct
PacifCorp Merchant
PaciCorp Merct
PacifCorp Merchant
Boneville Power Administration
Bonnevile Power Administration
Bonnevile Power Administration
Bonevile Power Administration
Bonnevile Power Administration
Bonneville Power Administraton
U.S. Bureau of Reclamation
U.S. Bureau of Reclamation
Boneville Power Adminisrati
Bonnevile Power Adinistratin
Boneville Power Administratio
Bonneville Power Administration
Bonneville Power Administration
Bonnevile Power Administration
30 BP Energy
31 cargill-Amant, LLC
32 Cargil-Amant, LLC
33 Cargil-Amant, LLC
34 CitiGroup Energy Inc,
TOTAL
Energy Delivered To
(Company of Public Authori)
(Foonote Affiliation)
(c)
Powder River Energy Corp.
Power River Energy Corp.
Powder River Energ Corp.
Powr River Energy Corp.
Monta-Dakota Utilities
Monta-Dakota Utilties
Black Hils Power & Light Com
Black Hills Power & Light Com
Bonnevile Power Administration
Bonneville Power Adinistratin
Bonneville Power Administration
Bonnevile Power Administration
Umpqua Indian Utility Cooperative
Umpqua Indian Utilty Cooperative
Bonnevile Power Administration
Bonevile Power Administration
Boneville Power Administration
Boneville Power Administration
Yakaa Power
Yakma Power
Bonnevile Power Administration
Bonneville Power Administration
Statisticl
Clasifi-cati
(d)
FERC FORM NO.1 (ED. 12-90)Page 328
............................................
............................................
Name of Respondent This 'O0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) nA Resubmission 04/0312008
i I QfREHlylI y i-YH '- i Mt:H~.(Jl ccount 456)(COntlnUec)(Includina transactions reftered to as 'wtieelina')
5. In column (e), identify the FERC Rate Schedule or Tarif 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 0) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY UneSchedule of (Substation or Other (Substation or Other Demand MegaWatt HOUrs IWl(taWattHörs No.Tari Number Designatin)Deignation)(MW)Reeived Deltrre(e)(f)(g)(h)
7V11-3 Yellowtil Sub.Sherida Sub.10 62,432 62,43 1
7V11-3 Yellowtail Sub.Sheridan Sub.4,491 4,491 2
7V11.3 Yellowtail Sub.Sherin Sub.S 51,767 51,76 3
7V11-3 Yellowtil Sub.Sheridan Sub.5,206 5,2OE 4
7V11-8 Various Varius 20,04 20,04E 5
7V11-8 Varius Various 415 41E 6
7V11-8 Various Various 8 e 7
7V11-7 72,00 72,OO 8
7V11-8 3,675 3,67E 9
7V11.8 14,339 14,33~10
7V11 Various Sherin Sub.40 28,30 28,3O~11
7V11 Various Sheridan Sub.98,097 98,091 12
7V11-7 Various WyoakSub.50 10,640 10,64 13
7V11-7 Various WyokSub.166,857 166,85 14
237 Various Various 31C 1,542,691 1,542,691 15
237 Various Various ..16
324 Lost Creek Hydro Variou 263,967 263,96 17
324 Lost Creek Hydro Various 18
7V11-3 azeySub.3 21,875 21,87E 19
7V11-3 GazeySub.2,209 2,20~20
7V11.7 USBR Green Spring 18 60,818 6O,81e 21
7V11-7 USBR Green Spring 2,148 2,1M:22
368 Malin Sub.Malin Sub.102 686,513 686,51~23
368 ___r-24
7V11.3 White Swanfoppeni 7 33,148 33,1M:25
7V11-3 White SwanfToppeni 3,108 3,101 26
299 Various Various 221 1,608,200 1,608,20(27
299 Various Various 28
7V11-7 3,77 3,m 29
7V11 30
7V11-8 665,722 665,72~31
7V11-8 4,901 4,901 32
7V11-7 168,829 168,82~33
7V11.8 1,44 1,44 34
2,382 16,933,144 16,933,1~
FERC FORM NO.1 (ED. 12-90)Page 329
Blank Page
............................................
(Next Page is 330)
............................................
Date of Report
(Mo, Da, Yr)
04/0312008
ccount 4 6Includin transactions reftered to as 'w eelin ')
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 Usted 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 service
rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmission Delivered for annual report
purpses only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
Year/Period of Report
End of 2oo7/Q4
Name of Respondent
PacifiCorp
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERSEnergy Charge (Other Charges)($) ($)(I) (m)Total Revenues ($) me
(k+i+m) No.
(n)
170,349 1
13,404 2
162,602 3
12,696 4
151,276 5
2,46 6
47 7
54,102 8
23,512 9
87,059 10
99,44 11
549,228 12
13
1,148,175 14
4,04,557 15
340,897 16
286,253 17
26,023 18
34,178 19
-217,918 20
40,950 21
36,45 22
230,895 23
19,421 24
88,317 25
-54,595 26
2,066,279 27
184,843 28
23,706 29
-38,250 30
3,829,527 31
36,554 32
1,217,058 33
14,694 34
56,22,453
143,329
162,602
99,44
499,506
1,113,75
3,976,61
38,268
40,950
3,829,527
1,217,058
14,694
25,870,980 21,508,540 8,84,933
FERC FORM NO.1 (ED. 12-90)Page 330
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)040300ccnt .1Includin transactions referred to as 'wheelin i
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilties, cooperatives, other public authorities,
qualifying facilities, non-traditional utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Servce, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of coes.
Year/Period of Report
End of 2007/04
Line
No.
Payment By
(Company of Public Authori)
(Footnote Affliation)
(a)
Statistical
Classifi-
cation
(d)
Energy Received Fro
(Company of Public Authori)
(Foonote Affilation)
(b)
Energy Delivered To
(Company of Public Authori)
(Foonote Affliatio)
(c)
Conoco Inc.
2 Coral Power
3 Cowlit County PUD
4 Cowlitz County PUD
5 Deseret Generation & Transmission
6 Deseret Generation & Transmission
7 Deseret Generation & Transmission
8 Eugene Water & Electric Board
9 Eugene Water & Electric Board
10 Eugene Water & Elecric Board
11 Eugene Water & Electric Board
12 Fall River Rural Electric Coop.
13 Fall River Rural Electric Coop.
14 Flathead Elecri Coorative Inc.
15 Flathead Elecric Cooperative Inc.
16 Idao Power Company
17 Idaho Power Company
18 Idaho Power Company
19 Idaho Power Compay
20 Idaho Power Company
21 Idaho Power Company
22 Idaho Power Company
23 Idaho Power Company
24 Idaho Power Company
25 JPM Ventures Energy
26 Moon Lake Electric Association
27 Moon Lake Electric Assocation
28 Municipal Energy Agency of Nebraka
29 Morgan Stanley Caitl Group, Inc.
30 Morgan Stanley Capital Group, Inc.
31 Morgan Stanley Capital Group, Inc.
32 Pacific Gas & Elecric
33 Pacific Gas & Elecric
34 PPM Energy Inc.
Maryville Hydro Parters
Maryvile Hydro Parters
Western Area Power Administrati
Western Area Power Adminitra
Nevada Poer Copay
Idaho Power Company
Ida Power Company
Flathead Electric Coop., Inc.
Flathead Elecri Coop., Inc.
Idao Power Compay
TOTAL
FERC FORM NO.1 (ED. 12-9)Page 328.1
............................................
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FîA Resubmission 04/0312008
1 IOF .1 Y i-YH q I Ht:H.~ ,(Jlccount 456)(Contlhued)
(Includincitransactions reftered to as 'wlieelinciõ)"
5. In column (e), identify the FERC Rate Schedule or Tanff 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 appropnate 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 0) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LinSchedule of (Subsatation or Other (Substation or Other Demand
Meawatt HOUrs Me_awatt Hours No.Tari Number Designation)Designation)(MW)Re1f)ived DeI~rred(e)(f)(g)(h)
7V11-8 Various 328 32E 1
7V11-8 Various 703 70~2
234 Swif Unit NO.2 Wooland Sub.3
234 Swif Unit No. 2 Wooland Sub.4
7V11-7 5
280 Various Various 105 1,539,792 1,539,79:6
280 Varius Various 105 146,652 146,65~7
7V11-5,7 Tieton Sub. Various 15 52,264 52,26A 8
7V11-5 Tieton Sub. Various 9
7V11-8 3,055 3,05f 10
7V11-7 14,06 14,Q6 11
32 Targhee Sub.Goshen Sub. 9 12
322 Targhee Sub.Goshen Sub.13
7V11-3 Yellowtil Sub.Various 1 4,381 4,381 14
7V11-3 Yellowtail Sub.Various 518 51E 15
7V11-7 24,626 24,621 16
7V11-7 281,725 281,721 17
7V11-7 3,696 3,691 18
7V11-8 318,63 318,63(19
7V11-8 8,872 8,87.20
257 Antelope Sub.Antelope Sub.21
257 Antelope Sub.Antel Sub.22
203 Jim Bridger Sub.Bridger Pump Station 23
203 Jim Briger Sub.Bridger Pump Station 24
7V11-8 11 11 25
302 Duchesne Duchesne S 12,715 12,71f 26
302 Duchesne Duchesne 3 1,050 1,05C 27
7V11-8 1,117 1,111 28
7V11-7 200 20(29
7V11-8 66,370 66,37(30
7V11-8 53,971 53,971 31
86 Malin Sub.Indian Springs 32
298 Sigurd-Glen Canyon Pinto-Four Comers 33
7V11-8 261,734 261,731 34
2,382 16,933,144 16,933,144
FERCFORM NO.1 (ED. 12-90)Page 329.1
Blank Page
............................................
(Next Page is 330.1)
............................................
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/0312008
YearlPeriod of Report
End of 2007/Q4
ccount ntinue
(Includin transactions reftered to as eelin ')
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 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 providé explanations following all required data.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energy Charges (Other Charges)($) ($)(I) (m)
2,359
7,318
2,359 1
7,318 2
90,578 3
8,228 4
28,020 5
3,44,932 6
370,018 7
372,103 8
34,591 9
15,84 10
30,468 11
138,701 12
12,609 13
37,197 14
3,101 15
759,375 16
1,123,794 17
16,647 18
1,752,341 19
54,732 20
67,672 21
6,152 22
14,927 23
1,357 24
82 25
17,726 26
1,64 27
6,757 28
4,888 29
457,424 30
343,181 31
237,50 32
369,620 33
2,60,n5 34
Total Revenues ($) e
(k+I+m) No.
(n)
90,578
1,709,985
28,020
33,125
15,84
30,468
10,834
759,375
1,123,794
1,752,341
82
8,07
6,757
4,88
457,424
268,547
2,600,n5
25,870,980 21,50,54 8,84,933 56,223,453
FERC FORM NO.1 (ED. 12-90)Page 330.1
Name of Respondent
PacifiCorp
This ~ort Is:
(1) I!An Oriina
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/0312008
ccount
(Includin transactis referred to as 'wheelin ')
1. Report all transmission of electricity, Le., wheeling, provided for other elecric 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 authori 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 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 service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of coes.
Year/Period of Report
End of 2007/04
Line
No.
Payment By
(Copany of Public Auri)
(Footnote Affiliatio)
(a)
Statistical
Classif-
cation
(d)
Energ Recived From
(Compay of Public Auhori)(Footne Afia)
(b)
Energ Delivered To
(Copany of Public Authority)
(Footnote Affilatin)
(c)
1 PPM Energ Inc.
2 PPM Energy Inc.
3 PPM Energy Inc.
4 PPM Energy Inc.
5 PPM Energy Inc.
6 PPM Energy Inc.
7 PPM Energy Inc.
8 Portland General Elecric
9 Portnd General Elecric
10 Powerex
11 Powerex
12 Powerex
13 Powerex
14 Powerex
15 Powerex
16 Powder River Energy Corpration
17 PPL Montana, LLC
18 PPL Montana, LLC
19 Public Service Compay of Colorado
20 Rainbow Energy Marketing
21 Rainbow Energy Marketing
22 Rainbow Energy Marketing
23 San Diego Gas & Elecric
24 Seattle City & Light
25 Seawest Windpower, Inc.
26 Seawest Windpower, Inc.
27 Sempra Energy Trading Co
28 Sempra Energy Trading Co
29 Sempra Energy Trading Co
30 Sempra Energy Solutions
31 Sempra Energy Solutions
32 Sierra Pacific Power Copany
33 Sierra Pacific Power Compay
34 Sierra Pacific Power Copay
Stateline Wind
Stateline Wind
Uinta
Uinta
Exxon Mobile
Exxon Mobile
Stateline Wind
Stateline Wind
Uinta
Uint
Nevada/Los Angeles
Nevada/Los Angeles
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.2
............................................
............................................
Name of Respondent This~rtIS:Date of Reprt Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) riA Resubmission 04/03/208
,:-.~ccount 456J(l,ontlnueaJ
(Including transactions reftered to as 'wtieelingf
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Recipt Point of Delivery Biling TRANSFER OF ENERGY UneSchedule of (Subsatation or Other (Substation or Other Demand Megawatt MOUrs MegawattHClrs No.Tari Number Deignation)Designatio)(MW)Recived Delivere
(e)(1)(g)(h)(i)0)
7V11-8 32,852 32,85.1
7V11-5 2
7V11-5 3
7V11-5 4
7V11-5 5
7V11-7 ~""Ali.'SUb.75 324,412 324,41~6
7V11-7 HarrAllenlMona Sub.27,68 27,~7
7V11-8 3,46 3,46C 8
7V11-8 25 2!9
7V11-7 ~WaeJcS"b.80 256,839 256,83~10
7V11-7 Wee Jet. Sub.28,022 28,02~11
7V11-8 475,567 475,56,12
7V11-8 13,831 13,831 13
7V11-7 138,33 138,33 14
7V11-7 1,5n 1,57i 15
59 Various Bufalo Sub.16
7V11-8 23,695 23,69!17
7V11-8 2,97£2,97E 18
7V11-8 53,695 53,695 19
7V11-7 53,362 53,36 20
7V11-8 10,252 10,25:1 21
7V11-8 2,05 2,056 22
86 Malin Sub.Indian Springs 23
7V11-7 WallulaSub.Mid-C 24
264 Foote Creek Sub.25
264 Foote Creek Sub.26
1V11-8 18,257 18,25 27
7V11-8 23,090 23,09 28
7V11-7 10,753 10,75~29
7V11-3 Various 17 102,949 102,94~30
7V11-3 Various 9,09 9,()31
7V11-8 219,861 219,861 32
7V11-8 29,492 29,49~33
7V11-7 675,819 675,8H 34
2,38 16,933,144 16,933,140
FERC FORM NO.1 (ED. 12-90)Page 329.2
Blank Page
............................................
(Next Page is 330.2)
-...........................................
Date of Report
(Mo, Da, Yr)
04/03/2008
ccount4Includin transactions reftered to as 'w eelin '
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 tye 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 16and 17, respectively.
11. Footnote entries and provide explanations following all required data.
Year/Period of Report
End of 2007/Q4
Name of Respondent
PacifCorp
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energy Charges (Other Charges)($) ($)(I) (m)Tot Revenues ($) ine
(k+I+m) No.
(n)
253,200 1
58,049 2
-76,832 3
231,949 4
26,589 5
1,670,625 6
151,875 7
28,175 8
146 9
1,447,875 10
131,625 11
3,272.638 12
85,997 13
852,84 14
4,742 15
175 16
143,122 17
17,3e 18
459,684 19
254,823 20
63,052 21
11,166 22
33,249 23
212,625 24
42,871 25
3,897 26
89,056 27
122,828 28
74,574 29
145,54 30
11,273 31
1,015,403 32
133,402 33
2,421,64 34
56,223,453
1,670,625
1,447,87
212,625
127,932
1,015,403
2,421,645
25,870,980 21,50,540 8,843,933
FERC FORM NO.1 (ED. 12-90)Page 33.2
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2007/04
(Includin tractions referred to as 'wheelin ')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilties, coperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authori. 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 Classifiction code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this coe
for any accunting 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.
Payment By
(Copany of Public Autri)
(Footnote Affliation)
(a)
1 Sierra Pacific Power Company
2 Southern Califorinia Edison Company
3 Southern Califorinia Edison Company
4 State of South Dakota
5 State of South Dakota
6 TransAlta Energy
7 TrasAlta Energy
8 Tri-State Generation & Transmissio
9 Tn-State Generation & Trasmision
10 Tri-State Generation & Transmission
11 Tri-State Generation & Transmission
12 United States Bureau of Reclamation
13 United States Bureau of Reclamation
14 United States Bureau of Reclamation
15 United States Bureau of Reclamation
16 Utah Asociated Municipa Power
17 Utah Associated Municipa Power
18 Utah Municipal Power Agency
19 Utah Municipal Power Agency
20 War Springs Power Enterprises
21 Warm Springs Power Enterprises
22 Western Area Power Administration
23 Western Area Power Administration
24 Western Area Power Administration
25 Western Area Power Administration
26 Western Area Power Administration
27 Western Area Power Administration
28 Weyerheuser Company
29
Energy Recived Fro
(Copa of Public Auri)
(Fooe Afliaon)
(b)
Energy Delivered To
(Compay of Public Authori)
(Footnote Affliatin)
(c)
Statistical
Classifi-
caion
(d)
Une
No.
Bonnevile Power Administration
Bonnevile Power Administration
Bonnevile Power Administration
Bonneville Power Administraion
Utah Associated Municipal Power
Uth Associated Municipa Power
Uta Municipal Power Agcy
Ut Municipal Power Agency
Warm Sprng Enterpries
Warm Springs Enterpses
Western Area Power Adinistration
Western Area Power Administration
Western Area Power Administration
Western Area Power Administration
Western Area Power Administration
Western Area Power Administration
Weyerhaeuser Company
U.S. Bureau of Reclamation
U.S. Bureau of Reclamation
Croked River Irrgation Distri
U.S. Bureau of Reclamation
Utah Associated Municipal Power
Utah Associated Municipal Power
Ut Municipa Power Agency
Utah Municipal Power Agency
Portland Genera Elecric Co.
Portland General Elecric Co.
Various WAPA Customers in PACE
Various WAPA Customers in PACE
Various WAPA Customers in PACE
Various WAPA Customers in PACE
Western Area Power Administratio
Western Area Power Administratio
Bonevlle Power Administration
30 Accrual true-up
31
32
33
34
TOTAL
FERC FORM NO.1 (ED. 12-9)Page 328.3
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) DA Resubmission 0403/2008
i , ~!" l:L.l:L; i MI.~II T i-YH '- i nt:M.~..l ccount 4b6J\L;ontlnUeO¡(Including transactions reffered to as 'wfieeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERCrate 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 u) the total megawatthours received and delivered.
FERCRate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY UneSchedule of (Subsatatin or Other (Substation or Other Demand Megwatt MOUI'Megwatt Hours No.Tari Number Designation)Designation)(MW)Received Dei~rred
(e)(f)(g)(h)(i)
7V11.7 12,40 12,40 1
86 Malin Sub. Indian Springs 2
298 3
7V11.7 Yellowtail Sub.WyokSub.A 16,760 16,76C 4
7V11-7 Yellowail Sub.WyoakSub.1,517 1,511 5
7V11-8 100 10C 6
7V11-8 7
123 Various Various 31 151,795 151,79f 8
123 15,553 15,55~9
7V11-8 35,54 35,54E 10
7V11-8 550 55(11
35 Franklin Sub.Burbnk . Pumps 29,41C 29,41 ( 12
35 Franklin Sub.Burbnk Pumps n2 n:13
67 Redmond Sub.Crooked River Pump 11,298 11,291 14
67 Pasco Sub. Dodd Road Sub.15
297 Various Various 338 2,991,342 2,991,34:16
297 Various Various 278,500 278,50(17
279 Varius Varius 109 557,139 557,13!18
279 Various Various 46,827 46,82 19
591 Pelton Reregulaton Round Bute Sub.16 76,149 76,14~20
591 Pelton Reregulation Round Bute Sub.8,219 8,2H 21
262,26 Various Various 328 1,548,722 1,548,72~22
262,263 Various Various 328 149,486 149,48 23
7V11.8 Varius Various 27,424 27,42A 24
7V11.8 Varius Various 2,90 2,90!25
7V11 Wyoing Distributio Wyoing Distribuion 1 6,350 6,35C 26
7V11 Wyoing Distribution 3 :i 27
32O,7V11-3 Westem Kraft Sub.Alvey Sub. 45 22,317 22,311 28
29
30
31
32
33
34
2,38 16,933,144 16,93,140
FERC FORM NO.1 (ED. 12-90)Page 32.3
Blank Page
............................................
(Next Page is 330.3)
-...........................................
Name of Respondent
PacifiCorp
This ~ort Is:
(1) IlAn Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/031008
ccount45(Includin transactions reftered to as 'w eelin ')
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 Q) 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.
Year/Period of Report
End of 2007/Q4
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICIT FOR OTHERSEnergy Charg (Other Charges)($) ($)(I) (m)Total Revenues ($) ine
(k+I+I) No.
(n)
51,150 1
204,248 2
369,620 3
89,100 4
8,100 5
584 6
99 7
91,107 8
1,145 9
256,749 10
13,432 11
29,410 12
772 13
11,407 14
2,669 15
7,174,814 16
1,061,852 17
2,210,989 18
194,599 19
109,725 20
9,975 21
2,594,313 22
230,780 23
405,057 24
60,035 25
16.932 26
~31.111 27
-382,64 28
29
80,425 30
31
32
33
34
56,223,453
89,1
584
91,107
29,410
9,915 911
6,875,087
2,112,594
109,725
2,593,313
405,057
19,
25,870,980 21,508,540 8,84,933
FERC FORM NO.1 (ED. 12-90)Page 330.3
aries and points.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 0410312008 2007/Q4
FOOTNOTE DATA
Line No.: 4 Column: m
n Access Transmission Tarff between varous
n Access Transmission Tarff between varous
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 04/03/2008 2007/Q4
FOOTNOTE DATA
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328 Line No.: 10 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328 Line No.: 10 Column: d
Non-Firm or Short-Term Fin Transmission Service under the 0 en Access Transmission Tariff between various pares and
chedule Pa e: 328 Line No.: 10 Column: m
December 200 Service.
¡Schedule Page: 328 Line No.: 11 Column: d
Network Transmission Service under the 0 en Access Transmission Tariff (S.A. 347) termnatin on December 31, 2017.chedule Pa e: 328 Line No.: 12 Column: d
Network Transmission Service under the 0 en Access Transmission Tarff (S.A. 347 on December 31,2017.
Schedule Pa e: 328 Line No.: 12 Column: m
Decmber 200 Service.
¡Schedule Page: 328 Line No.: 13 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tarff (S.A. 67) termnatin on December 31,2023.
Schedule Pa e: 328 Line No.: 14 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tarff (S.A. 67) termnating on December 31, 2023.
I§hedule Page: 328 Line No.: 14 Column: m
December 2006 Service.
¡Schedule Page: 328 Line No.: 15 Column: d
General Transfer A eement for network service in PACW. Ever een.
chedule Pa e: 328 Line No.: 15 Column: m
Demand dollar Ius a fixed cost calculate usin lant investment values at varous U.S. overnent facilties.
Schedule Pa e: 328 Line No.: 16 Column: d
General Transfer Agreement for network service in PACW. Ever een.
Schedule Pa e: 328 Line No.: 16 Column: m
Demand dollars plus a fixed cost calculated using plant investment values at varous U.S. governent facilties. December 200
Service.
¡Schedule Page: 328 Line No.: 17 Column: d
Network Transmission Service termnating on October 31,2008.
¡Schedule Page: 328 Line No.: 17 Column: m
Demand dollars Ius a fixed cost calculated usin lant investment values at varous U.S. overnent facilities.
chedule Pa e: 328 Line No.: 18 Column: d
Network Transmission Service termnating on October 31, 2008.
!Schedule Page: 328 Line No.: 18 Column: m
Demand dollars plus a fixed cost calculated using plant investment values at varous U.S. government facilties. December 2006
Service.
¡Schedule Page: 328 Line No.: 19 Column: d
Network Transmission Service and Distrbution Delivery Service under the Opn Access Transmission Tarff (S.A. 229) termnating
on September 30, 2011.
¡Schedule Page: 328 Line No.: 19 Column: f
Bonnevile Power Administration.
¡Schedule Page: 328 Line No.: 19 Column: m
Distrbution Service Charge. Primar Delivery Service. Regulation & Frequency Response. Prma Delivery & Distrbution Services
REFUD.
¡SChedule Page: 328 Line No.: 20 Column: d
Network Transmission Service and Distrbution Delivery Service under the Open Access Transmission Tarff (S.A. 229) termnating
on September 30,2011.
¡Schedule Page: 328 Line No.: 20 Column: f
Bonnevile Power Administration.¡Schedule Page: 328 Line No.: 20 Column: m I
Distribution Service Charge. Prmar Delivery Service. Regulation & Frequency Response. December 200 Service. Prmar Delivery
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 (2) A Resubmission 04/03/2008 2007104
FOOTNOTE DATA
& Distribution Services REFU.
I$chedule Page: 328 Line No.: 21 Column: d
Point-to-Point Transmission Service under the 0 en Access Transmission Tarff (S.A. 179) termnating on Se tember 30, 2025.
chedule Pa e: 328 Line No.: 21 Column:
Bonnevile Power Administration.
!Schedule Page: 328 Line No.: 22 Column: d
Point-to-Point Transmission Service under the 0 en Access Transmission Tarff (S.A. 179) termnatin
Schedule Pa e: 328 Line No.: 22 Column:
Bonnevile Power Administration.
¡shedule Page: 328 Line No.: 22 Column: m
December 200 Service.
¡Schedule Page: 328 Line No.: 23 Column: d
Use of Facilties Agreement for the Maln Transformer under the AC Interte Agreement with BPA date June 1, 1994. Subject to
termnation upon mutual agreement.
!Schedule Page: 328 Line No.: 23 Column: m
Sole use of facilties charge.
!Šchedule Page: 328 Line No.: 24 Column: d
Use of Facilities Agreement for the Maln Transformer under the AC Interte Agreement with BPA dated June 1, 1994. Subject to
termnation u on mutual agreement.
Schedule Pa e: 328 Line No.: 24 Column: m
Sole use of facilties chage. December 200 Service.
¡Schedule Page: 328 Line No.: 25 Column: d
Network Transmission Service and Distrbution Delivery Service under th Opn Access Transmission Tarff (S.A. 328) termnating
on September 30, 2008.
!Schedule Page: 328 Line No.: 25 Column: f
Bonneville Power Administration.
!Schedule Page: 328 Line No.: 25 Column: m
Distrbution Service Charge. Prmar Delivery Servce. Regulation & Frequency Response. Deposit Refund. Prima Delivery &
Distribution Services REFU. Penal revenues coverin imbalance char es er Schedules 4 and 9.
Schedule Pa e: 328 Line No.: 26 Column: d
Network Transmission Service and Distrbution Delivery Servce under th Open Access Transmission Tarff (S.A. 328) termnating
on Se tember 30, 2008.
chedule Pa e: 328 Line No.: 26 Column: f
Bonnevile Power Administration.!Schedule Page: 328 Line No.: 26 Column: m I
Distribution Service Charge. Pr Delivery Service. Regulation & Freuency Response. Deember 2006 Service. Prar Delivery
& Distrbution Services REFU.
I$chedule Page: 328 Line No.: 27 Column: d
General Transfer Agreement for network service in PAæ. Evergrn.
!Schedule Page: 328 Line No.: 27 Column: m
Sole use of facilties cha e. Cha es for monitorin , schedulin , load followin
Schedule Pa e: 328 Line No.: 28 Column: d
General Transfer A eement for network service in PACE. Evergreen.
chedule Page: 328 Line No.: 28 Column: m
Sole use of facilties char e. Char es for monitorin , schedulin ,load followin reserve. December 200 Service.
chedule Pa e: 328 Line No.: 29 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!Scheduie Page: 328 Line No.: 29 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Trasmission Tar.
!SChedule Page: 328 Line No.: 29 Column: d
Non-Firm or Short-Term Fir Transmission Service under the 0 en Access Transmission Tarff between varousSchedule Pa e: 328 Line No.: 29 Column: m
IFERC FORM NO.1 (ED. 12-87) Page 450.3
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
FOOTNOTE DATA
December 2006 Service.
¡Schedule Page: 328 Line No.: 30 Column: b
Various si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Page: 328 Line No.: 30 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328 Line No.: 30 Column: d
Non-Fir or Short-Term Firm Transmission Service under the 0 en Access Transmission Tariff between varous
chedule Page: 328 Line No.: 30 Column: m
Pri Delive & Distribution Services REFU.
Schedule Pa e: 328 Line No.: 31 Column: b
Varous si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Pa e: 328 Line No.: 31 Column: c
Varous si natories to the 7th Revised Volume IIPoint-to-Point Transmssion Tarff.
chedule Pa e: 328 Line No.: 31 Column: d
Non-Fir or Short-Term Firm Transmission Service under the 0 n Access Transmission Tarff between varous
Schedule Pa e: 328 Line No.: 32 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!Schedule Page: 328 Line No.: 32 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Shedule Page: 328 Line No.: 32 Column: d
Non-Fir or Short-Term Firm Transmission Service under the en Access Transmission Tariff between varous
Schedule Pa e: 328 Line No.: 32 Column: m
December 200 Service.
!Schedule Page: 328 Line No.: 33 Column: b
Various si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Pa e: 328 Line No.: 33 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡SChedule Page: 328 Line No.: 33 Column: d
Non-Firm or Short-Term Firm Transmission Service under the en Access Transmission Tarff between various
Schedule Page: 328 Line No.: 34 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328 Line No.: 34 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328 Line No.: 34 Column: d
Non-Firm or Short-Term Fir Transmission Service under the 0 n Access Transmission Tarff between varous pares and
Schedule Pa e: 328.1 Line No.: 1 Column: b
Various si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Pa e: 328.1 Line No.: 1 Column: c
Varous si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Pa e: 328.1 Line No.: 1 Column: d
Non-Firm or Short-Term Firm Transmission Service under the 0 n Access Transmission Tarff between varous pares and
Schedule Page: 328.1 Line No.: 2 Column: b
Various si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Pa e: 328.1 Line No.: 2 Column: c
Various si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Pa e: 328.1 Line No.: 2 Column: d
Non-Firm or Short-Term Firm Transmission Servce under the 0 en Access Transmission Tariff between varous
chedule Pa e: 328.1 Line No.: 3 Column: d
Agreement providing for transmission and operation of Cowlitz' Swift 2 Hydro Generation. Payment is for 26% of annual costs of
Swift-Cowlitz Transmission Line. A eement is for the life of Swift Unit No.2.
chedule Pa e: 328.1 Line No.: 4 Column: d
Agreement providing for transmission and operation of Cowlitz' Swift 2 Hydro Generation. Payment is for 26% of annual costs of
IFERC FORM NO.1 (ED. 12-87) Page 450.4
............................................
Name of Respondent This Report is:Date of Report Yea~Period of Report
(1) 2i An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 0403/2008 2007/Q4
FOOTNOTE DATA
July 1, 2008.
1,2008.
en Access Transmission Tarff between varous
n Access Transmission Tarff between varous
en Access Transmission Tarff (S.A. 227).
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 04/03/2008 2007/Q4
FOOTNOTE DATA
¡Schedule Page: 328.1 Line No.: 15 Column: d
Ever en Network Transmission Service and Distrbution Delivery Service under the Open Access Transmission Tarff (S.A. 227).
Schedule Page: 328.1 Line No.: 15 Column: m
December 2006 Service.
¡Schedule Page: 328.1 Line No.: 16 Column: d
Point-to-Point Transmission Service under the 0 en Access Transmission Tarff (S.A. 212) termnating Ma 31,2009.
Schedule Pa e: 328.1 Line No.: 17 Column: b
Varous si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
Schedule Pa e: 328.1 Line No.: 17 Column: c
Varous si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Pa e: 328.1 Line No.: 17 Column: d
Non-Fir or Short-Term Firm Transmission Service under the 0 n Access Transmission Tariff between varouschedule Pa e: 328.1 Line No.: 18 Column: b
Varous si atories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
hedule Pa e: 328.1 Line No.: 18 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Scheduie Page: 328.1 Line No.: 18 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between varous pares and
chedule Pa e: 328.1 Line No.: 18 Column: m
December2006 Service.
¡Schedule Page: 328.1 Line No.: 19 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 19 Column: c
Varous si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tar.
chedule Pa e: 328.1 Line No.: 19 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between varous ares and points. chedule Pa e: 328.1 Line No.: 20 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarf.
¡Schedule Page: 328.1 Line No.: 20 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Scheduie Page: 328.1 Line No.: 20 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between varous pares and chedule Pa e: 328.1 Line No.: 20 Column: m
December 2006 Service.
¡Schedule Page: 328.1 Line No.: 21 Column: b
Operation, maintenance or facilty lease services with no recipt or delivery of energy.
¡Schedule Page: 328.1 Line No.: 21 Column: c
o eration, maintenance or facility lease services with no receipt or delivery of energy.
chedule Pa : 328.1 Line No.: 21 Column: d
Use of Facilities Agreement - Antelope Substation (S.A. 257) termnating codermnous with the IdaholUSDOE Supply Agreement.
¡Shedule Page: 328.1 Line No.: 21 Column: m
Sole use of facilties chage.
¡Schedule Page: 328.1 Line No.: 22 Column: b
o ration, maintenance or facili lease services with no recei tor delive of energy.
Schedule Pa e: 328.1 Line No.: 22 Column: c
Operation, maintenance or facilty lease services with no receipt or delivery of energy.
¡Schedule Page: 328.1 Line No.: 22 Column: d
Use of Facilities Agreement - Antelope Substation (S.A. 257) termnating codermnous with the IdaholUSDOE Supply Agrment.
¡Schedule Page: 328.1 Line No.: 22 Column: m
December 2006 Servce.
I$chedule Page: 328.1 Line No.: 23 Column: b
Operation, maintenance or facilty lease servces with no receipt or delivery of energy.
IFERC FORM NO.1 (ED. 12-87) Page 450.6
............................................
Name of Respondent This Report is:Date of Report YearlPenod of Report
(1) K An Original (Mo, Da, Yr)PacifiCorp (2) A Resubmission 04/0312008 2oo7/Q4
FOOTNOTE DATA
of energy.
n 12-month wrtten notice.
n 12-month wrttn notice.
Column:d
eement for network servce in PAæ. Termates in 2047
Column:m
n Accss Transmission Tanff between vanous
IFERC FORM NO.1 (ED. 12-87) 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 04/03/2008 2007/Q4
FOOTNOTE DATA
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between varous pares and points.
¡Schedule Page: 328.1 Line No.: 31 Column: m
December 2006 Service.
!Schedule Page: 328.1 Line No.: 32 Column: b
Operation, maintenance or facilt lease services with no recei t or delive
Schedule Pa e: 328.1 Line No.: 32 Column: c
Operation, maintenance or facilty lease services with no recei t or delivery of ener y.
hedule Pa e: 328.1 Line No.: 32 Column: d
Malin to Indian Springs use of facilties Termnating August 1, 2007. PERC ruled on July 30, 2007, to extend the agreement though
Decmber 200.¡Schedule Page: 328.1 Line No.: 32 Column: m I
Sole use of facilties chage.
ISchedule Page: 328.1 Line No.: 33 Column: b I
Opration, maintenance or facilty lease services with no reeipt or delivery of energy.IScheule Page: 328.1 Line No.: 33. Column: c I
ration, mantenance or facili lease services with no recei t or delive of ener .
chedule Pa e:328.1 Line No.: 33 Column: d
Use of Facilties Agreement - Phase Shiftng Transformers At Sigurd-Glen Canyon 230kv transmission line and Pinto-Four Comers
345kv transmission line (S.A. 298), termnating Febru 12,2020.
chedule Pa e: 328.1 Line No.: 33 Column: m
Demand dollars Ius a fixed cost calculate usin lant investment values at varous U.S. ovemment facilties.
chedule Pa e: 328.1 Line No.: 34 Column: b
Varous signatones to the 7th Revised Volume 1 i Point-to-Point Transmission Tarff.
ISchedule Page: 328.1 Line No.: 34 Column: c
Varous signatones to the 7th Revised Volume 1 i Point-to-Point Transmission Tar.
ISchedule Page: 328.1 Line No.: 34 Column: d
Non-Fir or Short-Term Fir Transmission Service under the n Access Transmission Tariff between various
chedule Pa e: 328.2 Line No.: 1 Column: b
Varous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
ISchedule Page: 328.2 Line No.: 1 Column: c
Varous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.2 Line No.: 1 Column: d
Non-Firm or Short-Term Firm Transmission Service under the en Access Transmission Tarff between varous pares and
Schedule Pa e: 328.2 Line No.: 1 Column: m
December 200 Service.
ISchedule Page: 328.2 Line No.: 2 Column: d
Ancil Servces under th 0 en Access Transmission Tarff (S.A. 313) in effect until su erceded.
Schedule Pa e: 328.2 Line No.: 2 Column: m
Charges for monitoring, scheduling, load following and spinning reserve. Unauthonzed Use of Transmission Service and refunds.
Penal revenues covenn imbalance char es er Schedules 4 and 9.
chedule Pa e: 328.2 Line No.: 3 Column: d
Ancilar Services under the Open Access Transmission Tarff (S.A. 313) in effect unti su rceded.
chedule Pa e: 328.2 Line No.: 3 Column: m
Charges for monitonng, scheduling, load following and spinning reserve. Settlement adjustment. Unauthùnzed Use of Transmission
Service and refunds. December 200 Service.
¡Schedule Page: 328.2 Line No.: 4 Column: d
Ancilar Services under the 0 en Access Transmission Tariff (S.A. 315) in effect until su rceded.
Schedule Pa e: 328.2 Line No.: 4 Column: m
Charges for monitoring, scheduling, load following and spinning reserve. Regulation & Frequency Response. Penalty revenues
covenn imbalance char es er Schedules 4 and 9.
chedule Pa e: 328.2 Line No.: 5 Column: d
Ancilar Services under the Open Access Transmission Tarff (S.A. 315) in effect until superceded.
IFERC FORM NO.1 (ED. 12-87) Page 450.8
¡Schedule Page: 328.2 Line No.: 5 Column: m
December 2006 Service.
¡Schedule Page: 328.2 Line No.: 6 Column: d
Point-to-Point Transmission Service under the en Access Transmission Tarff (S.A. 279). Termnates April 30, 2008
chedule Pa e: 328.2 Line No.: 6 Column: f
Exxon Meteriu; Station.
¡Schedule Pa e: 328.2 Line No.: 7 Column: d
Point-to-Point Transmission Service under th 0 n Access Transmission Tarff (S.A. 279). Termnates A ril 30, 2008
chedule Pa e: 328.2 Line No.: 7 Column: f
Exxon Meterin Station.
chedule Pa e: 328.2 Line No.: 7 Column: m
December 2006 Service.
¡SchedUle Page: 328.2 Line No.: 8 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
~chedule Page: 328.2 Line No.: 8 Column: c
Varous si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
Schedule Pa e: 328.2 Line No.: 8 Column: d
Non-Fin or Short-Term Fin Transmission Servce under the 0 en Access Transmission Tarff between varous
chedule Pa e: 328.2 Line No.: 9 Column: b
Various si atories to the 7th Revised Volume 11 Point-to-Point Trasmission Tarff.
chedule Pa e: 328.2 Line No.: 9 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Trasmission Tar.
¡Schedule Page: 328.2 Line No.: 9 Column: d
Non-Fin or Short-Term Fin Trasmission Service under the 0 n Accss Transmission Tarff between varous pares and points.
chedule Pa e: 328.2 Line No.: 9 Column: m
December 2006 Service.
I$hedule Page: 328.2 Line No.: 10 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (S.A. 169) termnating on September 30,2012.
Customer assi ned 15 mw to PacifiCo Merchant thou h June 30, 2008.
chedule Pa e: 328.2 Line No.: 10 Column: f
Bonnevile Power Administration.
¡Schedule Page: 328.2 Line No.: 11 Column: d
Point-to-Point Transmission Servce under the Open Accss Tramission Tarff (S.A. 169) termnating on September 30, 2012.
Customer assigned 15 mw to PacifiCorp Merchant thou h June 30, 2008.
chedule Pa e: 328.2 Line No.: 11 Column: f
Bonnevile Power Administration.
~chedule Page: 328.2 Line No.: 11 Column: m
December 2006 Service.
ISchedule Page: 328.2 Line No.: 12 Column: b
Varous si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
hedule Pa e: 328.2 Line No.: 12 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
~chedule Page: 328.2 Line No.: 12 Column: d
Non-Fin or Short-Term Fin Transmission Service under the Open Access Transmission Tarff between various pares and points.
¡SChedule Page: 328.2 Line No.: 13 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Trasmission Tarff.
¡Schedule Page: 328.2 Line No.: 13 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Trasmission Tarff.
~chedule Page: 328.2 Line No.: 13 Column: d
Non-Fin or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between varous pares and points.
¡Schedule Page: 328.2 Line No.: 13 Column: m
December 2006 Service.
IFERC FORM NO.1 (ED. 12-87) Page 450.9
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) iç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2oo7/Q4
FOOTNOTE DATA
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
irhedule Page: 328.2 Line No.: 14 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
I$chedule Page: 328.2 Line No.: 14 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
lchedule Page: 328.2 Line No.: 14 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between various pares and
chedule Pa e: 328.2 Line No.: 15 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 15 Column: c
Varous signatories to the 7th Revise Volume 11 Point-to-Point Transmission Tarff.
lchedule Page: 328.2 Line No.: 15 Column: d
Non-Firm or Short-Term Fir Transmission Service under the Open Access Transmission Tarff between varous
chedule Pa e: 328.2 Line No.: 15 Column: m
December 2006 Service.
lchedule Page: 328.2 Line No.: 16 Column: c
S.J.RE.A. is the Sheridan Johnson Rural Electrfication Association.
lSchedulePage: 328.2 Line No.: 16 Column: d
Agreement providing for transmission servce from Western Area Power Administration's Caper Substation in Wyoming and
Yellowtl Substation in Montana to Sheridan-Johnson's load at PacifiCo's Buffalo Substation in Wyoming.
Schedule Pa e: 328.2 Line No.: 16 Column: m
Sole use of facilties cha e.
chedule Pa e: 328.2 Line No.: 17 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
lchedule Page: 328.2 Line No.: 17 Column: c
Varous si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Pa e: 328.2 Line No.: 17 Column: d
Non-Fir or Short-Term Fir Transmission Service under the Open Access Transmission Tarff between varous
hedule Pa e: 328.2 Line No.: 18 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
lchedule Page: 328.2 Line No.: 18 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 18 Column: d
Non-Fir or Short-Term Fir Transmission Service under the Open Access Transmission Tarff between varous
hedule Pa e: 328.2 Line No.: 18 Column: m
December 200 Service.
¡Schedule Page: 328.2 Line No.: 19 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 19 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tar.
!Schedule Page: 328.2 Line No.: 19 Column: d
Non-Firm or Short-Term Firm Transmission Service under the 0 n Access Transmission Tariff between varous pares and points.
Schedule Pa e: 328.2 Line No.: 20 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various pares and points.
¡Schedule Page: 328.2 Line No.: 21 Column: b
Varous si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
chedule Pa e: 328.2 Line No.: 21 Column: c
Varous si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Pa e: 328.2 Line No.: 21 Column: d
Non-Firm or Short-Term Fir Transmission Service under the 0 en Access Transmission Tariff between various
Schedule Pa e: 328.2 Line No.: 22 Column: b
Varous si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Pa e: 328.2 Line No.: 22 Column: c
FERC FORM NO.1 ED. 12-87 Page 45.10
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 040312008 2007/Q4
FOOTNOTE DATA
Various si natories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Pa e: 328.2 Line No.: 22 Column: d
Non-Fir or Short-Term Firm Transmission Service under the n Access Transmission Tarff between various paries and points.
chedule Pa e: 328.2 Line No.: 22 Column: m
December 200 Service.
!schedule Page: 328.2 Line No.: 23 Column: b
eration, maintenance or facil lease services with no receipt or delive of energy.
chedule Pa e: 328.2 Line No.: 23 Column: c
o ration, maintenance or facil lea services with no reei t or delive
chedule Pa e: 328.2 Line No.: 23 Column: d
Malin to Indian Springs use of facilties Termnating August 1, 200. PERC ruled on July 30, 2007, to extend the agreement through
December 2007.
Išchedule Page: 328.2 Line No.: 23 Column: m
Sole use of facilties char e.
Schedule Pa e: 328.2 Line No.: 24 Column: d
Point-to-Point Transmission Service under the 0 en Access Transmission Tar, (S.A. 289) termnatin November 30, 2008.
hedule Pa e: 328.2 Line No.: 25 Column: d
Use of Facilties (S.A. 264) termnating July 2014.
!Schedule Page: 328.2 Line No.: 25 Column: m
Sole use of facilties charge.
!schedule Page: 328.2 Line No.: 26 Column: d
Use of Facilities (S.A. 264) ternatig July 2014.
IShedule Page: 328.2 Line No.: 26 Column: m
December 2006 Service.
/schedule Page: 328.2 Line No.: 27 Column: b
Varous si natories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
chedule Pa e: 328.2 Line No.: 27 Column: c
Varous si atories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
hedule Pa : 328.2 Line No.: 27 Column: d
Non-Fir or Short-Term Firm Transmission Service under the 0 en Access Transmission Tarff between varous
chedule Pa e: 328.2 Line No.: 28 Column: b
Varous signtories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
ISchedule Page: 328.2 Line No.: 28 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tranmission Tar.
!schedule Page: 328.2 Line No.: 28 Column: d
Non~Fir or Short-Term Fir Transmission Service under th n Accss Tramission Tarff between varous pares and points.
Schedule Pa e: 328.2 Line No.: 28 Column: m
December 2006 Service.
¡Schedule Page: 328.2 Line No.: 29 Column: b
Varous si atories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
hedule Pa e: 328.2 Line No.: 29 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Shedule Page: 328.2 Line No.: 29 Column: d
Non-Fir or Short-Term Fir Transmission Service under the Open Access Transmission Tarff between varous pares and points.
¡Schedule Page: 328.2 Line No.: 30 Column: d
Network Transmission Service under the Open Access Trasmission Tarff (S.A. 299). Service provided puruat to rules &
regulations of Oregon Direct Access. Termnation upon notification pursuant to Oregon Direct Access and Open Access Transmission
Tariff.
¡Schedule Page: 328.2 Line No.: 30 Column: f =i
Bonneville Power Administration.I$chedule Page: 328.2 Line No.: 30 Column: m I
Regulation & Frequency Response. Penalty revenues covering imbalance chages per Schedules 4 and 9.
IFERC FORM NO.1 (ED. 12-87) Page 450.11 I
-...........................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/03/2008 2007/Q4
FOOTNOTE DATA
Column: f
ares and points.
en Access Transmission Tarff between varous ares and points.
Column:m
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
Line No.: 3 Column: f
Line No.: 3 Column: 9
overnent facilities.
31, 2008.
n Accss Transmission Tarff between varous
u on wrttn notication.
u on wrttn notification.
............................................
Name of Respondent This Report is:Date of Report Yea~Period of Report
(1) K An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 04/03/2008 20071Q4
FOOTNOTE DATA
Line No.: 11 Column: m
eement extended to Se tember 30, 2008.
eement
eement.
eement
a eement, letter agreement extended to September 30, 2008.
IFERC FORM NO.1 (ED. 12-87)Page 450.15
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 040312008 2007/04
FOOTNOTE DATA
-............................................
Blank Page
(Next Page is 332)
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) EiA Resubmission 04/03/200
TRANSIi ISSION OF ELECTRICITY BY OTHE S (Accunt 56)
(Including trasactns referred to as "wheeling")
1. Report all transmission, Le. wheeling or electricity pròvided 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 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 recived and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expnses as shown on bils or vouchers rendere to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferre. On column (g) report the total of all
other charges on bils or vouchers rendered to the respondent, including any out of period adjustments. Exlain in a footnote ell
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.
Une TRANSFER OF ENERG"EXPENSES FOR TRANSMISSION OF ELECTRICITY BYOTHER
No.Name of Company or Public Statistical Magawatt-Magawan-l,.emana l:nergy ~Total Cost ofR~ed !iurs Ctir Ctipes chl¥fes Tran~isiOnAuthori (Footnote Affliations)Clasifcation Deliver
(a)(b)(c)(d)(e)(f)
1 Arizona Public Servce -17 -17 -224 -216
2 Arizona Public Servce LFP 164,04 164,04 924,96 924,96
3 Arizoa Pubic Serv NF 9,163 9,163 32,00 ..32,00
4 Arizona Public Service OS 18,766 51,192
5 Arizona Public Servce SFP 201,041 201,041 65,829 653,829
6 Ashland, Ci of FNS 1,998 1,998 19,259 19,259
7 Avi Co.FNS 61,96 64,108 252,34 252,34
8 Avista Corp.NF 24,904 24,90 66,n2 66,m
9 Big Hom R. E. C.~3
10 Big Hom R. E. C.48,606
11 Blanding Cit LFP 71 71 426 426
12 Bonneile Power Adm.-3,541 -3,541 20,156 120,48 -46,998
13 BonneviUe Power Adm.FNS 48,879 519,271
14 Bonneviße Poer Ad.LFP 3,65,98 3,65,98 24,26,54 15,58 24,281,125
15 Bonnevße Powr Adm.NF 184,236 147'52~184,23
16 Bonnevile Powr Adm.OS 6,949,145 7,155,782 37,38,104 40,181,418
TOTAL 15,280,20 15,54,183 83,96,26 2,028,269 20,597,5n 106,592,111
FERC FORM NO. 113-Q (REV. 02-04)Page 332
............................................
-...........................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2O7/Q4
(2) FiA Resubmission 04/03/2008
TRANS~ ISSION OF ELECTRICITY BY OTHE S (Account 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, Le. wheeling or electricity provided by other electric utilties, cooperatives, municipalities, other public
authorities, qualifyng 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 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 peribd adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and 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 Sttistical Magawatt-Magawan-~manci l:nergy _~.)lner Totl Cost of1i0UIioursChttresCharrasChttresTrans~issioAuthonty (Foonote Affliation)Claification Receied Delivered ($(a)(b)(c)(d)(e)(1))
1 Bonnelle Powr Adm.SFP 1,429,111 1,497,207
2 CAISO -3,146 178,85
3 CAISO OS 5,653,238
4 CAISO SFP 554,66 55,66 1,688,206 1,68,20
5 Califrnia PX OS 15,738
6 Dere P. E. C.NF 8,351 8,351 30,224 30,224
7 Deret P. E. C.SFP 199,939 199,939 1,29,501 1,29,501
8 EI Paso Elec. Co.NF 31,872 31,872 55,99 55,995
9 EI Paso Elect. Co.SFP 150 150 326 326
10 Flathead Elec. Coo.OS 58,223
11 Rowll Electric As.LFP 211 211 353 353
12 HermistDn Gen Co., L.P.OS 165,355
13 Idaho Power Copany -89,46 -8,46 -1,411,015 -1,411,015
14 Idao Powr Copany FNS 8,916 8,916
15 IdahD Powr Company NF 46,80 93,028 239,314 20,63 259,94
16 Idaho Power Company OS 9,412,475
TOTAL 15,280,2lr 15,54,183 83,96,26f 2,028,269 20,597,5n 106,592,111
FEC FORM NO. 113-0 (REV. 02-()Page 332.1
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 0403100
TRANS ISSION OF ELECTRICITY BY OTHE S (Acnt 565)
(Including trasactions referred to as "wheeling")
1. Report all transmission, Le. wheeling or electricity provided 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 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 Servce 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. Exlain 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 typ of energy or service rendere.
6. Enter "TOTAL H in column (a) as the last line.
7. Footnote entries and provide explanations following all reuire data.
Year/Period of Report
End of 2oo7/Q4
Une
No. Name of Company or Public
Auhori (Footnote Afiliations)
(a)
1 Idaho Power Company
2 LA De of Water & Pwr
3 LA De of Water & Pw
4 LA De of Water & Pwr
5 MAPPCOR
6 Mo Lake Ele. Asoc.
7 Morgn Cit
8 Navajo Tribal Util Aut
9 Nevada Power Copany
10 Nevada Power Copany
11 Nevada Power Company
12 NorWestern Energy
13 NortWesern Energy
14 NortWestern Energ
15 NorthWestern Eney
16 Plate River Power
m~r
(e)
1,128,762
184,63
erC'7rs Total Cost ofTras~ssion
1,128,762
184,63
10,08
15,354
-6,802
81,497
171
1,382
165,342
629,44
3,120,317
-86,015
29,554
781,989
52,536
106
Statistica
Classifcaon
(b)
SFP
NF
OS
SFP 1,64 1,64 15,354
15 15 171
64,231 64,231 165,342
98,561 98,561 3,120,317
65,162 65,496 29,554
111,833 111,83 525,53
TOTAL 15,280,2 15,54,183 83,96,2,028,269 20,597,577 106,592,111
FERC FORM NO. 113 (REV. 02-()Page 332.2
............................................
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04/0312008
TRANSI\ ISS ION OF ELECTRICITY BY OTHE S (Account 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, Le. wheeling or electricity provided by other electric 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 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. Exlain 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 EN ERG" EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER~
No.Name of Company or Public Statistical Magawatt-Magawan-I)ernana ..nerg ~Tot Cost of
RooUTSed Iiours Char pes Cht¥rs Ch&rpes Trans~SSionAuhori (Foonote Affilations)Classifcation eceiv Delivered ($(a)(b)(c)(d)(e)(f)
1 Platte River Powr OS 10,861
2 Platte River Power SFP 197,331 197,331 96,00 96.00
3 Portland Gen. Elecric NF 21 21 26 ..26
4 Portand Gen. Elecric OS 743,35 744,53 143,654
5 PSC of Colorado LFP 110,725 116,457 849,84 849,84
.6 PSC of New Mexico -83,691 -83,691
7 PSC of Ne Mexico NF 976 976 8,853 8,853
8 PSC of New Mexico OS 21,926
9 PSC of New Mexico SFP 113,08 113,40 365,763 36,763
10 Salt River Pro SFP 7,36 7,36 18,455 18,455
11 Seatle Cit Ught NF 52,401 52,401 145,133 145,133
12 Sierra Pacific Power Co NF 9,729 9,729 74,88 ~74,88
13 Sierr Pacic Power Co OS 61,015
14 Sierra Pacic Power Co SFP 5,613 5,613 576,00 576,000
15 Snohomish PUD ND. 1 NF 208,146 208,146 469,323 469,323
16 Suprise Valley Elecr.OS -10,059
TOTAL 15,280,20:15,548,183 83,966,265 2,028,26 20,597,5n 106,592,111
FERC FORM NO. 113-0 (REV. 02-()Page 3323
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) EjA Resubmission 04038
TRANSII ISSION OF ELECTRICITY BY OTHE S (Account 56)
(Including trasactions referred to as "wheeling")
1. Report all transmission, Le. wheeling or electricity pròvided 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 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 coe 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 recived and delivere by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendere 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 rendere to the respondent, including any out of period adjustments. Explain in a footnote all
compnents 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 ty 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.
Una TRASFER OF ENERG'EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawau-!l.emano .Energy C~~rs Tota Cost ofR~~ed lìours c~rres c~r Trans~issAuthority (Footnote Affliations)Clasifion Delivered
(a)(b)(c)(d)(e)(1)(g)
1 Tri-Ste Ge & Transm LFP 113,97 119,711 84,84 849,84
2 Tri-Stae Ge & Trasm NF 21,58 21,58 62,n3 62,n3
3 Tri-Stte Gan & Transm OS 11,06
4 Uth As Muni Pw Sys 9,48
5 Uth Asoc Muni Pwr Sy SFP 267,438 267,43 1,2,05 1,321,23
6 Weser Are Power Adm.1,525 -10,168
7 Wesern Are Power Adm.FNS 3,S38,166 3,S38,166
8 Wesern Are Power Adm.LFP 65,536 656,536 3,27S,OO 3,275,000
9 Western Ar Power Adm.NF 17,935 17,93 71,118 71,118
10 Wesern Are Power Adm.OS 19,127 391,589
11 Wesern Area Power Adm.SFP 4,262 4,26 10,607 10,607
12 Accrual True-up 495,163
13
14
15
16
TOTAL 15,280,20:15,54,183 83,96,26 2,028,269 20,S97,Sn 106,592,111
FERC FORM NO. 113-Q (REV. 02-04)Page 332.4
............................................
.............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Onginal (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/04
FOOTNOTE DATA
Line No.: 1 Column:b
Line No.: 1 Column:g
Column:
Column:b
Line No.: 9 Column:g
Line No.: 10 Column:g
Line No.: 12 Column:b
Column:g
Column:
Column:g
Column:
Line No.: 2 Column:b
Line No.: 2 Column:g
Line No.: 3 Column:
Line No.: 5 Column:
Line No.: 10 Column:
Line No.: 12 Column:g
Line No.: 13 Column:b
cified Costs of Certin Facilties
Line No.: 5 Column:b
Line No.: 5 Column:
Line No.: 6 Column:g
Line No.: 7 Column:b
Line No.: 8 Column:g
Line No.: 10 Column:g
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 040312008 2oo7/Q4
FOOTNOTE DATA
Line No.: 12 Column: b
Line No.: 12 Column: 9
¡tied costs of certn facilties
¡tied costs of certn facilties
Line No.: 8 Column:g
Line No.: 13 Column:
Line No.: 16 Column:
Line No.: 3 Column:g
Line No.: 4 Column:b
Line No.: 4 Column:g
Line No.: 5 Column:
Line No.: 6 Column:b
Column:
Column:g
IFERC FORM NO. 1 (ED. 12-87) Page 450.2
............................................
Blank Page
(Next Page is 335)
Name of Respondent
I This trrt Is:I
Date of Rep'ort Year/Peri of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) 0 A Resubmission 04008
MISCELLANEOUS GENERAL EXPENSES (Accunt 93.2) (ELECTRIC)
Line DeCririon
~~\untNo.(a
1 Industry Association Dues 1,214,470
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Exenses
4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities
5 Oth Expn ::=5,000 show purpse, recipient, amount. Group if .. $5,00
6
7 Community & Economic Development:
8 Astora Area Chamber of Commerce 5,000
9 Cache Chamber of Commerce 5,00
10 Del Norte Chamber of Commerc 6,00
11 Economic Development Corp of Utah 166,06
12 Economic Development for Cetra Oregon 9,00
13 Klamath Conty Ecoomic Developent 12,810
14 Laraie Economic Develoment Corp 5,00
15 Laramie Regionl Airprt Bord 5,00
16 Oregon Economic Development Asociation 25,00
17 Redmond Economic Development 7,500
18 Rural Development Initiatives 5,00
19 Siskiyo Conty Economic 35,00
20 South Cost Development Council 7,500
21 Souhem Oregon Regioal Economic 15,00
22 State of Utah 10,00
23 Utah Ceer for Rural Life 8,00
24 Wallowa County Chaber of Commerce 5,00
25 Other 38,520
26
27 Corate MembersipS and Subscription:
28 Asiated Oregon Indutries 54,787
29 California Climate Action Registry 20,00
30 Idaho Mining Asociation 6,00
31 Intermountain Elecrica Assocation 7,50
32 Linkvile Kiwanis Club 5,605
33 Manufacturing 21 Colition 5,00
34 Nohern Tier Transmission Group 178,737
35 NW Power & Coservancy 21,00
36 Oregon Business Asociation 13,00
37 Oregon Business Council 19,809
38 Pacif Northwest Utilties Conference Comittee 52,302
39 Portand Business Allance 39,05
40 Rocky Mountain Electrica League 18,00
41 Salt Lae Area Chamber of Commerc 30,255
42 Utah Foundation 22,500
43 Utah Manufacturers Association 6,00
44 Uth Taxpayers Asiation 20,000
45 Western Electricity Coordinating Council 1,854,30
46 TOTAL 25,310,886
FERC FORM NO.1 (ED. 12-9)Page 335
............................................
............................................
Name of Respondent This ~ort Is:
I
Date Qt ReROrt
I
Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) Fi A Resubmission 04/03/2008
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line DeSCriltion AmountNo.(a (b)
6 Western Energy Institute 40,000
7 Wyoming Taxpayers Association 7,754
8 Yakima County Development 5,000
9 Other 116,655
10
11 Directors Fees - Regional Advisory Bord 170,588
12
13 Regulatory Asset Amortiztion:
14 Glenrok Mine Stipulation-UT (Excluding Reclamation)149,625
15 Glenrock Mine 1998 Cae-UT (Excluding Reclamation)1,152,774
16 98 Early Retirement- Oregon 3,676,94
17 Trasitio Plan 3,892,299
18 Utah Deferred Pension 3,159,014
19
20 .
21 General:
22 Thelen Reid & Priest LLP 10,00
23 MEHC Cro Charge 8,949,915
24 Lega settlements 11,00
25 Oter 10,60
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 25,310,88
FERC FORM NO.1 (ED. 12-94)Page 335.1
FERC FORM NO.1 (REV. 12-03)Page 336
............................................
Name of Respondent This 'lrt Is:Date of Report Year/Penod of Report
PacifCorp (1) An Onginal (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 043/2008
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Acnt 403, 404, 405)
(Except amortization of aquisition adjustments)
1. Report in secion 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 elecric plant (Accunts 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 accunting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
accunt or functional classification, as appropriate, to which a rate is applied. Identity at the bottom of Section C the tye 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 informtion for each plant subaccunt, accunt or functional classification Listed in column
(a). If plant mortlity studies are prepared to assist in estimating average service Lives, show in column (f) the ty mortality curve
seleced as most appropriate for the accunt and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available informtion 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 Deprecation and Amortization Charges
Depreciation Amortization of
Une DfRrection Exnse for Aset UmitedTerm Amortization of
No.Functional Classification xpnse Retiremen Cots Elecnc Plant Other Elecnc Tota(Accunt 40)(Acnt 40.1)(Acount 40)Plant (Acc 405)
(a)(b)(c)(d)(e)(1)
1 Intangible Plant 42,032,755 42,032,755
2 Steam Prodction Plant 147,079,86 147,079,866
3 Nuclear Production Plant
~ Hydraulic Production Plant-Conventional 12,921,513 40,526 12,96,039
5 Hydraulic Production Plant-Pumpe Storage
€ Other Producion Plant 32,481,622 293,921 32,775,54
i Transmission Plant 58,147,412 58,147,412
E Distnbution Plant 129,744,03 129,744,033
9 Regional Transmission and Market Operation
1C General Plant 38,122,398 2,90,901 41,031,299
11 Common Plant-Electnc
12 TOTAL 45,276,103 46,772,947
B. Basis for Amortization Charges
The amortization of Limited-Term Electnc Plant is based on straght-line amortization over the life of the asset.
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04/03/2008
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie i:sumaiea Net Applied Mortainy Average
No.Account No.Plant Base Avg. Service Salvage DeFlr. rates Curve Remaining
la\(In Th%tands)7~l (PerJrnt)( er;rnt)T'te 7~r
12 Hydraulic Prod Plant
13 Clearwater #1 (42)
14 336.00 OR 3 1.66
15
16 Other Prouction Plant
17 lakeSide
18 341.00 UT 41,901 35.00 2.86
19 342.00 UT 3,274 35.00 2.86
20 343.00 UT 162,289 35.00 2.86
21 34.00 UT 75,291 35.00 2.86
22 34.00 UT 40,592 35.00 2.86
23 34.00 UT 2,94 35.00 2.86
24
25 Maengo Wind Plant
26 341.00 WA 6,185 25.0(4.00
27 343.00 WA 215,247 25.0(4.00
28 34.00 WA 6,071 25.0C 4.00
29 345.00 WA 10,640 25.00 4.00
30 34.00 WA 161 25.00 4.00
31 347.00 WA 476 25.00 4.00
32
33 Eat Side Mobile
34 34.00 UT 84 20.00 5.00
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO.1 (REV. 12-()Page 337
Vehìcle Depreciation $12,494,116 $12,268,419
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 0410312008 2007/Q4
FOOTNOTE DATA
I$chedule Page: 336 Line No.: 12 Column: b '
Vehìcle depreciation is charged to functional accounts. The following table summzes the vehìcle depreciation expense that was
charged to the functional accounts.
Twelve Month Ending
December 31,2007 2006
¡Schedule Page: 336 Line No.: 14 Column: c
Not yet determned.
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Blank Page
(Next Page is 350)
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04l0008
REGULATORY COMMISSION EXPEN ES
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Line Description Assessed by Expenses Total .Deferred
No.(Furnish name of regulatory commission or boy the Regulatory of Expense for in Account
Commisio Current Year .182.3~doket or case number and a description of the cae)Utli (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
1 Before the Public Service Commission of Utah:
2 Annual Fee 3,396,65~3,396,652
3 Other Stte Regulatory Exenses
4
5 Before the Public Utilit Commission of
6 Oregon:
7 Annual Fee 2,471,00 2,471,04
8 Other State Regulatory Exnses 555,488 555,488
9
10 Before the Public Service Commission of
11 Wyoming:
12 Annual Fee 891,46 891,463
13 Other State Regulatory Expenses
14
15 Before the Washington Utilities and
16 Trasportation Commission:
17 Annual Fee 44,56 44,568
18 Other State Regulatory Expnses
19
20 Beore the Idaho Public Utilties Commission:
21 Annual Fee 328,764 328,764
22 Other Stte Regulatory Expenses
23
24 Before the Public Utilities Commission of
25 california:
26 Annual Fee 5,25 5,250
27 Other State Regulatory Expenses
28
29 Before the Federal Energy Regulatory
30 Commission:
31 Annual Fee 1,737,411 1,737,411
32 Annual Land Use Fee 185,OO 185,00
33
34 Deferred Regulatory Comission Expense 861,53~
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL .9,456,151 555,488 10,011,639 861,532
ÆRC FORM NO. 1 (ED. 12-96)Page 350
............................................
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) EjA Resubmission 04/03/2008
REG JLATORY COMMISSION EXPENSES (Continued)
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to Contra Amount Deferred in UneDepartment..i.l'ö~ii AmOUnt Account 182.3 Account Account 182.3 No.
(f)(a)(h)(i)0)(k)
End~t)Year
1
Electric 928 3,396,652 2
3
4
5
6
Eleri 928 2,471,043 7
Elecric 928 555,48 8
9
10
11
Elecri 928 891,46 12
13
14
15
16
Electri 928 440,568 17
18
19
20
Elecric 928 328,764 21
22
23
24
25
Electric 928 5,25C 26
27
28
29
30
Elecric 928 1,737,411 31
Electric 928 185,000 32
33
286,929 928 555,488 592,973 34
35
36
37
38
39
40
41
42
43
44
45
10,011,639 286,929 555,488 592,97~46
FERC FORM NO.1 (ED. 12-9)Page 351
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Me, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 0431
RESEARCH, DEVELOPMENT, AND DEMONS RATION ACTIVITIES
1. Describe and show below costs incurred and accounts charg during the year for technological research, development, and demonstration (R, D &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(ldentif
recipient regardless of affliation.) For any R, D & D work carried with others, show separately the respondent's cot for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accounts).
2. Indicate in column (a) the applicable classification, as shown below:
Classifictions:
A. Elecric R, D & D Performed Internally:a. Overd
(1) Generation b. Und
a. hydroelecri (3) Distribu
i. Recreation fish and wildlife (4) Reg Transmisío an Market Opration
ii Other hydroelecric (5) Envromen (otr th equipment)b. Fossil-fuel stea (6) Oter (Clasif an in items in exces of $5,00.)
c. Intemal combustion or ga turbine (7) Total Co Incrrd. Nuclar B. Eleri, R, D & D Penoed Exernly:
e. Unconventional generation (1) Resarch Supp to the elerical Research Council or the Elecric
1. Siting and heat reiecion Power Research Instiute
(2) Transmission
Line Classifcation Description
No.(a)(b)
1
2
3
4 A. Electric R D&D Perfrmed Intemally
5 (1) Generation
6 b. Fosil-Fuel Stea Integrated Gaif Cobine Cyle
7
8 B. Elecri R D&D Performed Exemally
9 (1) Research Support Elecri Power Research Institute
10 (4) Research Supprt Others B&W Advisory Work Group
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 352
............................................
............................................
Name of Respondent This ~ort Is:Date of Report Year/Penod of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 040312008
RESEARCH, DE VELOPMENT, AND DEMONSTRATION ACTIVITIES (Continuec)
(2) Research Support to Edison Electric 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, D & D items perormed intemally and in column (d) those items performed outside the company costing $5,000 or more,
bnefly descnbing the specific area of R, D & D (such as safet, corrosion control, pollution, automation, measurement, insulation, tye of appliance, etc.).
Group iters under $5,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classif items by typ of R, D & D
actiVty.
4. Show in column (e) the account number charged wih expenses dunng the year or the account to which amounts were caitalized during the year,
listing Account 107, Construction Work in Progress, firs. Show in column (f) the amounts related to the accont charged in column (e)
5. Show in column (g) the total unamortized accumulating of costs of projecs. This total must equal the baance in Account 188, Research,
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6. If costs have not been segregated for R, D &D activitie or projecs, submit estimates for columns (c), (d), and (f) with such amounts identified by
"Est."
7. Report separately research and related testing facilites operated by the respont.
Costs Incurred Internally Costs Incurred Externaly AMOUNTS CHARGED IN CURRENT YEAR Unamortized LineCurretc~ Year Current Year Ac~tt Am3)nt Accmulation No.
(d)(e (g)
1
2
3
4
5
52,837 3,374,853 557 3,427,69C 6
7
8
1,217,789 930.2 1,217,789 9
25,00 930.2 25,00 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 353
Name of Respondent
PacifCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 040320
DISTRIBUTION OF SAlRIES AND AGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Year/Period of Report
End of 2007/04
Line
No.
Classifcation
a
1 Electric
2 Operation
3 Production
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 Genera
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 Tota of lines 6 and 16)
24 Customer Accounts (Transcribe from line 7)
25 Customer Service and Informtion (Trascribe fro line 8)
26 Sales (Transcribe from line 9)
27 Administrative an General (Enter Tota of lines 10 an 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 Expl. and Dev.)
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service 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 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
FERC FORM NO.1 (ED. 12-88)Page 354
............................................
............................................
Name of Responent
PacifiCorp
DIST
This ~ort Is:
(1) ~An Original
(2) A Resubmission
IBUTION OF SALARIES AND WAG
Date of Report
(Mo, Da, Yr)
04/0312008
S (Continued)
Year/Period of Report
End of 2O7/Q4
Line
No.
Classification
a
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru
56 Transmission (Lines 35 and 47)
57 Distribution (Lines 36 and 48)
58 Customer Accounts (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 Utilty Departments
64 Operation and Maintenance
65 TOTAL All Utilit Dept. (Total of lines 28,62, and 64)
66 Utilty Plant
67 Construction (By Utilty Departments)
68 Elecric Plant
69 Gas Plant
70 Other (provide details in footnoe):
71 TOTAL Construction (Total of lines 68 thru 70)
72 Plant Removal (By Utilty Departments)
73 Elecric Plant
74 Gas Plant
75 Other (provide details in foonote):
76 TOTAL Plant Removal (Total ofline 73 thru 75)
n Other Acunts (Specif, provide details in footnote):
78 Fuel Stock
79 Miscellaneous Income Deuction
80 Miscellaneous Nonoperating / Nonutilty
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts
96 TOTAL SALRIES AND WAGES
10,1n,515 10,1n,515
10,1n,515 10,1n,515
23,521,098
265,978
86,593
23,521,098
265,978
864,593
24,651,669
518,308,732
24,651,669
518,308,732
FERC FORM NO. 1 (ED. 12-8)Page 355
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2007/04
(2) FiA Resubmission 0403200
PURCHASES AND SALES OF ANCILLR SERVICES
Report the amounts for each ty of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related biling determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d). (e), (f) and (g) report the amount of ancilary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e), (t). 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 reulatin and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (t), and (g) report the amount of energy imblance services purchased and sold during the year.
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) reprt the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (t), and (g) report the total amount of all other types ancilary services purchased or sold during
the yer. Include in a footnote and specify the amount for each tye of other ancilary service provided.
Amount Purc for th Year Amount Sold for the Year
Usage - Relaed Billng Deennina Usage - Related Biling Detenninant
Unit of Unit of
linE Type of Ancillary Service Number of Unit Mere Dolars Number of Unit Meure Dollars
No.(a)(b)(c)(d)(e)(f)(g)
1 Schulig. System Contro and Ditch MW 135.894
2 Readive Suply and Volage
~ Regaton and Frequency Respo 58,260,514 MWH 9,321,68 59,724,566 MWH 9,942,799
4 Ener Imbalance -161,25 MW -5,06,728
5 Opting Reserve- Spinning 67,977,88 MW 24.729,731 70,63,85 MWH 25,799,746
E Oprating Resrve - Suppent 67,977,88 MW 24,72,731 70,441,001 MWH 25,711,718
¡Oter 1,86 MWH 31,696
8 Totl (Line 1 Ihm 7)194,216,274 58,781,144 20,64,031 56,553,125
FERC FORM NO.1 (New 2-()Page 398
............................................
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2007/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/03/2008
M NTHL Y TRANSMISSION SYSTEM P AK LOAD
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, furnish the required infonnation for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through (j) by month the system' monthly maxmum megawatt load by statisticl classifications. See General Instruction for the
definition of each statistical classification.
NAME OF SYSTEM:
Une
No.Month
Ot
Seric
8 Totl for Quarter 2
9 July
10 Auust
11 September
12 Tota for Qurtr 3
13 Ocober
14 November
15 Dember
16 Totllor Qurter 4
17 Tolal Year 10
Dalelear
Monthly Peak
MW - Total
Day of
Monthly
Peak
(c)
1
Hor of Firm Netrk
Monly Seic for Self
Peak
(d)
Firm Netwrk
Service for
Otrs
(f)
Log-Term Firm
Point-ta-pont
Reeratins
Otr Long
Term Firm
Servce
(h)
Short-Term Firm
Point-ta-pont
Rervat
(i)(j
63,48 19,80
FERC FORM NO. 1J3Q (NEW. 07-()Page 400
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) LÇ An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 04/0312008 2007/04
FOOTNOTE DATA
¡Schedule Page: 400 Line No.: 1 Column: b
Reflects actual demands of control area load at time of Transmision System Pea
¡Schedule Page: 400 Line No.: 1 Column: e
Reflects actual demands of control area load at time of Transmision System Peak.
¡Schedule Page: 400 Line No.: 3 Column: b
Reflects actual demands of control area load at time of Transmision S stem Peak.
chedule Pa e: 400 Line No.: 3 Column: e
Reflects actual demads of control area load at time of Transmision System Peak.
/Schedule Page: 400 Line No.: 4 Column: e
Reflects actual demands of control area load at ti of Transmission System Peak
¡Schedule Page: 40 Line No.: 4 Column: g
Reflects reservations in effect at time of Tramission System Peak
~hedule Page: 40 Line No.: 4 Column: i
Reflects reservations in effect at tie of Transmission System Peak
¡Schedule Page: 400 Line No.: 5 Column: b
Reflects actual demads of control area load at tie of Transmision System Pea
I$hedule Page: 400 Line No.: 5 Column: e
Reflects actual demads of control area load at time of Transmision System Peak
!Shedule Page: 400 Line No.: 6 Column: b
Reflects actual demands of control area load at time of Transmision System Peak.
fGchedule Page: 400 Line No.: 6 Column: e
Reflects actual demands of control area load at tie of Transmision System Peak
!Schedule Page: 400 Line No.: 7 Column: b
Reflects actual demands of control area load at tie of Transmision System Peak.
¡Schedule Page: 400 Line No.: 7 Column: g
Reflects actual demands of control area load at time of Transmision System Peak.
¡Schedule Page: 400 Line No.: 8 Column: e
Reflects actual demands of control area load at time of Transmission System Peak
~hedule Page: 400 Line No.: 8 Column: g
Reflects reservations in effect at time of Transmission System Peak
l§chedule Page: 400 Line No.: 8 Column: i
Reflects reservations in effect at time of Transmission System Peak
I$hedule Page: 400 Line No.: 9 Column: b
Reflects actual demands of control area load at time of Tranmision System Pea
I$hedule Page: 40 Line No.: 9 Column: g
Reflects actual demands of contrl ara load at ti of Transmision System Peak.
¡Schedule Page: 400 Line No.: 11 Column: b
Reflects actual demands of control area load at time of Trasmision System Peak
!Schedule Page: 400 Line No.: 11 Column: e
Reflects actual demands of control area load at tie of Transmision System Peak.
¡Shedule Page: 400 Line No.: 12 Column: e
Reflects actual demands of control area load at time of Transmission System Peak.
¡Schedule Page: 400 Line No.: .12 Column: g
Reflects reservations in effect at time of Trasmission System Peak
¡Schedule Page: 400 Line No.: 12 Column: i
Reflects reservations in effect at time of Transmission System Peak
¡Schedule Page: 400 Line No.: 16 Column: e
Reflects actua demands of control ara load at time of Tranmission System Peak.
fGchedule Page: 400 Line No.: 16 Column: g
Reflects reservations in effect at tie of Transmission System Peak
!Schedule Page: 400 Line No.: 16 Column: i
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 04/03/2008 2007/Q4
FOOTNOTE DATA
Reflects reservations in effect at time of Transmission System Peak
IFERC FORM NO.1 (ED. 12-87)Page 450.2
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2007/04
(2) EiA Resubmission 04/031
ELECTRIC ENERGY ACCOU~ T
Report below the information called for concerning the disposition of electnc energ generted, purchased, exchanged and wheeled dunng the year.
Line 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 Saes to Ultimate Consumers (Including 53,39,478
3 Steam 48,172,01:i Interdrtmenta Sales)
4 Nuclear 23 Requiremen Saes for Resale (See 209,695
5 HydroConventional 3,748,86 instruion 4, page 311.)
6 Hydro-Pumped Storage -4,96 24 NonRequirements Saes for Resale (Se 13,514,160
7 Oter 6,21,889 insn 4, page 311.)
8 Less Energy for Pumping 25 Energy Furnished Without Charge
9 Net Generation (Enter Total of lines 3 58,187,807 26 Energ Used by the Compay (Elecnc 161,514
through 8)Dept Only, Excluding Sttion Use)
10 Purcases 13,186,n2 27 Totl Energ Losses 4,498,827
11 Power Exchanges:~28 TOTAL (Enter Total of Line 22 Through 71,n4,674
12 Received 27 (MUST EQUAL LINE 20)
13 Delivered 8,978.36
14 Net Exchanes (Line 12 minus line 13)..15 Transmissio For Other (Wheeling)
16 Received 16,93,140
17 Delivered 16,93,140
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses -267,981
20 TOTAL (Enter Totl of lines 9,10,14,18 71,n4,67~
an 19)
FERC FORM NO.1 (ED. 12-90)Page 4018
............................................
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) ñA Resubmission 04/03/2008
MONTHLY PEAKS AND OUTPUT
(1) Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
(2) Report on line 2 by month the system's output in Megawatt hours for each month.
(3) Report on line 3 by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
(4) Report on line 4 by month the system's monthly maximum megawatt load (60 minute integration) associated with the system.
(5) Report on lines 5 and 6 the specified information for each monhly peak load reported on line 4.
NAME OF SYSTEM:
Line Monthl Non-Requirments MONTHLY PEAK8aes for Resale &No.Month Total Monthly Energy Assoiated Losses Megawatt (See Instr. 4)Day of Moh Hour
(a)(b)(c)(d)(e)(f)
29 January 6,455,57i 1,100,247 8,64 16 08 PST
30 February 5,597,827 1,098,403 8,43 2 080 PST
31 March 5,781,156 1,252,36 7,809 1 190 PST
32 April 5,498,254 1,267,323 7,037 30 150 PST
33 May 5,623,927 1,015,163 7,804 31 1700 PDT
34 June 6,030,551 1,156,601 8,887 20 1700 PDT
35 July 6.48,867 954,615 9,n5 10 1700 PDT
36 August 6,456,293 1,086,826 9,406 14 1700 PDT
37 September 5,568,789 1,03,092 8,254 4 160 PST
38 October 5,873,734 1,241,151 7,144 31 080 PST
39 November 5,96,n2 1,183,998 8,395 28 180 PST
4C December 6,438,927 1,122,373 8,650 11 180 PST
41 TOTAL 71,n4,674 13,514,160
FERC FORM NO.1 (ED. 12-90)Page 401b
Name of Respondent This~rtlS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2O7/Q4(2) DA Resubmission 04/0312008 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Larg Plants)
1. Report data for plant in Service only.2. Large plants are steam plants wit 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 footnote any plant leased or operated
as a joint facilit.4. If net peak demand for 60 minutes is not available, give data which is available, speifng period.5. If any employees attendmore 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 athenn 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 consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than onefuel is bumed in a plant fumish only the composite heat rate for all fuels bumed.
Line Item Pla PlantNo.Nae: Carb Name:~
(a)(b)
1 Kind of Plant (Intemal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventiona, Outdoor, Boiler, etc)Outdoor Boiler Full Outdoor
3 Year Originally Construted 1954 1981
4 Year Lat Unit was Installed 1957 1981
5 Total Installed Ga (Max Gen Name Plate Ratings-MW)188.60 414.00
6 Net Peak Demand on Plant - MW (60 minutes)174 3707 Plant Hours Conneced to Lod 861 8432
8 Net Continuous Plant capabilit (Megwat)0 0
9 When Not Limited by Condenser Water 172 380
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 69 012Net Generation, Exusive of Plant Use - KWh 133934 288244100
13 Cost of Plant: Land and Land Rights 95656 1246
14 Structures and Improvements 12437266 5303203315Equipment Cots 7821206 33222286
16 Asset Retirement Cots 1852187 390017Total Cot 9345809 38654261
18 Cost per KW of Installed Capaci (line 17/5) Including 495.538 933.6721
19 Production Exenses: Oper, Supv, & Engr 10199 1310396
20 Fuel 161051 5216676
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Exnses 1136931 2053023Steam Fro Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Elecri Exnses 191n01 132061426Misc Steam (or Nuclear) Power Expenses 4730820 16033
27 Rents 16554 11616528Allowances00
29 Maintenance Supervsion and Engineeng 0 178630Mantenace of Structures 22447 862871
31 Maintenance of Boiler (or reactor) Plant 1973419 399756832Mantenance of Elecric Plant 708098 79721933Maintenace of Misc Steam (or Nuclear) Plat 373684 255602934Total Prouction Exenses 27289411 6857104
35 Expenses per Net KWh 0.020 0.0238
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Co Oil Compoite Col Oil Composite37Unit (Coal-tonslOil-barreVGas-mcf/Nuclear-indicae)Tons Barrels Tons Barrels
38 Quantity (Unit) of Fuel Bumed 64585 3347 0 1591193 2213 0
39 Avg Heat Cont - Fuel Bumed (btu/indicate if nuclear)12115 14~~0 9652 134879 040Avg Cost of FueVunit,as Delvd to.b. during year 24.393 99.736 0.00 31.712 76.66 0.00
41 Average Cost of Fuel per Unit Burned 24.621 0.00 0.00 32.678 0.000 0.0042Average Cost of Fuel Bumed per Milion BTU 1.016 16.962 1.036 1.693 13.534 1.69843Average Cost of Fuel Bumed per KWh Net Gen 0.011 0.00 0.011 0.017 0.00 0.01744Average BTU per KWh Net Generation 11588.569 14.696 1160.265 10656.382 4.349 10660.731
FI;RC FORM NO.1 (REV. 12-03)Page 402
............................................
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2007/Q4(2) DA Resubmission 04/03/2008 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accunts. Production expenses do not include Purchased Power. System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32. "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro. internal combustion or gas-turbine equipment, report eah as a separate plant. However, ifa gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbne with the steam plant.12. If a nuclear poer generating plant. briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs atributed to research and development; (b) tys of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant typ fuel used. fuel enrihment type and quantit for the
report perid and other physical and operating characteristics of plant.""LineName: Name: Name:Dave Johnston No.
(f)
Steam Steam Steam 1
Conventional Outdor Boler Semi-Outdo 2
1984 1979 1959 3
1986 1980 1972 4
155,60 172.10 816.80 5
156 166 758 6
8688 8760 8753 7
0 0 0 8
148 165 762 9
0 0 0 10
0 0 191 1111212941321925698612
1355853 137086 104108 13
57295720 35260 5069737 14
154125100 12881302 38310279 15
39236 55971 6594275 16
212815909 16470379 4513574 17
1367.7115 95.8296 552.5874 18
1849 30n91 695975 19
11971061 1753461 42371196 20
0 0 0 21
859624 141706 0 22
0 0 0 23
0 0 0 24
2n80 519891 0 25
1250201 51220 14956185 26
19912 7876 212751 27
0 0 0 28
285382 5580 0 29
299432 312175 23496 30
2525565 2917679 894570 31
449303 821158 7651191 32
360326 696158 1554039 33
18067055 25604643 7873240 34
0.0161 0.0194 0.0138 35
Coal Oil Compoite Coal Oil Gas Coal Oil Composite 36
Tons Barrels Tons Barrels MCF Tons Barrels 37
708786 206 0 667842 457 7392 3942421 6299 0 38
8437 14~~0 999 12236 1087 8052 140 0 39
15.803 97.005 0.00 24.755 111.901 0.00 10.515 95.166 0.00 40
16.607 0.00 0.000 26.138 0.000 3.686 10.595 0.00 0.00 41
0.984 16.497 1.000 1.307 21.n1 0.658 16.185 0.667 42
0.010 0.00 0.010 0.013 0.00 0.007 0.00 0.007 43
106.294 10.821 106n.115 10102.098 1.778 11145.142 6.501 11151.64 44
FERC FORM NO.1 (REV. 12.03)Page 40
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2007/04(2)DA Resubmission 04 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 instale capacit (name plate rating) of 25,00 Kw or more. Report in
this page gas-turbine and internal cobustion plants of 10,00 Kw or more, and nucler plants.3. Indicate by a fotnote any plant leased or operated
as a joint facilty.4. If net peak demand for 60 minutes is not available, give data whic is available, speifng period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employe assignabe to each plant.6. If ga is used and purchased on a
therm basis report the Btu content or the ga and the quanti of fuel bumed converted to Mct.7. Quantities of fuel burned (Une 38) and average cot
per unit of fuel bumed (Une 41) must be consistent with charges to expense accunts 501 and 547 (Une 42) as show on Une 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels bumed.
Une Item Plant Plant
No.Name:__Name:~
(a)
1 Kind of Plant (Internal Comb, Gas Turb, Nucler Steam Stea
2 Type of Constr (Conventional, Outdor, Boiler, etc)Outdor Boler Outdoor Boler
3 Year Originally Constructed 1965 1978
4 Year Lat Unit was Installed 1976 1978
5 Tota Installed Cap (Max Gen Name Plate Ratings-MW)81.30 44.00
6 Net Peak Demand on Plant - MW (60 minutes)79 411
7 Plant Hours Connected to Load 8760 8231
8 Net Cotinuous Plant Capailit (Megawatts)0 0
9 When Not Umited by Condenser Water 78 403
10 When Umited by Condenser Water 0 0
11 Average Number of Employees 0 74
12 Net Generation, Exclusive of Plant Use - KWh 6490 3035550
13 Cost of Plant: Land and Lad Righ 379735 9688975
14 Structures and Improvements 60233 61926142
15 Equipment Costs 61 0391 n 229829854
16 Aset Retirement Costs 208n 1062923
17 Total Cost 67442121 302507894
18 Cost per KW of Installed Capcit (line 17/5) Including 829.5464 682.8621
19 Proion Expenses: Oper, Supv, & Engr 156722 -1
20 Fuel 11195910 378921n
21 Coolants and Water (Nuclear Plants Only)0 0
22 Stea Exenses 95756 292581
23 Steam From Othr Sources 0 0
24 Stea Transferred (Cr)0 0
25 Elecric Expenses 2088 0
26 Misc Steam (or Nuclear) Power Exenses 40240 2633887
27 Rents 0 1522
28 Allowances 0 0
29 Maintenance Supervision and Engineering 24020 0
30 Maintenance of Strucures 145459 1975615
31 Maintenance of Boiler (or reactor) Plant 838026 5620197
32 Maintenance of Electric Plant 193556 795557
33 Maintenance of Misc Steam (or Nuclear) Plant 3700 221234
34 Total Prouction Expenses 1470200 52069
35 Exenses per Net KWh 0.0227 0.0172
36 Fuel: Kind (Col, Gas, Oil, or Nuclear)Coal Oil Gas Col Oil Copoe
37 Unit (Coal-tonsiOil-barreVGas-mcf/Nuclear-indicate)Tons Barrels MCF Tons Barrels
38 Quantit (Units) of Fuel Bumed 314700 376 96 1479754 5013 0
39 Avg Heat Cot - Fuel Burned (btulndicate if nuclear)1123 132579 1091 11290 14~~0
40 Avg Cost of FueVunit, as Delv to.b. during year 33.429 96.68 0.00 0.00 0.00 0.00
41 Average Cot of Fuel per Unit Burn 35.46 0.00 -0.172 25.26 0.00 0.00
42 Average Cost of Fuel Burned per Milion BTU 1.579 17.361 1.119 17.139 1.133
43 Average Cost of Fuel Burned per KWh Net Gen 0.016 0.00 0.012 0.00 0.012
44 Average BTU per KWh Net Generation 10892.524 3.229 11007.179 9.710 11016.88
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. Da,Yr)2oo7/Q4(2) OA Resubmission 04/03/2008 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are baed on U. S. of A. Accounts. Production expenses do not include Purchased Power. System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Accunt Nos. 553 and 554 on Line 32, "Maintenance of Elecric Plant." Indicte plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam. hydro, intemal combustion or gas-turbine equipment. report each as a separate plant. However, if a ga-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant. briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) tyes of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant typ fuel used, fuel enrichment tye and quantity for the
report period and other physical and operating characteristics of plant.~PM
Hunter Unit NO.3 ~Name: Name:Name: . No.
(e)
Steam Steam Steam 1
Outdoor Boiler Outdor Boiler Oudor Boiler 2
1980 1983 1978 3
1980 1983 1983 4
285.00 495.60 1223.60 5
264 48 1130 6
845 7017 8760 7
0 0 0 8
259 46 1122 9
0 0 0 10
74 74 222 11
20521740 295094200 80 12
9688975 1027541 2965331 13
50727551 899106 20256360 14
1539304 402956162 78609520 15
1062923 1062923 3188769 16
214788753 504205153 102150180 17
753.647 1017.361 83.831 18
-1 -1 -3 19
24841550 341787 9738514 20
0 0 0 21
294663 2937596 8810100 22
0 0 0 23
0 0 0 24
0 0 0 25
139052 3070682 5821 26
1522 2691 5735 27
0 0 0 28
0 0 0 29
1828705 2229888 60208 30
465389 1266913 22946499 31
937187 3711889 543 32
117679 119882 458795 33
357736 59385327 146929102 34
0.0173 0.0201 0.0183 35
Coal Oil Composite Coa Oil Compoite Coal Oil Compoite 36
Tons Barrels Tons Barrels Tons Barrels 37
970140 1662 0 132949 21173 0 377933 27848 0 38
1135 140 0 11260 140 0 11296 14~~0 390.00 0.00 0.00 0.00 0.000 0.00 25.272 99.112 0.00 40
25.437 0.00 0.00 24.492 0.00 0.00 25.038 0.00 0.00 41
1.120 16.816 1.127 1.088 16.792 1.153 1.108 16.856 1.38 42
0.012 0.00 0.012 0.011 0.001 0.012 0.012 0.00 0.012 43
10736.814 4.763 10741.576 10145.560 42.190 10187.750 10621.863 20.370 1062.233 44
FERC FORM NO.1 (REV. 12-()Page 40.1
Name of Respondent This wort Is:Date of Report Year/Penod of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)2oo7/Q4(2)DA Resubmission 048 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plats)(Cotinued)
1. Report data for plant in Service only.2. Large plants are steam plants with Instaled caacit (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 leed or operated
as a joint facilty.4. If net peak deman for 60 minutes is not availa, give data which is availabe, speng peno.5. If any employees attend
more than one plant, report on line 11 the approximate average number of emplyees asignable to each plant.6. If ga is used and purchased on a
therm basis report the Btu content or the gas and the quantit of fuel burn coverted to Me.7. Quantities of fuel bumed (Line 38) and average cost
per unit of fuel burned (Line 41) must be cosistent wih charge to expnse acnts 501 an 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the compoite heat rate for all fuels burn.
Line Item Plant Plant
No.Name: Huntington Name:~
(a)(b)
1 Kind of Plan (Internl Comb, Gas Turb, NuClear Steam Steam
2 Type of Constr (Conventional, Outdor, Boiler, etc)Outdor Boiler Semi-outdor
3 Year Onginally Constructed 1974 1974
4 Year Lat Unit was Instaled 19n 1979
5 Totl Instaled Cap (Ma Gen Name Plate Ratings-MW)996.00 1541.10
6 Net Peak Demand on Plant - MW (60 minutes)918 1414
7 Plan Hours Conneced to Load 8759 8759
8 Net Continuous Plant Capality (Megwatt)0 0
9 When Not Limited by Condnser Water 895 1413
10 Whe Limited by Condenser Water 0 0
11 Average Number of Employes 163 341
12 Net Generation, Exclusive of Plant Use - KWh 7127084 1005497000
13 Cost of Plant: Land and Land Rights 23882 1161925
14 Structures and Improvements 1120158n 134968247
15 Equipment Costs 50790766 785821165
16 Asset Retrement Costs 25003 6661
17 Total Cot 624814459 928614698
18 Cost per KW of Installed Capaci (line 17/5) Incudng 62.32 60.5662
19 Prouctio Exnses: Oper, Supv, & Engr 1342 17855550
20 Fuel 82679450 1390n086
21 Coolants and Water (Nuclear Plants Only)0 0
22 Stea Expenses 7926745 380n25
23 Steam From Other Sources 0 0
24 Steam Transferr (Cr)0 0
25 Elecnc Expenses 0 8038
26 Mise Steam (or Nuclear) Power Expenes 1031575 -16196118
27 Rents 3484 43243
28 Allowances 0 0
29 Maintenance Supervision and Engineenng 1385 8413
30 Maintenance of Structures 1602737 7987
31 Mantenance of Boiler (or reactor) Pl 627592 290788
32 Maintenance of Elecnc Plant 129851 n03496
33 Maintenance of Mise Steam (or Nuclear) Plat 1263732 2144172
34 Total Production Expenses 11276973 192592171
35 Exenses per Net KWh 0.0158 0.0192
36 Fue: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Copoite Col Oil Compoite
37 Unit (Coal-onslOil-barreVGas-mcflNucler-indcate)Tons Barrels Tons Barrels
38 Quantit (Units) of Fuel Burned 322177 8997 0 5709196 2940 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)11318 140 0 9136 140 0
40 Avg Cost of FueVunit, as Delvd to.b. dunng year 25.534 98.288 0.00 23.981 90.283 0.000
41 Average Cost of Fuel per Unit Burned 25.388 0.00 0.00 23.894 0.00 0.00
42 Average Cost of Fuel Burn per Million BTU 1.122 16.716 1.133 1.30 15.35 1.331
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 Generation 102.762 7.423 10240.184 10375.00 17.22 10392.230
FERC FORM NO. 1 (REV. 12-()Page 402.2
............................................
......................................'......
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2007/Q4(2)DA Resubmission 0403/2008 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Acunt 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 automaticaly operated plants.11. For a plant equipped with combinations of fosil fuel steam, nuclear
steam, hydro, intemal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) ty of cost unit
used for the various components of fuel cost; and (c) any other informative data concerning plant tye fuel used, fuel enrichment tye and quantit for the
report period and other physical and operating characteristics of plat.
Plant Plat Plam Line
Name: Naughton C=N~Gadsby Steam Plant No.
(d)(f)
Steam Steam Steam 1
Outdoor Boiler Conventional Outdor 2
1963 1978 1951 3
1971 1978 1955 4
707.20 289.70 257.60 5
706 278 194 6
8760 86 3520 7
0 0 0 8
700 268 235 9
0 0 0 10
140 72 37 11
521061800 225616800 308320 12
4290794 210526 1252090 13
643490 47920904 14080 14
323952614 271746601 56537656 15
2841694 761616 676487 16
395434146 3206967 72534279 17
559.154 1106.7989 281.5772 18
43688 558023 39175 19
77343857 1816735 26414704 20
0 0 0 21
680920 0 379 22
0 0 0 23
0 0 0 24
9184 0 0 259453408147833252226
200 9934 0 27
0 0 0 28
110499 614 0 2919649741315749530
8573325 4922299 122750 31
342281 958974 939500 32
9802 554950 572389 33
1100549 29751039 32676372 34
0.0211 0.0132 0.1068 35
Coal Gas Composite Coa Oil Compoite Gas 36
Tons MCF Tons Barrels MCF 37
2772108 188191 0 1651101 33 0 4118910 0 0 38
9929 106 0 7830 14~~0 1053 0 0 39
27.456 0.00 0.000 10.808 94.502 0.00 0.00 0.00 0.000 40
27.461 6.478 0.00 10.812 0.00 0.00 6.413 0.00 0.00 41
1.383 6.311 1.40 0.690 16.072 0.702 6.093 0.00 0.00 42
0.Q5 0.00 0.Q5 0.008 0.000 0.008 0.086 0.00 0.00 43
10565.099 37.070 1062.169 11460.245 8.705 11468.949 14176.352 0.00 0.00 44
FERC FORM NO.1 (REV. 12-()Page 403.2
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)207/04(2)DA Resubmission 04031008 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only.2. Large plants are steam plants with instaled cacit (name plte rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facilty.4. If net peak demand for 60 minutes is not available, give data which is available, specifing period.5. If any employees attendmore 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 atherm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense acnts 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 fuls burn.
Line Item Pla Plant
No.Name: Li Montn Name:~
(a)(b)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbne Combined Cycle
2 Type of Constr (Conventional, Outdor, Boiler, etc)Outdoor Boler Outdor
3 Year Originally Constructed 1972 1996
4 Year Last Unit was Installed 1972 1996
5 Total Installed Cap (Ma Gen Name Plate Ratings-MW)16.00 279.60
6 Net Peak Demand on Plat - MW (60 minutes)17 245
7 Plant Hours Conected to Load 83 858 Net Continuous Plant Cability (Megwatt)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 Generaio, Exclusive of Plant Use - KWh 11260200 171134
13 Cost of Plant: Lad and Land Rights 635 842245
14 Structures and Improements 217599 12522919
15 Equipment Costs 507183 1532426
16 Asset Retirement Costs 0 214373
17 Total Cost 5290067 1662182
18 Cot per KW of Installed Cacity (line 175) Includng 330.6292 596.6459
19 Production Expnses: Oper, Supv, & Engr 0 0
20 Fuel 1190700 52038225
21 Colants and Water (Nuclear Plants Only)0 0
22 Stea Expenses 0 023Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 025Elecric Expenses 955208 n91207
26 Misc Steam (or Nuclear) Power Expnses 0 0
Z1 Rents 0 028Allowances0029Mantenance Supervision and Engineering 0 030Maintenance of Structures 0 0
31 Mantenance of Boiler (or reactor) Plant 0 032Maintenance of Elecric Plant 0 0
33 Maintenance of Misc Steam (or Nuclear) Plant 59927 034Total Prouction Exnses 1292183 5982942
35 Expnses per Net KWh 0.1148 0.03
36 Fuel: Kind (Coal, Gas, Oil, or Nucear)Gas Gas
37 Unit (Coal-tons/Oil-barreVGas-mcflNucear-inclte)MCF MCF
38 Quantit (Units) of Fuel Burned 1945941 0 0 12139569 0 0
39 Avg Heat Cont - Fuel Burned (btulndicate if nuclear)1014 0 0 102 0 0
40 Avg Cot of FueVunit, 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 Burned 6.119 0.00 0.00 4.287 0.00 0.0042Average Cost of Fuel Burned per Milion BTU 6.034 0.00 0.00 4.195 0.00 0.00
43 Average Cost of Fuel Burned per KWh Net Gen 0.106 0.00 0.00 0.030 0.000 0.00
44 Average BTU per KWh Net Generation .17523.552 0.00 0.00 7248.46 0.000 0.00
FERe FORM NO.1 (REV. 12-03)Page 402.3
............................................
............................................
Name of Respondent This wort Is:Date of Report Year/Penod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2007/Q4(2) DA Resubmission 04/0312008 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large PlantsHContinued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account NoS.
547 and 549 on Une 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Une 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine wih the steam plant.12. If a nuclear power generating plant, bnefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attnbuted to research and development; (b) ty of cot units
used for the vanous components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel ennchment tye and quantiy for the
report penod and other physical an operating charactenstics of plant.
Name: "~h/" Name:. ..' Name: No.
e
Steam - Geothermal Steam Gas Turbine 1
Indoor Outdor Boiler Outdor 2
1984 1996 2002 3
2007 199 2002 4
38.10 61.50 217.00 5
37 46 215 6
7038 7303 5947 7
0 0 0 8
34 22 202 9
0 0 0 10
15 0 8 11
16387500 1218490 66703100 12
41195596 0 0 13
6698624 5733734 116354 14
6426128 28716806 622401 15
1336278 0 0 16
11366626 34505 738755 17
2983.1135 560.1714 3.40 18
31426 0 0 19
0 0 41701673 20
0 0 0 21-829 0 0 22
4845079 0 0 23
0 0 0 24
0 0 89994 25
1579607 2036 0 26
1458 0 109n690 27
0 0 0 28
0 0 0 29
158507 0 92698 30
31994 0 0 31
1450796 0 624790 32
66958 77 13617 3384554211436253311434
0.0515 0.002 0.0937 35
Gas 36
MCF 37
0 0 0 0 0 0 7097553 0 0 38
0 0 0 0 0 0 1041 0 0 390.00 0.00 0.00 0.000 0.00 0.00 0.00 0.00 0.00 40
0.000 0.00 0.000 0.00 0.00 0.00 5.876 0.00 0.000 410.00 0.00 0.00 0.00 0.000 0.00 5.645 0.00 0.00 42
0.000 0.00 0.00 0.00 0.00 0.00 0.06 0.00 0.00 430.00 0.000 0.00 0.00 0.00 0.00 11074.842 0.000 0.00 44
FERC FORM NO.1 (REV. 12-03)Page 403.3
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifCorp (1) An Onginal (Mo, Da, Yr)2007/Q4(2)DA Resubmission 0420 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plts)(Continued)
1. Report data for plant in Service only.2. Large plants are steam plants wi installed capacity (name plate rating) of 25,00 Kw or more. Report in
this page gas-turbine and intern 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 available, give data which is available, speifng peno.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 cotent or the ga and the quantit of fuel burned converted to Mct.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense account 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the compoite heat rate for all fuels burned.
Line Item Pla Plant
No.Name: Gady Gas Peakers Name: Currnt Crek
(a)(b)(c)
1 Kind of Plant (Internl Comb, Gas Turb, Nuclear Gas Turbne Combined Cycle
2 Type of Constr (Conventional, Outdor, Boler, etc)Outr Outdor
3 Year Onginally Costructed 202 2005
4 Year Lat Unit was Installed 20 200
5 Total Installed Cap (Ma Gen Name Plate Ratings-MW)141.00 56.90
6 Net Peak Demand on Plant - MW (60 minutes)124 568
7 Plant Hours Conneced to Load 5110 8370
8 Net Continuous Plant Capabilty (Megawatts)0 0
9 When Not Limited by Condenser Water 120 54
10 Whe Limited by Condenser Water 0 0
11 Average Number of Employee 0 21
12 Net Generation, Exclusive of Plant Use - KWh 32721700 3607100
13 Cost of Plant: Lad and Land Rights 0 34030
14 Structures and Improvements 412164 42374901
15 Equipment Costs 71981641 294996242
16 Aset Retirement Costs 0 13484
17 Total Cost 76103284 34099021
18 Cot per KW of Instaled Capacity (line 17/5) Including 539.7396 601.3565
19 Prouctio Expenses: Oper, Supv, & Engr 0 6984
20 Fuel 2299386 151425146
21 Colants and Water (Nuclear Plants Only)0 0
22 Steam Exnses 0 0
23 Steam From Other Sources 0 0
24 Steam Trasferred (Cr)0 0
25 Elecnc Expenses 16326 1819594
26 Mise Steam (or Nuclear) Power Expenses 0 16093
27 Rents 0 2123
28 Allowances 0 0
29 Maintenance Supervsion and Engineering 0 0
30 Maintenance of Structures 18322 323875
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electnc Plant 64701 2813553
33 Maintenance of Misc Steam (or Nuclear) Plant 145817 5166
34 Total Production Exenses 256 157150487
35 Expnses per Net KWh 0.0783 0.04
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Ga Gas
37 Unit (Co-tons/Oil-barreVGas-mcf/Nuclear-indicate)MCF MCF
38 Quantity (Units) of Fuel Burned 373 0 0 24810285 0 0
39 Avg Heat Cont - Fuel Burned (btulndicate if nuclear)1047 0 0 1045 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. dunng year 0.00 0.00 0.00 0.00 0.00 0.00
41 Average Cost of Fuel per Unit Burned 6.154 0.000 0.000 6.103 0.00 0.00
42 Average Cost of Fuel Burned per Milion BTU 5.879 0.00 0.00 5.842 0.00 0.00
43 Average Cost of Fuel Burned per KWh Net Gen 0.070 0.000 0.00 0.042 0.00 0.000
44 Average BTU per KWh Net Generation 11952.719 0.000 0.000 7189.511 0.00 0.00
FERC FORM NO.1 (REV. 12-03)Page 402.4
............................................
............................................
Name of Respondent This 00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Me, Da, Yr)2007/04(2) DA Resubmission 04/0312008 End of
STEAM.ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Mantenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, intemal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) tyes of cost units
used for the various components of fuel cost; and (c) any other infonnative data concerning plant type fuel used, fuel enrichment tye and quantity for the
report period and other physical and operating characteritics of plant.
Plant Plant Plant LineName: Lae Side Name:Name:No.
(d)(e)(f)
Combined Cycle 1
Outdoor 2
2007 3
2007 4
548.00 0.00 0.00 5
594 0 0 6
2482 0 0 7
0 0 0 854009
0 0 0 10
21 0 0 11
118586100 0 0 12
17296760 0 0 13
4190100 0 0 14
28492458 0 0 15
0 0 0 16
34590218 0 0 17
626.9894 0.0000 0.0000 18
31314 0 0 19
45n1901 0 0 20
0 0 0 21
0 0 0 22
0 0 0 23
0 0 0 24
1253357 0 0 25
0 0 0 26
0 0 0 27
0 0 0 28
0 0 0 29
15979 0 0 30
0 0 0 31
545625 0 0 32
1081 0 0 33
47619257 0 0 34
0.0402 0.~~0.~~35
Gas 36
MCF 37
n61318 0 0 0 0 0 0 0 0 38
1050 0 0 0 0 0 0 0 0 39
0.00 0.000 0.00 0.00 0.000 0.00 0.00 0.00 0.000 40
5.897 0.00 0.00 0.00 0.00 0.00 0.000 0.000 0.00 41
5.616 0.000 0.00 0.000 0.00 0.00 0.00 0.00 0.00 42
0.039 0.00 0.00 0.00 0.00 0.000 0.000 0.000 0.00 43
6873.149 0.000 0.00 0.00 0.00 0.00 0.00 0.00 0.00 44
FERC FORM NO.1 (REV. 12-03)Page 403.4
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Onginal (Mo, Da, Yr)PacifiCorp (2)A Resubmission 04/03/2008 2oo7/Q4
FOOTNOTE DATA
!Shedule Page: 402 Line No.: -1 Column: c
Cholla
The Cholla Plant is operated by Arzona Public Service Company. Respondent owns Unit No.4 plus 36.12% of related common
facilties. Data re ort re resents res ondent's shae. PacifiCo does not have em 10 ees at the Cholla Plant.
chedule Pa e: 402 Line No.: -1 Column: d
Colstrip
The Colstrp Plant is operated by PPL Montaa, LL and is jointly owned. Data reportd represents rèspondent's 10% share of
Colstri Plant Units NO.3 and No.4. PacifiCo does not have e 10 ees at the Colstr Plant.
hedule Pa e: 402 Line No.: -1 Column: e
Craig
The Craig Plant is operated by Tri-State Generation and Transmission Association and is jointly owned. Data reportd represents
respondent's 19.28% share of Craig Plant Units NO.1 and NO.2 and 12.86% of common facilties. PacifiCorp does not have
em 10 ees at the Crai Plant.
chedule Pa e: 402.1 Line No.: -1 Column: b
Hayden
The Hayden Plant is operated by Public Service Company of Colorado and is jointly owned. Data reported represents respondent's
24.5% (45 MW) share of Hayden Unit No. 1, 12.6% (33 MW) sha of Hayden Unit NO.2 and 17.5% of common facilities.
PacifiCo does not have em 10 ees at th Ha den Plant.
Schedule Pa e: 402.1 Line No.: -1 Column: c
Hunter Plant Unit No.1
Hunter Plant Unit NO.1 is owned by the respondent and Prvo City Corpration with an undivided interest of 93.75% and 6.25%,
respectively. Data reportd in colum (c) represents respondent's shae. Costs to operate and mantan ths unit are charged to
appropriate PERC accounts. Costs that were biled to minority owners for the operation and maintenance (excluding fuel) of ths unit
for calendar ear 2007 was $1.1 millon and was rimal cha ed to account 506.
hedule Pa e: 402.1 Line No.: -1 Column: d
Hunter Plant Unit No.2
Hunter Plant Unit No.2 is owned by the respondent, Deseret Power Electrc Cooperative and Uta Associated Municipal Power
Systems. Each with an undivided interest of 60.31%, 25.108% and 14.582% respectvely. Data reported in column (d) represents
respondent's share. Costs to operate and mantan ths unit ar chaged to appropriate PERC accounts, costs that were biled to
minority owners for the operation and mantenance (excluding fuel) of ths unit for calendar year 2007 was $6.1 millon and was
.rnil char ed to account 506.
Schedule Pa e: 402.1 Line No.: -1 Column: f
Hunter
Hunter Unit NO.1 is owned by the respondent and Provo City Corpration with an undivided interest of 93.75% and 6.25%
respectively. Hunter Unit No.2 is owned by the respondent, Deseret Power Electrc Cooperative and Uta Associated Municipal
Power Systems. Each with an undivided interest of 60.3 1 %,25.108% and 14.582% respectively. Data in column (t) represents
respondent's share. Costs to operate and maintan ths plant are charged to appropriate PERC accounts, costs that were biled to
minority owners for the operation an mantenance (excluding fuel) of this plant for calendar year 2007 was $7.2 millon and was
rimarl cha ed to account 506.
Schedule Pa e: 402.2 Line No.: -1 Column: c
Jim Bridger
Jim Bridger Plant is operated by PacifiCorp and colum (c) represents th respondent's share. Ownership of the plant is as follows:
PacifiCorp 66 213%, Idaho Power Company 33 1/3%. Costs to operate and mantan ths plant are charged to appropriate PERC
accounts, costs that were biled to minority owners for the operation and mantenance (excluding fuel) of ths plant for calendar year
2007 was $27.5 millon and was riarl char ed to account 506.
chedule Pa e: 402.2 Line No.: -1 Column: e
Wyodk
Wyoda Plant is operated by PacifiCorp and column (e) represents the respondent's share. Ownership of the plant is as follows:
PacifiCorp 80%, Black Hils Corporation 20%. Costs to operate and mantan ths plant are charged to appropriate PERC accounts,
costs that were biled to minority owners for the operation and mantenance (excluding fuel) of ths plant for calendar year 2007 was
$3.4 millon and was rimaril char ed to account 506.
Schedule Pa e: 402.3 Line No.: -1 Column: c
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) X An Original (Mo, Da, Yr)PacifiCorp (2) A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
Hermton
The Hermston Plant is operated by Hermston Operating Company, L.P. and is jointly owned. Data reported on lines S though 43
represent's the respondent's SO.O% share of the Hermston Plant. See Page 326- Purchased Power of ths Form No. 1 for furter
information on Hermston Generatin Com an ,L.P. PacifiCo does not have an em 10 ees at the Hermston Plant.
chedule Pa e: 402.3 Line No.: -1 Column: d
Blundell
Allor some of the renewable energy attbutes associate with ths generation may be used in future years to comply with state or
federa renewable portolio standards. For furter information regarding the Blundell generating facility, refer to Page 108, Important
Changes During the Year, Item 2, of ths Form NO.1.
In 2007, PacifiCo added Unit 2, a 10.7 MW bottomin c cle, to the Blundell
chedule Pa e: 402.3 Line No.: -1 Column: e
Cam Co-Gen
PacifiCorp owns the steam tubine generator and associated systems dirctly related to the operation of ths unit at Georgia-Pacific
Corporation's Cam, Washington paper mill. Modifications and upgrdes to the existing Cam paper mill were necessar to supply
ste to the tubine and to ensure continued operation of the unit in the event of mill closure. Georgia-Pacific retane ownership of
these modifications. Georgia-Pacific supplies the fuel and delivers the steam to PacifiCorp's turbine. PacifiCorp is responsible for
major maintenance costs only on the repair of the turbine generator and auxilar equipment. None of th facilties are jointly owned.
Each asset is wholly owned, either by PacifiCorp or Georgia-Pacific Corporation. PacifiCorp does not have employees at th Cam
Paper Mil.
¡Schedule Page: 402.3 Line No.: -1 Column: f
West Valey
In May 2002, PacifiCorp entered into a IS-year operating lease for an electrc generation facility with West Valley Leasing Company,
LLC ("West Valley"). West Valley is an indirect subsidiar of PacifiCorp' s former parent ScottshPower PLC. The facilty consists of
five generation units; each rated at 40 megawatt ("MW"), and is located in Uta. The lease term granted PacifiCorp two independent
early termnation options that provide PacifiCorp the right to termnate the lease an, at PacifiCorp's fuer option, to purchase the
facilty for predetermned amounts. On May 28, 200, PacifiCorp exercised its fit option to termnate the leas and subsequently
exercised its right to rescind the termnation on September 28,200. On December 1,2006, PacifiCorp waived its option to purhasethe facilty under the lease for $122.5 millon and exercised its second option to termnate the lease. As such, PacifiCorp made leas
payments of $10.0 millon for the year ending December 31, 2007 and is commtted to future minimum lease payments of $4.4 millon
for the ear endin December 31, 2008.
Schedule Pa e: 402 Line No.: 42 Column: e3
The Craig Plant 0 rates on coal with sta u provided b oil and natual gas. The com osite rate is 1.307.
chedule Pa e: 402 Line No.: 43 Column: e3
The Crai Plant 0 erates on coal with sta u rovided b oil and natual
chedule Pa e: 402 Line No.: 44 Column: e3
The Craig Plant 0 erates on coal with sta u rovided by oil and natural
Schedule Pa e: 402.1 Line No.: 42 Column: b3
The Ha den Plant 0 erates on coal with star up rovided b oil and natural as. The com osite rate is I.S74.
Schedule Pa e: 402.1 Line No.: 43 Column: b3
The Hayden Plant 0 rates on coal with sta u provided by oil and natual gas. The com osite rate is 0.016.
Schedule Pa e: 402.1 Line No.: 44 Column: b3
The Hayden Plant operates on coal with sta up provided by oil and natual gas. The composite rate is 1O,961.33S.
IFERC FORM NO.1 (ED. 12-S7) Page 450.2
Name of Respondent
PacifCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)(2) DA Resubmissio 04/031
HYDROELECTRIC GENERATING PLANT STATISTICS (lage Plnt)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacit (name plte ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilit, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is availale speifng peri.
. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Year/Period of Report
End of 2007/04
Line
No.
Item FERC Liceed Proec No. 2082
Plant Name:
FERC Licensed Projec No. 208
Plant Name: 11"I~
(a)
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction ty (Conventiona or Outdor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed ca (Gen nae plate Rati in MW)
6 Net Peak Demand on Plant-Megawatt (60 minutes)
7 Plant Hours Connec to Load
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditios
10 (b) Under the Mot Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Right
15 Structures and Improvements
16 Reservoirs, Dams, and Waterwys
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost perKW of Installed Capcity (line 20 / 5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Exnses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reseroirs, Dams, an Waterways
32 Maintenance of Electric Plant
33 Maintenance of Mise Hydraulic Plant
34 Total Production Exenses (total 23 thru 33)
35 Expenses per net KWh
Convention
1918
1922
20.00
25
6,632
Conventional
1925
1925
27.00
32
6,459
180,375
1,28,623
2,637,394
4,629,582
105,442
o
8,781,416
439.0708
20,914
1,642,177
2,922,163
4,352,405
240,200
o
9,177,859
339.9207
153,321
1,283
274
o
337,137
-729
o
9,90
6,908
53,699
18,385
580,182
0.001
191,217
1,732
370
o
453,439
-1,009
o
14,823
24,507
35,84
24,819
745,744
0.00
FERC FORM NO.1 (REV. 12-ÐS)Page 40
............................................
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2007/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 040312008
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Prouction Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1927
Plant Name:
Line
No.
FERC Licensed Project No. 1927
Plant Name: II !! I
FERC Licensed Proiec No. 2420
Plant Name:.e
Outdoor Outdoor
1953 1953 1927
1953 1953 1927
15.00 26.00 30.00
14 16 22
8,212 8,678 3,285
0 0 3,505,129
562,143 1,269,008 3,778,805
4,423,491 10,462,312 6,535,549
1,019,027 1,308,082 1,697,203
39,142 250,151 566,413
0 0 0
6,04,803 13,289,553 16,08,099
402.9202 511.1367 536.1033
92,402 158,743 189,148
9,888 17,139 1,925
99,394 172,284 71,764
0 0 0
278,246 410,215 531,897
1,474 2,556 10,267
0 0 0
19,853 15,472 10,089
37,835 36,113 26,90
123,475 49,365 51,905
40,234 76,181 199,827
702,801 938,06 1,093,731
0.0188 0.0207 0.0247
Page 40FERC FORM NO.1 (REV. 12-()
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2007/Q4(2)DA Resubmission 04032008 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,00 Kw or more of installed capaci (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, indicte such facts in a
footnote. If licensed project, give projec number.
3. If net peak demand for 60 minutes is not availale, give that whic is availabe speifng peri.
4. If a group of employees attends more than one generating plt, reprt on line 11 the apximate average number of employees assignable to each
plant.
Une Item FERC Uced Projec No.1927 FERC Licensed Projec No.20No.Plt Name: ..Plant Name:
(al (C)
1 Kind of Plant (Run-of-River or Storage).Storge
2 Plant Constructn ty (Conventional or Outdoor)Outdoor Conventional
3 Year Originaly Constructed 1952 190
4 Year La Unit was Installed 1952 1923
5 Total installed ca (Gen name plate Rating in MW)11.00 33.00
6 Net Pea Demand on Plant"Megawat (60 minutes)10 30
7 Plt Hours Connect to Lod 4,791 7,232
8 Net Plant Capability (in megawas)
9 (a) Under Mast Favorable Oper Conditions 10 33
10 (b) Under the Most Adverse Oper Coditions 10 33
11 Average Number of Employee 1 4
12 Net Generation, Exclusive of Plant Use - Kwh 35,712,00 76,033,00
13 Cot of Plant
14 Land and Land Rights 0 62,169
15 Structures and Improvements 562,328 1,33,26
16 Reservoirs, Dams, and Waterwys 6,200,989 7,820,729
17 Equipment Costs 1,213,586 3,918,628
18 Roads, Railroads, and Bridges 40,007 65,826
19 Asset Retirement Costs 0 0
20 TOTAL cot (Total of 14 thru 19)8,376,910 13,197,619
21 Cost per KW of Installed Cacity (line 20 / 5)761.5373 399.9278
22 Prouction Expnses
23 Operation Supervision and Engineering 68,442 88,748
24 Water for Power 7,251 2,117
25 Hydraulic Expenses 72,889 88,402
26 Electric Exens 0 0
27 Misc Hydraulic Power Generation Expenses 216,574 1,325,153
28 Rents 1,081 678
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 18,704 32,282
31 Maintenance of Reservoirs, Dams, and Waterways 33,487 74,960
32 Maintenance of Elecric Plant 52,22 112,817
33 Maintenance of Mis Hydraulic Pl 34,707 125,538
34 Total Prodion Exnse (totl 23 thru 33)505,357 1,850,695
35 Exenses per net KWh 0.0142 0.0243
FERC FORM NO.1 (REV. 12-()Page 40.1
............................................
............................................
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~An Original (Me, Da, Yr)
(2) DA Resubmission 04/0312008
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classifed as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, intemal combustion engine, or gas turbine equipment.
YearlPeriod of Report
End of 2oo71Q4
FERC Licensed Proect No. 2082
Plant Name: .. i
FERC Licensed Projec No.
Plant Name:
1927
Outdoor
1962
1962
18.00
18
8,648
Outdoor
1958
1958
97.98
83
6,919
Outdoor
1955
1955
31.99
31
8,590
341,706 26,2n 0
3,927,836 2,325,892 750,905
12,440,215 14,497,614 9,583,097
2,223,662 14,966,04 5,84,214
1,076,116 883,023 475,419
0 0 0
20,00,535 32,698,85 16,653,635
1,111.648 33.7298 520.5888
167,899 44,417 195,327
1,155 6,287 21,08
247 1,34 211,975
0 0 0
345,635 711,486 527,841
.721 641 3,145
0 0 0
537,92 6,982 22,617
14,449 66,183 49,952
28,828 35,429 28,601
16,546 98,404 85,535
1,111,960 1,373,172 1,146,081
0.0093 0.0050 0.0090
FERC FORM NO. 1 (REV. 12-()Page 407.1
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Origina (Mo, Da, Yr)2007/04(2) DA Resubmission 0403/20 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plans)
1. Large plants are hydro plants of 10,00 Kw or more of installed capacit (name plte ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilty, 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 available speifng period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Ucens Proiect No.1927 FERC Licensed Project No.935No.Plant Nam: Plant Name:
(a)(bY leI
1 Kind of Plant (Run-of-River or Storage)Storage (Re-Reg)
2 Plant Construction type (Conventional or Outdor)Outdor Conventional
3 Year Originally Constrcted 1956 1931
4 Year Lat Unit was Installed 1956 1958
5 Tota installed 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 Connet to Load 8,747 8,760
8 Net Plat Capilit (in megawatt)
9 (a) Under Mot Favorable Oper Coditions 34 151
10 (b) Under the Mot Advers Oper Conditns 34 151
11 Average Number of Employe 1 8
12 Net Generation, Exclusive of Plat Use - Kwh 148,711,00 473,420,00
13 Cot of Plant
14 Land and La Rights °1,08,128
15 Structures and Improvements 1,071,057 28,097,831
16 Reservoirs, Dams, and Waterways 17,735,463 9,701,286
17 Equipment Costs 2,089,025 14,080,128
18 Roads, Railroads, and Bridges 1,649,779 1,820,64
19 Asset Retirement Costs °°
20 TOTAL cot (Total of 14 thru 19)22,545,324 54,786,02
21 Cost per KW of Instaled Cacity (line 20 / 5)683.1916 402.8384
22 Producion Exnses
23 Operation Supervision and Engineering 201,100 1,471,765
24 Water for Power 21,754 11,94
25 Hydraulic Expeses 218,66 772,355
26 Elecric Expenses °°
27 Misc Hydraulic Power Generation Expenses 516,896 1,040,399
28 Rents 3,244 14
29 Maintenace Supervision and Engineering °°
30 Maintenance of Structures 34,996 8,155
31 Mantenance of Reservoirs, Dams, and Waterways 56,147 12,235
32 Maintenance of Electric Plant 18,63 33,68
33 Mantenance of Misc Hydraulic Plant 88,494 77,927
34 Total Prouction Exnses (tota 23 thru 33)1,159,937 3,428,480
35 Expses per net KWh 0.0078 0.0072
ÆRC FORM NO.1 (REV. 12.03)Page 406.2
............................................
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2oo7/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/0312008
HYDROELECTRIC GENERATING PLAT 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 Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1927
Plant Name:
Line
No.
FERC Licensed Projec No. 20
Plant Name:
FERC Licensed Projec No. 2630
Plant Name:
e
Conventional
1949
1950
42.50
43
8,683
1915
1920
30.00
23
8,760
Conventional
1928
1928
32.00
32
8,752
0 36,698 105,168
1,492,601 1,36,575 2,60,159
8,299,642 5,109,802 23,555,081
3,170,669 4,707,057 3,576,672
214,603 471,680 191,385
0 0 0
13,1n,515 11,690,812 30,028,465
310.0592 389.6937 938.3895
259,279 80,027 488,058
28,016 1,925 2,05
281,617 80,36 439
0 0 0
620,359 738,211 451,986
4,178 87 2,989
0 0 0
37,824 13,389 50,525
80,785 3,681 81,246
87,889 69,607 35,869
113,637 101,690 49,530
1,513,584 1,088,983 1,162,695
0.0072 0.0295 0.00
Page 407.2FERC FORM NO.1 (REV. 12-()
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)2007/Q4(2)DA Resubmisio 04/0312008 End of
HYDROELECTRIC GENERATING PLA STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacit (name plate ratings)
2. If any plant is leased, operated under a license from the Federa Energy Regulatory Commission, or operated as a joint facilit, indicate such facts in a
footnote. If licensed project, give proect number.
3. If net peak demand for 60 minutes is not available, give tht which is availale speifng peri.
4. If a group of employees attends more than one generating plant, report on line 11 the aproximate average number of employees assignable to each
plant.
Une Item FERC Ucense Proec No. 1927 FERC Licensed Project No.20No.plantName:~Plant Name: II
(a)
1 Kind of Plant (Run-of-River or Storage)Run-of-River Storage
2 Plant Construction ty (Convntion or Outdor)Outdoor Conventioal
3 Year Originally Constructed 1951 1924
4 Year Lat Unit was Instlled 1951 1924
5 Total installed cap (Gen name plate Ratig in MW)18.00 14.00
6 Net Peak Demand on Plant-Mewats (60 minutes)18 7
7 Plant Hours Connect to Lod 8,141 6,350
8 Net Plant Cabilit (in megawatts)
9 (a) Undr Mot Favorale Oper Conditions 18 15
10 (b) Under the Most Adverse Oper Conditions 18 15
11 Average Number of Employees 1 2
12 Net Generation, Exclusive of Plant Use - Kwh 81,721,00 15,156,00
13 Cot of Plant
14 Land and Land Rights °512,946
15 Strutures and Improvements 1,66,828 585,652
16 Reservoirs, Dams, and Waterways 5,58,139 5,00,225
17 Equipment Cots 1,341,717 2,072,224
18 Roads, Railroads, and Briges 16,n8 °
19 Aset Retirement Cots °°
20 TOTAL cot (Total of 14 thru 19)8,607,462 8,1n,047
21 Co per KW of Installed Capacity (line 20 / 5)478.1923 584.0748
22 Prouction Expenses
23 Operation Supervision an Engineering 112,123 37,346
24 Water for Power 17,094 898
25 Hydraulic Expenses 119,273 37,504
26 Electric Expees °°
27 Misc Hydraulic Power Generation Expenses 32,631 396,44
28 Rents 1,769 87
29 Maintenance Supervisio an Engineering °°
30 Mantenance of Structures 33,842 1,259
31 Mantenance of Reservoirs, Dams, and Waterways 30,303 -4,395
32 Maintenance of Electric Pl 73,178 26,44
33 Maintenace of Misc Hydraulic Plant 48,885 43,33
34 Total Proucion Expens (total 23 thru 33)759,098 538,919
35 Expenses per net KWh 0.0093 0.0356
ÆRC FORM NO.1 (REV. 12-03)Page 40.3
............................................
............................................
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2007/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/03/2008
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classifed as "Other Power Supply Expenses."
6. Report as a separate plat any plant equipped with combinations of steam, hydro, internal combustion engine. or gas turbine equipment.
FERC Licensed Project No. 1927
Plant Name:
2071 Line
II IUIII!III: No.
FERC Licensed Proect No. 2111
P~nt Name: ~ I
FERC Licensed Project No.
Plant Name: IIIIIJJ
Storage (Rs-Reg)
Outdor
1952
1952
11.00
12
5,437
Storage
Conventional
1958
1958
240.00
240
5,359
Storage
Coventionl
1953
1953
134.00
163
4,893
°7,813.808 2,776,917
956,491 6,64,724 6,60,88
5,594,167 37,63,791 26,554,793
2,183,095 15,633,362 14,702,865
56,124 395,145 1,395,512
°°0
8,789,877 68.122,830 52.038,972
799.0797 283.8451 388.3505
78,871 2,476.509 1,385,228
7,251 21,081 11,770
72,889 1,483,497 760,997
°°0
236,578 1,164,236 711,650
1,081 -131 .118
°°°
21,849 6,202 19,555
52,017 3.609 6,257
16,33 60,483 43,465
29,412 105,557 70,30
516,281 5,321,04 3,009,108
0.0125 0.005 0.0056
Page 407.3FERC FORM NO. 1 (REV. 12-0)
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2007/Q4(2)DA Resubmission 043120 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Larg Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capcity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilit, 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 available specifng period.
4. If a group of employees attends more than one generating plant, report on line 11 the aproximate average number of employees assignale to each
plant.
Line Item FERC Uc Pro No.0 FERC Licensed Proect No.0No.Pl Nae: ~,Pla Name:
(al (c)
1 Kind of Plan (Run-o-River or Storage)Run-of-River
2 Plant Constructon type (Conventional or Outdoor)Conventional
3 Year Originally Constructed 190
4 Year Last Unit was Instaled 1922
5 Totl installed ca (Gen name plate Rating in MW)10.30 0.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)8 0
7 Plant Hours Connect to Load 6,8n 0
8 Net Plant Capbilit (in megawatt)
9 (a) Under Most Favorale Oper Coditions 10 0
10 (b) Undr th Most Adverse Oper Codiions 10 0
11 Average Number of Employee 4 0
12 Net Generation, Exclusive of Plant Use - Kwh 20,164,00 0
13 Cost of Plant
14 Land and 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 Aset Retirement Costs 0 0
20 TOTAL cot (Tota of 14 thru 19)840,872 0
21 Cost per KW of Installed caac (line 20 1 5)81.631 0.~~
22 Productin Expenses
23 Operation Supervision and Engineering 64,941 0
24 Water for Power 661 0
25 Hydraulic Expenses 24,639 0
26 Elecri Expenses 0 0
27 Misc Hydraulic Power Generation Expenses 327,471 0
28 Rents -15 0
29 Maintenance Supervision and Engineering e 0
30 Maintenance of Structures 34 0
31 Maintenance of Reservoirs, Dams, and Waterays 3,172 0
32 Mantenance of Electric Plant 67,43 0
33 Mantenance of Misc Hydraulic Plat 69,665 0
34 Totl Prouction Expenss (total 23 thru 33)558,315 0
35 Expenses per net KWh 0.02 0.~~
FERC FORM NO.1 (REV. 12-03)Page 40.4
............................................
............................................
Name of Respondent
PacifiCorp
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/0312008
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Year/Period of Report
End of 2007/04
FERC Licensed Proiec No.
Plant Name:
FERC Licensed Projec No.
Plant Name:
o o FERC Licnsed Project No.
Plan Name:
o Line
No.(d)(e
0.00
o
o
0.00
o
o
0.00
o
o
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 00.~~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 00.~~0.000 0.~~
FERC FORM NO. 1 (REV. 12-0)Page 407.4
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 0410312008 2007/Q4
FOOTNOTE DATA
!Schedule Page: 406 Line No.: -1 Column: b
CopcoNo.1
All or some of the renewable energy attbutes associated with ths generation may be used in future years to comply with state or
federal renewable rtolio standards.
chedule Pa e: 406 Line No.: -1 Column: c
CopcoNo.2
Allor some of the renewable energy attbutes associated with ths generation may be used in future yèars to comply with state or
federal renewable portolio standards.
!Schedule Page: 406 Line No.: -1 Column: d
Clearwater No.1
Costs report for ths plant do not include signficant intangible costs due to relicensing and settement, which are recorded in PERC
account 302, Franchises and Consents, and ar not report on ths page. The net book value for relicensing and settlement on the
Nort Umpqua River system for the following projects at Deember 31,2007 was $71.2 millon: Lemolo 1, Lemolo 2, Clearater 1,
Cleawater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the Nort Umpqua Common Plant.
Allor some of the renewable energy attrbutes associate with ths generation may be usd in future year to comply with state or
federal renewable ortolio standards.
chedule Pa : 406 Line No.: -1 Column: e
Clearwater No.2
Costs reported for ths plant do not include signficat intagible costs due to relicensing and settement, which are recorded in PERC
account 302, Franchises and Consents, and are not report on ths page. The net book value for relicensing and settement on the
North Umpqua River system for the following projects at Deember 31, 2007 was $71.2 millon: Lemolo 1, Lemolo 2, Clearwater 1,
Clearater 2, Toketee, Fish Creek, Sod Springs, Slide Crek and th Nort Umpqua Common Plant.
Allor some of the renewable energy attbutes associated with ths generation may be use in futue year to comply with state or
federal renewable ortolio stadads.
chedule Pa e: 406 Line No.: -1 Column: f
Cuder
Costs reportd for ths plant do not include significant intangible costs due to relicensing, which ar recorded in PERC account 302,
Franchises and Consents, and are not reportd on ths page. The net book value for relicensing at December 31, 2007 was $1.2
millon.
Allor some of the renewable energy attbutes associated with ths generation may be used in future years to comply with state or
federal renewable ortolio stadards.
chedule Pa e: 406 Line No.: 1 Column: b
Copco No.1
Ponda e for eakn - stora e, U r Klamth Lae.
chedule Pa e: 406 Line No.: 1 Column: c
Copco No. 2
StoTa e, U r Klamath Lae.
chedule Pa : 406 Line No.: 1 Column: d
Clearwater No.1
Forebay for peakng.
¡SChedule Page: 406 Line No.: 1 Column: e
Clearwater No.2
Forebay for peakng.
!Schedule Page: 406.1 Line No.: -1 Column: bFish Crek
Costs reported for ths plant do not include signficant intangible costs due to relicensing, and settement which are recorded in PERC
account 302, Franchises and Consents, and are not reported on ths page. The net bok value for relicensing and settement on the
Nort Umpua River system for the following projects at December 31, 2007 was $71.2 millon: Lemolo 1, Lemolo 2, Clearater 1,
Clearater 2, Toketee,Fish Creek, Soda Springs, Slide Creek and the Nort Umpqua Common Plant.
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 04/0312008 2007/Q4
FOOTNOTE DATA
¡Schedule Page: 406.1 Line No.: -1 Column: c
Grace
Costs reportd for ths plant do not include significant intangible costs due to relicensing, and settlement which are recorded in PERC
account 302, Franchises and Consents, and are not reported on ths page. The net book value for relicensing and settlement on the
Bear River system for the following projects at December 31,2007 was $15 millon: Grace, Oneida and Soda.
Allor some of the renewable energy attbutes associated with ths generation may be used in futue year to comply with state or
federal renewable ortolio standards.
Schedule Pa e: 406.1 Line No.: -1 Column: d
Irn Gate
Allor some of the renewable energy attibutes associated with ths generation may he used in futue year to comply with state or
federal renewable ortolio stadards.
chedule Pa e: 406.1 Line No.: -1 Column: e
JCBoyie
Allor some of the renewable energy attibutes associated with upgrades to ths generation may be used in futue year to comply with
state or federal renewable porolio standards.
'$hedule Page: 406.1 Line No.: -1 Column: f
LemoloNo.l
Costs report for ths plant do not include significant intangible costs due to relicensing, and settlement which are recorded in PERC
acount 302, Franchises and Consents, and are not reported on ths page. The net book value for relicensing and settement on th
North Umpqua River system for the following projects at December 31, 2007 was $71.2 millon: Lemolo 1, Lemolo 2, Clearater 1,
Cleaater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the Nort Umpqua Common Plant.
Allor some of the renewable energy attbutes associated with upgrades to ths generation may be used in futue year to comply with
state or federal renewable ortolio stadards.
chedule Pa e: 406.1 Line No.: 1 Column: b
Fish Crek
Foreba for eakn .
Schedule Pa e: 406.1 Line No.: 1 Column: d
Iron Gate
Stora e for re lation.
hedule Pa e: 40.1 Line No.: 1 Column: e
JCBoyle
Ponda e for akin - stora e, U er Klamth Lae.cheduJe Pa e: 406.1 Column: f
LemoloNo.l
Storage, Lemolo Lae.
!Schedule Page: 40.2 Line No.: -1 Column: b
Lemolo No. 2
Costs reported for ths plant do not include significant intangible costs due to relicensing, and settlement which are recorded in PERC
account 302, Franchises and Consents, and are not reported on ths page. The net book value for relicensing and settlement on the
Nort Umpqua River system for the following projects at December 31,2007 was $71.2 millon: Lemolo 1, Lemolo 2, Clearater 1,
Clearwater 2, Toketee, Fish Creek, Soda S rings, Slide Creek and the Nort Urn ua Common Plant.
chedule Pa e: 406.2 Line No.: -1 Column: c
Merwin
Costs reported for ths plant do not include significant intangible costs due to relicensing, and settlement which are recorded in PERC
account 302, Franchises and Consents, and are not reportd on ths page. The net book value for relicensing and settement on the
Lewis River s stem for the followin roOects at December 31, 2007 was $429 thousand: Merwn, Yale, and Swift #1.
chedule Pa e:40.2 Line No.: -1 Column: d
Tokete
Costs reportd for ths plant do not include significant intangible costs due to relicensing, and settlement which are recorded in PERC
account 302, Franchises and Consents, and are not reported on ths page. The net book value for relicensing and settlenient on the
Nort Umpua River system for the following projects at December 31,2007 was $71.2 millon: Lemolo 1, Lemolo 2, Clearater 1,
I FERC FORM NO.1 (ED. 12-87) Page 450.2
Allor some of th renewable energy attbutes associated with ths generation may be use in future years to comply with state or
federal renewable portolio standards.
'$chedule Page: 40.3 Line No.: -1 Column: e
Swüt#l
IFERC FORM NO.1 (ED. 12-S7) Page 450.3
............................................
Name of Respondent This Report is:Date of Report Yea~Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04312008 2007/Q4
FOOTNOTE DATA
Clearater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the Nort Umpqua Common Plant.
Allor some of the renewable energy attbutes associated with ths generation may be used in future yeas to comply with state or
federal renewable ortfolio standards.
chedule Pa e: 406.2 Line No.: -1 Column: e
Oneida
Costs reported for ths plant do not include signficant intangible costs due to relicensing, and settlement which are recorded in PERC
account 302, Franchises and Consents, and are not report on ths page. Th net book value for relicensing and settement on the
Bear River system for the following projects at Deember 31, 2007 was $15 millon: Grace, Oneida and Soda.
Allor some of the renewable energy attbutes associate with ths generation may be used in futue years to comply with state or
federal renewable ortolio stadards.
hedule Pa e: 406.2 Line No.: -1 Column: f
Prospect No.2
Allor some of the renewable energy attbutes associated with ths generation may be us in future year to comply with state or
fedral renewable portolio stadads.
'$chedule Page: 406.2 Line No.: 1 Column: b
LemoloNo.2
Stora e, Lemolo Lae.
chedule Pa e: 406.2 Line No.: 1 Column: d
Tokete
Ponda e for eak - stor e, Lemolo Lae.
chedule Pa e: 406.2 Line No.: 1 Column: f
Propect No.2
Forebay for peakng.
!Schedule Page: 406.3 Line No.: -1 Column: b
Slide Creek
Costs reported for ths plant do not include signficant intangible costs due to relicensing, and settlement which are recorded in PERC
account 302, Franchises and Consents, and are not report on ths page. The net book value for relicensing and settlement on the
Nort Umpqua River system for the following projects at December 31, 2007 was $71.2 millon: Lemolo 1, Lemolo 2, Clearater 1,
Clearwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and th Nort Umpua Common Plant.
Allor some of the renewable energy attbutes associate with ths generation may be use in future years to comply with state or
federal renewable ortolio standards.
cheule Pa e: 406.3 Line No.: -1 Column: c
Sod
Costs reported for ths plant do not include significant intangible costs due to relicensing, and settlement which are recorded in PERC
account 302, Franchises and Consents, and are not reported on ths page. The net book value for relicensing and settement on th
Bear River system for the following projects at Deember 31, 2007 was $15 millon: Grace, Oneida and Soda.
Allor some of the renewable energy attbutes associated with ths generation may be used in futur years to comply with state or
federal renewable ortolio stadards.
Schedule Pa e: 406.3 Line No.: -1 Column: d
Sod Spri
Costs reported for ths plant do not include signficant intagible costs due to relicensing, and settement whch are recorded in PERC
account 302, Franchises and Consents, and ar not report on ths page. The net book value for relicensing and settement on the
Nort Umpqua River system for the following projects at December 31, 2007 was $71.2 millon: Lemolo 1, Lemolo 2, Clearwater 1,
Cleawater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
Costs reportd for this plant do not include significant intangible costs due to relicensing, and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on ths page. The net book value for relicensing and settlement on the
Lewis River system for the following rojects at December 31, 2007 was $429 thousand: Merwn, Yale, and Swift #1.
chedule Pa e: 406.3 Line No.: -1 Column: f
Yale
Costs reported for this plant do not include significant intangible costs due to relicensing, and settement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on ths page. The net book value for relicensing and settement on the
Lewis River s stem for the followin rojects at December 31, 2007 was $429 thousand: Merwn, Yale, and Swift #1.
chedule Pa e: 406.4 Line No.: -1 Column: b
Olmstead
The 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-S7) Page 450.4
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2007/Q4
This ~rt Is: Date of Report
(1) IlAn Original (Mo, Da, Yr)
(2) A Resubmission 0403120
G NERATING PLANT STATISTICS (Small Plants
1. Small generating plants are steam plants of, less than 25,00 Kw; internl combustion and gas turbine-plants, conventional hydro plants and pumpe
storage plants of less than 10,00 Kw installed capacity (name plate rating). 2. Designate any plant leaed from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project,
give project number in footnote.
Line Net Generation Cot of PlantName of Plant ExcludingNo.Plant Use
(e)(f)
1907 0.95
1917 6.85 6.3 30,91 8,788,512
1907 2.52 1.2 7,151
1913 1.11 1.2,863 896,299
1910 4.15 4.24,435 6,642,931
1913 1.00 1.1 302,594
1913 13.70 15.84,395 6,924,313
1957 2.81 2.8 18,52 1,791,40
1924 3.20 3.0 10,52 1,896,121
1903 2.20 2.0 13,049 1,088,570
1922 0.16 0.2 624 451,779
1896 2.00 0.8 1,796 4,896,073
1917 0.75 0.3 776 596,34
1983 1.73 1.3,00 2,715,132
1910 0.72 0.6 1,905 313,213
1897 5.00 4.0 12,263 9,818,038
1912 3.76 3.14,729 95,772
1932 7.2 7.2 44,199 6,930,313
194 1.00 0.9 2,024 371,469
1926 0.80 0.2 707 86,056
1910 1.18 0.5 2,837 90,669
1895 1.00 1.1 4,13 1,179,463
1915 0.50 1,337,279
1920 0.50 0.2 717 721,36
1986 0.74 O.651 1,169,596
1921 1.10 1.0 6,162 2,770,134
1911 3.85 2.0 16,483 2,728,814
190 0.60 0.6 371 354,926
7,475,589
4,979,168
13,381,109
1917 -4.50 -3.0 -4,963 16,501,074
1998
20
207
32.62
100.50
140.40
32.6
100.0
138.
95,139
289,452
160,63
36,966,153
172,38,705
238,779,233
FERC FORM NO.1 (REV. 12-0)Page 410
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) ri A Resubmission 04/0312008
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 withcombinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilzed in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cot (Incl Asset Operation Prouction Expenses Fuel Costs (in cents LineRetire. Costs) Per MW Exc'i. Fuel Fuel Maintenance Kind of Fuel (per Millon Btu)(g)(h)(i)(j (k)(I)
No.
1
18,999 6,112 Water 2
1,282,994 398,222 83,598 Water 3
138,148 5,927 Water 4
807,477 122,635 8,088 Water 5
1,600,708 192,80 286,279 Water 6
302,594 4,752 941 Water 7
505,424 275,987 86,177 Water 8
637,510 212,962 72,156 Water 9
592,538 69,66 25,423 Water 10
494,805 73,424 59,126 Water 11
2,823,619 23,754 15,778 Water 12
2,448,037 115,141 15,065 Water 13
795,131 75,108 42,44 Water 14
1,569,44 137,598 37,589 Water 15
43,018 48,784 23,003 Water 16
1,96,608 245,43 167,440 Water 17
253,66 106,328 26,902 Water 18
962,543 263,217 91,813 Water 19
371,469 33,463 10,527 Water 20
1,075,070 75,660 52,594 Water 21
766,669 87,825 17,775 Water 22
1,179,463 104,262 34,894 Water 23
2,674,558 31,146 2,492 Water 24
1,454,720 105,866 26,86 Water 25
1,580,535 34,349 12,159 Water 26
2,518,30 44,283 58,165 Water 27
708,783 212,027 78,142 Water 28
591,543 21,290 17,552 Water 29
2,569 13,533 30
-872,83 39,970 31
32
33
34
-3,666,905 236,218 35,871 Water 35
36
37
1,133,236 1,487,206 Wind 38
1,715,271 3,386,951 Wind 39
1,700,707 1,879,278 Wind 40
41
42
43
44
45
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 (2) A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
!Schedule Page: 410 Line No.: 1 Column: a
Common river s stem costs for the 0 eration of thse facilties ar allocate to each
chedule Pa e: 410 Line No.: 2 Column: a
American Fork
In August 200, the PERC authorized the removal of the I-MW (nameplate rating) American Fork hydroelectrc plant and facilties.
Decommssioning of the American Fork facilties has ben complete in accordance with the approved removal plan. The removal of
the dam, flowline and all facilities, with the exception of the powerhouse that has been designated a historical landmak, was
completed in December 2007. As of December 31, 2007, $4 millon had been spent for the decommssioning of the American Fork
h droelectric ro . ect.
SChedule Pa e: 410 Line No.: 3 Column: a
Ashton
Allor some of the renewable energy attbutes associate with ths generation may be use in futue years to comply with state or
federal renewable portolio stadads.
Costs reportd for ths plant do not include significant intangible costs due to relicensing which are recorded in PERC account 302,
Franchises and Consents, and are notre ortd on ths a e. The net book value for relicensin at December 31, 2007 was $375,259.
chedule Pa e: 410 Line No.: 4 Column: a
Upper Beaver
On September 14,2007, PacifiCorp closed the sale of the Upper Beaver Hydroelectrc Project, Federal Energy Regulatory
Commssion ("PERC") Project No. 814, assets and water rights, to the City of Beaver, Uta, for $2 millon. In accordance with
18 CFR Par 4.94 (t) Arcle 6, notification of the transfer of th license exemption was filed with the PERC. The Upper Beaver
Hydroelecc Project is locate in southwestern Uta, on th Beaver River nea th City of Beaver, upon United States Forest Service
("USFS") lands in the Fish Lae National Forest, and operate under th authority of a special use permt with the USFS. The
proceeds, net book value, and sellng costs were tranferred to account 102, Electrc plant purchas or sold. In March 2008,
PacifiCorp filed with the PERC th joural entres called for by the Uniform System of Accounts. The sale was approved by th
W oming, Ore on and Californa state commssions.
chedule Pa e: 410 Line No.: 5 Column: a
Bend
All or some of the renewable energy attbutes associated with ths generation may be used in future year to comply with state or
federal renewable portolio standards.
Costs reported for ths plant do not include significant intangible costs due to relicensing which are recorded in PERC account 302,
Franchises and Consents, and are not re ortd on ths a e. The net book value for relicensin at December 31, 2007 was $281,224.
chedule Pa e: 410 Line No.: 6 Column: a
BigFork
Allor some of the renewable energy attbutes assoiate with ths generation may be use in futue year to comply with state or
federal renewable portolio stadads.
Costs reported for ths plant do not include significant intangible costs due to relicensing which are recorded in PERC account 302,
Franchises and Consents, and are not re rtd on ths a e. The net book value for relicensin at December 31, 2007 was $573,106.
Schedule Pa e: 410 Line No.: 7 Column: a
Cline FaUs
Allor some of the renewable energy attibutes associated with ths generation may be used in future years to comply with state or
federal renewable ortfolio stadards.
chedule Page: 410 Line No.: 8 Column: a
Condit
In September 1999, a settement agrement to remove the 100MW (nameplate rating) Condit hydroelectrc project was signed by
PacifiCorp, state and federal agencies and non-governenta organizations. Under the original settement agreement, removal was
expected to begin in October 2006, with a tota cost to deommssion not to exceed $ I 7 millon, excluding inflation. In early
Februar 2005, the pares agr to modify the settlement agreement so tht removal will not begin until October 2008 for a tota
cost to decommssion not to excee $21 millon, excluding inflation. The settement agreement is contingent upon receiving a PERC
surrender order and other regulatory approvals that are not materially inconsistent with the amended settlement agreement. PacifiCorp
/FERCFORM NO.1 (ED. 12-87) Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/03/2008 2007/Q4
FOOTNOTE DATA
is in the process of acquiring all necessary permts, within the terms and conditions of the amended settlement agreement. If the
permtting process continues into the secönd quarr of 2008, the decommssioning wil not begin until October 200.
Costs reported for ths plant do not include signficant intangible 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, 200 was $120,264.
Schedule Pa e: 410 Line No.: 9 Column: a
Eagle Point
Allor some of the renewable energy attbutes associated with ths generation may be used in future year to comply with state or
federal renewable ortolio standards.
hedule Pa e: 410 Line No.: 10 Column: a
Eatside
Allor some of the renewable energy attbutes associated with ths generation may be used in future years to comply with state or
federal renewable ortolio stadards.
chedule Pa e: 410 Line No.: 11 Column: a
Fal Crek
Al or some of the renewable energy attbutes associated with ths generation may be used in futue years to comply with state or
federal renewable rtolio standards.
Schedule Pa e: 410 Line No.: 12 Column: a
Fountain Gren
Allor some of the renewable energy attbutes associated with ths generation may be used in futue year to comply with state or
federal renewable portolio stadards.
Costs reported for ths plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302,
Franchises and Consents, and ar not re orted on this a e. The net book value for relicensin at December 31, 200 was $8,608.
Schedule Pa e: 410 Line No.: 13 Column: a
Granite
Allor some of th renewable energy attbutes associated with ths generation may be used in future year to comply with state or
federal renewable ortolio stadards.
hedule Pa e: 410 Line No.: 14 Column: a
Gunlock
Allor some of the renewable energy attibutes associated with ths generation may be used in futue years to comply with state or
federal renewable portolio standars.
Costs reported for ths plant do not include signficant intangible costs due to relicensing which are recorded in FERC accout 302,
Franchises and Consents, and are not re orted on ths a e. The net book value for relicensin at December 31, 2007 was $52,775.
hedule Pa e:410 Line No.: 15 Column: a
Last Chance
Allor some of the renewable energy attbutes associated with ths generation may be used in futue year to comply with state or
federal renewable ortolio stadads.
chedule Pa e: 410 Line No.: 16 Column: a
Paris
Allor some of the renewable energy attibutes associated with ths generation may be used in future year to comply with state or
federal renewable portolio standards.
fSchedule Page: 410 Line No.: 17 Column: a
Pioneer
Allor some of the renewable energy attibutes associate with ths generation may be used in future years to comply with state or
federal renewable portolio standards.
Costs reported for ths plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302,
Franchises and Consents, and are not re orted on ths a e. The net book value for relicensin at December 31, 2007 was $125,995.
chedule Pa e: 410 Line No.: 18 Column: a
Prospect 1
Allor some of the renewable energy attbutes associated with ths generation may be used in futue years to comply with state or
IFERC FORM NO.1 (ED. 12-S7) Page 450.2
federal renewable portfolio standards.
¡Schedule Page: 410 Line No.: 19 Column: a
Prospect 3
Allor some of the renewable energy attbutes associated with ths generation may be used in future year to comply with state or
federal renewable portolio stadards.
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
Costs reported for ths plant do not include significant intangible costs due to relicensing which are recorded in PERC account 302,
Franchises and Consents, and are not reported on ths page. Th net bok value for relicensing at Prospect unit number 3 on December
31,2007 was $107,837.
!SChedule Page: 410 Line No.: 20 Column: a
Prospet 4
Allor some of the renewable energy attibutes associate with ths generation may be us in fu year to comply with state or
federal renewable portolio stadards.
¡Schedule Page: 410 Line No.: 21 Column: a
Sand Cove
Allor some of the renewable energy attbutes associate with ths generation may be us in fue year to comply with state or
federal renewable ortfolio standads.
hedule Pa e: 410 Line No.: 22 Column: a
Snake Crek
Allor some of the renewable energy attbutes associated with ths generation may be used in future year to comply with state or
federal renewable portolio standards.
Išchedule Page: 410 Line No.: 23 Column: a
Stairs
Allor some of the renewable energy attbutes associate with ths generation may be use in fue years to comply with state or
federal renewable portolio standards. .
Allor some of the renewable energy attrbutes associated with ths generation may be used in futue yeas to comply with state or
federal renewable ortolio standards.
chedule Pa e: 410 Line No.: 25 Column: a
Veyo
Allor some of the renewable energy attibutes associate with ths generation may be use in future years to comply with state or
federal renewable portolio standards. .
¡Schedule Page: 410 Line No.: 26 Column: a
Viva Naughton
Allor some of the renewable energy attbutes associated with ths generation may be used in future years to comply with state or
federal renewable portolio standards.
¡Schedule Page: 410 Line No.: 27 Column: a
WaUowa Falls
Allor some of th renewable energy attrbutes associate with ths generation may be used in future years to comply with state or
federal renewable ortolio stadards.
chedule Pa e: 410 Line No.: 28 Column: a
Weber
All or some of the renewable energy attbutes associated with ths generation may be used in futue years to comply with state or
federal renewable portolio stadards.
Costs reported for ths plant do not include signficant intangible costs due to relicensing which are recorded in PERC account 302,
Franchises and Consents, and are not reported on ths page. The net book value for relicensingat December 31, 2007 was $383,296.
IFERC FORM NO.1 (ED. 12-87) Page 450.3
-...........................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp i2) A Resubmission 04/0312008 2007/04
FOOTNOTE DATA
ISchedule Page: 410 Line No.: 29 Column: a
West Side
Allor some of the renewable energy attributes associated with ths generation may be used in future years to comply with state or
federal renewable ortolio standards.
chedule Pa e: 410 Line No.: 30 Column: a
Keno Regulating Dam
Used in regulating the release of water from Klamth Lae and in maintaining proper water sudace level in the Klamath River between
Klamth Falls and Keno, Ore on.
Schedule Pa e: 410 Line No.: 31 Column: a
Upper Klamath Lake
Storage reservoir for six plants on the Klamth River (Copco No.1, Copco No.2, Eat Side, West Side, John C. Boyle, and Iron
Gate).
¡Schedule Page: 410 Line No.: 32 Column: a
Nort Umpqua
Common plant in Nort Umpqua Project. All common roads, employee houses, control equipment, etc. ar in ths account.
Costs repored for ths plant do not include significant intangible costs due to relicensing and settement which ar recorded in PERC
account 302, Franchises and Consents, and are not reported on ths page. Th net bok value for relicensing and settement on the
Nort Umpqua River system for the following projects at Deember 31, 2007 was $71.2 millon: Lemolo 1, Lemolo 2, Oearater 1,
Clearater 2, Toketee, Fish Creek. Soda S nn s, Slide Creek and the Nort Urn ua Common Plant.
hedule Pa e: 410 Line No.: 38 Column: a
Foote Creek
The Foote Creek Wind Far is operated by Sea West Energy and is jointly owned. Costs reported for ths plant represents the
respondents share. Ownership of the plant is as follows: PacifiCorp 78.79%, Eugene Water and Electrc Board 21.21 %.
All or some of th renewable energy attbutes associated with ths generation may be used in futur years to comply with state or
federal renewable ortolio standads.
chedule Pa e: 410 Line No.: 39 Column: a
Lenig Juniper #1
Allor some of the renewable energy attbutes associated with ths generation may be used in future years to comply with state or
federal renewable portolio standards.
The cost of lant balance includes $478,678 of asset retiement costs.
chedule Pa e: 410 Line No.: 40 Column: a
Marengo
Allor some of the renewable energy attbutes associated with this generation may be used in futu years to comply with state or
federal renewable portfolio standards.
The cost of plant balance includes $475,680 of asset retirement costs.
IFERC FORM NO.1 (ED. 12-87) Page 450.4
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Me, Da, Yr)End of 2007/04
(2) FiA Resubmission 04031200
TRANSMISSION LINE STATIST CS
1. Report information conceming trasmission lines, cost of Iil)es, and expes for year. LIst each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plt costs are includ in Acnt 121, Nonutility Prort.
5. Indicate whether the type of supporting structure reported in coumn (e) is: (1) single poe wo or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line ha more than one ty of supprting struure, indicte the mileage of each type of constructon by
the use of brackets and extra lines. Minor portions of a transmision line of a dierent ty of construction nee 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 struures 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
poe miles of line on leased or partly owned structures in column (g). In a footnte, expain the bais of suc ocupancy and state whether expnses wih
respec to such structures are included in the expenses reported for the line deignated.
LIne
(Indicte .;~;'Type of LE~~l~ ~gie óliles)
NumberNo.~~u:ohl_\u ë1ergrounlfllnes
Supporting report circuit miles)Of
From To Operang De I un ò:lflure unf1H~Wi~res CircutsStruure~~i~ed of not erine(a)(b)(c)(d)(e)(g)(h)
1 Malin,OR Indian Springs, CA 50.01 50.00 Stee Tow 47.00 1
2 Mint, 10 Malin, OR 50.01 50.00 Stee Tower 44.00 1
3 Malin,OR Meord,OR 50.01 50.00 Steel Towe 84.00 1
4 Dixonville Sub, OR 500.01 50.00 Steel Tower 58.00 1
5 Main,OR Captain Jack, OR 500.01 500.00 Stee Towe 7.00 1
6 Meridian,OR 500.01 500.00 Steel Tower 74.00 1
7 Switchyard, MT 50.01 50.00 Steel Towr 1.00 1
8 Broadview A, MT 50.01 50.00 St Towr 112.00 1
9 Broadvew B, MT 50.01 50.00 Stee Towr 116.00 1
10 Towsend A, MT 50.01 50.00 Stee Tow 133.00 1
11 Townsend B, MT 50.01 50.00 St Towr 133.00 1
12 500 kV expenses
13
14 Subtotl 50 kV 584.00 627.00 11
15
16 Be Lomond Sub., UT Borah Substation, 10 345.01 345.00 Steel- H 133.00 1
17 Ben Lomond Sub., UT Terminal Substatio, UT 34.34.00 Steel- 0 47.00 2
18 Spaish Fork SUb., UT Camp Williams Sub., UT 345.34.00 Steel-SP 35.00 2
19 Huntington Plant, UT Sigurd Substation, UT 34.34.00 Stee - H 95.00 1
20 Hunton PI. Sub., UT Spanish Fork Sub., UT 34.34.00 Stee - H 78.00 1
21 Terminal Substation, UT Ninety Souh Sub., UT 34.0 34.00 Stee - SP 16.00 2
22 Emery Substatio, UT Sigurd Substati, UT 34.0 34.00 Stee - H 75.00 1
23 Sigurd Substation, UT camp Willias SUb., UT 34.0 34.00 Stee - H-P 116.00 1
24 Camp Willams Sub., UT Ninety South Sub., UT 34.01 34.00 Stee - SP 11.00 2
25 Terminal Substation, UT Cap Williams Sub., UT 34.01 34.00 Stee - 0 26.00 1
26 Emery Substation, UT camp Willias Sub., UT 34.0(34.00 Steel- H 121.00 1
27 Newcastle, UT Utah - Nevada Border 34.01 34.00 Stee - 0 54.00 1
28 Sigurd Substation, UT Newcastle, UT 34.01 34.00 Steel- 0 137.OC 1
29 Gohen Substation, 10 Kinport Subsation, 10 34.01 34.00 Stee - H 41.00 1
30 Huntington Plant, UT Four Comers Sub., NM 345.01 345.00 Woo-U 101.00 1
31 Camp Willams Sub., UT Huntington Plant, UT 34.0(345.00 Wood-U 107.00 1
32 Huntington Plant, UT Pinto Substation, UT 345.0(345.00 Woo-U 160.00 1
33 Camp Willams Sub., UT Sigurd Substation, UT 34.01 34.00 Wood-U 70.00 1
34 Jim Bridger Plant #3, WY Borah Substation, 10 34.01 34.00 Steel Tower 240.00 1
35 Jim Bridger Plant #2, WY Kinport Substation, 10 345.01 345.00 Stee Tower 234.00 1
36 TOTAL 15,494.00 m.oo 210
FERC FORM NO.1 (ED. 12-87)Page 422
............................................
............................................
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 040312008
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. R.eport Lower voltage Lines and higher vohage 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, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, bais of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts afected. Specif whether lessor, co-owner, 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. Base the plant cost figures called for in columns 0) to (I) on the boo cot at end of year.
VV~ i VI" LINi: (inciuae in coiumn U) Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-o-way)
Coductor
and Material Lad Construction and Total Cot Operation Mantenance Rents Totl IUneOther Costs Expenses Expenses (0)Exenes No.(i)(j)(k)(I)(m)(n)(p)
.1852 134,35f 5,551,720 5,68,076 1
272.0 3,08,4lX 151,381,95 154,468,356 2
272.0 2,907,17!38,015,889 40,923,06 3
272.0 1,468,20.19,597,617 21,06,821 4
272.0 9,231 1,460,042 1,46,27,5
272.0 4,769,43 26,255,86 31,025,301 6
95 KCMACSR 25,651 25,65 7
1795 KCM ACSR 218,75'5,413,613 5,632,372 8
1795 KCM ACSR 276,82'7,158,284 7,435,109 9
1795 KCM ACSR 418.61.6,56,174 6,986,787 10
175 KCM ACSR 436,161 6,491,204 6,927,372 11
16,507 853,926 99,199 *************12
13
13,725,16!267,920,022 281,645,181 16,507 853,926 99,19~***********14
15
p54.0 5,229,65,35,321,732 40,551,385 16
272.0 9,369,701 22,112,724 31,482,432 17
272.0 5,508,401 10,158,595 15,667,00 18
ß5.0 34,17 20,08,785 20,423,959 19
~54.0 855,931 17,683,26~18,539,205 20
272.0 2,557,85E 7,457,557 10,015,412 21
~54.0 320,31f 13,619,157 13,939,473 22
~54.0 510,49C 25,192,64 25,703,136 23
272.0 482,86E 3,89,713 4,378,579 24
272.0 4,301,93 7,970,335 12,272,272 25
95.0 926,251 27,921,108 28,847,359 26
954.0 2,320,87 50,682,835 53,00,707 27
954.0 56,0s(13,605,651 13,661,701 28
95.0 313,47i 2,571,824 2,88,301 29
954.0 117,66,2,893,80 3,011,~30
95.0 893,96 19,882,39 20,n6,35E 31
95.0 32
95.0 179,5lY 16,211,90 16,391,4OE 33
1272.0 1,128,22,26,302,241 27,430,4~34
272.0 1,09,79f 28,083,72E 29,183,524 35
85,897,343 1,695,585,078 1,781,482,421 125,807 13,323,841 1,316,314 14,765,96,36
FERC FORM NO.1 (ED. 12-87)Page 423
Name of Respondent This '00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmissio 040312
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of Iil'es, and expnses for year. Us each transmissio line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltge.
2. Transmission lines include all lines covered by the definition of trasmission system plant as gien in the Unifrm System of Accounts.1D0 not reportsubstation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commisio.
4. Exclude from this page any transmission lines for which plant cots are includ in Acnt 121, Nonutlit Property.
5. Indicate whether the type of supporting struure reported in column (e) is: (1) single poe woo or steel; (2) H-frame wood, or steel POIEIS; (3) tower;
or (4) underground construction If a transmision line has more than one ty of supportng struure, indicate the mileage of each ty of (~onstruction by
the use of brackets and extra lines. Minor portions of a transmission 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 totl poe miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reprted for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses wih
respet to such structures are included in the expenses reported for th line deignted.
Une (Inde .J~Typ of LE~G;h~ ~ie o'il91;)NumberNo.òterth u ~ergrolflines Of6Ó CVe 3 Dh lSe\Suppoing reprt circit mile)
From To Opting Deign on ~(flClure v~~u~wres CircuitsStructureof. Line I)ot ieI'Desl8lated ine(a)(b)(c)(d)(e)(g)(h)
1 Currant Creek Swtchrd, UT Mona Substin, UT 34.01 34.00 Steel.SP 1.00
2 Camp Wilias Sub, UT Mona Sub, UT 34.01 34.00 Woo.SP 8.OC 42.00 1
3 345 kV expense
4
5 Subtota 345 kV 1.90.00 42.00 25
6
7 Fairview, OR Isthmus, OR 230.01 230.00 HFrameWoo 12.00 1
8 Antelope Sub., ID Lost River 230kV Line, ID 23.lX 23.00 Woo.H 20.00 1
9 Walla Walla, WA Hells Canyon, ID 23.lX 230.00 H Fra Woo 78.00 1
10 Bethel,OR Fry,OR 23.lX 230.00 HFraWoo 26.00 1
11 Fry,OR Dixonville, OR 23.lX 23.00 HFraeWoo 45.00 1
12 Alvey,OR Dixonville, OR 230.lX 230.00 H Frame Woo 59.00 1
13 Troutdale, OR Linneman, OR 23.lX 230.00 Steel Towr 6.00 1
14 Trodale, OR Gresham,OR 230.lX 230.00 Steel Tower 6.00 1
15 McNary, WA Walla Walla, WA 23O.lX 230.00 H Fra Woo 56.00 1
16 BPA Heppner, OR Dalred Substation, OR 230.0(230.00 H Frame Woo 1.00 1
17 Sigurd Substation, UT Garfeld, UT 230.01 230.00 Woo.U 117.00 1
18 Dixonvile, OR Reston, OR 23O.lX 230.00 H Frame Woo 17.00 1
19 Yamsey,OR Klamath Falls, OR 230.lX 230.00 H Frame Woo 56.00 1
20 Yamsey,OR Klamath Falls, OR 23O.lX 230.00 Steel Towr 6.OC 1
21 Dixonville, OR Lone Pine, OR 23O.lX 23.00 H Frae Woo 8.00 1
22 Klamath Falls, OR Medord, OR 23O.lX 230.00 H Frame Woo 76.00 1
23 Klamath Falls, OR Malin. OR 23O.lX 230.00 HFrameWoo 35.00 1
24 Table Rock, SW Station, OR Grats Pas, OR 23.lX 230.00 HFraWoo 35.00 1
25 Grants Pas, OR Days Creek, OR 230.01 230.00 H Frame Woo 71.00 1
26 Dixonvile, OR Dixonville, OR 23O.lX 230.00 Woo 1.00
27 Sigurd Substation, UT Pavant Substation, UT 230.01 230.00 Woo-U 43.00 1
28 Pavant Substation, UT Nevada. Utah State line 230.01 230.00 Woo-U 98.00 1
29 Banock Pass, ID Antelope Sub., ID 23O.0l 230.00 Woo.U 76.00 1
30 Brady Substation, ID Treasureton Sub., ID 23O.0l 230.00 Woo.U 66.00 1
31 Ben Lomond Sub., UT Naughton PIt. #1, WY 23O.0l 230.00 Woo-U 88.00 1
32 Sigurd Substation, UT Arizona - Utah State line 23O.lX 230.00 Woo.U 149.00 1
33 Birch Creek Sub., WY Railroad Substation, WY 230.0l 230.00 WDod.HSW 12.00 1
34 Birch Creek Sub., WY Railroad Substation, WY 23O.OC 230.00 Woo.HSW 7.00 1
35 Ben Lomond Sub., UT Naughton Pit. #2, WY 23O.OC 230.00 Woo.U 59.00 1
36 TOTAL 15,494.OC m.oo 210
FEACFORM NO.1 (ED. 12-87)Page 422.1
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) fjA Resubmission 04/03/2008
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure 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 Iines. 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 porton thereof, for
which the respondent is not the sole owner but which the respodent operates or shares in the operation of, fumish a succinct statement explaning the
arrngement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Une, and how the expenses borne by the respondnt are accunted for, and accounts affected. Specif whether lessor, co-owner, 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 lee, annual rent for year, and how
determined. Specif whether lessee is an associated company.
10. Base the plant cost figures called for in columns Ol to (I) on the bok cost at end of year.
vv;: i ~. ....... \.nciuae in COlumn U) Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction an Total Cot Operation Maintenance Rents Total UneOther Costs Expnses Expenses Ex~
(i)Ol (k)(I)(m)(n)(0)(p)No.
1,178,479 1,178,476 1
272 9,578,059 9,578,056 2
1,160,237 246,299 .....****3
4
36,516,141 362,40,536 398,920,6n 1,160,237 246,299 **********'*5
6
54.0 285,32 1,702,523 1,987,845 7
79.0 12,921 1,200,282 1,213,211 8
272.0 64,39'11,244,11/11,30,501 9
272.0 351,98!1,90,416 2,260,39E 10
272.0 485,891 4,96,451 5,454,347 11
54.0 1,428,24 14,703,211 16,131,45 12
~4.0 423,03E 423,036 13
54.0 36,71 574,07/937,791 14
272.0 220,96 3,403,514 3,624,481 15
95.0 108,025 108,025 16
95.0 468,99:7,66,343 8,129,33 17
39,971 1,558,343 1,598,314 18
95.0 19
95.0 473,36 4,453,059 4,926,425 20
95.0 439,~4,128,249 4,567,81.21
95.0 173,6O 6,06,263 6,238,871 22
1172.0 115,441 1,798,928 1,914,376 23
ßs4.0 191,12 5,203,472 5,394,596 24
272.0 379,961 11,874,572 12,254,533 25
272.0 508,736 50,73 26
95.0 41,491 4,372,03 4,413,537 27
95.0 28
272.0 5,10~2,481,761 2,48,86 29
175.0 72,111 2,165,408 2,237,526 30
rr.O 426,121 4,570,641 4,996,767 31
954.0 22,64'4,584,254 4,60,897 32
954.0 165,05/1,299,642 1,46,696 33
954.0 181,041 1,520,22 1,701,26 34
272.0 736,03t 5,273,727 6,009,757 35
85,897,34 1,695,58,078 1,781,482,421 125,807 13,323,841 1,316,314 14,765,96 36
FERC FORM NO.1 (ED. 12-87)Page 423.1
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2007/04
(2) nA Resubmission 04008
TRANSMISSION LINE STATIST CS
1. Report infonnation concerning trasmission lines, cost of Ii,,es, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report trasmission lines below these voltages in group totals only for each voltage.
2. Trasmission lines include all lines covere by the definitio of trasmission system plant as given in the Unifonn System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Acunt 121, Nonutility Propert.
5. Indicate whether the type of supporting structure reprted in column (e) is: (1) single poe woo or steel; (2) H-frame wood, or stee poes; (3) tower;
or (4) underground construction If a transmission line has more than one ty of supporting struure, indicate the mileage of each ty of construction by
the use of brackets and extra lines. Minor portions of a transmision line of a dierent ty of costruion need not be distinguished from the remainder
of the line.
6. Report in columns (f) an (g) the total pole miles of eah trasmission line. Sho in coumn (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 structure the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in coumn (g). In a fooote, expn the bais of such ocupancy and state whether expenses wih
respe to such structures are included in the expenses repoed for the line deignated.
Line IIUN ur¡r LE~G;h~ ~oleeWile)
(Indicte wlìere Type of NumbeNo.öt~~~an Dh ~\u ~ergroulllines60 e3 ase Supporting report circuit miles)Of
From To Oprang Deed un òl1fliure .V~~liUJts CircuitsStrureof. Line Desisrated ne(a)(b)(c)(d)(e)(g)(h)
1 Ben Lomond Sub., UT Naugton Pit. #2, WY 23.23.00 Woo-U 29.00 1
2 Chappel Creek, WY Naughton Plant, WY 23.23.00 Woo Tower 46.00 1
3 Ben Lomond Sub., UT Tennina Substi, UT 230.230.00 Stee- D-P 76.00 1
4 Naughton Plant, WY Treasureton Sub., ID 23.0(230.00 Woo-U 79.00 1
5 Naughton Plant, WY Treasureton Sub., ID 230.0(230.00 Woo-U 1.00 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 BPAWooland, WA 230.0(230.00 HFraWoo 23.00 1
8 Union Gap, WA BPA Midway, WA 230.0(230.00 H Frame Woo 39.00 1
9 Walla Walla, WA Lewiston,ID 230.0(23.00 H Frame Woo 45.OC 1
10 Walla Walla, WA Wanapum,WA 23.0(230.00 H Frame Woo 33.00 1
11 Pomona,WA Wanaum, WA 23.01 230.00 HFraWoo 37.00 1
12 Pomona, WA Wanaum, WA 230.01 23.00 H Frae Woo 8.00 1
13 Mendian Sub, OR Lone Pine Sub, OR 230.01 230.00 Stee. DC 5.00 .
14 Mendian Sub, OR Lone Pine Sub, OR 23.01 230.00 Stee- DC 5.00
15 Gooe Creek, WY Yellowtl, MT 23.01 230.00 H Frae Wood 59.00 1
16 Yellowtail, MT Muddy Ridge, WY 230.01 23.00 H Frae Woo 176.00 1
17 Shendan, WY Decker, MT 230.01 230.00 H Frame Woo 12.00 1
18 Dave Johnston Plant, WY Casper, WY 230.01 230.00 H Frame Woo 31.00 1
19 Yellowtl, MT Casper, WY 230.01 230.00 HFrameWoo 149.00 1
20 Rock Spnngs, WY Kemmerer, WY 230.0(230.00 H Frae Woo 71.00 1
21 Rock Spnngs, WY Atlantic Cit, WY 230.0(230.00 H Frame Woo 69.00 1
22 Thennopolis, WY Riverton, WY 230.OC 230.00 H Frame Woo 51.00 1
23 Casper, WY Riverton, WY 230.OC 230.00 H Frame Woo 110.00 1
24 Dave Johnston Plant, WY Rock Spnngs, WY 230.OC 230.00 H Fra Woo 209.00 1
25 Dave Johnston Plant, WY Spence, WY 230.01 230.00 H Fra Woo 31.00 1
26 Riverton, WY Atlantic Cit, WY 230.()230.00 H Fra Woo 50.00 1
27 Rock Springs, WY Flaming Gorge, UT 230.0(230.00 H Frae Woo 48.00 1
28 Palisades, WY Gren River, WY 23.0(23.00 H Frame Woo 5.00 1
29 Buflo, WY Gilette, WY 230.()230.00 H Frame Woo 69.00 1
30 Jim Bndger Plant, WY Point of Rocks, WY 23O.()230.00 HFrameWoo 4.00 1
31 Jim Bndger Plant, WY Point of Rocks, WY 230.0(230.00 H Frame Wood 5.00
32 Dave Johnston Plant, WY Yellowcake, WY 230.0(230.00 H Frame Woo 69.00 1
33 Wyodak, WY Sub. Tie Line, WY 230.0(230.00 H Frame Wood 1.00 1
34 Jim Bndger Plant, WY Point of Rocks Ln 2, WY 230.()230.00 H Frame Wood 8.00 1
35 Blue Rim, WY South Trona, WY 230.0l 230.00 H Frame Woo 13.00 1
.
36 TOTAL 15,494.00 m.oo 210
FERC FORM NO.1 (ED. 12-87)Page 422.2
............................................
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04/03/2008
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines an higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, bais of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accunts affected. Specif whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated compay.
10. Bae the plant cost figures called for in columns (j) to (I) on the bok cot at end of year.
IJv;: I vI" LINE (Inciucie in Column ü) Land,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 Totl ine
Other Costs Expenses Exenses (0)Expenss No.(i)(j)(k)(I)(m)(n)(p)
1272.0 1,721,522 1,721,522 1
54.0 170,96 5,90,151 6,071,11S 2
272.0 572,45~10,217,612 10,79,071 3
54.0 56,49E 3,070,270 3,126,768 4
~54.0 56~27,377 27,946 5
~.O 1,29~335,329 33,622 6
~54.0 103,53~2,598,048 2,701,58 7
N272.0 172,451 1,709,377 1,881,828 8
~272.0 36,29l 6,331,575 6,697,86 9
~54.0 235,53 2,389,9~2,62,47C 10
1780.0 207,12 2,664,144 2,871,267 11
1556.5 161 1,514,18(1,514,34~12
272 2,003,740 2,003,741 13
14
272.0 1,714,52!2,100,252 3,814,781 15
272.0 1,615,02!5,951,730 7,56,755 16
272.0 26,09 63,118 656,211 17
95.0 14,921 1,147,311 1,162,245 18
271.0 130,19 9,689,026 9,819,223 19
271.0 52,90 3,439,244 3,492,15C 20
954.0 31.85~3,001,623 3,033,482 21
272.0 57,11;2,100,040 2,157,152 22
954.0 67,85 5,08,127 5,150,98 23
272.0 58,10.11,533,95~11,592,05E 24
272.0 33.001 2,658,645 2,691,65 25
271.0 48,281 3,806,177 3,85,45 26
272.0 30,76~2,662,969 2,693,73E 27
272.0 1 697,350 697,36_28
272.0 361,351 4,344,620 4,705,971 29
272.0 4,80 140,312 145,112 30
272.0 130,166 13O,16E 31
1272.0 294,29(6,158,106 6,452,39 32
1272.0 15,274 15,274 33
272.0 3,96 441,494 445,461 34
272.0 872,981 872,981 35
85,897,~1,695,58,078 1,781,482,421 125,807 13,323.841 1,316,314 14,765,96 36
FERC FORM NO. 1 (EO. 12-87)Page 423.2
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Ongina (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04/03/008
TRANSMISSION LINE STATIST CS
1. Report information conceming transmission lines, cost of Iilles, and expenses for ye. Ust each transmission line having nominal voltage of 132
kilovolts or greater. Report trasmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Acount 121, Nonutilty Propert.
5. Indicate whether the ty of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one 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 dierent ty of constrution ne not be distinguished from the remander
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmissio line. Sho in coumn (f) the poe miles of line on structures the cot of which is
reported for the line designated; conversely, show in column (g) th poe mil of line on strure the co of which is reported for another line. Report
pole miles of line on leased or partly owned struures in column (g). In a fotnte, explan the bais of such ocupancy and state whether expenses with
respect to such structures are includ in the expenses reported fo the line desgnated.
Une ¡fUN
(Indicate wlìere Typ of LE~G~~ li:e óliles)NumbeiNo.other than i nh i!)u ~ergron¡rlfnes
60 r.le 3 i"e Supportng report circuit miles)Of
From To Operating Designed . un ~1!Vclure I u~ftl"!~res CircuitsStructureof.Une of no er
(a)(b)(c)(e)oesl(lated ne
(d)(g)(h)
1 Moument, WY Exon Plant, WY 23.lX 23.00 H Fra Wo 13.00 1
2 Firéhole, WY Maface, WY 23O.OC 230.00 Stee Pole 2.00 1
3 Firehole, WY Mansface, WY 23O.OC 23.00 H Fra Woo 10.00 1
4 Monuments, WY So Trona, WY 23.lX 23.00 H Frame Woo 4.00 1
5 Spence Sub., WY Jim Bndger Plant, WY 23O.OC 230.00 HFrameWoo 47.00
6 Jim Bndger Plant, WY Mustang Sub., WY 23O.OC 230.00 HFrameWo 73.00 1
7 Spence Sub., WY Mustang Sub., WY 23.Ol 230.00 H Frame Wood 7100 1
8 Rock Springs, WY Flaming Gorge, UT 23O.Ol 230.00 Stee Tower 7.00 1
9 Une59,CA Copcll,CA 23.Ol 230.00 H Frame Woo 5.00 1
10 Anzonaltah State Une Glen canyon Sub., PI 23O.Ol 230.00 HFrameWoo 10.00 1
11 Miners Sub., WY Foote Creek Sub., WY 23O.Ol 230.00 Woo-H 29.00 1
12 Monument Sub., WY Craven Crek Sub., WY 23.Ol 230.00 Woo-H 20.0£1
13 Point of Rocks Sub., WY Rock Spnngs, WY 23.Ol 230.00 Woo-H 27.00 1
14 230 kV expenses
15
16 Subtotal 230 kV 3,317.00 5.00 72
17
18 Montana-Ida State line Grace Plant, ID 161.Ol 161.00 Woo-H 57.00 90.00 1
19 Goshen Substation, ID Rigby Substation, ID 161.Ol 161.00 Woo-H 61.00 1
20 Goshen Substation, ID Antelope Substation, ID 161.OC 161.00 Woo-H 45.00 1
21 Goshen Substation, ID Sugar Mil Substation, ID 161.OC 161.00 Woo-SP 17.00 1
22 Sugar Mil Sub., ID Rigby Substatio, ID 161.Ol 161.00 Woo-SP 17.00 1
23 Goshen Substation, ID Bonnevile Sub., 10 161.Ol 161.00 Woo.Sp.H 23.00 1
24 Billngs, MT Yellowtail, MT 161.01 161.00 HFraeWoo 46.00 1
25 Big Grassy Sub., ID Idaho Power Une, ID 161.Ol 161.00 Woo-H 1.00 1
26 Rigby Sub., ID Jefferson Robert, ID 161.Ol 161.00 Woo-SP 18.OC 1
27 Themopolis Sub, WY Wap Tie Une, WY 161.Ol
28 161 kVexpense
29
30 Subtotal 161 kV 285.00 90.00 9
31
32 Naughton Plant, WY Evanston Substation, WY 138.OC 138.00 Woo-H 67.00 1
33 Evanston Substation, WY Anschut Substation, WY 138.Ol 138.00 Woo-H 6.00 1
34 Evanston Substation, WY Anschut Substation, WY 138.rn 138.00 Woo-H 15.OC 1
35 Naughton Plant, WY carter Creek Sub., WY 138.Ol 138.00 Wood-H 36.01 1
36 TOTAL 15,494.00 m.oo 210
FERC FORM NO.1 (ED. 12-87)Page 422.3
.............................................
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 04/03/2008
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lineS. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leaed line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of coowner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specif whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another copany and give name of Lessee, date and terms of leae, annual rent for year, and how
determined. Specif whether lessee is an associated company.
10. Base the plant cot figures called for in columns (j) to (i) on the bok cost at end of year.
l;U;: I ui- LINt: (Include in COlumn OJ Lad,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Coductor
and Material La Construction and Total Cot Operation Maintenance Rents Total ineOther Costs Expenses Expenses Expenses(i)(j)(k)(I)(m)(n)(0)(p)No.
272.0 160,129 160,126 1
272.0 2
272.0 2,674,oo 2,674,00 3
272.0 2,726,304 2,726,30 4
272.0 170,295 170,295 5
272.0 9,760,523 9,760,52 6
272.0 9,565,742 9,56,742 7
272.0 4,48.744,631 749,11~8
4,33 820,071 824,41C 9
11,901 451,36 463,264 10
4,972,5GC 4,972,56C 11
4,548,52¡4,548,527 12
5,939,~5,939,08 13
31,548 2,896,603 396,~*************14
15
13,597,791 259,375,327 272,973,12f 31,s4E 2,896,60 39,993 *************16
17
l37.5 18,971 1,58,831 1,60,8O 18
~7.5 27,52 808,~83,90 19
00.5 8,85 2,667,758 2,676,615 20
007.5 48,22 1,482,266 1,530,49~21
007.5 27,53€1,210,1n 1,237,713 22
954.0 362,27 2,835,39 3,197,675 23
556.5 1,523,64 1,830,017 3,353,656 24~.5 26,2Of 26,208 25
556.5 76,301 1,284,658 1,36,96 26
12,306 12,30 27
41,926 251,180 4,54(*************28
29
2,093,34 13,743,001 15,836,34 41,929 251,180 4,540 *************30
31
95.0 146,64'4,036,2~4,182,854 32
95.0 129,12 504,914 634,O4~33
95.0 3,381 290,803 29,184 34
95.0 41,411 3,5n,596 3,619,00 35
85,897,34 1,695,585,078 1,781,482,421 125,807 13,323,841 1,316,314 14,765,96.36
FERC FORM NO.1 (ED. 12-8)Page 423.3
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Oa, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04208
TRANSMISSION LINE STATIST CS
1. Report information conceming transmission lines, cost of Iiries, and expenses for year. Ust each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these volges in group totals only for each voltage.
2. Transmission lines include all lines covered by the defnition of trasmissio system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all volges if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Acount 121, Nonutilit Proerty.
5. Indicate whether the ty of supporting structure reported in column (e) is: (1) single poe woo or steel; (2) H-frame woo, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one tye of supporting structre, indicate the mileage of each tye of constrution bythe use of brackets and extra lines. Minor portions of a transmission line of a diferent ty of construction need not be distinguished from the remainder
of the line.
6. Report in coumns (f) and (g) the total pole miles of each trasmission line. Show in coumn (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, sho in column (g) the poe mile of line on structures the cost of which is reported for another line. Report
poe miles of line on leased or partly owned structures in column (g). In a footne, expain the basis of such occupancy and state whether expenses with
respe to such structures are include in the expnses reprted for the line deiged.
Une IIUN (Indcae wtre Typ of LEn8Ji~ ~~ie eWileS)
No.u ergrounlfllnes Numbeòterth60 "'Ie 3 on ise \Supporting report circuit miles)Of
From To Oprating Designed un ~lriure 'U~t~lmres CircuitsStructureof. Line not er
(a)(b)(c)(e)oeslSlated ine
(d)(g)(h)
1 Railroad Sub., WY Carter Creek Sub., WY 138.0l 138.00 Woo-H 17.00 1
2 Painter Substation, WY Natural Gas Sub., WY 138.0l 138.00 Woo-H 5.00 1
3 Grace Plant, 10 Termnl. Sub., UT (103-104)138.0l 138.00 St- S 42.00 2
4 Grace Point, 10 Termn!. Sub., UT (103-104)138.138.00 Woo-H 211.00 2
5 Grace Plant, 10 Terminal Sub., UT (105)138.1 138.00 Woo.H 143.00 2
6 Grace Plant, 10 So Plant, 10 138.1 138.00 Woo-H 8.00 4.00 2
7 Oneida Plant, 10 Ovd Subsion, 10 138.0l 138.00 Woo-H 23.00 1
8 Antelope Substation, 10 Scovill Sub., 10 138.0l 138.00 Woo-H 1.00 1
9 Soda Plant, Idaho Monsato Sub., 10 138.0l 138.00 Woo-H 8.00 1
10 Caribou Substation, 10 Grace Plat, 10 138.0l 138.00 Woo.H 16.0(1
11 Caribou Substation, 10 Becker Substation, 10 138.0l 138.00 Woo-H 5.00 1
12 Treasureton Sub., 10 Franklin Sub., 10 138.0l 138.00 Woo-H&S 10.0(1
13 Franklin Substation, 10 Smithfield Sub., UT 138.0l 138.00 Wood-H 25.0(1
14 Midvalley Substation, UT Thirty South Sub., UT 138.0l 138.00 Woo-H 1.00 1
15 Angel Substation, UT Smith's UT 138.0l 138.00 Woo-H 1.00 1
16 Terminal Substation, UT 30 South Switch Rack, UT 138.0l 138.00 Stee- S 7.00 1
17 Jordan, UT Terminal Substation, UT 138.01 138.00 Woo-H 6.00 1
18 Whelan Substation. UT Amerian Falls Sub., UT 138.01 138.00 Woo-H 82.00 1
19 Cutler Plant, UT Wheelon Substation, UT 138.01 138.00 Woo-H 1.0(1
20 Terminal Substation, UT Helper Substatio, UT 138.0l 138.00 Woo-H 116.00 1
21 Hale Plant, UT Nebo Substation, UT 138.0l 138.00 Woo-H 54.00 1
22 Carbn Plant, UT Helper Substation, UT 138.0l 138.00 Woo-H 2.00 1
23 Terminal Substation, UT Toole Substation, UT 138.0(138.00 Woo.H 42.00 1
24 Wheelon Substation, UT Smithfield Sub., UT 138.0l 138.00 Woo-H 19.00 1.00 2
25 Helper Substation, UT Moab Substation, UT 138.0l 138.00 Woo.H 118.00 1
26 Ninetieth South Sub, UT Carbn Plant, UT 138.0(138.00 Woo-H 75.OC 2
27 Terminal Substation, UT Ninetieth South Sub, UT 138.0(138.00 Woo-H 16.00 2
28 30 South Switch Rack, UT McClelland Sub., UT 138.0(138.00 Woo.SP 6.00 1
29 Moab Substation, UT Pinto Substation, UT 138.0l 138.00 Woo-H 68.00 1
30 Pinto Substation, UT Abao, UT 138.01 138.00 Woo-H 45.00 1
31 Carbon Plant, UT Ashley Substation, UT 138.0l 138.00 Woo-H 92.00 1
32 McClelland Sub., UT Cottonwoo Sub., UT 138.0l 138.00 Woo.SP 6.00 1
33 Ashley Substation, UT Vernal Substion, UT 138.0l 138.00 Woo-H 12.00 1
34 Sigurd Substation, UT West Cer Substation, UT 138.0l 138.00 Woo-H 120.00 1
35 Ben Lomond Sub., UT EI Monte Substation, UT 138.01 138.00 Woo. H Sub 19.0(1
36 TOTAL 15,494.00 m.oo 210
FERC FORM NO.1 (ED. 12-87)Page 42.4
............................................
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 04/03/20
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure 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 two or more transmission line structure support lines of the same voltge, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereo, 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 respodent in the line, name of co-owner, basis of sharing
expenses of the Une, 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 leas to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specif whether lesee is an associated company.
10. Base the plant cot figures called for in columns (j to (I) on the bok cost at end of yer.
vVò:1 "" ....(Induoe inCõumn U) LaCl,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Lad rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cot Operation Maintenance Rents Tot inaOter Cots Expenses Expenses Expnses
(i)(j (k)(I)(m)(n)(0)(p)No.
170 72,62:3,821,01C 3,893,632 1
95.0 -12,42'-278~-291,26 2
95.0 765,181 13,267,18i 14,03,37,3
95.0 4
250.0 132,96 16,032,079 16,165,039 5
~.O 3,291 157,216 160,50 6~.O 4,81 596,581 601,398 7
397.5 14 41 100 8
397.5 2,55 295,902 298,457 9
95.0 18,28'420,886 439,170 10
397.5 14,42'145,941 160,365 11
95.0 39,101 541,49 58,599 12
397.5 47,61~1,094,65S 1,142,261 13
192,647 192,64 14
20,229 20,229 15
00.0 1,83 1,256,74E 1,258,58i 16
661,44 1,n6,21S 2,437,~17
1250.0 118,18(6,191,321 6,30,501 18
~50.0 69,072 69,07 19
~50.0 458,7g,12,490,71 12,949,518 20
ß97.5 27,54 4,607,792 4,63,331 21
954.0 71l 150,40~151,189 22
ß97.5 9,461 8,07,186 8,416,64 23
ß97.5 188,01 1,056,437 1,244,455 24
397.5 33,9&3,033,558 3,067,52E 25
95.0 34,83 5,622,14i 5,961,~26
272.0 426,741 1,228,422 1,65,168 27
95.0 58,31 1,56,31E 1,622,34 28
97.5 40,111 1,070,458 1,110,57,29
97.5 100,35 2,100,39 2,200,751 30
97.5 80,861 1,750,314 1,831,175 31
95.0 13,73:1,SOO.76C 1,514,49~32
97.5 5,54 325,44 330,99 33
91.5 62,15 3.548,776 3,610,931 34
95.0 18,84 850,357 869,202 35
85,897,343 1,695,585,078 1,781,482,421 125,807 13,323,841 1,316,31~14,765,96¡36
FERC FORM NO.1 (ED. 12-87)Page 423.4
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04318
TRANSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of Iiries, and expnses for year. Ust each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a Ste commission.
4. Exclude from this page any transmission lines for which plant co are incud in Acnt 121, Nonutilit Propert.
5. Indicate whether the tye 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 transmission line ha more th on ty of surtng struure, indicate the mileage of each tye of costruction by
the use of brackets and extra lines. Minor portions of a trasmision line of a dieren ty of construction need not be distinguished from the remainder
of the line.
6. Report in columns (1) and (g) the total pole miles of each transmisson line. Show in column (1) the poe miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the poe miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the bais of such occupancy and state whether expenses with
respet to such structures are included in the expnses reported for the line deignated.
Line (Indite .;~~'t Type of LEmG~~ ~~e ¿riles)NumbeiNo.mher th. oh is\u ~ergrouMlllnes Of6O""1e 3 Supprtng report circuit miles)
From To Operang Deiged un ~t!VClre u~f9t~~res CircuitsStructureof.Une Of not er
(a)(b)(c)(e)Desl8lated ne
(d)(g)(h)
1 Coonwoo Sub., UT Ninetith Sou Sub, UT 138.()138.00 Woo.SP 11.00 1
2 Terminal Substation, UT Rowy Substati, UT 138()138.00 Woo.H 56.00 1
3 Huntington Plant, UT McFaddn Substion, UT 138.()138.00 Woo.H 7.00 1
4 Ben Lomond Sub., UT EI Monte Substatin, UT 138()138.00 Woo.H 13.00 1
5 Coonwoo Sub., UT Silvercreek Sub., UT 138()138.00 Woo.SP 37.00 1
6 Ninetieth South Sub, UT Taylorsvile Sub., UT 138.()138.00 Woo.SP 9.00 1
7 Gadsby Plant, UT McClelland Sub., UT 138.()138.00 Woo.SP 4.00 1
8 Nineteth South Sub, UT Oquirr Substation, UT 138.()138.00 Woo.SP 10.00 2
9 Nebo, UT Jerusalem, UT 138.()138.00 Woo Towr 26.00 1
10 Ben Loond Sub., UT Western Zircon Sub., UT 138.01 138.00 Woo.H 14.0(1
11 Tooele Substation, UT Oquirrh Substi, UT 138.01 138.00 Woo.SP 21.00 1
12 Wheelon Substation, UT Nucor Steel Sub., UT 138.01 138.00 Woo.H 14.00 4.00 1
13 Nebo Substation, UT Martn-Maet Sub., UT 138.01 138.00 Woo.H 30.00 1
14 West Cedr Sub., UT Middleton Substi., UT 138.01 138.00 Woo-H 69.00 1
15 Gadsby Plant, UT Terminal Substation, UT 138.01 138.00 Woo.H 6.0(1
16 Oquirr Substation, UT Kennectt Sub., UT 138.01 138.00 Woo.H 4.00 1
17 Oquirrh Substation, UT Barney Substation, UT 138.01 138.00 Woo-HS 7.00 2
18 West Cedar Sub., UT Pepcn Subsation, UT 138.01 138.00 Woo-SP 13.OC 1
19 Taylorsville Substation, UT Mid-Valley Substation, UT 138.01 138.00 Steel. SP 5.00 1
20 Warren Substation, UT Kimberly Clark Sub., UT 138.0(138.00 Woo.HP 1.00 1
21 Honeyvile, UT Promontory, UT 138.OC 138.00 Woo Tower 22.00 1
22 Ninetieth Sout Sub, UT Hale Plant, UT 138.OC 138.00 Woo Towr 47.00 1
23 Dumas, UT Bimple, UT 138.()138.00 Woo Towr 4.00
24 Columbia Sub, UT Sunnyside Co. Gen., UT 138.0l 138.00 Woo Towr 2.00 1
25 Syracuse Sub, UT Ben Lomond Sub, UT 138.()138.00 Stee D-P 26.00 1
26 Hale Plant, UT Miday Sub, UT 138.()138.00 Wo.H 19.00 1
27 Jordn 138 kV, UT Fifh West 138 kV, UT 138.()138.00 Stee Towe 1.00 1
28 Gadsby 138 kV, UT Jord 138 kV, UT 138.()138.00 Stee Tower 1.00 1
29 Panther, UT Wilow Creek, UT 138.()138.00 Woo Tower 1.00 1
30 Hammer Substation, UT Butlervile Substation, UT 138.(138.00 Woo Tower 5.00 1
31 Midway Substation, UT Silver Creek Sub, UT 138.0(138.00 Wood Towr 14.00 1
32 Midway Substation, UT Cottonwood Sub, UT 138.(138.00 Woo Tower 10.00 1
33 McFadden Substation, UT Blackhawk Substation, UT 138.0l 138.00 Wood-H 11.00 1
34 West Valley Sub., UT Keams Substation, UT 138.0l 138.00 Woo.SP 2.00 1
35 Syrcuse Substation, UT Clearfield South Sub., UT 138.0l 138.00 Woo.SP 1.00 1
36 TOTAL 15,494.00 m.oo 210
FERC FORM NO.1 (ED. 12-8)Page 422.5
............................................
............................................
Name of Respondent This
Wrt
Is: Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 207/04
(2) FiA Resubmission 04/0312008
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. R.eport 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, furnish.a succinct statement explaining the
arrgement 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 expses borne by the respondent are accounted for, and accounts affected. Specif whether lesor, co-owner, 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 yer, and how
determined. Speif wheter lessee is an assiated company.
10. Bae the plant cot figures called for in columns ü) to (I) on the bok co at end of year.
vV;: I vr Lii,.i: (inciuae in t,oiumn UrIana EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Lad righm, and c~aring rig~-of-wa0
Coductor
and Material Land Construion and Total Cot Operation Maintenanc Renm Total LIneOther Costs Exnses'Expenses ~(i)ü)(k)(I)(m)(n)(0)No.
95.0 549,()2,230,64 2,77,707 1
95.0 222,28E 2,283,128 2,505,414 2
397.5 26!23,88 239,148 3
95.0 24,901 1,017,499 1,042,40 4
97.5 1n,82 6,159,264 6,337,08 5
95.0 5,17!2,550,11*2,55,3n 6
95.0 56,75!925,590 982,349 7
1795.0 243,44'3,54,4n 3,791,922 8
ß91.5 253,53 2,26,96 2,518,50 9
"50.0 96,45 96,211 1,06,66 10
95.0 252,891 3,057,455 3,310,34 11
17.0 46,94 90,120 956,061 12
ß97.5 66,45 1,796,523 1,86,975 13
ß97.5 25,14 2,178,96 2,204,112 14
272.0 66,m 810,47~1,479,244 15
95.0 251,54~251,54 16
95.0 16,661 457,43!474,101 17
95.0 43,59(1,08,22 1,131,812 18
272.0 33,46 2,500,072 2,53,531 19
~97.5 14,72~141,422 156,144 20
397.5 475,68~2,874,16~3,349,84 21
391.5 146,42~7.793,500 7,939,934 22
397.5 3,136,585 3,136,58 23
397.5 -41 2 .39 24
212.0 353,104 353,1ei 25
397.5 246,50 4,038,881 4,285~26
272.0 1 1,104,840 1,104,851 27
272.0 75'381,90 382,65 28
97.5 40,890 40,890 29
188,391 3,364,794 3,553,185 30
2,755,012 2,755,012 31
69,02!5,581,573 6,271,598 32
1,747,452 1,747,452 33
268,234 268,234 34
677,37E 6n,376 35
85,897,~1,695,585,078 1,181,48,421 125,80 13,323,841 1,316,31~14,765,96 36
FERC FORM NO.1 (ED. 12-87)Page 423.5
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Origina (Mo, Da, Yr)End of 2oo7/Q4
(2) EjA Resubmission 04
TRANSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of Ii,,es, and expnses for year. Ust each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutilty Propert.
5. Indicate whether the tye of supportng 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 transmission line has more than one tye 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 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 pole miles of line on struures the cost of whic is
reported for the line designated; conversely, show in column (g) the po miles of line on structure the cost of which is reported for another line. Report
pole miles of line on leased or partly owned struure in column (g). In a foe, expain the basis of such ocupacy and state whether expnses wit
respect to such structures are included in the expnses reported for the line deigated.
Line (Indicae .)li~;'Type of LE!Ji~ l~e o'liles)NumbeNo.other thani oh ~L u rgrounirllnes Of60 cvle 3 ase Supprting report circuit miles)
From To Operating Designed un ~tflcture u8t'"Ai~res CircitsStructureDeOJi~iYed I)ot erine(a)(b)(c)(d)(e)(g)(h)
1 Farmington Substation, UT Parrsh Substation, UT 138.0l 138.00 Steel. DC 5.00 1
2 Midvalley Substation, UT Cottonwoo Substation, UT 138.0l 138.00 Woo-DC 5.00 1
3 Taylorsile Substation, UT West Valley Substation, UT 138.0l 138.00 Stee- DC 3.00 3.00 1
4 Dynamo Sub, UT Tri-Cit Sub, UT 138.lX 138.00 Woo-SP 2.00 2
5 Oqruirr Sub, UT Tri-City Sub, UT 138.lX 138.00 Woo-SP 22.00 2
6 Bridgertand Sub, UT Green Canyon Sub, UT 138.lX 138.00 Woo-SP 16.00 1
7 138 kV expenses
8
9 Subtotal 138 kV 2,122.0(12.00 90
10
11
12 All 115 kV lines 115.0 115.00 Woo & Steel 1,548.00
13 All 69 kV lines 69.0 69.00 Woo & Steel 2,962.00 1.00
14 All 57 kV lines 57.0 57.00 Woo & Steel 113.00
15 All 46 kV lines 46.0 46.00 Woo & Stee 2,615.0l
16
17
18 Unclassified Plant at 12/1
19 Chappel Creek Unclassified Plant 23.0 23.00 Woo-H 35.00 1
20 Craven Creek Unclassified Plant 23.lX 230.00 Woo-H 3.00
21 Marengo Wind Plant Trans Unclassifed Plant 230.00 230.00 WooHFrae 4.00 1
22 Blundel Steam Plant Unclassifed Plant 69.00 69.00 WooSP 1
23 Unclasified Plant (Under $1,000,00 Projects)
24
25
26
27
28
29
30
31
32
33
34
35
36 TOTAL 15,494.00 m.oo 210
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 2oo7/Q4
(2) FiA Resubmission 04/03/2008
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. R.eport Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
yo do not include Lower voltage lines with higher voltage lines. If two or more transrnission 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, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affeced. Specif whether lessor, co-wner, or
other party is an associated company.
9. Designate any transmission line leased to another copany 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. Base the plant cost figures called for in columns (j to (i) on the bok cot at en of year.
VV¡; i ~, ~,... (InCIUae in t;lumn U) Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of La rights, and clearing right-of-way)
COnductor
and Materil La Construction and Total COst Operation Mantenance Rents Total Line
Other COsts Expenses Expnses ~nses
(i)(j (k)(I)(m)(n)(0)(p)No.
90,05 90,058 1
4,655,525 4,655,525 2
2,002,98 2,002,98(3
D-795 9,221,85C 9,221,850 4
557 41,207,670 41,207,670 5
272 9,233,887 9,233,881 6
~1,479,297 86,27E ***********fn 7
8
8,607,53:240,037,773 248,645,306 9 1,479,297 86,275 ***********..i 9
10
11
3,510,35!126,231,35 129,741,711 17,04 2,482,147 323,3Ù *************12
3,354,06 212,041,657 215,395, 72~16,40 1,735,641 119,26~..*******.***13
41,23'8,169,256 8,210,49t 4 4,464 331 ********....*14
4,451,70!184,802,66 189,254,36~2,36 2,460,34E 40,09 ...********..15
16
17
18
272 11,499,447 11,499,44 19
826,735 826,735 20
95 1,823,720 1,823,720 21
397 520,637 520,637 22
6,188,947 6,188,947 23
24
25
26
27
28
29
30
31
32
33
34
35
85,897,34 1,695,585,078 1,781,48,421 125,807 13,323,841 1,316,314 14,765,96 36
FERC FORM NO.1 (ED. 12-87)Pag 423.6
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 04103/2008 2007/Q4
FOOTNOTE DATA
!Schedule Page: 422 Line No.: 4 Column: a
The Alvey - Dixonvile 500kV line is jointly owned by the respondent and the Bonnevile Power Administration ("the BPA").
Ownership of the line is as follows: PacifiCorp 50.0%, the BPA 50.0%. Cost reported for ths line reflects the respondents 50.0%
share. Operation and maintenance costs are shared between the two pares and responsibility is as follows: PacifiCorp 58.0% and the
BPA42.0%.
rschedule Page: 422 Line No.: 6 Column: a
The Dixonvile - Meridian 500kV line is jointly owned by the respondent and the Bonnevile Power Administration ("the BPA").
Ownership of the line is as follows: PacifiCorp 50.0%, the BPA 50.0%. Cost reportd for ths line reflects the respondents 50.0%
shae. Operation and maintenance costs are shared between the two pares and responsibilty is as follows: PacifiCorp 58.0% and the
BPA42.0%.
Ißchedule Page: 422 Line No.: 7 Column: a
The Colstrp 4 - Switchyard 500kV line is jointly owned by the respondent, NortWestern Corporation, Puget Sound Power & Light,
Washington Water Power Company and Portand Genera Electrc. Ownership of the line is as follows: PacifiCorp 6.8%, all others
93.2%. Plant cost and 0 eration and mantenance costs re rt for ths line reflects the respondent's share.
chedule Pa e: 422 Line No.: 8 Column: a
The Colstrp - Broadview A 500kV line is jointly owned by th respndent, NortWestern Corporation, Puget Sound Power & Light,
Washington Water Power Company and Porand Genera Electrc. Ownership of th line is as follows: PacifiCorp 6.8%, all others
93.2%. Plant cost and operation and mantenance costs report for ths lie reflects th res ondent's share.
chedule Pa e: 422 Line No.: 9 Column: a
The Colstrip - Broadview B 500kV line is jointly owned by the respondent ,NortWestern Corporation, Puget Sound Power & Light,
Washington Water Power Company and Portland General Electrc. Ownership of the line is as follows: PacifiCorp 6.8%, all others
93.2%. Plant cost and 0 ration and maintenance costs re ortd for ths line reflects the res ondent's share.
chedule Pa e: 422 Line No.: 10 Column: a
The Broadview - Townsend A 500kV line is jointly owned by the respondent, NortWestern Corporation, Puget Sound Power &
Light, Washington Water Power Company and Portand General Elecc. Owrship of th line is as follows: PacifiCorp 8.1 %, all
others 91.9%. Plant cost and 0 ration and mantenance costs re rt for ths line reflects the res ndent's share.
chedule Pa e: 422 Line No.: 11 Column: a
The Broadview- Townsend B 500kV line is jointly owned by the respondent, NortWestern Corporation, Puget Sound Power &
Light, Washington Water Power Company and Portland General Electc. Ownership of the line is as follows: PacifiCorp 8.1 %, all
others 91.9%. Plant cost and operation and maintenance costs reported for ths line reflects the respondent's shae.
-...........................................
Blank Page
(Next Page is 424)
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifCorp (1) An Onginal (Me, Da, Yr)End of 2007/04
(2) riA Resubmission 040320
RANSMISSION LINES ADDED DURIi\G 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 permissible to report in these columns the
Line Line I UHt:I'H~ILerigthNo.From To in Type NumbêrÍJr Present UltimateMilesMiles
(a)(b)(c)(d)(e)(f)(g)
1 BOO Sub, UT Warren-Kimberly Clark, UT 1.24 WooSP 15.0(1 1
.:¡ Green Canyon Sub, UT Bndgerland Sub, UT 16.00 WooSP 15.00 1 1
3 Camp Willams, UT Mona, UT 50.00 Steel Obi Ck 10.00 2 2
.4 Chappel Creek, WY Jona FieldIriger, WY 35.00 WooH Frame 10.00 1 1
5 . Craven Creek, WY Enterpnselioneer, WY 3.00 WooH Frae 12.00 1 1
€ McClellad, UT Emigrati, UT 1.40 Woo Db Ckt 19.00 2 2
7 Merian, OR Lone Pine, OR 2.70 WooH Frae 12.00 1 1
8 Timp, UT Cherroo, UT 1.68 WooSP 14.00 1 1
9 Sunnse,UT Oquirrh, UT 2.37 SteelSP 14.00 2 2
1C Dymo, UT Tn-City, UT 2.42 WooSP 15.0(2 2
11 Bagerter, UT Oquirrh, UT 3.27 WooSP 14.0(--2
12 70th South, UT West Jordan, UT 1.50 Woo Db Ckt 18.00 1 2
1~ Mareng Wind Plnt, WA Talbot Sub, WA 4.00 WooH Frame 10.0(1 1
14
15
16
17
18
19
20
21
22
23
24
2f
26
2
28
29
30
31
32
33
3i
35
3€
37
38
39
4C
41
42
43
44 TOTAL 124.58 178.00 18 1~
FERCFORM NO.1 (REV. 12-()Page 424
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04/03/2008
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 ih 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.
JH::Voltage il LineSizeSpecifcationConf~uration KV Lad and Poles, Towers Conductors Asset Total No.
(h)(j
and (tiacing (O~rating)Land Rights and Fixtures and ?ievices Retire. Costs0(k)(I)(m)n)(0)(D)
397.5 ACSR Horzon/1O'131 625,47'625,471 1,250,943 1
1272 ACSR VerticaV10'138 6,291,04 2,942,84 9,233,887 2
1272 ACSR VerticaV25'34 9,578.059 9,578,059 3
1272 ACSR Horiz/19.6'230 6,824:~4,674,525 11,499,447 4
1272 ACSR Horiz/17.5'230 413,361 413,36 826,735 5
1557 ACSR VerticaV10'138 68,523 682,523 6
1272 ACSR Horizon12'230 185,431 66,8n 855,30 7
1557 ACSR Vertical/10'138 5,186,39 751,m 5,93,172 8
1557 ACSR Vertca10'138 22,96,~5,55,269 28,518,567 9
2-795 ACSR VerticaV10'138 5,055,4H 4,166,432 ~1557 ACSR Vertcal110'138 11
1557 ACSR Vertca10'138 1,615,07.273,46 1,88,537 12
795 ACSR VertV12'230 911,86 911,86 1,823,720 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
50,069,29 31,248,456 81,317,748 44
FERC FORM NO.1 (REV. 12-63)Page 425
!Schedule Page: 424 Line No.: 11 Column: 0
Costs included in Sunrse - Oquirrh line above.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp (2)A Resubmission 04/0312008 2007/Q4
FOOTNOTE DATA
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
............................................
Blank Page
(Next Page is 426)
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) DA Resubmission 040300
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 groupe 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 (t).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secndary Tertary
(a)(b)(c)(d)(e)
1 California
2 BELMNT DISTRIBUTION-NATTEN 69.OC 12.47
3 BIG SPRINGS DISTRIBUTION-UNATTEN 69.OC 12.47
4 CANBY#2 DISTRIBUION-UNATTEN 69.OC 2.40
5 CASTELLA DISTRIBUTION-UNATTEN 69.00 2.40
6 CLEARLAKE DISTRIBUTION-UNATTEN 69.00 12.47
7 CRESCENT CITY DISTRIBUTION-UNATTEN 12.47 4.16
8 DOG CREEK DISTRIBUTION-UNATTEN 69.OC 2.40
9 DORRIS DISTRIBUTION-UNATTEN 69.00 12.47
10 FORT JONES DISTRIBUTION-UNATTEN 69.DC 12.47
11 GASQUET DISTRIBUTION-UNATTEN 115.OC 12.47
12 GREENHORN D1STRIBUION-UNATTEN 69.00 12.47
13 HAMBURG DISTRIBUION-UNATTN 69.DC 2.40
14 HAPPY CAMP DISTRIBUTION-UNATTEN 69.OC 12.47
15 HORNBROOK DISTRIBUION-UNATTN 69.00 12.47
16 INTERNATIONAL PAPER DISTRIBUTON-UNATTEN 69.00 2.40
17 LAKE EARL DISTRIBUTION-UNATTEN 69.DC 12.47
18 LITTLE SHASTA DISTRIBUTION-UNATTEN 69.QC 7.20
19 LUCERNE DISTRIBUTION-UNATTEN 69.DC 12.47
20 MACDOEL DISTRIBUTION-UNATTEN 69.DC 20.80
21 MCCLOUD DISTRIBUTION-UNATTEN 69.OC 12.47
22 MILLER REDWOOD DISTRIBUTION-UNATTEN 69.DC 12.47
23 MONTAGUE DISTRIBUTION-UNATTN 69.DC 12.47
24 MOUNT SHASTA DISTRIBUTION-UNATTEN 69.00 12.47
25 NEWELL DISTRIBUION-UNATTN 69.00 12.47
26 NORTH DUNSMUIR DISTRIBUON-UNATTEN 69.DC 12.47
27 NORTHCREST DISTRIBUTION-UNATTN 69.DC 12.47
28 NUTGLADE DISTRIBUTON-UNATTN 69.0C 2.40
29 PATRICKS CREEK DISTRIBUTION-UNATTEN 115.00 7.20
30 PEREZ DISTRIBUTION-UNATTEN 69.OC 12.47
31 REDWOOD DISTRIBUTION-UNATTEN 69.00 12.47
32 SCOTT BAR DISTRIBUTION-UNATTEN 69.OC 12.47
33 SEIAD DISTRIBUTION-UNATTEN 69.OC 12.47
34 SHASTINA DISTRIBUTION-UNATTEN 69.OC 20.80
35 SHOTGUN CREEK DISTRIBUTON-UNATTEN 69.00 12.47
36 SIMONSON DISTRIBUTION-UNATTEN 69.OC 12.47
37 SMITH RIVER DISTRIBUTION-UNATTEN 69.00 12.47
38 SNOW BRUSH DISTRIBUTION-UNATTEN 69.00 7.20
39 SOUTH DUNSMUIR DISTRIBUnON-UNATTEN 69.00 4.16
40 TULELAKE DISTRIBUTION-UNATTEN 69.0(12.47
FERC FORM NO.1 (ED. 12-9)Page 426
............................................
....................................'........
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) fîA Resubmission 04/0312008
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 accunts
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 Une
(In Servce) (In MVa)Transformers Spare Type Of Equipment Tota Cacity No.In Service Trasformers Number of Unit
(ll)(j (j)
(In MVa)(1)(h)(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
Name of Respondent This~rtIS:Date of RelJrt Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2007/04
(2) ñA Resubmission 040320
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 substtion, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize accrding to funcion the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 TUNNEL DISTRIBUTION-UNATTEN 69.00 12.47
2 TURKEY HILL DISTRIBUTION-UNATTEN 69.00 12.47
3 WALKER BRYAN DISTRIBUTION-UNATTEN 69.00 12.47
4 WEED DISTRIBUTION-UNATTN 69.00 12.47
5 YUBA DISTRIBUON-UNATTEN 69.DC 12.47
6 YUROK DISTRIBUTON-UNATTEN 69.DC 12.47
7 Total 3140.47 48.96
8 NUMBER OF SUBSTATIONS UNATTENDED - 45
9
10 ALTURAS TID-UNATTENDED 115.DC 12.47 69.00
11 FALL CREEK HYDRO/TIDUNATTENDED 69.00 2.30
12 YREKA TID-UNATTENDED 115.00 12.47 69.00
13 Total 299.00 27.24 138.00
14 NUMBER OF SUBSTATIONS TID UNATTENDED - 3
15
16 AGER TRANSMISSION-ATTEND 115.OC 69.00
17 COPCO #1 HYDRO PLAT TRSMISSION-ATTEND 69.00 2.30
18 COPCO #2 HYDRO PLANT TRASMISSION-ATTND 69.OC 6.60
19 COPCO#2 TRANSMISSION-ATTEND 69.00 12.47
20 COPCO#2 TRANSMISSION-ATTEND 230.00 115.00
21 Total 552.00 205.37
22 NUMBER OF SUBSTATIONS TRANS ATTEND - 5
23
24 CRAG VIEW TRANSMISSION-UNATTEN 115.OC 69.00
25 DEL NORTE TRASMISSION-UNATTEN 115.00 69.00
26 IRON GATE HYDRO PLANT TRANSMISSION-UNATTN 69.00 6.60
27 WEED JUNCTION TRASMISSION-UNATTEN 115.00 69.00
28 Total 414.00 213.60
29 NUMBER OF SUBSTATIONS TRANS UNATTENDED. 4
30
31 Idaho
32 ALEXANDER DISTRIBUTION-UNATTEN 46.00 12.47
33 AMMON DISTRIBUTION-UNATTEN 69.DC 12.47
34 ANDERSON DISTRIBUTION-UNATTEN 69.00 12.47
35 ARCO DISTRIBUTION.UNATTEN 69.OC 12.47
36 ARIMO DISTRIBUTION-UNATTN 46.00 12.47
37 BANCROFT DISTRIBUTION.UNATTEN 46.00 12.47
38 BELSON DISTRIBUION-UNATTEN 69.OC 12.47
39 BERENICE DISTRIBUTION-UNATTEN 69.00 12.47
40 CAMAS DISTRIBUTION.UNATTEN 69.DC 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.1
............................................
.............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) nA Resubmission 04/03/2008
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 accunt. 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 Capacit No.In Service Transformers Number of Units
tf)to)th)(i)(j (Int~a)
6 6 1
13 3 2
7 1 3
13 1 4
4 3 5
4 3 6
332 113 7
8
9
31 4 10
3 3 11
95 2 12
129 9 13
14
15
5 3 16
28 6 2 17
60 3 1 18
2 3 19
125 1 20
220 16 3 21
22
23
19 3 24
150 2 25
19 1 26
38 3 27
226 9 28
29
30
31
4 1 32
11 1 33
20 1 34
6 1 35
8 1 36
4 1 37
13 1 38
11 1 39
14 1 40
FERC FORM NO.1 (ED. 12-9)Page 427.1
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 0403208
SUBSTATIONS
1. Report below the informtion 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 accrding to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)Name and Lotion of Substation Character of SubstationNo.Primary Secondry Tertiary
(a)(b)(c)(d)(e)
1 CANYON CREEK DISTRIBUTION-UNATTEN 69.DC 24.90
2 CHESTERFIELD DISTRIBUTION-UNATTEN 46.OC 12.47
3 CINDER BUTTE DISTRIBUION-UNATTEN 161.OC 12.47
4 CLEMENTS DISTRIBUTION-UNATTEN 69.OC 12.47
5 CLIFTON DISTRIBUTION.UNATTEN 46.00 12.47
6 COVE DISTIBUTION-UNATTEN 46.00 6.60
7 DOWNEY DISTRIBUTION-UNATTEN 46.OC 12.47
8 DUBOIS DISTRIBUTION-UNATTEN 69.OC 12.47
9 EASTMONT DISTRIBUTION-UNATTEN 69.OC 12.47
10 EGIN DISTRIBUTION-UNATTEN 69.00 12.47
11 EIGHT MILE DISTRIBUTION-UNATTEN 46.OC 12.47
12 GEORGETOWN DISTRIBUTION-UNATTEN 69.00 12.47
13 GRACE CITY STATION DISTRIBUTION-UNATTEN 46.DC 12.47
14 HAMER DISTRIBUTION-UNATTEN 69.OC 12.47
15 HAYES DISTRIBUTION-UNATTEN 69.0C 12.47
16 HENRY DISTRIBUTION.UNATTEN 46.00 12.47
17 HOLBROOD DISTRIBUTION-UNATTEN 69.DC 12.47
18 HOOPES DISTRIBUON-UNATTEN 69.DC 12.47
19 HORSLEY DISTRIBUTION-UNATTEN 46.OC 12.47
20 IDAHO FALLS DISTRIBUTION-UNATTEN 46.OC 12.47
21 INDIAN CREEK DISTRIBUTION-UNATTEN 69.00 12.47
22 JEFFCO DISTRIBUTION-UNATTEN 69.00 24.90
23 KETE DISTRIBUTION-UNATTEN 69.00 24.90
24 LAVA DISTRIBUION-UNATTEN 46.00 12.47
25 LUND DISTRIBUTION-UNATTN 46.00 12.47
26 MCCAMMON DISTRIBUTION-UNATTEN 46.00 12.47
27 MENAN DISTRIBUTN-UNATTEN 69.00 12.47
28 MERRILL DISTRIBUION-UNATTEN 69.OC 12.47
29 MILLER DISTRIBUTION-UNATTEN 69.00 12.47
30 MONTPELIER DISTRIBUTION-UNATTEN 69.00 12.47
31 MOODY DISTRIBUTION-UNATTEN 69.OC 24.90
32 NEWDALE DISTRIBUTION-UNATTEN 69.00 12.47
33 OSGOOD DISTRIBUTION-UNATTEN 69.0C 12.47
34 PRESTON DISTRIBUTION-UNATTEN 46.00 12.47
35 RAYMND DISTRIBUTION-UNATTEN 69.00 12.47
36 RENO DISTRIBUTION-UNATTEN 69.00 12.47
37 REXBURG DISTRIBUTION-UNATTEN 69.00 12.47
38 RIRIE DISTRIBUTION-UNATTEN 69.00 12.47
.39 ROBERTS DISTRIBUTION-UNATTEN 69.OC 12.47
40 RUDY DISTRIBUTION-UNATTEN 69.00 12.47
FERC FORM NO.1 (ED. 12-9)Page 426.2
............................................
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) ñA Resubmission 040312008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectiiers, 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 conipany.
Capacit of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In SerVIC)(In MVa)
Transformers Spare Type of Equipment Number of Units Tota Cacity No.In Service Trasformers (In MVa)(f (0)(h)(i)(j)(k)
20 1 1
5 1 2
30 1 1 3
5 1 4
4 1 5
21 4 6
5 1 7
13 1 8
14 1 9
14 1 10
3 1 11
6 1 12
5 1 13
14 1 14
9 1 15
3 1 16
6 1 17
9 1 18
4 1 19
20 1 20
3 1 21
22 1 22
14 1 23
3 1 24
5 1 25
3 1 26
11 1 27
20 1 28
5 1 29
8 1 30
14 1 31
20 1 32
20 1 33
13 1 34
2 1 35
20 1 36
33 2 37
9 1 38
8 1 39
7 1 40
fERC FORM NO.1 (ED. 12-96)Page 427.2
Name of Respondent This ff0rt Is:Date of Reprt Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) riA Resubmissio 04/03200
SUBSTATIONS
1. Report below the informtion 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 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 Secondary Tertiary
(a)(b)(c)(d)(e)
1 SAND CREEK DISTRIBUnON-UNATTEN 69.00 12.47
2 SANDUNE DISTRIBUTION-UNATTEN 69.00 24.90
3 SHELLEY DISTRIBUTION-UNATTEN 46.OC 12.47
4 SMITH DISTRIBUON-UNATTEN 69.00 12.47
5 SODA DISTRIBUTION-UNATTEN 138.00 7.20
6 SOUTH FORK DISTRIBUTION-UNATTEN 69.OC 12.47
7 SPUD DISTRIBUTION-UNATTEN 46.OC 12.47
8 ST. CHARLES DISTRIBUTION-UNATTEN 69.OC 12.47
9 SUGAR CITY DISTRIBUTION-UNATTEN 69.00 12.47
10 SUNNYDELL DISTRIBUTION-UNATTEN 69.OC 12.47
11 TANNER DISTRIBUTION-UNATTEN 46.00 12.47
12 TARGHEE DISTRIBUTION-UNATTEN 46.00 12.47
13 THORNTON DISTRIBUTION-UNATTEN 69.00 12.47
14 UCON DISTRIBUTION-UNATTEN 69.OC 12.47
15 WATKINS DISTRIBUTION-UNATTEN 69.00 12.47
16 WEBSTER DISTRIBUTION-UNATTEN 69.OC 12.47
17 WESTON DISTRIBUTION-UNATTEN 46.00 12.47
18 WINDSPER DISTRIBUTION-UNATTEN 69.00 24.90
19 Total 431.00 898.93
20 NUMBER OF SUBSTATIONS DIST UNATTENDED - 67
21
22 MALAD TID-UNATTENDED 138.0(46.00 12.47
23 MUD LAKE TIDUNATTENDED 69.0(12.47
24 RIGBY TID-UNATTENDED 161.0(12.47 69.00
25 SAINT ANTHONY TID-UNATTENDED 69.00 46.00 12.47
26 Total 437.00 116.94 93.94
27 NUMBER OF SUBSTATIONS TID UNATTENDED - 4
28
29 GRACE HYDRO TRASMISSION.ATTEND 138.00 46.00 6.60
30 Total 138.0(46.00 6.60
31 NUMBER OF SUBSTATIONS TRANS ATTENDED - 1
32
33 AMPS TRANSMISSION-UNATTEN 230.OC 69.00
34 ANTELOPE TRANSMISSION-UNATTEN 230.OC 161.00
35 ASHTON PLANT TRANSMISSION.UNATTEN 46.OC 2.40
36 BIG GRASSY TRANSMISSION.UNATTEN 161.00 69.00
37 BONNEVILLE TRANSMISSION.UNATTEN 161.OC 69.00
38 CARIBOU TRANSMISSION.UNATTEN 138.OC 46.00
39 CONDA TRANSMISSION-UNATTEN 138.00 46.00
40 FISH CREEK TRANSMISSION.UNATTEN 161.0(46.00
FERC FORM NO.1 (ED. 12-96)Pag 426.3
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2oo7/Q4
(2) ñA Resubmission 04/03/2008
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 shanng expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of accunt. 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 Type of Equipment Total Capcity No.In Service Transformers Number of Units (in~a)(f)(a)(h)(i)(i)(k
40 2 1
20 1 2
20 1 3
20 1 4
22 1 5
14 1 6
8 1 7
5 1 8
13 1 9
13 1 10
4 1 11
4 1 12
7 1 13
7 1 14
14 1 15
20 1 16
4 1 17
20 1 18
796 72 1 19
20
21
71 4 1 22
14 1 23
189 4 24
40 2 25
314 11 1 26
27
28
115 4 29
115 4 30
31
32
75 2 1 33
250 1 34
25 3 35
67 1 36
67 1 37
27 1 38
67 1 39
25 3 40
FERC FORM NO.1 (ED. 12-9)Page 427.3
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) ñA Resubmission 04/032008
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 (t).
Line VOLTAGE (In MVa)Name and Loction of Substation Chraer of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 FRANKLIN TRNSMISSION-UNATTEN 138.00 46.00
2 GOSHEN TRANSMISSION-UNATTEN 345.00 161.00 46.00
3 JEFFERSON TRANSMISSION-UNATTEN 161.00 69.00
4 LIFTON HYDRO TRANSMISSION-UNATTEN 69.00 2.30
5 ONEIDA TRANSMISSION-UNATTEN 138.00 12.50
6 OVID TRANSMISSION-UNATTEN 138.OC 69.00
7 SCOVILLE TRANSMISSION-UNATTEN 138.OC 69.00 46.00
8 SUGARMILL TRASMISSION-UNATTEN 161.OC 46.00 69.00
9 TREASURETON TRSMISSION-UNATTN 230.00 138.00
10 Total 2783.00 1121.20 161.00
11 NUMBER OF SUBSTATIONS TRANS UNATTENDED - 17
12
13 Oregon
14 26TH STREET DISTRIBUTION-UNATTEN 20.00 4.16
15 35TH STREET DISTRIBUTION-UNATTEN 20.80 2.40
16 AGNESS AVE DISTRIBUTION-UNATTEN 115.00 12.47
17 ALDERWOOD DISTRIBUTION-UNATTEN .69.00 12.47
18 ARLINGTON DISTRIBUnON-UNATTN 69.00 12.47
19 ATHENA DISTRIBUTION-UNATTEN 69.00 12.47
20 BANDON TIE DISTRIBUTION-UNATTEN 20.80 12.47
21 BEACON DISTRIBUION-UNATTN 69.0(12.47
22 BEALL LANE DISTRIBUION-UNATTEN 115.00 12.47
23 BEATT DISTRIBUTION-UNATTEN 69.0(12.47
24 BELKNAP DISTRIBUTION-UNATTEN 69.00 12.47
25 BLAOCK DISTRIBUTION-UNATTEN 69.00 12.47
26 BLOSS DISTRIBUTION-UNATTEN 115.00 12.47
27 BLY DISTRIBUTION-UNATTEN 69.00 12.47
28 BOISE CASCADE DISTRIBUTION-UNATTEN 69.00 11.00
29 BONANZA DISTRIBUTION-UNATTEN 69.00 12.47
30 BOND STREET DISTRIBUTION-UNATTEN 69.00 12.50
31 BROOKHURST DISTRIBUTION-UNATTEN 115.0(12.47
32 BROWNSVILLE DISTRIBUON-UNATTN 69.OC 20.80
33 BRYANT DISTRIBUTION-UNATTEN 69.0(12.47
34 BUCHANAN DISTRIBUTION-UNATTEN 115.OC 20.80
35 BUCKAROO DISTRIBUTION-UNATTEN 69.00 12.47
36 CAMPBELL DISTRIBUTION-UNATTEN 115.00 12.47
37 CANNON BEACH DISTRIBUTION-UNATTEN 115.00 12.47
38 CARNES DISTRIBUTION-UNATTEN 69.00 12.47
39 CASEBEER DISTRIBUTION-UNATTEN 69.00 20.80
40 CAVEMAN DISTRIBUTION-UNATTEN 115.OC 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.4
............................................
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) riA Resubmission 04/0312008
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.
capacit of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service)(In MVa)
Transformers Spare Type of Equipment Total Capacit No.In servce Transformers Number of Units
(IOCtva)
(f)(g)(h)(j en k)
75 1 1
763 8 1 2
233 3 3
6 2 4
40 2 5
30 1 6
76 2 7
168 3 8
533 2 9
2527 37 2 10
11
12
13
5 1 14
30 6 15
25 1 16
25 1 17
5 1 18
9 1 19
8 3 1 20
11 3 21
25 1 22
6 1 23
40 2 24
2 3 25
32 2 26
8 3 27
3 1 .28
8 3 29
25 1 30
50 2 31
13 1 32
34 2 33
40 2 34
34 2 35
20 1 36
13 1 37
9 3 38
20 1 39
45 2 40
FERC FORM NO.1 (ED. 12-9)Page 427.4
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yrt End of 2007/04
(2) riA Resubmission 041031200
SUBSTATIONS
1. Report below the informtion 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 TertaryPrimarySecndary
(a)(b)(c)(d)(e)
1 CHERRY LANE DISTRIBUTION-UNATIEN 69.00 12.47
2 CHILOQUIN MARKET DISTIBUION-UNATIEN 69.00 12.47
3 CHINAHAT DISTRIBUION-UNATIEN 69.00 12.47
4 CIRCLE BLVD DISTRIBUION-UNATIN 115.00 20.80
5 CLEVELAND AVE DISTRIBUTION-UNATIEN 69.00 12.47
6 CLINE FALLS HYDRO DISTRIBUTION-UNATIEN 12.47 2.40
7 CLOAKE DISTRIBUTION-UNATIEN 69.00 20.80
8 COBURG DISTRIBUTION-UNATIEN 69.00 20.80
9 COLISEUM DISTRIBUTION-UNATTEN 20.8(4.16
10 COLUMBIA DSITRIBUTION-UNATIEN 115.OC 12.47 57.00
11 COSAIVER DISTRIBUION-UNATTEN 115.00 20.80
12 COQUILLE DISTRIBUON.UNATIN 115.00 20.80
13 CREEK DISTRIBUnON-UNATIN 69.00 34.50
14 CROOKED RIVER RANCH DISTRIBUTION-UNATTEN 69.00 20.80
15 CROWFOOT DISTIBUTION-UNATTEN 115.00 12.47
16 CULLY DISTRIBUTION-UNATIEN 115.00 .12.47
17 CULVER DISTRIBUTION-UNATTEN 69.00 12.47
18 CUTLER CITY DISTRIBUTION-UNATTEN 20.80 4.16
19 DAIRY DISTRIBUTION-UNATTEN 69.00 12.47
20 DALS DISTRIBUTION-UNATTEN 115.00 20.80
21 DALREED DISTRIBUTION-UNATTEN 23O.0C 34.50
22 DESCHUTES DISTRIBUTION-UNATTEN 69.00 12.47
23 DEVILS LAKE DISTRIBUTION-UNATTEN 115.00 20.80
24 DIXON DISTRIBUTION-UNATTEN 115.00 4.16,
25 DODGE BRIDGE DISTRIBUION-UNATTEN 69.00 20.80
26 EAST VALLEY DISTRIBUTON-UNATIN 115.00 12.47
27 EMPIRE DISTRIBUTION-UNATTEN 115.00 20.80
28 ENTERPRISE DISTRIBUTION-UNATTEN 69.00 12.47
29 FERN HILL DISTRIBUTION-UNATTEN 115.00 12.47
30 FIELDER CREEK DISTRIBUTION-UNATTEN 115.00 20.80
31 FOOTHILLS DISTRIBUTION-UNATTEN 69.00 12.47
32 FRALEY DISTRIBUTION-UNATTEN 69.00 12.47
33 GARDEN VALLEY DISTRIBUTION-UNATTEN 69.OC 20.80
34 GAZLEY DISTRIBUTION-UNATTEN 69.00 12.47
35 GEARHART DISTRIBUTION-UNATIEN 12.47 4.16
36 GLENDALE DISTRIBUTION-UNATTEN 23O.OC 12.47
37 GLENEDEN DISTRIBUTION-UNATTEN 20.80 4.16
38 GLIDE DISTRIBUTION-UNATTEN 115.00 12.47
39 GOLD HILL DISTRIBUTION-UNATTEN 69.00 12.47
40 GORDON HOLLOW DISTRIBUTION-UNATTEN 69.00 12.47
FERC FORM NO.1 (ED. 12-9)Page 426.5
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PaCifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) ñA Resubmission 04/0312008
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 Line
(In Service)(In MVa)Transformers Spare
Typ Of Equipment Total cacity No.In Service Transformers Number of Units
(f (a)(h)(i)(j (Int:a)
25 1 1
5 3 2
25 1 3
80 2 4
45 2 5
1 3 6
20 1 7
1 3 8
9 2 9
55 2 1 10
20 1 11
40 2 12
5 1 13
25 2 14
20 1 .15
25 1 16
13 1 17
2 3 18
25 1 19
50 2 20
75 3 21
13 1 .22
50 2 23
7 1 24
13 1 25
45 2 26
20 1 27
19 2 28
13 1 29
25 1 30
21 4 31
5 3 32
20 1 33
8 3 34
8 3 35
25 2 36
5 1 37
13 1 38
11 3 39
6 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.5
Name of Respondent This oo0rt Is:Date of Reprt Year/Period of Report
PacifiCorp (1) X An Original (Me, Da, Yr)End of 2007/04
(2) ñA Resubmission 0420
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 accrding to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstatinNo.Pnmary Secondary Tertiary
(a)(b)(c)(d)(e)
1 GOSHEN DISTRIBUTION-UNATTEN 115.0(20.80
2 GRANT STREET DISmIBUTION-UNATIN 115.0(20.80
3 GRASS VALLEY DISmIBUTON-UNATTEN 20.80 4.16
4 GREEN DISTRIBUTON-UNATTEN 69.00 12.47
5 GRIFFIN CREEK DISTRIBUTION-UNATTEN 115.00 12.47
6 HAMAKER DISTRIBUTION-UNATTEN 69.00 12.47
7 HARRISBURG DISTRIBUTION-UNAlTEN 69.00 20.80
8 HENLEY DISTRIBUTION-UNAlTEN 69.00 12.47
9 HERMISTON DISTRIBUTION-UNATTEN 69.00 12.47
10 HILLVIEW DISTRIBUTION-UNAlTEN 115.0(20.80
11 HINKLE DISTRIBUTION-UNATTEN 69.0(12.47
12 HOLLADAY DISTRIBUTION-UNATTEN 115.00 12.47
13 HOLLYWOOD DISmIBUTON-UNATIN 115.OC 12.47
14 HOOD RIVER DISTRIBUTION-UNATTEN 69.00 12.47
15 HORNET DISTRIBUTION-UNATTEN 69.00 12.47
16 INDEPENDENCE DISTRIBUTION-UNAlTEN 69.OC 20.80
17 JACKSONVILLE DISTRIBUTION-UNATTEN 115.00 12.47 69.00
18 JEFFERSON DISmIBUTION-UNATTEN 69.OC 20.80
19 JEROME PRAIRIE DISTRIBUTION-UNATTEN 115.OC 12.47
20 JORDAN POINT DISmIBUTION-UNATTEN 115.00 12.47
21 JOSEPH DISTRIBUTION-UNATTEN 20.00 12.47
22 JUNCTION CITY DISTRIBUTION-UNATTEN 69.00 20.80
23 KENWOOD DISTRIBUTION-UNATTEN 69.00 12.47
24 KILLINGWORTH DISTRIBUTION-UNATTEN 69.00 12.47
25 KNAPPA SVENSEN DISTRIBUTION-UNATIN 115.00 12.47
26 LAKEPORT DISTRIBUTON-UNATTEN 69.00 12.47
27 LAKEVIEW DISTRIBUTION-UNATTEN 69.00 12.47
28 LANCASTER DISTRIBUTION-UNAlTEN 69.00 20.80
29 LEBANON DISTRIBUTION-UNATTEN 115.00 20.80
30 LINCOLN DISTRIBUTION-UNATIN 115.00 12.47
31 LOCKHART DISTRIBUTION-UNATTEN 115.0(20.80
32 LYONS DISTRIBUTION-UNATTEN 69.0(20.80
33 MADRAS DISTRIBUTION-UNATTEN 69.00 12.47
34 MALLORY DISTRIBUTION-UNATTEN 115.00 12.47
35 MARYS RIVER DISTRIBUTION-UNATTEN 115.OC 20.80
36 MEDCO DISTRIBUTION-UNATTEN 115.00 12.47
37 MEDFORD DISTRIBUTION-UNATTEN 69.OC 12.47
38 MERLIN DISTRIBUTION-UNAlTEN 115.00 12.47
39 MERRILL DISTRIBUTION-UNATTEN 69.0(12.47
40 MINAM DISTRIBUTION-UNATTEN 69.00 12.47
FERC FORM NO.1 (ED. 12-9)Page 426.6
............................................
............................................
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2)A Resubmission 04/0312008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capcity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service)(In MVa)Transformers Spare Typ of Equipment Tota Caacity No.In Service Transformers Number of Units
(f)(g)(h)(i)(j (In
(Wa)
20 1 1
45 2 2
1 4 3
25 1 4
20 1 5
8 3 6
13 1 7
6 3 8
40 2 9
45 2 10
20 1 11
75 3 12
50 2 13
40 2 14
20 1 15
20 1 16
75 2 17
13 1 18
20 1 19
20 1 20
6 1 1 21
25 2 22
3 3 23
40 2 24
6 1 25
50 2 26
9 3 27
13 3 28
40 2 29
105 3 30
40 2 31
9 1 32
25 2 33
25 1 34
20 1 35
20 1 36
79 14 37
45 2 38
17 6 39
1 40
FERC FORM NO.1 (ED. 12-96)Page 427.6
Name of Respondent ThiSwrtlS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 207/04
(2) DA Resubmission 040318
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).
Line VOLTAGE (In MVa)
No.Name and Loctin of Substati Chacter of Substation
Primary Secdary Tertiary
(a)(b)(c)(d)(e)1 MODOC .DISTRIBUTION-UNATTEN 69.00 12.47
2 MORO DISTRIBUTION-UNATTEN 20.80 2.40
3 MURDER CREEK DISTRIBUTION-UNATTEN 115.0(20.80
4 MYRTLE CREEK DISTRIBUTION-UNATTEN 69.00 12.47
5 MYRTLE POINT DISTRIBUTION-UNATTEN 115.0(20.80
6 NELSCOTT DISTRIBUTON-UNATTEN 20.80 4.16
7 NEW O'BRIEN DISTRI8UON-UNATTEN 115.00 12.47
8 OAK KNOLL DISTIBUION-UNATTN 115.00 12.47
9 OAKLAND DISTRI8UON-UNATTEN 115.00 12.47
10 ORCHARD STREET DISTRIBUION-UNATTN 12.47 4.16
11 OVERPASS DISTRIBUION-UNATTEN 69.00 12.47
12 PALLETTE DISTRIBUTION-UNATTEN 69.0(20.80
13 PARK STREET DISTRIBUTION-UNATTN 115.0(12.47
14 PARKROSE DISTRIBUTION-UNATTEN 57.00 12.47
15 PENDLETON DISTRIBUTION-UNATTEN 69.00 12.47
16 PILOT ROCK DISTIBUTION-UNATTEN 69.00 12.47
17 POWELL BUTE DISTRIBUTON-UNATTEN 115.00 12.47
18 PRINEVILLE DISTRIBUTION-UNATTEN 115.00 12.47
19 PROVOLT DISTRIBUION-UNATTEN 69.00 12.47
20 QUEEN AVE DISTRIBUTION-UNATTEN 69.00 20.80
21 RED BLANKET DISTRIBUTION-UNATTEN 69.00 4.16
22 REDMOND DISTIBUTON-UNATTEN 115.00 12.47
23 RICH MANUFACTURING DISTRIBUTION-UNATTN 57.00 12.47
24 RIDDLE DISTRIBUTION-UNATTEN 69.00 12.47
25 RIDDLE VENEER DISTRIBUTION-UNATTEN 69.00 12.47
26 ROGUE RIVER DISTRIBUTION-UNATTEN 69.00 12.47
27 ROSEBURG DISTRIBUTION-UNATTEN 115.00 20.80
28 ROSS AVE DISTRIBUTION-UNATTEN 69.00 12.47
29 ROXY DISTRIBUTION-UNATTN 115.00 12.50
30 RUCH DISTRIBUTON-UNATTN 69.0(12.47
31 RUNNINGY DISTRIBUION-UNATTN 69.0(20.80
32 RUSSELLVILLE DISTRIBUTION-UNATTN 115.OC 12.47
33 SAGE ROAD DISTRI8UON-UNATTN 115.0(12.47
34 SCENIC DISTRIBUTION-UNATTEN 115.00 12.47 69.00
35 SCIO DISTRIBUTION-UNATTEN 69.OC 12.47
36 SEASIDE DISTRIBUTION-UNATTEN 115.OC 12.47
37 SELMA DISTRIBUTION-UNATTEN 115.00 12.47
38 SHASTA WAY DISTRIBUTION-UNATTEN 12.47 4.16
39 SHEVLIN PARK DISTRIBUTION-UNATTEN 69.00 12.50
40 SIMTAG BOOSTER PUMP DISTRIBUTION-UNATTEN 34.S(4.16
FERC FORM NO.1 (ED. 12-9)Page 426.7
............................................
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) FiA Resubmission 040312008
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 part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service)(In MVa)
Transformers Spare Type of Equipment Total Capaty No.In Service Trasformers Number of Units (in~a)(f (0)(h)(i)(j)(k
6 3 1
2 3 2
100 4 3
14 1 4
9 1 5
4 1 6
9 1 7
45 2 8
8 1 9
2 3 10
45 2 11
1 1 1 12
40 2 13
39 2 14
46 7 1 15
22 2 16
6 1 17
50 2 18
11 3 19
50 2 20
2 3 21
50 2 22
8 1 23
14 1 24
25 1 25
25 2 26
50 2 27
9 3 28
25 1 29
9 1 30
9 1 31
45 2 32
40 2 33
70 3 34
8 1 35
40 2 36
9 1 37
2 3 38
25 1 39
19 2 40
FERC FORM NO.1 (ED. 12-9)Page 427.7
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) ñA Resubmission 04103/2008
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 Substation Chraer of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 SOUTH DUNES DISTRIBUTION-UNATTN 115.00 12.47
2 SOUTHGATE DISTRIBUTION-UNATTEN 69.00 20.80
3 SPRAGUE RIVER DISTRIBUTION-UNATTEN 69.00 12.47
4 STATE STREET DISTRIBUTION-UNATTEN 115.00 20.80
5 STAYTON DISTRIBUTION-UNATTEN 69.00 12.47
6 STEAMBOAT DISTRIBUTION-UNATTEN 115.00 7.20
7 STEVENS ROAD DISTRIBUTION-UNATTEN 115.00 20.80
8 SUTHERLIN DISTRIBUTON-UNATTN 115.()12.47
9 SWEETHOME DISTRIBUTION-UNATTEN 115.00 20.80
10 TAKELMA DISTRIBUTON-UNATTEN 115.()20.80
11 TALENT DISTRIBUTION-UNATTN 69.()12.47
12 TEXUM DISTRIBUTION-UNATTEN 69.00 12.47
13 TILLER DISTRIBUTION-UNATTEN 115.00 12.47
14 TOLO DISTRIBUTION.UNATTEN 69.00 12.47
15 UMAPINE DISTRIBUTION-UNATTEN 69.00 12.47
16 UMATILLA DISTRIBUTON-UNATTEN 69.00 12.47
17 US PLYWOOD DISTRIBUTION-UNATTN 20.80 4.16
18 VERNON DISTRIBUTION-UNATTEN 69.00 12.47
19 VILAS DISTRIBUON-UNATTEN 115.00 12.47
20 VILLAGE GREEN DISTRIBUION-UNATTN 115.()20.80
21 VINE STREET DISTRIBUTION-UNATTN 69.00 20.80
22 WALLOWA DISTRIBUTON-UNATTEN 69.()12.47
23 WARM SPRINGS DISTRIBUTION-UNATTEN 69.00 20.80
24 WARRENTON DISTRIBUTION-UNATTEN 115.00 12.47
25 WASCO DISTRIBUTION-UNATTEN 20.80 4.16
26 WECOMA BEACH DISTRIBUTION-UNATTEN 20.80 4.16
27 WESTERN KRAFT DISTRIBUTION.UNATTEN 115.00 12.47
28 WESTON DISTRIBUTION-UNATTEN 69.00 12.47
29 WESTSIDE HYDRO DISTRIBUTION-UNATTEN 69.00 12.47
30 WEYERHAUSER DISTRIBUTION-UNATTEN 69.()12.47
31 WHITE CITY DISTRIBUTION-UNATTEN 115.()12.47
32 WILLOW COVE DISTRIBUTION-UNATTEN 34.&4.16
33 WINSTON DISTRIBUION-UNATTEN 69.()12.47
34 YOUNGS BAY DISTRIBUTION-UNATTEN 115.()12.47
35 Total 15039.28 2472.84 195.00
36 NUMBER OF SUBSTATIONS DIST UNATENDED -181
37
38 ALBINA TID-UNATTENDED 115.00 12.47 69.00
39 APPLEGATE TID-UNATTENDED 115.OC 69.00 12.47
40 ASHLAND TID.UNATTENDED 115.00 69.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.8
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FíA Resubmission 040312008
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 accunting 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 Line
(In Service) (In MVa)Transformers Spare
Tota Capacity No.In Service Transformers Type of Equipment Number of Units
(ft (a)(h)ti)ü)
(In t~a)
9 1 1
20 1 2
7 3 3
40 2 4
55 2 5
1 6
25 1 7
13 1 8
42 2 9
13 1 10
50 2 11
17 6 12
1 1 13
11 1 14
13 1 15
25 2 16
13 2 17
50 2 18
25 1 19
40 2 20
22 4 21
7 1 22
13 3 23
25 2 24
3 3 25
3 1 26
50 2 .27
22 2 28
23 9 29
40 2 30
60 3 31
28 3 32
23 3 33
37 2 34
4409 365 5 35
36
37
1n 9 38
65 2 39
70 2 40
FERC FORM NO.1 (ED. 12-9)Page 427.8
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) riA Resubmission 04312008
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 BEND PLANT TIDUNATTENDED 69.00 4.16 12.47
2 CAVE JUNCTION TIDUNATTNDED 115.00 12.47 69.00
3 HAZELWOOD TID-UNATTENDED 115.00 69.00 12.47
4 KNOTT TID UNATTENDED 115.00 12.47 57.00
5 MILE HI TID-UNATTENDED 115.OC 69.00 12.47
6 PILOT BUTTE TID-UNATTENDED 230.OC 69.00 12.47
7 WINCHESTER TID-UNATTENDED 115.00 12.47 69.00
8 Totl 1219.OC 399.04 338.82
9 NUMBER OF SUBSTATIONS TID UNATTENDED - 10
10
11 CLEARWATER #1 HYDRO PLANT TRASMISSION-ATTEND 138.OC 6.90
12 CLEARWATER #2 HYDRO PLANT TRANSMISSION-ATTEND 138.00 12.00
13 FISH CREEK HYDRO TRASMISSION-ATTND 115.00 6.90
14 JC BOYLE HYDRO TRANSMISSION-ATTND 230.00 11.00
15 LEMOLO #1 HYDRO TRASMISSION-ATTEND 115.00 12.47
16 LEMOLO #2 HYDRO TRANSMISSION-ATTEND 115.00 12.00
17 PROSPECT 1 HYDRO TRANSMISSION-ATTND 69.00 2.30
18 PROSPECT 2 HYDRO TRANSMISSION-ATTEND 69.00 6.60
19 PROSPECT 3 HYDRO TRANSMISSION-ATTEND 69.OC 12.47
20 TOKETEE HYDRO TRANSMISSION-ATTEND 115.OC 6.90
21 Total 1173.OC 89.54
22 NUMBER OF SUBSTATIONS TRANS ATTENDED - 10
23
24 BEND PLANT TRNSMISSION-UNATTEN 4.16 2.40
25 CALAPooYA TRASMISSION-UNATTEN 230.00 69.00
26 CHILOQUIN TRASMISSION-UNATTEN 230.00 115.00 69.00
27 COLD SPRINGS TRANSMISSION-UNATTN 230.00 69.00
28 COVE TRANSMISSION-UNATTEN 230.00 69.00
29 DAYS CREEK TRANSMISSION-UNATTEN 115.00 69.00
30 DIAMOND HILL TRANSMISSION-UNATTEN 23O.OC 69.00
31 DIXONVILLE 115/230 TRANSMISSION-UNATTEN 230.00 115.00 69.00
TRANSMISSION-UNATTEN 5OO.OC 230.00
33 EAGLE POINT HYDRO TRANSMlSSION-UNATTN 115.00 2.40
34 EAST SIDE HYDRO TRASMISSION-UNATTEN 46.OC 12.47
35 FISH HOLE TRASMISSION-UNATTEN 115.OC 69.00
36 FRY TRANSMISSION-UNATTEN 230.OC 115.00
37 GRANTS PASS TRANSMISSION-UNATTEN 230.00 115.00 69.00
38 GREEN SPRINGS PLANT TRANSMISSION-UNATTEN 115.OC 69.00
39 HURRICANE TRANSMISSION-UNATTEN 230.00 69.00 2.40
40 ISTHMUS TRANSMISSION-UNATTEN 230.OC 115.00
FERC FORM NO.1 (ED. 12-9)Page 426.9
............................................
-...........................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) r'A Resubmission 04/0312008
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 accunting between the parties, and state amounts and accunts
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 capaity No.In Service Transformers Number of Units
(f)(a)(h)(i)CD
(in(~a)
23 3 1
70 2 2
132 4 3
187 8 4
39 4 5
400 4 6
75 5 7
1238 43 8
9
10
17 3 11
31 3 12
13 3 13
89 2 1 14
48 7 1 15
40 4 16
5 3 17
40 6 1 18
10 6 19
50 9 20
343 46 3 21
22
23
3 3 24
75 1 25
119 4 26
60 1 27
67 3 28
50 1 29
75 1 30
34 6 31
650 3 1 32
3 1 33
3 3 34
7 3 35
500 2 36"
458 4 37
19 3 38
29 2 39
250 1 40
FERC FORM NO. 1 (EO. 12-96)Page 427.9
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) nA Resubmission 04200
SUBSTATIONS
1. Report below the informtion 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 Chracter of Substion
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 KENNEDY TRANSMISSION-UNATTEN 69.OC 57.00
2 KLAMATH FALLS TRANSMISSION-UNATTEN 230.OC 69.00
3 LONEPINE TRANSMISSION-UNATTEN 23O.OC 115.00 69.00
TRANSMISSION-UNATTEN 5OO.OC 230.005 MONPAC TRASMISSION-UNATTEN 115.00 69.00
6 PONDEROSA TRANSMISSION-UNATTN 230.00 115.00
7 POWERDALE PLANT TRASMISSION-UNATTEN 69.OC 7.20
8 PROSPECT CENTRAL TRASMISSION-UNATTEN 115.00 69.00
9 ROBERTS CREEK TRANSMISSION-UNATTEN 115.00 69.00
10 SLIDE CREEK HYDRO TRSMISSION-UNATTEN 115.OC 7.00
11 SODA SPRINGS HYDRO TRANSMISSION-UNATTEN 115.0C 7.00
12 TROUTDALE TRANSMISSION-UNATTEN 230.00 115.00 69.00
13 TUCKER TRANSMISSION-UNATTEN 115.00 69.00
14 WALLOWA FALLS HYDRO TRANSMISSION-UNATTEN 20.&
15 Total 5578.96 2372.47 347.40
16 NUMBER OF SUBSTATIONS TRANS UNATTEND - 31
17
18 Utah
19 106THSOUTH DISTRIBUON-UNATTEN 138.00 12.50
20 118THSOUTH DISTRIBUTION-UNATTEN 138.00 12.47
21 70TH SOUTH DISTRIBUTION-UNATTEN 138.0(12.47
22 ALTAVIEW DISTRIBUION-UNATTEN 46.00 12.47
23 AMALGA DISTRIBUTION-UNATTEN 46.0(12.47
24 AMERICAN FORK DISTRIBUTION-UNATTEN 138.00 12.47
25 ARAGONITE DISTRIBUTION-UNATTEN 46.00 7.20
26 AURORA DISTRIBUTION-UNATTEN 46.00 12.47
27 BANGERTER DISTRIBUTION-UNATTEN 138.00 12.47
28 BEAR RIVER DISTRIBUTION-UNATTEN 46.00 12.47
29 BENJAMIN DISTRIBUTION-UNATTEN 46.00 12.47
30 BINGHAM DISTRIBUION-UNATTEN 46.00 12.47
31 BLUE CREEK DISTRIBUTON-UNATTN 46.00 12.47
32 BLUFF DISTRIBUON-UNATTN 69.OC 12.47
33 BLUFFDALE DISTRIBUTION-UNATTEN 46.00 12.47
34 BOTHWELL DISTRIBUTION-UNATTEN 46.00 12.47
35 BOX ELDER DISTRIBUTION-UNATTEN 46.00 12.47
36 BRIAN HEAD DISTRIBUTION-UNATTEN 46.00 12.47
37 BRICKYARD DISTRIBUTION-UNATTEN 46.00 12.47
38 BRIGHTON DISTRIBUTION-UNATTEN 46.OC 24.90
39 BROOKLAWN DISTRIBUTION-UNATTEN 46.0C 12.47
40 BRUNSWICK DISTRIBUTION-UNATTEN 46.00 12.47
FERC FORM NO.1 (ED. 12-9)Page 426.10
............................................
............................................
Name of Respondent This '00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) ¡=A Resubmission 04/0312008
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 coowner 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 assoiated company.
capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)Trasformers Spare Typ of Equipment Total Caciy No.In Service Transformers Number of Units
(a)ti)ti)(In ~~a)(1)(h)(k
33 1 1
251 6 1 2
733 10 3
1300 6 1 4
50 1 5
250 1 6
8 3 1 7
47 4 8
50 1 9
21 3 10
13 3 11
500 3 12
100 2 13
2 3 14
6070 89 4 15
16
17
18
30 1 19
30 1 20
1 21
45 2 22
11 1 23
30 1 24
1 1 25
3 1 26
50 1 27
17 2 28
2 1 29
11 1 30
2 3 31
1 3 32
9 1 33
4 1 34
14 1 35
14 1 36
9 1 37
26 2 38
6 1 39
60 3 40
FERC FORM NO.1 (ED. 12-96)Page 427.10
Name of Respondent This~rtIS:Date of ReJ)rt Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 207/04
(2) ñA Resubmission 0403
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 Locatio of Substation Chaer of Subtion
Primary Sedary Teriary
(a)(b)(c)(d)(e)
1 BURTON DISTRIBUTION-UNATTEN 34.50 12.47
2 BUSH DISTRIBUTION-UNATTN 46.00 12.47
3 CANNON DISTRIBUTION-UNATTN 46.00 12.47
4 CANYONLANDS DISTRIBUTION-UNATTEN 69.OC 12.47
5 CAPITOL DISTRIBUTION-UNATTEN 46.00 12.47
6 CARBIDE DISTRIBUTION-UNATTEN 46.00 7.20
7 CARBONVILLE DISTRIBUTION-UNATTEN 46.00 12.47
8 CARLISLE DISTRIBUTION-UNATTEN 138.00 12.50
9 CASTO SUBSTATION DISTRIBUON-UNATTN 46.OC 12.47
10 CENTENNIAL DISTRIBUTION-UNATTEN 138.00 12.47
11 CENTERVILLE DISTRIBUTON-UNATTEN 46.00 12.47
12 CENTRAL DISTRIBUIO-UNATTEN 46.00 12.47
13 CHAPEL HILL DISTRIBUTON-UNATTEN 138.00 12.47
14 CHERRYWOOD DISTRIBUTON-UNATTN 138.00 12.47
15 CIRCLEVILLE DISTRIBUTION-UNATTN 69.OC 12.47
16 CLEAR CREEK DISTRIBUTION-UNATTEN 46.OC 12.47
17 CLEARLAKE DISTRIBUTION-UNATTEN 46.OC 12.47
18 CLEARFIELD SOUTH DISTRIBUTION-UNATTEN 138.OC 12.47
19 CLINTON DISTRIBUTION-UNATTEN 138.OC 12.47
20 CLIVE DISTRIBUTION-UNATTN 46.OC 12.47
21 COALVILLE DISTRIBUTION-UNATTEN 46.OC 12.47
22 COLD WATER CANYON DISTIBUION-UNATTEN 138.00 12.47
23 COLEMAN DISTRIBUTION-UNATTN 138.OC 69.00 12.47
24 COLTON WELL DISTRIBUION-UNATTEN 46.OC 12.47
25 CORINNE DISTRIBUION-UNATTEN 46.OC 12.47
26 COVE FORT DISTRIBUTION-UNATTEN 46.00 12.47
27 CRESCENT JUNCTION DISTRIBUTION-UNATTEN 46.OC 7.20
28 CROSS HOLLOW DISTRIBUTION-UNATTEN 138.00 12.47
29 CUDAHY DISTRIBUTION-UNATTEN 138.00 12.47
30 DAMMERON VALLEY DISTRIBUTION-UNATTEN 34.5C 12.47
31 DECKER LAKE DISTRIBUTION-UNATTEN 138.00 12.47
32 DELLE DISTRIBUTION-UNATTEN 46.00 12.47
33 DELTA DISTRIBUTON-UNATTEN 46.0(12.47
34 DESERET DISTRIBUON-UNATTEN 46.0(4.16
35 DEWEYILLE DISTRIBUTION-UNATTEN 46.OC 12.47
36 DIMPLE DELL DISTRIBUTION-UNATTEN 138.OC 12.47
37 DIXIE DEER DISTRIBUTION-UNATTEN 34.50 12.47
38 DRAPER DISTRIBUTION-UNATTEN 46.00 12.47
39 DUMAS DISTRIBUTION-UNATTEN 138.00 12.47
40 EAST BENCH DISTRIBUTION-UNATTEN 138.OC 12.47
FERC FORM NO.1 (ED. 12-9)Pag 426.11
............................................
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) FiA Resubmission 04/03/2008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectiiers, 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 EOUIPMENT Line
(In Service)(In MVa)
Transformers Spare Typ of Equipment Tot capaity No.In Serve Transformers Number of Units
(1)(i:l (hI (il (j (in(~~a)
4 1 1
9 1 2
13 1 3
1 1 4
20 1 5
3 1 6
6 1 7
30 1 8
25 1 9
40 2 10
22 1 11
2 1 12
30 1 13,
25 1 14
3 1 15
4 1 16
3 17
60 2 18
50 2 19
4 1 20
20 2 21
30 1 22
106 4 23
1 3 24
3 1 25
2 3 26
1 1 27
22 1 28
22 1 29
42 1 30
55 2 31
6 1 32
23 2 33
2 1 34
4 1 35
60 2 36
2 1 37
23 2 38
60 2 39
30 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.11
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2O7/Q4
(2) FiA Resubmission 0431200
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 Loation of Substatio Charaer of Substation Primar Secdary Tertiary
(a)(b)(c)(d)(e)
1 EAST HYRUM DISTRIBUTION-UNAlTEN 46.00 12.47
2 EAST LAYTON DISTRIBUTION-UNAlTEN 138.00 12.47
3 EAST MILLCREEK DISTRIBUTION-UNAlTEN 46.00 12.47
4 EDEN DISTIBUTION-UNAlTEN 46.00 12.47
5 ELBERTA DISTRIBUTION-UNAlTEN 46.00 12.47
6 ELK MEADOWS DISTRIBUION-UNAlTEN 46.00 12.47
7 ELSINORE DISTIBUTON-UNAlTEN 46.OC 12.47
8 EMERYCITY DISTRIBUTON-UNAlTEN 69.OC 12.47
9 EMIGRATION DISTRIBUTON-UNAlTEN 46.OC 12.47
10 ENOCH DISTIBUON-UNAlTEN 138.OC 12.47
11 ENTERPRISE VALLEY DISTRIBUTION-UNAlTEN 138.00 12.47
12 EUREKA DISTRIBUTION-UNAlTEN 46.00 12.47
13 FARMINGTON DISTRIBUTION-UNAlTEN 138.00 12.47
14 FAYETE DISTRIBUTION-UNAlTEN 46.00 12.47
15 FERRON DISTRIBUTION-UNAlTEN 46.00 12.47
16 FIELDING DISTRIBUTION-UNAlTEN 46.00 12.00
17 FIFTH WEST DISTRIBUTION-UNAlTEN 138.OC 12.47
18 FLUX DISTRIBUTION-UNAlTEN 46.00 12.47
19 FOOL CREEK DISTRIBUTION-UNAlTEN 46.OC 12.47
20 FOUNTAIN GREEN DISTRIBUION-UNAlTEN 46.OC 12.47
21 FREEDOM DISTRIBUION-UNAlTEN 46.00 7.20
22 FRUIT HEIGHTS DISTRIBUTION-UNAlTEN 46.OC 12.47
23 GARDEN CITY DISTRIBUTION-UNAlTEN 46.OC 12.47
24 GATEWAY DISTRIBUTION-UNAlTEN 69.00 12.47
25 GORDON AVENUE DISTRIBUTION-UNAlTEN 138.00 12.50
26 GOSHEN DISTRIBUTION-UNAlTEN 46.00 12.47
27 GRANGER DISTRIBUTION-UNAlTEN 46.00 12.47
28 GRANTSVILLE DISTRIBUTION-UNAlTEN 46.00 12.47
29 GREEN RIVER DISTRIBUTION-UNAlTN 46.00 12.47
30 GROW DISTRIBUON-UNAlTEN 138.OC 12.47 46.00
31 GUNLOCK HYDRO DISTRIBUTION-UNAlTN 34.5C 2.30
32 GUNNISON DISTRIBUTION-UNAlTEN 46.00 12.47
33 HAMILTON DISTRIBUTON-UNAlTEN 34.50 12.47
34 HAMMER DISTRIBUTION-UNAlTEN 138.00 12.47
35 HAVASU DISTRIBUTION-UNAlTEN 69.OC 12.47
36 HELPER CITY DISTRIBUTION-UNAlTEN 46.0(4.16
37 HENEFER DISTRIBUTION-UNAlTEN 46.00 12.47
38 HIAWATHA DISTRIBUTION-UNAlTEN 46.00 4.16
39 HIGHLAND DIST DISTRIBUTION-UNAlTEN 46.00 12.47
40 HOGGARD DISTRIBUTION-UNAlTEN 138.00 12.47
FERC FORM NO.1 (ED. 12-9)Page 426.12
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) ñA Resubmission 04/031208
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses Or other accounting between the parties, and state amounts and accounts
affeced in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated compny.
caacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)Trasformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In ~~a)
(fl (g)(h)(i ul (k
6 1 1
30 1 2
20 1 3
12 2 4
5 1 5
3 1 6
2 1 7
3 3 8
25 1 9
14 1 10
10 1 11
3 1 12
30 1 13
1 2 14
5 1 15
6 1 16
30 1 17
4 1 18
2 1 19
2 1 20
1 21
22 1 22
6 1 23
28 2 1 24
30 1 25
2 1 26
43 2 27
10 1 28
5 2 29
72 3 30
1 1 31
11 1 32
1 3 33
60 2 34
3 1 35
3 3 36.
1 3 37
1 3 38
25 1 39
50 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.12
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Origina (Mo, Da, Yr)End of 2007/04
(2) riA Resubmission 04031
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 Substation Charaer of SUbsion
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 HOGLE DISTRIBUTION-UNATIEN 46.00 12.47
2 HOLDEN DISTRIBUON-UNATIEN 46.OC 12.47
3 HOLLAY DISTIBUTION-UNATIEN 46.OC 12.47
4 HUNTER DISTRIBUTION-UNATIEN 46.00 12.47
5 HUNTINGTON CITY DISTRIBUTION-UNATIEN 69.OC 12.47
6 HURRICANE FIELDS DISTRIBUTION-UNATIEN 34.5C 12.47
7 IRON MOUNTAIN DISTRIBUTION-UNATIEN 34.50 7.20
8 IRON SPRINGS DISTRIBUTION-UNATIEN 34.50 12.47
9 IRONTON DISTRIBUON-UNATIEN 46.OC 12.47
10 IVINS DISTIBUION-UNATIN 34.50 12.47
11 JORDAN NARROWS DISTRIBUTION-UNATIEN 46.OC 2.40
12 JORDAN PARK DISTRIBUION-UNATIEN 138.OC 12.47
13 JORDANELLE DISTRIBUION-UNATIEN 138.00 12.47
14 JUAB DISTRIBUTON-UNATIEN 46.00 12.47
15 JUNCTION DISTRIBUTION-UNATIEN 69.00 12.47
16 KAIBAS DISTRIBUTION-UNATIEN 69.00 12.47
17 KAMAS DISTRIBUTION-UNATIEN 46.00 12.47
18 KAARRAVILLE DISTRIBUTION-UNATIEN 34.50 12.47
19 KEARNS DISTRIBUTION-UNATIEN 138.00 12.47
20 KENSINGTON DISTRIBUTION-UNATIEN 46.00 4.16
21 LAKE PARK DISTRIBUTON-UNATIEN 138.00 12.47
22 LARK DISTRIBUION-UNATIEN 46.OC 12.47
23 LAAL DISTRIBUTION-UNATIN 69.00 12.47
24 LAYTON DISTRIBUTION-UNATIEN 46.00 12.47
25 LEGRANDE DISTRIBUTION-UNATIEN 46.00 12.47
26 LEWISTON DISTRIBUTION-UNATIEN 46.00 12.47
27 LINCOLN DISTRIBUTION-UNATIEN 46.00 12.47
28 LINDON DISTRIBUTION-UNATIEN 46.00 12.47
29 LISBON DISTRIBUTION-UNATIEN 69.00 12.47
30 L1TILE MOUNTAIN DISTRIBUTION-UNATIEN 46.00 12.47
31 LOAFER DISTRIBUTION-UNATIEN 46.00 12.47
32 LOGAN CANYON DISTRIBUION-UNATIEN 46.0C 7.20
33 LONETREE DISTRIBUTION-UNATIEN 34.50 12.47
34 LOWER BEAVER DISTRIBUTON-UNATIEN 46.OC 6.60
35 LYNNDYL DISTRIBUTION-UNATIEN 46.00 12.47
36 MAESER DISTRIBUTION-UNATIEN 69.00 12.47
37 MAGNA DISTRIBUTION-UNATIEN 138.OC 12.47
38 MANILA DISTRIBUTION-UNATIEN 46.00 12.47
39 MANTUA DISTRIBUTION-UNATIEN 46.00 12.47
40 MAPLETON DISTRIBUTION-UNATIEN 46.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.13
............................................
............................................
Name of Respondent This wort Is:Date of Report Year/Peri of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) ñA Resubmission 04/0312008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capcity No.In Service Transforers Number of Units
(f (a)(h)(j en
(in(~a)
22 1 1
4 1 2
32 2 3
22 1 4
13 2 5
1 3 6
1 1 7
5 3 8
2 1 9
22 1 10
13 2 11
30 1 12
30 1 13
2 3 14
3 1 15
5 1 16
7 1 17
1 3 18
60 2 19.
7 1 20
53 2 21
6 1 22
5 1 23
40 2 24 .
2 1 25
14 1 26
20 1 27
20 1 28
4 1 29
20 1 30
1 31
1 32
20 1 33
1 3 34
4 1 35
13 1 36
30 1 37
22 1 38
2 1 39
14 1 40
FERC FORM NO.1 (ED. 12-9)Page 427.13
Name of Respondent This~rtIS:Date of Rl3rt Year/Period of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2007/04
(2) ñA Resubmission 04032008
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 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 an Location of Substation Characer of Substatio
Pnmary Secndary Tertiary
(a)(b)(c)(d)(e)
1 MARRIOTT DISTRIBUION-UNATTN 46.00 12.47
2 MARYSVALE DISTRIBUTON-UNATTEN 46.00 12.47
3 MATHIS DISTRIBUTION-UNATTEN 46.00 12.47
4 MCCORNICK DISTRIBUTION-UNATTEN 46.00 12.47
5 MCKAY DISTRIBUTION-UNATTEN 46.00 12.47
6 MEAOWBROOK DISTRIBUTION-UNATTEN 138.00 12.47 46.00
7 MEDICAL DISTRIBUTION-UNATTEN 46.00 12.47
8 MELLING DISTRIBUTION-UNATTEN 34.50 4.16
9 MIDLAND DISTRIBUTION-UNATTEN 138.00 12.47
10 MIDVALE DISTRIBUTION-UNATTEN 46.00 12.47
11 MILFORD DISmIBUTION-UNATTEN 46.00 12.47
12 MILFORD TV DISTRIBUTON-UNATTN 46.00 7.20
13 MILLVILLE DISTRIBUTION-UNATTEN 46.00 12.47
14 MINERSVILLE DISTRIBUTION-UNATTEN 46.00 12.47
15 MOAB CITY DISTRIBUTION-UNATTN 69.00 12.47
16 MONTEZUMA DISTRIBUTION-UNATTEN 69.00 12.47
17 MOORE DISTRIBUTION-UNATTEN 69.00 12.47
18 MORGAN DISTRIBUTION-UNATTEN 46.0(4.16
19 MORONI DISTRIBUTION-UNATTEN 46.0(12.47
20 MORTON COURT DISTRIBUTION-UNATTEN 138.00 12.47
21 MOSS JUNCTION DISTRIBUTION-UNATTEN 46.0(12.47
22 MOUNTAIN DELL DISmIBUTION-UNATTEN 46.0(12.47
23 MOUNTAIN GREEN DISmIBUION-UNATTEN 46.OC 12.47
24 MYTON DISTRIBUTON-UNATTEN 69.00 12.47
25 NEW HARMONY DISmIBUTION-UNATTEN 69.00 12.47
26 NEWGATE DISTRIBUTON-UNATTEN 46.00 12.47
27 NEWTON DISTRIBUTION-UNATTEN 46.00 12.47
28 NIBLEY DISTRIBUTION-UNATTEN 46.00 24.90
29 NORTH BENCH DISTRIBUTION-UNATTEN 46.00 12.47
30 NORTH CEDAR DISTRIBUTION-UNATTEN 34.5C 4.16
31 NORTH FIELDS DISTRIBUTION-UNATTEN 46.00 12.47
32 NORTH LOGAN DISTRIBUTION-UNATTEN 46.00 12.47
33 NORTH OGDEN DISTRIBUTON-UNATTEN 46.OC 12.47
34 NORTH SALT LAKE DISTRIBUTION-UNATTN 46.00 12.47
35 NORTHEAST DISTRIBUTION-UNATTEN 46.00 12.47
36 NORTHRIDGE DISTRIBUTION-UNATTEN 46.00 12.47
37 OAKLAND AVE DISTRIBUTION-UNATTEN 46.00 12.47
38 OAKLEY DISTRIBUTION-UNATTEN 46.0C 12.47
39 OGDEN DEFENSE DEPOT DISTRIBUTION-UNATTEN 46.00 12.47
40 OLYMPUS DISmIBUTION-UNATTEN 46.0(12.47
FERe FORM NO.1 (ED. 12-96)Page 426.14
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 04103/2008
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 accunting 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 Service) (In MVa)Transformers Spare Type of Equipment Total Capcity No.In Service Transformers Number of Units
(f)(Q)(h)(i)(j (in(~a)
20 1 1
2 3 2
9 1 3
6 1 4
20 1 5
42 2 6
58 4 7
5 1 8
30 1 9
25 1 10
14 1 11
1 1 12
13 1 13
2 1 14
19 2 15
13 1 16
3 1 17
3 1 18
6 1 19
25 1 20
6 3 21
5 1 22
6 1 23
6 1 24
7 1 25
20 1 26
5 1 27
14 1 28
25 1 29
5 1 30
2 1 31
25 1 32
22 1 33
13 1 34
45 10 35
14 1 36
24 2 37
6 1 38
11 5 3 39
22 1 40
FERC FORM NO.1 (ED. 12-9)Page 427.14
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2007/04
(2) nA Resubmission 0403/008
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 accrding to funcion the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Seconda Tertiary
(a)(b)(c)(d)(e)
1 OPHIR DISTRIBUTION-UNATTEN 46.00 12.47
2 ORANGE DISmIBUTION-UNATTEN 46.0(12.47
3 ORANGEVILLE DISTRIBUTION-UNATTEN 69.00 12.47
40REM DISTRIBUTION-UNATTEN 46.0(12.47
50REMET DISmIBUTION-UNATTEN 115.0(12.47
6 PACK CREEK RESERVOIR DISTRIBUTION-UNATTEN 46.00 12.47
7 PANGUITCH DISTRIBUTION-UNATTEN 69.00 12.47
8 PARlETE STATION DISTRIBUTION-UNATTEN 69.00 24.90 -
9 PARKCITV DISTRIBUTION-UNATTEN 46.00 12.47
10 PARKWAY DISTRIBUTION-UNATTEN 138.00 12.47
11 PARLEYS DISTRIBUTION-UNATTEN 46.00 12.47
12 PELICAN POINT DISTRIBUION-UNATTEN 46.00 12.47
13 PINE CANYON DISmIBUION-UNATTEN 138.00 12.47
14 PINE CREEK DISTRIBUTON-UNATTEN 46.00 12.47
15 PINNACLE DISTRIBUION-UNATTEN 46.0(12.47
16 PLAINCITV DISTRIBUTION-UNATTEN 138.00 12.47
17 PLEASANT GROVE DISTRIBUTON-UNATTEN 46.00 12.47
18 PLEASANT VIEW DISTRIBUTION-UNATTEN 46.OC 12.47
19 PORTER ROCKWELL DISTRIBUTION-UNATTEN 138.0(12.47
20 PROMONTORY DISTRIBUTION-UNATTEN 46.00 12.47
21 QUAIL CREEK DISTRIBUTION.UNATTEN 34.50 12.47
22 QUARRY DISTRIBUTION-UNATTEN 138.00 12.47
23 QUITCHAPA DISTRIBUTION-UNATTEN 34.50 12.47
24 RAINS DISTRIBUON-UNATTEN 46.OC 7.20
25 RANDOLPH DISmIBUION-UNATTEN 46.00 12.47
26 RASMUSON DISmIBUTION.UNATTEN 46.00 12.47
27 RATTLESNAKE DISTRIBUTION-UNATTN 69.00 24.90
28 RED MOUNTAIN DISTRIBUION-UNATTEN 69.00 34.50
29 REDROCK DISTRIBUTION-UNATTEN 69.00 4.16
30 REDWOOD DISTRIBUTION-UNATTEN 46.00 12.47
31 RESEARCH PARK DISTRIBUTION-UNATTEN 46.00 12.47
32 RICH DISTRIBUTION-UNATTEN 69.00 12.47
33 RICHFIELD DISTRIBUTION-UNATTEN 46.0(12.47
34 RICHMOND DISTRIBUTION-UNATTEN 46.00 12.47
35 RIDGELAND DISTRIBUTION-UNATTEN 138.00 12.47
36 RITER DISTRIBUTION.UNATTEN 46.0(12.47
37 ROCK CANYON DISmIBUTION-UNATTEN 69.00 12.47
38 ROCKVILLE DISTRIBUTION-UNATTEN 34.&12.47
39 ROCKY POINT DISTRIBUTION-UNATTEN 138.00 13.20
40 ROSE PARK DISTRIBUTION-UNATTEN 46.0C 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.15
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) nA Resubmission 04/03/208
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 Service) (In MVa)Transformers Spare Type of Equipment Total Capity No.In Servce Trasforers Number of Units
(f)(g)(h)(i ul (In (~va)
k)
3 1 1
20 1 2
14 1 3
48 2 4
55 2 5
4 1 6
5 1 7
4 3 8
35 2 9
50 2 10
16 2 11
6 1 12
20 1 13
2 1 14
14 1 15
22 1 16
25 1 17
14 1 18
30 1 19
2 1 20
4 1 21
60 2 22
4 1 23
15 1 24
2 1 25
1 3 26
14 1 27
13 1 28
3 1 29
45 2 30
45 2 31
5 1 32
22 2 33
11 1 34
40 2 35
20 1 36
5 1 37
4 1 38
30 1 39
24 3 40
FERC FORM NO.1 (ED. 12-96)Page 427.15
Name of Respondent This ~rtIS:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) nA Resubmission 04/03100
SUBSTATIONS
1. Report below the informtion 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 accrding to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Loction of Substation Charaer of Substation
Primary Seconary Tertiary
(a)(b)(c)(d)(e)1 ROYAL DISTRIBUTION-UNATTEN 46.00 4.16
2 SALINA DISTRIBUTION-UNATTEN 46.00 12.47
3 SANDY DISTRIBUTION-UNATTEN 138.OC 12.47
4 SARATOGA DISTRIBUTION-UNATTEN 138.OC 12.47
5 SCIPIO DISTRIBUTION-UNATTN 46.OC 12.47
6 SCOFIELD RESERVOIR DISTRIBUTION-UNATTEN 46.00 7.20
7 SCOFIELD DISTRIBUION-UNATTEN 46.00 12.47
8 SECOND STREET DISTRIBUON-UNATTEN 46.00 12.47
9 SEVEN MILE DISTRIBUTION-UNATTEN 46.00 12.47
10 SHARON DISTRIBUTION-UNATTEN 46.00 12.47
11 SHIVWITS DISTRIBUTION-UNATTEN 34.50 4.16
12 SIXTH SOUT DISTRIBUTION-UNATTEN 46.OC 12.47
13 SKULL POINT DISTRIBUTION-UNATTEN 46.00 12.47
14 SNARR DISTRIBUTION-UNATTEN 46.OC 12.47
15 SNOWVILLE DISTRIBUION-UNATTEN 69.00 12.47
16 SNYDERVILLE DISTRIBUTION-UNATTEN 138.00 12.47
17 SOLDIER SUMMIT DISTRIBUTION-UNATTEN 69.00 12.47
18 SOUTH JORDAN DISTIBUION-UNATTEN 138.00 12.47
19 SOUTH MILFORD DISTRIBUTION-UNATTEN 46.OC 12.47
20 SOUTH MOUNTAIN DISTRIBUTION-UNATTEN 138.00 12.47
21 SOUTH OGDEN DISTRIBUTION-UNATTEN 46.00 12.47
22 SOUTH PARK DISTRIBUTION-UNATTEN 46.OC 12.47
23 SOUTH WEBER DISTRIBUTION-UNATTEN 138.00 12.47
24 SOUTHEAST DISTRIBUTION-UNATTEN 138.00 12.47 46.00
25 SOUTHWEST DISTRIBUTION-UNATTEN 46.00 12.47
26 SPANISH VALLEY DISTRIBUTION-UNATTEN 69.00 12.47
27 SPRINGDALE DISTRIBUTION-UNATTEN 34.5C 12.47
28 ST. JOHNS DISTRIBUTION-UNATTEN 46.00 12.47
29 STAIRS DISTRIBUTION-UNATTEN 12.41 2.40
30 STANSBURY DISTRIBUTION-UNATTEN 46.OC 12.47
31 SUMMIT CREEK DISTRIBUTION-UNATTEN 138.OC 12.47
32 SUMMIT PARK DISTRIBUION-UNATTEN 46.OC 12.47
33 SUNRISE DISTRIBUTION-UNATTEN 138.OC 12.47
34 SUPERIOR DISTRIBUTION-UNATTEN 69.00 12.47
35 SUTHERLAND DISTRIBUTION-UNATTEN 46.00 12.47
36 TAYLOR DISTRIBUTION-UNATTEN 46.00 12.47
37 THIEF CREEK DISTRIBUTION-UNATTEN 138.00 24.90
38 THIRD WEST DISTRIBUTION-UNATTEN 46.00 12.47
39 THIRTEENTH SOUTH DISTRIBUTION-UNATTEN 46.OC 12.47
40 THOMPSON DISTRIBUTION-UNATTEN 46.OC 4.16
FERC FORM NO.1 (ED. 12-96)Page 426.16
............................................
............................................
Name of Respondent This F~iort Is:Date of Report Year/Period of Report
PacifiCorp (1)~AnOnginal (Mo, Da, Yr)End of 2007/Q4
(2)A Resubmission 04/03/2008
SUBSTATIONS (Continued)
5. Show in columns (i), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substion Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)Transformers Spare Type of Equipment Total capacit No.In Service Transformers Number of Units
(f (a)(h)(n (j (In t:a)
3 1
11 1 2
60 2 3
30 1 4
1 3 5
1 6
1 3 7
13 2 8
5 3 9
20 1 10
6 1 11
20 1 12
2 1 13
40 2 14
5 1 15
30 1 16
13 1 17
30 1 18
20 2 19
60 2 20
25 1 21
14 1 22
50 1 23
50 2 24
22 2 25
6 1 26
4 1 27
4 1 28
2 1 29
20 1 30
14 1 31
7 1 32
30 1 33
8 1 34
6 1 35
14 1 36
14 1 37
40 2 38
24 3 39
2 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.16
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) ñA Resubmission 04
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
attnded 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 Lotin of Substation Charaer of Substati
Primary Secdary Tertiary
(a)(b)(c)(d)(e)
1 TOOELË DEPOT DISTRIBUTION.UNATTEN 46.OC 12.50
2 TOQUERVILLE DISTRIBUTION-UNATTEN 69.00 12.47 34.50
3 TRI CIT DISTRIBUTION-UNATTEN 138.OC 12.47
4 TWENTHIRD STREET DISTRIBUTION-UNATTEN 46.OC 12.47
5 UINTAH DISTRIBUTION-UNATTEN 46.0C 12.47
6 UNION DISTRIBUTION.UNATTEN 46.00 12.47
7 UNIVERSITY DISTRIBUTION-UNATTEN 46.00 4.16
8 VALLEY CENTER DISmIBUION-UNATTEN 46.DC 12.47
9 VERMILLION DISTRIBUON-UNATTN 46.00 12.47
10 VERNAL DISTRIBUTION-UNATTN 69.OC 12.47
11 VEYOHYDRO DISmIBUTN-UNATTEN 34.5C 2.40
12 VICKERS DISTRIBUON-UNATTEN 46.00 12.47
13 VINEYARD DISTRIBUTION-UNATTEN 46.00 12.47
14 WALFARE DISTRIBUTION-UNATTEN 46.0C 12.47
15 WALLSBURG DISTRIBUTION-UNATTEN 138.00 12.47
16 WALNUT GROVE DISTRIBUTION-UNATTEN 138.OC 12.50
17 WARREN DISTRIBUTION-UNATTEN 138.DC 12.47
18 WASATCH STATE PARK DISTRIBUTION-UNATTN 46.DC 12.47
19 WASHAKIE DISmIBUTION.UNATTN 138.Oc 4.16
20 WELBY DISTRIBUTION-UNATTEN 46.OC 12.47
21 WELLINGTON DISTRIBUTION-UNATTEN 46.00 12.47
22 WEST COMMERCIAL DISmIBUTION.UNATTEN 46.OC 12.47
23 WEST JORDAN DISTRIBUTION-UNATTEN 138.0C 12.47
24 WEST OGDEN DISTRIBUTION-UNATTEN 138.00 12.47
25 WEST ROY DISTRIBUTION-UNATTEN 46.OC 12.47
26 WEST TEMPLE DISTRIBUTION-UNATTEN 46.00 4.16
27 WESTFIELD DISTRIBUTION.UNATTEN 138.00 12.47
28 WESTWATER DISTRIBUTION-UNATTEN 69.DC 12.47
29 WHITE MESA DISTRIBUTION-UNATTEN 69.OC 12.47
30 WILLOWCREEK DISTRIBUTION-UNATTN 46.OC 12.47
31 WILLOWRIDGE DISTRIBUTION-UNATTN 46.00 12.47
32 WINCHESTER HILLS DISmIBUTION-UNATTEN 34.50 12.47
33 WINKLEMAN DISTRIBUTON-UNATTN 46.00 7.20
34 WOLFCREEK DISmIBUTION-UNATTEN 69.DC 12.47
35 WOOD CROSS DISTRIBUTION-UNATTEN 46.00 12.47
36 WOODRUFF DISTRIBUTION-UNATTEN 46.DC 12.47
37 Total 19907.47 3641.89 184.97
38 NUMBER OF SUBSTATIONS DIST UNATTENDED. 298
39
40 ANGEL TID-UNATTENDED 138.00 12.47 46.00
FERC FORM NO.1 (ED. 12-9)Page 426.17
............................................
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) nA Resubmission 04/0312008
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 sale 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 accunts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substatio Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service)(In MVa)Transformers Spare Typ of Equipment Total Capacity No.In Service Transformers Number of Unit (ln(~a)
(f)(g)(h)(j (j k)
14 1 1
34 2 2
30 1 3
13 1 4
39 2 5
50 2 6
48 4 7
22 1 8
3 1 9
33 2 10
2 3 11
2 1 12
25 1 13
5 1 14
13 1 15
30 1 16
30 1 17
2 3 18
14 1 19
22 1 20
4 1 21
22 1 22
28 1 23
30 1 24
25 1 25
60 3 26
20 1 27
1 3 28
14 1 29
6 1 30
14 1 31
4 1 32
1 33
6 1 34
20 1 35
2 1 36
5164 432 4 37
38
39
135 3 40
FERC FORM NO.1 (ED. 12-96)Page 42.17
Name of Respondent Ihis~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/04
(2) riA Resubmission 0403208
SUBSTATIONS
1. Report below the informtion 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 Location of Substation Character of Substatin
Primary Secndry Tertry
(a)(b)(c)(d)(e)
1 BDO TIDUNATTENDED 138.00 12.47
2 BUTLERVILLE TIDUNATTENDED 138.00 46.00 12.47
3 COTTONWOOD TIDUNATTNDED 138.00 12.47 46.00
4 EMMA PARK TID-UNATTENDED 138.00 12.47
5 HALE TID.UNATTENDED 138.00 46.00 12.47
6 HIGHLAND TIDUNATTENDED 138.00 12.47 46.00
7 JORDAN TID-UNATTENDED 138.00 46.00 12.47
8 JUDGE TID.UNATTENDED 46.00 12.47
9 MCCLELLAND TIDUNATTENDED 138.00 46.00 12.47
10 OQUIRRH TIDUNATTNDED 138.00 46.00 12.47
11 PARRISH TIDUNATTNDED 138.00 12.47 46.00
12 PIONEER PLANT TIDUNATTENDED 138.00 2.30 46.00
13 RIVERDALE TID-UNATTENDED 138.00 46.00 12.47
14 SEVIER TIDUNATTNDED 138.00 46.00 12.47
15 SILVER CREEK TIDUNATTENDED 138.00 12.47 46.00
16 SPHINX TID-UNATTENDED 46.00 12.47
17 SYRACUSE TID-UNATTENDED 138.00 46.00 12.47
18 TAYLORSVILLE TIDUNATTENDED 138.00 46.00 12.47
19 TERMINAL TID-UNATTENDED 345.00 12.47 46.00
20 T1MP TID-UNATTENDED 138.00 46.00 12.47
21 TOOELE TIDUNATTENDED 138.00 46.00 12.47
22 WEST VALLEY TIDUNATTNDED 138.00 12.47
23 Total 3197.00 645.47 459.17
24 NUMBER OF SUBSTATIONS TID UNATTENDED. 23
25
26 BLUNDELL PLANT TRSMISSION-ATTEND 46.00 12.47
27 CARBON PLANT TRANSMISSION-ATTND 138.00 13.80
28 EMERY TRANSMISSION-ATTEND 138.00 6.90 69.00
29 GADSBY PLANT TRANSMISSION-ATTEND 138.00 13.80 46..00
30 GADSBY TRANSMISSION.ATTEND 138.0(46.00
31 HUNTER PLAT TRANSMISSION-ATTEND 34.00 23.00
32 HUNTINGTON PLANT TRANSMISSION-ATTEND 345.0(23.00
33 Total 1288.0(138.97 115.00
34 NUMBER OF SUBSTATIONS TRAS ATTENDED - 7
35
36 90TH SOUTH TRANSMISSION-UNATTEN 345.0(138.00
37 ABAJO TRANSMISSION.UNATTEN 138.0(69.00
38 ASHLEY TRANSMISSIQN-UNATTEN 138.0(46.00
39 BARNEY TRANSMISSION.UNATTEN 138.00 46.00
40 BEN LOMOND TRANSMISSION-UNATTEN 345.OC 230.00 138.00
FERC FORM NO.1 (ED. 12-96)Page 426.18
............................................
-...........................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FÎA Resubmission 04/03/2008
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-wner, 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 Tota Capaciy No.In Service Transformers Type of Equipment Number of Unit
(g)(h)(j (In ~~a)
(f)(i)(k
30 1 1
175 3 2
289 7 3
8 1 4
114 2 5
97 2 6
164 2 7
22 1 8
340 4 9
135 3 10
97 2 11
51 7 12
180 3 13
26 4 14
100 2 15
3 4 3 16
60 5 17
358 4 18
1108 6 2 19
130 2 20
158 3 21
30 1 .22
4350 72 5 23
24
25
25 1 26
225 5 27
783 13 1 28
568 17 29
318 2 30
1513 5 1 31
981 4 32
4413 47 2 33
34
35
1538 6 1 36
67 1 37
133 2 38
100 1 39
1813 5 40
FERC FORM NO.1 (ED. 12-96)Page 427.18
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Origina (Mo, Da, Yr)End of 2007/04
(2) CíA Resubmission 04008
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 Substation Character of Substation
Primary Secndary Tertiary
(a)(b)(c).'(d)(e)1 BLACKHAWK TRASMISSION-UNATTN 138.00 69.00 46.00
2 BOOKCLIFFS TRSMISSION-UNATTEN 69.00 46.00
3 CAMERON TRASMISSION-UNATTN 138.00 46.00
4 CAMP WILLIAMS TRSMISSION-UNATTEN 34.00 138.00 12.47
5 CARBON TRNSMISSION-UNATTEN 46.00 2.40
6 COLUMBIA TRASMISSION-UNATTN 138.00 46.00
7 CRICKET MOUNTAIN REG STA TRANSMISSION-UNATTEN 46.00 46.00
8 CUTLER TRANSMISSION-UNATTEN 138.00 46.00
9 ELMONTE TRANSMISSION-UNATTEN 138.00 46.00
10 GARKANE TRASMISSION-UNATTEN 69.00 46.00
11 GREEN CANYON TRANSMISSION-UNATTEN 138.00 46.00
12 GRINDING TRASMISSION-UNATTEN 138.0(13.80
13 HELPER TRSMISSION-UNATTEN 138.0(46.00
14 HONEYILL TRASMISSIONUNATTEN 138.0(46.00
15 HORSESHOE TRSMISSION-UNATTEN 138.00 46.00 12.47
16 HUNTINGTON TRASMISSION-UNATTEN 34.00 138.00 69.00
17 JERUSALEM TRASMISSION-UNATTEN 138.00 46.00
18 LAMPO TRANSMISSION-UNATTEN 138.00 46.00
19 MCFADDEN TRANSMISSION-UNATTEN 138.00 46.00
20 MIDDLETON TRANSMISSION-UNATTEN 138.00 69.00 34.50
21 MIDVALLEY TRANSMISSION-UNATTEN 34.0(138.00
22 MIDWAY CITY TRANSMISSION-UNATTEN 138.00 46.00
23 MINERAL PRODUCTS TRASMISSION-UNATTEN 69.0(46.00
24 MOAB TRANSMISSION-UNATTN 138.00 69.00
25 NEBO TRSMISSION-UNATTEN 138.00 46.00
26 OLMSTED TRANSMISSION-UNATTEN 46.00 2.40
27 PAROWAN VALLEY TRASMISSION-UNATTEN 230.00 138.00 34.50
28 PAVANT TRASMISSION-UNATTN 230.00 46.00
29 PINTO TRANSMISSION-UNATTEN 34.0(138.00 69.00
30 RED BUTT TRANSMISSION-UNATTEN 23O.OC 138.00
31 SAND COVE HYDRO TRANSMISSION-UNATTEN 34.5C 2.40
32 SIGURD TRANSMISSION-UNATTEN 34.OC 230.00 138.00
33 SMITHFIELD TRANSMISSION-UNATTEN 138.00 46.00 12.47
34 SPANISH FORK TRANSMISSION-UNATTEN 345.00 138.00 46.00
35 STGEORGE TRASMISSION-UNATTEN 138.OC 16.50
36 UPPER BEAVER HYDRO TRANSMISSION-UNATTEN 46.OC 2.30
37 WEBER PLANT TRANSMISSION-UNATTEN 46.OC 2.30
38 WEST CEDAR .TRASMISSION-UNATTEN 23O.OC 138.00 34.50
39 Total 7187.50 2986.10 64.91
40 NUMBER OF SUBSTATIONS TRANS UNATTENDED. 43
FERC FORM NO.1 (ED. 12-96)Page 426.19
............................................
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04/0312008
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. Speify 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 Une
(In Service)(In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Servce Transformers Number of Units
(f)(0)Ch)(j Ci)
(In (~~a)
100 2 1
6 3 1 2
25 3 3
169 2 4
8 1 5
33 1 6
15 1 7
70 2 8
313 3 9
33 1 10
67 2 11
225 3 12
142 2 13
35 1 14
80 2 15
270 4 16
67 1 17
75 1 18
45 1 19
141 4 20
90 2 21
67 1 22
13 1 23
67 1 24
68 2 25
15 1 26
138 2 27
133 2 28
258 3 29
400 1 30
1 31
1124 6 32
63 2 33
1017 5 34
100 3 1 35
5 1 36
7 1 37
131 2 38
10076 92 3 39
40
FERC FORM NO. 1 (ED. 12-96)Page 427.19
Name of Respondent This~rtIS:Date of Report Year/Penod of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 0403008
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 accrding 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 Secndry Tertary
(a)(b)(c)(d)(e)
1
2 Washington
3 ATTALlA DISTRIBUTION-UNATTEN 69.00 12.47
4 BOWMAN DISTRIBUTION-UNATTEN 69.00 12.47
5 CASCADE KRAFT DISTIBUON-UNATTEN 69.OC 12.47 4.16
6 CLINTON DISTRIBUON-UNATTN 115.OC 12.47
7 DAYTON DISTRIBUTION-UNATTEN 69.00 12.47
8 DODD ROAD DISTIBUTON-UNATTEN 69.OC 20.80
9 GRANDVIEW DISTRIBUTION-UNATTEN 115.OC 12.47 69.00
10 HOPLAND DISTIBUTION-UNATTEN 115.OC 12.47
11 MILLCREEK DISTRIBUTION-UNATTEN 69.OC 12.47
12 NACHES HYDRO DISTRIBUTION-UNATTEN 115.00 12.47
13 NOB HILL DISTRIBUTION-UNATTEN 115.00 12.47
14 NORTH PARK DISTRIBUTION-UNATTEN 115.00 12.47
15 ORCHARD DISTRIBUTION-UNATTEN 115.00 12.47
16 PACIFIC DISTRIBUION-UNATTEN 115.00 12.47
17 POMEROY DISTRIBUTON-UNATTEN 69.00 12.47
18 PROSPECT POINT DISTIBUTION-UNATTN 69.OC 12.47
19 PUNKIN CENTER DISTRIBUTION-UNATTEN 115.00 12.47
20 RIVER ROAD DISTRIBUION-UNATTEN 115.OC 12.47
21 SELAH DISTRIBUTION-UNATTEN 115.OC 12.47
22 SULPHUR CREEK DISTRIBUTION-UNATTEN 115.00 12.47
23 SUNNYSIDE DISTRIBUTION-UNATTEN 115.OC 12.47
24 TIETON DISTRIBUTION-UNATTEN 115.00 12.47 34.50
25 TOPPENISH DISTRIBUTION-UNATTEN 115.00 12.47
26 TOUCHET DISTRIBUTION-UNATTEN 69.00 12.47
27 VOELKER DISTRIBUTION-UNATTEN 115.00 12.47
28 WAITSBURG DISTRIBUTION-UNATTEN 69.00 12.47
29 WAPATO DISTRIBUTION-UNATTN 115.OC 12.47
30 WENAS DISTRIBUION-UNATTEN 115.00 12.47
31 WHITE SWAN DISTRIBUTON-UNATTEN 115.OC 12.47
32 WILEY DISTRIBUTION-UNATTEN 115.OC 12.47
33 Total 2990.OC 382.43 107.66
34 NUMBER OF SUBSTATIONS DIST UNATTENDED - 30
35
36 CENTRAL TID-UNATTENDED 69.00 12.47
37 UNION GAP TIDUNATTENDED 230.OC 115.00 12.47
38 Total 299.00 127.47 12.47
39 NUMBER OF SUBSTATIONS TID UNATTENDED - 2
40
FERC FORM NO.1 (ED. 12..96)Page 426.20
............................................
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 04/0312008
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 part is an associated company.
.
Capacity of Substatio Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In servce) (In MVa)Transformers Spare Typ of Equipment Total Capaci No.In Service Transformers Number of Units
(In ~~a)(f)(g)(h)(i)(j (k
1
2
25 1 3
45 2 4
117 6 5
25 1 6
23 2 7
25 4 8
56 2 9
34 2 10
45 2 11
20 1 12
42 2 13
45 2 14
50 2 15
28 3 16
9 1 17
40 2 18
20 2 19
51 4 20
45 2 21
25 1 22
45 2 23
29 2 24
50 2 25
6 1 26
25 1 27
9 1 28
45 2 29
25 2 30
22 2 31
45 2 32
1071 61 33
34
35
14 1 36
348 5 37
362 6 38
39
40
FERC FORM NO.1 (ED. 12-96)Page 427.20
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2O7/Q4
(2) DA Resubmission 040312008
SUBSTATIONS
1. Report below the informtion 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 Substaion Character of Substation
Primary Secondry Teriary
(a)(b)(c)(d)(e)
1 CONDIT PLANT TRASMISSION-ATIEND 69.OC 2.30
2 MERWIN PLAT TRANSMISSION-ATIEND 115.00 13.20
3 YALEPLA TRANSMISSION-ATIEND 230.OC 13.80
4 Tota 414.OC 29.30
5 NUMBER OF SUBSTATIONS TRANS ATIENDED - 3
6
7 OUTLOOK TRANSMISSION-UNATIEN 230.OC 115.00
8 PASCO TRANSMISSION-UNATIEN 115.00 69.00 7.20
9 POMONA HEIGHTS TRSMISSION-UNATIN 230.OC 115.00
10 SWIFT 1 PLANT TRASMISSION-UNATIEN 23.00 13.00
11 WALLA WAL 230KV TRSMISSION-UNATIN 230.OC 69.00
12 WALLULA TRANSMISSION-UNATIEN 230.OC 69.00
13 Total 1265.00 450.00 7.20
14 NUMBER OF SUBSTATIONS TRANS UNATIENDED - 6
15
16 Wyoming
17 AIR BASE DISTRIBUTION-UNATIEN 12.47 2.40
18 ANTELOPE MINE DISTRIBUTION-UNATIEN 230.OC 34.50
19 ASTLE STREET DISTRIBUTION-UNATIEN 34.50 13.20
20 BAILEY DOME DISTRIBUTON-UNATIEN 57.00 12.47
21 BAR X DISTRIBUTION-UNATIEN 23.OC 34.50
22 BID MUDDY DISTRIBUTION-UNATIN 69.00 12.47
23 BIG PINEY DISTRIBUTION-UNATIEN 69.OC 24.90
24 BLACKS FORK DISTRIBUTION.UNATIEN 230.00 34.50
25 BRIDGER PUMP DISTRIBUTON-UNATIN 23.00 34.50 13.20
26 BRYAN DISTRIBUTION-UNATIEN 115.OC 12.47
27 BUFFALO TOWN DISTRIBUTION.UNATIEN 20.80 4.16
28 BYRON DISTRIBUTION-UNATIEN 34.50 4.16
29 CASSA DISTRIBUTION-UNATIEN 57.OC 20.80
30 CENTER STREET DISTRIBUTION-UNATIEN 115.00 4.16
31 CHAPMAN STATION DISTRIBUTION.UNATIEN 46.OC 12.47
32 CHATHAM DISTRIBUON.UNATIEN 34.50 4.16
33 CHUKAR DISTIBUTON-UNATIN 12.41 4.16
34 CHURCH AND DWIGHT DISTRIBUTION-UNATIEN 34.50 0.48
35 COKEVILLE D1STRIBUTION-UNATIEN 46.00 24.90
36 COLUMBIA-GENEVA DISTRIBUTION-UNATIEN 230.00 13.80
37 COMMUNITY PARK DISTRIBUTION-UNATIEN 69.00 12.47
38 CROOKS GAP DISTRIBUTION-UNATIEN 34.50 12.47
39 DEER CREEK DISTRIBUTION-UNATIEN 69.OC 12.47
40 DJCOALMINE DISTRIBUTION.UNATIEN 69.0(34.50
PERC FORM NO.1 (ED. 12-9)Page 426.21
............................................
-...........................................
Name of Respondent This~rtIS:Dale of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2oo7/Q4
(2) ÕA Resubmission 04/031200
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 accunting 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 Capcit No.In Service Transformers Number of Unit
(In MVa)(fl (a)(h)(I)(j)(k)
13 6 1 1
183 9 1 2
144 3 1 3
34 18 3 4
5
6
125 1 7
39 9 8
30 2 9
261 3 1 10
300 2 11
120 2 12
1145 19 1 13
14
15.
16
1 3 17
25 1 18
13 1 19
2 1 20
25 1 21
7 1 22
8 1 23
150 2 24
73 4 25
25 1 26
2 3 27
2 3 28
2 6 1 29
13 1 30
4 1 31
3 32
1 3 33
3 2 34
4 1 35
45 2 36
40 2 37
5 3 38
9 1 39
13 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.21
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 04/03120
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 accrding to funcion the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertry
(a)(b)(c)(d)(e)1 DOUGLAS DISTRIBUTION-UNATTEN 57.00 2.30
2 DRYFORK DISTRIBUnON-UNATTEN 69.00 4.16
3 ELK BASIN DISTRIBUTION-UNATTEN 34.5C 7.20
4 EMIGRANT DISTRIBUTION-UNATTEN 115.0(12.47
5 EVANS DISmIBUTION-UNATTN 69.0(12.47
6 EVANSTON DISTRIBUTION-UNATTEN 138.00 12.47
7 FARMERS UNION DISmIBUTION-UNATTEN 34.50 4.16
8 FIREHOLE DISTRIBUTION-UNATTEN 230.00 34.50
9 FORT CASPER DISTRIBUTION-UNATTEN 69.00 12.47
10 FORT SANDERS DISTRIBUTION-UNATTEN 115.00 13.20
11 FRANNIE DISTRIBUTION-UNATTEN 230.00 34.50
12 FRONTIER DISTRIBUTION-UNATTEN 69.00 4.16
13 GARLAND D1STRIBUTION-UNATTEN 230.00 34.50
14 GLENDO DISTRIBUTION-UNATTEN 57.00 4.16
15 GRASS CREEK DISTRIBUTION-UNATTEN 230.00 34.50
16 GREAT DIVIDE DISTRIBUTION-UNATTEN 115.00 34.50
17 GREYBULL DISTRIBUTIO-UNATTEN 34.50 4.16
18 HANNA DISTRIBUTION-UNATTEN 34.50 12.47
19 JACKAOPE DISTRIBUTION-UNATTEN 115.00 12.47
20 KEMMERER DISTRIBUTION-UNATTEN 69.00 24.90
21 KIRBY CREEK PUMPING STATION DISTRIBUTION-UNATTEN 34.50 2.40
22 KIRBY CREEK DISTRIBUTION-UNATTEN 34.50 4.16
23 LANDER DISTRIBUTION-UNATTEN 34.50 12.47
24 LARAMIE DISTRIBUTION-UNATTEN 115.00 13.20
25 LATHAM DISTRIBUTION-UNATTEN 23.00 34.50
26 LINCH DISTRIBUTION-UNATTEN 69.00 13.80
27 LITTLE MOUNTAIN DISTRIBUTION-UNATTEN 230.00 34.50
28 LOVELL DISmIBUION-UNATTEN 34.50 4.16
29 MANDERSON DISmIBUTION-UNATTEN 34.5C 4.16
30 MILLIRON DISTRIBUTION-UNATTEN 34.S(13.80
31 MILLS DISmIBUTION-UNATTEN 12.41 4.16
32 MURPHY DOME DISTRIBUTION-UNATTEN 34.50 13.20
33 NUGGET DISTRIBUTION-UNATTEN 69.0(7.20
34 OPAL DISTRIBUTION-UNATTEN 46.00 24.90
35 ORIN DISTRIBUTION-UNATTEN 57.00 12.47
36 ORPHA DISTRIBUTION-UNATTEN 57.0(7.20
37 PARCO DISTRIBUTION-UNATTEN 34.5C 12.47
38 PINEDALE DISTRIBUTION-UNATTEN 69.OC 24.90
39 PITCHFORK DISTRIBUTION-UNATTEN 69.OC 24.90
40 POINT OF ROCKS DISTRIBUTION-UNATTEN 230.00 34.50
FERC FORM NO, 1 (ED. 12-96)Page 426.22
............................................
............................................
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2)A Resubmission 04/03/2008
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 Une
(In Service)(In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(f)(0)(h)en 0)
(In (~~a)
6 3 1
9 1 2
5 1 3
13 1 4
9 1 5
40 2 6
2 3 7
50 2 8
25 1 9
20 1 10
50 2 11
6 1 12
45 2 13
3 4 14
25 1 15
20 1 16
3 1 17
6 1 18
25 1 19
10 1 20
3 3 21
2 3 22
25 2 23
50 2 24
25 1 25
13 1 26
20 1 27
4 3 28
1 3 29
13 1 1 30
1 3 31
5 1 32
1 33
8 1 34
2 3 35
3 3 36
5 1 37
8 1 38
17 9 2 39
25 1 40
FERC FORM NO.1 (EO. 12'")Page 427.2
Name of Respondent This~rtIS:Date of ReJ)rt Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) FiA Resubmission 04032008
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 substtions 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 Loation of Substation Chaer of Substati
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 POISON SPIDER DISTRIBUION-UNATTEN 69.00 2.40
2 POLECAT DISTRIBUTON-UNATTN 34.50 12.47
3 RANBOW DISTRIBUTION-UNATTEN 34.50 13.20
4 RAVEN DISTRIBUTION-UNATTEN 230.00 34.50
5 RED BUTTE DISTRIBUTION-UNATTEN 69.00 12.47
6 REFINERY DISTRIBUTION-UNATTEN 115.OC 12.47
7 SAGE HILL DISTRIBUTION-UNATTEN 34.50 13.20
8 SHOSHONI DISTRIBUTION~UNATTEN 34.&2.40
9 SLATE CREEK DISTRIBUION-UNATTEN 69.00 12.47
10 SOUTH CODY DISTRIBUTN-UNATTEN 69.OC 24.90
11 SOUTH ELK BASIN DISTRIBUTN-UNATTN 34.5C 4.16
12 SOUTH TRONA DISTRIBUION-UNATTN 23O.OC 34.50
13 SPRING CREEK DISTRIBUTION-UNATTEN 115.OC 13.20
14 SVILAR DISTRIBUTION-UNATTEN 34.50 4.16
15 TEN MILE DISTRIBUTION-UNATTEN 69.00 34.50
16 THERMOPOLIS TOWN DISTRIBUTION-UNATTEN 34.50 4.16
17 THUNDER CREEK DISTRIBUTION-UNATTEN 57.00 12.47
18 VETERANS DISTRIBUTION-UNATTEN 34.5C 13.20
19 WELCH DISTRIBUTION-UNATTEN 57.OC 2.40
20 WERTZ-SINCLAIR DISTRIBUION-UNATTEN 57.OC 4.16 12.50
21 WEST ADAMS DISTRIBUTION-UNATTEN 34.5C 4.16
22 WESTERN CLAY DISTRIBUTON-UNATTEN 34.5C 0.48
23 WESTVACO DISTRIBUTION-UNATTEN 230.00 34.50
24 WORLAND TOWN DISTRIBUTON-UNATTEN 34.5C 4.16
25 WYOPO DISTRIBUTION-UNATTEN 230.00 34.50
26 WYUTA DISTRIBUTION-UNATTEN 46.OC 12.47
27 Total 788.21 1357.50 25.70
28 NUMBER OF SUBSTATIONS DIST UNATTENDED- 90
29
30 LABARGE TID-UNATTENDED 69.00 24.90
31 BUFFALO TID-UNATTENDED 230.00 20.80
32 HILLTOP TIDUNATTENDED 115.00 34.50 20.80
33 RIVERTON 230 TIDUNATTNDED 230.00 12.47 34.50
34 YELLOWCAKE TIDUNATTENDED 23.00 34.50
35 Total 874.00 127.17 55.30
36 NUMBER OF SUBSTATIONS T/D UNATTENDED - 5
37
38 DAVE JOHNSTON PLAT TRANSMISSION-ATTEND 230.00 115.00 69.00
!RANSMISSION-ATTEND 34.00 230.00 34.5040 JIM BRIDGER UNITS 1-4 TRANSMISSION-ATTEND 34.00 22.00
FERC FORM NO.1 (ED. 12-96)Page 426.2
............................................
-...........................................
Name of Respondent This ll0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) riA Resubmission 040312008
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
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 shanng 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 Typ of Equipment Total Capacity No.In Service Transformers Number of Units
(ft (a)(h)(j)(j (In (~~a)
3 1 1
2 3 2
13 1 3
200 2 4
20 1 5
45 2 6
6 1 7
2 3 8
1 1 9
14 3 1 10
2 6 11
150 2 12
25 1 13
2 3 14
13 1 15
5 1 16
9 1 17
25 2 18
3 3 19
2 6 20
3 1 21
1 1 22
25 1 23
5 1 24
20 1 1 25
1 26
1670 173 6 27
28
29
8 6 30
20 1 31
45 2 1 32
50 3 33
25 1 34
148 13 1 35
36
37
1358 17 38
108 22 39
1122 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.23
Name of Respondent Ths ~rt Is:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 207/04
(2) nA Resubmission 04032008
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 Subsation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 NAUGHTON TRANSMISSION-ATTEND 230.00 69.00
2 WYODAK 230K TRANSMISSION-ATTEND 230.00 69.00
3 WYODAK PLAT TRASMISSION-ATTND 23.00 22.00
4 Total 1610.00 527.00 103.50
5 NUMBER OF SUBSTATIONS TRANS ATTENDED - 6
6
7 BAIROIL TRANSMISSION.UNATTEN 115.00 34.50 57.00
8 CASPER TRANSMISSION.UNATTN 230.00 115.00 69.00
9 CHAPPELL CREEK TRANSMISSION-UNATTEN 230.00 69.00
10 FOOTE CREEK WIND FARM TRANSMISSION-UNATTEN 230.00 34.50
11 GLENDO AUTO TRANSMISSION-UNATTN 69.OC 57.00
12 MANSFACE TRANSMISSION-UNATTEN 23O.OC 34.50
13 MIDWEST TRANSMISSION.UNATTN 230.00 69.00 34.50
14 MINERS TRANSMISSION.UNATTN 230.00 115.00 34.50
15 MUSTANG TRASMISSION-UNATTEN 23.00 115.00
16 OREGON BASIN TRANSMISSION.UNATTEN 230.00 34.50 69.00
17 PLATTE TRASMISSION-UNATTN 230.00 115.00 34.50
18 RAILROAD TRANSMISSION.UNATTEN 230.00 138.00
19 ROCK SPRINGS 230 TRANSMISSION-UNATTN 230.00 34.50
20 SAGE TRANSMISSION-UNATTEN 69.00 46.00
21 THERMOPOLIS TRANSMISSION-UNATTEN 230.00 115.00
22 YELLOWTAIL TRANSMISSION-UNATTEN 230.00 161.00
23 Total 3243.00 1287.50 298.50
24 NUMBER OF SUBSTATIONS TRANS UNATTENDED - 16
25
26
27 CALIFORNIA
28 Distribution - 45
29 TIO-3
30 Transmission - 9
31
32 IDAHO
33 Distribution - 67
34 TIO.4
35 Transmission -18
36
37 OREGON
38 Distribution - 181
39 T/D -10
40 Transmission - 41
FERC FORM NO.1 (ED. 12-96)Page 426.24
...................................'..........
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2007/Q4
(2) nA Resubmission 04/0312008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectiiers, 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 accunting between the parties, and state amounts and accounts
affected in respondent's books of accunt. Specify in each case whether lessor, co-wner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service)(In MVa)
Transformers Spare Typ of Equipment Total Capcit No.In Service Transformers Number of Units
(f)(g)(hl (i)(j (in~~a)
1232 15 1 1
60 1 2
50 3 1 3
5359 60 2 4
5
6
53 3 7
517 6 8
67 1 9
196 2 10
15 2 11
20 1 12
91 4 13
58 4 1 14
200 2 15
115 4 16
165 4 17
400 1 18
75 3 19
22 1 20
175 2 21
100 1 22
2269 41 1 23
24
25
26
27
332 28
129 29
44 30
31
32
796 33
314 34
2642 35
36
37
4409 38
1238 39
6413 40
FERC FORM NO.1 (ED. 12-9)Page 427.24
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2O7/Q4
(2) nA Resubmission 0431208
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 Character of Substatn
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1
2 UTAH
3 Distribution - 298
4 T/D-23
5 Transmission - 50
6
7 WASHINGTON
8 Distribution - 30
9 TID - 2
10 Trasmission - 9
11
12 WYOMING
13 Distributn - 90
14 TID-5
15 Trasmission - 22
16
17 ALL STATES
18 Distribution - 711
19 TID -47
20 Transmission -149
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)Pag 426.25
............................................
-...........................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo7/Q4
(2) nA Resubmission 04/03/2008
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 party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformrs Spare Typ of Equipment Total Cacit No.In Service Trasformers Number of Units
(f)(g)(hl en
(In MVa)
(i)(k)
1
2
5164 3
430 4
14489 5
6
7
1071 .8
362 9
1485 10
11
12
1670 13
148 14
7628 15
16
17
1342 18
6541 19
33103 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. 12-96)Page 427.2
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 04/0312008 2007/04
FOOTNOTE DATA
¡Schedule Page: 426.9 Line No.: 32 Column: a
The Dixonvile 500kV Substation is jointly owned by th respondent and the Bonnevile Power Administration ("the BPA").
Ownership of the substation is as follows: PacifiCorp 50.0%, the BPA 50.0%. Opration and mantenance costs are shared between
the two ares and res onsibil is as follows: PacifiCo 58.0%, and the BPA 42.0%.
chedule Pa : 426.10 Line No.: 4 Column: a
The Meridian 500kV Substation is jointly owned by the respondent and th Bonneville Power Administration ("th BPA"). Ownership
of the substation is as follows: PacifiCorp 50.0%, th BPA 50.0%. Opration and mantenane costs are shad between the two
ares and res onsibil is as follows: PacifiCo 58.0%, and the BPA 42.0%.
chedule Pa e: 426.23 tine No.: 39 Column: a
The Jim Bridger 345kV Substation is jointly owned by th respondent and Idao Power Company. Ownership of the substation is as
follows: PacifCorp 66.7%, Idaho Power Company 33.3%. Opration and maintenance costs are shared between the two pares and
responsibilty is as follows: PacifiCorp 66.7%, and Idaho Power Company 33.3%.
-...........................................
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
Corpration
controlled by .................................................................................... 103
incorporated ..................................................................................... 101
CPA, background informtion on ....................................................................... 101
CPA Certification, this report form ................................................................. i-ii
FERC FORM NO.1 (ED. 12-9)Index 1
INDEX (continued)
Schedule Page No.
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 coimon utility plant .......................................................................... 356
of electric plant ................................................................................ 219
336-337
Directors ............................................................................................ ios
Discount- premium on long-term debt ............................................................. 256-257
Oistribution 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, suimry ...................................................... 323
unamortized debt ................................................................................. 256
Extraordinary property losses ........................................................................ 230
Filing requirements, this report form
General informtion .................................................................................. 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 information ............................................................................ 101
FERC FORM NO.1 (ED.12-95)Index 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' 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 departments ................................................................. 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)Indx 3
INDEX (continued)
Schedule
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
Page No.
Plant - utility and accumulated provisions for depreciation
amortization and depletion (summry) ............................................................. 201
Pollution control facilities, accumlated 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
Pumpd storage generating plant statistics ....................................................... 408-409
Purchased power (including power exchanges) ...................................................... 326-327
Reacquired capital stock ............................................................................. 250
Reacquired long-term debt ........................................................................ 256-257
Receivers' certificates .......................................................................... 256-257
Reconciliation of reported net income with taxle incom
from Federal income taxes ...................................................................... 261
Regulatory coimission expenses deferred.............................................................. 233
Regulatory coimission 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 ................................................................................... 105
distribution of .............................................................................. 354-355
officers' ........................................................................................ 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. 12-90)Inx 4
............................................
............................................
INDEX (continued)
Schedule Page No.
Taxes
accrued and prepaid
charged during year
on income, deferred
.......... .......................................................................................................................................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. 12-9)Index 5