2009Annual Report.pdf

~~~l~OUNTAIN R""CEI\lcnii ,,'1:,''-..'' -,.:¡ 'i rc.,,,.,'bo-F
June 3, 2010
201 South Main, Suite 2300
tOm JIM _ 3 AM 9:1+1 Salt Lake City, Utah 84111
VI OVERNIGHT DELIVERY 10 1' kl(~~"..,'r\J ~..J
UTiUTIE~
Idaho Public Utilties Commssion
472 West Washigton
Boise, ID 83702-5983
Attention:Jean D. Jewell
Commission Secreta
RE: FERC Form 1
PacifiCorp (d.b.a. Rocky Mounta Power) submits for filing one copy of PacifiCorp's anual
FERC Form 1 report for the year ended December 31, 2009.
PacifiCorp respectfuly requests tht all data requests regarding ths matter be addressed to:
By email (preferred):dataequest(fpacificorp.com
By reguar mail:Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
Please direct any inormal questions to Ted Weston, Reguatory Manger, at [phone].
Enclosure
. THIS FILING IS "
Item 1: 00 An Initial (Original)
Submission
OR 0 Resubmission No.
PAc -Ë-
FERC FINANCIAL REPORT
FERC FORM No.1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
..
These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
. other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Form 1 Approved
OMS No. 1902-0021
(Expires 2/29/2009)
Form 1-F Approved
OMS No. 1902-0029
(Expires 2/28/2009)
Form 3-Q Approved
OMS No. 1902-0205
(Expires 2/28/2009)
:::xl,.-..i
~....
~
IW
Exact Legal Name of Respondent (Company)
PacifiCorp End of
Year/Period of Report
.
2009/Q4
FERC FORM No.1/3-Q (REV. 02-04)
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 utilities, 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 utilities, licensees and others subject to the jurisdiction of the Federal Energy
Regulatory Commission. These reports are also considered to be non-confidential public use forms.
II. Who Must Submit
Each Major electric utilit, liænsee, or other, as classified in the Commission's Uniform System of Accounts
Prescribed for Public Utilities and Liænsees Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101),
must submitFERC Form 1 (18 C.F.R. § 14t.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 millon megawatt hours of total annual sales,
(2) 100 megawatt hours of annual sales for resale,
(3) 500 megawatt hours of annual power exchanges delivered, or
(4) 500 megawatt hours of annual wheeling for others (deliveries plus losses).
II. What and Where to Submit
(a) Submit FERC Forms 1 and 3-Qelectronically through the forms submission softare. Retain one copy of each report
for your fies. Any electronic submission must be created by using the forms submission softare provided free by the
Commission at its web site: http://ww.ferc.gov/docs-filng/eforms/form-1/elec-subm-soft.asp. The softare is
used to submit the electronic filing to the Commission via the Internet.
(b) The Cororate Offcer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
(c) Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the
latest Annual Report to Stockholder. Unless eFilng the Annual Report to Stockholders, mail the stockholders report to
the Secretary of the Commission at:
Secretary
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
(d) For the CPA Certifcation Statement, submit within 30 days after filing the FERC Form 1, a letter or report
(not applicable to fiers classified as Class C or Class D prior to January 1, 1984). The CPA Certfication Statement can
be either eFiled. or mailed to the Secretary of the Commission at the address above.
FERC FORM 1 & 3-Q (ED. 03-07)
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
Statement of Income
Statement of Retained Earnings
Statement of Cash Flows
Nótes 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 arereported. .
"In connection with ourregular examination of the financial statements of _ for the year ended on which we have
reported separately under date of , we have also reviewed schedules
of FERC Form NO.1 for the year filed with the Federal Energy Regulatory Commission, for
conformity in all material respects with the requirements of the Federal Energy RegulatoryComl1ission as set forth in its
applicable Uniform System of Accounts and published accounting releases. Our review forthis purpose included such
tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph
(except as noted below) conform in all material respects with the accounting requirements of the Federal Energy
Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases."
The letter or report must state which, if any, of the pages above do not conform to the Commission's requirements.
Describe the discrepancies that exist.
(f) Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling.
To further that effort, new selections, "Annual Report to Stockholders," and "CPA Certification Statement" have been
added to the dropdown "pick list" from which companies must choose when 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-filing/eforms.asp#3Q-gas .
IV. When to Submit:
FERC Forms 1 and 3-Q must be filed by the following schedule:
FERC FORM 1 & 3-Q (ED. 03-07)ii
a) FERC Form 1 for each year ending Deæmber 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-needèd, and completing and reviewing the collection of information. The public reporting burden for
the FERC Form 3-Q collection of information is estimated to average 150 hours per response.
Send comments regarding these burden estimates or any aspect of these collectons of information,
including suggestions for reducing burden, to the Federal Energy Regulator Commission, 888 First Street NE,
Washington, DC 20426 (Attention: Information Clearanæ Offcer); and to the Ofce of Information and Regulatory Affairs,
Offce of Management and Budget, Washington, DC 20503 (Attention: Desk Offcer for the Federal Energy Regulatory
Commission). No person shall be subject to any penalty if any collection of information does not display a valid control
number (44 U.S.C. § 3512 (a)).
FERC FORM 1 & 3-Q (ED. 03-07)iii
GENERAL INSTRUCTIONS
i. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret
all accounting words and phrases in accordance with the USofA.
II. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and
figures per unit where cents are importnt. The truncating of cents is allowed except on the four basic financial statements
where roundin9is 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.
ILL Complete each question fully and accurately, even if it has been answered in à previous report. Enter the
word "None" where it truly and completely states the fact.
iV. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not
Applicable" in column (d) on the List of Schedules, pages 2 and 3.
V. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the
header of each page is to be completed only for resubmissions (see VII. below).
VI. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must
be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the
numbers in parentheses.
VII For any resubmissions, submit the electronic fiing 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 periods/years or to other reports in lieu of required entries,
except as specifically authorized.
iX. Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based
upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different
figures were used.
Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:
FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission
Service as described in Order No. 888 and the Open Access Transmission Tariff. "Self' means the respondent.
FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as
described in Order No. 888 and the Open Access Transmission Tariff.
LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and" firm"
means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse
conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access
Transmission Tariff. For all transactions identified as LFP, provide in a footnote the
FERC FORM 1& 3-Q (ED. 03-07)iv
termination date of the contract defined as the earliest date either buyer or seller can unilaterally canæl the contract.
OLF - Other Long-Term Firm Transmission Service. Report servce provided under contracts which do not conform to the
terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and "firm" means that service
cannotbe 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 service which can not be placed in the
above-mentioned classifications, such as all other serviæ regardless of the length of the contract and service FERC
Form. Describe the type of service in a footnote for each eAry;
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 footno!~ for each adjustment. . .
DEFINITIONS
i. Commission Authorization (Comm. Auth.) -The authzation of the Federal Energy Regulatory Commission, or
~iny other Commission. Name the commission whose authorization was obtained and give date of the authorization.
II. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose
behalf the report is made. _. .
FERCFORM 1 & 3-Q (ED. 03-07)v
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, draHiage district, or other political subdivision or
agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or
distributing power; ......
(11) "project' means. a complete unit of improvement or development, consisting of a power house, all water
conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit,
and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power
there from to the point of junction with the distribution system or with the interconnected primary transmission system, all
miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights,
rìghts-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or
appropriate in the maintenance and operation of such unit;
"Sec. 4. The Commission is hereby authorized and empowered
(a) To make investigations and to collect and record data concerning the utilization of the water 'resources of any region
to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and
concerning the location, capacity, development -costs, and relation to markets of power sites; ... to the extent the
Commission may deem neæssary or useful for the purposes of this Act."
"Sec. 304. (a) Every Licensee and every public utiity shall fie with the Commission such annual and other periodic or
special* reports as the Commission may be rules and regulations or other prescribe as necessary or appropriate to assist
the Commission in the -proper administration of this Act. The Commission may prescribe the manner and FERC Form in
which such reports salt be made, and require from such persons specific answers to all questions upon which the
Commission may need information. The Commission may require that such reports shall include, among other things, full
information as to assets and Liabilties, capitalization, net investment, and reduction thereof, gross receipts, interest dl,e
and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the
project and other facilties, cost of renewals and replacement of the project works and other facilities,depreciation,
generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such
person to make adequate provision for currently determining such costs and other facts. Such reports shall be made
under oath unless the Commission otherwise specifies*.1 0
FERC FORM 1. & 3-Q (ED. 03-07)vi
"Sec. 309. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind
such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among
other things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may
prescribe the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the
Commission, the information which they shall contain, and the time within which they shall be field..."
General Penalties
The Commission may assess up to $1 milion per day per violation of its rules and regulations. See
FPA § 316(a) (2005), 16 U.S.C. § 8250(a).
FERC FORM 1 & 3-Q (ED. 03-07)vii
FERC FORM NO. 1/3-Q:
REPORT OF MAJOR ELECTRIC UTILITIES LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent
PacifiCorp
03 Previous Name and Date of Change (if name changed during year)
02 Year/Period of Report
End of 2009/04
/ /
04 Address of Principal Offce at End of Period (Street, City, State, Zip Code)
825 N.E. Multnomah, Suite 1900, Portland, OR 97232
05 Name of Contact Person
Henry E. Lay
i 07 Address of Contact Person (Street, City, State, Zip Code)
825 N.E Multnomah, Suite 1900, Portland, OR 97232
06 Title of Contact Person
Corporate Controller
08 Telephone of Contact Person,/ncluding
Area Code
[phone]
09This Report Is
(1) IX An Original (2) D-A Resubmission
1 o Date of Report
(Mo,Da, Yr)
04/14/2010
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned offcer certifies that:
I have examined this reprt 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 Accounts.
01 Name
Dou las K. Stuver
02 TitleSenior VP & Chif Financial Ofcer DouglasKStuver 04/14/2010
TIle 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
03 Signature 04 Date Signed
(Mo,Da, Yr)
FERC FORM No.1/3-Q (REV. 02-04)Page 1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
LIST OF SCHEDULES (Electric Utilty)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
1 General Information 101
2 Control Over Respondent 102 ....
3 Corporations Controll by Respondent .103
4 Oficers 104
5 Director 105
6 Informatin on Formula Rates 106(a)(b)
7 Important Chages During the Year 108-109
8 Comparative Balance Sheet 110-113
9 Statement of Income for the Year 114-117
10 Statement of Retained Earnings for the Year 118-119
11 Statement of Cash Flows 120-121
12 Notes to Financial Statements 122-123
13 Statement of Accum Comp Incme, Comp Income, and Hedging Activities 122(a)(b)
14 Summary of Utilit Plant & Accumulated Provisions for Dep, Amrt & Dep 20201
15 Nuclar Fuel Materials 202-203 N/A
16 Elecric Plant in Service 204-207
17 Electric Plant Leased to Others 213 N/A .
18 Elecc Plant Held for Future Use 214
19 COl'truion Work in Progress-Eletri 216
20 Accumulated Provisi for Deprecation of Electric Utilit Plant 219
21 Investmet of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowces 228(ab)-229(ab)
24 Extraordinar Property Losses 230 N/A
25 Unrecovered Plant and Regulatory Study Costs 230
26 Transmission Service and Generation Interconnection Study Costs 231
27 Oter Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accumulated Derred Income Taxes 234
30 Capil Stock 250251
31 Otr Paid-in Capital 253
32 Capital Stock Expense 254
33 Long-Term Debt 256-257
34 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 261
35 Taxes Accrued, Prepaid and Charged During the Year 262-263
36 Accumulated Deferred Investment Tax Credits 266-267
FERC FORM NO.1 (ED. 12-96)Page 2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2)FiA Resubmission 04/14/2010 .
LI T OF SCHEDULES (Electric Utilty) (continued)
..
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certin 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 Other Deferred Credits ,269
38 Accumulated Deferred Income Taxes-Accelerated Amortization Propert 272-273 N/A
39 Accumulated Deferred Income Taxes-Other Property 274-275
40 Accumulated Deferred Income Taxes-other 276-277
41 Other Regulatory Liabilties 278
42 Electric Operating Revenues 300-301
43 Sales of Electcity by Rate Schedules 304
44 Sales for Resale 310-311
45 Electric Operation and Maintenance Expenses ..320-323
46 Purchased Power 326-327
47 Transmission of Electricity for Others 328-330
48 Transmission of Electricity by ISO/RTOs 331 N/A
49 Transmission of Elecricity by Others .332
50 Miscellaneos General Expenses-Electric 335
51 Depreciaton and Amortization of Electric Plant 336-337
52 Regulatory Commission Expenses 350-351
53 Research,Development and Demonstration Activities 352-353
54 Distribution of Salaries and Wages 354-355
55 Common Utilty Plant and Expenses 356 N/A
56 Amounts inclded in ISO/RTO Setlement Statements 397 N/A
57 Purchase and Sale of Ancilary Services 398
58 Monthly Transmission System Peak Load .'400
59 Monthly ISO/RTO Transmission System Peak Load 400a N/A
60 Elec Energy Accont 401
61 Monthly Peaks and Output 401
62 Steam Electric Generating Plant Statistics 402-403
.63 Hydroelectc Generating Plant Statistics 406-407
64 Pumped Storage Generating Plant Statistics 408-409 N/A
65 Geerating Plant Statistics Pages 410-411
66 Transmission Line Statistics Pages 422-423
.
FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) nA Resubmission 04/14/2010
LI T OF SCHEDULES (Electric Utilty) (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
No.
Title of Schedule Reference
Page No.
(b)
424-425
426-427
429
450
Remarks
(a)
67 Transmission Lines Added During the Year
68 Substations
69 Transactions with Associated (Affliated) Companies
70 Footnote Data
Stockholders' Reports Check appropriate box:
o Two copies wil be submitted
o No annual report to stockholders is prepared
(c)
.
.
.,
FERC FORM NO. t(ED. 12-96)Page 4
Name of Respondent
PacifiCorp
This Report Is:
(1) 00 An Original
(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
04/14/2010
Year/Period of Report
End of 2009/Q4
GENERAL INFORMATION
1. Provide name and title of offcer having custody of the general corporate books of account and address of
offce where the general corporate books are kept, and address of offce where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
Douglas K. Stuver, Senior Vice President and Chief Financial Officer
825 N.E. Multnomah, Suite 1900
Portland, OR 97232-4116
Corporate Books are kept at:
825 N.E. Multnomah, Suite 1900
Portland, OR 97232-4116
2. Provide the name of the State under the laws of which respondent is incorporated, and date ofincorporation.
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.
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not applicable
4. State the classes or utility and other serviæs furnished by respondent during the year in each State in which .
the respondent operated.
PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United States regulated electric comany
serving 1.7 million retail customrs, including residential, comrcial, industrial and other customrs
in portions of the states of Utah, Oregon, Wyomng, Washington, Idahb and California. PacifiCorp
delivers electricity to customrs in Utah, Wyoming and Idaho under the trade nam Rocky Mountain Power
and to customrs in Oregon, Washington and California under the trade nam Pacific Power. PacifiCorp's
electric generation and comrcial and trading functions are operated under the trade nam PacifiCorp
Ener.gy.
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 ærtifieo financial statements?
(1) 0 Yes...Enter the date when such independent accountant was initially engaged:
(2) IX No
FERC FORM NO.1 (ED. 12-87)PAGE 101
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA .
I$chedule Page: 101 Line No.: 1 Column: Item 2
PacifiCorp was initially incorporated in 1910 under the laws of the state of Maine under the name Pacific Power & Light Company.
In 1984, Pacific Power & Light Company changed its name to PacifiCorp. In 1989, it merged with Utah Power and Light Company, a
Utah corporation, in a transaction wherein both corprations merged into a newly-formed Oregon corporation. The resultig Oregon
corporation was re-named PacifiCorp, which is the opertig entity today.
l FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
This Report Is:
(1) 00 An Original
(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
04/14/2010
Year/Period of Report
End of 2009/Q4
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held
control over the repondent at the end of the year, state name of 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%) (89.5% controlled by Berkshire Hathaway Inc.)
PPW Holdings LLC (100% controlled by MidAmerican Energy Holdings Company)
PacifiCorp (100%. of common stock held by PPW Holdings LLC)
FERC FORM NO.1 (ED. 12.96)Page 102
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
CORPORATIONS CONTROLLED BY R SPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of contrl.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interpsition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effecively 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 Name of Company Controlled Ki of Business Percnt Vot Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
1 ,L('';c,
..i....,.'..,.,.))'; ii.,'....',.':i
i Mining 100
2 Energy West Mining Company Mining 100
3 Glenrock Coal Company Mining 100
4 Interwest Mining Company Mining 100
5 Pacific Minerals, Inc.Mining 100
6 ...:..............!/'.)Mini 66.67,.,,":+:.
7 PacifiCorp Environmental Remediation Company Enviromental Serices 100-
ICT......r.....a;, ¡¡ ii'
8 Rain Forest Carb Credit 100~
9 Management Services 100
10 Mining 21.40
11 PacifiCorp Foundation Not-fer-prfi fondation ,."...,i':
12
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FERC FORM NO.1 (ED. 12-96)Page 103
~j,
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp .(2)A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA
Canopy Botanicals, Inc. were dissolved.
I FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/04
(2) EiA Resubmission 04/14/2010
OFFICERS
1. Report below the name, title and salary for each executive offcer whose salary is $50,000 or more. An "executive offcer" 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 penorms 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.
,:sai.ary~ W ~for Year
(c)
: Chairman'ofthe Board and Chief Executive Offcer
3 Senior Vice President and Chief Financial Offcer Douglas K. Stuver 228,800
4 President, Rocky Mountain Power A. Richard Walje 351,900
5 President, Pacific Power R. Patrick Reiten 265,740
6 President, PacifiCorp Energy 236,000
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FERC FORM NO.1 (ED. 12-96)Page 104
Name of Respondent This Report is:. ~Date. of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp I (2) A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA -
\Schedule Page: 104 Line No.: 1 Cci/umn: a
PacifiCorp sets fort the salary information for its "named executive offcers" for the year ended December 31,2009, consistent with
I tern 402 of Regulation $- K promulgated by the Securties and Exchange Commission in its Anual Report on. Form 10- K. . Salar
informtion of other officers wil be provided to the Federal Energy Regulatory Commission (the "FERC") upon request, but the
company considers such information personal and confidential to such offcers. See 18 CFR 388.l07(d), (t).
\Schedule Page: 104 Line No.: 2 Column: b
Mr. Abel receives no direct compensation from PacifiCorp. PacifiCorp reimburses MidAmerican Energy Holdigs Company
("MEHC") for the cost of Mr. Abel's time spent on matter supportng PacifiCorp, including compensation paid to him by MEHC,
pursuant to an intercompanyadministtive services agreement among MEHC âld its subsidiares. Please refer to MEHC's Annual
Report on Form 10-K for the year ended December 31, 2009 (File No. 001-14881) for executive compensation information for Mr.
AbeL.
¡Schedule Page: 104 Line No.: 6 Column: b
For additional information regarding changes in the status ofPacifiCorp's offcers refer to page 108, Important Changes During the
Year, Item 13,ofthis Form No.1. On Januar 13,2010, Mr. Lasich resigned as President ofPacifiCorp Energy and as a diector of
PacifiCorp effective Februar 1,2010.
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This wort Is:Date of Report Year/Penod of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
DIRECTORS
1. Report below the inforation called for concerning each direcor of the respondent who held offce at any time during the year. Include in column (a), abbreviated
titles of the directors who are offcers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairmn of the Executive Committe by a double asterisk.
L~g.Name (anii ,I lUe) or uirector PnnClpal Business Address. (a)(b)1 ~
2 666 Grand Avenue, Suite DM29, Des Moines, Iowa 50309
3 R. Patrick Reiten (President, Pacific Power) . 825 NE Multnomah, Suite 2000, Portland, Oregon 97232
4 A. Richard Walje (President, Rocky Mountain Power)201 South Main, Suite 2300, Salt Lake City, Utah 84111
5 Douglas L. Anderson 302 Soth 36th Street, Omaha, Nebraska 68131
6 Brent E. Gale (Senior Vice President)825 NE Multmah, Suite 2000, Portand, Oregon 97232
7 Patnck J. Goodman 666 Grand Avenue, Suite DM29, Des Moines, Iowa 50309
1407 West Nort Temple, Sui 320, Salt Lake City, Utah 84116
9 Mark C. Moench (SVP and General Counsel, PacifiCorp) 201 Soth Main, Suite 2400, Salt Lake City, Utah 84111
10 Nataie L. Hocken (VP and General Counsel, Pacifc Power)825 NE Multnomh, Suite 2000, Portand, Oregon 97232
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FERC FORM NO.1 (ED. 12-95)Page 105
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp i (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
!šchedule Page: 105 Line No.: 2 Column: a
Curently there is only one committe, a Compensation Committee, of which the sole member is Mr. AbeL.
!šchedule Page: 105 Line No.: 8 Column: a
For additional information regarding changes in the status ofPacifiCorp's directors referto page 108, Important Changes During the
Year, Item 13, of this Form No.1. On Januar 13,2010, Mr. Lasich resigned as President ofPacifiCorp Energy and as a director of
PacifiCorp effective Februar 1,2010.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Responden This in0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) 0 A Resubmission 04/14/2010
INFORMATION ON FORMULA RA ES
FERC Rate Schedulerrariff Number FERC Proceeding .-
Does the respondent have formula rates?DYes
.1Z No
1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceding (i.e. Docket No)
accepting the rate(s) or changes in the accpted rate.
..ine
No.FERC Rate Schedule or Tari Number FERC Proceeding
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FERC FORM NO.1 (NEW. 12.(8)Page 106
Name of Respondent This (l0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) Fi A Resubmission 04/14/2010 .. .
INFORMATION ON FORMULA RATES
FERC Rate SchedulelTariff Number FERC Proceeding ..
Does the respondent file with the Commission annual (or more frequent)DYesfilings containing the inputs to the formula rate(s)?
IZ No,
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
Formula Rate FERC RateLineDocument Date Schedule Number ór
No.Accession No.\ Filed Date Docket No.Description Tariff Number
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FERC FORM NO.1 (NEW. 12-08)Page 106a
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) D A Resubi:ission 04/14/2010
.INFORMATION ON FORMULA RATES
Formula Rate Variances
1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from
amounts reported in the Form 1.
2. The footnote should provide a narrative description explaining how the "rate" (or biling) was derived if different from the reported amount in the
Form 1.
3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other itéms
impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.
4. Where th Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote...
Line
No.Page No(s).Schedule Column Line No
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FERC FORM NO.1 (NEW. 12-08)Page 106b
Name of Respondent
PacifiCorp
Date of Report Year/Period of Report
End of 2009/Q4
This Report Is:
(1) 12 An Original
(2) 0 A Resubmission .
IMPORTANT CHANGES DURING THE QUARTERIEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a rèference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If aëquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization .
3. Purchase or sale of an operating unit or system: Give a brief description of the propert, and of the transactions relating thereto, and
reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were
submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such al!thorization.-
5. Importnt extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers
added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new
continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated ännual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important iegal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an offcer,
director, security holder reported on Page 106, voting trustee, associated company or known associate of any of these persons was a
part or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in offcers, directors, major security holders and voting powers of the respondent that may have occurred
during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affilated companies through a cash
management proram(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
04/14/2010
PAGE 1 08 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12"96)Page 108
.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
ITEM 1.
Changes in. Franchise Rights
State Effective Date Expiration Date Fee
(Fee attche to frchise agreement)
California (a)
None
Idaho (b)
None
Oreon (c)
Myrle Point 04/22/2009 04/22/2029 5.0%
Philomath 08/01/2009 08/01/2019 7.0%
Jefferson 12/08/2009 12/08/2029 7.0%
Hood River 12/11/2009 12/11/2029 5.0%
Lebanon 12/22/2009 12/22/2019 5.94%
Utah (b)
Washington Terrace 01/27/2009 01/27/2019 6.0%
Hyde Park 03/27/2009 03/27/2034
South Salt Lake City 04/21/200 04/21/2034 6.0%
Wales 10/26/2009 10/26/2034
Moab 10/28/2009 10/28/2024 3.0%
Lehi (1M Flash Plant)11/02/2009 11/02/2010 (e)6.0%
Gunnison 12/08/2009 12/08/2034 6.0%
Centereld 12/08/2009 12/08/2034 6.0%
Oakley 12/14/200 12/14/2024
Washington (b)
None
Wyoming (d)
Rollng Hils 08/11/2009 08/11/2034 2.0%
(a) In California, franchise fees are an expense to PacifiCorp and are embedded in rates.
(b) In Idao, Uta and Washington, PacifiCorp collects frchise fees from customers and remits them
directly to the applicable municipalities.
(c) In Oregon, the firt3.5% of the frnchise fees is an expense to PacifiCorp and is embedded in rates.
Any amount above the 3.5% is collected from customer and remittd diectly to the applicable
municipalities.
(d) In Wyomig, the fist 1.0% of the frchise fees is an expense to PacifiCorp and is embedded in
rates. Any amount above the 1.0% is collected from customers and remitted diectly to the applicable
municipalities.
(e) The initial term of the agreement is one year from the effective date. It wil automatically renew each
year for seven consecutive years, unless either par gives appropriate notice to termate.
I FERC FORM NO. 1 (ED. 12-96)Page 109.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
ITEM 2.
Acquisition of Ownership in Other Companies
On September 15, 200S, after having received the requisite regulatory approvals, PacifiCorp acquired from TNA Merchant Projects,
Inc., an affiiate Qf .suez Energy Nort America, Inc., 100% of the equity interests of Chehalis Power Generating, LLC("Ç)lehalis"),
an entity owning a 520-megawatf ("MW") natual gas-fired generating facilty located in Chehalis, Washington. The total cash
purchase price was $30S millon and the estimated fair value of the acquired entity was priarily allocated to the facilty, which was
included in account 102, Electrc plant purchased or sold. Chehalis was merged into PacifiCorp immediately following the
acquisition. The results of the facilty's operations have been included in PacifiCorp's fmancial statements since the acquisition date.
In May 2009, the Federal Energy Regulatory Commission (the "FERC") approved the journal entres called for by the Uniform
System of Accounts, with modifications to the piichase accounting adjustments for asset retirement obligations. Accordingly,
PacifiCorp cleared account 102, Electrc plant purchased or sold and recorded the purchase to the appropriate plant accounts.
Commssion authorizations associated with the acquisition were as follows:
. Federal Trade Commission - Trasaction identification number 200S1 103, granted May 9, 200S.
. FERC - Docket No. ECOS-S2-000, issued July 17, 200S.
. Washington Energy Facilty Site Evaluation Council- Order No. S36, effective July S, 200S.
. Federal Communications Commission ~ File number 0003447617, consent dated May 23, 200S.
. Oregon Public Utility Commssion (the "OPUC") - Order No. OS-376, effective July 17, 200S, granting the petition for waiver of
the OPUC's competitive bidding guidelines;
. Utah Public Servce Commssion (the "UPSC") - Docket No. OS-035-35, dated. August 30, 200S, grnting the request for
approval to acquire a significant energy resource.
ITEM 3.
Purchase or Sale of an Operating Unit or System
In August 2009, PacifiCorp received FERC approval in Docket Nos. EC09-S6-000 and EC09-S6-00 1, pursuant to section 203 of the
Federal Power Act, for the aêquisition of a portoÌi of a 69-kilovolt ("kV") electrc transmission facilty from Garkane Energy
Cooperative, Inc. The acquisition was completed in September 2009. The purchase included electrc trsmission line facilities from,
and including, the interconnect point at the Clifton Wilson substation located in Hurcane, Utah to the Twin Cities substation located
in Hildale, Utah. In February 2010, the FERC approved the joural entres called for by the Uniform System of Accounts in Docket
No. AC1O-44-000. Accordingly, PacifiCorp cleared account 102, Electrc plant purchased or sold and recorded the purchase to the
appropriate plant accounts.
ITEM 4.
Important Leaseholds
None.
ITEM 5.
Important Extension or Reduction of Transmission System or Distribution Territory
For discussion of trsmission lines added during the year, refer to pages 424-425 of tils Form No. 1. Durng the year ended
December 31, 2009, PacifiCorp did not significantly increase or decrease its distrbution terrtory.
IFE:RC FORM NO.1 (ED. 12-96) Page 109.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) LÇ An Original (Mo, Oa, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
ITEM 6.
Financing Activities
Short- Term Debt and Revolving Credit Agreements
Regulatory authorities limit PacifiCorp to $1.5 bilion of short-ter debt. PacifiCorp had no short-term debt outstanding as of
December 31, 2009 compared to $85 million outstadig as of December 31, 2008 at a weighted-average interest rate of 1 %. The
decrease in short-term debt was primarly due to the proceeds from the issuance of long-term debt and $125 million of capital
contrbutions received from MERC durg the peod, parially offset by capital expenditues and matuties of long-term debt in
excess of net cash provided by operating activities.
Commission authorizations for up to $1.5 bilion outstandig at anyone tie in commercial paper and other unsecured short-term
debt are as follows:
· OPUC - Docket No. UF-4120, Order No. 98-158, dated April 16, 1998.
· Washington Utilities and Transporttion Commission (the "WUC") - Docket No. UE-980404, dated April 8, 1998.
· Idao Public Utilities Commission (the "IPUC") - Case No. PAC-E-06-01, Order No. 29999, dated March 14, 2006.
· FERC - Docket No. ES07 -61-000, dated November 26, 2007, lettr order effective Janua 1, 2008 through December 31, 2009.
· FERC - Docket No. ES09-50-000, dated October 9,200, lettr order effective Januar 1,2010 through December 31, 2011.
PacifiCorp had no outstading borrowings under its unsecured revolving crdit facilities as of December 31, 2009 or 2008.
For fuer discussion, refer to Note 8 of Notes to Financial Stateents in this Form NO.1.
Long-Term Debt
In addition to the debt issuances discussed herein, PacifiCorp mae scheduled repayments on long-ter debt totaling $138 milion and
$412 millon durng the years ended December 31, 2009 an 2008, respectively.
In Janua 2009, PacifiCorp issued $350 milion of its 5.50% Firt Mortgage Bonds due January 15, 2019 and $650 milion of its
6.00% First Mortgage Bonds due Januar 15, 2039. The net proceeds were used to repay short-term debt, fund capital expenditues
and for general corporate puroses. State commssion authorizations for this issuance were as follows:
· OPUC - DocketNo. UF-424~, Order No. 08-013, dated Janua 14,2008.
· IPUC - Case No. PAC-E-07-16, Order No. 30489, dated January 22, 2008.
As of December 3 i, 2009, PacifiCorp had $517 milion of letter of credit available to provide credit enhancement and liquidity
support for variable~rate ta-exempt bond obligations totaling $504 milion plus interest. These committed bank argements were
fuly available at December 31,2009 and expire periodically thugh May 2012.
IFERC FORM NO.1 (ED. 12-96)Page 109.3
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
In March 2010, PacifiCorp received regulatory authority from the IPUC to issue an additional $2.0 bilion oflong-term debt though
Februar 28, 2015. PacifiCorp has regulatory authority from the OPUC to issue an additional $2.0 bilion of long-term debt.
PacifiCorp must make a notice fiing with the WUTC prior to any futue issuance. State commission authorizations are as follows:
· OPUC - Docket No. UF-4262, Order No. 10-062, dated February 23,2010.
· IPUC - Case No. PAC~E-10-02, Order No. 31018, dated March 5, 2010.
PacifiCorp may from tie to time seek to acquire its outstanding debt securties though cash purchases in the open market, privately
negotiated trnsactions or otherwise. Any debt securties repurchased by PacifiCorp may be reissued or resold by PacifiCorpfrom
time to time and wil depend ori prevailing market conditions, PacifiCorp's liquidity requirements, contractual restrctions and other
factors. The amounts involved may be materiaL.
ITEM 7.
Changes in Artcles of Incorporation or Amendments to Charter
None.
ITEMS.
Estimated Annual Effect of Signifcant Wage Scale Changes
PacifiCorp's bargaining unit wage scale changes were as follows:
Unions Represented % Increase (a)Effective Date(s)
Estimated Anual
Financial Impact (b)
IBEW 57 Generation (UT, ID & WY)
IBEW 57 Power Delivery (UT, ID & WY
Total
2.81%
2.81%
1126/2009
1126/2009
$1,072,019
2,267,014
3339,033$
(a) This percentage increase represents the increase in wages for all effective dates durng the calenda year as
compared to the wage scale of the prior effective period.
(b) The estimated annual impact is based on the time period from the effective date of the increase to the end of the
calendar year. Some amountsm:iy be reimbursed by joint owners.
I FERC FORM NO.1 (ED. 12-96)Page 109.4
..
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmissiol1 04/14/2010 2009/Q4
..IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
ITEM 9.
Legal Proceedings
PacifiCorp is par to a varety of legal actions arsing out of the normal coure of business. Plaintiffs occasionally seek punitive or
exemplary daages. PacifiCorp does not believe that such normal and routine litigation wil have a material effect on its financial
results. PacifiCorp is also involved in other kids of legal actions, some of which assert or may assert claims or seek to impose fines,
penalties and other costs in substantial amounts and are descrbed below.
In December 2000, Wah Chang, a large industral customer ofPacifCorp that opertes a reactive and refractory metals manufactug
facility in Milersburg, Oregon, fied an action before the OPUC asserg that the rates set by a special taff with PacifiCorp and
approved by the OPUC were not just and reasonable. In October 2001, the OPUC dismissed Wah Chag's petition and found that
Wah Chang assumed the risk of price increases under the special taff. Wah Chang petitioned the Circuit Cour for Maron County,
Oregon for review of the OPUC's order. In June 2002, the Circuit Cour for Maron County, Oregon, granted Wah Chang's motion
and ordered the OPUC to reopen the record to allow Wah Chang the opportnity to present new evidence of alleged market
manipulation durng the energy crisis. In September 2009, the OPUC dismissed Wah Chang's petition and reaffrmed that the rates set
by the special taff were just and reasonable. In October 2009, Wah Chang filed with the Oregon Cour of Appeals a petition for
judicial review of the OPUC's September 2009 order denying Wah Chang relief.
In a separate but related proceedig, in December 200, Wah Chang fied a complaint in the Circuit Cour for Linn County, Oregon,
assertg that the special tarff with PacifiCorp is subject to rescission based on theories of mutu mistae of fact, frstration of
purose and impracticability. In August 2002, the Circuit Cour for Lin County, Oregon, granted PacifiCorp's motion for sumar
judgment dismissing Wah Chang's complaint. In Februar 2004, theCircuIt Cour for Lin County, Oregon, granted Wah Chang's
motion to reopen the case to present additional evidence of alleged market mapulation. In December 2007, Wah Chang fied a
second amended complaint seekig recover of a porton of the costs paid under the special taff based on various theories of legal
relief, including partial rescission, unjust enrchment, and breach of duty of good faith and fair dealing. In August 2009, the Circuit
Cour for Linn County, Oregon, grnted Wah Chang's request to fie a third amended complaint containing a claim for punitive
damages. In December 2009, PacifiCorp's motion for sumar judgment based on the OPUC's September 2009 order was denied by
the Circuit Court for Linn County, Oregon. The tral date. has been stayed until 201 1. Wah Chang is seekig $37 millon (less the
amount Wah Chang would have paid for electrcity absent the special taff in compensatory damages and $200 milion in punitive
daages. PacifiCorp intends to vigorously defend these claims and believes tht the outcome of these proceedings wil not have a
material impact on its financial results.
In Februar 2007, the Sierra Club and the Wyomfg Outdoor Council fied a complaint against PacifiCorp in the federal distrct cour
in Cheyenne, Wyoming, alleging violations of the Wyoming state opacity stadads at PacifiCorp's Jim Bridger generating facility in
Wyomig. Under Wyoming state requirements, which ar par of th Jim Bridger generatig facilty's Title V permit and are
enforceable by private citizens under the federal Clean Air Act, a potential source of pollutats such as a coal-fired generatig facility
must meet minimum standards for opacity, which is a measurement of light that is obscured in the flue of a generating facility. The
complaint alleged thousands of violations of assered six-miute compliance periods and sought an. injunction orderig the Jim
Bridger generating facility's compliance with opacity limits, civil penalties of $32,500 pe day per violation and the plaintiffs' costs of
litigation. In August 2009, the cour ruled on a nube of sum judgment motions by which it determined that the plaintiffs have
sufficient legal standing to proceed with their complaint and that all other issues raised in the sum judgment motions wil be
resolved at tral. In Februar 2010, PacifiCorp, the Sier Club and the Wyomig Outdoor Council reached an agreement in priciple
to settle all outstandig claim in the action. The settlement will be memorialized in a consent decree to be fied with the United States
Environmental Protection Agency (the "EPA") for review and also with the cour for review and approval. If approved by the cour as
expected, the settlement is not expected to have a material impact on PacifiCorp's fiancial results.
IFERC FORM NO.1 (ED. 12-96)Page 109.5 l
Name of Respondent .- .This Report is:Pate of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/04
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
In October 2005, PacifiCorp was added as a defendant to a lawsuìt origìnally fied ìn Februar 2005 ìn state distrct court ìn Salt Lake
City, Uta by USA Power, LLC and its afflìated companies, USA Power Parers, LLC and Sprig Canyon, LLC (collectively,
"USA Power"), against Uta attorney Jody L. Wìliams and the law Tir Holme, Roberts & Owen, LLP, who represent PacifiCorp on
varous matters from time to time. USA Power was the developer of a planed generation project ìn Mona, Utah called
Sprig Canyon, which PacifiCorp, as par of its resource procurement process, at one tìme considered as an alternative to the Curant
Creek generating facilìty. USA Power's complaint alleged that PacifiCorp misappropriated confidential proprieta information ìn
violation of Utah's Uniform Trade Secrets Act and accused PacìfiCorp of breach of contrct and related claìms. USA Power seeks
$250 mìlion ìn damages, statutory doublìng of damages for ìts trde secrets violation claim, punitive damages, costs and attorneys'
fees. After considerg varous motions for summary judgment, the court ruled ìn October 2007 ìn favor of PacifiCorp on all counts
and dismìssed the plaìntiffs' claiin in their entìrety. In February 2008, the plaìntiffsfied a petition requesting consideration of theìr
appeal by the Utah Supreme CoUr. The plaintiffs' request was grted and they fied a brief in November 2008 with the Utah
Supreme Cour. In Januar 2009, PacìfiCorp fied its reply brief. PacifiCorp belìeves that its defenses that prevaìled ìn the tral cour
wìl prevaìl on appeaL. Furhermoré, PacifiCorp expects that the outcome of any appeal wìll not have a material impact on its fiancial
results.
ITEM 10.
Offcer, Director & Security Holder Transactions
None.
ITEM 11.
(Reserved)
IFERCFORMNO.1 (ED. 12-96) Page 109.6
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
ITEM 12.
General Regulation
PacifiCorp is subject to comprehensive governental regulation, which significantly influences its operating environment, prices
charged to customers, capital strctue, costs and ability to recover costs.
Certain regulatory matters are subject to uncertinties that require the use of estimates on the financial statements, particularly that
related to Oregon Senate Bil408 ("SB 408"). Refer to Note 5 of Notes to Financial Statements in this Form NO.1 for furter
discussion.
FederatRegulation
The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act, the Energy Policy Act
and other federal statutes. The FERC regulates rates for interstate sales of electrcity in wholesale markets; transmission of electrc
power, including pricing and expansion of trsmission systems; electrc system reliability; utility holding companies; accounting;
securties issuances; and other matters, including constrction and operation of hydroelectrc projects. The FERC also has the
enforcement authority to assess civil penalties of up to $1 millon per day per violation of rules, regulations and orders issued under
the Federal Power Act. PacifiCorp has implemented program that facilitate compliance with the FERC regulations described below,
including having instituted compliance monitoring procedures.
Wholesale Electrcity and Capacity
The FERC regulates PacifiCorp's rates charged to wholesale customer for electrcity and trsmission capacity and related services.
Most of PacifiCorp's wholesale electrc sales and purchases tae place under market-based pricing allowed by the FERC and are
therefore subject to market volatility.
The FERC conducts a trennal review of PacifiCorp's maket-based pricing authority. PacifiCorp must demonstrate the lack of
market power in order to charge market-based rates for sales of wholesale electrcity and electrc generation capacity in its balancing
authority ars. PacifiCorp's next trennial fiing is due in June 2010. Under the FERC's market-based rules, PacifiCorp must also fie
a notice of change in statu when there is a significant chage in the conditions that the FERC relied upon in granting market-basedpricing authority. PacifiCorp is curently authoried to sell at market-based rates.
Transmission
PacifiCorp's wholesale transmission servces are regulated by the FERC under cost-based regulation subject to PacifiCorp's Open
Access Transmission Tarff ("OATT"). In accordace with its OATT, PacifiCorp offers several transmission services to wholesale
customers:
· Network transmission service (guted serice that integrtes generting resources to serve retail loads);
· Long- and short-ter firm point-to-point trsmission service (gunteed serice with fixed delivery and receipt
points); and
· Non-firm point-to-point service ("as available" service with fixed delivery and receipt points).
These services are offered on a non-discriatory basis, which means that all potential customers are provided an equal opportity
to access the transmission system. PacifiCorp's trnsmission business is managed and operated independently from its commercial
and trding business, in accordance with the FERC Stadads of Conduct.
.. For retail customers, transmission costs are not separated from, but rather are "bundled" with, generation and distrbution costs in
rates approved by state regulatory commssions.
I FERC FORM NO. 1 (ED. 12-96)Page 109.7
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp ì2) A Resubmission 04/14/2010 2009/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued).
FERC Order No. 890 - Preventing Undue Discrimination and Preference in Transmission Service
In Februar 2007, theFERC adopted a final rule in FERC Order No. 890, "Preventing Undue Discrimination and Preference in
Transmission Servce" ("Order No. 890") designed to strengthen the pro forma OATT by providing greater specificity and increasing
transparency. The most signficant revisions to the pro forma OATT relate to the development of more consistent methodologies for
calculating available trnsfer capability, changes to the transmission planing process, changes to the pricing of certain genertor and
energy imbalances to encourage efficient scheduling behavior and changes regarding long-term point-to-point trnsmission service,
including the addition of conditional firm long-term point-to-point transmission service and generation re-dispatch. The FERC has
issued rules through a set of subsequent orders clarfyng Order No. 890. As a transmission provider with an OATT on fie with the
FERC, PacifiCorp is required to comply with the requirements of this rule. PacifiCorp made its first compliance filing amending its
OATT in July 2007. The FERC has contiued to issue rules through a set of subsequent orders clarfYing Order No. 890. In response
to these varous orders, PacifiCorp has made several required compliance fiings.
FERC Reliabilty Standards
The FERC has approved an extensive number of reliabilty standads developed by the Nort Amercan Electrc. Reliabilty
C~rporation and the Western Electrcity Coordinating Council (the "WECC"), including critical infrastrctue protection stadads
and regional stadard variations. PacifiCorp must comply with all applicable standards. Compliance, enforcement and monitoring
oversight of these standads is cared out by the FERC and the WECC. Durng 2007, the WECC. audited PacifiCorp's compliance
with several of the approved reliability standards, and in November 2008, the FERC assumed control of certin aspects of the
WECC's audit. In May 2009, PacifiCorp received a notice of alleged violation and proposed sanctions related to the portons of the
WECC's 2007 audit that remained with the WECC. In July 2009, PacifiCorp reached a settlement in principle with the WECC, and a
settlement agreement was executed in Februar 2010. The results of the settlement wil not have a material impact on PacifiCorp's
financial results. Refer to Note 13 of Notes to Financial Statements included in this Form NO.1 for additional informtion regarding
certin aspects of the WECC's 2007 audit curently under the FERC's authority.
Hydroelectric Relicensing - Klamath River Hydroelectric Facilities
PacifiCorp's Klanith hydroelectrc system is the only hydroelectrc generatig facility for which PacifiCorp is engaged in the
relicensing process with the FERC. PacifiCorp also has requested the FERC to allow decommissioning of certain hydroelectrc
systems. Most ofPacifiCorp's hydroelectrc generating facilities are licensed by theFERC as major systems under the Federl Power
Act, and certin of these systems are licensed under the Oregon Hydroelectrc Act. Refer to Note 13 of Notes to Financial Statements
in this Form No.1 for an update regarding hydroelectrc relicensing for PacifiCorp's Klamath hydroelectrc system.
Hydroelectric Decommissioning - Condit Hydroelectric Facility - White Salmon River, Washington
In September 1999, a settlement agreement to remove the 14-MW Condit hydroelectrc facility was signed by PacifiCorp, state and
federal agencies and non-govérmental organizations. Under the original settlement agreement, removal was expected to begin in
October 2006, with a total cost to decommssion not to exceed $17 milion, excluding infation. In early Febru 2005, the pares
agreed to modifY the settement agreement so that removal would not begin until October 2008, with a total cost to decommission not
to exceed $21 milion, excludig inflation. The settlement agreement is contingent upon receiving a FERC surender order and other
regulatory approvals that are not materially inconsistent with the amended settlement agreement. PacifiCorp is in the process of
acquirng all necessar permts within the terms and conditions of the amended settlement agreement. Given the ongoing permittg
process and the time needed for system removal and to evaluate impacts on natual resources, decommissioning is now expected to
begin no earlier than October 2QlO. In March 2008, the United States Ary Corps of Engineers requested PacifiCorp complete an
additional study of expected decommissioning impacts on aquatic resources. In January 2009, the study work was completed and the
results were provided to the United States Ary Corps of Engineers and the Washington Deparent of Ecology. In Januar 2010,
the Washington Deparent of Ecology released the Final Second Supplemental Environmental Impact Statement which formally
considered this additional information. Absent fuher information requests, the Washington Departent of Ecology is expected to
complete the Clean Water Act 401 certification process within the second quarer of 2010. Remaining perittng includes a
404 permit from the United States Ary Corps of Engineers and a surender order from the FERC.
IFERC FORM NO.1 (ED. 12-96) Page 109.8
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009/Q4 J'
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
Northwest Refùnd Case
For a discussion of the Northwest Refud case, refer to Note 13 of Notes to Financial Statements in this Form No.1.
United States Mine Safety
PacifiCorp's mining operations are regulated by the federal Mine Safety and Health Administration ("MSHA"), which admnisters
federal mine safety and health laws, regulations and state reguatory agencies. The Mine Improvement and New Emergency Response
Act of2006 ("MIER Act"), enacted in June 2006, amended previous mine safety and health laws to improve mine safety and health
and accident preparedness. PacifiCorp is required to develop a wrtten emergency response plan specific to each underground mine it
operates. These plans must be reviewed by MSHA every six months. It also requires every mie to have at least two rescue team
located within one hour, and it limits the legal liabilty of rescue team members and the companies that employ them. The MIR Act
also increases civil and criinal penalties for violations of federal mie safety standads and gives MSHA the ability to institute a
civil action for relief, including a tempora or permnent injunction, restrining order or other appropriate order against a mine
operator who fails to pay the penalties or fines.
State Regulation
PacifiCorp pursues a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs.
Historically, state utility commssions have established rates on a cost-of-service basis, which are designed to allow a utility an
opportnity to recover its costs of providing services and to ear a reasonable retu on its investments. A utility's cost of service
generally reflects its allowed operting expenses, including energy costs, operation and maintenance expense, depreciation expense
and income and other tax expense, reduced by wholesale electrc sales and other revenue. State utility commissions may adjust rates
pursuant to a review of (a) the utility's revenue and expenses durg a defied test period and (b) the utility's level of investment.
State utility commissions tyically have the authority to review and change rates on their own initiative. States may also initiate
reviews at the request of a utility, utility customer, a governental agency or a representative of a group of customers. The utility and
such paries, however, may agree with one another not to request a review of or changes to rates for a specified period of time.
I FERC FORM NO.1 (ED. 12-96)Page 109.9
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
In addition to recovery though general rates, PacifiCorp also achieves recovery of certin costs through varous adjustment
mechanisms as summarzed below.
State Regulator Base Rate Test Period
Utah Public Servce
Commission
Forecasted or historical with
known and ineasurble
changes (I)
Oregon Public Utility
Commssion
Forecasted
Wyoming Public Serice
Commssion (the "WPSC")
Forecasted or historical with
known and meaurable
changes (1)
Washington Utilities and
Trasporttion Commssion
Historical with known and
measble changes
Idao Public Utilities
Commssion
Historical with known and
measurble changes
California Public Utilities
Commssion (the "CPUC")
Forecasted
Adjustment Mechanism
PacifiCoip has requeste approval of an energy cost adjustment
mechanism ("ECAM") to recover the difference between base net
power costs set durng a general rate cae and actual net power
costs.
A recover mechanism is available for a single capital investment
project that in total exceeds i % of existing rate bae when a
general rate case has occured within the preceding i 8 months.
Annual trition adjustment mechanism ("TAM"), a mechasm
for anual rate adjustments for forecasted net vàrable power
costs; no tre-up to actul net variable power costs.
Renewable adjustment clause ("RAC") to recover the revenue
requirement of new renewable resources and associated
trmission that are not reflected in general rate.
Annual tre-up of taes authorized to be collecte in rates
compared to taxes paid by PacifiCoip, as defined by Oregon
statute and adnistrtive rules unde SB 408.
Power cost adjustment mechanism ("PCAM") based on forecasted
net power costs, later tred-up to actual net power costs, subject
to dead bands and customer sharg. PacifiCoip has requeste
approval of a new ECAM to replace the existing PCAM, which is
set to expire in November 2010.
Deferrl mechanism of costs for up to 24 month of new ba load
generation resources and eligible renewable resources that quali:t
uner the state's emssions perormance standard and are not
reflected in general rates.
ECAM to recover the difference between base net power costs set
durng a general rate case and actul net power costs, subject to
customer shàrng and other adjustments.
Post test-year adjustment mechaism for major capital additiris
("PT AM - capital additions"), a mechanism that allows for rate
adjustments outside of the context of a trtional rate case for th
reVenue requirement assoiated with capital additions exceedg
$50 millon on a total-company basis. Filed as eligible capita
additions are placed into service.
Energy cost adjustment clause ("ECAC") that allows for an
annua update to actul andforecasted net variable power costs.
Post test-year adjustment mechanism for atttion ("PTAM -
atttion''), a mechanism that allows for an anual adjustment to
costs other than net vàrable power costs.
(I) PacifiCoip has relied on both historical test periods with known and meaurble adjustments and forecasted test periods. The WPSC
has not issued a final ruling on its preference between historical or forecasted test perods.
I FERC FORM NO. 1 (ED. 12-96)Page 109.10
. .
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) .A Resubmission 04/14/2010 20Ò9/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued). .
PacifiCorp's energy effciency program costs ar collected though separtely established rates that are adjusted perodically based on
actual and expected costs, as approved by.the respective state utility commssion.
Utah
In July 2008, PacifiCorp filed a general rate case with the UPSC requesting an annual increase of $161 million prior to any
consideration of the UPSC's order in the 2007 generl rate case. In September 2008, PacifiCorp filed supplemental testimony that
reflected then-curent revenues and other adjustments based on the August 2008 order in the 2007 general rate case. The supplemental
filing reduced PacifiCorp's request to $115 million. In October 2008, the UPSC issued an order changing the test period from the
twelve months ending June 2009 using end-of;period rate base to the forecast calenda year 2009 using average rate base. In
December 2008, PacifiCorp updated its filing to reflect the change in the test period. The updated fiing proposed an increase of
$116 milion. In March 2009, a settlement agreement was filed with the UPSC resolving all remaining revenue requirement issues,
resulting in pares agreeing, among other settlement terms, on an annual increase of $45 milion, or an average price increase of 3%,
effective May 8, 2009. In April 2009, the UPSC issued its final order approving the revenue requirement settlement agreement.
In March 2009, Utah's governor signed Senate Bil 75 that provides additional regulatory tools for the UPSC to use in the ratemaking
process. The additional tools provided in the legislation allow for single item cost recovery of major capital investments outside of the
general rate case process and allow for, but do not require, the use of an energy balancing account.
In March 2009, PacifiCorp fied for an ECAM with the UPSC. The fiing recommends that the UPSC adopt the ECAM to recover the
difference between base net power costs set in the next Uta gen rate case and actual net power costs. The UPSC has separated the
application into two phases to first address whether the mechanism is in the public interest, and then if it is found to be in the public
interest, to determine the tye of mechanism that should be implemented. Hearngs on the public interest phase were completed in
Januar 2010. In Februry 2010, the UPSC issued an order to proceed to the second phase to address design considerations in the
development of an ECAM. Additionally, in February 2010, PacifiCorp fied an application with the UPSC seeking approval to defer
the difference between the net power costs allowed by the UPSC's final order in PacifiCorp's 2009 general rate case and the actual
net power costs incured. If approved, the filing would establish a deferred cost balance to be considered for collection though any
potential mechanism established in the second phase of the ECAM proeedig.
In February 2010, an application was filed with the UPSC by the Uta Association of Energy User requesting an order requirng
PacifiCorp to defer for later ratemaing treatment all revenues associated with sale of renewable energy credits in excess of the level
included in Uta rates. If approved, Uta's share of any renewable.onrgy credit sales above $18.5 milion anually would be subject
to consideration in a futue proceeding.
In June 2009, PacifiCorp fied a general rate case with the UPSC for an increase of $67 million, or an average price increase of 5%.
The forecasted test period is the twelve months ending June 30, 2010. In November 2009, as par of its rebuttl and surebuttl filings,
PacifiCorp reduced its rate increase request to $53 millon. The UPSC issued its order Febr 18, 2010, approving a price increase
of $32 milion, or an average price increase of 2%.
In June 2009, PacifiCorp fied with the UPSC to increae its demad-side management ("DSM") cost recovery mechanism in Utah
from an average of 2% of a customer's eligible monthly charges to 6%. In Augut 2009, a settlement agreement was filed with the
UPSC requesting the DSM cost recover mechanism be adjusted to 5%, representig an estimated annual increase of $35 million,
which would enable PacifiCorp to contiue to fu ongoing DSM progr and to recover previously incured DSM expenditues.
The UPSC approved the settlement agreement in August 200, and the 5% DSM cost recover mechanism became effective
September 1, 2009.
In Februar 2010, PacifiCorp fied an alternative cost recovery application with the UPSC requesting recovery of $34 million
associated with two major constrction projects that are expected to be completed and in-service by June 2010. The mechanism
provides for a ruling from the lJSC within 150 days of the application. In March 2010, PacifiCorp updated its cost recovery
application, reducing the net revenue requiremet impact of the two major constrction projects to $33 milion.
IFERC FORM NO.1 (ED. 12-96)Page 109.11
.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
Oregon
In March 2009, PacifiCorp made the initial fiing for the annual TAM with the OPUC for an annual increase of $2 i milion to recover
the anticipated net power costs for the year beginning Janua i, 2010. In August 2009, PacifiCorp fied a revision to its anticipated
net power costs for the TAM, reflecting a slight decrease in the overall request to $20 millon. In September 2009, PacifiCorp fied a
settlement stipulation with the OPUC reducing the requested increase to $4 millon, or an average price increase of less thn 1%. In
October 2009, the OPUC issued an order approving the settlement stipulation. In November 2009, PacifiCorp fied the final net power
costs update forthe TAM, based on the latest forward price cure. The final update shows a net power costs increase of $4 milion, or
an average price increase of less than i %. The effective date for the TAM was Januar i, 20 i O.
In April 2009, PacifiCorp filed a general rate case with the OPUC requesting an annual increase of $92 milion. In August 2009, the
requested annual increase was reduced to $83 milion. In September 2009, PacifiCorp fied a settlement stipulation with the OPUC
fuher reducing the proposed annual increase to $42 milion, or an average price increase of 4%. The stipulation agreement also
includes thee tariff riders to collect an additional $8 milion over a thee-year period associated with varous cost initiatives. In
Januar 2010, the OPUC approved the stipulation effective February 2, 2010.
In Februar 2010, PacifCorp made the initial fiing for the anual TAM with the OPUC for an annual increase of $69 milion to
recover the anticipated net power costs forecasted for calenda year 2011. The rates in the TAM fiing will be effective Januar i,
201 i and are subject to updates throughout the proceeding.
In March 2010, PacifiCorp fied a general rate case with the OPUC requesting an annual increase of $13 i milion, or an average price
increase of 13%. If approved by the OPUC, the rates wil be effective Januar 1,2011.
For a discussion ofSB 408, refer to Note 5 of Notes to Financial Statements in this Form No.1.
Wyoming
In July 2008, PacifiCorp fied a general rate case with the WPSC requesting an annual increase of$34 million with an effective date
of May 24,2009. Power costs were excluded from the filing and were addressed separately in PacifiCorp's anual PCAM application
fied in Febru 2009. In October 2008, the general rate case request was reduced by $5 milion, to $29 milion, to reflect a change in
the in-service date of the High Plains wind-powered generating facilty. In March 2009, a settlement agreement was fied with the
WPSC revising the requested increase in Wyoming rates to $18 million anually beginning May 24, 2009, for an average overall
price increase of 4%. Following public heargs in March 2009, the WPSC issued a fmal order approving the stipulation agreement in
May 2009.
In Febru 2009, PacifiCorp filed its annual PCAM application with the WPSc. The PCAM application requested recovery of the
difference between actual net power costs and the amount included in base rates, subject to certin limitations, for the period
December i, 2007 th(),~gh November 30,2008, and established for the first time an adjustment for the difference between forecasted
net power costs and the amount included in base rates for the period December i, 2008 through November 30, 2009. In the 2009
PCAM application, PacifiCorp requested a $2 milion reduction to the current annual surcharge rate based on the results for the
twelve-month period ended November 30,2008, as well as a $16millon increase to the annual surcharge rate for the forecasted
twelve-month period ending November 30, 2009, resulting in a net increase to the annual surcharge rate of $14 million on a combined
basis. In March 2009, the WPSC approved PacifiCorp's motion to implement an interim rate increase of$7 million, effective April i,
2009 consistent with the interimPCAM increase agreed to in the 2008 general rate case settlement agreement. In July 2009, a
stipulation agreement was signed by the major parcipants in the case requestig that the April 2009 interi rate increase become the
permanent rate for the entire amortzation period through March 31, 20 i 0, effectively reducing the net increase of $ i 4 milion sought
in the application to $7 million, or an average price increase of 1%. In August 2009, the WPSC held a public hearig to consider the
stipulation agreement, and after considering the evidence, the WPSC issued a bench decision approving the stipulation effective
September 1,2009.
IFERC FORM NO.1 (ED. 12-96)Page 109.12
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/14/20-10 2009/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
In October 2009, PacifiCorp filed a general rate case with the WPSC requesting a rate increase of $71 million. Power costs are
included in the general rate case, reflecting increased coal costs and the expiration of low cost long-term power purchase contrcts.
The application is based on a test period endig December 31, 2010. Two regulatory policy issues related to the tax treatment of
equity AFUDC and the accounting for coal strpping costs ar included in the case, which if approved by the WPSC, would reduce
the requested rate increase by $9 millon to an overll requested increase of $62 million, or an average price increase of 12%. The
application requests a rate effective date of August 1, 2010. In March 2010, a multi-part stipulation was filed with the WPSC
agreeing to an overall rate increase of $36 millon, or an average price increase of 7%, to be implemented in two phases. If the
stipulation is approved by the WPSC, the firt phase, consisting of a $26 millon increase, will be effective July 1, 2010 and the
second phase, consisting of the remaining $10 millon increase, will be effective Februry 1, 2011. The WPSC has scheduled public
heargs for April 2010.
In Januar 2010, PacifiCorp filed its anua PCAM application with the WPSC requesting recovery of $8 milion in deferred net
power costs. In March 2010, a multi-par stipulation was fied with the WPSC agreeing to reduce the requested recovery to
$4 milion with an effective date of April 1,2010. The stipulation is subject to approval by the WPSC.
In April 2010, PacifiCorp filed an application with the WPSC requesting approval of a new ECAM to replace the existing PCAM,
which is set to expire in November 2010.
Washington
In Febrary 2008, PacifiCorp filed a general rate case with the WUC for an anual increase of $35 milion. In August 2008,
PacifiCorp fied with the WUTC an all-par settlement agrement in which the pares agreed to an overall rate increase of
$20 milion, or 9%. The settlement was approved by the WUC in October 2008 with the new rates effective October 15, 2008. The
increase is composed of an $ 1 8 millon increase to base rates, as well as a $2 milion annual surcharge for approximately thee years
related to recovery of higher power costs incured in 2005 due to poor hydroelectrc conditions. PacifiCorp agreed to drop the curent
proposal for a generation cost adjustment mechanism and fuher commtted not to propose such a mechanism in the next general rate
case.
In Februar 2009, PacifiCorp filed a general rate case with the WUTC for an anual increase of $39 milion. The filing included a
request to begin collection ofa deferrl for costs associated with the 520-MW Chehalis natual gas-fired generating facilty prior to its
inclusion in rate base beginning in Januar 2010. The associated costs are estimated at $15 millon. PacifiCorp has proposed to
recover these costs through an extension of its hydroelectrc deferal mechanism, thereby not affectig curent customer rates. In
August 2009, PacifiCorp filed an all-par settlement agreement proposing an annual increase of $14 milion, or an average price
increase of 5%. In December 2009, the WUTC approved the all-par settlement agreement. The new rates became effective
Januar 1,2010.
Idaho
In September 2008, PacifiCorp fied a general rate case with the IPUC for an annual increase of $6 million. In February 2009, a
settlement signed by PacifiCorp, the IPUC staff and intervening pares was fied with the IPUC resolving all issues in the 2008
general rate case. The agreement stipulated a $4 milion increase, or an average price increase of3%, for non-contract retail customers
in Idaho. As par of the stipulation, intervening pares acknowledged that PacifiCorp's acquisition of the 520-MW Chehalis natual
gas-fired generatig facility was prudent and the investment should be included in PacifiCorp's revenue requirement, and that
PacifiCorp had demonstrated that its DSM programs are prudent. The pares also agreed on a base level of net power costs for any
futue ECAM calculati~ms. In April 2009, the IPUC issued an order approving the stipulation effective April 18,2009.
In June 2009, an agreement was reached with pares to the ECAM docket allowing for the implementation of an ECAM to recover
the difference between the base level of net power costs recoveed in rates and actual costs incured, subject to the calculation
methodology of the mechanism. In September 2009, the IPUC issued an order approving the ECAM stipulation as fied with an
effective date of July 1, 2009. In Februar 2010, PacifiCorp filed an ECAM application with the IPUC requestig recovery of
$2 millon in deferred net power costs. In March 2010, the IPUC issued an order approving PacifiCorp's ECAM application for
recovery of$2 millon effective April 1,2010.
I FERC FORM NO.1 (ED. 12-96)Page 109.13
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(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/14/2010 2009/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued).
..
California
In February 2009, PacifiCorp filed a PTAM - capital additions with the CPUC for major capital additions amounting to a rate
increase of $1 milion, or an average price increase of 2%. The fiing. included the addition of four major renewable resources: the
99-MW Seven Mile Hil, the 99-MW Glenrock, the 39-MW Glenock II and the 99-MW Rolling Hils wind-powered generating
facilties. The rates became effectve March 19, 2009. In October 2009, PacifiCorp fied aPTAM - capital additions with the CPUC
for major capital aacìitions amounting to a rate increase of$l milion, or an average price increase of 1%. The fiing included the
addition of two major renewable resources: the 99-MW High Plains and the 28-MW McFadden RidgeI wind-powered generating
facilities: The rates became effective November 21,2009.
In Februar 2009, PacifiCorp filed an application to extend its PTAM. - atttion (an adjustment for infation) though 2010 and to
delay filing its next general rate caseby one year. The application was approved by the CPUC in April 2009. In October 2009,
PacifiCorp filed its annual PTAM - atttion with the CPUC. The filing requested an incrèaseof $1 milion, or an average price
increase oft %. The rates became effective January 1,2010.
In July 2009, PacifiCorp made its annual fiing under the ECAC requesting a rate reduction of $5 milion, or an averagè price
decrease of 5%, due to a decrease in net power costs. In December 2009, the CPUC approved the ECAC with an effective date of
Januar 1,2010.
In November 2009, PacifiCorp fied a general rate case with the CPUC requesting an annual increase of $8 milion, or an average
price increase of 10%. If approved by the CPUC, the rates wil be effective Januar 1, 2011.
In March 2010, PacifiCorp fied an application with the CPUC for authorization to offer PacifiCorp's California customers a solar
incentive program that would pay incentives to customers for installng solar photovoltaic equipment at their homes or businesses.
The program would be fuded through a new surcharge designed to collect the proposed anual program budget of approximately
$1 milion, or an average price increase of 1 %. Funds collected through the surcharge would only be used to pay customer incentives
and cover the admistrtive costs associated with the program. PacifiCorp has requested an effective date of August 2,2010.
In March 2010, PacifiCorp filed an advice fiing with the CPUC that would allow PacifiCorp to complete the transition of certain
Klamth irrigation customers from contract rates to full taff rates as agreed to as part of the 2005 California general rate case. If
approved by the CPUC, the change will result in an anual rate increase of $1 milion effective April 17, 2010.
Environmental Laws and Regulation
PacifiCorp is subject to federal, state and local laws and regulations regarding air and wate quality, hazardous and solid waste
disposal, protected species and other environmental matters that have the potential to impact PacifiCorp' s curent and futue
operations. In addition to imposing continuing compliance obligations, these laws and regulations provide authority to levy substatial
penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are admnistered by the
EPA and varous other state and local agencies. All such laws and regulations are subject to a range of interpretation, which may
ultimately be resolved by the cours. Environmental laws and regulations contiue to evolve, and PacifiCorp is unable to predict the
impact of the changing laws and regulations on its operations and financial results. PacifiCorp believes it is in material compliance
with all applicable laws and regulations.
Clean Air Standards
The Clean Air Act is a federal law, administered by the EPA, that provides a framework for protecting and improvig the nation's air
quality and controllng sources of air emissions. The. implementation of new standards is generally outlined in State Implementation
Plans ("SIPs"). SIPs, which are a collection of regulations, programs and policies to be followed, are subject to public hearngs, must
be approved by the EPA and var by state. Some states may adopt additional or more strngent requirements than those implemented
by the EPA. The major Clean Air Act programs, which most directly affect PacifiCorp's operations, are described below.
I FERC. FORM NO.1 (EO. 12-96)Page 109.14
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(1) ~ An Original (Mo, Da, Yr)
PaclfiCorp (2) A Resubmission 04/14/2010 2009104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
National AmbientAir Quality Standards
Under the authority of the Clean Air Act, the EPA sets miimum national ambient air quality standards for six principal pollutants,
consisting of carbon monoxide, lead, nitrogen oxide (''N0x''), pariculate matter, ozone and sulfur dioxide ("SUi'), considered
harl to public health and the environment. Areas that achieve the stadards, as determined by ambient air quality monitoring, are
characterized as being in attinent, while those that fail to meet the standards are designated as being nonattinment areas.
Generally, sources of emissions in a nonattinment area that are determined to contrbute to the nonattinment are required to reduce
emissions. Most air quality standards require measurment over a defied period of time to determine the average concentration of the
pollutant present.
On December 14,2009, the EPA designated the Uta counties of Davis and Salt Lake, as well as portons of Box Elder, Cache,
Tooele, Uta and Weber counties, to be in nonattinment of the fme parculate mattr stadad. This designation has the potential to
impact PacifiCorp's Little Mountain, Lae Side and Gadby facilities, dependig on the requirements to be established in the Utah
SIP. The impact on the PacifiCorp facilties is not anticipated to be significant.
In Januar 2010, the EPA proposed a rule to strengten the national ambient air quality standad for ground level ozone. The
proposed rule arses out of legal challenges claiming that the March 2008 rule that reduced the standad from 80 pars per bilion to 75
pars per bilion was not strct enough. The new rule proposes a stadad between 60 and 70 pars per bilion. The EPA expects to
issue final stadads later in 2010 with SIPs submitted in 2013.
In Januar 2010, the EPA fmalized a one-hour air quality stadad for nitrogen dioxide at 0.10 par per millon. State attainent
designations must be submittd to the EPA by Janua 1,2011 and the EPA must finalize the designations by January 1,2012.
In Novembe 2009, the EPA proposed a new national ambient air quality stadad for S02 to a level of between 50 and 100 pars per
bilion measured over one hour. The existig priar stadads for S02 are 140 part per billon measured over 24 hours and 30 pars
per bilion measured over an entire year. The EPA is under a consnt deree to tae final action on the proposed standards by
June 2010.
If the strcter standards are implemented, the number of counties designated as nonattinent areas may increase. Businesses
operating in newly designated nonattinent counties could face inreased regulation and costs to monitor or reduce emissions. For
instance, existing major emissions sources may have to install reasonably available control technologies to achieve certain reductions
in emissions and undertke additional monitorig, recordkeeping and reortng. The constrction or modification of facilties that are
sources of emissions could become more diffcult in nonattint areas. Until the EPA issues the fmal rules and any legal challenges
. are settled, the impacts on PacifiCorp cannot be determned.
I FERC FORM NO. 1 (ED. 12-96)Page 109.15
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Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
CleanAir Mercury Rule
The Clean Air Mercury Rule ("CAM"), issued by the EPA in March 2005, was the United States' fit attempt to regulate mercur
emissions from coal-fired generating facilities through the use of a market-based cap-and-trde system. The CAMR, which mandated
emissions reductions of approximately 70% by 2018, was overtrned by the United States Cour of Appeals for the Distrct of
Columbia Circuit ("D.C. Circuit") in Februar 2008. The EPA plans to propose a new rule that wil require coal-fied generating
facilities to reduce mercur emissions by utilizing a mandated "Maximum Achievable Control Technology" rather than a
cap-and-trde system. Under a consent decree, the EPA must issue a proposed rule to regulate mercur emission by March 2011 and a
fmal rule no later than November 2011. If adopted, the new rule wil likely result in incremental costs to install and maintain mercury
emissions control equipment at each ofPacifiCorp's coal-fired generating facilities and would increase the cost ofprovidlg service
to customers. Until the EPA issues the proposed and fmal rules, the impacts on PacifiCorp cannot be deterned.
Clean Air Interstate Rule
The EPA promulgated the Clean Air Interstate Rule ("CAIR") in March 2005 to reduce emissions of NOx and S02, precursors of
ozone and parculate matter, from down-wind sources. The CAI required states in the eastern United States to reduce emissions by
implementing a plan based on a market-based cap-and-trade system, emission reductions, or both. The CAIR created separate trading
programs for NOx and S02 emission credits. The NOx and S02 emissions reductions were planned to be accomplished in two
phases, in 2009-2010 and 2015.
In July 2008, a three-judge panel of the D.C. Circuit issued a unanimous decision vacatig the CAIR. In December 2008, the D.C.
Circuit issued an opinion remanding, without vacating, the CAIR back to the EPA to conduct proceedings to fix the flaws in CAIR
consistent with the D.C. Circuit's July 2008 ruling. The D.C. Circuit did not impose a schedule for completion on the EPA in its
ruling, and the EPA informed the D.C. Circuit that development and finalization of a replacement rule could take approximately two
years.
PacifiCorp's generating facilities are not subject to the CAIR. The impact of the replacement rule cannot be determined until the EPA
issues its final rule. It is possible that the existig CAIR may be replaced with more strngent requirements to reduce S02 and NOx
emissions and that these requirements could be extended to the wester United States through regulation or legislation such as the
Clean Air Act Amendments of 2010, introduced in Februar 2010 by Senators Tom Carer and Lamar Alexander. However, the
provisions are not anticipated to have a material impact on PacifiCorp.
Regional Haze
The EPA has initiated a regional haze progrm intended to improve visibility in designated federally protected areas ("Class I areas").
Some ofPacifiCorp's generating facilities meet the threshold applicability criteria under the Cleaii Air Visibilty Rules. In accordance
with the federal requirements, states were required to submit SIPs by December 2007 to demonstrate reasonable progress towards
achieving naturl visibility condItions in Class I areas by requirg emission controls, known as best available retrofit technology, on
sources constrcted between 1962 and 1977 with emissions that are anticipated to cause or contrbute to impairent of visibilty.
Wyoming has not yet submitted its SIP. Wyoming issued best available retrofit technology permts to PacifiCorp on December 31,
2009, requirng PacifiCorp to implement emission control projects that are consistent with the planned emission reduction projects at
PacifiCorp's Wyoming generating facilities. PacifiCorp has appealed certin provisions of the Naughton and Jim Bridger generating
facilities' permts. Utah submitted its SIP and suggested that the emission reduction projects planned by PacifiCorp are suffcient to
meet its initial emission reduction requirements. In January 2009, the EPA made a finding that 37 states, including Wyoming, had
failed to file a SIP that met some or all of the basic regional haze program requirements. As a result, Wyoming has two years from
Januar 2009 to fie and obtain the EPA's approval of a. SIP that meets all of the regional haze progrm requirements or the state wil
be subject to a federal implementation plan administered by the EPA. PacifiCorp believes that its planned emission reduction projects
wil satisfy the regional haze requirements in Uta and Wyoming. It is possible that additional controls may be required after the
respective SIPs have been submitted and approved or that the timing of installation of planned controls could change.
I FERC FORM NO. 1 (ED. 12-96)Page 109.16
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(1 ) ~ An Original (Mo, Oa, Yr)
PacifiCorp 1(2)A Resubmission 04/14/2010 2009/Q4
IMPORTANT CHANGES DURING THE QUARTER/EAR (Continued)
New Source Review
Under existing New Source Review ("NSR") provisions of the Clean Air Act, any facilty that emits regulated pollutants is required
to obtain a permit from the EPA or a state regulatory agency pnor to (a) begiing constrction of a new major stationary source of a
regulated pollutant or (b) maing a physical or operational change to an existig stationar source of such pollutats that increases
certin levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and
replacement of equipment). In general, projects subject to NSR regulations require pre-constrction review and permittig under the
Prevention of Significant Detenoration ("PSD") provisions of the Clean Air Act. Under the PSD program, a project that emits
threshold levels of regulated pollutants must undergo an analysis to determine the best available control technology and evaluate the
most effective emissions controls after consideration of a number of factors. Violations of NSR regulations, which may be alleged by
the EPA, states, environmental groups and others, potentially subject a company to matenal fmes and other sanctions and remedies,
including installation of enhanced pollution controls and fuding of supplemental environmental projects.
As part of an industr-wide investigation to assess compliance with the NSR and PSD provisions, the EPA has requested information
and supporting documentation from numerous utilities regardig their capital projects for vanous generatig facilities. A NSR
enforcement case against an unelated utility has been decided by the United States Supreme Cour, holding that an increase in the
annual emissions of a generating facility, when combined with a modification (i.e., a physical or operational change), may trgger
NSR permtting. Between 2001 and 2003, PacifiCorp responded to requests for information relating to capital projects at its
generatig facilities. PacifiCorp has been engaged in penodic discussions with the EPA over severl years regarding PacifiCorp's
historical projects and their compliance with NSR and PSD provisions. Final resolution has not been achieved. PacifiCorp cannot
predict the outcome of its discussions with the EPA at this tie; however, PacifiCorp could be required to install additional emissions
controls and incur additional costs and penalties in the event it is determned that PacifiCorp's histoncal projects did not meet all
regulatory requirements.
Numerous changes have been proposed to the NSR rules and regulations over the last several years. In addition to the proposed
changes, diffenng interpretations by the EPA and the cour, and the recent change in admstrtion, create nsk and uncertinty for
entities when seeking permits for new projects an installing emssion controls at existing facilities under NSR requirments.
PacifiCorp monitors these changes and interrettions to enur perittg activities are conducted in accordance with the applicable
requirements.
Climate Change
The increased global attention to climate change has resulted in significant measures being proposed at the federal level to regulate
greenhouse gas ("OHO") emissions. The United States Congress and federal policy makers, with President Obama's support, are
considenng comprehensive climate change legislation such as the Amencan Clean Energy and Secunty Act of 2009
("Waxman~Markey bil"), which includes a maket-based cap-and-trade progr that is intended to reduce OHO emissions 83%
below 2005 levels by 2050. In December 2009, the EPA published its findings that OHO emissions theaten the public health and
welfare, and it is pursuing regulation of OHO emssions under the Clea Ai Act. In early 2010, legislation and resolutions were
introduced in the United States Congress that would disapprove the fidigs submittd by the EPA and clarify that the United States
Congress did not intend to regulate OHO emissions under the Clea Air Act. To date, two bils, one by Representative Early Pomeroy
and one by Representatives Ike Skelton, Colln Peterson and Jo An Emeron, have bee introduced in the United States House of
Representatives seeking to amend the Clean Air Act to preclude the EPA from regulatig OHO emissions under the Clean Air Act. In
addition, a disapproval resolution has been intruced by Sentor Lisa Murkowski and others in the United States Senate
disapproving the EPA's OHO endagerment finding. Litigation has also been filed in the D.C. Circuit challenging the EPA's ORO
endangerment finding, including an action by twelve member of the United States House of Representatives. An additional 15
lawsuits have been filed by states, vanous industr groups, and others, petitioning the cour for review of the endangerent fmding.
PacifiCorp support the implementation of reasonable emissions caps, but opposes the trading mechanism as imposing additionàl
costs that do not result in decreased emissions. PacifiCorp also believes that any law or regulation should provide a reasonable
transition penod to allow the phase in of low-carn generating technologies tht will achieve sustainable and cost-effective OHO
emissions reduction benefits.
Ii=ERC FORMNO. 1 (ED. 12-96) Page 109.17
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(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/04
IMPORTANT CHANGES DURING THE OUARTERll:AR (Continued)
..
While the debate continues at the federal and international level over the direction of climate change policy, several states have
developed or are developing state-specific laws or regional legislative initiatives to report or mìtigate GHG emìssions. In addition,
governental, non-governental and environmental organizations have become more active in pursuing . litigation under existing
laws.
PacifiCorp voluntarily reports its GHG emìssions to the California Climate Action Registr and Th Climate Registr. In September
2009, the EPA issued its final rule regarding mandatory reportng of GHG ("GHG Reporting") beginning Janua 1, 2010. Under
GHG Reportng, suppliers of fossil fuels, manufactuers of vehicles and engines, and facilities that emit 25,000 metrc tons or more
per year ofGHG emìssions are required to submìt annual reports to the EPA. PacifiCorp is subject to this requirement and wil submit
its fist report by March 31, 2011.
PacifiCorp is committed to operating in an environmentally responsible maner. Examples ofPacifiCorp's significant investments in
programs and facilities that wil mitigate its GHG emissions include:
. PacifiCorp is the second largest owner of wind-powered generation capacity in the United States among rate-regulated
utilities. Over the last three year, PacifiCorp has added 787 MW of owned wind generation capacity at a total cost of
$1.6 bilion to its portolio of generating assets. PacifiCorp curently owns 921 MW of wind-powered generation capacity,
excluding its 111-MW Dunlap Ranch I wind-powered generatig facility that is curently under constrction. Additionally,
PacifiCorp has purchase power agreements with 705 MW of wind-powered generation capacity. Other renewable resources
owned or contracted total an incremental capacity of 105 MW.
. PacifiCorp owns 1,158 MW of hydroelectrc generation capacity.
. PacifiCorp's Energy Gateway Transmìssion Expansion Progranirepresents a plan to build approximately 2,000 miles of new
high-voltage transmission lines at a cost exceeding $6 bilion. The plan includes several trsmission line segments that wil:
(a) address customer load growth; (b) improve system reliability; (c) reduce transmission system constraints; (d) provide
access to diverse resource areas, including renewable resources; and (e) improve the flow of electrcity thoughout
PacifiCorp's six-state service area and the Western United States.
. PacifiCorp has offered customers a comprehensive set of DSM programs for more than 20 years. The programs assist
customers to manage the timing of their usage, as well as to reduce overall energy consumption, resulting in lower utility
bils.
The impact of pending federal, regional, state and international accords, legislation, regulation, or judicial proceedings related to
climate change canot be quantified in any meaningful range at this time. New laws, regulations or rules limitig GHG emìssions
could have a material adverse impact on PacifiCorp, the United States and the global economy. Companies and industries with higher
GHG emissions, such as utilties with significant coal-fired generatig facilities, wil be subject to more direct impacts and greater
financial and regulatory risks. The impact is dependent on numerous factors, none of which can be meaningfully quantified at this
time. These factors include, but are not limited to, the magnitude and tiing of GHG emissions reduction requirements; the design of
the requirements; the cost, availability and effectiveness of emìssion control technology; the price, distrbution method and
availabilty of offsets and allowances used for compliance; governent-imposed compliance costs; and the existence and natue of
incremental cost recovery mechanisms. Examples of how new laws and regulations may impact PacifiCorp include:
IFERC FORM NO.1 (ED. 12-96) Page 109.18
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(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04L14/2010 2009/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
· Additional costs may be incured to purchase required emission allowances under the proposed market-based cap-and-trade
system in excess of allocations that are received at no cost. These purchases would be necessary until new technologies could
be developed and deployed to reduce emissions or lower carn generation is available;
· Acquirig and renewing constrction and operating perits for new and existing facilities may be costly and diffcult;
· Additional costs may be incured to purhase and deploy new generatig technologies;
· Costs may be incured to retire existing coal facilities before the end of thir otherwise useful lives or to conver them to bur
fuels, such as natul gas or biomass, that result in lower emissions;
· Operating costs may be higher and unit outputs may be lower; and
· Higher interest and financing costs and reduced access to capital markets may result to the extent that fmancial markets view
climate change and GHG emissions as a fmancial risk.
PacifiCorp expects it wil be allowed to recover prudently incured costs to comply with climate change requirements.
The impact of events or conditions caused by climate change, whether from natul processes or human activities, could var widely,
from highly localized to worldwide, and the extent to which a utility's opertions may be affected is uncertain. Climate change may
cause physical and fmancial risk though, among other things, sea level rise, changes in precipitation and extreme weather events.
Consumer demand for energy may increase or decrease, based on overll changes in weather and as customers promote lower energy
consumption through the continued use of energy effciency progrs or other means. Availability of resources to generate
electrcity, such as water. for hydroelectrc production and cooling puroses, may also be impacted by climate change and could
influence PacifiCorp's existing and futue electrcity generation portfolio. These issues may have a direct impact on the costs of
electrcity production and increase the price customers payor their demand for electrcity.
International Accords
The December 2009 Copenagen Accord called on offcials from developed nations to voluntary commt to quantified
economy-wide emissions tagets for 2020 by Janua 31, 2010. In Januar 2010, the Obama administration formally declared its
desire to be associated with the Copenhagen Accord, informng the United Nations Fraework Convention on Climate Change of the
goal of reducing United States GHG emissions approximately 17% from 2005 levels by 2020, contingent upon the enactment of
United States energy and climate change legislation. The United States' goal is not binding or enforceable absent from fuher action
by the United States Congress to enact climate change legislation.
;federal Legislation
In June 2009, the United States House of Representatives passed the Waxman-Markey bilL. In addition to a federal renewable
portfolio standard, which would require utilities to obtan a porton of their energy from certin qualifying renewable sources and
energy effciency measures, the bil requires a reduction in GHG emssions begiing in 2012, with emission reduction tagetsof3%
below 2005 levels by 2012; 17% below 2005 levels by 2020; 42% below 2005 levels by 2030; and 83% below 2005 levels by 2050
under a cap-and-trade program. In September 2009, a simlar bil was intruced in the United States Senate by Senators Barbara
Boxer and John Kerr, which would require a reduction in GHG emissions begiing in 2012 with emssion reduction targets
consistent with the Wax-Markey bil, with the exception of the 2020 taget, which requires 20% reductions below 2005 levels.
IFERC FORM NO.1 (ED. 12-96)Page 109.19
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(1) ó An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/04
I..IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
Greenhouse Gas Tailoring Rule
The EPA published a proposed GHG "tailoring rule" in October 2009 that would require sources of GHG emissions in excess of
25,000 tons of carbon dioxide ("C02") equivalent to conduct a determination of best available control technology under the PSD
provisions for new and modified sources. In addition, the proposal would require sources of C02 equivalent emissions of25,000 tons
or more to obtain a Title V operating permit or incorporate 'GHG emissions into existing sources' Title V pelmts when they are
renewed. The EPA is curently working to fmalize the rules with an anticipated effective date for stationar sources beginning in
2011. Until final rules are issued, PacifiCorp cannot determne the impact on its facilities. Several organizations have indicated that
they intend to challenge the EPA's final GHG tailoring rule.
Regional and State Activities
Several states have developed state-specific laws or regional legislative initiatives to report or mitigate GHG emissions that are
expected to impact PacifiCorp, including:
. The Western Climate Initiative, a comprehensive regional effort to reduce GHG emissions by 15% below 2005 levels by
2020 through a cap-and-trade progr that includes the electrcity sector. The Western Climate Initiative includes the states
of California, Montaa, New Mexico, Oregon, Utah and Washington and the Canadian provinces of British Columbia,
Manitoba, Ontao and Quebec. The state and provincial parters have agreed to begin reporting GHG emissions in 2011 for
emissions that occur in 2010. The first phase of the cap-and-trade progrm will begin on Januar 1,2012.
. An executive order signed by California's governor in June 2005 would reduce GHG emissions in that state to 2000 levels
by 2010, to 1990 levels by 2020 and 80% below 1990 levels by 2050. In addition, Californa has adopted legislation that
imposes a GHGemission pedormance standad to all electrcity generated within the state or delivered from outside the state
that is no higher than the GHG emission levels of a state-of-the-ar combined-cycle natual gas-fired generating facilty, as
well as legislation that adopts an economy-wide cap on GHG emissions to 1990 levels by 2020. An effort is curently
underway to gather a suffcient numer of signatues to institute a California ballot initiative, referenced as the "California
Jobs Initiative", which seeks to place before the voters a requirement to suspend GHG regulations promulgated under
California's GHG emission reduction legislation (Assembly Bil 32) until California's unemployment rate is lowered to
5.5%.
. Over the past thee years, the states of California, Washington and Oregon have adopted GHG emissions performance
standards for base load electrical generating resources. Under the laws in all three states, the emissions pedormance
standads provide that emissions must not exceed 1,100 Ibs of C02 per megawatt hour ("MW"). These GHG emissions
pedormance standads generally prohibit electrc utilties from enterig into long-term fmancial commitments (e.g., new
ownership investments, upgrades, or new or renewed contracts with a term of five or more years) unless any base load
generation supplied under long-term fmancial commitments comply with the GHG emissions pedormance standads.
. The Washington and Oregon governors enacted legislation in May 2007 and August 2007, respectively, establishing goals
for the reduction ofGHG emissions in their respective states. Washington's goals seek to (a) reduce emissions to 1990 levels
by 2020; (b) reduce emissions to 25% below 1990 levels by 2035; and (c) reduce emissions to 50% below 1990 levels by
2050, or 70% below Washington's forecasted emissions in 2050. Oregon's goals seek to (a) cease the growth of Oregon
GHG emissions by 2010; (b) reduce GHG levels to 10% below 1990 levels by 2020; and (c) reduce GHG levels to at least
75% below 1990 levels by 2050. Each state's legislation also calls for state governent to develop policy recommendations
in the future to assist in the monitoring and achievement of these goals.
Greenhouse Gas Litigation
PacifiCorp closely monitors ongoing environmental litigation. Many of the pendig cases described below relate to lawsuits against
industr that attempt to link GHG emissions to public or private har. PacifiCorp believes the cases are without mert, despite recent
decisions where United States Cour of Appeals reversed distrct cour rulings dismissing the cases in 2009. The lower cours initially
IFERC FORM NO.1 (ED. 12-96)Page 109.20
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.IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
refrìned from adjudicating the cases under the "political question" doctre, beause oftheìr ìnhêrently political natue. Neverteless,
an adverse rulìng ìn any of these cases would lìkely result ìn ìncreased regulation ofGHG eintters, ìhcluding PacìfiCorp's generatig
facìlties, and financìal uncertìnty.
In September 2009, the Unìted States Cour of Appeals for the Second Cìrcuìt (the "Second Cìrcuìt") ìssued ìts opìnìon ìn the case of
Connecticut v. American Electric Power, et aI, whìch remanded to the lower cour a nuìsance actìon by eìght states and the Cìty of
New York agaìnst five large utilìty emìtters of C02. The Unìted States Dìstrct Cour for the Southern Dìstrct of New York (the
"Southern Dìstrct of New York") dìsmìssed the case ìn 2005, holdìng that the claìm that GHG einssìons from the defendats'
coal-fueled generatìng facìlties were causìng har clìmate change and should be enjoìned as a publìc nuìsance under federal
common law presented a poIìtical questìon that the cour lacked jursdiction to decìde. The Second Cìrcuìt rejected thìs conclusìon
and stated the Southern Dìstrct of New York was not precluded from deterìng the case on ìts merits.
In October 2009, a thee judge panel ìn the Unìted States Cour of Appeals for the Fìft Cìrcuìt (the "Fìfth Cìrcuìt") ìssued ìts opìnìon
ìn the case of Ned Comer, et al. v. Murphy Oil USA, et al., a putative class action lawsuìt agaìnst ìnsurance, oìl, coal and chemìcal
companìes, based on claìms that the defendats' GHG einssìons contrbuted to global warìng that ìn tu caused a rise ìn sea levels
and added to the ferocìty of Hurcane Katra, whìch combìned to dage the plaìntiffs private propert, as well as publìc propert.
In 2007, the Unìted States Dìstrct Cour for the Southern Dìstrct of Mìssìssìppì (the "Southern Dìstrct of Mìssìssìppì") disinssed the
case based on the lack of stadìng and fuer held that the claìms were bared by the polìtical questìon doctrne. The Fìfth Cìrcuìt
reversed the lower cour decìsìon and held that the plaìntìffs had standìng to asser theìr publìc and private nuìsance, trespass and
neglìgence claìms, and concluded that the claìm dìd not present a politìcal questìon. The case was remanded to the Southern Dìstrct
of Mìssìssìppì for further proceedìngs wìth the cour notìng that ìt had not deterined, and would leave to the lower cour to analyze,
whether the alleged chaìn of causatìon satisfies the proxìmate cause requìrement under Mìssìssìppì state common law.
In October 2009, the Unìted States Dìstrct Cour for the Norter Dìstrct of Calìfornìa (the "Northern Dìstrct of Californìa")
granted the defendats' motions to dìsinss ìn the case of Native Vilage of Kivalina v. ExonMobil Corporation, et al. The plaìntìffs
fied theìr complaìnt ìn Febru 2008, assertìng claìm agaìnst 24 defendats, ìncludig electrc generating companìes, oìl companìes
and a coal company, for publìc nuìsance under state and federal common law based on the defendats' GHG einssìons. MEHC was a
named defendant ìn the Kivalina case. The Northern Dìstrct of Californìa dìsinssed all of the plaìntìffs' federal c1aìms, holdìng that
the cour lacked subject matter jursdìctìon to hear the c1aìms under the political questìon doctrne, and that the plaìntiffs lacked
stadìng to brng theìr claìms. The Nortern Dìstrct of Californìa declìned to hear the state law claìm and the case was dìsinssed
wìth prejudìce to theìr future presentatìon ìn an appropriate state cour.
Severallawsuìts have also been fied agaìnst goverental agencìes, most notably Massachusetts v. EPA. In April 2007, ìn
Massachusetts v. EPA, the Unìted States Supreme Cour found that GHG are aìr pollutats and are covered by the Clean Aìr Act. The
Unìted States Supreme Cour decìsìon resulted from a petition for rulemakng fied by more than a dozen envìronmental, renewable
energy and other organìzations. The cour held that the EPA must deteìne whether or not GHG emìssìons contrbute to aìr pollutìon
whìch may reasonably be antìcìpated to endanger publìc health or welfar, or whether the scìence ìs too uncertìn to make a reasoned
decìsìon. In December 2009, the EPA detered that GHG einssìons ìn the atmosphere threaten the public health and welfare of
curent and futue generatìons and ìs pursuìng regulation of GHG einssìons under the Clean Aìr Act. Unless siiperseded by
congressìonal action, the EPA ruling ìs lìkely to lead to strcter einssìon lìmts.
Renewable Portfolio Standards
The renewable portfolìo standads" ("RPS") descrbed below could sìgnìficantly ìmpact PacìfiCorp's financìal results. Resources that
meet the qualifyng electrcìty requìrements under the RPS var from state to state. Each state's RPS requìres some form of
complìance reportìng and PacìfiCorp can be subject to penalties ìn the event of noncompliance.
In November 2006, Washìngton voters approved a ballot ìnìtiative establishìng a RPS requìrement for qualifyìng electrc utilities,
ìncludìng PacìfiCorp. The requìrements are 3% ofretaìl sales by Janua 1,2012 though 2015, 9% ofretaìl sales by January 1,2016
through 2019 and 15% ofretaìl sales by Januar 1,2020. The WUC has adopted fmal rules to ìmplement the ìnìtìative.
IFERC FORM NO.1 (ED. 12-96) Page 109.21
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original .(Mo, Da, Yr)
PacifiCorp .'2) A Resubmission 04/14/2010 .2009/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
In Jùne 2007, the Oregon Renewable Energy Act ("OREA") was adopted, providing a comprehensive renewable energy policy for
Oregon. Subject to certin exemptions and cost limitations established in the OREA, PacifiCorp and other qualifying electrc utilities
must meet minimum qualifying electrcity requirements for electrcity sold to retail customers of at least 5% in 2011 through 2014,
15% in 2015 through 2019,20% in 2020 though 2024, and 25% in 2025 and subsequent years. As required by the OREA, the OPUC
has approved an automatic adjustment clause to allow an electrc utility, including PacifiCorp, to recover prudently incured costs of
its investments in renewable energy generating facilities and associated trnsmission costs.
California law requires electrc utilities to increase their procurement of renewable resources by at least 1 % of their anual retail
electrcity sales per year so that 20% of their anual electrcity sales are procured from reriewable resources by no later than
December31, 2010. In May 2008, PacifiCorp and other small multi-junsdictionalutilities ("SMJU) received fuher guidance from
the CPUC on the treatment of SMJUs in the Californa RPS progrm. In August 2008, concurent with its anual RPS compliance
fiing, PacifiCorp, joined by another SMJU, filed a Joint Motion for Review of the decision, including banking of RPS procurement
made while it awaited fuer guidance from the CPUC on the treatment of SMJUs dunng the 2004-2006 period. In May 2009, the
CPUC denied the Joint Motion for Review.
In September 2009, California's governor issued Executive Order S-21-09 requiring the California Air Resources Board to adopt a
regulation consistent with a 33% renewable electrcity energy taget established in Executive Order S-14-08 by July 31, 20 i 0 that wil
encourage the creation and use of renewable energy sources and build on the existing RPS program.
In March 2008, Utah's governor signed Utah Senate Bil 202. Among other things, this law provides that, beginning inthe year 2025,
20% of adjusted retail electrc sales of all Uta utilities be supplied by renewable energy, if it is cost effective. Retail electrc sales
wil be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon. emissions, and for sales
avoided as a result of energy effciency and DSM programs. Qualifying renewable energy sources can be located anywhere in the
WECC areas, and renewable energy credits can be used.
Water Quality Standards
The federl Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving wate quality
in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean
Water Act requires that cooling water intake strctues reflect the "best technology available for minimizing adverse environmental
impact" to aquatic organisms. InJul)' 2004, the EPA established significant new technology-based performance standads for existing
electrc generatig facilities that tae in more than 50 million gallons of water per day. These rules are aimed at minimizing the
adveÌ'e environmental impacts of cooling water intake strctues 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 remanded almost all aspects of the
rule to the EPA, without addressing whether companies with cooling water intae strctues were required to comply with these
requirements. On appeal from the Second Circuit, in April 2009, the United States Supreme Cour ruled that the EPA perissibly
relied on a cost-benefit analysis in setting the national performance stadards regarding "best technology available for minimizing
adverse enviromnental impact" at cooling water intae strctues and in providing for cost-benefit variances from those standads as
part of the §3 i 6(b) Clean Water Act PhaseU regulations. The United States Supreme Cour remanded the case back to the Second
Circuit to conduct fuher proceedigs consistent with its opinion. Compliance and the potential costs of compliance, therefore, cannot
be ascertined until such time as the Second Circuit takes action or fuher action is taken by the EPA. Curently, PacifiCorp's Dave
Johnston Plant, which has water cooling towers, exceeds the 50 milion gallons of water per day intae theshold. In the event that
PacifiCorp's existing intake strctues require modification or alternative technology required by new rules, expenditues to comply
with these requirements could be significant. PacifiCorp believes that it curently has, or has initiated the process to receive, all
required water quality pennts.
I FERC FORM NO. 1 (ED. 12-96)Psge 109.22
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
Coal Combustion Byproduct Disposal
In December 2008, an ash impoundment dike at the Tenessee Valley Authority's Kingston power plant collapsed after heavy rain,
releasing a significant amount of fly ash and bottom ash, coal combustion byproducts, and water to the surounding area. In light of
this incident, federal and state offcials have called for greater regulation of coal combustion storage and disposaL. The EPA is
curently considerig the regulation of coal combustion byproducts under the Resource Conservation and Recovery Act and a
proposed rule addressing these materials is iment. PacifiCorp operates 16 surface impoundments and six landfills that contain coal
combustion byproducts. These ash impoundments and landfills may be impacted by additional regulation, partcularly ifthe materials
are regulated as hazardous waste under Subtitle C of the Resource Conseration Act, and could pose significant addtional costs
associated with ash management and disposal activities at PacifiCorp's coal-frred generating facilties. The impact of any new
regulations on coal combustion byproducts cannot be determned at this time.
Other
Other laws, regulations and agencies to which PacifiCorp is subject include, but are not limted to:
· The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws may require
any curent or former owners or operators of a disposal site, as well as trsporters or generators of hazardous substances
sent to such disposal site, to share in environmental remediation costs. Refer to Note 13 of Notes to Financial Statements in
this Form No.1 for additional information regarding environmental contingencies.
· The federal Surace Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation
and closure standads that must be met durg and upon completion of miing activities. Refer to Note 10 of Notes to
Financial Statements in this Form NO.1 for additional informtion regardig mie reclamation obligations.
· The FERC oversees the relicensing of existig hydroelectrc systems and is also responsible for the oversight and issuance of
licenses for new constrction of hydroelectrc system, da safety inspections and environmental monitoring. Refer to
Note 13 of Notes to Financial Statements in this Form NO.1 for additional informtion regarding the relicensing of certin of
PacifiCorp's existing hydroelectrc facilities.
Future Generation and Conservation
Integrated Resource Plan
As required by certin state regulations, PacifiCorp uses an Integrted 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 timng ofPacifiCorp's expected futue resource needs and an associated optimal futue
resource mix that accounts for plang uncerinty, risks, reliabilty impacts, state energy policies and other factors. The IRP is a
coordinated effort with staeholders in each of the six states wher PacifiCorp opetes. PacifiCorp files its IRP on a biennial basis,
and for four of its six state jursdictions, receives a formal notification as to whether the IR meets the commission's IR standads
and gudelines. In May 2009, PacifiCorp filed its 2008 IR with each of its state commssions. Durg 2009, PacifiCorp received
orders from the WUTC and the IPUC acknowledging that the 2008 IR met their applicable standads and guidelines. Durng 2010,
the OPUC and the UPSC issued orders acknowledging the 2008 IR.
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 Original (Mo, Oa, Yr)
PacifiCorp 1(2). A Resubmission 04/14/2010 2009/Q4
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)....
Requests for Proposals
PacifiCorp has issued a series of separate Reqiiests for Proposals ("RFPs"), each of which focuses on a specific category of resources
consistent with the IR. The IRP and the RFPs provide for the identification and staged procurement of resources in futue ýears to
achieve a balance of load requirements and resources. As required by applicable laws and regulations, PacifiCorp fies draft RFPs
with the UPSC, the OPUCand the WUTC prior to issuance to the market. Approval by the UPSC, the OPUC or the WUTC may be
required depending on the natue of the RFPs.
In August 2009, under PacifiCorp's 2008R-l renewable resources RFP (approved by the OPUC in September 2008), PacifiCorp
executed a power purchase agreement to purchase the entire output of the proposed 200~MW Top of the World wind-powered
generatig facilty located in Wyoming. The generation of the energy and associated renewable energy credits under this agreement
are expected to commence by December 2010 and continue for a period of 20 years. PacifiCorp's Z009R renewable resources RFP
(approved by the OPUC with modification in July 2009) seeks additional cost-effective renewable generation projects with no single
resource greater than 300 MW, combined total resources of no more than 400 MW and on-line dates no later than December 31,
2012. As a result of the 2009R renewable resources RFP, PacifiCorp's 11 l-MW Dunlap Ranch I wind-powered generating facility
located in Wyoming was selected and constrction has commenced. Negotiations were also initiated with the remaining final shortist
bidder under the 2009R renewable resources RFP.
In October 2009, PacifiCorp filed a request for approval with the UPSC to re-issue the All Source RFP, which was previously
suspended in April 2009. In October 2009 and November 2009, respectively, the UPSC and the OPUC approved resumption of the
All Source RFP. The All Source RFP seeks up to 1,500 MW on a system wide basis from projects with in-service dates from 2014
through 2016. In December 2009, the All Source RFP was issued to the market. Proposals have been received under the All Source
RFP and evaluations are curently underway.
Demand-side Management
PacifiCorp has provided a comprehensive set. of DSM programs to its customers since the 1970s. The progrms are designed to
reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Curent
programs offer servces to customers such as energy engineering audits and information on how to improve the effciency of their
homes and businesses. To assist customers in investing in energy effciency, PacifiCorp offers rebates or incentives encouraging the
purchase and installation of high-effciency equipment such as lighting, heatig and cooling equipment, weatherization, motors,
process equipment and systems, as well as incentives for efficient constrction. Incentives are also paid to solicit parcipation in load
management progrs by residential, business and agrcultual customers through programs, such as PacifiCorp's residential and
small commercial air conditioner load control program and irgation equipment load control programs. Subject to random prudence
reviews, state regulations allow for contemporaneous recovery of costs incured for the DSM progrms though state-specific energy
effciency service charges paid by retail electrc customers. In addition to these DSM programs, PacifiCorp has load curilment
contracts with a number of large industral customers that deliver up to 342 MW of load reduction when needed. Recovery for the
costs associated with the large industrial load management progr is determined through PacifiCorp's general rate case process. In
2009, $106 millon was expended on the DSM programs in PacifiCorp's six-state service area, resulting in an estiated
457,000 MW of first-year energy savings and44l MW of peak load management. Total demand-side load available for control in
2009, including both load management from the large industral curilment contrcts and DSM programs, was 783 MW.
I FERC FORM NO. 1 (ED. 12-96)Page 109.24
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009/Q4 .
IMPORTANT CHANGES DURING THE QUARTERIEAR (èontinued)
Credit Ratings
PacifiCorp's senior secured and senior unsecured credit ratings are as follows:
Fitch Moody's Standard & Poor's
Senior secured debt A-A2 A
Senior unsecured debt BBB+Baal A-
Outlook Stable Stable Stable
Debt and preferreG securties of PacifiCorp are rated by the credit rating agencies. Assigned credit ratings are based on each rating
agency's assessment of PacifiCorp's abilty to, in general, meet the obligations of its issued debt. The credit ratings are not a
recommendation to buy, sell or hold securties, and there is no assurnce that a parcular credit rating wil contiue for any given
period of tie.
PacifiCorp has no credit rating-downgrde trggers that would accelerate the matuty dates of outstanding debt and a change in
ratings is not an event of default under the applicable debt instrents. PacifiCorp's unsecured revolving credit facilities do not
require the maintenance of a minimum credit rating level in order to drw upon their availabilty. However, commitment fees and
interest rates under the credit facilties are tied to credit ratigs and increase or decrease when the ratings change. A ratings
dQwngrade could also increase the futue cost of commercial paper, short- and long-term debt issuances or new credit facilities.
Cerain authorizations or exemptions by regulatory commssions for the issuance of securties are valid as long as PacifiCorp
maintains investment grade ratigs on senior secured debt. A downgrade below that level would necessitate new regulatory
applications and approvals.
In accordace with industr practice, certin agreements, includig derivative contrcts, contain provisions that require PacifiCorp to
maintain specific credit ratings on. its unsecurd debt from one or more of the major credit rating agencies. These agreements,
including dervative contrcts, may either specifically provide bilateral rights to demand cash or other securty if credit exposures on a
net basis exceed specified rating-depedent thshold levels ("credit-risk-related contingent featues") or provide the right for
counterpariesto demand "adequate assurance" in the event of a materal adverse change in PacifiCorp's creditworthiness. These
rights can vary by contract and by counterar. As of December 31, 2009, PacifiCorp's credit ratings from the thee recognized
credt rating agencies were investment gre. If all credt-risk-related contigent featues or adequate assurnce provisions for these
agreements, including derivative contract, had been trggered as of December 31,2009, PacifiCorp would have been required to post
$310 milion of additional collateraL. PacifiCorp's collatral requirements could fluctuate considerably due to market price volatility,
changes in credit ratings or other factors. Refer to Note 7 of Notes to Financial Statements included in this Form No. 1 for a
discussion ofPacifiCorp's collateral requirements specific to PacifiCorp's derivative contracts.
IFERC FORM NO.1 (ED. 12-96) Page 109.25
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp ¡ (2)A Resubmission 04/14/2010 2oo9/Q4 ..
.IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
ITEM 13.
Offcer & Director Changes
On Januar 13,2010, A. Rober Lasich accepted the position of Vice President and General Counsel, Procurement for MERC, and
accordingly resigned as President ofPacifiCorp Energy, a business unit of PacifiCorp, and as director of PacifiCorp, both effective
Febru 1, 2010.
On Januar 13, 2010, Micheal G. Dun was elected President of PacifiCorp Energy and director of PacifiCorp, both effective
Februar 1, 2010. Mr. Dunn, 44, previously served as President of Ker River Gas Transmission Company ("Kern River") since
June 2007. Prior to that, Mr. Dunn served as Vice President of Operations, Information Technologyand Engineering at Kern River.
Kern River is an indirect subsidiar ofMERC.
ITEM 14.
Not applicable.
IFERC FORM NO.1 (ED. 12-96) Page 109.26
Deloitte~Deloitt & Touche LLP
390 U.S. Bancorp Tower
111 S.W. Fifth Ave.
Portland, OR 97204-362
USA
Tel: + 1 503222 1341
Fax: + 1 5032242172
ww.deloitte.com
INDEPENDENT AUDITORS' REPORT
PacifiCorp
Portland, Oregon
We have audited the balance sheet-regulatory basis ofPacifiCorp (the "Company") as of December 31,
2009, and the related statements of income - regulatory basis; retained earings - regulatory basis; and
cash flows - regulatory basis, for the year ended December 31,2009, included on pages 110 through 123
of the accompanying Federal Energy Regulatory Commission Form i. These financial statements are the
responsibilty of the Company's management. Our responsibilty is to express an opinion on these
financial statements based on our audit.
We conducted our audit in accordance with auditing standars generally accepted in the United States of
America. Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are fre of material misstatement. An audit includes consideration of
internal control over financial reporting as a basis for designing audit procedures that are appropnatein
the circumstances, but not for the purpse of expressing an opinion on the effectiveness of the Company's
internal control over financial 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 prepar in accordance with the accounting
requirements ofthe Federal Energy Regulatory Commission as set fort 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 propneta capital of the Company as of December 31, 2009, and the results of its
operations and its cash flows for the yea ended December 31, 2009, 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 information and use of the board of directors and management of the
Company 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 parie.
Dtl~ '" T~ . LLP
March 1,2010
Member ofDeloitt Touche Tobmats
PacifiCorp
Name of Respondent This Report Is: Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/14/2010 End of 2009/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.
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
47
48
49
50
51
52
Title of Account
(a)
UTILITY PLANT
Ref.
Page No.
(b)
Current Year
End of OuarterlYear
Balance
(c)
Prior Year
End Balance
12/31
(d)
200-201
200-201
!Í "yJ!/,,".%....._./¡¡.~/._ ifi?4u:AØA :f$J: Yij;; Y:X:;:,; y y
FERCFORM NO.1 (REV. 12-03)
Utility Plant (101-106,114)
Construction Work in Progress (107)
TOTAL Utilty Plant (Enter Total of lines 2 and 3)
(Less) Accum. Provo for Depr. Amort. Depl. (108,110, 111, 115)
Net Utilit Plant (Enter Total of line 4 less 5)
Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)
Nuclear Fuel Materials ann Assemblies-Stock Account (120.2)
Nuclear Fuel Assemblies in Reactor (120.3)
Spent Nuclear Fuel (120.4)
Nuclear Fuel Under Capital Leases (120.6)
(Less) Accum. Provo for Amort. of Nucl. Fuel Assemblies (120.5)
Ne Nuclear Fuel (Enter Total of lines 7-11 less 12)
Net Utilty Plant (Enter Total of lines 6 and 13)
Utilty Plant Adjustments (116)
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutilty Propert (121)
(Less) Accum. Provo for Depr. and Amort. (122)
Investments in Associated Companies (123)
Investment in Subsidiary Companies (123.1)
(For Cost of Account 123.1, See Footnote Page 224, line 42)
Noncurrent Portion of Allowances
Other Investments (124)
Sinking Funds (125)
Depreciation Fund (126)
Amortization Fund - Federal (127)
Other Special Funds (128)
Special Funds (Non Major Only) (129)
Long-Term Portion of Deivative Assets (175)
Long-Term Portion of Derivative Assets - Hedges (176)
TOTAL Other Propert and Investments (Lines 18-21 and 23-31)
CURRENT AND ACCRUED ASSETS
Cash and Working Funds (Non-major Only) (130)
Cash (131)
Special Deposits (132-134)
Working Fund (135)
Temporary Cash Investments (136)
Notes Receiv;:le (141)
Custoer Accnts Recable (142)
Other Accounts Receivable (143)
(Less) Accum. Provo for Uncollectible Acct.-Credit (144)
Noteli Receivable from Associated Companies (145)
Accounts Receivable from Assoc. Companies (146)
Fuel Stock (151)
Fuei Stoc Expenses Undistributed (152)
Residuals (Elec) and Extracted Products (153)
Plant Materials and Operating Supplies (154)
Merchandise (155)
Other Materials and Supplies (156)
Nuclear Materials Held for Sale (157)
Allowances (158.1 and 158.2)
200-201
19,881,830,192
1,799,367,394
21,681,197,586
7,199,824,404
14,481,373,182
o
o
o
o
o
o
o
14,481,373,182
o
o
202-203
202-203
18,62,953,925
1,208,785,536
19,671,739,461
6,848,927,351
12,822,812,110
o
o
o
o
o
o
o
12,822,812,110
o
o__'-~./'W~II~'ßI
11,538,314 9,497,834
1,421,418 1,455,833
11,220,813 9,031,958
224-225 184,718,167 171,510,195
228-229 0 0
84,336,862 85,601,343
0 0
0 0
0 0
6,945,599 8,081,370
0 0
42,909,107 86,579,549
0 0
340,247,444 368,846,416I.ty// __ /0' Ji'''
227
227
227
227
227
227
202-203/227
228-229
o
4,238,848
610,443
1,920
81,769,678
208,656
361,520,728
32,319,952
7,052,112
4,748,292
14,254,320
170,930,143
o
o
178,147,022
o
o
o
o
o
15,725,712
2,048,982
2,020
3,937,516
270,949
346,007,077
43,610,380
8,679,145
20,797,545
8,447,228
136,802,882
o
o
170,075,369
o
o
o
o
Page 110
Name of Respondent
PacifCorp
This Report Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/14/2010 End of
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBIT~ontinued)
Year/Period of Report
2009/04
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
Title of Account
(a)
(Less) Noncurrent Portion of Allowances
Stores Expense Undistributed (163)
Gas Stored Underground - Current (164.1)
Liquefied Natural Gas Stored and Held for Proessing (164.2-164.3)
Prepayments (165)
Advances for Gas (166-167)
Interest and Dividends Receivable (171)
Rents Receivable (172)
Accrued Utility Revenues (173)
Miscellaneous Current and Accred Assets (174)
Derivative Instrument Assets (175)
(Less)Long-Term Portion of Derivative Instrument Assts (175)
Derivative Instrument Assets - Hedges (176)
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176
Total Current and Accrued Assets (Lines 34 through 66)
DEFERRED DEBITS
Unamortized Debt Expenses (181)
Extaordinary Propert Losses (182.1)
Unrecovered Plant and Regulatory Study Costs (182.2)
Other Regulatory Asets (182.3)
Prelim. Survey and Investigation Charges (Electric) (183)
Preliminary Natural Gas Survey and Investigation Charges 183.1)
Other Preliminar Survey and Investigation Charges (183.2)
Clearing Accunts (184)
Temporary Facilties (185)
Miscellaneous Deferred Debits (186)
Daf. Losses from DispositiOn of Utilty Pit. (187)
Research, Devel. and Demonstration Expend. (188)
Unamortized Loss on Reaquired Debt (189)
Accumulated Deferred Incme Taxes (190)
Unrecovered Purchased Gas Costs (191)
Total Deferred Debits (lines 69 through 83)
TOTAL ASSETS (lines 14-16, 32, 67, and 84)
Ref.
Page No.
(b)
Current Year
End of OuarterlYear
Balance
(c)
Prior Year
End Balance
12/31
(d)
Line
No.
227
o
o
o
28,102
2,172,050
210,896,000
8,854,407
260,256,083
86,579,549
o
o
1,219,442,820
/ %/7/J/0 //~...'ffß '0 ..w;: a/;~yj.~ Ifr; I;;;.
35,978,910 30,017,721
230a 0 0
230b 5,289,133 10,439,101
232 1,550,913,652 1,626,353,730
3,116,069 1,091,392
0 0
0 0
0 0
89,891 88,829
233 67,302,539 72,806,094
0 0
352-353 0 0
13,778,067 16,563,180
234 587,517,758 586,940,125
0 0
2,263,986,019 2,344,300,172
18,550,965,133 16,755,401,518
FERC FORM NO.1 (REV. 12-03)Page 111
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
I FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
PacifiCorp (1) IX An Original (mo, da, yr)
(2)0 A Resubmission 04/14/2010 end of 2009/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prior Year
Ref.End of OuarterlYear End BalanceNo.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201)250251 3,417 ,945,896 3,417,945,896
3 Preferred Stock Issu (204)250-251 41,463,300 41,463,300
4 Capital Stock Subscribed (202, 205)0 0
5 Stock Liabilty for Convel'ion (203, 206)0 0
6 Premium on Capital Stock (207)0 0
7 Other Paid-In Capital (208-211).253 . 1,002,063,956 877,063,956
8 InstallmentS. Received on Capital Stock (212)252 0 0
9 (Less) Discount on Capital Stock (213)254 0 0
10 (Less) Capital Stock Expense (214)254b 41,288,201 41,288,207
11 Retained Earnings (215, 215.1,216)118-119 2,225,701,34f 1,687,760,382
12 Unappropriated Undistributed Subsidiary Eamings (216.1)118-119 8,330,470 6,508,778
13 (Less) Reaquired Capital Stock (217)250-251 0 0
14 Noncorporate Proprietorship (Non-major only) (218).0 0
15 Accumulated Other Comprehensive Income (219)122(a)(b)-5,819,577 -2,550,680
16 Total Proprietary Capital (lines 2 through 15)6,648,397,184 5,986,903,425
17 LONG-TERM DEBT
18 Bonds (221)256-257 6,372,343,OOC 5,510,797,000
19 (Less) Reaquired Bonds (222)256-257 0 0
20 Advances from Associated Companies (223)256-257 0 0
21 Other Long-Term Debt (224)256-257 0 0
22 Unamortized Premium on Long-Term Debt (225)35,563 38,281
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)15,413,483 7,963,911
24 Total Long-Term Debt (lines 18 through 23)6,356,965,080 5,502,871,370
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurent (227)57,295,450 59,390,328
27 Accumulated Prvision for Propert Insurance (228.1)C 0
28 Accumulated Provision for Injuries and Damages (228.2)7,487,871 8,501,565
29 Accumulated Provision for Pensins and Benefits (228.3)592,543,11 (60,317,224
30 Accumulated Miscellaneos Operating Provisions (228.4)41,878,303 42,256,560
31 Accmued Provision for Rate Refunds (229)C 0
32 Long-Term Portion of Derivative Instrument Liabilities 409,727,11C 490,202,449
33 Long-Term Portion of Derivative Instrumen Liabilties - Hed 0 0
34 Asset Retirement Obligations (230)102,516,932 80,948,143
35 Total Other Noncurrent Liabilties (lines 26 through 34)1,211,448,776 1,285,616,269
.36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231).. 0 85,000,000
38 Accunts Payable (232)539,268,266 744,182,870
39 Notes Paya to Associated Companies (233)0 0
40 Accounts Payable to Associated Companie (234)13,729,206 17,383,942
41 Customr Deposits (235)31,895,824 21,919,032
42 Taxes Accrd (236)262-263 46,747,021 28,648,482
43 Interest Accrued (237)111,56,228 88,654,332
44 Dividends Declared (238)520,947 520,947
45 Matured Long-Term Debt (239)0 0
FERC FORM NO.1 (rev. 12-Q3) Page 112
Name of Respondent This Report is:Date of Report Year/Period of Report
PacifiCorp (1 )1i An Original (mo, da, yr)
(2)0 A Resubmission 04/14/2010 end of 20091Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIT~ntinued)
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 Collections Payable (241)15,796,380 14,388,665
48 Miscellaneous Current and Accrued Liabilties (242).63,197,16i:67,406,951
49 Obligations Under Capital Leases-Current (243)1,725,318 5,768,004
50 Derivative Instrumènt Liabilties (244)494,721,339 620,548,360
51 (Less) Long-Term Portion of Derivative Instrument Liabilties 409,727,110 490,202,449
52 Derivative Instrument Liabilties - Hedges (245)0 0
53 (Less) Long-Term Portion of Derivative Instrument Liabilties-Hedges 0 0
54 Total Current and Accrued Liabilties (lines 37 through 53)909,442,58E 1,204,219,136
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)20,946,236 20,259,578
57 Accumulated Deferred Investment Tax Credits (255)266-267 45,888,892 49,828,356
58 Deferred Gains from Disposition of Utilty Plant (256)0 0
59 Other Deferred Credits (253)269 40,157,480 42,762,022
60 Other Regulatory Liabilties (254)278 64,164,255 76,456,654
61 Unamortized Gain on Reaquired Debt (257)0 0
62 Accum. Deferred Income Taxes-Accel. Amort.(281)272-277 0 0
63 Accum. Deferred Ir-come Taxes-Other Propert (282)2,802,655,179 2,095,724,933
64 Accum. Deferred Income Taxes-Other (283)450,899,466 490,759,775
65 Total Deferred Credits (lines 56 through 64)3,424,711,508 2,775,791,318
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)18,550,965,133 16,755,401,518
.
FERC FORM NO.1 (rev. 12-03)Page 113
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) EiA Resubmission 04/14/2010
..STATEMENT OF INCOME
Quarterly
1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the
data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
2. Enter in column (e) the balance for the reporting qUàrter and in column (f) the balance for the same three month period for the prior year.
3. Report in column (g) the quarter to date amounts for electric utilty function; in column (i) the quarter to date amounts for gas utilty, and in column (k)
the quarter to date amounts for other utilty function for the current year quarter.
4. Report in column (h) the quarter to date amounts for electric utilty function; in column 0) the quarter to date amounts for gas utilty, and in column (i) the
quarter to date amonts for other utilty function for the prior year quarter.
5. If additional columns are needed, place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses frm Utilit Plant Leased to Others, in another utilty columnin a similar manner to
a utilty department. .Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in coumns (c) and (d) totals.
7. Report amounts in account 414, Other Utilty Operating Income, in the same manner as accunts 412 and 413 above.
Line Total Tota Currnt 3 Months Pnor 3 Months
No.Currnt Year to Pror Year to Ende Ended
(Ref.)Date Balance fo Date Balance for Quarteny Only Quarterly Only
Title of Accunt Page No.QuarterNear QuarterNear No 4th Quartr No 4th Quarter
(a)(b)(c) (d) (e) (f)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301 ~3 Operating Expenses
4 Operation Expenses (401)321J23 2,279,099,66 2,593,626,077
5 Maintenance Expenses (402)321J23 Ii 374,652,182
6 Depreciaon Expese (403)33637 416,636,387
7 Depreciation Exense for Asset Retirement Costs (403.1)336-37
8 Amort. & Depl. of Utility Plant (404-405)336-337 32,391,772 40,332,43
9 Amort. of Utilty Plant Acq. Adj. (406)336-37 5,479,353 5,479,353
10 Amort. Propert Losses, Unrecov Plant and Regulatory Study Costs (407)5,149,968 5,107,035
11 Amort. of Conversion Expenses (407)
12 Regulatory Debits (407.3)1,549,004 7,057,628
13 (Les) Reguatory Credts (407.4)
14 Taxes Ot Than Incme Taxes (408.1)262-263 ..15 Income Taxes - Federl (409.1)262-263
16 - Otr (409.1)262-26
17 Provision for Deferr Income Taxes (410.1)234,272-m 1,368,522,890 669,322,953
18 (Less) Proviion for Defeed Incoe Taxes-Cr. (411.1)234, 272-277 688,511,583 356,785,266.
19 InvestmentT ax Credit Adj. - Net( 411.4)266 -1,874,204 -1,874,204
20 (Less) Gains from DiSp. of Utility Plant (411.6)
21 Losses frm Disp. of utli Plant (411.7)
22 (Less) Gains from Disposition of Allowances (411.8)3,790,891 4,889,027
23 Losses frm Disposition of Allowances (411.9)
24 Accretion Expense (411.10)
25 TOTAL Utility Operatig Expenses (Enter Tota of lines 4 th 24)3,515,690,48 3,769,087,216
26 Net Util Oper Inc (Enter Tot line 2 less 25) Carr to Pg117,lie 27 83,075,894 725,498,770
FERC FORM NO. 1f3-Q (REV. 02-()Page 114
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for important notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utilty's customers or which may result in materia.1 refund to the utility with respect to power or gas purchases. State for each year effected the
gross revenues or costs to which the contingency relates and the ta effect together with an explanation of the major factors which affect the rights of the
utilty to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accunts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
15. If the columns are insuffcient for reporting additional utilty departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(g) (h)
GAS UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(i) 0)
OTHER UTILITY
Current Year to Date Previous Yearto Date
(in dollal') (in dollal')(k) (I)Line
No.
3,790,891 4,889,027
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
2,593,626,077
374,652,182
416,636,387
32,391,772
5,479,353
5,149,968
40,332,443
5,479,353
5,107,035
1,549,004 7,057,628
123,877,487
-472,156,577
-2,026,201
1,368,522,890
688,511,583
-1,874,204
112,424,490
-83,683,183
-8,319,652
669,322,953
356,785,266
-1,874,204
3,515,690,486
838,075,894
3,769,087,216
725,498,770
FERC FORM NO.1 (ED. 12-96)Page 115
..
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) EjA Resubmission 04/14/2010
STA EMENT OF INCOME FOR THE YEAR (continued)
Line TOTAL Current 3 Month Pnor 3 Months
No.Ende Ended
(Ref.)Quartrl Only Quartery Only
Title of Account Page No.Current Year Previous Year No 4th Qurter No 4th Quarter
(a)(b)(c)(d)(e)(I)
..
27 Net Utility Operating Income (Carned forward from page 114)838,075,894 725,498,770
28 Other Inco and Dedctons
29 Other Income
30 Nonuti Opting Income
31 Revenu From Merchandising, Jobbing and Contrct Work (415)1,526,343 2,278,244
32 (Less)Costs and Exp. of Merchandising, Job. & Contrct Work (416)1,518,065 2,44,146
33 Revenu From Nonutility Operations (417)241,243 233,693
34 (Less) Expenes of Nonutilty Operations (417.1)28,326 26,272
35 Nonopeatig Rental Income (418)74,959 60,570
36 Equity in Earngs of Subsidiary Companies (418.1) .119 1,811,740 -1,905,654
37 Interest and Dividend Income (419)20,556,977 10,637,009
38 Allowance for Other Funds Used During Constrction (419.1)63,955,322 46,616,392
39 Miscllaneous Nonoperating Income (421)32,225,273 144,442,511
40 Gain on Disposition of Propert (421.1)2,267,272 2,378,680
41 TOTAL Other Income (Enter Total of lines 31 thru 40)121,112,738 202,271,027
42 Other Income Deductions
43 Loss on Disposition of Propert (421.2)82,456 263,455
44 Miscellaneous Amorzation (425)1,263,905 1,165,477
45 Donations (426.1)2,997,500 2,848,144
46 Ufe Insurance (426.2)-5,605,297 -2,259,327
47 Penaltes (426.3)400,132 1,560,618
48 Exp. for Certin Civic, Political & Related Activties (426.4)1,519,511 1,265,718
49 Other Deductions (426.5)34,666,110 143,419,880
50 TOTAL Otr Income Deductions (Total of lines 43 thru 49)35,324,317 148,263,965
51 Taxes Applic. to Other Income and Deductons
52 Taxes Other Than Ine Taxes (408.2)262-263 576,313 238,746
53 Income Taxes-Federa (409.2)262-263 29,005,691 20,014,193
54 Income Taxes-Other (409.2)262-263 3,941,391 2,719,596
55 Provisio for Deferred Inc. Taxes (410.2)234, 272.277 99,093,919 146,049,815
56 (Less) Provision for Deferred Income Taxes-Cr. (411.2)234, 272-27 99,416,511 146,94,899
57 Investment Tax Credit Adj.-Net (411.5)
58 (Less) Investment Tax Credits (420)2,065,260 2,06,260
59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)31,135,543 20,012,191
60 Net Other Income and Deductions (Total oflnes 41, 50, 59)54,652,878 33,994,871
61 Interest Chares
62 Interest on Long-Term Debt (427)369,236,11 313,572,989
63 Amort. of Debt Disc. and Expense (428)3,786,241 3,072,734
64 Amortzaon of Loss on Reaquired Debt (428.1)2,785,112 4,223,214
65 (Less) Amor. of Premium on Debt-Credit (429)2,718 2,718
66 (Less) Amortzation of Gain on Reaquired Debt-Credit (429.1)
67 Interest on Debt to Assoc. Companies (430)
68 Other Intees Expense (431)10,26,106 14,625,063
69 (Less) Allowance for Borrowed Funds Used Dunng Constrcton-Cr. (432)35,186,532 34,280,545
70 Net Interest Charges (Total of lines 62 thru 69)350,882,326 301,210,737
71 Income Befo Exrdinary Items (Total of lines 27, 60 and 70)541,84,44 458,282,904
72 Exraordinar Items
73 Exrainary Income (434)
74 (Less) Exordinary Deductons (435)
75 Net Exraordinary Items (Total of line 73 less line 74)
76 Income Taxs-Federal and Other (409.3)262.263
77 Exraordinary Items After Taxes (line 75 less line 76)
78 Net Income (Total of line .71 and 77)541,846,446 458,282,904
FERC FORM NO. 1/3.Q (REV. 02-04)Page 117
Name of Respondent . This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp 1(2) A Resubmission 04/14/2010 2009/Q4
.-FOOTNOTE DATA
I$chedule Page: 114 Line No.: 6 Column: c
Vehicle depreciation is charged to fuctional accounts. The following table sumarzes the vehicle depreciation expense that was
charged to the fuctional accounts.
Years Ended December 31,2009 2008
Vehicle Depreciation $ 13,886,246 $ 13,465,822
'¡chedule Page: 114 Line No.: 7 Column: c I
PacifiCorp records the depreciation expense of asset retirement obligations as either a regulatory asset or liability.'¡chedule Page: 114 Line No.: 14 Column: c I
Payroll taes are charged to fuctional accounts, which is consistent with where labor is charged. The following table summarizes the
payroll tax expense that was charged to the functional accounts.
Years Ended December 31,2009 2008
Payroll Tax Expense $ 38,397,330 $ 37,428,777
'$chedule Page: 114 Line No.: 15 Column: c
The credit reported in the curent year tax expense is primarly attbutable to a provision for net opemting loss (tax basis) and tax
credit carrbacks for the calenda year ended December 31,2009. PacifiCorp's net operating loss (tax basis) for calenda year ended
December 31, 2009 is primarily attbutable to accelerated tax depreciation, tax bonus depreciation taen in excess of book
de reciation, and re airs deduction.
chedule Pa e: 114 Line No.: 15 Column: d
The credit reported in the prior year tax expense is priarly attbutable to a provision for net operating loss (tax basis) and tax credit
carbacks for the calenda year ended December 31, 2008. PacifiCorp's net operating loss (tax basis) is primarly attbutable to
accelerated tax d reciation and tax bonus d reciation taen in excess of book de reciation.
chedule Pa e: 114 Line No.: 16 Column: c
See footnote line 15, colum c
'$chedule Page: 114 Line No.: 16 Column: d
See footnote line 15, colum d
'$chedule Page: 114 Line No.: 24 Column: c
Pacificorp records the accretion expense of asset retirement obligations as either a regulatory asset or liability,
I FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
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 accunt 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line ItemNo. (a)
UNAPPROPRIATED RETAINED EANINGS (Accunt 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Eamings (Accunt 439)
4
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acct. 439)
10 Adoption of SFAS No. 158 measurement date provisions, net
11 of tax of ($943,130)
12
13
14
15 TOTAL Debits to Retained Eamings (Acc. 439)
16 Balance Transferred frm Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
18
19
20
21
22 TOTAl Appropriations of Retained Eamings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24 Preferred Stock, various series and rates
25
26
27
28
29 TOTAL Diviends Declared-Prefer Stoc (Acc. 437)
30 Dividends Declared-Common Stock (Accunt 438)
31
32
33
34
35
36 TOTAL Dividends Declare-Common Stock (Acct. 438)
37 Transfers frm Acct 216.1, Unapprop. Undistrib. Subsidiary Eamings
38 Balance - End of Period (Total 1 ,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Accunt 215)
39
40
Contr Primary
ccount Affected
(b)
Current
QuarterNear
Year to Date
Balance
(c)
Previous
QuarterNear
Year to Date
Balance
(d)! ~ftfií..I~--------~~
¡ A'~!~;; I ;Y~"Jrr :.::-
-- -I -----~ii~~-m.K0..,; ;¿j¡;&I/ Y~ßí ;;
228.3 1,366,264)
540,034,706
1,366,264)
460,188,558
¿¡¡i~ / .%!w""*'z 0 - Z 0rÍl .W53¡fl!lif " 7.......01111 0 7. P. t& :f.ai~ ".~./ iifi. wlff / /fig
238 -2,083,790 2,083,790)
-2,083,790 2,083,790)
~9,952
2,222,125,535
( 856,888)
1,684,184,571
FERC FORM NO. 1/3-Q (REV. 02-04)Page 118
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report(1) ~An Onginal (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
STATEMENT OF RETAINED EARNINGS
1. Do (lot 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 incme tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain ina footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation isto be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals everitually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Current Previous
QuarterN ear QuarterNear
Contra Primary Year to Date Year to Date
Line Item ccount Affected Balance Balance
No.(a)(b)(c)(d)
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP.RETAINED EARNINGS -AMORT. Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 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 (Account
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Eamings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52 Transfers to/from Unapprop. Retained Earnings (Account 216)
53 Balance-End of Year (Total lines 49 thru 52)
6,508,778 7,557,544
1,811,740 1,905,654)
9,952 856,888
8,330,470 6,508,778
FERC FORM NO. 1/3-Q (REV. 02-(4)Page 119
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
ro'ects.
I FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
This ~ort Is:
(1) ~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/14/2010
Year/Period of Report
End of 2009/Q4
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial-paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and
Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertining to operating actvities only. Gains and losses pertining to investing and financing activities should be
reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cah outfow to acquire other companies. Proviqe a reconciliation of assets acquired with liabilities assumed in the Notes
to the Finanial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconcilation of
the dollar amount of leases capitalized with the plant cost.
(a)
1 Net Cash Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion
5
6
7 Unrealized Losses/(Gains) on Derivative Contracts
8 Deferred Income Taxes (Net)
9 Investment Tax Credit Adjustment (Net)
10 Net (Increase) Decrease in Receivables
11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Accrued Expenses
14 Net (Increase) Decrease in Other Regulatory Assets
15 Net Increase (Decrease) in Other Regulatory Liabilties
16 (Less) Allowance for Other Funds Used During Construction
17 (i.ess) Undistributed Earnings from Subsidiary Companies
18 Amounts Due To/From Affliates, Net
19 Derivative Collateral (Net)
20
21
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)
23
Line
No.
Description (See Instruction NO.1 for Explanation of Codes)Current Year to Date
.QuarterNear
(b)
Previous Year to Date
. QuarterN ear
(c)
726,000
647,364,615
-3,939,464
-10,227,986
-41,858,225
61,572
311,719,127
-3,939,464
_ 4,400,377
-57,076,891
37,768,396
12,441,383
-6,970,542
63,955,322
1,811,740
-216,306,739
57,400,001
-30,082,350
7,685,336
-36,836,116
-2,020
46,616,392
-1,905,654
-9,844,783
-81,900,000
-53,394,167
1,461,089,825 984,398,206
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utilty Plant (less nuclear fuel)
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utilty Plant
29 Gross Additions to Nonutilty Plant
30 (Less) Allowance for Other Funds Used During Construction
31 Acquisitions, Net of Cash Acquired
32
33
34 Cash Outfows for Plant (Total of lines 26 thru33)
35
36 Acquisition of Other Noncurrent Assets (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 Associated and Subsidiary Companies
43
44 Purchase of Investmnt Securities (a)
45 Proceeds from Sales of Investment Securities (a)
-2,356,195,937 -1,805,989,623
-63,955,322 -46,616,392
-307,682,572
-2,292,240,615 -2,067,055,803
..i_"-C7Wllfli' "JI~ z:JI/ -/.~
1,274,203 3,012,032
-10,417,000
16,029,414
1B_.l&/~BiIl""j: ;..
-269,354
458,430
-9,698
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)
04/14/2010
Year/Period of Report
End of 2009/Q4
(1) Codes to be used:(a) Net Proceds or Payments;(b)Bonds, debentures and othe long-term debt; (c) Include commercial paper; and (d) Identify separaely such items asinvestments, fixed assets, intangibles, etc. ..
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliatin 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 to operating aciviies only. Gains and losses pertining to investing and financing actvities should be
reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taes paid.
(4) Investing Activities: Include at Other (line 31) net cah outfow to acquire other copanie. Provide a reconcilation of assets acquired with liabilities assumed in the Notes
to th Financial statements. Do not include on this statement the dollar amoun of lese capitlized per the USofA General Instruction 20; instead provide a reconcilation of
the dollar amount of leases capitalized with the plant cost.
Line
No.
Description (See Instruction NO.1 for Explanation of Coes)
(a)
Current Year to Date
QuarterlYear
(b)
Previous Year to Date
QuarterlY ear
(c)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (Increase) Decrease in Receivables
50 Net (Increase) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accrued Expenses
53
54
55
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Equity Contribution
65 Reacuired Bonds
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68
69
70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Paymnts for Retirement of:
73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote):
77 Repayment of Capital Lease Obligations
78 Net Decrease in Short-Term Debt (c)
79 Reacquired Bonds
80 Dividends on Preferred Stock
81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activitis
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
3,540,757 4,988,593
982,802,997 792,126,293
125,000,000 450,000,000
216,470,000
84,991,027
1,107,802,997 1,543,587,3201_
-138,454,000 -412,408,000
-5,811,642
-84,991,027
-709,310
-2,083,790
-216,470,000
-2,083,790
86,010,446 19,665,248
FERC FORM NO.1 (ED. 12-96)Page 121
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA
¡Schedule Page: 120 Line No.: 5 Column: a
Amortzation of Softare & Other Intangìbles
Amortzation of Hydroelectrc Relicensing Costs
Amortzation of Electrc Plant Acquisition Adjustment
Amortzation of Regulatory Assets
Years Ended December 31,
2009 2008
$ 32,391,772 $ 40,332,443
1,263,905 1,165,477
5,479,353 5,479,353
6,698,972 12,164,663
$ 45,834,002 $ 59,141,936
!Schedule Page: 120 Line No.: 20 Column: a
Coal & Steam Depreciation & Depletion included in Cost of Fuel
PMI Earings included in Cost of Fuel
(Gain)/Loss on Sale of Propert
Deferred Credits - Deferred Compensation
Accumulated Provision for Pension & Benefits
Write-Off of Assets Under Constrction
Accumulated Provision for MiningÆnvironlecom
BPA Transmission (Prepayments)/Refuds
Long-Term Notes Receivable
Other
Years Ended December 31,2009 2008
$ 13,212,110 $ 12,035,196
(11,386,280) (8,910,812)
(2,357,000) (2,588,295)
(169,928) (2,125,011)
(32,053,411) (42,626,647)
4,489,364 4,813,141
(5,286,415) (3,044,671)4,217,125 (7,488,000)
314,177 (2,357,519)
(1,062,092) (1,101,549)
$ (30,082,350) $ (53,394,167)
!Schedule Page: 120 Line No.: 53 Column: a
Other Investmts/Special Funds
Temporar Facilties
Restrcted Cash
Years Ended December 31,
2009 2008
$ 1,020,004 $ 3,344,372
(1,062) 26,471
2,521,815 1,617,750
$ 3,540,757 $ 4,988,593
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
Name of Respondent
PacifiCorp
Date of Report Year/Penod of Report
End of 2009/Q4
This Report Is:
(1) 12 AnOriginal
(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 bnef 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 utilit. Give also a bnef explanation of any dividends in arrears on
cumulative preferred stock.
3. For Account 116, Utiity 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 authonzations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortzed Gain on Reacquired Debt, are not used, give an
explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restnctions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes suffcient disclosures sO as to make the intenm information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a matenal effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting pnnciples and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrwings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were matenal 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 appeanng in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
04/14/2010
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
.
.
FERC FORM NO.1 (ED. 12-96)Page 122
Name of Respondent This Report is:Date of Report Year/Period of Report
(1).lÇ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
PACIFICORP AN SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS
(1) Organization and Operations
PacifiCorp, which includes PacifiCorp and its subsidiares, is a United States regulated electrc company serving i. 7 million retail
customers, including residential, commercial, industral and other customers in portons of the states of Utah, Oregon, Wyoming,
Washington, Idao and California. PacifiCorp owns, or has interests in, anumber of therml, hydroelectrc, wind-powered and
geothermal generating facilities, as well as electrc transmission and distrbution assets. PacifiCorp also buys and sells electrcity on
the wholesale market with public and private utilities, energy marketing companies and incorporated municipalities. PacifiCorp is
subject to comprehensive state and federal regulation: PacifiCorp's subsidiares support its electrc utility operations by providing coal
mining facilities and services and environmental remediation services. PacifiCorp is an indirect subsidiar of MidAmerican Energy
Holdings Company ("MEHC"), a holding company based in Des Moines, Iowa that owns subsidiares pricipally engaged in energy
businesses. MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2) Summary of Signifcant Accounting Policies
Basis of Presentation
These financial statements are prepared in accordance with the requirements of the Federal Energy Regulatory Commission
(the "FERC") as set fort in its applicable Uniform System of Accounts and published accountig releases, which is a comprehensive
basis of accounting other than accounting principles generally accepted in the United States of America ("GAA"). These notes
include disclosures required by GAAP adjusted to the FERC basis of presentation, and include specific information requested by the
FERC.
The following are the significant differences between the FERC accounting and reporting stadads and GAA.
Investments in Subsidiaries
PacifiCorp accounts for certin investments in subsidiaries using the equity method rather than consolidating the assets,
liabilties, revenues and expenses of the subsidiaries as required by GAA. GAAP requires that entities in which a company
holds acontrollng financial interest be consolidated. The accounting for investments in these certain subsidiares using the
equity method rather than the consolidation method in accordance with GAA has no effect on net income or retained
earings.
Accumulated Costs of Removal
The accumulated costs of removal for PacifiCorp's utility plant that do not meet the GAA definition of an asset retirement
obligation ("ARO") are classified as a regulatory liability under GAA and as accumulated depreciation under the FERC
accounting and reportng standards.
Income Taxes
Accumulated deferred income taxes are classified as curent and non-curent on the balance sheet for GAA. Under the
FERCaccountig and reportng standads, accumulated deferred income taxes are classified as gross non-curent assets and
gross non-curent liabilties. Additionally, there are certin presentational differences between FERC and GAA for amounts
related to unecognized tax benefits associated with temporar differences in accordance with FERC Docket
No. AI07 -2-000, "Accounting and Financial Reporting for Uncertinty in Income Taxes" issued on May 25, 2007.
Interest and penalties on income taes for GAA are classified as income ta expense. An such amounts are classified as
interest income, interest expense and penalties under the FERC accountig and reportng standads.
IFERC FORM NO.1 (ED. 12-88) Page 123.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 0 An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Unrealized Gains and Losses on Derivative Instrments
The FERC accounting and reporting stadads require that unrealized gains and losses on denvative instrments that are not
recorded as a net regulatory asset or accumulated other comprehensive income ("AOCI") be classified gross in the statement
of income in accordance with FERC Order 627, "Accounting and Reportg of Financial Instrents, Comprehensive
Income, Denvatives and Hedging Activities." Unrealized gains and losses on energy contracts accounted for as denvatives
are presented on the Statement of Income as miscellaneous nonoperating income for unealized gains and as other deductions
for unrealized losses. For GAA, unealized gains and losses on energy denvative contracts not held for trading puroses are
presented on the Statement of Income as revenues for sales contracts and as energy costs and operating expense for purchase
and financial swap energy contracts.
Reclassifcations
Certain other reclassifications of balance sheet, income statement and cash flow amounts have been made in order to
conform to the FERC basis of presentation. These reclassifications had no effect on net income.
Use of Estimates in Preparation of Financial Statements
The preparation of financial statements in conformty with GAA requis maagement to make estimates and assumptions that affect
the reported amounts of assets and liabilities at the date of the fiancial statements and the reported amounts of revenue and expenses
dunng the penod. These estimates include, but are not limited to, unbiled revenue; valuation of certin financial assets and liabilities,
including denvative contracts; effects of regulation; long-lived aset reovery; accountig for contingencies, including environmental,
regulatory and income tax matters; AROs; and certin assumptions made in accounting for pension and other postretirement benefits.
Actual results may differ from the estimates used in prepang the financial statements.
Accountingfor the Effects of Certain Types of Regulation
PacifiCorp prepares its financial statements in accordance with authontative guidance for regulated operations, which recognzes the
economic effects of regulation. Accordingly, PacifiCorp is required to defer the recognition of certain costs or income if it is probable
that, through the ratemaking process, there wil be a corrsponding increase or decrease in futue regulated rates.
PacifiCorp continually evaluates the applicability of the guidace for regulated operations and assesses whether its regulatory assets
and liabilities are probable of futue inclusion in reguated rates by considenng factors such as a change in the regulator's approach to
setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition which
could limit PacifiCorp's abilty to recover its costs. Based upon this continuous assessment, PacifiCorp believes the application of the
guidance for regulated opetions is appropnate and its existig regulatory assets and liabilities are probable of inclusion in regulated
rates. The assessment reflects the curent political and regulatory climate at both the state and federal levels and is subject to change in
the futue. If it becomes no longer probable that these costs or income wil be included in regulated rates, the related regulatory assets
and liabilities wil be wntten off to operating income, refuded to customers or reflected as an adjustment to futue regulated rates.
Fair Value Measurements
As defined under GAA, fair value is the pnce that would be received to sell an asset or paid to transfer a liability between market
parcipants in the pnncipal market or in the most advantageous market when no pnncipal market exists. Market parCipants are
assumed to be independent, knowledgeable, and able and willing to trsact. Nonpeñormce or credit nsk is considered when
determing the fair value of assets and liabilities. Considerble judgment may be required in interpreting market data used to develop
the estimates of fair value.
IFERC FORM NO.1 (ED. 12-88)Page 123.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp . (2) A Resubmission 04/14/2010 20091Q4
NOTES TO FINANCIAL STATEMENTS (Continued).
Cash Equivalents, Restricted Cash and Investments
Cash equivalents consist of funds invested in commercial paper, money market accounts and in other investments with a matuty of
three month~ or less when purchased. Cash and cash equivalents exclude amounts. where availabilty is restrcted by legal
requirements, loan agreements or other contractual provisions. Restricted amounts are included in other special fuds and special
deposits on the Compartive Balance Sheet. Total cash and cash equivalents were as follows as of December 31 (in milions):
2009 2008
$4 $16
82 4
$86 $20
Cash (131)
Working fuds (135)
Tempora cash investments (136)
Total cash and cash equivalents
Allowance for Doubtfl Accounts
The allowance for doubtfl accounts is basedonPacifiCorp's assessment of the collectibility of payments from its customers. This
assessment requires judgment regarding the ability of customers to pay the amounts owed to PacifiCorp or the outcome of any
pending disputes. The change in the balance of the allowance for doubtful accounts, which is included in accumulated provision for
uncollectible accounts on the Comparative Balance Sheet was as follows for the years ended December 31 (in milions):
Begining balance
Chaged to operation expenses, net
W rite-off,net
Ending balance
2009 2008
$9 $7
12 14
(4)(2)
$7 $9
Derivatives
PacifiCorp employs a number of different derivative contracts, including forwards, futues, options, swaps and other agreements, to
manage price risk for electrcity, natul gas and other commodities and interest rate risk. Derivative contracts are recorded on the
Comparative Balance Sheet as either assets or liabilties and are stated at fair value unless they are designated as normal purchases
and normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect reductions permtted under master
nettng argements with counterpartes and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for
and may be designated as normal purchases andnormäl sales. Normal purchases and normal sales are not marked-to-market and
operatig revenues or operation expenses are recognized on the Statement of Income when the contrcts settle.
For PacifiCorp's derivatives designated as hedgig contracts, PacifiCorp formlly assesses, at inception and thereafter, whether the
hedging contract is highly effective in offsettng changes in the hedged item. PacifiCorp formally documents hedging activity by
transaction tye and risk management strategy.
IFERC FORM NO.1 (ED. 12-88)Page 123.3
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/14/2010 2009104
NOTES TO FINANCIAL STATEMENTS (Continued)
Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are included on the
Statements of Accumulated Comprehensive Income, Comprehensive Income, and Hedging Activities as AOCI, net of ta, until the
contract settles and the hedged item is recognized in earings. PacifiCorp discontinues hedge accounting prospectively when it has
determined that a derivative .no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted
transaction wil occur. When hedge accountig 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 AOCI will remain in AOCI until the contrct settles and the hedged item is recognized in earings, unless it becomes
probable that the hedged forecasted trsaction will not occu, at which time associated deferred amounts in AOCI are immediately
recognized in earnings.
For PacifiCorp's derivatives not designated as hedgig contrcts, the settled amount is generally included in regulated rates.
Accordingly, the net unrealized gains and losses associated with interi price movements on contracts that are accounted for as
derivatives and probable of inclusion in regulated rates are recorded as net regulatory assets and liabilities. For contrcts not probable
of inclusion in regulated rates, changes in fair value are recognized in earings.
Inventories
Inventories consist mainly of materials and supplies, coal stocks, natural gas and fuel oil, which are stated at the lower of average cost
or market.
Net Utilty Plant
General
Utility plant is recorded at historical cost. PacifiCorp capitalizes all constrction-related materal, direct labor and contrct services,. as
well as indirect constrction costs, which includes debt and equity allowance for fu usd durg constrction ("AFUC"). The
cost of major additions and betterments are capitalized, while costs for replacements, maintenance and repairs that do not improve or
extend the lives of the related assets are charged to operating expense as incurred.
Depreciation and amortzation are generally computed by applying the composite or straight-line method based on either estimated
useful lives or mandated recovery periods as prescbed by PacifiCorp's varous regulatory authorities. Periodic depreciation studies
are completed to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates
are ultiately approved by the various regulatory authorities. Net salvage includes the estimated futue residual values of the assets
and any estimated removal costs, including AROs and other costs of removaL. Estited removal costs that are recovered though
approved depreciation rates, but that do not meet the requirements of a legal ARO, are reflected in accumulated provision for
depreciation on the Compartive Balance Sheet, and as such costs are incurd, the provision is reduced.
Generally when PacifiCorp retires or sells a component of depreciable utility plant, it charges the original cost and any cost of
removal and salvage to accumulated provision for depreciation. Any gain or loss on disposals of all other assets is recorded though
earings.
PacifiCorp records debt and equity AFUC, which represents the estited costs of debt and equity funds necessar to finance
additions to utility plant. AFUDC is capitalized as a component of utility plant, with offsettg credits to the Statement of Income.
After constrction is completed,PacifiCorp is permitted to ear a retu on these costs as a component of the related asset, as well as
recover these costs through depreciation expense over the expected useful life of the related assets.
I FERC FORM NO.1 (ED. 12-88)Page 123.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da,Yr)
PacifiCorp 1(2)A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Asset Retirement Obligations
PacifiCorp recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon
retirement of an asset. The fair value of an ARO liability is recognized in the penod in which it is incured, if a reasonable estimate of
fair value can be made, and is added to the caring amount of the associated asset, which is then depreciated over the remaining
useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the expected value of
the retirement obligation (with corresponding adjustments to utility plant) and for accretion of the ARO liability due to the passage of
time. The difference between the ARO liability, the corresponding ARO asset included in utility. plant and amounts recovered in
depreciation rates to satisfy such liabilities is recorded as a regulatory asset or liability.
Revenue Recognition
Revenue is recognized as electrcity is delivered or servces are provided. Revenue recognized includes unbiled, as well as biled,
amounts. As of December 31, 2009 and 2008, unbiled revenue was $214 milion and $211 millon, respectively, and is included in
accrued utility revenues on the Comparative Balance Sheet. Rates charged are established by regulators or contrctual agreements.
The determnation of sales to individual customers is based on the reading of the customer's meter, which is performed on a
systematic basis thoughout the month. At the end of each month, amounts of energy provided to customers since the date of the last
meter reading are estimated, and the corresponding unbiled revenue is recorded. The estimate is reversed in the following month and
actual revenue is recorded based on subsequent meter readings.
The monthly unbiled revenues of PacifiCorp are determined by the estimation of unbiled energy provided durig the period, the
assignent of unbiled energy provided to customer classes and the average rate per customer class. Factors that can impact the
estimate of unbiled energy provided include, but are not limited to, seasonal weather patterns, customer usage patterns, historical
trends, volumes, line losses, retail rate changes and composition of customer çlasses.
PacifiCorp records sales, franchise and excise taes collected directly from customers and remitted directly to the taxing authorities on
a net basis on the Statement oflncome.
Income Taxes
Berkshire Hathaway includes PacifiCorp in its United States federal income ta retu. Consistent with established regulatory
practice, PacifiCorp's provision for income taes has been computed on a stand-alone basis.
Deferred tax assets and liabilties are based on differences between the financial statement and tax basis of assets and liabilities using
estimated tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferrd income
tax assets and liabilities that are associated with components of other comprehensive income are charged or credited directly to other
comprehensive income. Changes in deferred income tax assets and liabilities that are associated with income tax tienefits related to
certain proper-related basis differences and other various differences that PacifiCorp is required to pass on to its customers in most
state jursdictions are charged or credited directly to a regulatory asset or liability. These amounts were recognzed as a net reglatory
asset totaling $401 milion and $409 millon as of December 31,2009 and 2008, respectively, and wil be included in regulated rates
when the temporar differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of
income tax expense.
Investment tax credits are generally deferred and amortzed over the estiated useful lives of the related properties or as prescribed by
varous regulatory jurisdictions.
I FERC FORM NO.1 (ED. 12-88)Page 123.5
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp 1(2) . A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continúed)
In determining PacifiCorp's income taes, management is required to interpret complex tax laws and regulations, which includes
consideration of regulatory implications imposed by PacifiCorp's varous regulatory jursdictions. In preparig tax retus, PacifiCorp
is subject to continuous examinations by federl, state and IQcal tax authorities that may give rise to different interpretations of these
complex laws and regulations. Due to the natue of the examation process, it generally takes years before these examnations are
completed and these matters are resolved. Although the ultimte resolution ofPacifiCorp's federal, state and local tax examinations is
uncertin, PacifiCorp believes it has made adequate provisions for these ta positions. The aggregate amount of any additional tax
liabilities that may result from these examations, if any, is not expected to have a material adverse effect on PacifiCorp's financial
results. PacifiCorp recognizes the tax benefit from an uncertin ta position only if it is more likely than not that the tax position wil
be sustained on examiation by the taxing authorities, based on the technical merits of the position. The ta benefits recognized in the
financial statements from such a position are measured based on the largest benefit that has a greater than fift percent likelihood of
being realized upon ultimate settlement. Estimated interest and penalties, if any, related to uncertain tax positions are included in
interest income, interest expense and penalties on the Statement of Income.
Segment Information
PacifiCorp curently has one segment, which includes its regulated elec1rc utility operations.
New Accounting Pronouncements
In Januar 2010, the Financial Accountig Stadads Board (the "FASB") issued Accountig Standards Update ("ASU")
No. 2010-06 ("ASU No. 2010-06"), which amends FASB Accounting Stadads Codification ("ASC") Topic 820, "Fair Value
Measurements and Disclosures" ("ASC Topic 820"). ASU No. 2010-06 requires disclosure of (a) the amount of significant transfers
into and out of Levels 1 and 2 of the fair value hierarchy and the reasons for those trnsfers and (b) gross presentation of purchases,
sales, issuances and settlements in the Level3 fair value measurement rollforward. This guidance clarfies that existing fair value
measurement disclosures should be presented for each class of assets and liabilities. The existing disclosures about the valuation
techniques and inputs used to measure fair value for both recurg and nonrecurng fair value measurements have also been clarfied
to ensure such disclosures are presented for the Levels 2 and 3 fair value measurements. This guidace is effective for interi and
annual reportg periods beginning after December 15, 2009, with the exception of the disclosure requirement to present purchases,
sales, issuaces and settlements gross in the Level 3 fair value measurement rollforward, which is effective for fiscal years begining
after December 15, 2010, and for interim periods within those fiscal year. PacifiCorp is curently evaluatig the impact of adopting
this guidance on its disclosures included within Notes to Financial Stateents.
In August 2009, the F ASB issued ASU No. 2009-05, which amends ASC Topic 820. ASU No. 2009-05 clarfies how to measure the
fair value of a liability for which a quoted price in an active market for the identical liabilty is not available. This guidance also
clarifies that both a quoted price in an active market for the identical liability at the measurement date and the quoted price for the
identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required
represent Levell fair value measurements. PacifiCorp adopted ths guidance as of October 1, 2009 and the adoption did not have a
materal impact on PacifiCorp's fmancial results and disclosures included within Notes to Financial Statements.
In April 2009, the FASB issued authoritative guidace (included in ASC Topic 820) that clarfies the determination of fair value when
a market is not active and if a transaction is not orderly. In addition, this guidace amends previous GAAP to require disclosures in
interim and annual periods of the inputs and valuation techniques used to measure fair value and a discussion of changes in valuation
techniques and related inputs, if any, -durg the period and defmes "major categories" consistet with those descrbed in previously
existing GAAP. PacifiCorp adopted this guidance as of April 1,2009 and the adoption did not have a materal impact on PacifiCorp's
financial results and disclosures included within Notes to Financial Statements.
IFERC FORM NO.1 (ED. 12-SS) Page 123.6
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp ì2) A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued). .~.
In December 2008, the FASB issued authoritative guidance (included in ASC Topic 715, "Compensation - Retiement Benefits") that
requires enhanced disclosures about plan assets of defined benefit pension and other postretiement benefit plans to enable investors
to better understand how investment allocation decisions are made and the major categories of plan assets. In addition, this guidance
requires disclosure of the inputs and valuation techniques used to measure fair value and the effect of fair value measurements using
significant unobservable inputs on changes in plan assets and establishes disclosurè requirements for significant concentrations of risk
within plan assets. PacifiCorp adopted this guidance as of December 31,2009 and induded the required disclosures within Notes to
Financial Statements. Refer to Note 11 for additional discussion.
In March 2008, the FASB issued authoritative gudance (included in ASC Topic 815, "Dervatives and Hedging") that requires
enhanced disclosures about derivative contracts and hedging activities to enable investors to better understad how and why an entity
uses derivative contracts and their effects on an entity~s financial results.PacifiCorp adopted this guidace as of March 31,2009 and
included the required disclosures within Notes to Financial Statements. Refer to Note 7 for additional discussion.
(3) Net Utilty Plant
Depreciable Lives
The average depreciable lives of utility plant curently in use by category are as follows:
Generation:
Steam plant
Hydroelectrc plant
Wind plant
Other plant
Transmission
Distrbution
Intangible plant (1)
Other
20-57 years
24- 80 years
25 years
15 -40 year
25 -75 years
44-52 years
5 - 50 years
5 -29 year
(1) Computer softare costs included in intagible plant are initially assigned a depreciable life of 5 to 10 year.
Utility Plant Acquisition
On September 15,2008, after having received the required regulatory approvals, PacifiCorp acquired from TNA Merchant Projects,
Inc., an affliate of Suez Energy Nort America, Inc., 100% of the equity. interests of Chehalis Power Generatig, LLC, an entity
owning a 520-megawatt ("MW") natual gas-fired generating facility located in Chehalis, Washington. The total cash purchase price
was $308 mìlion and the estimated fair value of the acquired entity was primarly allocated to the facilty. Chehalis Power
Generating, LLC was merged into PacifiCorp imediately following the acquisition. The results of the facilty's operations have been
included in PacifiCorp's financial statements since the acquisition date.
Unallocated Acquisiton Adjustments
PacifiCorp has unallocated acquisition adjustments that represent the excess of costs of the acquired interests in utility plant purchased
from the entity that first devoted the assets to utilty serice over their net book value in those assets. These unallocated acquisition
adjustments included in utility plant had an original cost of $157 mìlion as of December 31, 2009 and 2008, and accumulated
provision for depreciation, amortzation and depletion of $96 millon and $91 mìlion as of December 31, 2009 and 2008,
respectively.
I FERC FORM NO.1 (ED. 12-88)Page 123.7
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009104
NOTES TO FINANCIAL STATEMENTS (Continued)
Depreciation Study
In August 2007, P¡icifiCorp filed applications with the regulatory commissions in Uta, Oregon, Wyoming, Washington and Idao to
change its rates of depreciation prospectively based on a new depreciation study. PacifiCorp received approval to change the
depreciation rates effective Januar 1, 2008. The Oregon Public Utilty Commssion (the "OPUC") order required additional
modifications related to the depreciation lives of coal-frred generatig facilities, which were approved in August 2008. The revised
depreciation rates generally reflect an extension of the lives ofPacifiCorp's assets. The most significant change resulted in an increase
in the range of depreciable lives for steam plant from 20 - 43 year to 20 - 57 years. The revised depreciation rates resulted in a
benefit to income before income tax expense durng the year ended December 31, 2008 of approximately $47 milion.
(4) Jointly Owned Utility Faëilties
Under joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided intèrests in jointly
owned generation and transmission facilities. PacifiCorp accounts for its proportionate share of each facilty, and each joint owner has
provided financing for its share of each generating facility or trnsmission line. Operating costs of each facility are assigned to joint
owners based on their percentage of ownership or energy production, depending on the natue of the cost. Operating costs and
expenses on the Statement ofIncome include PacifiCorp's share of the expenses of these facilities.
The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility as of December 31, 2009
(dollars in milions):
Accumulated
Facilty Depreciation
PacifCorp in and
Share Servce Amortization
Jim Bridger Nos. 1 - 4 (1)67%$1,031 $508
Wyodk (1)80 339 183
Hunter No. 1 94 306 158
Colstr Nos. 3 and 4 (1)10 248 131
Hunter No. 2 60 194 95
Hermiston (2)50 174 45
Craig Nos. 1 and 2 19 168 85
Hayden No.1 25 46 24
Foote Creek 79 37 16
Hayden No. 2 13 28 16
Other transmission and distrbution facilities Varous 84 26
Total $2655 $1.2&7
(1) Inludes trsmission lines and substations.
(2) PacifiCorp has contrcted to purchase the remaning 50"10 of the outpt of th Herto generting facility.
Construction
Work-in-
Progress
$ 42
20
35
i
24
2
2
1
29$ 156
IFERC FORM NO.1 (ED. 12-88)Page 123.8
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
c
(5) Regulatory Matters
Regulatory Assets and Liabilties
Regulatory assets represent costs that are expected to be recovered in futue regulated rates. Regulatory liabilities represent income to
be recognized or amounts to be retued to customers in futue periods. PacifiCorp had regulatory assets not earing a retu on
investment of $1.85 bilion and $1.460 bilion as of December 31,2009 and 2008, respectively.
Rate Matters
Oregon Senate Bil 408 (USB 408")
SB 408 requires PacifiCorp and other large regulated, investor-owned utilities that provide electrc or natûral gas servce to Oregon
customers to file an annual report each October with the OPUC comparg income taxes collected and income taxes paid, as defined
by the statute and its administrative rules. If after its review, the OPUC determines the amount of income taes collected differs from
the amount of income taxes paid by more than $100,000, the OPUC must require the public utility to establish an automatic
adjustment clause to account for the difference.
In April 2008, the OPUC approved the recovery of $35 millon, plus interest, related to the 2006 ta year. The OPUC's April 2008
order on PacifiCorp's 2006 tax report is being challenged by the Industral Customers of Northwest Utilities, which filed a petition in
May 2008 with the Oregon Cour of Appeals seeking judicial review of the April 2008 order. PacifiCorp believes the outcome of
these proceedings wil not have a material impact on its financial results.
In October 2009, PacifiCorp filed its 2008 tax report under SB 408. PacifiCorp's filing forthe 2008 tax year indicated that PacifiCorp
paid $38 milion more in income taxes than was collected in rates from its retail customers. In January 2010, PacifiCorp entered into a
stipulation with OPUC staff and the Citizens' Utility Board of Oregon, agreeing to a lower recover totaling $2 milion, includig
interest. In April 2010, the OPUC issued an order adopting the stipulation in its entirety.
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 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(6) Fair Value Measurements
The caring amounts ofPacifiCorp's cash, certin cash equivalents, receivables, special funds, other investments, payables, accrued
liabilties and short-term borrowings approximate fair value because of the short-term matuty of these instrents. PacifiCorp has
varous financial assets and liabilities that are measured at fair value on the financial statements using inputs from the thee levels of
the fair value hierarchy. A financial asset or liability classification within the hierachy is determined based on the lowest level input
that is signficant to the fair value measurement. The thee levels are as follows:
· Level i - Inputs are unadjusted quoted prices in active makets for identical assets or liabilities that PacifiCorp has the
ability to access at the measurement date.
· Level 2 - Inputs include quoted prices for simlar assets or liabilities in active markets, quoted prices for identical or
similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset
or liabilty and inputs that are derived principally from or corroborated by observable market data by correlation or other
means (market corroborated inputs).
· Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market parcipants would use in
pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best
information available, including its own data.
The following table presents PacifiCorp's assets and liabilties reognized on the Compartive Balance Sheet and measured at fair
value on a recurng basis as of December 31, 2009 (in milions):
Input Levels for Fair Value
Measurements
Description Levell Level 2 Level 3 Other (1)Total
Assets (2):
Investments in available-for-sale securties:
Money market mutual fuds (3)$94 $$$$94
Commodity derivatives 285 6 (140)151
$94 $285 $6 $(J40)$245
Liabilties:
Commodity derivatives $$(274)$(386)$165 $(495)
(1) Prmarly represents nettng under maer nettng argem an a ne cah collal reeivale of $25 milli.
(2) Refer to Note 1 i for informaton regarding the fair value of peion an oth postetrent beefit plan assets as it is excludd from these amounts.
(3) Amunts ar included in other investments, other spial fuds an te cah invests on the Comptive Balance Sheet. The fair value of
these money market mutual fuds approximaes cost.
IFERC FORM NO.1 (ED. 12-88)Page 123.10
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009104
NOTES to FINANCIAL STATEMENTS (Continued)
The following table presents PacifiCorp's assets and liabilties recognized on the Comparative Balance Sheet and measured at fair
value on a recurng basis as of December 31, 2008 (in millons):
Input Levels for Fair Value
Measurements
Description Levell Level 2 Level 3 Other (1)Total
Assets (2):
Investments in available~for-sale securities:
Money market mutual funds (3)$17 $$$$17
Commodity denvatives 474 88 (302)260
$17 $474 $88 $(302)$277
Liabilties:
Commodity derivatives $$(485)$(496)$361 $(620)
(I) Prmarly represents nettng under master netting arangements and a net cash colIaterl receivable of$82 millon.
(2) Does not include investments in either pension or other postrtirement benefit plan assets.
(3) Amounts ar included in other investments, other special fuds and temporary cash investments on the Compartive Balance Sheet. The fair value of
these money market mutual fuds approximates cost.
PacifiCorp's investments in money market mutual funds are accounted for as available-for-sale secunties and are stated at fair value.
When available, a readily observable quoted market pnce or net asset value of an identical secunty in an active market is used to
record the fair value. In the absence of a quoted market pnce or net asset value of an identical. secunty, the fair value is determed
using pncing models or net asset values based on observable market inputs and quoted market pnces of secunties with similar
charactenstics.
When available, the fair value of denvative . contrcts is determined using unadjusted quoted pnces for identical contracts on the
applicable exchange in which PacifiCorp trsacts.. When quoted pnces for identical contracts ar not available, PacifiCorp uses
forward pnce cures denved from market pnce quotations, when available, or internally developed and commercial models, with
internal and external fundamental data inputs. Market pnce quotations are obtained from independent energy brokers, exchanges,
direct communication with market paricipants and actual transactions executed by PacifiCorp. Market pnce quotations for certin
major electncity and natual gas trading hubs are generally readily obtainable for the first six years; therefore, PacifiCorp's forward
pnce cures for those locations and penods reflect observable market quotes. Market pnce quotations for other electncity and natual
gas trding hubs are not as readily obtainable for the first six years. Given that limited market data exists for these contracts, as well as
for those contracts that are not actively traded, PacifiCorp uses forward pnce cures denved from internal models based on perceived
pncing relationships to major trading hubs that are based on significant unobservable inputs. Refer to Note 7 for fuher discussion
regarding PacifiCorp's nsk management and hedging activities.
Contrcts with explicit or embedded optionality are valuedl:Y separating each contract into its physical and financial forward, swap
and option components. Forward and swap components are valued against the appropnate forward pncecure. Option components
are valued using Black-Scholes-type models, such as European option, Asian option, spread option and best-of option, with the
appropnate forward pnce cure and other inputs.
IFERC FORM NO.1 (ED. 12-88)Page 123.11
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2Ç An Original (Mo, Da, Yr)
PacifiCorp '2) A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table reconciles the beginning and ending balances of PacifiCorp's commodity denvative assets and liabilities
measured at fair value on a recurng basis using significant Level 3 inputs for the years ended December 31 (in milions):
2009 2008
Beginning balance
Changes in fair value recognized in regulatory assets
Purchases, sales, issuances and settlements
Net trnsfers into or out of Level 3
Ending balance
$(408)
(5)
56
(23)
(380)
$(311)
- (98)
(12)
13
(408)$$
PacifiCor's long-term debt is carned at cost on the financial statements. The fair value of PacifiCorp's long-term debt has been
estimated based on quoted market pnces, where available, or at the present value of futue cash flows discounted at rates consistent
with comparable matunties with similar credit nsks. The caring amount of PacifiCorp's vanable-rate long-term debt approximates
fair value because of the frequent repncing of these instrents at maket rates. The following table presents the carrng amount and
estimated fair value ofPacifiCorp's long-ter debt as of Decembe 31 (in millons):
2009 2008
Carrng Fair Carrying Fair
Amount Value Amount Value
Long-ter debt $6357 $6,843 $5503 $5769
IFERC FORM NO.1 (ED. 12-88)Page 123.12
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp (2) A Resubriission 04/14/2010 .2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(7) Risk Management and Hedging Activities
PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to
electrcity and natul gas commodity price risk as it has an obligation to serve retail customer load in its regulated service terrtories.
PacifiCorp's load and generation assets represent substantial underlying commodity positions. Exposures to commodity prices consist
mainly of varations in the price of fuel required to generate electrcity and wholesale electrcity that is purchased and sold. Electrcity
and natual gas prices are subject to wide price swigs as supply and demand for these commodities are impacted by, among many
other unpredictable items, changing weather, market liquidity, generating facility availability, customer usage, storage, and
trsmission and transporttion constrints. Interest rate risk exists on variable-rate debt, commercial paper and futue debt issuances.
PacifiCorp does not engage in a material amount of proprieta trading activities.
PacifiCorp has estblished a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each
of the vaous types of risk involved in its business. To mitigate a porton of its commodity risk, PacifiCorp uses commodity
derivative contracts, including forwards, futues, options,. swaps and other agreements, to effectively secure futue supply or sell
futue production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to varable interest rates
and by monitoring market changes in interest rates. PacifiCorp may from time to time enter into interest rate derivative contrcts, such
as interest rate swaps or lòcks, to effectively modify PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in
place durng the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the
unhedged porton to changes in market prices.
There have been. no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Notes 2 and 6 for
additional information on derivative contracts.
The following table, which excludes contracts that qualify for the normal purchases and normal sales exception afforded by GAA,
sumarzes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts
presented on a net basis on the Comparative Balance Sheet as of December 3 1,2009 (in millons):
Balance Sheet Locations
Derivative Assets Derivative Liabilties
Current Noncurrent Current Noncurrent Total
Not Designated as Hedging Contracts (1)(2):
Commity assets
Commdity liabilities
Total
$$$8 $
(142)
(14)
$291
(660)
(369)
191
(29)
162
61
(17
44
31
(472)
(441)
Designated as Cash Flow-Hedging Contracts:
Commodity assets
Commdity liabilities
Total
Total derivaties
Cas collaterl receivable (payable)
Total derivatives - net basis $
162
(54)
108 $
44
(J
43 $
(134)
49
(85) $
(441)
31
(410)$
(369)
25
(344)
(1) Derivative contracts withn these categories are subject to mate nettng argements and are presented on a net basis on the Compartive
Balance Sheet.
(2) The majority ofPacifiCorp's commodity derivatives not designated as hedging contrcts are expected to be included in reguated rates and as of
December 31, 2009, a net regulatory asset of $367 millon was recorded related to the net derivative liabilties of $369 millon.
I FERC FORM NO.1 (ED. 12-88)Page 123.13
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009104
NOTES TO FINANCIAL STATEMENTS (Continued)
Not Designated as Hedging Contracts
For PacifiCorp's commodity derivatives not designated as hedging contracts, the settled amount is generally included in regulated
rates. Accordingly, the net unrealized gains and losses associated with interi price movements on contracts that are accounteçl for as
derivatives and probable of inclusion in regulated rates are recorded as net regulatory assets. The following table reconciles the .
beginning and ending balances of PacifiCorp's net regulatory assets and sumares the pre-tax gains and losses on commodity
derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earings for the year ended December 31 (in
milions):
2009
Beginning balance
Changes in fair value recognized in net regulatory assets
Gains reclassified to earnings - operatig revenues
Losses reclassified to earings ~ operation expenses
Ending balance
$442
(74)
222
(223)
367$
For PacifiCorp's derivatives not designated as hedging contracts and for which changes in fair value are not recorded as a net
reglatory asset or liability, unealized gains and losses are recorded on the Statements of Income as miscellaneous nonoperating
income for unrealized gains and as other deductions for unealized losses. The following table sumarzes the pre-ta gains (losses)
included within the Statement of Income associated with PacifiCorp's derivative contrcts not designated as hedging contrcts and
not recorded as a net regulatory asset or liability for the year ended December 31 (in millons):
Commodity derivatives:
Miscellaneous non-operatig income
Other deductions
Total
2009
$
23
(7)
6
Designated as Cash Flow Hedging Contracts
PacifiCorp uses dervative contrcts accounted for as cash flow hedges to hedge electrcity and natual gas commodity prices. The
gains and losses on these derivative contrcts ar recognzed in other comprehensive income. Derivative contrcts accounted for as
cash flow hedges were not material for the year ended December 31,2009. Hedge ineffectiveness on contracts with unealized gains
is recognized as miscellaneous non-operating income and hedge ineffectiveness on contracts with unealized losses is recognized as
other deductions. For the years ended December 31, 2009 and 2008, hedge ineffectiveness was insignificant.
IFERC FORM NO.1 (ED. 12-SS) Page 123.14
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 20091Q4
NOTES TO FINANCIAL STATEMENTS Cc;ontinued)
Derivative Contract Volumes
The following table sumarzes the net notional amounts of outstanding derivative contracts with fixed price terms that comprise the
mark-to-market values as of December 31 (in millions):
Unit of
Measure 2009
Commodity contracts:
Electrcity sales
Natual gas purchases
Fuel purchases
Megawatt hours
Decatherms
Gallons
(22)
201
14
Credit Risk
PacifiCorp extends unsecured credit to other utilities, energy marketers, financial institutions and. other market paricipants in
conjunction with wholesale energy supply and marketing activities. Credit risk relates to the risk of loss that might occur as a result of
nonperformance by counterparties on their contractul obligations to make or take delivery of electrcity, natul gas or other
commodities and to make financial settlements of these obligations. Credit risk may be concentrated to the extent that one or more
groups of counterparties have similar economic, industr or other characteristics that would cause their ability to meet contractul
obligations to be simlarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a
counterpart may default due to circumtances relating directly to it, but also the risk that a counterpart may default due to
circumstances involving other market paricipants that have a direct or indirect relationship with the counterpart.
PacifiCorp analyzes the financial condition of each significant wholesalecounterpart before entering into any transactions,
establishes limits on the amount of unsecured credit to be extended to each counterpar and evaluates the appropriateness of
unsecured credit limits on an ongoing basis. To mitigate exposure to the financial risks of wholesale counterpares, PacifiCorp enters
into nettng and collateral arrangements that may include margining and cross-product nettng agreements and obtaining third-part
guartees, letters of credit and cash deposits. Counterpares may be assessed interest fees for delayed payments. If required,
PacifiCorp exercises rights under these arangements, including calling on the counterpart's credit support arrangement.
Collateral and Contingent Features.
In accordace with industr practice, certain derivative contracts contain provisions that require PacifiCorp to maintain specific credit
ratings from one or more of the major credit ratig agencies on its unsecured debt. These derivative contracts may either specifically
provide bilateral rights to demand cash or other securty if credit exposures on a net basis exceed specified rating-dependent theshold
levels ("credit-risk-related contigent featues") or provide the right for counterarties to demand "adequate assurance" in the event of
a material adverse change in PacifiCorp's creditworthiness. These rights can var by contract and by counterpar. As of
December 31,2009, PacifiCorp's credit ratigs from the thee recognized credit rating agencies were investment grade.
The aggrgate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent featues
totaled $353 milion as of December 31, 2009, for which PacifiCorp had posted collateral of $80 millon. If allcredit-risk-related
contingent featues for derivative contrcts in liability positions had been trggered as of December 31,2009, PacifiCorp would have
been required to post $159 milion of additional collateraL. PacifiCorp's collateral requirements could fluctute considerably due to
market price volatility, changes in credit ratings or other factors.
IFERC FORM NO.1 (ED. 12-88)Page 123.15
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubtnission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
. (8) Short-Term Borrowings and Other Financing Agreements
PacifiCorp has two unsecured revolving credit facilities totaling $ I .395 bilion. The credit facilities include a fixed or varable
borrowing option for which rates var based on the borrowing option and PacifiCorp's credit ratings for its senior unecured
long-term debt securties. These facilties support PacifiCorp's comterCIal paper program and certin varablé-rate tax-exempt bond
obligations. As of December 3 I, 2009, PaCIfiCorp had letters of credit issued under the credit agreements totaling $220 millon to
support varable-rate tax-exempt bond obligations and had no borrowings outstanding under its credit facilities. In addition, the credit
facilities support $38 milion ofunenhanced varable-rate ta-exempt bond obligations as of December 31,2009. As of December 31,
2008, PacifiCorp had outstading commercial paper borrowings of $85 million at an average rate of i %. Each revolving credit
agreement includes a covenant not to exceed a specified debt-to-capitalization ratio of 0.65 to 1.0.. PacifiCorp was in compliance with
the covenants of its revolving credit and the other above-noted fmancing agrements as of December 3 1,2009.
The following table sumares PacifiCorp's availabilty under its two unsecured revolving credit facilties as of December 3 i, 2009
(in millions):
Total unsecured revolving credit facilties
Less:
Short-term debt (credit facility borrowings or commercial paper)
Support for unenhanced variable-rate tax-exempt bond obligations
Letters of credit supporting varable-rate ta-exempt bond obligations
Net unsecured revolving credit facilities available
$1,395
$
(38)
(220)
Ll37
Total bank commitment amounts under credit agreements:
Januar 1,2010 through July 6, 201 i
July 7,201 i though July 6, 2012
July 7, 2012 though October 23,2012
October 24,2012 through July 6,2013
$1,395
1,355
1,265
630
As of December 31, 2009, PacifiCorp had approximately $15 milion of additional letter of credit issued on its behalf to provide
credit support for certin transactions as required by third pares. These committed bank argements were all fully available as of
December 3 I, 2009 and have provisions that automtically extend the anual expiration dates for an additional year unless the issuing
ban elects not to renew a letter of credit prior to the expirtion date.
I FERC FORM NO.1 (ED. 12-88)Page 123.16
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(9) Long-Term Debt and Capital Lease Obligations
PacifiCorp's long-term debt and capital lease obligations were as follows as of December 31 (in millions):
ParValue Amount
Average
Interest
Rate
20082009
Amount
Average
Interest
Rate
Long-term debt:
First mortgage bonds:
5.0% to 9.2%, due through 2014 $1,047 $1,047 6.5%$1,185 6.6%
5.5% to 8.7%, due 2015 to 2019 862 858 5.6 511 5.7
6.7% to 8.5%, due 2021 to 2023 324 324 7.7 324 7.7
6.7% due 2026 100 100 6.7 100 6.7
5.9% to 7.7% due 2031 to 2034 500 499 7.0 499 7.0
5.3% to 6.4%, due 2035 to 2039 2,800 2,790 6.0 2,145 6.0
Tax-exempt bond obligations:
Variable rates, due 2013 (1)41 41 0.3 41 0.8
Variable rates, due 2014 to 2025 325 325 0.5 325 1.
Variable rates, due 2024 (1)176 176 0.2 176 0.9
Variable rates, due 2014 to 2025 (1) (2)113 113 3.8 113 3.8
5.6% to 5.7%, due 2021 to 2023 (1)71 71 5.6 71 5.6
6.2% due 2030 13 13 6.2 13 6.2
Total long-term debt $6372 $6.357 $5.503
Capital lease obligations:
8.8% to 14.8%, due though 2036 $59 $59 11.7 $65 11.6
(1)Secured by pledged first mortgage bonds generally at the same interest rates, matuty dates and redption prvisions as the.~-exempt bond
obligations.
(2)Interest rates curently fixed for a te at 3.4% to 4.1 %, with $45 millon and $68 millon scheduled to reset in 2010 an 2013, respectively.
The issuance ofPacifiCorp's first mortgage bonds is limited by available propért, earings tests and other provisions ofPacifiCorp's
mortgage. Approximately $19.8 bilion of the eligible assets (based on original cost) of PacifiCorp were subject to the lien of the
mortgage as of December 31,2009.
In Januar 2009, PacifiCorp issued $350 milion of its 5.50% Firt Mortgage Bonds due Januar 15, 2019 and $650 milion of its
6.00% First Mortgage Bonds due January 15, 2039. The net proceeds were used to repay short-term debt, fud capital expenditues
and for general corporate purposes.
In September 2008, PacifiCorp acquired $216 million of its insured varable-rate ta-exempt bond obligations due to the significant
reduction in market liquidity for insured varable-rate obligations. In November 2008, the associated insurance and related standby
bond purchase agreements were terminated and these varable-rate long-term debt obligations were remaketed with credit
enhancement and liquidity support provided by $220 millon of letters of credit issued under PacifiCorp's two unsecured revolxing
credit facilities.
IFERCFORM NO.1 (ED. 12-SS) 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 04/14/2010 20091Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
In July 2008, PacifiCorp issued $500 millon of its 5.65% Firt Mortgage Bonds due July 15,2018 and $300 milion of its 6.35% First
Mortgage Bonds due July 15,2038.
In March 2010, PacifiCorp received regulatory authority from the Idao Public Utilities Commssion to issue an additional
$2.0 bilion of long-term debt through Februar 28, 2015. PacifiCorp has regulatory authority from the OPUC to issue an additional
$2.0 bilion öf long-term debt. PacifiCorp must mae a notice fiing with the Washington Utilities and Transporttion Commission
prior to any future issuace.
As of December 31, 2009, $5.2 bilion of first mortgage bonds were redeemable at PacifiCorp's option at redemption prices
dependent upon United States Treasur yields. As of December 31,2009, $542 millon of varable-rate tax-exempt bond obligations
and $84 million of fixed-rate tax~exempt bond obligations were redeemable at PacifiCorp's option at par. The remaining long-term
debt was not redeemable as of December 31, 2009.
As of December 31, 2009, PacifiCorp had $517 million of lettrs of credit available to provide credit enhancement and liquidity
support for varable-rate tax-exempt bond obligations totaling $504 millon plus inteest. These commtted bank argements were
fully available as of December 31, 2009 and expire periodically though May 2012.
PacifiCor's letters of credit generally contain simlar covenants and default provisions to those contained in PacifiCorp's revolving
credit agreement, including a covenant not to exceed a specified debt-to-capitalization ratio of 0.65 to 1.0. PacifiCorp monitors these
covenants on a regular basis in order to ensure that events of default will not occur and as of December 31, 2009, PacifiCorp. was in
compliance with these covenants.
PacifiCorp has entered into long-term agreements that quaify as capital leases and expire at varous dates through October 2036 for
transporttion services, power purchase agreements, real estate and for the use of certin equipment. The trnsporttion servces
agreements included as capital leases are for the right to use pipeline facilties to provide natul gas to thee of PacifiCorp's
generatig facilities. Net assets accounted for as capital leas of $59 millon and $65 milion as of December 31, 2009 and 2008,
respectively, were included in net utility plant on the Compartive Balance Sheet.
As of December 31,2009, the annual matuties of long-term debt and capital lease obligations, excluding unamortzed discounts, for
2010 and thereafter ar as follows (in milions):
Long-Term Capital Lease
Debt Obligations Total
2010 $14 $9 $23
2011 587 8 595
2012 17 8 25
2013 261 12 273
2014 253 8 261
Thereafter 5,240 94 5,334
Total 6,372 139 6,511
Unamortzed discount (15)(15)
Amounts representig interest (1)(80)(80)
Total $6357 $59 $6.416
(I)Inteest expese on capital lease obligations is recorded as rent expene.
IFERC FORM NO.1 (ED. 12-88)Page 123.18
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da,Yr)
PacifiCorp ..(2) A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
.
(10) Asset Retirement Obligations
PacifiCorp estimates its ARO liabilities based upon detailed engineering calculations of the amount and ting of futue cash
spending for a third part to perfonn the required work. Spending estimates are escalated for inflation and then discounted at a
credit -adjusted, risk-free rate. Changes in estimates could occur. for a number of reasons, including plan revisions, inflation and
changes in the amount and timing of the expected work.
PacifiCorp does not recognize liabilities for AROs for which the fair value canot be reasonably estiated. Due to the indetermate
removal date, the fair value of the associated liabilities on certin trnsmission, distrbution and other assets canot curently be
estimted and no amounts are recognized on the financial statements other than those included in the regulatory removal cost liability
established via approved depreciation rates.
The change in the balance of the total ARO liabilty is summarzed as follows as of December 31 (in milions):
2009 2008
$
81
3
(5)
19
5
103
$
$
75
2
(4)
4
4
81
Balance, January 1
Additions
Retirements
Change in estimated costs (1)
Accretion (2)
Balance, December 31
$
(I) Results from changes in the timing and amounts of estimated cash flows for certin plant and mine reclamation.
(2) PacifiCorp records the accretion expense of asset retirement obligations as either a regulatory asset or liability.
Certain of PacifiCorp's decommssioning and reclamation obligations relate to jointly owned facilities and mine sites. For
decommssioning, PacifiCorp is commtted to pay a proportonate share of the decommissioning costs based upon its ownership
percentage, or in the case of mine reclamation obligations, PacifiCorp has commtted to pay a proportonate share of mine reclamation
costs based on the amount of coal purchased by PacifiCorp. In the event of default by any of the other joint parcipants, PacifCorp
potentially may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaultig
par's liabilty. PacifiCorp's estimated share of the decommssioning and reclamation obligations are primarly recorded as ARO
liabilities.
IFERC FORM NO.1 (ED. 12-SS) 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 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(11) Employee Benefit Plans
PacifiCorp sponsors defmed benefit pension plans that cover the majority of its employees and also provides certin postretirement
healthcare and life insurace benefits though varous plans for eligible retiees. In addition, PacifiCorp sponsors a defined
contrbution 401(k) employee savings plan (the "401(k) Plan"). Non-union employees hired on or after January 1, 2008 and certin
union new hires are not eligible to parcipate in the PacifiCorp Retiement Plan (the "Retiement Plan"). These employees are eligible
to receive enhanced benefits under the 401(k) Plan.
Pension and Other Postretirement Benefit Plans
PacifiCorp's pension plans include a non-contrbutory defined benefit pension plan, the Retirement Plan; the Supplemental Executive
Retirement Plan (the "SERP"); and certin joint trst union plan to which PacifiCorp contrbutes on behalf of certin bargaining
units. All non-union Retiement Plan participants, as well as certin union parcipants, ear benefits based on a cash balance formula.
Certin union employees covered under the Retirement Plan continue to ear benefits based on the employee's years of service and
average monthly pay in the 60 consecutive months of highest payout of the last 120 months, with adjustments to reflect benefits
estimated to be received from social securty.
The cost of other postretirement benefits, includig healthcar and life inurce benefits for eligible retiees, is accrued over the
active service period of employees. PacifiCorp funds these other postrtiement benefits though a combination of funding vehicles.
PacifiCorp also contrbutes to joint trst union plans for postretiement benefits offered to certin bargaining units.
Measurement Date Change
PacifiCorp adopted the measurement date provisions included in the authoritative guidace for retirement benefits at December 31,
2008, which requires that an employer measure plan assets and beefit obligations at the end of the employer's fiscal year. Effective
December 31, 2008, PacifiCorp changed its measurement date from September 30 to December 31 and recorded a $14 milion
transitional adjustment. The components of the measurment date change transitional adjustmnt were as follows on a pre-tax basis
(in milions):
Service cost
Interest cost
Expected retu on plan assets
Net amortization
Total
Pension$ 7
16
(18)
2$ 7
Other Postretiement$ 2
8
(7)
4$ 7
Total
$9
24
(25)
6
14$
The $ 14 milion tranitional adjustment included $ I 2 milion recorded as an increase in regulatory assets for the porton considered
probable of inclusion in regulated rates and $2 millon recorded as a reduction ($1 milion after-tax) in retained earings for the
porton not considered probable of inclusion in regulated rates. The $12 millon increas to regulatory assets is being amortzed over
three to 10 year based on agreements with varous state regulatory commssions. The recognition of service cost, interest cost and
expected retu on plan assets, totaling $8 millon, resulted in an incr in pesion and other postretirment liabilities. The
$6 millon net amortization represents recogntion of prior serce cost, net trsition obligation and acturial net loss and resulted in a
reduction in regulatory assets.
Curtailments
In August 2008, non-union employee parcipants in the Retireent Plan were offered the option to contiue to receive pay credits in
their curent cash balance formula of the Retiement Plan or receive equivalent fixed contrbutions to the 401(k) Plan. The election
was effective Januar 1, 2009 and resulted in the recognition of a $38 million curilment gain. PacifiCorp recorded $36 milion of the
curilment gain as a reduction to regulatory assets as of December 3 I, 2008, representing the amount to be retued to customer in
rates. The reduction to regulatory assets is being amortized over a perod of thee to i 0 years based on agrements with varous state
regulatory commissions.
IFERC FORM NO.1 (ED. 12-88) Page 123.20
Name of Respondent This Report is:Date of Report Year/Peri()d of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp 1(2) . A Resubmission 0411412010 20091Q4 ...
NOTES TO FINANCIAL STATEMENTS (Continued)
Effective December 31, 2007, Local Union No. 659 of the International Brotherhood of Electrcal Workers ("Local 659") electectto
cease paricipation in the Retirement Plan and partcipate only in the 401(k) Plan with enhanced benefits. As a result of this election,
the Local 659 paricipants' Retirement Plan benefits were frozen as of December 31, 2007. This change resulted in a $2 millon
curailment gain that was recorded as a reduction to regulatory assets as of December 31, 2008 based on the requirement to retu the
amount to customers in rates. The reduction to regulatory assets is being amortzed over a period of thee to 10 years based on
agreements with various state regulatory commissions. Also as a result of this change, PacifiCorp's pension liability and regulatory
assets each decreased by $13 millon.
Effective March 31, 2010, Utility Workers Union of America Local Union No. 127 ("Local 127") ceased parcipation in the
Retirement Plan and parcipate only in the 401(k) Plan with enanced benefits. As a result, the Local127 paricipants' Retirement
Plan benefits were frozen on March 31, 2010. The impacts of this change are not expected to significantly impact PacifiCorp's
financial results.
Change in Benefit Formula
Effective June 1, 2007, PacifiCorp switched from a traditional final-average-pay formula for the Retirement 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 liability and regulatory assets each decreased by
$111 milion.
NetPeriodic Benefit Cost
For puroses of calculatig the expected retu on plan assets, a market-related value is used. The market-related value of plan assets
is calculated by spreading the difference between expected and actual investment retus over a five-year period beginning after the
first year in which they occur.
Net periodic benefit cost for the plans included the following components for the years ended December 31 (in milions):
$
Other Postretirement
2009 2008 (2)
5 $7
33 33
(29)(28)
12 15
I
22 $27
Servce cost (I)
Interest cost
Expected retu on plan assets
Net amortiztion
Net amortization ofregulatoiy assets
Curilment gain
Net perodc benefi cost
$
Pension
2009 2008 (2)
16 $27
71 67
(70)(72)
10 7
(8)
(2)
19 $27$$
.Ti) Serce cost excludes $ II millon of contrbutions to the joint trt union pla durng each ofthe year ended December 31, 200 and 2008.
(2) Excludes the implit of the measuremnt date change and the portion of the curilment gains required to be returned to customers in rates. Refer
to "Measemnt Date Change" and "Curilments" above.
I FERC FORM NO.1 (ED. 12-88)Page 123.21
.".
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifCorp (2)A Resubmission 04/14/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Funded Status
The following table is a reconciliation of the fair value of plan assets for the years ended December 3 i (in milions):
Plan assets at fai value, beginning of year
Employer contrbutions
Participant contrbutions
Actual return on plan assets
Benefits paid
Plan assets at fair value, end of year
Pension
2009 2008
$692 $963
54 70
160 (224)
(81)(17
$825 $692
Other Postretirement
2009 200
$284
24
9
70
(3)
350
$378
42
14
(103)
(47)
284$$
The following table is a reconciliation of the benefit obligations for the year ended December 3 i (in millons):
Pension Other Postretirement
2009 2008 2009 2008
Benfit obligation, beginning of year $1,00 $1,111 $489 $536
Serce cost (I)16 34 5 9
Interest cost (I)71 83 33 41
Partcipat contrbutions 9 14
Plan amendments (I)(7)(4)(12)
Curilment (13)
Acturial loss (gain)124 (21)47 (56)
Benefits paid, net of Medicare subsidy (81)(117)(34)(43)
Cost of tennnation benefits
Benefit obligation, end of year $1199 $1070 $545 $489
Accumulated benefit obligation, end of year $I 178 $i 048
(I) Included in the pension and other postrret liabilties in contion with th meurt dae change in 2008 was additional serice cost of
$7 millon and $2 millon and additional inteest cost of $16 millon and $8 millon for th peion and other postretirent benefit plans,
respectively.
IFERC FORM NO.1 (ED. 12-88)Page 123.22
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da,Yr)
PacifiCórp I (2) A Resubmission 04/14/2010 2009/Q4
.NOTES TO FINANCIAL STATEMENTS (Continued)
The funded status of the plans and the amounts recognzed on the Comparative Balance Sheet are as follows as of December 31
(in millions):
Pension Other Postretirement
2009 2008 2009 2608
Plan assets at fair value, end of year $825 $692 $350 $284
Less -Benefit obligation, end of yea 1.99 1.070 545 489
Funded status $(374)$(38)$(195)$(205)
Amunts recognized on the Compartive Balance Sheet:
Othet current liabilities $(4)$(4)$$
Otr long-ter liabilities (30)(34)(195)(205)
Amounts recognized $(34)$(378)$(J95)$(205)
The SERP has no plan assets; however, PacifiCorp has a Rabbi trst that holds corporate-owned life insurance and other investments
to provide funding for the futue cash requirements of the SERP.The cash surender value of all of the policies included in the Rabbi
trst, net of amounts borrowed against the cash surender value, plus the fair market value of other Rabbi trst investments, was
$39 milion and $38 million as of December 31, 2009 and 2008, respectively. These assets are not included in the plan assets in the
above table, but are reflected on the Comparative Balance Sheet. The portion of the pension plans' projected benefit obligation related
to the SERP was $55 million and $50 milion as of December 31, 2009 and 2008, respectively. The SERP's accumulated benefit
obligation totaled $55 milion and $50 million as of December 31,2009 and 2008, respectively.
Unrecognized Amounts
The portion of the fuded status of the plans not yet recognized in net periodic benefit cost is as follows as of December 31 (in
millons):
Pension2009 2008 Other Postretirement2009 2008
Amunts not yet recognized as components of net perodic benefit cost:
Net loss
Pror servce (credit) cost
Net trsition obligation
Regulato deferrls (l)
Total
$523
(60)
$508
(68)
$135 $128
I
45
6
180$
(24)
439 $
(3)
408 $
29
5
169 $
(I) Consists of amooots related to the porton of the curlment gains and the measurment date change tritional adjustment that are considered
probable of inclusion in reguated rates.
IFERC FORM NO.1 (ED. 12-88)Page 123.23
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifCorp (2) A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
A reconciliation of the begining and ending balances of amounts not yet recognized as components of net periodic benefit cost for
the years ended December 31, 2009 and 2008 is as follows (in milions):
Accumulated
Other
Reglatory Comprehensive
Aset Loss, Net Total
Pension
Balanc, January 1,2008 $132 $6 $138
Net loss (gain) arsing durng the year 293 (2)291
Pnor servce credt arsing durng the yea (7)(7)Curilmnt gains (11)(n)Measemnt date change 6 6
Net amrtization (1)(9)(9)
Tota 272 (2)270
Balance, December 31, 2008 $404 $4 $408
Balance, Janua 1,2009 $404 $4 $408
Net loss ansing durng the year 29 5 34
Pnor service credit ansing durng the year (1)(1)Net amorization (2)(2)
Total 26 5 31
Balance, December 31, 2009 $430 $9 $439
Deferred
Regulatory Income
Asset Taxes Total
Other Postrtirement
Balance, Janua 1, 2008 $95 $27 $122
Net loss (gain) ansing durng the yea 91 (7)84
PnOl service cret arsing durng the yea (13)(13)Measement date change 6 6
Net amrtization (1)(19)(19)
Tota 65 m 58
Balance, Decemb 31, 2008 $160 $20 $180
Balance, Janua 1,2009 $160 $20 $180
Net loss arsing durng the year 4 3 7
Pnor service credt ansing durng the year (I)(1)Trasition obligation credit arsing durng the year (3)(3)Net amzation (14)(14)
Total (14)3 (11)
Balance, December 31, 2009 $146 $23 $169
(I)Included in the net amorzation for 2008 was $2 millon an $4 millon for the pension and other postretirement beefit plans, respectively, in
connection with the measurement date change in 2008.
The net loss, prior serice credit, net trsition obligation and regulatory deferls that will be amortzed in 2010 into net periodic
benefit cost are estimated to be as follows (in millons):
Net Prior Serve Net Trasition Regulatory
Loss Credit Obligati Deferral Total
Pension $32 $(9)$$(9)$14
Other postretirement 4 10 I IS
Total $36 $(9)$10 $(8)$29
IFERC FORM NO.1 (ED. 12-88)Page 123.24
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Plan Assumptions
Assumptions used to determine benefit obligations and net periòdic benefit cost were as follows for the year ended December 31:
Benefit obligatons as of the measurement date:
Discount rate
Rate of compensation increase
Pension Other Postretirement
2009 2008 2009 2008
5.80%6.90%5.85%6.90%
3.00 3.50 N/A NfA
6.90%6.30%6.90%6.45%
7.75 7.75 7.75 7.75
3.50 4.00 NfA N/A
Net benefit cost for the perod ended:
Discount rate
Expecte retu on plan assets
Rate of compenation increase
In establishing its assumption as to the expected retu on plan assets, PacifiCorp reviews the expected asset allocation and develops
retu assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
Assumed healthcare cost trend rates were as follows as of December 31:
Healthcare cost trend rate assumed for next yea - under 65
Healthcare cost trend rate assumed for next yea - over 65
Rate that the cost trend rate grdually declines to
Year that the rate reaches the rate it is assued to reman at - under 65
Year that the rate reaches the rate it is assumed to reman at - over 65
2009 2008
8%8%
8 6
5 5
2016 2012
2016 2010
A one-percentage-point change in assumed healthcare cost trend rates would have the following effects (in milions):
Increase (Decrease)
One Percentage-Point One Percentage-PointIncrease Decrease
Effect on total serce and inteest cost
Effect on other postretirement beefit obligation
$3
31
$(2)
(26)
IFERC FORM NO.1 (ED. 12-88)Page 123.25
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
-NOTES TO FINANCIAL STATEMENTS (Continued)
Contributions and Benefit Payments
Employer contrbutions to the pension, other postretirment benefit and joint trst union plans are expected to be $109 milion,
$25 millon and $12 million, respectively, durg 2010. Fundig to PacifiCorp's Retiement Plan trst is based upon the actuanally
deterined costs of the plan and the requirments of the Interal Revenue Code, the Employee Retiement Income Secunty Act of
1974 and the Pension Protection Act of 2006, as amended. PacifiCorp considers contrbuting additional amounts from time to time in
order to achieve certin fudig levels specified under the Pension Protection Act of 2006, as amended. PacifiCorp's funding policy
for its other postretirement benefit plans is to contrbute an amount equal to the sum of the net periodic benefit cost and the Medicare
subsidies expected to be eared durg the penod.
The Plan's expected benefit payments to parcipants for its pension and other postretirement benefit plans for 2010 though 2014 and
for the five years thereafter are sumarzed below (in millons):
Projected Benefit Payments
Other Postretirement
Pension Gross Medicare Subsidy Net of Subsidy
2010 $99 $34 $(3)$31
2011 102 37 (3)34
2012 104 39 (4)35
2013 11 1 41 (4)37
2014 116 43 (5)38
2015 -2019 525 239 (32)207
Plan Assets
Investment Policy and Asset Allocation
PacifiCorp's investment policy for its pension and other postrtiement benefit plans is to balance nsk and return through a diversified
portfolio of fixed income securties, equity securties and other alterative investments. Matuties for fixed income securties are
managed to targets consistent with prudent rik toleraces. Th plans retain outside investment advisors to manage plan investments
within the parameters outlined by the PacifiCorp Pension Conntte. PacifiCorp maages the investment portfolio in line with the
investment policy with suffcient liquidity to meet near-term benefit payments. The retu on assets assumption for each plan is based
on a weighted-average of the expected penormance for the tyes of assets in which the plans invest.
PacifiCorp's target allocations (percentage of plan assets) for the pension and other postretirement benefit plan assets are as follows as
of December 31,2009:
Cash and cash equivalents
Equity seurties (2)
Fixed-income securties (2)
Limited parership intersts
Pemi(l)
%
0- 1
53-57
33-37
8- 12
Other Postretirement(l)
%
0- 1
61 -65
33-37
1 -3
(1)PacifiCorp's penion plan trt includes a serate account that is us to fud beefits for the other postrtiment beefit plan. In addition to this
separte account, the assets for the other postretirement beefit plans are held in two Volunta Employees' Beneficiaries Association ("VEBA")
trts, each of which hàS its own investmt allocation strtegies. Taret alloctions for the other postrtirement benefit plans include the separte
account of the pension plan trst and the two VEBA trts.
For purses of taet allocaton percentages, investment fuds have been allocated .based on the underlying investments in equity and
fixed-income securties.
(2)
IFERC FORM NO.1 (ED. 12-88)Page 123.26
.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp i2). A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued).
The followìng table presents the faìr value ofPacìfiCorp's plan assets, by major category, as of December 31, 2009 (ìn mìllöns):
Input Levels for Fair Value Measurements
Levell (1)Level 2 (1)Level 3 (1)Total
Pension
Cash and cash equivalents $$4 $$4
Fixed-income securties:
United States goverent obligations 20 20
Corprate obligations 44 44
Interational governent obligations 65 65
Municipal obligation 2 2
Agency, asset and mortgage-backed obligations 43 43
Equity securties:
United States equity securties 296 2%
International equity securties 4 4
Investment fuds (2)95 168 263
Limited parership interests (3)80 80
Total (4)$415 $326 $80 $821
Other postretirement
Cash and cash equivalents $3 $$$3
Fixed-income securties:
Unite States goverent obligations 2 2
Corporate obligations 4 4
International goverment obligations 6 6
Agency, asset and mortgage-backed obligations 4 4
Equity securties:
United States equity securties 115 115
International equity securties 2 2
Investment fuds (2)101 104 205
Limited parership interests (3)8 8
Total (4)$223 $118 $8 $349
(i) Refer to Note 6 for additional discussion regarding the three levels oftle fair value hierarchy.
(2) Investmt funds for the pension and other postretirement benefit plans include investments of 14% and 29%, respectvely, in United States equity
securties;49% and 23%, respectively, in international equity securties; 13% and 17%, respectively, in United States governent obligations; 8%
and 10%, respectively, in corporate obligations; 9% and 11%, respectively, in interational governent obligations; and 7% and 10%, respectively,
in agency, asset and mortgage-backed obligations.
(3) Limited parerhip interests include severl private equity fuds that invest primaly in buyout, growth equity and ventu capitaL.
(4) Netreceivables of $4 milion and $1 millon, respectively, related to the pension and other postretirement benefit plans are excluded from the fair
value measurement hierchy.
When avaìlable, a readìly obserable quoted market price or net asset value of an ìdentical securty ìn an active market ìs used to
record the faìr value. In the absence of a quoted market price or net asset value of an ìdentical securty, the faìr value ìs determìned
usìng pricìng models or net asset values based on observable market ìnputs and quoted market prices of securities wìth sìmìlar
characteristìcs. When observable market data ìs not avaìlable,the faìr value ìs determedusìng unobservable ìnputs, such as
estimated futue cash flows, purchase multiples paìd ìn other comparable thìrd-par transactions or other ìnformatìon. Investments ìn
lìmìted parershìps are valued at estimated faìr value based on the Plan's proportonate share of the parershìps' faìr value as
recordedìuthe parershìps' most recently avaìlablefiancìal statements adjusted for recent actìvìty and forecasted retus. The faìr
values recorded ìn the partershìps' financìal statements are generally determìned based on closìng publìc market prices for publìcly
traded securties and as determìned by the general parers foróther ìnvestments based on factors ìncludìng estìmated futue cash
flows, purchase multiples paìd ìn other comparble thìrd-part transactìons, comparable publìc company trdìng multiples and other
ìnformatìon.
WERe FORM NO.1 (ED. 12-88)Page 123.27
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table reconciles the begining and ending balances ofPacifiCorp's plan assets measured at fair value using significant
Level 3 inputs for the year ended December 3 I, 2009 (in millons):
Limited Partership Interests
Pension Other Postretirement
Balance, January 1, 2009
Actul retu on plan assets still held at peod end (I)
Puchass, sales, issuaces and settlements
Balance, December 31,2009
$78
5
(3
80
$7
i
$$8
(I) Actu retu on pension plan assets for limited parerhip intest consisted of milize appreciation of $5 millon related to assets held at
December 31, 2009.
Defined Contribution Plan
PacifiCorp's 401(k) Plan covers substatially all employees. PacifiCorp's contrbutions are based priarly on each partcipant's level
of contrbution and canot exceed the maimum allowable for ta puroses to the 401(k) Plan. PacifiCorp's contrbutions were
$34 milion and $23 milion durg the year ended Deembe 31, 2009 and 2008, respectively. As previously described, certin
parcipants now receive enhanced benefits in the 401(k) Plan and no longer accrue benefits in the Retirement Plan.
I FERC FORM NO. 1 (ED. 12-88)Page 123.28
..
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009104
NOTES TO FINANCIAL STATEMENTS (Continued)
(12) Income Taxes
Income tax expense (benefit) consists of the following for the years ended December 31 (in milions):
2009 2008
Current:
Federal
State
Total
$(443)
2
(441)
$(64)
(6)
(70)
Deferred:
Federal
State
Total
646
34
680
276
36
312
Investment tax credits
Total income ta expense $
(4)
235 $
(4)
238
A reconcilation of the federal statutory income ta rate to the effective income ta rate applicable to income before income tax
expense is as follows for the years ended December 3 i :
2009 2008
Federal statutory tax rate
State taxes, net of federal benefit
Tax credits (1)
Other
Effective income tax rate
35%
3
(6)
(2)
30%
35%
3
(5)
1
34%
(I) Prmaly attbutable to the impact of federa renewable electrcity production ta credits related to qualifyng wind-powered generting facilities
that extend 10 yea from the date the facilties were placed in service.
I FERC FORM NO.1 (ED. 12-88)Page 123.29
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2. An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 20091Q4
NOTES TO FINANCIAL STATEMENTS (Continued)-.
.
The net deferred income ta liability consists of the following as of December 31 (in millons):
2009 2008
Deferred tax assets:
Employee benefits
Derivative contrcts
Regulatory liabilities
Other
$244
140
40
164
588
$246
169
42
130
587
Deferred tax liabilties:
Utility plant
Regulatory assets
Other
Net deferred ta liability
(2,381)
(838)
(35)
(3,254)
(2,666)
(1,656)
(880)
(50)
(2.586)
(1.992)$$
The sale of PacifiCorp to MEHC on March 21, 2006 trggered certin ta related events that remain unsettled. PacifiCorp does not
believe that the ta, if any, arsing from the ultiate settlement of these events wil have a materal impact on its financial results.
As of December 31, 2009 and 2008, PacifiCorp had a net liability of $75 milion and a net asset of $13 million, respectively, for
uncertin tax positions. As of December 31, 2009 and 2008, the net liability for uncertin tax positions included $6 millon and the net
asset for uncertai tax positions included $14 milion, respectively, of ta positions that, if recognized, would have an impact on the
effective tax rate. The remaining unecognized ta benefits relate to positions for which ultiate deductibility is highly certin but for
which there is uncertinty as to the timing of such deductibility. Recognition of these ta benefits, other than applicable interest and
pealties, would not affect PacifiCorp's effective ta rate.
The United States Internl Revenue Serice has closed its examation ofPacifiCorp's income ta retus though the 2003 tax year.
In most cases, state jurisdictions have closed their examations ofPacifiCorp's income tax retus though 1993.
I FERC FORM NO.1 (ED. 12-88)Page 123.30
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(13) Commitments and Contingencies
PacifiCorp is par to a varety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or
exemplary damages. PacifiCorp does not believe that such normal and routine litigation wil have a material effect on its fmancial
results. PacifiCorp is also involved in other kinds of legal actions, some of which assert or may asser claims or seek to impose fines,
penalties and other costs in substantial amounts and are described bèlow.
Legal Matters
In Februar 2007, the Sierra Club and the Wyomig Outdoor Council filed a complaint against PacifiCorp in the federal distrct cour
in Cheyenne, Wyoming, alleging violations of the Wyoming state opacity standards at PacifiCorp's Jim Bridger generatig facility in
Wyoming. Under Wyoming state requirements, which are par of the Jim Bridger generating facility's Title V permit and are
enforceable by private citizens under the federal Clean Air Act, a potential source of pollutants such as a coal-fied generating facilty
must meet minimum standads for opacity, which is a measurement of light that is obscured in the flue of a generatig facility. The
complaint alleged thousands of violations of assered six-minute compliance periods and sought an injunction orderig the Jim
Bridger generating facility's compliance with opacity limits, civil penalties of $32,500 per day per violation and the plaintiffs' costs of
litigation. In August 2009, the cour ruled on a number of sumary judgment motions by which it determined that the plaintiffs have
suffcient legal standing to proceed with their complaint and that all other issues raised in the sumary judgment motions wil be
resolved at tral. In February 2010, PacifiCorp, the Sierr Club and the Wyoming Outdoor Council reached an agreement in principle
to settle all outstading claims in the action. The settlement wil be memorialized in a consent decree to be fied with the United States
Environmental Protection Agency (the "EPA") for review and also with the cour for review and approvaL. If approved by the cour as
expected, the settlement is not expected to have a material impact on PacifiCorp's fmancial results.
Environmental Regulation
Environmental Matters
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, hazardous and solid waste
disposal, protected species and other environmental matters that have the potential to impact PacifiCorp' s curent and futue
operations. PacifiCorp believes it is in material compliance with curent environmental requirements.
New Source Review
As part of an industr-wide investigation to assess compliance with the New Source Review ("NSR") and Prevention of Significant
Deterioration ("PSD") provisions, the EPA has requested from numerous utilities information and supportng documentation
regarding their capital projects for various generating facilities. Between 2001 and 2003, PacifiCorp responded to requests for
information relating to its capital projects at its generating facilities, and it has been engaged in periodic discussions with the EPA
over several years regardig its historical projects and their compliance with NSR and PSD provisions. An NSR enforcement case
against another utility has been decided by the United States Supreme Cour, holding that an increase in. anual emissions of a
generatig facility, when combined with a modification (i.e., a physical or operational change), may trgger NSR permittg.
PacifiCorp could be required to install additional emissions controls, and incur additional costs and penalties, in the event it is
deermined that PacifiCorp's historical projects did not meet all regulatory requirements. The impact of these additional emissions
controls, costs and penalties, if any, on PacifiCorp's financial results cannot be determned at this tie.
IFERC FORM NO.1 (ED. 12-SS) page 123.31
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp ì2) A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Accrued Environmental Costs
PacifiCorp is fully or partly responsible for envionmenta remediation at varous contamiated sites, including sites that are or were
par of PacifiCorp's operations and sites owned by third pares. PacifiCorp accrues environmental remediation expenses when the
expenses are believed to be probable and can be reasonably estiated. The quatificatin of envionmental exposures is based on
many factors, including changing laws and regulations, advancements in environmental technologies, the quality of available
site-specific informtion, site investigation results, expected remedation or settlement tielines, PacifiCorp's proportonate
responsibility, contrctul indemnities and coverage provided by insurce policies. The liabilty recorded as of December 31, 2009
and 2008 was $7 millon and $11 millon, respectively, and is included in other deferred credits on the Comparative Balance Sheet.
Environmental remediation liabilties that separtely result from the normal operation of long-lived assets and that are legal
obligations associated with the retirement of those assets are separtely accounted for as AROs.
Hydroelectric Relicensing
PacifiCorp's hydroelectrc portfolio consists of 47 generatig facilities with an aggregate facility net owned capacity of 1,158 MW.
The FERC regulates 98% of the net capacity of this portolio though 16 individual licenses, which tyically have terms of 30 to
50 years. PacifiCorp expects to incur ongoing operatig and maintennce expense and capital expenditues associated with the term
of its renewed hydroelectrc licenses and settlement ageements, including natul resource enancements. PacifiCorp's Klamath
hydroelectrc system is curently operating under anual licenses. Substatially all ofPacifiCorp's remaining hydroelectrc generating
facilties are operating under licenses that expire between 2030 and 2058.
Klamath Hvdroelectric System - Klamath River. Oregon and California
In Februar 2004, PacifiCorp filed with the FERC a fmal application for a new license to operate the 170-MW Klamath hydroelectric
system in anticipation of the March 2006 expiration of the existig license. PacifiCorp is currently operating under an annual license
issued by the FERC and expects to continue operating unde anual licenses until the relicensing process is complete or the system's
four mainstem dams are removed. As part of the relicensing process, the FERC is requird to pedorm an environmental review and in
November 2007, the FERC issued its final environmental imact statement. The United States Fish and Wildlife Serice and the
National Mare Fisheries Service issued fmal biological opinions in Deember 2007 analyzig the Klamath hydroelectrc system's
impact on endagered species under a new FERC license consistent with the FERC staffs recommended license alternative and term
and conditions issued by the United States Deparents of the Inteor and Commerce. These ters and conditions include
constrction of upstream and downstream fish passage facilties at the Klamath hydroelectc system's four mainstem dams. Prior to
the FERC issuing a fmal license, PacifiCorp is required to obtain water quality cerfications from Oregon and California. PacifiCorp
curently has water quality applications pending in Oregon and Californa.
In November 2008, PadfiCorp signed a non~binding agreement in principle ("AI") that laid out a framework for the disposition of
PacifiCorp's Klamath hydroelectrc system relicensing process, including a path toward potential dam trnsfer and removal by an
entity other than PacifiCorp no earlier than 2020. Subsequent to release of the AlP, negotiations between the pares continued with an
expanded group of staeholders. A Tmal drft of the Klamth Hydroelectrc Settlement Agreement ("KHSA") was released in
Januar 2010 for public review. The partes to the KHSA, which include PacifiCorp, the Unitd States Deparent of the Interior, theUnited States Departent of Commerce, the State of Californa, the State of Orgon and varous other governental and
non-governental settlement parties, signed the KHSA in Febru 2010. Federal legislation to endorse and enact provisions of the
KHSA is expected to be introduced in the United States Congress in 2010.
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)
PacjfiCorp 1(2)A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
.
Under the terms of the KHSA, the United States Deparents of the Interior and Commerce wil conduct scientific and engineering
studies and consult with state, local and trbal governents and other stakeholders, as appropriate, to deterne by March 31,2012
whether removal of the Klamath hydroelectrc system' s four mainstem dam will advance restorntion. of the salmonid fisheries. of the
Klamath Basin and. is in the public interest. This deternation wil be made by the United States Secretary of the Interior. If it is
determined that dam removal should proceed, dam removal is expected to commence no earlier than 2020.
Under the KHSA, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilties. For da removal to
occur,federnllegislation consistent with the KHSA must be enacted to provide, among other things, protection for PacifiCorp from
all liabilities associated with dam removal activities. In addition, the KHSA limits PacifCorp's contrbution to da removal costs to
no more than $200 millon, of which up to $184 milion would be collected from PacifiCorp's Oregon customers with the remainder
to be collected from PacifiCorp's California customers. An additional $250 millon for dam removal costs is expected to be raised
through a California bond measure. If da removal costs exceed $200 milion and if the State of California is unable to rnisethe
funds necessar for dam removal costs, suffcient funds would need to be obtained elsewhere in order for the KHSA and dam removal
to proceed.
Actual removal of a facility would occur only after all permits for removal are obtained and the facility and associated land are
transferred toa dam removal entity. Prior to potetial removal of a facilty, the facilty wil generally continue to operate as it does
curently. However, PacifiCorp is responsible for implementing interi measures to provide additionaliesource protections, water
quality improvements, habitat enhancement for aquatic species and increased funding for hatcher operations in the Klamath River
Basin.
In July 2009, Oregon's governor signed a bil authoriing PacifiCorp to collect surcharges from its Oregon customers for Oregon's
share of the customer contribution for the cost of removing the Klamath hydroelectric system's four mainstem dams. On March 18,
2010, PacifiCorp fied with the OPUC to begin collecting the surcharge from Oregon customers, as of that date, subject to refud
based on the OPUC's determination that the surcharges result in rates that are fair, just and reasonable. Also, in March 2010,
PacifiCorp filed with the California Public Utilties Commission to collect a surcharge from PacifiCorp's California customers
begining January 1, 2011. The proceeds from the surcharges wil be deposited in trst accounts to be established by each of the
respective utilty commissions.
As of December 31,2009 and 2008, PacifiCorp had $67 millon and $57 milion, respectively, in costs related to the relicensing of the
Klamath hydroelectrc system included in constrction work in progress on the Comparative Balance Sheet.
Hydroelectric Commitments
As described above, certin of PacifiCorp's hydroelectrc licenses contain requirements for PacifiCorp to make cerin capital and
operatig expenditues related to its hydroelectrc facilties. PacifiCorp estimates it is obligated to make capital expenditues of
approximately $266 milion over the next 10 years related to these licenses.
FERCIssues
FERC Investigation
Durng 2007, the Western Electrcity Coordinatig Council (the "WECC") audited PacifiCorp's compliance with severnl of the
reliability standards developed by the Nort American Electrc Reliability Corporation (the "NERC"). In April 2008, PacifiCorp
received notice of a preliminar non-public investigation from the FERC and the NERC to determine whether an outage that occured
in PacìfiCorp's trsmission system in Februar 2008 involved any violations of reliability stadards. In November 2008, PacifiCorp
received preliminar. fmdings from the FERC staff regarding its non-public investigation into the Febru 2008 outage. Also in
November 2008, in conjunction with the reliability standads review, the FERC assumed control of certain aspects of the WECC's
2007 audit. PacifiCorp has engaged in discussions with FERC staff regarding fmdings related to the WECC audit and the non-public
investigation. However, PacifiCorp cannot predict the impact of the audit or the non-public investigation on its fmancial results at this
time.
IFERC FORM NO.1 (ED. 12-88) Page 123.33
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Northwest Refund Case
In June 2003, the FERC termnated its proceeding relatig to the possibilty of requirng refunds for wholesale spot-market bilateral
sales in the Pacific Nortwest between December 2000 and June 2001. The FERC concluded that orderig refunds would not be an
appropriate resolution of the matter. In November 2003, the FERC issued its fmal order denying rehearing. Several market
paricipants, excluding PacifiCorp, fied petitions in the United States Cour of Appeals for the Ninth Circuit (the "Ninth Circuit") for
review of theFERC's final order. In August 2007, the Ninth Circuit concluded that the FERC failed to adequately explain how it
considered or examined new evidence showig intentional maket maipulation in California and its potential ties to the Pacific
Northwest, and that the FERC should not have excluded from the Pacific Nortwest refud proceeding purchases of energy in. the
Pacific Nortwest spot market made by the California Energy Resources Scheduling ("CERS") division of the California Deparent
of Water Resources. Without issuing the mandate order, the Ninth Circuit remanded the case to the FERC..to (a) address the new
market manipulation evidence in detail and account for it in any future order regarding the award or denial of refuds in the
proceedings; (b) include sales to CERS in its analysis; and (c) fuer consider its refund decision in light of related, intervening
opinions of the cour. The Ninth Circuit offered no opinion on the FERC's findigs based on the record established by the
administrative law judge and did not rule on the merits of the FERC's November 2003 decision to deny refuds. In April 2009, the
Ninth Circuit issued a formal mandate order, completing the remand of the case to the FERC, which has not yet underten fuer
action. PacifiCorp cannot predict the futu coure of this proceedig and its impact on its fiancial results, if any, at this time.
Purchase Obligations
PacifiCorp has the following unconditional purchase obligations as of December 31, 2009 that are not reflected on the Comparative
Balance Sheet. Minimum payments required for the year ending December 31 (in millons):
2010 2011 2012 2013 2014 Thereafter Total
Purchased electrcity $262 $165 $124 $127 $98 $596 $1,372
Fuel 554 366 225 213 207 1,198 2,763
Constrction 677 172 32 7 18 99 1,005
Transmission 117 111 101 89 75 775 1,268
Operating leases 5 5 4 4 3 40 61
Other 107 29 10 10 6 43 205
Total commitments $ 1.722 $848 $496 $450 $407 $2751 $6674
Purchased Electricity
As par of its energy resource portolio, PacifiCorp acquies a porton of its electrcity through long-term purchases and exchange
agreements. PacifiCorp has several power purhase agreements with wid-powered and other generating facilities that are not
included in the table above as the payments ar based on the amount of energy generted and there are no minimum payments.
Included in the minimum fixed annual payments for purhased electrcity above ar commtments to purchase electrcity from several
hydroelectrc systems under long-term arangemets with public utilty distrcts. These purchases are made on a "cost-of-service"
basis for a stated percentage of system output and for a like percentage of system operating expenses and debt service. These costs are
included in operation expenses on the Statement of Income. PacifiCorp is required to pay its porton of operatig costs and its porton
of the debt servce, whether or not any electrcity is produced. These argements accounted for less than 5% of PacifiCorp's 2009
. and 2008 energy sources.
Fuel
PacifiCorphas "tae or pay" coal and natul gas contrcts that require minimum payments.
IFERC FORM NO.1 (ED. 12-88)Page 123.34
.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Constrction
PacifiCorp has an ongoing constrction program to meet increased electrcity usage, customer growt and system reliabilty
opjectives. As of December 31, 2009, PacifiCorp had estimated long-term purchase obligations related to its constrction program
primarly for the mstallation of emissions control equipment, certin segments of the Energy Gateway Transmission Expansion
Program and for new wid-powered generating facilties. Amounts included in the purchase obligations table above relate to fi
commitments. The amounts described below include amounts to which PacifiCorp is not yet fily committed though a purchase
order or other agreement.
PacifiCorp's Energy Gateway Transmision Expansion Program represents a plan to build approximately 2,000miles of new
high-voltage transmission lines, with an estimated cost exceeding $6 billon, primàrly in Wyoming, Utah, Idao, Oregon and the
desert Southwest. The plan includes several transmission line segments that will: (a) address customer load growth; (b) improve
system reliability; (c) reduce transmission system constraints; (d) provide access to diverse resource areas, including renewable
resources; and (e) improve the flow of electrcity throughout PacifiCorp's six-state service area and the Western United States.
Proposed trsmission line segments are re-evaluated to ensure maximum benefits and ting before commttng to move forward
with permitting and constrction. The first major tranmission segment associated with this plan is expected to be placed in servce
during 2010, with other segments placed in service through 2019, depending on siting, permtting and constrction schedules.
As par of the March 2006 acquisition of PacifiCorp, MERC and PacifiCorp made a number of commtments to the state regulatory
commissions in all six states in which PacifiCorp has retail customers. These commtments are generally being implemented over
severnl years following the acquisition and are subjectto subsequent regulatory review and approval. As of December 31,2009, the
status of the key financial commtments was as follows:
. Invest approximately $812 millon in emissions reduction technology for PacifiCorp's existing coal-fired generatig
facilities. Through December 31,2009, PacifiCorp had spent a total of $865 milion, including non-cash equity AFUDC,
on these emissions reduction projects. Durg 2010, PacifiCorp expects to file notification of its completion of this
commitment with the applicable state regulatory commssions.
. Invest in certin transmission and distrbution system projects that would enhance reliabilty, faciltate the receipt of
renewable resources and enable fuher system optimzation in an amount that was originally estimated to be
approximately $520 milion at the date of the acquisition. Though December 31, 2009, PacifiCorp had spent a tota of
$796 milion in capital expenditues, including non-cash equity AFUDC, which was in excess of the original estimate
due to the evolving natue of the projects agreed to in the commitment. This amount includes costs for the trnsmission
expansion program discussed above.
Transmission
PacifiCorp has agreements for the right to trnsmit electrcity over other entities' transmission lines to faciltate deliver to
PacifiCorp's customers.
Operating Leases
PacifiCorp leases offces, certain operatig facilities, land and equipment under operatig leases that expire at varous dates though
the year ending December 31, 2092. Certain leases contain renewal options for varying periods and escalation clauses for adjustig
rent to reflect changes in price indices. These leases generally require PacifiCorp to pay for insurance, taes and maintenance
applicable to the leased propert.
Net rent expense was $21 milion and $25 milion during the years ended December 31, 2009 and 2008, respectively.
I FERC 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 04/14/2010 2009/Q4
.. ...NOTES TO FINANCIAL STATEMENTS (Continued)
Other
PacifiCorp has purchase obligations related to equipment mainenance and varous other service and maintenance agreements.
(14) Preferred Stock
PacifCorp'spreferred stock, not subject to madatory redemption, was as follows as of December 31 (shares in thousands, dollars in
milions, except per share amounts):
Redemption
Price Per Share
2009
Shares Amoúnt
2008
Shares Amount
Series:
Serial Preferred, $100 stated value,
3,500 shares authorized
4.52% to 4.72%
5.00% to 5.40%
6.00%
7.00%
5% Preferred, $100 stated value,
127 shares authorized
$102.3 to $103.5
$100.0 to $101.0
Non-redeemable
Non-redeemable
$15
10
1
2
$15
10
1
2
157
108
6
18
157
108
6
18
$110.0 126
415 $
13
41
126
415 $
13
41
Generally, preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrctions. In the event of
volunta liquidatioii, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends.
Upon involunta liquidation, all prefered stock is entitled to stated value plus accrued dividends. Dividends on all preferred stock
are cumulative. Holders also have the right toelect 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 not yet due for payment on preferd stock wer $1 millon as of December 31, 2009 and 2008.
IFERC FORM NO.1 (ED. 12-SS) Page 123.36
.
Name of Respondent This Report is:Oate of Report Year/Period of Report
(1) ~ An Original (Mo, Oa, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(15) Common Shareholder's Equity
Through PPW Holdings LLC, MEHC is the sole shareholder of PacifiCorp's common stock. The state regulatory orders that
authorized MEHC's March 2006 acquisition of PacifiCorp contain restrctions on PacifiCorp's ability to pay dividends to the extent
that they would reduce PacifiCorp's common stock equity below specified percentages of defined capitalization.
As of December 31, 2009, the most restrctive of these commtments prohibits PacifiCorpfrom making any distrbution to PPW
Holdings LLC or MEHC without prior state regulatory approval to the extent that it would reducePacifiCorp's common stock equity
below 47.25% of its total capitalization, excluding short-term debt and curent matutiesoflong-term debt. This miimum level of
common equity declines to 46.25% for the year ending December 31,2010,45.25% for the year ending December 31,2011 and 44%
thereafter. The ters of this commtment treat 50% of PacifiCorp's remaining balance of preferred stock in existence prior to the
March 2006 acquisition of PacifiCorp by MEHC as common equity. As of December 31, 2009, PacifiCorp's actual çommon stock
equity percentage, as calculated under this measure, was 51 %, and PacifiCorp was permitted to dividend $92S milion under this
commitment.
These commitments also restrct PacifiCorp from making any distrbutions to either PPW Holdings LLC or MEHC if PacifiCorp's
unsecured debt rating is BBB- or lower by Standard & Poor's Rating Services or Fitch Ratings or Baa3 or lower by Moody's Investor
Service, as indicated by two of the three rating services. As of December31, 2009, PacifiCorp's unsecured debt ratig was A- by
Stadard & Poor's Ratig Services, BBB+ by Fitch Ratings and Baal by Moody's Investor Service.
PacifiCorp is also subject to a maximum debt-to-tota1 capitalization percentage under various financing agreements as fuher
discussed in NotesS and 9.
(16) Related-Party Transactions
Transactions with MEHC
PacifiCorp has an intercompany administrative services agreement with its indirect parent company, MEHC. Services provided by.
PacifiCorp and charged to affliates relate priarly to administrtive services, financial statement preparation and direct-assigned
employees; Receivables associated with these activities were $- millon and $1 millon as of December 3 C 2009 and 2008,
respectively. Servces provided by affliates and charged to PacifiCorp relate priarly to the administrative serices provided under
the intercompany administrative services agreement among MEHC and its affiiates. These expenses totaled $9 milion durng each of
the year ended December 31, 2009 and 2008. Payables associated with these expenses were $2 millon and $1 milion as of
December 31, 2009 and 2008, respectively.
PacifiCorp engages in varous transactions with several of its affliated companies in the ordiar course of business. Services
provided by affiiates in the ordinar course of business and charged to PacifiCorp relate primarily to the transporttion of natul gas
and relocation services. These expenses totaled $3 milion and $6 millon durng the years ended December 31, 2009 and 2008,
respectively. Payables associated with these expenses were $1 milion and $2 milion as of December 31, 2009 and 2008,
respectively.
PacifiCorp has long-term transporttion contracts with Burlington Northern Santa Fe, LLC ("BNSF"), a wholly owned subsidiar of
Berkshire Hathaway and PacifiCorp's ultiate parent company. Transportation costs under these contracts were $29 milion and
$32 millon duîg the years ended December 31, 2009 and 2008, respectively. As of December 3 i, 2009 and 2008, PacifiCorp had
$1 millon and $2 million, respectively, of accounts payable to BNSF outstanding under these contracts, including indirect payab1es
related to a jointly owned facility.
IFERC FORM NO.1 (ED. 12-88)Page 123.37
Name of Respondent This Report is:Date of Report Year/Period. of Report
(1) ~ An Original (Mo, Oa, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
PacifiCorp paricipates in a captive insurance progr provided by MEHC Insurance Services Ltd. ("MISL"),a wholly owned
subsidiary of MEHC. MISL covers all or significant portons of the propert damage and liabilty insurance deductibles in many of
PacifiCorp's curent policies, as well as overhead distrbution and trnsmission line propert 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 actuarial assessments and market rates to cover loss claim, administrtive expenses and appropriate reserves, but as a
result of regulatory commitments are capped though December 31,2010. Certin costs associated with the program are prepaid and
amortzed over the policy coverage period expirng March 20, 2010. Premium expenses were $7 milion durg each of the years
ended December 31, 2009 and 2008. Prepayments to MISL were $2 millon as of December 31, 2009 and 2008. Receivables for
claims were $10 milion and $7 millon as of December 31,2009 and 2008, respectively.
PacifiCorp is par to a ta-sharg agreement and is par of the Berkshir Hathaway United States federal income tax retu. As of
December 3 i, 2009 and 2008, income taes receivable from MEHC were $249 millon and $42 milion, respectively.
Transactions with Unconsolidated Subsidiaries of PacifCorp
In the ordinary course of business, PacifiCorp engages in varous transactions with its unconsolidated subsidiaries. Services provided
by PacifiCorp and charged to its subsidiaries relate priarily to management services, income taxes and labor. These receivables were
$4 million and $1 milion as of December 31, 2009 and 2008, respectively. Services provided by subsidiaries and charged to
PacifiCorp primaly relate to coal purchases. These payables were $10 milion and $14 million as of December 31,2009 and 2008,
respectively. Expeses for these coal purchases were $126 millon and $123 millon durg the years ended December 31,2009 and
2008, respectively.
PacifiCorp is par to an umbrella loan agreement with one subsidiar. Regulatory authoriations permt PacifiCorp to loan up to $30
million each to certain subsidiares and to borrow from each of these subsidiares, provided that the borrowings bear interest at rates
that do not exceed the interest rates that PacifiCorp would otherise incur externally. As of December 31,2009 and 2008, advances
by PacifiCorp under the ters of the umbrella loan agrement were $5 millon and $2 i millon, respectively, including interest.
(17) Supplemental Cash Flows Information
The sumar of supplemental cash flows information is as follows for the years ended December 31 (in milions):
Supplemental disclosure of non-cash investing and fmancing actvities:
Utiity plant additions in accounts payable
Utilty plant addtions acquired under capita lease obligations
200 2008
$322 $280
$(248)$(52)
$240 $398
$$17
Interest paid, net of amounts capitalized
Income taxes (received) paid, net
IFERC FORM NO.1 (ED. 12-88)Page 123.38
Name of Respondent .This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010 c
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amòunts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the accunts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
.
Line Item Unrealized Gains and Minimum Pension Foreign Currency Other
No.Losses on Available-Liabilty adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a)(b)(c)(d)(e)
1 Balance of Account 219 at Beginning of
Preceding Year 40,954 (3,557,338)
2 Preceding QtrlYr to Date Reclassifcations
from Acct 219 to Net Income
3 Preceding QuarterlYear to Date Changes in
Fair Value (171,723)1,137,427
4 Total (Iines2and 3)(171,723)1,137,427
5 Bålance of Account 219 at End of Preceding -QuarterlYear
6 Balance of Account 219 at Beginning of
Current Year (130,769)(2,419,911)
7 Current QtrlYr to Date Reclassifications
from Acct 219 to Net Income 191,182
8 Current QuarterlYear to Date Changes in ..
Fair Value (60,413)(3,399,666)
9 Total (lines 7 and 8)130,769 ..(3,399,666)
10 Balance of Account 219 at End of Current
QuarterlYear
--
.
FERC FORM NO.1 (NEW 06-02)Page 122a
Name of Respondent
PacifiCorp
This R.~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, ANDHEDGING ACTIVITIES
Year/Period of Report
End of 2009/Q4
Line
No.
Other Cash Flow
Hedges
Interest Rate Swaps
Other Cash Flow
Hedges
(Specify)
Totals for each
category of items
recorded in
Accunt 219
(h)
( 3,516,384)
(f)(g)
1
2
, 3
4
5
6
7
8
9
10
965,704
965,704
2,550,680)
2,550,680)
191,182
3,460,079)
3,268,897)
5,819,577)
Net Income (Carried
Forward from
Page 117, Line 78)
Total
Comprehensive
Income
FERC FORM NO.1 (NEW 06-02)Page 122b
.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp .(2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
f$chedule Page: 122(a)(b) Line No.: 5 Column: b
Unrealized loss on available-for-sale securties of ($210,751) less tax of$79,982 nettg to ($130,769).
~chedule Page: 122(a)(b) Line No.: 5 Column: e
Unrecognized amounts on retirement benefits of ($3,900,000) less tax of$ 1 ,480,089 nettng to ($2,419,911).
~chedule Page: 122(a)(b) Line No.: 10 Column: e
Unrecognized amounts on retirement benefits of ($9,379,000) less ta of $3,559,423 netting to ($5,819,577).
I FERC FORM NO. 1 (ED. 12-87)Page 450.1
a e 0 epo
(Mo, Da, Yr)
04114/2010
SUMMA Y OF UTILITY PLANT AND ACCUM LATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electrc function, in column (d) the amount for gas functon, in column (e), (f), and (g) report other (specify) and in
column (h) common function.
End of
(a)
Total Company for the
Current YearlQuarter Ended
(b)
Electric
(c)
Line
No.
Classification
Utilty Plant
2 In Service
3 Plant in Service (Classified)
4 Propert 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 Oters
10 Held for Future Use
11 Construction Work in Progress
12 Acquisition Adjustments
13 Total Utilty Plant (8 thru 12)
14 Accum Prov for Depr, Amort, & Depl
15 Net Utilit Plat (13 less 14)
16 Detaiiof Acum Prov for Depr, Amort & Depl
17 In service:
18 Deprecition
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Landan Rights
21 Amort of Other Utility Plant
22 Totalln Seric (18 thru 21)
23 Leased to Others
24 Depreciation
25 Amortizatin and Depletion
26 Tota Leased to Otrs (24 & 25)
27 Hel for Fut Use
28 Depreciation
29 Amortization
30 Tota Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amo of Plant Acquisition Adj
33 Total Accm Prov (equals 14) (22,26,30,31,32)
7 7.~.Æi~~"'77/ 77WÆP/
w~~,:"*~ %i 77;Wff~% .;;;; AM M JJ,1'/ZMf: t~A f?::!;XfI Wg # ;:
19,527,440,207
65,393,121
3,003,416
115,125,119
19,527,440,207
65,393,121
3,003,416
115,125,119
19,710,961,863 19,710,961,863
13,674,549
1,799,367,394
157,193,780
21,681,197,586
7,199,824,404
14,481,373,182
13,674,549
1,799,367,394
157,193,780
21,681,197,586
7,199,824,404
14,481,373,182
96,326,873
7,199,824,404
96,326,873
7,199,824,404
FERC FORM NO.1 (ED. 12'-89)Page 200
Name of Respondent
PacifiCorp
Gas
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Specify) Othi:r (Specify) Other (Specify)
Year/Period of Report
End of 2009/Q4
Common
(d)(e)(f)(g)(h)
Line
No.~;;;;;;i~'/:;;;;fl"."";;,~;;..;;;;...
~H...i"~.~.~../_~~~~ii..,;w¿p_..-~~II¿IIIIj'T~~~~' ~ ~¡f// / /.."II..~ Jí /. 12/12$'1 _.. ./ if .--¡tjt/iii pdø p/%ûM."WgK¡._.i./r/
32
33
FERC FORM NO. 1 (ED. 12-89)Page 201
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da,Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/04
FOOTNOTE DATA
fSchedule Page: 200 Line No.: 18
Depreciation is comprised of:
Depreciation
Depletion
Total
Column: c
$6,627,761,298
36,136,233
$6,663,897,531
I FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
ELECTRI PLANT IN SERVICE (Account 101,102,103 and 106)
1. Report below the original cost of electric plant in service according to the prescribed accunts.
2. In addition to Accunt 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account
103, Experimental Electric Plant Unclassified; and Account 106, Completed Constrction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For reVisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accunts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of
plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accmulated depreciation provision. Include also in column (d)ine ccount a ance itions
No. a Beginnin~ of Year
1 1. INTANGIBLE PLANT
2 (301) Organization
3 302) Franchises and Consents
4 (303) Miscellaneous Intangible Plant
5 TOTAL Intangible Plant (Enter Total of lines 2;3, and 4)
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights
9 (311) Structures and Improvements
10 (312) Boiler Plant Equipment
11 (313) Engines and Engine-Driven Generators
12 (314) Turbogenerator Units
13 (315) Accessory Electric Equipment
14 (316) Misc. Power Plant Equipment
15 (317) Asset Retirement Costs for Steam Production
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)
17 B. Nuclear Production Plant
18 (320) Land and Land Rights
19 (321 Structures and-Improvements
20 (322) Reactor Plant Equipment
21 (323 Turbo enerator Units
22 (324) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Proion Plant (Enter Total of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 330) Land and Land Rights
28 (331) Structures and Improvements
29 (332) Reservoirs, Dams, and Waterways
30 (333) Water Wheels, Turbines, and Generators
31 (334) Accessory Electric Equipment
32 (335) Misc. Power PLant Equipment
33 (336) Roads, Railroads, and Bridges
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
36 D. Other Prouction Plant
37 34) Land and Land R' hts
38 341) Structures and Improvements
39 (342) Fuel Holders, Products, and Accessories
40 (343) Prime Movers
41 (344) Generators
42 (345) Accesory Electric Equipment
43 (346) Misc. Power Plant Equipment
44 (347) Asset Retirement Costs for Other Production
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)
.;0%~~~y~:.:l'.W'''.7:~''.¥Mw..x.w 7/// W~_.///W:Z!1Jff / ~ / ~1!_,....,%iÁ/' / ø .', /ff)í,7 / Mid / . / iø/fJl_ 7 - ~.øJl/ Jl i:
.162,091,776
559,153,929
721,245,705
436,147
32,932,340
33,368,487
95,846,500
815,948,688
2,979,007,633
33,153
24,753,054
189,279,669
804,355,376
362,445,428
26,460,892
27,254,154
5,111,318,671
37,474,088
5,090,565
3,243,121
13,455,007
273,328,657
..1',.7......,.,~;~!..,.M
19,692,835
87,066,858
296,190,974
102,877,058
52,221,914
2,377,969
14,727,440
522,905
15,856,905
21,260,450
12,718,272
5,021,272
901
1,473,655
.w /:"~M.'''.' all'''.dkw /7f."Jl575,155,048 56,854,360
21,542,917
108,191,405
9,194,264
1,638,219,095
235,221,712
135,044,678
7,184,019
2,038,672
2,156,636,762
7,843,110,481
2,017,510
580,375,255
2,672,868
1,623,312
1,303,845
587,992,790
918,175,807
FERC FORM NO.1 (REV. 12-05)Page 204
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
ELECTRIC PLANT IN SERVICE Accunt 1D1,102, 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 text of Accunts 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 utility plant accounts. Include also in column (f) the additions or reductns of primary accunt
classifications arising from distribution of amounts initially recorded in Accunt 102, include in column (e) the amounts wit repe to acmulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offet 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 acct 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 Accunt 102, state the propert purchased or sold, name of vendor or purchase,
and date of transaction. If proposed joumal entres have been filed with the Comission as required by the Uniform Syste of Accounts, give also dateRetirements Adjustments Transfers Balanc at LineEnd lg)Year No.
Year/Period oIReport
End of 2009/Q4
17,626,119
17,626,119
162,527,923
589,907,847
752,435,770
15,447,697
15,447,697/;; ;Yg:Uø *P?..:WMjl,/ ø ;y;:¥;*~ ,; / /y//!/ 0 ;Y UP?!;Y ø jfjgn4;; E;;. 0i~ ;;.1'" Y;;0LJ:;;ii&u 1-idæ&;;w./& 0';&/ %df%Ak:A %1/ ,,$;;;;.ø4Y;; w/TJ~~.~~'~A2? % /% ~,,~~
3,270,654
41,687,173
95,879,653
838,579,575
3,124,068,006
1,148,487
-2,532,123
10,035,118
805,282
641,258
1,670,586
58,110,071
1,075,830
161,756
146,050
832,870,176
366,892,467
29,208,805
37,319,815
5,324,818,497
-1,718,760
-1,718,760?fi~~//~ ..!i.~// %~li¡P.
/% / ¥ ::ii./ i.i..ii?!i/ ....irllíf/. /,/y //0% / / / x.. / W;I.i%/l."fi.;0/ ._~ _&0 ~Ji// &0 i~J _
369
415,668
627,879
1,754,844
865,609
25,810
223,812
-5,757
1,809,322
-2,005,625
-2,403,951
2,663,277
38,067
-35,047
20,209,614
104,317,417
314,817,920
111,436,535
59,040,854
2,391,127
15,942,236
3,913,991 60,286 628,155,703/' i0.i~Ai¡¡ :: 1filji./'Ii1 l!~.~/ _...../ / / % / ~/ ßIi ~ %imff% / t~%~ /il .~/. ~y );p;; / 0/ 0J
1,973,791 23,516,708
37,255 45,277,745 155,449,405
1,617,410 10,811,674
18,494,425 75,986,169 2,276,086,094
109,64,532 347,539,112
39,889 93,593,961 230,222,062
4,995,666 12,179,685
689,117 4,031,634
18,571,569 333,778,391 3,059,836,374
80,595,631 -1,718,760 333,838,677 9,012,810,574
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
FERC FORM NO.1 (REV. 12.05)205Page
Name of Respondent
PacifiCorp
ine
No.
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)ccount a ance
Beginning of Year(a) (b
Year/Period of Report
End of 2009/Q4
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights
49 352) Structures and Improvements
50 (353) Station Equipment
51 354) Towers and Fixtures
52 (355) Poles and Fixtures
53 (356) Overhead Conductors and Devices
54 357) Underground Conduit
55 (358) Underground Conductors and Devices
56 (359) Roads and Trails
57 (359.1) Asset Retirement Costs for Transmission Plant
58 TO"TAL Transmission Plant (Enter Total Of lines 48 thru 57
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights
61 361) Structures and Improvements
62 (362) Station Equipment
63 (363 Stora e Battery Equipment
64 (364) Poles, Towers, and Fixtures
65 365) Overhead Conductors and Devices
66 (366) Underground Conduit
67 (367) Underground Conductors and Devices
68 (368) Line Transformers
69 (369) Services
70 (370) Meters
71 (371) Installations on Customer Premises
72 (372) Leased Propert on Customer Premises
73 (373 Street Lighting and Signal Systems
74 (374) Asset Retirement Costs for Distribution Plant
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380 Land and Land Rights
78 (381) Structures and Improvements
79 (382) Computer Hardware
80 (383) Computer Softare
81 (384) Communication Equipment
82 (385) Miscelaneous Regional Transmission and Market Operation Plant
83 (386) Ast Retirement Costs for Regional Transmission and Market Oper
84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Rights
87 (390) Structures and Improvements
88 (391) Ofce Furniture and Equipment
89 (392) Transportation Equipment
90 (393) Stores Equipment
91 394) Tools, Shop and Garage Equipment
92 (395) Laboratory Equipment
93 (396) PoWer Operated Equipment
94 (397) Communication Equipment
95 (398) Miscellaneous Equipment
96 SUBTOTAL (Enter Total of lines 86 thru 95)
97 (399) Other Tangible Propert
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98)
100 TOTAL Accounts 101 and 106)
101 (102) Electric Plant Purchased (See Instr. 8)
102 (Less) (102) Electric Plant Sold (See Instr. 8)
103 (103 Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)
95,350,555
70,696,617
1,148,864,289
433,558,992
553,638,259
730,267,034
3,209,582
7,490,175
11,453,447
3,675,164
4,945,391
168,201,623
46,195,433
32,204,534
35,261,518
2,246
39,549
79,954
v, ...I! / 0 f¿i 'îf2. %w4......_../ 0/ /% Z~ .1140 /~ ;;;#1 '/ i¿: /;f1/$// /; ;IB/; &/%; ~ik /j£'iF ø
3,054,528,950 290,605,412
46,526,763
58,354,467
731,786,998
1,457,804
873,534,943
620,174,971
279,913,506
677,463,735
1,023,120,299
535,288,103
187,558,731
8,813,849
5,439,651
304,432
69,434,219
41,600,184
16,500,354
13,471,362
25,162,081
47,892,005
25,352,511
8,253,578
65,164
61,496,138
499,185
5,105,989,492
1,904,514
1,437,860
256,817,915
-'Ji";:';7 /::;:r;:....~..
~ßrj..".... (¿...:Z:.;:t:i;;/
16,094,266
229,487,385
89,052,008
99,362,782
13,644,340
62,760,306
38,973,211
126,473,492
241,911,600
6,357,082
924,116,472
3,645,149
16,452,054
6,266,070
519,740
2,336,006
1,309,776
9,949,554
24,704,180
624,360
65,806,889
39,748
1,197,249,133
17,922,123,761
302,819,070
18,224,942,831
FERC FORM NO.1 (REV. 12-05)Page 206
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
Retirements
This ~ort Is: Date of Report
(1) ~An Original (Mo,Da, Yr)
(2) A Resubmission 04/14/2010
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)Adjustments Transfers Balance at
End lJYear
249,764
119,438
7,259,384
655,458
2,369,670
1,836,417
2,285,083
10,843,762
-2,859,155
1,149,469
-42,204
-1,108,932
101,061,038
86,366,332
1,306,947,373
480,248,436
583,430,919
762,583,203
3,211,828
7,529,724
11,535,0681,667
12,490,131 10,269,690 3,342,913,921
3,775
114,063
3,737,013
445,310
7,981,769
-8,569,947
52,407,949
66,526,605
788,914,257
1,457,804
909,346,119
633,551,900
292,200,023
701,110,916
1,062,949,128
559,763,102
187,209,616
8,809,120
5,789,008
3,068,657
1,194,825
1,514,900
8,063,176
877,512
8,591,513
69,893
-54,768
9,980
-11,180
1,009,400 62,391,252
1,937,045
5,328,574,83634,033,735 -198,836"~0 .~::" /0 .,. :i ~ 0/;/ f/.
~:??i / 0 ~.~j1..lT.J / l........./ / 0 0.( / 0 /~ / / // ilj'/// W ;;/wj~ % /;(;:A :tU;;i;$;y::~_ ,,/md.lJi;y ßy$ tø$;;/;ø;i;l;;0% ;: 1:~/g$/__~
106,129 16,200,395
1,766,143 160,936 231,527,327
24,307,943 142,615 81,338,734
5,380,345 -102,299 100,146,208
356,794 92,703 13,899,989
2,354,374 -24,302 62,717,636
3,261,240 67,056 37,088,803
4,958,902 -38,763 131,425,381
21,468,866 1,035,122 246,182,036
220,260 54,828 6,816,010
64,074,867 1,494,025 927,342,519
39,748
68,893,068 1,205,830,225
213,638,684 19,642,565,326
3,003,416
213,638,684 -1,718,760 58,153,885 19,645,568,742
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
76
77
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
FERC FORM NO.1 (REV. 12'(5)207Page
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
.FOOTNOTE DATA
!Schedule Page: 204 Line No.: 97Account Description
(a)
Column: b
Balance Beginning of Additions Retirements Adjustments Balance at End of
Year Year
(b)(c)(d)(e)(g)
$2,634,916 $$$$2,634,916
52,550,647 52,550,647
40,385,161 66,472 (2,017)191,550 40,641,166
12,180,880 (24,376)12,156,504
3,424,575 3,424,575
65,527,839 6,644,746 (2,488,958)69,683,627
17,699,562 17,699,562
10,652,772 10,652,772
17,001,312 1,522,774 (549,041)17,975,045
4,695,073 758,777 (1,556,936)3,896,914
1,180,419 8,500 (46,030)121,702 1,264,591
5,160,806 10,801 (11,914)5,159,693
2,11 7,020 333,480 (116,122)(169,377)2,165,001
615,912 (2,661)(22,807)(22,173)568,271
36,839,783 708,655 37,548,438
426,236 426,236
$ 273,092,913 $ 10,051,544 $(4,818,201)$121,702 $ 278,447,958
Column: c
Column: d
39921
39922
39930
39941
39944
39945
39946
39947
39948
39949
. 39951
39952
39960
39961
39970
399915
Land Owed in Fee
Lad Rights
Strctures
Surace - Plant Equipment
Surace - Electrc Power Facilities
Underground - Coal Mine Equipment
Longwall Shields
Longwall Equipment
Mainline Extension
Section Extesion
Vehicles
Heavy Constrction. Equipment
Miscellaneous General Equipment
Compurers - Mmnfrme
Mine Development and Road Extension
Coal Mine Asset Retirement Obligations
Total Plant Used in Mining Activities
¡Schedule Page: 204 Line No.: 97
See footnote line 97, colum b.
~chedule Page: 204 Line No.: 97
See footnote line 97, colum b.
¡Schedule Page: 204 Line No.: 97 Column: f
See footnote line 97, colum b.
~chedule Page: 204 Line No.: 97 Column: g
See footnote line 97, colum b.
~chedule Page: 204 Line No.: 101 Column: c
In August 2009, PacifiCorp received FERC approval in Docket Nos. EC09-86-000 and EC09-86-001, pursuant to section 203 of the
Federl Power Act, for the acquisition of a portion of a 69-kilovolt ("kV") electrc trsmission facility from Garkane Energy
Cooperative, Inc. The acquisition was completed in September 2009. The purchase included electrc transmission line facilties from,
and includig, the interconnect point at the Clifton Wilson substaton located in Hurcane, Utah to the Twin Cities substation located
in Hildale, Utah. In Februar 2010, the FERC approved the joural entres called for by the Uniform System of Accounts in Docket
No. ACIO-44-000. Accordigly, PacifiCorp cleared account 102, Electrc plant purchased or sold and recorded the purchase to the
appropriate plant accounts.
~chedule Page: 204 Line No.: 101 Column: f
On September 15,2008, after having received the requisite regulatory approvals, PacifiCorp acquired from TNA Merchant Projects,
Inc., an affliate of Suez Energy Nort America, Inc., 100% of the equity interests of Chehalis Power Generating,LLC ("Chehalis"),
an entity owning a 520-megawatt ("MW") natual gas-fired genertig facility located in Chehalis, Washington. The total cash
purchase price was $308 milion and the estimated fair value of the acquired entity was priarily allocated to the facility, which was
included in account 102, Electrc plant purchased or sold. Chehalis was merged into PacifiCorp immediately following the
acquisition. The results of the facility's operations have been included in PacifiCorp's financial statements since the acquisition date.
In May 2009, the Federal Energy Regulatory Commssion approved the joural entries called for by the Uniform System of Accounts,
with modifications to the purchase accountig adjustments for asset retiement obligations. Accordingly, PacifiCorp cleared.
account 102, Electrc plant purchased or sold andrecorded the purchase to the appropriate plant accounts. Refer to page 108,
Important Changes During the Year, Item 2, of this Form NO.1 for fuer discussion.
I FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
This ~ort Is:
(1) L:An Original
A Resubmission
Year/Period of Report
End of 2009/Q4
LineNo.
1 Land and Rights:
2
3 North Horn Mountain Coal Properties
4 Barnes Butte Substation
5 Wild Horse Wind Plant
6 Twelve Mile Wind Plant
7 Jumbers Point Substation
8 Mountain Greel1Substation
9 Hoggard Substation
10
11 Miscellaneous, each under $250,000:
12
13
14
15
16
17
18
19
20
21 Other Propert:
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
953,014
746,268
6,763,094
2,160,207
1,173,276
281,758
880,553
716,379
47 Total .¿¿..is. if %0./~ ..., ;:.11 13,674,549
FERC FORM NO.1 (ED. 12-96)Page 214
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCotp (2)A Resubmission 04/14/2010 .2009/Q4
FOOTNOTE DATA
I$chedule Page: 214 Line No.: 3 Column: c
The North Hom Mountain Coal Propertes are needed to access futue coal portals and federal coal reserves when existing East
Mountain coal mines are mined out.
I$chedu/e Page: 214 Line No.: 5 Column: c
Land purchased for wind fars with an estimated constrction date of 20 i 7 or befai:e subject to the timing of completion of the
Energy Gateway Transmission Expansion Project.
Ißchedule Page: 214 Line No.: 6 Column: c
Land purchased for wind farms with an estimated constrction date of 20 i 7 or before subject to the timing of completion of the
Energy Gateway Transmission Expansion Project.
Ißchedule Page: 214 Line No.: 11 Column: c
Varous dates and plans.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
CONSTRUC ION WORK IN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of project in process of constructon (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Accunt 1 07 of the Uniform System of Accunts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1 ,000,000, whichever is less) may be groupe..
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
1 Intangible:
2 Klamath River System Relicensing 66,907,218
3 C&T TriP II Energy Trading Systems 4,296,447
c 4 SAP license and maintenance enhancements 2,406,070
5 CY09 MS Offce and Windows TOM 1,240,898
6
7 Production:
8 Dave Johnston U3 SO~& PM Emission Control Upgrades 262,088,428
9 Dunlap Ranch I Wind Plant (111 MW)97,821,911
10 Dave Johnston U4 S02 & PM Emission Control Upgrades 70,299,477
11 Naughton U2 Flue Gas Desulfurization System 42,358,741
12 Naughton U1 Flue Gas Desulfurization System 33,583,859
13 Huntington U1 Clean Air - PM 33,479,214
14 Lewis River System Relicensing Implementation 17,919,864
15 Hunter U2 Clean Air-PM 17,094,809
16 Wyodak U1 S02 and PM Emission Control Upgrade 16,836,533
17 Hunter U1 Turbine Upgrade HP/IP/LP 16,132,380
18 Blundell U3 Project 14,719,647
19 North Umpqua River System Relicensing Implementation 15,137,164
20 Jim Bridger U1 S02 & PM Emission Control Upgrades .8,211,822
21 Huntington U1 S02 & PM Emission Control Upgrades 7,414,348
22 Jim Bridger U1 Turbine Upgrade HP/IP/LP 6,980,920
23 Huntington Water Effciency Management 4,953,348
24 Jim Bridger U3 S02 & PM Emission Control Upgrades 4,683,825
25 Dave Johnston U3 - Replace BoilerlTurbine Controls 4,473,082
26 Hunte U1 Main Contrs Replacement 4;316,284
27 Jim Bridger U1 Reheater Replacement 10 4,160,800
28 Dave Johnston U3 Low NOx Bumers 3,738,728
29 Huntington U1 Turbine Upgrade HPIIP/LP 3,716,010
30 Hunter U1 Economizer Replacement 3,563,421
31 Hunter U2 Turbine Upgrade HPIIP/LP 3,234,158
32 Huntingon U2 Steam Coil Air Preheaters ...3,151,162
33 Huntington U1 Economizer Replacement 3,098,384
34 Hayden Coal Unloading Facility 2,720,313
35 Ashton Dam Seepage Control 2,710,865
36 Hunter U1 Low Temp. SH Replacement 2,645,673
37 Jim Bridger U1 Generator Rewind 2,286,906
38 Jim Bridger NERC/CIPS Compliance Work .2,021,987
39 Huntington U2 Turbine Upgrade HP/IP/LP 1,900,057c
40 Hunter U3 Turbine Upgrade HP/IP/LP 1,821,121
41 Hunter U1 S02 & PM Emission Control Upgrades 1,778,231
42 Jim Bridger U3 Turbine Upgrade HP/IP/LP 1,667,653
43 TOTAL 1,799,367,394
FERC FORM NO.1 (ED. 12-87)Page 216
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) . CiA Resubmission 04/14/2010
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Accunt 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line Description of Project Construction work in ¡irogress -
No.Electric (Account 107)
(a)(b)
1 Jim Bridger U4 Turbine Upgrade HP/IP/LP 1,631,217
2 Gadsby NERC/CIPS Compliance Work 1,619,747,
3 Jim Bridger U2 Turbine Upgrade HP/IP/LP 1,609,899
4 Jim Bridger U1 Clean Air - NOx 1,596,678
5 Rogue River System Relicensing Implementation 1,583,989
6 Huntington NERC/CIPS Compliance Work 1,517,536
7 Dave Johnston U3 - Horizontal SH Replace 1,372,507
8 Currant Creek Block 2 Development 1,302,690
9 Dave Johnston NERC/CIPS Compliance Work .1,273,641
10 Currant Creek NERC/CIPS Compliance Work 1,264,948.
11 Hunter U2 Main Controls Replacement 1,246,758
12 Hunter U2 Economizer Replacement 1,185,291
13 Hunter U2 S02 & PM Emission Control Upgrades 1,182,674
14 Dave Johnston U3 - SSH Assembly/Header Replace 1,154,187
15 Lake Side Block 2 Development 1,150,254
16 Huntington U1 Clean Air - NOx 1,147,695
17 Wyodak NERC/CIPS Compliance Work 1,135,414
18 Bear River System Relicensing Implementation 1,209,691
19 Hunter NERC/CIPS Compliance Work 1,093,540
20 Hunter Cond PollW/Ash DCS Replacements 1,091,264
21 Jim Bridger U1 APH Baskets 10 1,081,682
22 Swift Slope Stabilzation (East Slope).1,040,165
23 Carbon NERC/CIPS Compliance Work 1,024,744
24 Colstrip U3-U4: Mercury Control 1,017,875
25 Huntèr U2 Low Temp. SH Replacement 1,004,336
26
27 Transmission:...
28 Populus-Terminal: Dbl Ckt 345 kV Transmission Line -623,130,078
29 Thre Peaks Sub: Install 345 kV Sub 35,784,861
30 Dave Johnston Bridger Midpoint 500kV Line 28,965,992
31 St George-Red Butte 138kV Line 19,048,921
32 Mona-Oquirr Line 16,982,292
33 Bridger Mona 500kV Line 14,445,,374
34 90 South-CW 345kV Line Double Circuit 9,474,814
35 Line 37 Conv to 115kV Bid Nickel Mt Sub 7,963,713
36 Upper Green River Basin - Jonah Field & ParadiSe Subs/Lines .7,501,436
37 Dave Johnston to Casper 230kV No 1 &2 Line Rebuild 6,795,527
38 Malin Sub Series Capacitor Replacement 3,272,341
39 Maintain TOT 4A-4B Transmission Capabilty .2,593,564
40 Oquirrh Terminal 345kV Line 2,293,063
41 Parrish Gap Const New 230-69kV Sub 2,255,824
42 Pinto Sub 345kV Series Capacitors 2,146,989
43 TOTAL 1,799,367,394
FERC FORM NO.1 (ED. 12-87)Page 216.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/04
(2) ¡=A Resubmission 04/14/2010
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" project last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
1 Califomia-Oregon Intertie Transfer Capabilty Incr 2,094,552
2 Wallula McNary 230kV Line ..1,922,536
3 Vickers Sub Add 46kV Circuit Breakers 1,253,290
4 West Point-New 138 kV Line & 40 MVA Sub 1,211,660
5 Southwest WY Silver Creek Build 138kV Line 1,204,429
6 Line 88 - 115kV Jerome Prairie to Cave Juncton 1,093,077
7 Outlook Sub Add 115kV Circuit Breaker 1,057,630
8 Dunlap Ranch I Wind Plant Ph1 Intercn 0203 1,053,950
..9 Chappel Creek 230kV Cimarex Energy 1,009,830
10
11 Distribution:.
12 Dowell Sub Const New 115kV Substation 4,477,613
13 Saratoga Sub Add 2nd Trnsf Rebid Tran Jumper 3,504,281
14 Norheast Instl2nd 4-12kV Tmsf 4-12kV 3,389,293
15 Texum Sub Rebid & Incr Capacity 25MVA 3,313,371
16 Community Park Sub Conv to 115-12 5kV 2,617,621
17 Copper Hils New 138-12 5kV Sub 2,581,075
18 Stevens Road Sub Add 2nd Xfmr & 3rd Fdr 2,466,443
19 City Creek Ctr New 40 MW Dev for PRI 2,133,261
20 Skypark Build New 138-12.5kV Substation 1,980,565
21 Tamarisk New 138-12.5kV Sub 1,137,847
22 Smifield Substation Add New Feeder 13 1,075,436
23
24 General:..
25 Mobile Radio Replacement Proect 18,805,636
26 Deer Creek Mine-Reconstruct LonaR Sysm 5,663,156
27 Mobile Radio Purch-implement VHF Spectrum 2,737,187
28 Control Center Disaster Recovery Imprv Ph 2 2,056,968
29 PCC/SCC Router Replacement TOM 1,647,926
30 IP Telephony Project 1,190,841
31 Deer Creek Mine-( 1) 60" Terminal Group 1,067,995
32
33 Miscllaneous pro each under $1 ,000,000 113,854,956
34
35
36
37
38 .
39
40
41
42
.
43 TOTAL 1,799,367,394-
FERC FORM NO.1 (ED. 12-87)Page 216.2
Name of Respondent
PacifiCorp
This ~o. rt IS:. Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (C), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable propert.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Year/Period of Report
End of 2009/Q4
emine
No.(a)
Balance Beginning of Year
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense
4 (403.1) Depreciation Expense for Asset
Retirement Costs
5 (413) Exp. of Elec. PIt. Leas. to Others
6 Transportation Expenses-Clearing
7 Other Clearing Accunts
8 Other Accounts (Specify, details in footnote):
6,343,121,197 6,343,121,197
27,072,473
500,235,934 500,235,9341 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired
13 Cost of Removal
14 Salvage (Credit)
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
oflines 12 thru 14)
1 Other Debí or Cr. Items (Describe, details in
fotnote):
17
18 Book Cost or Asset Retirement Costs Retired
Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
-~~-
195,151,937
50,740,495
5,823,180
240,069,252
6,663,897,531
2,512,694,439
195,151,937
50,740,495
5,823,180
240,069,252
60,609,652
6,663,897,531
2,512,694,439
Section B. Balances at End of Year According to Functional Classification
Steam Production
Nuclear Production
Hydraulic Prouction-Conventional
23 Hydraulic Production-Pumped Storage
24 Other Production
251,713,352
285,159,398
1,142,839,345
2,003,524,851
2 Transmission
27 Regional Transmission and Market Operation
28 General
2 TOTAL (Enter Total of lines 20 thru 28)
467,966,146
6,663,897,531
467,966,146
6,663,897,531
251,713,352
285,159,398
1,142,839,345
2,003,524,851
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 04/14/2010 2009/04
FOOTNOTE DATA
I§chedule Page: 219 Line No.: 4 Column: b
PacifiCorp records the depreciation expense of asset retiement obligations as either a regulatory asset or liability.
f$chedule Page: 219 Line No.: 8 Column: b
Depreciation of mining assets included in account 151 Fuel Stock - until consumed
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 Amortization
Total Other Accounts
$10,454,473
233,947
1,220,290
13,886,246
185,368
1,092,149
27,072,473$
I§chedule Page: 219 Line No.: 16 Column: b
Chehalis plant trsfer from account 102 Electrc plant purchased or sold
Other items including:
- Recovery from third paries for asset relocations and daaged propert
- Insurance recoveries
- Adjustments of reserve related to electrc plant sold
- Reclassifications from electrc plant
$53,162,249
7,447,403
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4(2) OA Resubmission 04/14/2010
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
1.Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the. advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
ACCunt 418.1.
ILine Description of Investment Date Acquired Date Of Amount or investment at
No.(a)(b)
Mal~rity Beginning of Year
(d)
1 PACIFIC MINERAS, INC .12/31/1991 ,
2 Common Stock 1
3 Capital Contributions 47,960,000
4 Undistributed Eamings 102,321,791
5 SUBTOTAL 150,281,792
6
7 PACIFICORp ENVIRONMENTAL REMEDIATION COMPANY 8/19/1994
8 Common Stock 1,000,000
9 Capital Contributions 13,719,625
10 Undistributed Subsidiary Earnings .6,518,730
11 SUBTOTAL 21,238,355
12
13 PACIFICORP FUTURE GENERATIONS, INC 9/19/1999
14 Undistributed Subsidiary Earnings -9,952
15 SUBTOTAL -9,952
16 '.
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31 .
32
33
34 c
35
36 .
37
38
39
40
41
.
42 Total Cost of Accunt 123.1 $62,679,6261 TOTAL 171,510,195
FERC FORM NO.1 (ED. 12-89)Page 224
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4(2) DA Resubmission 04/14/2010
INVESTMENT IN SUBSIDIARY COMPANIES (Accunt 123.1) (Continued).
4. For any securities; notes, or accunts that were pledged designate such securiies, notes, or accunts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disosed of during the year.
7. In column (h) report for each investment disposed of during the year, the gan or loss represented by the difference between cost of the investment (or
the other amount at which carred in the books of account if differece from cost) and the selling prce thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, cOlunin(a) the TOTAL cost of Accunt 123.1
t:quity in SUbSidiary Revenues for Year AIount Of investment at uain or LOSS from Investment Line
Eamin~~tf Yéar
(f)
EndtJtear DiSp~Wrd of No.
1
1 2
47,960,000 3
113,708,071 4
11,386,280 161,668,072 5
6
7
1,000,000 8
13,719,625 9
1,811,740 8,330,470 10
1,811,740 23,050,095 11
12
13~-9,952 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
13,198,020 184,718,167 -9,952 42
FERC FORM NO.1 (ED. 12-89)Page 225
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ó An Original (Mo, Da, Yr)
PacifiCorp .'2)A Resubmission 04/14/2010 2009/04
FOOTNOTE DATA
ISchedule Page: 224 Line No.: 4 Column: e
Pacific Minerals, Inc. ("PMI") is a wholly owned subsidiar ofPacifiCorp that holds a 66.67% ownership interest in Bridger Coal
Company, a coal mining joint ventue with Idaho Energy Resources Company, a subsidiar ofIdao PowerCompany. Equity
earings on PacifiCorp's investment in PMI represent intercómpany profit in Bridger Coal Company's sales of coal to PacifiCorp.
Such amounts are not recorded in account 418.1 Equity in Earings of Subsidiar Companies. Rather, PacifiCorp records PMI's
earnings before interest and taxes as an offset to fuel inventory, which is charged to fuel expense as consumed, aîd records interest
and taes in their respective line items.
¡Schedule Page: 224 Line No.: 14 Column: h
Effective December 3 i, 2009, PacifiCorp Futue Generations, Inc. and its subsidiar Canopy Botanicals, Inc. were dissolved.
I FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This ~ort Is:..Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2009/04(2)OA Resubmission 04/14/2010 End of
MATERIALS AND SUPPLIES
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the departent or departments which use the class of materiaL.
2. Give an explanation of importnt inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing account, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
. . clearing, if applicable.
Line Account Balance Balance Department or
No.Beginning of Year End of Year Departments which
Use Material
(a)(b)(c)(d)
1 Fuel Stock (Account 151)136,802,882 170,930,143 Electrc
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Exracted Products (Account 153)
4 Plant Materials and Operating Supplies (Accunt 154)
5 Assigned to - Construction (Estimated)76,746,318 69,236,794 Electric
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)71,228,040 87,614,292 Electric
8 Transmission Plant (Estimated)497,646 838,582 Electric
9 Distribution Plant (Estimated)16,772,938 16,134,398 Electric
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote)Electric
12 TOTAL Account 154 (Enter Total of lines 5 thru 11)170,075,369 178,147,022
13 Merchandile (Accunt 155)
14 Other Materials and SuppUes (Account 156)
15 Nuclear Materials Held for Sale (Accunt 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163)
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)306,878,251 349,077,165
FERC FORM NO.1 (REV. 12-05)Page 227
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009104
FOOTNOTE DATA
I$chedule Page: 227
MiningM&S
General Plant M&S
Line No.: 11
$4,656,652
173,775
$4,830,427
Line No.: 11
$4,170,119
152,837
$4,322,956
Column: b
!Šchedule Page: 227
MiningM&S
General Plant M&S
Column: c
I FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
Year/Period of Report
2009/Q4End of
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmission 04/14/2010
Allowances (Accounts 158.1 and 158.2)
1. Report below the particulars (details) called for concerning allowances.
2. Report all acquisitions of allowances at cost.
3. Report 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 ü)-(k).
5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
Line S02 Allowances Inventory Currnt Year 2010
No. (Account 158.1)
(a)
1 Balance-Beginning of Year
2
3
4
5
6
7
8 Purchaseslransfers:
9
10
11
12
13
14
15 Totl
16
17
18
19
20
21 Cost of SalesfTransfers:
22 see footnote for deta
23
24
25
26
27
28 Total
29 Balance-End of Year
30
31
32
33
34
35
Acquired During Year:
Issued (Less Withheld Allow)
Retumed by EPA
0;; ¡: 7 7 7¡/!Yi.wt ~.if/r¡f.jY/:fJ!;;4A7 ii¥.6.~£1i....~ ¡jf........Y//Si/qy~:f/ 0 /// A%~if ~.qy;;/ tiL; ;; ß~Æ~&Wyy ¿¿ _:: /~ %
~%..l'~ 0 Ajf0/ w/ ~.//7..._f!...ff.Ø.'10 7%/ ;;:...0 ....q:.......~.~~0~Æ.;; 77; Ø/ % Y ;; 4;f ~1: Y__.~;:t0_ $Æ¡tMjh*ÆØÆ~ wxAØlf.ßJ%f:w;!:fa i; y ;; /",- ;;Ørj% i;;$
:/' ~~- -~ ~ ~~~ ~- --~~ ~~~ ~/0~.l. 7~_~i~j7;;A
iiY/~ 0Øj¡í! ~j¡i%¿;iil/li!.i / ii;irfIl£P:0 /p/%f 0W1¡¿jWt;1dW7t.n................................"/;; /// "$/!!%Y; //;U9Å¥i%;0Òj_0K/;;ft7/gpÆi:¥~y?i~ß#)J~ " . w;1JiW.ø'" _Wi Wi w)M;;Y;
Relinquished During Year:
Charges to Account 509
Other:
47,500.0
26,951.0 144,002.00
36
37
38
39
40
41
42
43
44
45
46
Sales:
Net Sales Proceeds(Assoc. Co.)
Net Sales Proceeds (Other)
Gains
Losses
Allowances Withheld (Acct 158.2)
Balance-Beginning of Year
Add: Withheld by EPA
Deduct: Returned by EPA
Cost of Sales
Balance-End of Year
MY 0."~0 7;;;.~~1î/5/7 ~7~_~
Sales:
Net Sales Proceeds (Assoc. Co.)
Net Sales Proces (Other)
Gains
Losses
.FERC FORM NO.1 (ED. 12-95)Page 2288
Name of Respondent
PacifiCorp
Year/Period of Report
2009/Q4End of
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmission 04/14/2010
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 UniforrnSystem of Accounts).
8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies.
9. Reportthe net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.
10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
Amt.
(g)
Future YearsNo. Arrt.
k
Totals Line
No.
2011
2,259.00 2,259.00
FERC FORM NO.1 (ED. 12-95)Page 229a
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)..
PacifiCorp (2)A Resubmission 04/14/2010 2009104
FOOTNOTE DATA
Išchedule Page: 228 Line No.: 22 Column: b
The names of purchasers/transferees and the number of allowances disposed of in the curent year are provided below.
Vitol, Inc.
NRG Power Marketing LLC
Koch Supply and Trading, LP
Edison Mission Marketing and Tradiig, Inc.
Ohio Valley Electrc Corporation
CE2 Environmental Opportities I LP
CE2 Environmental Markets LP
Shell Energy North America (US), LP
AES Deepwater, Inc.
18,000
10,000
7,500
5,000
2,500
1,250
1,250
1,000
1,000
47,500
I FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/14/2010
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
Line Description of Unrecovered Plant WRITTEN OFF DURING YEARrotalCosts Balance atNo.and Regulatory Study Costs (Include Amount Recognisedin the description of costs, the date of of Charges During Year Accunt Amount End of Year Commission Authorization to use Acc 182.2 Charged
and period of amorization (mo, yr to mo, yr))
(a)(b)(c)(d)(e)(f)
21 Unrecovered Plant: Trojan Nuclear 3,479,179 407 1.670,007 1,809,172
22 Plant located near Portland, OR 0
.
23 Date of Retirement: 12/31/1992
24 Date of Commission Authorization:
25 04/20/1993
26 Amortization Period: 01/1993
27 through 01/2011 . ...
28
29 Unrecovered Plant: Powerdale 6,959,922 407 3,479,961 3,479,961
30 Hydro Electc Plant
31 Date of Retirement: 02/08/2007
32 Date of Commission Authorization:
33 05/14/2007 .
34 Amortization Period: 05/2007 .
35 hrough 12/2010
36
37
38
39
40
41
42 .
43
44
45
46
47
48
49 TOTAL 10,439,101 5,149,968 5,289,133
FERC FORM NO.1 (ED. 12-88)Page 23Gb
This ~ort Is: Date of Report
(1 ) ~ An Original (Mo. Da. Yr)
(2) A Resubmission 04/14/2010
Transmission Servce and Generation Intercnnection Study Costs
1. Report the particulars (details) called for conceming the costs incurred and the reimbursments received for perfrming transmission service and
generator interconnection studies.
2. List each study separately.
3. In column (a) provide the name of the study.
4. In Column (b) report the cost incurred to perform the study at the end of period.
5. In column (c) report the account charged with the cost of the study.
6. In coumn (d) report the amonts received for reimbursement of the study costs at end of period.
7. In column (e) report the account credited with the reimbursement recived for performing the study.
ine
No.Descrption
(a)
Transmission Studies
2 i§
Costs Incurrd During
Period
(b)
eim ursements
Received During
the Period
(d)
Account Credited
With Reimbursment
(e)
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
3 Aref 557400
4 Aref 558590
5 Aref 508134
6 Aref 523183
7 Aref 531024
8 Aref 527444,527445,527464
9 Aref 526124
10 Aref 526123
11 Aref 546410
12 Aref 560666
13 Aref 563056
14 Aref 567900
15 Aref 575862
16 Aref 578260
17 Aref 581025
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
Customer Studies Accruals
6,598 5616000
14,459 5616000
3,195 5616000
100 5616000
873 5616000
2,603 5616000
824 5616000
1,826 5616000
1,366 5616000
15,044 5616000
4,892 5616000
4,835 5616000
6,210 5616000
5,391 5616000
3,629 5616000
3,541 5616000
1,285 5616000
100 1070000
393 1070000
Aref495604
Aref 516316
Generation Studies
GIQ0102
GIQ0093
GIQ0169
GIQ0190
GIQ0128
GIQ0194
GIQ0197
GIQ0210
GIQ0130
GIQ0220
GIQ0148
GlQ0135
GIQ136
GIQ0137
GIQ0208
GIQ0153
GIQ0175
GlQ0229
GIQ0231
1,222 5617000
960 5617000
60 5617000
523 5617000
13,503 5617000
360 5617000
811 5617000
2,987 5617000
913 5617000
629 5617000
144 5617000
2,040 5617000
626 5617000
1,505 5617000
888 5617000
435 5617000
530 5617000
9,716 5617000
17,374 5617000
1,222 4562000
960 4562000
60 4562000
523 4562000
13,503 4562000
360 4562000
811 4562000
2,987 4562000
913 4562000
629 4562000
144 4562000
2,040 4562000
626 4562000
1,505 4562000
888 4562000
435 4562000
688 4562000
9,716 4562000
17,374 4562000
FERC FORM NO.1/1-F/3-Q (NEW. 03-07)Page 231
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
Transmission Service and Generation IntercòiinectÎon Study Costs
Year/Period of Report
End of 2009/Q4
(continued)
Description
(a)
1 Transmission Studies
2 Aref 530263
3 Aref 495604
4 Aref531617
5 Aref541087
6 Aref 540950
7 Aref 548695
8 Aref 552990
9 Aref 554206
10 Aref 578305
11 Aref 575662
12 Aref 575869
13 Aref 583614
14 Aref 583608
15
16
17
18
19
20
21 Generation Studies
22 GIQ0152
23 GIQ0016
24 GIQ0154
25 GIQ0172
26 GIQ0173
27 GIQ0178
28 GIQ0235
29 GIQ0239
30 GIQ0238
31 GIQ0174
32 GIQ0187
33 GIQ0188
34 GIQ0189
35 GIQ0193
36 GIQ0218
37 GIQ0221
38 GIQ0240
39 GIQ0208
40 GIQ0241
Costs Incurred During
Period
(b)
Accunt Charged
(c)
Account Credited
With Reimbursment
(e)-------------- - --
4,832 1070000
8,783 1070000
251 1070000
6,635 1070000
4,000 1070000
4,065 1070000
3,119 1070000
7,004 1070000
4,502 1070000
3,587 1070000
3,811 1070000
1,337 1070000
1 ,228 1070000
1,386 5617000
13,606 5617000
321 5617000
392 5617000
284 5617000
247 5617000
5,781 5617000
74 5617000
1,366 5617000
4,471 5617000
1,085 5617000
2,946 5617000
46 5617000
4,319 5617000
8,287 5617000
2,838 5617000
11,250 5617000
1,321 5617000
1,799 5617000
1,386 4562000
13,606 4562000
321 4562000
392 4562000
284 4562000
247 4562000
5,781 4562000
74 4562000
1,366 4562000
4,471 4562000
1,085 4562000
2,946 4562000
46 4562000
4,319 4562000
8,287 4562000
2,838 4562000
11 ,250 4562000
1,321 4562000
1,799 4562000
FERC FORM NO.1/1-F/3-Q (NEW. 03-07)Page 231.1
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
Transmission Service and Generation Intercnnection Study Costs
Year/Period of Report
End of 2009/04
(continued)
ina
No.Descrption
(a)
1 Transmission Studies
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
Costs Incurred During
Period
(b)
Accunt Charged
(c)
eim ursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)- - ----- ---
Generation Studies
GIQ0225
GIQ0226
GIQ0246
GIQ0247
GIQ0249
GIQ0242
GIQ0171
GIQ0217
GIQ0198
GIQ0200
GIQ0201
GIQ0230
GIQ0228
GIQ0234
GIQ0248
GIQ0236
GIQ0199
GIQ0244
GIQ0250
18,722 561700
12,138 5617000
5,96 5617000
5,052 5617000
3,000 5617000
279 561700
4,266 561700
1,672 5617000
5,953 561700
7,052 561700
7,122 561700
17,783 561700
11,575 561700
20,973 5617000
12,737 561700
3,339 561700
32,205 5617000
4,057 5617000
10,559 561700
18,722 4562000
12,138 4562000
5,964 4562000
5,052 4562000
3,000 4562000
279 4562000
4,266 4562000
1,672 4562000
5,653 4562000
7,052 4562000
7,122 4562000
11,297 4562000
11,575 4562000
20,973 4562000
12,737 4562000
3,339 4562000
32,205 4562000
4,057 4562000
10,559 4562000
FERC FORM NO. 1/1.F/3-Q (NEW. 03-67)Page 231.2
Name .of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
Transmission Service and Generation Interconnection Study Costs (continued)
ne
No.
eim ursementsReceived During
the Period
(d)
Account Credited
With Reimbursement
(e)
Costs Incurred During
- Period
(b)
Description
(a)
1 Transmission Studies
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
Accunt Charged(c) ---- - ---- - ------- ----------
Generation Studies
6,742 5617000
2,139 5617000
2,133 5617000
355 5617000
20,914 5617000
15,486 5617000
14,655 5617000
4,336 5617000
3,538 5617000
4,680 5617000
1,085 5617000
12,499 5617000
7,143 5617000
43,220 5617000
5,780 5617000
11,121 5617000
74 5617000
13,312 5617000
14,976 5617000
6,742 4562000
2,139 4562000
2,133 4562000
355 4562000
20,914 4562000
15,486 4562000
14,655 4562000
4,336 4562000
3,538 4562000
4,680 4562000
1,085 4562000
12,499 4562000
7,143 4562000
43,220 4562000
5,780 4562000
11,121 4562000
74 4562000
13,312 4562000
14,976 4562000
GIQ0209
GIQ0251
GIQ0252
GIQ0253
GIQ0243
GIQ0220
GIQ0178
GIQ0191
GIQ0254
GIQ0175
GIQ0255
GIQ0229
GIQ0256
GIQ0258
GIQ1100
GIQ0257
GIQ0240
GIQ0190
GIQ0255
FERC FORM NO. 1J1-FJ3-Q (NEW. 03-07)Page 231.3
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
Transmission Service and Generation Interconnecton Study Costs
Year/Period of Report
End of 2009/Q4
(continued)
ine
No.Description
(a)
1 Transmission Studies
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
Costs Incurr During
Period
(b)
Accunt Charged
(c)
eim ursments
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
Generation Studies
GIQ0259
GIQ0259
GIQ0260
GIQ0225
GIQ0226
GIQ0247
GIQ0238
GIQ0197
GIQ0234
GIQ0266
GIQ0257
GIQ0269
GIQ0249
GIQ0254
GIQ0268
GIQ0243
GIQ0273
GIQ0174
GIQ0145
4,879 561700
2,721 5617000
8,136 561700
8,817 561700
6,427 5617000
32,486 5617000
4,648 5617000
5,754 5617000
14,343 561700
4,387 561700
1,274 561700
11,005 561700
6,350 561700
24,664 5617000
7,94 561700
13,050 5617000
3,252 5617000
144 5617000
576) 5617000
4,879 4562000
911 4562000
8,136 4562000
8,817 4562000
6,427 4562000
32,486 4562000
4,648 4562000
5,754 4562000
14,343 4562000
3,950 4562000
1,274 4562000
11,005 4562000
6,350 4562000
24,664 4562000
7,948 4562000
13,050 4562000
3,252 4562000
144 4562000
576) 4562000
FERC FORM NO. 1/1.F/3-Q (NEW. 03-07)Page 231.4
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
Transmission Service and Generation Interconnection Study Costs (continued)
ine
No.Account Credited
With Reimbursement
(e)
Costs Incurred During
Period
(b)
Description
(a)
1 Transmission Studies
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
Accunt Charged
(c)- ------ -- -- ----- --- - - - - ---
Generation Studies
GIQ0145
.Gla0184
GIQ0260
GIQ0274
GIQ0275
GIQ0276
GIQ0277
GIQ0247
GIQ0278
GIQ0279
GIQ0280
GIQ0248
GIQ0269
GIQ0283
GIQ0281
GlQ0282
GIQ0255
GIQ0285
GIQ0286
1,847 5617000
808 5617000
12,209 5617000
8,701 5617000
5,898 5617000
3,247 5617000
7,157 5617000
7,030 5617000
3,653 5617000
8,354 5617000
2,412 5617000
9,177 5617000
5,891 5617000
3,441 5617000
1,704 5617000
1,293 5617000
2,716 5617000
769 5617000
1,376 5617000
4562000
4562000
12,209 4562000
8,701 4562000
5,898 4562000
3,247 4562000
7,157 4562000
7,030 4562000
3,653 4562000
8,354 4562000
2,412 4562000
9,177 4562000
5,891 4562000
3,441 4562000
1,704 4562000
1,293 4562000
2,716 4562000
769 4562000
1,376 4562000
FERC FORM NO. 1/1.F/3-Q (NEW. 03-07)Page 231.5
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1)~ AnOriginal (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
Transmission Service and Generation Interconnection Study Costs
Year/Period of Report
End of 2009/Q4
(continued)
ine
No.Descrption
(a)
1 Transmission Studies
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
Costs Incrr During
Period
(b)
Accunt Charged
(c)
eim ursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)- - -- - - -- -------
Generation Studies
GIQ0287
GlQ0288
GIQ0289
GIQ0290
GIQ0268
GIQ0291
GlQ0292
GIQ0254
GIQ0293
GIQ0294
GIQ0295
GIQ0296
GIQ0297
GIQ0277
GIQ0298
GIQ0299
GIQ0300
GIQ0302
GIQ0303
9,652 5617000
2,00 561700
6,205 5617000
5,028 5617000
10,748 5617000
7,106 5617000
3,458 5617000
2,843 5617000
5,675 5617000
6,092 5617000
3,353 561700
1,157 561700
4,698 561700
11,440 561700
5,150 5617000
933 5617000
4,305 5617000
687 5617000
778 5617000
9,652 4562000
2,000 4562000
6,205 4562000
5,028 4562000
10,748 4562000
7,106 4562000
3,458 4562000
2,843 4562000
5,675 4562000
6,092 4562000
3,353 4562000
1,157 4562000
4,698 4562000
11,440 4562000
5,150 4562000
933 4562000
4,305 4562000
687 4562000
778 4562000
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07)Page 231.6
Name of Respondent
PacifiCorp
This ~ort 15: Date of Report
(1)~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
Transmission Service and Generation Interconnection Study Costs
Year/Period of Report
End of 2009/Q4
(continued)
ina
No.Costs Incurred During
Period
(b)
Account Charged
(c)---- ------- ---- - --------- -- - --Descrption
(a)
.1 Transmission Studies
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
Generation Studies
GIQ0304
GlQ0305
GIQ0306
GIQ0307
GIQ0308
GIQ0309
546 5617000
573 5617000
513 5617000
631 5617000
631 5617000
180 5617000
17,484 5617000
3,383 5617000
3,191 5617000
121 5617000
454 5617000
16,724 5617000
713 5617000
9,202 5617000
10,628 5617000
7,958 5617000
1,290 5617000
979 5617000
1 ,738 1070000
eim ursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
Customer Studies Accruals
GIQ0203
GlQ0184
GIQ0185
GIQ0186
GIQ237A
GIQ0265
GIQ0270
GIQ0271
GIQ0284
GIQ0270
GIQ0271
GIQ0223
546 4562000
573 4562000
513 4562000
631 4562000
631 4562000
180 4562000
4562000
FERC FORM NO. 1/1~F/3-Q (NEW. 03-07)Page 231.7
Name of Respondent
PacifCorp
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
Transmission Service and Generation Intercnnection Study Costs
Year/Period of Report
End of 2009/Q4
(continued)
ine
No.Description
(a)
1 Transmission Studies
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
Costs Incurrd During
Period
(b)
Accunt Charged
(c)
eim ursementsReceived During
the Period
(d)
Account Credited
With Reimbursement
(e)
Generation Studies
GIQ0233
GIQ0185
G1Q237A-C
GIQ0224
GIQ0233
GIQ0267
GIQ0272
GIQ0301
149
60
1,238
7,719
3,891
102,826
6,765
1,512
1070000
1070000
1070000
1070000
1070000
107000
1070000
1070000
FERC FORM NO. 1/1.F/3-Q (NEW. 03-07)Page 231.8
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 04/14/2010 2009/Q4
FOOTNOTE DATA
!Schedule Page: 231 Line No.: 2 Column: a
Aref 551495,551500,551501,551503
I FERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FlA Resubmisson 04/14/2010
OTHER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for concerning 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 $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
....
Line Description and Purpose of Balance at Debit CREDITS Balance at end of
No.Other Regulatory Assets Beni of vvnnen OTT uunng vvnnen OTT uunng Current QuarterNear
~"Cu the QuartrN ear the Period
QuartrN ear Accunt Charged Amount
.(a)(b)(c)(d)(e)(f)
1 California DSM Regulatory Asset (1,001,355)816,551 908 1,914,337 -2,099,141
2 Idaho DSM Regulatory Asset 3,691,73 6,478,590 908 6,09,288 4,072,036
3 Utah DSM Regulatory Asset 7,622,161 57,253,987 908 36,355,470 28,520,678
4 Washington DSM Regulatory Asset (64,615)6,66,181 431,908 4,874,427 1,727,139
5 Wyoming DSM Regulatory Asset 310,06 1,34,59 908 4,122,625 -2,468,965
6 DSM Regulatory Assets- Accruals 5,46,89 232 487,179 4,977,717
7 Calif. Alternative Rate For Energy (CARE)2,64,174 142 1,243,605 1,396,569
8 Transition Plan - OR (10)6,161,872 930.2 3,892,299 2,269,573
9 2006 Transition Plan - WA (3)955,571 920 637,047 318,524
10 200 Transition Plan - 10 (3)1,220,389 920 610,194 610,195
11 2006 Transition Severance Costs . WY (3)2,655,556 920 1,593,334 1,062,222
12 Deferred Income Taxes Electric 439,741,785 282 17,572,495 422,169,290
13 Impletation Costs OR Retail Access (5)2 407.3 2
14 Sdi 781 Direct Accss Shopping Incentive (84)231,712 407.3 299,227 -68,360
15 Glenrock Mine Excluding Recamation UT (9)1,126,424 930.2 1,014,206 112,218
16 Deferr Excess Net Powr Costs - OR UE 116 161,631 13,732 175,363
17 Deferred Excess Net Power CostsJECAC - CA (475,407)1,2~2,130,220 -2,604,371
18 Deferred Excess Net Power Costs - WY 2007 (1)8,63,355 28,90 555 8,66,255
19 Deferred Excess Net Power Costs. WY 2008 (1)24,231,911 2,807,84 555 17,06.920 9,970,836
20 Deferrd Excess Net Power Costs - WY 2009 1,53,40 1,539,406
21 Deferred Excess Net Power Costs - WA Hydro (3)6,017,44 417,102 555 2,070,140 4,364,406
22 Deferred Excess Net Power Costs. 10 2009 2,615,813 2,615,813
23 Envienta Costs (10)7,034,873 1,801,923 925 1,320,414 7,516,382
24 Environtal Costs - WA (10)(54,100)88,747 925 132,490 -591,843
25 Reg Asset - Environmental Cost 4,477,314 253 1,036,173 3,441,141
26 Cholla Plant Trasacton Costs (26)9,63,148 551 1,122,425 8,511,723
27 Chona Plant Transaction Costs - OR (26)(461,89)53,814 -408,082
28 Chona Plant Transaction Costs - WA (26)(83,637)97,00 -735,631
29 Chona Plant Transaction Costs - 10 (26)(28,021)32,973 "..-250,048
30 Washington Colstrip #3 (22)63,63 456 52,188 578,447
31 Derivative Net Regulatory Asset 44,142,129 426.5 74,84,538 367,301,591
32 Asse Retiement Obligations Regulatory Difference 57,282,618 19,971,276 230 12,262,322 64,991,572
33 Pension/Other Postetirement/SERP 56,85,328 39,122,490_27,23,402 575,745,416
34 RTO Grid West N/R Reg Asset 53,172 182.3 53,172
35 Contr Reg Asset. RTO Grid West (53,172)53,172
36 RTO Grid West N/R - OR 953,339 80,769 1,034,108
37 RTO Grid West N/R . WY (3)23,05 90 138,03 92,022
38 RTO Grid West N/R - 10 (5)81,48 90 27,162 54,324...
Deferred Independent Evaluator Fee - UT -12,57339(93,250)133,677 235 53,000
40 Deferred Independent Evaluator Fee - OR (1)1,23,615 676,029 551 870,524 1,042,120
41 Deferr Intervenor Funding Grants - 10 35,160 39,403 928 13,185 61,378
42 Deferrd Intervenor Funding Grnts - OR (26,89)416,331 928,431 .324,467 -17,032
43 Deferred Intervenor Funding Grants - CA (1)180,429 928 180,429
..
i.
44 TOTAL 1,626,353,730 190,913,03 266,353,108 1,550,913,652
FERC FORM NO. 1/3.Q (REV. 02-0)Page 232
Name of Respondent This wort Is: .Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
OTHER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for concerning 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 $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being arnQrtized, show period of amortization.
Line Description and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of wnnen OTT uunng wnnen OTT uuring Currnt QuarterlY ~ar ..
Current the QuarterlY ear the Period
QuarterlY ear Accunt Charged Amount
(a)(b)(c)(d)(e)(f)
1 BPA Wasngton Balancing Account 1,317,668 214,916 440,44 .1,532,584
2 BPA Idaho Balancing Account 1,926,018 155,562 2,081,580
3 OR Renewable Adjustment Clause (1)12,962,257 3,935,282 142 .11,700,598 5,196,941
4 Goodnoe Hils Damages 510,000 510,000
5 Lake Side Damages (38)1,051,00 930.2 18,278 1,032,722
6 SB 408 Regulatory Asset - OR (1)12,782,760 19,778,310 142 22,790,454 9,770,616
7 SB 408 Regulatory Asset . MCBIT (22,043)-22,043
8 Chehalis Plant Revenue Requirement - WA 18,000,000 18,OOO,OÒO
9 Regulatory Assets. Reclassifications 1,948,992 5,536,681 -
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 1,626,353,730 190,913,030 266,353,108 1,550,913,652
.
FERC FORM NO. 1/3.Q (REV. 02-04)Page 232.1
Name of Respondent This Report is:.Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/04
FOOTNOTE DATA
'$chedule Page: 232 Line No.: 17 Column: d
Account 440
Account 442
Account 555
'$chedule Page: 232 Line No.: 33 Column: d
Pensions and benefits are char ed to fuctional accounts, which is consistent with where labor is char ed.
chedule Pa e:232.1 Line No.: 9 Column: f
OThe following sumares regulatory assets reclassifications:
Reclassified from Regulatory Assets to Regulatory Liabilities:
California DSM Regulatory Asset
Wyoming DSM Regulatory Asset
Sch 781 Direct Access Shopping Incentive
Deferred Excess Net Power CostsÆCAC - CA
Deferred Intervenor Funding Grants - OR
Deferred Independent Evaluator Fee - UT
SB 408 Reglatory Asset - MCBIT
Year Ended
December 31, 2009
$2,099,141
2,468,965
68,360
2,604,371
175,032
12,573
22,043
Reclassified from Regulatory Liabilities to Regulatory Assets:
Washington Low Income Progrm
$
35,188
7,485,673
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010.
MISCELLANEOUS 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% oftheBalance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
,
Line Decription of Miscellaneous Balance at Debits .CREDITS Balance at
No.Deferred Debits Beginning of Year ~çcoum.Amount End of Year
(a)
Char~ed
(e)(f)(b)(c)(d
1 Joseph Settlement (20)1,247,876 557 137,381 1,110,495
2
3 Lacomb Irrigation (24)598,170 557 45,720 552,450
4
5 Bogus Creek (42)1,283,120 557 41,280 1,241,á40
6 .
7 Mead Phoenix Availabilty .
8 & Trans Charge (50)14,512,280 565 377,760 14,134,520
9
10 TGS Buyout (23)171,498 557 15,473 156,025
11
12 Hermiston Swap (40)4,735,871 557 171,693 4,564,178
13
14 Deferred Longwall Costs 1,178,385 3,653,257 151 3,837,514 994,128
15
16 Point to Point Transmission 1,155,7'63 ,Q;607,625 142 1,189,488 2,573,900
17 .
18 Deferred Coal Costs - Wyodak
19 Settlement (22)4,692,545 151 335,182 4,357,363
20
21 Deferred Coal Costs - Arch
22 Settlement (3)4,300,468 151 2,587,363 1,713,105
23
24 Defered Colstrip Plant Costs 118,061 967,100 1,085,161
25
.26 Jim Boyd Hydro Buyout (11)421,205 557 82,860 338,345
27
28 Credit Agmt Costs (5)1,921,498 38,500 431 452,226 1,507,772
29
30 PCRB LOC/SBBPA Costs (5)676,054 427 202,816 473,238
31
32 PCRB Mode Conversion Costs (10)390,004 427 128,039 261,965
33
34 '94 Series Restruct. Costs (16)746,024 469,040 427 109,652 1,105,12
35
36 Emission Reduction Credits 406,980 2,550,000 2,956,980
37
38 LGIAL T Transmission Prepaid 9,542,974 412,161 142,232 6,726,832 3,228,303
39
40 Lease Incentives (11 )1,425,467 454 155,119 1,270,348
41
42 LT Lease Comm Prepaid (10)832,801 931 92,820 739,981
43
44 BPA L T Transm Prepaid 9,888,000 941,367 165,232 1,236,058 9,593,309
45
46 Lake Side Maint. Prepayment 6,077,531 4,772,844 107 1,372,787 9,477,588
47 Misc. Work in Progress
48 ,Deferred Reguiatory Comm.
Expenses (See pages 350 - 351)
49 TOTAL 72,806,094 67,302,539
.
FERC FORM NO. 1 (ED. 12-94)Page 233
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
MISCELLANEOUS DEFFERED DEBITS (Accunt 186)
1.Report below the particuiars (details) called for conceming 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 $100,000, whichever is less) may be grouped by
classes.
Line Descrption of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~i~Amount End of Year
(a)(b)(c)(e)(f)
1
2 Chehalis Maint. Prepayment 6,274,592 4,040,952 107 7,728,473 2,587,071
3
4 Currant Creek Maint. Prepayment 1,167,388 1,167,388....
5
6 Other Deferred Debits with
7 balances less than $100,000 208,927 various 97,253 111,674
8
9
10
11
12
13
14
15
16 .
17
18
19
20
21
22
23 ..
24
25
26
27 .
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Misc. Work in Progress
.
48 Deferr Regulatory Comm.
Expenses (See pages 350 - 351)
49 TOTAL 72,806,094 67,302,539
FERC FORM NO.1 (ED. 12-9)Page 233.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
Line Description and Location ~No.of Year of Year
(a)(b) (c)
1 Electric
2 Employee Benefits 246,078,312 243,734,412
3 Derivative Contracts 168,654,420 139,689,181
4 Regulatory Liabilties 41,530,110 40,091,582
5
6
7 Other .-130,677,283 164,002,583
8 TOTAL Electric (Enter Total of lines 2 thru 7)586,940,125 587,517,758
9 Gas
10
11
12
13
14
15 Other
16 TOTAL Gas (Enter Total oflines 10 thru 15
17 Other (Specify)
18 TOTAL (Acc 190) (Total of lines 8, 16 and 17)586,940,125 587,517,758
.Notes
."
..
FERC FORM NO.1 (ED. 12-88)Page 234
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
CAPITAL STOCKS (Accunt 201 and 204). ~ ..
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series
of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries incoiiimn (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
.
Line Class and Series of Stock and Number of shares Par or Stated Call Price at
No.Name of Stock Series Authorized by Charter Value per share End of Year
(a)(b)(c)(d)
1 Common Stock (Account 201 )750,000,000
2 PacifiCorp is a wholly
3 owned indirect subsidiary of
4 MidAmerican Energy Holdings Company .
5
6 TOTAL COMMON STOCK 750,000,000
7
8
9 Preferred Stock (Account 204):
10 5% Cumulative Preferred 126,533 100.00 110.00
11
12
13 Serial Preferred, Cumulative:3,500,000
14 4.52% Series 100.00 103.50
15 7.00% Series 100.00
16 6.00% Series 100.00
17 5.00% Series 100.00 100.00
18 5.40% Series 100.00 101.00
19 4.72% Series 100.00 .103.50
20 4.56% Series .100.00 102.34
21 No Par Seral Preferred 16,000,000
22
23 TOTAL PREFERRED STOCK 19,626,533
24
25
26
27
28
29
30
31
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED. 12-91)Page 250
Name of Respondent This ï!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) ¡=A Resubmission 04/14/2010
..CAPITAL STOCKS (Accunt 201 and 204) (Continued)
3. Give particuiars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT Line
(Total amount outstanding without reduction AS REACQUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
Shares Amount Shares G9st Shares AmO)unt
(e)(f)(g)(h)(i)
357,060,915 3,417,945,896 .1
.2.
3
4
5
357,060,915 3,417,945,896 6
7
8
9
126,243 12,624,300 10
.11
.
12
13
2,065 206,500 14
.18,046 1,804,600 15
5,930 593,000 16
41,908 4,190,800 17
65,959 6,595,900 18
69,890 6,989,000 19
84,592 8,459,200 20
.21
22
414,633 41,463,300 23
24
25
26
27
28
.29
30
31
32
33
34
...35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED. 12-88)Page 251
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA .
¡Schedule Page: 250 Line No.: 1 Column: d
This class of stock is not redeemable.
¡Schedule Page: 250. Line No.: 15 Column: d
This series of preferred stock is not redeemable.
¡Schedule Page: 250 Line No.: 16 Column: d
This series of preferred stock is not redeemable.
Oregon Public Utility Commssion, Docket No. UF-4228, Order No. 06-417, dated July 17,2006.
Washington Utilities and Trasportation Commission, Docket No. UE-060974, Order No.1, dated June 28, 2006.
Idaho Public Utilities Commission, Case No. PAC-E-06-7, Order No. 30099, dated July 7, 2006.
As of December 31, 2009, 30,000,000 shares authoried; 30,000,000 available.
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/14/2010 .
OTHER PAID-IN CAPITAL (Accunts 208-211, inc.)
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accunts. Provide a
subheading for each account and show a total for the account, as well as total of an accounts for reconcilation with balance sheet, Page 112. Add more
columns for any account if deemed necessary. Explain changes made in any accunt during the year and give the accunting entries effecting such
change.
(8) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end of
year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Account 211 )-Classify amounts included in this account according to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
Wce It~r .... Arygtnto.
1 Accunt 211 Miscellaneous Paid-in Capital
2 Additional Paid-in Capital
3 Share based payments .
4 Tax benefit frm stock option exercises
5 Benefit plan separation
6 Capital contributions
7 Gain on sale of Scottish Power stock
',..8 Qualified production activity tax deduction
9 Contribution of Intermountain Geothermal
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 TOTAL 1,002,063,956
FERC FORM NO.1 (ED. 12-87)Page 253
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
'$chedule Page: 253 Line No.: 3 Column: b
Represents the fair value of stock options granted by Scottsh Power pIc for which cerin pedormance measures were met in March
2005. These options became fully vested in May 2005.
I$chedule Page: 253 Line No.: 4 Column: b
Represents the income tax deduction attbutable to the exercise of stock options grnted by Scottish Power pIc.
!schedule Page: 253 Line No.: 5 Column: b
Represents the effect of trnsferrng benefit plans to PPM Energy, Inc. as a result of the sale ofPacifiCorp by Scottsh Power pIc.
!schedule Page: 253 Line No.: 6 Column: b I
Represents capital contrbutions to PacifiCorp (with no shares of stock issued) from its indirect parent MidAercan Energy Roldings
Company ("MERC"), of which $125,000,000 were made durng the year ended December 31,2009.
~chedule Page: 253 Line No.: 7 Column: b
Represents a realized gain on stock related to separtion of PPM Energy, Inc. parcipants from the deferred compensation plan.
~chedule Page: 253 Line No.: 8 Column: b
Represents amounts associated with IRC 199 qualified production activities.
~chedule Page: 253 Line No.: 9 Column: b
Represents contrbution ofIntermountain Geothermal Company to PacifiCorp from MERC in Marh 2006, subsequent to the sale of
PacifiCorp to MERC. Intermountain Geothermal Company was merged with and into its direct parent, PacifiCorp, on August 31,
2007, with PacifiCorp suriving.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
.(2) FiA Resubmission 04/14/2010
CAPITAL STOCK EXPENSE (Accunt 214)
1.Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
....
I Line ciass ana ::eries or ::tocK .Balance at Ena or year
No.(a)(b)
1 Common Stock 41,101,062
2
3 Preferred Stock::
4 5.00% Serial 98,049
5 4.52% Serial 9,676
6 4.72% Serial .30,349
7 4.56% Serial .49,071
8 ..
9 .
.
10 ~
11
12
13 .
14
15
16
17
18
19
20
21
22 TOTAL 41,288,207
FERC FORM NO.1 (ED. 12-87)Page 254b
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/14/2010
LONG-TERM DEBT (Accunt 221,222,223 and 224).
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accunts 221, Bonds, 222,..
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3, For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4.. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accunts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 Bonds: (Account 221)
2 First Mortgage Bonds:
3
4 8.271% Series due October 1, 2010 48,972,000
5 7.978% Series due October 1, 2011 4,422,000
6 6.900% Series due November 15, 2011 500,000,000 3,567,009
7 1,735,000 D
8 8.493% Series due October 1, 2012 19,772,000
9 8.797% Series due October 1, 2013 16,203,000
10 5.450% Series due September 15, 2013 200,00,000 1,422,659
11 232,000 D
12 4.950% Series due August 15, 2014 .200,00,000 1,442,365
13 728,000 D
14 8.734% Series due October 1, 2014 28,218,000
15 8.294% Series due October 1, 2015 46,946,000
16 8.635% Series due October 1, 2016 18,750,000
17 8.470% Series due October 1, 2017 19,609,000
18 5.650% Series due July 15, 2018 500,000,000 3,067,221
19 905,000 D
350,000,000 2,509,869
21 2,292,500 D
22 7.700% Series due November 15, 2031 300,000,000 2,874,150
23 864,000 D
24 5.900cy Series due August 15, 2034 200,00,000 1,892,365
25 .722,000 D
26 5.25% Series due June 15, 2035 300,00,000 2,912,055
27 .1,080,000 D
28 6.10% Series due August 1, 2036 350,00,000 2,908,542
29 1,141,000 D
30 5.75% Series due April 1, 2037 .600,000,000 589,216
31 24,000 D
32
~
33 TOTAL 6,632,262,000 76,586,665
FERC FORM NO.1 (ED. 12-96)Page 256
Name of Respondent
PacifiCorp
YearlPeriod of Report
End of 2009/Q4
This ~ort Is: Date of Report(1) ~An Onginal (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
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 crèdited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accunts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year,
describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Intereston Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD us an in~LineNominal Date Date of (Total amount outstan ing. without I nterest for Year No.
of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)
resPYRfent)
(i)
1
2
3
04/15/1992 10/01/2010 0411511992 10/01/2010 4,754,000 665,588 4
04/15/1992 10/01/2011 0411511992 10/01/2011 793,000 84,268 5
11/15/2001 11/15/2011 11/15/2001 11/15/2011 500,000,000 34,500,000 6
7
04/15/1992 10/01/2012 04/15/1992 10/01/2012 5,178,000 532,893 8
04/15/1992 10/01/2013 04/15/1992 10/01/2013 5,440,000 550,802 9
09/15/2003 09/15/2013 11/15/2001 09/15/2013 200,000,000 10,900,000 10
11
0812412004 08115/2014 08/24/2004 08/15/2014 200,000,000 9,900,000 12
13
04/15/1992 10/0112014 04/15/1992 10/01/2014 11,179,000 1,089,435 14
04/15/1992 10/01/2015 04/15/1992 10/01/2015 20,721,000 1,879,524 15
04/15/1992 10/01/2016 04/15/1992 10/01/2016 9,346,000 868,163 16
04/15/1992 10/01/2017 04/15/1992 10/01/2017 10,562,000 951,647 17
07/17/2008 07/15/2018 07/1712008 07/15/2018 500,000,000 28,171,528 18
19
01/08/2009 01/15/2019 01/08/2009 01/15/2019 . 350,000,000 18,822,222 20
21
11/15/2001 11/15/2031 11/15/2001 11/15/2031 300,000,000 23,100,000 22
23
08/24/200 08/15/2034 08/24/2004 08/15/2034 200,000,000 11,800,000 24
25
06/13/2005 06/15/2035 06/13/2005 0611512035 300,000,000 15,750,000 26
27
08/10/2006 08/01/2036 08/10/2006 08/01/2036 350,000,000 21,350,000 28
29
03/14/2007 04/01/2037 03/14/2007 04/01/2037 600,000,000 34,500,000 30
31
32
.~.IP"""6,372,343,000 369,236,11733
FERC FORM NO.1 (ED. 12-96)Page 257
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) EJ Resubmission 04/14/2010 .
LONG-TERM DEBT (Accunt 221, 222, 223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accunts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For recivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. ~ Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expanse,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 6.25% Series due October 15, 2037 600,000,000 5,127,281
2 750,000 D
3 6.35% Series due July 15, 2038 300,000,000 2,290,333
4 1,671,000 D
650,000,000 6,123,685
6 6,175,000 D
7 7.00% Series H Medium-Term Notes due Jul. 15,2009 125,000,000 1,976,904
8 .451,250 D
9 9.15% Series C Medium-Term Notes due Aug. 9, 2011 8,000,000 75,327
10 8.95% Seres C Medium-Term Notes due Sept. 1,2011 25,000,000 175,398
11 8.95% Series C Medium-Term Notes due Sept. 1, 2011 20,000,000 132,118
12 8.92% Series C Medium-Term Notes due Sept. 1,2011 20,000,000 188,318
13 8.29% Series C Medium-Term Notes due Dec. 30, 2011 3,000,000 23,040
14 8.26% Series C Medium-Term Notes due Jan. 10,2012 1,000,000 7,649
15 8.28% Series C Medium-Term Notes due Jan. 10,2012 2,000,000 13,297
16 8.25% Series C Medium-Term Notes due Feb. 1,2012 3,000,000 22,946
17 8.13% Series E Medium-Term Notes due Jan. 22, 2013 10,000,000 75,827
18 8.53% Series C Medium-Term Notes due Dec. 16,2021 15,000,000 115,202
19 8.375% Series C Medium-Term Notes due Dec. 31,2021 5,000,000 38,400
20 8.26% Series C Medium-Term Notes due Jan. 7, 2022 5,000,000 33,243
21 8.27% Series C Medium-Term Notes due Jan. 10, 2022 4,000,000 30,594
22 8.05% Series E Medium-Term Notes due Sept. 1,2022 15,000,000 131,471
23 8.07% Series E Medium-Term Notes due Sept. 9, 2022 8,000,000 70,118
24 8.12% Series E Medium-Term Notes due Sept. 9, 2022 50,000,000 438,238
25 8.11 % Series E Medium-Term Notes due Sept. 9, 2022 12,000,000 105,177
26 8.05% Series E Medium-Term Notes due Sept. 14,2022 10,000,000 87,648
27 8.08% Series E Medium-Term Notes due Oct. 14,2022 26,000,000 208,198
28 8.08% Series E Medium-Term Notes due Oct. 14,2022 25,000,000 200,190
29 8.23% Series EMedium-Term Notes due Jan. 20, 2023 5,000,000 37,914
30 8.23% Series E Medium-Term Notes due Jan. 20, 2023 4,000,000 30,331
31 .-81,56Q P
32 7.26% Series F Medium-Term Notes due July 21,2023 27,000,000 246,981
33 TOTAL 6,632,262,00 76,586,665
FERC FORM NO.1 (ED. 12-96)Page 256.1
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
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 crEldited 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 òf 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 nominaiiyootstanding 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 andAccount 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.
Year/Period of Report
End of 2009/Q4
Name of Respondent
PacifiCorp
AMORTIZATION PERIOD us nin§Line
Nominal Date Date of (Total amount outstan Ing without Interest for Year No.
of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)
resP~~dent)
(I)
10/03/2007 10/15/2037 10/03/2007 10/15/2037 600,000,000 37,395,833 1
2
07/17/2008 07/15/2038 07/172008 07/15/2038 300,000,000 18,997,084 3
4
01108/2009 01/15/2039 01/08/2009 01/15/2039 650,000,000 38,133,333 5
6
07/15/1997 07/15/2009 07/15/1997 07/15/2009 4,715,278 7
8
0819/1991 08/09/2011 08/09/1991 08/09/2011 8,000,000 732,000 9
08/16/1991 09/01/2011 08/16/1991 09/01/2011 25,000,000 2,237,500 10
08/16/1991 09/01/2011 08/16/1991 09/01/2011 20,000,000 1,790,000 11
08/16/1991 09/01/2011 08/16/1991 09/01/2011 20,000,000 1,784,000 12
12131/1991 12130/2011 12131/1991 12130/2011 3,000,000 248,700 13
01/09/1992 01/10/2012 01/09/1992 01/10/2012 1,000,000 82,600 14
01/10/1992 01/10/2012 01/10/1992 01/10/2012 2,000,000 165,600 15
01/15/1992 02/01/2012 01/15/1992 02101/2012 3,000,000 247,500 16
01/20/1993 01/22/2013 01/20/1993 01/22/2013 10,000,000 813,000 17
12116/1991 12116/2021 12116/1991 12/16/2021 15,000,000 1,279,500 18
12131/1991 12131/2021 12131/1991 12131/2021 5,000,000 418,750 19
01/08/1992 01/07/2022 01/08/1992 01/07/2022 5,000,000 413,000 20
01/09/1992 01/10/2022 01/09/1992 01/10/2022 4,000,000 330,800 21
09/1811992 09/01/2022 09/18/1992 09/01/2022 15,000,000 1,207,500 22
09/09/1992 09/09/2022 09/09/1992 09/09/2022 8,000,000 645,600 23
09/11/1992 09/09/2022 09/11/1992 09/09/2022 50,000,000 4,060,000 24
09111/1992 09/09/2022 09/11/1992 09/09/2022 12,000,000 973,200 25
09/14/1992 09/14/2022 09/14/1992 09/14/2022 10,000,000 805,000 26
10/15/1992 10/14/2022 10/15/1992 10/14/2022 26,000,000 2,100;800 27
10/15/1992 10/14/2022 10/15/1992 10/14/2022 25,000,000 2,020,000 28
01/20/1993 01/20/2023 01/20/1993 01/20/2023 5,000,000 411,500 29
01/29/1993 01/20/2023 01/29/1993 01/20/2023 4,000,000 329,200 30
31
07/2211993 07/21/2023 07/2211993 07/21/2023 27,000,000 1,960,200 32
0Pf M ../øÆf 0lfiiJJ ..;¡ ~0/Ø.:~..//~" _6,372,343,000 369,236,117 33
FERC FORM NO.1 (ED. 12-96)Page 257.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
....(2) FiA Resubmission 04/14/2010
LONG-TERM DEBT (Account 221,22,223 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 descriptin of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discourit with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accunts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 7.26% Series F Medium-Term Notes due July 21,2023 11,000,000 100,622
2 7.23% Series F Medium-Term Notes due Aug. 16,2023 15,00,000 137,211
3 7.24% Series F Medium-Term Notes due Aug. 16,2023 30,000,00 274,423
4 6.75% Series F Medium-Term Notes due Sept. 14,2023 5,000,000 38,250
5 6.75% Series F Medium-Term Notes due Sept. 14,2023 2,000,000 15,300
6 6.72% Series F Medium-Term Notes due Sept. 14,2023 2,000,00 15,300
7 6.75% Series F Medium-Term Notes due Oct. 26, 2023 20,000,000 152,326
8 6.75% Series F Medium-Term Notes due Oct. 26, 2023 16,000,00 121,861
9 6.75% Series F Medium-Term Notes due Oct. 26, 2023 12,000,000 91,396
10 6.71% Series G Medium-Term Notes due Jan. 15,2026 100,000,000 904,467
11 Subtotal - First Mortgage Bonds 5,893,892,000 61,731,625
12
13 Pollu Control Obligations - Secured by Pledged First Morgage Bonds:
14
15 Poll Ctr Rev Refunding Bonds, Moffat County, CO, Ses 199 40,655,00 874,159
16 5-5/8% Poll Ctrl Rev Refunding Bonds, Lincoln Conty, WY, Se 1993 8,300,00 228,980
17 197,125 D
18 5.65% Poll Ctrl Rev Refunding Bonds, Emery County, Uth, Series 1993A 46,500,000 1,624,793
19 5-5/8% Poll Ctrl Rev Refunding Bonds, Emery Coooty, Utah, Seris 1993B 16,400,000 625,551
20 .
389,500 D
21 Poll Ctrl Rev Refunding Bonds, Sweetwater Couty, WY, Seres 1994 21,260,000 510,479
22 PoIlCtrl Rev Refunding Bonds, Converse County, WY, Series 1994 8,190,000 209,777
23 Poll Ctrl Rev Refunding Bonds, Emery County, UT, Seris 1994 121,940,00 3,274,246
24 Poll Ctrl Rev Refunding Bonds, Carbon County, UT, Series 199 .9,365,00 206,519
25 Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 199 15,060,00 422,858
26 Poll Ctr Rev Refunding Bonds, Converse County, WY, Seres 1988 17,000,00 155,970
27 Poll Ctrl Revenue Bonds, Sweetwater County, WY, Series 1984 15,000,000 122,887
28 105,000 D
29 Poll Ctrl Rev Refunding Bonds, Lincoln Cnty, WY, Series 1991 45,000,000 771,836
30 Poll Ctrl Revenue Bonds, City of Forsyt, MT, Series 1986 8,500,000 304,824
31 Environ. Imprvmnt Rev Bonds, Converse County, WY, Series 1995 5,300,000 132,043
32 Environ. Imprvmnt Rev Bonds, Lincoln County, WY, Series 1995 22,000,000 404,262
I...
33 TOTAL 6,632,262,00 76,586,665
FERC FORM NO.1 (ED. 12-96)P¡¡ge 256.2
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
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) pnnciple repaid
during year. Give Commission authorization numbers and dates.
13. Ii 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 secunties which have been nominally issued and are nominally outstanding at end of year,
describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD us an in~LineNominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)
resP?Rtent)
(I)
07/2211993 07/21/2023 07/2211993 07/21/2023 11,000,000 798,600 1
08/16/1993 08/16/2023 08/16/1993 08/16/2023 15,000,000 1,084,500 2
08/16/1993 08/16/2023 08/16/1993 08/16/2023 30,000,000 2,172,000 3
09/14/1993 09/14/2023 09/14/1993 09/14/2023 5,000,000 337,500 4
09/14/1993 09/14/2023 09/14/1993 09/14/2023 2,000,000 135,000 5
09/14/1993 09/14/2023 09/14/1993 09/14/2023 2,000,000 134,400 6
10/26/1993 10/26/2023 10/26/1993 10/26/2023 20,000,000 1,350,000 7
10/26/1993 10/26/2023 10/26/1993 10/26/2023 16,000,000 1,080,000 8
10/26/1993 10/26/2023 10/26/1993 10/26/2023 12,000,000 810,000 9
01/23/1996 01/15/2026 01/23/1996 01/15/2026 100,000,000 6,710,000 10
5,633,973,000 354,325,548 11
12
13
14
11/171994 05/01/2013 11/17/1994 05/01/2013 40,655,000 366,868 15
11/15/1993 11/01/2021 11/15/1993 11/01i2021 8,300,000 476,835 16
17
11/15/1993 11/01/2023 11/15/1993 11/01/2023 46,500,000 2,683,050 18
11/15/1993 11/01/2023 11/15/1993 11/01/2023 16,400,000 942,180 19
20
11/17/1994 1 t/01/2024 11/17/1994 11/01/2024 21,260,000 185,191 21
11/17/1994 11/01/2024 11/17/1994 11/01/2024 8,190,000 65,159 22
11/171994 11/01/2024 11/17/1994 11/01/2024 121,940,000 1,146,055 23
11/17/1994 11/01/2024 11/1711994 11/01/2024 9,365,000 77,291 24
11/1711994 11/01/2024 11/17/1994 11/01/2024 15,060,000 132,958 25
01/0111988 01/01/2014 01/01/1988 01/01/2014 17,000,000 680,352 26
12101/1984 12101/2014 12/01/1984 12101/2014 15,000,000 600,357 27
28
01/17/1991 01/01/2016 01/17/1991 01/01/2016 45,000,000 1,640,685 29
12101/1986 12/01/2016 12/01/1986 12/01/2016 8,500,000 359,450 30
11/171995 11/01/2025 11/17/1995 11/01/2025 5,300,000 224,251 31
11/17/1995 11/01/2025 11/17/1995 11/01/2025 22,000,000 953,231 32
/0 :i'!..* 01%.. "If çg¿i/0 ii/ / ""t a/..0h /ii 6,372,343,000 369,236,117 33
FERC FORM NO.1 (ED. 12-96)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 2009/Q4
(2) DA Resubmission 04/14/2010
L )NG-TERM DEBT (Accunt 221,222,223 and 224)
1. Report by balance sheet account the particulars (details) conceming 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 acounts. Designate
demand notes as such. Include in column (a) namesof associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 Subtotal Pollution Control Obligations - Secured by Pledged First Mortgage Bonds 400,470,000 10,560,809
2
3
4 Pollution Control Obligations - Unsecured
5
6 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992A 9,335,000 167,524
7 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992B 6,305,000 151,908
8 Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 22,485,000 242,163
9 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988B 11,500,000 84,822
10 Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Ser. 1990A 70,000,000 660,750
11 Poll Ctr Rev Refndng Bonds, Emery County, UT, Series 1991 45,000,000 872,505
12 Poll Ctr Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988A 50,000,000 422,43
13 Poll Ctrl Rev Refnng Bonds, City of Forsyth, MT, Series 1988 45,000,000 380,198
14 Poll Ctrl Rev Refndng Bonds, City of Gilette, WY, Ser. 1988 41,200,000 351,905
15 Environ. Imprmnt Rev Bonds, Sweetwater County, WY, Series 1995 24,400,000 225,000
16 6.150% Environ. Imprvmnt Rev Bonds, Emery County, UT, Series 1996 12,675,000 556,549
17 178,464 D
18
19 Subtotal - Pollution Control Obligations - UnseCUred 337,900,000 4,294,231
20
21
22
23 TOTAL ACCOUNT 221 6,632,262,00 76,586,665
24 .
25
26 Reacquired Bonds: (Accunt 222)
27
28
29 Advances from Associated Companies: (Accunt 223)
30
31
32
.33 TOTAL 6,632,262,00C 76,586,665
FERC FORM NO.1 (ED. 12-96)Page 256.3
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
LONG-TERM DEBT (Accunt221, 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 anyof its long-term debt securities give particuiars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year,
describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Nominal Date
of Issue
(d)
Date of
Maturity
(e)
AMORTIZATION PERIOD usaning
(Total amount outstanaing withoutreduction for amounts held byreSP?~dent)
400,470,000 10,533,913
Interest for Year
Amount
(i)
Date From
(f)
Date To
(g)
09/29/1992 12/01/2020 09/29/1992 12/01/2020 9,335,000 206,385
09/29/1992 12/01/2020 09/29/1992 12/01/2020 6,305,000 139,396
09/29/1992 12/01/2020 09/29/1992 12/01/2020 22,485,000 497,116
01/01/1988 01/01/2014 01/01/1988 01/01/2014 11,500,000 100,793
07/25/1990 07/01/2015 07/25/1990 07/01/2015 70,000,000 625,694
OS/23/1991 07/01/2015 OS/23/1991 07/01/2015 45,000,000 437,777
01/01/1988 01/01/2017 01/01/1988 01/01/2017 50,000,000 533,479
01/01/1988 01/01/2018 01/01/1988 01/01/2018 45,000,000 415,921
01/01/1988 01/01/2018 01/01/1988 01/01/2018 41,200,000 386,588
12/14/1995 11/01/2025 12/14/1995 11/01/2025 24,400,000 253,994
09/24/1996 09/01/2030 09/24/1996 09/01/2030 12,675,000 779,513
337,900,000 4,376,656
6,372,343,000 369,236,117
..~.:.. ~./~f'4!6,372,343,000 369,236,117 33
FERC FORM NO.1 (ED. 12-96)Page 257.3
Line
No.
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
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
LONG-TERM DEBT (Accunt 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 colurn~a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 Other Long-Term Debt: (Account 224)
2
3 TOTAL ACCOUNT 224
4
5
7
8
9
10
11
12
13
14
15
16 .
17 .
18
19
20
21
22
23
24
25
26
27
28 .
29
30
31
32
33 TOTAL 6,632,262,000 76,586,665
FERC FORM NO.1 (ED. 12-96)Page 256.4
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
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. Ina footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year,
describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Date From
(f)
Date To
(g)
usn ing
(Total amount outstanaing withoutreduction for amounts held byresP?~tent)
Interest for Year
Amount
(i)
Line
No.Nominal Date
of Issue
(d)
Date of
Maturity
(e)
AMORTIZATION PERIOD
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
'fA fa " :"" ;fAA _" ////7 6,372,343,000 369,236,117 33
FERC FORM NO.1 (ED. 12-96)Page 257.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp .(2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
I$chedule Page: 256 Line No.: 20 Column: a
In Januar 2009, PacifiCorp issued $350 milion of its 5.500/Ó Firt Mortgage Bonds due Januar 15,2019. State commission
authorizations for this issuace were as follows:
Oregon Public Utilty Commssion, Docket No. UF-4243, Order No. 08-013, dated January 14,2008.
Idaho Public Utility Commssion, Case No. PAC-E-07-16, Order No. 30489, dated Januar 22, 2008.
¡Schedule Page: 256.1 Line No.: 5 Column: a
In Januar 2009, PacifiCorp issued $650 milion of its 6.00% First MortgageBonds due Januar 15,2039. State commission
authoriations for this issuance were as follows:
Oregon Public Utilty Commission, Docket No. UF-4243, Order No. 08-013, dated January 14,2008.
Idaho Public Utility Commssion, Case No. PAC-E-07-16, Order No. 30489, dated January 22, 2008.
¡Schedule Page: 256.4 Line No.: 6 Column: a
For authorization for the issuance oflong-term debt ($2.0 bilion authorized; $200 milion available as of December 31,2009), refer
to page 108, Important Changes During the Year, Item 6, of this Form No.1.
Authorization to borrow the proceeds of pollution control revenue refuding bonds issued (total of $300,345,000 authorized and
available as of December 31, 2009) by the counties of Emery, Uta; Carbon, Utah; Converse, Wyoming; Lincoln, Wyoming;
Sweetwater, Wyoming; and Moffat, Colorao; and
Authorization to borrow the proceeds of new pollution control revenue bonds issued (total of $150,000,000 authorized and available
as of December 31,2009) by one or more of the following counties or municipalities: Emery, Utah; Converse, Wyoming; Lincoln,
Wyoming; Sweetwater, Wyoming; City of Gilette, Wyoming; Navajo County, Arona; and Routt County, Colorado is as follows:
Oregon Public Utility Commssion, Docket No. UF-4250, Order No. 08-382, dated July 29, 2008.
Idaho Public Utilities Commssion, Case No. P AC-E-08-05, Order No. 30606, dated August 4, 2008.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1 )~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
RECONCILIATION OF REPORTED NET INCOME WITH TAXBLE INCOME FOR FEDERAL INCOME TAXES
Year/Period of Report
End of 2009/Q4
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconcilation, as far as practicable, the same detail as fumished on Schedule M-1 of the ta retum for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconcilng amount.
2. If the utilty is a member of a group which files a consolidated Federal tax retum, reconcile reported net income with taxable net income as if a separate
return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated retum. State names of group member, tax
assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the
above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
ine
No.
1 Net Income for the Year (Page 117)
2
3
4. Taxable Income Not Reported on Books
5
6
7
8
1.-1.-.L /;Yl../ A/A/!liv yiffffy!;
/ .Jj / x/a /
19 Deductions on Retum Not Charged Against Book Income
20
21
22
23
24
25
26 State Tax Deductions
27 Federal Tax Net Income
28 Show Computation of Tax:
29
30 Federal Income Tax at 35.00%
31 Provision to Return Adjustment
32 ax Reserve changes
33 Tax Settleent
34 Contingenc Reserve
35 Wind Credits
36 Mining Rescue Training Credit
37 Research & Experimentation-Çredits
38 Foreign Tax Credit
39 Fuel Tax Credit
40 Current Fed Tax Interest
41
42
43 Federal Income Tax Accrual
44
2,085,657,228
-3,059,956
-567,145,314
-198,500,860
-222,559,895
11,260,190
7,125,204
1,500,000
-44,324,047
-66,989
-115,125
-20,000
-15,376
2,566,012
FERC FORM NO.1 (ED. 12-96)Page ..261
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
I§chedule Page: 261 Line No.: 8 Column: a
Parcular (Details)
PMI Dividend Gross Up for Foreign Tax Credit
Income Tax Interest
Sec. 481a Adjustment - Repair Deduction
CIAC
Reimbursements
Avoided Costs
Capitalization of Test Energy
Energy trading derivatives - curent
Energy trading derivatives - noncurent
Regulatory liability BP A balancing accounts
W A Rate Refunds
Regulatory Liability - UT Home Energy Lifeline
Regulatory Liability - OR Balance Consol
OR Regulatory AssetJiability Consolidation
Regulatory Liability - OR Energy Conservation Charge
Regulatory Liability - Blue Sky Program OR
Regulatory Liability - Blue Sky Program CA
UT DSM - SMU Offset
Wilow Wind Account Receivable
Deferred Coal Cost - Arch
Debt to Equity Securities Unralized Gainoss
Equity Earnings in Subsidiares
Total
Amounts
$ 20,000
2,666,318
16,316,468
53,575,515
5,135,323
80,524,655
187,102
1,258,283
949,904
1,430,552
228,659
13,830
2,619,115
13,819
46,722
96,929
19,763
2,850,000
105,214
2,587,363
3,516,254
(1.811.740)
$ 172,350,048
I§chedule Page: 261 Line No.: 13. Column: a
Paricular (Details)
Fed/State Tax Expense
% capitalized labor costs for Power tax input
Meals & Enterainment
Penalties
Lobbying expenses
Meals & Entertainment - Bridger Coal
MEHC Insurance Services - Premium
Mining Rescue Training Credit Addback - PacifiCorp
30% capitalized labor costs for Power ta input
Book Depreciation
Book Cost Depletion - Addback
May 2000 Transition Plan Costs - OR
Glenrock Excluding Reclamation - UT
Regulatory Asset - Pension Liability Adj.
Regulatory Asset - Post Ret. Liabilty
Environmental Clean-up Accrul
Environmental Costs - W A
Cholla Plant Transaction Costs - APS Amortzation
WA Disallowed Colstrp #3 - Write-off
CA Deferred Intervenor Funding
Regulatory Asset - Lake Side Liquidation
RTO Grid West NIR - Allowance
RTO Grid West Notes Receivable - WY
RTO Grid West Notes Receivable - il
IFERC FORM NO.1 (ED. 12-S7)
Amounts
$ 232,667,189
1,831,632
1,101,248 .
600,132
1,685,174
8,508
6,969,001
46,236
20,578,968
535,808,937
2,639,462
3,892,299
1,014,206
9,883,00
12,226,000
554,665
43,743
938,633
52,188
180,429
18,278
53,172
138,033
27,162
Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ó An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA ,
Regulatory Asset - Pension MMT - UT
Regulatory Asset - Post - Ret MMT - OR
Regulatory Asset - Post - Ret MMT - WY
Regulatory Asset - Post - Ret MMT - UT
Regulatory Asset - Post - Ret :MT - ID
Regulatory Asset - Post - Ret MM - CA
Regulatory Asset - Deferred OR Independent Evaluator Fees
Unrecovered Plant - Powerdale
Deferred Excess Net Power Costs - CA
Defered Excess Net Power Costs - WY
Deferred Excess Net Power Costs - WY 08
Deferred Excess Net Power Costs - W A Hydro
ID MEHC 2006 Transition Costs
WY - 2006 Transition Severace Costs
OR - RCAC Sep-Dec 07 Deferred
OR SB 408 Recovery
Trojan Decommissioning Costs - Regulatory
781 Shopping Incentive
SB 1149 Costs
NW Power Act - WA
Regulatory asset - Net Derivatives
Coal Pile Inventory Adjustment
Prepaid Taxes - UT PUC
Prepaid Taxes - ID PUC
RTO Grid West Note Receivable - w/o - WA
TGS Buyout
Lakeview Buyout
Joseph Settlement
Herston Swap
Western Coal Carer Postretiement Benefit Accrul
Post Merger Loss-Reacquisition Debt - Addback
ARO Regulatory Liabilities
Non-ARO Liability - Regulatory Liability
Reg Liability - Other -Balance Reclass
Reg Liability - DefNPC Balance Reclass
Reg Liability - SB 1149 Balance Reclass
Proper Insurance (same as Injures & Damages)
CA - California Alternative Rate for Energy Progrm (CARE)
March 2006 Transition Plan Costs - W A
Bonus Liabilty - Electrc - Cash Basis (2.5 months)
Pension / Retiement Accrual - Cash Basis
ARO Liabilty
Distrbution O&M Amortization of Write-off
Bear River Settlement Agreement
Rogue River - Habitat Enhancement Liability
Lewis River Settlement Agreement
Other Environmental Liabilties.
N. Umpqua Settlement Agreement
Umpqua Settlement Agreement
Defered Revenue - Citibank
Accrued Insurnce Premium Tax
Reverse Accrued Final Reclamation
Post Employment Benefits Book Reserve
IFERC FORM NO.1 (ED. 12-87) Page 450.2
338,368
199,297
278,231
332,959
394,287
17,235
194,495
4,070,159
2,128,963
8,635,355
14,261,075
1,653,038
610,194
1,593,333
7,765,316
3,012,143
1,572,028
67,515
2
2,220,689
74,840,538
1,198,886
7,167
66,620
46,941
15,474
3,606
137,381
171,693
380,000
2,785,112
892,146
23,435,597
244,836
2,604,370
68,360
109,564
1,243,605
637,047
38,386
63,920
22,457,843
688
433,059
24,290
185,233
1,236,615
1,263,905
525,756
79,595
192,477
293,378
1,785,438
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Pacifiorp i (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Bridger Coal Company ARO - Liabilty
Penalties - PM!
PMI Fuel Tax Cr
Mine Rescue Training Credit Addback - PMI
Book Depreciation - PM!
Vacation Accrul - PMI
Coal Mine Development - PM!
Bridger Coal Company Section 471 Adjustment - PMI
Total
6,706,137
279,107
15,376
20,753
15,299,289
67,354
4,444,185
521,25
$ 1,047,125,829
¡Schedule Page: 261 Line No.: 18 Column: a
Paricular (Details)
MEHC Insurnce Services - Receivable
Tax Exempt Interest - CA IOU
Medicare Subsidy
Bridger Coal Tax Exempt Interest Income
AFUDC
Basis Intangible Difference
DefRegulatory Asset - OR DefNet Power Costs
Deferred Intervener Funding Grants
Contr - RTO Grid West NIR Allowance
W A - Chehalis Plant Revenue Requirement
Derivatives - Current
Regulatory Liability - W A Low Energy Program
Oregon Gain on Sale
Regulatory Liability - Blue Sky Progr W A
Regulatory Liability - Blue Sky Progr UT
Regulatory Liability - Blue Sky Program il
Regulatory Liability - Blue Sky Progr WY
Regulatory Liability - Deferred Benefit Arh Settlement
Regulatory Liability - UT Gain on Sale of Asset
Regulatory Liability - il Gain on Sale of Asset
Regulatory Liability - WY Gain on Sale of Asset
SMU Revenue Imputation - UT regulatory liabilty
Derivatives - noncurent
Def Regulatory Asset - Transmission Service Deposit
DefRegulatory Asset - Foote Creek Contrt
Deferred Regulatory Expense
Tenant Lease Allow - PSU Call Center
Uneared Joint Use Pole Contact Revenue
DukeJermiston Contract Renegotiation
Redding Contract - Prepaid
Bridger Coal Company Gainoss on Assets Disposed
Debt to Equity Securties Mark to Market Accrual - Bridger - Reclass
Dividend Received Deduction - PM!
PM! - Fuel Cost Adjustment
Bridger Coal Company Reclamation Trust Earings - PM!
Total
Amounts
$ (20,302,078)
(904)
(6,063,000)
(21,532)
(94,462,842)
(4,645,782)
(13,732)
(91,864)
(53,172)
(18,000,000)
(38,567,924)
(10,607)
(957,698)
(46,537)
(186,880)
(21,877)
(24,937)
(1,836,574)
(1,019,355)
(156,434)
(352,888)
(5,606,807)
(37,754,802)
(1,637,750)
(137,640)
(26,217)
(60,323)
(179,120)
(754,839)
(549,996)
(1,847)
(3,516,254)
(373,123)
(1,168,993)
(1,146,125)
$ (239,750,453)
ISchedule Page: 261 Line No.: 25 Column: a
Paricular (Details)
Tax Percentage Depletion - Blundell Stea Field (prior IGC)
PPL Pre -1943 Prefered Stock Div - Deduction
IFERC FORM NO.1 (ED. 12-87) Page 450.3
$
Amounts
(431,583)
(381,063)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/04
FOOTNOTE DATA .
.
Utah Deferred Comp/ COLI
Repair Deduction
Tax Depreciation
Capitalized Depreciation
Gain / (Loss) on Prop. Disposition
Coal Mine Development
Coal Mine Extension
Removal Costs
Cholla SHL-NOPA (Lease Amortzation)
ARO - reclass to ARO liabilities
ARO - reclass to reguatory assets/lability & ARO liabilty
Book GainLoss on Land Sales
Tax Percentage Depletion - Deduction
DTA 105.154 Section 383 capital loss carr forward
DTA 105.155 Section 382 NOL car forward
Tax Depletion
ARO Regulatory Assets
Goodnoe Hils Liquidation Damages - WY
RTO Grid West Notes Receivable - OR
Contr Pension Regulatory Asset MMT & CTG - OR
Contra Pension Regulatory Asset MMT & CTG - WY
Contra Pension Regulatory Asset CTG - UT
Contr Pension Regulatory Asset MMT & CTG - CA
Contra Pension Regulatory Asset CTG - W A
Deferred Excess Net Power Costs - WY 08
Deferred UT Independent Evaluation Fee
Deferred Excess Net Power Costs - ID 09
Idao Customer Balancing Account
Weatherization
Regulatory Asset balance reclass
Reg Asset - SB 1149 Balance Reclass
Reg Asset - Other - Balance Reclass
Reg Asset - Def NPC Balance Reclass
Trapper Mining Stock Basis
Prepaid Taxes - OR PUC
Other Prepaid
Prepaid Taxes - Propert Taxes
WY Joint Water Board Reserve - Deduction
Wasach workers comp reserve
West Valley Lease Reduction - CA
West Valley Lease Reduction - ID
West Valley Lease Reduction - WY
A&G Credit - CA
A&G Credit - ID
A&G Credit - WY
Self Insured Health Benefit
Vacation Accrual- Cash Basis (2.5 months)
Deferred Compensation Accrual - Cash Basis
Severance Accrual - Cash Basis
Accrued CIC Severance
Pension Liability
Post-Retiement Liability
SERP Liability
I FERC FORM NO. 1 (ED. 12-87) Page 450.4
(5,066,251)
(123,958,317)
(1,622,113,173)
(4,989,970)
(25,010,569)
(433,210)
(1,641,996)
(51,617,122)
(68,842)
(16,001,650)
(23,435,597)
(1,077,748)
(7,886,500)
(43,795)
(186,450)
(173,901)
(7,348,338)
(510,000)
(80,769)
(979,620)
(1,367,611)
(5,867,400)
(84,718)
(237,141)
(1,539,406)
(80,676)
(2,615,813)
(155,562)
(18,706,576)
(2,619,115)
(68,360)
(244,836)
(2,604,370)
(1,529,077)
(51,760)
(1,877,954)
(4,680,901)
(300,000)
(255,901)
(28,291)
(437,852)
(1,365,919)
(45,315)
(451,245)
(1,476,750)
(707,070)
(532,490)
(169,928)
(233,045)
(839,908)
(69,316,122)
(13,468,497)
(690,345)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/04
FOOTNOTE DATA
M&S Inventory Write-Off
Bad Debts Allowance - Cash Basis
R & E - Sec.74 Deduction
Oregon LIC Bid Liability Reserve
Accrued Royalties
Misc. Non-Curent Accrued Liabilty
Misc. Curent and Accrued Liability
Amortzation NOPAs 99-00 RAR
MCI FOG Wire Lease
Injures and Damages Accrul - Cash Basis
Bridger Coal Company ARO - Regulatory Asset
Bridger Coal Company Underground Mine Cost Depletion
PMI Overrding Coal Royalty % Depletion - PacifiCorp
Depreciation (Tax Depreciation M-l) - PMI
Coal Mine Extension Costs - PP&E - PMI
Sec. 263A Inventory Change - PMI
PMI Development Cost Amortzation
PMI Pre-Strpping Costs
Bridger Coal Company Extraction Taxes Payable - PMI
Total
/Schedule Page: 261 Line No.: 43 Column: b
(1,250,181)
(1,168,170)
(9,127,439)
(342,000)
(5,051,429)
(833,757)
(1,845,876)
(58,446)
(314)
(1,013,694)
(6,706,137)
(134,860)
(14,662)
(25,160,966)
(731,202)
(307,884)
(3,507,875)
(221,151)
(94,767)
$ (2,085,657,228)
Berkshire Hathaway Inc. includes PacifiCorp in its United States federal income tax retu. PacifiCorp's provision for income taxes has
been computed on a stad-alone basis.
Names of group members who wil me a consolidated Federal Tax Return:
UnderMEHC:
PPW Holdings LLC Sub-Group:
PacifiCorp
PPW Holdings LLC
PacifiCorp Sub-Group:
Centrlia Miing Company
Energy West Mining Company
Glenrock Coal Company
Interwest Miniig Company
Pacific Minerals, Inc.
PacifiCorp Environmental Remeclation Co.
PacifiCorp Futue Generations, Inc.
PacifiCorp Investment Management, Inc.
MEHC Sub-Group:
Alaska Gas Transmission Company, LLC
Allerton Capital, Ltd
American Pacific Finance Company
American Pacific Finance Company II
Arona Home Serices, L.L.C.
IFERC FORM NO.1 (ED. 12-87)
BG Energy Holdig LLC
BG Energy LLC
BGE Holdigs LLC
CalEnergy Generation Oprating Company
CalEnergy Holdings, Inc
Page 450.5
.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
MEHC Sub-Group (continued):
CalEnergy International Services, Inc
CalEnergy International, Inc
CalEnergy Minerals Development LLC
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 Geothermal, LLC
CE Indonesia Geothermal, Inc
CE InternatÍonal Investments, Inc
CE Obsidian Energy LLC
CE Obsidian Holding LLC
CE Power, Inc
CE/TALLC
Champion Realty, Inc
Chancellor Title Services, Inc
Cimed Leasing Company
Columbia Title of Florida, Inc
Constellation Energy Holdings LLC
Cordova Energy Company LLC
Cordova Funding Corporation
Dakota Dunes Development Company
DCCO,Inc
Edina Financial Services, Inc
Edina Realty Insurance, LLC
Edina Realty Referrl Network, Inc
Edina Realty Relocation, Inc
Edina Realty Title, Inc
Edna Realty, Inc
Esslinger- W ooten-Maxwell, Inc
E- W -M Referrl Services, Inc.
FFR, Inc
First Realty, Ltd
First Reserve Insurance, Inc
For Rent, Inc
HMSV Financial Services, Inc
HN Heritage Title Holdings, LLC
HN Insurance Holdings, LLC
HN Mortgage, LLC
HN Real Estate Group N.C., Inc.
HN Real Estate Group, LLC
I FERC FORM NO.1 (ED. 12-87)
HN Referral Corporation
HomeServices Financial Holdings, Inc
HomeServices Financial, LLC
HomeSerices Financial-Iowa, LLC
HomeServices Insurance, Inc
HomeServices of Alabama, Inc.
HomeServices of America, Inc
HomeServices of California, Inc
HomeServices of Florda, Inc
HomeServices of Ilinois d//a Koenig & Strey GM
HomeServices of Iowa, Inc
HomeServices of Kentucky Real Estate Academy, LLC
HomeServices of Kentucky, Inc
HomeServces of Nebraska, Inc
HomeServices of Nevada, Inc
HomeServices of the Carolinas, Inc
HomeServices Referral Network, LLC
HomeServces Relocation, LLC
HSR Equity Funding, Inc
Huff Commercial Group, LLC
Huff Realty Insurnce, LLC
Huff-Drees Realty, Inc.
IMO Company, Inc
InsurceSouth, LLC
InterCoast Capital Company
InterCoast Energy Company
Iowa Realty Company, Inc
Iowa Realty Insurance Agency, Inc
Iowa Title Company
IWGCo8
J.S. White Associates, Inc
JBRC, Inc.
Jenny Pruitt & Associates
Jim Huff Realty, Inc.
JP &A, Inc
JRBW Realty, Inc d//a RealtySouth
Kansas City Title, Inc
Kentucky Residential Referrl Service, LLC
Kern River Funding Corporation
Ker River Gas Transmission Compay
KR Acquisition 1, LLC
KR Acquisition 2, LLC
KR Holding, LLC
Larabee School of Real Estate & Insurance
M & M Ranch Acquisition Company, LLC
M & M Ranch Holding Company, LLC
MEC Constrction Services Company
MEHC Alaska Holding 1, LLC
MEHC Alaska Holding 2, LLC
MEHC America Trasco, LLC
MEHC Insurance Services Ltd.
MEHC Investment, Inc
Page 450.6
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2). A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
MEHC Sub-Group (continued):
MEHC Merger Sub Inc
MEHC Texas Trasco, LLC
MHC Investment Company
MHC,Inc
Mid-America Referral Network, Inc.
MidAerican Commercial R.E. Services, Inc
MidAerican Energy Company
MidAerican Energy Holdings Company
MidAmerican Energy Machining Services LLC
MidAmerican Funding, LLC
MidAerican Nuclear Energy Company, LLC
MidAerican Nuclear Energy Holdings Co., LLC
MidAmerican Services Company
MidAmerican Transmission, LLC
Midland Escrow Services, Inc
Midwest Capital Group, Inc
Midwest Gas Company
MortgageSouth, LLC
MWR Capital, Inc
Nebraska Land Title & Abstrct Company
NNGC Acquisition, LLC
Norther Aurora Inc
Nortern Natual Gas Company
Pickford Escrow Company, Inc
Pickford Golden State Member LLC
Pickford Holdings LLC
Pickford Real Estate, Inc
Pickford Services Company, Inc
Plaza Financial Services, L.L.C.
Plaz Mortgage Services, L.L.C.
Preferred Carolinas Realty, Inc
Prefered Carolinas Title Agency, L.L.c.
Professional Referrl Organization, Inc
Quad Cities Energy Company
Real Estate Link, LLC
Real Estate Referral Network, Inc
Reece & Nichols Allance, Inc
Reece & Nichols Realtors, Inc
Referral Company of Nort Carolina, Inc
RHL Referral Company, L.L.C.
Robert Brothers, Inc
Roy H. Long Realty Company, Inc
Safe Haror Holding Company, LLC
Salton Sea Minerals Corporation
San Diego PCRE, Inc
Semonin Realtors, Inc
Southwest Relocation, LLC
The Escrow Fir
The Referrl Company
TitleSouth, LLC
Trinity Mortgage Parers, Inc
Two Rivers, Inc
United Settlement Serices, L.C.
West Valley Holdings, LLC
With respect to members of the MEHC Sub-Group, MEHC requires all subsidiares to payor receive from MEHC an amount of tax based
primarily on the stand-alone method of allocation. The computation includes all tax benefits from tax deductions stemming from cost
borne by utility customers.
Berkshire Hathaway Inc. Sub-Group:
21st Communities, Inc.
21st Mortgage Corporation
21st SPC, Inc.
AAS-Lunen, Inc.
Acme Brick Company
Acme Brick DFW, Inc.
Acme Brick Sales Company
Acme Building Brands, Inc.
Acme Investment Company
Acme Management Company
Acme Ocbs Brick and Stone, Inc.
Acme Service Company, L.P.
A4alet/Scott Fetzer Company
AEG Processing Center No. 58, Inc.
AEG Processing Center No. 35, Inc.
Agile Mfg, Inc.
AJF Warehouse Distrbutors, Inc.
I FERC FORM NO. 1 (ED. 12-87)
ALfEX Homes, Inc.
Albecca Inc.
Alexander City Flying Servces, Inc.
All Bilt Uniforms
Alpha Caro Motor Express, Inc.
Ambucor Health Solutions, Inc.
America All Risk Insurce Services, Inc.
American Centenial Insurance Company
Amercan Commercial Claims Administrators, Inc.
American Dair Queen Corporation
Amercan Employer Group, Inc.
American Tile Supply, Inc.
Anderson Hardwood Floors, Inc.(:fa Shaw-Raor Floors, Inc)
Apeks Apparel, Inc.
Applied Group Insurnce Holdings, Inc.
Applied Investigations Inc.
Applied Logisitics, Inc.
Page 450.7
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp (2) A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group (continued):
AppliedPremiinFinance, Inc.
Applied Processing Center No. 60, Inc.
Applied Risk Services of New York, Inc.
Applied Risk Serices, Inc.
Applied Underwters, Inc.
Atlanta International Insurance Company
AU Captive Risk Assurance Co
AU Captive Risk Assurance Co., Inc.
AU Holding Company, Inc.
AUI Employer Group No. 42, Inc.
Ben Bridge Jeweler, Inc.
Benjamin Moore & Co.
Berkshire Hathaway Credit Corp.
Berkshire Hathaway Finance Corporation
Berkshire Hathaway Inc. (Common Parent)
Berkshire Hathaway Life Insurnce Co. ofNE
Berksire Hathaway Assurance Company
BH Affordable Housing Inc
BH Columbia Inc.
BH Finance, Inc.
BH Shoe Holdings, Inc.
BHG Strctued Settlements, Inc.
BHRInc.
BHSF, Inc.
Blue Chip Stamps
BNJ NetJets, Inc.
Boat America Corporation
Boat U.S, Inc.
Boat U.S. Travel International, Ltd.
Boot Royalty Company
Borsheim Jewelr Company Inc.
BR Agency, Inc.
Bricker-Mincolla Uniform
Brilliant National Services, Inc.
British Insurance Company of Cayman
Brooks Sports, Inc. & Subsidiary
Brookwood Insurance Company
Business Wire Canada Inc.
Business Wire, Inc.
C & R Insurance Services, Inc.
California Employer Group No. 27, Inc.
California Insurnce Company
Camp Manufactung Company
Campbell Hausfeld/Scott Fetzer Company
Carefree/Scott Fetzer Company
Cavalier Homes, Inc.
Central States Indemnity Co. of Omaha
Central States of Omaha Companies, Inc.
CG Service, Inc.-
Chatwell, Inc
Chippewa Shoe Company
Citadel Insurnce Company
IFERC FORM NO.1 (ED. 12-S7)
CJE II, Inc.
Claims Services, Inc.
Clayton Commercial Buildings, Inc.
Clayton Homes, Inc.
CMH Capital, Inc.
CMH Hodgenvile, Inc.
CMH Homes, Inc.
CMH Manufactung West, Inc.
CMH Manufactung, Inc.
CMH ofKY, Inc.
CMH Parks, Inc.
CMH Serices, Inc.
CMH Set and Finish, Inc.
Cologne Reinsurance Company of America
Cologne Services Corporation
Columbia Insurnce Company
Combined Claims Services, Inc.
Command Uniforms
Commercial Casualty Insurance Company
Commercial General Indemnity, Inc.
Commonwealth Uniforms Inc.
Complementa Coatings Corporation
CompuTrus, Inc.
Continental Divide Insurance Co.
Contiental Indemnity Company
Corbond Corporation
Cornusker Casualty Company
CaRT Business Services Corporation
Coverage Dynamics.Group, Inc.
Criterion Insurce Agency
Cross Creek Apparel, LLC
Crowley Garent Mfg Co Inc.
Crowley Shir Mfg Co Inc.
CSI Life Insurance Company
CTB Credit Corp.
CTB International Corp.
CTB IP, Inc.
CTB MN Investments Co. Inc.
CTB, Inc.
Cumberland Asset Management, Inc.
Cypress Insurance Company
Dairy Queen Corporate Stores, Inc.
Dair Queen of Georgia, Inc.
Denver Brick Company
Dexter Shoe Company
DQ Funding Corporation
DQ Joint Ventue Stores, Inc.
DQ Managed Stores, Inc.
DQ Wholly-Owned Stores, Inc.
DQF, Inc.
DQGC,Inc.
Eco Color Company
Page 450.8
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group (continued):
Edmonds 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.
Faireld Insurance Co.
Faraday Capital Limited
Farors, Inc.
FFG Insurance Company
Finial Holdings, Inc.
Finial Insurce Company
Finial Reinsurance Company
First Berkshire Hathaway Life Insurance Company
FlightSafety Capital Corp.
FlightSafety China, Inc.
FlightSafety Development, Inc.
FlightSafety International Inc.
FlightSafety New York, Inc.
. FlightSafety Properties, Inc.
FlightSafety Services Corpration
Floors Inc.
Footwear Investment Company
Forest River Financial Services, Inc.
Forest River Housing, Inc.
Forest River Waranty Company
Forest River, Inc.
France/Scott Fetzer Company
Freedom Warehouse Corp.
Fruit of the Loom Caribbean, Inc.
Fruit of the Loom Trading Company
Frut of the Loom, Inc.
FSI Delaware Holding Corp.
FTL Regional Sales Co., Inc.
FTL Sales Company, Inc.
. Garan Central America Corp.
Garan Incorporated
Garan Manufactung Corp
Garan Services Corp
Gateway Underwriters Agency,Inc.
GEICO Casualty Company
GEICO Corporation
GEICO General Insurce Company
GEICO Indemnity Company
GEICO Insurance Agency, Inc.
GEICO Products, Inc.
Gen Re Intermediares Corporation
General Re Corporate Finance, Inc.
General Re Corporation
General Re Financial Products Corporation
General Re Funding Corporation
I FERC FORM NO.1 (EO. 12-87)
General Re Investment Holdings Corporation
General Re New England Asset Management
General Re Servces Corporation
General Reinsurance Corporation
Generl Sta Indemnity Company
General Sta Management Company
General Sta National Insurnce Company
Genesis Indemnity Insurance Company
Genesis Insurce Company
Genesis Underwtig Management Company
Giles Industres, Inc.
Glass Mountain Optics, Inc.
GMK, Ltd.
Golden Skilet International, Inc.
Government Employees Financial Corporation
Governent Employees Insurance Company
GRD Global, Inc.
GRD Holdings Corporation
Griffey Uniform
H.H.Brown Shoe Company,Inc.
H.H.Brown Shoe Technologies,Inc.
H.I. Justi and Sons, Inc.
Halex/Scott Fetzer Company
Hall of Fame Paint Supply Inc.
Hardy Frames, Inc.
Hars Uniforms
Harson Uniform
HDS Redevelopment Corporation
HeatPipe Technologies
Helzberg's Diamond Shops, Inc.
Henley Holdigs, LLC
Hohman & Barard, Inc.
Homefit Agency, Inc.
Homemakers Plaza, Inc.
Indecor Group Inc. d//a J.C.Licht Company
Innovative Building Products, Inc.
Insurance Counselors of Nevada, Inc.
International America Group Inc.
International American Management Company
Interational Dair Queen, Inc.
International Insurance Underwters,Inc.
Isabela Shoe Corporation
J. S. Justi, Inc.
Janovic/Plaz Inc.
JME3CO
Johns Manville China, LTD.
Johns Manville Corporation
Johns Manvile, Inc.
Jordan's Furitue, Inc.
Justin Belt Company, Inc.
Justin Boot Company
Justi Brands, Inc.
Page 450.9
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp ! (2)A Resubmission 04/14/2010 2009/Q4
FOOtNOTE DATA
Berkshire Hathaway Inc. Sub-Group (continued):
Justin Industries, Inc.
Kale Uniforms
Kansas Bankers Surety Company
Karelkorn Shoppes, Inc.
Kay Uniform
Kleberg Holdings Inc.
. LA Terminals, Inc.
Leesburg Yam Mils, Inc.
M & C Products, Inc.
Macro Retailng, Inc.
Mapletree Transporttion, Inc.
Martn Manufactung Company
Marn Mils, Inc.
Marland Ventues, 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 Midwest, Inc.
McLane Minesota Inc.
McLane New Jersey, Inc.
McLane Southern, Inc.
McLane Suneast, Inc.
McLane Western, Inc.
Medical Protective Corporation
Medical Protective Finance Corporation
Medical Protective Insurance Services, Inc.
MedPro Risk Retention Services, Inc.
Metro Uniforms
MH Transport, Inc.
Miler-Sage, Inc.
MiTek Framings, Inc.
MiTek Holdings, Inc.
MiTek Industres, Inc.
MiTek, Inc.
MMX Corporation
Mobile Disaster Strctues, Inc.
Mossy Oak Apparel Company
Mount Vernon Fire Insurce Company
Mountain View Marketing, Inc.
Mouser Electronics, Inc.
MS Propert Company
MTSub, Inc.
National Fire & Marie Insurance Co.
National Indemnity Company
National indemnity Company of Mid-America
National Indemnity Company of the South
National Liability & Fire Insurance Co.
National Reinsurance Corporation
IFERC FORM NO.1 (ED. 12-87)
Nationwide Uniforms
Nebraska Furitue Mar, Inc.
NetJets Aviation Inc.
NetJets Europe Holdings LLC
NetJets Inc.
NetJets International Inc.
NetJets Large Aircraft, Inc.
NetJets Leasing, Inc.
NetJets M E Inc.
NetJets Sales Inc.
NetJets Services Inc.
NetJets U.S., Inc.
NFM of Kansas, Inc.
Nick Bloom Uniform
NJ Executive Services Inc.
NJA Jets Inc.
NJE Holdings LLC
NJI Sales Inc.
NJI, Inc.
Nocona Boot Company
Nort American Casualty Co
Nort Star Reinsurance Corporation
Nort Sta Syndicate, Inc.
Nortern States Agency, Inc.
Nortland/Scott Fetzer Company
Oak River Insurance Company
OBHInc.
Old City Pait & Decorating, Inc.
Orange Julius of Amerca
Pan-Am Shoe Co., Inc.
Pima Uniforms
Pinnacle Paint & Decorating, Inc.
PIR Management Inc
Plaza Financial Services Co.
Plaza Resources Co.
Ponce Fashions, Inc.
Portland Gold Corp. d//a! Maine Paint Service
Precision Brand Products
Precision Steel Warehouse - Charlotte
. Precision Steel Warehouse - Franklin Park
Priority One Financial Serces, Inc.
Pro Installations, Inc.
Professional Dataolutions, Inc.
Promesa Health, Inc.
Queen Caret Corporation
R.C.Wiley Home Furshings
Rabun Apparel, Inc.
Railsplitter Holdings Corporation
RainbowState Paint & Decorating Inc.
Redwood Fire and Casualty Insurance Co.
RENTCO Trailer Corporation
Resolute Management Inc.
Page 450.10
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group (contiued):
Richline Group, Inc.
Rigwalt & Liesche Co
Roberts Men's Shop
Running with Heels (Micro Retailing, Inc.)
Russell Brads LLC (f/ka Russell Corporation)
RusselFFinancial Services, Inc.
Salado Sales, Inc.
Scott Fetzer Finanial 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 ContractFlooring Installation Services, Inc.
Shaw Contract Flooring Services, Inc.
Shaw Diversified Services, Inc.
Shaw Floors, Inc.
Shaw Funding Company
Shaw Industres Group, Inc.
Shaw Industres, Inc.
Shaw Intertional Services, Inc. (tka Shaw Financial Services, Inc.)
Shaw Retail Properies, Inc.
Shaw Transport, Inc.
SHX Floorig, Inc.
SHX Leasing, Inc.
SidePlate Systems, Inc.
Silver State Uniform
Simon's Incorporated
Simpad, Inc.
Soco West, Inc.
Sofft Shoe Company, Inc.
Sol Fran Uniforms Inc.
Somerset Services
Southern Energy Homes of Pennsylvania, Inc.
Southern Energy Homes, Inc.
Sportexe Constrction Services, Inc. -
Stahl/Scott Fetzer Company
Sta Furitue Company
Strategic Staff Management, Inc.
Strck Mexicana, S.A.
Technical Coatings Co.
The Ben Bridge Corpor¡ition
The BVD Licensing Corp.
The Eagle Company
The Fechheimer Brothers Co.
The Indecor Group, Inc.
The Medical Protective Company
The Pampered Chef Nort America, Ltd
The Pampeed Chef, Ltd
The Scott Fetzer Company
TM Custom Air Systems, Inc.
IFERC FORM NO.1 (ED. 12-87) Page 450.11
Tony Lama Company
Top Five Club, Inc.
TPC - EuropeanHoldings, Ltd.
Transco, Inc.
TTl, Inc.
U.S. Investment Corporation
U.S. Liability Insurance Company
U.S. Underwters Insurance Company
Undergarent Fashions, Inc.
Unified Supply Chain, Inc.
Uniforms of Texas
Union Sales, Inc.
Union Underear Co., Inc.
Unione Italiana Reinsurance Company of America, Inc.
United Consumer Financial Services, Inc.
United Direct Finance Inc.
United States Aviation Underwters, Inc.
Universal Uniforms
Vanderbilt ABS Corp.
Vanderbilt Mortgage & Finance, Inc.
Vanderbilt Propert & Casualty Insurance Co., Ltd.
Vanderbilt SPC, Inc.
Vanity Fair Inc.
Verita Insurance Group, Inc.
Vessel Assist Association of America, Inc.
Vessel Assist Insurce Services, Inc.
VFI-Mexico, Inc.
Virginia Paint Co., Inc.
Vision Retailing
Wayne/Scott Fetzer Company
Waynesburg Shir Company Inc.
Wesco Financial Corporation
Wesco Holdings Midwest, Inc.
Wesco-Financial Insurance Co.
West Virginia Uniforms
WesterScott Fetzer Company
Wheeler Brick Company, Inc.
Whitter, Clark & Daniels, Inc
Witt Brick & Supply, Inc.
WMCCorp.
Woodperfect, Inc.
World Book Encyclopedia,. Inc.
World Book, Inc.
World Book/Scott Fetzer Company, Inc.
Worldbook.com Inc.
X-L-CO., Inc.
XLI, Inc.
XTR Inc.
XTR Chassis, Inc.
XTR Companies, Inc.
XTR Corporation
XTR Finance Corporation
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifCorp 1(2) A Resubmission 04/14/2010 2009104
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group (continued):
XTRA Intermodal, Inc.
XTRA International Pacific, LTD.
XTRA Interational, LTD.
XTRA Mexicana, S.A. de C.V.
Zuckerbergs Uniform
IFERC FORM NO.1 (ED. 12-S7) Page 450.12
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCqrp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
TAXES ACCRUED, PREPAID AND CHAF GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued ta accunts and show the total taxes charged to operations and other accunts during
. the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accunts, (not charged to prepaid or accrued taes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts crdited to proporions of prepaid taes chargeable to currnt year, and (c) taes paid and chared direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total ta for each State and subdivision can readily be ascertained.
ine Kind of Tax BALANCE AT BEGINNING OF YEAR ,taxes le~~S Adjust-ChargedNo.(See instruction 5)T axes Accrued i-repato i axes ~ring ~ring ments(Account 236)(Include in Accunt 165)ear ear
(a)(b)(c)(d).(e)(f)
1 Federa:
2 Incme 39,022,654 -443,150,886 -260,820,650
3 FICA 452,938 17,521 37,052,655 36,833,710
4 Unemployment 57,329 364,709 369,136
5 Excise Tax - Coal 90,184 4,218,596 4,140,975
6 Subtotal 600,451 39,040,175 -401,514,926 -219,476,829 7,394,247
7 ~
8 State:
9
10 Arizona:
11 Propert 917,815 1,921,133 1,878,382
12 Income .638,661 440,661 -153,076 .
13 Subtotal 917,815 638,661 2,361,794 1,725,306
14
15 California:.
16 Propert 2,215,392 2,215,392
17 Unemployment 1,497 31,560 33,057
18 Franchise-Income .657,111 5,557 -287,199
19 Use 7,251 140,752 142,422
20 Local Franchise 862,975 1,159,804 1,086,413
21 Subtotal 871,723 657,111 3,553,065 3,190,085
22
23 Corao:
24 Propert 1,920,000 1,935,380 1,954,380
25 Income 138,583 94,583
26 Subtotal 1,920,000 138,583 2,029,963 1,954,380
27
28 Idaho:
29 Propert 1,747,058 3,496,756 3,187,061
30 Income -33,042 -590,251 83,230
31 KWh 11,912 32,595 29,495
32 Unemployment 842 44,434 44,543
33 Use 3,361 110,331 112,855
34 Subtotal 1,763,173 -330,042 3,093,865 3,457,184
35
36 Montana:
37 Propert 1,398,191 2,802,927 2,801,127
38 Corporate License-Income 282,662 226,484 -209,838
39 Unemployment 138 592 730
40 Energy License 60,495 166,489 193,622
,
41 TOTAL 28,648,482 51,215,626 -257,508,339 -77,402,933 9,256,232
FERC FORM NO.1 (ED. 12-96)Page 262
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
TAXES ACCRUED, PREPAID AND CHARGED DUliNG YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column(f) and explain each adjustment in a foot- note.. Designate debit adjustments
by-parentheses.
7. Do not indude on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
_ pertaining to electric operations. . Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertining to other utilty departments and
amounts charged to Accounts 408.2 ¡:nd 409.2. Also shown in column (I) the taxes charged to utilty 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 apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepai Taxes Electric Extraordinary Items . AO¡Ustments to K~t.Other No.
ACCO~m236)(Inc!. in Account 165)(Account 408.1, 409.1)(Account 409.3)Eamings (Accunt 439)
(h)(i)ü)(k).(I)
1
15,057,106 243,804,243 -472,156,577 IE654,362
52,902 .
167,805 .,
15,932,175 243,804,243 -472,156,577 70,641,651 6
7
8
9
10
960,566 1,921,133 11
44,924 386,198 ~960,566 44,924 2,307,331 54,463 13
14
15
2,016,663 IE 17
364,355 -116,046 18
5,581 19
936,366 1,159,804 20
941,947 364,355 3,060,421 492,644 21
22
23
1,901,000 1,934,635 ~44,000 94,579 25
1,901,000 44,000 2,029,214 749 26
27
28
2,056,753 3,312,653 29
343,39 -860,429 30
15,012 32,595 31
733 32
837 33
2,073,335 343,439 2,484,819 609,046 34
35
36
1,399,991 2,802,927 37
-153,660 197,105 ~39
33,362 166,489 40
46,747,021 258,675,803 -350,305,291 92,796,952 41
.
FERC FORM NO.1 (ED. 12-96)Page 263
Name of Respondent This î!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accunts dunng
the year. Do not include gasoline and other sales taxes which have been charged to the accunts to which the taxed matenal 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 dunng the year and charged direct to final accunts, (not charged to prepaid or accrued taes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proortions of prepaid taxes chargeable to current year, and (c) taes paid and charged direct to operations or accounts other than
acerued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total ta for each State and subdivision can readily be ascertained.
ii.ine Kind of Tax BALANCE AT BEGINNING OF YEAR :1tes ie~fâs Adjust-C argedNo.(See instruction 5)Taxes Accrued F'repald Taxes ~i?g ~ring ments
(Accunt 236)(Include in Accunt 165)ear
(a)(b) .(c)(d)(e)(f)
1 Wholesale Energy ..43,104 118,652 137,968
2 Subtotal 1,501,928 282,662 3,315,144 2,923,609
3
4 New Mexico:
5 Propert 5,306 8,247 13,553
6 Income 1,752 1,802 50
7 Subtotal 5,306 1,752 10,049 13,603
8
9 Oregon:
10 Propert 8,670,415 18,314,174 19,264,470
11 Unemployment 57,574 1,613,738 1,632,793
12 Wilsonvile Payroll 198 850 760
13 Excise-Income -3,349,849 -3,151,426 1,121,010
14 City of Portland-Income -8,414 -85,314 100
15 Department of Energy 324,718 , .682,162
16 Tri-Met 347,378 891,484 887,403
17 Lane County 2,571 2,571
18 Franchise 4,064,890 21,551,799 ... 21,421,018
19 Subtotal 4,470,040 5,56,870 39,820,038 44,330,125
20
21 Uta:
22 Propert 881,853 43,374,988 43,858;491
23 Income 5,225,854 1,211,934 -329,716
24 Unemployment 53,173 205,927 206,950
25 Navajo Nation 1,549 1,549
26 Use 416,901 4,133,107 4,235,093
27 Subtota 1,351,927 5,225,854 48,927,505 47,972,367
28
29 Washington:
30 Proper 8,553,361 6,095,225 7,861,586
31 Unemployment 8,88 67,087 73,359
32 Business & Occupation 25,795 159,722 180,519
33 Public Utilty 875,00 10,921,843 10,121,843
34 Natural Gas Use Tax 964,129 2,420,896 2,935,466..35 Use 64,704 803,403 829,184
36 Land Tax 63 63
37 Subtotal 10,491,872 20,468,239 22,002,020
38
39 Wyoming:.
40i Propert 4,351,898 13,087,488 10,894,988
41 TOTAL 28,648,482 51,215,626 -257,508,339 -77,402,933 9,256,232
FERC FORM NO.1 (ED. 12-96)Page 262.1
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entres with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in COlumn (I) only the amounts charged to Accounts 408.1 and 409.1
pertining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utilty departments and
amounts ctiarged to Accounts 408.2 and 409.2. Also shown in column (I) the taes charged to utilty plant or other balance sheet accounts.
. . .9. For any tax apportioned to more than one utilty department or account, state in a footnote the basis (necessity) of appôrtioning slJch ta.
.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued .Prepaid Taxes Electric Extraordinary Items Adjustments to Ret.Other No.
ACC~~n 236)(Inc!. in Accunt 165)(Account 408.1, 409.1)(Account 409.3)Eamings (Accunt 439)
(h)(i)ü)(k)(I)
23,788 118,652 1
1,457,141 -153,660 3,285,173 29,971 2
3
..4
8,247 5
.1,528 ~9,775 274 7
8
9
9,620,711 17,771,107 10
38,519 11
288 12
922,587 -4,826,485 ii 13
1,000 -86,081 14
357,444 682,162 15
351,459 ..16
.17
4,195,671 21,551,799 18
4,943,381 10,544,298 35,092,502 4,727,536 19
20
21
398,350 40,790,528 22
3,684,204 -577,730 23
52,150 24
1,549 25
314,915 26
765,15 3,684,204 40,214,347 8,713,158 27
28
29
6,787,000 5,951,027 .30
2,611 ..31
4,998 156,529 32
1,675,000 10,921,843 33
449,559 34
38,923 35
63 ..36
8,958,091 17,029,462 3,438,777 37
38
39
.6,544,398 10,494,186 ~.
46,747,021 258,675,803 -350,305,291 92,796,952 41
FERC FORM NO.1 (ED. 12-96)Page 263.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/14/2010
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accunts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charg to th 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 accunts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taes paid and charged direct to operations or accunts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total ta for each State and subdivision can readily be ascertined.
.
iLine Kind of Tax BALANCE AT BEGINNING OF YEAR cii:~~le~tâS Adjust-No.(See instruction 5)Taxes Accrued ~repa~d Taxes ~ring ~ring ments(Accunt 236)(Include in Accunt 165)ear ear(a)(b)(c)(d)(e)(f)
1 Unemployment 4,881 170,438 173,318
2 Franchise 241,500 1,513,182 1,515,582
3 Use 111,384 1,324,943 1,325,033
4 Annual Report 53,226 53,226
5 Subtotal 4,709,663 16,149,277 13,962,147
d .6
7 State Other 3,761,160
8
9 Miscellaneous:
10 Goshute Possessory 27,023 13,722 40,745
11 Sho-Ban Possessory 132,712 132,712
12 Navajo Possessory 17,561 36,004 35,563
13 Ute Possessory 17,523 17,523
14 Crow Possessory 62,262 62,262
15 Umatila Possessory 52,080 52,080
16 Other Taxes 202,185 202,185
17 Subtotal 44,584 4,277,648 543,070 1,861,985
18
19
20
21 .
22
23
24
25
26
27
28
29
30
31 .
32
33
34 .
35
36
37
38
39 .
40
41 TOTAL 28,648,482 51,215,626 -257,508,33 -77,402,933 9,256,232
FERC FORM NO.1 (ED. 12-96)Page 262.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1 ) An Original (Mo, Da, Yr)End of 2009/Q4
(2) r=A Resubmission 04/14/2010
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accunts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
trnsmittal of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utilit departents and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utilty plant or other balance sheet accunts.
9. For any tax apportioned to more than one utilty department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accréd Prepaid Taxes Electric Elåraordinary Items ~J~~ro_~ACCO~m236)(Incl. in Account 165)(Account 408.1, 409.1)(Account 409.3)Earnings (Account 439) er .
(h)(i)0)(k) (I)
2,001 1
239,100 1,513,182 2
111,294 3
.53,226 4
6,896,793 12,060,594 4,088,683 5
~ ~. -..6
1,899,175 .3,761,160 7
8
9
13,722 10
132,712 11
18,002 ~36,004 12
17,523 .13
62,262 14
52,080 15
.202,185 16
1,917,177 4,277,648 17
18
19
20
21
22
23
.c-24
25
26
27
28
29
30
31
32
33
34
..35
36
37
38
39
40
46,747,021 258,675,803 -350,305,291 92,796,952 41
.
FERC FORM NO.1 (ED. 12-96)Page 263.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
I§chedule Page: 262 Line No.: 2 Column: f
Reclass of unecognized tax benefits $
Reclass as a result of an effective settlement of an
Internal Revenue Service Exam
Effective settlement ofInternal Revenue Servce ExamTotal adjustments $
Amount
7,382,752
Account
174
11,548
(53)
7,394,247
283
131
I§chedule Page: 262 Line No.: 2 Column: i
Federal income tax a licable to other income & deductons - 409.2
chedule Pa e: 262 Line No.: 3 Column: i
Payroll taxes of$2,007,076 for Energy West were charged to Fuel Stock - 151. All other payroll taes are charged to fuctional
accounts, which is consistent with where labor is charged.
¡Schedule Page: 262 Line No.: 4 Column: I
Payroll taes of $20,862 for Energy West were charged to Fuel Stock - 151. All other payroll taes are charged to functional
accounts, which is consistent with where labor is charged.
~chedule Page: 262 Line No.: 5 Column: i
Fuel inventory - 151
~chedule Page: 262 Line No.: 12 Column: i
State income tax applicable to other income & deductions - 409.2
~chedule Page: 262 Line No.: 16 Column: i
Taxes applicable to other income & deductions
Constrction
Distnbution rent expense, rents
Tota
$
Amount
141,647
55,601
1,481
198,729
Account
408.2/409.2
107
589
$
I$chedule Page: 262 Line No.: 17 Column: i
Varous operations and maintenance accounts.
I$chedule Page: 262 Line No.: 18 Column: i
State income tax applicable to other income & deductions - 409.2
I$chedule Page: 262 Line No.: 19 Column: i
Cleann account - 184
chedule Pa e: 262 Line No.: 24 Column: i
Taxes applicable to other income & deductions - 408.2, 409.2
I$chedule Page: 262 Line No.: 25 Column: i
State income tax applicable to other income & deductions - 409.2
I$chedule Page: 262 Line No.: 29 Column: i
Taxes applicable to other income & deductions
Constrction
Total
$
Amount
1,945
182,158
184,103
Account
408.2/409.2
107
$
I$chedule Page: 262 Line No.: 30 Column: I
State income tax applicable to other income & deductions - 409.2
I$chedule Page: 262 Line No.: 32 Column: i
Varous operations and maintenance accounts.
I$chedule Page: 262 Line No.: 33 Column: i
Clearg account - 184
I$chedule Page: 262 Line No.: 38 Column: i
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 1(2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA .
State income tax applicable to other income & deductions - 409.2
I$chedule Page: 262 Line No.: 39 Column: i
Varius operations and maintenance accounts.
I$chedule Page: 262.1 Line No.: 6 Column: i
State income tax applicable to other income & deductions - 409.2
I$chedule Page: 262.1 Line No.: 10 Column: i
Taxes applicable to other income & deductions
Constrction
Distnbution rent expense, rents
Total
Amount
19,588
467,605
55,874
543,067
$
$
Account
408.2/409.2
107
589
¡Schedule Page: 262.1 Line No.: 11 Column: i
Varous 0 erations and maintenance accounts.
chedule Page: 262.1 Line No.: 12 Column: i
V arous operations and maintenance accounts.
I$chedule Page: 262.1 Line No.: 13 Column: i
State income tax applicable to other income & deductions - 409.2
I$chedule Page: 262.1 Line No.: 14 Column: i
State income tax applicable to other income & deductions - 409.2
!$chedule Page: 262.1 Line No.: 16 Column: i
Various operations and maintenance accounts.
I$chedule Page: 262.1 Line No.: 17 Column: i
Varous operations and maintenance accounts.
¡Schedule Page: 262.1 Line No.: 22 Column: i
Taxes applicable to other income & deductions
Fuel stock
Constrction
Total
Amount
86,194
1,639,605
858,661
2,584,460
$
$
Account
408.2/409.2
151
107
I$chedule Page: 262.1 Line No.: 23 Column: i
State income tax applicable to other income & deductions - 409.2
I$chedule Page: 262.1 Line No.: 24 Column: i
Fuel stock
Operations and maintenance accounts
Total
Amount
20,308
185,619
205,927
$
$
AccoUnt
151
Varous
I§chedule Page: 262.1 Line No.: 26 Column: i
Clearg account - 184
¡Schedule Page: 262.1 Line No.: 30 Column: i
Amount
91,999
42,288
9,911
144,198
Taxes applicable to other income & deductions
Constrction
Distnbution rent expense, rents
Total
$
$
!$chedule Page: 262,1 Line No.: 31 Column: i
V arous operations and maintenance accounts.
I$chedulePage: 262.1 Line No.: 32 Column: i
I FERC FORM NO.1 (ED. 12-87)Page 450.2
Account
408.2/409.2
107
589
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo,Da, Yr)
PacifiCorp 1(2) .A Resubmission 04/14/2010 2009/04
FOOTNOTE DATA
Fuel stock - 151
~chedule Page: 262.1 Line No.: 34 Column: i
Fuel stock - 151
~chedule Page: 262.1 Line No.: 35 Column: i
Clearg account - 184
~chedule Page: 262.1 Line No.: 40 Column: i
Amount
Taxes applicable to other income & deductions
Constrction
Distrbution rent expense, rents
Total
$934
2,579,537
12,831
2,593,302
Account
408.2/409.2
107
589
$
~chedule Page: 262.2 Line No.: 1 Column: i
V arious operations and maintenance accounts.
~chedule Page: 262.2 Line No.: 3 Column: i
Clearing account - 184
¡Schedule Page: 262.2 Line No.: 7 Column: f
Reclass as a result of an effective settlement of anInternal Revenue Service Exam $
Effective settlement ofInternal Revenue Service ExamTotal adjustments $
Amount Account
1,471,654
390,331
1,861,985
174
131
I FERC FORM NO.1 (ED. 12-87)Page 450.3
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
ACCUMULA ED DEFERRED INVESTMENT TAX REDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and non utilty
operations. Explain by footnote any correction adjustments to the account balance shown in column (g). Include in column (i) the average
period over which the tax credits are amortized.
Line ccount Balance at eginmng
No Subdjvisions of Year. (a). (b)
1 Electric Utilty
23%
34%
47%
510%
610%
7 Idaho
8 TOTAL
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10
11
12
1310%
14
15 Total Nonutilty
16
17
18
1
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
3
40
41
42
43
44
45
46
47
48
38,809,669
8,918,674
777,893
48506236 .
1,322,120 420
1,322,120
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) ¡=A Resubmission 04/14/2010
ACCUMULATED 0 FERRED INVESTMENT TAX CREDI S (Account 255) (continued)
...~ADJUSTMENT EXPLANATION .Lineof Year of AI ocation No.to Incomeh i --t
2
.3
..4
37,000,901 48.37 5
7,294,222 30 6
712,457 30 7
45,007,580 .8
9
10
11
12
881,312 30 .13
14
881,312 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
~ame of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2oo9/Q4
FOOTNOTE DATA
!Schedule Page: 266 Line No.: 5 Column: e
46(t)2
!Schedule Page: 266 Line No.: 6 Column: e
46(t) 1
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
OTHER DEFFERED CREDITS (Account 253)
1.Report below the particulars (details) called for concerning C!ther deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
Line Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
(b)Account(a)(c)(d)(e)(f)
1
2 Working Capital Deposits 2,841,878 568,666 3,410,54
3 .
4 Reclamation Costs - Trapper Mine 4,276,612 222,740 4,499,352
5 .
6 Reclamation Costs - Deseret Mine 534,826 534,826
7 .
8 Reclamation Costs - Trail
9 Mountain Mine 1,126,798 131 35,850 1,090,948
10
11 Deferred Compensation Plans 9,961,369 124 2,002,763 1,832,835 9,791,441
12 .
13 Transmission Service Deposits 3,531,125 131,235 4,793,723 3,155,973 1,893,375
14 .
15 MCI F.O.G. wire lease 558,097 454 3,347,013 3,346,699 557,783
16
17 Redding Contract (20)3,850,072 456 549,99 3,300,076
18
19 Foote Creek Contract (15)842,942 142 137,640 705,302
20
21 Environmental Liabilties 5,691,680 131,182.3 922,008 2,158,623 6,928,295
22
23 Uneamed Joint Use Pole Contact 3,521,617 454 8,425,899 8,246,779 3,342,497
24
25 Oregon DSM Loans NPV Unearned 716,516 456 255,974 460,542
26
27 Other Deferred Creits - C& T 833,757 555 833,757
28
29 Deferred Revenue -
30 Duke/Hermison Gas Settement (5)1,918,549 547,555 754,839 1,163,710
31
32 Transmission Security Deposits 1,300,000 250,000 1,550,000
33
34 Other deferred credits with
35 balances less than $500,000 1,256,184 various 327,395 928,789
36
37 .
38 .
39
40
41
42 .
43 .
44 .
45
46
47 TOTAL 42,762,022 22,386,857 19,782,315 40,157,480
FERC FORM NO.1 (ED. 12-94)Page 269
Name of Respondent
PacifiCorp
Year/Period of Report
End òf 2009/Q4
This ~ortls: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
ACCUMULATE DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to propert not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line
No.
Account Balance at
Beginning of Year Amounts Debited
to Accunt 410.1
(c)
Amounts Credited
to Accunt 411.1
(d)(a)(b)
1 Account 282
2 Electric
3 Gas
4 FAS 109 Regulatory Asset.
5 TOTAL (Enter Total of lines 2 thru 4)
6 Nonutiity
7
8
9 TOTAL Accunt 282 (Enter Total of lines 5 thru 8)
10 Classification of TOTAL
11 Federal Income Tax
12 State Income Tax
13 Locallncomè Tax
./ ~/í / "tt.i lf7 "'. Wií.¡¡.. 00% 'l70k š %£Ztø / "/ '" / 0 Ii 77 ° '%lff0 07..07..š7~r7;.i% .17 Yr.7 iB~1f%ø :W~7 . 7 ~1f70" .i
1,654,239,715 1,039,771,299 314,322,980
439,741,785
2,093,981,500
1,743,433
1,039,771,299 314,322,980
2,095,724,933 1,039,771,299 314,322,980
0.;:,;::p" ;;fé /0 % *"a .¡:%Mr%~£~1 .. :: .x.rr;r0 y;g.;;. 7/ 7 '11.::%1
~."k zkj;Jg" 1I.~1I~0"/ / '0..' f¿;.~.Ij/ 0 ~.&
1,845,017,675
250,707,258
915,385,599
124,385,700
276,721,169
37,601,811
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
E TAXES - OTHER PROPERTY (Accunt 282) (Continued)
Year/Period of Report
End of 2009/Q4
ACCUMULATED DEFERRED INCa
3. Use footnotes as required.
CHANGES DURING YEAR
Amouts Debited Amounts Credited
to Account 410.2 to Accunt 411.2
ADJUSTMENTS
Amount
Balance at
End of Year
Line
Ncí.
Debits
#';~. i;¡Jl......I..z ~..%iØ/ / ~ 7 w/ % ~.%I~. _~ i",.;;',.Jl / 0 0 #di*?i ~;i% /% /0d0f1.øZ// / '/ t0~
9,55
1,29
776,98
105,58
22,964,57
3,120,50
7,429,211
1,009,50
1
2
3
4
5
6
7
8
9
o
2,467,379,311 11
335,275,86 12
13
8,438,71
8,438,71
NOTES (Continued)
.'
FERC FORM NO.1 (ED. 12-96)Page 275
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
Year/Period of Report
End of 2009/Q4
Name of Respondent
PacifiCorp
Line
No.
Accunt
(a)
Balance at
Beginning of Year
(b)
1 Account 283
2 Electric
3 Regulatory Assets
4
5
440,004,173 48,668,071 54,261,407
6 Other Deferred Liabilties
7
8
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
11
12
13
14
15
16
50,755,602 70,039,834 70,287,258
490,759,775 118,707,905 124,548,665W!~:.~.:ø, ~:::Ä"./;A
H TOTAL Gas (Total of lines 11 thru 16)
18
19 TOTAL (Acct 283) (Enter Total of lines 9; Hand 18)
20 ClassifICtion of TOTAL
21 Federal Income Tax
22 State Income Tax
23 Local Income Tax
490,759,775 118,707,905 124,548,665t~0w;'Y"~.~:.;7:;t~ßø.
432,050,152
58,709,623
104,507,123
14,200,782
109,649,165
14,899,500
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Accunt 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.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.2 to Accunt 411.2
ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.
477,531 190, 282 35,310,385 34,637,390
44,915,501 73,795,764 52,057,363 46,918,077 450,899,466
~a";jf..;~lI~.;J¡Ø0øÆ.1íßi;W / / / fiiff ll..~~~.:~
44,915,501 73,795,764 52,057,363 46,918,077
11
12
13
14
15
16
17
18
450,899,466 19
o
396,958,249 21
53,941,217 22
23
1/ ii/.Wf! ..!& "'. /0% _.;.j4/...////.~//_. ~ / /0r:;I;:// ~..
39,542,352
5,373,149
64,967,729
8,828,035
45,829,848
6,227,515
41,305,364
5,612,713
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 277
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 )~An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/04
FOOTNOTE DATA
¡Schedule Page: 276 Line No.: 6 Column: i
Accounts
190 Accunlulated Deferred Income Taxes
282 Accum. Deferred Income Taxes-Other Propert
219 Accumulated Other Comprehensìve Income
236 Taxes Accrued
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) n Original (Mo, Da, Yr)End of 2009/Q4
(2) Ei Resubmission 04/14/2010
OTHER REGULATORY LIABILITIES (Accunt 254)
1. Report below the particulars (details) called for conce.ming other regulator 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 $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilties being amortized, show period of åmortization.
.Balance at Beginin Balance at EndDEBITSLineDescription and Purpose of of Current of Current
No.Other Regulatory Liabilties QuarterlY ear ~ccnt AInt Credits QuarterlY earCredited
(a)(b)(c)(d)(e)(f)
1 Incoe Tax Regulatory Liabilit 21.373,276 190 1,013,954 20,359,322
2 Income Tax Reg. Uab. -WA Flow through 9.793.58 190 8,916,956 876,629
3 OR Gain on Sales of Asets (1)1,416.86 142 1,246,456 288,758 459,170
4 Propert Insurance Reserve 109,560 109,564
5 SMUD Revenue Imputation (11)25,669,853 440,42 5.94,105 337,29!20,063,046
6 SMUD Revenue Imputati UT 2,850,OOC 2,850,000
7 Oregon Rate Refund 79,96 79,964
8 WA Rate Refund 228,65 228,659
9 Utah Home Energy Lifeline 40,026 142 2.665,935 2,679,765 413,856
10 BPA Washington Balancing Acunt 903,021 903,021
11 BPA Oregon Balancing Accunt 98,54 1,430,55 2,419,092
12 AROI Reg Difference - Deer Creek Mine Reclamation 621,20 230 156,465 335,798 800,538
13 ARO/Reg Difference - Trojn Nuclear Plant 3,373,34 230 102.707 338,31¿3,608,948
14 CA West Valley Lease Red (3)28,291 142 29,510 1,219
15 ID West Valley Lease Red (3)..437,852 44,42,142 437,852
16 WY West Valey Lease Red. (3)1,365,919 44,42,142 1,36,919
17 A&G Credit - CA (3)45,316 142 47,2 1,952
18 A&G Credit ID (3)451,245 44,42,142 451.245
19 A&G Credit WY (3)1,476,750 44,442,142 1,52.805 49,055
20 Washington Low Income Program (24,581)142 1,157.99 1,147,391 -35,188
21 OR Consolatin 11,853 13.818 131,471
22 Bl Sky- OR 281,314 232 1,172.921 1,269,850 378,243
23 BlueSky-WA 86,82 232 20,859 157,322 40,285
24 BlueSky-CA 47,63 232 50,817 70,580 67,399
25 Bl Sky- UT 921,774 232 2,751,129 2,56,250 734,895
26 Blue Sky-IO 50,500 232 80,807 58,930 28,623
27 BlueSky-WY 101,066 232 223,005 198,068 76,129
28 OR Energy Conservation Charge 775,874 232 8,579,678 8,626,00 822,596
29 CA Gai on Sale of Asets 45,03 .45.034
30 UT Gain on Sale of Assets 1.019.35 421.1 1.019,355
31 ID Gain on Sale of Assets 156,43 182.3 156,43
32 WY Gain on Sale of Assets 3588 421.1 3588
33 Deferr Ar Coal Settlement (3)3,05,86 557 1,83,574 1,217,286
34 Reg Liabilit - Reclassifications 1.9491 5,536,681
35
36
37
38
39
40
.
41 TOTAL 76,456,654 41,489,64 29,197,243 64,164,255.
FERC FORM NO. 1/3-Q (REV 02.04)Page 278
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
'§chedule Page: 278 Line No.: 34 Column: f
The following sumarzes regulatory liabilities reclassifications:
Reclassified from Regulatory Assets to Regulatory Liabilities:
California DSM Regulatory Asset
Wyoming DSM Regulatory Asset
Sch 781 Direct Access Shopping Incentive
Deferred Excess Net Power Costs/ECAC- CA
Defered Intervenor Funding Grants - OR
Deferred Independent Evaluator Fee - UT
SB 408 Regulatory Asset - MCBIT
Year Ended
December 31, 2009
$2,099,141
2,468,965
68,360
2,604,371
175,032
12,573
22,043
Reclassified from Regulatory Liabilities to Regulatory Assets:
Washington Low Income Program
$
35,188
7,485,673
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
ELECTRIC OPERATING REVENUES ( ccunt 400)
1. The following instructions generally apply to the annual version of these pages. Do not report quarterly dat in columns (c), (e), (t), and (g). Unbilled revenues and MWH
relatedto un biled revenues need not be reported separately as reuired in the annual version ofthese pages.
2. Report below operating revenues for each prescrbed accunt, and manufactured gas revenues in total.
3. Report number of customers, columns (t) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that Where separate meter readings are
added for billng purposes, one customer should be conted for each group of meters adde. The -average number of customers means the average of twelve figures at the
close of each month.
4. If increases or decreases from previous period (columns (c),(e), and (g)), are notderived from previously reported figures, explai any inconsistencies in a footnote.
5. Disclose amounts of $250,000 or greater in a footnote for accunts 451,456, and 457.2.
Line
No.
Title of Accunt
Sales of Electricity
2 (440) Residential Sales
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)
5 Large (or Ind.) (See Instr. 4)
6 (444) Public Street and Highway Lighting
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
1 0 TOTAL Sales to Ultimate Consumers
11 (447) Sales for Resale
12 TOTAL Sales of Electricity
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provo for Refunds
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues
18 (453) Sales of Water and Water Power
19 (454) Rent from Eletric Propert
20 (455) Interdepartmental Rents
21 (456) Oter Electrc Revenues
22 (456.1) Revenues from Transmission of Electricity of Other
23 (457.1) Regonal Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues
27 TOTAL Electric Operating Revenues
Operating Revenues Year
to Dale Ouartei1y/Annual
(b)
Operating Revenues
Previous year (no Quartei1y)
(c)(a)
1,120,956,943
976,991,304
20,91;3,398
19,032,148
1,062,312,561
998,397,465
19,865,594
18,443,905
3,484,413,566
643,321,157
4,127,734,723
3,444,033,188
860,950,758
4,304,983,946
4,127,734,723 4,304,983,946
7,486,736
7,079,770
26,06
20,579,425
63,697,983
18,876,459
75,553,244
226,031,657 189,602,040
4,494,585,986
FERC FORM NO. 1/3-Q (REV. 12-05)Page 300
Name of Respondent
PacifiCorp
This ~ort Is:
(1) ~An Original
(2) A Resubmission
ELECTRIC OPERATING REVENUES (
Date of Report
(Mo, Da, Yr)
04/14/2010
ccount 400)
Year/Period of Report
End of 2009/Q4
6. Commercial and industrial Sales, Accunt 442, may be classified accrding to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by
the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Accunt 442 of the Uniform System of Accounts. Explain basis of
classification in a footnote.)
7. See pages 108-109, Important Chiinges During Period, for important new territory added and importnt rate increase or decreases.
8. For Lines 2.4,5,and 6,see Page 304 for amounts relating to unbiled revenue by accounts.
9. Include unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD
Yeiir to Date Quartrly/Annual Amount Previous year (no Quarte~y)(d) (e)
AVG.NO. CUSTOMERS PER MONTH Line
Current Year (no Quarterly) Previous Year (no Quarterly) No.(ry (g)
16,194,257 16,055,182 213,730 210,217 4
19,934,268 21,494,710 34,070 34,172 5
144,765 141,122 3,948 4,080 6
437,595 449,314 13 13 7
8
9
52,709,525 54,361,783 1,718,485 1,706,127
12,349,061 12,344,976
65,058,586 66,706,759 1,718,485 1,706,127 12
13
65,058,586 66,706,759 1,718,485 1,706,127 14
Line 12, cölumn (b) includes $
Line 12, column (d) includes
213,989,000 of unbiléd revenues.
3,380,278 MWH relatingto unbiled revenues
FERC FORM NO. 1/3-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 I (2) A Resubmission 04/14/2010 2009/Q4
. FOOTNOTE DATA
¡Schedule Page: 300 Line No.: 11 Column: f
For a complete list of the number of customers see pages 310-311 Sales for Resale of this Form No. 1.
I$chedule Page: 300 Line No.: 11 Column: g
For a complete list of the number of customers see ages 310-311 Sales for Resale of this Form No. 1.chedule Page: 300 Line No.: 17 Column: b
(451) Miscellaneous Service Revenues include the following items that are $250,000 or grater:
Account service charge - disconnects/reconnects
Customer contract flat rate billngs
$ 4,609,636
2,188,111
I$chedule Page: 300 Line No.: 21 Column: b
(456) Other Electrc Revenues include the following items tht are $250,000 or greater:
Renewable energy credit sales
Demand-side management revenue
Energy exchange credits
Ancilar serices
Steam sales
F1yashly-product sales
Phase shifting equipment fee from WECC
Power sale and exchange agreements
Revenue from generation interonnection and trsmission service request studies
Maintenance charges for work on transmission facilties
Net profit on sales ofmatenals and supplies inventory
$50,793,765
50,259,795
8,415,849
7,216,814
4,857,715
3,238,868
1,271,449
1,091,292
840,474
423,133
361,448
I$chedule Page: 300 Line No.: 27 Column: b
Sales of Electricity
Residential Sales - Account (440)
Commercial and Industral Sales - Account (442)
Small (Commercial)
Large (Industral)
Public Street and Highway Lighting - Account (444)
Other Sales to Public Authonties - Account (445)
Sales to Railroads and Railways - Account (446)
Interdeparental Sales - Account (448)
Page 300 Page 304 Vanance
Year ended Year ended Year ended
December 31,December 31,December 31,
2009 2009 2009
$1,346,519,773 $1,346,519,773 $
1,120,956,943 1,120,956,943
976,991,304 976,991,304 -(a)
20,913,398 20,913,398
19,032,148 19,032,148
Total Sales to Ultimate Consumers 3,484,413,566 3,484,413,566
Sales for Resale - Account (447)643,321,157 643,321,157 (b)
Total Sales of Electrcity 4,127,734,723 3,484,413,566 643,321,157
(Less) Provision for Rate Refuds - Account (449.1 )
Total Revenues Net of Provisions for Refuds 4,127,734,723 3,484,413,566 643,321,157
Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacjfiCorp Ih) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA .
Forfeited Discounts - Account (450)
Miscellaneous Service Revenues - Account (451)
Sales of Water and Water Power - Account (453)
Rent from Electrc Proper - Account (454)
Interdeparental Rents - Account (455)
Other Electrc Revenues - Account (456)
Revenues from Transmission of Electrcity of Others (456.1)
7,318,368
6,908,893
12,154
19,158,931
7,318,368
6,908,893
12,154
19,158,931
128,935,328
63,697,983
124,707,208 4,228,120 (c)
63,697,983 (b)
Total Operating Revenues $ 3,642,519,120 $ 711,247,260$ 4,353,766,380
(a) The large industral line on page 300 includes account 442.2 Industral Sales of $891,577,996 and account442.3 Irrgation
Sales of $85,413,308.
(b) Sales for Resale and Revenues from Transmission of Electrcity of Others are not included on page 304 Sales of Electrcity by
Rate Schedules as the revenues are included in pages 310-311 Sales for Resale and pages 328-330 Transmission of Electrcity for
Others, respectively, in this Form No. 1.
(c) The variance in Other Electrc Revenues-Account (456) is as follows:
Page 300 Page 304 Variance
Steam Sales $4,857,715 $$4,857,715
Materials and Supplies Inventory Net Profit (629,595)(629,595)
Other Electrc Revenues - Account (456)124,707,208 124,707,208
TOTAL Other Electrc Revenues - Account (456)$128,935,328 $124,707,208 $4,228,120
I$chedule Page: 300 Line No.: 1 Column: $
The following is a reconciliation of the unbiled revenue accrual at December 31, 2009 and the reversal of the December 31, 2008
unbiled revenue accral.
Curent year unbiled revenue accrual
Prior year unbiled revenue accrual reversal
Change in unbiled revenue accrual
December 31, 2009
$ 213,989,000
(210,896,000)
$ . 3,093,000
I$chedule Page: 300 Line No.: 1 Column: MWH
The following is a reconciliation of the unbiled MWh accrual at December 31, 2009 and the reversal of the December 31, 2008
unbiled MW accral.
Curent year unbiled MWh accrual
Prior year unbiled MW accrual reversal
Ctiange in MWh accrul
December 31, 2009
3,380,278
(3,440,267)
(59,989)
\FERC FORM NO.1 (ED. 12-S7) Page 450.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
.SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate sèhedule in effect during the year the MWH of electicity 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 seuence 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 entres in column (d) for the specil schedule should denote the duplication in number of reported
customers.
4. The average humber of customers should be the number of bils rendered during the year divided by the number of biling 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 biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
lOne Numoer ana ime or Kate scneauie Mwn~oia Kevenue.Average Numoer ~vvn_oT ~aies K~~~'S~1der
No.(a)(b)(c)ofC~~omers Per l~stomer
(f)
1 RESIDENTIAL SALES - .
2 CALIFORNIA
3 06CHCKOOOR-CA RES CHECK M 1
4 06LNX00102-L1NE EXT 80% G 78
5 06LNX00109-REFINREF ADV+76
6 06NETMT135 - CA RES NET 177 20,610 17 10,412 0.1164
7 060AL T015R-QUTD AR LGT SR 349 75,055 381 916 0.2151
8 06RESDOOOD-RES SRVC 204,930 23,437,545 19,282 10,628 0.1144
9 06RESDDL06-CA LOW INCOME 102,250 11,616,537 8,847 11,558 0.1136
10 06RESDDM9M-MUL TI FAMILY 268 29,660 f 33,500 0.1107
11 06RESDDS8M-MUL T FAM SBMET 1,348 125,920 1~103,692 .0.0934
12 ACQUISITION COMMITMENT-A and 24,929
13 ACQUISTION COMMITMENT-WEST 15,564
14 REVENUE ADJUSTMENT --1,415,755
15 SMUD REVENUE IMPUTATIONS 55,652
16 06RESDOODN - CA RES SRVC -99,451 11,274,738 7,680 12,945 0.1134
17 UNBILLED REV - UNCOLLECTIBLE -4,00
18 UNBILLED REVENUE -2,174 -42,OO 0.0193
19 IDAHO
20 07LNX00010-MNTHl Y 80%GUAR 980
21 07LNXOO035-ADV 8O%MO GUAR 2,955
22 07NETMT135 -10 RESIDENTIAL 706 52.570 37 19,081 0.0745
2~070ALC0007 -CUST OWN LIGHT 1(3,697 .1 10,00C 0.3697
24 070ALT07AR-SECURITY AR LG 111 43,941 14C 79~0.3959
25 07RESDOO01-RES SRVC 411,01;¿36,891,331 40,583 10,128 0.0898
26 07RESD0001-RES SRVC 1,187
27 07RESDOO36-RES SRVC-OPTIO 309,965 22,414,057 .16,132 19,214 0.0723
28 07RESD0036-RES SRVC-OPTI -1,078
29 BPA BALANCING ACCOUNT -196,535
30 UNBILLED REV - UNCOLLECTIBLE -14,00
31 ACQUISITION COMMITMENT-A and 110,93f
32 ACQUISITION 107,64~
33 SMUD REVENUE IMPUTATIONS 108,347
34 UNBILLED REVENUE -5,455 -279,OOC ...0.0511
35 OREGON
36 01CHCKOOOR-RES CHECK MTR 1
37 01COST0004 - 01RESDOO04 5,451,610 243,004,7H 0.046
38 01 HABIT004 - 01 RESDOO04 45,84e 1,991,222 0.0434
39 01 LNXOO1 02-L1NE EXT 80% G 17,725
40 01LNX00105-CNTRCT $ MIN G 12
~-
.
41 TOTAL Biled 1,718,48!30,70 0.060042Total Un biled Rev.(See Instr. 6)~((~0.O51€
43 TOTAL 52,709,52 3,642,519,120 .~~ 1, 718,8!30,67 0.0691
FERCFORM 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 2009/Q4
(2) OA Resubmission 04/14/2010
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year theMWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300~301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residentiaL.
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils 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 biled pursuant thereto.
6. 'Report amount of unbiled revenue as of end of year for each applicable revenue account subheading.
ine Numoer ana ime or Kate scneaUie Mvvn ::oia Kevenue Average Numoer ~vvn_oT ::aies K~~h'~~lder
No.(a)(b)(c)
of Cu(~~omers Per 9~stomer
(f)
1 01LNX00109-REF/NREF ADV +5,875
2 01NETMT135-NET METERING 286,682 621
3 01 NETMT135-NET METERING -25,585
4 010AL T014R-OUTD AR LGTRE 2,627 381,472 2,937 894 0.1452
5 010AL T014R-DUTD AR LGT RE -10,526 ..
6 01 PTOU0004 - 01 RESDOO04 21,868 977,608 0.0447
7 01RENEW004 - 01RESDOO04 198,375 8,519,890 0.0429
8 01 RESD0004-RES SRVC 244,164,792 470,808
9 01 RESD0004-RES SRVC -21,975,532
10 01 RESD004T - RES Time Option 925,082 1,396
11 01 RESD004T - RES Time Option -8,473
12 01UPPLOOOR-BASE SCH FALL 4
13 BPA BALANCING ACCOUNT -1,352,633
14 OR GAIN ON SALE OF ASSET 484,373
15 OR SB408 RECOVERY -4,732,592
16 OR SB838 RECOVERY -3,431,715
17 SMUD REVENUE IMPUTATIONS 735,070
18 UNBILLED REV - UNCOLLECTIBLE -45,000
19 UNBILLED REVENUE -68,449 -4,032,000 0.0589
20 UTAH .
21 08BLSKY01R-BLUESKY ENERGY -1
22 08CFR00001-MTH FACILITY S 1,409
23 08CHCKOOOR-UT RES CHECK M 1
24 08COOLKPRR - Utah Cool Keeper 80,033
25 08LNXOOOO1-MTHLY 80% GUAR 3,028 .
26 08LNX00005- MNTHL Y MIN GUAR 132
27 08LNXOO13-80% MTHLY MIN 29,226
28 08LNX00016 - 80% annual 368 .
29 08LNX00108-ANN COST MTHL Y 3,589
30 08MHTPOO25-MOBILE HOME &12,083 849,834 11 1,098,455 0.0703
31 08NETMT135 - Net Metering 3,067 261,179 406 7,554 0.0852
32 080AL T007R-SECURITY AR LG 2,881 801,864 3,180 906 0.2783
33 08PTLDOOOR-POST TOP LIGHT 115 8,654 33 .3,485 0.0753
34 08RESDOOO1-RES SRVC 6,275,021 536,785,256 670,678 9,356 0.0855
35 08RESD0002-RES SRVC-OPTIO 2,877 242,642 339 8,487 0.0843
36 OBRESD0003-L1FELINE PRGRM 210,57S 17,758,808 .26,634 7,906 0.0843
37 08UPPLOOOR-BASE SCH FALL 4
38 SMUD REVENUE IMPUTATIONS -128,533
39 UNBILLED REV - UNCOLLECTIBLE .-62,000
40 UNBILLED REVENUE -10,935 -358,000 0.0327
--
41 TOTAL Biled 1,718,485 30,70 0.0690
42 Total Unbiled Rev.(See Instr. 6)~C (-0.051€
43 TOTAL 52,709,52 3,642,519,120 1,718,485 30,67 0.0691
FERC FORM NO. 1 (ED. 12-95)Page 304.1
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
SALES OF ELECTRICITY BY RATE SCHEDULES ..
1. Report below for eacll 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 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 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 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 biled pursuant thereto.
6. Repor amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
I Line Numoer ana Iitie Of Kate scneauie Mvvn ;:010 Kevenue Average Numoer isvvn_ Of ;:aies K~~~'S~/der
No.(a)(b)(c)of c~~)omers Per l(à)stomer
(f)
1 WASHINGTON
" 02LNX00109-REF/NREF ADV +203
3 02NETMT135 - WA RES NET 17E 12,189 9 19,556 0.0693
4 02NETMT135 - WA RES NET -556
5 020ALTB15R-WA OUTO AR LGT 1,107 148,783 1,192 929 0.134
6 020ALTB15R-WA OUTD AR LGT -3,218
7 02RESD0016-WA RES SRVC 1,627,647 117,731,011 99,334 16,386 0.0723
8 02RESD0016-WA RES SRVC -4,816,545
9 02RESD0017-BILL ASSISTANC 71,240 5,155,472 4,101 17,371 0.0724
10 02RESD0017-BILL ASSISTANCE -212,576
11 02RESD0018-WA 3 PHASE RES 2,668 210,785 95 28,084 0.0790
12 02RESD0018-WA 3 PHASE RES -7,821
13 02RESD018X-WA 3 PHASE RES 583 45,322 23 25,348 0.0777
14 02RESD018X-WA 3 PHASE RES -1,694
15 02RFNDCENT - CENTRALIA RFND -3
16 02ZZMERGCR-MERGER CREDITS 1
17 ACQUISITION COMMITMENT-A and 275
1EBPA BALANCING ACCOUNT -1,905,297
19 SMUD REVENUE IMPUTATIONS 196,762
2c WASHINGTON - CHEHALIS 7,920,0()
21 UNBILLED REV - UNCOLLECTIBLE -15,000
22 UN BILLED REVENUE -28,567 -1,556,000 0.0545
23 WYOMING
24 05LNX00109-REFINREF ADV +1,973
25 05NETMT135 - EXPERIMENTAL 634 51,176 44 14,409 0.0807
26 050AL T015R-oUTD AR LGT SR 95~146,586 1,116 853 0.1540
27 05RESO002-WY OPTIONAL -24
28 05RESD0002-WY RES SRVC 928,95:1 76,856,694 95,900 9,687 0.0827
29 05RESD018X-RES 3 PHASE SR 1C 857 1 10,000 0.0857
30 ACQUISITION COMMITMENT-A and 179,869
31 ACQUISITION 161,021
32 SMUO REVENUE IMPUTATIONS 90,916 .
3~UNBILLEO REV - UNCOLLECTIBLE -12,000
34 UNBILLED REVENUE -13,8H -1,028,000 0.0744
35 05RESD0002-WY RES SRVC 136,508 11,194,392 12,588 10,844 0.0820
36 OSUPPLOOOR-BASE SCH FALL 1
37 090AL T207R-SECURITY AR LG 82 23,350 97 845 0.2848
38 05NETMT135 - EXPERIMENTAL 221 16,915 8 27,625 0.0765
35 09RESOO2 2
40 09RESDOO02 -E -787 4 -1,50C 0.1312
..
1-41 TOTAL Biled 1,718,8!30,70 0.069(
42 Total Unbiled Rev.(See Instr. 6)~I (-0.051
43 TOTAL 52,709,52 3,642,519,120 1,718,48f 30,67~0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.2
Name. of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) . An Original (Mo, Da, Yr)End of 2009/Q4
(2) fiA Resubmission 04/14/2010
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 à 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 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 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 divided by the number of billng periods during the year (12 if
all billngs are made montnly).
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.
Line l'Iumoer ana. IllIe or Kate scneauie Mwn::oia Kevenue l\veragi\~umoer ~vvn_or ::aies KiW~'S~lder
No.(a)(b)(c)of Cu(~ omers Per l(à)stomer
(f)
1 UNBILLED REVENUE -262 6,000 .-0.0229
2 LESS MULTIPLE BILLINGS -97,999
3
4 TOTAL RESIDENTIAL SALES 15,998,640 1,346,519,773 1,466,724 10,908 0.0842
5
6 COMMERCIAL SALES
7 CALIFORNIA
8 06CHCKOOON-CA NRES CHECK 1
9 06GNSV0025-CA GEN SRVC 61,986 8,469,437 6,893 8,993 0.1366
10 06GNSV025F-GEN SRVC-o: 20 907 139,139 92 9,859 0.1534
11 06GNSVOA32-GEN SRVC-20 KW 79,584 9,002,037 923 86,223 0.1131
12 06LGSV048T-LRG GEN SERV 69,161 5,071,910 11 6,287,364 0.0733
13 06LGSVOA36-LRG GEN SRVC-Q 84,475 7,963,331 190 444,605 0.0943
14 06LNX00102-L1NE EXT 80% G 12,260
15 06LNX00103-LINE EXT 80% G 298
16 06LNX00105-CNTRCT $ MIN G 4,596
17 06LNX00109-REF/NREF ADV +80,322
18 06LNX00300 - 80% MONTHLY MIN 9,237
19 06LNX00311 - LINE EXT 80%2,870
20 06NMT36135-CA GEN SVC NET 34 3,559 1 34,000 0.1047
21 060AL T015N-QUTD AR LGT SR 742 160,944 539 1,377 0.2169
22 06RCFL0042-AIRWAY &ATHLE 223 36,039 38 5,868 0.1616
23 06WHSV0031-COMM WTR HEATI 194 22,807 28 6,929 0.1176
24 06NMT25135-CA GEN SVC NET ...1
25 06NMT32135-CA GENSVC NET 117 13,636 2 58,500 0.1165
26 ACQUISITION COMMITMENT-A and 18,404
27 ACQUISITION 11,490
28 REVENUE ADJUSTMENT --1,029,682
29 SMUD REVENUE IMPUTATIONS 41,085
30 06LNX00110-REF/NREF ADV +6,630 .
31 UNBILLED REVENUE 2,802 401,000 0.1431
32 IDAHO
33 07CISH0019-GOMM &IND SPA 7,506 504,657 131 57,298 0.0672
34 07GNSVOO06-GEN SRVC-LRG P 192,961 12,513,109 943 204,625 0.0648
35 07GNSV0009-GEN SRVC-HI VO 39,816 1,787,561 1 39,816,000 0.0449
36 07GNSV0023-GEN SRVC-SML P 122,135 9,759,831 .6,163 19,817 0.0799
37 07GNSV0035-GEN SRVCOPTION 515 26,310 2 257,500 0.0511
38 07GNSV006A-GEN SRVC-LRG P 28,892 1,998,210 214 135,009 0.0692
39 07GNSV023A-GEN SRVC-SML P 16,059 1,323,081 1,155 13,904 0.0824
40 07GNSV023F-GEN SRVC SML P 18 2,634 7 2,571 0.1463
41 TOTAL Bm" ~1,718,48t 30,70 0.0690
42 TotalUnbiled Rev.(See Instr. 6) -59,98 (L -0.0516
43 TOTAL I 52,709,52 3,642,519,120 1,718,48!30,67.0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.3
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
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 "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 entres in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendered during the year divided by the number of billng periods during the year (12 if
all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a fotnote the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year fo each applicable revenue accunt subheading.
TIne Numoer ana Iitie or Kate scneauie Mwn::oia Kevenue Averagi~NUmOer iewaor::aies K~n'Seyer
No.ofC~~omers Per C(à)stomer hold(a)(b)(c)(f)
1 07LNX00010-MNTHL Y 80%GUAR 10,991l
2 07LNX00035-ADV 8O%MO GUAR 327,533
3 07LNXOOO4D-ADV+REFCHG+80%70,822
4 070AL T007N-SECURITY AR LG 24S 90,876 18€1,333 0.3664
5 070AL T07 AN-SECURITY AR LG 1~4,713 14 857 0.3928
6 07LNX00312 -ID LINE EX 3,911
7 07NMT23135 - ID NET MTR-4E 3,870 2 24,50C 0.0790
8 07LNX00015-ANNUAL 80%GUAR 3,44C
9 07LNX00311 - LINE EXT 80%38,490
10 07LNX00020 - ID MONTHLY 722
1 07LNX00300-80% MONTHLY MIN 2,762
12 ACQUISITION COMMITMENT-A and 64,495
13 ACQUISITION 62,581
14 BPA BALANCING ACCOUNT 40,396
15 SMUD REVENUE IMPUTATIONS 60,241
16 UNBILLED REVENUE 26,785 1,733,00C 0.0647
17 OREGON .
18 01COST0023, OR GEN SRV, COST 982,08~44,445,674 0.0453
19 01 COSTOO48 - 01 LGSV0048 765,9E~31,516,399 0.0411
20 01COST023F - OR GEN SRV-3,30C 158,204 0.0479
21 01COSTB023 - OR GEN SRV,69,287 4,178,237 0.0468
22 01COSTL030 - OR LRG GEN SRV,1,080,31.46,647,204 0.0432
23 01COSTS028, OR GEN SERV,1,938,3&86,139,94~0.0444
24 01COSTS030 - OR GEN SRV CBS;:1,19~42,031 0.0352
25 01GNSB0023 - BPA DISC, '" 30 kW -346,826 .
26 01GNSB0023, OR GEN SRV, BPA, '"4,959,174 14,375
27 01GNSBOO28 - OR GEN SRVC,-520,063
28 01GNSB0028, OR GEN SRV, BPA, ;:2,767,720 568 .
29 01 GNSB023T - OR GEN SRV - TOU 27,446 53 .
30 01GNSB023T - OR GEN SRVC,-2,601
31 01GNSV0023, OR GEN SRV, '" 30 36,056,~55,970
32 01GNSV0028, OR GEN SRV ;: 30 39,545,37~9,024
33 01 GNSV023F - OR GEN SRV - FLA 1 10,ja.1,335,86;,830 12,993 0.1239
34 01GNSV023M - OR GEN SRV,.H 1,622 1 19,000 0.0854
35 01GNSV023T, OR GEN SRV, TOU 152,595 237
36 01HABT0023, OR HABITAT 2,32i 106,6H 0.0458
37 01HABTB023 - OR HABITAT 191 9,053 0.0474
38 01LGSB0030, GEN DEL SRV,;: 200 -216,836
39 01 LGSBOO30, GEN DEL SRV, ;:200 793,713 30
40 01 LGSV0030 - OR LRG GEN SRV, ;:16,556,310 662
41 TOTAL Biled 1,718,481 30,70 0.069C42Total Unbiled Rev.(See Instr. 6)~((-0.051€43 TOTAL 52,709,52 3,642,519,120 1,718,45i 30,67~0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.4
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) AnOriginal (Mo, Da, Yr)End of 2009/04
(2) EiA Resubmission 04/14/2010
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 "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 acunt 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 ìm 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 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 biled pursuant thereto.
. 6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
I Line I'lumoer ana I lUe or M:aie scneaUie IVlvvn ;:010 Revenue Average Numoer ¡swaor ::aies ~~~is~lder
No.(a)(b)(c)of c~~)omers Per l~stomer
(f)
.1 01 LGSV0048-1OOOKW AND OVR 7,745,775 96
2 01 LGSV048M-LRG GEN SRVC 1 53,302 2,435,620 1 53,302,000 0.0457
3 01LNX00100-L1NE EXT 60% G 5,221
4 01LNX00102-L1NE EXT 80% G ..515,358
5 01LNX00103-L1NE EXT 80% G 3,276
6 01LNX00105-GNTRCT $ MIN G 16,195
7 01LNX00109-REF/NREF ADV +1,927,031
8 01LNX00110-REF/NREF ADV +9,183
9 01 LNX00300 - LINE EXT 80%124,552
10 01LNX00311 - LINE EXT 80% G 81,021
11 01 LPRS047M-PART REO SRVC 3,956 401,630 3 1,318,667 0.1015
12 01NMT23135 - OR NET MTR, GEN,39,974 63
13 01 OAL T014N-QUTD AR LGT NR 1,630 245,116 1,175 1,387 0.1504
14 010ALT014N-OUTD AR LGT NR -6,306
15 010AL T015N-OUTD AR LGT NR 6,148 791,688 3,110 1,977 0.1288
16 01 PTOU0023, OR GEN SRV, TOU 3,842 171,176 0.0446
17 01PTOUB023, OR GEN SRV, TOU 695 30,234 0.0435
18 01 RCFL0054-REC FIELD LGT 1,029 91,700 102 10,088 0.0891
19 01 RENW0023, OR RENW USAGE 9,058 416,939 0.0460
20 01 RENWB023 - OR RENEWABLE 547 26,045 0.0476
21 01STDAY023 - OR DAY STD OFR,1,919 74,580 0.0389
22 01STDAY028- OR DAY STD OFF,7,040 270,547 0.0384
23 01STDAY030 - OR STD DAY OFF,4,520 172,938 0.0383
24 01UPPLOOON-BASE SCH FPACI 70
25 BPA BALANCING ACCOUNT 0 -68,282
26 01LGSB0048 - LG GEN SVC :;-13,518
27 01 LGSB0048 - LG GEN SVC :;48,289 1
28 01NMT28135 - OR NET MTR, GEN,121,901 26 .0
2~01 NMT30135 - OR NET MTR, GEN,..96,640 4
30 01LGSV028M - OR LGSV, .:1000 602 41,313 1 602,000 0.0686
31 01GNSV030M - OR GEN SRV, 200 1,600 92,647 1 1,600,000 0'0.0579
32 01GNSV0728 - OR GEN SVC DIR 68,880 6
33 01 GNSV0730 -OR GEN SVC DIR 823,608 32
34 01GNSV0748 LG GEN SVC DIR .2,600 2
35 OR GAIN ON SALE OF ASSET 435,013
36 OR SB408RECOVERY 4,144,707
37 OR SB 838 RECOVERY -2,795,590
38 SMUD REVENUE IMPUTATIONS 641,871
39 UNBILLED REVENUE 39,405 3,634,000 0.0922
40 UTAH
1-41 TOTAL Biled 1 ,718,48~30,70 0.069C
42 Total Unbiled Rev.(See Instr. 6)-59.fI C (-0.051€
43 TOTAL 52,.709,52 3,642,519,120 1,718,48~30,67 0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.5
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010 ..
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect dunng 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 prescnbed operating revenue accunt in the sequence followed in"Electnc Operating Revenues," Page
300-301. If the sales under any rate schule are classified in more than one revenue accunt, 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 classificatin (such as a general residential
schedule and an off peak water heating schdule), the entres in column (d) for the speial scdule 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 divded 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 unbiled revenue as of end of year for each applicable revenue accunt subheadin.
ine Numoer ana I ite or Kate scneaUie Revenue Average Numoer ~vvn_or ;;aies ~~~~~lderNo.(a)(b)(c)of C~~)omers Per ?~stomer
(f)
1 08CFRoo051-MTH FAC SRVCHG 44,57~
2 08CFRoo052-ANN FAC SVCCHG ;,
3 08COOLKPRN - A1C DIRECT LOAD 2,700
4 08GNSVOOO6-GEN SRVC-DISTR 4,710,604 318,094,29f 10,923 431,25€0.0675
5 08GNSVOOO9-GEN SRVC-HI VO 274,239 12,496,244 23 11,923,435 0.0456
6 08GNSV0023-GEN SRVC-DISTR 1,229,433 98,632,772 68,368 17,983 0.0802
7 08GNSV006A-GEN SRVC-ENERG 189,922 17,292,018 1,746 108,775 0.0910
8 08GNSV006B-GEN SRVC-DEM&8,780 651,963 Hi 462,105 0.0743
9 08GNSV006M-MNL DIST VOLTG 3,691 200,889 7 527,286 0.0544
10 08GNSV009A-GEN SRVC HI VO 23,880 1,178,864 2 11,940,000 0.0494
. 11 08GNSV009M-MANL HIGH VOLT 1,67..63,865 0.0382
12 08GNSV023F-GEN SRVC FIXED 1,407 155,508 13~10,659 0.1105
13 08GNSV023M~GNSV DIST VOLT 106 8,778 €17,667 0.0828
14 08GNSV06AM-MNL ENERGY TOD 180 30,307 1 180,000 0.1684
15 08GNSV06MN-GNSV DIST VOLT 26,302 1,628,817 440 59,780 0.0619
16 08LNX00002-MTHL Y 80% GUAR 566,792
.. 17 08LNXoo04-ANNUAL 80%GUAR 5,910
18 08LNXOoo06-FIXD MTHL Y MIN 16,639
19 08LNX00014-80% MIN MNTHL Y 2,207,051
2C 08LNX00017-ADV/REF&80%ANN 144,106
21 08LNX00158-ANNUALCOST MTH 33,817
22 08LNX00300 - LINE EX 80% PLUS 143,76(
23 08LNX00310 -IRR, 80% ANNUAL 18f
24 08LNXOO312 UT IRG LINE EXT 7,491
25 08NMT06135 - UT NET MTR, GEN,3,905 268,482 6 650,83~0.0688
26 08NMT08135 -NET METERING GEN 5,43 315,497 .1 5,433,000 0.0581
27 08NMT23135 - UT NET MTR, GEN,47..40,728 .36 13,111 0.0863
28 080AL T007N-SECURITY AR LG 8,859 2,001,520 4,611 1,921 0.2259
29 08POLE007&-POLES W/L1GHT 1;¿1
30 08PRSV031M-BKUP MNT&SUPPL 10,12f 647,240 ;,5,062,500 0.0639
31 08PTLDOOO~POST TOP LIGHT 3f 2,851 f 7,60C 0.0750
32 08TOSS015F-TRAFFIC SIG NM 22C 18,704 3..6,875 0.0850
33 08TOSS0015-TRAF & OTHER S 1,164 103,126 49€2,347 0.0886
34 08MONL001&-MTR OUTDONIGHT 12,790 886,457 326 39,245 c 0.0693
35 SMUD REVENUE IMPUTATIONS -148,498
36 08LNX00311 - LINE EXT 80%188,519
37 08GNSV0008 - UT GEN SVC TOU ;:921,58 53,511,819 141 6,536,057 ..0.0581
38 08GNSV008M - UT GEN SVC TOU ;:34,23S 2,112,817 5 6,847,600 0.0617
39 UNBILLED REVENUE 19,106 1,926,00 0.1008
40 WASHINGTON
41 TOTAL Biled 1,718,481 30,70 0.069C
42 Total Unbiled Rev.(See Instr. 6)~((-0.0511
43 TOTAL 52,709,52 3,642,519,12 1,718,48f 30,67 0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.6
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) EiA Resubmission 04/14/2010
SALES OF ELECTRICITY BY RATE SCHEDUL,ES
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 òn 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 scheduie 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 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 divided by the number of biling 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 biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue account subheading.
¡Line l'IUmDer ana ime or Kate scneClule Mwn~olCl Kevenue Average NumDer IS wa or--es KW~~~/der
No.(a)(b)(c)
of c~~)omers Per r~stomer
(f)
1 02GNSB0024-WA GEN SRVC DO 42,138 3,255,593 3,194 13,193 0.0773
2 02GNSB0024-WA GEN SRVC DO -123,173
3 02GNSB024F-GEN SRVC DOM/F 154 15,211 6 25,667 0.0988
4 02GNSB024F-GEN SRVC DOM/F -2
5 02GNSB24FP-WA GEN SVC 185 95,242 101 1,832 0.5148
6 02GNSB24FP-WA GEN SVC -570
7 02GNSV0024-WA GEN SRVC .479,283 33,920,784 14,128 33,924 0.0708
8 02GNSV024F-WA GEN SRVC-FL 1,117 118,796 113 9,885 0.1064
9 02LGSB0036-LRG GEN SVC IRG 81,058 4,775,727 94 862,319 0.0589
10 02LGSB0036-LRG GENSVC IRG -241,236
11 02LGSV0036-WA LRG GEN SRV 713,397 42,892,027 836 853,346 0.0601
12 02LGSV048T -LRG GEN SRVC 1 135,161 7,383,037 25 5,406,440 0.0546
13 02LNX00102-L1NE EXT 80% G 65,142
14 02LNX00103-L1NE EXT 80% G 6,579
15 02LNX001 05-CNTRCT $ MIN G -596
16 02LNX00109-REF/NREF ADV +327,338
17 02LNX0011 O-REF /N REF ADV +13,155 ,
18 02LNX00112-YR INCURRED CH 669
19 02LNX00300-L1NE EX 80% G 2,663
20 02LNX00310 -IRG, 80% ANNUAL 2,685 .
21 02LNX00311 - LINE EXT 80%23,939
22 020AL T015N-WA OUTD AR LGT 1,671 207,735 863 1,936 0.1243
23 020AL TB15N-WA OUTD AR LGT 613 81,808 538 1,139 0.1335
24 020AL TB15N-WA OUTD AR LGT -1,788
25 02RCFL0054-WA REC FIELD L 259 21,297 29 8,931 0.0822
26 02RFNDCENT - CENTRALIA RFND 5
27 02ZMERGCR-MERGER CREDITS 2
28 02NMT24135, Net metering, WA 71 5,270 3 23,667 0.0742
29 02NMT36135-WA NET METER LRG 36 .3,299 1 36,000 0.0916
30 ACQUISITION COMMITMENT-A and 244
31 BPA BALANCING ACCOUNT -143,821
32 SMUD REVENUE IMPUTATIONS 170,832
3~WASHINGTON - CHEHALIS 6,120,000
..34 UNBILLED REVENUE 25,266 1,683,000 0.0666.
35 WYOMING .
36 05CHCKOOON-WY NRES 1
37 05GNSC0025- WY SMALL 87 6,119 14 6,214 0.0703
38 05GNSV0025-WY GEN SRVC 532,548 38,153,917 18,008 29,573 0.0716
3~05GNSV0028-GEN SVC =-15 KW 577,716 42,333,671 4,475 129,099 0.0733
40 05GNSV025F-GEN SRVC-FL RA 987 125,909 190 5,195 0.1276
41 TOTAL Biled 1,718,48!30,70 0.069C
42 Total Unbiled Rev.(See Instr. 6)I ~9..,((-0.051E
43 TOTAL 52,709,52 3,642,519,120 1,718,48E 30,67.0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.7
Name of Respondent This 'ì0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/14/2010
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 UElectric 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 accunt classification (such as a general residential
schedule and an off peak water heating schedule), the entries in coumn (d) fo the spcial 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 periods during the year (12 if
all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a fotnote the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
ine Numoer ana I iteOT Kate scneClule Mwn:sOICl Kevenue l'verage Numoer Iswn_OT :saies KiW~~~~r
No.(a)(b)(c)of C~~)omers Per r~stomer (f) ...
1 05LGSV0046-WY LRG GEN SRV 180,748 10,313,334 19 9,513,053 0.0571
2 05LGSV046M-WY LRG GEN SERV 36,691 2,025,659 1 36,691,000 0.0552
3 05LGSV048T-LRG GENSRVTIM 9,898 582,181 1 9,898,000 0.0588
4 05LNX00100-L1NE EXT 60% G 46
5 05LNX00102-L1NE EXT 80% G 513,295
6 05LNX00103-L1NE EXT 80%808
7 05LNX00105-CNTRCT $ MIN G 5,343
8 05LNX00109-REF/NREF ADV +635,421
9 05LNX00110-REF/NREF ADV+580
10 05LNX00114-TEMP SVC 12MO=-5,076
11 05NMT25135 - WY NET MTR, GEN,24 20,200 5 48,600 0.0831
12 05NMT28135-NET MTR SMALL 381 36,040 4 95,250 0.0946
13 050AL T015N-OUTD AR LGT SR 2,944 449,626 1,764 1,669 0.1527
14 05RCFL0054-WY REC FIELD L 683 54,614 5;:13,135 0.0800
15 05LNX00300 - LINE EXT 80%225,224
16 05LNX00311 - LINE EXT 80%44,341
17 ACQUISITION COMMITMENT-A and 246,065
18 ACQUISITION 220,28(.
19 SMUD REVENUE IMPUTATIONS 126,75C
20 UNBILLED REVENUE -6,656 -140,OOC 0.0210
21 05GNSC0025 - WY SMALL 2E 1,630 3 8,333 0.0652
22 05GNSV0025 - WY GEN SRVC 72,63~5,112,017 2,209 32,883 0.0704
23 05GNSV0028-GEN SVC =- 15 KW 68,82C 5,073,601 6~106,698 0.0737
24 05GNSV025F-GEN SRVC-FL RA 191 18,758 32 5,969 0.0982
25 05GNSV028M-GEN SVC =- 15 KW 1,098 75,362 1 1,098,000 0.0686
26 05LNX00102-L1NE EXT 80% G 6,415
27 05LNX00109-REF/NREF ADV +146,890
28 05LNX00110-REF/NREF ADV +840
29 05LNX00114-TEMP SVC 335
30 09GNSV0025-GEN SVC-SINGLE -2C -19,669 2 -10,000 0.9835
31 09GNSV025F-GEN SVC-FIXED ~288 f 500 0.0960
32 09GNSV025M-GEN SVC-MANUAL 981 66,100 1 981,000 0.0675
33 05NMT25135 - WY NET MTR, GEN,4E 2,747 1 45,000 0.0610
34 05NMT28135-NET MTR SMALL 6~4,576 1 63,000 0.0726
.35 090AL T207N-SECURITY AR LG 267 70,810 143 1,867 0.2652
36 09MONL0213-WY MTR OUTDOOR €1,051 :;3,000 0.1752
37 09SLCU2123-MTR OUTDONIGHT 7 44 2 3,50C 0.0634
38 05LNX00300 - LINE EX 80%32,608
39 05LNX00311 - LINE EXT 80%5,822
40 UNBILLED REVENUE 953 116,000 0.1217
-
41 TOTAL Biled 1,718,48f 30,701 0.069C42Total Unbiled Rev.(See Instr. 6)~(C -0.051t
43 TOTAL 52,709,52 3,642,519,120 1,718,48f 30,67.0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.8
Name of Respondent This l!0rt Is:Date of Report Year/Penod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electncity sold, revenue, average number of customer, average Kwh per
cùstomer, 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 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 dunng the year divided by the number of biling periods during the year (12 if
all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue account subheading.
I Line I'lumoer ana Ilte or Kate scneauie Mwn::oia Kevenue Average Numoer Kwaor::aies K~~~'S~rcr
No.(a)(b)(c)
of Cus&omers Per e¡à)stomer(d .(f)
1 LESS MULTIPLE BILLINGS -27,722
2
3 TOTAL COMMERCIAL SALES 16,194,257 1,120,956,943 213,730 75,770 0.0692
4
5 INDUSTRIAL SALES
6 CALIFORNIA
7 06GNSV0025-CA GEN SRVC 599 87,146 93 6,441 0.1455
8 06GNSVOA32-GEN SRVC-20 KW 1,904 244,988 29 65,655 0.1287
9 06LGSV048T-LRG GEN SERV 39,534 2,885,422 5 7,906,800 0.0730
10 06LGSVOA36-LRG GEN SRVC-O 5,247 554,742 15 349,800 0.1057
11 06LNX00109-REF/NREF ADV +1,482
12 ACQUISITION COMMITMENT-A and 3,935
13 ACQUISITION 2,457
14 REVENUE ADJUSTMENT -.-195,132
15 SMUD REVENUE IMPUTATIONS 7,862 .
16 UNBILLED REVENUE -1,032 -40,000 0.0388
17 IDAHO
18 07CFROO001-MTH FACILITY S 2,011
19 07CISH0019-GOMM & IND 153 10,824 3 51,000 0.0707
20 07GNS80006-IDAHO GEN 669 37,700 1 669,000 0.0564
21 07GNSV0006-GEN SRVC-LRG P 96,219 5,319,611 118 815,415 0.0553
22 07GNSV0008-GEN SRVC-MEDIU 328 17,182 1 328,000 0.0524
23 07GNSV0009-GEN SRVC-HI VO 73,460 3,483,571 11 6,678,182 0.0474
24 07GNSV0023-GEN SRVC-SML P 9,383 733,412 353 26,581 0.0782
25 07GNSV0035-GEN SRVCOPTION 1,234 57,879 1 1,234,000 0.0469
26 07GNSV006A-GEN SRVC-LRG P 4,841 328,112 32 151,281 0.0678
27 07GNSV023A-GEN SRVC-SML P 2,098 191,327 247 .8,494 0.0912
28 07GNSV023S-IDAHO TRAFFIC 8 1,101 3 2,667 0.1376
29 07LNX00035-ADV 80%MO GUÀR 1,525
3C 07LNX00108-ANN COST MTHL Y 1,996
31 07LNX00300 - 80% MONTHLY MIN .2,723
32 070AL T007N-SECURITY AR LG 13 4,805 17 765 0.3696
33 070ALT07 AN-SECURITY AR LG i 2 706 3 667 0.3530
3A 07SPCLOO01 1,015,300 44,056,231 1 1,015,300,000 0.0434
35 07SPCLOO02 89,536 3,697,685 1 89,536;000 0.0413
36 ACQUISITION COMMITMENT-A and 275,815
37 ACQUISITION 267,629
38 BPA BALANCING ACCOUNT 1,942
39 SMUD REVENUE IMPUTATIONS 249,187
40 UNBILLED REVENUE 8,284 321,000 0.0387
.
41 TOTAL Biled 1,718,48!30,70 0.069C
42 Total Unbilled Rev.(See Instr. 6)I ~.9"((-0.051€
43 TOTAL 52,709,52 3,642,519,120 1,718,8!30,67 0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.9
Name of Respondent This wort Is:Date of Report Year/Penod of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
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 accont 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 schedule in the same revenue account classification (such as a general 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 bils rendered during the year divided by the number of billng penods during the year (12 if
all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a fotnote the estimated additional revenue biled pursuant thereto.
6. Report aruntof unbiled revenue as of end of year for each applicable revenue accunt subheading.
ine lIumoer ana ime or Kate scneauie Mvvn ~oia Kevenue P;erage Numoer i:vvn_or ~aies KiW~~~~r
No.(a)(b)(c)of C~~)omers Per l~stomer
(f)
1 OREGON
2 01 COST0023, OR GEN SRV, COST 20,779 944,948 0.0455
3 01COST0048 - 01LGSV0048 1,278,099 51,846,060 0.0406
4 01COST023F - OR GEN SRV-3 168 0.0560
5 01COSTB023 - OR GEN SRV,400 18,584 0.0465
6 01COSTL030 - OR LRG GEN SRV,190,973 8,305,961
...
0.0435
7 01COSTS028, OR GEN SERV,99,307 4,411,296 0.044
8 01GNSB0023 - BPA DISC, c: 30 -1,52€
9 01GNSB0023, OR GEN SRV, BPA, c:24,666 65
10 01GNSB0028 - OR GEN SRVC,.-2,565
11 01GNSB0028, OR GEN SRV, BPA, ~20,253 6
12 01 GNSV0023, OR GEN SRV, c: 30 816,718 1,146
13 01 GNSV0028, OR GEN SRV ~ 30 2,647,912 516
14 01GNSV023F - OR GEN SRV - FLAT 3 850 3 1,000 0.2833
15 01GNSV023M - OR GEN SRV,14 2,292 1 14,000 0.1637
16 01 GNSV023T, OR GEN SRV, TOU 2,805 4
17 01 HABT0023, OR HABITAT 4 201 .0.0503
18 01 LGSV0030 - OR LRG GEN SRV, ~4,548,369 165
19 01LGSV0048-1000KWAND OVR 12,386,712 108 .
20 01LGSV048M-LRG GEN SRVC 1 490,770 21,669,676 6 81,795,000 0.0442
21 01LNX00102-L1NE EXT 80% G 3,90~
22 01LNX00105-CNTRCT $ MIN 1,659
23 01LNX00109-REF/NREF ADV .663
2~01LNX00300- LINE EXT 80%21,491
25 01 LPRS047M-PART REQ 395,217 17,706,309 ~98,804,250 0.0448
26 01NMT28135 - OR NET MTR, GEN,6,422 2
27 010AL T014N-QUTD AR LGT NR 5 611 5 1,000 0.1222
28 010AL T014N-QUTD AR LGT -18 .
29 010AL T015N-OUTD AR LGT 358 44,064 148 2,419 0.1231
30 01 PTOU0023, OR GEN SRV, TOU 64 2,848 0.0445
31 01 RENWOO23, OR RENW USAGE 226 10,343 0.0458
...32 01RENWB023 - OR RENEWABLE 23
33 BPA BALACING ACCOUNT -283
34 01STDAY023 - OR DAY STD OFR,31 1,20(0.0387
35 OR GAIN ON SALE OF ASSET 300,64f
36 OR SB 408 RECOVERY 2,676,175
37 OR SB 838 RECOVERY -1,632,118
38 SMUD REVENUE IMPUTATIONS 388,340
39 UNBILLED REVENUE 5,975 1,052,000 0.1761
40 UTAH
1
41 TOTAL Biled 1,718,48f 30,70 0.069C
42 Total Unbiled Rev.(Se Instr. 6)~C (-0.051E43TOTAL52,709,52 3,642,519,12 1,718,48f 30,67 0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.10
Name of Respondent This ï!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
SALES OF ELECTRICITY BY RATE SCHEDULES
1.. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendered during the year divided by the number of billng periods during the year (12 if
alFbilings 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.
Line I'lumoer ana .1 lUe ot Kate sChedule l\WhSold Kevenue Average Numoer iswttot Sales ~t'~er:erof Cu(~tlmers Per ?~stomer hold
No.(a)(b)(c)(f)
1 08CFR00051-MTH FAC SRVCHG 15,948
2 08EFOP0021-ELEC FURNACE 0 ,1,960 147,704 2 980,000 0.0754
3 08EFOP021 M-ELEC FURNACE 0 1,176 135,521 3 392,000 0.1152
4 08GNSV0006-GEN SRVC-DISTR 689,915 50,067,071 1,239 556,832 0.0726
5 08GNSV0009-GEN SRVC-HI VO 2,569,357 109,132,227 112 22,940,688 0.0425
6 08GNSV0023-GEN SRVC-DISTR .61,032 4,966,984 3,705 16,473 0.0814
7 08GNSV006A-GEN SRVC-ENERG 49,619 4,829,373 248 200,077 0.0973
8 08GNSV006B-GEN 6,969 511,429 10 696,900 0.0734
9 08GNSV009A-GEN SRVC HI VO 15,183 1,019,312 6 2,530,500 0.0671
10 08GNSV009M-MANL HIGH 970,492 38,376,088 11 88,226,545 ..0.0395
11 08GNSV023F-GEN SRVC FIXED 4 1,656 1 4,000 0.4140
12 08GNSV06MN-GNSV DIST VOLT 1,165 83,183 30 38,833 0.0714
13 08GNSV09AM-MAN TOD HIVOL T 1,262 106,993 1 1,262,000 0.0848
14 08LNX00002-MTHL Y 80% GUAR 23,777
15 08LNX00004-ANNUAL 80%GUAR 12,464
16 08LNX00014-80% MIN 73,478
17 08LNXOO017-ADV/REF&80%ANN 3,410
18 08LNX00311 - LINE EXT 80%1,660
19 08LNX00300 - LINE EXT 80% PLUS 99,349
20 08LNX00310 -IRR, 80% ANNUAL 6 .
21 080ALT007N-SECURITY AR 1,471 305,190 519 2,834 0.2075
22 08TOSS0015-TRAF & OTHER S 32 2,574 9 3,556 0.0804
23 08MONL0015-MTR OUTDONIGHT 12 2,763 6 2,000 0.2303
24 OBNMT23135 - UT NET MTR,GEN,62 4,026 1 62,000 0.0649
i 25 08SPCLOO01 363,446 14,459,495 . 1 363,446,000 0.0398
26 08SPCLOO02 695,212 19,125,60 1 695,212,000 0.0275
27 08SPCLOO03 .778,970 26,953,532 1 778,970,000 0.0346
28 08SPCLOO05 .253,662 9,281,595 1 253,662,000 0.0366.
29 SMUD REVENUE IMPUTATIONS -164,928
30 OBGNSV06AM-MNL ENERGY TOD .189 20,505 2 94,500 0.1085
31 08GNSVOO8 - UT GEN -SVC TOU :;887,483 54,512,084 ..114 7,784,939 0.0614.. ..
3.0 08GNSV008M - UT GEN SVC TOU :;60,130 3,578,503 7 8,590,0Oc 0.0595
33 UNBILLED REVENUE -10,914 1,058,000 ;0.0969
34 WASHINGTON
35 02GNSB0024-WA GEN SRVC cc 2,760 206,876 98 28,163 0.0750
36 02GNSB0024-WA GEN SRVC DO -7,726
37 02GNSB24FP-WA GEN SVC 5 1,899 1 5,000 0.3798
38 02GNSB24FP-WA GEN SVC -13
39 02GNSV0024-WA GEN SRVC 16,583 1,199,690 370 44,819 0.0723
40 02GNSV024F-WA GEN 33 6,647 4 8,250 0.2014
41 TOTAL Billed 1,718,48 30,70 0.0690
42 Total Unbiled Rev.(See Instr. 6)~((-0.0516
43 TOTAL 52,709,52 3,642,519,120 1,718,48'30,67.0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.11
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) . An Original (Mo, Da, Yr)End of 2oo9/Q4
(2) FiA Resubmission 04/14/2010.
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 "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the numberof bils rendered during the year divded by the number of biling periods during the year (12 if
all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a fotnote the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
ine Numoer ana Iitie or Rare scneauie MWff~la t(evenue l\veragi\~umoer Kwn~or :;aies t(~~~~iiJr
No.(a)(b)(c)ofC~~omers Per r~stomer
(f)
1 02LGSV0036-WA LRG GEN SRV 128,361 7,853,744 123 1,043,585 0.0612
2 02LGSV048M-WA LRG GEN SRV 17,243 1,224,200 1 17,243,OOC 0.0710
3 02LGSV048T-LRG GEN SRVC 1 660,556 31,950,527 32 20,642,375 0.0484
4 020AL T015N-WA OUTD AR LGT 119 13,84E 42 2,833 0.1164
5 020ALTB15N-WA OUTD AR LGT 29 3,830 18 1,611 0.1321
6 020ALTB15N-WA OUTO AR LGT -81
7 02PRSV47TM-LRG PART REQMT 1,540 167,035 1 1,540,000 0.1085
8 02LGSB0036-LRG GEN SVC IRG 4,581 430,088 29 157,966 0.0939
9 02LGSB0036-LRG GENSVC IRG -13,424
10 ACQUISITION COMMITMENT-A and --182
11 BPA BALANCING ACCOUNT -8,560
12 SMUD REVENUE IMPUTATIONS 105,570
13 WASHINGTON - CHEHALIS 3,060,000
14 UNBILLED REVENUE 16,578 1,224,000 0.0738
15 WYOMING
16 05GNSV0025-WY GEN SRVC 124,314 7,996,854 1,247 99,690 0.0643
17 05GNSV0028-GEN SRVC =-15 KW 161,489 10,332,054 567 284,813 0.0640
18 05GNSV025F-GEN SRVC-FL RA 41 4,447 9 4,556 0.1085
~05LGSV0046-WY LRG GEN 1,414,34S 75,513,111 55 25,715,36 0.0534
2C 05LGSV046M-WY LRG GEN 257,07€13,010,600 2 128,538,000 0.0506
21 05LGSV048M-TOU=-1000KW MAN 1,227,254 50,339,493 3 409,084,667 0.0410
22 05LGSV048T-LRG GENSRV TIM 1,154,020 47,902,084 10 115,402,000 0.0415
23 05LNX00100-L1NE EX 60% G 34,62S
24 05LNX00102-L1NE EX 80% G 195,024
25 05LNX00105-GNTRCT $ MIN G 48,277
26 05LNX00109-REF/NREF ADV +125,478
27 050AL T015N-OUTD AR LGT SR 88 12,350 46 1,913 0.1403
28 05PRSV033M-PART SERV REQ 851,021 43,455,703 4 212,756,750 0.0511
29 ACQUISITION COMMITMENT-A and 1,099,870
30 ACQUISITION 984,617
31 SMUD REVENUE IMPUTATIONS 557,577
32 05LNX00300 - LINE EXT 80%27,31~
33 UNBILLED REVENUE -58,28~-2,857,OO 0.0490
34 05GNSV0025-WY GEN SRVC 15,95~1,102,83S 311 51,296 0.0691
35 05GNSV0028-GEN SVC =- 15 KW 20,972 1,422,56S 9.223,106 0.0678
36 05GNSV025M - General Service 7~6,574 1 75,00C 0.0877
37 05GNSV028M-GEN SVC =- 15 KW 3,288 174,821 4 822,000 .0.0532
38 05LGSV0046-WY LRG GEN SRV 29,44 1,771,952 4 7,361,000 0.0602
39 05LGSV048M- TOU=-1000KW MAN 328,405 13,568,473 3 109,46,333 0.0413
40 05LGSV048T-LRG GENSRV 1,055,64 45,089,419 9 117,293,778 0.0427-41 TOTAL Biled 1,718,48f 30,70 0.069(
42 Total Un biled Rev.(See Instr. 6)~'fI ((-0.051E
43 TOTAL 52,709,52 3,642,519,12 1,718,4Bf 30,67.0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.12
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
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 classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule .should dénote 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 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 unbiled revenue as of end of year for each applicable revenue aCcunt subheading.
iune I'lumoer ana 1 lUe or rtaie scneouie Mvvn ;:010 rtevenue Average NUmber . KWaOT :saies K.~~r:is~kr
No.(a)(b)(c)of cu(~tlmers Per y~stomer
(f)
1 05LNX00102-L1NE EXT 80% G 18
2 05LNX00109-REF/NREF ADV 11
3 05PRSV033M-PART SERV REQ 45,571 2,307,902 3 15,190,333 0.0506
4 09GNSV0025-GEN SVC-SINGLE -139 -11,288 .0.0812
5 09GNSV025M-GEN SVC-MANUAL 2,256 122,705 3 752,000 0.0544
6 090AL T207N-SECURITY AR 5 1,057 3 1,667 0.2114
7 09PRSV033M 365 105,160 1 365,000 0.2881
8 UNBILLED REVENUE 2,583 124,000 0.0480
9 LESS MULTIPLE BILLINGS -1,258
10
11 TOTAL INDUSTRIAL SALES 18,712,080 891,577,996 10,983 1,703,731 0.0476
12
13 IRRIGATION SALES
14 CALIFORNIA
15 06APSV0020-AG PMP SRVC 66,143 6,987,098 1,353 48,886 0.1056
16 06LNX00102-L1NE EXT 80% G 961
17 06LNX00103-L1NE EXT 80% G 8,351
18 06LNX00110-REFINREF ADV +40,825
19 06LNX00310 - IRG, 80% ANNUAL 553
20 06LNXOO312 - CA IRG LINE EX 693
21 06USBR0040-KLAM IRG ONPRJ 26,820 2,404,084 671 39,970 0.0896
22 06LNX00109-REF/NREF ADV +247
23 IRRIGATION UN BILLED -2
24 IDAHO
25 07APSA010L - IRG & Pump BPA -826
26 07APSA010L - IRG & Pump Large 391,887 28,925,349 3,247 120,692 0.0738
27 07APSA010S -IRG & PUMP BPA -912
28 07APSA010S - lRG & Pump Small 4,066 379,529 400 10,165 0.0933
29 07 APSAL 1 OX - IRG & PUMP - Large 73,169 5,513,630 788 92,854 0.0754
30 07APSAS10X -IRG & PUMP - Small 1,663 169,036 219 7,594 0.1016
31 07APSB010L -IRG & Pump BPA ..285
3.07APSB010L -IRG & Pump Large -7 . .-873 0.1247
33 07APSC010L -IRG PUMP Srv BPA 492
34 07APSC010L -IRG PUMP Srv Large -11 -1,096 0.0996
35 07APSCL10X-IRG&PUMP LARGE -9
36 07APSVCNLL-LRG LOAD CANAL 25,857 1,728,923 81 319,222 .0.0669
37 07APSVCNLS-SML LOAD CANAL 147 13,262 18 8,167 0.0902
38 07LNX00015-ANNUAL 80%GUAR 5,943
39 07LNXOO040-ADV+REFCHG+80%186,950
40 07LNX00107-SUBD ADV & AIC 1,097
41 TOTAL Biled 1,718,48!30,70 0.069C
42 Total Unbilled Rev.(See Instr. 6)~((-o.051€
43 TOTAL 52,709,52 3,642,519,120 1,718,4~30,67 0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.13
Name of Respondent This î!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
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 "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue accunt, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the 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 entres in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billng periods during the year (12 if
all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a fotnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
ine Numoer ana Ilte or Kate scneouie Mvvn ::01.0 Kevenue Average Numoer ~vvn_or ;;aies r(~~~'g~~er
No.of Cu(~trmers i Per r~stomer(a)(b)(c)(f)
1 07LNX00310 80% ANNUAL 1,185
2 07LNX00312 - ID LINE EXT 18,501
3 07APSN010L -ID LG IRR & PUMP 3,14!i 262,487 51 61,667 0.0835
4 07APSN010S -IRRIGATION,..336 28,025 17 19,765 0.0834
5 07APSNS10X -IRRIGATION,702 2 1,500 0.2340
6 07ZZMERGCR-MERGER CREDITS -1
7 IRRIGATION BPA BAL ACCT 309,762
8 UNBILLED REV - IRRIGATION !i
9 OREGON
10 01APSV0041-AG PMP SRVC BP 1,866,458 4,696
11 01APSV001-AG PMP SRVC BP -167,941
12 01APSV041L-OR Pumping Serv 2,620,778 1,101
13 01APSV041L..RPumping Serv BPA -284,328
14 01 APSV041T - AGR PUMP SRV -2,324
15 01APSV041T - AGR PUMP 27,259 59
16 01APSV041X-AG PMP SRVC 83,828 248
17 01APSV41XL-OR Pumping Serv no 163,64 55
18 01 BPADEBIT-BPA ADJUST FEE 36,673
19 01COST0041 -01APSV0041 130,37(5,800,578 0.0445
¿c 01COST008 - 01LGSV0048 8,41;,340,126 0.0404
21 01COSTS028, OR GEN SERV,23(10,477 0.0456
22 01 GNSV0028, OR GEN SRV ,. 30 6,038 .2
23 01HABIT041 - 01APSV0041 AG A 194 0.0485
24 01 LGSB0048 - LG GEN SVC ,.-31,372
25 01 LGSB0048 - LG GEN SVC ,.71,829 1
26 01LNX00102-L1NE EX 80% G 84
27 01LNX00103-LINE EX 80% G 18,749
28 01LNX00109-REF/NREF ADV +6,324
29 01 LNX00110-REF/NREF ADV +115,656
30 01 LNX0031 O-LINE EXTNSION 2,392
31 01PTOUOO41 - 01APSV0041 AG 651 25,756 0.0392
32 01RENEW041-01APSV0041 AG 120 5,406 0.0451
33 01SLX00005-KLAMATH FALLS 180,210
34 01SLX00013-K FALLS IRG 1'1 9,033
35 01SLX00014-K FALLS IRG MI 2,542
36 01STDAY041 - Daily Standard Ofer 47 985 0.0210
37 01USBGV033-KLAMATH IRG TOU -31
38 01USBOF033-KLAMATH BASIN 44,836 1,225,153 652 68,767 0.0273
39 01 USBON033-KLAMATH BASIN -125,299
4(01 USBON033-KLAMATH BASIN 52,490 1,296,72!i 1,397 37,57~0.0247
,.41 TOTAL Biled 1,718,481 30,70 0.069(
42 Total Unbiled Rev.(See Instr. 6)~9.fI ((-0.051f
43 TOTAL
I 52,709,52 3,642,519,12 1,718,48!i 30,67 0.0691
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 2009/Q4
.(2) OA Resubmission 04/14/2010
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each råte schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenUe per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils 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 biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue account subheading.
I Line Numoer ana Ilte or Kate scneouie Mwn ::010 Kevenue Average Numoer Kwaor::aies K~n~e_i:er
No.of c~~)omers Per t(à)stomer hold
(a)(b)(c)(f)
1 01USBON033-KLAMATH BASIN -145,198
2 01 USBGV033-IRG TOU W/O BPA 2,964 51,910 10 296,400 0.0175
3 IRRIGATION BPA BAL ACCT -7,116 .
4 IRRIGATION UNBILLED 76 5,000 0.0658
5 01LNX00312 - OR IRG LINE EX 9,315
6 01NMT33135 - OR NET MTR-1
7 01NMT41135 - NETMTRAG PMP 1
8 01ZZMERGCR-MERGER CREDITS 5
90R GAIN ON SALE OF ASSET 22,685
10 OR Irrigation - BPA adjustment 17,167
11 OR SB408 RECOVERY 218,391
12 OR SB 838 RECOVERY -199,960
13 UTAH
14 08APSV0010-IRR & SOIL DRA 185,190 10,874,683 2,618 70,737 0.0587
15 08APSV10NS- Irg Soil Drain Pump N 14,82 832,491 88 168,659 0.0561
16 08LNX00002-MTHL Y 80% GUAR 985
17 08LNX00004-ANNUAL 80%GUAR 26,710
18 08LNX00014-80% MIN MNTHL Y 1,811
19 08LNXOO017-ADV/REF&80%ANN 181,918
20 08LNX00300 - LINE EXT 80% PLUS -255
21 08LNX00310 -IRR, 80% ANNUAL 6,823
22 08LNX00312 UT IRG LINE EXT 4,208
23 08NMT10135-UT IRR SOIL DRNG 19 1,420 1 19,000 0.0747
2A UNBILLED REV - IRRIGATION 225 14,000 0.0622
25 WASHINGTON
26 02APSV0040-WA AG PMP SRVC .144,135 9,711,488 4,615 31,232 0.0674
27 02APSV0040-WA AG PMP SRVC -384,070
28 02APSV040X-WA AG PMP SRVC 24,724 1,1555,638 698 35,421 0.0670
29 02BPADEBIT-BPA ADJUST FEE 9,693
30 02LNX00102-L1NE EX 80% G 878
31 02LNX00103-L1NE EXT 80% G 10,482
3.02LNX00105-CNTRCT $ MIN G 30
3~O;lLNX00109-REF/NREF ADV +39 ..
34 02LNX0011 D-REF/NREF ADV +100,557
35 02LNX00310 -IRG, 80% ANNUAL 1,703
36 02LNX00312 - WA IRG LINE EXT 7,011 .
37 02ZZMERGCR-MERGER CREDITS 3
38 WASHINGTON - CHEHALIS 720,000
39 IRRIGATION BPA BAL ACCT -162,641
40 IRRIGATION UNBILLED .57 3,000 0.0526
41 TOTAL Biled 1,718,8 30,70 0.069(
42 Total Unbiled Rev.(See Instr. 6)~.((-0.05H
43 TOTAL 52,709,52 3,642,519,120 1,718,48E 30,67.0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.15
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) . An Original (Mo, Da, Vr)End of 2009/Q4
(2)FiA Resubmission 04/14/2010
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 "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 accunt classification (such as a general residential
schedule and an off peak water heating schedule), the entres in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendered during the year divided by the number of billng 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 biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue account subheading.
ine Numoer ana Ilte or Kate scneauie Mvvn ::oia Kevenue Average Numoer ¡svvaor yaleS ~~'s~erNo.(a)(b)(c)of C~~)omers Per 9~stomer
(f)
1 WYOMING
2 05APS00040-AG PUMPING SVC 16,25€1,194,666 606 26,825 0.0735
3 05LNX00110-REF/NREF ADV +58,3i
4 05LNX00103-L1NE EXT 80% G 8,72f
5 05LNX00312 - WY IRG LINE EX 357
6 IRRIGATION UN BILLED 17 1,000 0.0588
7 05LNX00110-REF/NREF ADV +15,544
8 09APSV0210-IRR & SOIL ORA 3,296 253,719 65 50,708 0.0770
9 LESS MULTIPLE BILLINGS -674
10
11 TOTAL IRRIGATION SALES 1,222,188 85,413,308 23,087 52,938 0.0699
12
13 PUBLIC STREET&HIGHWAY
14 CALIFORNIA .
15 06COSL0052-CO-OWND STR LG 8 6,834 5 1,600 0.8543
16 06CUSL053F-SPECIAL CUST 0 1,22f 155,279 12C 10,208 0.1268
17 06CUSL058F-CUST OWND STR 242 34,578 2~10,522 0.1429
18 06HPSV0051-HI PRESSURE SO 681 168,687 n 9,329 0.2477
19 UNBILLED REVENUE 31 6,000 0.1935
20 IDAHO
21 07GNSV023S-IDAHO TRAFFIC 16C 15,572 25 6,400 0.0973
22 07SLC000l1-STR LGT CO-OWN 11C 48,239 30 "3,667 0.4385
23 07SLCU012E-ENGY STR 120 13,48E 6 13,667 0.1096
24 07SLCU012F-FULL MNT STR 1,94(365,705 276 6,975 0.1879
25 07SLCU012P-PART MNT STR LGT 194 26,697 16 12,125 0.1376
26 UNBILLED REVENUE 24 3,000 0.1250
27 OREGON
28 01COSL0052-STR LGT SRVC C 97B 116,267 63 15,524 0.1189
29 01CUSL0053-CUS-OWNED MTRD ..809 55,106 69 11,725 0.0681
30 01 CUSL053E-STR LGT SVC 8,316 566,525 166 50,096 0.0681
31 01CUSL053F-STR LGT SRVC C 267 27,77B 22 12,136 0.1040
32 01 HPSV0051-HI PRESSURE SO 17,811 3,402,34 681 26,154 0.1910
33 01 MVSL005D-MERC VAPSTR LG 9,949 1,196,80 261 37,262 0.1203
34 010ALT014N-0UTD AR LGT NR j 61E ~1,000 0.2053
35 010AL T014N-OUTD AR LGT NR -12
36 010ALT015N-OUTD AR LGT NR B 1,06!i 4 2,000 0.1331
37 BPA BALANCING ACCOUNT -1
38 OR GAIN ON SALE OF ASSET 3,739
39 OR SB408 RECOVERY 33,054
40 OR SB 838 RECOVERY -17,255
41 TOTAL Biled 1,718,481 30,70 0.069C
42 Total Un biled Rev.(See Instr. 6)!I -0.051E
43 TOTAL 52,709,52 3,642,519,12 1,718,48f 30,67.0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.16
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
.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 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 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 additonal revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end ofyear for each applicable revenue account subheading.
Line Numoer ana Ille OT t(ate scneaUie Mvvn ::oia t(evenue Average Number Kvvn_oT :saies ~~n~e_rer
of cu(~~omers Per l(à)stomer hold
No.(a)(b)(c)(f)
1 UNBILLED REVENUE 464 68,000 0.1466
2 UTAH
3 08CFR00012-STR LGTS (CONV 54
4 08CFR00051-MTH FAC SRVCHG 4,529
5 08CFR00061-U/G AREA LIGHT 85 ..
6 08CFR00062-STREET LIGHTS 79
7 08HAXT0060-L1GHTNG-HAXON 38 1
8 080AL T007N-SECURITY AR LG 5 1,536 5 1,000 0.3072
9 08TQSS015F-TRAFFIC SIG NM 1,142 83,934 126 9,063 0.0735
1Ö 08SLCOOO11-STR LGT CO-OWN 23,085 6,709,431 1,019 22,655 0.2906
11 08TOSS0015-TRAF & OTHER S 2,997 277,747 1,528 1,961 0.0927
12 08MONL0015-MTR OUTDONIGHT 1,057 81,564 54 19,574 0.0772
13 08SLCU012P-STR LGT CUST-O 6,585 815,501 242 27,211 0.1238
14 08SLCU012F-STR LGT CUST-O 3,389 467,142 148 22,899 0.1378
15 08SLD13ES1-DECOR CUST-OWN -2
16 08SLCU012E-DECOR CUST -OWN 39,501 2,519,984 410 96,344 0.0638
17 08THIK0077-STR LIGHT SPEC 141 17,277 1 141,000 0.1225
18 UNBILLED REVENUE 323 51,000 0.1579
19 WASHINGTON
20 02CFROOO12-STR LGTS (CONV 91
21 02COSL0052-WA STR LGT SRV 443 59,009 19 23,316 0.1332
22 02CUSL053F-WA STR LGT SRV 3,675 234,714 107 34,346 0.0639
23 02CUSL053M-WA STR LGT SRV 1,158 73,232 93 12,452 0.0632
24 02HPSVOO51-WA HI PRESSURE 3,103 562,958 148 20,966 0.1814
25 02MVSL0057-WA MERC VAPSTR 2,013 225,704 46 43,761 0.1121
26 WASHINGTON - CHEHALIS 180,000
27 UNBILLED REVENUE 780 90,000 0.1154
28 WYOMING ..
29 05COSL0057-CO-OWND STR LG 320 67,201 21 15,238 0.2100
3(05CUSL058F-CUST OWND STR 418 28,309 37 .11,297 0.0677
31 OSCUSL058M-CUST OWND STR 70 4,611 10 7,000 0.0659
32 05CUSLOE58-WY CUST OWNED 705 45,340 31 22,742 0.0643
33 05CUSLOM58-CUST OWNED 38 2,999 5 7,60(0.0789
34 05HPSV0051-HI PRESSURE SO 4,636 1,009,517 154 30,104 02178
35 050ALT015N-QUTD AR LGT SR 3
36 05MVS00053-MERCURY VAPOR 3,963 515,059 267 14,84~0.1300
37 UNBILLED REVENUE 166 26,000 0.1566
38 09MONL0213-WY MTR OUTDOOR 26 2,257 1 26,000 0.0868
39 09SLC00211-STR LGT CO-OWN 1,388 386,956 48 28,917 0.2788
4C 09SLCU2121-STR LGT CUST-O 35 4,324 10 3,500 0.1235
-
41 TOTAL Biled 1,718,481 30,70 0.069(
42 Total Unbiled Rev.(See Instr. 6)~((.-0.051t
43 TOTAL 52,709,52 3,642,519,120 1,718,48!30,67 0.0691
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 2009/Q4
(2) nA Resubmission 04/14/2010
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 "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 accunt classification (such as a general residential
schedule and an off peak water heating schedule), the entres in coumn (d) for the speial schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendere during the year divided by the number of billng periods during the year (12 if
all billngs are made. monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnte the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
Line NumOer ana Iitie ot Kate scneoUie MWtf~ola t(evenue AVerag~\~umoer Kwn_ot t;aies ~~r's~lderNo.(a)(b)(c)of cu(~ omers Per r~stomer
(f)
1 09SLCU2122-TRAF & OTHER S 24 1,25'i 14 1,714 0.0523
2 09SLCU2123-MTR OUTDONIGHT 4 278 1 4,000 0.0695
3 09SLCUP212-CUST OWNED 46 7,847 9 5,111 0.1706
4 09TOSS0213-WY TRAF & OTHER 39 1,728 13 3,000 0.0443
5 UNBILLED REVENUE 141 56,000 0.3972
6 LESS MULTIPLE BILLINGS -2,475
7
8 TOTAL PUBLIC STREET &144,76f 20,913,398 3,948 36,668 0.1445
9
10 OTHER SALES TO PUBLIC AUTH
11 UTAH
12 08GNSVOO6-GEN SRVC-DISTR 2,338 155,904 4 584,500 0.0667
13 08GNSV0023-GEN SRVC-DISTR 29 2,785 3 9,667 0.0960
14 08GNSV009M-MANL HIGH VOLT 438,695 18,893,014 4 109,673,750 0.0431
15 080ALT007N-SECURITY AR LG 18 4,445 2 9,000 0.2469
16 UNBILLED REVENUE -3,485 -24,OOC 0.0069
17
if TOTAL OTHER SALES TO PUBLIC 437,595 19,032, 14~13 33,661,154 0.0435
te
2C FORFEITED DISCOUNTS
21 CALIFORNIA
22 Late Fees 267,617~IDAHO
24 Late Fees 411,562
25 OREGON
26 Late Fees 2,566,024
27 UTAH
28 Late Fees 2,947,238
~WASHINGTON
3C Late Fees 556,652
31 WYOMING
32 Late Fees 569,27f
3~
34 TOTAL FORFEITED DISCOUNTS 7,318,3E I...
35
-, 36 MISCELLANEOUS SERVICE REV i..
37 CALIFORNIA
38 06CFR00003-MTH MAINTENANC 1,454 .
39 06CONN0300-CA RECONNECTIO 115,750 .
40 06FCBUYOUT 196,359
41 TOTAL Biled 1,718,48!30,70 0.069C
42 Total Unbiled Rev.(See Instr. 6)~((-0.051E
43 TOTAL 52,709,52 3,642,519,12 1,718,48i 30,67 0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.18
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/14/2010
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 opèrating 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
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 peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendered during the year divided by the number of billng 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.
ine l'lumoer ana I lUe OT Kaie scneauie Mvvn ;:010 Kevenue Average Numoer ~ vvn.oT ;;aies K~ris~lder
No.(a)(b)(c)
of Cu(~)omers Per 9~stomer
(f)
1 06RCHK0300-CA RET CHK CHR 15,276
2 06TAMP030D-A TAMP & UNAU 2,625
3 06TEMP0300-CA TEMP SRVC C 2,665
4 06TRBL0300-CA TROUBLE CAL 90
5 06XMTRTAMP-TAMPERING-521
6 Home Comfort 1,224
7 Other 2,679
8 IDAHO
9 07CFR00001-MTH FAC SRVCHG 2,056
10 07CONN0300-ID RECONNECTIO 114,605
11 07FCBUYOUT - FAC CHG BUYOUT 1,723
12 07RCHK0300-ID RET CHK CHR 37,080
13 07TAMP0300 1,575
14 07TEMP0014-TEMP SRVC CONN ..10,315
15 07XMTRTAMP-TAMPERING -97
16 Weatherization Loans ID 629
17 Oter -4
18 OREGON .
19 01CFR00001-MTH FACILITY S 61,966
20 01CFROOO03-MTH MAINTENANC 26,039
21 01CFRO0004-EMRGNCY ST&BY 25,056
22 01 CFROOOOS-INTERMTNT 42,230
23 01CFR00013-MTH MISC CHRG 2,284
24 01CFR00014-YR MISC CHRG 5
25 01CONN0300-RECONNECTION C 628,S10
26 01 DPAC0300-DEMAND PULSE 3,000
27 01 ESSC0600 - ESS charges 7,150
28 01 FCBUYOUT-FAC CHG BUYOUT 395,537
25 01 RCHK0300-RETURNED CHECK 300,800
3C 01TAMP0300-TAMP & UNAUTH 11,850 ...
31 01TEMP0300-TEMP SRVC CHRG 79,065
32 01TRBL0300- TROUBLE CALL C 40
33 01XMTRTAMP-TAMPERING -6,532
34 Other 2,959
35 UTAH
36 08CFR00013-MTH MISC CHRG 147,885
37 08CFR00051-MTH FAC SRVCHG 74,695
38 08CFR00052-ANN FAC SVCCHG 424
39 08CFR00053-MTHLY MAINTFEE 10,575 .
40 08CFROO063-MTH MISC CHARG 3,301
41 TOTAL Biled 1,718,48~30,70 0.0690
42 Total Unbilled Rev.(See Instr. 6)~C (-0.0516
43 TOTAL 52,709,52 3,642,519,120 1,718,48~30,67 0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.19
Name of Respondent This Ï!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
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, averae 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 accunt, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Whee the same customers are served under more thn one rate schedule in the same revenue account classificatio (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 periods during the year (12 if
all billngs are made monthly).
5. For any rate schedule having a fuel adjustrnent clause state in a fotnote 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 Number anci Iitie or Rate scneoUie Mvvn ;:010 Revenue Average Number isvvn. or :;aies ~~'Si~erNo.(a)(b)(c)of C~~\omers Per l(ã)stomer
(f)
1 08CFR00064-ANN MISC CHARG 6,660
2 08CONN0300-RECONN&DISCONN 254,970
3 08CONTSERV-3RD PARTY O/S 292,53~
4 08FCBUYOUT-FAC CHG BUYOUT 518,434
5 08NCON0300-UT FEE NRES RE 6,455
6 08RCHK0300-UT RET CHK CHR 458,280
7 08RCON0001-CONNECT FEE 1,534,970
8 08TAMP0300-TAMPERING&UNAU 16,950
9 08TEMP0014-TEMP SRVC CONN 284,670
10 08XMTRTAMP-TAMPERING-12,482
11 Energy Finanswer 12,000 94:¿
12 Energy Finanswer new Com 36,87!i
13 Other 23,275
14 08GNSVOOO9-GEN SRVC-HI VO -3,654
15 08VISIT300 - UT Visit, Service Ca 279,910
16 WASHINGTON
17 02CFROOOO3-MTH MAINTENANC 1,320
18 02CFR00004-EMRGNCY ST&BY 5,9OC
19 02CFROOOO5-INTERMTNT SRVC 4,31~
20 02CONN030o-WA RECONNECTIO 124,085
21 02FCBUYOUT - FAC CHG BUYOUT 5,163
22 02RCHK0300-WA RET CHK CHR 62,36C
23 02TAMP0300-WA TAMP & UNAU 5,77f
24 02TEMP0300.WA TEMP SRVC C 20,04f
25 02XMTRTAMP-TAMPERING -1,857
26 Energy Finanswer new Com 4,084
27 Home Cofort 4,701
28 Other -19,420
29 WYOMING
30 05CFROO3-MTH MAINTENANC 8,032
31 05CFROO-EMRGNCY ST&BY 19,472
32 05CFROOOO5-INTERMTNT SRVC 10,607
33 05CFROO013.MTH MISC CHRG 3,186
34 05CONN0300-WY RECONNECTIO 131,33(1
35 05FCBUYOUT - FAC CHG BUYOUT 111,601 .
36 05LONGFORM-BILL PRINT 8C
37 05RCHK0300-WY RET CHK CHR 68,490
38 05TAMP0300 1,650
39 05TEMP0300-WY TEMP SRVC C 28,875
40 Other -7,237
41 TOTAL Biled 1,718,48!30,70 0.069(
42 Total Unbiled Rev.(See Instr. 6)~-0.0511
43 TOTAL 52,709,52 3,642,519,120 1,718,48f 30,67.0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.20
Name of Respondent This (!0r! Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/04
(2) r=A Resubmission 04/14/2010
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 classifed 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 bils 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 biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accont subheading.
I Line Numoer ana iiue or /"ate scneaUie Mvvn ;:010 Kevenue Average Numoer -isWh.ot saies 'l~nise I.erNo.of cu(~)omers Per r~stomer hold
(a)(b)(c)(f)
i 05XMTRTAMP-TAMPERING-201
2 09CFR00005-INTERMTNT SRVC 339
3 05CONN0300-WY RECONNECTIO 27,760
4 05FCBUYOUT - FAC CHG BUYOUT 206,838
5 05RCHK0300-WY RET CHK CHR 11,190
6 05SERV0300-WY SRVC CALLS 120
705TAMP0300 150
8 05TEMP0300-WY TEMP SRVC C 1,700
9 09CFR00001-MTH FAC SRVCHG 5,393
10 09CFR00014-YR MISCCHRG 3 .
11 Energy Finanswer 12,000 425
12 Other -1,869
13
14 TOTAL MISC SERVICE REV 6,908,893
15
16 SALES OF WATER AND WTR PWR
17 UTAH 3,254
18 WYOMING 8,900
19 TOTAL WATER AND WATER PWR 12,154
20
21 RENT FROM ELEC PROPERTIES
22 CALIFORNIA
23 06CFR00OO-MTH RNTAL CHRG 1,710 ..
24 RENT REV-TRANSMISS 55
25 Rent Revenue - Subleases .17,123
26 Joint use 545,902
.-
27 IDAHO
28 07CFROOOO9- YR LSE CHRG-EO 789
29 071f.,¡CHGOO-INVEST MNT CHG 180
30 07LOOP0014-MTH FEE PRE-AS -2,870 .
31 07POlE0075-STEEL POLES US .281
32 07XTRN0013-RNTILSE L& PRO 103,108
33 RENT REVENUE-HYDRO 13,750
34 Rent Revenue - Subleases 2,216
35 Joint use 198,816 .
36 OREGON
37 01 CFR00006-MTH RNTAL CHRG 519,151
38 RENTS - COMMON .432,563
38 Rents - Non Common .,25
40 MCI FOGWIRE REVENUE 3,347,013
.
41 TOTAL Biled 1,718,48'30,70i 0.069C
42 Total Unbiled Rev.(See Instr. 6)~C .C -0.051€
43 TOTAL 52,709,52 3,642,519,120 1,718,48f 30,67.0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.21
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) . An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
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 "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue accunt, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the 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 entres in column (d) for the special schdule should denote the duplication in number of reported
customes.
4. The average number of customers should be the number of bils rendered during the year dMded by the number of biling 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 estmated additional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
IUne Numoer ana ime 01 Kate scneauie Mvvn ~oia Kevenue Average Numoer ~vvn. Of ;;aies ~~~wis~~erNo.(a)(b)(c)of C~~)omers Per r~stomer
(f)
1 Rent Revenue - Subleases 333,190
2 RENT REVENUE-HYDRO 28,543
3 RENT REV-TRASMISS 224,663
4 RENT REV-DISTRIBUT 35,364
5 RENT REV-GEN(COMM)61,259
6 Joint use 4,382,214
7 UTAH .
8 08CFR00056-MTH EQUIP RENT 33
9 08CFR00058-MTH EQUIP LEAS 709,502
10 08INVCHGON-INVEST MNT CHG 4,682
11 08INVCHGOR-INVEST MNT CHG 301
12 08LOOP014N-TEMP SERV CONN -4,067
13 08POLEOO04-POLE ATT ACHMEN 2,004
14 08POLE0075-STEEL POLES US 64,248 .
15 08XTRN0013-RNT/LSE L& PRO 75,184
16 RENTS - COMMON -19,690
17 Rents - Non Common 12,288
18 RENT REVENUE-STEAM 94,94~
19 RENT REVENUE-HYDRO 134,964
20 RENT REV-TRANSMISS 746,163
21 RENT REV-DISTRIBUT 484,488
22 RENT REV-GEN(COMM)8,607
23 Rent Revenue - Subleases 2,441,325
24 Joint use 1,971,364
25 WASHINGTON
26 02CFR00001-MTH FACILITY S 2,104
27 02CFROO06-MTH RNTAL CHRG -14,415
28 RENT REVENUE-HYDRO 633,841
29 RENT REV-DISTRIBUT .15,624
30 RENT REV-GEN(COMM)37,032
31 RENT REV-TRANSMISS 7,263
32 Rent Revenue - Subleases 44,159
33 Joint use 987,309
34 WYOMING
35 05CFR00001-MTH FACILITY S 11,438
36 05CFROOOO6-MTH RNTAL CHRG 2,521
37 RENT REVENUE-STEAM 41,068
38 RENT REVENUE-HYDRO 14,64
39 RENT REV-TRANSMISS 850
40 RENT REV-DISTRIBUT .7,513
..
41 TOTAL Biled 1-~,~1,718,481 30,70 0.069C
42 Total Unbiled Rev.(See Instr. 6)-0.05H
43 TOTAL 52,709,52 3,642,519,120 1,718,48~30,67 0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.22
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) AnOriginal (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/14/2010
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, Listthe 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 divided by the number of biling 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 biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue account subheading...
¡Line Numoer ana Ilte or Kate scneauie Mwn :soia Kevenue Average Numoer Kwaor:saies ~~n~e-,:.er
No.of cu(~)omers Per r~stomer hold
(a)(b)(c)(f)
1 Rent Revenue - Subleases 18,070
2 Joint use 347,572
3 09LOOP0214-MTH FEE PRE-AS 180 .
4 09POLE0075-8TEEL POLES US 20,128
5 RENT REVENUE-STEAM 5,453
6 Joint Use 5,193
7 .
8 TOTAL RENT FROM ELEC PROP 19,158,931
9 ...
10 OTHER ELEC ESTIMATE .--375,040
11 RENEWABLE ENERGY CREDIT 50,793,765
12 NON-WHEELING SYSTEM 9,622,751
13 Other Elec (exclud Wheel)7,262,676
14 CALIFORNIA
15 DSM REV-CA SBC OFF -1,097,786
16 Fish, Wildlife, Recr 6,669
17 IDAHO
18 DSM REV-ID SBC 5,010,486 .
19 Other Elec (exclud Wheel)123
20 OREGON
21 3RD PARTY TRANS 423,133
22 DSM REVENUE - OREGON ECC 8,579,678 .
23 Other Elec (exclud Wheel)2,248,385
24 Other Elec DSR carr chrg 317,738
25 01XTRN0011-SALE ORDERS (I 3,775
26 UTAH
27 ELEC INC-OTHR 81,577
28 FL YASH SALES 2,198,373
29 DSM REV-UT SBC OFFSET 36,046,587
30 Fish, Wildlife, Recr 2,280
31 08XTRN0011-SALE ORDERS (I 21,288
32 M&S INVENTORY REVENUE 965,154
33 WASHINGTON
34 Fish, Wildlife, Recr 3,356
35 Wash Colstrip 3 -52,188
36 WYOMING
37 FL YASH SALES 1,020,891
38 WY Regulatory Recovery Fee ,200,015
3~DSM REVENUE - WY SBC - CAT 1 468,221
40 DSM REVENUE - WY SBC - CAT 2 230,731
41 TOTAL Billed 1,718,8!30,70 0.069(
42 Total Unbiled Rev.(See Instr. 6)~('(-0.05H
43 TOTAL 52,709,52 3,642,519,120 1,718,48E 30,67.0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.23
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
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 "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue accunt, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue accont classification (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 bils 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 Ilaving 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 applicale revenue account subheading.
I Line Numoer ana Ilte or Kate scneaUie Mvvn ;:010 Kevenue Average Numoer 'Swn. or :;aies ~~~'s~lderNo.(a)(b)(c)of C~~)omers Per y~stomer
(f)
1 DSM REVENUE - WY SBC - CAT 3 97,384 .
2 Other Elec (exclud Whèel)-:2
3 FL YASH SALES 19,604
4 DSM REVENUE - WY SBC - CAT 1 214,311
5 DSM REVENUE - WY SBC - CAT 2 125,656
6 DSM REVENUE - WY SBC - CAT 3 266,792
7 05XTRN0011 - SALES ORDERS INV 825
8 TOTAL OTHER ELEC REVENUE 124,707,208
9
10
11
12 --
13
14
15
16
17
18
19
21:
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Biled 1,718,481 30,70 0.069(
42 Total Unbiled Rev.(See Instr. 6)I :!((-0.0511
43 TOTAL 52,709,52 3,642,519,12 1,718,48f 30,67~0.0691
FERC FORM NO.1 (ED. 12-95)Page 304.24
.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp '2) A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA
¡Schedule Page: 304 Line No.: 41 Column: b
The following table is a reconciliation of the biled and unbilled MW for the year 2009.
MWh
Total biled in 2009
12/31/2008 unbiled MW reversal
Total MW eared and biled in 2009
52,769,514
(3,440,267)
49,329,247
12/31/2009 unbiled MW accrual 3.380,278
Total MW (unbiled and biled) in 2009 52,709,525
ISchedule Page: 304 Line No.: 41 Column: c
The following table is a reconciliation of the biled and unbiled revenue for the year 2009.
Revenue
Total biled in 2009
12/31/2008 unbiled revenue reversal
Total revenue earned and biled in 2009
$3,639,426,120
(210,896,000)
3,428,530,120
12/31/2009 unbiled revenue accrual 213,989,000
Total revenue (unbiled and biled) in 2009 $3,642,519,120
ISchedule Page: 304 Line No.: 42 Column: c
For fuer discussion on unbiled revenue refer to page 300, Electrc Operating Revenues, line 12, colum (b).
I FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This ~ort Is:Date of Report .Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2)ñA Resubmission 04/14/2010
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for .
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation 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 suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less .i1
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 relfability 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.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Glassifi-Schedule or Monthly illng Avera~e Averaß6catiTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Requirement Sales
2 Brigham City RQ T-12 19 18 17
3 Deaver, Town of RQ T-4 0.2 0.1 0.1
4 Helpe City RQ T-6 1 1 0.9~:~T-6 0.7 0.6 0.6
T-6 0.2 0.2 0.27 RQ T-6 1 1 1
8 Portland General Electric Company RQ 147 NA NA NA
9 Price City RQ T-12 13 12 11
10 Accrual True-up ..RQ NA NA NA NA
11
12 Nonrequirement Sales
13 Anaheim, City of SF WSPP NA NA NA
14 Arzona Public Service Company T-12 . NA NJl NA
Subtotal RQ 0 0 0
Subtotal non-RQ (0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310
Name of Respondent This ~ort Is:Date .of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
SALES FOR RESALE (Account 447) (Continued)
OS.Jor other service. use this category only for those services whichcannot 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 0
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 Lónger) 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 service, enter NA in columns (d), (e) ahd (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non.RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal- Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
1
101.762 1.833.836 2.102.756 3,936,592 2
1.038 15.767 18.640 34,407 3
7,973 115.285 110.781 288,196 4
3,702 72.092 65.508 137.600 5
1.165 20.762 20.292 41,054 6
8,181 126.713 142.507 269.220 7
11,327 1.003.932 1,013.358 8
73,238 1.233.188 1,499.326 2.732,514 9
-2,778 -100,300 10.
.11
12
2,400 75.560 -,75.560 13
190 ....17.980 14
205,608 3,417.643 4.963,742 .-28.744 8,352,641
12.143,453 27,530,851 966,262,430 -358,824,765 634,968,S16
12,349,061 30,94,494 971,226,172 -358,853,509 643,321,157
FERC FORM NO.1 (ED. 12.90)Page 311
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010 .
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 affliation 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 reliabiliy 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" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under advers conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service 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 contrct.
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 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.
Line Name of Company or Public Authority Statistica FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schule or Monthly iUing Avera~Avera~cation Tari Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Arizona Public Service Company SF T-12 NA NA NA
2 Avista Corpration SF T-13 NA NA NA
3 Avista Corporation SF WSPP NA NA NA
4 BP Energy Company WSPP NA NJ!NA
5 BP Energy Company SF WSPP NA .NJ!NA
6 Barclays Bank PLC T-12 NA NJ!NA
7 Barclays Bank PLC SF T-12 NJ!NA NA
8 Basin Electric Power Cooperative T-11 NJ!NJ!NA
9 Basin Electric Power Cooperative SF T-11 NJ!NJ!NA
10 Basin Electric Power Cooperative SF WSPP NA NA NA
11 Black Hils Power, Inc.441 50 50 41
12 Black Hils Power, Inc.WSPP NA NA NA
13 Black Hils Power, Inc.SF WSPP NA NA NA
14 Bonnevile Power Adminisation T-13 NA NA NA
Subtotal RQ C 0 0
Subtotal non-RQ C 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.1
Name of Respondent This (l0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/1412010
.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 servícefrom 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 atline number one. After listing all RQ sales, enter "Subtotal- RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through ,(k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (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 oil bils rendered to the purchaser.
8. Repor demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k),the total charge shown on bils rendered to the purchaser.
. 9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The .Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The .Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)u)(k)
93,193 2,590,803 2,590,80:3 1
69 2,120 2.
74,299 2,353,049 2,353,049 3
440 "17,932 4
225,424 11,817,291 11,817,291 5
467 39,550 6
1,471,517 94,724,053 94,724,053 7
816 28,663 8
1,178 31,427 9
33,415 1,222,031 1,222,031 10
358,074 6,212,723 5,652,158 11,864,881 11
19,298 593,945 593,945 12
36,447 1,548,181 1,548,181 13
-8 14
205,608 3,417,643 4,963,742 -28,744 8,352,641
12,143,453 27,530,851 966,262,430 -358,824,765 634,968,516
12,349,061 30,948,494 971,226,172 -358,853,509 64,321,157
FERC FORM NO.1 (ED. 12-90)Page 311.1
Name of Respondent ThiS~rIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Oriinal (Mo, Da, Yr)End of 2009/Q4
(2) A Resubmission 04/14/2010
SALES FOR RESALE (Account 4'7)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions 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 thè
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 affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under 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 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 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.
Line Name of Company or Public Authority Statistica FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliatis)Classifi-Schedule or Monthly illng . t'vera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)
.
(c)(d)(e)(f)
1 BonneviHe Power Administration 368 N,I N,I NA
2 Bonnevile Power Administration T-11 NJI NJI NA
3 BonneviUe Power Administration T-12 NJI NJI NA
4 Bonnevile Power Administraton T-13 NJI NJI NA
5 BonneviUe Power Admiistration SF WSPP NJI NJI NA
6 SF T-13 NJI NJI NA
7 Burbank, City of SF WSPP NJI NJI NA
8 California Indepen System Operator T-12 NA NA NA
9 California Independent System Operator SF T-12 N,I NJI NA
10 Cargil Power Markets, LLC T-12 NA NA NA
11 Cargil Power Markets, LLC T-12 NA NA NA
12 Cargil Powe Markets, LLC SF T-11 NA NA NA
rF
T-12 NA NA NA14 SF T-13 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0.
FERC FORM NO.1 (ED. 12-90)Page 310.2
This ~ort Is: Date of Report
(1) IlAn Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
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 0
the service in a footnote.
AD - for Out-of-period adjustment. Use this code far 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 - Ron 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 types of service, enterNA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, inclúding
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RO grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges (h+i+j)No.
($)($)
(g)(h)(i)(k)
2,030 62,677 1
3,109 98,345 2
32,961 2,068,632 2,068,632 3
73 1,896 4
150,204 5,047,995 5,047,995 5
47 1,043 6
17,248 556,250 556,250 7
720 -526,130 8
491,019 14,587,376 14,587,376 9
801 42,393 10
50 3,900 3,900 11
9,126 245,134 12
1,466,084 49,668,637 49,669,637 13
2 55 14
205,608
12,143,453
12,349,061
3,417,643
27,530,851
30,948,494
4,963,742
966,262,430
971,226,172
-28,744
-358,824,765
-358,853,509
8,352,641
634,968,516
64,321,157
FERC FORM NO.1 (EO. 12-90)Page 311.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
SALES. FOR RESALE (Accunt 4'7).
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation 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 inits system resource 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" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and 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.
Line Name of Company or Public Authority Statistical FERC Rate Ave~Actal Demand (MW)
No.(Footnote Affliations)Classifi-SCule or Monthly illng t'vera~e Avera~
cation Tari Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Citigroup Energy, Inc.T-12 NA NJI NA
2 Citigroup Energy, Inc.SF T-11 NA NJI NA
3 Citigroup Energy, Inc.SF T-12 NA NJI NA
4 Clatskanie People's Utilty Distric SF WSPP NA NA NA
5 Colorado River Commission of Nevada SF WSPP .NA NJI NA
6 Colorado Springs Utilties SF WSPP NA NA NA
7 Conoco Inc.SF T-12 NA NJI NA
T-12 NA NJI NA
9 Constellation Energy Commodities Group SF T-11 NA NA NA
10 Constellation Energy Commodities Group SF T-11 NA NA ÑA
11 Constellation Energy Commodities Group SF T-12 NA NA NA
12 Credit Suisse Energy LLC T-12 NA NA NA
13 Credit Suisse Energy LLC SF T-12 NA NA NA
14 DB Energy Traing LLC T-12 NA NA NA
Subtotal RQ (0 0
Subtota non-RQ (0 0
Total ~0 0
FERC FORM NO.1 (ED. 12-90)Page 310.3
This ~ort Is: Date of Report
(1) l2An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
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 0
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 numl:er one. After listing all RQ sales, enter "Subtotal - RQ" in
column (å). The remaining sales may then be listed in any order. Enter "Subtotal-NQn-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of 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. Repor demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQJNon-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on. Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2009/Q4
Name of Respondent
PacifiCorp
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges (h+i+j)No.
($)($)
(g)(h)(i)(k)
157 9,598 1
7 185 2
1,047,752 70,879,167 70,879,167 3
2,191 66,862 66,862 4
48,800 1,493,280 1,493,280 5
492 22,611 22,611 6
188,160 6,517,979 6,517,979 7
223 12,341 8
3,678 128,378 9
77 2,840 10
461,195 15,969,630 15,969,630 11
985 72,575 12
972,715 64,525,611 64,525,611 13
6 255 14
205,608
12,143,453
12,349,061
3,417,643
27,530,851
30,948,494
4,963,742
966,262,430
971,226,172
-28,744
-358,824,765
-358,853,509
8,352,641
634,966,516
643,321,157
FERC FORM NO. 1 (ED. 12-90)Page 311.3
Name of Respondent This ø0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) riA Resubmission 04/14/2010
SALES FORirESALE (Accunt 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settement 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 affliation 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 ina 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 Longér. 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.
Line Name of Company or Public Authrity Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly illng Avera~e Avera~cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
~T-12 NA NA NA
WSPP NA NA NA
3 EDF Trading Nort Amerca, LLC SF T-12 NJl .NA NA
4 EI Paso Electric Compay WSPP NJl NJl NA5 EI Paso Electric Company SF.WSPP NJl NJl NA
6 Endure Energy, LLC SF T-11 NJl NA NA
7 Endure Energy, LLC SF WSPP NJl NA NA
8 Eugne Water & Electc Board SF T-11 NJl NA NA
9 Eugene Water & Electric Board .SF WSPP NA NA NA
10 Gila River Power, L.P.SF T-11 NA NA NA
11 Gila River Power, L.P.SF WSPP NA NA NA12 Glendale, City of SF WSPP .NA NA NA~SF T-13 NA NA NA14 Grant County PUD #2 SF WSPP NA NA NA
Subtotal RO 0 0 0
Subttal non-RO 0 0 0
Total ..
000
...
FERC FORM NO.1 (ED. 12-90)Page 310.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
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 schedulès or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8.. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) mustbe subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal- RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
160,598 5,241,436 5,241,436 1
80 2,560 2,560 2
301,590 11,056,072 11,056,072 3
16 60f 4
31,962 1,149,178 1,149,178 5
56 1,807 6
21,181 599,242 599,242 7
271 0 .10,767 8
8,300 284,785 284,785 9
17 585 10
24,941 762,659 762,659 11
35 1,75~1,750 12
36 1,184 13
17,467 564,165 564,165 14
205,608 3,417,643 4,963,742 -28,744 8,352,641
12,143,453 27,530,851 966,262,430 -358,824,765 634,968,516
12;349,061 30,948,494 971,226,172 -358,853,509 643,321,157
FERC FORM NO.1 (ED. 12-90)Page 311.4
Name of Respondent This Report Is:Date of Report Year/Penod of Report
PacifiCorp (1) IKAn Onginal (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
SALES FOR RESALE (Accunt 4.7)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exChanges during the year. Do not report exchanges of electricity ( i.e., transactions 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 affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements service must be the
same as, or second only to, the supplier's 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 seice 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 perid 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.
Line Name of Company or Public Authonty Statistical FERC Rate Avera;Actual Demand (MW)
No.(Footnote Affliations)Classif-Schule or Monthly illing Avera~e Avera~
cation Tari Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)~(c)(d)(e)(f)
1 Hurricane, City of T-12 NA NA NA
2 Iberdrola Renewables, Inc.T-11 NA NA NA
3 Iberdrola Renewables, Inc..T-11 NA NA NA
4 Iberdrola Renewables, Inc..T-12 NA NA NA
5 Idaho Power Company WSPP NA NA NA
6 Idaho Power Company T-11 NA .NA NA
7 Idaho Power Company SF T-11 NA NA NA
8 Idaho Power Compny SF T-13 NA NA NA
9 Idaho Power Company SF WSPP NA NA NA
10 Integrys Energy Services, Inc.SF T-11 NA NA NA
11 Integrys Energy Services, Inc.SF WSPP NA NA NA
12 Intermountain Renewable Power, LLC T-11 NA .-NA NA
13 Intermountain Renewable Power, LlC T-11 NA NA NA
14 J. Aron & Company T-12 NA NA NA
.
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.5
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
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 0
the service in a footnote.
AD ~ for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minutè 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 types of charges, including
out-of-period adjustments, in column ü). Explain in a footnote all components of the amount shown in column ü). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2009/Q4
Name of Respondent
PacifiCorp
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(j)(k)
186 13,950 13,950 1
33 1,105 2
9,660 308,907 3
565,093 18,828,432 18,828,432 4
9 414 5
688 20,686 6
1,772 48,431 7
485 17,455 8
36,770 1,255,554 1,255,554 9
8 305 10
2,000 78,900 78,900 11
219 5,05 12
926 34,053 13
80 9,452 14
205,608
12,143,453
12,349,061
3,417,643
27,530,851
30,948,494
4,963,742
966,262,430
971,226,172
-28,744
-358,824,765
-358,853,509
8,352,641
634,968,516
64,321,157
FERC FORM NO.1 (ED. 12-90)Page 311.5
Name of Respondent This ~ort Is:Date of Reprt Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
SALES FOR RESALE (Accunt 4-7)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( 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 affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for toiig~term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The 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.
..
Line Name of Company or Public Authori Statistical FERC Rate Averaße Actal Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly illng l\vera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Demani Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 J. Aron & Company SF T-12 N,L NA NA
2 J.P. Morgan Ventures Energy Corporation SF T-11 NA NA NA
3 J.P. Morgan Ventures Energy Corporation SF T-12 N,L NA NA
301 N,L NA NA
5 Los Angeles Dept. of Water & Power SF WSPP N,L NA NA
6 Macquari Cook Power Inc.SF T-11 N,L NA NA
~WSPP NA NA NA
WSPP N,L NA NA
9 Moesto Irrigation District SF WSPP NA NA NA
10 Morgan Stanley Capital Group, Inc. .T-12 NA NA NA
11 Morgan Stanley Capital Group, Inc. SF T-11 NA NA NA
12 Morgan Stanley Capital Group, Inc.SF T-12 NA NA NA
13 Municipal Energy Agency of Nebraska SF WSPP NA NA NA
14 Nevada Power Company SF WSPP NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total .
0 00
FERC FORM NO.1 (ED. 12-90)Page 310.6
Name of Respondent This ~ort Is:Date. of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) ¡=A Resubmission 04/14/2010
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 0
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 pnor 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-Ncn-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 tanff 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliets 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 åhdexplain.
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 Q), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
207,579 10,828,769 10,828,769 .1..
2 71 2
315,370 11,468,024 11,468,024 3.
577,331 25,739,038 25,739,038 4
295,242 9,891,247 9,891,247 5
20 6
137,732 4,366,479 4,366,479 7
3,400 77,750 77,750 8
63,722 2,319,751 2,319,751 9
3,628 169,184 10.
5,649 187,308 11
2,209,690 128,070,164 128,136,044 12
9,652 322,522 .322,522 13
60,000 2,641,160 2,641,160 14
205,608 3,417,643 4,963,742 -28,744 8,352,641
12,143,453 27,530,851 966,262,430 -358,824,765 634,968,516.
12,349,061 30,94,49 971,226,172 -358,853,509 64,321,157
FERC FORM NO.1 (ED. 12-90)Page 311.6
Name of Respondent
PacifiCorp
.This ~ort Is:
(1) I2An Original
(2) nA Resubmissi
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of elecricity ( 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 affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service. Requirements servce is servic 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 suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF- for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and 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.
Date of Report
(Mo, Da, Yr)
04/14/2010
Year/Period of Report
End of 2009/Q4
Line
No.
Name of Company or Public Authority
(Footnote Affliations)
Statisticl
Classif
cation
(b)(a)
1 NextEra Energy Power Marketing, LLC
2 NextEra Energy Power Marketing, LLC
3 NorthWestern Energy
4 NorthWestem Energy
5 Northern California Power Agency
6 Northpoint Energy Solutions Inc.
7 PPL EnergyPlus, LLC
8 PPL Montana, LLC
9 Pacifi Gas & Electric Company
14 Portland General Electric Company
SF
SF
SF
SF
SF
SF
SF
SF
FERC Rate
Schedule orTarif Number
(c)
T-11
WSPP
T-13
WSPP
WSPP
WSPP
WSPP
T-11
T-11
WSPP
WSPP
T-12
T-12
T-12
Average
Monthly Billig
Demand (MW)
(d)
Actual Demand (MW)
. ..verage Average
Monthly NCP Deman Monthly CPlJemand(e) (f)
NA
NJl
NJl
NJl
NJl
NJl
NJl
NJl
NJl
NA
NA
NA
NA
NA
Nfl
Nfl
Nfl
Nfl
Nfl
Nfl
Nfl
Nfl
NJl
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Subtotal RQ
Subtotal non-RQ c
o
o
oTotal
o o
o
oo
FERC FORM NO.1 (ED. 12-90)Page 310.7
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
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 0
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or ntrue-ups" for service provided in pnor 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-RQn in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of 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 renclered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-penod adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
MegaWatt Hours REVENUE Total ($)Line
Sold Demand. Charges Energy Charges (h+i+j)No.
($)($)
(g)(h)(i)(k)
288 12,164 1
76,055 2,905,590 2,905,590 2
167 5,123 3
1,647 65,530 65,530 4
5,261 198,723 198,723 5
28,638 1,023,674 1,023,674 6
83,389 2,575,245 2,575,245 7
453 15,794 8
6 208 9
238,823 10,316,353 10,316,353 10
2,325 68,050 68,050 11
18 983 12
94,525 4,064,323 13
11 363 14
205,608
12,143,453
12,349,061
3,417,643
27,530,851
30,948,494
4,963,742
966,262,430
971,226,172
-28,744
-358,824,765
-358,853,509
8,352,641
634,968,516
643,321,157
FERC FORM NO.1 (ED. 12-90)Page 311.7
Name of Respondent This 180rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2oo9/Q4
(2) r=A Resubmission 04/14/2010
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 affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions ofthe 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 adver conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF . for intermediate-term firm service. The same as LF servce except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Ave~Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly i11i l\vera~e Avera~
cation Tari Numbe Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Portland General Electric Company SF T-11 NA NA NA
2 Portland General Electnc Company SF T-12 NA NA NA
3 Portland General Electnc Company SF T-13 NA NA NA
4 Powerex Corporation lI WSPP ..NA NA NA
5 Powerex Corporation T-11 NA NA NA
6 Powerex Corpration T-11 NA NA NA
7 Powerex Corpration
.-
WSPP NA NA NA
8 Public Servce Company of Colorado 320 NA NA NA
9 Public Service Company of Colorado WSPP NA NA NA
10 Public Service Company of Colorado 320 107 101 84
11 Public Service Company of Colorado SF T-11 NA NA NA
12 Public Service Company of Colorado ..WSPP NA NA NA
13 Public Service Company of New Mexico WSPP . NA NA NA
14 Public Service Company of New Mexico SF WSPP NA NA NA
Subtotal RQ 0 0 0
Subtotl non-RQ a 0 0.
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.8
This ~ort Is: Date of Report
(1) llAn Onginal (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
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 0
the service in a footnote.
AD - for Out-tif-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
yeàrs. Provide an explanation ina 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). Theremaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate scheduleS or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in cólumn (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawCltt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges (h+i+j)No.
($)($)
(g)(h)(i)(k)
19 783 1
153,727 6,499,591 6,499,591 2
125 4,811 3
190 17,445 4
17,339 527,349 5
12,345 378,505 6
911,432 25,956,721 25,956,721 7
-1,471,182 8
1,462 79,952 9
700,179 14,367,960 34,658,860 49,026,820 10
1,522 34,234 11
91,502 2,707,206 12
3,000 13
118,977 3,880,082 3,880,082 14
205,608
12,143,453
12,349,061
3,417,643
27,530,851
30,948,494
4,963,742
966,262,430
971,226,172
-28,744
-358,824,765
-358,853,509
8,352,641
634,968,516
64,321,157
FERC FORM NO.1 (ED. 12-90)Page 311.8
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation 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 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 which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less ..
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the 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.
Line Name of Company or Public Authority Staisticl FERC Rate Ave~e Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or MonthlY iIing t\vera~e Aver~cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Puget Sound Energy,lnc.SF T-13 Nfl NA NA
2 Puget Sound Energy, Inc.SF WSPP Nfl NJl NA
3 Rainbow Energy Marketing Corpration SF T-11 Nfl NJl NA
4 Rainbow Energy Marketing Corporation SF WSPP NA NJl NA
5 Raser Power Systems, LLC SF T-11 Nfl NA NA
6 Redding, City of SF WSPP Nfl NA NA
7 Riverside, City of SF WSPP NJl NJl NA
8 Sacramento Municipal Utilty District .250 Nfl NA NA
9 Sacramento Municipal Utilty District WSPP NA NA NA
10 Sacramento Municipal Utilty District 250 NA NA NA
11 Sacramento Municipal Utilty District T-13 NA NA NA
12 Sacramento Municipal Utility District .WSPP NA NA NA
13 Salt River Project WSPP NA NA NA
14 Salt River Project WSPP NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ C 0 0
...Total 0 0 0
. .
FERC FORM NO.1 (ED. 12-90)Page 310.9
This ~ort Is:
(1) ~An Original
(2) A Resubmission
SALES FOR RESALE (Account 447)
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 0
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minuteiiitegration) 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 types of charges; including
out-af-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.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/14/2010
Year/Period of Report
End of 2009/Q4
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
32 1,119 1
185,580 5,754,449 2
2,421 73,600 3
84,210 2,606,038 4
35 761 5
3,361 119,056 6
1,440 56,160 7
-1,208 258,776 8
1,208 71,816 9
564,109 12,833,480 10
5 214 11
162,47 5,764,953 12
63 1,641 13
219,000 6,690,484 6,690,484 14
205,608
12,143,453
12,349,061
3,417,643
27,530,851
30,948,494
4,963,742
966,262,430
971,226,172
-28,744
-358,824,765
-358,853,509
8,352,641
634,968,516
643,321,157
FERC FORM NO.1 (ED. 12-90)Page 311.9
Name of Respondent This Re ort Is:Date of Report Year/Period of Report
PacifiCorp (1) ~An Original (Mo, Da, Yr)End of 2009/Q4
..(2)A Resubmisson 04/14/2010
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 exchànges 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 affliation the respondent has with the purchaser.
3. In column (b), enter à 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 suppliets service to its own ultimate consumers.
LF - för tong-term 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 mustattempt 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 reliabilty of
service, aside from transmission constraints, must match the availabilit and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera;Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly illng Av~e Avera~
cation Tari Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Salt River Project SF T-11 NA NA NA
2 Salt River Project SF WSPP NA NA NA
3 San Diego Gas & Elecic Company SF WSPP NA NA NA
4 Santa Clara, City of SF WSPP NA NA NA
5 Seattle Cit Light T-11 .NA NA NA
6 Seattle City Light SF T-13 NA NA NA
7 Seattle City Ligt SF WSPP NA NA NA
8 Sempra Energ Solutions, LLC SF WSPP NA NA NA
9 Sempra Energy Trading LLC i-T-12 NA NA NA
10 Sempra Energy Trading LLC T-12 NA NA NA
11 Sempra Generation ..T-12 NA NA NA
12 Shell Energy North America (US), L.P.WSPP NA NA NA
13 Shell Energy North America (US), L.P.SF T-11 NA NA NA
14 SheD Energy North America (US), L.P.SF WSPP NA NA NA
Subtotal RQ C 0 0
Subtotal non-RQ C 0 0
Total Ð 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.10
Name of Respondent This 780rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nAResubmission 04/14/2010
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 0
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 - RQn in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maXimum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (6D-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 spown on bils rendered to the purchaser. .
8. Report demand charges in column (h), energy charges in column (i), and the total of a.ny other types of charges, including
out-of-period adjustments, in column 0).Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g)through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges ~(h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
695 15,302 1
48,303 1,345,628 1,345,628 2
454,678 16,217,612 16,217,612 3
2,685 82,525 82,525 4
281 "00'54~9,306 5
9 311 6
35,735 1,003,545 7
5,864 157'6~~157,65€8
24 2,003 9
1,372,078 74,249,459 74,249,459 10
2,240 61'90~61,900 11
100 4,200 12
.198 7,063 13
1,101,172 52,884,326 52,884,326 14
205,608 3,417,643 4,963,742 "28,744 8,352,641
12,143,453 27,530,851 966,262,430 -358,824,765 634,9GS,516
12,349,061 30,948,494 971,226,172 -358,853,509 643,321,157
FERC FORM NO.1 (ED. 12-90)Page 311.10
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
SALES FOR RESALE (Accunt 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 affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements ser\ice 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 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.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schule or Monthly iIing t'vera~e Averaf¥
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)
.-
(c)(d)(e)(f)
1 Sierra Pacific Power Company 258 NA NA NA
2 Sierra Pacific Power Company 258 75 75 75
3 Sierra Pacific Power Company T.11 NA NA NA
4 Sierra Pacific Power Company T-11 NA NA NA5~SF T-13 NA NA NA6 W SF WSPP NA NA NA
7 Southern California Edison Company SF T-12 NA NA NA8 fF WSPP NA NA NA9 SF WSPP NA NA NA10 Tacoma, Cit of SF WSPP NA NA NA
11 The Energy Authority SF T-11 NA NA NA
12 The Energy Authority SF WSPP NA NA NA
13 TransAlta Energy Marketing Inc.T-12 NA NA NA
14 TransAlta Energy Marketing Inc.T-12 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.11
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) . OA Resubmission 04/14/2010
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 01
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 types of service, enter NA În columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
~194,965 1
74,340 2,521,500 3,065,782 5,587,282 2
884 27,375 3
246 10,797 4
344 12,396 5
53,805 2,976,238 2,976,238 6
129,029 4,609,129 4,609,129 7
7,250 219,500 . .~219,500 8
600 27,092 27,092 9
2,100 61,375 61,375 10
18 11
22,965 734,520 734,520 12
11 1,83 13
1,315,190 .48,195,982 48,195,982 14
205,608 3,417,643 4,963,742 -28,744 8,352,641
12,143,453 27,530,851 966,262,430 -358,824,765 634,968,516
12,349,061 30,948,494 971,226,172 -358,853,509 643,321,157
FERC FORM NO.1 (ED. 12-90)Page 311.11
Name of Respondent Thi5~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
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 thePurchased Power schedule (Page 326-327).
2. Enter the name of th purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code base 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 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 reliability of
service, aside from transmission constraints, must match the availabilty and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly iIing . lwera~e Avera~cation Tari Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 TransAlta Energy Marketing Inc.SF T-11 NA NA NA
2 TransAlta Energy Marketing Inc.SF T-12 NA NA NA
3 TransCanada Energy Sales Ltd.SF WSPP NA NA NA~SF T-11 NA NA NA
5 Tri-State Generation & Transmission SF WSPP 0.7 .0.7 0.1
6 Tucson Electric Power Company SF WSPP NA NA NA
7 Turlock Irrgation District SF T-13 NA NA NA
8 Turlock Irrigation Distri SF WSPP NA NA NA
9 UBS Warburg Energy LLC ~T-12 NA NA NA
10 UBS Warburg Energy LLC T-12 NA NA NA
11 UNS Electric, Inc.,.WSPP NA NA NA
12 Utah Associated Municipal Power Systems WSPP NA NA NA
13 Utah Associated Municipal Power Systems SF T-11 NA NA NA
14 Uta ASSOCiated Municipal Power Systems SF WSPP NA NA NA
Subtotal RQ C 0 0
Subtotl non-RQ C 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.12
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) l.An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
SALES FOR RESALE Accunt 447 Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature 0
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. . For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average.monthly coincident peak (CP) .
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). MonthlyNCP 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 types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required datå.
Year/Period of Report
End of 2009/Q4
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
440 15,075 1
271,045 8,605,025 8,611,788 2
1,960 88,800 88,800 3
639 17,068 4
121,877 32,468 4,088,869 4,121,337 5
196,173 6,022,201 6,022,201 6
1 33 7
28,540 933,695 933,695 8
15 820 9
138,575 9,796,612 9,796,612 10
156,825 4,194,337 4,194,337 11
15,994 639,760 639,760 12
4 142 13
1,17Q 41,345 41,345 14
205,608
12,143,453
12,349,061
3,417,643
27,530,851
30,948,494
4,963,742
966,262,430
971,226,172
-28,744
-358,824,765
8,352,641
634,968,516
-358,853,509 64,321,157
FERC FORM NO.1 (ED. 12-90)Page 311.12
Name of Respondent This î80rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
SALES FOR RESALE (Account 447).
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for.imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. .Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b),. enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, thesuppliets 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 eárliest 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 "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 fie years or Longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera;Actal Demand (MW)
No.(Footnote Affliations)Classif-Scedule or Monthly . lin .i.wera~e Aver~
cation Tari Number Demand (MW)Monthly NC Deman Monthly C . emand
(a)(b)(c)(d)(e)(f)
1 Utah Municipal Power Agency 433 34 34 34
2 Utah Municipal Power Agency SF T-3 Nfl Nfl NA
3 Western Area Power Administration SF T-11 Nfl Nfl NA
4 Westem Area Power Administration SF WSPP Nfl Nfl NA
5 Test Generation NA Nfl Nfl NA
6 Bookout Sales AD NA Nfl Nfl NA
7 Trade Sales AD NA Nfl Nfl NA
8 ACcrual True-up NA NA N)i N)l NA
9
10
11
12
13
14
Subtotal RQ 0 0 0
Subtotal non-RQ (J 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.13
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1 )!KAn Original (Mo, Da, Yr)End of 2009/Q4
(2)DA Resubmission 04/14/2010
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 accunting 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 cOILJmn (a) after this Listing. Enter .Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliets 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 hi colurTn (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
204,722 4,396,200 4,757,739 9,153,939 1
16,035 532,769 532,769 2
2,722 89,496 3
129,142 4,375,853 4,375,853 4
-8,553 -212,166 5
-9,811,672 -314,938,843 6
45,464,949 7
-6,770 575,818 8
9
10
11
12
13
14
205,608 3,417,643 4,963,742 -28,744 8,352,641
12,143,453 27,530,851"966,262,430 -358,824,765 634,968,516
12,349,061 30,948,494 971,226,172 -358,853,509 64,321,157
FERC FORM NO.1 (ED. 12.90)Page 311.13
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
!Schedule Page: 310 Line No.: 4 Column:j
Settlement Adjustment.
!Schedule Page: 310 Line No.: 6 Column: a
Com lete name is Navajo Tribal Utilty Authority (Mexican Hat).
chedule Page: 310 Line No.: 7 Column: a
Complete name is Navajo Tribal Utility Authority (Red Mesa).
ISchedule Page: 310 Line No.: 8 Column: j
Settlement Adjustment.
'$chedule Page: 310 Line No.: 10 Column: j I
Represents the differerice between actual requirement sales revenues for the period as reflected on the individual line items within this
schedule, and the accruals charged to account 447 during the period.
'$chedule Page: 310 Line No.: 14 Column: b
Settlement Adjustment.
'$chedule Page: 310 Line No.: 14 Column: j
Settlement Adjustment.
'$chedule Page: 310.1 Line No.: 2 Column: j
Reserve Share.
'$chedule Page: 310.1 Line No.: 4 Column: b
Settlement Adjustment.
'$chedule Page: 310.1 Line No.: 4 Column: j
Settlement Adjustment.
'$chedule Page: 310.1 Line No.: 6 Column: b
Settlement Adjustment.
'$chedule Page: 310.1 Line No.: 6 Column: j
Settlement Adjustment.
'$chedule Page: 310.1 Line No.: 8 Column: b
Basin Electric Power Company - FERC T-ll (Evergreen Network Transmission serice under the Ope Access Transmission Tarff
(S.A. 228 & 233)) - Contract termation date: 12 months notification.
'$chedule Page: 310.1 Line No.: 8 Column: j
Transmission Losses.
'$chedule Page: 310.1 Line No.: 9 Column: j
Transmission Losses.
'$chedule Page: 310.1 Line No.: 11 Column: b
Black Hils Power & Light Company - FERC 441 - Contract termination date: December 31,2023.
'$chedule Page: 310.1 Line No.: 12 Column: b
Seconda, Economy and/or non-fir sales, including some hourly fir transactions.
¡Schedule Page: 310.1 Line No.: 14 Column: b
Settlement Adjustment.
'$chedule Page: 310.1 Line No.: 14 Column: j
Settlement Adjustment.
lSchedule Page: 310.2 Line No.: 1 Column: b
Bonnevile Power Administration - FERC 368 (Use of Facilities Agrement for the Malin Trasformer under the AC Interte
Agreement with BPA)~ Contrct termination date: Upon mutul agreement.
'$chedule Page: 310.2 Line No.: 1 Column: j
Transmission Losses.
lSchedule Page: 310.2 Line No.: 2 . Column: bBonnevile Power Admstration - FERC T -11 (Point-to-Point Trasmission Seice under the Open Access Transmission Tarff
(S.A. 179)) - Contract termation date: September 30, 2025.
lSchedule Page: 310.2 Line No.: 2 Column: jTrasmission Losses.
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)
PacifCorp I (2) A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA.
I$chedule Page: 310.2 Line No.: 3 Column: b
Bonnevile Power Administration - FERC T -12 - Contract termination date: April 22, 2024.
!Šchedule Page: 310.2 Line No.: 4 Column: j
Reserve Share.
I§chedule Page: 310.2 Line No.: 6 Column: a
Com lete name is British Columbia Trasmission Co oration.
chedule Pa e: 310.2 Line No.: 6 Column:'
Reserve Share.
I§chedule Page: 310.2 Line No.: 8 Column: b
Settlement Adjustment.
I§chedule Page: 310.2 Line No.: 8 Column: j
Settlement Adjustment.
I§chedule Page: 310.2 Line No.: 10 Column: b
Settlement Adjustment.
I§chedule Page: 310.2 Line No.: 10 Column: j
Settlement Adjustment.
I§chedule Page: 310.2 Line No.: 11 Column: b
Seconda, Economy and/or non-firm sales, including some hourly firm trsactions.
I§chedule Page: 310.2 Line No.: 12 Column:j
Trasmission Losses.
I§chedule Page: 310.2 Line No.: 13 Column:j
Pond Sale.
¡Schedule Page: 310.2 Line No.: 14 Column: a
Complete name is Public Utility Distrct NO.1 of Chelan COUl
Schedule Page: 310.2 Line No.: 14 Column: j
Reserve Share.
I§chedule Page: 310.3 Line No.: 1 Column: b
Settlement Adjustment.
I§chedule Page: 310.3 Line No.: 1 Column: j
Settlement Adjutment.
I§chedule Page: 310.3 Line No.: 2 Column: j
Trasmission Losses.
I§chedule Page: 310.3 Line No.: 8 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "CONSTELLATION ENERGY COMMODITIES GROUP" ON
PAGES 310-310.13:
Complete name is Constellation Energy Commodities Group, Inc.
¡Schedule Page: 310.3 Line No.: 8 Column: b
Settlement Ad' ustment.
chedule Page: 310.3 Line No.: 8 Column: j
Setement Adjustment.
I§chedule Page: 310.3 Line No.: 9 Column: j
Transmission Losses.
I§chedule Page: 310.3 Line No.: 10 Column: j
Unauthorized use charges.
I§chedule Page: 310.3 Line No.: 12 Column: b
Settlement Adjustment.
I§chedule Page: 310.3 Line No.: 12 Column: j
Settlement Adjustment.
I§chedule Page: 310.3 Line No.: 14 Column: b
Settlement Adjustment.
I§chedule Page: 310.3 Line No.: 14 Column: j
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 1(2) . A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
...
Settlement Adjustment.
~chedule Page: 310.4 Line No.: 2 Column: a
Com lete name is Public Utili Distrct No.1 ofDou las Coun
chedule Pa e: 310.4 Line No.: 4 Column: b
Settlement Adjustment.
~chedule Page: 310.4 Line No.: 4 Column:)
Settlement Adjustment.
~chedule Page: 310.4 Line No.: 6 Column:)
Transmission Losses.
~chedule Page: 310.4 Line No.: B Column:)
Trasmission Losses.
~chedule Page: 310.4 Line No.: 10 Column:)
Transmission Losses.
~chedule Page: 310.4 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "GRANT COUNTY PUD #2" ON PAGES 310-310.13:
Complete name is Public Utility Distrct NO.2 of Grat County.
~chedule Page: 310.4 Line No.: 13 Column:)
Reserve Share.
~chedule Page: 310.5 Line No.: 1 Column: b
Hurcane, City of - FERC T-12 - Contrt termnation date: August 31, 2007.~chedule Page: 310.5 Line No.: 2 Column: b I
Iberdola Renewab1es, Inc. - FERC T -11 (Point-to-Point Transmission Serice under the Open Access Transmission Tariff (S.A. 279))
- Contract termination date: April 30, 2009.
~chedule Page: 310.5 Line No.: 2 Column:)
Transmission Losses.
~chedule Page: 310.5 Line No.: 3 Column:)
Transmission Losses.
~chedule Page: 310.5 Line No.: 5 Column: b
Settlement Adjustment.
~chedule Page: 310.5 Line No.: 5 Column:)
Settlement Adjustment.
~chedule Page: 310.5 Line No.: 6 Column: b
Idaho Power Company - FERC T -11 (Point-to-Point Trasmission Service under the Open Access Trasmission Tariff (S.A. 212)) -
Contract termination date: May 31, 2012.
~chedule Page: 310.5 Line No.: 6 Column:)
Transmission Losses.
~chedule Page: 310.5 Line No.: 7 Column:)
Transmission Losses.
~chedule Page: 310.5 Line No.: B Column:)
Resere Share.
¡Schedule Page: 310.5 Line No.: 10 Column:)
Transmission Losses.
~cheduie Page: 310.5 Line No.: 12 Column: b
Intermountain Renewable Power, LLC - FERC T-1 i (Point-to-Point Trasmission Service under the Open Access Trasmission
Tarff (SA 509)) - Contrct termation date: Apri 30, 2029.
~chedule Page: 310.5 Line No.: 12 Column:)
Transmission Losses.
~chedule Page: 310.5 Line No.: 13 Column: b
Intermountain Renewable Power, LLC - FERC T-11 (Point-to-Point Transmission Service under the Open Access Trasmission
Tariff (S.A. 509)) - Contrct termation date: Apri130, 2029.
~chedule Page: 310.5 Line No.: 13 Column:)
I FERC FORM NO. 1 (ED. 12-87) Page 450.3
C.
Name of Respondent ""This Report is:Date. of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 20091Q4
..FOOTNOTE DATA
Unauthorized use charges.
¡Schedule Page: 310.5 Line No.: 14 Column: b
Settlement Adjustment.
I$chedule Page: 310.5 Line No.: 14 Column: j
Settlement Adjustment.
¡Schedule Page: 310.6 Line No.: 2 Column: j
Transmission Losses.
I$chedule Page: 310.6 Line No.: 4 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "LOS ANGELES DEPT. OF WATER & POWER" ON PAGES
310-310.13:
Complete name is Los Angeles Departent of Water and Power.
¡Schedule Page: 310.6 Line No.: 4 Column: b
Los Angeles Deparent of Water and Power - FERC 301 - Contract termination date: June 15,2027.
I$chedule Page: 310.6 Line No.: 6 Column: j
Transmission Losses.
I$chedule Page: 310.6 Line No.: 8 . Column: a
Complete name is Metropolitan Water Distrct of Southern California.
I$chedule Page: 310.6 Line No.: 10 Column: b
Settlement Adjustment.
I$chedule Page: 310.6 Line No.: 10 Column: j
Settlement Adjustment.
I$chedule Page: 310.6 Line No.: 11 Column:j
Trasmission Losses.
I$chedule Page: 310.6 Line No.: 12 Column: j
Liquidated Damages.
I$chedule Page: 310.7 Line No.: ., Column: b
NextEra Energy Power Marketing, LLC - FERC T -11 (Point-to-Point Transmission Service under the Open Access Transmission
Tariff (S.A. 626)) - Contract termnation date: December 31, 2011.
I$chedule Page: 310.7 Line No.: 1 Column:j
Transmission Losses.
¡Schedule Page: 310.7 Line No.: 3 Column: j
Reserve Share.
I$chedule page: 310.7 Line No.: 8 Column: j
Transmission Losses.
I$chedule Page: 310.7 Line No.: 9 Column:j
Transmission Losses.
I$chedulePage: 310.7 Line No.: 11 Column: a
Complete name is Pacific Northwest Generating Cooperative.
¡Schedule Page: 310.7 Line No.: 12 Column: b
Settlement Adjustment.
I$chedule Page: 310.7 Line No.: 12 Column:j
Settlement Adjustment.
I$chedule Page: 310.7 Line No.: 14 Column: b
Settlement Adjustment.
I$chedule Page: 310.7 Line No.: 14 Column:j
Settlement Adjustment.
I$chedule Page: 310.8 Line No.: 1 Column: j
Transmission Losses.
I$chedule Page: 310.8 Line No.: 3 Column: j
Reserve Share.
I$chedule Page: 310.8 Line No.: 4 Column: b
IFERCFORM NO.1 (ED. 12-87) Page 450.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4 ,
FOOTNOTE DATA
.
Settlement Adjustment.
¡Schedule Page: 310.8 Line No.: 4 Column: J
Settlement Adjustment.
I$chedule Page: 310.8 Line NQ.: 5 Column: b
PowerEx - FERC T -11 (Point-to-Point Transmission Service under the Open Access Transmission Tarff (S.A. 363)) - Contrct
termination date: September 30, 2012.
I$chedule Page: 310.8 Line No.: 5 Column: J
Transmission Losses.
I$chedule Page: 310.8 Line No.: 6 Column: j
Transmission Losses.
I$chedule Page: 310.8 Line No.: 8 Column: b
Settlement Adjustment.
I$chedule Page: 310.8 Line No.: 8 Column: j
Settlement Adjustment.
I$chedule Page: 310.8 Line No.: 9 Column: b
Settlement Adjustment.
I$chedule Page: 310.8 Line No.: 9 Column: j
Settlement Adjustment.
I$chedule Page: 310.8 Line No.: 10 Column: b
Public Service Com any of Colorado - FERC 320 - Contrct terination date: December 31, 2011.
chedule Page: 310.8 Line No.: 11 Column:j
Trasmission Losses.
I$chedule Page: 310.8 Line No.: 13 Column: b
Secondar, Economy and/or non-fi sales, including some hourly fi trsactions.
I$chedule Page: 310.8 Line No.: 13 Column: j
Operating Reserve.
I$chedule Page: 310.9 Line No.: 1 Column: j
Resere Share.
I$chedule Page: 310.9 Line No.: 3 Column: j
Transmission Losses.
I$chedule Page: 310.9 Line No.: 5 Column: j
Transmission Losses.
¡Schedule Page: 310.9 Line No.: 8 Column: b
Settlement Adjustment.
I$chedule Page: 310.9 Line No.: 8 Column: j
Settlement Adjustment.
I$chedule Page: 310.9 Line No.: 9 Column: b
Settlement Adjustment.
I$chedule Page: 310.9 Line No.: 9 Column: j
Settlement Adjustment.
I$chedule Page: 310.9 Line No.: 10 Column: b
Sacramento Munici al Util Distrct - FERC 250 - Contrt termation date: December 31,2014.
cheule Pa e: 310.9 Line No.: 11 Column: .
Reserve Share.
I$chedule Page: 310.9 Line No.: 13 Column: b
Settlement Adjustment.
I$chedule Page: 310.9 Line No.: 13 Column:j
Settlement Adjustment.
I$cheule Page: 310.9 Line No.: 14 Column: b
Salt River Project - WSPP - Contrct termnation date: December 31,2009.
I$chedule Page: 310.10 Line No.: 1 Column: j
IFERC FORM NO.1 (ED. 12-87) Page 450.5
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da,Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Transmission Losses.
'$chedule Page: 310.10 Line No.: 5 . Column: b
Seattle City Light - FERC T -1 i (Point-to-Point Transmission ServiCe under the Open Access Transmission Tarff (S.A. 289)) -
Contract termnation date: October 31,2014.
'$chedule Page: 310.10 Line No.: 5 Column:j
Transmission Losses.
I$chedule Page: 310.10 Line No.: 6 Column: j
Reserve Share. -
¡Schedule Page: 310.10 Line No.: 9 Column: b
Settlement Adjustment.
¡Schedule Page: 310.10 Line No.: 9 Column: j
Settlement Adjustment.
I$chedule Page: 310.10 Line No.: 12 Column: b
Settlement Adjustment.
¡Schedule Page: 310.10 Line No.: 12 Column: j
Settlement Adjustment.
'$chedule Page: 310.10 Line No.: 13 Column: j
Trasmission Losses.
I$chedule Page: 310.11 Line No.: 1 Column: b
Settlement Adjustment. .
¡Schedule Page: 310.11 Line No.: 1 Column: j
Settlement Adjustment.
I§chedule Page: 310.11 Line No.: 2 Column: b
Sierra Pacific Power Compan - FERC 258 - Contrct termination date: Februa 28,2009.
chedule Page: 310.11 Line No.: 3 Column: b
Sierra Pacific Power Company - FERC T - 1 1 (Pavant Capacitor Ownership, Operation and Maintenance Letter Agreement dated
November 9, 2000) ~ Contract termination date: 90 days notification.
¡Schedule Page: 310.11 Line No.: 3 Column: j
Transmission Losses.
¡Schedule Page: 310.11 Line No.: 4 Column: j
Trasmission Losses.
I§chedule Page: 310.11 Line No.: 5 Column: j
Reserve Share.
!Schedule Page: 310.11 Line No.: 6 Column: a
Complete name is Public Utility Distrct NO.1 of Snohomish County.
!Schedule Page: 310.11 Line No.: 9 Column: a
Com lete name is State of California De arent of Water Resources.
chedule Pa e: 310.11 Line No.: 11 Column:'
Transmission Losses.
!Schedule Page: 310.11 Line No.: 13 Column: b
Settlement Ad' ustment.
chedule Pa e: 310.11 Line No.: 13 Column:'
Settlement Adjustment.
!Schedule Page: 310.11 Line No.: 14 Column: b
TransAlta Energy Marketing, Inc. - FERC T-12 - Contract termnation date: December 31,2010. .
¡Schedule Page: 310.12 Line No.: 1 Column: j
Transmission Losses.
!Schedule Page: 310.12 Line No.: 2 Column: j
Liquidated Damages.
!Schedule Page: 310.12 Line No.: 4 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "TRI-STATE GENERATION & TRSMISSION' ON PAGES
IFERC FORM NO.1 (ED. 12-87) Page 450.6
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
310-310.13:
Complete name is Tri-State Generation and Tramission Association, Inc.
fSchedlile Page: 310.12 Line No.: 4 Column: j
Transmission Losses.
fSchedule Page: 310.12 Line No.: 7 Column: j
Reserve Share.
fSchedule Page: 310.12 Line No;: 9 Column: b
Settlement Adjustment.
fSchedule Page: 310.12 Line No.: 9 Column: j
Settlement Adjustment.
fSchedule Page: 310.12 Line No.: 12 Column: b
Secondary, Economy and/or non-fIr sales, including some hourly fIr trsactions.
fSchedule Page: 310.12 Line No.: 13 Column: j .. .
Unauthorized use charges.
fSchedule Page: 310.13 Line No.: 1 Column: b
Uta Municipal Power Agency - FERC 433 - Contrt termation date: June 30, 2017.
fSchedule Page: 310.13 Line No.: 3 Column: j
Transmission Losses.
fSchedule Page: 310.13 Line No.: 5 Column: b
Seconda, Economy and/or non-fi sales, includin some hourly fIr transactions.
chedule Page: 310.13 Line No.: 5 Column: j
The negative revenue reported on this line reflects test energy generated at the Glenrock, High Plains and MacFadden Ridge power
plants that were trnsferred to constrction. Energy generated durg testig was delivered to PacifiCorp's electric system for sale, as
required by the guidance in .18 CFR Electrc Plant Instrctions 18( a), is a component of constrction and is the fair value of the
energy delivered.
fSchedule Page: 310.13 Line No.: 6 Column: j
Recognition and reportg of gains and losses on bokouts under authoritative accounting guidance.
fSchedule Page: 310.13 Line No.: 7 Column: J
Recognition and reportn of ains and losses on ener trn contrts under authoritative accounting guidance.
chedule Pa e: 310.13 Line No.: 8 Column:'
Represents the difference between actul nonrequirement sales revenues for the period as reflected on the individual line items within
this schedule, and the accruls charged to account 447 durng the period.
IFERC FORM NO. 1 (ED. 12-87)Page 450.7
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year .is not derived from previously reported figures, explain in footnote.Line Account Amount forNo ~~. W ~
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering
5 (501 Fuel
6 (502) Steam Expenses
7 (503) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr.
9 (505) Electric Expenses
10 (506) Miscellaneous Steam Power Expenses
11 (507) Rents
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12)
14 Maintenance
15 (510 Maintenance Supervision and Engineering
16 (511) Maintenance of Structures
17 (512) Maintenance of Boiler Plant
18 (513) Maintenance of Electric Plant
19 (514) Maintenance of Miscellaneous Steam Plant
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)
21 TOTAL Power Production Expenses-Steam Power (EntrTot lines 13 & 20)
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering
25 (518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr.
30 (523) Electric Expenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
34 Maintenance
35 (528) Maintenance Supervision and Engineering
36 (529) Maintenance of Structures
37 (530) Maintenance of Reactor Plant Equipment
38 (531) Maintenance of Electric Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 C. Hydraulic Power Generation
43 0 eration
44 (535 Operation Supervision and Engineering
45 (536) Water for Power
46 (537) Hydraulic Expenses
47 (538) Electric Expenses
48 (539) Miscellaneous Hydraulic Power Generation Expenses
49 (540) Rents
50 TOTAL Operation (Enter Total of Lines 44 thru 49)
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering
54 (542) Maintenance of Structures
55 (543) Maintenance of Reservoirs, Dams, and Waterways
56 (544) Maintenance of Electric Plant
57 545) Maintenance of Miscellaneous Hydraulic Plant
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)
Amount forPrevious Year
(c)
21,376,391
620,266,055
35,509,089
3,597,576
21,838,417
624,912,062
37,487,518
3,371,385
3,904,528
43,559,253
450,415
4,303,303
43,572,425
281,381
"7~"""" y. ~%¡ç~"""728,663,307 735,766,491
7_W"'""."~JV"/"""
.:r.3 /'%w'f.~'fÁ/~'f;.~?/~~il~);
5,970,114
22,825,065
94,433,581
33,727,522
12,681,273
169,637,555
898,300,862
6,008,903
24,834,108
86,675,457
28,874,080
12,753,101
159,145,649
894,912,140
~..r / ~ø'f%~/' i!"'If~ 'fwz.%.i
'" il..l/g%4f:'*.~ /.' /~f.II'.%if;p_~:r.øfl.W$ii~/ %0/f;; if "~Æ#%#g. fW%W:rd:ñ ;; /d~.g"W";~~. z../'/ ;Ø-~/~// / \/'f
9,385,219
290209
3,518,610
8,826,196
301,387
4,090,454
15,385,413
183,444
28,762,895
15,930,741
141,239
29,290,017~ /w.J:, /7W~r.%Z,"j% 7/!~"1~;;:Ær.~J¿il.".;~~:
84,358
1,207,112
1,600,540
1,515,716
2,539,316
6,947,042
35,709,937
2,681
1,225,169
1,437,284
1,572,617
2,15t,81
6,389,532
35,679,549
FERC FORM NO. 1 (ED. 12-93)Page 320
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission- 04/14/2010
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount forNo ~~. ~ ~
60 D. Other Power Generation
61 Operation
62 546) Operation Supervision and Engineering
63 (547) Fuel
64 (548 Generation Expenses
65 (549) Miscellaneous Other Power Generation Expenses
66 (550) Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66)
68 Maintenance
69 (551 Maintenance Supervision and Engineering
70 (552) Maintenance of Structures
71 553) Maintenance of Generating and Electric Plant
72 (554) Maintenance of Miscellaneous Other Power Genertion Plant
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)
74 TOTAL Power Production Expenses-OtherPower (Enter Tot of 67 & 73)
75 E. Other Power Supply Expenses
76 (555) Purchased Power
77 (556) System Control and Load Dispatching
78 (557) Other Expenses
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)
80 TOTAL Power Production Expenses (Total oflines 21, 41,59,74 & 79
81 2. TRANSMISSION EXPENSES
82 Operation
83 560) Operation Supervision and Engineering
84 (561) Load Dispatching
85 561.1) Load Dispatch-Reliabilty
86 (561.2) Load Dispatch-Monitor and Operate Transmission System
87 (561.3) Load Dispatch-Transmission Service and Scheduling
88 (561.4) Scheduling, S stem Control and Dispatch Services
89 (561.5) Reliabilty, Planning and Standards Development
90 (561.6) Transmissio Service Studies
91 561.7) Generation Interconnection Studies
92 (561.8) Reliabilty, Planning and Standards Development Serves
93 (562 Station Expenses
94 (563) Overead Lines Expenses
95 (564) Underground Unes Expenses
96 (565) Transmission of Electicity by Oters
97 (566) Miscellaneous Transmission Expenses
98 (567 Rents
99 TOTAL Operation (Enter Total of lines 83 thru 98)
100 Maintenance
101 (568) Maintenance Supervision and Engineering
102 (569) Maintenance of Structures
103 (569.1 Maintenance of Computer Hardware
104 (569.2) Maintenance of Computer Softare
105 (569.3) Maintenance of Communication Equi ment
106 (569.4) Maintenance of Miscellaneous Regional Transmss Plant
107 (570) Matenance of Station Equipment
108 (571) Maintenance of Overhead Lines
109 (572) Maintenance of Underground Lines
110 (573) Maintenance of Miscellaneous Transmission Plant
111 TOTAL Maintenance (Total of lines 101 thru 110)
112 TOTAL Transmission Expenses (Total of lines 99 and 111
AmountJorPrevious Year
(c)
316,964
461,743,015
15,739,485
18,635,853
1,861,264
498,296,581
218,466
466,962,755
17,845,036
10,943,849
6;739,843
502,709,949
1,544,031
14,986,840
1,321,906
17,852,777
516,149,358
1,280,348
5,911,258
482,926
7,674,532
510,384,481.ø:r;f_./Æ ¡/ß~~4Y1""l!_
456,211,649 754,189,849
1,514,461 1,997,891
49,819,215 56,143,944
507,545,325 812,331,.684
1,957,705,482 2,253,307,854
6,088,583 7,808,710
8,347,455 7,114,390
83,728
76,671 73,289
899,582 1,264,738
1,506,478 1,869,851
245,152 93,337
35,453
788
79,505
974,621
3,005,647
9,822
3,284
290,283
636,171
3,199,160
10,549,624
19,620,066
51,599
182,001
34,499,304
172,874,522
11,093,119
16,204,998
480,533
31,917,370
174,010,394
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This Report Is: Date of Report
(1) l!An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount forN Current Yearo. (a) (b)
113 3. REGIONAL MARKET EXPENSES
J 14 Operation
115 (575.1) Operation Supervision
116 575.2 Day-Ahead and Real-Time Market Faciltation
117 (575.3) Transmission Rights Market Faciltation
118 (575.4) Capacity Market Facilitation
119 (575.5) Ancilary Services Market Faciltation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Faciltation, Monitonng and Compliance Services
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)
124 Maintenance
125 (576.1) Maintenance of Structures and Improvements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Softare
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering
135 (581) Load Dispatching
136 (582) Statio Expenses
137 (583) Overhead Line Expenses
138 584) Underground Line Expenses
139 (585) Street Lighting and Signal System Expenses
140 586) Meter Expenses
141 (587) Customer Installations Expenses
142 (588) Miscellaneous Expenses
143 (589) Rents
144 TOTAL Operation (Enter Total of lines 134 thru 143)
145 Maintenance
146 (590) Maintenance Supervision and Engineering
147 (591) Maintenance of Structures
148 (592) Maintenance of Station Equipment
149 (593) Maintenance of Overhead Lines
150 (594) Maintenance of Underground Lines
151 (595) Maintenance of Line Transformers
152 (596) Maintenance of Street Lighting and Signal Systems
153 (597) Maintenance of Meters
154 (598) Maintenance of Miscellaneous Distnbution Plant
155 TOTAL Maintenance (Total of lines 146 thru 154)
156 TOTAL Distribution Expenses (Total of lines 144 andt55)
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Opratin
159 (901) Supervision
160 902) Meter Reading Expenses
161 903) Customer Records and Collection Expenses
162 (904) Uncollectible Accounts
163 (905) Miscellaneous Customer Accounts Expenses
164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163)
AmountJprPrevious Year
(c)
..~~~~~~~~w..~ :~;~
r¡Tiøp~i7 ~I"i;~ "7~ii.7~'''";J¡~~:':'""~~;;i$;::.~
19,654,389
13,439,746
3,879,687
5,794,824
305
207,152
6,713,560
12,459,259
7,441,400
3,196,255
72,786,577
20,296,814
12,782,671
4,574,167
5,392,347
403
222,030
7,204,688
11,063,638
8,389,281
3,038,169
72,964,208.;K;'i"~"" 7ßP%~~""
;r".::;~.. a-'Æ0 : =": .. ¿~7i"~ Æ,7:'" W":~:'7~ JIW:ei....
7,535,970
2,015,990
12,800,357
83,336,655
22,486,595
1,105,880
4,217,687
5,637,023
3,546,007
142,682,164
215,468,741
6,421,892
2,030,161
11,547,226
85,001,337
23,539,909
1,116,622
4,138,856
5,212,174
3,391,891
142,400,068
215,364,276
2,554,096
22,520,219
56,280,326
12,175,795
254,571
93,785,007
2,477,949
25,289,712
56,637,149
14,674,714
229,561
99,309,085
FERCFORM NO.1 (ED. 12-93)Page 322
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account AmounVforNo ~~. ~ ~
1656. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision
168 (908) Customer Assistance Expenses
169 (909) Informational and Instructional Expenses
170 910) Miscellaneous Customer Service and Informational Expenses
171 TOTAL Customer Service and Information Expenses (Total 167 th 170)
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision
175 (912) Demonstrating and Sellng Expenses
176 (913) Advertsing Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expnses (Enter Total of lines 174 thru 177)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries
182 (921) Offce Supplies and Expenses
183 (Less) (922) Administrative Expenses Transferred-Credit
184 (923) Outside Services Employed
185 (924) Propert Insurance
186 (925) Injuries and Damages
187 (926) Employee Pensins and Benefit
188 (927) Franchise Requirements
189 (928) Regulatory Commission Expenses
190 (929 (Less) Duplicate Charges-Cr.
191 (930.1) General Advertising Expenses
192 930.2) Miscellaneous General Expenses
193 (931) Rents
194 TOTAL Operation (Enter Total of lines 181 thru 193)
195 Maintenance
196 (935) Maintenance of General Plant
197 TOTAL Administrative & General Expenses Total of lines 194 and 196)
198 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197)
286,17
66,102,006
4,924,267
150,054
71,462,744
72,874,820
11,031,087
25,866,775
11,039,350
23,970,317
7,434,336
Year/Period of Report
End of 2009/Q4
Amount,prPrevious Year
(c)
247,987
51,829,080
4,101,589
63,857
56,242,513
67,200,789
11,470,988
21,538,493
11,890,876
31,882,383
9,475,122
16,464,747
3,420,842
35,761
19,659,625
6,199,584
139,422,010
11,630,262
3,987,182
35,163
18,540,495
6,318,703
142,919,106
23,197,501
162,619,511
2,673,916,007
27,125,031
170,044,137
2,968,278,259
FERC FORM NO.1 (ED. 12-93)Page 323
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mó, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 20091Q4
.FOOTNOTE DATA
~c;hedule Page: 320 Line No.: 187 Column: b
Pensions and benefits are charged to functional accounts, which is consistent with where labor is charged. The followig table
summarzes the pension and benefit expense that was charged to the fuctional accounts.
2009
Years Ended
December 3 i,
2008
Pension & Benefits Expense $ 143,975,955 $ 145,242,536
.IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This '00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
PU~CHAciED POWER W'ccou~t 555)nclu ing power exc anges .
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplie 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 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 ofthe 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 thcone 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, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Acal Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average . AveragecationTariff Number Demand (MW)Monthly NCP Deman!Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Power Purchases
2 AES Wind Generation, Inc.LU NA NA NA
3 Albany, City of "NA NA NA
4 Albany, City of LU NA NA NA
5 Anaheim, City of NA NA .NA
6 Anaheim, City of SF NA NA NA
7 Arizona Public Service Company NA NA NA
8 Arzona Public Service Company NA NA NA
9 Arizona Public Service Company NA NA NA
10 Arizona Public Service Company SF NA NA NA
11 Avista Corporation NA NA NA
12 Avista Corporation SF NA NA NA
13 Azusa, City of SF NA NA NA
14 BP Energy Company SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326
Name of Respondent This 00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/14/2010
,ccount~~g~~) (L;ontinuea)W' '~(ínciuding power exchange )
AD - for out-of-period adjustment Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
.. designation for the contract On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average 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 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 megawatthours
of power exchanges received and delivered, used as the basis for settlement Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bills received as settlement by the respondent For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all rèquired data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchsed MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total. O+k+l)No.Received Delivered
~l ~~~\'l
of Settlement ($)
(g)(h)(i)(m)
..1
134,8H 4,783,38 4,783,383 2
"-284 3.
66C 42,08G 42,080 4
2~30e 300 5
2,96E 101,804 101,804 6
12"M 7,500 7
59,10C 1,788,27E 1,788,275 8
3,70C 110,20C 110,200 9
,9O,82f 2,778,33~2,778,332 10
500 11
103,50~3,087,41 3,095,306 12
.3 36 13
120,07£4,333,19 -9,544,178 14
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211,64~
FERC FORM NO.1 (ED. 12-90)Page 327
Name of Respondent This ~ort Is: --Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04114/2010
PU~CHA~ED POWER hACCUW 5 5)(nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 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 ofLF 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 expe that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.LJse 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 intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature 0
the service in a footnote for each adjustment.
Line Name of Company or Public Authorit Statistica FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schdule or Monthly Billng Average AveragecationTar Number Demand (MW)Mothly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Ballard Hog Farms Inc...NA NA NA
2 Ballard Hog Farms Inc.LU 0.01 NA NA
3 Barclays Bank PLC "NA NA NA
4 Barclys Bank PLC SF NA NA NA
5 Beaver City NA NA NA
6 Bell Mountain Hydro, LLC LU NA NA NA
LU NA NA NA8 SF NA NA NA9 Big Top, LLC LU NA NA NA
10 Biomass One, L.P.LU 22.5 18.7 15.0
11 Birch Creek Hydro LU NA NA NA
12 Black Hils Power, Inc.NA NA NA
13 Black Hils Power, Inc.LU NA NA NA
14 Black Hils Power, Inc.NA NA NA
.
Total
FERC FORM NO.1 (ED. 12-90)Page 326.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) j"A Resubmission 04/14/2010
ccouRt,~~~i \ (I,ontinuea), ~ .~, '~ìínCluding power exc anges)
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column(k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.Received Delivered
~l \~~~fl
of Settlement ($)
(g)(h)(i)(m)
47 1
101 277 5,51 5,792 2
34E 27,735 3
529,13~20,190,571 -5,761,850 4
6€5,65 5,657 5
2H 17,16 12,612 6
1,491 76,61 76,617 7
4,OOC 42,00C 42,000 8
82~48,26~48,265 9
127,00 2,399,625 17,165,61 25,091,470 10
12,02E 656,40 656,48 11
-7 II 88,677 12..
2,45C .1,159,656 13
4C 1,34C 1,340 14
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211 ,64~
FERC FORM NO.1 (ED. 12-90)Page 327.1
Name of Respondent This 00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
PU~CHASED POWER hACCOUW 555)
( ncluding 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the supplier
includes prOjects load for this service in its system resource planning). In addition, the reliabilty of requirement service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-ter service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of-the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly Biling Averagè Average
cation Tari Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
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 Harold Foster & Robert Walker LU NA NA NA
5 Bonnevile Power Administration NA NA NA
6 Bonnevile Power Administration 575 575 478
7 Bonnevi Power Administration NA NA NA
8 Bonnevile Poer Administration NA NA NA
9 Bonneville Power Administration NA NA NA
10 Bonnevile Power Administration SF NA NA NA
11 Burbank, Cit of .NA NA NA
12 Burbank, City of SF NA NA NA
13 Butter Creek Power, LLC LU NA NA NA
14 CDM Hydroelectric Company LU NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.2
Name of Respondent This iæ0rt Is:Date of Report Year/Period of Report
PaçifiCorp (1) X An Original (Mo, Da, Yr)End Of 2009/Q4
(2) DA Resubmission 04/14/2010
I-L Kl,HAriRtil ccouRt.~~~UContlnued)Including power exc anges)~.
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, 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered,~used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges,including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt ofehergy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ~l \~~\'1
of Settlement ($)
(g)(h)(i)(m)
29,43S 1,067,124 1,067,124 1
3,89 116,59(116,590 2
40(29,96(29,966 3
1,00(34,80!34,808 4.-47,083 5
49,697,250 49,697,250 6.1,845,106 7
~331,217 8
80 9
304,49(5,987,32 6,078,038 10
281
ø 17,117 11
26,021 934,21~934,213 12
5,011 223,70e 223,705 13
30,01!1,634,59~1,634,595 14
.~
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211 ,64~
FERC FORM NO.1 (ED. 12-90)Page 327.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) ¡=A Resubmission 04/14/2010
PU~CHAJlED POWER hAccu3t 51 5)
(nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The 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 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 0
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistil FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average AveragecationTariff Number Demand (MW)Monthly. NCP Demani Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Califomia Independent Sysm Operator NA NA NA
2 Califomia Independent Sysem Operator SF NA NA NA
3 Cargil Power Markets, LLC NA NA NA
4 Cargil Power Markets, LLC NA NA NA
5 Cargil Power Markets, LLC .SF NA NA NA6~U 4.4 4.1 3.37 LU NA NA NA8 Chelan County PUD #1 SF NA NA .NA
9 Chevron U.S.A Inc...NA NA NA
10 Citigroup Energy, Inc.NA NA NA
11 Citigroup Energy, Inc.SF NA NA NA
12 City of Buffalo LU 0.2 0.2 0.2
13 Clatskanie People's Utilty District SF NA NA NA
14 Colorado River Commission of Nevada NA NA NA
Total
FERC FORM NO.1 (ED. 12.90)Page 326.3
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
.y w, "'õ"",, .,.....~~~l\ccoun~~8~~)(GOntinued)Including power exchange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote. for each adjustment.
. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which serVice, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly(or longer) basis, enter the
monthly average 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 (50-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (50-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated ona megawatt basis and explain.
5. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401 ,line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.Received Delivered
~I \~~\W
of Settlement ($)
(g)(h)(i)(m)
75C 19,795 1
513,351 18,029,51 18,029,512 2
31¿11,387 3
1,321 28,601 28,608 4
1,591,54!48,538,541 48,538,541 5
28,42 456,550 2,618,11'3,074,665 6
353,761 3,686,164 7
36,87:865,14 867,804 8
6,12,329,21 329,217 9
22 %9,248 10...
548,281 16,467,4~.8,385,289 11
1,87C 28,884 153,70A 182,588 12
3,391 100'78~100,780 13
35(14,778 14
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211,64~
FERC FORM NO.1 (ED, 12-90)Page 327.3
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
PU~CHAJtED POWER hACCOUßt 555)(nclu 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the 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 eithr 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 onè year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the 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 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 0
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average AveragecationTari Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Colorado River Commission of Nevada SF NA NA NA
2 Colorado Sprngs Utilties SF NA NA NA
3 Commercial Energy Management, Inc.LU NA NA NA
4 Conoco Inc.SF NA NA NA:~NA NA NA
NA NA NA
7 Constellatio Energy Commodities Group SF NA NA NA~0.3 0.4 0.3
1~ Credit Suisse Energy LLC
NA NA NA
NA NA NA
11 Credit Suisse Energy LLC SF NA NA NA
12 Cameron A. Curtiss LU NA NA NA
13 DB Energy Traing LLC SF NA NA NA
14 DR Johnson Lumber Company LU NA NA NA
.
Total
FERC FORM NO.1 (ED. 12-90)Page 326.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
.(2) DA Resubmission 04/14/2010
ccount~~g~~) t l,ontinued)~ ,~,.. '(íncíuding power exchange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups. for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment...
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or Charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column(g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.Received Delivered ~l ~t~\'l
of Settlement ($)
(g)(h)(i)(m)
. 17~8,06.8,062 1
8C 4,56(4,560 2
1,59€83,54.83,543 3
87,23€3,174,66f 3,174,667 4
1,171 ,180,242 5
14,15 619,091 619,091 6
215,8H 9,549,87 -2,286,223 7
2,62f 6,080 135,17 141,258 8
489,437 9
64 61,767 10
333,801 18,489,79 10,034,062 11
9~6,40£6,409 12
207,04f 6,071,39C .6,071,390 13
56,756 3,672,43£3,672,439 14
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211 ,64~
FERC FORM NO.1 (ED. 12-90)Page 327.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of .2009/Q4
(2) riA Resubmission 04/14/2010
PU~CHAJiED POWER hACCUW 555)(nclu 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 settements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller;
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "frm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This 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 expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availabilty and reliability 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, capacity, etc.
and any settlements forimbalan.ced 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 01
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistil FERC Rate Averae Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schule or Monthly Billng Average Average
.catio Tar Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Davis County Waste Management ..NA NA NA
2 Davis County Waste Management NA NA NA
3 Deschutes Valley Water District LU 5.8 4.0 2.7
4 Deseret Power Electric Cooperative 100 100 89
5 Deutsche Bank AG SF NA NA NA
6 Douglas County Forest Products NA NA NA
7 Douglas County Forest Products IU NA NA NA
8 NA NA NA
9 Douglas County PUD #1 NA NA NA
10 Douglas County PUD #1 LU NA NA NA
11 Douglas County PUD #1 NA NA NA
12 Douglas County PUD #1 SF NA NA NA
13 Douglas County Public Works LU 0.5 0.6 0.3
14 Draper Irrigation Company IU NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.5
Name of Respondent This (80rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 04/14/2010
PU ~CHA~~gl ccunt~~~Llcontinued).Including power exchanges)
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
identifid in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the tlour (60-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t) must
be in megaw;atts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered tottie 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-peri 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 rèceived as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges ~T~ÜWd)No.Received Delivered ~l \~l
($) of Settlement ($)
(g)(h)(i)(I) (m)
E ... 307 1
89~46,28¿46,284 2
26,18~571,014 2,712,673 3,283,687 3
736,90C 13,856,971 13;018,62 30,531,425 4
-2,819,636 5
-1,645 6
1,3m 42,64 42,64 7
-37,974 8
-92,949 9
214,19,.2,871,143 10
38,22A 757,381 757,381 11
14,82E 468,70C'469,267 12
3,40 .53,513 395,26E 448,778 13
51 28,42,28,422 14
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 .450,708,841 456,211 ,64~
FERC FORM NO.1 (ED. 12-90)Page 327.5
..
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
PU~CHAJlED POWER hAccou3t 5 5)(nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3; In column (b), enter a Statistical Classification Code base on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis ~Le., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "frm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contrct.
IF - for intermediate-term fiim service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term"means five years or longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature 01
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly Billing Averge AveragecationTan Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Dry Creek LLC LU NA NA NA
2 Dynegy Power Marketing SF NA NA NA
3 EDF Trading North America, LLC ~NA NA NA
4 EDF Trading North America, LLC NA NA NA
5 Eagle Point Irrigation District WÅ 0.7 0.5 0.3
6 EI Paso Electric Company NA NA NA
7 EI Paso Electric Company SF NA NA NA
8 Endure Energy, LLC SF NA NA NA
9 Eugene Water & Electric Board SF NA NA NA
10 Eurus Combine Hils I, LLC LU NA NA NA
11 Evergreen BioPower, LLC -NA NA NA
12 Evergreen BioPower, LLC LU NA NA NA
13 Exon Mobile Production Company LU NA NA NA
14 Falls Creek H.P. Limited Partnership LU 3.1 3.4 . 1.4
Total
FERC FORM NO.1 (ED. 12-90)Page 326.6
Name of Respondent This '00rt Is:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
ccouHta~~~~) (Continued).....
'(íncluding 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 afootnote 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 scheduies, 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 othertypes 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 suppliets system reaches its monthly peak. Demand reported in columns (e) and (t) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a foôtnote 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 crêdits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide expianations following all required data.
MegWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)No.
Received Delivered ~l \~~\fl
of Settlement ($)
(g)(h).(i)(m)
11,80~606,92€606,928 1
24,52'864,675 864,675 2
3,10C 192,20C 192,200 3
95,19~.2,812,921 -2,878,238 4
2,901 38,860 316,151 355,011 5
-31 -2,505 6
43,31~.1,056,21 ¡ iW 1,056,291 7
20,681 651,631 651,636 8
33,84.863,231 863,230 9
104,57.3,631,78 3,631,783 10
2,781 145,417 11
40,37,.1,971,61!1,971,619 12.
645,86 30,821,131 30,821,131 13
15,94~199,567 1,629,311 1,828,883 14
..
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211 ,64~
.
FERC FORM NO.1 (ED. 12-90)Page 327.6
Name of Respondent This 1Ë0rt Is:Date of RepOrt Year/Penod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/14/2010
PU~CHAJlED POWER hAccuW 5 5)(nclu 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
.
RQ - for requirements service. Requirements serice is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF -for short-term service.Use this category for all firm services, where the durtion 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 reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacit, 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 0
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statisticl FERC Rate Average Actual Dema (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly Billng Average AveragecatinTarif Number Deman (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Farmers Irrigation District LU 3.6 3.4 2.0
2 Loyd Fery LU NA NA NA
3 Filmore City NA NA NA
4 Finley BioEnergy, LLC LU NA NA NA
5 Fortis Energy Marketing & Trading GP SF NA NA NA
6 Four Comers Windfarm, LLC LU NA NA NA
7 Four Mile Canyon VVindfarm, LLC LU NA NA NA
8 Shoshone Irrigation District LU 2.5 1.4 1.0
9 General Chemical Corporation r-NA NA NA
10 George Deuyter & Sons Dairy 0.7 1.0 0.7
11 Georgetown Irrgation Company ..NA NA NA
12 Gila River Power, L.P..NA NA NA
13 Gila River Power, L.P..SF NA NA NA
14 Glendale, City of SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.7
Name of Respondent This 00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
ccouH~~~~ucontlnued ).(lncluding power exc anges)
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 serviceinvolvin9 demand charges imposed on a monnthly (or longer) basis, entèrthe
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 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 suppliets 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 iri column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the. basis for settlement. Do not report net exchange.
7. Report demand charges in column (j, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excllJdes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered
~l \~~\fl
of Settement ($)
(g)(h)(i)(m)
22,85~308,228 2,354,51C 2,662,738 1
24 15,94 15,943 2
18,19,68(19,680 3
27,361 1,765,30.1,765,302 4
35,60(1,197,43(-950,917 5
5,30A 271,26 271,267 6
5,65.282,14 282,143 7
9,59t 157,630 375,58\533,219 8
1,79.26,7Oc 26,700 9
6,421 2,014 ..324,3()326,318 10
2,35t 126,441 126,441 11
78f 28,4O¡28,400 12.
145,601 4,588,71 4,588,713 13
2L 1,Om 1,008 14
.
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211 ,64~
.
FERC FORM NO.1 (ED. 12-90)Page 327.7
This~rtls:
(1)~An Original
(2) A Resubmission
PURCHASED POWER (Accur¡t 5 5)
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/14/2010
Year/Period of Report
End of 2009/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 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 r.eliable 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 .a_s LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-terrservice from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
os - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature 0
the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billng
Demand (MW)
(d)
Acual Demand (MW)vera verage
Monthly NCP Deman Monthly CP Demand(e) (f)
Hil Air Force Base
Hurricane, City of
lberdrola Renewables, Inc.
lberdrola Renewables, Inc.SF
NA
NA
NA
14
NA
NA
NA
NA
NA
240
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
240
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
218
NA
NA
NA
NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.8
This ~ort Is:
(1) IlAn Original
(2) A Resubmission
AccountIncluding power exchanges)
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
'PacifiCor
Year/Period of Report
End of 2009/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 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 (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 suppliers system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain. .
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MeaWatt Hours
Purchased
POWER EXCHANGES
MegaWatt Hours MegaWatt HoursReceived Delivered(h) (i)Demand Charges
~1(g)
34,971,330
84,063
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211,64
FERC FORM NO.1 (ED. 12-90)Page 327.8
COST/SETTLEMENT OF POWER
Energy Charges Other Charges\~~ \'1
Name of Respondent This 'r0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
PU~CHAJlED POWER hAccouW 555).(nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 "frm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliability 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 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 01
the service in a footnote for each adjustment.
Une Name of Company or Public Authority Statistic FERC Rate Average . Actual Demand (MW)
No.(Footnote Affliations)Classi-Schedule or Monthly Billng Average AveragecatioTari Number Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Idaho Falls, City of LU NA NA NA
2 Idaho Power Company ~NA NA NA
3 Idaho Power Company NA NA NA
4 Idaho Power Company SF NA NA NA
5 Idaho Power Company SF NA NA NA
6 Integrys Energy Services, Inc.SF NA NA NA
7 Intermountin Power Agency LU NA NA NA
8 International Paper NA NA NA
9 J. Aron & Company NA NA NA
10 J. Aron & Company SF NA NA NA
11 NA NA NA
12 J.P. Morgan Ventures Energy Corp.SF NA NA NA
13 SF NA NA NA
14 Kennecott Utah Copper LLC IU NA NA NA
Total ..
FERC FORM NO.1 (ED. 12-90)Page 326.9
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) r'A Resubmission 04/14/2010
ccoun~~g~~ \ (ContinUed)'(Including power exchange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided inpriór reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP
dema.nd 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) inwhich 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 types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
~l \~~\fl
of Settlement ($)
(g)(h)(i)(m)
48,419 2,784,700 1
-H -752 2
4,55(60,42 60,425 3
36,42f 1,290,992 4
21,67f 759,2 761,739 5
1,20(42,60(.42,600 6
577,331 25,739,031 25,739,038 7
357,35'23,669,66;23,669,663 8
11 1,183 9
49,191 1,766,94 -5,124,444 10
5(1,25 1,250 11
401,22~12,904,411 12,661,778 12.-2,541,248 13
183,99 13,818,80~13,818,803 ,14
11,462,391 14,027,658 14,213,609 124,783,622 782,136;88 -450,708,841 456,211,64~
FERC FORM NO.1 (ED. 12-90)Page 327.9
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
PU~CHAJiED POWER \tccouW 5 5)
( nclu. 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (I.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the 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
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliability of
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 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 01
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average AveragecationTariff Number Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Kennecott Utah Copper LLC LU NA NA NA
2 L&M Angus Ranch, LLC LU NA NA NA
3 Lacomb Irrigation District LU NA NA NA
4 Box Canyon Limited Partnership LU .2.3 2.9 1.3:-NA NA NA
NA NA NA
7 Los Angeles Dept. of Water & Power SF NA NA NA
8 Lower Valley Energy, Inc.IU NA NA NA
9 Luckey, Paul LU NA NA NA
10 Macquarie Cook Power Inc.SF NA NA NA
11 Magnesium Corporation of America IU NA NA NA
12 Magnesium Corporation of America NA NA NA
13 Marsh Valley Hydro & Electric Company LU NA NA NA
14 Middle Fork Irrgation District LU NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.10
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
ccu~t.~~~L \ (Continued)'ìínèíuding power exc anges)
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 designàtions under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of serviGe involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average biling demand in column (d), the average monthlynon-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) al1(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 (j), energy charges in column (k), and the total of any other types of charges, inch,iding
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 thanincremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) thr()ugh (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ~l \~~\fl
of Settlement ($)
(g)(h)(i)(m)
9,735,404 1
1,421 77,761 .77,761 2
4,71 155,61€ft 188,485 3
14,59 219,747 1,578,561 1,798,314 4
3.ii 2,334 5
84(6,72 44,990 6
110,67E 3,300,52 3,306,416 7
1,81"105,4 105,464 8
28 M.oo=34,081 9
62,884 2,216,83 1,912,807 . 10
119,269 3,717,88 3,717;889 11
ø 1,537,460 12
5,229 285,891 285,891 13
22,904 .1,110,981 1,110,981 14
..
.
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211,649
FERC FORM NO.1 (ED. 12-90)Page 327.10
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
PU~CHA~ED POWER W'ccußt 5 5)(nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firmH 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 Hintermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of the designated unit.
IU - for intermediate-term servce from a designated geherating unit.The same as LU service expec that Hintermediate-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 0
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Averag Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schdule or Moly Billng Averae 7WeragecationTar Numbr Demnd (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Mik Creek Hydro LU NA NA NA
2 Mirant Americas Energ Marketing, L.P.SF NA NA NA
3 Modesto Irrigation Distrct SF NA NA NA
4 Monsanto Company IU NA NA NA
5 Morgan City NA NA NA
6 Morgan Stanley Capital Group, Inc."NA NA NA
7 Morgan Stanley Capital Group, Inc.IF 100 100 100
8 Morgan Stanley Capital Group, Inc.SF NA NA NA
.....9 Mountain Energy, Inc.LU NA NA NA.~10 Mountain Wind Power II, LLC NA NA NA
11 Mountain Wind Power II, LLC NA NA NA
12 Mountain Wind Power, LLC .NA NA NA
13 Nephi City NA NA NA
14 Nevada Power Company NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.11
Name of Respondent This 00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/14/2010
.i-U ccoun~~g~~ L (L;ontlnUeo)'(including power exchange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average 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). MonthlyNCP
demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (50-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the rnegawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy.. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
~l \~~Wl
of Settlement ($)
(g)(h)(i)(m)
10,53 558,83f 558,838 1
12C 6,96C 6,960 2.
40C 42,80C 42,800 3
13,410,115 4
2 3,18 3,187 5
....3,48 155,040 6
328,80C 1,515,000 17,709,84 19,224,840 7
1,390,765 63,709,91 46,749,413 8
79 5,05 5,056 9
81"33,618 10.
202,840 13,116,241 13,108,075 11
128,330 .7,199,62 7,199,623 12
1€1'5~1,558 13
-11 -537 14
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211,64~
FERC FORM NO.1 (ED. 12-90)Page 327.11
Name of Respondent ThiS~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmission 04/14/2010
PU~CHAJlED POWER hAccunt 5 5)
(nclu 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the 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 outof the cotrct.
IF - for intermediate-term firm service.The same as LF service expec that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm 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 reliability 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, 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 Oi
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schule or Monthl Billng Averae AveragecationTarif Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Nevada Power Company SF NA NA NA
2 Nicholson Sunnybar Ranch "NA NA NA.
3 Nicholson Sunnybar Ranch LU NA NA NA
4 HDI Associates V, LP LU 0.4 0.5 0.2
5 NorthWestern Energy SF NA NA NA
6 Northpoint Energy Solutions Inc.SF NA NA NA
7 Nucor Corporation IF NA NA NA
8 O.J. Power Company LU NA NA NA
9 Occidental Power Services, Inc. .SF NA NA NA~U 0.03 0.04 0.02
11 Oregon Environmental Industries, LLC LU NA NA NA
12 Oregon Trail Windfarm, LLC LU NA NA NA
13 PPL EnergyPlus, LLC SF NA NA NA
14 Pacific Canyon Windfarm, LLC LU NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.12
Name of Respondent This 780rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/14/2010 ..
.CCU~\~g~l) (ContinUed)
..~, .. 'ì1ncíuding 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 billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
. monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.Received Delivered
~l ~~~\fl
of Settlement ($)
(g)(h)(i)(m)
33,76A 1,321;61C ~1,384,842 1.1,188 2
1,72E 93,51S 93,519 3
1,92€38,035 205,76C 243,795 4
1,11€22,93~==33,160 5
18,99 610,481 610,487 6
~4,722,600 7
76 38,32~38,324 8
11,35C 370,37"370,372 9
151 2,797 14,26C 17,057 10
18,36f 891,52.891,523 11
10,188 441,34~441,349 12
21,116 882,74E 882,746 13
6,435 287,52€287,528 14
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211 ,64~
FERC FORM NO.1 (ED. 12-90)Page 327.12
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1 )IKAn Original (Mo, Da, Yr)End of 2009/Q4
(2)¡=A Resubmission 04/14/2010
PU~CHASED POWER Ifccount 5 5)
( ncluding 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the orginal contractal terms and conditions of the service as follows:
RQ - for requirements service. Requirements serv 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 reliability of requirement service must be the
same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credit for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature a
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)C1ssif-SChedule or Monthly Biling Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Pacific Gas & Electric Company SF NA NA NA
2 SF NA NA NA
3 Pacific Summit Energy LLC *NA NA NA
4 Pacific Summit Energy LLC SF NA NA NA
5 Pasadena, Cit of NA NA NA
6 Payson City Corporation NA NA NA
7 Platte River Power Authority SF NA NA NA
8 Portand General Electric Company NA NA NA
9 Portland General Electric Company NA NA NA
10 Portland General Electric Company SF NA NA NA
11 Powerex Corporation SF NA NA NA
12 Preston City Hydro LU NA NA NA
13 Provo City NA NA NA
14 Public Service Company of Colorado NA NA NA
Total
FERC FORM NO. 1 (ED. 12.90)Page 326.13
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) r=A Resubmission 04/14/2010
v ,,~, '''(1~'- , ccunta~g~~)(l,ontlnUed).Including power exchange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On sepàrate 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchasés on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER .Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered
~l \~~\fl
of Settlement ($)
(g)(h)(i)(m)
6,816 260,23C 260,230 1
4,4H 188,931 188,931 2
11 456 3
127,84.4,723,87i 4,723,877 4
2,37¡14,20C 14,200 5
1¿.1,531 1,531 6
3,081 87,848 7
m¡537,165 8
12,02'359,000 9
122,65 4,452,43 4,467,142 10
232,67 10,424,391 10,424,398 11
1,86¡91,86¿91,864 12
14 11,42¡11,429 13
581 41,365 14.
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211,64¡
! ..
FERC FORM NO.1 (ED. 12-90)Page 327.13
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) r=AResubmission 04/14/2010
PU~CHAdTED POWER hAccoußt 5 5)
(nclu 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classifcation 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 mustattempt to buy emergency energy from
.. third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The 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, 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 0
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actal Demand (MW)
Classif-Schedule or Monthly Billng .Average J\erageNo.(Footnote Affliations)cation Tari Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Public Service Company of Colorado SF NA NA NA:~NA NA NA
NA NA NA
4 PUD #1 of Lews County NA NA NA
5 Puget Sound Energy, Inc. SF NA NA NA
6 RRI Energy Services, Inc...NA NA NA
7 Rainbow Energy Marketing Corporation NA NA NA
8 Rainbow Energy Marketing Corporation SF NA NA NA
9 Ralphs Ranch, Inc..LU NA NA NA
10 Redding, City of SF NA NA NA
11 Riverside, City of NA NA NA
12 Rocky Mountain Generation Cooperative.SF NA NA NA
13 Roseburg Forest Product Co.LU NA NA NA
14 Rough & Ready Lumber Company LU NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.14
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) i"A Resubmission 04/14/2010
I-U -(l,HA~rU. CCUH\~~~§) (l,ontinuea)Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups. for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average 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 types of service, enter NA in columns (d), (e) and (t). MonthlyNCP
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. Report demand charges in column (j, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total Q+k+l)No.Received Delivered ~l ~i~Wl
of Settlement ($)
(g)(h)(i)(m)
10,64C 390,76 390,767 .. 1
134,61€3,607,841 3,730,659 2
66£18,153 3
6,261 166,17 166,177 4
175,631 6,018,31f ri 6,031,778 5
2,10C 113,40(113,400 6
91"38,66(38,660 7
79,73:.2,003,08 2,003,087 8
21 25,75 25,757 9
78C 44,50lJ 44,500 10
2,58'21,105 21,105 11
13,27€....313,383 313,383 12
163,561 9,337,27C 9,337,270 13
8,55 .553,304 553,304 14
11,462,391 14,027,658 14,213,609 1?;4,783,622 782,136,868 -450,708,841 456,211 ,64~
FERC FORM NO.1 (ED. 12-90)Page 327.14
Name of Respondent This Re ort Is:Date of Report Year/Period of Report
PacifiCorp (1 )X An Onginal (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmission 04/14/2010 .
PU~CHA~ED POWER hACCOUW 5 5)
(nclu ing power exc anges ~
1. Report all power purchases madè 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 affliation the respondent has with the seller.
3. .In column (b), enter a Statistical Classification Code based on the oriinal 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 sèrvice which meets
the definition of RQ service. For all transacion identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The 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 electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the L~ngth of the contract and service from designated units of Less than one year. Describe the nature 0
the service in a footnote for each adjustment.
Line Name of Company or Public Authonty Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif Schedule or Monthly Billng Average AveragecationTari Number Dend (MW)Monthly NCP Deman Monthly CP Demand..(a)(b)(c)(d)(e)(f)
1 Roush Hydro, Inc.LU NA NA NA
2 Sacramento Municipal Utilty Distrct NA NA NA
3 Sacramento Municipal Utility Distnct NA NA NA
4 Sacramento Municipal Utilty Distnct NA NA NA
5 Sacramento Municipal Utiity District SF NA NA NA
6 Salt River Project ~NA NA NA
7 Salt River Project SF NA NA NA
8 San Diego Gas & Electric Company SF NA NA NA
9 Sand Ranch Windfarm, LLC LU NA NA NA
10 Santiam Water Control District LU 0.2 0.2 0.2
11 Seattle City Light SF NA NA NA
12 Sempra Energy Solutions LLC SF NA NA NA
13 Sempra Energy Trading LLC SF NA NA NA
14 Sempra Generation SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.15
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo,. Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
.ccunt~~:n \ (Continued)(Including power exchanges)
AD - for out-of-period adjustrnent. 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, tariff 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 amonnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), andthe 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 iritegration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawaUhours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased.MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total Ü+k+l)No.Received Delivered ~l \~~\'1
of Settlement ($)
(g)(h)(i)(m)
21 13,79~13,793 1
199,170 2
219,00(3,519,33 3,519,330 3
143,800 4
20,42.736,68 736,687 5
4!1,531 6
235,64 7,963,85 7,963,892 7
6,431 241,93(241,930 8.
9,34!407,621 407,621 9
1,52'13,632 140,831 154,469 10
92,73'2,692,021 2,696,655 11
2,40(54,73 54,736 12
511,50A 25,579,03 6,975,690 13
5,901 212,35f 212,358 14
,
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211,64~
FERC FORM NO.1 (ED. 12-90)Page 327.15
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
PU~CHASED POWER Ifccu~t 555)
( ncluding 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 transacton in column (a). Do not abbreviate Or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service.must be the
same as, or second only to, the 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 àdverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availabilty and reliability of the designated unit.
IU - for intermiate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and servic from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average iweragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 SheH Energy North America (US), L.P.e NA NA NA
2 Shell Energy North America (US), L.P.NA NA NA
3 Sierra Pacific Power Company NA NA NA
4 Sierra Pacific Power Company SF NA NA NA
5 Simplot Phosphates, LLC LU 10 12 9
I~~.2.3 1.6 1.0
NA NA NA
8 Southem California Edison Company .NA NA NA
9 SOuthern California Edison Company NA NA NA
10 Southern California Edison Company SF NA NA NA
11 Southwestem Public Service Company =NA NA NA
12 Spanish Fork City NA NA NA
13 Spanish Fork Wind Park 2, LLC LU NA NA NA
14 Springvile City .NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.16
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo; Da, Yr)End of 2009/Q4
(2) r'A Resubmission 04/14/2010
.PI. ~CHA ccount.~~~L(Continued)"(Including power exchanges)
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 theFERC 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 serviceirwolving demand charges imposed on amonnthly (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 (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 (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in.column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered
~l \i~\'1
of Settlement ($)
(g)(h)(i)(m)
2E
"4,547 1
443,32(17,209,75 -1,417,101 2
c131 -7,190 3
9,07!259,01 279,429 4
72,20'395,200 2,749,24 3,144,443 5
7,86(119,741 754,531 874,272 6
77,63!2,219,04'2,219,045 7-280 8
41,79,832,48i 832,481 9
67,221 2,225,49~2,225,499 10
1,24\38,88'38,885 11
41 .3,78i 3,786 12
..
46,4H 2,407,17E 2,407,176 13
2~3,74f 3,748 14
11,462,391 14,027,658.14,213,609 124,783,622 782,136,868 -450,708,841 456,211,64~
FERC FORM NO.1 (ED. 12-90)Page 327.16
Name of Respondent ThiS~rIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) A Resubmission 04/14/2010
PU~CHAdTED POWER hACCUßt 555)(nclu ing power exc anges
1. Report all power purchases made during the year~ Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncte the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the supplier
includes projects load for this service in its system 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 "frm" means that service cannotbe 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 cateory should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the 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 those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate .Average Actal Demand (MW)
No.(Footnote Affliations)Classi Schedule or Monthly Billng Average AveragecatiTari Numbe Demand (MW)Monthly NCP Demal)Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Stahlbush Island Farms, Inc.IU NA NA NA
2 StraWberry Electric Service Distrct -NA NA NA
3 Sunderland Dairy Inc.LU 0.02 0.02 0.02
4 Sunnyside Cogeneration Associates LU 51.8 52.7 49.6
5 Tacoma, City of SF NA NA NA
6 Tesoro Refining and Marketing Company IU NA NA NA
7 Thayn Hydro LLC LU 0.3 0.4 0.3
8 The Energy Authori SF NA NA NA
9 Three Buttes Wind power, LLC LU NA NA NA
10 Threemile Canyon Wind i, LLC LU NA NA . ~NA
11 TransAlta Energy Marketing Inc.NA NA NA
12 TransAlta Energy Marketing Inc.IF NA NA NA
13 TransAlta Energy Marketing Inc.SF NA NA NA
14 TransCanada Energy Sales Ltd.SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.17
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (MQ, Da, Yr)End of 2009/Q4
(2) ÕA Resubmission 04/14/2010
v ,~, '~(í'='1 ccunt.~~~~)((;ontlnUed)Including power exchanges
AD - for out-of-period adjustment. Use this code for any accunting 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
idehtified in column (b), is provided.
5. For requirements RQ purchases and any typ.e 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 (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. 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 setternent 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 (9) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
~l \~~\'1
of Settlement ($)
(g)(h)(i)(m)
1,03~67,93~67,939 1
5t 4,63~4,639 2
10(1,296 3,2~4,534 3
410,93!10,377,743 14,657,321:25,035,069 4
38,65 986,OH -988,165 5
191,921 14,317,42 14,317,423 6
2,701 69,204 192,82t 262,032 7
42,63t 1,489,5Ot 1,489,506 8
39,97~2,399,39(2,399,390 9
8,1m 271,7m 271,709 10
19~10,510 11
1,315,20C 46,552,37 45,923,626 12
244,1gA 7,718,291:7,718,296 13
8,40C 389,5Oc 389,500 14
.
11,462,391 14,027,658 14,213,609 124,783,62.782,136,868 -450,708,841 456,211,64~
FERC FORM NO.1 (ED. 12-90)Page 327.17
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
PU~CHAJiED POWER hAccou1t 5 5)(nclu 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the 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 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 years or longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availabilty and reliability of the designated unit.
IU -for intermediate-term service frm a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature 01
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW).
No.(Footnote Affliations)Classifi-Schule or Monthly Billng Average AveragecationTanf Numbe Demand (MW)Monthly NCP Demani Monthly CP Demand
~
(c)(d)(e)(f)
35 33 30
2 Tri-State Generation & Transmission NA NA NA
3. Tri-State Generation & Transmission SF NA NA NA
4 Tucson Electric Power Company NA NA NA
5 Tucson Electric Power Company SF NA NA NA
6 Turlock Irrigation District SF NA NA NA
7 UBS Securities LLC SF NA NA NA
8 UBS Warburg Energy LLC SF 25 NA NA9 UNS Electric, Inc. SF NA NA NA~NA NA NA
11 Utah Municipal Power Agency NA NA NA
12 Utah Municipal Power Agency SF NA NA .NA
13 Wadeland South LLC LU 0.03 0.01 0.01
14 Wagon Trail, LLC LU NA NA NA
i
Total ~
FERC FORM NO.1 (ED. 12-90)Page 326.18
Name of Respondent This '00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
~ "' '~(íncii ccouRt.~~~L(contlnUed)Including power exc anges)
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-coincîdent peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour(60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)No.Received Delivered
~I \i~\fl
of Settlement ($)
(g)(h)(i)(m)
199,501 8,395,800 4,560,73C 12,956,530 1
71C 28,04C 28,040 2
39,73~1,358,38C f1 1,376,035 3
1,12f 13,70C 13,700 4
52,471 1 ,503,40~f1 1,505,271 5
2,40 75,4H 75,19 6
-15,264 7
80C 662,250 29,00 ø -3,630,182 8.
61€24,32C 24,320 9
3C 90(900 10
7,19~253,43 253,433 11.
2,93 105,68~105,689 12
41 571 1,31A 1,885 13
2,33..109,67 109,673 14
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211 ,64~
FERC FORM NO.1 (ED. 12-90)Page 327.18
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2009/Q4
(2) ¡=A Resubmission 04/14/2010
PU~CHAJlED POWER hACCOUW 5 5)(nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation th respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 frr service which meets
the definition of RQ service. For àll transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the 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 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 01
the serice in a footnote for each adjustment.
Line Name of Company or Public Authority Statistil FERC Rate Avera Actual Demand (MW)
No.(Footnote Affliations)Class-Schule or Monthly Billng Averae AveragecatiTari Numb Demand (MW)Monthly NCP Demani Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Walla Walla, City of LU 2.0 1.7 ..1.5
2 Ward Butte Windfarm, LLC LU NA NA NA
3 Warm Springs Forest Products LU NA NA NA
4 Weber County, State of Utah LU NA NA NA
5 Western Ar Power Administrtion "NA NA NA
6 Western Area Power Administration NA NA NA
7 Westem Area Power Administration SF NA NA NA
8 Wolverine Creek Energ LLC LU NA NA NA
9 Yakima-Tieton Irrgation District LU NA NA NA
10 Accrual True-up NA NA NA NA
11 Line Lóss Retum .AD NA NA NA
12 Bookout Purchases AD NA NA NA.
13 MWH Settlement AD NA NA NA
14 Trade Purchases AD NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.19
Name of Respondent This (80rlIS:Date of Report Year/Period of Report
PacifiCorp (1) X. An Onginal (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
ccouRt.~~~ucontlnued )~"~, "'(íncluding power exc anges)
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column G),energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. Ifmore energy was delivered than received, enter a negative amount. If the settlement amount (I)
include creaits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.
Received Delivered.
~I ~t~\'1
of Settlement ($)
(g)(h)(i)(m)
12,27E 140,750 1,620,40 1,761,157 1
6,29 281,29'281,294 2
1,68 41,28L 41,284 3
5,66!256,93E 256,936 4
1E 5
5~1,371 1,375 6
29,68~675'13~686,277 7
153,761 8,392,26'8,392,264 8
7,01.425,2!425,826 9
~19,889,611 10
-1,081,438 11
-9,811,71L -314,938,844 12
-1,128,353 13
-45,464,949 14
11,462,391 14,027,658 14,213,609 124,783,622 782,136,861:-450,708,841 456,211 ,64~
.,
FERC FORM NO.1 (ED. 12-90)Page 327.19
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
PU~CHAdlED POWER L,Accunt 555)
(nclu ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statisti.cal Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements servce is service which the supplier plans to provide on an ongoing basis (Le., the supplier
includes 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 "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 RQ serice. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and 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.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiriations)Classifi-Schedule or Monthly Biling Average AveragecationTariff Number Demand (MW) Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 liquiated Damage AD NA NA NA
2
3 Power Exchanges
4 Arizona Public service Company .306 NA NA NA
5 Arizona Public Service Company EX 306 NA NA NA
6 Avista Corporation EX 554 NA NA NA
7 Basin Electrc Power Cooperative EX T-11 NA NA NA
8 Black Hils Power, Inc.EX 246 NA NA NA
9 Bonnevile Power Administration 237 NA NA NA
10 Bonnvile Power Administration NA NA NA NA
11 Bonnevile Power Administration T-11 NA NA .NA
12 Bonnevile Power Administration T-12 NA NA ...NA
13 BonneviHe Power Administration EX 237 NA NA NA
14 Bonneville Powér Administration EX 256 NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.20
This ~ort Is:
(1) llAn Onginal
(2) A Resubmission
ccountIncluding power exchanges)
AD - for out-of-period adjustment. Use this code for any accunting adjustments or "true-ups" for service provided in prior reporting
years. . Provide an explanation in a footnote for each adjustment.
Date of Report
(Mo, Da, Yr)
04/14/2010
Year/Period of Report
End of 2009/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 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 (t). Forall 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 suppliets 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 types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote. .
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt HoursReceived Delivered(h) (i)Demand Charges
~l
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
\~l WI
LineTotal O+k+l) N
of Settlement ($) o.
(m)
-500,000 1
2
3
10,120 4
11,045,321 5
6
338,429 7
8
200 9
-1,136,133 10
-9,075 11
286,667 12
-87,922 13
-55,360 14
285
570,761
1,621
16,022
179
571,592
3,804
61,320
20
3,016
194
6,920 6,920
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211,64
FERC FORM NO.1 (ED. 12-90)Page 327.20
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission .04/14/2010
PU~CHAciED POWER hAccu1t 555)
(nclu 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ -for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the 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 transacton identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or sefler 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 fhis 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 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 trnsactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Moth Billng Average .
Average cation Tari Numbe Demand (MW)Monthly NCP Dean Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Bonnevile Power Administration EX 347 NA NA NA
2 Bonnevile Power Administration EX 368 NA NA NA
3 Bonnevile Power Administration EX 554 NA NA NA
4 Bonnevile Power Administration EX (16)NA NA NA
5 Bonneville Power Administration EX T-11 NA NA NA
6 Bonnevile Power Administration EX T-12 NA NA .NA
7 Chelan County PUD #1 EX 554 NA NA NA
8 Chelan County PUD #1 NA NA NA NA
9 Chelan County PUD #1 EX T-12 NA NA NA
10 Colockum Transmission Company EX T-12 NA NA NA
11 Constellation Energy Commodities Group EX T-11 NA NA NA
12 Cowlitz County PUD #1 EX 554 NA NA NA
13 Deseret Power Electric Cooperative 280 NA
..~
NA NA
14 Deseret Power Electc Cooperative EX 280 NA NA NA
Total
FERC FORM NO.1 (ED. 12.90)Page 326.21
Name of Respondent
PacifiCorp
_Year/Period of Report
End of 2009/Q4
This ~ort Is:
(1) ~AnOriginal
(2) A Resubmission
ccountIncluding power exchanges)
AD - for out-of-period adjustment. Use this code forany 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 (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0). energy charges in column (k), and the total. of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column(J. Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than iñè:remental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt HoursReceived Delivered(h) (i)
1,49,700 1,442,869
238,802 238,802
226,808 40,793
Demand Charges
~l
COST/SETTLEMENT OF POWER
Energy Charges Other Charges\~~ \ll LineTotal O+k+l) N
of Settlement ($) o.
(m)
-140,000 1
2
3
-32,071,635 4
67,935 5
823,209 6
7
8
9
10
2,487 11
12
149,873 13
-1,287,341 14
MegaWatt Hours
Purchased
12,223
98,817
1,711
170,681
408
32,326
8,732
86,417
16,969
856
30,809
268,153
1,610
205,669
-3,546
63,968
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211,64
FERC FORM NO.1 (ED. 12-90)Page 327.21
Name of Respondent This ~ort Is:Date of Reprt Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
PU~CHAcUED POWER hAccouW 555)
(nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
. acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the supplier
includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must be the
same as, or second only to, the suppliets 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 seiier can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliability of
sèrvice, 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 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 Authorit Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly Billng Average Average
cation Tari Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Emerald Peoples Utilty Distrct _351 NA NA NA
2 Emerald Peoples Utilty District EX 351 NA NA NA
3 Eugene Water & Electric Board EX T-12 NA NA NA
4 Grant County PUP #2 EX 554 NA NA NA
5 lberdrola Renewables, Inc.EX T-11 NA NA NA
6 Idaho Power Company EX 380 NA NA NA
7 Intermountan Renwable Power, LLC EX T-11 NA NA .NA
8 Los Angles Dept. of Water & Power EX OV-1 NA NA NA
9 Milford Wind Corrdor Phase i, LLC EX OV-1 NA NA NA
10 NextEra Energy Power Marketing, LLC EX T-11 NA NA NA
11 Portand General Electric Company EX 554 NA NA NA
12 Powerex Corporation EX T-11 NA NA NA
13 Public Service Company of Colorado EX 319 NA NA NA
14 Public Service Company of Colorado EX 320 NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.22
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/14/2010
Year/Period of Report
End of 2009/Q4
This ~ort Is:
(1) ~An Original
(2) A Resubmission
ccountIncluding power exchanges)
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, tariff 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-minuteintegration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
POWER EXCHANGES
MegaWatt Hours MegaWatt HoursReceived Delivered(h) (i)Demand Charges
~l
COST/SETTLEMENT OF POWER
Energy Charges Other Charges~i~ \'l Line
Total Ü+k+l)No.of Settlement ($)
(m)
93 1
-11,283 2
-13,283 3
4
140,424 5
6
4,938 7
84,693 8
-8,693 9
362,528 10
11
11,916 12
13
1,800,000 14
(g)
-4
451
16,435 16,559
37,574
14,605 9,039
263,500 237,712
1,827 1,754
1,360
1,360
10,897 538
154,417 153,258
909 496
6,095
437,975 437,565
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211,64
FERC FORM NO.1 (ED. 12-90)Page 327.22
-
Name of Respondent This Wor Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
PU~CHAJlED POWER hAccu~t 555)(nclu 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 resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The 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 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 forthose 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 Authori Statistil FERC Rate Average Actal Demand (MW)
No.(Footnote Affliations)Class-SCul or Monthly Billing Average AveragecationTari Number Demand (MW)Monthly NCP Demani Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Public Servce Company of Colorado JjNA NA NA NA
2 Public Service Company of Colorado EX T-12 NA NA NA
3 Redding, City of EX 364 NA NA NA
4 Seattle City Light EX 554 NA NA NA
5 Sempra Energy Solutions LLC "T-11 NA NA NA
6 Sempra Energy Solutions LLC EX T-11 NA NA NA
7 Tri-State Generation & Transmission 319 NA NA NA
8 Tri-State Generation & Transmission EX 319 NA NA NA
9 Tucson Electric Power Company NA NA NA NA
10 Utah Assoc. Municipal Power Systems T-11 NA NA NA
11 Utah Assoc. Municipal Power Systems EX T-11 NA NA NA
12 Utah Municipal Power Agency T-11 NA NA NA
13 Utah Municipal Power Agency EX T-11 NA NA NA
14 Warm Springs Power Enterprises EX T-11 NA NA .NA
Total -
FERC FORM NO.1 (ED. 12-90)Page 326.23
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is:
(1) \2AnOriginal
(2) A Resubmission
CCUtltIncluding power exchanges)
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
monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.Received Delivered ~l ~~~\'1
of Settlement ($)
(g)(h)(i)(m)
2,522 1
71,133 75,545 -374,024 2
116,859 117,279 18,811 3
295,482 301,430 -744,715 4
71 -377 17,988 5
6,259 2,484 90,67 6
8,085 7
6,095 40,200 8
10,589 9
346 -1,554 92,951 10
132,153 53,618 2,324,771 11
1 19 12
45,825 3,256 1,393,600 13
2,125 5,969 -131,098 14
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211,64
FERC FORM NO.1 (ED. 12-9Q)Page 327.23
Name of Respondent This lË0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmisson 04/14/2010
PU~CHAdTED POWERchAccuW 5 5)
( nclu . ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Gode 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 sùpplier
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
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availabilty and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-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 0
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actal Demand (MW)
No.(Footnote Affliations)Classif Schedule or Monthly Billng Average Average
cation Tari Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Western Area Power Administration ~LAS-4 NA NA NA
2 Western Area Power Administration EX 262 NA NA NA
3 Western Area Power Administration EX LAS-4 NA NA NA
4
5 System Deviation NA NA NA
6
7
8
9
10
11
12
13
14
Total
FERC FORM NO.1 (ED. 12-90)Page 326.24
Name of Respondent This 180rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
vow. .nìí~'" 0 . ccoun~~g~~:(l,ontlnUed)Including power exchange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting ..
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average 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 (t). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CPdemand 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. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
~I \~~\'1
of Settlement ($)
(g)(h)(i)(m)
3,136 -5,112 234,105 1
678 2
8,249 104,801 -918,019 3
4
31,351 5
6
7
8
9
10
11
12
13
14
11,462,391 14,027,658 14,213,609 124,783,622 782,136,868 -450,708,841 456,211 ,64~
FERC FORM NO.1 (ED. 12-90)Page 327.24
Name of Respondent This Report is:.Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009104
FOOTNOTE DATA
I$chedule Page: 326 Line No.: 3 Column: b
Settlement adjustment.
I§chedule Page: 326 Line No.: 3 Column: i
Settlement adjustment.
I§chedule Page: 326 Line No.: 5 Column: b
Seconda, economy and/or non-firm.
I§chedule Page: 326 Line No.: 7 Column: b
Settlement adjustment.
¡Schedule Page: 326 Line No.: 7 Column: i
Settlement adjustment.
I§chedule Page: 326 Line No.: 8 Column: b
Anzona Public Service - Contrct Termination Date: October 31,2020.
I§chedule Page: 326 Line No.: 9 Column: b
Secondar, economy and/or non-fii.
¡Schedule Page: 326 Line No.: 11 Column: b
Secondary, economy and/or non-firm.
¡Schedule Page: 326 Line No.: 11 Column: i
Liabil associated with paper ond at h dro facil located on the Lewis River in the state of Washington.
chedule Page: 326 Line No.: 12 Column: i
Reserve Share.
¡Schedule Page: 326 Line No.: 14 Column: i
Financial Swap.
!tchedule Page: 326.1 Line No.: 1 Column: b
Settlement adjustment.
I§chedule Page: 326.1 Line No.: 1 Column: i
Settlement adjustment.
¡Schedule Page: 326.1 Line No.: 3 Column: b
Settlement adjustment.
I§chedule Page: 326.1 Line No.: 3 Column: i
Settlement adjustment.
I§chedule Page: 326.1 Line No.: 4 Column: i
Financial Swap.
I§chedule Page: 326.1 Line No.: 5 Column: b
Under Electrc Service Agreement subject to termation upon tiely notification.
!tchedule Page: 326.1 Line No.: 6 Column: i
Damages for non-deliver of generation.
I§chedule Page: 326.1 Line No.: 8 Column: a
Com lete name is Public Utility Distrct NO.1 of Benton Coun
chedule Pa e: 326.1 Line No.: 10 Column: i
Non- eneration agreement.
chedule Pa e: 326.1 Line No.: 12 Column: b
Settlement adjustment.
I§chedule Page: 326.1 Line No.: 12 Column: i
Operation and maintenance expense associated with the combustion tubine located in Rapid City, South Dakotà.
!tchedule Page: 326.1 Line No.: 13 Column: i
Operation and maintenance expense associated with the combustion tubine located in Rapid Ci , South Dakota.
chedule Pa e: 326.1 Line No.: 14 Column: b
Secondar, econom and/or non-firm.
chedule Pa e: 326.2 Line No.: 3 Column: b
Blandig City - Contrt Terination Date: March 31, 2012.
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 I (2) A Resubmission 04/14/2010 .2009/Q4
FOOTNOTE DATA
.
!Schedule Page: 326.2 Line No.: 5 Column: b
Settlement ad'ustment.
chedule Pa e: 326.2 Line No.: 5 Column: i
Operating reserves.
!Schedule Page: 326.2 Line No.: 6 Column: b
Bonnevile Power Admnistration - Contract Termination Date: August 31,2011.
¡Schedule Page: 326.2 Line No.: 7 Column: b
Bonnevile Power Admnistration - Contract Termnation Date: 30 days wrtten notice.
!Schedule Page: 326.2 Line No.: 7 Column: i
Operating reserves.
!Schedule Page: 326.2 Line No.: 8 Column: b
Seconda, economy and/or non-firm.
!Schedule Page: 326.2 Line No.: 8 Column: i
Operating reserves.
!Schedule Page: 326.2 Line No.: 9 Column: b
Settlement adjustment.
¡Schedule Page: 326.2 Line No.: 9 Column: i
Reserve Share.
!Schedule Page: 326.2 Line No.: 10 Column: i
Reserve Share.
!Schedule Page: 326.2 Line No.: 11 Column: b
1 Settlement adjustment.
!Schedule Page: 326.2 Line No.: 11 Column: i
Settlement adjustment.
!Schedule Page: 326.3 Line No.: 1 Column: b
Settlement adjustment.
!Schedule Page: 326.3 Line No.: 1 Column: i
Settlement adjustment.
!Schedule Page: 326.3 Line No.: 3 Column: b
Settlement adjustment.
!Schedule Page: 326.3 Line No.: 3 Column: i
Settlement adjustment.
!Schedule Page: 326.3 Line No.: 4 Column: b
Secondar, economy and/or non-firm.
!Schedule Page: 326.3 Line No.: 7 Column: a
1 THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "CHELAN COUNTY PUD #1" ONPAGES 326-326.24:
Complete name is Public Utility Distrct No. 1 of Chelan County.
!Schedule Page: 326.3 Line No.: 7 Column: i
Opeatin expense, bond interest, amortization and taxes.
chedule Pa e: 326.3 Line No.: 8 Column: i
Reserve Share.
¡Schedule Page: 326.3 Line No.: 10 Column: b
Settlement adjustment.
!Schedule Page: 326.3 Line No.: 10 Column: i
Settlement adjustment.
!Schedule Page: 326.3 Line No.: 11 Column: i
Financial Swap.
!Schedule Page: 326.3 Line No.: 14 Column: b
Settlement adjustment.
!Schedule Page: 326.3 ~ Line No.: 14 Column: i
Settlement adjustment.
IFERC FORM NO.1 (ED. 12-S7) Page 450.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp 1(2) A Resubmission 04/14/2010 2009/Q4
..FOOTNOTE DATA
!ßchedule Page: 326.4 Line No.: 5 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "CONSTELLATION ENERGY COMMODITIES GROUP" ON
PAGES 326-326.24:
Complete name is Constellation Energy Commodities Group, Inc.
~chedule Page: 326.4 Line No.: 5 Column: b
Settlement adjustment.
~chedule Page: 326.4 Line No.: 5 Column: i
Settlement adjustment.
~chedule Page: 326.4 Line No.: 6 Column: b
Secon , economy and/or non-firm.
chedule Page: 326.4 Line No.: 7 Column: i
Financial Swap.
I$chedule Page: 326.4 Line No.: 9 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "COWLITZ COUNTY PUD #1" ON PAGES 326-326.24:
Complete name is Public Utility Distnct NO.1 of Cowlitz County.
~chedule Page: 326.4 Line No.: 9 Column: b
Secondar, economy and/or non-firm.
~chedule Page: 326.4 Line No.: 9 Column: i
Liability associated with paper pond at hydro facilty located on the Lewis River in the state of Washington. ¡Schedule Page: 326.4 Line No.: 10 Column: b
Settlement adjustment.
~chedule Page: 326.4 Line No.: 10 Column: i
Settlement adjustment.
I$chedule Page: 326.4 Line No.: 11 Column: i
Financial Swap.
I$chedule Page: 326.5 Line No.: 1 Column: b
Settlement adjustment.
~chedule Page: 326.5 Line No.: 1 Column: i
Settlement adjustment.
I$chedule Page: 326.5 Line No.: 4 Column: b
Deseret Generation & Transmission - Contrct Teration Date: September 30, 2024.
I$chedule Page: 326.5 Line No.: 4 Column: i
Operation and maintenance expense associated with a coal tid genertig facilty located in Vernl, Utah.
I$chedule Page: 326.5 Line No.: 5 Column: i
Financial Swap.
~chedule Page: 326.5 Line No.: 6 Column: b
Settlement adjustment.
I$chedule Page: 326.5 Line No.: 6 Column: i
Settlement adjustment.
I$chedule Page: 326.5 Line No.: 8 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCUNCES OF "DOUGLAS COUN PUD #1" ON PAGES 326-326.24:
Com lete name is Public Utili Distrct No. 1 ofDou las Coun
chedule Pa e: 326.5 Line No.: 8 Column: b
Settlement adjustment.
I$chedule Page: 326.5 Line No.: 8 Column: i
Settlement adjustment.
~chedule Page: 326.5 Line No.: 9 Column: b
Settlement adjustment.
~chedule Page: 326.5 Line No.: 9 Column: i
Operating expense, bond interest, amortization and taes.
~chedule Page: 326.5 Line No.: 10 Column: i
IFERC FORM NO.1 (ED. 12-87) Page 450.3
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/04
FOOTNOTE DATA . ~.
Operting expense, bond interest, amortzation and taxes.
I$chedule Page: 326.5 Line No.: 11 . Column: b
Seconda, economy and/or non-fi.
¡Schedule Page: 326.5 Line No.: 12 Column: i
Reserve Share.
!Šchedule Page: 326.6 Line No.: 3 Column: b
Secondar, economy and/or non-firm.
I$chedule Page: 326.6 Line No.: 4 Column: i
Financial Swap.
I$chedule Page: 326.6 Line No.: 6 Column: b
Settlement adjustment.
¡Schedule Page: 326.6 Line No.: 6 Column: i
Line loss.
I$chedule Page: 326.6 Line No.: 7 Column: i
Line loss.
I$chedule Page: 326.6 Line No.: 11 Column: b
Settlement adjustment.
I$chedule Page: 326.6 Line No.: 11 Column: i
Settlement adjustment.
I$chedu/e Page: 326.7 Line No.: 3 Column: b
Under Electrc Service Agreement subject to terination upon tiely notification.
¡Schedule Page: 326.7 Line No.: 5 Column: i
Financial Swap.
¡Schedule Page: 326.7 Line No.: 9 Column: b
Secondary, economy and/or non-firm.
I$chedule Page: 326.7 . Line No.: 12 Column: b
Secondar, economy and/or non-firm.
I$chedule Page: 326.8 Line No.: 1 Column: b
Under Electrc Service Agreement subject to termination upon tiely notification.
I$chedule Page: 326.8 Line No.: 2 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "GRANT COUNTY PUD #2" ON PAGES 326-326.24:
Com lete name is Public Utili Distrct NO.2 of Grant Coun
Schedule Pa e: 326.8 Line No.: 2 Column: b
Settlement adjustment.
I$chedule Page: 326.8 Line No.: 2 Column: i
Operating expense, bond interest, amortization and taes.
I$chedule Page: 326.8 Line No.: 3 Column: b
Settlement ad'ustment.
chedule Page: 326.8 Line No.: 3 Column: /
Ancí1ar services and cost recovery adjustment.
I$chedule Page: 32~.8 Line No.: 4 Column: b
Grant County Public Utí1ty Distrct NO.2 - Contract Termination Date: 2 year wrtten notice.
I$chedule Page: 326.8 Line No.: 4 Column: i
Ancí1ar services and cost recovery adjustment.
I$chedule Page: 326.8 Line No.: 5 Column: i
Operatig expense, bond interest, amortization and taxes.
I$chedule Page: 326.8 Line No.: 6 Column: b
Seconda, economy and/or non-firm.
I$chedule Page: 3~6.8 Line No.: 6 Column: i
Liability associated with paper pond at hydro fací1ty located on the Lewis Rivet in the state of Washington.
I$chedule Page: 326.8 Line No.: 7 Column: i
I FERC FORM NO.1 (ED. 12-87) Page 450.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA
.
Reserve Share.
'$chedule Page: 326.8 Line No.: 8 Column: b
Under Electrc Service Agreement subject to termination upon tiely notification.
'$chedule Page: 326.8 Line No.: 9 Column: a
Hermston Generating Company, L.P. operates the Hermston Generatig Plant, which isjointly owned. PacifiCorp owns 50% of the
plant. See page 402.3 column (c) of this Form NO.1 for fuer information on the Hermston Generting Plant.
'$chedule Page: 326.8 Line No.: 9 Column: b
Settlement adjustment.
'$chedule Page: 326.8 Line No.: 9 Column: i
Settlement adjustment. On peak incentive, supplementa dispatch effciency expense, sta-up charges and committee settlements.
'$chedule Page: 326.8 Line No.: 10 Column: a
Hermiston Generating Company, L.P. operates the Hermston Generatig Plant, which is jointly owned. PacifiCorp owns 50% of the
plant. See page 402.3 column (c) of this Form No.1 for fuer information on the Hermiston Generating Plant.
'$chedule Page: 326.8 Line No.: 10 Column: i .1
On peak incentive, supplemental dispatch effciency expense, sta-up charges and committee settlements. '$chedule Page: 326.8 Line No.: 12 Column: b I
Hurcane, City of - Contract Termination Date: August 31,2012.
'$chedule Page: 326.8 Line No.: 13 Column: b I
Settlement adjustment.
'$chedule Page: 326.8 Line No.: 13 Column: i I
Settlement adjustment.
'$chedule Page: 326.8 Line No.: 14 Column: i I
Financial Swap.
'$chedule Page: 326.9 Line No.: 1 Column: i I
Labor, e uipment and administrtion fees associated with h dro ro'ect in Idaho Falls, Idao.
chedule Pa e: 326.9 Line No.: 2 Column: b
Settlement adjustment.
'$chedule Page: 326.9 Line No.: 2 Column: i
Settlement adjustment.
'$chedule Page: 326.9 Line No.: 3 Column: b
Seconda, econom and/or non-firm.
chedule Page: 326.9 Line No.: 4 Column: i
Line loss.
'$chedule Page: 326.9 Line No.: 5 Column: i
Reserve Share.
'$chedule Page: 326.9 Line No.: 8 Column: b
Secondary, economy and/or non-fi.
'$chedule Page: 326.9 Line No.: 9 Column: b
Settlement adjustment.
'$chedule Page: 326.9 Line No.: 9 Column: i
Settlement adjustment.
¡Schedule Page: 326.9 Line No.: 10 Column: i
Financial Swap.
'$chedule Page: 326.9 Line No.: 11 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "J.P. MORGAN VENTS ENERGY CORP." ON PAGES
326-326.24:
Complete name is J.P. Morgan Ventus Ener Corporation.
chedule Pa e: 326.9 Line No.: 11 Column: b
Seconda, economy and/or non-firm.
'$chedule Page: 326.9 Line No.: 12 Column: i
Financial Swap.
IFERC FORM NO.1 (ED. 12-S7) Page 450.5
...'
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA .
!Schedule Page: 326.9 Line No.: 13 Column: a
Complete name is JPMorgan Chase Ban, National Association.
!Schedule Page: 326.9 Line No.: 13 Column: i
Financial Swap.
l$chedule Page: 326.10 Line No.: 1 Column: i
Compensation for self-generation.
!Schedule Page: 326.10 Line No.: 3 Column: i
Fixed annual payment.
l$chedule Page: 326.10 Line No.: 5 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "LOS ANGELES DEPT. OF WATER & POWER" ON PAGES
326-326.24:
Complete name is Los Angeles Deparent of Water and Power.
!Schedule Page: 326.10 Line No.: 5 Column: b
Settlement adjustment.
¡Schedule Page: 326.10 Line No.: 5 Column: i
Settlement adjustment.
l$chedule Page: 326.10 Line No.: 6 Column: b
Secondary, economy and/or non-firm.
!Schedule Page: 326.10 Line No.: 6 Column: i
Operating reserves.
!Schedule Page: 326.10 Line No.: 7 Column: I
Line loss.
!Schedule Page: 326.10 Line No.: 10 Column: i
Financial Swap.
¡Schedule Page: 326.10 Line No.: 12 Column: b
Ma esium Co oration of America - Contract Termination Date: December 31,2009.
chedule Pa e: 326.10 Line No.: 12 Column: i
Operating reserves.
¡Schedule Page: 326.11 Line No.: 4 Column: i
Compensation for intern tible service and operating reserves.
chedule Pa e: 326.11 Line No.: 5 Column:b
Under Electrc Service Agreement sub'ect to termination upon timel notification.
chedule Pa e: 326.11 Line No.: 6 Column: b
Settlement adjustment.
l$chedule Page: 326.11 Line No.: 6 Column: i
Settlement adjustment.
l$chedule Page: 326.11 Line No.: 8 Column: i
Financial Swap.
!Schedule Page: 326.11 Line No.: 10 Column: b
Settlement adjustment.
!Schedule Page: 326.11 Line No.: 10 Column: i
Settlement adjustment.
!Schedule Page: 326.11 Line No.: 11 Column: i
Damages for non-delivery of generation.
l$chedule Page: 326.11 Line No.: 13 Column:b
Under Electrc Service Agreement subject to termination upon tiely notification.
!Schedule Page: 326.11 Line No.: 14 Column: b
, Settlement adjustment.
!Schedule Page: 326.11 Line No.: 14 Column: i
Line loss.
l$chedule Page: 326.12 Line No.: 1 Column: i
I FERC FORM NO. 1 (ED. 12-87) Page 450.6
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Line loss.
!Schedule Page: 326.12 Line No.: 2 Column: b
Settement adjustment.
¡Schedule Page: 326.12 Line No.: 2 Column: i
Settlement adustment.
chedule Pa e: 326.12 Line No.: 5 Column: i
Reserve Share.
I$chedule Page: 326.12 Line No.: 7 Column: i
Operating reserves.
I$chedule Page: 326.12 Line No.: 10 Column: a
Complete name is Odell Creek Hydroelectrc Investors, Ltd.
I$chedule Page: 326.13 Line No.: 2 Column: a
Complete name is Pacific Nortwest Generating Cooperative.
I$chedule Page: 326.13 . Line No.: 3 Column: b
Settlement adjustment.
I$chedule Page: 326.13 Line No.: 3 Column: i
Settlement adjustment.
I$chedule Page: 326.13 Line No.: 5 Column: b
Secondary, economy and/or non-firm.
I$chedule Page: 326.13 Line No.: 6 Column: b
Under Electrc Service Agreement subject to teration upon timely notification.
I$chedule Page: 326.13 Line No.: 7 Column: i
Line loss.
I$chedule Page: 326.13 Line No.: 8 Column: b
Settlement adjustment.
I$chedule Page: 326.13 Line No.: 8 Column: i
Operation expense plus amortzation of unecovered costs of Cove Project.
I$chedule Page: 326.13 Line No.: 9 Column: b
Portland Generl Electrc Company - Contract Termation Date: Round Butt project no longer operting for power production
puroses.
!Schedule Page: 326.13 Line No.: 9 Column: i
Operation expense plus amortzation of unrecovered costs of Cove Project.
I$chedule Page: 326.13 Line No.: 10 Column: i
Reserve Share.
¡Schedule Page: 326.13 Line No.: 13 Column: b
Under Electrc Service Agreement subject to termination u on tiely notification.
chedule Pa e: 326.13 Line No.: 14 Column: b
Settlement adjustment.
I$chedule Page: 326.13 Line No.: 14 Column: i
Settlement adjustment.
I$chedule Page: 326.14 Line No.: 2 Column: i
Line loss.
I$chedule Page: 326.14 Line No.: 3 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PUD #1 OF LEWIS COUNTY" ON PAGES 326-326.24:
Com 1ete name is Public Utili Distrct No.1 of Lewis Coun
chedule Pa e: 326.14 Line No.: 3 Column: b
Settlement adjustment.
I$chedule Page: 326.14 Line No.: 3 Column: i
Settlement adjustment.
I$chedule Page: 326.14 Line No.: 4 Column: b
Public Utility Distct NO.1 of Lewis County - Contrct Ternation Date: 60 days wrtten notice.
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 1(2) . A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
'¡Chedule Page: 326.14 Line No.: 5 Column: i
Reserve Share.
'¡chedule Page: 326.14 Line No.: 7 Column: b
Secondar, economy and/or non-firm.
'¡chedule Page: 326.14 Line No.: 11 Column: b
Seconda, economy and/or non-firm.
'¡chedule Page: 326.15 Line No.: 2 Column: b
Settlement adjustment.
'¡chedule Page: 326.15 Line No.: 2 Column: i
Settlement adjustment.
'¡chedule Page: 326.15 Line No.: 3 Column: b
Sacramento Municipal Utility Distrct - Contrct Termnation Date: December 31, 2014.
'¡chedule Page: 326.15 Line No.: 4 Column: b
Secondary, economy and/or non-firm.
'¡chedule Page: 326.15 Line No.: 4 Column: i
Operating reserves.
'¡Chedule Page: 326.15 Line No.: 6 Column: b
Settlement adjustment.
'¡chedule Page: 326.15 Line No.: 6 Column: i
Settlement adjustment.
'¡chedule Page: 326.15 Line No.: 7 Column: i
Line loss.
'¡chedule Page: 326.15 Line No.: 11 Column: i
Reserve Share.
'¡chedule Page: 326.15 Line No.: 13 Column: i
Financial Swap.
'¡chedule Page: 326.16 Line No.: 1 Column: b
Settlement adjustment.
'¡chedule Page: 326.16 Line No.: 1 Column: i
Settlement adjustment.
ISchedule Page: 326.16 Line No.: 2 Column: i
Financial Swap.
'¡chedule Page: 326.16 Line No.: 3 Column: b
Settlement adjustment.
ISchedule Page: 326.16 Line No.: 3 Column: i
Settlement adjustment.
'¡chedule Page: 326.16 Line No.: 4 Column: i
Reserve Share and Line loss.
'¡chedule Page: 326.16 Line No.: 7 Column: a
Complete name is Public Utiltiy Distrct No.1 of Snohomish County.
'¡chedule Page: 326.16 Line No.: 8 Column: b
Settlement adjustment.
'¡chedule Page: 326.16 Line No.: 8 Column: i
Settlement adjustment.
'¡chedule Page: 326.16 Line No.: 9 Column: b
Secondary, economy and/or non-firm.
'¡chedule Page: 326.16 Line No.: 12 Column: b
Under Electrc Service Agreement subject to termination upon tiely notification.
'¡chedule Page: 326.16 Line No.: 14 Column: b
Under Electrc Service Agreement sub' ect to terination u on time! notification.
chedule Pa e: 326.17 Line No.: 2 Column: b
I FERC FORM NO. 1 (ED. 12-87) Page 450.8
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Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp I (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Under Electrc Service Agreement subject to termination upòn tiely notification.
!Schedule Page: 326.17 Line No.: 5 Column: i
Resere Share.
I$chedule Page: 326.17 Line No.: 11 Column: b
Settlement adjustment.
!SChedule Page: 326.17 Line No.: 11 Column: i
Settlement adjustment.
!Schedule Page: 326.17 Line No.: 12 Column: i
Operating reserve reimbursement.
I$chedule Page: 326.18 Line No.: 1 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "TR-STA TE GENERA nON & TRNSMISSION" ON PAGES
326-326.24:
Complete name is Tri-State Generation and Transmission Association, Inc.
!Schedule Page: 326.18 Line No.: 1 Column: b
Tri-State Generation & Transmission - Contract Termination Date: December 31, 2020.
l§chedule Page: 326.18 Line No.: 2 Column: b
Seconda, economy and/or non-firm.
!Schedule Page: 326.18 Line No.: 3 Column: i
Line loss.
l§chedtile Page: 326.18 Line No.: 4 Column: b
Secondar, economy and/or non-firm.
l§chedule Page: 326.18 Line No.: 5 Column: i
Line loss.
I$chedule Page: 326.18 Line No.: 7 Column: i
Financial Swa .
chedule Pa e: 326.18 Linè No.: 8 Column: i
Financial Swap.
!Schedule Page: 326.18 Line No.: 10 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "UTAH ASSOC. MUCIPAL POWER SYSTEMS" ON PAGES
326-326.24:
Complete name is Utah Associated Municipal Power Systems.
l§chedule Page: 326.18 Line No.: 11 Column: b
Secondar, economy and/or non-firm.
I$chedule Page: 326.19 Line No.: 5 Column: b
Settlement adjustment.
l§chedule Page: 326.19 Line No.: 6 Column: b
Seconda, economy and/or non-firm.
l§chedule Page: 326.19 Line No.: 7 Column: i
Reserve Share and Line loss.
l§cheduJe Page: 326.19 Line No.: 10 Column: i
Represents the difference between actul purchase expenses for the peod as reflected on the individual line items within this
schedule, and the accruals charged to account 555 dur this 'od and excess net wer cost deferrals.
chedule Page: 326.19 Line No.: 11 Column: i
Delivery of energy to settle loss dispute.
l§chedule Page: 326.19 Line No.: 12 Column: i
Recognition and re ortg of gains and losses on bookouts under authoritative guidance.
chedule Page: 326.19 Line No.: 13 Column: i
Liability associated with settlement for unmeteed megawatt hour.
l§chedule Page: 326.19 Line No.: 14 Column: i
Recognition and reportg of gains and losses on energy trading contrcts under authoritative guidace.
l§chedule Page: 326.20. Line No.: 1 Column: i
IFERC FORM NO. 1 (ED. 12-87) Page 450.9
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Oa, Yr)
PacifiCorp 1(2) . A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Damages associated with Naughton plant overhaul dèlay.
¡Schedule Page: 326.20 Line No.: 4 Column: b
Settlement ad'ustment.
chedule Page: 326.20 Line No.: 4 Column: i
Exchange energy expense.
¡Schedule Page: 326.20 Line No.: 5 Column: i
Exchange energy expense.
¡Schedule Page: 326.20 Line No.: 7 Column: i
Imbalance energy.
¡Schedule Page: 326.20 Line No.: 9 Column: b
Settlement adjustment.
¡Schedule Page: 326.20 Line No.: 9 Column: i
Load factonng and storage charges.
¡Schedule Page: 326.20 Line No.: 10 Column: b
Settlement adjustment.
¡Schedule Page: 326.20 Line No.: 10 Column: i
Pacific Northwest Electrc Power Planning and Conservation Act, FERC Electrc Tarff, Onginal Volume NO.1.
¡Schedule Page: 326.20 Line No.: 11 Column: b
Settlement adjustment.
¡Schedule Page: 326.20 Line No.: 11 Column: i
Imbalance energy.
¡Schedule Page: 326.20 Line No.: 12 Column: b
Settlement adjustment.
¡Schedule Page: 326.20 Line No.: 12 Column: i
Exchan e ener ex ense and Imbalanèe ener
chedule Pa e: 326.20 Line No.: 13 Column: i
Load factonng and storage charges.
¡Schedule Page: 326.20 Line No.: 14 Column: i
Load factonng and storage charges.
¡Schedule Page: 326.21 Line No.: 1 Column: i
Exchange energy expense.
¡Schedule Page: 326.21 Line No.: 4 Column: h
These megawatt hours represent book entr only. No actual energy transfer took place.
¡Schedule Page: 326.21 Line No.: 4 Column: i
These megawatt hours re resent book entr only. No actual energy transfer took place.
chedule Pa e: 326.21 Line No.: 4 Column: i
Pacific Northwest Electrc Power Planning and Conservation Act, FERC Electrc Tarff, Onginal Volume NO.1.
¡Schedule Page: 326.21 Line No.: 5 Column: i
Imbalance energy.
¡Schedule Page: 326.21 Line No.: 6 Column: i
Exchange energy expense and Imbalance energy.
¡Schedule Page: 326.21 Line No.: 8 Column: b
Not ap licable: adjustment for inadvertent interchange.
chedule Pa e: 326.21 Line No.: 11 Column: i
Imbalance energy.
¡Schedule Page: 326.21 Line No.: 13 Column: b
Settlement adjustment.
¡Schedule Page: 326.21 Line No.: 13 Column: i
Imbalance energy.
¡Schedule Page: 326.21 Line No.: 14 Column: i
Imbalance energy.
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 ì2) A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA
I$chedule Page: 326.22 Line No.: 1 Column: b
Settlement adjustment.
I§chedule Page: 326.22 Line No.: 1 Column: i
Load factoring and storage charges.
I$chedule Page: 326.22 Line No.: 2 Column: i
Load factoring and storage charges.
!schedule Page: 326.22 Line No.: 3 Column: i
Exchange energy expense.
!schedule Page: 326.22 Line No.: 5 Column: i
Imbalance energy.
!schedule Page: 326.22 Line No.: 7 Column: i
Imbalance energy.
!schedule Page: 326.22 Line No.: 8 Column: i
Station service for third par wind project.
!schedule Page: 326.22 Line No.: 9 Column: i
Reimbursement for providing station service to third par wind project.
!schedule Page: 326.22 Line No.: 10 Column: i
Imbalance energy.
!schedule Page: 326.22 Line No.: 12 Column: i
Imbalance energy.
!schedule Page: 326.22 Line No.: 14 Column: i
Load factoring and storage charges.
!schedule Page: 326.23 Line No.: 1 Column: b
Not applicable: adjustment for inadvertent interchange.
!schedule Page: 326.23 Line No.: 2 Column: i
Exchange energy expense.
!schedule Page: 326.23 Line No.: 3 Column: i
Exchange energy expense.
!schedule Page: 326.23 Line No.: 4 Column: i
Exchange energy expense.
!schedule Page: 326.23 Line No.: 5 Column: b
Settlement adjustment.
!schedule Page: 326.23 Line No.: 5 Column: i
Imbalance energy.
!schedule Page: 326.23 Line No.: 6 Column: i
Imbalance energy.
!schedule Page: 326.23 Line No.: 7 Column: b
Settlement ad'ustment.
chedule Page: 326.23 Line No.: 7 Column: i
Imbalance energy.
!schedule Page: 326.23 Line No.: 8 Column: i
Imbalance energy.
!schedule Page: 326.23 Line No.: 9 Column: b
Not applicable: adjustment for inadvertent intechange.
!schedule Page: 326.23 Line No.: 10 Column: b
Settlement adjustment.
!schedule Page: 326.23 Line No.: 10 Column: i
Imbalance energy.
!schedule Page: 326.23 Line No.: 11 Column: i
Imbalance energy.
!schedule Page: 326.23 Line No.: 12 Column: b
I FERC FORM NO. 1 (ED. 12-87) Page 450.11
Name of Respondeht This Report is:Date of Report YearlPeriod of Report
(1) 6 An Original (Mo, Da, Yr)
PacifiCorp ¡ (2) . A Resubmission 04/14/2010 2009/04 . .
FOOTNOTE DATA
Settlement adjustment.
!Schedule Page: 326.23 Line No.: 12 Column: i
Imbalance energy.
¡Schedule Page: 326.23 Line No.: 13 Column: i
Imbalance energy.
!$chedule Page: 326.23 Line No.: 14 Column: i
Imbalance ener .
chedule Page: 326.24 Line No.: 1 Column: b
Settlement adjustnent.
!Schedule Page: 326.24 Line No.: 1 Column: i
Imbalance energy.
!Schedule Page: 326.24 Line No.: 3 Column: i
Imbalance energy.
!Schedule Page: 326.24 Line No.: 5 Column: b
Not applicable: adjustment for inadvertent interchange.
IFERC FORM NO.1 (ED. 12-87)Page 450.12
Name of Respondent
PacifiCorp
This ~ort Is:
(1) IlAn Original
(2) A Resubmission
Year/Period of Report
End of 2009/Q4
Date of Report
(Mo, Da, Yr)
04/14/2010
ccunt
(Including transactons referred to as 'weeling')
1. Report all transmission of electricity, Le., Wheeling, provided for other electric utilties, cooperatives, other public authorities, qualifying
facilities, non-traditional utility suppliers and.ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.Provide the full name of each company or public auority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation 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 serice 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 eachadjustmenLSee General Instruction for definitions of codes.
Line Payment By
No.(Company of Public Authority)
(Footnote Affliation)
(a)
1 Basin Electric Power Cooperative
2 Basin Electric Power Cooperative
3 Basin Electric Power Cooperative
4 Basin Electric Power Cooperative
5 Basin Electric Power Cooperative
6 Bear Energy, LP
7
8 Black Hils/Colorado Elec. ut. Co.
9 Black Hils, Inc.
10 Black Hils, Inc.
11 Black Hils, Inc.
12 Black Hils, Inc.
13 Black Hils, Inc.
14 Black Hils, Inc.
15 Bonnevile Power Administration
16 Bonnevile Power Administration
17 Bonnevile Power Administration
18 Bonnevile Power Administration
19 Bonnevile Power Administration
20 Bonnevile Power Ädministration
21 Bonnevile Power Administration
22 Bonnevile Power Administration
23 Bonneville Power Administration
24 Bonnevile Power Administration
25 Bonneville Power Administration
26 Bonnevile Power Administration
27 Bonneville Power Administration
28 Bonnevile Power Administration
29 Bonnevile Power Administration
30 Bonnevile Power Administration
31 Bonnevile Power Administration
32 Bonnevile Power Administration
33 Bonnevile Power Administration
34 Bonnevile Power Administration
Energy Received From
(Company of Public Authority)
(Footnote Affliation)
(b)
Westem Area Power Administrtion
Westem Area Powr Administration
Westem Are Power Administration
Westem Area Power Administration
Energy Delivered To
(Company of Public Authority)
(Footnote Affliation)
(c)
Statistical
Classif-
cation
(d)
Bonevile Power Administrtion
Bonnele Power Administrtion
Bonneville Power Administration
Bonnevile Power Administration
Bonneville Power Administration
Bonnevile Power Administration
Bonneville Power Administration
Bonnevile Power Administrtion
Montana-Dakota Utilties Co.
Montana-Dakota Utilties Co.
Black Hils, Inc.
Black Hils, Inc.
Bonnevile Power Administration
Bonnevile Power Administration
Bonnevile Power Administration
Bonnevile Power Administration
Umpqua Indian Utilty Cooperative
Umpqua Indian Utilty Cooperative
United States Bure of Recam.
Bonneville Power Administrtion
BonnevHle Power Admiistrtion
Bonneville Power Administrtion
Bonnevile Power Admiistration
Bonnevile Power Administration
Bonnevile Power Administrtion
Bonnevile Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Yakama Power
Yakama Power
Bonnevile Power Administration
Bonnevile Power Administration
Bonneville Power Administrtion
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328
Name of Respondent This l80rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
I .. t:Lt:i. I KI~II Y ~"v " ,'-".. v cqunt 456)(Contlnued)--
(Including transactions reffered to as 'wtìeehng')
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 deli\leredas specified in the
contract.
7. Report in column (h) the number of megawatts of billng demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and Ol the total megaw¡;tth()urs received and delivered.
FERC Rate Point of Receipt Point of Delivery BUling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand ~egaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received.Delivered
(e)(f)(g)(h)(i)0)
7V11-3,4 Yellowtil Sub Sheridan Sub 22 134,691 134,691 1
7V11-3,4 Yellowtail Sub Sheridan Sub 9,997 9,99 2
7V11 Yellowtil Sub Sheridan Sub 11 53,955 53,95!3
7V11 Yellowtail Sub Sheridan Sub 4,550 4,55(4
7V11-8 Various Various 26,300 26,30(5
7V11-8 7V11-8 7V11-8 6
7V11-7 Various Various 26 2t 7
7V11-8 Various Various 328 32€8
7V11-8 Various Various 33,062 33,06"9
7V11-8 Various Various 1,616 1,61€10
7V11 Various Sheridan Sub 43 131,401 131,401 11
7V11 Various .Sheridan Sub 28,575 28,57E 12
7V11-7 Various WyodakSub 50 157,764 157,764 13
7V11-7 Various WyodakSub 15,384 15,384 14
RS.237 Various Various 310 1,432,798 1,432,79f 15
RS.237 Various Various 132,958 132,95f 16
RS.324 Lost Creek Hydro Pit Various 261,370 261,37C 17
R.S.324 Lost Creek Hydro Pit Various 15,778 15,77 18
7V11-3,4 Bonnevile Power Ad Gazley Substation 3 23,861 23,861 19
7V11-3 Bonnevile Power Ad Gazley Substation 2,274 2,27'20
7V11-3,4 Bonnevile Power Ad Tieton Substation 2 1,829 1,82!21
7V11-3,4 Bonnevile Power Ad Tieton Substation 594 59'22
7V11-3,4 McNary Substation Hinkle Substation .1 412 41 23
7V11-7 USBR Green Springs Bonnevile Power Adm 18 63,825 63,82!24
7V11-7 USBR Green Springs Bonnevile Power Adm ..4,124 4,12'25
RS.368 Malin Sub -Malin Sub 612,811 612,811 26
RS.368 Malin Sub Malin Sub 63,418 63,411 27
7V11-3,4 Bonnevile Power Adm White Swanfoppenish 6 36,204 36,204 28
7V11-3,4 Bonnevile Power Adm White Swanrroppenish...3,643 3,64~29
RS.299 Various Various 217 1,349,203 1,349,2m 30
RS.299 Various Various 214,768 214,76f 31
7V11-8 Various Various 32
7V11-3,4 Cardwell-Merwin ChelatchieNiew 24 107,692 107,69..33
7V11-3,4 Cardwell-Merwin ChelatchieNiew 16,537 16,53 34
1,969 14,464,153 14,464,15
FERC FORM NO.1 (ED. 12-90)Page 329
Name of Respondent
PacifiCorp
his ~ort Is:
(1) ~An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/14/2010
ccunt ontinue
(Including transactions reffered to as 'w eling'
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 bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on 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 provide explanations following all required data.
Year/Period of Report
End of 2009/Q4
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energy Charges (Other Charges)($) ($)(I) (m)
250,418
157,100
624,376
43,798
27,03
14,705
400,950
80,824
955,342
333,46
25,608,245 9,402,623 28,687,115 63,697,983
FERC FORM NO.1 (ED. 12-90)Page 330
Total Revenues ($)
(k+l+m)
(n)
ine
No.
317,639 1
25,567 2
157,100 3
14,620 4
138,212 5
6 6
152 7
1,997 8
118,042 9
10,188 10
624,376 11
57,417 12
1,113,750 13
101,250 14
4,023,301 15
375,653 16
286,253 17
26,023 18
176,701 19
16,005 20
27,706 21
2,512 22
14,772 23
400,950 24
36,450 25
246,946 26
22,450 27
201,559 28
14,327 29
1,979,915 30
181,871 31
12 32
354,674 33
37,511 34
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) llAn Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010I I ccount
(Including transactions referred to as 'wheeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying
facilities, non-traditional 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 affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS . Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Year/Period of Report
End of 2009/Q4
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affliation)
(a)
Cargil Power Markets, LLC
Cargil Power Markets, LLC
Cargil Power Markets, LLC
CitiGroup Energy, Inc.
Colorado Springs Utilties
Foote Creek II, LLC
Foote Creek ill, LLC
Gila River Power, L.P.
Iberdrola Renewables Inc.
.Iberdrola Renewables Inc.
Iberdrola Renewables Inc.
Iberdrola Renewables Inc.
lberdrola Renewables Inc.
Iberdrola Renewables Inc.
Iberdrola Renewables Inc.
Iberdrola Renewables Inc.
Iberdrola Renewables Inc.
Idaho Power Company
Idaho Power Company
Idaho Power Company
Energy Received From
(Company of Public Authority)
(Footnote Affliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affliation)
(c)
Statistical
Classifi-
cation
(d)
Iberdrola Renewables Inc.
Iberdrola Renewables Inc.
Iberdrola Renewables Inc.
Exxon Mobile Corporation
Exon Mobile Corporation
Nevada Power Company
Nevada Power Company
TOTAL
Page 328.1FERC FORM NO.1 (ED. 12-90)
Name of Respondent This l80rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
:TRU;ITY,(ACCunt 45ö)(Contínued).(Including transactions reffered to as 'wIeeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billng demand that is specied in the firm transmission service contract.Demand
reported in column (h) must be.jn megawatt. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Deliver Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Othe Demand MegaWatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)(g)(h)(i)ij
7V11-8 Various Various 278,389 278,38~1
7V11-8 Various Various 31,846 31,84€2
7V11-7 Various .Various 1,200 1,20C 3
7V11-8 Various Various 148 14f 4
7V11-8 Various Various 5
Various Various 80,367 80,36 6
7V11-8 Various Various 43,603 43,60~7
7V11-7 Various Various 96 9€8
R.S.234 Swift Unit NO.2 Woodland Sub 9
R.S.234 Swift Unit NO.2 Woodland Sub 10
R.S.280 Various Various 105 1,563,223 1,563,22,11
R.S.280 Various Various 150,925 150,92!12
7V11-8 Various Various 1,251 1,251 13
7V11-7 EnelCove Fort Mona 25 14
7V11-8 Various Various 5,046 5,04€15
7V11-8 Various Various 153 15,16
R.S.322 Targhee Sub Goshen Sub 17
R.S.322 Targhee Sub Goshen Sub 18
7V11-3 Yellowtail Sub Various 2 423 42~19
SA 264 Foote Creek Sub Various 20
SA 264 Foote Creek Sub Various 21
7V11-8 Various Various 379 37e 22
7V11-8 Various Various 108,915 108,9Ü 23
7V11-8 Various Various 12,915 12,91~24
7V11-7 Various Various 21,36€21,36€25
7V11-5,9 Wallula Sub Wallula Sub 26
7V11-8 Wallula Sub Wallula Sub 27
7V11-5,9 28
7V11-5,9 29
7V11-7 Exxon Metering Statn Harr Allen/Mona Sub 3C 74,272 74,27 30
7V11-7 Exon Metering Statn Harr Allen/Mona Sub 17,102 17,10:31
7V11-7 Red Butte Borah/Brady 75 19,616 19,61€32
7V11-7 Red Butte Borah/Brady 33
7V11-7 Various Various 12,47~12,47'34
1,969 14,464,153 14,46,15
.
FERC FORM NO.1 (ED. 12-90)Page 329.1
Name of Respondent
PacifiCorp
This ~ort Is:
(1) ~An Original
(2) A Resubmission
Year/Period of Report
End of 2009/Q4
Date of Report
(Mo, Da, Yr)
04/14/2010
Account ontinued
(Including transactions reffered to as 'w eeling')
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the 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 bills orvouchers 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 G) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all re.quired data.
Demand Charges
($) ..
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energy Charges (Other Charges)($) ($)(I) . (m)
1,318,897
Total Revenues ($) ine
(k+l+m) No.
(n)
1,012,646
1,318,897 1
272,695 2
6,20 3
882 4
6 5
470,082 6
272,236 7
372 8
100,149 9
9,048 10
3,480,342 11
297,032 12
6,331 13
131,625 14
30,006 15
894 16
138,699 17
12,609 18
3,074 19
33,168 20
3,015 21
2,797 22
1,231,492 23
61,206 24
290,229 25
68,093 26
7,253 27
255,709 28
42,144 29
1,032,750 30
151,875 31
665,386 32
-2,177 33
1,012,646 34
665,386
2,206,655
1,032,750
25,608,245 9,402,623 28,687,115 63,697,983
FERC FORM NO.1 (ED. 12-90)Page 330.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
ccoun
(Including transactons referred to as 'weeling')
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 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 affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on.Jhe 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 FirmTransmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other TransmIssion Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affliation)
(a)
Idaho Power Company
Idaho Power Company
Idaho Power Company
Idaho Power Company
Idaho Power Company
Idaho Power Company
Integrys Energy Services, Inc.
Integrys Energy Services, Inc.
Intermountain Renewable Power LLC
JPM Ventures Energy
Macquarie Cook Power, Inc.
Moon Lake Electric Association
Moon Lake Electric Association
JP Morgan Ventures Energy Cooperation
JP Morgan Ventures Energy Cooperation
JP Morgan Ventures Energy Cooperation
NextEra Energy Resources, LLC
Pacifi Gas & Electrc Company
Pacific Gas & Electri Company
Pacific Gas & Electric Company
Portland Geneal Electric Company
Powerex Corporation
Powerex Corporation
Powerex Corporation
Powerex Corpration
Powerex Corporation
Powder River Energy Corporation
Powder River Energy Corporation
PPL EnergyPlus, LLC
PPL EnergyPlus, LLC
TOTAL
Energy Received From
(Company of Public Authority)
(Footnote Affliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affl.iation)
(c)
Statistical
Classifi-
cation
(d)
Page 328.2FERC FORM NO.1 (ED. 12-90)
Name of Respondent This ÏË0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
. cLcL; I KIL;l I Y ccount 456)(Continued)
.(InclUding transactions reffered to as 'wtieeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the .
designation for the substation, or other appropriate identification for where energy was received as specified in the contract.In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
i:eported 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.
.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand ~egãWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
7V11-8 Various Various 27,146 27,14t 1
7V11-8 Various .Various 28 2f 2
RS.257 Antelope Sub Antelope Sub 3
RS.257 Antelope Sub Antelope Sub 4
SA 203 Jim Bridger Sub Bridger Pump Station 5
SA 203 Jim Bridger Sub Bridger Pump Station 6
7V11-8 Various Various 15 1f 7
7V11-8 Various Various 125 12f 8
7V11-7,9 Sigurd-345KV bus Mona 11 18,414 18,414 9
7V11-8 Various Various 50 5C 10
7V11-8 Various Various 11
RS.302 Duchesne Duchesne 14,499 14,49~12
RS.302 Duchesne Duchesne 1,213 1,21~13
7V11-8 Various Various 113,276 113,27E 14
7V11-8 Various Various 6,830 6,83C 15
.Various Various 16
7V11-7,9 Wallula Sub Wala-Mid-C 80 800 80C 17
RS.607 Malin Sub Indian Springs 18
RS.298 Sigurd-Glen Canyon Pinto-Four Corners 19
7V11-8 Various Various 140 14(20
7V11-8 Various Various 427 42 21
7V11-7 Bonnevile Power Adm Weed Jct. Sub 80 345,953 345,95~22
7V11-7 Bonnevile Power Adm Weed Jct. Sub 23,710 23,71C 23
Various Various 412,139 412, 13~24
7V11-8 Various Various 25,562 25,56.25
7V11-7 Various Various 434 43.1 26
RS.123 Various Buffalo Sub 27
RS.123 Various Buffalo Sub .28
7V11-8 Various ¡Various 9,U44 9,04.1 29
7V11-8 Various Various 554 55.30
7V11-7 Various Various .31,600 31,60(31
7V11-8 Various Various 2,332 2,33~32
7V11-8 Various .Various 800 80C 33
7V11-7 Various Various 35,949 35,94!34
1,969 14,464,153 14,464,15~
FERC FORM NO.1 (ED. 12-90)Page 329.2
Name of Respondent
PacifiCor
Year/Period of Report
End of 2009/Q4
ccunt
(Including transactons reffered to as 'w eeling')
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 orvouchers rendered,including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j must be reported as Transmission Recived and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectvely.
11. Footnote entries and provide explanations following all required data.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energy Charges (Other Charges)($) ($)(I) (m)
156,935
Total Revenues ($) ine
(k+l+m) No.
(n)
115,164
156,935 1
1,659 2
67,672 3
6,152 4
14,927 5
1,357 6
1,343 7
730 8
200,606 9
292 10
6 11
18,221 12
1,563 13
804,598 14
51,036 15
619 16
167,806 17
20,000,000 18
327,547 19
981 20
2,756 21
1,690,875 22
131,625 23
2,277,588 24
143,058 25
2,638 26
159 27
16 28
53,412 29
3,434 30
139,742 31
16,282 32
4,672 33
115,164 34
155,925
162,000
1,690,875
25,608,245 9,402,623 28,687,115 63,697,983
FERC FORM NO.1 (ED. 12-90)Page 330.2
This ~ort Is:
(1) ~An Original
(2) A Resubmissioni Account
(Including transactions referred to as 'wheeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilties, cooperatives, other public authorities, qualifying
facilties, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or trúncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondenthas with the entities listed in columns (a), (b) or (c)
4. In. column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Rainbow Energy Marketing
2 Rainbow Energy Marketing
3 Raser Power Systems LLC
4 Salt River Project
5 Seattle City & Light
6 Sempra Energy Solutions LLC
7 Sempra Energy Solutions LLC
8 Shell Energy North America
9 Shell Energy North America
10 Sierra Pacific Power Company
11 Sierra Pacifc Power Company
12 Sierra Pacific Power Company
13 Sierra Pacific Power Company
14 Southem California Edison Company
15 State of Soth Dakota
16 State of South Dakota
17 TransAlta Energy Marketing Corp.
18 TransAlta Energy Marketing Corp.
19
20 Tri-State Generation & Transmission
21 Tri-State Generation & Transmission
22 United States Bureau of Reclamation
23 United States Bureau of Reclamation Bonnevile Power Administration
24 United States Bureau of Reclamation Bonnevile Power Administration
25 United States Bureau of Reclamation Bonnevile Power Administration
26 United States Bureau of Reclamation Westem Area Power Administration
27 United States Bureau of Reclamation Weber Basin
28 Utah Associated Municipal Power Systems Utah AssOC. Municipal Power
29 Utah Associated Municipal Power Systems Utah Assoc. Municipal Power Utah Assoc. Municipal Power
30 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency
31 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency
32 Warm Springs Power Enterprises Warm Springs Enterprises
33 Warm Springs Power Enterprises Warm Springs Enterprises
34 Western Area Power Administration Westem Area Power Administration
TOTAL
Page 328.3FERC FORM NO.1 (ED. 12-90)
Name of Respondent This 'ròrt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010..... i KIS;ITY ccunfA56ntinuea)
(Including trnsactions reffered to as 'wlìeeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, .point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is speced in the firm transmission service contract.Demand
reported in column (h) must be in megawatt. Footnote any demand not stated on a megawatts basis and explain.
6. Report in column (i) and 0) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt~ours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)(g)(h)(I)u)
7V11-8 Various Various 17,671 17,671 1
7V11-8 Various Various 10,724 10,n~2
7V11-7 Various Various 775 77~3
7V11-7 Various Various 15,523 15,52"4
7V11-7 Walluia Sub Wala-Mid-G Path 25 4,379 4,37E 5
7V11-3,4 Various 15 73,958 73,95~6
7V11-3,4 Bonnevile Pwr Adm Various 8,764 8,764 7
7V11-8 Various Various 3,979 3,97E 8
7V11-8 Various Various 134 13'9
7V11-8 Various Various 3,539 3,5~10
7V11-8 Various Various 850 85C 11
7V11-7 Various Various 12
7V11-7 Various Various 53,901 53,901 13
RS.298 Sigurd-Glen Canyon Pinto-Four Comer 14
7V11-7 Yellowtail Sub WyodakSub 4 18,581 18,581 15
7V11-7 Yellowtail Sub WyodakSub 16
7V11-8 Various Various 9,226 9,22t 17
7V11-8 Various Various 4,279 4,2TI 18
RS.123 Various Various 31 151,066 151,O6€19
RS.123 Various Various 16,994 16,994 20
7V11-8 Various Various 13,148 13,14S 21
7V11 Walla Walla Sub Burbank Pumps 1 2,376 2,3i€22
7V11 Walla Walla Sub Burbank Pumps 23
RS.67 Redmond Substation Crooked River Pump 7,691 7,691 24
RS.67 Redmond Substation Croked River Pumps 25
RS.286 Various Various 23,887 23,88 26
RS.286 Various Varius 1,300 1,3Oc 27
RS.297 Various Various 338 2,927,950 2,927,95l 28
RS.297 Various Various 296,627 296,2 29
RS.297 Various Various 109 527,992 527,9~30
RS.297 Various Various 50,002 50,OO~31
R.S.591 Pelton Reregulating Round Butte Sub 75,382 75,38~32
RS.591 Pelton Reregulating Round Butte Sub 7,355 7,3&33
Various Various 33 1,465,175 1,465,17~34
1.96~14,46,153 14,464,15~.
FERC FORM NO.1 (ED. 12-90)"., Page 329.3
Name of Respondent
PacifiCorp
ccount
(Including transactions reffered to as 'w eeling')
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bíls 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 bíls rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmis,sion Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
'11. Footnote entries and provide explanations following all required data.
This ~ort Is:
(1) IlAn Original
(2) A Resubmission
Year/Period of Report
End of 2009/Q4
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)ine
($)($)($)(k+l+m)No.
(k)(I~(m)(n)
92,720 92,720 1
60,136 2
3,720 3,720 3
90,654 90,654 4
50,625 50,625 5
101,960 111,765 6
12,974 7
28,517 28,517 8
783 9
28,751 28,751 10
5,445 11
12
221,856 13
327,547 14
89,100 89,100 15
8,100 16
66,418 66,418 17
49,110 18
95,371 95,371 19
2,663 20
92,039 92,039 21
12,428 37,090 22
1,730 23
12,721 24
531 25
23,887 26
1,300 27
6,924,597 7,479,837 28
655,802 29
1,873,828 1,972,223 30
176,966 31
109,725 32
9,975 33
2,556,785 2,556,785 34
25,608,245 9,402,623 28,687,115 63,697,983
FERC FORM NO.1 (ED. 12-90)Page 330.3
Name of Respondent This ¡:e ort Is:Date of Report Year/Period of Report
PacifiCorp (1 )X An Original (Mo, Da, Yr)End of 2009/Q4
(2).. A Resubmission 04/14/2010
;)1 ELECTKIl,l I Y i-UK UI He (::J~ccount 456.1)
(Including transactions referred to as 'weeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilties, cooperatives, other public authorities, qualifying
facilties, 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 orpublic 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 affliation 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 - Firrn 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 ina footnote for each
adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy DeUvered To Statistical
No.(Company of Public Authority)(Company of Public Authori)(Company of Public Autrit)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Western Area Power Administration Westem Area Power Administrtion
2 Western Area Power Administration Westem Area Power Administration
3 Western Area Power Administration Westem Area Power Administration ~~
4 Western Area Power Administration Westem Area Power Administration Westem Area Power Administration
5 Westem Area Power Administration Westem Area Power Administration Westem Area Power Administration "
6 Accrual True-up .
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29 .
30
31
32
33
34
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.4
Name of Respondent This 00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) r=A Resubmission 04/14/2010
I ! U.!, I:LI:(' i 1'1.1,11 y ccount 45ö)i(,ontlnued)
(Including transactions reffered to as 'wfieeling')
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 (t), 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
reportéd in column (h) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery ..Billng TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other .(Substation or Other Demand MegaWatt Hours . MegaWatt Hours No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)Ol
æ Various Various . .152,278 152,27€1
7V11-8 Various Various 71,690 71,69C 2
7V11-8 Various Various 3
7V11 Wyoming Distribution Wyoming Distribution 1 10,457 10,451 4
7V11 Wyoming Distribution Wyoming Distribution 3 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
1,969 14,464,153 14,464,15
FERC FORM NO.1 (ED. 12-90)Page 329.4
Name of Respondent This Fì:rrt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4.(2) nA Resubmission 04/1412010
~_~': ii Y i-~K ~ 11HtK~vli~~unt '100) \lJontlnUed)
(Including transactions raftered to as 'w eeling')
...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 bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
239,251 1
913,865 913,865 2
81,441 3
20,499 56,644 4
5,058 5
-993,505 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
..
25,608,245 9,402,623 28,687,115 63,697,983
FERC FORM NO.1 (ED. 12-90)Page 330.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2) . A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
\Schedule Page: 328 Line No.: 1 Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "POWDER RIR ENERGY CORP." ON PAGES 328 - 330:
Complete name is Powder River Energy Corporation.
!Schedule Page: 328 Line No.: 1 Column: d
Evergreen Network Transmission Service under the Open Access Transmission Tariff (S.A. 228 & 505), paral termination in
December 2009 and Januar 2010.
!Schedule Page: 328 Line No.: 1 Column: m
Distrbution Service Charge. Primary Delivery Serice. Regulation & Frequency Response. Penalty revenues coverig imbalance
char es er Schedules 4 and 9.
chedule Pa e: 328 Line No.: 2 Column: d
Evergreen Network Transmission Service under the Open Access Transmission Tariff (S.A. 228 & 505), partial termination in
December 2009 and Januar 2010.
¡Schedule Page: .328 Line No.: 2- Column: m
Distrbution Service Charge. Regulation & Frequency Response. December 2008 Service. Penalty revenues covering imbalance
char es er Schedules 4 and 9. December 2008 Service.
chedule Pa e: 328 Line No.: 3 Column: d
Evergreen Network Transmission Service under the Open Access Transmission Tarff (S.A. 228 & 505), paral termination in
December 2009 and Januar 2010.
!Schedule Page: 328 Line No.: 4 Column: d
Evergreen Network Transmission Service under the Open Access Transmission Tarff (S.A. 228 & 505), parial termination in
December 2009 and Januar 2010.
!Schedule Page: 328 Line No.: 4 Column: m
December 2008 Service. Regulation & Frequency Response.
¡Schedule Page: 328 Line No.: 5 Column: b
Varous si atories to the 7th Revised Volume 11 Point-to-Point Trasmission Tarff.
chedule Pa e: 328 Line No.: 5 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!Schedule Page: 328 Line No.: 5 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
!Schedule Page: 328 Line No.: 6 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!Schedule Page: 328 Line No.: 6 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328 Line No.: 6 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access TransmissioiiTarffbetween varous paries and points.
!Schedule Page: 328 Line No.: 6 Column: m
December 2008 Service.
!Schedule Page: 328 Line No.: 7 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "BLACK HILLS/COLORAO ELEC. UT. CO." ON PAGES
328-330:
Complete name is Black Hils/Colorado Electrc Utility Company, L.P.
!Schedule Page: 328 Line No.: 7 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!Schedule Page: 328 Line No.: 7 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!Schedule Page: 328 Line No.: 7 Column: d
Ever een General Transfer A . eement for transmission service char es to varous trnsmission and distrbution delive
chedule Pa e: 328 Line No.: 8 Column: b
Various signatories to the 7th Revised Volume 11 PoinHo-Point Transmission Tarff.
!Schedule Page: 328 Line No.: 8 Column: c
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 04/14/2010 2009/Q4
FOOTNOTE DATA
Varous signtories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I§chedule Page: 328 Line No.: 8 Column: d
Non-Fir or Short-Term Fir Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
I§chedule Page: 328 Line No.: 9 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
I§chedule Page: 328 Line No.: 9 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I§chedule Page: 328 Line No.: 9 Column: d
Non-Firm or Short-Term Firm Trasmission Servce under the en Access Transmission Tarffbetween varous paries and points.
chedule Page: 328 Line No.: 10 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
I§chedule Page: 328 Line No.: 10 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I§chedule Page: 328 Line No.: 10 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween varous paries and points.
I§chedule Page: 328 Line No.: 10 Column: m
December 2008 Service.
I§chedule Page: 328 Line No.: 11 Column: b
PacifiCo Ener , a business unit of PacifiCo res onsible for electrc
chedule Pa e: 328 Line No.: 11 Column: d
Network Transmission Service under the Open Access Trasmission Tarff (S.A. 347) termating on December 31, 2017.
I§chedule Page: 328 Line No.: 12 Column: b
PacifiCo Ener , a business unit of PacifiCo res onsible for electrc eneration and commodi tradin activities.
chedule Pa e: 328 Line No.: 12 Column: d
Network Trasmission Service under the Open Access Trasmission Tarff (SA. 347) terminating on December 31,2017.
I§chedule Page: 328 Line No.: 12 Column: m
December 2008 Service.
I§chedule Page: 328 Line No.: 13 Column: bPacifiCo Ener , a business unit of PacifiCo res onsible for electrc
chedule Pa e: 328 Line No.: 13 Column: d
Point-to-Point Transmission Service under the Open Access Trasmission Tarff (S.A. 67) termnatig on December 31, 2023.
I§chedule Page: 328 Line No.: 14 Column: b
PacifiCorp Energy, a business unit ofPacifiCorp res onsible for electrc enertion and commodity trading activities.
chedule Page: 328 Line No.: 14 Column: d
Point-to-Point Transmission Service under the Open Access Tramission Tarff (S.A. 67) termnating on December 31, 2023.
I§chedule Page: 328 Line No.: 14 Column: m
December 2008 Service.
I§chedule Page: 328 Line No.: 15 Column: d
Ever een Generl Transfer A eement for transmission service char es to varous trsmission and distrbution delive
chedule Pa e: 328 Line No.: 15 Column: m
Sole use of facilities/direct assigned facilities charge.
I§chedule Page: 328 Line No.: 16 Column: d
Evergreen General Transfer Agreement for trnsmission servce charges to varous trsmission and distrbution delivery points.
I§chedule Page: 328. Line No.: 16 Column: m
December 2008 Service.
I§chedule Page: 328 Line No.: 17 Column: d
Le ac use of facilties as defined in the contrt. Ternati October 2010.
chedule Pa e: 328 Line No.: 17 Column: m
Sole use of facilties charge based on a capacity factor and or proportional use as defined in the contrct. Customer capacity is
56MW.
I§chedule Page: 328 Line No.: 18 Column: d
I FERC FORM NO.1 (ED. 12-87) Page 450.2
Name of Respondént This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Column:m
revenues coverin imbalance char es er Schedules 4 and 9.
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 04/14/2010 2009/Q4
FOOTNOTE DATA
June I, 1994. Subject to termination upon mutual agreement.
~chedule Page: 328 Line No.: 27 Column: m
December 2008 Service. Sole use of facilties charge based on a capacity factor and or proportional use as defined in the contrct.
Customer ca aci is 110 MW.
chedule Pa e: 328 Line No.: 28 Column: d
Network Transmission Service and Distrbution Delivery Service under the Open Access Transmission Tarff (S.A. 328) termnating
on Se tember 30,2011.
chedule Pa e: 328 Line No.: 28 Column: m
Distrbution Service Charge. Primar Deliveiy Serice. Regulation & Frequency Response. Penalty revenues coverig imbalance
char es er Schedules 4 and 9.
chedule Pa e: 328 Line No.: 29 Column:d
Network Transmission Service and Distribution Delivery Service under the Open Access Transmission Tarff (S.A. 328) terminatig
on Se tember 30, 2011.
chedule Pa e: 328 Line No.: 29 Column: m
Distrbution Service Charge. Primar Delivery Service. Regulation & Frequency Response. December 2008 Service. Penalty revenues
coverig imbalance charges per Schedules 4 and 9.
~chedule Page: 328 Line No.: 30 Column: d
Ever een General Trasfer A eement for trsmission service to various transmission and distrbution delive
chedule Pa e: 328 Line No.: 30 Column: m
Sole use of facilities/direct assigned facilities char e. Charges for monitoring, schedulin , load following and s ining reserve.
Schedule Pa e: 328 Line No.: 31 Column: d
Ever een General Trasfer A eement for trsmission service to various trsmission and distrbution delive
chedule Pa e: 328 Line No.: 31 Column: m
Sole use of facilties/direct assigned facilities charge. Charges for monitoring, scheduling, load following and spinning reserve.
December 2008 Service.
~Chedule Page: 328 Line No.: 32 Column: b
Varous signtories to the 7th Revised Volwne 11 Point-to-Point Tramission Tariff.
~chedule Page: 328 . Line No.: 32 Column: c
Various signatories to the 7th Revised Volwne 11 Point-to-Point Trasmission Tarff.
~chedule Page: 328 Line No.: 32 Column: d
Non-Finn or Short-Term Fir Trasmission Service under the Open Access Transmission Tarffbetween varous parties and
chedule Page: 328 Line No.: 33 Column: d
Network Transmission Service under the Open Access Trasmission Tarff (SA. 370) terminating on December 7, 2012 or with 6
month written notice.
~chedule Page: 328 Line No.: 33 Column: m
Regulation & Frequenc Response. Penalty revenues coverig imbalance charges per Schedules 4 and 9.
chedule Page: 328 Line No.: 34 Column: d
Network Transmission Service under the Open Access Transmission Tariff (S.A. 370) terminating on December 7,2012 or with 6
month wrtten notice.
~chedule Page: 328 Line No.: 34 Column: m
Regulation & Frequency Response. December 2008 Service. Penal revenues coveri imbalance charges per Schedules 4 and 9.
chedule Pa e: 328.1 Line No.: 1 Column: b
Varous signatories to the 7th Revised Volwne 11 Point-to-Point Tramission Tarff.
~chedule Page: 328.1 Line No.: 1 Column: c
Various signatories to the 7th Revised Volwne 11 Point-to-Point Transmission Tarff.
~chedule Page: 328.1 Line No.: 1 Column: d
Non-Finn or Short-Term Firm Trasmission Service under the Open Access Trasmission Tarffbetween varous paries and points.
~chedule Page: 328.1 Line No.: 2 Column: b
Varous signatories to the 7th Revised Volwne 11 Point-to-Point Transmission Tarff.
~chedule Page: 328.1 Line No.: 2 Column: c
Varous signatories to the 7th Revised Volwne 11 Point-to-Point Transmission Tarff.
I FERC FORM NO. 1 (ED. 12-87)Page 450.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA
¡Schedule Page: 328.1 Line No.: 2 Column: d
Non-Fir or Short-Term Fir Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
¡Schedule Page: 328.1 Line No.: 2 Column: m
December 2008 Service.
¡Schedule Page: 328.1 Line No.: 3 Column:b
Various signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 3. Column: c
Vanous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
'$chedule Page: 328.1 Line No.: 3 Column: d
Non-Finn or Short-Term Firm Transmission Service under the Open Access Transmission Tanffbetween varous pares and points.
¡Schedule Page: 328.1 Line No.: 4 Column: b
Various signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
ISchedule Page: 328.1 Line No.: 4 Column: c
Various signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tanff.
¡Schedule Page: 328.1 Line No.: 4 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various pares and points.
ISchedule Page: 328.1 Line No.: 5 Column: b
Various signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tanff.
ISchedule Page: 328.1 Line No.: 5 Column: c
Varous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 5 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various paries and points.
ISchedule Page: 328.1 Line No.: 6 Column: a .
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "CONSTELLATION ENERGY COMMODITIES GROUP" ON
PAGES 328 - 330:
. Complete name is Constellation Energy Coinodities Group, Inc.
ISchedule Page: 328.1 Line No.: 6 Column: b
Varous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
ISchedule Page: 328.1 Line No.: 6 Column: c
Varous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 6 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various paries and points.
ISchedule Page: 328.1 Line No.: 6 Column: e
7VLL-5, 8,9, 11
ISchedule Page: 328.1 Line No.: 6 Column: m
Charges for monitonng, scheduling, load following and spinning reserve. Unauthonzed Use of Transmission Service. Penalty
revenues covenng imbalance charges per Schedules 4 and 9.
¡Schedule Page: 328.1 Line No.: 7 Column: b
Varous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
ISchedule Page: 328.1 Line No.: 7 Column: c
Varous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
ISchedule Page: 328.1 Line No.: 7 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tanffbetween various parties and points.
ISchedule Page: 328.1 Line No.: 7 Column: m . .. .. . I
Charges for monitonng, scheduling, load following and spinning reserve. Unauthonzed Use of Transmission Service. December 2008
Service. Penalty revenues covenng imbalance charges per Schedules 4 and 9.
ISchedule Page: 328.1 Line No.: 8 Column: b
Varous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
ISchedule Page: 328.1 Line No.: 8 Column: c
Various signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
'$chedule Page: 328.1 Line No.: 8 Column: d
IFERC FORM NO.1 (ED. 12-87) Page 450.5
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between various partes and points.
I$chedule Page: 328.1 . Line No.: 8 Column: m
December 2008 Service.
I$chedule Page: 328.1 Line No.: 9 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "COWLITZ COUNTY PUD" ON PAGES 328 - 330:
Com lete name is Public Utili Distrct NO.1 of Cowlitz Coun .
chedule Pa e: 328.1 Line No.: 9 Column: d
Agreement providing for transmission and opertion of Cowlitz's Swift 2 Hydro Generation. Payment is for 26% of annual costs of
Swift-Cowlitz Trasmission Line. Agreement is for the life of Swift Unit NO.2.
¡Schedule Page: 328.1 Line No.: 9 Column: m
Sole use of facilities charge based on a capacity factor and or proportional use as defied in the contract. Customer capacity is
82MW.
¡Schedule Page: 328.1 Line No.: 10 Column: d
Agreement providing for trsmission and operation of Cowlitz's Swift 2 Hydro Generation. Payment is for 26% of anual costs of
Swift-Cowlitz Transmission Line. Agreement is for the life of Swift Unit NO.2.
¡Schedule Page: 328.1 Line No.: 10 Column: m
December 2008 Service. Sole use of facilities charge based on a capacity factor and or proportional use as defined iii the contract.
Customer ca acI is 82 MW.
chedule Pa e: 328.1 Line No.: 11 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF"DESERET GEN. & TRAS. COOP" ON PAGES 328 - 330:
Com lete name is Deseret Generation and Trasmission Coo ertive.
chedule Pa e: 328.1 Line No.: 11 Column: d
Legacy Transmission Service Operatig Agreement and Control Ara Services Agreement for transmission services. Transmission
Service Operating Agreement - tenation upon mutul agrement. Control Area Services Agreement - termination upon two years
written notice b either
chedule Pa e: 328.1 Line No.: 11 Column: m
Charges for monitorig, scheduling, load following and spinning resere. Distrbution Service Charge. Regulation & Frequency
Response. Meter Interogation Services.
¡Schedule Page: 328.1 Line No.: 12 Column: d
Legacy Trasmission Service Operating Agreement and Control Area Services Agreement for transmission services. Transmission
Service Operating Agreement - termnation upon mutual agreement. Control Area Services Agreement - termination upon two years
wrtten notice b either
chedule Pa e: 328.1 Line No.: 12 Column: m
Charges for monitorig, scheduling, load following and spining reserve. Distrbution Service Charge. Regulation & Frequency
Response. Meter Interrogation Services. December 2008 Service.
¡Schedule Page: 328.1 Line No.: 13 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Trasmission Tarff.
¡Schedule Page: 328.1 Line No.: 13 Column: c
Various si atories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
chedule Page: 328.1 Line No.: 13 Column: d
Non-Fir or Short-Term Firm Trasmission Service under the Open Access Tranmission Tarffbetween various paries and points.
¡Schedule Page: 328.1 Line No.: 14 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
¡Schedule Page: 328.1 Line No.: 14 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tarff, (S.A. 426) defered until November 1,2010-
ternating April 30, 2042.
¡Schedule Page: 328.1 Line No.: 14 Column: m
Extension of Commencement Date Fee.
¡Schedule Page: 328.1 Line No.: 15 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 15 Column: c
I FERC FORM NO. 1 (ED. 12-87)Page 450.6
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Various signatories to the 7th Revised Volume i i Point-to-Point Transmission Tarff.
!Šchedule Page: 328.1 Line No.: 15 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween varous pares and points.
!Šchedule Page: 328.1 Line No.: 16 Column: b
V arous signatories to the 7th Revised Volume 1 i Point-to-Point Transmission Tariff.
!Šchedule Page: 328.1 Line No.: 16 Column: c
Various i¡ignatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!ŠchedulePage: 328.1 Line No.: 16 Column: d
Non-Firm Or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
¡Schedule Page: 328.1 Line No.: 16 Column: m
. December 2008 Service.
!Šchedule Page: 328.1 Line No.: 17 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "FALL RIVER RURL ELECTRIC COOP." ON PAGES 328 - 330:
Com lete name is Fall River Rural Electrc Coo erative.
Schedule Pa e: 328.1 Line No.: 17 Column: d
Le ac use offacilities as defined in the contract. Ternatin
Schedule Pa e: 328.1 Line No.: 17 Column: m
Sole use of facilities char e based on a ca aci factor and or
chedule Pa e: 328.1 Line No.: 18 Column: d
Le ac use of facilities as dermed in the contract. Termnatin
chedule Pa e: 328.1 Line No.: 18 Column: m
December 2008 Service. Sole use of facilities charge based on a capacity factor and or proportional use as defined in the contract.
Customer ca acI is 9 MW.
chedule Pa e: 328.1 Line No.: 19 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "FLATHEAD ELECTRC COOP., INC." ON PAGES 328 - 330:
Complete name is Flathead Electrc Cooperative, Inc.
!Šchedule Page: 328.1 Line No.: 19 Column: d
Network integration transmission service terminated and servce is being covered through a Basin Electrc Power Cooperative's
transmission service a eement.
chedule Pa e: 328.1 Line No.: 19 Column: m
Distrbution Service Charge. Priary Delivery Service. Regulation & Frequency Response. December 2008 Serice.
!Šchedule Page: 328.1 Line No.: 20 Column: c
PacifiCorp Energy, a business unit ofPacifiCorp responsible for electrc generation and commodity trading activities.
!Šchedule Page: 328.1 Line No.: 20 Column: d
Direct Assi ent Facilities Service A reement S.A. 264 for oint-to- oint transmission at 34.5kv. Termnatin luI 2014.
chedule Pa e: 328.1 Line No.: 20 Column: m
Sole use of facilities charge based on a capacity factor and or proportonal use as defined in the contract.
!Šchedule Page: 328.1 Line No.: 21 Column: c
PacifiCo Ener , a business unit of PacifiCo res onsible for electrc eneration and commodi tradin activities.
Schedule Pa e: 328.1 Line No.: 21 Column: d
Direct Assi ent Facilties Service A eement S.A. 264 for oint-to- oint transmission at 34.5kv. Termnatin lui 2014.
chedule Pa e: 328.1 Line No.: 21 Column: m
December 2008 Service. Sole USe of facilities charge based on a capacity factor and or proportional use as defined in the contract.
!Šchedule Page: 328.1 Line No.: 22 Column: b . . . .
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!Šchedule Page: 328.1 Line No.: 22 Column: c
Various signatories to the 7th Revised Volume 1 i Point-to-Point Transmission Tarff.
!Šchedule Page: 328.1 Line No.: 22 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access TransmissÍon Tarffbetween varous paries and points.
!Šchedule Page: 328.1 Line No.: 23 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
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 ì2) . A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA .
f$chedule Page: 328.1 Line No.: 23 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
lSchedule Page: 328.1 Line No.: 23 Column: d .
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various parties and points.
lSchedule Page: 328.1 Line No.: 24 Column: b
Varous signatories to the 7th Revised Volume 11 Point-toPoint Tramission Tarff.
!$chedule Page: 328.1 Line No.: 24 Column: c
Varous signatories to the 7th Revised Volume 11 Point-toPoint Tramission Tarff.
lSchedule Page: 328.1 Line No.: 24 Column: d
Non-Fir or Short-Term Fir Trasmission Service under the Open Access Trasmission Tarffbetween varous paries and points.
f$chedule Page: 328.1 Line No.: 24 Column: m
December 2008 Service.
lSchedule Page: 328.1 Line No.: 25 Column: b
Various signatories to the 7th Revised Voluie 11 Point-to-Point Transmission Tarff.
lSchedule Page: 328.1 Line No.: 25 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
lSchedule Page: 328.1 Line No.: 25 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous pares and points.
'$chedule Page: 328.1 Line No.: 26 Column: d
Ancilar Services under the Open Access Tramission Tarff (S.A. 313) in effect until superceded.
lSchedule Page: 328.1 Line No.: 26 Column: m
Charges for monitorig, scheduling, load following and spinning reserve. Unauthorized Use of Trasmission Service. Penalty
revenues covering imbalance charges per Schedules 4 and 9.
lSchedule Page: 328.1 Line No.: 27 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various paries and points.lSchedule Page: 328.1 Linè No.: 27 Column: m I
Charges for monitorig, scheduling, load following and spinning reserve. Unauthorized Use of Transmission Servce. December 2008
Serice. Penal revenues coverig imbalance char es er Schedules 4 and 9.
chedule Pa e: 328.1 Line No.: 28 Column: c
Iberdrola Renewables Inc. and Utah Associated Municipal Power Systems.
lSchedule Page: 328.1 Line No.: 28 Column: d
Ancil Services under the Open Access Transmission Tarff (S.A. 3 i 5) in effect until superceded.
Schedule Page: 328.1 Line No.: 28 Column: f
Lon Hollow, WY switchin station.
Schedule Pa e: 328.1 Line No.: 28 Column:
Lon Hollow, WY switchin station.
chedule Pa e: 328.1 Line No.: 28 Column: m
Charges for monitoring, scheduling, load followig and spinning reserve. Unauthorized Use of Transmission Service. Penalty
revenues covering imbalance charges per Schedules 4 and 9.
lSchedule Page: 328.1 Line No.: 29 Column: c
. Ibrdrola Renewables Inc. and Utah Associated Municipal Power Systems.
!$chedule Page: 328.1 Line No.: 29 Column: d
Ancilar Services under the Open Access Trasmission Tarff (S.A. 315) in effect until superceded.
I$chedule Page: 328.1 Line No.: 29 Column: f
Lon Hollow, WY switchin station.
chedule Pa e: 328.1 Line No.: 29 Column:
Lon Hollow, WY switchin station.
chedule Pa e: 328.1 Line No.: 29 Column: m
Charges for monitoring, scheduling, load following and spinning reserve. Unauthorized Use of Trasmission Service. December 2008
Service. Penalty revenues covering imbalance charges per Schedules 4 and 9.
lSchedule Page: 328.1 Line No.: 30 Column: d
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 1(2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Point-to-Point Transmission Service under the 0 en Access Transmission Tarff S.A. 279 . Terminates A n130, 2014.
chedule Pa e: 328.1 Line No.: 31 Column: d
Point-to-Point Transmission Service under the en Access Transmission Tariff S.A.279 . Termates A n130, 2014.
chedule Pa e: 328.1 Line No.: 31 Column: m
December 2008 Service.
¡Schedule Page: 328.1 Line No.: 32 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tarff (S.A. 212) terminating May 31, 2014.
¡Schedule Page: 328.1 Line No.: 33 Column: d
Point-to-Point Transmission Service under the Open Access Tmnsmission Tanff(S.A. 212) termnating May 31, 2014.
¡Schedule Page: 328.1 Line No.: 33 Column: m
Ca aci reassignment refud for October 2008. December 2008 Service.
Schedule Pa e: 328.1 Line No.: 34 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tanff.
¡Schedule Page: 328.1 Line No.: 34 Column: c
Varous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 34 Column: d
Non-Firm or Short-Term Firm TransmissionService under the Open Access Transmission Tarffbetween various paries and points.
¡Schedule Page: 328.2 Line No.: 1 Column: b
Varous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 1 Column: c
Various signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tanff.
¡Schedule Page: 328.2 Line No.: 1 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between varous pares and points.
¡Schedule Page: 328.2 Line No.: 2 Column: b
Various signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 2 Column: c
Vanous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 2 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous parties and points.
¡Schedule Page: 328.2 Line No.: 2 Column: m
December 2008 Service.
¡Schedule Page: 328.2 Line No.: 3 Column: b
Opemtion, maintenance and facility lease services with no receipt or delivery of ener
chedule Pa e: 328.2 Line No.: 3 Column: c
Operation, maintenance and facili lease services with no receipt or delivery of energy.
chedule Pa e: 328.2 Line No.: 3 Column: d
Use of Facilities Agreement - Antelope Substation (R.S. 257) termnating coterminous with the IdaholUSDOE Supply Agreement.
¡Schedule Page: 328.2 Line No.: 3 Column: m
Sole use of facilities/direct assigned facilities charge.
¡Schedule Page: 328.2 Line No.: 4 Column: b
Operation, maintenance and facilty lease serices with no receipt or delivery of energy.
¡Schedule Page: 328.2 Line No.: 4 Column: c
Operation, maintenance and facilty lease services with no receipt or delivery of energy.
¡SchediJe Page: 328.2 Line No.: 4 Column: d
Use of Facilities Agreement - Antelope Substation (R.S. 257) termnating cotermnous with the IdaholUSDOE Supply Agreement.
¡Schedule Page: 328.2 Line No.: 4 Column: m
December 2008 Service.
¡Schedule Page: 328.2 Line No.: 5 Column: b
Operation, maintenance and facility lease services with no receipt or delivery of energy.
¡Schedule Page: 328.2 Line No.: 5 Column: c
Opemtion, maintenance and facilty lease services with no receipt or delivery of energy.
IFERC FORMNO.1 (ED. 12-87) Page 450.9
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
~chedule Page: 328.2 Line No.: 5 Column: d
Use of Facilities Agreement - Jim Bridger Pu (S.A. 203) - terination upon 12-month wrtten notice.
chedule Pa e: 328.2 Line No.: 5 Column: m
Sole use of facilities/direct assigned facilities charge.
~chedule Page: 328.2 Line No.: 6 Column: b
Operation, maintenance and facility lease serices with no receipt or deliver of energy.
~chedule Page: 328.2 Line No.: 6 Column: c
Operation, maintenance and facility lease services with no receipt or delivery of energy.
~chedule Page: 328.2 Line No.: 6 Column: d
Use of Facilities Agreeent - Jim Bridger Pump (S.A. 203) - termination upon 12-month wrttn notice.
~chedule Page: 328.2 Line No.: 6 Column: m
December 2008 Service.
~chedule Page: 328.2 Line No.: 7 Column: b
Varous signatories to the 7th Revised Volume 1 i Point-to-Point Transmission Tarff.
~chedule Page: 328.2 Line No.: 7 Column: c
Varous signatories to the 7th Revised Volume II Point-to-Point Transmission Tarff.
I$chedule Page: 328.2 Line No.: 7 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
I$chedule Page: 328.2 Line No.: 8 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tranmission Tarff.
I$chedule Page: 328.2 Line No.: 8 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Trasmission Tarff.
I$chedule Page: 328.2 Line No.: 8 Column: d
Non-Firm or Short-Term Fir Trasmission Service under the Open Access Transmission Tarffbetween various pares and points.
I$chedule Page: 328.2 Line No.: 8 Column: m
December 2008 Service.
I$chedule Page: 328.2 Line No.: 9 Column: d
Point-to-Point Transmission Serice under the Access Trasmission Tariff (S.A. 509) terminating April 30, 2029.
chedule Page: 328.2 Line No.: 9 Column: m
Charges for monitoring, scheduling, load following and spinning reserve. Penalty revenues covering imbalance charges per Schedules
4 and 9.
I$chedule Page: 328.2 Line No.: 10 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
I$chedule Page: 328.2 Line No.: 10 Column: c
Varous si atories to the 7th Revised Volume 1 i Point-to-Point Transmission Tarff.
chedule Page: 328.2 Line No.: 10 Column: d
Non-Firm or Short-Term Fir Trasmission Serice under the Open Access Transmission Tarffbetween varous paries and points.
I$chedule Page: 328.2 Line No.: 11 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Trasmission Tarff.
I$chedule Page: 328.2 Line No.: 11 Column: c
Various signatories to the 7th Revised Volume 1 i Point-to-Point Tramission Tarff.
¡Schedule Page: 328.2 Line No.: 11 Column: d
Non-Fir or Short-Term Fir Trasmission Serice under the en Access Transmission Tarffbetwee varous paries and
chedule Pa e: 328.2 Line No.: 12 Column: d
Le ac Transmission Servce and Interconnection A eement for use of facilities. Terinates in 2047.
chedule Pa e: 328.2 Line No.: 12 Column: m
Sole use of facilities charge based on a capacity factor and or proportonal use as defied in the contract. Customer capacity is
2.5MW.
I$chedule Page: 328.2 Line No.: 13 Column: d
Le ac Transmission Serce and Interconnection A eement for use of facilities. Terinates in 2047.
chedule Pa e: 328.2 Line No.: 13 Column: m
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 04/14/2010 2009/Q4
..FOOTNOTE DATA
December 2008 Service. Sole use of facilities charge based on a capacity factor and or proportional use as defined in the contract.
Customer ca aci is 2.5 MW.
chedule Pa e: 328.2 Line No.: 14 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Ißchedule Page: 328.2 Line No.: 14 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I$chedule Page: 328.2 Line No.: 14 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween various partes and points.
I$chedule Page: 328.2 Line No.: 15 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I$chedule Page: 328.2 Line No.: 15 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
I$chedule Page: 328.2 Line No.: 15 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various pares and points.
I$chedule Page: 328.2 Line No.: 15 Column: m
December 2008 Service.
I$chedule Page: 328.2 Line No.: 16 Column: b
Vârious signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Scheduìe Page: 328.2 Line No.: 16 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I$chedule Page: 328.2 Line No.: 16 Column: d
Non-Firm or Short-Term Fir Transmission Service under the Open Access Transmission Tarffbetween various partes and points.
I$chedule Page: 328.2 Line No.: 16 Column: e
7th rev T -voL.!! - Schedule 7
¡Schedule Page: 328.2 Line No.: 17 Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "GRANT COUNTY PUD" ON PAGES 328 - 330:
Complete name is Grant County Public Utility Distrct.
I$chedule Page: 328.2 Line No.: 17 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff, (S.A. 626), assignent from Seattle City & Light,
terminating December 31, 2011.I$chedule Page: 328.2 Line No.: 17 Column: m I
Charges formonitorig, scheduling, load following and spinning reserve. Penalty revenues coverig imbalance charges per Schedules
4 and 9.
I$chedule Page: 328.2 Line No.: 18 Column: b
Operation, maintenance and facility lease services with no receipt or delivery of energy.
!ßchedule Page: 328.2 Line No.: 18 Column: c
Operation, maintenance and facility lease services with no receipt or delivery of energy.
!ßchedule Page: 328.2 Line No.: 18 Column: d
Malin to Round Mountain facilities lease (R.S. 607). Terminating December 31, 2017.
¡Schedule Page: 328.2 Line No.: 18 Column: in
Sole use offacilities. Total ca aci of the line is 800 MW nort to south and 612.5 MW south to north.
chedule Pa e: 328.2 Line No.: 19 Column: b
Operation, maintenance and facility lease services with no recei t or delivery of energy.
chedule Pa e: 328.2 Line No.: 19 Column: c
Operation, maintenance and facility lease serices with no receipt or delivery of energy.
!ßchedule Page: 328.2 Line No.: 19 Column: d
Use of Facilities Agreement - Phase Shifting Transformers at Sigud-Glen Canyon 230kv transmission line and Pinto-Four Comers
345kv transmission line (SA 298), terminating Februar 12, 2020.
!ßchedule Page: 328.2 Line No.: 19 Column: m
Sole use of facilties/direct assigned facilities charge.
I$chedule Page: 328.2 Line No.: 20 Column: b
IFERC FORM NO.1 (ED. 12-S7) Page 450.11
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)PacifiCorp ..(2)A Resubmission 04/14/2010 2009104
FOOTNOTE DATA
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
~chedule Page: 328.2 Line No.: 20 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
~chedule Page: 328.2 Line No.: 20 Column: d
Non-Fir or Short-Term Firm Transmission Serice under the Opn Access Transmission Tarffbetween various parties and points.
f$chedule Page: 328.2 Line No.: 21 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
~chedule Page: 328.2 Line No.: 21 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
~chedule Page: 328.2 Line No.': 21 Column: d
Non-Firm or Short-Term Firm Trasmission Service under the Open Access Transmission Tarffbetween varous paries and points.
~chedule Page: 328.2 Line No.: 22 Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "CASIO" ON PAGES 328 - 330:
Complete nàme is Californa ISO.
I$chedule Page: 328.2 Line No.: 22 Column: d
Point-to-Point Transmission Service under the Open Access Trasmission Tarff (S.A. 169) termnating on September 30, 2012.
I§chedule Page: 328.2 Line No.: 23 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tarff (S.A. 169) termnating on September 30,2012.¡Schedule Page: 328.2 Line No.: 23 Column: m
December 2008 Service.
I§chedule Page: 328.2 Line No.: 24 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I§chedule Page: 328.2 Line No.: 24 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Tranmission Tarff.
I§chedule Page: 328.2 Line No.: 24 Column: d
Non-Fir or Short-Term Firm Transmission Serice under the Open Access Transmission Tarffbetween various paries and points.
I§chedule Page: 328.2 Line No.: 24 Column: e
7VII-5, 8, 9I$chedule Page: 328.2 Line No.: 24 Column: m I
Charges for monitorig, scheduling, load following and spinning reserve. Penalty revenues coverig imbalance charges per Schedules
4 and 9.
I§chedule Page: 328.2 Line No.: 25 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
~chedule Page: 328.2 Line No.: 25 Column: c
Various si atoriesto the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Pa e: 328.2 Line No.: 25 Column: d
Non-Fir or Short-Term Firm Transmission Serce under the en Access Trasmission Tarffbetween varous paries and points.
chedule Page: 328.2 Line No.: 25 Column: m
December 2008 Service.
~chedule Page: 328.2 Line No.: 26 Column: b
Various si atories to the 7th Revised Volume IIPoint-to-Point Transmission Tarff.
chedule Pa e: 328.2 Line No.: 26 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I§chedule Page: 328.2 Line No.: 26 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
¡Schedule Page: 328.2 Line No.: 27 Column: b
Varous Western Association Power Admnistrtion Interconnection in PACE
'$chedule Page: 328.2 Line No.: 27 Column: c
Sheridan-Johnson Rurl Electrfication Association
I§chedule Page: 328.2 Line No.: 27 Column: d
Legacy Transmission Serce Agreement (R.S. 123). Terminating October 1, 2014.
IFERC FORM NO.1 (ED. 12-87) Page 450.12
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp (2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
..
¡Schedule Page: 328.2 Line No.: 27 Column: m
Sole use of facilities/direct assigned facilties charge.
I§chedule Page: 328.2 Line No.: 28 Column: b
Varous Western Association Power Admnistrtion Interconnection in PACE
I$chedule Page: 328.2 Line No.: 28 Column: c
Sheridan Johnson Rural Electrfication Association
!Schedule Page: 328.2 Line No.: 28 Column: d
Le ac Transmission Service A reement R.S. 123 . Terminatin October 1,2014.
chedule Pa : 328.2 Line No.: 28 Column: m
Sole use of facilities/direct assigned facilities charge. December 2008 Service.
I$chedule Page: 328.2 Line No.: 29 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 29 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 29 Column: d
Non-Fir or Short-Term Firm Transmission Serice under the Open Access Transmission Tarffbetween various parties and points.
¡Schedule Page: 328.2 Line No.: 30 Column: b
Various signatories to the 7th Revised Volume i i Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 30 Column: c
Various signatories to the 7th Revised Volume i i Point-to-Point Transmission Tarff.
I§chedule Page: 328.2 Line No.: 30 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween varous paries andpoints.
¡Schedule Page: 328.2 Line No.: 30 Column: m
December 2008 Service.
lSchedule Page: 328.2 Line No.: 31 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRNCES OF "PUBLIC SERVICE CO. OF COLORADO" ON PAGES 328 - 330:
Complete name is Public Service Company of Colorado.
¡Schedule Page: 328.2 Line No.: 31 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 31 Column: c
Various signatories to the 7th Revised Volume 11. Point-to-Point Transmission Tarff.
I§chedule Page: 328.2 Line No.: 31 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous parties and points.
¡Schedule Page: 328.2 Line No.: 32 Column: b
Various signatories to the 7th Revised Volume 1 i Point-to-Point Transmission Tariff.
ISchedule Page: 328.2 Line No.: 32 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
ISchedule Page: 328.2 Line No.: 32 Column: d
Non-Firm or Short-Term Fir Transmission Service under the Open Access Transmission Tariffbetween various paries and points.
¡Schedule Page: 328.2 Line No.: 33 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedu/e Page: 328.2 Line No.: 33 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.2 Line No.: 33 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various paries and points.
¡Schedule Page: 328.2 Line No.: 33 Column: m
December 2008 Servce.
I§chedule Page: 328.2 Line No.: 34 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "RAINOW ENERGY MARKTING" ON PAGES 328 - 330:
Complete name is Rainbow Energy Marketig Corporation.
ISchedule Page: 328.2 Line No.: 34 Column: b
IFERC FORM NO.1 (ED. 12-87) Page 450.13
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Varous sígnatories to the 7th Revísed Volume 11 Pomt-to-Pomt Transinssíon Tarff.
I$chedule Page: 328.2 Line No.: 34 Column: c
Varous sígnatories to the 7th Revísed Volume 11 Pomt-to-Pomt Tramíssíon Tarff.
'$chedule Page: 328.2 Line No.: 34 Column: d
Non-Fínn or Short-Term Fírm Transmíssíon Servíce under the Open Access Transinssíon Tariffbetween varíous partes and poínts.
'§chedule Page: 328.3 Line No.: 1 Column: b
Varíous sígnatories to the 7th Revísed Volume 11 Pomt-to-Pomt Transinssíon Tarff.
'§chedule Page: 328.3 Line No.: 1 Column: c
Varíous sígnatories to the 7th Revísed Volume 11 Pomt-to-Pomt Transmíssíon Tarff.
'§chedule Page: 328.3 Line No.: 1 Column: d
Non-Fír or Short-Term Fírm Transmíssíon Servíce under the Open Access Transinssíon Tariffbetween varous partíes and poínts.
'§chedule Page: 328.3 Line No.: 2 Column: b
Varous sígnatories to the 7th Revísed Volume 11 Pomt-to-Pomt Transmíssíon Tarff.
'$chedule Page: 328.3 Line No.: 2 Column: c
Varous sígnatories to the 7th Revísed Volume 11 Pomt-to-Pomt Transmíssíon Tariff.
'§chedule Page: 328.3 Line No.: 2 Column: d
Non-Fír or Short-Term Fírm Transmíssíon Servíce under the Open Access Transinssíon Tarffbetween varous paríes and poínts.
¡Schedule Page: 328.3 Line No.: 2 Column: m
December 2008 Servíce.
'$chedule Page: 328.3 Line No.: 3 Column: b
Varous sígnatories to the 7th Revísed Volume 11 Pomt-to-Pomt Traninssíon Tarff.
'§cheduie Page: 328.3 Line No.: 3 Column: c
Varíous sígnatories to the 7th Revísed Volume 11 Pomt-to-Pomt Tramíssíon Tarff.
'§chedule Page: 328.3 Line No.: 3 Column: d
Non-Fínn or Short-Term Fír Transmíssíon Servíce under the Open Access Transinssíon Tarffbetween varous partes and poínts.
¡Schedule Page: 328.3 Line No.: 4 Column: b
Varous sígnatories to the 7th Revísed Volume 11 Pomt-to-Pomt Trainssíon Tariff.
'§chedule Page: 328.3 Line No.: 4 Column: c
Varous sígnatories to the 7th Revísed Volume 11 Pomt-to-Pomt Transmíssíon Tarff.
'§chedule Page: 328.3 Line No.: 4 Column: d
Non-Fírm or Short~ Term Fír Trasmíssíon Servíce under the Open Access Transinssíon Tarffbetween varous partíes and poínts.
'§chedule Page: 328.3 Line No.: 5 Column: d
Pomt-to-Poínt Transmíssíon Servíce under the Open Access Trasmissíon Tarff, (7th revísed S.A. 289) terínatmg October 31,
2014.
'§chedule Page: 328.3 Line No.: 6 Column: d
Network Transmíssíon Servíce under the Open Access Trasmíssíon Tarff (S.A. 299). Servíce províded pursuant to rules and
regulatíons of Oregon Direct Access. Termatíon upon notification puruant to Oregon Dírect Access and Open Access Transmíssíon
Tarff.
'§chedule Page: 328.3 Line No.: 6 Column: f
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "BONNVILE PWR ADM." ON PAGES 328-330: Complete name
ís Bonnevíle Power Admínístratíon.
!Schedule Page: 328.3 Line No.: 6 Column: m
Regulatíon & Frequency Response. Penalty revenues coverg ímbalance charges per Schedules 4 and 9.
'§chedule Page: 328.3 . Line No.: 7 Column: d
Network Transmissíon Servíce under the Open Access Trasmissíon Tarff (S.A. 299). Serce províded puruant to rules &
regulatíons of Oregon Direct Access. Termnation upon notification pursuat to Oregon Dírect Access and Open Access Transmissíon
Tariff.
'§chedule Page: 328.3 Line No.: 7 Column: m
Regulation & Frequency Response. December 2008 Seríce. Penalty revenues coverng ímbalance charges per Schedules 4 and 9.
'§chedule Page: 328.3 Line No.: 8 Column: b
Varous sígnatories to the 7th Revísed Volume 11 Pomt-to-Pomt Tramíssíon Tarff.
IFERC FORM NO.1 (ED. 12-S7) Page 450.14
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ó An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 ~2009/04 .
FOOTNOTE DATA .
!Schedule Page: 328.3 Line No.: 8 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328.3 Line No.: 8 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transtnssion Tarffbetween varous pares and points.
¡Schedule Page: 328.3 Line No.: 9 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 9 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 9 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various pares and points.
¡Schedule Page: 328.3 Line No.: 9 Column: m
December 2008 Service.
¡Schedule Page: 328.3 Line No.: 10 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328.3 Line No.: 10 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328.3 Line No.: 10 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various paries and points.
I$chedule Page: 328.3 Line No.: 11 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 11 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 11 Column: d
Non-Firm or Short-Term Fir Transmission Service under the Open Access Transmission Tarffbetween various paries and points.
¡Schedule Page: 328.3 Linè No.: 11 Column: m
December 2008 Service.
¡Schedule Page: 328.3 Line No.: 12 Column: b
Various signatories to the 7th RevisedVolume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 12 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 12 Column: d
Non-Firm or Short-Term Firm Trasmission Service under the Open Access Transmission Tarffbetween various pares and points.
¡Schedule Page: 328.3 Line No.: 13 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 13 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 13 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous aries and points.
chedule Page: 328.3 Line No.: 13 Column: m
December 2008 Service.
¡Schedule Page: 328.3 Line No.: 14 Column: b
Operation, maintenance and facility lease services with no receipt or delivery of energy.
¡Schedule Pilge: 328.3 Line No.: 14 Column: c
Operation, maintenance and facility lease services with no receipt or delivery of energy.
¡Schedule Page: 328.3 Line No.: 14 . Column: d
Use of Facilities Agreement - Phase Shifting Transformers at Sigud-Glen Canyon 230kv transmission line and Pinto-Four Comers
345kv transmission line (SA 298), terminating Februar 12, 2020.
¡Schedule Page: 328.3 Line No.: 14 Column: m
Sole use of facilties/direct assigned facilities charge.
¡Schedule Page: 328.3 Line No.: 15 Column: d
Point-to-Point Transmission Serice under the Open Access Transmission Tariff (S.A. 170) termnating on May 31, 2014.
IFERC FORM NO.1 (ED. 12-87) Page 450.15
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)PacifiCorp 1(2)A Resubmission 04/14/2010 2009lQ4
FOOTNOTE DATA
I$chedule Page: 328.3 Line No.: 16 Column: d
Point-to-Point Transmission Service under the Open Access Trasmission Tariff (S.A. 170) termnating on May 31, 2014.
I$chedule Page: 328.3 Line No.: 16 Column: m
December 2008 Service.
~chedule Page: 328.3 Line No.: 17 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
~chedule Page: 328.3 Line No.: 17 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I$chedule Page: 328.3 Line No.: 17 Column: d
Non-Firm or Short- Term Firm Transmission Service under the Open Access Transmission Tariffbetween various pares and points.
I$chedule Page: 328.3 Line No.: 18 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 18 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I$chedule Page: 328.3 Line No.: 18 Column: d
Non-Firm or Short-Term Fir Trasmission Servce under the Open Access Transmission Tarffbetween various paries and points.
¡Schedule Page: 328.3 Line No.: 18 Column: m
December 2008 Service.
¡Schedule Page: 328.3 Line No.: 19 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "TR-STATE GENERATION & TRANSMISSION" ON PAGES 328
-330:
Complete name is Tri-State Generation and Transmission Association, Inc.
¡Schedule Page: 328.3 Line No.: 19 Column: b
Operation, maintenance and facility lease services with no receipt Or delivery of energy.
¡Schedule Page: 328.3 Line No.: 19 Column: c
Operation, maintenance and facilty lease services with no receipt or delivery of energy.
¡Schedule Page: 328.3 Line No.: 19 Column: d
Le ac Trasmission Service A eement R.S. 123 . Termatin October 1,2014.
chedule Pa e: 328.3 Line No.: 20 Column: b
o eration, maintenance and facilty lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 20 Column: c
o eration, maintenance and facili lease services with no recei t or delivery of ener
chedule Pa e: 328.3 Line No.: 20 Column: d
Le ac Transmission Serice A eement R.S. 123 . Terminatin October 1, 2014.
chedule Pa e: 328.3 Line No.: 20 Column: m
December 2008 Service.
I$chedule Page: 328.3 Line No.: 21 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
I$chedule Page: 328.3 Line No.: 21 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff
¡Schedule Page: 328.3 Line No.: 21 Column: d
Non-Firm or Short-Term Firm Trasmission Serce under the Open Access Tranmission Tarff between varous pares and points.¡Schedule Page: 328.3 Line No.: 22 Column: d .. I
Network Transmission Serice and Distrbution Delivery Serice under the Open Access Trasmission Tariff (S.A. 506). Termnation
upon written notification.
¡Schedule Page: 328.3 Line No.: 22 Column: m
Distrbution Servce Char e. Primar Delivery Serice.
chedule Pa e: 328.3 Line No.: 23 Column: d
Network Transmission Service and Distrbution Delivery Service under the Open Access Trasmission Tarff (S.A. 506). Termination
upon wrtten notification.
I$chedule Page: 328.3 Line No.: 23 Column: m
IFERC FORM NO.1 (ED. 12-87) Page 450.16
...
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ AnOriginal (Mo, Da, Yr)
PacifiCorp 1(2) . A Resubmission 04/14/2010 2009/Q4
..
FOOTNOTE DATA ...
2008 ri delive and distrbution ad'ustments. December 2008 Service.
chedule Pa e: 328.3 Line No.: 24 Column: d
Legacy agreement For Use Of Facilities For the Transmission of Electrcal Power and Energy (RS. 67). Termation upon one yea
wrtten notice.
rschedule Page: 328.3 Line No.: 24 Column: m
Sole use of facilities charge based on a capacity factor and or proportonal use as dermed in the contrct.
¡Schedule Page: 328.3 Line No.: 25 Column: d
Legacy agreement For Use Of Facilities For the Transmission of Electrical Power and Energy (RS. 67). Termnating with one year
wrtten notice.
¡Schedule Page: 328.3 Line No.: 25 Column: m
December 2008 Service. Sole use of facilties charge based on a capacity factor and or proportonal use as defined in the contrct.
¡Schedule Page: 328.3 Line No.: 26 Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "WEBER BASIN" ON PAGES 328 - 330:
Complete name is Weber Basin Water Conservancy Distrct.
¡Schedule Page: 328.3 Line No.: 26 Column: d I
Legacy Water Exchange and Transmission Service Agreement (R S. 286) for energy deliveries at and below 138kv. Terminating any
time after A rill, 2040 with four eats wrtten notification.
chedule Pa e: 328.3 Line No.: 26 Column: m
Energy consumption charge for deliveries at and below 138kv.
¡Schedule Page: 328.3 Line No.: 27 Column: d I
Legacy Water Exchange and Transmission Service Agreement (R S. 286) for energy deliveries at and below 138kv. Terminatig any
time after A ril i, 2040 with four ears wrtten notification.
chedule Pa e: 328.3 Line No.: 27 Column: m
December 2008 Service. Energycónsumption charge for deliveries at and below 138kv.
¡Schedule Page: 328.3 Line No.: 28 Column: b
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "UTAH ASSOC. MUCIPAL POWER" ON PAGES 328 - 330:
Complete name is Utah Associated Múnicipal Power Systems.
¡Schedule Page: 328.3 Line No.: 28 Column: d
Legacy Amended and Restated Transmission Service and Operatig Agreement (R.S. 297) for transmission services. Subject to
termination u on mutual a eement and re lacement a eements are in effect.
chedule Pa e: 328.3 Line No.: 28 Column: m
Charges for monitoring, scheduling, load following and spinning reserve. Distrbution Service Charge. Unauthorized Use of
Transmission Service.
¡Schedule Page: 328.3 Line No.: 29 Column: d
Legacy Amended and Restated Transmission Service and Operatig Agreement (R.S. 297) for transmission services. Subject to
termnation upon mutual agreement and replacement agreements are in effect.
¡Schedule Page: 328.3 Line No.: 29 Column: m
Charges for monitoring, scheduling, load following and spinning reserve. Distrbution Service Char e. December 2008 Service.
chedule Pa e: 328.3 Line No.: 30 Column: d
Legacy 2nd Amended Transmission Service and Operating Agreement for trmission services (R.S. 279). Subject to termnation
u on mutual a eement and re lacement a eements are in effect.
chedule Pa e: 328.3 Line No.: 30 Column: m
Charges for monitoring, scheduling, load following and spinning reserve.
¡Schedule Page: 328.3 Line No.: 31 Column: d
Legacy 2nd Amended Transmission Service and Operating Agreement for transmission services (R.S. 279). Subject to termnation
u on mutual a eement and re lacement a eements are in effect.
chedule Pa e: 328.3 Line No.: 31 Column: m
Charges for monitoring, scheduling, load following and spinning reserve. December 2008 Service.
¡Schedule Page: 328.3 Line No.: 32 Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PORTLAN GENERAL ELECTRC CO." ON PAGES 328 - 330:
Complete name is Portland General Electrc Company.
¡Schedule Page: 328.3 Line No.: 32 Column: d
I FERC FORM NO. 1 (ED. 12-87) Page 450.17
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo,Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Ever een General Transfer A eement for trnsmission servce cha es to varous trsmission and distrbution deliv
Schedule Pa e: 328.3 Line No.: 32 Column: m
Sole use of facilities charge based on a capacity factor and or proportional use as defied in the contract. Customer capacity is
16MW.
I§chedule Page: 328.3 Line No.: 33 Column: d
Transmission Service Agreement (R.S. 591) terminatig Janua 1,2032.
I§chedule Page: 328.3 Line No.: 33 Column: m
December 2008 Service. Sole use of facilties charge based on a capacity factor and or proportional use as defined in the contrct.
Customer ca aci is 16 MW.
chedule Pa e: 328.3 Line No.: 34 Column: c
Various Western Area Power Admistrtion customers in PacifiCorp's control area.
¡Schedule Page: 328.3 Line No.: 34 Column: d I
Transmission Interconnection and Transmission Service Agreement (R.S. 262) for transmission service to preferential customers and
Low Voltage Transmission Service (R.S. 263) for deliveries of Colorado River Storage Project power and energy to certin
munici alities at servce below 138kv. Terminatin after thee ear wrtten notice and mutul consent.
Schedule Pa e: 328.3 Line No.: 34 Column: e
R.S. 262 & 263
¡Schedule Page: 328.4 Line No.: 1 Column: c
Varous Western Area Power Admnistrtion customers in PacifiCorp's control area.
¡Schedule Page: 328.4 Line No.: 1 Column: d
Transmission Interconnection and Transmission Service Agreement (R.S. 262) for transmission service to preferential customers and
Low Voltage Transmission Service (R.S. 263) for deliveries of Colorao River Storage Project power and energy to certin
munici alities at service below 138kv. Terminti after thee ear wrttn notice and mutual consent.
Schedule Pa e: 328.4 Line No.: 1 Column: e
R.s. 262 & 263
¡Schedule Page: 328.4 Line No.: 1 Column: m
December 2008 Service.
¡Schedule Page: 328.4 Line No.: 2 Column: c
Various signatories to the 7th Revised Volume 1 i Point-to-Point Transmission Tarff.
¡Schedule Page: 328.4 Line No.: 2 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween various paries and points.
¡Schedule Page: 328.4 Line No.: 3 Column: c
Varous signatories to the 7th Revised Volume i 1 Point-to-Point Trasmission Tarff
¡Schedule Page: 328.4 Line No.: 3 Column: d
Non-Firm or Short-Term Firm Transmission Servce under the Open Access Trasmission Tarffbetween various paries and points.
¡Schedule Page: 328.4 Line No.: 3 Column: m
December 2008 Service.
¡Schedule Page: 328.4 Line No.: 4 Column: d
Evergreen Network Transmission Servce under the Op Access Trasmission Tarff (S.A. i 75).
¡Schedule Page: 328.4 Line No.: 4 Column: m
Distrbution Service Charge. Primar Deliver Serce.
¡Schedule Page: 328.4 Line No.: 5 Column: d
Ever een Network Transmission Serice under the en Access Trasmission Tarff (S.A. i 75).
chedule Page: 328.4 Line No.: 5 Column: m
Distrbution Service Charge. Primar Delive Serce. December 2008 Serice.
chedule Pa e: 328.4 Line No.: 6 Column: m
Represents the difference 'between actual wheeling revenues for the perod as reflected on the individual line items within this
schedule, and the accruals credited to account 456.1 durng the perod.
I FERC FORM NO. 1 (ED. 12-87)Page 450.18
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as ''wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilties, t:ooperatives, 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 affliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provicied
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
. FNS - Firm Network Transmission Service for Self, lFP - Long-Term Firm Point-to-Point Transmission Reservations. OlF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) rePort the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered. .
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
Line TRANSFER OF ENERG
No.Name of Company or Public Statistical Magawatt-agawa -
tiours tioursAuthority (Footnote Affliations)Classification Received Delivered
(a)(b)(c)(d)
fi 222,069 222,069
9,234 9,234
3 Arizona Pt Srv. Co.
4 Arzona Public Srv. Co.30,981 30,981 128,617
5 Ashland, City of 1,845 1,845
6 Avista Corporation -600 -600 -1,600
7 Avista Corpration 52,108 53,856 206,460
8 Avista Cooration 20,931 20,931 82,824
9 Avista Corpration 5,520 5,520 14,858
10
11 38,557 38,557 33,769
1,964,012
13 BomiviH Powr Admin.5,621,547 5,621,547 45,415,94
14 Bonneville Power Admin.NF 96,834 96,834 153,530
15 Bonnevile Power Admin.as 5,505,499 5,724,708 34,799,705
16 BonevHle Power Admin.SFP 29,976 29,976 76,935
nergyCharges
($)
(f)
erCharges
($)
(g)
17,747
419,293
145,402
59,418
TOTAL 15,707,595 117,161,21016,060,9 16,355,485 98,453,642 2,999,973
FERC FORM NO. 1/3.q (REV. 02-04)Page 332
Total Cost ofTrans~tsion
1,087,640
35,622
3,928
128,617
17,747
-1,600
206,460
82,824
14,858
130,848
17,580
1,965,818
47,358,999
572,823
37,400,515
136,353
Date of Report
(Mo, Da, Yr)
04/14/2010
TRANS ISS ION OF ELECTRICITY BY OTHE S (Account 565)
(Including transactions referred to as "weeling")
1. Report all transmission, i.e. 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 affliation with the
transmissin service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OlF - Other
long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and as - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours recived and delived by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnçite explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRASFER OF ENERGY
No. Name of Company or Public agawatt- agawa -
Iiours IioursAuthority (Footnote Affliations) Received Delivered~ ~ ~
Year/Period of Report
End of 2009/Q4
Name of Respondent
PacifiCorp
557,341
-3,60
17,563
-9,200
738
557,341
-3,00
17,563
-9,200
738
-2,500
2,763,692
-20,500
1,922
11 Idaho Power Compny -1,674,370
12 Idaho Power Company 6,426
13 Ida Power Company 1,86,573 1,862,573 3,128,65
14 Idaho Power Company NF 402,653 458,80 1,063,723
15 Idaho Power Company OS
16 Idaho Powe Company SFP 135,995 135,995 244,395
TOTAL 16,06,96 16,355,48 98,453,64 2,99,973 15,707,595 11,161,210
FERC FORM NO. 1/3.Q (REV. 02-04)Page 332.1
Total Cost ofTrans~ssion
561,306
1,984,953
2,179,960
-2,500
2,763,692
-20,500
1,922
-696
59,798
176,594
-1,684,718
6,426
3,128,654
1,075,314
9,132,976
244,395
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04114/2010
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling")
1. Repor all transmission, Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS ~ Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to~ Point Transmission Reservations, NF ~ Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bils or vouchers rendered to the respondent. including any out of period adjustments. Explain in a footnote all components of the
amount shoWn in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERGY
No. Name of Company Or Public Statistical agawatt- agawa -tiourS tioursAuthority (Footnote Affliations) Classification Received Delivered(a) (b) (c) (d)1 OS
2,149 2,149 19,341
6 Nevada Power Company -832 -832
7 Nevada Power Company 46,157 46,157 137,375
8 Nevada Power Company
9 Nevada Power Company 61,792 61,792 184,342
158,532 163,744 704,161
4,152 4,152 17,975
17,563 17,563 966,000
16 Portand Gen. Electrc
Year/Perkid of Report
End of 2009/Q4
137,375
57,900
184,342
704,161
38,422
17,975
966,000
14,882
1,064
-828,000
TOTAL 16,060,96 16,355,485 98,53,642 117,161,210
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.2
2,999,973 15,707,595
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
TRANSMISSION OF ELECTRICITY BY OTHE S (Account 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity pròvided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affliation 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 Servce, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and as - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Year/Period of Report
End of 2009/Q4
Line
No. Name of Company or Public
Authority (Footnote Affliations)
(a)
1~1
erCharges
($)
(g)
119,844
11,107
569
806 80 2,289
250 250 709
-5,800 -5,800 -40,616
13,507 13,507 83,281
3,833 3,833 17,472
15 Tri-Slale Gen & Transm
16 Tri-Stale Gen & Transm
125,224
15,616
884,178
44,049
131,329
15,616NF
as
Total Cost of
Trans~ssion
-325,000
884,178
589,415
1,616
21,275
2,289
709
-47,126
83,281
15,851
17,472
9,336
-782,000
884,178
44,049
21,083
TOTAL 16,060,96 16,35,485 98,453,64 2,99,973 15,707,595 11,161,210
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.3
This ~ort Is: Date of Report
(1) ~An Original (Mo, Oa, Yr)
(2) A Resubmission 04/14/2010
TRANSMISSION OF ELECTRICITY BY OTHERS (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 facìlities, 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 affliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission ReserVations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,including. the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERGY
No. Name of Company or Public Statistical agawatt- agawa -Iiours IioursAuthority (Footnote Affliations) Classification Received Delivered(a~ (b) (c) (d)NF 1,964 1,964
OS
SFP
Name of Respondent
PacifCorp
YearlPeriod of Report
End of 2009/Q4
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
50 50 155
242,235 242,235 1,293,600
11 Western Area Power Adm.
12 Western Area Power Adm.
13 Western Area Power Adm.
14 Western Area Power Adm.
15 Accrual True-up
16
7,331
4,465,373
215,182 215,182 2,250,000
NF 7,599 7,599 16,353
OS
SFP 6,902 6,902 27,138
nergyCharges
($)
(f)
erCharges
($)
(g)
Total Cost of
Trans~ssion
6,088
1,174
155
-296
1,293,600
7,000
15,910
-1,682,919
8,520
4,465,373
2,250,000
16,353
391,037
27,138
-1,459,672
TOTAL 16,060,96 16,355,485 98,453,642 117,161,210
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.4
2,999,973 15,707,595
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
'$chedule Page: 332 Line No.: 1 Column: a
THS FOOTNOTE APPLIES TO ALL OCCURNCES OF "ARONA PUBLIC SRV. CO." ON PAGE 332:
Complete name is Arzona Public Serice Company
¡Schedule Page: 332 Line No.: 1 Column: b
Arzona Public Service Co. - Contract Termation Dates: May 1,2013, August 31,2013, Januar 11,2041 and May 31, 2047.
¡Schedule Page: 332 Line No.: 3 Column: gAncilar Services.
¡Schedule Page: 332 Line No.: 6 Column: b
Settlement Ad'ustment.
chedule Pa e: 332 Line No.: 10 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "BIG HORN RUR ELECTRIC'
ON PAGE 332:
Complete name is Big Hom Rural Electrc Cooperative.
¡Schedule Page: 332 Line No.: 10 Column: g
Use of Facilities.
¡Schedule Page: 332 Line No.: 11 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "BONNVILLE POWER ADMIN."
ON PAGE 332:
Complete name is Bonnevile Power Admnistrtion.
ISchedule Page: 332 Line No.: 11 Column: b
Settlement Adjustment.
¡Schedule Page: 332 Line No.: 11 Column: g
Ancilar Services. Use of Facilities.
¡Schedule Page: 332 Line No.: 12 Column: g
Use of Facilities.
¡Schedule Page: 332 Line No.: 13 Column: b
Bonnevile Power Admnistration - Contrct Termation Dates: July 1,2009, October 1,2009, Januar 1,2010, Januar 1,2011,
July 1,2011, September 1, 2011, December 1,2011, April 1,2012, July 1,2012, November 1,2012, July 1,2013, September 1,
2013, October 1,2013, December 1, 2013, Januar 1,2014, October 1, 2027, November 1, 2033 and evergreen.
ISchedule Page: 332 Line No.: 13 Column: g
Ancilar Services.
¡Schedule Page: 332 Line No.: 15 Column: g
Ancilar Services. Use of Facilities.
¡Schedule Page: 332.1 Line No.: 1 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF ''CA IN. SYS. OPERATOR"
ON PAGE 332.1:
Complete name is California Independent System Opertor Corpration.
ISchedule Page: 332.1 Line No.: 1 Column: b
Settlement Adjustment.
¡Schedule Page: 332.1 Line No.: 1 Column: g
Ancilar Services.
¡Schedule Page: 332.1 Line No.: 2 Column: gAncilar Serices.
ISchedule Page: 332.1 Line No.: 4 Column: a
THS FOOTNOTE APPLIES TO ALL OCCURNCES OF "DESERET PWR ELECT. COOP"
I FERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This Report is:Oate of Report Yéar/Period of Report
(1) ~ An Original (Mo, Oa, Yr)
PacifiCorp . (2) A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA
ON PAGE 332.l:
Complete name is Deseret Power Electrc Cooperative.
I$chedule Page: 332.1 Line No.: 4 Column: b
Settlement Adjustment.
I$chedule Page: 332.1 Line No.: 5 Column: b
Deseret Generation & Transmission - Contract Termation Dates: October 31,2012, September 1, 2018.
I$chedule Page: 332.1 Line No.: 6 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "EL PASO ELECT. CO."
ON PAGE 332.1:
Complete name is El Paso Electrc Company.
I$chedule Page: 332.1 Line No.: 6 Column: b
Settlement Adjustment.
I$chedule Page: 332.1 Line No.: 8 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "FLATHEAD ELECT-COOP."
ON PAGE 332.1:
Complete name is Flathead Electrc Cooperative.
!Schedule Page: 332.1 Line No.: 8 Column: b
Settlement Adjustment.
¡Schedule Page: 332.1 Line No.: 8 Column: g
Use of Facilities.
!Schedule Page: 332.1 Line No.: 9 Column: g
Use of Facilities.
!Schedule Page: 332.1 Line No.: 10 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "HERMISTON GEN CO., L.P."
ON PAGE 332.1:
Complete name is Hermiston Generating Company, L.P.
!Schedule Page: 332.1 Line No.: 10 Column: g
Use of Facilities.
!Schedule Page: 332.1 Line No.: 11 Column: b
Settlement Adjustment.
¡Schedule Page: 332.1 Line No.: 11 Column: g
Respondent's portion of specified costs of certain facilities.
!Schedule Page: 332.1 Line No.: 13 Column: b
Idao Power Company - Contract Termination Dates: June 13,2009, April 1, 2011.
¡Schedule Page: 332.1 Line No.: 15 Column: g
Ancilar Serices. Use of Facilities. Respondent's portion of specified costs of certin facilities.
!Schedule Page: 332.2 Line No.: 1 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "LOS ANG. DEPT WATERlWR"
ON PAGE 332.2:
Complete name is Los Angeles Departent of Water and Power.
!Schedule Page: 332.2 Line No.: 1 Column: g
Ancilar Services.
!Schedule Page: 332.2 Line No.: 3 Column: g
Patronage refund.
!Schedule Page: 332~2 Line No.: 4 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "MOON LAK ELECT. ASSOC."
IFERC FORM NO~ 1 (ED. 12-S7) 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 04/14/2010 2009/04
FOOTNOTE DATA
ON PAGE 332.2:
Complete name is Moon Lake Electrc Association.
¡Schedule Page: 332.2 Line No.: 4 Column: b
Settlement Adjustment.
¡Schedule Page: 332.2 Line No.: 4 Column: g
Use of Facilities.
¡Schedule Page: 332.2 Line No.: 5 Column: g
Use of Facilities.
¡Schedule Page: 332.2 Line No.: 6 Column: b
Settlement Adjustment.
¡Schedule Page: 332.2 Line No.: 8 Column: g
Ancilar Services.
¡Schedule Page: 332.2 Line No.: 10 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "NORTHWESTERN CORP." ON PAGE 332.2:
Complete nameis NortWestern Corporation.
¡Schedule Page: 332.2 Line No.: 11 Column: gAncilar Services.
¡Schedule Page: 332.2 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PLATT RIR POWER" ON PAGE 332.2:
Complete name is Platt River Power Authority.
¡Schedule Page: 332.2 Line No.: 13 Column: b
Platt River Power Authority - Contract Termation Date: October31, 2012.
¡Schedule Page: 332.2 Line No.: 14 Column: gAncilar Services.
¡Schedule Page: 332.2 Line No.: 15 . Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PORTLAN GEN. ELECTRC"
ON PAGE 332.2:
Complete name is Portland General Electrc Company.
¡Schedule Page: 332.2 Line No.: 15 Column: g
Use of Facilities.
¡Schedule Page: 332.2 Line No.: 16 Column: e
Reassignent of Bonnevile Power Administration trsmission.
¡Schedule Page: 332.3 Line No.: 1 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURCES OF "POWEREX" ON PAGE 332.3:
Complete name is Powerex Corporation.
¡Schedule Page: 332.3 Line No.: 1 Column: e
Reassignent of Bonnevile Power Administrtion trsmssion.
¡Schedule Page: 332.3 Line No.: 2 Column: aTHIS FOOTNOTE APPLIES TO ALL OCCURCES OF "PUBLIC SERVICE CO OF CO"
ON PAGE 332.3:
Complete name is Public Service Company of Colorado.
¡Schedule Page: 332.3 Line No.: 2 Column: b
Public Service Company of Colorado - Contract Termation Date: The date that all generatig plants comprising PacifiCorp
resources have been retied from service or interests trsferred.
¡Schedule Page: 332.3 Line No.: 3 Column: a
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 I (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PUBLIC SERVICE CO OF NM"
ON PAGE 332.3:
Complete name is Public Service Company of New Mexico.
!Schedule Page: 332.3 Line No.: 3 Column: b
Public Service Compan of New Mexico - Contract Termination Date: December 1,2012.
Schedule Pa e: 332.3 Line No.: 5 Column:
Ancilar Services.
\schedule Page: 332.3 Line No.: 8 .Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "SIERR PACIFIC POWER CO"
ON PAGE 332.3:
Complete name is Sierra Pacific Power Company.
\schedule Page: 332.3 Line No.: 8 Column: b
Settlement Adjustment.
\schedule Page: 332.3 Line No.~ 8 Column: g
Ancilar Services.
¡Schedule Page: 332.3 Line No.: 10 Column: g
Ancillar Services.
\schedule Page: 332.3 Line No.: 12 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "SURRISE VALLEY ELECTR."
ON PAGE 332.3:
Complete name is Surrise Valley Electrfication Corp.
¡Schedule Page: 332.3 Line No.: 12 Column: g
Use of Facilities.
\schedule Page: 332.3 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "TRNSALTA ENGY MKT INC."
ON PAGE 332.3:
Complete name is TransAlta Energy Marketing Inc.
¡Schedule Page: 332.3 Line No.: 13 Column: e
Reassignent of Bonnevile Power Administration trnsmission.
\schedule Page: 332.3 Line No.: 14 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "TRI-STATE GEN & TRANSM"
ON PAGE 332.3:
Complete name is Tri-State Generation & Transmission Association, Inc.
¡Schedule Page: 332.3 Line No.: 14 Column: b
Tri-StateGeneration & Transmission - Contract Termination Date: The date that all generating plants comprising PacifiCorp
resources have been retired from service: or interests transferred.
\schedule Page: .332.3 Line No.: 16 Column: g
Ancilar Services.
\schedule Page: 332.4 Line No.: 1 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF ~'TUCSON ELECTRC POWER" ON PAGE 332.4:
Complete name is Tucson Electrc Power Company.
\schedule Page: 332.4 Line No.: 2 Column: g
Ancilar Services.
\schedule Page: 332.4 Line No.: 4 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "UTAH ASSOC MU PWR SYS"
ON PAGE 332.4:
IFERC FORM NO.1 (ED. 12-87) Page 450.4
Name of Respondent This Report is:Date of Report Year/Period- of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
Complete name is Utah Associated Municipal Power Systems.
~chedule Page: 332.4 Line No.: 4 Column: b
Settlement Ad'ustment.
Schedule Page: 332.4 Line No.: 4 Column:
Ancilary Services.
~chedule Page: 332.4 Line No.: 5 Column: b
Uta Associated Municipal Power Systems - Contrct Termnation Date: November 30, 2009.
~chedule Page: 332.4 Line No.: 6 Column: g
Use of Facilities.
~chedule Page: 332.4 Line No.: 7 Column: g
Ancilar Serices.
~chedule Page: 332.4 Line No.: 8 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "WESPORT FIELD SRV LLC"
ONlAGE332.4:
Complete name is Wesport Field Services, LLC.
~chedule Page: 332.4 Line No.: 8 Column: b
Westport Field Serices, LLC - Contract Termination Date: Evergreen.
~chedule Page: 332.4 Line No.: 8 Column: e
Reimbursement for providing third part service.
~chedule Page: 332.4 Line No.: 9 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "WESTERN AREA POWER ADM."
ON PAGE 332.4:
Complete name is Western Area Power Admstration.
~chedule Page: 332.4 Line No.: 9 Column: b
Settlement Adjustment.
~chedule Page: 332.4 Line No.: 9 Column: g
Ancilar Services.
~chedule Page: 332.4 Line No.: 11 Column: b
Western Area Power Administrtion - Contract Termination Date: May 31, 2022.
¡Schedule Page: 332.4 Line No.: 13 Column: g
Ancilar Services. Use of Facilities.
~chedule Page: 332.4 Line No.: 15 Column: g
Represents the difference between actul wheeling expees for the period as reflected on the individual line items within this
schedule, and the accrals charged to account 565 durig the perod.
IFERC FORM NO.1 (ED. 12-S7) Page 450.5
Name of Respondent This ~ort Is:Date of ReRort
I
Year/Period of Report
.PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) n A Resubmission 04/14/2010
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line Descri)tion Amount
No.(a (b)
1 Industry Assoçiation Dues 1,028,546
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities ..
5 Oth Expn =-=5,000 show purpose, recipient, amount. Group if.: $5,000 ...
6 ..
.
7 Community and Economic Development and .
8 Corporate Memberships and Subscriptions:
9 Clatsop Economic Development 12,500
10 Cottage Grove Area Chamber of Commerce 10,000
11 Economic Development Corp of Utah
..102,000
12 Hood River County Chamber of Commerce 5,00
13 Idaho Economic Development 5,000
14 Klamath County Economic Development 10,000
15 Linn-Benton Community College 10,000
16 Newspaper Agency LLC 10,000
17 North-Northeast Business Assoc 5,00
18 Northwest Energy Effciency 8,00
19 NW Grassroots and Communication 5,000
20 Oregon Economic Development Assoc 10,000
21 Oregon Entrepreneurs Network 5,000
22 Oregon Manufacturing Extension Part 6,500
23 Port of Columbia 14,000
24 Portland State University 5,000
25 Rural Development Initiatives Inc 5,000
26 Salem Economic Development 5,000
27 South Coast Development Council 7,500
28 Southern Oregon Regional Economic 6,000
29 Utah Center for Rural Life 5,000
30 Utah Spor Commission 79,572
31 Wyoming Business Council 5,000
32 Yakima County Development 5,000
33 Assoc of Regional Economic Development 5,00
34 Associated Oregon Industries 28,000
35 California Climate Action Registry 10,000
36 Economic Development for Central Oregon 15,000
37 Four County Eco Development Corp 25,000
38 Greater Yakima Chamber of Commerce .7,556
39 Idaho Mining Association 6,000
40 Intermountain Electrical Assoc 9,000
41 Laramie Economic Development Corp 5,000
42 Northern Tier Transmission Group 353,726
43 Nortwest Power and Conservation 15,000
44 Oregon Business Assciation 11,000
45 Oregon Business Council 21,975
46 TOTAL 19,659,625
FERC FORM NO.1 (ED. 12-94)Page 335
Name of Respondent This ~ort Is:
I
Date of Rep'ort Year/Period of Report
PacifiCorp (1) . An Original (Mo, Da, Yr)End of 2009/Q4
(2) n A Resubmission 04/14/2010
MISCELLANEOUS GENERAL EXPENSES (Accunt 930.2) (ELECTRIC)
Line Descftion AmountNo.(a (b)
6 Oregon Economic Development Assoc 5,00
7 Oregon Solar Energy Indstrs Assoc 5,00
8 Oregon Sport Authority Foundation 5,00
9 Pacific Northwest Utilties Conference Committee 69,069
10 Portland Business Allance 39,250
11 Redmond Economic Development 5,000
12 Rocky Mountain Electrical League 18,000
13 Salt Lake Area Chamber of Commerce 30,555
14 UCA Usersgroup 5,000
15 Upstate California Economic 6,000
16 Utah Foundation 15,000
17 Utah Hispanic Chamber of Commerce 5,000
18 Utah Manufacturers Association 6,000
19 West Assoc ,28,511
20 Westem Electricity Coordinating Council 3,910,285
21 Westem Energy Institute 41,003
22 Wyoming Business Allance 7,600
23 Wyoming Taxpayers Association 7,1.28
24 Yakima County Development 7,500
25 Other 159,339
26
27 Directors Fees - Regional Advisory Boards 113,982
28 .
29 General:
30 MidAmerican Mgmt Fee 8,353,029
31 PricewaterhouseCoopers LLP 7,600
32 Other 2,116
33
34 Regulatory Asset Amortization:
35 Glenrock Mine UT 1998 Case (Excluding Reclamation)864,581
36 Glenrock Mine UT Stipulat. (Excluding Reclamation)149,625
37 Transition Plan 3,892,299
38 WY Lakeside Liquidated Damages 18,278
39
40
41
42
43
44 .
45
46 TOTAL 19,659,625
FERC FORM NO.1 (ED. 12-94)Page 335.1
Name of Respondent This i!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04114/2010
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403,404,405)
(Except amortization of aquisition adjustments)
1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortzation of Other Electric
Plant (Account 405).
2. Rep()rt ihSection 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
accunt or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included
in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total.Indicate at the bottm of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as rnost appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
cornposite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the
bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Depreciation Amortization of
Line D~reciation Expense for Asset Limited Term Amortization of
No.Functional Classification xpense Retirement Costs Electric Plant Other Electic Total
(Account 403)(Accunt 403.1 )(Account 404)Plant (Acc 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 29,820,783 29,820,783
2 Steam Production Plant 118,906,009 118,906,009
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 15,450,360 46,981 15,497,341
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 97,173,546 97,173,546
7 Transmission Plant 62,893,206 62,893,206
8 Distribution Plant 143,343,279 143,343,279
9 Regional Transmission and Market Operation
10 General Plant 35,397,061 2,524,008 37,921,069
11 Common Plant-Elecric
12 TOTAL 32,391,772 505,555,233
B. Basis for Amortization Charges
The amorttion of Limited-Term Electric Plant is based on straight-line amortization over the life of the asset.
FERC FORM NO.1 (REV. 12-63)Page 336
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) CIA Resubmission 04/14/2010
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
.Line uepreciaoie i:snmatea Net Appiiea Moriamy Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining(In Thousands)7~l (peráfnt)(per~int)Tr8e
7~~(a)... fb)(e
12 OTHER PRODUCTION
13 Westse Mobile
14 Generaor
15 344.00 OR 866 20.00 5.00
16
17 WIND GENERATION .
18 High Plains /
19 McFadden Ridge I
20 341.00WY 7,785 24.87 -1.00 4.06
21 343.00WY 245,562 24,87 -1.00 4.06
22 34.00WY 6,947 24.87 -1.00 4.06
23 345.00WY 14,564 24.87 -1.00 4.06
24 346.00WY 114 24.87 -1.00 4.06
25
26
27
28
29
30 .
31
32
33
34
35
36
37
38
39 .
40
41
42
43
44
45 .
46
47
48
49 ..
50
FERC FORM NO.1 (REV. 12-63)Page 337
.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA ...
!Schedule Page: 336 Line No.: 12 Column: b
Vehicle depreciation is charged to functional accounts. Durng the year ended December 31, 2009, vehicle depreciation expense of
$13,886,246 was charged to functional accounts.
\schedule Page: 336 Line No.: 12 Column: e
PacifiCorp records the depreciation expense of asset retirement obligations as either a regulatory asset or liability.
I FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
R GULATORY 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 part.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Line Description Assessed by Expenses Total . Deferred.
No.(Fumish name of regulatory commission or body the Regulatory of Expense for in Account
Commissi Current Year 18;2.3 a¡docket or case number and a description of the case)Utilty (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
1 Public Service Commission of Utah:.
2 AnnualFee 3,943,566 3,943,569
3 Rate Case 963,253 963,263
4
5 Public Utilty Commission of Oregon:
6 Annual Fee 3,157,187 3,157,187
7 Rate Case 337,159 337,159
8 Other State Regulatory Expenses 317,489 317,489
9
10 Public Service Commission of Wyoming:
11 Annual Fee 1,291,764 1,291,764
12 Rate Case 315,837 315,837
13
14 Washington Utilties and Transporttion
15 Commission:
16 Annual Fee 514,244 514,244
17 Rate Case 109,993 109,993
18
19 Idaho Public Utilities Commission:
20 Annual Fee 394,653 394,653
21 Rate Case 17,944 17,944
22 Other State Regulatory Expenses 13,185 13,185
23
24 Public Utilites Commission of California:
25 Annual Fee 861 861
26 Rate Case 199,207 199,207
27 Other State Regulatory Expenses 180,429 180,42~
28
29 Rate Cases - All States 15,763 15,763
30
31 Federal Energy Regulatory Commission:
32 Annual Fee 1,831,75~1,831,753
33 Annual Land Use Fee 491,725 491,725
34 Transmission Rate Case 2,368,722 2,368,722
35
36 Deferred Reglatory Commission Expense -51,307
37
38
39
40
41
42
43.
44 .
45
I.
46 TOTAL 11,625,756 4,838,991 16,464,747 -51,307
FERC FORM NO.1 (ED. 12-96)Page 350
Name of Respon.dent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
LATORY 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. Minoritems (less than $25,000) may be grouped.
Electric
Electric
Electric
928
928
928
AMORTIZED DURING YEAR
Deferred to Contra Amount Deferred in Line
Accunt 182.3 Account Accunt 182.3 No.End of Year
(h)(i)0)(k)(I)
1
3,943,569 2
963,263 3
4
5
3,157,187 6
337,159 7
317,489 8
9
10
1,291,764 11
315,837 12
13
14
15
514,244 16
109,993 17
18
19
394,653 20
17,944 21
13,185 22
23
24
861 25
199,207 26
180,429 27
28
15,763 29
30
31
1,831,753 32
491,725 33
2,368,722 34
35
448,756 928/254 336,071 61,378 36
37
38
39
40
41
42
43
44
45
Electric
Electric
928
928
Electri
Electric
Electic
928
928
928
Electric
Electric
928
928
Electic
Electric
928
928
Electric 928.
Elecric 928
Electric 928
Electri 928
Electric 928
Electric 928
Electric 928
_0./_:1 16,464,747 336,071 61,378 46
FERC FORM NO.1 (ED. 12-96)Page 351
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: pate of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wage~ for the year. Segregate amounts originally charged to clearing accounts to
Utilty Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
1 Electric
2 Operation
3 Production
4 Transmission
5 Regional Market
6 Distribution
7 Customer Accunts
8 Customer Service and Informational
9 Sales
10 Administrative and General
11 TOTAL Operation (Enter Total of lines 3 thru 10)
12 Maintenance
13 Production
14 Transmission
15 Regional Market
16 Distribution
17 Administrative and General
18 TOTAL Maintenance (Total of lines 13 thru 17)
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)
21 Transmission (Enter Total of lines 4 and 14)
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)
24 Customer Accounts (Transcribe from line 7)
25 Customer Service and Informational (Transcribe from line 8)
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17)
28 TOTAL OpeL and Maint. (Total of lines 20 thru 27)
29 Gas
30 Operation
31 Production-Manufactured Gas
32 Production-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
(a)
Direct PayrollDistribution
(b)
TotalLine
No.
Classifcation
FERC FORM NO.1 (ED. 12-88)Page 354
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Year/Period of Report
End of 2009/Q4
(a)
Direct PayrollDistribution
(b)
TotalLine
No.
Classification
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 47)
56 Transmission (Lines35 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 Utilty Dept. (Total of lines 28,62, and 64)
66 Utilty Plant
67 Construction (By Utilty Departments)
68 Electric Plant
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Constrction (Total of lines 68 thru 70)
72 Plant Removal (By Utilty Departments)
73 Electric Plant
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)
77 Other Accounts (Specify, provide details in footnote):
78 Fuel Stock
79 Miscellaneous Other Income Deductions
80 Miscellaneous Nonoperating/Nonutilty
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts
96 TOTAL SALARIES AND WAGES
361,424,755 361,424,755_..~'% ~ " c=~~ /00¡r~~- ~"" WW?8ap"~~~~f ////?i,i( AX_;; _ /7' #/16///& !J"!:~p~rr.,,,,'~i::~~~;iX5I
146,881,411 146,881,411
146,881,411 146,881,411
F'(~"'%jf~i0/ iidf$ lø.liß/~/ 0 i(W!?øz/~
9,162,675 9,162,675
9,162,675 9,162,675
24,418,419 24,418,419
352,592 352,592
797,544 797,544
25,568,555
543,037,396
25,568,555
543,037,396
FERC FORM NO.1 (ED. 12-BB)Page 355
Name of Respondent This 'mort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo9/Q4
(2)nA Resubmission 04/14/2010
..PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Accss Transmission Tariff.
In columns for usage, report usage-related billng 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 spld during the year.
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactve supply and voltage control services. purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and i:old during the year.
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancilary services purchased or sold during the
year. Include in a footnote and specify the amount for each type of other ancilary service provided.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Billng Determinant Usage - Related Billng Determinant
Unit of Unit of
LinE Type of Ancilary Service Number of Units Measure Dollars Number of Units Measure Dollars
No.(a)(b)(c)(d)(e)(f)(g)
1 Scheduling, System Control and Dispatch 144,444
2 Reactve Supply an Volte
3 Regulation an Frequency Response 57,151,357 MW 9,144,217 57,94,882 MWh 9,772,080
4 Energy Imbaance -119,90 MWh -3,571,023
5 Operatig Reserv - Spinning 63,685,481 MW 23,182,297 66,509,841 MWh 24,280,656
€Operating Resrve - Supplemet 63,685,481 MWh 23,182,297 65,590,206 MWh 23,937,632
7 Oter
8 Totl (Li 1 thru 7)184,522,319 55,508,811 189,925,023 54,563,789
.
..
FERC FORM NO.1 (New 2.04)Page 398
Name of Respondent .
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) IlAn Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
M NTHL Y TRANSMISSION SYSTEM PEAK LOAD
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, furnish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through 0) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the
definition of each statistical classification.
NAME OF SYSTEM:
Line
No.Month
Other
Service
(a)
1 Januai
2 February
3 March
4 Total for Quartr 1
5 April
6 May
7 June
8 Total for Quarter 2
9 July
10 August
11 September
12 Total for Quartr 3
13 October
14 November
15 December
16 Total for Quarr 4
17 TotaYearto
Datelear
Monthly Peak
MW - Total
Day of Hour of Firm Network Firm Network Long-Term Firm
Monthly Monthly Service for Self Service for Point-te-point
Peak Peak Others Reservations
(e)(f)(g)
Short-Term Firm
PoinHo-point
Reservation
(i)
Other Long-
Term Firm
Service
(h)(b)
21,50
18,981
19,67
60,16
20,47
21,51
22,12
64,10
22,92
21,91
21,85
66,69
16,16
15,66
17,07
48,90
99,683 1,367 65,963 55,623 17,231
FERC FORM NO. 4/3-Q (NEW. 07-04)Page 400
0)
1,408
1,353
1,299
4,060
1,278
1,399
1,511
4,188
1,636
1,646
1,559
4,841
1,220
1,357
1,565
4,142
Name of Respondent This Report is:Date of Report Year/Period of Report
(1)~An Original (Mo, Da, Yr)
PacifiCorp '2) A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA
!Schedule Page: 400 Line No.: 4 Column: e
Reflects actual demands of control area load at tie of Trasmission System Peale
!Schedule Page: 400 Line No.: 4 Column: ,
Reflects actual demands of control area load at tie of Trasmission S stem Peak.
chedule Page: 400 Line No.: 4 Column:
Reflects reservations in OASIS at time of Transmission System Peak.
I§chedule Page: 400 Line No.: 4 Column: i
Reflects reservations in OASIS at time of Transmission System Peak.
I§chedule Page: 400 Line No.: 8 Column: e
Refer to footnote for line 4 column e).
chedule Pa e: 400 Line No.: 8 Column:'
Refer to footnote for line 4 column
chedule Pa e: 400 Line No.: 8 Column:
Refer to footnote for line 4 colum
chedule Pa e: 400 Line No.: 8 Column: i
Refer to footnote for line 4 column (i).
I§chedulePage: 400 Line No.: 12 Column: e
Refer to footnote for line 4 column (e).
I§chedule Page: 400 Line No.: 12 Column:'
Refer to footnote for line 4 column (t).
I§chedule Page: 400 Line No.: 12 Column: g
Refer to footnote for line 4 column (g).
I§chedule Page: 400 Line No.: 12 Column: i
Refer to footnote for line 4 column (i).
I§chedule Page: 400 Line No.: 16 Column: e
Refer to footnote for line 4 column (e).
I§chedule Page: 400 Line No.: 16 Column:'
Refer to footnote for line 4 column (t).
I§chedule Page: 400 Line No.: 16 Column: g
Refer to footnote for line 4 column (g).
I§chedule Page: 400 Line No.: 16 Column: i
Refer to footnote for line 4 column (i).
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
Name of Respondent
PacifiCorp
This ~ort Is:
(1) ~An Original
(2) A Resubmission
ELECTRIC ENERGY ACCOUNT
Date of Report
(Mo,Da, Yr)
04/14/2010
Year/Period of Report
End of 2009/Q4
Report below the information called for conceming the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line
No.
Item
(b)(a)
1 SOURCES OF ENERGY
2 Generation (Excluding Station Use):
3 Steam
4 Nuclear
5 Hydro-Conventional
6 Hydro-Pumped Storage
7 Other
8 Less Energy for Pumping
9 Net Generation (Enter Total of lines 3
through 8)
10 Purchases
11 PoWer Exchanges:
12 Received
13 Delivered
14 Net Exchanges (Line 12 minus line 13)
15 Transmission For Other (Wheeling)
16 Received
17 Delivered
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
MegaWatt Hours
(b)I'~£..r...I,.... ~..t';Aii r .jý"', Z1Æi :I.
46,087,59
3,545,71
-1,30
8,772,95
58,04,96
11,462,391_.~;K
14,027,65
14,213,60
-185,951~%ø f!!i #i.rrr.N/"-
14,464,15
14,464,1
Line
No.
Item MegaWatt Hours
..0 / yjJ..:.ß: ._
52,709,525
205,608
12,143,453
131,439
4,196,858
69,386,883
FERC FORM NO.1 (ED. 12-90)Page401a
(a)
21 DISPOSITION OF ENERGY
22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
23 Requirements Sales for Resale (See
instrucion 4, page 311.)
24 Non-Requirements Sales for Resale (See
instruction 4, page 311.)
25 Energy Furnished Without Charge
26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
27 Total Energy Losses
28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
Name of Respondent This 780rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo,Da, Yr)End of 2009/Q4
(2) ñA Resubmission 04/14/2010 .
MONTHLY PEAKS AND OUTPl T
1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, fumish the require
information for each non- integrated system.
2. Report in column (b) by month the system's output in Megawatt hours for each month.
. 3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses assciated with the sales..
4. Report in column (d) by month the system's monthly maximum megawatt load (60 minute integration) assocated with the system.
5. Report in column (e) and (f) the specifed information for each monthly peak load reported in column (d).
NAME OF SYSTEM:.i.
Line Monthly Non-Requirments MONTHLY PEAKSales for Resale &No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(f)
29 January 6,408,275 1,152,395 8,524 27 0800 PST
3ë February 5,613,917 1,034,060 8,187 10 1900 PST
31 March 5,974,490 1,267,096 7,828 11 0800 PST
32 April 5,151,385 894,687 7,213 1 0900 PDT
33 May 5,300,712 878,138 7,912 29 1600 PDT
34 June 5,138,144 785,696 8,340 29 1700 PDT
35 July 6,213,028 901,436 9,420 27 1700 PDT
36 August 6,129,956 1,109,686 9,042 3 1700 PDT
37 September 5,575,955 972,815 8,499 2 1600 PDT
38 October 5,543,767 1,034,091 7,414 28 0900 PDT
39 November 5,832,041 1,076,664 8,015 30 1800 PST
40 December 6,505,213 1,036,689 9,336 9 0800 PST
41 TOTAL 69,386,883 12,143,453
FERC FORM NO. 1 (ED. 12.90)Page 401b
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2009/Q4
(2)OA Resubmission 04/14/2010 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kwor 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, specifyini; period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name: Carbon Name:~
(a)(b)
1 Kind of Plant (Intemal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor Boiler Full Outdoor
3 Year OriginaUy Constructed 1954 1981
4 Year Last Unit was Installed 1957 1981
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)188.60 414.00
6. Net Peak Demand on Plant - MW (60 minutes).176 385
7 Plant Hours Connected to Load 8717 8462
8 Net Continuous Plant Capabilty (Megawatts)0 0
9 When Not Limited by Condenser Water .172 395
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 70 0
12 Net Generation, Exclusive of Plant Use - KWh 1211875000 2877189000
13 Cost of Plant: Land and Land Rights 956546 2448255
14 Structures and Improvements 14711825 57386063
15 Equipment Costs 103555029 459550611
16 Asset Retirement Costs 6527359 39000
17 Total Cost 125750759 519423929
18 Cost Per KW of Installed Capacity (line 17/5) Including 666.7591 1254.6472
19 Production Expenses: Oper, Supv, & Engr 61684 1216352
20 Fuel 19612994 56204755
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 1396202 5101692
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Elecric Expenses 1810205 1150021
26 Misc Steam (or Nuclear) Power Expenses 4934749 1502518
27 Rents 170 .1762
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 1912378
30 Maintenance of Structures 336038 938302
31 Maintenance of Boiler (or reactor) Plant 2988372 3403827
32 Maintenance of Electric Plant 1556410 410626
33 Maintenance of Misc Steam (or Nuclear) Plant 294454 3020817
34 Total Production Expenses 32991278 74863050
35 Expenses per Net KWh 0.0272 0.0260
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Composite Coal Oil Composite
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)Tons Barrels Tons Barrels
38 Quantity (Units) of Fuel Burned .561433 3456 0 1553172 1530 0
39 Avg Heat Cont - Fuel Bumed (btu/indicate if nuclear)12079 140000 0 9529 130042 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 34.043 86.065 0.000 33.796 97.687 0.000
41 Average Cost of Fuel per Unit Burned 34.404 86.065 0.000 36.091 97.687 0.000
42 Average Cost of Fuel Bumed per Milion BTU 1.424 .14.637 1.444 1.894 17.887 1.898
43 Averae Cost of Fuel Bumed per KWh Net Gen 0.016 0.000 0.016 0.019 0.000 0.019
44 Averge BTU per KWh Net Generation 11191.461 16.771 11208.232 10287.940 2.904 10290.844
..
c
FERC FORM NO.1 (REV. 12-03)Page 402
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2009/Q4(2)DA Resubmission 04/14/2010 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Prouction expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For ie and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbin unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data coceming plant tye fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.Plant Plant Plant Line..~~.Dave Johnston No.
(f)Sæam Sæam Steam 1
Conventional Outdoo Boiler Semi-Outdoor 2
1984 1979 1959 3
1986 1980 1972 4
155.60 172.10 816.80 5
151 .165 766 6
8531 8760 8760 7
0 0 0 8
148 165 762 9
0 0 0 10
0 0 189 11
873534000 1349226000 5015234000 12
1355853 137086 10451083 13
58203289 36283734 57419130 14
.158047854 129835925 478527178 15
39236 35149 11441950 16
217646232 166291894 557839341 17
1398.7547 966.2516 682.9571 18
17204 346038 709742 19
10373467 19362415 45387118 20
0 0 0 21
788274 1434977 -40618 22
0 0 0 23
0 0 0 24
20783 632520 0 25
1457012 1073216 17159533 26
21677 0 148543 27
0 0 0 28
261059 620263 0 29
341245 398230 2442564 30
2577695 2775904 12629287 31
304935 584242 8595794 32
395840 80594 1702185 33
16559191 28032399 88734148 34
0.0190 0.0208 0.0177 35
Coal Oil Composite Coal Oil Copoite Coal Composite 36
Tons Barrels Tons Barrls Tons Barrls 37
547384 1035 0 .667587 48 0 3561945 18425 0 38
8504 140000 0 10023 133693 0 7986 140000 0 39
17.956 92.173 0.000 27.575 121.943 0.000 12.288 85.805 0.000 40
18.1'77 92.173 0.000 28.938 121.943 0.000 12.298 85.805 0.000 41
1.104 15.675 1.114 1.444 21.721 1.447 0.770 14.593 0.796 42
0.012 0.000 0.012 0.014 0.000 0.014 0.009 0.000 0.009 43
10657.757 6.965 10664.722 9918.615 0.199 9918.813 11343.627 21.602 11365.228 44
FERC FORM NO.1 (REV. 12-03)Page 403
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2009/Q4
(2)OA Resubmission 04/14/2010 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating~of 25,000 Kwor more. Report in
this page gas-turbine and intemal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facilty. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities of fuel bumed (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant .
No.~~Name:~Name: . . .
(a)c. .
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler,etc)Outdoor Boiler .Outdoor Boiler
3 Year Originally Constructed 1965 1978
4 Year Last Unit was Installed 1976 1978
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)81.30 457.70
6 Net Peak Demand on Plant - MW (60 minutes)79 406
7 Plant Hours Connected to Load 8741 8165
8 Net Continuous Plant Capability (Megawatts)0 0
9 When Not Limited by Condenser Water 78 403
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 0 0
12 Net Generation, Exclusive of Plant Use - KWh 572069000 2988412000
13 Cost of Plant: Land and Land Rights 379735 9688975
14 Structures and Improvements 5973764 63023096
15 Equipment Costs 62511609 232879738
16 Asset Retirement Costs 20877 953193
17 Total Cost 68885985 306545002
18 Cost per KW of Installed Capacity (line 17/5) Including 847.3061 669.7509
19 Production Expenses: Oper, Supv, & Engr 274635 9
20 Fuel 10812381 39453933
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 936512 2885015
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 275031 0
26 Misc Steam (or Nuclear) Power Expenses 658249 1866496
27 Rents 0 36
28 Allowances 0 0
29 Maintenance Supervision and Engineering 231859 0
30 Maintenance of Structures 144681 2020238
31 Maintenance of Boiler (or reactor) Plant 1097242 5066533
32 Maintenance of Electric Plant 950135 1066457
33 Maintenance of Misc Steam (or Nuclear) Plant 371286 92204
34 Total Production Expenses 15752011 52450921
35 Expenses per Net KWh 0.0275 0.0176
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Composite Coal Oil Cornposite
37 Unit (Coal-tons/Oil-barrel/Gas-mcflNuclear-indicate)Tons Barrels Tons Barrels
38 Quantity (Units) of Fuel Burned 274462 388 0 1429788 347 0
39 Avg Heat Cont - Fuel Bumed (btu/indicate if nuclear)11451 133333 0 11494 140000 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 36.836 124.046 0.000 0.000 0.000 0.000
41 Average Cost of Fuel per Unit Burned ...39.091 124.046 0.000 27.370 0.000 0.000
42 Average Cost of Fuel Bumed per Milion BTU 1.707 22.150 1.20 1.191 15.797 1.200
43 Average Cost of Fuel Bumed per KWh Net Gen 0.019 0.000 0.019 0.013 0.000 0.013
44 Average BTU per KWh Net Generation 10987.432 3.798 10991.230 10998.930 6.783 11005.713
.
FERC FORM NO.1 (REV. 12-03)Page 402.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCor (1 r An Original (Mo, Da, Yr)2009/Q4(2)OA Resubmission 04/14/2010 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Prouction expenses do not include Purchase Power, System Contrl 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 Electc Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informtive data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and pther physical and operating characteristics of plant.~~~Plant LineName: Name:Hunter Unit No. 3 Name:~No.
(e)I--i-Steam Steam Steam 1
Outdoor Boiler Outdoor Boiler Outdoor Boiler 2
1980 1983 1978 3
1980 1983 1983 4
294.50 495.60 1247.80 5
260 465 1118 6
7977 8076 8760 7
0 0 0 8
259 460 1122 9
0 0 0 10
0 0 223 11
1919186000 3163584000 8071182000 12
9688975 10275401 29653351 13
51902741 9104170 205974007 14
155835995 409607088 798322821 15
953193 953193 2859579 16
218380904 511883852 1036809758 17
741.5311 1032.8568 830.9102 18
...0 0 9 19
25483250 39919514 104856697 20
0 0 0 21
2879751 2895780 .8660546 22
0 0 0 23
0 0 0 24
0 0 0 25
-3012030 2495825 1350291 26
36 36 108 27
0 0 0 28
0 0 0 29
1949545 1841148 5810931 30
5095985 8726696 18889214 31
.1170308 1187195 3423960 32
115600 .211740 419544 33
33682445 57277934 143411300 34
0.0176 0.0181 0.0178 35
Coal Oil Composite Coal Composie Coal Oil Composite 36
.. Tons Barrels Tons Barrels Tons Barrels .37
916714 3490 0 1429028 10817 .0 3775530 17754 0 38
11613 140000 0 11414 140000 0 11508 140000 0 39
0.000 0.000 0.000 0.000 0.000 0.000 27.494 90.181 0.000 40
27.449 0.000 0.000 27.262 0.000 0.000 27.349 90.181 0.000 41
1.182 15.598 1.196 1.194 15.106 1.221 1.188 15.337 1.205 42
0.013 .0.000 0.013 0.012 0.000 0.012 0.013 0.00 0.013 43
11093.719 10.694 11104.413 10311.604 20.105 10331.709 10766.182 12.935 10779.117 44
FERC FORM NO.1 (REV. 12-03)Page 403.1
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2009/Q4
(2)DA Resubmission 04/14/2010 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and intemal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facilty. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned. '
Line Item Plant Plant
No.Name: Huntington Name:~
(a)(b)c ....
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler, etc).Outdoor Boiler Semi-0utdoor
3 Year Originally Constructed .1974 1974
4 Year Last Unit was Installed 1977 1979
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)996.00 1545.10
6 Net Peak Demand on Plant - MW (60 minutes).,893 1427
7 Plant Hours Connected to Load 8716 8760
8 Net Continuous Plant Capabilty (Megawatts)0 .0
9 When Not Limited by Condenser Water .895 1411
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 166 346
12 Net Generation, Exclusive of Plant Use - KWh ..6753764000 10205788000
13 Cost of Plant: Land and Land Rights 2386782 1161925
14 Structures and Improvements 114795130 139315508
15 Equipment Costs 519092603 842656040
16 Asset Retirement Costs 2528174 4672990
17 Total Cost 638802689 987806463
18 Cost per KW of Installed Capacity (line 17/5) Including 641.3682 639.3156
19 Production Expenses: Oper, Supv, & Engr 27278 18005919
20 Fuel 72225359 153880101
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 7937097 3955919
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 0 6741
26 Misc Steam (or Nuclear) Power Expenses 10861739 -14874547
27 Rents 99829 162397
28 Allowances 0 0
29 Maintenance Supervision and Engineering 1148565 565038
30 Maintenance of Structures 2102720 8014043
31 Maintenance of Boiler (or reactor) Plant 8062385 24007785
32 Maintenance of Electric Plant 2080488 8326771
33 Maintenance of Misc Steam (or Nuclear) Plant 1211100 2904601
34 Total Production Expenses 105756560 204954768
35 Expenses per Net KWh 0.0157 0.0201
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal .Composite Coal Oil Composite
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)..Tons Barrels Tons Barrels
38 Quantity (Units) of Fuel Bumed 2742685 10980 0 5605754 17615 0
39 Avg Heat Cont - Fuel Burned (btulindicate if nuclear)12329 140000 0 9219 140000 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 25.969 93.715 0.000 27.430 94.516 0.000
41 Average Cost of Fuel per Unit Burned 25.959 93.715 0.000 27.153 94.516 0.000
42 Average Cost of Fuel Bumed per Milion BTU 1.053 15.938 1.067 1.473 16.074 1.487
43 Average Cost of Fuel Burned per KWh Net Gen 0.011 0.000 0.011 0.015 0.000 0.015
44 Average BTU per KWh Net Generation 10013.541 9.560 10023.101 10126.934 10.149 10137.083
.
FERC FORM NO. 1 (REV. 12-03)Page 402.2
Name of Respondent This ~ort Is: .. .Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2009/Q4(2) OA Resubmission 04/14/2010 End of
.
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Prouction expenses do not include Purchased Power, System Contrl and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expnses, Accunt Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with. combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turb with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess cots attbuted to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any othr informative data coceming plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant ~p"m Line
Name: Naughton Name: Name:Gadsby Steam Plant No.
(d)"
(f)e
Steam Steam Steam 1
Outdoor Boiler Coventional Outdoor 2
1963 1978 1951 3
1971 1978 1955 4
707.20 289.70 251.60 5
710 280 200 6
8760 8315 3753 7
0 0 0 8
700 268 231 9
0 0 0 10
144 67 38 11
4752632000 2173325000 256104000 12
4290826 210526 1252090 13
68909211 50622953 15072596 14
366019199 278115837 58376560 15
6618388 613826 587008 16
445837624 329563142 75288254 17
630.4265 1137.6015 299.2379 18
324827 230568 112089 19
74045306 19381981 34139992 20
0 0 0 21
5333061 0 0 22
0 .0 0 23
0 0 0 24
9228 0 0 25
9224358 4272348 4077590 26
0 6288 0 27
0 0 0 28
1225396 5556 0 29
1439317 474208 220739 30
10677987 5398045 1772321 31
4789264 145166 850210 32
1024574 28854 188443 33
108093318 31509202 41361384 34
0.0227 0.0145 0.1615 35
Coal Composite Coal Oil Composite Gas 36
Tons MCF Tons Barrels MCF 37
2494866 409757 0 1608054 6243 0 3628836 0 .0 38
9907 1033 0 7968 140000 0 1043 0 0 39
28.529 6.654 0.000 11.782 98.704 0.000 9.408 0.000 0.000 40
28.586 6.654 0.000 11.670 98.704 0.000 9.408 0.000 0.000 41
1.443 6.440 1.485 0.732 16.787 0.755 9.024 0.000 0.000 42
0.015 0.001 0.016 0.009 0.000 0.009 0.133 0.000 0.000 43
10400.984 89.078 10490.062 11790.38 16.892 11807.276 14772.370 0.000 0.000 44
FERC FORM NO.1 (REV. 12-03)Page 403.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Oa, Yr)2009/Q4
(2)OA Resubmission 04/14/2010 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facilty. 4. If net peak demand for 60 minutes is not aVailabie, give data which is available, specifyng period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accunts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is bumed in a plant furnish only the composite heat rate for all fuels burned.
-
Line Item Plant Plant
No.Name: Lit/e Mountain Name:~
(a)(b)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine Combined Cycle
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor Boiler Outdoor
3 Year Originally Constructed 1972 1996
4 Year Last Unit was Installed 1972 1996
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)16.00 279.60
6 Net Peak Demand on Plant - MW (60 minutes)17 245
7 Plant Hours Connected to Load 7976 7899
8 Net Continuous Plant Capabilty (Megawatts)0 0
9 When Not Limited by Condenser Water 14 237
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 6 0
12 Net Generation, Exclusive of Plant Use - KWh 109399000 1550620000
13 Cost of Plant: Land and Land Rights 635 842245
14 Structures and Improvements 337028 1284996
15 Equipment Costs 5211774 156147473
16 Asset Retirement Costs 0 214373
17 Total Cost 5549437 170049087
18 Cost per KW of Installed Capacity (line 17/5) Including 346.8398 608.1870
19 Production Expenses: Oper, Supv, & Engr 0 0
20 Fuel 17244593 52931527
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 906225 7483824
26 Misc Steam (or Nuclear) Power Expenses 0 0
27 Rents 0 0
28 Allowances 0 ..0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 0 0
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 712185 0
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 18863003 60415351
35 Expenses per Net KWh 0.1724 0.0390
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas Gas
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)MCF MCF
38 Quantity (Units) of Fuel Burned 1977227 0 0 11250180 0 0
39 Avg Heat Cont - Fuel Bumed (btu/indicate if nuclear)1046 0 0 1019 0 0
40 Avg Cost of Fuel/unit, as Oelvd f.o.b. during year 8.722 0.000 0.000 4.705 0.000 0.000
41 Average Cost of Fuel per Unit Burned 8.722 0.000 0.000 4.705 0.000 0.000
42 Average Cost of Fuel Bumed per Millon BTU 8.339 0.000 0.000 4.615 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.158 0.000 0.000 0.034 0.000 0.000
44 Average BTU per KWh Net Generation 18902.440 0.000 0.000 7397.100 0.000 0.000 .
-
.
FERC FORM NO.1 (REV. 12'(3)Page 402.3
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2009/Q4(2) OA Resubmission 04/14/2010 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accunts. Producton 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, Accunt Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electrc Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steàm, hydro, internl combustion or gas-turbine equipment, report each as a searate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventionàl steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accunting method for cost of power generated including any excess cost attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informtive data conceming plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
N,me, . N.m,,, .. . N.m" .. No.
Steam - Geothermal Steam Combined Cycle 1
Indoor Outdoor Boiler Outdoor 2
1984 1996 2003 3
2007 1996 2003 4
38.10 61.50 593.30 5
36 46 519 6
8594 6764 4652 7
0 0 0 8
34 22 520 9
0 0 0 10
22 0 18 11
279121000 86384000 1747252000 12
41195596 0 1973791 13
7900332 5733734 23230141 14
68774244 28716806 313849140 15
1336278 0 689117 16
119206450 3450540 339742189 17
3128.7782 560.1714 572.6314 18
50045 0 83486 19
0 0 89420353 20
0 0 0 21
5426 0 0 22
3597576 0 0 23
0 0 0 24
0 0 2661898 25
1806790 0 0 26
9640 0 15909 27
0 0 0 28
0 0 0 29
162048 0 10917 30
153519 0 0 31
403022 0 2875548 32
55291 0 0 33
6243357 0 95068111 34
0.0224 0.0000 0.0544 35
Gas 36
MCF 37
0 0 0 0 0 0 12530185 0 0 38
0 0 o ..0 0 0 1032 0 0 39
0.000 0.000 0.000 0.000 0.000 0.000 7.136 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.000 7.136 -c-0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.000 6.918 0.000 0.000 42
0.000 ..0.000 0.000 0.000 0.000 0.000 0.051 0.000 0.00 43
0.000 0.000 0.000 0.000 0.000 0.000 7397.744 0.000 0.000 44
FERC FORM NO.1 (REV. 12-03)Page 403.3
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2009/Q4(2) OA Resubmission 04/14/2010 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and intemal combustion plants of 10,000 Kw or more, and nucleár 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, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities of fuel bumed (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accunts 501 and 547 (Line 42) as show on Line 20.8. If more than one
. fuel is bumed in a plant furnish only the composite heatrate for all fuels burned.
. Line Item Plant Plant
No.Name: Gadsby Gas Peakers Name:Currnt Creek
(a)(b)(c)
1 Kind of Plant (Intemal Comb, Gas Turb, Nuclear Gas Turbine Combined Cycle
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor Outdoor
3 Year Originally Constructed 2002 2005
4 Year Last Unit was Installed 2002 2006
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)181.10 566.90
6 Net Peak Demand on Plant - MW (60 minutes)121 568
7 Plant Hours Connected to Load 5982 7654
8 Net Continuous Plant Capabilty (Megawatts)0 0
9 When Not Limited by Condenser Water 122 550
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 0 19
12 Net Generation, Exclusive of Plant Use - KWh .349713000 2464463000
13 Cost of Plant: Land and Land Rights 0 3403277
14 Structures and Improvements 4241952 43802097
15 Equipment Costs 72822026 305516243
16 Asset Retirement Costs 0 134848
17 Total Cost 77063978 352856465
18 Cost per KWof Installed Capacity (line 17/5) Including 425.5327 622.4316
19 Production Expenses: Oper, Supv, & Engr 0 99940
20 Fuel 35489120 147818357
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses ~1641160 2351396
26 Misc Steam (or Nuclear) Power Expenses 0 0
27 Rents 0 6149
28 Allowances .0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 193326 250824
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 2966597 6436998
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 40290203 156963664
35 Expenses per Net KWh 0.1152 0.0637
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas ...Gas
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)MCF MCF
38 Quantity (Units) of Fuel Burned .4019844 0 0 17314372 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)1046 0 0 1052 0 0 ..
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 8.828 0.000 0.000 8.537 0.000 0.00
41 Average Cost of Fuel pèr Unit Bumed 8.828 0.000 0.000 8.537 0.000 0,000
42 Average Cost of Fuel Bumed per Milion BTU 8.442 0.000 0.000 8.118 0.000 0.000
43 Average Cost of Fuel Bumed per KWh Net Gen 0.101 0.000 0.000 0.060 0.000 0.000
44 Average BTU per KWh Net Generation 12020.788 0.000 0.000 7388.233 0.000 0.000
FERC FORM NO.1 (REV. 12-03)Page 402.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2009/Q4(2) DA Resubmission 04/14/2010 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Producion expenses do not include Purchase Power, System Contrl and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expnses, Accunt Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance-Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unt functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear poer generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and devlopment; (b) types of cot units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name: Lake Side Name:Name:No.
(d)(e)(f).
Combined Cycle 1
Outdoor 2
2007 3
2007 4
591.30 0.00 0.00 5
597 0 0 6
5912 0 0 7
0 0 0 8
558 0 0 9
0 0 0 10
..22 0 0 11
2099013000 0 0 12
17296760 0 0 13
27700094 0 0 14
306701044 0 0 15
0 0 ..0 16
351697898 0 0 17
594.7876 0.0000 0.0000 18
133539 0 0 19
118839066 0 .0 20
0 0 0 21
0 0 0 22
0 0 0 23
0 0 0 24
2606241 0 0 25
0 0 0 26
0 0 0 27
0 0 0 28
0 0 0 29
1088964 0 0 30
0 0 0 31
1885555 0 0 32
0 0 .0 33
124553365 0 0 34
0.0593 0.000 0.0000 35
Gas 36
MCF 37
14857205 0 0 0 0 0 0 0 0 38
1032 0 0 0 0 0 0 0 0 39
7.999 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40
1.999 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41
7'754 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42
0.057 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43
7301.651 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 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) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/14/2010 2009/Q4 .
FOOTNOTE DATA
.
I$chedule Page: 402 Line No.: -1 Column: c
Cholla
The Cholla Plant is operated by Arzona Public Service Company. PacifiCorp owns Unit No.4 plus 36.85% of related common
facilities. Data reported represents PacifiCorp's share. PacifiCorp does not have employees at the Cholla Plant.
Column: d
Fuel oil is used for sta-u u oses.
Schedule Pa e: 402 Line No.: -1 Column: è
Craig
The Craig Plant is operated by Tri-State Generation and Transmission Association and is jointly owned. Data reported represents
PacifiCorp's 19.28% share of Craig Plant Units No. 1 and NO.2 and 12.86% of common facilities. PacifiCorp does not have
employees at the Craig Plant.
Fuel oil is used for star-uchedule Pa e: 402.1 Column: b
Hayden
The Hayden Plant is operated by Public Servce Company of Colorado and is jointly owned. Data reported represents PacifiCorp's
24.5% (45 MW) share of Hayden Unit No.1, 12.6% (33 MW) share of Hayden Unit No.2 and 17.5% of common facilities.
PacifiCorp does not have employees at the Hayden Plant.
Fuel oil is used for star-uchedule Pa e: 402.1 Column: c
Hunter Plant Unit No.1
Hunter Plant Unit NO.1 is owned by PacifiCorp and Uta Municipal Power Agency with an undivided interest of 93.75% and 6.25%,
respectively. Data reported in colum (c) represents PacifiCorp's share. Costs to operate and maintain this unit are charged to
appropriate FERC accounts. Costs that were biled to miority owners for the operation and maintenance (excluding fuel) of this unit
for calendar year 2009 were $1.1 millon and were priarly charged to account 506.
Fuel oil is used for sta-uchedule Pa e: 402.1 Column: d
Hunter Plant Unit No.2
Hunter Plant Unit NO.2 is owned by PacifiCorp, Deseret Power Electrc Cooperative and Utah Associated Municipal Power Systems,
each with an undivided interest of 60.31%,25.108% and 14.582% respectively. Data reported in colum (d) represents PacifiCorp's
share. Costs to operate and maintain this unit are charged to appropriate FERC accounts. Costs that were biled to minority owners for
the operation and maintenance (excluding fuel) of this unit for calenda year 2009 were $6.2 millon and were primarily charged to
account 506.
Fuel oil is usedfor sta-uchedule Pa e: 402.1 Column: f
Hunter
Hunter Unit NO.1 is owned by PacifiCorp and Utah Municipal Power Agency with an undivided interest of 93.75% and 6.25%
respectively. Hunter Unit NO.2 is owned by PacifiCorp, Deseret Power Electrc Cooperative and Utah Associated Municipal Power
Systems, each with an undivided interest of 60.31%, 25.108% and 14.582% respectively. Data in colum (t) represents PacifiCorp's
share. Costs to operate and maintain this plant are charged to appropriate FERC accounts. Costs that were biled to minority owners
for the operation and maintenance (excluding fuel) of this plant for caIendar year 2009 were $7.3 milion and were primaly charged
to account 506.
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 04/14/2010 2009/Q4
FOOTNOTE DATA
Fuel oil is used for start-uchedufe Pa e: 402.2 Column: c
Jim Bridger
Jim Bridger Plant is operated by PacifiCorp and column (c) represents PacifiCorp's share. Owership of the plant is as follows:
PacifiCorp 66 2/3%, Idaho Power Company 33 1/3%. Costs to operate and maintain this plant are charged to appropriate FERC
accounts. Costs that 'Yere biled to minority owners for the operation and maintenance (excluding fuel) of this plant for calenda year
2009 were $25.2 milion and were priarly charged to account 506.
Fuel oil is used for start-uchedule Pa e: 402.2 Column: e
Wyodak
Wyodak Plant is operated by PacifiCorp and colum (e) represents PacifiCorp's share. Ownership of the plant is as follows:
PacifiCorp 80%, Black Hils Corporation 20%. Costs to operate and maintain this plant are charged to appropriate FERC accounts.
Costs that were billed to minority owners for the operation and maintenance (excluding fuel) of this plant for calenda year 2009 were
$3.4 milion ànd were priarly charged to account 506.
Fuel oil is used for sta-uchedule Pa e: 402.3 Column: c
Hermiston
The Hermiston Plant is operated by Hermiston Genertig Company, L.P. and is jointly owned. Data reported represents PacifiCorp's
50.0% share of the Hermiston Plant. See Page 326- Purchased Power of this Form NO.1 for further information on Hermiston
Generatin Com an , L.P. PacifiCo does not have an em 10 ees at the Hermiston Plant.
chedule Pa e: 402.3 Line No.: -1 Column: d
Blundell
All or some of the renewable energy attbutes associated with this generation may be: (i) used in futue years to comply with state or
federal renewable portfolio standards or other regulatory requirements or (ii) sold to third pares in the form of renewable energy
credits or other environmental commodities.
!Schedule Page: 402.3 Line No.: -1 Column: e
Camas Co-Gen
PacifiCorp owns the steam tubine generator and associated systems directly related to the opertion of this unit at Georgia-Pacific
Corporation's Camas, Washington paper mil. Modifications and upgrdes to the existing Camas paper mill were necessar to supply
steam to the tubine and to ensure contiued operation of the unit in the event of mill closure. Georgia-Pacific retained ownership of
these modifications. Georgia-Pacific supplies the fuel and deliver the steam to PacifiCorp's tubine. PacifiCorp is responsible for
major maintenance costs only on the repair of the tuine generator and auxiliar equipment. None of the facilities are jointly owned.
Each asset is wholly owned, either by PacifiCorp or Georgia-Pacific Corporation. PacifiCorp does not have employees at the Camas
Paper Mil.
!Schedule Page: 402.3 Line No.:.-1 Column: f
Chehalis
On September 15,2008, after having received the requisite regulatory approvals, PacifiCorp acquired from TNA Merchant Projects,
Inc., an affliate of Suez Energy Nort America, Inc., 100% of the equity interests of Chehalis Power Generatig, LLC ("Chehalis"),
an entity owning a 520-megawatt ("MW") natul gas-fired genertig facilty located in Chehalis, Washington. The total cash
purchase price was $308 millon and the estimated fair value of the acquird entity was prily allocated to the facility, which was
included in account 102, Electrc plant purchased or sold. Chehalis was merged into PacifiCorp immediately following the
acquisition. The results of the facility's operations have been included in PacifiCorp's fiancial stateents since the acquisition date.
In May 2009, the Federal Energy Regulatory Commission approved the joural entres called for by the Uniform System of Accounts,
with modifications to the purchase accountig adjustments for asset retiement obligations. Accordingly, PacifiCorp cleared
account 102 and recorded the urchase to the a ro riate lant accounts.
chedule Pa e: 402 Line No.: 36 Column: b2
Fuel oil is used for sta-up puroses.
I§chedule Page: 402 Line No.: 36 Column: f2
Fuel oil is used for sta-up puroses.
!schedule Page: 402.1 Line No.: 36 Column: e2
I FERC 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 04/14/2010 20091Q4
FOOTNOTE DATA
Fuel oil is used for start-up purposes.
¡Schedule Page: 402.2 Line No.: 36 Column: b2
Fuel oil is used for star-up puroses.
I§chedule Pagé: 402.2 Line No.: 36 Column: d2
Natual gas is used for star-up purposes.
IFERC FORM NO.1 (ED. 12-87) Page 450.3
Name of Respondent
PacifiCorp
YearlPeriod of ReportThis ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmission 04/14/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilty, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available speciing 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.
End of 2009/Q4
Line
No.
Item
(a)
FERC License Project No. 2082
Plant Name: ~A FERC Licensed Project No. 2082
Plant Name: rim _,
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Ratingin MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capabilty (in megawatt)
9 (a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive c: Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20 1 5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Powe
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Conventional
1918
1922
20.00
24
5,831
Conventional
1925
1925
27.00
29
5,555
'ff 7 "":i ii "7.i%7Yßi7/~i.l!. "0. .'f~'0 "ii%.cq.I!....¡¡ -7."i%/iil 0 ilig ~?!t/ 07 _ø. ~...!í ..~
28
28
1
79,739,000
34
34
2
97,920,000
180,375
1,600,534
2,644,597
5,151,002
105,442
o
9,681,950
484.0975
20,914
2,191,526
2,954,724
10,337,560
479,588
o
15,984,312
592.0116
!WØ/ . 12% i!"%0;%:iHd"ß/7" .//4...// .1!¡i._........2 all/7 %;;..i?12 . 7~."/". /", ... .~.~. .'¡i,l4AY"
153,358
620
1,116
o
437,081
3,338
o
6,840
73,118
35,154
32,337
742,962
0.0093
218,208
837
1,507
o
451,712
4,579
o
16,169
149,902
94,747
34,939
972,600
0.0099
FERC FORM NO.1 (REV. 12-03)Page 406
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmlssion 04/14/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accoUnts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC LicensedProject No. 1927
Plant Name: ~ .FERC Licensed Project No. 1927
Plant Name: ~FERC Licensed Project No. 2420
. Plant Name: . ..
Line
. No.
Outdoor
1953
1953
15.00
13
7,978
Outdoor
1953
1953
26.00
17
8,294
1
2
1927 3
1927 4
30.00 5
29 6
5,401 7-_"~_~J16j"ßw~lI¡;iJ,;"_~3
_..Z;L-._
18 31 29 9
18 31 29 10
1 1 3 11
35,759,000 41,993,000 88,528,000 12
_~~.3:l6_3"~
0 0 3,505,129 14
1,191,014 1,625,933 3,891,430 15
4,428,345 14,775,194 6,645,544 16
1,189,202 1,518,619 14,548,820 17
39,142 250,151 572,059 18
0 0 0 19
6,847,703 18,169,897 29,162,982 20
456.5135 698.8422 972.0994 21
91,907 153,750 246,334 23
12,270 21,268 930 24
63,963 110,870 70,134 25
0 0 0 26
226,354 448,115 602,597 27
6,084 10,546 271 28
145 251 0 29
26,586 39,112 1,657 30
53,258 46,591 26,712 31
45,771 10,370 8,623 32
46,370 80,374 174,227 33
572,708 921,247 1,131,485 34
0.0160 0.0219 0.0128 35
FERC FORM NO.1 (REV. 12-03)Page 407
Name of Respondent
PacifiCorp
YearlPeriod of Report
End of 2oo91Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmission 04/14/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilty, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
(a)
FERC Licensed Project No. 1927
Plant Name: ~. '"
FERC Licènsed.Project No. 20
Plant Name: p _ .
Line
No.
Item
1 Kind of Plant (Run-of-River or Storage)
2 Plant Constrction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 201 5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Outdoor
1952
1952
11.00
10
4,222
1908
1923
33.00
31
7,576~/ ff*'ã;¡ ~~)....~.,
$;; 0\% $1201;::6 A /; %';y ¿jrk
10
10
1
33,450,000
33
33
3
59,082,000~~g /i0~. /~I /w/~ 7t.i_
o
825,661
12,685,388
1,336,038
519,399
o
15,366,486
1,396.9533
62,169
1,618,231
9,208,496
4,231,900
97,073
o
15,217,869
461.1475
70 *./..iWl'dWdi"'// . i( //x...,.~/r ..I~M_g~/7 ::.. "Ø;%~.;; / ~~Ai:lJl 8i&wi.ø_
83,758
8,998
46,907
o
199,249
4,462
106
16,725
25,340
11,557
37,150
434,252
0.0130
260,547
1,023
83,641
o
1,332,068
927
o
14,694
126,159
41,959
110,935
1,971,953
0.0334
FERC FORM NO.1 (REV. 12-03)Page 406.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmission 04/14/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2082Plant Name: ~ . .,FERC Licensed Project No. 2082 FERC Licensed Project No. 1927
Plant Name: ~~ Plant Name: . ~~Line
No.
"f"~.f~~~~1I'~Jji;;,~~
1
Outdoor Outdoor Outdoor 2
1962 1958 1955 3
1962 1958 1955 4
18.00 97.98 31.99 5
18 79 30 6
8,631 6,103 8,148 7
~~.%0"1f1#00~lI~IJAI.";~~iiÆlil~if.;;#~iI~
19 83 32 9
19 83 32 10
1 2 1 11
112,647,000 222,073,000 127,486,000 12
d~. .ff.,.;i.'~j?'..Y x..II......~...i!~.A °0 ',~~; Z j¡ 'ff . ..~;,y_i!ií.. /o/ ~~Ti.úi...."~ .;ff~..tyw/...,~.;;~. ~.. .;..~~.ßMi....k,¡l0 ~.~ "&0£. Ý.
341,706
4,610,225
12,930,242
2,248,775
1,076,116
o
21,207,064
1,178.1702
26,277
2,439,780
14,564,782
15,041,090
886,710
o
32,958,639
336.3813
o 14
1,792,374 15
9,130,690 16
6,083,729 17
475,419 18
o 19
17,482,212 20
546.4899 21
147,737 440,944 226,707 23
558 3,038 26,167 24
1,004 5,467 136,413 25
0 0 0 26
326,255 601,583 507,872 27
3,004 1,044 12,976 28
0 0 309 29
556,758 40,519 52,907 30
55,282 107,365 96,662 31
64,257 24,874 24,844 32
23,292 62,966 98,891 33
1,178,147 1,287,800 1,183,748 34
0.0105 0.0058 0.0093 35
FERC FORM NO.1 (REV. 12-03)Page 407.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmission 04/14/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any planfis leased, operated under a license from the Federal Energy Regulator Commission, or operated as a joint facilty, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item FERC Licensed Project No. 1927
Plant Name:
(a)f!
FERC Licensed Project No.
Plant Name: ir
935
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on PJant-Megawatts(60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cot (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20 / 5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Powr
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 cMaintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Outdoor
1956
1956
33.00
34
4,468
1931
1958
136.00
148
8,670/ 'iS'/ . ../ílJi/~ ;7~.,
34
34
1
89,595,000
151
151
2
452,443,000/1& // iI 'J~J.dk /_7 /~ ~
o
3,283,342
23,240,294
11,398,052
1,649,n9
o
39,571,467
1,199.1354
1,086,417
36,685,802
10,004,954
15,980,829
2,092,829
o
65,850,831
484.1973/ it"/:Y~I~
189,650
26,994
140,720
o
986,647
13,386
319
57,576
58,319
10,923
102,013
1,586,547
0.0177
1,257,788
24,183
526,728
o
1,019,052
2,547
o
40,600
n,178
74,003
270,282
3,292,361
0.0073
FERC FORM NO.1 (REV. 12-03)Page 406.2
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/14/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accunts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 20Plant Name: ..
e
FERC Licensed Project No. 2630
. Plant Name:
Conventional Conventional
1949 1915 1928
1950 1920 1928
42.50 30.00 32.00
44 19 36
6,103 8,744 8,6091~"'~~_."'6..rlr~".ß&l:~¿~JI
45 28 36 9
45 28 36 10
1 2 1 11
213,049,000 33,079,000 226,390,000 12"_~"'~~"'~i~í~~J&.Æø"J..J
0 36,698 105,168 14
2,210,838 1,407,894 2,778,308 15
8,352,148 5,088,376 24,751,241 16
3,266,170 5,155,612 3,600,442 17
257,079 511,059 267,572 18
0 0 0 19
14,086,235 12,199,639 31,502,731 20
331.4408 406.6546 984.4603 211I;t;"_~.~.JI&Æøjí~rll~J_.!ØÆø~!1
255,174 233,533 681,049 23
34,765 930 992 24
181,230 76,037 1,786 25
0 0 0 26
635,548 724,713 477,821 27
17,239 843 4,901 28
410 0 0 .29
66,111 12,434 24,529 30
79,265 448 199,281 31
92,992 82,888 5,884 32
132,171 72,184 77,569 33
1,494,905 1,204,010 1,473,812 34
0.0070 0.0364 0.0065 35
FERC FORM NO.1 (REV. 12-03)Page 407.2
This ~ort Is: Date of Report(1) ~An Onginal (Mo, Da, Yr)
(2) DA Resubmission 04/14/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilty, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available speciing 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.
Name of Respondent
PacifiCorp
YearlPeriod of Report
End of 2009/Q4
Line
No.
Item
a)
FERC Licensed Project No. 1927
Plant Name: ~ .~~(õffø_a if
FERC Licensed Project No. 20
Plant Name: !l _.
1 Kind of Plant (Run-of-River or storage)
2 Plant Constrction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bndges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20 15)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Exenses
26 Electric"Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineenng
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Run-of-River
Outdoor
1951
1951
18.00
18
7,892
Storage
Conventional
1924
1924
14.00
9
6,319
Il z ~4'4 /:lIlIJ:Jf/ z 71B/~ 018 w " :'-;~
18
18
1
80,364,000
14
14
2
11,824,000/1 /7'Z/ z~
o
1,802,822
5,640,915
1,365,431
16,778
o
8,825,946
490.3303
511,675
672,316
5,763,324
2,203,022
o
o
9,150,337
653.5955
o .. ßi5J( '0f~.!i XL! "77//00% /'.00 / 1I..iP&.
103,850
14,724
76,756
o
283,168
7,301
174
29,830
26,328
45,354
56,716
64,201
0.0080
120,563
434
35,484
o
426,089
393
o
12,656
35,568
22,829
31,185
685,201
0.0580
FERC FORM NO.1 (REV. 12-03)Page 406.3
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/14/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accunts or combinations of accunts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1927
Plant Name: ~~~wAWØ"øAl,Ø,ØfarÆW#,Ø~&ØAW.øø~,Ø#.
FERC Licensed Project No. 2111Plant Name: . .
e
Line
No.
1
2
1952 1958 1953 3
1952 1958 1953 4
11.00 240.00 .134.00 5
12 248 163 6
7,802 5,598 5,476 7~~ßi~g¿;_!iJg_$%.!Wi"",%.ßy~¡~gA*b
12 264 164 9
12 263 164 10
1 2 2 11
51,112,000 591,615,000 540,238,000 12_.~_.;~~';iJf'-:~;Y_:¡f__
0 7,813,808 3,299,822 14
1,127,558 8,891,329 6,822,963 15
13,607,662 41,176,239 27,333,548 16
2,192,253 16,092,927 14,887,463 17
56,124 1,004,508 1,395,512 18
0 0 0 19
16,983,597 74,978,811 53,739,308 20
1,543.9634 312.4117 401.0396 21t..~~~~;.~6_.~J:%;ý~;?~:;:J:
72,971 2,156,956 1,229,924 23
8,998 42,676 23,828 24
46,907 1,218,758 518,982 25
0 0 0 26
223,871 1,371,561 877,628 27
4,462 70,294 2,509 28
106 0 0 29
24,328 49,185 22,972 30
42,934 18,508 30,505 31
31,664 136,150 272,602 32
34,502 462,509 274,062 33
490,743 5,526,597 3,253,012 34
0.0096 0.0093 0.0060 35
FERC FORM NO.1 (REV. 12-03)Page 407.3
Name of Respondent
PacifiCorp
Year/Penod of Report
End of 2009/Q4
This ~ort Is: Date of Report(1) ~An Onginal (Mo, Da, Yr)
(2) DA Resubmission 04/14/2010
. HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilty, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item FERC Licensed Project No.
Plant Name:
o FERC Licensed Project No.
Plant Name:
o
(a)(c)
1 Kind of Plant (Run-of-River or Storae)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bndges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20 15)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineenng
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electnc Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
4l il z;; /WØ0 x;; ./ ;: RrZW%Y.Wf/i? 7ß .~",7 _i; ~~£.~ii1l/ . ~IIM ~i: f0ziWøS :.0 . I".
Run-of-River
Conventional
1904
1922
10.30
10
7,162
0.00
o
o
V,:t
10
10
4
25,606,000
o
o
o
o
o
369,124
529,217
31,914
12,641
o
942,896
91.5433
o
o
o
o
o
o
o
0.0000,.~ 0" 4Ç.0..1% "'C1Ii'0.ßi$.:.-'._';w"w_.~
81,619
319
24,079
o
262,859
93
o
56
15,301
14,177
86,547
485,050
0.0189
o
o
o
o
o
o
o
o
o
o
o
o
0.0000
FERC FORM NO.1 (REV. 12.03)Page 406.4
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2009/Q4
This Report Is: Date of Report
(1) I2An Original (Mo, Da, Yr)
(2) OA Resubmission 04/14/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accunts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 0
Plant Name:
FERC Licensed Project No. 0
Plant Name:
FERC Licensed Project No.
Plant Name:
o Line
No.
(d)(e)
_.g~.~.""~"¡..;i.~.i¡¡7B1~Y0
0.00
o
o
0.00
o
o
1
2
3
4
0.00 5
o 6
o 7
o
o
o
o
o
o
o
o
o 9
o 10
o 11
o 12~.jJ~'~.i_~á.~~~::,aJ_£6/;~"
0 0 0 14
0 0 0 15
0 0 0 16
0 0 0 17
0 0 0 18
0 0 0 19
0 0 0 20
0.0000 0.0000 0.0000 21~._~..~.g¡~:.
0 0 0 23
0 0 0 24
0 0 0 25
0 0 0 26
0 0 0 27
0 0 0 28
0 0 0 29
0 0 0 30
0 0 0 31
0 0 0 32
0 0 0 33
0 0 0 34
0.0000 0.0000 0.0000 35
FERC FORM NO.1 (REV. 12-63)Page 407.4
Name of Respondent ....This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
I$chedule Page: 406 Line No.: -1 Column: b
CopcoNo.l
All or some of the renewable energy attbutes associated with generation from these generating facilities may be: (a) used in futue
years to comply with renewable portfolio stadads or other regulatory requirements or (b) sold to third parties in the form of
renewable ener credits or other environmental commodties.
chedule Pa e: 406 Line No.: -1 Column: c
Copco No.2
All or some of the renewable energy attbutes associated with generation from these generatig facilities may be: (a) used in futue
years to comply with renewable portfolio standads or other regulatory requirements or (b) sold to third parties in the form of
renewable ener credits or other environmental commodties.
chedule Pa e: 406 Line No.: -1 Column: d
Clearwater No. 1
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31,2009 was $66,669,978: Lemolo 1, Lemolo 2, Clearwater 1,
Clearwater 2, Toketee, Fish Creek, Soda Sprigs, Slide Creek and the Nort Umpqua Common Plant.
All or some of the renewable energy attbutes associated with generation from these generatig facilities may be: (a) used in futue
years to comply with renewable portfolio standads or other regulatory requirements or (b) sold to third parties in the form of
renewable ener credits or other environmental commodities.
chedule Pa e: 406 Line No.: -1 Column:e
Clearwater No.2
Costs reported for this plant do not include significant intagible costs due to relicensing and settlement, which are recorded inFERC
acçount 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31, 2009 was $66,669,978: Lemolo 1, Lemolo 2, Clearwater 1,
Clearwater 2, Toketee, Fish Creek, Soda Sprigs, Slide Creek and the Nort Umpqua Common Plant.
All or some of the renewable energy attbutes associated with generation from these generatig facilities may be: (a) used in futue
years to comply with renewable portfolio standads or other regulatory requirements or (b) sold to third paries in the form of
renewable ener credits or other environmental commodties.
chedule Pa e: 406 Line No.: -1 Column: f
Cutler
Costs reported for this plant do not include significant intagible costs due to relicensing, which are recorded in FERC account 302,
Franchises and Consents, and are not reported on this page. The net book value for relicensing at December 31, 2009 was $ 1 ,036,287.
Line No.: 1 Column: e
Line No.: -1 Column: b
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA
Clearwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
All or some of the renewable energy attbutes associated with generation from these generating facilities may be: (a) used.in futue
years to comply with renewable portfolio stadards or other regulatory requirements or(b) sold to third pares in the form of
renewable ener credits or other environmental commodities.
chedule Pa e: 406.1 Line No.: -1 Column: c
Grace
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
Bear River system for the following projects at December 31,2009 was $13,984,813: Grace, Oneida and Soda.
All or some of the renewable energy attbutes associated with generation from these generating facilities may be: (a) used in futue
years to comply with renewable portfolio standads or other regulatory requirements or (b) sold to third paries in the form of
renewable eher credits or other environmental commodities.
chedule Pa e: 406.1 Line No.: -1 Column: d
Iron Gate
All or some of the renewable energy attbutes associated with generation from these generating facilities may be: (a) used in futue
years to comply with renewable portfolio stadards or other regulatory requirements or (b) sold to third paries in the form of
renewable ener credits or other environmental commodities.
chedule Pa e: 406.1 Line No.: -1. Column: e
JC Boyle
All or some of the renewable energy attbutes associated with generation from these generating facilties may be: (a) used in futue
years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of
renewable ener credits or other environmental commodities.
chedule Pa e: 406.1 Line No.: -1 Column: f
Lemolo No.1
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reportd on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31,2009 was $66,669,978: Lemolo 1, Lemolo 2, Clearater 1,
Clearwater 2, Toketee, Fish Creek, Soda Sprigs, Slide Creek and the North Umpqua Common Plant.
Line No.: 1 Column: d
Line No.: 1 Column: e
Line No.: -1 Column: b
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 ... 04/14/2010 2009/Q4
FOOTNOTE DATA
All or some of the renewable energy attbutes associated with generation from these generating facilities may be: (a) used in futue
years to comply with renewable portolio stadads or other regulatory requirments or (b) sold to third paries in the form of
renewable ener credits or other environmental commodities.
chedule Pa e: 406.2 Line No.: -1 Column: c
Merwn
Costs reported for this plant do not include significant intagible costs due to relicensing and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reportd on this page. The net book value for relicensing and settlement on the
Lewis River system for the following projects at December 3 i, 2009 was $40,480,460: Merwin, Yale, and Swift # i.
All or some of the renewable energy attbutes assoCiated with generation from these generating facilities may be: (a) used in futue
years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third paries in the form of
renewable ener credits or other environmental commodities.
chedule Pa e: 406.2 Line No.: -1 Column: d
Toketee
Costs reported for this plant do not include significant intagible costs due to relicensing and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31,2009 was $66,669,978: Lemolo 1, Lemolo 2, Clearwater 1,
Clearwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
All or some of the renewable energy attbutes associated with generation from these generating facilities may be: (a) used in futue
years to comply with renewable portfolio stadads or other regulatory requirements or (b) sold to third pares in the form of
renewable ener credits or other environmental commodities.
chedule Pa e: 406.2 Line No.: -1 Column: e
Oneida
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
Bear River system for the following projects at December 31,2009 was $13,984,813: Grace, Oneida and Soda.
All or some of the renewable energy attbutes associated with generation from these generating facilties may be: (a) used in futue
years to comply with renewable portfolio stadads or other regulatory requirements or (b) sold to third paries in the form of
renewable ener credits or other environmental commodities.
chedule Pa e: 406.2 Line No.: -1 Column: f
Prospect No.2
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement at
Prospect units 1,2, and 4 on December 31,2009 was $7,245,959.
Line No.: 1 Column: d
Line No.: -1 Column: b
. Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mö, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
NorthUmpqua River system for the following projects at December 31,2009 was $66,669,978: Lemolo I,Lemolo 2, Clearater 1,
Clearater 2, Toketee, Fish Creek, Soda Sprigs, Slide Creek and the North Umpqua Common Plant.
All or some of the renewable energy attbutes associated with generation from these generating facilities may be: (a) used in futue
years to comply with renewable portfolio stadards or other regulatory requirements or (b) sold to third paries in the form of
renewable ener credits or other environmental commodities.
Schedule Pa e: 406.3 Line No.: -1 Column: c
Soda
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
Bear River system for the following projects at December 31,2009 was $13,984,813: Grace, Oneida and Soda.
All or some of the renewable energy attbutes associated with generation from these generating facilities may be: (a) used in futue
years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third paries in the form of
renewable ener credits or other environmental commodities.
Schedule Pa e: 406.3 Line No.: -1 Column: d
Soda Springs
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31,2009 was $66,669,978: Lemolo 1, Lemolo 2, Clearater 1,
Clearwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
All or some of the renewable energy attbutes associated with generation from these generating facilities may be: (a) used in futue
years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third paries in the form of
renewable ener credits or other environmental commodities.
chedule Pa e: 406.3 Line No.: -1 Column: e
Swift #1
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
Lewis River system for the following projects at December 31, 2009 was $40,480,460: Merwin, Yale, and Swift #1.
All or some of the renewable energy attbutes associated with generation from these generating facilities may be: (a) used in futue
years to comply with renewable portfolio stadads or other regulatory requirements or (b) sold to third pares in the form of
renewable ener credits or other environmental commodities.
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 settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reportd on this page. The net book value for relicensing and settlement on the
Lewis River system for the following projects at December 31, 2009 was $40,480,460: Merwin, Yale, and Swift # 1.
All or some of the renewable energy attbutes associated with generation from these generating facilities may be: (a) used in futue
years to comply with renewable portfolio stadads or other regulatory requirements or (b) sold to third pares in the form of
renewable ener credits or other environmental commodities.
chedule Pa : 406.4 Line No.: -1 Column: b
Olmsted
The Olmsted Plant is owned by the U.S. Bureau of Land Reclamation. PacifiCorp has a 25-year lease begining in 1990. PacifiCorp
operates the plant and owns all the generation. The cost of the Olmsted plant includes leasehold improvements and facilties which
PacifiCorp holds title.
All or some of the renewable energy attbutes associated with generation from these generating facilities may be: (a) used in futue
years to comply with renewable portfolio standads or other regulatory requirements or (b) sold to third paries in the form of
renewable energy credits or other environmental commodities.
IFERC FORM NO.1 (ED. 12-87)Page 450.4
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/14/2010
GENERATING PLANT STATISTICS (Small Plants
1. Small generating plants are steam plants of, less than 25,000 Kw; intemal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as ajoint facilty, and give a concise statement of the fact in a footnote. If licensed project, give
project number in footnote.
Year/Period of Report
End of 2009/Q4
Line Year Net GenerationName of Plant Orig.Excluding Cost of Plant
No.Const.Plant Use
(b)(e)(f)
1917 6.85 6.6 33,735 8,901,803
1913 1.11 1.0 3,169 1,311,390
1910 4.15 4.6 28,977 7,088,545
1913 1.00 338,978
1913 13.70 15.0 81,802 6,932,772
1957 2.81 2.8 17,375 1,801,778
1924 3.20 3.0 7,656 1,992,974
1903 2.20 2.0 14,701 1,286,479
1922 0.16 0.1 737 624,480
1896 2.00 1.2 7,339 5,002,434
1917 0.75 0.5 1,578 656,163
1983 1.73 1.3 4,034 2,802,691
1910 0.72 0.7 2,80 410,525
1897 5.00 4.24,695 10,738,733
1923 6.00 720,239
1912 3.76 4.6 29,008 1,033,321
1932 7.20 7.7 35,639 6,958,213
194 1.00 0.9 2,379 357,755
1926 0.80 0.5 1,297 891,596
1910 1.18 1.0 3,588 1,019,558
1895 1.00 1.2 6,47 1,596,871
1915 0.50 1,350,659
1920 0.50 0.3 1,011 835,949
1986 0.74 0.3 851 1,195,939
1921 1.10 1.0 6,656 2,834,145
1911 3.85 2.0 15,154 2,889,714
1908 0.60 0.6 1,066 468,574
7,501,154
5,063,528
14,147,981
1917 19,296,114-2.0 -1,300-4.50
1999 32.62 31.0 86,324 37,196,623
Glenrock 2008 99.00 99.0 253,875 199,803,708
Glenrock II 2009 39.00 38.0 84,675 87,151,990
Rollng Hils 2009 99.00 99.0 207,820 200,996,518
Goodnoe Hils 2008 94.00 93.0 237,374 179,757,749
Leaning Juniper 1 2006 100.50 100.0 258,767 174,191,781
Marengo 2007 140.40 138.0 316,552 236,868,467
Marengo II 2008 70.20 69.0 158,279 127,879,828
Seven Mile Hil 2008 99.00 99.0 303,510 198,738,782
Seven Mile Hil ii 2008 19.50 19.0 62,229 41,775,232
FERC FORM NO.1 (REV. 12-03)Page 410
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) !KAn Original (Mo, Da, Yr)End of 2009/Q4
(2) r"A Resubmission 04/14/2010
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period.5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilzed in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset Operation Production Expenses Fuel Costs (in cents Line.,. Retire. Costs) Per MW Exc'1. Fuel Fuel Maintenance Kind of Fuel (per Milion Btu)No.(g)(h)(i)0)(k)(I)
1
1,299,533 402,667 107,524 Water 2
...1,181,432 56,980 4,269 Water 3
1,708,083 322,169 .57,962 Water 4
338,978 5,042 724 Water 5
506,02 ..397,378 66,475 Water 6
641,202 261,276 59,323 Water 7
622,804 139,871 7,852 Water 8
584,763 91,307 32,806 Water 9
3,903,000 25,098 -2,370 Water 10
2,501,217 120,769 18,084 Water 11
874,884 .53,382 11,989 Water 12
1,620,053 129,615 14,966 Water 13
570,174 42,027 19,747 Water 14
2,147,747 282,186 140,023 Water 15
120,040 147,135 6,446 Water 16
274,819 168,736 -15,528 Water 17
966,418 401,256 111,224 Water 18
357,755 47,785 47,327 Water 19
1,114,495 52,688 14,391 Water 20
864,032 92,105 28,756 Water 21
1,596,871 91,149 10,153 Water 22
2,701,318 32,053 3,520 Water 23
1,671,898 49,900 70,407 Water 24
1,616,134 78,185 25,430 Water 25
2,576,495 41,145 31,364 Water 26
750,575 191,872 61,378 Water 27
780,957 50,400 21,780 Water 28
3,377 8,159 29
157,408 20,606 30
31
.32
33
-4,288,025 205,529 51,321 Water 34
.35
36
1,140,301 1,630,021 Wind 37
2,018,219 1,313,119 92,496 Wind 38
2,234,666 432,263 21,909 Wind 39
2,030,268 1,901,925 55,616 Wind 40
1,912,316 1,913,858 57,490 Wind 41
1,733,252 2,677,232 63,356 Wind 42
1,687,097 4,826,041 87,866 Wind 43
1,821,650 2,039,396 43,933 Wind 44
2,007,462 1,339,535 118,755 Wind 45
2,142,320 274,818 23,991 Wind 46
FERC FORM NO.1 (REV. 12-03)Page 411
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmission 04/14/2010
G NERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25,000 Kw; intemal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating).'"2, Designate any plant leased from others, operated under a licnse from
the Federal Energy Regulatory Commission, or operated as a joint facilty, and give a concise statement of the facts in a footnote. If licensed project, give
project number in footnote.
Line Year Install t;a\?city i:et ..eaK Net GenerationName of Plant Orig.Name Plate atin Demand Excluding Cost of Plant
No.Const.(In MW)(6~arn.)Plant Use
(a)(b)(c)(e)(f)
1 High Plains 2009 99.00 98.0 72,695 219,244,704
2 McFadden Ridge i 2009 28.50 27.0 20,558 56,762,967
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
FERC FORM NO.1 (REV. 12-03)Page 410.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) riA Resubmission 04/14/2010
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. List plants appropnately 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 availabe, give the which is available, specifying penod.5. If any plant is equipped with
combinations of steam, hydro intemal 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 Cost (Incl Asset Operation Production Expenses Fuel Costs (in cents LineRetire. Costs) Per MW Exc'1. Fuel Fuel Maintenance Kind of Fuel (per Milion Btu)No.(g)(h)(i)0)(k)(i)
2,214,593 186,553 675,439 Wind 1
1,991,683 49,753 ..191,033 Wind 2.
3
4
S
..".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
..
FERC FORM NO.1 (REV. 12-03)Page 411.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/04
FOOTNOTE DATA
fSchedule Page: 410 Line No.: 1 Column: a
Common river s stem costs for the 0 eration of these facilties are allocated to each
Schedule Pa e: 410 Line No.: 2 Column: a
Ashton
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federal renewable portfolio standards or other regulatory requirements or (ii) sold to third pares in the form of renewable energy
credits or other environmental commodities.
Costs reported for this plant do not include intagible costs due to relicensing which are recorded in FERC account 302, Franchises
and Consents, and are not re orted onthÌs a e. The net book value for relicensin at December 31, 2009 was $178,000.
chedule Pa e: 410 Line No.: 4 Column: a
BigFork
All or some of the renewable energy attbutes associated with this generation may be (i) used in futu year to comply with state or
federal renewable portfolio stadads or other regulatory requirements or (ii) sold to third pares in the form of renewable energy
credits or other environmental commodities.
Costs reported for this plant do not include intagible costs due to relicensing which are recorded in FERC account 302, Franchises
and Consents, and are not re orted on this a e. The net book value for relicensin at December 31, 2009 was $547,892.
chedule Pa e: 410 Line No.: 5 Column: a
Cline Falls
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federal renewable portfolio standards or other regulatory requirements or (ii) sold to third paries in the form of renewable energy
credits or other environmental commodities.
I$chedule Page: 410 Line No.: 6 Column: a
Condit
In September 1999, a settlement agreement to remove the 14-MW Condit hydroelectrc facilty was signed by PacifiCorp, state and
federal agencies and non-governental organizations. Under the original settlement agreement, removal was expected to. begin in
October 2006, with a total cost to decommssion not to exceed $17 millon, excluding inflation. In early Februry 2005, the paries
agreed to modify the settlement agreement so that removal would not begin until October 2008, with a total cost to decommssion not
to exceed $21 million, excluding inflation. The settlement agrement is contigent upon receiving a FERC surender order and other
regulatory approvals that are not materially inconsistent with the amended settlement agreement. PacifiCorp is in the process of
acquirng all necessar permts within the terms and conditions of the amended settlement agreement. Given the ongoing permtting
process and the time needed for system removal and to evaluate impacts on natul resources, decommissioning is now expected to
begin no earlier than October 2010. In March 2008, the Unite States Ary Corps of Engieers requested PacifiCorp complete an
additional study of expected decommssioning impacts on aquatic resources. In Janua 2009, the study work was completed and the
results were provided to the United States Ary Corps of Engieer and the Washingtn Deparent of Ecology. In Januar 2010,
the Washington Departent of Ecology released the Final Second Supplemental Environmental Impact Statement which formally
considered this additional information. Absent fuer informtion requests, the Washington Deparent of Ecology is expected to
complete the Clean Water Act 401 certfication process within the second quarer of 2010. Remaining permittg includes a 404
permt from the United States Ary Corps of Enginees and a surender order from the FERC.
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) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
~chedule Page: 410 Line No.: 7 Column: a
Eagle Point
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federal renewable portfolio standards or other regulatory requirements or (ii) sold to thiÌd pares in the form of renewable energy
credits or other environmental commodities.
¡Schedule Page: 410 Line No.: 8 Column: a
Eastside
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federal renewable portfolio standads or other regulatory requirements or (ii) sold to third partes in the form of renewable energy
credits or other environmental commodities.
¡Schedule Page: 410 Line No.: 9 Column: a
FaUCreek
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federal renewable portfolio standads or other regulatory requirements or (ii) sold to third partes in the form of renewable energy
credits or other environmental commodities.
¡Schedule Page: 410 Line No.: 10 Column: a
Fountain Green
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federal renewable portfolio standards or other regulatory requirements or (ii) sold to third partes in the form of renewable energy
credits or other environmental commodities.
Costs reported for this plant do not include intangible costs due to relicensing which are recorded in FERC account 302, Franchises
and Consents, and are not re orted on this a e. The net book value for relicensin at December 3 i, 2009 was $1,524.
chedule Pa e: 410 Line No.: 11 Column: a
Granite
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue year to comply with state or
federal renewable portfolio standads or other regulatory requirements or (ii) sold to third paries in the form of renewable energy
credits or other envionmental commodities.
¡Schedule Page: 410 Line No.: 12 Column: a
Gunlock
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federal renewable portfolio standards or other regulatory requirements or (ii) sold to third partes in the form of renewable energy
credits or other enviromhental commodities.
Costs reported for this plant do not include intagible costs due to relicensing which are recorded in FERC account 302, Franchises
and Consents, and are not re orted on this a e. The net book value for relicensin at December 31,2009 was $44,303.
chedule Pa e: 410 Line No.: 13 Column: a
Last Chance
All or some of the renewable energy attbutes associated with this generation may be (i) used in future years to comply with state or
federal renewable portfolio standads or other regulatory requirements or (ii) sold to third partes in the form of renewable energy
credits or other environmental commodities.
¡Schedule Page: 410 Line No.: 14 Column: a
Paris
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federal renewable portfolio standads or other regulatory requirements or (ii) sold to third paries in the form of renewable energy
credits or other environmental commodities.
¡Schedule Page: 410 Line No.: 15 Column: a
Pioneer
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federal renewable portolio standads or other regulatory requirements or (ii) sold to third partes in the form of renewable energy
credits or other environmental commodities.
IFERC FORM NO.1 (ED. 12-S7) Page 450.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Me, Da, Yr)
PacifiCorp ! (2) A Resubmission 04/14/2010 20091Q4
FOOTNOTE DATA
Costs reported for this plant do not include intagible costs due to relicensing which are recorded in FERC account 302. Franchises
and Consents, and are not r orted on this a e. The net book value for relicensin at December 31,2009 was $114,855.
chédule Pa e: 410 Line No.: 16 Column: a
Powerdale
In June 2003, PacifiCorp entered into a settlement agreement to remove the 6-MW Powerdale plant rather than pursue a new license,
based on an analysis of the costs and benefits of relicensing versus decommissioning. Removal of the Powerdale dam and associated
system featues, which is subject to the FERC and other regulatory approvals, is projected to cost $6 millon, excluding inflation.
Plant shut down and removal was scheduled to commence in 2010. However, in November 2006, flooding damaged the Powerdale
plant and rendered its generating capabilities inoperable. In Febru 2007, the FERC granted PacifiCorp's request to cease
generation at the plant; however, removal is still scheduled for 2010. Also in Febru 2007, PacifiCorp submitted cl request to the
FERC to allow PacifiCorp to defer the remaining net book value and any additional removal costs of this system as a regulatory asset.
In May 2007, the FERC issued an order that approved PacifiCorp's proposed accounting 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
regulatory commssions to defer and recover these costs.
The remaining costs in colum (t) represent land and equipment that will be trsferred or sold after the plant is decommissioned.
¡Schedule Page: 410 Line No.: 17 Column: a
Prospect 1
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state Or
federal renewable portfolio standards or other regulatory requirements or (ii) sold to third partes in the form of renewable energy
credits or other environmental commodities.
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement at
Pros ect units 1,2, and 4 at December 31,2009 was $7,245,959.
chedule Pa e: 410 Line No.: 18 Column: a
Prospect 3
All or some of the renewable energy attbutes associate with this genertion may be (i) used in futue years to comply with state or
federal renewable portfolio standards or other regulatory requirements or (ii) sold to third partes in the form of renewable energy
credits or other environmental commodities.
Costs reported for this plant do not include intangible costs due to relicensing which are recorded in FERC account 302, Franchises
and Consents, and are not reported on this page. The net book value for relicensing at Prospect unit number 3 at December 31, 2009
was $88,213.
'§chedule Page: 410 Line No.: 19 Column: a
Prospect 4
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federal renewable portfolio standards or other regulatory requirements or (ii) sold to third pares in the form of renewable energy
credits or other environmental commodities.
Costs reported for this plant do not include significant intagible costs due to relicensing and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reprted on this page. The net book value for relicensing and settlement at
Pros ect units 1, 2, and 4 at December 31, 2009 was $7,245,959.
chedule Pa e: 410 Line No.: 20 Column: a
Sand Cove
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue year to comply with state or
federal renewable portfolio stadards or other regulatory requirements or (ii) sold to third pares in the form of renewable energy
credits or other environmental commodities.
'§chedule Page: 410 Line No.: 21 Column: a
Snake Creek
All or some of the renewable energy attbutes associated with this genertion may be (i) used in futue years to comply with state or
federal renewable portfolio standads or other regulatory requirements or (ii) sold to third pares in the form of renewable energy
IFERC FORM NO.1 (ED. 12-87) Page 450.3
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
...
credits or other environmental commodities.
Schedule Page: 410 Line No.: 22 Column: a
Stairs
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue year to comply with state or
federal renewable portfolio stadards or other regulatory requirements or (ii) sold to third partes in the form of renewable energy
credits or other environmental commodities.
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federal renewable portfolio standards or other regulatory requirements or (ii) sold to third partes in the form of renewable energy
credits or other environmental commodities.
I$chedule Page: 410 Line No.: 24 Column: a
Veyo
All or some of the renewable energy attbutes associated with this generation may be (i) used in future years to comply with state or
federal renewable portfolio standards or other regulatory requirements or (ii) sold to third pares in the form of renewable energy
credits or other environmental commodities.
I$chedule Page: 410 Line No.: 25 Column: a
Viva Naughton
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federal renewable portfolio standards or other regulatory requirements or (ii) sold to third parties in the form of renewable energy
credits or other environmental commodities.
I$chedule Page: 410 Line No.: 26 Column: a
Wallowa Falls
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federa renewable portfolio standads or other regulatory requirements or (ii) sold to third pares in the form of renewable energy
credits or other environmental commodities.
ISchedulePage: 410 Line No.: 27 Column: a
Weber
All or some of the renewable energy attbutes associated with this generation may be (i) used in futue years to comply with state or
federal renewable portfolio standads or other regulatory requirements or (ii) sold to third partes in the form of renewable energy
credits or other environmental commodities.
Column: a
Column: a
Page 450.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/14/2010 20091Q4
..FOOTNOTE DATA .
North Umpqua
Represents facilities that support the Nort Umpqua River system projects. All common roads, employee houses, control equipment,
etc. are in this account.
Costs reported for this plant do not include significant intagible costs due to relicensing and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
Nort Umpqua River system for the following projects at December 31, 2009 was $66,669,978: Lemolo 1, Lemolo 2, Clearwater 1,
Clearwater 2, Toketee, Fish Creek, Soda S rin s, Slide Creek and the North Urn ua Common Plant.
chedule Pa e: 410 Line No.: 36 Column: a
This footnote applies to all wind-powered generating facilties. All or some of the renewable energy attbutes associated with this
generation maybe (i) used in futue year to comply with state or federal renewable portolio stadards or other regulatory
requirements or (ii) sold to third partes in the form of renewable energy credits or other environmental commodities.
I$chedule Page: 410 Line No.: 37 Column: a
Foote Creek
The Foote Creek wind-powered generating facilty is operated by SeaWest Energy and is jointly owned. Data reported represents
PacifiCorp's share. Ownership of the plant is as follows: PacifiCorp 78.79%, Eugene Water and Electrc Board 21.21 %.
IFERC FORM NO.1 (ED. 12-87)Page 450.5
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of Iin!'s, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutilty Propert.
5. Indicte whether the type of supportng structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicàte the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of constrction need not be distinguished from the remainder
. of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on strctures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line \lni Type of LE~~Ji~ ~gle ólileS)
(Indicate wtiere NumberNo.other than u dergroun;rlInes
60 cvcle, 3 phase)Supporting report circuit miles)Of
From To Operating un ~trl,cture unt1~ru(m:res CircuitsDesignedStructureof Line o I'ot erDesil8atedLine....(a)(b)(c)(d)(e)(g)(h)
1 MALIN, OR PG&E ROUND MTN, CA 500.0C 500.00 Steel Tower 47.00 1
2 KLAMATH CO-GEN, OR CAPTAIN JACK, OR 500.0C 500.00 Steel Tower 26.00 1
3 MERIDIAN, OR KLAMATH CO-GEN, OR SOO.OC 500.00 Steel Tower 58.00 1~'XONVIUE500.0R 500.0C 500.00 Steel Tower 58.00 15 MERIDIAN, OR 500.0C 500.00 Steel Tower 74.00 1
6 CAPTAIN JACK, OR MALIN, OR 500.0C 500.00 Steel Tower 7.00 1
7 MIDPOINT, OR MALIN, OR 500.0(500.00 Steel Tower 446.00 1
8 SWITCHYARD, MT 500.0(500.00 Steel Tower 1.00 1
9 .BROADVIEW A, MT 500.0(500.00 Steel Tower 112.00 1
10 BROADVIEW B, MT 500.0C 500.00 Steel Tower 116.00 1
11 OWNSEND A, MT 500.0 500.00 Steel Tower 133.00 1
12 TOWNSEND B, MT 500.0 500.00 Steel Tower 133.00 1
13 500 kV Costs and expenses
14
15 Subtotal 500 kV 1,211.00 12
16
17 BEN LOMOND, UT BORAH,ID 345.0 345.00 Wood-H 133.00 1
18 BEN LOMOND, UT CAMP WILLIAMS, UT 345.0 345.00 SteelSP 70.00 1
19 BEN LOMOND, UT TERMINAL, UT 345.0C 345.00 47.00 1
20 EMERY, UT CAMP WILLIAMS, UT 345.0C 345.00 Steel Tower 121.00 1
21 CAMP WILLIAMS, UT MONA #3, UT 345.0C 345.00 Wood.H 47.00 1
22 NINETY SOUTH, UT CAMP WILLIAMS, UT 345.0C 345.00 SteelSP 11.00 1
23 CAMP WILLIAMS, UT MONA#1, UT 345.0C 345.00 Wood.H 47.00 1
24 CAMP WILLIAMS, UT MONA #2, UT 345.0C 345.00 Steel Tower 47.00 1
25 SPANISH FORK, UT CAMP WILLIAMS, UT 345.0C 345.00 35.00 1
26 TERMINAL, UT CAMP WILLIAMS, UT 345.0C 345.00 Steel SP 26.00 1
27 TERMINAL, UT CAMP WILLIAMS #2, UT 345.0C 345.00 23.00 1
28 EMERY, UT HUNTINGTON, UT 345.0C 345.00 Wood-H 20.00 1
29 EMERY, UT SIGURD #1, UT 345.0C 345.00 Steel-H 7400 1
30 EMERY, UT SIGURD #2, UT 345.0C 345.00 Steel-H 75.00 1
31 FOUR CORNERS, NM PINTO, UT 345.0C 345.00 Wood-H 101.00 1
32 GOSHEN,ID KINPORT,ID 345.0C 345.00 Wood-H 41.00 1
33 HUNTINGTON, UT PINTO, UT 345.0C 345.00 Wood-H 160;00 1
34 HUNTINGTON, UT SPANISH FORK, UT 345.0C 345.00 Wood-H 78.00 1
35 TERMINAL, UT NINETY SOUTH, UT 345.0C 345.00 SteelSP 16.00 1
36 TOTAL 15,802.00 648.00 240
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This Ï!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) r=A Resubmission 04/14/2010
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltge 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) arid the pole miles of the other line(s) in column (g)
8. Designate any transmission line or pton thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lesso, 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 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 accunted for, and accunts affecd. Specify whether lessor, cowner, 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. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (I) on the bok cost at end of year.
l,U:: r UF LINt: (inClUde in çoiumn 0) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses
(0)
Expenses No.(i)0)(k)(I)(m)(n)(p)
13-1852 ACSR 51/27 1
13-1272 ACSR 36/1 2
13-1272 ACSR 36/1 3
13-1272 ACSR 54/19 4
ß-1272 ACSR 54/19 5
13-2250 MC /91 6
13-1272 ACSR 36/1 7
8
9
10
11
12
13,734,191 269,584,360 283,318,55C 976,000 374,982 1,350,98 13
14
13,734,191 269,584,360 283,318,550 976,000 374,982 1,350,98 15
16
12-954 ACSR 54/7 17
12-1272 ACSR 45/7 18
D-1272 ACSR 45/7 19
0-1272 ACSR 45/7 20
0-954 ACSR 45/7 21
0-1272 ACSR 45/7 22
0-122 ACSR 45/7 23
0-954 ACSR 54/7 24
0-1272 ACSR 45/7 25
0-1272 ACSR 45/7 26
~-1272 ACSR 45/7 27
D-95 ACSR 54/7 28
0-954 ACSR 54/7 29
0-954 ACSR 54/7 30
0-795 ACSR 45/7 31
0-795 ACSR 45/7 32
0.795 ACSR 45/7 33
0-1272 ACSR 45/7 34
0.1272 ACSR 45/7 35
.
90,436,374 1,853,139,117 1,943,575,491 245,152 19,620,06!1,641,382 21,506,60(36
FERC FORM NO.1 (ED. 12-87)Page 423
Name of Respondent This (!0rt Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) . OA Resubmission 04/14/2010
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lin~s, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts.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 type of supporting structure reported in column (e) is: (1) single pole wood ,or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) undergrqund construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
.the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line IIUN
ri~d1~~~~~~Type of LENGJiH ~ole wileS)~Ilt e SSD NumberNo.other than u dergroun lines Of60 cycle, 30hase)Supporting report circuit miles)
From To Operating Designed un¿:l(y~ure uga:~~~1W¡rS CircuitsStructureDesip;ated Line(a)(b)(c)(d)(e)(g)(h)
1 MONA, UT SIGURD #1, UT 345.0(345.00 SleelTower 69.00 1
2 MONA, UT SIGURD #2, UT 345.0(345.00 69.00 1
3 SIGURD, UT UT 1 NV BORDER, UT 345.0(345.00 Wood-H 190.00 1
4 JIM BRIDGER, WY BORAH,ID 345.0(345.00 SleelTower 239.00 1
5 JIM BRIDGER, WY KINPORT,ID 345.0(345.00 SleelTower 234.00 1
6 MONA, UT HUNTINGTON, UT 345.0(345.00 Steel Tower 60.00 1
7 CURRENT CREEK, UT MONA, UT 345.0(345.00 SteelSP 1.00 1
8 CAMP WILLIAMS, UT MONA #4, UT 345.0(345.00 Wood- H 5.00 42.00 1
9 345 kV costs and expenses
10
11 Subtotal 345 kV 1,838.00 243.00 27
12
13 ANTELOPE, ID ANACONDA, ID 230.0(230.00 Wood- H 76.00 1
14 ANTELOPE, ID LOST RIVER, ID 230.0(230.00 Wood- H 20.00 1
15 BEN LOMOND, UT NAUGHTON #1, WY 230.0(230.0Q.Wood-H 88.00 1
16 BEN LOMOND, UT NAUGHTON #2, WY 230.0(230.00 Wood- H 88.00 1
17 BIRCH CREEK, UT RAILROAD, UT 230.0(230.00 Wood- H 19.00 1
18 BEN LOMOND, UT TERMINAL, UT 230.0(230.00 Steel Tower 47.00 1
19 TREASURETON, ID BRADY,ID 230.0 230.00 Wood-H 66.00 1
20 GLEN CANYON, AZ .SIGURD, UT 230.0(230.00 Wood- H 159.00 1
21 GONDER (ELY), UT PAVANT, UT 230.0(230.00 Wood- H 98.00 1
22 NAUGHTON; WY TREASURETON, 10 230.0(230.00 Wood- H 80.00 1
23 PAROWAN VALLEY, UT SIGURD, UT 230.0(230.00 Wood- H 94.00 1
24 PAROWAN VALLEY, UT WEST CEDAR, UT 230.0(230.00 Wood-H 26.00 1
25 PAVANT, UT SIGURD, UT 230.0C 230.00 Wood-H 43.00 1
26 PALISADES SS, WY BLUE RIM, WY 230.0(230.00 Wood- H 4.00 1
27 BUFFALO, WY CASPER, WY 230.0C .230.00 Wood- H 107.00 1
28 GOOSE CREEK, WY BUFFALO, WY 230.0C 230.00 Wood-H 43.00 1
29 WYODAK,WY BUFFALO, WY 230.0(230.00 Wood-H 69.00 1
30 JIM BRIDGER, WY DAVE JOHNSTON, WY 230.0(230.00 Wood-H 218.00 1
31 ROCK SPRINGS, WY JIM BRIDGER, WY .230.0(230.00 Wood- H 35.00 1
32 JIM BRIDGER, WY SPENCE, WY 230.0(230.00 Wood-H 149.00 1
33 CASPER, WY DAVE JOHNSTON, WY 230.0(230.00 Wood-H 32.00 1
34 CASPER, WY RIVERTON, WY 230.0(230.00 Wood-H 110.00 1
35 DAVE JOHNSTON, WY CASPER, WY 230.0(230.00 Wood-H 46.00 1
36 TOTAL 15,802.00 648.00 240..
FERC FORM NO.1 (ED. 12-S7)Page 422.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010 .
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 fotnote 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 emount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of cowner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accunted for, and accounts affected. Specify 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. Specify whether lessee.is an associated company.
10. Base the plant cost figures called for in columns ü) to (I) on the bo cost at end of year.
COST '1F i INF /Include in Column U) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses
(0)
Expenses No.(i)ü)(k)(I)(m)(n)(p)
-795 ACSR 4517 1
-954 ACSR 5417 2
'-954 ACSR 54/7 3
'-1272 ACSR 4517 4
'-1272 ACSR 4517 5
'-954 ACSR 5417 6
-954 ACSR 5417 7
2-954 ACSR 5417 8
37,090,94£376,147,084 413,238,030 80,463 1,524,103 331,345 1,935,911 9
10
37,090,94£376,147,084 413,238,030 80,463 1,524,103 331,345 1,935,911 11
12
1272 ACSR 451 13
95 ACSR 4517 14
2-795 ACSR 2617 15
t?-795 ACSR 2617 16
ß54 ACSR 5417 17
127 ACSR 451 18
95 ACSR 2617 19
ß54 ACSR 4517 20
95 ACSR 4517 21
1272 ACSR 4517 22
95 ACSR 4517 23
95 ACSR 4517 24
95 ACSR 4517 25
1272 ACSR 36/1 26
1272 ACSR 36/1 27
1795 ACSR 2617 28
1272 ACSR 36/1 29
1272 ACSR 4517 30
1272 ACSR 36/1 31
1272 ACSR 36/1 32
1272 ACSR 36/1 33
1272 ACSR 36/1 34
1272 ACSR 36/1 35
90,436,374 1,853,139,11 1,943,575,491 245,152 19,620,066 1,641,382 21,506,60(36
.,
FERC FORM NO.1 (ED. 12-87)Page 423.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
TRANSMISSION L1NESTATISTICS .
1. Report information concerning transmission lines, cost of Iin~s, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts.Do not report
. substation costs and expenses on this page. .
3. Report data by individual lines for all voltages ifso 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 type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a differenIIype of construction need ni;t be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost òfwhich is
reported for the line designated; conversely, shoW in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line .IIUN
(Indicate w~~'(
LENGJiH role wiles)Type of ~I)t e aSdo NumberNo.other than u dergroun lines Of60 cvcle 3 phase)Supporting report circuit miles)
From Operating un ~l!1Cture unf;:1lu~h~res CircuitsToDesignedStructureof.Lln~o Al'ot erDes1l;a ed Line(a)(b)(c)(d)(e)(g)(h)
1 DAVE JOHNSTON, WY WYODAK,WY 230.0(230.00 Wood-H 69.00 1
2 MONUMENT, WY SHUTE CREEK, WY 230.0(230.00 Wood.H 13.00 1
3 FIREHOLE, WY MONUMENT, WY 230.0(230.00 Wood-H 50.00 1
4 ROCK SPRINGS, WY FLAMING GORGE, UT 230.0(230.00 Wood-H 55.00 1
5 YELLOWTAIL, MT GOOSE CREEK, WY .230.0(230.00 Wood-H 59.00 1
6 NAUGHTON, WY MONUMENT, WY 230.0(230.00 Wood.H 30.00 1
7 ROCK SPRINGS, WY MONUMENT, WY 230.0(230.00 Wood-H 41.00 1
8 RIVERTON, WY ROCK SPRINGS, WY 230.0(230.00 Wood-H 119.00 1
9 RIVERTON, WY THERMOPOLIS, WY 230.01 230.00 Wood-H 51.00 1
10 THERMOPOLIS, WY YELLOWTAIL, MT 230.01 230.00 Wood-H 176.00 1
11 CHAPPEL CREEK, WY CRAVEN CREEK, WY 230.01 230.00 Wood-H 30.00 1
12 CRAVEN CREEK, WY NAUGHTON, WY 230.01 230.00 Wood-H 16.00 1
13 CHAPPEL CREEK, WY JONAH GAS, WY 230.01 230.00 Wood-H 32.00 1
14 CHAPPEL CREEK, WY CHIMNEY BUTTE, WY 230.0 230.00 Wood-H 14.00 6.00 1
15 MINERS,WY FOOTE CREEK, WY 230.0 230.00 Wood-H 39.00 1
16 POINT OF ROCKS, WY ROCK SPRINGS, WY 230.0 230.00 Wood-H 27.00 1
17 MONUMENT, WY CRAVEN CREEK, WY 230.01 230.00 Wood- H 20.00 1
18 YAMSAY, OR KLAMATH FALLS, OR 230.01 230.00 Wood. H 63.00 1
19 KLAMATH FALLS, OR MALIN, OR 230.0 230.00 Wood- H 35.00 1
20 LONE PINE, OR KLAMATH FALLS, OR 230.0 230.00 Wood-H 76.00 1
21 LONE PINE, OR MERIDIAN, OR 230.0 230.00 5.00 1
22 GRANTS PASS, OR DIXONVILLE LINE 72, OR 230.0 230.00 Wood-H 62.00 1
23 DIXONVILLE, OR RESTON BPA, OR 230.0 230.00 Wood-H 17.00 1
24 TAP TO HANNA, OR HANNA BPA, OR 230.0 230.00 Wood-H 9.00 1
25 DIXONVILLE 500, OR DIXONVILLE 230, OR 230.0 230.00 Wood-H 1.00 1
26 MERIDIAN, OR GRANTS PASS, OR 230.0 230.00 Wood-H 35.00 1
27 MERIDIAN, OR LONE PINE, OR 230.0 230.00 SteelSP 5.00 1
28 FAIRVIEW BPA, OR ISTHMUS, OR 230.0 230.00 Wood-H 12.00 1
29 TROUTDALE BPA, OR PGE GRESHAM, OR 230.0 230.00 Steel Tower 6.00 1
30 TROUTDALE BPA, OR LINNEMAN, OR 230.0 230.00 Steel Tower 6.00 1
31 SWIFT NO.1, WA SWIFT No.2, WA 230.0 230.00 Wood.H 2.00 1
32 SWIFT No.2, WA WOODLAND BPA SS, WA 230.0 230.00 Wood-H 23.00 1
33 FRY,OR BETHEL, OR 230.0 230.00 Wood-H 26.00 1
34 FRY,OR ALVEY, OR 230.0 230.00 Wood-H 45.00 1
35 ALVEY, OR DIXONVILLE, OR 230.0 230.00 Wood-H 59.00 1
36 TOTAL 15,802.00 648.00 240
FERC FORM NO. 1 (ED. 12-87)Page 422.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) . An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
TRANSMISSION 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 Iines. If tw or more transmission line structures support lines of the same voltage, report the
pole miles ofthe primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or porton thereof for which the respondent is not the sole owrier. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement expiaining 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
ofthe Line, and how the expenses borne by the respondent are acconted for, and accounts affected. Specify 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 lesse is an associated company.
10. Base the plant cost figures called for in columns 0) to (i) on the boo cost at end of year.
I.v~ i VI" LINE (inClUde in Column OJ Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses
(0)
Expenses No.(i)0)(k)(I)(m)(n)(p)
1272 ACSR 36/1 1
1272 ACSR 36/1 2
1272 ACSR 45/7 3
1272 ACSR 36/1 4
95 ACSR 2617 5
1272 ACSR 36/1 6
1272 ACSR 36/1 7
1272 ACSR 36/1 8
1272 ACSR 36/1 9
1272 ACSR 36/1 10
54 ACSR 54/7 11
54 ACSR5417 12
1272 ACSR 4517 13
1272 ACSR 36/1 14
1272 ACSR 36/1 15
1272 ACSR 36/1 16
1272 ACSR 45/7 17
95 ACSR 2617 18
1272 ACSR 36/1 19
95 ACSR 2617 20
1272 ACSR 36/1 21
1272 ACSR 361 22
95 ACSR 2617 23
95 ACSR 2617 24
1272 ACSR 36/1 25
1272 ACSR 36/1 26
1272 ACSR 54/19 27
1272 ACSR 36/1 28
54 ACSR 4517 29
00 ACSR 5417 ..30
54 ACSR 4517 31
54 ACSR 4517 32
1272 ACSR 36/1 .33
1272 ACSR 36/1 34
1272 ACSR 36/1 35
90,436,374 1,853,139,11 1,943,575,491 245,152 19,620,066 1,641,382 21,506,60C 36
FERC FORM NO.1 (ED. 12-87)Page 423.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original _(Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
TRANSMISSION LINE STATISTICS .
1. Report information concerning transmission lines, cost of Iin~s, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts.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 type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. . Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
repored for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line Ui:::lliNA IIUN
O~d1¿:i~~i\~~Type of LE~G;ir ~ole Wiles)Number~nt e seroNo.other than u dergroun lines Of60 cvcle, 30hase)Supporting report circuit miles)
un -=(riClure unrsr~lf~res CircuitsFromToOperatingDesignedStructureof Line ofAnot eroesilRatedLine
(a)(b)(c)(d)(e)(g)(h)
1 HURRICANE, OR WALLA WALLA, WA 230.0C 230.00 Wood-H 78.00 1
2 MCNARY BPA, WA WALLA WALLA, WA 230.0C 230.00 Wood-H 56.00 1
3 WALLA WALLA, WA AVISTA LEWISTON, WA 230.0C 230.00 Wood-H 45.00 1
4 WALLA WALLA, WA WANAPUM,WA 230.0C 230.00 Wood- H 33.00 1
5 TALBOT, WA MARENGO, WA 230.0C 230.00 Wood- H 8.00 1
6 UNION GAP, WA MIDWAY BPA, WA 230.0C 230.00 Wood-H 39.00 1
7 WANAPUM, WA POMONA, WA 230.0C 230.00 Wood-H 37.00 1
8 POMONA, WA UNION GAP, WA 230.0C 230.00 Wood-H 8.00 1
9 230 kV costs and expenses
10
11 Subtotal 230 kV 3,344.00 11.00 66
12
13 10 / MT BORDER, 10 GOSHEN,IO 161.0C 161.00 Wood- H 90.00 1
14 ANTELOPE, 10 GOSHEN,IO 161.0C 161.00 Wood-H 45.00 1
15 BONNEVILLE, 10 EAGLEROCK, 10 161.0C 161.00 WoodSP 9.00 1
16 EAGLEROCK, 10 SUGARMILL, ID 161.0(161.00 WoodSP 3.00 1
17 GOSHEN,IO GRACE,ID 161.0(161.00 Wood-H 57.00 1
18 GOSHEN, ID RIGBY, 10 161.0 161.00 Wood-H 31.00 1
19 GOSHEN, 10 SUGAR MILL, 10 161.0 161.00 Wood SP 17.00 1
20 SUGARMILL, 10 RIGBY, 10 161.0 161.00 WoodSP 17.00 1
21 EAGLEROCK, 10 GOSHEN,IO 161.0 161.00 Wood-H 12.00 1
22 YELLOWTAIL, MT RIMROCK, MT 161.0 161.00 Wood-H 46.00 1
23 RIGBY,m JEFFERSON, 10 161.0 161.00 WoodSP 18.00 1
24 161 kV costs and expenses
25 ..
26 Subtotal 161 kV 255.00 90.00 11
27
28 WHEELON,IO AMERICAN FALLS, ID 138.0C 138.00 Wood-H 86.00 1
29 OQUIRRH, UT TOOELE, UT 138.0C 138.00 Wood-SP 21.00 1
30 OQUIRRH, UT KCC BARNEY, UT 138.0C 138.00 Wood-H 5.00 1
31 ANSCHTZ CO-GEN, WY RAILROAD, WY 138.0C 138.00 Wood-H 25.00 1
32 ANTELOPE, 10 SCOVILLE #1 , 10 138.0C 138.00 Wood.H 1.00 1
33 ANTELOPE, ID SCOVILLE #2, 10 138.0C 138.00 Wood-H 1.00 1
34 ASHLEY, UT CARBON, UT 138.0C 138.00 Wood- H 92.00 1
35 ASHLEY, UT VERNAL, UT 138.0(138.00 Wood-H 12.0C 1
36 TOTAL 15,802.00 648.00 240
.
FERC FORM NO.1 (ED. 12-87)Page 422.3
Name of Respondent .This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line strcture twice. R~port Lower voltge Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of cowner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accunted for, and accunts affected. Specify 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. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (I) on the book cost at end of year.
..
l,U:: I ui- LINe (InCIUae in (,olumn OJ Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Constrction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Exenses (0)
Expenses No.(i)0)(k)(i)(m)(n)(p)
1272 ACSR 36/1 1
1272 ACSR 36/1 2
1272 ACSR 36/1 3
1272 ACSR 36/1 4
95 ACSR 2617 5
Ø54 ACSR 4517 6
1272 ACSR 36/1 7
1272 ACSR 36/1 8
10,541,77 315,613,966 326,155,738 136,44 3,558,410 399,311 4,094,165 9
10
10,541,77 315,613,966 326,155,738 136,44 3,558,410 399,311 4,094,165 11
12
D50HH CU 17 13
ß97.5 ACSR 2617 14
ß54 ACSR 4517 15
ß54 ACSR 45 16
250HH CU 17 17
ß97.5 ACSR 26/18
ß97.5 ACSR 2617 19
ß97.5 ACSR 2617 20
1272 ACSR 4517 21
~56.5 ACS 26/22
ß97.5 ACSR 26/23
623,49(15,133,015 15,756,505 330,601 9,563 340,16L 24
25
623,49(15,133,015 15,756,505 330,601 9,563 340,16 26
27
D50CUHD/12 28
95 ACSR 4517 29
95 ACSR 2617 30
95 ACSR 2617 31
ß97.5 ACSR 2617 32
ß97.5 ACSR 2617 33
$97.5 ACSR 2617 34
397.5 ACSR 2617 35
90,436,374 1,853,139,11 1,943,575,491 245,152 19,620,066 1,641,38,21,506,60C 36
FERC FORM NO.1 (ED. 12-87)Page 423.3
Name òf Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of Iin!'s, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts.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. Indicàte whether the type of supportng structure reported in column (e) is: (1) single pole wòod or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
.
Line IIUN YOL' rllr:i: (1(\/\LE~GJ,H ~ole Wiles)
Nò.
...(Indicate wliere Type of Iii t e sd 0 Number
other than u dergroun lines Of60 cvcle, 3 Dhase\Supporting report circuit miles)
From To un ::tructure vnfl~res CircuitsOperatingDesignedStructureof Lin~o L7~e er
(a)(b)(c)(d)(e)Desit;aed
(g)(h)
1 BEKER INDUST, ID THREEMILE KNOLL, 10 138.0(138.00 Wood.H 4.00 1
2 BEN LOMOND, UT BRIGHAM CITY, UT 138.0(138.00 Wood.H 14.00 1
3 BEN LOMOND, UT ELMONTE, UT 138.0(138.00 Wood. H 14.00 1
4 BEN LOMOND, UT EL MONTE, UT 138.0(138.00 Wood.H 13.00 1
5 BEN LOMOND, UT HONEYVILLE, UT 138.0(138.00 22.00 1
6 BEN LOMOND, UT CLINTON, UT 138.0(138.00 23.00 1
7 BEN LOMOND, UT ANGEL, UT 138.0(138.00 Wood.SP 28.00 1
8 BEN LOMOND, UT W ZIRCONIUM, UT 138.0(138.00 Wood.SP 14.00 1
9 BEN LOMOND, UT WHEELON, UT 138.0 138.00 Steel Tower 42.00 1
10 BRIGHAM CITY, UT WHEELON, UT 138.0(138.00 Wood. H 24.00 1
11 CAMERON, UT PAROWAN, UT 138.0 138.00 Wood.H 35.00 1
12 CAMERON, UT SIGURD, UT 138.0 138.00 Wood.H 64.00 1
13 CARBON, UT HELPER, UT 138.0 138.00 Wood.H 2.00 1
14 CARBON, UT HELPER, UT 138.0 138.00 Wood. H 2.00 1
15 CARBON, UT SPANISH FORK, UT 138.0C 138.00 Steel Tower 54.00 1
16 CARBON, UT SPANISH FORK, UT 138.0C 138.00 52.00 1
17 THREEMILE KNOLL, 10 GRACE #1, ID 138.0C 138.00 Wood.H 17.00 1
18 THREEMILEKNOLL,ID GRACE#2,ID 138.0C 138.00 Wood.H 17.00 1
19 THREEMILE KNOLL, ID MONSANTO 1, ID 138.0(138.00 Wood.H 2.00 1
20 THREEMILE KNOLL, ID MONSANTO 2, ID 138.0(138.00 Wood.SP 2.00 1
21 PAINTER, WY CLEAR CREEK, WY 138.0(138.00 Wood.SP 5.00 1
22 COLUMBIA, WY MOUNDS SWRK, UT 138.0(138.00 Wood.H . 9.00 1
23 COTTONWOOD, UT MCCLELLAND, UT 138.01 138.00 Wood.SP 6.00 1
24 COTTONWOOD, UT HAMMER, UT 138.01 138.00 Wood.SP 5.00 1
25 COTTONWOOD, UT SILVER CREEK, UT 138.01 138.00 Wood.SP 29.00 1
26 CUTLER, UT WHEELON, UT 138.01 138.00 Wood.SP 1.00 1
27 ENTERPRISE, UT MIDDLETON, UT 138.01 138.00 Wood.H 17.00 1
28 WEST CEDAR, UT ENTERPRISE VALLEY, UT 138.01 138.00 Wood.H 33.00 1
29 FRANKLIN, UT SMITHFIELD, UT 138.01 138.00 Wood.SP 25.00 1
30 FRANKLIN, ID TREASURETON, 10 138.l 138.00 Wood.SP 10.00 1
31 JORDAN, UT MCCLELLAND, UT 138.0l 138.00 Wood.SP 5.00 1
32 GADSBY, UT TERMINAL, UT 138.01 138.00 Wood-SP 6.00 1
33 JORDAN, UT TERMINAL, UT 138.0 138.00 Wood.SP 6.00 1
34 TlMP, UT HALE, UT 138.0 138.00 Steel- SP 4.00 1
35 TRI-CITY, UT AMERICAN FORK, UT 138.0 138.00 Steel.SP 10.00 1
36 TOTAL 15,802.00 648.00 240
FERC FORM NO.1 (ED. 12-87)Page 422.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
TRANSMISSION 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 transmiion 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 respondent operates or shres in th operation of, fumish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percnt ownershi by respodet in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accunted for, and accunts affected. Specify 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. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (i) on the boo cost at end of year.
\,u~ i ul" LINE (Include in \,oiumn OJ Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses
(0)Expenses No.(i)0)(k)(I)(m)(n)(p)
95 ACSR 26/7 1
97.5 ACSR 26/7 2
95 ACSR 45/7 3
95ACSR451 4
50CUHD /12 5
95 ACSR45/7 6
95 ACSR45/7 7
95AAC/37 8
50CUHD/12 9
95 ACSR 26/7 10
97.5 ACSR 26/7 11
97.5 ACSR 26/7 12
~54 ACSR 54/7 13
1556.5 ACSR 26/7 14
14/0 COMP 15
1795 ACSR 26/7 16
1'50 CUHD /12 17
1272 ACSR 45/7 18
1272 ACSR 45/7 19
1272 ACSR 451 20
95 ACSR 26/7 21
~66.8 ACSR 26/7 22
95 AAC 137 23
95AAC/37 24
ß97;5 ACSR 26/7 25
ß97.5 ACSR 26/7 26
1272 ACSR 45/7 27
ß97.5 ACSR 26/7 28
ß97.5 ACSR 26/7 29
95 ACSR 45/7 30
95AAC/37 31
1272 ACSR 45/7 32
1272 AAC 161 33
34
1272 ACSR 451 35
.90,436,374 1,853,139,117 1,94,575,491 245,152 19,620,06 1,641,382 21,506,60(36
FERC FORM NO.1 (ED. 12-87)Page 423.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DAResubmission 04/14/2010
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of Iin~s, and expenses for year.. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts.Do not report
substation costs and expenses on this page.
3. Repor 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, Nonutilit Propert.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole woo or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the us of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column(f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line (Indicate wtiere Type of LENGJiH ~oie Wiles)Number~Ilt e seroNo.other than u dergroun Iines
-60 cvcle, 3 phase)Supporting report circuit miles)Of
From To Operating Designed un ~trl,eture I ur.V::tr.u~fi~res CircuitsStructureofLln~o ~o er
Desil;a ed ine(a)(b)(c)(d)(e)(g)(h)
1 ABAJO, UT PINTO, UT 138.0C 138.00 Wood-SP 44.00 1
2 ONEIDA, ID GRACE,ID 138.0C 138.00 Wood-H 19.00 1
3 TREASURETON, ID GRACE 103, ID 138.0C 138.00 Steel Tower 25.00 1
4 TREASURETON,ID GRACE 104, ID 138.0C 138.00 25.00 1
5 NEBO, UT DRY CREEK, UT 138.0C 138.00 Wood-H 37.00 1
6 NINETY SOUTH, UT HALE, UT 138.0C 138.00 Wood- H 42.00 1
7 TIMP, UT SPANISH FORK, UT 138.0C 138.00 Wood-SP 23.00 1
8 HALE, UT TANNER, UT 138.0C 138.00 Wood-H 7.00 1
9 MOUNDS SWRK, UT HELPER, UT 138.0C 138.00 Wood-H 29.00 1
10 HONEYVILLE, UT WHEELON, UT 138.0C 138.00 14.00 1
11 HUNTINGTON, UT MCFADDEN, UT 138.0C 138.00 Wood-H 7.00 1
12 TERMINAL, UT KENNECOTT, UT 138.0C 138.00 9.00 1
... 13 KILN, UT NEBO, UT 138.0C 138.00 Wood-H 30.00 1
14 MCCLELLAND, UT MIDVALLEY, UT 138.0C 138.00 Wood-SP 6.00 1
15 MOUNDS SWRK, UT MOAB, UT 138.0C 138.00 Wood-H 80.00 1
16 MOAB, UT PINTO, UT 138.0C 138.00 Wood-H 68.00 1
17 NAUGHTON, WY NGPL, WY 138.0C 138.00 Wood-H 35.00 1
18 NAUGHTON, WY PAINTER, WY 138.0C 138.00 Wood-H 46.00 1
19 NGPL, WY TAP TO STR 204, WY 138.0C 138.00 Wood- H 12.00 1
20 NINETY SOUTH, UT OQUIRRH, UT 138.0C 138.00 Wood-SP 10.00 1
21 TAYLORSVILLE, UT NINETY SOUTH, UT 138.0(138.00 Wood-SP 7.00 1
22 MID VALLEY, UT NINETY SOUTH, UT 138.0C 138.00 Wood-H 9.00 1
23 NUCOR STEEL, UT WHEELON, UT 138.0C 138.00 Wood-H 10.00 1
24 ONEIDA,ID OVID,ID 138.0C 138.00 Wood-H 23.00 1
25 TREASURETON, ID ONEIDA,ID 138.0C 138.00 Wood-H 6.00 1
26 PAINTER, WY RAILROAD, WY 138.0(138.00 Wood-H 7.00 1
27 PAROWAN, UT WEST CEDAR, UT 138.0C 138.00 Wood-H 21.00 1
28 TAP TO ANGEL SOUTH, UT TAP TO PARRISH, UT 138.0C 138.00 13.00 1
29 PARRISH, UT TERMINAL, UT 138.0(138.00 SteelSP 16.00 1
30 PARRISH, UT TERMINAL, UT 138.0(138.00 14.00 1
31 RAILROAD, WY WHITNEY, WY 138.0C 138.00 Wood- H 17.00 1
32 BEN LOMOND, UT SYRACUSE, UT 138.0(230.00 .25.00 1
33 TERMINAL, UT ROWLEY, UT 138.0(138.00 Wood-H 56.00 1
34 GREEN CANYON, UT WHEELON, UT 138.0(138.00 Wood-SP 19.00 1
35 SPANISH FORK, UT TANNER, UT 138.0(138.00 Wood-H 10.00 1
36 TOTAL 15,802.00 648.00 240
FERC FORM NO.1 (ED. 12-87)Page 422.5
Name of Respondent This im0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
TRANSMISSION 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 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 oter than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accunted for, and accunts affected. Specify whether lessor, co-owner, orother part is
an associated company.
9. Designate any transmission line leased to another company and give name of Lesee, date and terms of.lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns ü) to (I) on th bok cost at end of year.
COST OF LINE (Include in Column UJ Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses
(0)
Expenses No.(i)ü)(k)(i)(m)(n)(p)
397.5 ACSR 26/7 1
250 CUHD 112 2
?50CUHDI1 3
?50CUHD/12 4
1272 ACSR 45/7 5
1272 ACSR 45/7 6
1272 ACSR 45/7 7
1272 ACSR 45/7 .8
397.5 ACSR 26/9
?50CUHD/12 10
397.5 ACSR 26/7 11
95 ACSR 26/7 12
397.5 AC$R 26/7 13
95 ACSR 26/7 14
397.5 ACSR 26/7 15
397.5 ACSR 26/7 16
95 ACSR 26/7 17
1272 ACSR 45/18
95 ACSR 26/7 19
1020 ACCCrr 20
95AAC/37 21
1272 ACSR 45/22
95 ACSR 45/7 23
~36.4 ACSR 26/7 24
D50CUHD112 25
1272 ACSR 45/26
~97.5 ACSR 26/7 27
95AAC/37 28
95 ACSR45/7 29
95 ACSR 26/7 30
95 ACSR 26/7 31
95AAC/37 32
95AAC/37 33
~36.4 ACSR 26/7 34
1272 ACSR 45/35...
.
90,436,374 1,853,139,117 1,943,575,491 245,152 19,620,066 1,641,382 21,506,60C 36
FERC FORM NO.1 (ED. 12-87)Page 423.5
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of Iin~s, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts.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 type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H~frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
. the use of brackets and exta lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on ¡eased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line \/ni Type of LE~~Ji~ ~gie ólileS)
(Indicate wliere NumberNo.other than u dergrounirllnes Of.60 cvcle, 3 ohase)Supportng report circuit miles)
I un ~irl;ciure I unf~ir't1l~res CircuitsFromToOperatingDesignedStructureof Line o MO erDesilnatedLine
(a)(b)(c)(d)(e)(g)(h)
1 TAP TO ANGEL NORTH, UT TAP TO PARRISH, UT 138.0 138.00 13.00 1
2 TERMINAL, UT MIDVALLEY, UT 138.0 138.00 Wood.H 7.00 1
3 TERMINAL, UT CENT / MIDVALLEY, UT 138.0 138.00 Steel.SP 7.00 1
4 TERMINAL, UT TOOELE, UT 138.0 138.00 Wood. H 35.00 1
5 WHEELON #103, UT TREASURETON, ID 138.0C 138.00 Steel Tower 29.00 1
6 WHEELON #104, UT TREASURETON, ID 138.0C 138.00 29.00 1
7 WHEELON #105, UT TREASURETON, ID 138.0C 138.00 Wood-H 29.00 1
8 KCC BARNEY, UT KCCGRIND, UT 138.0C 138.00 Wood-H 1.00 1
9 TERMINAL, UT LAKE PARK, UT 138.0C 138.00 Wood-H 14.00 1
10 OQUIRRH, UT KCC BINGHAM, UT 138.0C 138.00 Wood.H 8.00 1
11 WEST CEDAR, UT COMMERCE, UT 138.0C 138.00 Wood-SP 13.00 1
12 HALE, UT SPANISH FORK, UT 138.0C 138.00 Wood- H 18.00 1
13 MID VALLEY, UT TAYLORSVILLE, UT 138.0C 138.00 Wood-SP 5.00 1
14 PARRISH, UT TERMINAL, UT 138.0C 138.00 Steel-SP 14.00 1
15 JERUSALM, LIT NEBO, UT 138.0C 138.00 Wood.H 26.00 1
16 HALE, UT MIDWAY, UT 138.0C 138.00 Wood-H 19.00 1
17 DIMPLE DELL, UT DUMAS, UT 138.0C 138.00 UlG 4.00 1
18 HONEYVILLE, UT LAMPO, UT 138.0C 138.00 Wood- H 25.00 1
19 GADSBY, UT JORDAN, UT 138.0C 138.00 Wood.SP 1.00 1
20 MID VALLEY, UT COTTONWOOD, UT 138.0C 138.00 Wood-SP 5.00 1
21 NINETY SOUTH, UT SANDY, UT 138.0C 138.00 Steel-SP 1.00 1
22 MICRON, UT CAMP WILLIAMS, UT 138.0C 138.00 9.00 1
23 MCFADDEN, UT BLACKHAWK, UT 138.0C 138.00 Wood-H 11.00 1
24 NINETY SOUTH, UT QUARRY SUBSTATION, UT 138.0C 138.00 Wood-SP 8.00 1
25 90th S. QUARRY TAP, UT DIMPLE DELL SUB, UT 138.0(138.00 U/G 2.00 1
26 ELMONTE, UT STR30B, UT 138.0(138.00 Steel.SP 4.00 1
27 ELMONTE, UT PIONEER, UT 138.0(138.00 Steel-SP 1.00 1
28 SYRACUSE, UT CLEARFIELD SOUTH, UT 138.0 138.00 Steel- SP 1.00 1
.'. ..29 MID VALLEY, UT COTTONWOOD, UT 138.0(138.00 Steel- SP 5.00 1
30 HAMMER, UT BUTLERVILLE, UT 138.0 138.00 2.00i 1
31 BUTLERVILLE, UT NINETY SOUTH, UT 138.0 138.00 Steel-SP 9.00 1
32 KEARNS, UT TAYLORSVILLE, UT 138.0 138.00 Wood-SP 2.00 1
33 SILVER CREEK SUB, UT JORDANELLE SUB, UT 138.0 138.00 Steel.SP 10.00 1
34 KEARNS, UT WEST VALLEY, UT 138.0 138.00 Wood-SP 2.00 1
35 RIVERDALE, UT 105 TAP, UT 138.0C 138.00 Steel-SP 21.00 1
36 TOTAL 15,802.00 648.00 240
.
FERC FORM NO.1 (ED. 12-87)Page 422.6
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/14/2010
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltge Lines and higher voltage lines as one line. Designate in a fotnote if
you do not include Lower voltage lines with higher voltage Iines. If two or more transmission line structures support lines of the same volte, report the
pole miles of the primary$tcture in column (f) and the pole miles of the other line(s)in column (g)
8. Designate any transmission line or porton thereof for which the respondent is notthe 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 thana leased line, or portion thereof, for which
the respondent is not the sole òwner but which the respondent operates or shares in the operation of, fumish a succinct statement explaining the
arr¡:ngement and givirig particulars (details) of such matters as percnt owrship 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 accunte for, and accounts affected. Specify whethr 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. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (i) on the book cost at end of year.
COST OF LINt: iinciuae in (,oiumn U) Lami,EXPENSES, EXCEPT DEPRECIATION AND TAxES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses
(0)
Expenses No.(i)(j)(k)(i)(m)(n)(p)
95AAC/37 1
~272 ACSR 4517 2
1272AAC/61 3
~/OACSR6/1 .4
b50 CUHD /12 5
~50 CUHD /12 6
I?50CUHD/12 7
95 ACSR 2617 8
1557.4 ACSRI 9
1397.5 ACSR 2617 10
95 ACSR 2617 .11
1272 ACSR 45/12
1272AAC/61 13
95 ACSR 4517 14
1397.5 ACSR 2617 15
1397.5 ACSR 26/16
1750 KCMIL 17
1397.5 ACSR 2617 18
1272AAC/61 19
1557.4 ACSRf 20
95AAC/37 21
95 ACSR 2617 22
95 ACSR 2617 23
95AAC/37 24
1750 KCMIL 25
1272 ACSR 45/7 26
272 ACSR 45/27
1272 ACSR 4517 28
1557.4ACSRf .29
95 ACSR 2617 30
95AAC/37 31
95 ACSR 2617 32
95 ACSR 2617 33
1557.4 ACSRf 34
95 ACSR 2617 35
90,436,374 1,853,139,11 1,94,575,491 245,15.19,620,066 1,641,382 21,506,601 36
FERC FORM NO.1 (ED. 12-87)Page 423.6
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010 .
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of Iin~s, and expenses for year. List each trahsmission line having nominal voltag 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
substatiön costs and expenses on this page.
3. Report data by individual lines for all völtages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Accunt 121, Nonutilty Propert.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supportng structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. . Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in cölumns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are inCluded in the expenses reported for the line designated.-
Line (Indicate w~~i'Type of LENG;rH ~ole Wiles)Number~nt e sdONo.other than u dergroun hnes
60 cvcle. 30hase)Supporting report circuit miles)Of..Un ~tructure unf~ru1h~res CircuitsFromToOperatingDesignedStructureof Line o Lnot erDesirRatedine
(a)(b)(c)(d)(e)(g)(h)
1 OQUIRRH, UT SUNRISE / TRI-CITY, UT 138.0(138.00 Steel.SP 25.00 1
2 OQUIRRH, UT BANGERTER / TRI-CITY, UT 138.0(138.00 21.00 1
3 DYNAMO, UT TRI-CITY #2, UT 138.0(138.00 2.00 1
4 TIMP#2, UT DYNAMO, UT 138.(138.00 2.00 1
.5 DYNAMO, UT TRI-CITY #1, UT 138.0(138.00 Steel- SP 2.00 1
6 TIMP#1, UT DYNAMO, UT 138.0 138.00 Steel-SP 2.00 1
7 MIDDLETON, UT ST. GEORGE, UT 138.0 138.00 Wood-H 1.00 1
8 BRIDGERLAND, UT GREEN CANYON, UT 138.0C 138.00 Steel-SP 16.00 1
9 SYRACUSE, UT TERMINAL, UT 138.0C 230.00 29.00 1
10 BONANZA, UT CHAPITA, UT 138.0C 138.00 Wood-H 8.00 1
11 138 kV costs and expenses
12
13 Subtotal 138 kV 1,874.00 304.00 123
14
15
16 All 115 kV Lines 115.0C 115.00 Wood & Steel 1,575.00
17 All 69 kV Lines 69.0C 59.00 Wood & Steel 3,000.00
18 All 57 kV Lines 57.0C 57.00 Wood&Stèel 113.00
19 All 46 kV Lines 46.0(46.00 Wood & Steel 2,592.00
20 .
21
22
23
24 .
25
26
27
28 1
29
30
31
32
33
34
35
36 TOTAL 15,802.00 648.00 240
FERCFORM NO.1 (ED. 12-87)Page 422.7
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. R~port 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 porton thereof for which the respndent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amøunt of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accunted for, and accunts affected. Specify 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 book cost at end of year.
(,U::T UF LINt: (InCIUae in (,olumn U) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Exnses Expenses Expenses
(i)0)(k)(I)(m)(n)(0)(p)No.
1557.4 ACSRI 1
1557.4 ACSRI 2
1?-795 ACSR 26/7 3
1557.4 ACSRI 4
b-795 ACSR 26/7 5
1557.4 ACSRI 6
~97.5 ACSR 26/7 7
1272 ACSR 45/7 8
1272 ACSR 45/7 9
95 ACSR 26/7 10
13,651,51 303,43,022 317,094,536 3,221 2,642,906 86,609 2,732,731 11
.12
13,651,51 303,443,022 317,094,53€3,221 2,642,906 86,609 2,732,731 13
14
15
3,791,22 143,054,067 146,84,289 12,181 4,437,152 247,707 4,697,04(16
4,635,86 222,568,540 227,204,407 6,620 3,141,461 146,112 3,294,19!17
44,011 9,745,287 9,789,297 48,602 1,865 50,46 18
6,323,36 197,849,776 204,17,139 6,223 2,960,825 43,888 3,010,93 19
20
21
22
23
24
25
26
27
.28
29
30
31
.32
33
34
35
90,436,374 1,853,139,11 1,94,575,491 245,15.19,620,06E 1,641,382 21,506,60(36
FERC FORM NO.1 (ED. 12-87)Page 423.7
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2).. A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
¡Schedule Page: 422 Line No.: 4 Column: a
The Alvey - Dixonvile 500kV line is jointly owned by the respondent and the Boiineville Power Admnistrtion (ntheBPAn).
Ownership of the line is as follows: PacifiCorp 50.0%, the BPA 50.0%. Cost reported for this line reflects the respondent's 50.0%
share. Operation and maintenance costs are shared between the two paries and responsibility is as follows: PacifiCorp 58.0% and the
BPA42.0%.
!Schedule Page: 422 Line No.: 5 Column: a
The Dixonvile - Mendian 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 this line reflects the respondent's 50.0%
share. Operation and maiiltenance costs are shared between the two partes and responsibility is as follows: PacifiCorp 58.0% and the
BPA42.0%.
ISchedule Page: 422 Line No.: 8 Column: a I
the Colstrp 4 - Switchyard 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 operation and maintenance costs reported for this line reflects the respondent's share.
!Schedule Page: 422 Line No.: 9 Column: a I
The Colstrp - Broadview A 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 operation and maintenance costs reported for this line reflects the respondent's share.
!Schedule Page: 422 Line No.: 10 Column: a I
The Colstrp ~ Broadview B 500kV line is jointly owned by the respondent, NorthWestern 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 operation and maintenance costs reported for this line reflects the respondent's share.
!Schedule Page: 422 Line No.: 11 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 Portland General Electrc. Ownership of the line is as follows: PacifiCorp 8.1%, all
others 91.9%. Plant cost and operation and maintenance costs reported for this line reflects the respondent's share.
!Schedule Page: 422 Line No.: 12 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 Electrc. Ownership of the line is as follows: PacifiCorp 8.1 %, all
others 91.9%. Plant cost and operation and maintenance costs reported for this line reflects the respondent's share.
!Schedule Page: 422.4 Line No.: 34 Column: i
1557.4 ACSRlTW 36/7
IFERC FORM NO.1 (ED. 12-S7) Page 450.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) . An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
TRANSMISSION LINES ADDED DURI GYEAR
1. Report below the information called for concerning Transmission lines added or altered during the year.It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (i) to (0), it is permissible to report in these columns the
Line LINE 'IUN L~r;h IINI. :: I KUl, lUKe l,
Kl,U I I:: 1-1:
No.From To in Type Numbèrper Present UltimateMilesMiles
(a)(b)(c)(d)(e)(f)(g)
1 HERRIMAN TAP, UT HERRIMAN SUB., UT 4.00 Steel- SP 21.0e 1 1
2 CHAPPEL CREEK, WY CHIMNEY BUTE, WY 20.00 Wood - H B.Oe 1 1
3 FOOTE CREEK, WY HIGH PLAINS WIND, WY 10.00 Woo-H B.OO 1 1
4 WINDSTAR, WY GLENROCK WIND, WY 13.00 Wood-H B.OO 1 1
5 HONEYVILLE, UT LAMPO, UT 3.00 Steel- SP 17.00 1 2
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 50.00 62.00 5 €
FERC FORM NO.1 (REV. 12-63)Page 424
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) . An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/14/2010
TRAN MISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (i) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate
such other characteristic.
Voltage LINe (.U::I Line
Size .Specification Conf~uration KV Land and Poles, Towers Conductors Asset Total No.
and pacing (Operating)Land ~i9hts and Fixtures and D~tiCes Retire. Costs
(h)(i)m (k)(I (m)(n (0)(p)
1557 ACSR Verlcal10'138 4,301,444 2,967,68 634,311 7,903,439 1
1272 ACSR Horiz 19'-6"230 87,807 3,448,33 2,063,707 5,599,844 2
1272 ACSR Horiz 19'-6"230 262,400 4,144,88 1,036,221 5,443,503 3
1272 ACSR Horiz 19'-6"230 6,244,714 3,254,395 9,499,109 4
1272 ACSR Verlcal10'138 163,187 650,529 544,638 1,358,354 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
4,814,838 17,456,139 7,533,272 29,804,249 44
FERC FORM NO.1 (REV. 12-03)Page 425
Name of Respondent This (80rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 04/14/2010
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 (t).
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary .Secondary Tertiary
(a)(b)(c)(d)(e)
1 California
2 BELMONT SUB DISTRIBUTION-UNA TTEN 69.00 12.47
3 BIG SPRINGS SUB DISTRIBUTION-UNATTEN 69.00 12.47
4 CANBY#2 DISTRIBUTION-UNA TTEN 69.00 2.40
5 CASTELLA SUB DISTRIBUTION-UNA TTEN 69.00 2.40
6 CLEAR LAKE SUB DISTRIBUTION-UNATTEN 69.00 12.47
7 DOG CREEK SUB DISTRIBUTION-UNA TTEN 69.00 2.40
8 DORRIS SUB DISTRIBUTION-UNA TTEN 69.00 12.47
9 FORT JONES SUB DISTRIBUTION-UNA TTEN 69.00 12.47
10 GASOUETSUB DISTRIBUTION-UNATTEN 115.00 12.47
11 GREENHORN SUB DISTRIBUTION-UNATTEN 69.0C 12.47
12 HAMBURG SUB DISTRIBUTION-UNATTEN 69.00 2.40
13 HAPPY CAMP SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 HORNBROOK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
15 INTERNATIONAL PAPER SUB DISTRIBUTION-UNATTEN 69.00 2.40
16 LAKE EARL SUB DISTRIBUTION-UNATTEN 69.00 12.47
17 LITTLE SHASTA SUB DISTRIBUTION-UNATTEN 69.00 7.20
18 LUCERNE SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 MACDOEL SUB DISTRIBUTION-UNA TTEN 69.00 20.80
20 MCCLOUD SUB DISTRIBUTION-UNATTEN 69.00 12.47
21 MILLER REDWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
22 MONTAGUE SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 MORRISON CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.50
24 MOUNT SHASTA SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 NEWELL SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 NORTH DUNSMUIR SUB DISTRIBUTION-UNATTEN 69.00 12.47
27 NORTHCREST SUB DISTRIBUTION-UNATTEN 69.00 12.47
28 NUTGLADE SUB DISTRIBUTION-UNATTEN 69.00 2.40
29 PATRICKS CREEK SUB DISTRIBUTION-UNATTEN 115.00 7.20
30 PEREZ SUB DISTRIBUTION-UNATTEN 69.0C 12.47
31 REDWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 SCOTT BAR SUB DISTRIBUTION-NATTEN 69.00 12.47
33 SEIAD SUB DISTRIBUTION-UNATTEN 69.DC 12.47
34 SHASTINA SUB DISTRIBUTION-UNATTEN 69.00 20.80
35 SHOTGUN CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 SMITH RIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47
37 SNOW BRUSH SUB DISTRIBUTION-UNATTEN 69.00 7.20
38 SOUTH DUNSMUIR SUB DISTRIBUTION-UNATTEN 69.00 4.16
39 TULELAKE SUB DISTRIBUTION-UNATTEN 69.00 12.47
40 TUNNEL SUB DISTRIBUTION-UNATTEN 69.QO 12.47
FERC FORM NO.1 (ED. 12-96)~Page 426
Name of Respondent This lË0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
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 öf 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 Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
1
25 1 2
6 1 3
1 3 4
2 3 5
4 3 6.
1 7.
8 3 8
6 1 9
9 1 10
13 1 11
1 1 12
8 3 13
4 3 14
9 3 15
13 1 16
2 3 17
4 1 18
31 2 ~'19
6 1 20
4 3 21
6 .1 22
14 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
6 3 36.,
3 37
2 3 38.
20 1 39
6 6 40
FERC FORM NO.1 (ED. 12-96)Page 427
Name of Respondent This 180rt Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
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 transmÎssionor distribution and whether
attended or unattended. Afthe end of the page, summarize accrding to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary.
(a)(b)(c)(d)(e)
1 WALKER BRYAN SUB DISTRIBUTION-UNA TTEN 69.00 12.47
2 WEED SUB DISTRIBUTION-UNA TTEN 115.00 12.47
3 YUBA SUB DISTRIBUTION-UNATTEN 69.00 12.47
4 YUROKSUB DISTRIBUTION-UNATTEN 69.00 12.47
5 Total .3105.00 468.36
6 Number of Substations- 43 .
7
8 ALTURAS TID-UNATTENDED 115.00 12.47 69.00
9 FALL CREEK HYDRO/SUB TID-UNATTENDED 69.00 2.30
10 YREKA SUB TID-UNATTENDED 115.00 12.47 69.00
11 Total 299.00 27.24 138.00
12 Number of Substations- 3
13
14 AGERSUB TRANSMISSION-A TTENDE 115.00 69.00
15 COPCO #1 HYDRO PLANT TRANSMISSION-A TTENDE 69.00 2.30
16 COPCO #2 230 SUB TRANSMISSION-A TTENDE 230.00 115.00
17 COPCO #2 HYDRO PLANT TRANSMISSION-A TTENDE 69.00 6.60
18 COPCO#2SUB TRNSMISSION-ATTENDE 69.00 12.47
19 CRAG VIEW SUB TRANSMISSION-UNATTEN 115.00 69.00
20 DEL NORTE SUB TRANSMISSION-UNA TTEN 115.00 69.00
21 IRON GATE HYDRO PLANT TRANSMISSION-UNATTEN 69.00 6.60
22 WEED JUNCTION SUB TRANSMISSION-UNATTEN 115.00 69.00
23 Total .966.00 418.97
24 Number of Substations- 9
25
26 Idaho
27 ALEXNDER DISTRIBUTION-UNATTEN 46.00 12.47
28 AMMON DISTRIBUTION-UNATTEN 69.00 12.47
29 ANDERSON DISTRIBUTION-UNATTEN 69.00 12.47
30 ARCO DISTRIBUTION-UNATTEN 69.00 12.47
31 ARIMO DISTRIBUTION-UNATTEN 46.00 12.47
32 BANCROFT SUB DISTRIBUTION-UNATTEN 46.00 12.47
33 BELSON SUB DISTRIBUTION-UNA TTEN 69.00 12.47 ..
34 BERENICE SUB DISTRIBUTION-UNA TTEN 69.00 12.47
35 CAMAS SUB DISTRIBUTION-UNATTEN 69.00 .12.47
36 CANYON CREEK SUB DISTRIBUTION-UNATTEN 69.00 24.90
37 CHESTERFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 CINDER BUTTE SUB DISTRIBUTION-UNATTEN 161.00 12.47
39 CLEMENTS SUB DISTRIBUTION-UNATTEN 69.00 12.47
40 CLIFTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Oa, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
SUBSTATIONS (Continued)
5. Show in columns (I), ü),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 Total Capacity No.In Service Transformers Type of Equipment Number of Units
~(In MVa)
(f)(g)(h)(i)ü)(k)
7 1 1
25 1 2
4 3 3
4 3 4
337 102 5
6.
7
31 4 8
3 3 9
95 2 10
129 9 11
12
.13
5 3 14
28 6 2 15
375 2 16
60 3 1 17
2 3 18
19 3 19
150 2 20
19 1 21
38 3 .22
696 26 3 23
24
25
26
4 1 .27
14 1
.28
20 1 29
6 1 30
8 1 31
4 .1 32
13 1 ..33.
11 1 34
14 1 35
20 1 36
5 1 37
30 1 1 38
5 1 39
4 1 40
-
FERC FORM NO.1 (ED. 12-96)Page 427.1
Name of Respondent This ~rt Is: .Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) i"A Resubmission 04/14/2010
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Charaer of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 COVE SUB DISTRIBUTION-UNATTEN 46.00 6.60
2 DOWNEY SUB DISTRIBUTION-UNATTEN 46.00 12.47
3 DUBOIS SUB DISTRIBUTION-UNATTEN 69.00 12.47
4 EASTMONT SUB DISTRIBUTION-UNA TTEN 69.00 12.47
5 EGIN SUB DISTRIBUTION-UNA TTEN i 69.00 12.47
6 EIGHT MILE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
7 GEORGETOWN SUB DISTRIBUTION-UNA TTEN 69.00 12.47
8 GRACE CITY SUBSTATION DISTRIBUTION-UNA TTEN 46.00 12.47
9 HAMER SUB DISTRIBUTION-UNA TTEN 69.00 12.47
10 HAYES SUB DISTRIBUTION-UNA TTEN 69.00 12.47
11 HENRY SUB DISTRIBUTION-UNA TTEN 46.00 12.47
12 HOLBROOD SUB DISTRIBUTION-UNA TTEN 69.00 12.47
13 HOOPES SUB DISTRIBUTION-UNA TTEN 69.00 12.47
14 HORSLEY SUB DISTRIBUTION-UNA TTEN 46.00 12.47
15 IDAHO FALLS SUB DISTRIBUTION-UNA TTEN 46.00 12.47
16 INDIAN CREEK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
17 JEFFCO SUB DISTRIBUTION-UNA TTEN 69.00 24.90
18 KETTLE SUB DISTRIBUTION-UNA TTEN 69.00 24.90
19 LAVA SUB DISTRIBUTION-UNA TTEN 46.00 12.47
20 LUND SUB DISTRIBUTION-UNA TTEN 46.00 12.47
21 MCCAMMON SUB DISTRIBUTION-UNATTEN 46.00 12.47
22 MENAN SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 MERRILL SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 MILLER SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 MONTPELIER SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 MOODY SUB DISTRIBUTION-UNATTEN 69.00 24.90
27 NEWDALE SUB DISTRIBUTION-UNATTEN 69.00 12.47
28 OSGOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
29 PRESTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
30 RAYMOND SUB DISTRIBUTION-UNATTEN 69.00 12.47
31 RENO SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 REXBURG SUB DISTRIBUnON-UNATTEN 69.00 12.47 .
33 RIRIE SUB DISTRIBUTION-UNATTEN 69.00 12.47
34 ROBERTS SUB DISTRIBUTION-UNATTEN 69.00 12.47
35 RUDY SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 SAND CREEK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
37 SANDUNESUB DISTRIBUTION-UNA TTEN 69.00 24.90
38 SHELLEY SUB DISTRIBUTION-UNA TTEN 46.00 12.47 .
39 SMITH SUB DISTRIBUTION-UNATTEN 69.00 12.47
40 SODA SUB DISTRIBUTION-UNATTEN 138.00 7.20
FERC FORM NO.1 (ED. 12-96)Page 426.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent.For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Total Capacity No.In Servce Transformers Type of Equipment Number of Units
(f)(h)
(In MVa)
(g)(i)0)(k)
21 4 1
5 1 2
13 1 3
14 1 .4
14 1 .5
3 1 6
6 1 7
5 1 8
14 1 9
.9 1 10
3 1 11
6 1 12
9 1 13
4 1 14
20 1 15
3 1 16
22 1 17
14 1 18
3 1 19
5 1 20
3 1 21
11 1 22
20 1 23
5 1 24.
8 1 25
14 1 26
20 1 27
20 1 28
13 1 29
.2 1 30
20 1 31
33 2 32
9 1 33
8 1 34
7 1 35...
40 2 36
20 1 37
20 1 38
20 1 39
22 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.2
Name of Respondent This Report Is:Date of Report YearlPeriod of Report
PacifiCorp (1) !KAn Original (Mo, Da, Yr)End of 2009/Q4
....(2) nA Resubmission 04/14/2010
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
.--Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 SOUTH FORK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
2 SPUD SUB DISTRIBUTION-UNA TTEN 46.00 12.47
3 ST. CHARLES SUB DISTRIBUTION-UNA TTEN 69.00 12.47
4 SUGAR CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47
5 SUNNYDELL SUB DISTRIBUTION-UNATTEN 69.00 12.47
6 TANNER SUB DISTRIBUTION-UNA TTEN 46.00 12.47
7 TARGHEE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
8 THORNTON SUB DISTRIBUTION-UNA TTEN 69.00 12.47
9 UCON SUB DISTRIBUTION-UNA TTEN 69.00 12.47
10 WATKINS SUB DISTRIBUTION-UNATTEN 69.00 12.47
11 WEBSTER SUB DISTRIBUTION-UNATTEN 69.00 12.47
12 WESTON SUB DISTRIBUTION-UNA TTEN 46.00 12.47
13 WINDSPER SUB DISTRIBUTION-UNATTEN 69.00 24.90
14 Total 4301.00 898.93
15 Number of Substations- 67
16
17 MALAD SUB TID-UNATTENDED 138.00 46.00 12.47
18 MUD LAKE SUB TID-UNATTENDED 69.00 12.47
19 RIGBY SUB TID-UNATTENDED 161.00 12.47 69.00
20 SAINT ANTHONY SUB TID-UNATTENDED 69.0C 46.00 12.47
21 Total 437.00 116.94 93.94
22 Number of Substations- 4
23
24 GRACE HYDRO TRANSMISSION-A TTENDE 138.00 46.00 6.60
25 AMPS SUB TRASMISSION-UNATTEN .230.00 69.00
26 ANTELOPE SUB TRANSMISSION-UNATTEN 230.00 .161.00
27 ASHTON PLANT TRSMISSION-UNATTEN 46.00 2.40
28 BIG GRASSY SUB TRANSMISSION-UNATTEN 161.00 69.00
29 BONNEVILLE SUB TRASMISSION-UNATTEN 161.00 69.00
30 CONDASUB TRASMISSION-UNATTEN 138.00 46.00
31 FISH CREEK SUB TRANSMISSION-UNATTEN 161.00 46.00
32 FRANKLIN SUB TRANSMISSION-UNATTEN 138.00 46.00
33 GOSHEN SUB TRANSMISSION-UNATTEN 345.00 161.00 46.00
34 JEFFERSON SUB TRASMISSION-UNATTEN 161.00 69.00
35 LIFTON HYDRO TRANSMISSION-UNATTEN 69.00 2.30
36 ONEIDA SUB TRANSMISSION-UNATTEN 138.00 12.50
37 OVID SUB TRANSMISSION-UNATTEN 138.00 69.00
38 SCOVILLE SUB TRANSMISSION-UNATTEN 138.00 69.00 46.00
39 SUGARMILL SUB TRANSMISSION-UNATTEN 161.00 46.00 69.00
40 THREEMILE KNOLL SUB TRANSMISSION-UNATTEN 345.0C 138.00 46.00
--
FERC FORM NO.1 (ED. 12-96)Page 426.3
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifCorp (1 )(8An Original (Mo, Da, Yr)End of 2009/Q4
(2)ñA Resubmission 04/14/2010
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
affêcted in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(f)
(In MVa)
(g)(h)(i)(j)(k)
14 .
1 1
8 1 2.
5 1 3
13 1 4
13 1 5.
4 1 6
4 1 7
7 1 8
7 1 9
14 1 10
20 1 11
4 1 12
20 1
.13
799 72 1 14
15
16
71 4 1 17
14 1 18
189 4 19
40 2 20
314 11 1 21
22
23
115 4 24
75 2 1 25
250 1 26
25 3 27
67 1 28
67 1 29
67 1 30
25 3 31
75 1 32
763 8 1 33
233 3 34
6 2 35
40 2 36
30 1 37
76 2 ..,38
168 3 39
700 1 40
...
FERC FORM NO.1 (ED. 12-96)Page 427.3
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 TREASURETON SUB TRASMISSION-UNATTEN 230.00 138.00
2 Total 3128.00 1259.20 213.60
3 Number of Substations- 18
4
5 Oregon .
6 26TH STREET DISTRIBUTION-UNATTEN 20.80 4.16
7 35TH STREET DISTRIBUTION-UNA TTEN 20.80 2.40
8 AGNESS AVE DISTRIBUTION-UNA TTEN 115.00 12.47
9 ALDERWOOD DISTRIBUTION-UNATTEN 69.00 12.47
10 ARLINGTON DISTRIBUTION-UNA TTEN 69.00 12.47
11 ATHENA DISTRIBUTION-UNATTEN 69.00 12.47
12 BANDON TIE SUB DISTRIBUTION-UNATTEN 20.80 12.47
13 BEACON SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 BEALL LANE SUB DISTRIBUTION-UNATTEN 115.00 12.47
15 BEATT SUB DISTRIBUTION-UNA TTEN 69.00 12.47
16 BELKNAP DISTRIBUTION-UNA TTEN 69.00 12.47
17 BLALOCK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
18 BLOSS SUB DISTRIBUTION-UNA TTEN 115.00 12.47
19 BLYSUB DISTRIBUTION-UNA TTEN 69.00 12.47
20 BOISE CASCADE SUB DISTRIBUTION-UNA TTEN 69.00 11.00
21 BONANZA SUB DISTRIBUTION-UNA TTEN 69.00 12.47
22 BOND STREET SUB .DISTRIBUTION-UNATTEN 69.00 12.50
23 BROOKHURST SUB DISTRIBUTION-UNATTEN 115.00 12.47
24 BROWNSVILLE SUB DISTRIBUTION-UNATTEN 69.00 20.80
25 BRYANT SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 BUCHANAN SUB DISTRIBUTION-UNA TTEN 115.00 20.80
27 BUCKAROO SUB DISTRIBUTION-UNA TTEN 69.00 12.47
28 CAMPBELL SUB DISTRIBUTION-UNATTEN 115.00 12.47
29 CANNON BEACH SUB DISTRIBUTION-UNATTEN 115.00 12.47
30 CARNES SUB DISTRIBUTION-UNATTEN 69.00 12.47
31 CASEBEER SUB DISTRIBUTION-UNATTEN 69.0C 20.80
32 CAVEMAN SUB DISTRIBUTION-UNATTEN 115.0C 12.47
33 CHERRY LANE SUB DISTRIBUTION-UNATTEN 69.00 12.47
34 CHILOQUIN MARKET SUB DISTRIBUTION-UNATTEN 69.00 12.47
35 CHINA HAT SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 CIRCLE BLVD SUB DISTRIBUTION-UNA TTEN 115.00 20.80
37 CLEVELAND AVE SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 CLINE FALLS HYDRO DISTRIBUTION-UNATTEN 12.47 2.40
39 CLOAKESUB DISTRIBUTION-UNATTEN 69.00 20.80
40 COBURG SUB DISTRIBUTION-UNATTEN 69.00 20.80
FERC FORM NO.1 (ED. 12-96)Page 426.4
Name of Respondent This ii0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
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 accóunt. 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 Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
533 2 1
3315 41 .2 2
.3
4
..5
5 1 6
30 6 7
25 1 8
25 1 9
5 1 10
9 1 11
8 3 1 12
11 3 13
25 1 14
6 1 15
40 2 16
2 3 17
32 2 18
8 3 19
3 1 20
8 3 21
25 1 22
50 2 23
13 1 24
34 2 25
40 2 26
34 2 27
20 1 28
13 1 29
9 3 30
20 1 31
45 2 32
25 1 33.
5 3 34
25 1 35
80 2 36
45 2 37
1 3 .38
20 1 39
1 3 40
FERC FORM NO.1 (EO. 12-96)Page 427.4
Name of Respondent This (80rt Is:Date of Report Year/Period of Report
PaciCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
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, summarie accrding to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 COLISEUM SUB DISTRIBUTION-UNATTEN 20.80 4.16
2 COLUMBIA SUB DISTRIBUTION-UNA TTEN 115.00 12.47 57.00
3 COOS RIVER SUB DISTRIBUTION-UNATTEN 115.00 20.80
4 COQUILLE SUB DISTRIBUTION-UNATTEN 115.00 20.80
5 CREEK SUB DISTRIBUTION-UNA TTEN 69.00 34.50
6 CROOKED RIVER RANCH SUB DISTRIBUTION-UNATTEN 69.00 20.80
7 CROWFOOT SUB DISTRIBUTION-UNATTEN 115.00 12.47
8 CULLY SUB DISTRIBUTION-UNATTEN 115.00 12.47
9 CULVER SUB DISTRIBUTION-UNA TTEN 69.00 12.47
10 CUTLER CITY SUB DISTRIBUTION-UNA TTEN 20.80 4.16
11 DAIRY SUB DISTRIBUTION-UNA TTEN 69.00 12.47
12 DALLAS SUB DISTRIBUTION-UNA TTEN 115.0(20.80
13 DALREEDSUB DISTRIBUTION-UNA TTEN 230.00 34.50
14 DESCHUTES SUB DISTRIBUTION-UNA TTEN 69.00 12.47
15 DEVILS LAKE SUB DISTRIBUTION-UNATTEN 115.00 20.80
16 DIXON SUB DISTRIBUTION-UNATTEN 115.00 4.16
17 DODGE BRIDGE SUB DISTRIBUTION-UNATTEN 69.00 20.80
18 EAST VALLEY SUB DISTRIBUTION-UNATTEN 115.00 12.47
19 EMPIRE SUB DISTRIBUTION-UNATTEN 115.00 20.80
20 ENTERPRISE SUB DISTRIBUTION-UNATTEN 69.00 12.47
21 FERN HILL SUB DISTRIBUTION-UNA TTEN 115.00 12.47
22 FIELDER CREEK SUB DISTRIBUTION-UNA TTEN 115.00 20.80
23 FOOTHILLS SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 FRALEY SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 GARDEN VALLEY SUB DISTRIBUTION-UNATTEN 69.00 20.80
26 GAZLEYSUB DISTRIBUTION-UNATTEN 69.00 12.47
27 GLENDALE SUB DISTRIBUTION-UNATTEN 230.00 12.47
28 GLENEDEN SUB DISTRIBUTION-UNATTEN 20.80 4.16
29 GLIDE SUB DISTRIBUTION-UNATTEN 115.00 12.47
30 GOLD HILL SUB DISTRIBUTION-UNATTEN 69.00 12.47
31 GORDON HOLLOW SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 GOSHEN SUB DISTRIBUTION-UNATTEN 115.00 20.80
33 GRANT STREET SUB DISTRIBUTJON-UNATTEN 115.00 20.80
34 GRASS VALLEY SUB DISTRIBUTION-UNATTEN 20.80 4.16
35 GREEN SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 GRIFFIN CREEK SUB DISTRIBUTION-UNATTEN . 115.00 12.47
37 HAMAKER SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 HARRISBURG SUB DISTRIBUTION-UNA TTEN 69.00 20.80
39 HENLEY SUB DISTRIBUTION-UNATTEN 69.0C 12.47
40 HERMISTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
...
FERC FORM NO.1 (ED. 12-96)Page 426.5
Name of Respondent This ø0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4.
(2) FiA Resubmission 04/14/2010
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 aècount. 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 Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
9 2 -1
55 2 1 2
20 1 3
40 2 -4
5 1 5
25 2 6
20 1 7
25 1 8
13 1 9
2 3 10
25 1 11
50 2 12
75 3 13
13 1 14
50 2 15
7 1 16
13 1 17
45 2 18
20 1 19
19 2 20
13 1 21
25 1 22
21 4 23
5 3 24
20 1 25
8 3 26
25 2 27
5 1 28
13 1 29
11 3 30
6 1 31
20 1 32
45 2 33.
1 4 34
"i 25 1 35..
20 1 36
8 3 37
13 1 38
6 3 39
40 2 40
FERC FORMNO. 1 (ED. 12-96)Page 427.5
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
SUBSTATIONS
1. Report below the infonnation called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 HILLVIEW SUB DISTRIBUTION-UNA TIEN 115.00 20.80
2 HINKLE SUB DISTRIBUTION-UNA TIEN 69.00 12.47
3 HOLLADAY SUB DISTRIBUTION-UNA TIEN 115.00 12.47
4 HOLLYWOOD SUB DISTRIBUTION-UNA TIEN 115.00 12.47
5 HOOD RIVER SUB DISTRIBUTION-UNA TIEN 69.00 12.47
6 HORNET SUB DISTRIBUTION-UNA TIEN 69.00 12.47
7 HUNTERS CIRCLE TEMP SUB DISTRIBUTION-UNA TIEN 69.00 12.47
8 ILLAHEE FLATS SUB DISTRIBUTION-UNA TIEN 115.00 12.47
9 INDEPENDENCE SUB DISTRIBUTION-UNATIEN 69.00 20.80
10 JACKSONVILLE SUB DISTRIBUTION-UNA TIEN 115.00 12.47 69.00
11 JEFFERSON SUB DISTRIBUTION-UNA TIEN 69.00 20.80
12 JEROME PRAIRIE SUB DISTRIBUTION-UNA TIEN 115.00 12.47
13 JORDAN POINT SUB DISTRIBUTION-UNA TIEN 115.00 12.47
14 JOSEPH SUB DISTRIBUTION-UNA TIEN 20.80 12.47
15 JUNCTION CITY SUB DISTRIBUTION-UNA TIEN 69.00 20.80
16 KENWOOD SUB DISTRIBUTION-UNA TIEN 69.00 12.47
17 KILLINGWORTH SUB DISTRIBUTION-UNATIEN 69.00 12.47
18 KNAPPA SVENSEN SUB DISTRIBUTION-UNA TIEN 115.00 12.47
19 LAKEPORT SUB DISTRIBUTION-UNA TIEN 69.00 12.47
20 LAKEVIEW SUB DISTRIBUTION-UNATIEN 69.00 12.47
21 LANCASTER SUB DISTRIBUTION-UNATIEN 69.00 20.80
22 LEBANON SUB DISTRIBUTION-UNATIEN 115.00 20.80
23 LINCOLN SUB DISTRIBUTION-UNATIEN 115.00 12.47
24 LOCKHART SUB DISTRIBUTION-UNATIEN 115.00 20.80
25 LYONS SUB DISTRIBUTION-UNATIEN 69.00 20.80
26 MADRAS SUB DISTRIBUTION-UNATIEN 69.00 12.47
27 MALLORY SUB DISTRIBUTION-UNA TIEN 115.00 12.47
28 MARYS RIVER SUB DISTRIBUTION-UNA TIEN 115.00 20.80
29 MEDCOSUB DISTRIBUTION-UNA TIEN 115.00 12.47
30 MEDFORD DISTRIBUTION-UNATIEN 69.00 12.47
31 MERLIN SUB DISTRIBUTION-UNATIEN 115.00 12.47
32 MERRILL SUB DISTRIBUTION-UNATIEN 69.00 12.47
33 MINAMSUB DISTRIBUTION-UNATIEN 69.00 12.47 ...
34 MODOC SUB ..DISTRIBUTION-UNATIEN 69.00 12.47
35 MOROSUB DISTRIBUTION-UNATIEN 20.80 2.40
36 MURDER CREEK SUB DISTRIBUTION-UNA TIEN 115.00 20.80
37 MYRTLE CREEK SUB DISTRIBUTION-UNATIEN 69.00 12.47
38 MYRTLE POINT SUB DISTRIBUTION-UNA TIEN 115.00 20.80
39 NELSCOTISUB DISTRIBUTION-UNA TIEN 20.80 4.16
40 NEW O'BRIEN SUB DISTRIBUTION-UNATIEN 115.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.6
Name of Respondent This ~ort Is:Date of Report Year/Periodof Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/14/2010
SUBSTATIONS (Continued).
5. Show in columns (1),0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.-ål'd auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
45 2 1
20 1 2
75 3 3
50 2 4
40 2 5
20 1 6
13 1 7
2 1 8
20 1 9
75 2 10
13 1 11
20 1 12
20 1 13
6 1 1 14
25 2 15
3 3 16
40 2 17
6 1 18
50 2 19
9 3 20
13 3 21
40 2 22
105 3 23
40 2 ..24
9 1 .25
25 2 26
25 1 27
20 1 28
20 1 29
79 14 30
45 2 31
17 6 .32
.. 1 33
6 ..3 34
2 3 35
100 4 36
14 1 37
9 1 38
4 1 39
9 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.6
Name of Respondent This 180rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
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 (t).
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Pnmary Secondary Tertiary
(a)(b)(c)(d)(e)
1 OAK KNOLL SUB DISTRIBUTION-UNA TTEN 115.0C 12.47
2 OAKLAND SUB DISTRIBUTION-UNATTEN 115.00 12.47
3 OREMETSUB DISTRIBUTION.UNATTEN 115.0C 12.47
4 OVERPASS SUB DISTRIBUTION-UNATTEN 69.00 12.47
5 PALLETTE SUB DISTRIBUTION-UNATTEN 69.00 20.80
6 PARK STREET SUB DISTRIBUTION-UNA TTEN 115.00 12.47
7 PARKROSE SUB DISTRIBUTION-UNATTEN 57.00 12.47
8 PENDLETON SUB DISTRIBUTION-UNATTEN 69.00 12.47
9 PILOT ROCK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
10 POWELL BUTTE SUB DISTRIBUTION-UNA TTEN 115.00 12.47
11 PRINEVILLE SUB DISTRIBUTION-UNA TTEN 115.00 12.47
12 PROVOLTSUB DISTRIBUTION-UNA TTEN 69.00 12.47
13 QUEEN AVE SUB DISTRIBUTION-UNATTEN 69.00 20.80
14 RED BLANKET SUB DISTRIBUTION-UNATTEN 69.00 4.16
15 REDMOND SUB DISTRIBUTION-UNATTEN 115.00 12.47
16 RICH MANUFACTURING SUB DISTRIBUTION-UNATTEN 57.00 12.47
17 RIDDLE SUB DISTRIBUTION-UNATTEN 69.00 12.47
18 RIDDLE VENEER SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 ROGUE RIVER SUB DISTRIBUTION-UNA TTEN 69.00 12.47
20 ROSEBURG SUB DISTRIBUTION-UNA TTEN 115.00 20.80
21 ROSS AVE SUB DISTRIBUTION-UNA TTEN 69.00 12.47 .
22 ROXYANNSUB DISTRIBUTION-UNA TTEN 115.00 12.50
23 RUCH SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 RUNNING Y SUB DISTRIBUTION-UNATTEN 69.00 20.80
25 RUSSELLVILLE SUB DISTRIBUTION-UNATTEN 115.00 12.47
26 SAGE ROAD SUB DISTRIBUTION-UNATTEN 115.00 12.47
27 SCENIC SUB DISTRIBUTION-UNATTEN 115.00 12.47 69.00
28 SCIOSUB DISTRIBUTION-UNATTEN 69.00 12.47
29 SEASIDE SUB DISTRIBUTION-UNATTEN 115.00 12.47
30 SELMA SUB DISTRIBUTION-UNATTEN 115.00 12.47
31 SHASTA WAY SUB DISTRIBUTION-UNATTEN 12.47 4.16
32 SHEVLIN PARK DISTRIBUTION-UNATTEN 69.00 12.50
33 SIMTAG BOOSTER PUMP DISTRIBUTION-UNATTEN 34.5C 4.16
34 SOUTH DUNES SUB DISTRIBUTION-UNATTEN 115.00 12.47
35 SOUTHGATE SUB DISTRIBUTION-UNATTEN 69.00 20.80
36 SPRAGUE RIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47
37 STATE STREET SUB DISTRIBUTION-UNATTEN 115.00 20.80
38 STAYTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
39 STEAMBOAT SUB DISTRIBUTION-UNA TTEN 115.00 7.20 ....
40 STEVENS ROAD SUB DISTRIBUTION-UNATTEN 115.00 20.80
FERC FORM NO.1 (ED. 12-96)Page 426.7
Name of Respondent This '(0rt Is:Date of Report Year/Period of Report
PacîfCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner,or other part is an associated company.
CapacitY of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(10 MVa)
Transformers Spare Type of Equipment Number of Units Total CapacitY No.In Service Transformers
(In MVa)
(f)(g)(h)(i)ü)(k)
45 2 1.
8 1 2
55 2 3
45 -2 4
1 1 1 5
40 2 6
39 21 7
46 7 1 8
22 2 9
6 1 10
50 2 11
11 3 12
50 2 13
2 3 .14
50 2 15.
8 1 16
14 1 17
25 1 18
25 2 19
50 2 20
9 3 21
25 1 22
9 1 23
9 1 24
45 2 25
40 2 26
70 3 27
8 1 28
40 2 29
9 1 30
2 3 31...
25 1 32
19 .2 33
9 1 34.
20 1 35
7 3 36
40 2 .37
55 2 38
1 39.
25 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.7
.
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
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 (t).
..
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Prmary Secondary Tertiary
(a)(b)(c)(d)(e)
1 SUTHERLIN SUB DISTRIBUTION-UNATTEN 115.00 12.00
2 SWEET HOME SUB .DISTRIBUTION-UNATTEN 115.00 20.80
3 TAKELMA SUB DISTRIBUTION-UNATTEN 115.00 20.80
4 TALENT SUB DISTRIBUTION-UNATTEN 69.0C 12.47
5 TEXUM SUB DISTRIBUTION-UNATTEN 69.00 12.47
6 TILLER SUB DISTRIBUTION-UNA TTEN 115.00 12.47
7 TOLOSUB DISTRIBUTION-UNA TTEN 69.00 12.47
8 TURKEY HILL SUB DISTRIBUTION-UNATTEN 69.00 12.47
9 UMAPINE SUB DISTRIBUTION-UNA TTEN 69.00 12.47
10 UMATILLA SUB DISTRIBUTION-UNATTEN 69.00 12.47
11 VERNON SUB DISTRIBUTION-UNATTEN 69.00 12.47
12 VILAS SUB DISTRIBUTION-UNATTEN 115.00 12.47
13 VILLAGE GREEN SUB DISTRIBUTION-UNATTEN 115.00 20.80
14 VINE STREET SUB DISTRIBUTION-UNATTEN 69.00 20.80
15 WALLOWA SUB DISTRIBUTION-UNATTEN 69.00 12.47
16 WARM SPRINGS SUB DISTRIBUTION-UNA TTEN 69.00 20.80
17 WARRENTON SUB DISTRIBUTION-UNA TTEN 115.00 12.47
18 WASCO SUB DISTRIBUTION-UNA TTEN 20.8(J 4.16
19 WECOMA BEACH SUB DISTRIBUTION-UNA TTEN 20.80 4.16
20 WESTERN KRAFT SUB DISTRIBUTION-UNA TTEN 115.00 12.47
21 WESTON SUB D1TRIBUTION-UNA TTEN 69.00 12.47
22 WESTSIDE HYDRO/SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 WEYERHAUSER SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 WHITE CITY DISTRIBUTION-UNATTEN 115.00 12.47
25 WILLOW COVE SUB DISTRIBUTION-UNA TTEN 34.50 4.16
26 WINSTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
27 YEW AVENUE SUB DISTRIBUTION-UNA TTEN 115.00 12.50
28 YOUNGS BAY SUB DISTRIBUTION-UNA TTEN 115.00 12.47
29 Total 15476.54 2522.27 195.00
30 Number of Substations- 183
31
32 ALBINA SUB TID-UNATTENDED 115.00 12.47 69.00
33 APPLEGATE SUB TID-UNATTENDED 115.00 69.00 12.47
34 ASHLAND MTN AVE SUB TID-UNATTENDED 115.00 69.00 12.47
35 BEND PLANT TID-UNATTENDED 69.00 4.16 12.47
36 CAVE JUNCTION SUB TID-UNATTENDED 115.00 12.47 69.00
37 HAZELWOOD SUB TID-UNATTENDED 115.00 69.00 12.47
38 KNOTT SUB TID-UNATTENDED 115.00 12.47 57.00
39 MILE HI SUB TID-UNATTENDED 115.00 69.00 12.47
40 PILOT BUTTE SUB TID-UNATTENDED 230.00 69.00 12.47
...
FERC FORM NO.1 (ED. 12-96)Page 426.8
Name of Respondent.This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) ~An Original (Mo, Da, Yr)End of 2009/Q4
.(2) DA Resubmission 04/14/2010
.SUBSTATIONS (Continued)..
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Total Capacity No.In Service Transformèrs Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
25 1 1
42 2 2
13 1 3
50 2 4.
17 6 .5..
1 1 6
11 1 7
13 3 8
13 1 9
25 2 10
50 2 11
25 1 .12
40 2 13
22 4 14
7 1 15
13 3 16
25 2 17
3 3 18
3 1 19
50 2 20
22 2 21
23 9 22
40 2 23
60 3 ..24
.28 3 25
23 3 26
25 1 27
37 2 28
4506 .365 5 29
30
31
177 9 32
65 2 .33
70 2 34
23 3 35
.70 2 36
132 4 ..37
187 8 38
39 4 39
400 4 40
FERC FORM NO.1 (ED. 12-96)Page 427.8
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
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. (t).
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 WINCHESTER SUB T/D-UNA TTENDED 115.00 12.47 69.00
2 Total 1219.00 399.04 338.82
3 Number of Substations- 10
4
5 CLEARWATER #1 HYDRO PLANT TRANSMISSION-A TTENDE 138.0C 6.90
6 CLEARWATER #2 HYDRO PLANT TRANSMISSION-A TTENDE 138.00 12.00
7 FISH CREEK HYDRO TRANSMISSION-ATTENDE 115.00 6.90
8 JC BOYLE HYDRO TRANSMISSION-ATTENDE 230.00 11.00
9 LEMOLO #1 HYDRO TRANSMISSION-ATTENDE 11.30 12.50
10 LEMOLO #2 HYDRO TRANSMISSION-ATTENDE 115.00 12.00
11 PROSPECT 1 HYDRO TRANSMISSION-ATTENDE 69.00 2.30
12 PROSPECT 2 HYDRO TRANSMISSION-A TTENDE 69.0C 6.60
13 PROSPECT 3 HYDRO TRASMISSION-A TTENDE 69.00 12.47
14 TOKETEE HYDRO TRANSMISSION-A TTENDE 115.0C 6.90
15 BEND PLANT TRANSMISSION-UNA TTEN 4.16 2.40
16 CALAPOOYA SUB TRANSMISSION-UNA TTEN 230.00 69.00
17 CHILOQUIN SUB TRANSMISSION-UNA TTEN 23O.0C 115.00 69.00
18 COLD SPRINGS SUB TRANSMISSION-UNATTEN 230.00 69.00
19 COVE SUB TRNSMISSION-UNATTEN 230.00 69.00
20 DAYS CREEK SUB TRANSMISSION-UNATTEN 115.0C 69.00
21 DIAMOND HILL SUB TRANSMISSION-UNATTEN 230.00 69.00
22 DIXONVILLE 115/230 SUB TRNSMISSION-UNA TTEN 230.00 115.00 69.00
TRANSMISSION-UNA TTEN 500.00 230.00
24 EAGLE POINT HYDRO TRANSMISSION-UNATTEN 115.00 2.40
25 EAST SIDE HYDRO TRANSMISSION-UNA TTEN 46.00 12.47
26 FISH HOLE SUB TRANSMISSION-UNA TTEN 115.00 69.00
27 FRY SUB TRANSMISSION-UNATTEN 230.00 115.00
28 GRANTS PASS SUB TRANSMISSION-UNATTEN 230.00 115.00 69.00
29 GREEN SPRINGS PLANT/SUB TRANSMISSION-UNATTEN 115.00 69.00
30 HURRICANE SUB TRNSMISSION-UNATTEN 230.00 69.00 2.40
31 ISTHMUS SUB TRASMISSION-UNATTEN 230.00 115.00
32 KENNEDY SUB TRASMISSION-UNATTEN 69.00 57.00
33 KLAMATH FALLS SUB TRANSMISSION-UNATTEN 230.00 69.00
34 LONE PINE SUB TRANSMISSION-UNA TTEN 230.00 115.00 69.00
TRANSMISSION-UNA TTEN 500.00 230,0036 MONPAC SUB TRANSMISSION-UNATTEN 115.00 69.00
37 PONDEROSA SUB TRASMISSION-UNATTEN 230.00 115.00
38 POWERDALE PLANT TRANSMISSION-UNATTEN 69.00 7.20
39 PROSPECT CENTRAL SUB TRANSMISSION-UNATTEN 115.00 69.00
40 ROBERTS CREEK SUB TRANSMISSION-UNATTEN 115.00 69.00
FERC FORM NO.1 (ED. 12-96)Page 426.9
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
SUBSTATIONS (Continued)
5. Show in columns (i), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
75 5 1
1238 43 2
3.
4
17 3 5
31 3 6
13 3 .7
89 2 1 8
2 3 1 9
40 4 10
5 3 11
40 6 1 12
10 6 13
50 9 14
3 3 .15
75 1 16
119 4 17
60 1 18
67 3 19
50 1 20
75 1 21
344 6 22
650 3 1 23
3 1 24
3 3 25
7 3 26
500 2 27
458 4 28
19 3 29
29 2 30
250 1 31
33 1 32
251 6 1 33.
733 10 34
1300 6 1 35
50 1 36
250 1 37
8 3 1 38
47 4 .......39
50 1 40
FERC FORM NO. 1 (ED. 12-96)Page 427.9
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2009/Q4
(2). OA Resubmission 04/14/2010
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, summarie accrding to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 SLIDE CREEK HYDRO TRANSMISSION-UNATTEN 115.00 7.00
2 SODA SPRINGS HYDRO TRANSMISSION-UNATTEN 115.00 7.00
3 TROUTDALE SUB TRANSMISSION-UNATTEN 230.00 115.00 69.00
4 TUCKER SUB TRANSMISSION-UNA TTEN 115.0C 69.00
5 WALLOWA FALLS HYDRO TRASMISSION-UNATTEN 20.80
6 Total 6648.26 2462.04 347.40
7 Number of Substations- 41
8
9 Utah
10 106TH SOUTH SUB DISTRIBUTION-UNA TTEN 138.00 12.50
11 118TH SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.47
12 23RDSTSUB DISTRIBUTION-UNATTEN 46.00 12.47
13 70TH SOUTH SUB DISTRIBUTION-UNA TTEN 138.00 12.47
14 ALTAVIEW DISTRIBUTION-UNA TTEN 46.00 12.47
15 AMALGA DISTRIBUTION-UNA TTEN 46.00 12.47
16 AMERICAN FORK DISTRIBUTION-UNATTEN 138.00 12.47
17 ARAGONITE DISTRIBUTION-UNATTEN 46.00 7.20
18 AURORA SUB DISTRIBUTION-UNATTEN 46.00 12.47
19 BANGERTER SUB DISTRIBUTION-UNA TTEN 138.00 12.47
20 BEAR RIVER SUB DISTRIBUTION-UNA TTEN 46.00 12.47
21 BENJAMIN SUB DISTRIBUTION-UNATTEN 46.00 12.47
22 BINGHAM SUB DISTRIBUTION-UNATTEN 46.00 12.47
23 BLUE CREEK DISTRIBUTION-UNATTEN 46.00 12.47
24 BLUFF SUB DISTRIBUTION-UNATTEN 69.0C 12.47
25 BLUFFDALE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
26 BOTHWELL SUB DISTRIBUTION-UNATTEN 46.00 12.47
27 BOX ELDER SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 BRIAN HEAD SUB DISTRIBUTION-UNATTEN 46.00 12.47
29 BRICKYARD SUB DISTRIBUTION-UNATTEN 46.00 12.47
30 BRIGHTON SUB DlTRIBUTION-UNATTEN 46.00 24.90
31 BROOKLAWN SUB DISTRIBUTION-UNATTEN 46.00 12.47
32 BRUNSWICK SUB DISTRIBUTION-UNA TTEN 46.00 12.47
33 BURTON SUB DISTRIBUTION-UNA TTEN 34.50 12.47
34 BUSH SUB DISTRIBUTION-UNATTEN 46.00 12.47
35 CANNON SUB DISTRIBUTION-UNATTEN 46.0C 12.47
36 CANYONLANDS SUB DISTRIBUTION-UNATTEN 69.00 12.47
37 CAPITOL SUB DISTRIBUTION-UNATTEN 46.OC 12.47
38 CARBIDE SUB DISTRIBUTION-UNATTEN 46.OC 7.20
39 CARBONVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 CARLISLE SUB DISTRIBUTION-UNATTEN 138.00 12.50
FERC FORM NO.1 (ED. 12-96)Page 426.10
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1 ) (gAn Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
SUBSTATIONS (Continued)
5. Show in columns (1),0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual. rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other 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 Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)(j (k)
21 3 1
13 3 2
. 500 3 3
100 2 4
2 ..3 5
6367 131 7 6
7
8
9
30 1 10
30 1 11
13 1 12
30 1 13
45 2 14
11 1 15
30 1 16
1 1 17
3 1 18
50 1 19
17 2 20
2 1 21
11 1 22
2 3 23
1 3 24
9 1 25
4 1
.26
14 1 27
14 1 28
9 1 29
26 2 30
.6 1 31
60 3 32
11 3 33
9 1 34
13 1 35.
1 1 36
20 1 37
. 3 1 38
6 1 39
30 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.10
Name of Respondent This Î:0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
".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 (t).
.
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 CASTO SUBSTATION DISTRIBUTION-UNATTEN 46.00 12.47
2 CENTENNIAL SUB DISTRIBUTION-UNATTEN 138.00 12.47
3 CENTERVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
4 CENTRAL SUB DISTRIBUTION-UNATTEN 43.80 12.47
5 CHAPEL HILL SUB DISTRIBUTION-UNA TTEN 138.00 12.47
6 CHERRYWOOD SUB DISTRIBUTION-UNATTEN 138.00 12.47
7 CIRCLEVILLE SUB DISTRIBUTION-UNA TTEN 69.00 12.47
8 CLEAR CREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47
9 CLEAR LAKE SUB DISTRIBUTION-UNATTEN 46.00 12.47
10 CLEARFIELD SOUTH DISTRIBUTION-UNATTEN 138.00 12.47
11 CLiNTON,SUB DISTRIBUTION-UNATTEN 138.00 12.47
12 CLIVE SUB DISTRIBUTION-UNATTEN 46.00 12.47
13 COALVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 COLD WATER CANYON SUB DISTRIBUTION-UNATTEN 138.00 12.47
15 COLEMAN SUB DISTRIBUTION-UNA TTEN 138.0C 69.00 12.47
16 COL TON WELL SUB DISTRIBUTION-UNA TTEN 46.00 12.47
17 COMMERCE SUB DISTRIBUTION-UNA TTEN 138.00 12.50
18 CORINNE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
19 COVE FORT SUB DISTRIBUTION-UNA TTEN 46.00 12.47
20 COZYDALE SUB DISTRIBUTION-UNA TTEN 138.00 12.50
21 CRESCENT JUNCTION SUB DISTRIBUTION-UNATTEN 46.00 7.20
22 CROSS HOLLOW SUB DISTRIBUTION-UNATTEN 138.00 12.47
23 CUDAHY SUB DISTRIBUTION-UNATTEN 138.00 12.47
24 DAMMERON VALLEY SUB DISTRIBUTION-UNATTEN 34.50 12.47
25 DECADE SUB DISTRIBUTION-UNATTEN 138.00 12.50
26 DECKER LAKE SUB DISTRIBUTION-UNATTEN 138.00 12.47
27 DELLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 DELTA SUB DISTRIBUTION-UNATTEN 46.00 69.00
29 DESERET SUB DISTRIBUTION-UNATTEN 46.00 4.16
30 DEWEYVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
31 DIMPLE DELL SUB DISTRIBUTION-UNATTEN 138.00 12.47
32 DIXIE DEER SUB DISTRIBUTION-UNA TTEN 34.50 12.47
33 DRAPER SUB DISTRIBUTION-UNATTEN 46.00 12.47
34 DUMAS SUB DISTRIBUTION-UNATTEN 138.00 .'12.47
35 EAST BENCH SUB DISTRIBUTION-UNATTEN 138.00 12.47
36 EAST HYRUM SUB DISTRIBUTION-UNA TTEN 46.00 12.47
37 EAST LAYTON SUB DISTRIBUTION-UNA TTEN 138.00 12.47
38 EAST MILLCREEK SUB DISTRIBUTION-UNA TTEN 46.00 12.47
39 EDEN SUB DISTRIBUTION-UNA TTEN 46.00 12.47
40 ELBERTA SUB DISTRIBUTION-UNATTEN 46.00 12.47
.
FERC FORM NO.1 (ED. 12-96)Page 426.11
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
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, aiid 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 Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
25 1 1
40 2 2
22 ~
1
.3
9 1 4
..
30 1 5
25 1 6
3 1 7
4 1 8
3 9
60 2 10
50 2 11
4 1 12
20 2 13
30 1 14
106 4 15
1 3 16
30 1 17.
3 1 18
.2 3 19
30 1 20
1 1 21
22 1 22.
30 1 23
42 1 24.
60 2 25
55 2 26
6 1 27
~
48 3 28
2 1 29
4 1 30
60 2 31
2 1 32
23 2 .33
60 2 34
30 1 35
6 1 36
60 2 37
20 1 38
19 2 39
5 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.11
Name of Respondent This 180rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
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).
..
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(é)
1 ELK MEADOWS SUB DISTRIBUTION-UNATTEN 46.00 12.47
2 ELSINORE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
3 EMERY CITY SUB DISTRIBUTION-UNA TTEN 69.00 12.47
4 EMIGRATION SUB .DISTRIBUTION-UNATTEN 46.00 12.47
5 ENOCH SUB DISTRIBUTION-UNA TTEN 138.00 12.47
6 ENTERPRISE VALLEY SUB DISTRIBUTION-UNA TTEN .138.00 12.47
7 EUREKA SUB DISTRIBUTION-UNA TTEN 46.00 12.47
8 FARMINGTON SUB DISTRIBUTION-UNATTEN 138.00 12.47
9 FAYETTE SUB DISTRIBUTION-UNATTEN 46.00 12.47
10 FERRON SUB DISTRIBUTION-UNATTEN 46.00 12.47
11 FIELDING SUB DISTRIBUTION-UNATTEN 46.00 12.00
12 FIFTH WEST SUB DISTRIBUTION-UNA TTEN 138.00 12.47
13 FLUX SUB DISTRIBUTION-UNA TTEN 46.00 12.47
14 FOOL CREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47
15 FOUNTAIN GREEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
16 FREEDOM SUBSTATION DISTRIBUTION-UNATTEN 46.00 7.20
17 FRUIT HEIGHTS SUB DISTRIBUTION-UNATTEN 46.00 12.47
18 GARDEN CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 GATEWAY SUB DISTRIBUTION-UNATTEN 69.00 12.47
20 GOLD RUSH SUB DISTRIBUTION-UNATTEN 138.00 12.50
21 GORDON AVENUE SUB DISTRIBUTION-UNATTEN 138.00 12.50
22 GOSHEN SUB DISTRIBUTION-UNA TTEN 46.00 12.47
23 GRANGER SUB DISTRIBUTION-UNA TTEN 46.00 12.47
24 GRANTSVILLE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
25 GREEN RIVER SUB DISTRIBUTION-UNA TTEN 46.00 12.47
26 GROW SUB DISTRIBUTION-UNATTEN 138.00 12.47 46.00
27 GUNLOCK HYDRO DISTRIBUTION-UNATTEN 34.50 2.30
28 GUNNISON SUB DISTRIBUTION-UNA TTEN 46.00 12.47
29 HAMIL TON SUB DISTRIBUTION-UNATTEN 34.50 12.47
30 HAMMER SUB DISTRIBUTION-UNATTEN 138.00 12.47
31 HAVASU SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 HELPER CITY SUB DISTRIBUTION-UNATTEN 46.00 4.16
33 HENEFER SUB DISTRIBUTION-UNATTEN 46.00 12.47
34 HERRIMAN SUB DISTRIBUTION-UNATTEN 138.00 12.47
35 HIAWATHA SUB DISTRIBUTION-UNATTN 46.00 4.16
36 HIGHLAND DIST SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 HOGGARD SUB DISTRIBUTION-UNATTEN 138.00 12.47
38 HOGLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 HOLDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 HOLLADAY SUB DISTRIBUTION-UNATTEN .46.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.12
.
Name of Respondent This lË0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) r=AResubmission 04/14/2010
.SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-Owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Servicè)(In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
3 1 .1
2 1 2
3 3 .3
25 1
.4
14 1 5
10 1 6
3 1 7
30 1 8
1 2 9
5 1 10
6 1 11
30 1 12
4 1 13
2 1 14
2 1 15
1 16
22 1 17
13 1 18
28 2 1 19
30 1 20
30 1 21
2 1 22
43 2 23
24 1 24
5 2 25
72 3 26
1 1 27
11 1 28
1 3 29
60 2 30
3 1 31
3 3 32
4 1
.33
30 1 34
1 3 35
25 1 36
50 2 "37
22 1 38
~
4 1 39
32 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.12
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
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 (t).
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 HUNTER SUB .DISTRIBUTION-UNA TTEN 46.00 12.47
2 HUNTINGTON CITY SUB DISTRIBUTION-UNA TTEN 69.00 12.47
3 IRON MOUNTAIN SUB DISTRIBUTION-UNA TTEN 34.50 7.20
4 IRON SPRINGS SUB DISTRIBUTION-UNA TTEN 34.50 12.47.
5 IRONTON SUB DISTRIBUTION-UNA TTEN 46.00 12.47
6 IVINS SUB .DISTRIBUTION-UNA TTEN 34.50 12.47
7 JORDAN NARROWS SUB DISTRIBUTION-UNATTEN 46.00 2.40
8 JORDAN PARK SUB DISTRIBUTION-UNATTEN 138.00 12.47
9 JORDANELLE SUB DISTRIBUTION-UNATTEN 138.00 12.47
10 JUAB SUB DISTRIBUTION-UNATTEN 46.00 12.47
11 JUNCTION SUB DISTRIBUTION-UNATTEN 69.00 12.47
12 KAIBABSUB DISTRIBUTION-UNA TTEN 69.00 12.47
13 KAAS SUB DISTRIBUTION-UNA TTEN 46.00 12.47
14 KEARNS SUB DISTRIBUTION-UNA TTEN 138.00 12.47
15 KENSINGTON SUB DISTRIBUTION-UNATTEN 46.00 4.16
16 LAKE PARK SUB DISTRIBUTION-UNA TTEN 138.00 12.47
17 LARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
18 LAYTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
19 LEGRANDE SUB DISTRIBUTION-UNATTEN 46.00 12.47
20 LEWISTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
21 LINCOLN SUB DISTRIBUTION-UNA TTEN 46.00 12.47
22 LINDON SUB DISTRIBUTION-UNA TTEN 46.00 12.47
23 LISBON SUB DISTRIBUTION-UNA TTEN 69.00 12.47
24 LITTLE MOUNTAIN SUB DISTRIBUTION-UNA TIEN 46.00 12.47
25 LOAFER SUB DISTRIBUTION-UNA TTEN 46.00 12.47
26 LOGAN CANYON SUB DISTRIBUTION-UNATTEN 46.00 7.20
27 LONE TREE SUB DISTRIBUTION-UNATTEN 34.50 12.47
28 LOWER BEAVER SUB DISTRIBUTION-UNATTEN 46.00 6.60
29 LYNNDYL SUB DISTRIBUTION-UNATIEN 46.00 12.47
30 MAESERSUB DISTRIBUTION-UNATTEN 69.00 12.47
31 MAGNA SUB DISTRIBUTION-UNATTEN 138.00 12.47
32 MANILA SUB DISTRIBUTION-UNATIEN 46.00 12.47
33 MANTUA SUB DISTRIBUTION-UNATIEN 46.00 12.47
34 MAPLETON SUB DISTRIBUTION-UNATTEN 46.00 12.47
35 MARRIOTT SUB DISTRIBUTION-UNATTEN 46.00 12.47
.36 MARYSVALE SUB DISTRIBUTION-UNATIEN 46.00 12.47
37 MATHIS SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 MCCORNICK SUB DISTRIBUTION-UNATIEN 46.00 12.47
39 MCKAY SUB DISTRIBUTION-UNATIN 46.00 12.47
40 MEADOWBROOK SUB DISTRIBUTION-UNATTEN 138.00 12.47 46.00
FERC FORM NO.1 (ED. 12.96)Page 426.13
Name of Respondent This 180rt Is:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
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 LineTransformersSpare
.
(In Service)(In MVa)In Service Transformers Type of Equipment Number of Units Total Capacity No.
(In MVa)
(f)(g)(h)(i)ü)(k)
.22 1 1
13 2 2
1 1 3
5 3 4
2 1 5
22 1 6
13 2 7
30 1 8
30 1 9
2 3 10
3 1 11
5 1 12
7 1 13
60 2 14
7 1 15
53 2 16
6 1 17
40 2 18
2 1 19
14 .1 20
20 1 21
20 1 22
4 1 23
20 1 24
1 25
1 1 26
20 1 27
1 3 28
4 1 29....
13 1 30
30 1 31
22 1 32
2 1 33.
14 1 34
20 1 35
2 3 36
9 1 37
.. 6 1 38
20 1 39
42 2 40
-
FERC FORM NO.1 (ED. 12-96)Page 427.13
Name of Respondent This io0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
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).
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 MEDICAL SUB DISTRIBUTION-UNA TTEN 46.00 12.47
2 MELLING SUB DISTRIBUTION-UNATTEN 34.50 4.16
3 MIDLAND SUB DISTRIBUTION-UNATTEN 138.0C 12.47
4 MIDVALE SUB DISTRIBUTION-UNATTEN 46.0C 12.47
5 MILFORD SUB DISTRIBUTION-UNA TTEN 46.0C 12.47
6 MILFORD TV SUB DISTRIBUTION-UNA TTEN 46.00 7.20
7 MILLVILLE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
8 MINERSVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
9 MOAB CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47
10 MONTEZUMA SUB DISTRIBUTION-UNA TTEN 69.00 12.47
11 MOORE SUB DISTRIBUTION-UNA TTEN 69.00 12.47
12 MORGAN SUB DISTRIBUTION-UNA TTEN 46.00 4.16
13 MORONI SUB DISTRIBUTION-UNATTEN 46.0C 12.47
14 MORTON COURT SUB DISTRIBUTION-UNATTEN 138.OC 12.47
15 MOSS JUNCTION SUB DISTRIBUTION-UNA TTEN 46.00 12.47
16 MOUNTAIN DELL SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 MOUNTAIN GREEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
18 MYTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 NEW HARMONY SUB "DISTRIBUTION-UNA TTEN 69.00 12.47
20 NEWGATESUB DISTRIBUTION-UNA TTEN 46.00 12.47
21 NEWTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
22 NIBLEYSUB DISTRIBUTION-UNA TTEN 46.00 24.90
23 NORTH BENCH SUB DISTRIBUTION-UNATTEN 46.00 12.47
24 NORTH FIELDS SUB DISTRIBUTION-UNATTEN 46.00 12.47
25 NORTH LOGAN SUB DISTRIBUTION-UNATTEN 46.00 12.47
26 NORTH OGDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
27 NORTH SALT LAKE SUB DISTRIBUTION-UNATTEN 46.00 13.20
28 NORTHEAST SUB DISTRIBUTION-UNATTEN 46.00 12.47
29 NORTHRIDGE SUB DISTRIBUTION-UNATTEN 46.0C 12.47
30 OAKLAND AVE SUB DISTRIBUTION-UNATTEN 46.00 12.47
31 OAKLEY SUB DISTRIBUTION-UNATTEN 46.0C 12.47
32 OLYMPUS SUB D1STRIBUTION-UNATTEN 46.00 12.47
33 OPHIR SUB DISTRIBUTION-UNATTEN 46.00 12.47
34 ORANGE SUB DISTRIBUTION-UNATTEN 46.00 12.47
35 ORANGEVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 OREMSUB DISTRIBUTION-UNATTEN 46.00 12.47
37 PACK CREEK RESERVOIR DISTRIBUTION-UNATTEN 46.00 12.47
38 PANGUITCH SUB DISTRIBUTION-UNATTEN 69.00 12.47
39 PARlETTE SUBSTATION DISTRIBUTION-UNATTEN 69.00 24.90
40 PARK CITY SUB DISTRIBUTION-UNATTEN 46.OC 12.47 .
.
FERC FORM NO.1 (ED. 12-96)Page 426.14
Name of Respondent This î80rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmissioh 04/14/2010
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 isan associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)(j)(k)
58 4 1
5 1 2
30 1 .3
25 1 4
14 1 5
1 1 6
13 1 .7
2 1 8
19 2 9
13 1 10
3 1 11
3 1 12
6 1 13
25 1 14
6 3 15
5 1 16
6 1 17
6 1 18
7 1 19
20 1 20
5 1 21
14 1 22
25 1 23
2 1 24
25 1 25.
22 1 26
25 1 27.
45 10 28
14 1 29
24 2 30
6 1 31
22 1 32
3 1 33
20 1 34..
14 1 35
.48 362
4 1 37.
5 1 38
4 3 39
35 2 40
...
FERC FORM NO.1 (ED. 12-96)Page 427.14
Name of Respondent This ~ort Is:Date of Report Year/Penodof Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
.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 sèrving 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)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertary
(a)(b)(c)(d)(e)
1 PARKWAY SUB DISTRIBUTION-UNA TTEN 138.00 12.47
2 PARLEYS SUB DISTRIBUTION-UNATTEN 46.00 12.47
3 PELICAN POINT SUB DISTRIBUTION-UNATTEN 46.00 12.47
4 PINE CANYON SUB DISTRIBUTION-UNATTEN 138.00 12.47
5 PINE CREEK SUB DISTRIBUTION"UNA TTEN 46.00 12.47
6 PINNACLE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
7 PLAIN CITY SUB DISTRIBUTION-UNATTEN 138.00 12.47
8 PLEASANT GROVE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
9 PLEASANT VIEW SUB DISTRIBUTION-UNATTEN 46.00 12.47
10 PORTER ROCKWELL SUB DISTRIBUTION-UNA TTEN 138.00 12.47
11 PROMONTORY SUB DISTRIBUTION-UNATTEN 46.00 12.47 .
12 QUAIL CREEK SUB DISTRIBUTION-UNATTEN 34.50 12.47
13 QUARRY SUB DISTRIBUTION-UNA TTEN 138.00 12.47
14 QUICHAPA SUB DISTRIBUTION-UNATTEN 34.50 12.47
15 RAINS SUB DISTRIBUTION-UNATTEN 46.00 7.20
16 RANDOLPH SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 RASMUSON SUB DISTRIBUTION-UNA TTEN 46.00 12.47
18 RATTLESNAKE SUB DISTRIBUTION-UNA TTEN 69.00 24.90
19 RED MOUNTAIN SUB DISTRIBUTION-UNA TTEN 69.00 34.50
20 RED ROCK SUB DISTRIBUTION-UNA TTEN 69.00 4.16
21 REDWOOD SUB DISTRIBUTION-UNA TTEN 46.00 12.47
22 RESEARCH PARK SUB DISTRIBUTION-UNA TTEN 46.00 12.47
23 RICH SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 RICHFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47
25 RICHMOND SUB DISTRIBUTION-UNA TTEN 46.00 12.47
26 RIDGELAND SUB DISTRIBUTION-UNATTEN 138.00 12.47
27 RITER SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 ROCK CANYON SUB DISTRIBUTION-UNA TTEN 69.00 12.47
29 ROCKVILLE SUB DISTRIBUTION-UNATTEN 34.50 12.47
30 ROCKY POINT DISTRIBUTION-UNATTEN 138.00 13.20
31 ROSE PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
32 ROYAL SUB DISTRIBUTION-UNATTEN 46.00 4.16
33 SAUNA SUB DISTRIBUTION-UNATTEN 46.00 12.47
34 SANDY SUB DISTRIBUTION-UNATTEN 138.00 12.47
35 SARATOGA SUB DISTRIBUTION-UNATTEN 138.00 12.47
36 SCIPIO SUB DISTRIBUTION-UNATTEN 46.00 12.47 ..
37 SCOFIELD RESERVOIR SUB DISTRIBUTION-UNATTEN 46.00 7.20
38 SCOFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 SECOND STREET SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 SEVEN MILE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.15
Name of Respondent This 00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) liA Resubmission 04/14/2010
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Total Capacity No.In Servce Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)u)(k)
50 2 1
16 2 2
6 1 3
55 2 4.
2 1 5
14 1 6
22 1 7.
25 1 8
14 1 9
30 1 10
2 1 11
4 1 12
60 2 13
4 1 14
15 1 15
2 1 16
1 3 17
14 1 18
13 1 19
3 1 20
45 2 21
45 2 22
5 1 23
22 2 24
11 1 25
40 2 26
20 1 27
5 1 28
4 1 29
30 1 30
24 3 31
3 32
11 1 33
60 2 34
30 1 .35
1 3 36
1 37
1 3 38
13 2 39
5 3 40
.
FERC FORM NO.1 (ED. 12-96)Page 427.15
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) ñA Resubmission 04/14/2010
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 witb capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, butthe 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 Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 SHARON SUB DISTRfBUTION-UNATTEN 46.00 12.47
2 SHIVWITS SUB DISTRIBUTION-UNATTEN 34.50 4.16
3 SHORELINE SUB DISTRIBUTION-UNATTEN 138.00 13.20
4 SIXTH SOUTH SUB DISTRIBUTION-UNATTEN 46.00 12.47
5 SKULL VALLEY SUB DISTRIBUTION-UNATTEN 46.00 12.47
6 SNARR SUB DISTRIBUTION-UNATTEN 46.00 12.47
7 SNOWVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47
8 SNYDERVILLE SUB DISTRIBUTION-UNA TTEN 138.00 12.47
9 SOLDIER SUMMIT SUB DISTRIBUTION-UNA TTEN 69.00 12.47
10 SOUTH JORDAN SUB DISTRIBUTION-UNATTEN 138.00 12.47
11 SOUTH MILFORD SUB DISTRIBUTION-UNATTEN 46.00 12.47
12 SOUTH MOUNTAIN SUB DISTRIBUTION-UNATTEN 138.00 12.47
13 SOUTH OGDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 SOUTH PARK SUB DISTRIBUTION-UNATTEN 138.00 12.47
15 SOUTH WEBER SUB DISTRIBUTION-UNATTEN 138.00 12.47
16 SOUTHEAST SUB DISTRIBUTION-UNATTEN 138.00 12.47 46.00
17 SOUTHWEST SUB DISTRIBUTION-UNA TTEN 46.00 12.47
18 SPANISH VALLEY SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 SPRINGDALE SUB DISTRIBUTION-UNA TTEN ~4.50 12.47
20 ST. JOHNS SUB DISTRIBUTION-UNA TTEN 46.00 12.47
21 STAIRS SUB DISTRIBUTION-UNA TTEN 12.47 2.40
22 STANSBURY SUB DISTRIBUTION-UNA TTEN 46.00 12.47
23 SUMMIT CREEK SUB DISTRIBUTION-UNATTEN 138.00 12.47
24 SUMMIT PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
25 SUNRISE SUB.DISTRIBUTION-UNATTEN 138.00 12.47
26 SUPERIOR SUB DISTRIBUTION-UNATTEN 69.00 12.47
27 SUTHERLAND SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 TAYLOR SUB DISTRIBUTION-UNATTEN 46.00 12.47
29 THIEF CREEK SUB DISTRIBUTION-UNATTEN 138.00 24.90
30 THIRD WEST SUB DISTRIBUTION-UNATTEN 46.00 12.47
31 THIRTEENTH SOUTH SUB DISTRIBUTION-UNA TTEN 46.00 12.47
32 THOMPSON SUB DISTRIBUTION-UNATTEN 46.00 4.16
33 TOOELE DEPOT SUB DISTRIBUTION-UNATTEN 46.00 12.50
34 TOQUERVILLE SUB ..DISTRIBUTION-UNATTEN 69.00 12.47 34.50
35 TRI CITY SUB DISTRIBUTION-UNATTEN 138.00 12.47
36 UINTAH SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 UNION SUB DISTRIBUTION-UNA TTEN 46.00 12.47 .
38 UNIVERSITY SUB DISTRIBUTION-UNATTEN 46.00 4.16
39 VALLEY CENTER SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 VERMILLION SUB DISTRIBUTION-UNATTN 46.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.16
Name of Respondent This mort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) rïA Resubmission 04/14/2010
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.
-
CClpacity of Substation Number of NUmber of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Servíce T ransfol1ers Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
20 1 1
6 1
_.2
60 2 3
20 1 4
2 1 .5
40 2 6
5 1 7
30 1 8
13 1 9
30 1 10
20 2 11
60 2 12
25 1 13
30 1 14
. 50 1 15
50 2 .16
22 2 17
6 1 18
4 1 19.
4 1 20
2 1 21
20 1 22
14 1 23
7 1 24
30 1 25
8 1 26
6 1 27.
14 1 28
14 1 29.
40 2 30
24 3 31-
2 1 32
25 1 33
34 2 34
30 1 35
39 2 36
50 2 37
48 4 38
22 1 39
3 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.16
Name of Respondent This ÏË0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
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 (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Characer of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 VERNAL SUB DISTRIBUTION-UNA TIEN 69.00 12.47
2 VEYO HYDRO DISTRIBUTION-UNA TIEN 34.50 2.40
3 VICKERS SUB DISTRIBUTION-UNATIEN 46.00 12.47
4 VINEYARD SUB DISTRIBUTION-UNA TIEN 46.00 12.47
5 WALLSBURG SUB DISTRIBUTION-UNATIEN 138.00 12.47
6 WALNUT GROVE SUB DISTRIBUTION-UNATIEN 138.00 12.50
7 WARREN SUB DISTRIBUTION-UNA TIEN 138.00 12.47
8 WASATCH STATE PARK SUB DISTRIBUTION-UNATIEN 46.00 12.47
9 WASHAKIE SUB DISTRIBUTION-UNATIEN 138.00 4.16
10 WELBY SUB DISTRIBUTION-UNATIEN 46.00 12.47
11 WELFARE SUB DISTRIBUTION-UNATIEN 46.00 12.47
12 WELLINGTON SUB DISTRIBUTION-UNATIEN 46.00 12.47
13 WEST COMMERCIAL SUB DISTRIBUTION-UNA TIEN 46.00 12.47
14 WEST JORDAN SUB DISTRIBUTION-UNA TIEN 138.00 12.47
15 WEST OGDEN SUB DISTRIBUTION-UNA TIEN 138.00 12.47
16 WEST ROY SUB DISTRIBUTION-UNA TIEN 46.00 12.47
17 WEST TEMPLE SUB DISTRIBUTION-UNATIEN 46.00 4.16
18 WESTFIELD SUB DISTRIBUTION-UNATIEN 138.00 12.47
19 WESTWATER SUB DISTRIBUTION-UNATIEN 69.00 12.47
20 WHITE MESA SUB DISTRIBUTION-UNATIEN 69.00 12.47
21 WHITE ROCK SUB DISTRIBUTION-UNATIEN 138.00 12.47
22 WILLOWCREEK SUB DISTRIBUTION-UNA TIEN 46.00 12.47
23 WILLOWRIDGE SUB DISTRIBUTION-UNA TIEN 46.00 12.47
24 WINCHESTER HILLS SUB DISTRIBUTION-UNA TIEN 34.50 12.47
25 WINKLEMAN SUB DISTRIBUTION-UNA TIEN 46.00 7.20
26 WOLF CREEK SUB DISTRIBUTION-UNA TIEN 69.00 12.47
27 WOOD CROSS SUB DISTRIBUTION-UNA TIEN 46.00 12.47
28 WOODRUFF SUB DISTRIBUTION-UNATIEN 46.00 12.47
29 Total 20652.77 3720.78 184.97
30 Number of Substations- 299
31
32 ANGEL SUB TIDNATTNDED 138.00 12.47 46.00
33 BDO SUBSTATION TIDUNATTNDED 138.00 12.47
34 BUTLERVILLE SUB TID-UNATIENDED .138.00 46.00 12.47
35 COTIONWOOD SUB T/D-UNATIENDED 138.00 12.47 46.00
36 EMMA PARK SUBSTATION T/D-UNATIENDED 138.00 12.47
37 HALE SUB T/D-UNATIENDED 138.00 46.00 12.47
38 HIGHLAND SUB T/D-UNATIENDED 138.00 12.47 46.00
39 JORDAN SUB T/D-UNA TIENDED .. 138.00 46.00 12.47
40 JUDGE SUB T/D-UNATIENDED 46.00 12.47
i
FERC FORM NO.1 (ED. 12-96)Page 42e.17
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission
.04/14/2010
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment suchas rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Total Capacity No.In Service Transformers Type of Equipmen Number of Units
(In MVa)
(f)(Q)(h)(i)ü)(k)
33 2 ... ~1
2 3 2
2 1 3
25 .1 4
13 1 5
30 1 6
30 1 7
2 3 8
14 1 9
22 1 10
5 1 11
4 1 12
22 1 13
28 1 14
30 1 15
25 1 16
60 3 17
20 1 18
1 3 19
14 1 20
30 1 21
1 1 22.
14 1 23
4 1 24
1 25
6 1 26
20 1 27
2 1 28
5564 429 1 29
30
31
135 3 32
..30 1 33
175 3 34
289 7 35
8 1 36
114 2 37
97 2 38
164 2 39.
22 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.17
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) . X An Onginal (Mo, Da, Yr)End of 2009/Q4
(2) . riA Resubmission 04/14/2010
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 1 0 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)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertary
(a)(b)(c)(d)(e)
1 MCCLELLAND SUB TID-UNATTENDED 138.00 46.00 12.47
2 OQUIRRH SUB TID-UNATTENDED 138.00 46.00 12.47
3 PARRISH SUB TID-UNATTENDED 138.00 12.47 46.00
4 PIONEER PLANT TID-UNATTENDED 138.00 2.30 46.00
5 RIVERDALE SUB TID-UNATTENDED 138.00 46.00 12.47
6 SEVIER SUB TID-UNATTENDED 138.00 46.00 12.47
7 SILVER CREEK SUB TID-UNATTENDED 138.00 12.47 46.00
8 SPHINXSUB TID-UNATTENDED 46.00 12.47
9 SYRACUSE SUB TID-UNATTENDED 138.00 46.00 12.47
10 TAYLORSVILLE SUB TID-UNATTENDED 138.00 46.00 12.47
11 TERMINAL TID-UNATTENDED 345.00 12.47 46.00
12 TIMPSUB TID-UNATTENDED 138.00 46.00 12.47
13 TOOELE SUB TID-UNATTENDED 138.00 46.00 12.47
14 WEST VALLEY SUB TID-UNATTENDED 138.00 12.47
15 Total 3197.00 645.47 459.17
16 Number of Substations- 23
17
18 BLUNDELL PLANT TRANSMISSION-ATTENDE 46.00 12.47
19 CARBON PLANT TRANSMISSION-ATTENDE 138.00 13.80
20 EMERY SUB TRANSMISSION-A TTENDE 138.00 6.90 69.00
21 GADSBY PLANT TRANSMISSION-A TTENDE .138.00 13.80 46.00
22 GADSBY SUB .TRANSMISSION-A TTENDE 138.00 46.00
23 HUNTER PLANT TRANSMISSION-A TTENDE 345.00 23.00
24 HUNTINGTON PLANT TRANSMISSION-A TTENDE 345.00 23.00
25 90TH SOUTH SUB TRANSMISSION-UNATTEN 345.00 138.00
26 ABAJOSUB TRANSMISSION-UNATTEN 138.00 69.00
27 ASHLEY SUB TRASMISSION-UNATTEN 138.00 46.00
28 BARNEY SUB TRANSMISSION-UNATTEN 138.00 46.00
29 BEN LOMOND SUB TRASMISSION-UNA TTEN 345.00 230.00 138.00
30 BLACKHAWK SUB TRASMISSION-UNATTEN 138.00 69.00 46.00
31 BOOKCLIFFS SUB TRANSMISSION-UNATTEN 69.00 46.00
32 CAMERON SUB ..TRANSMISSION-UNATTEN 138.00 46.00
33 CAMP WILLIAMS SUB TRANSMISSION-UNATTEN 345.00 138.00 12.47
34 CARBON SUB TRANSMISSION-UNA TTEN 46.00 2.40
35 COLUMBIA SUB TRANSMISSION-UNATTEN 138.00 46.00
36 CRANER FLAT SUB TRANSMISSION-UNATTEN 138.00 12.47
37 CUTLER SUB TRANSMISSION-UNATTEN 138.00 46.00
38 EL MONTE SUB TRANSMISSION-UNATTEN 138.00 46.00
39 GARKANESUB TRANSMISSION-UNATTEN 69.00 46.00
40 GREEN CANYON SUB TRANSMISSION-UNATTEN 138.00 46.00
FERC FORM NO.1 (ED. 12-96)Page 426.18
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2009/Q4
(2)DA Resubmission 04/14/2010
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 equipmentôperated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(Î)ü)(k)
340 4 1
135 3 2
97 2 ;3
51 7 4
180 3 .5.
34 4 6
100 2 7
3 4 3 8
600 5 9
358 4 10
1108 6 2 11
130 2 12
158 3 13
30 1 14.
4358 72 5 .15
16
17
25 1 18
225 5 19
783 13 1 20
568 17 21.
318 2 22
1513 5 1 23
981 4 24
1538 6 1 25
67 1 26
133 2 27
100 1 28
1813 5 29
100 2 30.
6 ..3 1 31
25 3 32
169 2 33
8 1 34
33 1 35
40 2 36
70 2 37
313 3 38
33 1 39
67 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.18
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2009/Q4
(2) j"A Resubmission 04/14/2010
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 (t).
.
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 GRINDING SUB TRANSMISSION-UNATTEN 138.00 13.80
2 HELPER SUB .TRANSMISSION-UNA TTEN 138.00 46.00
3 HONEYVILLE SUB TRANSMISSION-UNA TTEN 138.00 46.00
4 HORSESHOE SUB TRANSMISSION-UNA TTEN 138.00 46.00 12.47
5 HUNTINGTON SUB TRANSMISSION-UNA TTEN 345.00 138.00 69.00
6 JERUSALEM SUB TRANSMISSION-UNA TTEN 138.00 46.00
7 LAMPO SUB TRANSMISSION-UNATTEN 138.00 46.00
8 MCFADDEN SUB TRANSMISSION-UNATTEN 138.00 46.00
9 MIDDLETON SUB TRANSMISSION-UNATTEN 138.00 69.00 34.50
10 MIDVALLEY SUB TRANSMISSION-UNA TTEN 345.00 138.00
11 MIDWAY CITY SUB TRANSMISSION-UNATTEN 138.00 46.00
12 MINERAL PRODUCTS SUB TRANSMISSION-UNA TTEN 69.00 46.00
13 MOAB SUB TRANSMISSION-UNA TTEN 138.00 69.00
14 NEBOSUB TRANSMISSION-UNATTEN 138.00 46.00
15 OLMSTED SUB TRANSMISSION-UNA TTEN 46.00 2.40
16 PAROWAN VALLEY SUB TRANSMISSION-UNA TTEN 230.00 138.00 34.50
17 PAVANT SUB TRANSMISSION-UNATTEN 230.00 46.00
18 PINTO SUB TRANSMISSION-UNATTEN 345.00 138.00 69.00
19 RED BUTTE SUB TRANSMISSION-UNATTEN 230.00 138.00
20 SAND COVE HYDRO TRANSMISSION-UNATTEN 34.50 2.40
21 SIGURD SUB TRANSMISSION-UNATTEN 345.00 230.00 138.00
22 SMITHFIELD SUB TRANSMISSION-UNATTEN 138.00 46.00 12.47
23 SPANISH FORK SUB TRANSMISSION-UNATTEN 345.00 138.00 46.00
24 ST GEORGE SUB TRANSMISSION-UNA TTEN 138.00 16.50
25 WEBER PLANT/SUB TRANSMISSION-UNA TTEN 46.00 2.30
26 WESTCEDAR SUB TRANSMISSION-UNATTEN 230.00 138.00 34.50
27 Total 8521.50 3089.24 761.91
28 Number of Substations- 49
29
30 Washington
31 ATTAllA SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 BOWMAN SUB DISTRIBUTION-UNATTEN 69.00 12.47
33 CASCADE KRAFT SUB DISTRIBUTION-UNA TTEN 69.00 12.47 4.16
34 CLINTON SUB DISTRIBUTION-UNATTEN 115.00 12.47
35 DAYTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 DODD ROAD SUB DISTRIBUTION-UNA TTEN 69.00 20.80
37 GRANDVIEW SUB DISTRIBUTION-UNATTEN 115.00 12.47 69.00
38 HOPLAND SUB DISTRIBUTION-UNATTEN 115.00 12.47
39 MILL CREEK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
40 NACHES HYDRO DISTRIBUTION-UNATTEN 115.00 12.47
.
FERC FORM NO.1 (ED. 12-96)Page 426.19
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) r=A Resubmission 04/14/2010
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Type of Equipment Number of Units Total Capacity No.In Service Transformers
(In MVa)
(f)(g)(h)(i)0)(k)
225 3 1.
142 2 2.
35 1 3
80 2 4
270 4 5
67 1 6
75 1 ....7
45 1 8
141 4 9
900 2 10
67 1 11
13 .,.
1 12
67 1 13
67 1 14
15 1 15
138 2 16
133 2 17
258 3 18
i 400 1 19
1 20
1124 6 21
63 2 22
1017 5 23
100 3 1 24
7 1 25
131 2 26
14508 138 5 27
28
29
30
25 1 31
45 2 32
117 6 33
25 1 34
23 2 35
25 4 .36
56 2 37
. ..50 2 38
45 2 39
20 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.19
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
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 accrding to
functional character, but the number of such substations must be shown.
4. Indicate incolumn (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 ståtions in
column (t).
Line -VOLTAGE (In MVa)Name and Location of Substation Character of Substation. No.Pnmary Secondary Tertiary
(a)(b)(c)(d)(e)
1 NOB HILL SUB DISTRIBUTION-UNATTEN 115.00 12.47
2 NORTH PARK SUB DISTRIBUTION-UNATTEN 115.00 12.47
3 ORCHARD SUB DISTRIBUTION-UNA TTEN 115.00 12.47
4 PACIFIC SUB DISTRIBUTION-UNATTEN 115.00 12.47
5 POMEROY SUB DISTRIBUTION-UNATTEN 69.00 12.47
6 PROSPECT POINT SUB DISTRIBUTION-UNATTEN 69.00 12.47
7 PUNKIN CENTER SUB DISTRIBUTION-UNA TTEN 115.00 12.47
8 RIVER ROAD SUB DISTRIBUTION-UNATTEN 115.00 12.47
9 SELAH SUB DISTRIBUTION-UNATTEN 115.00 12.47
10 SULPHUR CREEK SUB DISTRIBUTION-UNATTEN 115.00 12.47
11 SUNNYSIDE SUB DISTRIBUTION-UNATTEN 115.00 12.47
12 TIETON SUB DISTRIBUTION-UNATTEN 115.00 12.47 34.50
13 TOPPENISH SUB DISTRIBUTION-UNATTEN 115.00 12.47
14 TOUCHET SUB DISTRIBUTION-UNATTEN 69.00 12.47
15 VOELKER SUB DISTRIBUTION-UNATTEN 115.00 12.47
16 WAITSBURG SUB DISTRIBUTION-UNA TTEN 69.00 12.47
17 WAPATO SUB DISTRIBUTION-UNA TTEN 115.00 12.47
18 WENASSUB DISTRIBUTION-UNATTEN 115.00 12.47
19 WHITE SWAN SUB DISTRIBUTION-UNATTEN 115.00 12.47
20 WILEY SUB DISTRIBUTION-UNATTEN 115.00 12.47
21 Total 2990.0C 382.43 107.66
22 Number of Substations- 30
23
24 CENTRAL SUB TID-UNATTENDED 69.00 12.47
25 UNION GAP SUB TID-UNATTENDED 230.00 115.00 12.47
26 Total 299.00 127.47 12.47
27 Number of Substations- 2
28
29 CONDIT PLANT TRANSMISSION-ATTENDE 69.00 2.30
30 MERWIN PLANT TRASMISSION-ATTNDE 115.00 13.20
31 YALE PLANT TRANSMISSION-ATTENDE 230.00 13.80
32 OUTLOOK SUB TRASMISSION-UNATTEN 230.00 115.00
33 PASCO SUB TRANSMISSION-UNA TTEN 115.00 69.00 7.20
34 POMONA HEIGHTS SUB TRANSMISSION-UNA TTEN 230.00 115.00
35 SWIFT 1 PLANT .TRANSMISSION-UNA TTEN 230.00 13.00
36 WALLA WALLA 230KV SUB TRANSMISSION-UNA TTEN 230.00 69.00
37 WALLULA SUB TRASMISSION-UNATTEN 230.00 69.00
38 WINE COUNTRY SUB TRNSMISSION-UNATTEN 230.00 115.00
39 Total 1909.00 594.30 7.20
40 Number of Substations- 10 -
FERC FORM NO.1 (ED. 12-96)Page 426.20
Name of Respondent This 780rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010
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 òthers, 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 èxpenses 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 .Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
42 2 1..
45 2 2
.50 2 3
28 3 4
9 1 5~ .
40 2 6
20 2 7
51 4 8
45 2 9
25 1 10
45 2 11
29 2 12
50 2 13
6 1 14
25 1 15
9 1 16
45 2 17
25 2 18
22 2 19
45 2 20
1087 61 21
..22
23
14 1 24
348 5 25
362 6 26
27
.28
13 6 1 29
183 9 1 30
144 3 1 31
125 1 32
39 9 33
300 2 34
261 3 1 35
300 2 36
120 2 37
250 1 38
1735 38 4 39
40
...
FERC FORM NO.1 (ED. 12-96)Page 427.20
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
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, summarie accrding to functon the capacities reported for the individual stations in
column (t).
Une VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1
2 Wyoming .
3 AIR BASE DISTRIBUTION-UNATIEN 12.47 2.40
4 ANTELOPE MINE DISTRIBUTION-UNATIEN 230.00 34.50
5 ASTLE STREET DISTRIBUTION-UNA TIEN 34.50 13.20
6 BAILEY DOME SUB DISTRIBUTION-UNA TIEN 57.00 12.47
7 BARXSUB DISTRIBUTION-UNATIEN 230.00 34.50
8 BID MUDDY SUB DISTRIBUTION-UNATIEN 69.00 .12.47
9 BIG PINEY SUB.DISTRIBUTION-UNATIEN 69.00 24.90
10 BLACKS FORK DISTRIBUTION-UNA TIEN 230.00 34.50
11 BRIDGER PUMP SUB DISTRIBUTION-UNA TIEN 230.00 34.50 13.20
12 BRYAN SUB DISTRIBUTION-UNA TIEN 115.00 12.47
13 BUFFALO TOWN SUB DISTRIBUTION-UNATIEN 20.80 4.16
14 BYRON SUB DISTRIBUTION-UNATIEN 34.50 4.16
15 CASSASUB DISTRIBUTION-UNATIEN 57.00 20.80
16 CENTER STREET SUB .DISTRIBUTION-UNA TIEN 115.00 4.16
17 CHAPMAN SUBSTATION DISTRIBUTION-UNATIEN 46.00 12.47
18 CHATHAM SUB DISTRIBUTION-UNATIEN 34.50 4.16
19 CHUKARSUB DISTRIBUTION-UNATIEN 12.47 4.16
20 CHURCH AND DWIGHT SUB DISTRIBUTION-UNATIEN 34.50 0.48 .
21 COKEVILLE SUB DISTRIBUTION-UNA TIEN 46.00 24.90
22 COLUMBIA-GENEVA SUB DISTRIBUTION-UNA TIEN 230.00 13.80
23 COMMUNITY PARK SUB DISTRIBUTION-UNATIEN 69.0C 12.47
24 CROOKS GAP SUB DISTRIBUTION-UNATIEN 34.50 12.47
25 DEER CREEK SUB DISTRIBUTION-UNATIEN 69.00 12.47
26 DJ COAL MINE SUB D1STRIBUTION-UNATIEN 69.00 34.50
27 DOUGLAS SUB DISTRIBUTION-UNATIEN 57.00 2.30
28 DRY FORK SUB DISTRIBUTION-UNATIEN 69.00 4.16
29 ELK BASIN SUB DISTRIBUTION-UNATIEN 34.50 7.20
30 ELKHORN SUB DISTRIBUTION-NATIEN 115.00 12.50
31 EMIGRANT SUB DISTRIBUTION-UNATIEN 115.00 12.47 .. ...
32 EVANS SUB DISTRIBUTION-UNATIEN 69.00 12.47
33 EVANSTON SUB DISTRIBUTION-UNA TIEN 138.00 12.47
34 FARMERS UNION SUB DISTRIBUTION-UNATIEN 34.50 4.16
35 FIREHOLE SUB DISTRIBUTION-UNATIEN 230.00 34.50
36 FORT CASPER SUB DISTRIBUTION-UNATIEN 69.00 12.47
37 FORT SANDERS SUB DISTRIBUTION-UNATIEN 115.00 13.20
38 FRANNIE SUB DISTRIBUTION-UNATIEN 230.00 34.50
39 FRONTIER SUB DISTRIBUTION-UNATIEN 69.00 4.16
40 GARLAND SUB DISTRIBUTION-UNATIEN 230.00 34.50
FERC FORM NO.1 (ED. 12-96)Page 426.21
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
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 ormajor items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
1
2
1 3 .3
25 1 4
13 1 5
2 1 6
25 1 7
7 1 8
8 1 9
150 2 .10
73 4 11
25 1 12
2 3 13
2 3 14
2 6 1 15
13 1 16
4 1
.17
3 18
1 3 19
3 2 20
4 1 21
45 2 22
40 2 23
5 3 24
9 1 25
13 1 26
6 3 27
9 1 28
5 ..1 29
.25 1 30
13 1 31
9 1 32
40 2 33
2 3 34
50 2 35
25 1 36
20 1 37
50 2 38
.6 1 39
45 2 40
FERC FORM NO. 1 (ED. 12-96)Page .427.21
Name of Respondent This ~ort Is:Date of Report Year/Penod of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2009/Q4
(2) ñA Resubmission 04/14/2010
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 thè page, summarize accrding to function the capacities reported for the individual stations in
column (t).
..
VOLTAGE (In MVa) Line Name and Location of Substation Character of SubstationNo.Primar Secondary Tertiary
(a)(b)(c)(d)(e)
1 GLENDO SUB DISTRIBUTION-UNATTEN 57.00 4.16
2 GRAS CREEK SUB DISTRIBUTION-UNATTEN 230.00 34.50
3 GRET DIVIDE SUB DISTRIBUTION-UNATTEN 115.00 34.50
4 GREYBULL SUB DISTRIBUTION-UNA TTEN 34.50 4.16
5 HANNA SUB DISTRIBUTION-UNA TTEN 34.50 12.47
6 JACKALOPE SUB DISTRIBUTION-UNA TTEN 115.00 12.47
7 KEMMERER SUB DISTRIBUTION-UNA TTEN 69.00 24.90
8 KIRBY CREEK PUMPING STATION DISTRIBUTION-UNA TTEN 34.50 2.40
9 KIRBY CREEK SUB DISTRIBUTION-UNA TTEN 34.50 4.16
10 LANDER SUB DISTRIBUTION-UNA TTEN 34.50 12.47
11 LARAMIE SUB DISTRIBUTION-UNATTEN 115.00 13.20
12 LATHAM SUB DISTRIBUTION-UNATTEN 230.00 34.50
13 LINCH SUB DISTRIBUTION-UNATTEN 69.00 13.80
14 LITTLE MOUNTAIN SUB DISTRIBUTION-UNA TTEN 230.00 34.50
15 LOVELL SUB DISTRIBUTION-UNATTEN 34.50 4.16
16 MILL IRON SUB DISTRIBUTION-UNATTEN 34.50 13.80
17 MILLS SUB DISTRIBUTION-UNA TTEN 12.47 4.16
18 MURPHY DOME SUB DISTRIBUTION-UNA TTEN 34.50 13.20
19 NUGGETTSUB DISTRIBUTION-UNA TTEN 69.00 7.20
20 OPAL SUB DISTRIBUTION-UNA TTEN 46.00 24.90
21 ORIN SUB DISTRIBUTION-UNATTEN 57.00 12.47
22 ORPHASUB DISTRIBUTION-UNATTEN 57.00 7.20
23 PARCO SUB DISTRIBUTION-UNATTEN 34.50 12.47
24 PINEDALE SUB DISTRIBUTION-UNATTEN 69.00 24.90
25 PITCHFORK SUB DISTRIBUTION-UNATTEN 69.00 24.90
26 POINT OF ROCKS SUB DISTRIBUTION-UNATTEN 230.00 34.50
27 POISON SPIDER SUB DISTRIBUTION-UNA TTEN 69.00 2.40
28 POLECAT SUB DISTRIBUTION-UNA TTEN 34.50 12.47
29 RAINBOW SUB DISTRIBUTION-UNATTEN 34.50 13.20
30 RAVEN SUB DISTRIBUTION-UNA TTEN 230.00 34.50
31 RED BUTTE SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 REFINERY SUB DISTRIBUTION-UNA TTEN 115.00 12.47
33 SAGE HILL SUB DISTRIBUTION-UNATTEN 34.50 13.20
34 SHOSHONI SUB DISTRIBUTION-UNATTEN 34.50 2.40
35 SLATE CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 SOUTH CODY SUB DISTRIBUTION-UNA TTEN 69.00 24.90
37 SOUTH ELK BASIN SUB DISTRIBUTION-UNATTEN 34.50 4.16
38 SOUTH TRONA SUB DISTRIBUTION-UNATTEN 230.00 34.50
39 SPRING CREEK SUB DISTRIBUTION-UNATTEN 115.00 13.20
40 SVILARSUB DISTRIBUTION-UNATTEN 34.50 4.16
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 2009/Q4
(2) OA Resubmission 04/14/2010
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.
Capacity of Substation Numberof Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line.
(In Service)(In MVa)
Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
3 4 .1
25 1 2
20 1 3
3 1 .4
6 1
.5
25 1 6
10 1 7
3 3 8
2 3 9
25 2 10
50 2 11
25 1 12
13 1 13
20 1 14
4 3 15
13 1 1 16
1 3 17
5 1 18
1 19
8 1 20
2 3 21
3 3 22
5 1 23
.8 1 24
17 9 2 25
25 1 26
3 1 27
2 3 28
13 1 29
200 2 30
20 1 31
45 2 32
6 1 33
2 3 34
1 1 35
14 . 3 1 36
2 6 37
150 2 38
25 1 39
2 3 40
FERC FORM NO.1 (ED. 12-96)Page 427.22
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
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 (t).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 TEN MILE STEP DOWN SUB DISTRIBUTION-UNA TTEN 34.S(12.50
2 TEN MILE SUB DISTRIBUTION-UNATTEN 69.0(34.50
3 THERMOPOLIS TOWN SUB DISTRIBUTION-UNATTEN 34.50 4.16
4 THUNDER CREEK SUB DISTRIBUTION-UNATTEN 57.00 12.47
5 VETERANS SUB DISTRIBUTION-UNATTEN 34.50 13.20
6 WELCH SUB DISTRIBUTION-UNA TTEN 57.00 2.40
7 WERTZ-SINCLAIR SUB DISTRIBUTION-UNA TTEN 57.00 4.16 12.50
8 WEST ADAMS SUB DISTRIBUTION-UNATTEN 34.50 4.16
9 WESTERN CLAY SUB DISTRIBUTION-UNATTEN 34.50 0.48
10 WESTVACO SUB DISTRIBUTION-UNATTEN 230.00 34.50
11 WORLAND TOWN SUB DISTRIBUTION-UNATTEN 34.50 4.16
12 WYOPOSUB DISTRIBUTION-UNATTEN 230.00 34.50
13 WYUTASUB DISTRIBUTION-UNATTEN 46.00 12.47
14 Total 8000.21 1378,34 25.70
15 Number of Substations- 91
16
17 BUFFALO SUB TID-UNATTENDED 230.00 20.80
18 HILLTOP SUB TID-UNATTENDED 115.0C 34.50 20.80
19 LABARGE SUB TID-UNATTENDED 69.00 24.90
20 RIVERTON 230 SUB TID-UNATTENDED 230.0C 12.47 34.50
21 YELLOWCAKE SUB TID-UNATTENDED 230.00 34.50
22 Total .874.00 127.17 55.30
23 Number of Substations- 5
24
25 DAVE JOHNSTON PLANTISUB TRANSMISSION-ATTENDE 230.00 115.00 69.00
!RASMISSION-ATTENDE 345.00 230.00 34.50
27 JIM BRIDGER UNITS 1-4 TRANSMISSION-ATTENDE 345.00 22.00
TRANSMISSION-A TTENDE 230.00 69.0029 TRANSMISSION-ATTENDE 230.00 69.0030 WYODAK PLANT TRANSMISSION-ATTENDE 230.00 22.00
31 BAIROIL SUB TRASMISSION-UNATTEN 115.00 34.50 57.00
32 CASPER SUB TRASMISSION-UNATTEN 230.0C 115.00 69.00
33 CHAPPELL CREEK SUB TRASMISSION-UNATTEN 230.00 69.00
34 CHIMNEY BUTTE SUB TRANSMISSION-UNATTEN 230.00 69.00
35 FOOTE CREEK WIND FARM TRANSMISSION-UNATTEN 23O.0C 34.50
36 GLENDO AUTO SUB .TRANSMISSION-UNATTEN 69.00 57.00
37 MANSFACE SUB TRANSMISSION-UNA TTEN 230.00 34.50
38 MIDWEST SUB TRANSMISSION-UNA TTEN 230.00 69.00 34.50
39 MINERS SUB TRANSMISSION-UNA TTEN 230.00 115.00 34.50
40 MUSTANG SUB TRANSMISSION-UNATTEN 230.0(115.00
...
FERC FORM NO.1 (ED. 12-96)Page 426.23
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
. PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) OA Resubmission 04/14/2010 .
SUBSTATIONS (Continued)
5. Show in columns (i), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Servce)(In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
.5 1 1
13 1 2
5 1 3
9 1 .4
25 2 5
3 3 6
2 6 7
3 1 8
1 1 9
25 1 10
5 1 11
20 1 1 12
1 13
1699 172 6 14
15
16
20 1 17
45 2 1 18
8 6 19
50 3 20
25 1 21
148 13 1 22
23
.24
1358 17 25
1084 22 26
1122 2 27
1232 15 1 28
60 1 29
503 3 1 30
53 3 31
517 6 ...32.
67 1 33
75 1
.34
196 2 35
15 2 36
20 1
.37
91 4 38
58 4 1 39
200 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.23
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2009/Q4
(2) nA Resubmission 04/14/2010
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 OREGON BASIN SUB TRANSMISSION-UNA TTEN 230.00 34.50 69.00
2 PLATTE SUB TRANSMISSION-UNA TTEN 230.00 115.00 34.50
3 RAILROAD SUB TRANSMISSION-UNA TTEN 230.00 1:38.00
4 ROCK SPRINGS 230 SUB TRANSMISSION-UNATTEN 230.00 34.50
5 SAGE SUB TRANSMISSION-UNA TTEN 69.00 46.00
6 THERMOPOLIS SUB TRANSMISSION-UNATTEN 230.00 115.00
7 YELLOWTAIL SUB TRANSMISSION-UNA TTEN 230.00 161.00
8 Total 5083.00 1883.50 402.00
9 Number of Substations- 23
10
11 CALIFORNIA
12 Distribution - 43
13 TID - 3
14 Transmission - 9
15
16 IDAHO
17 Distribution - 67
18 TID -4
19 Transmission -18
20
21 OREGON
22 Distribution -183
23 TID - 10
24 Transmission - 41
25
26 UTAH .
27 Distribution -299
28 TID - 23
29 Transmission - 49
30
31 WASHINGTON
32 Distribution - 30
33 TID -2
34 Transmission - 10
35
36 WYOMING
37 Distribution - 91
38 TID -5
-
39 Transmission - 23
40
FERC FORM NO. 1 (ED. 12-96)Page 426.24
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2)nA Resubmission 04/14/2010
SUBSTATIONS (Continued)..
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity,
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
65 2 1
165 4 2
.400 1 3
50 2 4
22 1 5
.
175 2 6
100 1 7
7628 99 3 8
9
10
11
337 12
129 13
696 14
15
16
799 17
314 18.
3315 19
20
21
4506 22
1238 23
6367 24
25.
26
5564 27
4358 28
14508 29
30
--31
1087 .32
362 33
1735 34
35
36
1699 37
148 38
7628 39
40
FERC FORM NO. 1 (ED. 12-96)Page 427.24
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) ñA Resubmission 04/14/2010
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 (t).
Une VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 ALL STATES .
2 Ditriution - 713
3 T/D -47
4 Transmission - 150
5 .
6
7
8
9
10
11
12
13
14
15 .
16
17 .
18
19
20
21
22
23
24
25
26
27
28
29
30 .
31
32
33
34
35
36
37
38
39
40 ..
FERC FORM NO. 1 (ED. 12-96)Page 426.25
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) (KAn Original (Mo, Da, Yr)End of 2009/Q4
(2) riA Resubmission 04/14/2010
..SUBSTATIONS (Continued)
5. Show in columns (1),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 party is an associated company.
.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service)(In MVa)
Transformers Spare Type of Equipment Number of Units Total Capacity No.In Service Transformers (In MVa)
(f)(g)(h)(i)ul (k)
1
13992 2.
6549 3.
34249 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
FERC FORM NO.1 (ED. 12-96)Page 427.25
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp . (2) A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
¡Schedule Page: 426.9 Line No.: 23 Column: a
The Dixonvile 500kV Substation is jointly owned by the respondent and the Bonnevile Power Admnistraton (the "BP A").
Ownership of the substation is as follows: PacifiCorp 50.0% and the BPA 50.0%. Operation and maintenance costs are shared
between the two paries and responsibility is as follows:PacifiCorp 58.0% and the BP A 42.0%.
Išchedule Page: 426.9 Line No.: 35 Column: a
TheMeridian 500kV Substation is jointly owned by the respondent and the Bonnevile Power Admnistration (the "BPA").
Ownership of the substation is as follows: PacifiCorp 50.0% and the BPA 50.0%. Operation and maintenance costs are shared
between the two paries and responsibility is as follows: PacifiCorp 58.0% and the BPA 42.0%.
Išchedule Page: 426.23 Line No.: 26 Column: a I
The Jim Bridger 345kV Substation is jointly owned by the respondent and Idaho Power Company. Ownership of the substation is as
follow: PacifiCorp 66.7% and Idao Power Company 33.3%. Operation and maintenance costs are shared between the two paries
and responsibility is as follows: PacifiCorp 66.7% and Idao Power Company 33.3%.
Išchedule Page: 426.23 Line No.: 29 Column: a
The Wyodak 230kV Substation is jointly owned by the respondent and Black Hils Power. Ownerhip of the substation is as follows:
PacifiCorp 80.0% and Black Hils Power 20.0%. Operation and maintenance costs are shared between the two pares and
responsibility is as follows: PacifiCorp 80.0% and Black Hils Power 20.0%.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) r=A Resubmission 04/14/2010
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affliated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount biled to the respondent or biled to
an assocated/affilated company for non-power goods and services. The good or service must be specific in nature. Respondents should not
attempt to include or aggregate amounts in a nonspecific category such as "general".
3. Where amounts biled to or received from the associated (affliated) company are based on an allocation process, explain in a footnote.
Line Name of Accunt
Assiciated/ Affliated Charged or Amount
No.Description of the Non-Power Good or Service Company Credited Charged or Credited
(a)~1 Non.powerGoodsor Services Provided by Affliated
2 Long-term coal transporttion contracts
3 Right-of-way fees Burlington Northern::? Ii IiIi 24,872
4
5 Consulting and labor services 930.2,426.5, 107 ~'II!li¡iil,l~lI~~~~~~~,/.
6 .
7 Residential real estate brokerage and relocation
8 services !û'llli,ll,.I1¡!!¡¡I¡III,-786,589
9
10 Natural gas transportation services iif$em!0i~~i7'Cl",501,547 3,310,174
11
12 Captive propert and liabilty insurance iim~I-C ::V~;924,925 7,161,477
13
14 Coal ¡!I,IIIII!,))he.151 116,190,987
15 Labor services Pacific Minerals, Inc.511,232 200,802
16
17
18
19
20 Non-power Goods or Services Provided for Affliate
21 Labor and benefits services
22
23 Labor and other services Pacific Minerals, Inc.501,107 2,416,583
24 Management fee Pacific Minerals, Inc.557 1,205,173
25 .
26
27 ..
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
.
FERC FORM NO.1 (New)
FERC FORM NO. 1.F (New)
Page 428
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp (2)A Resubmission 04/14/2010 2009/Q4
FOOTNOTE DATA
!Šchedule Page: 429 Line No.: 2 Column:
This footnote applies to all occurences of "Burlington Norter" on page 429: Complete name is BurlingtonNorthem Santa Fe
Corporation ("BNSF").
owned subsidia ofMEHC.
owned subsidi ofMEHC.
I FERC FORM NO. 1 (ED. 12-87)Page 450.1
INDEX
Schedule Page No.
Accrued and prepãid 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
Capi tal Stock ........................................................................................ 251
expense ...................;...................................................................... 254
premiums ......................................................................................... 252
reacquired ....................................................................................... 251
subscribed ....................................................................................... 252
Cash flows, statement of ......................................................................... 120-121
Changes
important during year ........................................................................ 108-109
Construction
work in progress - common utility plant .......................................................... 356
work in progress - electric ...................................................................... 216
work in progress - other utility departments ................................................. 200-201
Control
corporations controlled by respondent ............................................................ 103
over respondent .................................................................................. 102
Corporation
controlled by .................................................................................... 103-
incorporated ..................................................................................... 101
CPA, background infòrmation on ....................................................................... 101
CPA Certification, this report form .............................................................,... i-ii
FERC FORM NO. 1 (ED. 12-93)Index
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 common utility plant .......................................................................... 356
of electric plant ................................................................................ 219
336-337
Directors ............................................................................................ 105
Discount - premium on long-term debt ............................................................. 256-257
Distribution of salaries and wages ............................................................... 354-355
Dividend appropriations .......................................................................... 11S-119
Earnings, Retained ............................................................................... 11S-119
Electric energy account .............................................................................. 401
Expenses
electric operation and maintenance ........................................................... 320-323
electric öperation and maintenance, summary ...................................................... 323
unamortized debt ................................................................................. 256
Extraordinary property losses ........................................................................ 230
Filing requirements, this report form
General information .................................................................................. 101
Instructions for filing the FERC Form 1 ............................................................. i-iv
Generating plant statistics
hydroelectric (large) ........................................................................ 406-407
pumped storage (large) ....................................................................... 40S-409
small plants ................................................................................. 410-411
steam-electric (large) ....................................................................... 402-403
Hydro-electric generating plant statistics ....................................................... 406-407
Identification ....................................................................................... 101
Important changes during year .................................................................... 10S-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
capi tal 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)Index 3
INDEX (continued)
Schedule Page No.
Plant - electric
accumulated provision for depreciation ........................................................... 219
construction work in progress .................................................................... 216
held for future use .............................................................................. 214
in service ................................................................................... 204-207
leased to others ................................................................................. 213
Plant - utility and accumulated provisions for depreciation
amortization and depletion (summary) ............................................................. 201
Pollution control facilities, accumulated deferred
income taxes ..................................................................................... 234
Power Exchanges .................................................................................. 326-327
Premium and discount on long-term debt ................. .,............................................ 256
Premium on capital stock ............................................................................. 251
Prepaid taxes .................................................................................... 262-263
Property - losses, extraordinary ..................................................................... 230
Pumped storage generating plant statistics ....................................................... 408-409
Purchased power (including power exchanges) ...................................................... 326-327
Reacquired capital stock ............................................................................. 250
Reacquired long-term debt ........................................................................ 256-257
Receivers' certificates .......................................................................... 256-257
Reconciliation of reported net income with taxable income
from Federal income taxes ...................................................................... 261
Regulatory commission expenses deferred .............................................................. 233
Regulatory commission expenses for year .......................................................... 350-351
Research, development and demonstration activities ............................................... 352-353
Retained Earnings
amortization reserve Federal ..................................................................... 119
appropriated ................................................................................. 118-119
statement of, for the year................................................................... 118-119
unappropriated ............................................................................... 118-119
Revenues - electric operating .................................................................... 300-301
Salaries and wages
directors fees ................................................................................... 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)Index 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. 12-90)Index 5
~ROCKY MOUNTAINPOR
A OMIO Of PACtACOP RECE ¡:n
201 Sout Main, Suit 2300
Salt Lake Cit, Uth 84111
iOlOMAY 28 AM II: 30
May 28, 2010
VI OVERNIGHT DELIVERY
Idaho Public Utilties Commssion
472 West Washigton
Boise, il 83702-5983,
Attention:Jean D. Jewell
Commssion Secreta
Re:Commission Annual Report 2009
Rocky Mounta Power, a division ofPacifiCorp, hereby submits for fiing an origial and seven
(7) copies of the Idaho Public Utilties Commssion Anua Report 2009. PacifiCorp's anua
FERC Form 1 was shipped for filing April 14,2010.
It is respectively requested that all formal correspondence and sta requests regarding ths matter
be addressed to:
By E-mail (preferred):dataequest(fPacifiCorp.com
By Fax:[phone]
By regular mail:Data Request Response Center
PacifiCorp
825 NE Multnomah Suite 2000
Portland, OR 97232
Any informal inquiries may be diected to Ted Weston, Idao Reguatory Manger at 801-220-
2963.
Sincerely,
n.no__. J¿¡ ~/~r0
Jeffery K. Laren
Vice President, Reguation
Page
Number
1
2
3 - 6
7
8
9
10
11 - 12
13
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM NO.1
FOR
MULTI-STATE ELECTRIC COMPANIES 28ìU HAY 28
INDEX
Title
Statement of Operating Income for the Year
Electric Operating Revenues
Electric Operation and Maintenance Expenses
Depreciation and Amortization of Electric Plant
Taxes, Other Than Income Taxes
Non-Utility Propert
Summary of Utility Plant and Accumulated Provisions
Electric Plant in Service
Materials and Supplies
M 559 (11000) (12/96)Paç¡ej
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) .. An Original (Mo, Da, Yr)dba Rocky Mountain Power (2) _ A resubmission May 26, 2010 Dec. 31, 2009
STATE OF IDAHO STATEMENT OF OPERATING INCOME FOR THE YEAR
ELECTRIC UTILITY
Line ACCOUNT (Ref)
No.Page
No.Current Year Previous Year
(a)(b)(c)(d)
1 UTILITY OPERATING INCOME
2 Operatina Revenues (400)2 232,599,319 255,576,999
3 Operatina Expenses
4 Operation Expenses (401)3-6 131,123,707 157,693,957
5 Maintenance Expenses (402)3-6 20,753,478 20,302,529
6 Depreciation Expenses (403) (A)7 23,075,971 22,141,858
7 Amort. & Depl. of Utiltv Plant 1404-405)7 1,552,773 2,155,279
8 Amort. of Utilitv Plant ACQ. Adi (406)278,175 318,186
Amort. of Propert Losses, Unrecovered
9 Plant and Regulatory Study Costs (407)280,737 336,221
10 Amort. of Conversion Expenses (407)--
11 Taxes other Than Income Taxes (408.1) iS)8 5,041,687 4,904,875
12 Income Taxes - Federal (409.1)(10,134,445 14,773,615
13 -Other 1409.1)11,343,396)(417,772
14 Provision for Deferred Income Taxes (410.1)45,893,908 30,632,497
15 Provision for Deferred Income Taxes - Cr. 1411.1)(18,372,660 (14,829,314)
16 InvestmentTax Credit Adj. - Net (411.4)(190,629 (219,739
17 (Gains) frm Disp. of Utility Plant (411.6)--
18 Losses from Disp. of Utiltv Plant 1411.7)--
19 (Gains) from Emission Allowances (215,192 (315,306
20 lGains) Loss on Sale of Utilitv Plant 151,349 1103,876
TOTAL Utility Operating Expenses
21 (Enter Total of Lines 4 thru 20)197,692,765 217,825,780
Net Utility Operating Income (Enter Total of ....
22 line 2 less 21)34,906,554 37,751,219
(A) Vehicle depreciation is charged to functional accounts.
Payroll taxes are charged to functional accounts, which is consistent with where labor is charged.
IDAHO SUPPLEMENT Page 1
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Name of Respondent This Repor Is:Date of Report Year of Report
PacifiCorp (1 )..An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2)-A resubmission May 26,2010 Dec. 31, 2009
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES -IDAHO
.
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 500 Operation Supervision and Enoineerino 1,086,939 1,266,099
5 501 Fuel 35,154,665 40,122,749
6 502 Steam Expenses 1,809,879 2,170,220
7 (503) Stèam from Other Sources 204,218 217,429
8 Less) (504) Steam Transferred. Cr..-
9 505) Electric Expenses 199,838 247,630
10 506) Miscellaneous Steam Power Expenses 2,213,516 2,525,521
11 507) Rents 22,869 16,334
12 TOTAL Operation (Enter Total of lines 4 thru 11)40,691,924 46,565,982
13 Maintenance
14 510) Maintenance Supervision and Engineering 305,774 346,029
15 511 Maintenance of Structures .1,160,095 1,440,505
16 512 Maintenance öf Boiler Plant 4,798,961 5,024,482
17 513 Maintenance of Electric Plant 1,712,848 1,674,389
18 514) Maintenance of Miscellaneous Steam Plant 648,040 735,467
19 TOTAL Maintenance (Enter Total of lines 14 thru 18)8,625,718 9,220,872
20 TOTAL Power Production Expenses. Steam Power (Enter Total of lines 12 & 19)49,317,642 55,786,854
21 B. Nuclear Power Generation
22 Operation
23 (517) Operation Supervision and Engineerino --
24 518) Fuel .-
25 519) Coolants and Water -
26 520) Steam Expenses --
27 (521) Steam from Other Sources .-
28 (Less) (522) Steam Transferred. Cr...
29 (523) Electric Expenses .-
30 524) Miscellaneous Nuclear Power Expenses .-
31 (525) Rents .-
32 TOTAL Operation (Enter Total of lines 23 thru 31)..
33 Maintenance
34 528) Maintenance Supervision and Engineering --
35 529) Maintenance of Structures -.
36 530) Maintenance of Reactor Plant Equipment ..
37 531) Maintenance of Electric Plant .-
38 (532) Maintenance of Miscellaneous Nuclear Plant .-
39 TOTAL Maintenance (Enter Total of lines 34 thru 38).-
40 TOTAL Power Production Expenses - Nuclear Power (Enter Total of lines 32 & 39)--
41 C. Hydraulic Power Generation
42 Operation
43 535) Operation Supervision and Enoineerino 476,467 512,537
44 536) Water for Power 14,733 17,502
45 (537) Hydraulic Expenses 178,632 237,533
46 538) Electric Expenses --
47 539) Miscellaneous Hvdraulic Power Generation Expenses 893,500 1,036,304
48 540) Rents 9,313 8,202
49 . TOTAL Operation (Enter Total of Iinès 43 thru 48)1,572,645 1,812,078
IDAHO SUPPLEMENT Page 3
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) i An Original (Mo, Da,Yr)dba Rocky Mountain Power (2) _A resubmission May 26, 2010 Dec. 31, 2009
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES -IDAHC
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
..Line Amount for Amount for
No.Account Current Year Previous Year
(à)(b)(c)
50 C. Hvdraulic Power Generation (Continued)
51 Maintenance
52 (541) Maintenance Supervision and Engineering 4,283 156
53 542) Maintenance of Structures 61,282 71,146
54 543) Maintenance of Reservoirs, Dams; and Waterwavs 81,256 83,463
55 (544) Maintenance of Electric Plant 76,950 91,322
56 545) Maintenance of Miscellaneous Hvdraulic Plant 128,915 124,953
57 TOTAL Maintenance (Enter Total of lines 52 thru 56)352,686 371,040
58 TOTAL Power Production Expenses - Hvdraulic Power (Enter Total of lines 49 & 57)1,925,331 2,183,118
59 D. Other Power Generation
60 Operation
61 546) Operation Supervision and Engineering 16,092 12,686
62 547) Fuel 26,647,050 30,518,527
63 548) Generation Expenses 790,943 1,053,278
64 549) Miscellaneous Other Power Generation Expenses 946,101 635,509
65 550) Rents 94,492 408,480
66 TOTAL Operation (Enter Total of lines 61 thru 65)28,494,678 32,628,480
67 Maintenance .
68 551) Maintenance Supervision and Engineering --
69 552) Maintenance of Structures 77,422 75,393
70 553) Maintenance of Generation and Electric Plant 746,652 346,580
71 554) Maintenance of Miscellaneous Other Power Generation Plant 66,504 29,322
72 TOTAL Maintenance (Enter Total of lines 68 thru 71)890,578 451,295
73 TOTAL Power Production Expenses - Other Power (Enter Total of lines 66 & 72)29,385,256 33,079,775
74 E. Other Power Supply Expenses
75 (555) Purchased Power 25,479,413 45,333,059
76 556) Svstem Control and Load Dispatchina 76,886 116,018
77 (557) Other Expenses (1)5,364,703 7,644,461
78 TOTAL Other Power Supplv Expenses (Enter Total of lines 75 thru 77)30,921,002 53,093,538
79 TOTAL Power Production Expenses - (Enter Total of lines 20, 40, 58, 73 and 78)111,549,231 144,143,285
80 2. TRANSMISSION EXPENSES
81 Operation
82 560) Operation Supervision and Enaineering 309,104 453,452
83 (561) Load Dispatching 473,344 495,694
84 562 Station Expenses 76,481 108,582
85 563 Overhead Line Expenses 12,446 5,420
86 (564 Underground Line Expenses --
87 565 Transmission of Electricity bv Others 5,954,869 7,060,389
88 566) Miscellaneous Transmission Expenses 121,493 104,244
89 (567) Rents 84,121 47,772
90 TOTAL Operation (Enter Total of lines 82 thru 89)7,031,858 8,275,553
91 Maintenance
92 568 Maintenance Supervision and Engineering 1,800 570
93 569 Maintenance of Structures 206,145 239,765
94 (570 Maintenance of Station Equipment 535,580 644,177
95 571) Maintenance of Overhead Lines 996,067 941,044
96 572) Maintenance of Underground Lines 2,620 -
97 (573) Maintenance of Miscellaneous Transmission Plant 9,240 27,906
98 TOTAL Maintenance (Enter Total of lines 92 thru 97).1,751,452 1,853,42
99 TOTAL Transmission Expenses (Enter Total of lines 90 and 98)8,783,310 10,128,995
100 3. DISTRIBUTION EXPENSES
101 Ooeration
102 580\ Operation Supervision and Enaineering 945,046 894,939
103 (581) Load Dispatching 622,006 595,952
(1) The Idaho amounts in FERC account 557 are $2,505,779 for Current Year and $3,238,393 for Previous Year. However, these amounts have
been increased by $2,858,925 for Current Year and $4,406,068 for Previous year because of the estimated impact of the embedded cost
differentials on Idaho results.
IDAHO SUPPLEMENT Page 4
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) .l An Original (Mo,Da, Yr)dba Rocky Mountain Power (2) _A resubmission May 26,2010 Dec. 31, 2009
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
.(a)(b)(c)
104 3. DISTRIBUTION EXPENSES (Continued)
105 (582) Station Expenses 209,928 255,140
106 583) Overhead Line Expenses 302,758 162,592
107 584)Underaround Line Expenses --
108 (585) Street Liahtina and Sianal Svstem Expenses 9,587 10,351
109 586) Meter Expenses 305,876 397,340
110 587) Customer Installations Exoenses 448,940 709,324
111 (588) Miscellaneous Distribution Expenses 332,391 370,170
112 589) Rents 31,021 27,195
113 TOTAL Operation (Enter Total of lines 102 thru 112)3,207,553 3,423,003
114 Maintenance
115 590) Maintenance Supervision and Engineering 383,076 302,779
116 (591) Maintenance of Structures 153,547 118,918
117 592) Maintenance of Station Equipment 877,853 664,135
118 593) Maintenance of Overhead Lines 5,157,927 4,533,920
119 594) Maintenance of Underground Lines .733,133 646,670
120 595) Maintenance of Line Transformers 50,037 52,059
121 (596) Maintenance of Street Lightina and Sianal Systems 132,712 163,040
122 597) Maintenance of Meters 347,618 317,714
123 (598) Maintenance of Miscellaneous Distribution Plant 112,223 86,051
124 TOTAL Maintenance (Enter Total of lines 115 thru 123)7,948,126 6,885,286
125 TOTAL Distribution Expenses (Enter Total of lines 113 and 124)11,155,679 10,308,289
126 4. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
127 Ooeration
128 (901) Supervision 110,843 92,212
129 902) Meter Reading Expenses 1,682,422 1,807,158
130 903) Customer Records and Collection Expenses 2,226,934 2,155,564
131 904) Uncollectible Accounts 472,261 303,856
132 905) Miscellaneous Customer Accounts Expenses 9,391 8,556
133 TOTAL Customer Accunts Expenses (Enter Total of lines 128 thru 132)4,501,851 4,367,346
134 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
135 Operation
136 (907) Supervision 11,106 9,619
137 908) Customer Assistance Expenses 6,641,783 1,565,402
138 909) Informational and Instructional Expenses 177,389 154,192
139 910) Miscellaneous Customer Service and Informational Expenses 5,819 2,476
140 TOTAL Cust. Service and Informational Exp. (Enter Total of lines 136 thru 139)6,836,097 1,731,689
141 6. SALES EXPENSES
142 Operation
143 (9111 Supervision --
144 912) Demonstratina and Sellna Expenses ~. --
145 913) Advertising Expenses --
146 '916) Miscellaneous Sales Expenses --
147 TOTAL Sales Expenses (Enter Total of lines 143 thru 146)--
148 7. ADMINISTRATIVE AND GENERAL EXPENSES
149 Operation
150 920\ Administrative and General Salaries 4,940,778 1,953,895
151 1'9211 Offce Supplies and Expense 593,038 700,062
152 (Less) (922) Administrative Expenses Transferred - Cr.(1,322,151 (1,208,446
153 923 Outside Services Emplovee 564,232 667,017
154 (924 Propert Insurance ~1,225,216 1,788,804
155 925 Injuries and Damages 379,998 531,614
156 926 Emplovee Pensions and Benefis --
157 ~
IDAHO SUPPLEMENT Page 5
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) i An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) _ A resubmission May 26,2010 Dec. 31, 2009
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) -IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
157 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
158 (927) Franchise Requirements --
159 928) Regulatory Commission Expenses 647,365 543,491
160 929) Duolicate Charges - Cr.(174,852 (223,706
161 930.1) General Advertisino Expenses --
162 930.2) Miscellaneöus General Expenses 744,714 741,466
163 (931) Rents 267,761 302,091
164 TOTAL Operation (Enter Total of lines 150 thru 163)7,866,099 5,796,288
165 Maitenance
166 935) Maintenance of General Plant 1,184,918 1,520,594
167 TOTAL Administrative and General Expenses (Enter Total of lines 164 & 166)9,051,017 7,316,882
168 i U I AL i:iectnc uperation and Maintenance Expenses (Enter Total of lines 79, 99, 125,
133,140,147, and 167)151,877,185 177,996,486
SUMMARY OF ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
Line Functional Classifications Operation Maintenance Total
No.(a)(b)(c)(d)
169 Power Production Expenses
170 Electric Generation:
171 Steam Power 40,691,924 8,625,718 49,317,642
172 Nuclear Power --.
173 Hydraulic -Conventional 1,572,645 352,686 1,925,331
174 Other Power Generation 28,494,678 890,578 29,385,256
175 Other Power Supply Expenses 30,921,002 30,921,002
176 Total Power Production Expenses 101,680,249 9,868,982 111,549,231
177 Transmission Expenses 7,031,858 1,751,452 8,783,310
178 Distribution Expenses 3,207,553 7,948,126 11,155,679
179 Customer Accounts Expenses 4,501,851 4,501,851
180 Customer Service and Informational Expenses 6,836,097 6,836,097
181 Sales Expenses -.
182 Adm. and General Expenses 7,866,099 1,184,918 9,051,017
183 Total Electric Operation and Maintenance Expenses 131,123;707 20,753,478 151,877,185
IDAHO SUPPLEMENT Page 6
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) -e An Original (Mo, Da, Yr)dba Rocky Mountain Power (2) _ A resubmission May 26, 2010 Dec. 31, 2009
.
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Accounts 403, 404, 405)
(Except amortization of acquisition adjustments)
A. Summary of Depreciation and Amortization Charges
Line Depreciation Amortization of Amortization of
No.Functional Classification Expense Limited-Term Electric Other Electric Total
(Account 403) (A)Plant (Acc. 404)Plant (Acct. 405)
(a)(b)(c)(d)(e)
1 Intangible Plant 1,493,206 1,493,206
2 Steam Production Plant 5,571,210 5,571,210
3 Nuclear Production Plant -.
4 Hydraulic Production Plant - Conventional 784,381 784,381
5 Hydraulic Production Plant - Pumped StoraQe -.
6 Other Production Plant 4,921,190 2,385 4,923,575
7 Transmission Plant 3,192,949 3,192,949
8 Distribution Plant 6,682,658 6,682,658
9 General Plant 1,923,583 57,182 1,980,765
10 Common Plant - Electric .
11 TOTAL 23,075,971 1,552,773 -24,628,744
STATE OF IDAHO - ALLOCATED
(A) Vehicle depreciation is charged to functional accunts.
IDAHO SUPPLEMENT Page 7
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) i An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) _ A resubmission May 26,2010 Dec. 31, 2009
KIND OF TAX AMOUNT
.
1 Propert 4,463,130
2 Miscellaneous .578,557
3
4
5
6
.
7
8
9
10 .
11
12
13
14
15
16
17
18
19
20 Total ( Must agree with page 1, line 11.)5,041,687
STATE OF IDAHO - ALLOCATED
TAXES, OTHER THAN INCOME TAXES
ACCOUNT 408 1 (Ell
(B) Payroll taxes are charged to functional accounts, which is consistent with where labor is charged.
IDAHO SUPPLEMENT Page 8
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Name of Respondent This Report Is:Date of Report Year of ReportPacifiCorp(1) .l An Original (Mo, Da, Yr)dba Rocky Mountain Power (2) _ A resubmission May 26, 2010 Dec. 31, 2009
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(bj (c)
1 UTILITY PLANT
2 In Service
3 Plant In Service (Classified).951,922,513 955,902,116
4 Properl Under Capital Lease ill --
5 ...Plant Purchased or Sold 7,762,964 8,791,718
6 Completed Constructon not Classified 4,095,461 3,252,244
7 Experimental Plant Unclassifed --
8 Total (Enter Total of Lines 3 through 7)963,780,938 967,946,078
9 Leased To Others --
10 Held for Future Use 580,625 750,560
11 Construction Work In Process 91,972,627 67,820,539
12 Acquisition Adjustments 7,980,380 9,128,243
13 Total Utiltv Plant (Enter Total of Lines 8 throuah 12)1,064,314,570 1,045,645,420
14 Accumulated Provision for Deoreciation, Amortzation & Depletion 367,926,958 389,746,293
15 Net Utilitv Plant (Enter Total of Line 13 less Line 14)696,387,612 655,899,127
DETAIL OF ACCUMULATED PROVISION FOR DEPRECIATION, AMORTIZATION AND
16 DEPLETION
17 In Service
18 Depreciation 343,017,043 363,401,052
19 Amortization/Depletion of Producina Natural Gas Land And Land Rights --
20 Amortization of Underaround Storaae Land and Land Riahts --
21 Amortization of Other Utilitv Plant 20,158,701 21,228,818
22 .Total In Service (Enter Total of Lines 18 through 21)363,175,744 384,629,870
23 Leased To Others
24 Depreciation --
25 Amorttion And Deoletion --
26 Total Leased to Others (Enter Total of Lines 24 and 25)--
27 Held for Future Use
28 Depreciation --
29 Amortization -.-
30 Total Held for Future Use (Enter Total of Lines 28 and 29)--
31 Abandonment of Leases (Natural Gas)--
32 .Accumulated Provision for Asset Acquisition Adjustment 4,751,214 5,116,423
Tot Accumulated Provisions (Should Agree With Line 14 above) (Enter Total of Lines
33 22, 26, 30, 31 and 32)367,926,958 389,746,293
34
(i) Capitalleases are not included in rate base; they are charged to operating expense.
IDAHO SUPPLEMENT Page 10
ELECTRIC PLANT IN SERVICE - STATE OF IDAHO (ALLOCATED)
(In addition to Account 101, Electric Plant In Service (Classified), this schedule includes Account 102, Electric Plant
Purchased or Sold, Account 103, Experimental Electric Plant Unclassified and
Accunt 106, Completed Construction Not Classified-Electric.)
1. Report below the original cost of electric plant in 3. Credit adjustments of plant accounts should be
service according to prescribed accounts.enclosed in parentheses to indicate the negative effect
of such amounts.
2. Do not include as adjustments, corrections of
additions and retirements for the current or the
preceding year.
Line Balance at End ofNo.Account Beginning Balance Year
(a)(b)(g)
1 1. INTANGIBLE PLANT
2 301) Organization --
3 302) Franchises and Consents 7,254,241 7,710,760
4 303) Miscellaneous Intangible Plant 29,779,555 28,106,698
5 TOTAL Intanoible Plant (Enter Total of lines 2,3, and 4)37,033,796 35,817,458
6 2. PRODUCTION PLANT
7 A Steam Production Plant
8 (310) Land and Land Riahts 5,428,705 4,870,169
9 311) Structures and Improvements 46,937,258 42,067,263
10 312) Boiler Plant Equipment 168,618,554 155,381,489
11 313) Engines and Engine Driven Generators --
12 314 Turbogenerator Units 45,180,197 41,644,648
13 315 Accessorv Electric Equipment 20,390,793 18,604,762
14 (316 Misc. Power Plant Equipment 1,515,785 1,417,423
15 TOTAL Steam Production Plant (Enter Total of lines 8 thru 14)288,071,292 263,985,754
16 B. Nuclear Production Plant
17 (320) Land and Land Rights --
18 321) Structures and Improvements --
19 322 Reactor Plant Equipment --
20 323 Turbogenerator Units --
21 324 Accessory Electric Eauipment --
22 325 Misc. Power Plant Equipment --
23 TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 22)--
24 C. Hydraulic Production Plant
25 (330 Land and Land Riahts 1,143,555 1,012,879
26 331 Structures and Improvements 4,958,440 4,852,448
27 332 Reservoirs, Dams, and Waterways 16,727,953 15,508,390
28 333 Water Wheels, Turbines, and Generators 5,616,447 5,440,601
29 (334) Accessorv Electric Equipment 2,768,451 2,824,176
30 335) Misc. Power Plant Equipment 143,508 121,058
31 (336) Roads, Railroads, and Bridges 829,230 775,921
32 TOTAL Hydraulic Production Plant (Enter Total of lines 25 thru 31)32,187,584 30,535,473
33 D. Other Production Plant
34 340) Land and Land Rights 1,250,990 1,143,789
35 341) Structures and Improvements 6,419,904 6,669,510
36 342) Fuel Holders, Products, and Accssories 536,054 496,431
37 343) Prime Movers 73,560,400 99,032,854
38 344 Generators 13,374,080 14,710,230
39 345 Accessorv Electric Eauipment 7,296,653 9,249,857
40 (346 Misc. Power Plant Equipment 402,103 491,526
41 TOTAL Other Production Plant (Enter Total of lines 34 thru 40)102,840,184 131,794,197
42 i U I AL t-rOductlon t-iant (t:nter Total of lines 1~, ;¿;j, ,j;¿, ana 41)423,099,060 426,315,424
IDAHO SUPPLEMENT Page 11
ELECTRIC PLANT IN SERVICE (Continued) STATE OF IDAHO (ALLOCATED)
Line Balance End ofNo.Account Beginning Balance Year
(a)(b)(g)
43 3. TRANSMISSION PLANT
44 350) Land and Land Riahts 5,478,889 4,985,691
45 352) Structures and Improvements 3,901,893 3,963,046
46 (353) Station Equipment 63,172,280 62,349,650
47 354) Towers and Fixtures 24,823,566 22,318,694
48 (355) Poles and Fixtures 30,966,465 27,850,728
49 (356 Overhead Conductors and Devices 41,007,286 36,808,896
50 357 Underground Conduit 188,356 163,000
51 358 Underaround Conductors and Devices 431,335 381,263
52 359) Roads and Trails 665,647 581,508
53 TOTAL Transmission Plant (Enter Total of lines 44 thru 52)170,635,717 159,402,476
54 4. DISTRIBUTION PLANT
55 360) Land and Land Rights ..1,255,542 1,295,303
56 361) Structures and Improvements 1,151,317 1,493,953
57 362 Station Equipment 26,123,899 26,448,680
58 363 Storage Battery Equipment --
59 364 Poles, Towers, and Fixtures 56,159,120 59,208,069
60 365) Overhead Conductors and Devices 32,973,127 33,561,563
61 366 Underaround Conduit 6,942,477 7,255,335
62 367 Underaround Conductors and Devices 22,642,301 23,436,444
63 368 Line Transformers 62,062,240 64,719,406
64 369) Services 25,683,819 27,232,773
65 (370) Meters ..13,817,534 13,860,550
66 (371) Installations on Customer Premises 162,607 164,985
67 372) Leased Propert on Customer Premises 2,437 -
68 (373) Street Lighting and Signal Systems 592,483 600,185
69 TOTAL Distribution Plant (Enter Total of lines 55 thru 613)249,568,903 259,277,246
70 5. GENERAL PLANT
71 389 Land and Land Rights 555,588 527,617
72 390 Structures and Imorovements 16,306,746 15,692,289
73 391 Ofce Furniture and Equipment 5,217,332 4,496,220
74 (392 Transportation Equipment 6,437,195 6,369,557
75 393 Stores Eauipment 867,D2 801,723
76 394) Tools, Shop and Garaae Equipment 3,430,881 3,261,288
77 (395 Laboratory Equipment 2,041,070 1,911,683
78 (396 Power Ooerated Equipment 8,750,317 8,903,079
79 397 Communication Equipment 14,367,405 13,185,206
80 398 Miscellaneous Eauioment 339,542 331,206
81 SUBTOTAL (Enter Total of lines 71 thru 80)58,313,118 55,479,868
82 (399) Other Tangible Propert 17,251,522 15,630,041
83 TOTAL General Plant (Enter Total of lines 8fthru 82)75,564,640 71,109,909
84 TOTAL (Accounts 101)955,902,116 951,922,513
85 1(102) Electric Plant Purchased 8,791,718 7,762,964
86 Plant Sold --
87 (103) Experimental Electric Plant Unclassified --
88 (106) Plant Unclassified 3,252,244 4,095,461
89 TOTAL Elecric Plant in Service 967,946,078 963,780,938
IDAHO SUPPLEMENT Page 12
STATE OF IDAHO --ALLOCATED
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report Is:
(1) i An Onginal
(2) A.resubmission
Date of Report
(Mo, Da, Yr)
May 26, 2010
Year of Report
Dec. 31, 2009
MATERIALS AND SUPPLIES
1. For Accunt 154, report the amount of plant materials
and operating supplies under the pnmary functional
classifications as indicated in column (a); estimates of
amounts by function are accptable. In column (d),
designate the departent or departments which use the
class of matenal.
2. Give an explanation of importnt inventory adjustments
during the year (on a supplemental page) showing general
classs of material and supplies and the vanous
accunts (operating expense, cleanng accunts, plant,
etc.) affecte - debited or credited. Show separately
debits or credits to stores expense clearing, ifapplicable. -
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Balance
Beginning of
Year
(b)
ACCOUNT
(a)
15
16
17
18
19
20 TOTAL Matenals and Supplies (Per Balance Sheet)
IDAHO SUPPLEMENT Page 13
Balance
End of Year
(c)
8,560,903
Departent or
Departments
Which Use Matenal
(d)
Electric
4,556,395
241,126
4,581,385
2,955
9,381,861
Electric
Electric
Electric
Electnc
17,942,764