2010Annual Report.pdf

~~~OUNTAIN
May 31, 2011
RECEIVED
2nO HAY 31 AM 9: 42
201 South Main, Suite 2300
Salt Lake City, Utah 84111
VI OVERNIGHT DELIVERY
Idaho Public Utilties Commssion
472 West Washigton
Boise, ID 83702-5983
Attention:Jean D. Jewell
Commission Secreta
RE: FERC Form i
PacifiCorp (d.b.a. Rocky Mounta Power) submits for fiing one copy of PacifiCorp's anua
FERC Form 1 report for the year ended December 31, 2010.
PacifiCorp respectfully requests tht all data requests regarding this 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 dirt any inormal questions to Ted Weston, Reguatory Maner, at [phone].
~tllaAýO\)ß
Vice President, Reguation
Enclosure
THIS FILING IS
Item 1: 00 An Initial (Original)
Submission
OR D Resubmission No.
PAc-E
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 repors to be of confidential nature
Form 1 Approved
OMS No. 1902-0021
(Expires 12/31/2011)
Form 1-F Approved
OMS No. 1902-0029
(Expires 12/31/2011)
Form 3-Q Approved
OMS No. 1902-0205
(Expires .1/31/2012)
~--:i~
w-?i('rn
"2
íO':~
\D..i;N
Exact Legal Name of Respondent (Company)
PacifiCorp End of
Year/Period of Report
2010/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) isan annual regulatory requirement for Major electric utilities, licensees and others
(18 C.F.R. § 141.1). FERC Form No. 3-0 ( FERC Form 3-0)is a quarterly regulatory requirement which supplements the
annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and
operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy
Regulatory Commission. These reports are also considered to be non-confidential public use forms.
II. Who Must Submit
Each Major electric utility, liænsee, or other, as classified in the Commission's Uniform System of Accounts
Prescribed for Public Utilties and Licensees Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101),
must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-0 (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 3-0 electronically through the forms submission softare. Retain one copy of each report
for your files. Any electronic submission must be created by using the forms submission softare provided free by the
Commission at its web site: http://ww.ferc.gov/docs..filing/eforms/form-1/elec-subm-soft.asp. The softare is
used to submit the electronic filing to the Commission via the Internet.
(b) The Corporate Offær Certification must be submitted electronically as part of the FERC Forms 1 and 3-0 fiings.
(c) Submit immediately upon publication, by eithereFiling or mail, two (2) copies to the Secretary of the Commission, the
latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to
the Secretary of the Commission at:
Secretary
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
(d) For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report
(not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can
be either eFiled or mailed to the Secretary of the Commission at the address above.
FERC FORM 1 & 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 liænsed by a regulatory authority of a State or other political subdivision of the U. S. (See 18
C.F.R. §§ 41.10-41.12 for specific qualifications.)
Reference Schedules Pages
Comparative Balance Sheet
Statement of Income
Statement of Retained Earnings
Statement of Cash Flows
Notes to Financial Statements
110-113
114-117
118-119
120-121
122-123
e) The following format must be used for the CPA Certification Statement unless unusual circumstanæs or conditions,
explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are
reported.
"In connection with our regular examination of the financial statements of _ for the year ended on which we have
reported separately under date of , we have also reviewed schedules
of FERC Form NO.1 for the year filed with the Federal Energy Regulatory Commission, for
conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its
applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such
tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph
(except as noted below) conform in all material respects with the accounting requirements of the Federal Energy
Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases."
The letter or report must state which, if any, of the pages above do not conform to the Commission's requirements.
Describe the discrepancies that exist.
(f) Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling.
To further that effort, new selections, "Annual Report to Stockholders," and "CPA Certification Statement" have been
added to the dropdown "pick list" from which companies must choose when eFiling. Further instructions are found on the
Commission's website at http://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 Jerc.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 3-0 must be fied 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 3-0 for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. §141.400).
V. Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,144
hours per response, including the time for reviewing instructions, searching existing data sources, gathering and
maintaining the data-needed, and completing and. reviewing the collection of information. The public reporting burden for
the FERC Form 3-:Q collection of information is estimated to average 150 hours per response.
Send comments regarding these burden estimates or any aspect of these collections of information,
including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426 (Attention: Information Clearance Offcer); and to the Offce of Information and Regulatory Affairs,
Office 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)ii
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 unitwhere cents are important. The truncating of cents is allowed except on the four basic financial statements
where rounding is required,) The amounts shown on all supporting pages must agree with the amounts entered on the
statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance
sheetaccoùnts the balances at the end of the current reporting period, and use for statement of income accounts the
current yeats year to date amounts.
III Complete each question fully and accurately, even if it has been answered in a previous report. Enter the
word "None" where it truly and completely states the fact.
IV. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not
Applicable" in column (d) on the List of Schedules, pages 2 and 3.
V. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the
header of each page is to be completed only for resubmissions.(see VII. below).
VI. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must
be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the
numbers in parentheses.
VII For any resubmissions, submit the electronic 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 referto 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 iríterrupted 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 cancel the contract.
OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the
terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and "firm" means that service
cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all
transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either
buyer or seller can unilaterally get out of the contract.
SFP . Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point
transmission reservations, where the duration of each period of reservation is less than one-year.
NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions.
OS - Other Transmission Service. Use this classification only for those services which can not be placed in the
above-mentioned classifications, such as all other serviæ regardless of the length of the contract and service FERC
Form. Describe the type of service in a footnote for each entry.
AD . Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior
reporting periods. Provide an explanation in a footnote for each adjustment.
DEFINITIONS
i. Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or
any other Commission. Name the commission whose authorization was obtained and give date of the authorization.
II. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose
behalf the report is made.
FERC FORM 1 & 3-Q (ED. 03-07)v
EXCERPTS FROM THE LAW
Federal Powér 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. Itst)all not include 'municipalities, as hereinafter defined;
(4) 'Person' means an individual or a corporation;
(5) 'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act,
and any assignee or successor in interest thereof;
(7) 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or
agency of a State competent under the Laws thereof to carr and the business of developing, transmitting, unitizing, or
distributing power; ......
(11) "project' means. a complete unit of improvement or development, consisting of a power house, all water
conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit,
and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power
there from to the point of junction with the distribution system or with the interconnected primary transmission system, all
miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights,
rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or
appropriate in the maintenance and operation of such unit;
"Sec. 4. The Commission is hereby authorized and empowered
(a) To make investigations and to collect and record data concerning the utilization of the water'resources of any region
to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and
concerning the location, capacity, development -costs, and relation to markets of power sites; ... to the extent the
.. Commission may deem necessary or useful for the purposes of this Act."
"Sec. 304. (a) Every Licensee and every public utility shall file with the Commission such annual and other periodic or
special* reports as the Commission may be rules and regulations or other prescribe as necessary or appropriate to assist
the Commission in the -proper administration of this Act. The Commission may prescribe the manner and FERC Form in
which such reports salt be made, and require from such persons specific answers to all questions upon which the
Commission may need information. The Commission may require that such reports shall include, among other things, full
information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due
and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the
project and other facilities, cost of renewals and replacement of the project works and other facilties, depreciation,
generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such
person to make adequate provision for currently determining such costs and other facts. Such reports shall be made
under oath unless the Commission otherwise specifies*.1 0
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 .02 Year/Period of Report
PacifiCorp End of 2010/04
03 Previous Name and Date of Change (if name changed during year)
/ /
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
825 N.E. Multnomah, Suite 1900, Portland, OR 97232
05 Name of Contact Person 06 Title of Contact Person
Henry E. Lay Corporate Controller
.
07Address of Contact Person (Street, City, State, Zip Code)
825 N.E Multnomah, Suite 1900, Portland, OR 97232
08 Telephone of Contact Person,lncludíng 09 This Report Is 10 Date of Report
Area Code (1) IX An Original (2) D A Resubmission (Mo, Da, Yr)
[phone] 04/18/2011
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of tact 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 03 S'¥WlJ4 (( ~04 Date Signed
DOUQlas K. Stuver (Mo, Oa, Yr)02 Title
Senior VP & Chief Financial Officer Dougl s K. Stuver -04/18/2011
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Departent of the United States any
false, ficttious or fraudulent statements as to any matter within its jurisdiction.
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 2010/Q4
(2) OA Resubmission 04/18/2011
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 Corprations Controlled by Respondent 103
4 Offcers 104
5 Directors 105
6 Information on Formula Rates 106(a)(b)
7 Important Changes During the Year 108-109 .
8 Comparative Balance Sheet 110-113
9 Statement of Income for the Year 114-117
10 Statement of Retained Eamings for the Year 118-119.
11 Statement of Cash Flows 120-121
12 Notes to Financial Statements 122-123
.13 Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b)
14 Summary of Utilty Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
15 Nuclear Fuel Materials 202-203 N/A ...
16 Electric Plant in Service 204..207
17 Electric Plant Leased to Others 213 N/A
18 Electric Plant Held for Future Use 214
19 Construction Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Electric Utilty Plant 219
21 Investment of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowances 228(ab )-229(ab)
24 Exraordinary Propert Losses .230 N/A-
25 Unrecovered Plant and Regulatory Study Costs 230
26 Transmission Service and Generation Interconnection Study Costs 231
27 Other Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accumulated Deferred Income Taxes 234
30 Capital Stock 250-251
31 Other 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 2010/Q4
(2) DA Resubmission 04/18/2011 .
UtiT OF SCHEDULES (Electnc 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 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
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 Electricity 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 Electricity by Others 332
50 Miscellaneous General Expenses-Eièctric 335
51 Depreciation 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 included in ISO/RTO Settlement 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 Electric Energy Account 401
61 Monthly Peaks and Output 401
62 Steam Electric Generating Plant Statistics 402-403
63 Hydroelectric Generating Plant Statistics 406-407
64 Pumped Storage Generating Plant Statistics 408-409 N/A
65 Generating Plant Statistics Pages 410-411 ..
66 Transmission Line Statistics Pages 422-423
FERCFORM NO.1 (ED. 12-96)Page 3
Name of Respondent
PacifiCorp
.
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2011
LI T OF SCHEDULES (Electric Utilty) (continued)
Year/Period of Report
End of 2010/Q4
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
(c)
Stockholders' Reports Check appropriate box:
l: Two copies wil be submitted
o No annual report to stockholders is prepared
.
FERC FORM NO.1 (ED. 12-96)Page 4
Name of Respondent
PacifiCorp
This Report Is:
(1) IX An Original
(2) D A Resubmission
Date of Report
(Mo, Da, Yr)
04/18/2011
Year/Period of Report
End of 2010/Q4
GENERAL INFORMATION
1. Provide name and title of offær 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 accunt
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 Boòks are kept at:
825 N.E. Multnomh, Suite 1900,
Portland, OR 97232-4116
2. Provide the name of the State under the laws of which respondent is incorporated, and date of iricorporation.
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 propert of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not applicable
4. State the classes or utility and other services 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 company
serving 1.7 million retail customers, including residential , comrcial, industrial and other customrs
in portions of the states of Utah, Oregon, wyoming, Washington, Idaho and California. PacifiCorp
delivers electricity to customers in Utah, Wyomng and Idao under the trade nam Rocky Mountain Power
and to customers in Oregon, Washington and California under the trade nam Pacific Power. PacifiCorp' s
electric generation, comrcial and trading, and coal mining functions are operated under the trade nam
PacifiCorp Energy.
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's ærtified financial statements?
(1) D 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 04/18/2011 2010/Q4
FOOTNOTE DATA
ISchedulePagê: 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 andLight Company, a
Utah corporation, in a transaction wherein both corporations merged into a newly formed Oregon corporation. The resultig Oregon
corporation was re-named PacifiCorp, which is the operating entity today.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
.
Name of Respondent
PacifiCorp
This Report Is:
(1) 00 An Original
(2) D A Resubmission
Date of Report
(Mo, Da, Yr)
04/18/2011
Year/Period of Report
End of 2010/Q4
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held
control over the repondent at the end of the year, state name of controlling corporation or organization, manner in
which control was held, and extent of control. If control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. If control was held by a trustee(s), state
name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
.
Berkshire Hathaway Inc.(a)
MidAmerican Energy Holdings Company (100%)
PPW HoldingsLLC (100% còntrolled by MidAmerican Energy Holdings Company)
Pacificorp (100% of common stock held by PPW Holdings LLC)
(a) Berkshire Hathaway Inc. owns 89.85%, Walter Scott, Jr. (1) (along with family members and related entities) owns 5.63% and
Gregory E. Abel owns 0.80% of MEHC's common stock.
(1) Excludes 2,778,000 shares held by family members and family controlled trusts and corporations, or Scott Family Interests, as to
which Mr. Scott disclaims beneficial ownership.
FERC FORM NO.1 (ED. 12-96)Page 102
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
C RPORATIONS CONTROLLED BY R SPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accunts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direc action without the consent of the other, as where the
voting control is equally divided between two holders, or each part holds a veto power over the other. Joint control may exist by mutual
agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the
. Uniform System of Accounts, regardless of the relative voting rights of each part.
Line
No.
Name of Company Controlled Kind of Business
(b)
Percent Voting
Stock Owned
(c)
100
100
100
100
100
66.67
100
100
21.40
Footnote
Ref.
(d)
10 PacifiCorp Foundation
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
Mining
Mining
Mining
Management Services
Management Services
Mining
Environmental Services
Management Services
Mining
Non-profit foundation
FERC FORM NO.1 (ED. 12-96)Page 103
Name of Respondent This Report is:Date of Report Year/Period of He port
(1) ~ An Original (Mo, Da, Yr)
PacifCorp I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
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 performs similar policy making functions.
2. If a èhange 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.~Name of Offcer . ::alaryNo. (a)for Year
(b)(c)1"~ - 8%% "8" ..;t-ø ,-..mmw ~ ,,- w ~
2 Chairman of the Board and Chief Executive Offcer -.Wi iq~h' /' _ m Wi
3 Senior Vice President and Chief Financial Offcer Douglas K. Stuver 233,525
4 . President, Rocky Mountain Power A. Richard Walje 357,150
5 President, Pacific Power R. Patrick Reiten 265,740
6 President, PacifCorp Energy ,."Ø-"0 m%~"230,114Wrø,miiì 8
7 .
8 Other Executive Offcers in 2010:
9 President, PacifiCorp Energy 22,9440%' æi~
10
11
12 .
13 .
14
15
16
17
18
19
20
21 .
22
23
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25
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27
28
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31
32
33
34
3~
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (ED. 12-96)Page 104
.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp . (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 104 Line No.: 1 Column: a
PacifiCorp sets fort the salar information for its "named executive offcers" for the year ended December 31, 2010, consistent with
Item 402 of Regulation S-K promulgated by the Securties and Exchange Commission in its Anual Report on Form 10-K. Salary
information of other offcers wil be provided to the Federal Energy Regulatory Commssion (the "FERC") upon request, but the
company considers such information personal and confidential to such officers. See 18 CFR 388.107(d), (t).
ISchedule Page: 104 Line No.: 2 Column: b
Mr. Abel receives no direct compensation from PacifiCorp. PacifiCorp reimburses MidAerican Energy Roldings Company
("MERC") for the cost of Mr. Abel's time spent on matters supporting PacifiCorp,including compensation paid to him by MERC,
pursuant to an intercompany administrative services agreement among MERC and its subsidiaries. Please refer to MERC's Anual
Report on Form 10-Kfor the year ended December 31, 2010 (File No. 001-14881) for executive compensation information for Mr.
AbeL.
\Schedule Page: 104 Line No.: 6 Column: b
For additional informtion regarding changes in the status of PacifiCorp's officers refer to Importnt Changes Durg the
Quarter/Year, Item 13 of this Form No.1. On Januar 13,2010, Mr. Dun was elected President ofPacifiCorp Energy and director
ofPacifiCorp, both effective February 1,2010.
¡Schedule Page: 104 Line No.: 9 Column: b
For additional information regarding changes in the status ofPacifiCorp's offcers refer to Importnt Changes Durg the
Quarer/Year, Item 13 of this Form No.1. On January 13, 2010, Mr. Lasich resigned as President ofPacifiCorp Energy and director
ofPacifiCorp, both effective February 1,2010.
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 2010/04
(2) EiA Resubmission 04/18/2011
DIRECTORS
1. Report below the information called for concerning each director 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 Chairman of the Executive Committee by a double asterisk.
L~g.Name (ançl ,I me) or uirector I-nncipai !:usiness AOOress
(a)(b)
1 PacifiCorp Board of Directors as of December 31,2010:
2 ~"~ø.!Ø-",%':m ""W w,i-w -;i "".~~.666 Grand Avenue, Suite DM29, Des Moines, Iowa 503090~.
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 South 36th Street, Omaha, Nebraska 68131
6 Brent E. Gale (SeniorVice President).825 NE Multnomah, Suite 2000, Portland, Oregon 97232
7 Patrick J. Goodman 666 Grand Avenue, Suite DM29, Des Moines, Iowa 50309
1407 West North Temple, Suite 320, Salt Lake City, Utah 84116
9 Mark C. Moench (SVP and General Counsel, PacifiCorp) 201 South Main, Suite 2400, Salt Lake Cit, Utah 84111
10 Natalie L. Hocken (VP and General Counsel, Pacific Power)825 NE Multnomah, Suite 2000, Portland, Oregon 97232
11
12 Other PacifiCorp Board of Directors in 2010:-
13 1407 West Nort Temple, Suite 320, Salt Lake City, Utah 84116-
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
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 04/18/2011 2010/Q4
FOOTNOTE DATA
!Schedule Page: 105 Line No.: 2 Column: a
Currently there is .onlyone committee, a Compensation Committee, of which the sole member is Mr. AbeL.
I§chedule Page: 105 Line No.: 8 Column: a
For additional information regarding changes in the status ofPacifiCorp's directors refer to Importnt Changes Durg the
QuarerlYear, Item 13 of this Form No. 1. On Januar 13,2010, Mr. Dunn Was elected President ofPacifiCorp Energy and diector of
PacifiCorp, both effective February 1,2010.
!Schedule Page: 105 Line No.: 13 Column: a
For additional information regarding changes in the status ofPacifiCorp's directors refer to Importt Changes Durg the
QuarterlYear, Item 13 of this Form No. 1. On January 13,2010, Mr. Lasich resigned as President ofPacifiCorp Energy and director
ofPacifiCorp, both effective Februar 1, 2010.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/1812011
INFORMATION ON FORMULA RA ES
FERc Rate SchedulelTariff Number FERC Proceing
Does the respondent have formula rates?DYes
(Z No
1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (Leo Docket No)
accepting the rate(s) or changes in the accpted rate.
Line
No.FERC Rate Schedule or Tariff Number FERC Proceeding
1 .
2
3
4
5
6
7
8
9
10
11
12
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14 .
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29
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33
34
35
36
37
38
39
40
41
FERC FORM NO.1 (NEW. 12-08)Page 106
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1)1! An Original (Mo, Da. Yr)End of 2010/Q4
(2) Ei A Resubmission 04/18/2011
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)?
(X 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 or
No.Accession No.\ Filed Date Docket No.Description Tariff Number
1
2
3
4
5 ..
6
7
8
9
10 .
11
12
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18 ...
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45
46
FERC FORM NO.1 (NEW. 12-08)Page 106a
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
.(2) Fi A Resubmission 04/18/2011
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 billng) 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 items
impacting formula rate Înputs differ from amounts reported in Form 1 schedule amounts.
4. Where the CommissÎoii 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
1
2 .
3
4
5
6
7
8
9 .
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11 ..
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FERC FORM NO.1 (NEW. 12-08)Page 106b
Name of Respondent
PacifiCorp
This Repor Is:
(1) 12 An Original
(2) D A Resubmission
IMPORTANT CHANGES DURING THE. QUARTERIEAR
Date of Report Year/Period of Report
End of 2010/Q404/18/2011
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and importnt additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the propert, and of the transactions relating thereto, and
reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were
submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers
added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new
continuing sources of gas made available to it from purchases, development, purchase cotract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERc or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an offcer,
director, security holder reported on Page 106, voting trustee, associated company or known associate of any of these persons was a
party or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in 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, oraffliated companies through acash
management program(s). Additionally, please describe plans, if any to regain at least a 30 percentproprietary ratio.
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) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
ITEM 1.
Changes in Franchise Rights
The following table includes new or modified franchise agreements. The fee represents either the fee attached to the franchise
agreement, an associated tax or fee.
State
California (I)
. None
Idaho (2)
None
Oregon (3)
Coquile
Glendale
Athena
Prievile
Falls City(4)
Wasco
Dallas
Sutherljn
Junction City
Coos Bay
Gates
Madras
Utah(2)
Salt Lae County
Duchesne County
Layton
South Jordan
West Jorda
Eagle Mountain
Mayfield
Washington (2)
Zilah (5)
Wyoming (6)
Worland (7)
BarNunn
Riveron
Glendo
Effective Date Expiration Date Fee
01129/2010 01129/2020
02/02/2010 02/02/2020
04/2112010 04/2112030
06/10/2010 06110/2015
06/0112010 06/0112020
06118/2010 06/18/2015
08/24/2010 08/24/2020
0910112010 09/0112020
1010112010 10/0112020
09117/2010 09/17/2015
II 10 1120 10 1110112020
12114/2010 0110112021
04106/2010 0410612035
04/19/2010 0411912020
06/08/2010 06/08/2015
07/22/2010 07/22/2025
10/1312010 10/13/2045
11103/2010 11103/2015
12/08/2010 12/08/2040
05/1712010 0511712020
09/0111999 09/0112014
0111512010 01115/2035
04/22/2010 04/22/2030
04/2812010 04/28/2035
5.0%
7.0%
3.5%
5.0%
6.0%
3.5%
7.0%
3.5%
5.0%
7.0%
7.0%
7.0%
5.0%
6.0%
6.0%
3.0%
6.0%
5.0%
4.0%
6.0%
2.0%
IFERC FORM NO.1 (ED. 12-96)Page 109.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2S An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010104
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
(1) In Californa, frchise agreement fees are an expense to PacifiCorp and are embedded in rates.
(2) In Idaho, Utah and Washington, PacifiCorp collects frchise agreement fees from customers and remits them directly to the applicable muncipalities.
(3) In Orgon, the first 3.5% of the frchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 3.5% is collected frm
customers and remitted directly to the applicable municipalities.
(4) The ter of this frchise agreement is for i 0 years with a rate review in five yea.
(5) The term of this franchise agreement shall be for two successive five-year ter, unless one par gives the other wrttn notice ternating the frnchise
agreement at least 90 days before the end of a frnchise term.
(6) In Wyomig, the first 1.0% of the frnchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 1.0% is collected
from customer and remitted directly to the applicable municipalities.
(7) Represents a fee increase only; effective July 1,2010.
ITEM 2.
Acquisition of Ownership in Other Companies
None.
ITEM 3.
Purchase or Sale of an Operating Unit
In Januar 2010, PacifiCorp received approval from the Federal Energy Regulatory Commission (the "FERC") in Docket
No. EC10-13-000, pursuånt to Section 203 of the Federal Power Act, for the acquisition of the Goshen Senes Capacitor Ban from
Idao Power Company ("Idao Power"). The purchase included a 345 kilovolt ("kV"), 3-phase, 60.:Hert, 2-equal~segrent outdoor
senes capacitor bank and associated nghts and propert. In December 2010, the FERC approved the joural entres required by the
Uniform System of Accounts ("US of A") in Docket No. ACll-5-000. Accordingly, PacifiCorp cleared account 102, Electrc plant
purchased or sold, and recorded the purchase to the appropnate plant accounts.
In Februar 2010, the FERC approved the joural entres required by the USofA as presented in Docket No. AC10-44-000 for the
acquisition of a porton of a 69 kV electrc transmission facility from Garkane Energy Cooperative, Inc.
In July 2010, PacifiCorp received approval from the FERC in Docket No. ER10-1217-000, pursuant to Section 205 of the Federal
Power Act, of the joint ownership and operatig agreement with Idaho Power for the 345 kV Populus substation. In addition,
PacifiCorp acquired a portion of the 500 kV Hemigway substation from Idaho Power. The Populus substation was constrcted by
PacifiCorp, and the Hemingway substation was constrcted by Idaho Power.
In December 2010, PacifiCorp closed the sale of undivided ownership interests in certin of PacifiCorp's transmission facilities to
Black Híls Power, Inc. ("Black Híls"). The sale consisted of a 22.5% undivided ownership interest in the 230 kV Windsta
substation and a 15% undivided ownership interest in the 230 kV Dave Johnston substation, both located in Converse County,
Wyomig, and a 56.25% undivided ownership interest in a 230 kV transmission line between the Windsta substation and the Dave
Johnston substation. The sale provides Black Híls 450 megawatts ("MW") of transmission nghts through the facilities. Pursuant to a
joint operating and maintenance agreement between PacifiCorp and Black Híls, PacifiCorp wíl operate and maintain the facilities in
their entirety. The assets sold have been included in account 102, Electrc plant purchased or sold, and PacifiCorp wíl file the joural
entries required by the USofA within the required six-month penod from the date of the sale. Commission authorizations associated
with the sale were as follows:
. Oregon Public Utility Commssion (the "0PUC") - Order No. 10-449, effective November 15, 2010.
. California Public Utilities Commission (the "CPUC") - Advice Letter 424-E and 425-E, both effective December 9, 2010.
. Wyoming Public Service Commission (the "WPSC") - Docket No. 20000-382-EA-10, effective Februar 22, 2011, pursuant
to open meeting action taen on December 28,2010.
IFERC FORM NO.1 (ED. 12-96)Page 109.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010104
IMPORTANT CHANGES DURING THE OUARTERIR (Continued)
In March 2011, PacifiCorp entered into an agreement for the sale of the Snake Creek hydroelectrc generatig facility with Heber
Light & Power Company. The sale wil close after all regulatory approvals have been obtained. PacifiCorp is in the process of fiing
applications for approval of the sale with the OPUC, CPUC and WPSc.
ITEM 4.
Important Leaseholds
None.
ITEM 5.
Important Extension or Reduction of Transmission System or Distrbution Territory
Durng the year ended December 31,2010, PacifiCorp did not significantly increase or decrease its distribution terrtory. Refer to
pages 424-425 of this Form NO.1 for additional information regarding transmission lines added or removed durg the year.
ITEM 6.
Financing Activities
Short-term Debt and Revolving Credit Facilities
Regulatory authorities limit PacifiCorp to $1.5 bilion of short-ter debt. PacifiCorp had $36 milion of short-term debt outstanding
as of December 31, 2010 at a weighted-averge interest rate of 0.3% as compared to no short-term debt outstading as of
December 31, 2009. PacifiCorp had no outstading borrowigs under its unsecured revolving credit facilities as of December 31,
2010 or 2009.
Commssion authorizations for up to $1.5 bilion outstading 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 Transportation Commission (the "WUC") - Docket No. UE-980404, dated April 8, 1998.
· Idaho Public Utilities Commission (the "IPUC") - Case No. PAC-E-06-01, Order No. 29999, dated March 14, 2006,
effective through April 30, 2011.
· IPUC - Case No. PAC-E-II-09, Order No. 32221, dated April 8, 2011, effective through April 30, 2016.
· FERC - Docket No. ES09-50-000, dated October 9, 2009, letter order effective Januar 1, 2010 through December 31, 2011.
For fuher discussion, refer to Note 8 of Notes to Financial Statements included in this Form No.1.
Long-term Debt
In addition to the debt issuances discussed herein, PacifiCorp made scheduled repayments on long-term debt totaling $15 millon and
. $138 milion during the years ended December 31,2010 and 2009, respectively.
In January 2009, PacifiCorp issued $350 milion of its 5.50% First Mortgage Bonds due Januar 15, 2019 and $650 milion of its
6.00% First Mortgage Bonds due Januar 15, 2039. The net proceeds were used to repay short-ter debt, to fud capital expenditues
and for general corporate puroses.
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 1(2)A Resubmission 04/18/2011 2010/Q4
.IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
In June 2010, PacifiCorp completèd a re-offerig of a $45 million series of tax-exempt bond obligations. The interest rate for this
obligation was previously fixed for a term which, upon scheduled expiration, was converted to a variable-rate with credit
enhancement and liquidity support provided by a $46 milion letter of credit issued under one of PacifiCorp's unsecured revolving
credit facilities. In September 2010, PacifiCorp completed a re-offering of varable-rate tax-exempt bond obligations totaling
$38 milion. Letters of credit totaling $39 million were issued under one of PacifiCorp's unsecured revolving credit facilities to
provide credit enhancement and liquidity support for these previously unenhanced obligations.
As of December 31, 2010, PacìfiCorp had $601 milion of lettrs of credit available to provide credit enhancement and liquidity
support for varable-rate tax-exempt bond obligations totaling $587 milion plus interest. These letters of credit were fully available at
December 31, 2010 and expire periodically through May 2012.
PacifiCorp has regulatory authority from the OPUC and the IPUC to issue an additional $2.0 bilion of long-term debt. PacìfiCorp
must make a notice filing with the WUTC prior to any futue issuance. Also, in December 2010, PacifiCorpfiled a shelf registration
statement with the United stites Securties and Exchange Commission (the "SEC") coverig futue first mortgage bond issuances.
State commission authorizations are as follows:
. OPUC - Docket No. UF-4262, Order No. 10-062, dated February 23, 2010.
. IPUC - Case No. PAC-E-IO-02, Order No. 31018, dated March 5, 2010.
, PacifiCorp's Mortgage and Deed of Trust creates a lien on most of PacifiCorp's electrc utility propert, allowing the issuance of
bonds based on a percentage of utility propert additions, bond credits arsing from retirement of previously outstanding bonds or
deposits of cash. The amount of bonds that PacifiCorp may issue generally is also subject to a net earngs test. As of December 31,
2010, PacifiCorp estimated it would be able to issue up to $5.9 bilion of new fist mortgage bonds under the most restrctive issuance
test in the mortgage. Any issuances are subject to market conditions and amounts may be fuer limited by regulatory authorizations
or commtments or by covenants and tests contained in other fiancing agreements. PacifiCorp also has the ability to release propert
from the lien of the mortgage on the basis of propert additions, bond credits or deposits of cash.
PacifiCorp may from time to tie seek to acquire its outstanding debt securities through cash purchases in the open market, privately
negotiated transactions or otherwise. Any debt securities repurchased by PacifiCorp may be reissued or resold by PacifiCorp from
time to time and wil depend on prevailing market conditions, PacifiCorp's liquidity requirements, contractual restrctions and other
factors. The amounts involved may be materiaL.
Preferred Stock
In May 2010, PacifiCorp received an unsolicited offer to repurchase certain shares of PacifiCorp's preferred stock. As a result,
PacifiCorp purchased and canceled 4,036 shares of its $100 stated value 4.72% Serial Preferred Stock for $318,844, at an average
price per share of $79, and 3,266 shares of its $100 stated value 4.56% Serial Preferred Stock for $241,684, at an average price per
share of$74.
Common Shareholder's Equity
In Januar 2011, PacifiCorp declared a dividend of $275 milion, which was paid to PPW Holdigs LLC, a direct subsidiar of
MidAerican Energy Holdings Company ("MEHC") on Februar 28,2011.
In March 2011, PacifiCorp declared a dividend of$275 million payable to PPW Holdings LLC on April 20, 2011.
Cash capital contrbutions from MEHC were $100 millon and $125 milion durng the years ended December 31,2010 and 2009,
respectively.
IFERC 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 Resubmission 04/18/2011 2010104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
ITEM 7.
Changes in Articles of Incorporation or Amendments to Charter
None.
ITEMS.
Estimated Annual Effect of Wage Scale Changes
PacifiCorp's bargaining unit wage scale changes were as follows:
Unions Represented % Increase (1)Effective Date(s)
Estimated Annual
Financial Impact (2)
2.1%
0.8%
2.3%
2.3%
6/26/2010
112612010
0.9%
2.1%
5/26/2010
1/03/2010
110312010
(1) This percentage increase represents the increase in wages for all effective dates durng the calendar year as compared to the wage scale of the prior effective
period.
(2) The estimated annual impact is based on the time period from the effective date of the increase to the end of the calenda year. Some amounts may be
reimbured by joint owners.
Labor Agreement
A new four-year contract for Western Energy Workers International Brotherhood of Boilermakers Local S 1978 ("union") went into
effect April 1, 2011. The labor agreement between Pacific Minerals, Inc. ("PMI") and the union expired November 25, 2010.
IFERC FORM NO.1 (ED. 12-96)Page 109.5
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) XAn Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/18/2011 2010104
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
ITEM 9.
Legal Proceedings
PacifiCorp is par to a varety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or
exemplar damages. PacifiCorp does not believe that such normal and routie litigation wil have a material impact on its fiancial
results. PacifiCorp is also involved in other kinds 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 described below. In addition to the following discussion, refer to Note 13 of
Notes to Financial Statements in this Form NO.1.
In December 2000, Wah Chang, a large industral customer ofPacifiCorp, fied an action before the OPUC assertng that the rates set
by a special tariff with PacifiCorp and approved by the OPUC were not just and reasonable due to alleged market manipulation durng
the energy crisis. In October 2001, the OPUC dismissed Wah Chang's petition and found that Wah Chang assumed the risk of price
increases under the special tarff. Wah Chang petitioned the Circuit Cour for Maron County, Oregon for review of the OPUC's
order. In June 2002, the Circuit Cour for Marion County, Oregon, granted Wah Chang's motion for review, and ordered the OPUC to
reopen the record to allow Wah Chang the opportnity to present new evidence. In September 2009, the OPUC dismissed Wah
Chang's petition and reaffired that the rates set by the special taff were just and reasonable. In October 2009, Wah Chang fied
with the Oregon Cour of Appeals a petition for judicial review of the OPUC's September 2009 order denying Wah Chang relief. In
July 2010, the Oregon Cour of Appeals accepted judicial review.
In a separate but related proceeding, in December2000, Wah Chang filed a complaintin the Circuit Cour for Linn County, Oregon,
asserting that the OPUC-approved special taff with PacifiCorp is subject to rescission based on theories of mutual mistae offact,
frstration of purose and impracticability. In August 2002, the Circuit Cour for Linn County, Oregon, granted PacifiCorp's motion
for summary judgment dismissing Wah Chang's complaint. In February 2004, the Circuit Court for Linn County, Oregon, granted
Wah Chang's mótion to reopen the case to present additional evidence of alleged market manipulation. In December 2007, Wah
Chang fied a second amended complaint seeking recovery of a portion of the costs paid under the special tariff based on various
theories of legal relief, including parial rescission, unjust enrchment, and breach of duty of good faith and fair dealing. In
August 2009, the Circuit Court for Linn County, Oregon, granted Wah Chang's request to fie a third amended complaint containing a
claim for punitive damages. The trial began in April 2011. Wah Chang is seeking $37 milion (less the amount Wah Chang would
have paid for electrcity absent the special tariff) in compensatory damages and $200 million in punitive damages. PacifiCorp intends
to vigorously defend these claims and believes that the outcome of these proceedings wil not have a material impact on its financial
results.
In October 2005, PacifiCorp was added as a defendant to a lawsuit originally filed in Februar 2005 in the Third Distrct Cour for
Salt Lake County, Utah ("Third Distrct Cour") by USA Power, LLC and its affliated companies, USA Power Parers, LLC and
Spring Canyon Energy, LLC (collectively, "USA Power"), against Utah attorney Jody L. Wiliams and the law fir Holme,
Roberts & Owen, LLP, who represent PacifiCorp on varous matters from tie to time. USA Power was the developer of a planed
generation project in Mona, Utah called Spring Canyon, which PacifiCorp, as par of its resource procurement process, at one time
considered as an alternative to the Curant Creek generating facility. USA Power's complaint alleged that PacifiCorp misappropriated
confidential proprietary information in violation of Utah's Uniform Trade Secrets Act and accused PacifiCorp of breach of contrct
and related claims. USA Power seeks $250 milion in damages, statutory doubling of damages- for its trade secrets violation claim,
punitive damages, costs and attorneys' fees. The statutory doubling of damages only applies to the plaintiffs' trade secret claim and
could increase the total damages sought to $500 million. After considering various motions for sumar judgment, the cour ruled in
October 2007 in favor ofPacifiCorp on all counts and dismissed the plaintiffs' claims in their entirety. In Februar 2008, the plaintiffs
filed a petition requesting consideration by the Uta Supreme Cour of two of their five claims. The plaintiffs' request was granted and
they filed a brief in November 2008 with the Utah Supreme Cour. In Januar 2009, PacifiCorp filed its reply brief. In May 2010, the
Utah Supreme Cour reversed and remanded the case back to the Third Distrct Cour for fuer consideration. The Third Distrct
Cour set an eight-week tral for June and July 2011. PacifiCorp cannot predict the outcome of these proceedings, but believes that the
outcome will not have a material impact on its financial results.
IFERC FORM NO.1 (ED. 12-96)Page 109.6
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010104
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
ITEM 10.
Offcer, Director, Security Holder and Associated Company Transactions
Security Owership of Certain Beneficial Owners and Management and Related Stockholder Matters
PacifiCorp is a consolidated. subsidiary of MEHC and its common stock is indirectly owned by MEHC, 666 Grand Avenue,
Des Moines, Iowa 50309. MEHC is a consolidated subsidiar of Berkshie Hathaway Inc. ("Berkshire Hathaway") that, as of
January 31,2011, owns 89.85% ofMEHC's common stok. The balance ofMEHC's common stock is owned by Walter Scott, Jr.
(along with family members and related entities), a member of MEHC's Board of Directors, and Gregory E. Abel, PacifiCorp's
Chairman and Chief Executive Offcer.
None of PacifiCorp's executive offcers and directors owns shares of its preferred stock. The following table sets forth certin
information as of Januar 31,2011 regarding the beneficial ownership ofMEHC's common stock and the Class A and Class.B shares
of Berkshire Hathaway common stock held by each ofPacifiCorp's directors, executive officers and all ofPacifiCorp's directors and
executive offcers as a group as ofJanuar 31, 2011.
Beneficial Owner
MEHC
Common Stock
Number of
Shares
BeneficiaUy
Owned (I)
Percentage of
Clas (I)
Berkshire Hathaway
Class A Common Stock Class B Common StockNumber of Number ofShares Shares
Beneficialy Percentage of Beneficially Percentage ofOwned (I) Dass (I) Owned (I) Class (I)
Gregoiy E. Abel (2)
Douglas L. Anderson
MichealG. Du
Brent E. GalePatrck J.Goo
Natalie L. Hocken
Mark C. Moenh (3).
R. Patrck Reiten
Douglas K. Stuver
A. Richard Wale
4
4
3
*
asa
ons)
Indicates beneficial ownership of less than one percent of all outstadig shares.
(1)Includes shares which the listed beneficial owner is deemed to have the right to acquire beneficial ownership under Rule 13d-3(d) under the Securties
Exchange Act, including, among other thngs, shares which the liste beneficial owner has the right to acquire withn 60 days.
(2)In accordace with a shareholders' agreement, as amended on December 7,2005, basd on an assumed value for MEHC's common stock and the closing
price of Berkshire Hathaway common stock on Januaiy 3 i, 2011, Mr. Abel would be entitled to exchange his shares of MEHC common stock for either
1,120 shares of Berkshire Hathaway Class A stock or 1,676,651 shares of Berkshire Hathaway Class B stock. Assumng an exchange of all available MEHC
shares into either Berkshire Hathaway Class A shares or Berkshire Hathaway Class B shares, Mr. Abel would beneficially own less than 1 % of the
outstanding shares of either class of stock.
(3)Excludes 12 Class A shares and 15,000 Class B shares of Berkshire Hathaway common stock held by a family corporation and famly limited partership, as
to which Mr. Moench disclaims beneficial ownership.
IFERC FORM NO.1 (ED. 12-96)Page 109.7
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010104
.
IMPORTANT CHANGES DURING THE QUARTERlEAR(Continued)
Other Matters
Pursuant to a shareholders' agreement, as amended on December 7, 2005, Mr. Abel is able to require Berkshire Hathaway to
exchange any or all of his shares of MEHC common stock for shares of Berkshire Hathaway common stock. The number of shares
of Berkshire Hathaway common stock to be exchanged is based on the fair market value of MEHC common stock divided by the
closing price of the Berkshire Hathaway common stock on the day prior to the date of exchange.
Certain Relationships and Related Transactions
The Berkshire Hathaway Inc. Code of Business Conduct and Ethics and the MEHC Code of Business Conduct, or the Codes, which
apply to all of PacifiCorp's directors, officers and employees and those of PacifiCorp's subsidiares, generally gover the review,
approval or ratification of any related-person transaction. A related-person transaction is one in which PacifiCorp or any of
PacifiCorp's subsidiaries paricipate and in which one or more ofPacifiCorp's directors, executive offcers, holders of more than five
percent of PacifiCorp's votig securties or any of such persons' immediate family members have a direct or indirect material
interest.
Under the Codes, all ofPacifiCorp's diectors and executive offcers (including thoseofPacifiCorp's subsidiaries) must disclose to
PacifiCorp's legal deparent any material trnsaction or relationship that reasonably could be expected to give rise to a conflct with
PacifiCorp's interests. No action may be taken with respect to such transaction or relationship until approved by the legal
departent. For PacifiCorp's chief executive offcer and chief financial offcer, prior approval for any such transaction or
relationship must be given by Berkshire Hathaway's audit committee. In addition, prior legal deparent approval must be obtained
before a director or executive officer can accept employment, offces or board positions in other for-profit businesses, or engage in
his or her 0)V business that raises a potential conflict or appearance of conflict with PacifiCorp' s interests.
Under an intercompany administrative services. agreement PacifiCorp has entered into with MEHC and its other subsidiares, the
costs of certain administrative services provided by MEHC to PacifiCorp or by PacifiCorp to MEHC, or shared with MEHC and
'other subsidiaries, are directly charged or allocated to the entity receiving such services. This agreement has been filed with the
utility regulatory commissions in the states where PacifiCorp serves retail customers. PacifiCorp also provides an annual report of all
transactions with its affiiates to PacifiCorp's state regulatory commissions, who have the authority to refuse recovery in rates for
payments PacifiCorp makes to its affliates deemed to have the effect of subsidizing the separate business activities of MEHC or its
other subsidiares.
Refer to Note 17 of Notes to Financial Statements and page 429, Transactions with Associated (Affiiated) Companies, in this
Form NO.1 for additional information regarding related-par trsactions.
ITEM 11.
(Reserved)
IFERC FORM NO.1 (ED. 12-96)Page 109.8
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
ITEM 12.
General Regulation
PacifiCorp is subject to comprehensive goverental 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 estiates on the financial statements, parcularly that
related to Oregon Senate Bil 408 ("SB 408"). Refer to Note 5 of Notes to Financial Statements in this Form NO.1 for fuer
discussion.
Federal Regulation
The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act, the Energy Policy Act of
2005. ("Energy Policy Act") and other federal statutes. The FERC regulates rates for wholesale sales of electrcity; transmission of
electrcity, including pricing and regional planing for the expansion of trsmission systems; electrc system reliabilty; utility
holding companies; accounting; securties issuances; and other matters, including constrction and operation of hydroelectrc
facilities. The PERC also has the enforcement authority to assess civil penalties of up to $1 milion per day per violation of rules,
regulations and orders issued under the Federal Power Act. PacifiCorp has implemented progrms that facilitate compliance with the
FERC regulations described below, including having instituted compliance monitorig procedures.
i
Wholesale Electricity and Capacity
The FERC regulates PacifiCorp's rates charged to wholesale customers for electrcity and trnsmission capacity and related services.
Most of PacifiCorp's wholesale electrcity sales and purchases take place under market-based pricing allowed by the FERC and are
therefore subject to market volatility.
The FERC conducts trennial reviews ofPacifiCorp's market-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 market areas.
PacifiCorp's most recent trennial filing was made in June 20 1 0 and is curently pending before the FERC, while its next trennial
filing is due in June 2013. Under the FERC's market-based rules, PacifiCorp must also file a notice of change in status when there is a
significant change in the conditions that the FERC relied upon in grting market-based pricing authority. PacifiCorp is curently
authorized to sell electrcity on the wholesale market at market~based rates.
Transmission
PacifiCorp's wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp's Open
Access Transmission Tarff ("OATT"). In accordance with its OATT, PacifiCorp offers several transmission services to wholesale
custOmers:
· Network trnsmission service (service that integrtes generatig resources to serve retail loads);
· Long- and short-term firm point-to-point transmission service (service with fixed delivery and receipt points); and
· Non-firm point-to-point service (service with fixed delivery and receipt points on an as available basis).
These services are offered on a non-discrimiatory basis, which means that all potential customers are provided an equal opportity
to access the transmission system. PacifiCorp's transmission business is managed and operated independently from its commercial and
trading business, in accordance with the FERC rules. PacifiCorp has made several required compliance filings in accordance with
these rules.
IFERC FORM NO.1 (ED. 12-96)Page 109.9
Name of Respondent .This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010104
IMPORTANT CHANGES DURING THE OUARTERlEAR(Continued)
FERC Reliabilty Standards
The FERC has approved an extensive number of reliability standads developed by the Nort American Electrc Reliabilty
Corporation (the lINERClI) and the Western Electrcity Coordiating Council (the "WECCli), including critical infrastrctue
protection standards and regional standard variations. PacifiCorp must comply with all applicable standards. Compliance,
enforcement and monitorig oversight of these standards is cared out by the FERC, the NERC and the WECC. In 2007, the WECC
audited PacifiCorp's compliance with several of the approved reliability stadards, 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 with the
WECC. The results of the settlement did not have a material impact onPacifiCorp's fmancial results. Refer to Note 13 of Notes to
Financial Statements in this Form NO.1 for. additional information regarding cerain aspects of the WECC's 2007 audit currently
under the FERC's authority and the FERC's reliability standards review.
Hydroelectric Relicensing
PacifiCorp's Klamath hydroelectrc system is the only significant hydroelectrc generating facility for which PacifiCorp is engaged in
the relicensing process with the FERC. PacifiCorp also has requested the FERC to allow decommissioning of certin hydroelectrc
systems. Most ofPacifiCorp's hydroelectric generating facilities are licensed by the FERC as major systems under the Federal Power
Act, and certain 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'sKlamath hydroelectrc system.
Hydroelectric Decommissioning
Powerdale Hydroelectric Facility - Hood Riyer, Oregon
In June 2003, PacifiCorp entered into a settlement agreement to decommission the 6-MW Powerdale hydroelectrc facility rather than
pursue a new license, based on an analysis of the costs and benefits of relicensing versus decommissioning. In 2007, the FERC
authorized PacifiCorp to cease generation at the facility and approved PacifiCorp's proposed accounting entres to defer the remaining
net book value and any additional removal costs of the system as a regulatory asset. PacifiCorp received approval from its state
regulatory commissions to defer and recover these costs. In April 2010, PacifiCorp initiated removal of the Powerdale dam and
associated system featues as stipulated in the FERC Surender Order. As of October 31, 2010, decommssioning activities, including
dam removal and site restoration, were completed. PacifiCorp wil monitor restored areas until early 2012 when the project land wil
be transferred to the Columbia Land Trust, Oregon Deparent ofFish and Wildlife and Hood River County. Removal costs for the
Powerdale dam and associated system features were approximately $4 million, and additional monitoring costs are not expected to
exceed $1 milion.
Condit Hydroelectric Facilty - White Salmon Riyer, 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-governental organizations. In early Februar 2005, the pares agreed to modify the settlement agreement,
establishing a total cost to decommssion not to exceed $21 milion, excluding inflation. In October 2010, the Washington Deparent
of Ecology issued a Clean Water Act 401 certificate, and in December 2010, the FERC issued a surender order for project
decommssioning. In January 2011, PacifiCorp filed a request for clarification and rehearg of the surender order and a motion for
stay with the FERC. In April 2011, a motion for extension of time was fied with the FERC requesting that the FERC allow project
decommssioning to be delayed until 2012 as the FERC has not yet issùed an order on PacifiCorp's request for rehearing on the
surender order. PacifiCorp wil consider a 2011 decommssioning provided: (a) the FERC issues an order on rehearg in April 2011
granting all ofPacifiCorp's rehearig requests; (b) PacifiCorp's contractor agrees to a later notice to proceed date; (c) other paries to
the rehearng do not appeal the FERC's order; and (d) PacifiCorp can feasibly manage a 2011 decommissioning. Remaining
permitting includes a Section 404 permit from the United States Ary Corps of Engineers.
IFERC 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 04/18/2011 2010/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
Northwest Refund Case
For a discussion of the Nortwest 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 Admnistration ("MSHA"), which admisters
federal mine safety and health laws and regulations, and state reguatory agencies. MSHA has the statutory authority to institute a
civil action for relief, including a tempora or peranent injunction, restring order or other appropriate order against a mine
operator who fails to pay penalties or fines for violations of federl mine safety stadads. Federal law requires PacifiCorp to have a
wrtten emergency response plan specific to each underground mie it operates, which is reviewed by MSHA every six months, and
to have at least two rescue teams located within one hour of each mie. Refer to "Coal Mine Safety Disclosures Required by the
Dodd-Frank Wall Street Reform and Consumer Protection Act" below for fuher informtion regarding the coal mie and coal
processing facilities that PacifiCorp operates.
State Regulation
PacifiCorp pursues a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs.
Historically, state regulatory commissions have established rates on a cost-of-service basis, which are designed to allow a utility an
opportity 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 operating expenses, includig energy costs, opertion and maintenance expense, depreciation expense
and income. and other tax expense, reduced by wholesale electrcity sales and other revenue. The. allowed operating expenses are
tyically based on estimates of normalized costs, which may differ from realized costs in a given year covered by the established
rates. State regulatory commissions may adjust rates pursuant to a review of (a) the utility's revenue and expenses durg a defined
test period and (b) the utility's level of investment. State regulatory commissions tyically have the authority to review and change
rates on their own initiative; however, they may also initiate reviews at the request of a utility, utility customer, a governmental
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.
PacifiCorp's retail rates are generally based on the cost of providing trditional bundled services, including generation, transmission
and distrbution services. Historically, the state regulatory framework in PacifiCorp's service areas reflect specified net power costs as
par of bundled retail rates or incorporated net power cost adjustment clauses in PacifiCorp's retail rates andtarffs. In states where net
power cost adjustment clauses exist, permitted periodic adjustments to cost recovery from customers provide protection to PacifiCorp
against exposure to changes in net power costs.
Except for Oregon andW ashington, PacifiCorp has an exclusive right to serve customers within its service terrtories, and in tu, has
the obligation to provide electric service to those customers within its allocated service territory. Under Oregon law, PacifiCorp has
the exclusive right and obligation to provide electrc distrbution services to all customers within its allocated service terrtory;
however, nonresidential customers have the right to choose alternative electrcity service suppliers. The impact of these programs on
PacifiCorp's financial results has not been materiaL. In Washington, state law does not provide for exclusive service terrtory
allocation. PacifiCorp's service terrtory in Washington is surounded by other public utilities with whom PacifiCorp has from time to
time entered into service area agreements under the jursdiction of the WUÇ.
IFERC FORM NO.1 (ED. 12-96)Page 109.11
Name of Respondent .This Report is;Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifCorp I (2) A Resubmission 04/18/2011 2010/Q4
IMPORTANT CHANGES DÙRING THE QUARTERNEAR (Continued)
.
In addition to recovery through rates, PacifiCorpalso achieves recovery of certin costs though various adjustment mechanisms as
sumarzed below.
State Regulator Base Rate Test Period
Uta Public Service Commssion Forecasted or historical with
known and meaurable changes (I)("UPSC")
Oregon Public Utility Commsion Forecasted
Wyorrg Public Servce Commssion Forecasted or historical with
known and measable changes (I)
Washington Utilities and
Transporttion Commssion
Historial with known and
measurble changes
Idao Public Utilities Commssion Historical with known and
measurble changes
California Public Utilities
Commssion
Forecasted
Adjustment Mechanism
Energy balancing account ("EBA") under which 70% of the difference
between base net power costs established in a general rate case and actul
net power costs, subject to other adjustments, would be subject to the
EBA mechanism between the generl rate cases. The EBA wil be
effective October i, 2011.
A recovery mechanism is available f9r a single capital investmnt project
that in total exceeds 1 % of existing rate base when a general rate cae has
occurred withn the preceding 18 month.
Anual transition adjustment mechansm ("TAM") based on forecasted
net variable power costs; no tre-up to actul net varable power costs.
Renewable adjustment clause ("RAC") to recover the revenue requirement
of new renewable resources and associated transmission that are not
reflected in general rates.
Annual tre-up of taes authorized to be collected in rates compared to
taes paid by PacifiCorp, as defmed by Oregon statute and admistrtive
rules under SB 408.
Energy cost adjustment mechanism ("ECAM") under which 70% of any
difference between actual and forecated net power costs established in a
general rate case would be subject to the ECAM mechanism between
general rate cases.
Deferrl mechansm of costs for up to 24 months of new base load
generation resources and eligible renewable resources and related
trsmission that qualify under the state's emssions perormnce stadad
and are not reflected in general rates.
ECAM under which 90% of the difference between base net power costs
established in a general rate case and actul net power costs, subject to
other adjustments, would be subject to the ECAM mechanism between the
general rate cases.
Post test-year adjustment mechanism for major capital additions ("PT AM
- capital additions") that allows for rate adjustments outside of the context
of a trtional general rate cae for the revenue requirement associate
with capital addtions exceeding $50 million on a total-company basis.
Filed as eligible capital additions are placed into service.
Energy cost adjustment clause ("ECAC") that allows for an anual update
to actual and forecasted net varable power costs.
Post test-year adjustment mechanism for atttion ("PT AM - atttion"), a
mechansm that allows for an anual adjustment to costs other than net
varable power costs.
(1) PacifiCorp has relied on both historical test periods with known and measurble adjustments, as well as forecasted test perods.
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 (2) A Resubmission 04/18/2011 2010104
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
Generally,PacìfiCorp's demand-sìde management ("DSM") progr costs are collected though separately establìshed rates that are
adjusted periodìcally based on actual and expected costs, as approved by the respectìve state regulatory cornssìon. As such,
recovery ofDSM program costs has no ìrpact on net ìncome.
Rate Proceedings
FERC
As a result of a 2007 multì-par settlement wìth the FERC regarding long-term shared usage, coordìnated operatìon and maìntenance,
and plannìng of certìn 500-kV transmìssìon lìnes, PacìfiCorp agreed to fie a Federal Power Act Section 205 general rate change
filìng for ìts system.~wìde transmìssìon servìce rates no later than June 1, 2011. PacìfiCorp ìs ìn the process of preparg for thìsfilìng,
whìch wìl occur no later than the agreed upon date.
State Commissions
Utah
In March 2009, PacìfiCorp filed for anECAM wìth the UPSC. The filìng recommended that the UPSC adopt the mechanìsm to
recover the dìfference between base net power costs set ìn the next Uta general rate case and actual net power costs. In Februar
2010, PacìfiCorp filed an applìcation wìth the UPSC seekìng approval to defer the dìfference between the net power costs allowed by
the UPSC'sfinal order ìn PacìfiCorp's 2009 general rate case and the actual net power costs ìncured. Also ìn Februar 2010, the Utah
Assocìation of Energy Users fied a motion wìth the UPSC requestig deferrl of ìncremental renewable energy credit revenue ìn
excess of the renewable energy credit value utilìzed ìn Uta rates establìshed by the 2009 general rate case. In July 2010, the UPSC
ìssued an order approvìng a stipulation that would establìsh defered accounts for both net power costs and renewable energy credit
revenues ìn excess of the levels curently ìnc1uded ìn rates, subject to the UPSC's (mal detenìnatìon of the ratemakìng treatment of
the deferrals. In December 2010, the UPSC approved a separte stìpulatìon that provìdes a $3 mìlìon monthly credit to customers
effectìve January 1, 2011 that wìl be applìed toward the UPSC's final decìsìon. In March 2011, the UPSC ìssued ìts fmal order
approvìng the use of an EBA ìn Utah, whìch wìl begìn at the conc1usìon of the pending general rate case. Under the EBA, whìch wìl
begìn as a four year pìlot program, 70% of any dìfference between actual costs ìncured and those establìshed ìn base rates, subject to
certaìn other adjustments, wìl be subject to the EBA mechanìsm between general rate cases. The UPSC dìd not provìde the final
resolution of the dìfferences ìn net power costs and renewable energy credìt revenues from the 2009 general rate case, but ìndìcated
that ìt would address the potential deferrals separately from the March 2011 order. In Aprìl 201 1, PacìfiCorp fied a petìtion wìth the
UPSC for c1arìfication and reconsìderatìon of the final order.
In February 2010, PacìfiCorp filed an applìcation wìth the UPSC requestìng an ìncrease of $34 rnllon assocìated wìth two major
constrction projects that were completed and ìn servìce by June 2010. The applìcatìon requested recovery ìn conjunctìon wìth a
future rate change. In March 2010, PacìfiCorp updated ìts applìcatìon to reflect the cost of capìtal decìsìons from the February 2010
general rate case order, reducìng the amount requested for recovery to $33 mìlìon. In May 2010, a multi-part stipulation was filed
wìth the UPSC agreeìng to recovery of $31 rnllon. In June 2010, the stipulation was approved by the UPSC.
In August 2010, PacìfiCorp fied an applìcatìon wìth the UPSC requestìng an ìncrease of $39 rnl1on assocìated wìth two major
constrction projects expected to be complete and ìn servìce by December 2010. The applìcatìon requested a 5% ìncrease ìn rates
effectìve January 2011 encompassìng both the $39 rnllon requested ìncrease and the $31 rnllìon ìncrease approved by the UPSC ìn
June 2010. In December201O, the UPSC approved a stìpulatìon that provìdes for a $64 mìlìon ìncrease that encompasses both the
February 2010 and the August 2010 applìcations. The stìpulation also provìdes for collection of a one-tìme $16 mìlìon surcharge for
recovery of amounts related to the Februry 2010 applìcatìon that were deferred durg the period July 2010 to December 2010. The
new rates were effectìve Januar 1,2011.
In Januar 2011, PacìfiCorp filed a general rate case wìth the UPSC requesting a rate ìncrease of $232 mìlìon, or an average price
ìncrease of 14%. If approved by the UPSC, the rates wìl be effective September 201 1.
IFERC FORM NO.1 (ED. 12-96) Page 109.13
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
Oregon
In Februar 2010, PacifiCorp made its initial fiing for the annual TAM with the OPUC for an annual increase of $69 milion to
recover the anticipated net power costs forecasted for calenda year 2011. In July 2010, an all-part stipulation was filed with the
OPUC agreeing to an increase of $58 million, or an average price increase of 6%. The OPUC approved the all-part stipulation in
September 2010, subject to updates for anticipated net power costs through November 2010. PacifiCorp fied the scheduled updates to
net power costs in July and November 2010. In December 2010, PacifiCorp fied a final update to net power costs, reflecting an
increase of $60 million, or an average price increase of 6%. The OPUC approved the increase in December 2010 with an effective
date ofJanuar i, 2011.
In March 2010, PacifiCorp filed a general rate case with the OPUC requesting an increase of $131 million, or an average price
increase of 13%. In July 2010, a multi-par stipulation was filed with the OPUC agreeing to an anual increase of $85 million, or an
average price increase of 8%. The stipulation required PacifiCorp to file updated costs for the Populus to Terminal trnsmission line
once the asset was placed in service. In December 2010, PacifiCorp fied the updated costs based on the November 2010
placed-in-service date and reduced the annual increase to $80 million, or an average price increase of 8%. In December 201O,the
OPUC approved the stipulation. The new rates were effective Januar 1,2011.
In March 2011, PacifiCorpmade its initial fiing for the annual TAM with the OPUC for an annual increase of $62 milion, or an
average price increase of 5%, to recover the anticipated net power costs forecasted for calendar year 2012. The new rates wil be
effective Januar 1,2012 and are subject to updates throughout the proceeding.
Wyoming
In October 2009, PacifiCorp filed a general rate case with the WPSC requesting a rate increase of $71 milion with an effective date
of August 1, 2010. Net power costs included in the general rate case filing reflected an increase in coal costs and the expiration oflow
cost long-term power purchase contracts. The application was based on a test period ending December 31,2010. In March 2010, a
multi-part stipulation was fied 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. In May 2010, the WPSC approved the settlement agreement. The firt phase of the rate
increase, consisting of a $26 million increase, became effective July 1, 2010 and the second phase, consisting of the remaining
$10 milion increase, was effective Februar 1,2011.
In January 2010, PacifiCorp filed its anual power cost adjustment mechanism ("PCAM) application with the WPSC requestig
recovery of $8 million in deferred net power costs. In March 2010, a multi-part stipulation was filed with the WPSC agreeing to
reduce the requested recovery to $4 million. In May 2010, the WPSC approved the settlement agreement allowing for the change in
the PCAM surcharge rate effective April 1, 2010.
In April 2010, PacifiCorp fied an application with the WPSC requesting approval of a new ECAM to replace the existing PCAM.
The PCAM concluded with the final deferral of net power costs in November 2010 and collection through March 2012. In November
2010, the WPSC approved effective December 1, 2010, the deferral of net power costs incured above or below base net power costs
curently provided for in rates until the WPSC iSsues an order on PacifiCorp'sapplication for the ECAM. In November 2010, the
WPSç held heargs for the establishment and design of an ECAM. In February 2011, the WPSC issued an order approving an
ECAM under which the base net power costs wil be established in general rate cases based on forecasted net power costs and 70% of
any difference between actual and forecasted net power costs, subject to certain other adjustments, wil be subject to the ECAM
mechanism between general rate cases.
In Februar 2011, PacifiCorp filed its final PCAM application with the WPSC requesting recovery of $16 milion in deferred net
power costs. If approved by the WPSC, the application would result in an $11 milion rate increase over the $5 million curently
reflected in the tarff. PacifiCorp requested and received approval from the WPSC to implement an interim rate change effeëtive
April 1, 2011, which wil be in effect untilthe WPSC issues a final order.
IFERC FORM NO.1 (ED. 12-96)Page 109.14
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
In November 2010, PacifiCorp fied a general rate case with the WPSC requesting a rate increase of$98 million, or an average price
increase of 11%. If approved by the WPSC, the rates will be effective September 20 I i.
. Washington
In May 2010, PacifiCòrp filed a general rate case with the WUC requesting an anual increase of $57 milion, or an average price
increase of21 %. In November 2010, the requested anual increase was reduced to $49 milion, or an average price increase of 18%.
In March 201 i, the WUTC issued a final order and a clarfication letter approving an anual increase of $33 milion, or an average
price increase of 12%, offset in the first year by a customer bil crdit of $5 million, or 2% related to the sale of renewable energy
credits expected durng the rate year. The new rates were effective in April 201 1. In April 2011, PacifiCorp filed a petition for
reconsideration requestig the WUTC to reconsider varous items on the fial order including income tax and net power cost issues
and the WUTC's conclusions with respect to rate of retu. The petition wil be deemed denied if, within 20 days from the April 4,
201 i filing date, theWUTC does not either rule on the petition or issue a notice specifying the date it wil act on the petition.
Idaho
In February 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 effective April 1, 2010.
In May 2010, PacifiCorp fied a general rate case with the IPUC requesting an anual increase of $28 milion, or an average price
increase of 14%. In November 2010, the requested anual increase was reduced to $25 milion, or an average price increase of 12%.
In December 2010, the IPUC issued an interim order approving an anual increase of $ i 4 million, or an average price increase of 7%
with an effective date of December 28, 2010. In Februar 201 i, the IPUC issued its fmal order with no revisions to the December
2010 increase. In March 2011, PacifiCorp petitioned the IPUC seekig reconsideration or rehearig on certin aspects of the order. In
March 2011, the IPUC staff fied reply comments to PacifiCorp's motion for reconsideration accepting correctons identified by
PacifiCorp and providing for a slight increase in the recovery. In April 2011, the IPUC issued an order accepting in par and rejecting
in par PacifiCorp's petition for reconsideration resulting in no material effect on the IPUC's initial order.
In June 2010, the IPUC approved an increase to PacifiCorp's energy effciency rider to fud DSM programs of $1 million, or an
average price increase of 1%, with an effective date of July 1,2010. As a result of the 1% increase, the energy effciency rider
increased to 5%. In Deçember 2010, the IPUC reduced the energy efficiency rider to 3%.
In Februar 2011, PacifiCorp filed an ECAM application with the IPUC requestig recover of $13 milion in deferred net power
costs. In March 20 i i, the IPUC issued an order approving recovery of $10 million begiing in 2011 and the remaining $3 million
begining in 2012. The rate change was effective April 1, 2011.
California
In November 2009, PacifiCorp filed a general rate case with the CPUC requestig an annual increase of $8 milion, or an average
price increase of 10%. In June 2010, PacifiCorp filed an all-par settement agreement with the CPUC that reflects an annual increase
of $4 milion, or an average price increase of 5%, and includes the establishment of revised depreciation rates on California
distrbution assets. In September 2010, the CPUC approved the settlement agreement with an effective date of January 1, 201 i.
In August 2010, PacifiCorp filed an application with the CPUC to increase rates pursuant to the ECAC. In the application, PacifiCorp
requested a rate increase of $9 milion, or an average price increase of 1 1%. In November 2010, the CPUC approved the ECAC with
an effective date of Januar i, 20 i i.
IFERC FORM NO.1 (ED. 12-96)Page 109.15
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portolio stadads,
emissions pedormance standards, climate change, coal combustion bypròducts, 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 administered by the United States Environmental
Protection Agency (the "EPA") and various 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 continue 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. In addition to the following discussion, refer to Note 13
ófNotes to Financial Statements in this Form No. 1.
Clean Air Standards
The Clean Air Act is a federal law, administered by the EPA that provides a framework for protectig and improving the nation's air
quality and controllng sources of air emissions. The implementation of new standads is generally outlined in State Implementation
Plans ("SIPs"). SIPs, which are a collection of regulations, programs and policies to be followed, vary by state and are subject to
public hearngs and EPA approvài. Some states may adopt additional or more strgent requirements than those implemented by the
EPA. The major Clean Air Act programs, which most directly affect PacifiCorp's operations, are described below.
National Ambient Air Quality Standards
Under the authority of the Clean Air Act, the EPA sets minimum national ambient air quality standards for six principal. pollutants,
consisting of carbon monoxide, lead, nitrogen oxides, particulate matter, ozone and sulfu dioxide, considered harmful to public
health and the environment. Areas that achieve the standads, as determined by ambient air quality monitoring, are characterized as
being in attainment, while those that fail to meet the stadads are designated as being nonattainment 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 standads require measurement over a defined period of time to determne the average concentration of the pollutat present.
In December 2009, the EPA designated the Utah counties of Davis and Salt Lake, as well as portons of Box Elder, Cache, Tooele,
Utah and Weber counties, to be in nonattinment of the fine pariculate matter standard. This designation has the potential to impact
PacifiCorp's Little Mountain, Lake Side and Gadsby facilities, depending on the requirements to be established in the Utah SIP. The
impact on the PacifiCorp facilities is not anticipated to be significant.
In January 2010, the EPA proposed a rule to strengthen the national ambient air quality stadard for ground level ozone. The
proposed rule arises out oflegal challenges claiming that the March 2008 rule that reduced the stadard from 80 parts per bilion to 75
parts per bilion was not strct enough. The new rule proposes a standard between 60 and 70 pars per bilion. The EPA has delayed
issuance of the final ozone standards until July 2011.
In January 2010, the EPA finalized a one-hour air quality standard for nitrogen dioxide at 0.10 par per milion. State attainment
designations were required to be submitted to the EPA by Januar 1,2011, and the EPA must finalize the designations by Januar 1,
2012.
IFERC FORM NO.1 (ED. 12-96)Page 109.16
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2: An Original (Mo, Da, Yr)
PacifiCorp '2) . A Resubmission 04/18/2011 2010104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
In June 2010, the EPA finalized a new national ambient air quality stadad for sulfu dioxide. Under the new rule, the existing
24-hour and annual standards for sulfu dioxide, which were 140 par per bilion measured over 24 hour and 30 par per bilion
measured over an entire year, were replaced with a new one-hour stadad of 75 pars per bilion. The new rule wil utilize a
three-year average to determine attinment. The rule wil utilize source modeling, in addition to the installation of ambient monitors
where sulfu dioxide emissions impact populated areas, with new monitors required to be in-service no later than Januar 2013.
Attinent designations are due by June 2012, with SIPs due by 2014 and final attinment demonstrations by August 2017.
As new, more strngent standards are adopted, the number of counties designated as non attinment areas is likely to increase.
Businesses operating in newly designated nonattinent counties could face increased regulation and costs to monitor or reduce
emissions. For instance, existing major emissions sources may have to install reasonably available control technologies to achieve
certin reductions in emissions and underte additional monitorig, recordkeeping and reportng. The constrction or modification of
facilities that are sources of emissions could become more diffcult in nonattinment areas. Until additional monitorig and modeling
is conducted, the impacts on PacifiCorp canot be determined.
Hazardous Air Pollutant Maximum Achievable Control Technology
The EPA issued the proposed Hazardous Air Pollutat Maximum Achievable Control Technology rule for coal- and oil-fueled
electrc generating units in March 2011. The proposed rule sets standards for lOnon-mercur hazardous air pollutant ("HAP") metals,
mercury and acid gases and establishes work practices to minmize emissions of organic HAPs. The proposed rule establishes numeric
emission limits for mercur, total metals, parculate matter and hydrogen chloride, which wil be effective three years after the final
rule is issued. The EPA indicated the public comment period would be open for 60 days after the proposed rule is published in the
Federal Register and the final rule would be issued in November 2011. PacifiCorp is reviewing the proposed rule; the impacts on
PacitiCorp have not yet been determned.
Regional Haze
The EPA has initiated a regional haze program intended to improve visibilty in designated federally protected areas ("Class I areas").
Some of PacifiCorp's generatig facilities meet the threshold applicabilìty criteria to be eligible units uider the Clean Air Visibility
Rules. In accordance with the federal requirements, states were required to submit SIPs by December 2007 to demonstrte reasonable
progress towards achieving. natural visibility conditions in Class I areas by requirng emissions 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 visibility. Wyoming issued best available retrofit technology permits to PacifiCorp on December 31,2009, requirig
PacifiCorp to implement emissions control projects that are consistent with the planned emissions reduction projects at PacifiCorp's
Wyoming generatig facilities. PacifiCorp appealed certin provisions of the Naughton and Jim Bridger generating facilities' permits,
but the appeals were settled. Utah submitted its SIP and suggested that the emissions reduction projects planned by PacifiCorp are
suffcient to meet its initial emissions reduction requirements. Utah amended its regional haze SIP in April 2011 and submitted the
revisions to the EPA for consideration. In Januar 2009, the EPA found that 37 states, including Wyomig, had failed to file a SIP
that met some or all of the basic regional haze program requirements. Wyoming submittd its regional haze SIP to the EPA in
January 2011. PacifiCorp believes that its planned emissions reduction projects wil satisfy the regional haze requirements in Utah and
Wyoming. It is possible that additional controls may be required after the respective SIPs have been considered by the EPA or that the
timing of installation of planned controls could change.
IFERC FORM NO.1 (ED. 12-96)Page 109.17
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
New Source Review
Under existing New Source Review ("NSR") provisions of the Clean Air Act, any facility that emits regulated pollutants is required to
obtain a pennt from the EPA or a state regulatory agency prior to (a) begining constrction of a new major stationar source of a
regulated pollutant or (b) making a physical. or operational change to an existing stationar source of such pollutants that increases
certin levels of emissions, unless the changes are exempt under the regulations (including routie maintenance, repair and
replacement of equipment). In general, projects subject to NSR regulations require pre-constrction review and permittg under the
Prevention of Significant Deterioration ("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 ofNSR regulations, which may be alleged by
the EPA, states, environmental groups and others, potentially subject a company to materal fies 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 supportng documentation from numerous utilities regarding their capital projects for varous generating facilities. A NSR
enforcement case against an unelated utility has been decided by the United States Supreme Cour, holding that an increase in the
anual emissions of a generating facility, when combined with a modification (i.e., a physical or operational change), may trgger
NSR permitting. Between 2001 and 2003, PacifiCorp responded to requests for information relating to its capital projects at its
generating facilities. PacifiCorp has been engaged in periodic discussions with the EPA over several 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 time; however, PacifiCorp could be required to install additional emissions
controls and incur additional costs and penalties in the event it is detennned that PacifiCorp's historical 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, . differig interpretations by the EPA and the cours create risk and uncertinty for entities when seeking pennts for new
projects and installing emissions controls at existing facilities under NSR requirements. PacifiCorp monitors these changes and
interpretations to ensure penntting 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 ("GHG") emissions. The United States Congress has considered, but has not adopted comprehensive climate change
legislation, which included a market-based cap-and~trade program that was intended to reduce GHG emissions 83% below 2005
levels by 2050.
In December 2009, the EPA published its findings that GHG threaten the public health and welfare and is pursuing regulation of
GHG emissions under the Clean Air Act. Additionally, in May 2010, the EPA issued the greenhouse gas "tailoring rule" to address
permitting requirements for GHG after determining that GHG are subject to regulation and would trgger Clean Air Act pennttng
requirements for stationary sources begining in January 2011. Numerous lawsuits have been filed on both the EPA's endangerment
finding and the tailoring rule and are pending in the D.C. Circuit.
PacifiCorp supports the implementation of reasonable emissions caps, but opposes trading mechanisms that impose additional costs
and do not result in decreased emissions. PacifiCorp also believes that any law or regulation should provide a reasonable transition
period to allow the phase in of low-carbon generating technologies that wil achieve sustainable and cost-effective GHG emissions
reduction benefits.
IFERC FORM NO.1 (ED. 12-96)Page 109.18
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp '2)A Resubmission 04/18/2011 2010104
IMPORTANTCHANGES DURING THE OUARTERIEAR (Continued)
While the debate contiues at the federal and international level over the direction of climate change policy, several states have
developed or are developing stte-specific laws or regional initiatives to report or mitigate GHG emissions. In addition, governental,
non-governental and environmental organizations have become more active in pursuing climate change related litigation under
existing laws.
PacifiCorp voluntaly reports its GHG emissions to the California Climte Action Registr and The Climate Registr. In September
2009, the EPA issued its final rule regarding mandatory reprtg of GHG ("GHG Reporting") begining Januar 1, 2010. Under
GHG Reportng, suppliers of fossil fuels, manufacturs of vehicles and engines, and facilities that emit 25,000 metrc tons or more
per year ofGHG are required to submit annual report to the EPA. PacifiCorp is subject to this requirement. The EPA deferred the
fiing of the first report from March 31, 2011 to September30, 2011 to incorporate changes to its electronic reporting system.
PacifiCorp is commtted to operating in an environmentally responsible maner. Examples of PacifiCorp's significant investments in
progrs and facilities that wil mitigate its GHG emissions include:
· PacifiCorp owns the second largest portfolio of wind-powered generating capacity in the United States among rate-regulated
utilities. As of December 31, 2010, PacifiCorp owned 1,032 MW of wind-powered generating capacity and has purchase
power agreements with 705 MW of wind-powered generatig capacity. PacifiCorp has invested $2.1 bilion in
wind-powered generating facilities.
. PacifiCorp owns 1,157 MW of hydroelectrc generatig capacity.
. PacifiCorp's Energy Gateway Trasmission Expansion Program reresents a plan to build approximately 2,000 miles of new
high-voltage transmission lines with an estiated cost exceeding $6 bilion. The plan includes several trnsmission line
segments that wil: (a) address customer load growth; (b) improve system reliability; (c) reduce transmission system
constraints; (d) provide access to diverse generation resources, including renewable resources; and (e) improve the flow of
electrcity thoughout PacifiCorp's six-state servce area.
· 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.
· PacifiCorp has installed and upgraded emissions control equipment at certin of its coal-fired generating facilities to reduce
emissions of sulfu dioxide and nitrogen oxides.
The impact of pending federal, regional, state and international accords, legislation, regulation, or judicial proceedings related to
climate change cannot be quantified in any meaningful range at this time. New requirements limiting GHG emissions could have a
material adverse impact on PacifiCorp, the United States and the global economy. Companies and industries with higher GHG
emissions, such as utilities with significant coal-fired generating facilities, wil be subject to more diect 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 timng of GHG emissions reduction requirements; the design of the
requirements; the cost, availability and effectiveness of emissions control technology; the price, distrbution method and availability
of offsets and allowances used for compliance; governent-imposed compliance costs; and the existence and nature of incremental
cost recovery mechanisms. Examples of how new requirements may impact PacifiCorp include:
· Additional costs may be incured to purchase required emissions allowances under any 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 carbon generation is available;
IFERC FORM NO.1 (ED. 12-96)Page 109.19
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 04/18/2011 2010104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
. Acquinng and renewing constrction and operating permts for new and existing facilities may be costly and diffcult;
. Additional costs may be incured to purchase and deploy new generating technologies;
. Costs may be incured to retie existing coal facilities before the end of their otherwise useful lives or to convert them to bur
fuels, such as natual gas or biomass, that result in lower emissions;
. Operating costs may be higher and unit outputs may be lower;
. 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 financial nsk; and
. PacifiCorp's electrc transmission and retail sales may be impacted in response to changes in customer demand and
requirements to reduce GHG emissions.
PacifiCorp expects it wil be allowed to recover the prudently incured costs to comply with climate change requirements.
The impact of events or conditions caused by climate change, whether from natural processes or humn activities, could var widely,
from highly localizedto worldwide, and the extent to which a utility's operations may be affected is uncertin. Climate change may
cause physical and financial nsk through, among other things, sea level nse, changes in precipitation and extreme weather events.
Consumer demand for energy may increase or decrease, based on overall changes in weather and as customers promote lower energy
consumption through the continued use of energy effciency progrms 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 generatig portfolio. These issues may have a direct impact on the costs of
electrcity production and increase the pnce customers payor their demand for electrcity.
International Accords
Under the United Nations Framework Convention on Climate Change, adopted in 1992, members of the convention meet penodically
to discuss international responses to climate change. To date, the United States has not made a binding reduction commitment as a
result of these international discussions.
IFERC FORM NO.1 (ED. 12-96)Page 109.20
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/18/2011 2010104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
Federal Legislation
In June 2009, the United States House of Representatives passed the American Clean Energy and Securty Act of 2009
("Waxman-Markey bil"). In addition to a federal renewable portfolio standad ("RPS"), which would have required utilities to obtain
a portion of their energy from certain qualifying renewable sOurces and energy effciency measures, the bil required a reduction in
GHG emissions begining in 2012, with emissions reduction targets of 3% 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. Similar legislation was
introduced in the Senate, but it did not pass.
Greenhouse Gas Tailoring Rule
The EPA finalized the GHG "tailorig rule" in May 2010 requirg new or modified sources of GHG emissions with increases of
75,000 or more tons per year of total GHG to determine the best available control technology for their GHG emissions beginnng in
Januar 2011. New or existing major sources wil also be subject to Title V operating permt requirements for GHG. Beginning July
1, 2011 through June 30, 2013, new constrction projects that emit GHG emissions of at least 100,000 tons per year and
modifications of existing facilities that increase GHG emissions by at least 75,000 tons per year wil be subject to permitting
requirements and facilities that were previously not subject to Title V permittng requirements will be required to obtain Title V
permts if they emit at least 100,000 tons per year of carbon dioxide equivalents. Several legal challenges have been filed to the EPA's
final GHG tailoring rule in the D.C. Circuit. The EPA issued a GHG best available control technology guidance document in
November 2010 in an effort to provide permttg authorities guidace on how to conduct abest available control technology review
for GHG. Until the permittng authorities begi to implement the tailorig rule and dèterme what constitutes best available control
technology for GHG, the impacts of the tailorig rule on PacifiCorp canot be fully determed.
Regional and State Activities
Several states have developed state-specific laws or regional legislative intiatives to report or mitigate GHG emissions thatare
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 acap-and-trade program that includes the electrcity sector. The Western Climate Initiative includes the states
of California, Montana, New Mexico, Oregon, Utah and Washington and the Canadian provinces of British Columbia,
Manitoba, Ontao and Quebec. The state and provincial parers have agreed to begin reportng GHG emissions in 2011 for
emissions that occured in 2010. The fit phas of the cap-and-tre progr is scheduled to 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. The California Air Resources Board proposed regulations
to adopt a GHG cap-atd-trade program in October 2010; however, those regulations have not yet been fmalized. In addition,
California has adopted legislation that imposes a GHG emissions performance standard to all electrcity generated within the
state or delivered from outside the state that is no higher than the GHG emissions levels of a state-of-the-ar combined-cycle
natual gas-fired generating facility, as well as legislation that adopts an economy-wide cap on GHG emissions to 1990
levels by 2020.
· Over the past several years, the states of California, Washington and Oregon have adopted GHG emissions performance
standads for base load electrcal generating resources. Under the laws in all three states, the emissions performance
standads provide that emissions must not exceed 1,100 Ibs of carbon dioxide per megawatt hour ("MW"). These GHG
emissions performance standards generally prohibit electrc utilities from entering into long-term financial commtments
(e.g., new ownership investments, upgrades, or new or renewed contracts with a term of 5 or more years) unless any base
load generation supplied under long-term financial commtments comply with the GHG emissions performance standards.
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 1(2)A Resubmission 04/18/2011 2010/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
. 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 growt of Oregon GHG
emissions by 2010; (b) reduce GHG levels toJO% 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 monitorig and achievement ofthèse goals.
Renewable Portfolio Standards
The RPS descnbed below could significantly impact. PacifiCorp's financial results. Resources that meet the qualifying electrcity
requirements under the RPS vary from state to state. Each state's RPS requires some form of compliance reportg and PacifiCorp can
be subject to penalties in the event of noncompliance.
In November 2006, Washington voters approved a ballot initiative establishing a RPS requirement for qualifying electrc utilties,
including PacifiCorp. The requirements are 3% of retail sales by Januar 1, 2012 through 2015, 9% of retail sales by Januar 1, 2016
through 2019 and 15% of retail sales by January 1,2020. The WUTC has adopted final rules to implement the initiative.
In June 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 electricity sold to retail customers of at least 5% in 2011 though 2014,
15% in 2015 though 2019, 20% in 2020 through 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 transmission costs.
In 2011, the California Legislatue passed, and the governor signed, legislation to expand the state's RPS to require 20% of retail load
to be procured from renewable resources by December 31,2013,25% by December 31,2016 and 33% by December 31,2020 and
each year thereafter. The new law wil likely supersede the California Air Resources Board 33% renewable electrcity standad
adopted pursuant to Executive Order S-21-09 in September 2009. The 2011 legislation expands the RPS to all Californa retail sellers,
provides additional flexible compliance mechanisms for retail sellers and modifies the types of renewable electrcity products that
may be used to comply with the law.
In March 2008, Uta's governor signed Utah Senate Bil 202. Among other things, this law provides that, beginning in the year 2025,
20% of adjusted retail electrc sales of all Utah 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.
IFERC FORM NO.1 (ED. 12-96)Page 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 04/18/2011 2010/Q4
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
Water Quality Standards
The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality
in the United States though a progrm that regulates, among other things, discharges to and withdrawals from waterways. The Clean
Water Act requires that cooling water intae strctues reflect the "best technology available for minimizing adverse environmental
impact" to aquatic organisms. In July 2004, the EPA established signficant new technology-based performance standards for existing
electrc generating facilities that take in more than 50 millon gallons of water per day. These rules are aimed at minimzing the
adverse environmenta impacts of cooling water intae strctues by reducing the number of aquatic organisms lost as a result of
water withdrawals. In response to a legal challenge to the rue, in Janua 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 permssibly
relied on a cost~benefit analysis in setting the national performce standads regarding "best technology available for minimiing
adverse environmental impact" at cooling water intake strctues and in providing for cost-benefit variances from those stadads as
par of the §316(b) Clean Water Act Phase II regulations. The United States Supreme Cour remanded the case back to the Second
Circuit to conduct fuer proceedings consistent with its opinion. Compliance and the potential costs of compliance, therefore, cannot
be ascertined until such time as the Second Circuit taes action or fuher action is taen by the EPA. Curently, PacifiCorp's Dave
Johnston generating facility, which has water cooling towers, exceeds the 50 million gallons of water per day intake threshold. In the
event that PacifiCorp's existing intae 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 permts.
Coal Combustion Byproduct Disposal
In December 2008, an ash impoundment dike at the Tennessee 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 the storage and disposal of coal combustion byproducts.
In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion bypro ducts, presentig
two alternatives tò regulation under the Resource Conservation and Recovery Act ("RCRA"). Under the fist option, coal combustion
byproducts would be regulated as special waste under RCRA Subtitle C and the EPA would establish requirements. for coal
combustion byproducts from the point of generation to disposition, including the closure of disposal units. Alternatively, the EPA is
considerig regulation under RCRA Subtitle D under which it would establish minimum nationwide standards for the disposal of coal
combustion byproducts. Under both options, surace impoundments utilized for coal combustion byproducts would have to be cleaned
and closed unless they could meet more strgent regulatory requirements; in addition, more strgent requirements would be
implemented for new ash landflls and expansions of existing ash landfills. PacifiCorp operates 16 surface impoundments and six
landfills that contain coal combustion byproducts. These ash impoundments and landfills may be impacted by the newly proposed
regulation, partcularly if the materials are regulated as hazardous or special waste under RCRA Subtitle C, and could pose significant
additional costs associated with ash management and disposal activities at PacifiCorp's coal-fired generating facilities. The public
comment period closed in November 2010; however, the timng of the final rule is not known. The impact of the proposed regulations
on coal combustion byproducts cannot be determned at this time.
IFERC FORM NO.1 (ED. 12-96)Page 109.23
Name of Respondent (i This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
.IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
Other
Other laws, regulations and agencies to which PacifiCorp is subject to 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 trnsporters or generators of hazardous substances
sent to such disposal site, to share in environmental remediation costs.
. The federal Sudace Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation
and closure standards that must be met durg and upon completion of mining activities.
. 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 systems, dam safety inspections and environmental monitorig. Refer to
Note 13 of Notes to Financial Statements in this Form No.1 for additional information 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 Integrated Resource Plan ("IRP") to develop a long-term view of prudent
futue ac.tions 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 tiing of PacifiCorp's expected futue resource needs and an associated optimal futue
resource mix that accounts for planning uncertinty, risks, reliability impacts, state energy policies and other factors. The IRP is a
coordinated effort with staeholders in each of the six states where PacifiCorp operates. PacifiCorp fies its IR on a biennial basis
and receives a formal notification in five states as to whether the IRP meets the commission's IR standads and guidelines, referred to
as acknowledgment. PacifiCorp has received acknowledgment of its 2008 IRP from the state commissions in Oregon, Utah,
Washington, Idaho and Wyoming. In March 2011, PacifiCorp filed its 2011 IRP with the state commissions.
Requests for Proposals
PacifiCorp has issued a series of individual Requests for Proposals ("RFPs"), each of which focuses on a specific category of electrc
generation resources consistent with the IRP. The IRP and the RFPs provide for the identification and staged procurement of
resources in futue years to achieve a balance of load requirements and resources. As required by applicable laws and regulations,
PacifiCorp fies draft RFPs with the UPSC, the OPUC and 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-1 renewable resources RFP (approved by the OPUC in September 2008), PacifiCorp
executed a power purchase agreement to purchase the entie output of the 200-MW Top of the World wind-powered generatig
facility located in Wyomig and the associated renewable energy credits. The generating facility reached commercial operation in
October 2010, and the power purchase agreement wil continue for a period of 20 years. PacifiCorp's 2009R 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 ll1-MW Dunlap Ranch I wind-powered generating facility
located in Wyoming was constrcted and placed in servce in October 2010.
IFERC FORM NO.1 (ED. 12-96)Page 109.24
.
Name of Respondent This Report is:Date of Report 'lear/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
IMPORTANT CHANGES DURING THE QUARTERlEAR(Continued)
In October 2009, PacifiCorp filed a request for approval with the UPSC to re-issue the All Source RFP, which was previously
suspended in Apn12009. In October 2009 and November 2009, respectively, the UPSC and the OPUC approved resumption of the
All Source RFP. The All Source RFPseeks up to 1,500 MW on a system wide basis from projects with in-service dates from 2014
though 2016. In December 2009, the All Source RFP was issued to the market. As a result, PacifiCorpsignedan engineer, procure
and constrct contract, subject to regulatory approval, for the approximately 637-MW Lake Side 2 natual gas-fired combined-cycle
generatig facility, which is expected to be placed in service by June 2014. The Lake Side 2 generatig facility will be constrcted
adjacent to PacifiCorp's Lake Side generatig facility, which is located in Vineyard, Utah, about 40 miles south of Salt Lake City.
PacifiCorp expects that the UPSC wil issue an order approving the con.strction of Lake Side 2 in the sprig of 20 11.
Demand-side Management
PacifiCorp has provided a comprehensive set of DSM program to its customers since the 1970s. The programs are designed to
reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Curent
programs offer services to customers such as energy engineerig audits and informtion on how to improve the effciency of their
homes and businesses. To assist customers in investig in energy effciency, PacifiCorp offers rebates or incentives encourging the
purchase and installation of high-effciency equipment such as lightig, heatig and cooling equipment, weathenzation, motors,
process equipment and systems, as well as incentives for effcient constrction. Incentives are also paid to solicit participation in load
management programs by residential, business and agrcultual customers though programs, such as. PacifiCorp's residential and
small commercial air conditioner load control program and irgation equipment load control programs. Although subject to prudence
reviews, state regulations allow for contemporaneous recovery of costs incured for the DSM programs though state-specific energy
efficiency surcharges to retail customers or for recovery of costs though rates. In addition to these DSMprograms, PacifiCorp has
load curilment contracts with a number of large industral customers that deliver up to 305 MW of load reduction when needed.
Recover for the costs associated with the large industral load management progr is determned through PacifiCorp's general rate
case process. Durng 2010, $113 million was expended on PacifiCorp's DSM programs, resultig in an estimated 499,054 MW of
first-year energy savings and an estimated 481 MW of peak load management. Total demand-side load available for control durng
2010, including both load management from the large industral curilment contracts and DSM programs, was 718 MW.
Collateral and Contingent Features
PacifiCorp's senior secured and senior unsecured debt credit ratigs are as follows:
Fitch Moody's Standard & Poor's
Senior
A-
BBB+
Stable
Baal A-
Debt and preferred securities of PacifiCorp are rated by credit ratig agencies. Assigned credit ratings are based on each ratig
agency's assessment of PacifiCorp's ability to, in general, meet the obligations of its issued debt or preferred secunties. The credit
ratings are not a recommendation to buy, sell or hold securties, and there is no assurance that a partcular credit rating wil contiue
for any given penod of time.
PacifiCorp has no credit rating downgrade 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 mimum credit ratig level in order to drw upon their availability. However, commtment fees and
interest rates under the credit facilities Ìre tied to credit ratings and increase or decrease when the ratings change. A ratigs
downgrade could also increase the futue cost of commercial paper, short- and long-term debt issuances or new credit facilities.
Certin authonzations or exemptions by regulatory commissions for the issuance of securties are valid as long as PacifiCorp
maintains investment grade ratings on senior secured debt. A downgrade below that level would necessitate new regulatory
applications and approvals.
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 1(2) A Resubmission 04/18/2011 2010104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
In accordance with industr practice, certin wholesale energy agreements, including derivative contracts, contain provisions that
require PacifiCorp to maintain specific credit ratngs on its unsecured debt from one or more of the three recognized credit rating
agencies. These agreements, including derivative contracts, may either specifically provide bilateral rights to demand cash or other
securty if credit exposures on a net basis exceed specified ratg-dependent threshold levels ("credit-risk-related contigent featues")
or provide the right for counterpares to demand "adequate assurance" in the event of a material adverse change in PacifiCorp's
creditworthiness. These rights can vary by contract and by counterpart. As of December31, 2010, PacifiCorp's credit ratings from
the three recognized crédit rating agencies were investment grade. If all credit-risk-related contigent featues or adequate assurance
provisions for these agreements, including derivative contracts, had been trggered as of December 31,2010, PacifiCorp would have
been required to post $225 milion of additional collateraL. PacifiCorp's collateral requirements could fluctuate considerably due to
market price volatility, changes in credit ratings, changes in legislation or regulation or other factors. Refer to Note 7 of Notes tö
Financial Statements in this Form NO.1 for a discussion of PacifiCorp's collateral requirements specific to PacifiCorp's derivative
contracts.
In July 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act ("Reform Act"). The
Reform Act reshapes financial regulation in the United States by creating new regulators, regulating new markets and firm and
providing new enforcement powers to regulators. Virally all major areas of the Reform Act, including collateral requirements on
derivative contrcts, wil be the subject of regulatory interpretation and implementation rules requiring rulemaking proceedigs that
may tae several years to complete.
PacifiCorp is a par to derivative contracts, including over-the-counter derivative contracts. The Reform Act provides for extensive
new regulation of over-the-counter derivative contracts and certain market partcipants, including ìmposition of mandatory clearng,
exchange trading, capital and margin requirements for "swap dealers" and "major swap parcipants." The Reform Act provides
certin exemptions from these regulations for cOmmercial end-users that use derivatives to hedge and manage the commercial risk of
their businesses. Although PacifiCorp generally does not enter into over~the-counter derivative contracts for puroses unelated to
hedging of commercial risk and does not believe it will be considered a swap dealer or major swap partcipant, the outcome of the
rulemaking proceedings canot be predicted and, therefore, the impact of the Reform Act on PacifiCorp's financial results cannot be
detennined at this time.
Coal Mines
PacifiCorp has interests in coal mines that support its coal-frred generating facilities. These mines supplied 29% and 31% of
PacifiCorp's total coal requirements durng the years ended December 31, 2010 and 2009, respectively. The remaining coal
requirements are acquired through long- and short-term third-part contracts.PacifiCorp's mines are located adjacent to cerin of its
coal-frred generating facilities, which significantly reduces overall trnsportation costs included in fuel expense. Most ofPacifiCorp's
coal reserves are held puruant to leases from the federal governent through the Bureau of Land Management and from certin
states and private partes. The leases generally have multi-year term that may be renewed or extended only with the consent of the
lessor and require payment of rents and royalties. In addition, federal and state regulations require that comprehensive environmental
protection and reclamation standards be met durng the course of mining operations and upon completion of mining activities.
IFERC FORM NO.1 (ED. 12-96) Page 109.26
.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/04
IMPORTANTCHANGES DURING THE OUARTERIEAR (Continued)
Coal reserve estimates are subject to adjustment as a result of the development of additional engineering and geological data, new
mining technology and changes in regulation and economic factors affectig the utilization of such reserves. Recoverable coal
reserves as of December 31, 2010, based on PacifiCorp's most recent engierig studies, were as follows (in milions):
Coal Mine Location Generating Facilty Served Mining Method Recoverable Tons
(I) These coal reseres are leased and mined by Bridger Coal Company, ("Bridger Coal") a joint ventu between PMI and a subsidiary ofIdaho Power. PMI, a
wholly owned subsidiar of PacifiCorp, has a two-thrds inteest in the joint ventue. The amounts included above represent only PacifiCorp's two-thrds
interest in the coal reseres.
(2) These coal reserves are leaed by PacifiCorp and mined by a wholly owned subsidiar ofPacifiCorp.
(3) These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware non-stock corpration operated on a coopertive basis, in which PacifiCorp
has an ownership interest of 2 1%. The amount included above reresents only PacifiCorp's 2 i % inteest in the coal reserves. PacifiCorp does not operate the
Trapper Mine.
For sudace mine operations, PacifiCorp removes the overburden with heavy earh-moving equipment, such asdraglines and power
shovels. Once exposed, PacifiCorp drlls, fractues and systematically removes the coal using haul trcks or conveyors to transport the
coal to the associated generating facility. PacifiCorp reclaims distubed areas as part of its normal mining activities. Aftr final coal
removal, draglines, power shovels, excavators or loaders are used to backfill the remaining pits with the overburden removed at the
begining of the process. Once the overburden and topsoil have been replaced, vegetation and plant life are re-established, and other
improvements are made that have local community and environmental benefits. Draglines are used at the Bridger sUDace mine and
draglines with shovels and trcks are used at the Trapper sUDace mine.
F or underground mine operations, a longwall is used as a mechanical shearer to extrt coal. from long rectangular blocks of medium
to thick seams. In longwall mining, PacifiCorp also uses continuous miners to develop access to these long rectangular coal blocks.
Hydraulically powered support temporarily hold up the roof of the mine while a rotatig drm mechanically advances across the face
of the coal seam, cutting the coal from the face. Chain conveyors then move the loosened coal to an underground mie conveyor
system for delivery to thesudace. Once coal is extracted from an area, the roof is allowed to collapse in a controlled fashion.
PacifiCorp operates the Deer Creek, Bridger sUDace and Bridger underground coal mines, as well as the Cottonwood Preparatory
Plant and Wyoda Coal Crushing Facility. Refer below for fuer information about the coal mies and coal processing facilities that
PacifiCorp operates.
Recoverability by sUDace mining methods tyically ranges from 90% to 95%. Recoverability by underground ming techniques
ranges from 50% to 70%. To meet applicable standards, PacifiCorp blends coal mied at its owned mines with contracted coal and
utilizes emissions reduction technologies for controlling sulfu dioxide and other emissions. For fuel needs at PacifiCorp's coal-fired
generating facilities in excess of coal reserves available, PacifiCorp believes it will be able to purchase coal under both long- and
short-term contracts to supply its generatig facilities with coal over their curently expected remaining useful lives.
Durng the year ended December 31,2010, PacifiCorp-owned coal-fired generating facilities held suffcient sulfu dioxide emission
allowances to comply with the EPA Title IV requirements.
IFERC FORM NO.1 (ED. 12-96)Page 109.27
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp I (2) A Resubmission 04/18/2011 2010/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
Coal Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act
The operation of PacifiCorp's coal mines and coal processing facilities. is regulated by MSHA under the Federal Mine. Safety and
Health Act of 1977 ("Mine Safety Act"). MSHA inspects PacifiCorp's coal mines and coal processing facilities on a reguar basis and
may issue citations, notices, orders, or any combination thereof, when it believes a violation has occured under the Mine Safety Act.
For citations, monetar penalties are assessed by MSHA. Citations, notices and orders can be contested and appealed and the severity
and assessment of penalties may be reduced or, in some cases, dismissed through the appeal process.
The table below summares the total number of citations, notices and orders issued and penalties assessed by MSHA for each coal
mine or coal processing facility operated by PacifiCorp under the indicated provisions of the Mine Safety Act durg the thee- and
six-month periods ended December 31,2010. Legal actions pending before the Federal Mine Safety and Health Review Commission,
which are not exclusive to citations, notices, orders and penalties assessed by MSHA,are as of December 31, 2010. Closed or idled
mines have been excluded from the table below as no citations, orders or notices were issued for such mines durg the thee- and
, six-month periods ended December 31, 2010. In addition, there were no fatalities at PacifiCorp's coal mines or coal processing
facilities durng the three- and six-month periods ended December 31, 2010.
Coal Mine or
Coal Processing Facilty
Three-month period ended
December 31, 2010
Deer Creek
Bridger (surace)
Bridger (undergound)
Cottonwood Preparatory Plant
Wyod Coal Crushing Facilty
Six-month period ended
December 31,2010
Deer Creek
Mine SafetyAct
Total
Section Value of
Section 104(a)Section 107(a)Proposed
Signifcant &Section 104(d)Section Imminent Section MSHA Legal
Substantial 104(b)Citations &1l0(b)(2)Danger 104(e)Assessments Actions
Citations(l)Orders(2)Orders(3)Citations(4)Orders(5)Notice(6)(in thousands)Pending
3
2
7
3 6
Bridger (surface)
Bridger (undeound)
Cottonwood Preparatory Plant
Wyoda Coal Cruhing Facility
13
4
16
7
17
6
IFERC FORM NO.1 (ED. 12-96)Page 109.28
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp 1(2)A Resubmission 04/18/2011 2010104
IMPORTANT CHANGES DURING THE QUARTERIEAR (Continued)
(I) For alleged violations ofa'inining safety stadad or regulation where ther exists a reasonable likelihood that the hazard contrbuted to or wil result in an
injur or illness of a reasonably serious natue.
(2) For aUeged failure to totally abate the subject mattr of a Mine Safety Act section 104(a) citation within the period specified in the citation.
(3) For an alleged unwarrantable failure (i.e., aggrvated conduct constituting more than ordinar negligence) to comply with a mining safety stadad or
regulation.
(4) For alleged flagrnt violations (i.e., reckless or reate failur to mae renable effor to elimiate a known violation of a madatory health or safety
stadad that substatially and proximately caused, or reaonably caus or reasably could have bee expected to cause, death or serious bodily injur).
(5) The total number of iminent dager order (i.e., the existece of any condition or pratice in a coal or other mine which could reasonably be expected to
cause death or serious physical har before such condition or prtice can be abat).
(6) For a pattrn, or the potential to have a pattern, of violations of madatory health or safety stadads that are of such natue as could have signficatly and
substantially contrbuted to the cause and effect of coal or other mine health or safety hazds.
ITEM 13.
Offcer & Director Changes
PacifiCorp discloses information for its "named executive offcers" ("NEOs") consistent with Item 402 of Regulation S-K
promulgated by the SEC in its Anual Report on Form 10-K.
On Januar 13,2010, A. Robert Lasich accepted the position of Vice President and General Counsel, Procurement for MEHC, and
accordigly resigned as President of PacifiCorp Energy, a business unit of PacifiCorp, and as director of PacifiCorp, both effective
February 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 previously served as President of Kern River Gas Transmission Company ("Kern River") since
June 2007. Prior to that, Mr. Dunn served as Vice President of Operations, Information Technology and Engineerig at Kern River.
Kern River is an indirect subsidúiry ofMEHC.
ITEM 14.
Not applicable.
IFERC FORM NO.1 (ED. 12-96)Page 109.29
Deloitte~Deloitt & Touche LLP
3900 U.S. Sancorp Towr
111 S.W. Fift Ave.
Portland. OR 97204-3642
USA
Tel: [phone]
Fax: [phone]
ww.deloite.com
INDEPENDENT AUDITORS' REPORT
PacifiCorp
Portland, Oregon
We have audited theconsoIidated balance sheet - regulatory basis ofPacifCorp and subsidiaries (the
"Company') as of December 31, 2010, and the relate consolidated statements of income - regulatory
basis; retained eatngs - reguatory basis; and cash flows - regulatory basis, for the yeai then ended,
included on pages 110 though 123 of the accompanying Federa Energy Reguatory Commission
Form NO.1. These financial statements are the responsibility of the Company's maagement. Our
responsibilty is to express an opinion on these financial statements based on our audits.
We conducted our audit in accordace with auditing standards generally accepted in the United States of
America. Those stadards require that we plan and perform the audit to obtan reasonable assurce about
whether the financial statements are free of material misstatement. An audit includes consideration of
internalcontrol over financial repoi:ting. as a basis for designg audit procedures tht are appropriate in
the circumstaces, but not for the purose of expressing an opinion on the effectiveness of the Company's
internal control over financial reportng. Accordingly, we express no such opinion. An audit also includes
examinig, on a test basis, evidence supporting the amounts and disclosures in the fmancial statements,
assessing the accounting principles used and signficant estimates made by management, as well as
evaluating the overall fiancial statement presentation. We believe that our audit provides a.reasonable
basis for our opinion.
As discussed in Note 2, these financialstateinnts were prepared in accordace with the accountig
requirements of the Federal Energy Reguatory Commssion as set fort in its applicable Uniform System
of Accounts and published accountig releases, which is a comprehensive basis of accountig other th
accounting principles generally accepted in the United States of America.
In our opinion, such consolidated regulatory-basis financial statements present faily, .in all material
respects, the assets,liabiltìes, and proprieta capita of the Company as of December 31, 2010, and the
results of its operatìons and its cash flows. for the year then ended, in accordnce with the accountig
requiements of the Federal Energy Regulatory Commssion as setfort in its applicable Uniform System
of Accounts and published accountig releases.
Ths report is intended solely for the informtion and use of the board ofdirectors and management of the
Company and for filing with the Federal Energy Regulatory Commssion and is not intended to be and
should not be used by anyone other th these specified parties.
DJ. ., T~ LLP
Februar 28,2011 (April 18, 2011 as to the effects of Revenue Procedure 2011-26 described in Note 12)
Memer of
Deloltte ToucIiTQhm.t5 Lil)ted
Name of Respondent
PacifiCorp
This Report Is: Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2011 End of 2010/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
line
No.Title of Account
(a)
UTILITY PLANT
Ref.
Page No.
(b)
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
Utilty 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 Utilty Plant (Enter Total of line 4 less 5)
Nuclear Fuel in Process of Ref.,Conv.,Enrich., and Fab. (120.1)
Nuclear Fuel Materials and 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)
Net 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 Subsídiary 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 Derivative 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 Receivable (141)
Customer Accounts Receivable (142)
Other Accounts Receivable (143)
(Less) Accum. Provo for Uncollectible Acct.-Credit (144)
Notes Receivable from Associated Companies (145)
Accunts Receivable from Assoc. Companies (146)
Fuel Stock (151)
Fuel Stock Expenses Undistnbuted (152)
Residuals (Elec) and Extracted Products (153)
Plant Materials and Operating Supplies (154)
Merchandise (155)
Other Matenals and Supplies (156)
Nuclear Matenals Held for Sale (157)
Allowances (158.1 and 158.2)
200.201
200-201
200-201
202-203
202-203
224-225
228-229
227
227
227
227
227
227
202-203/227
228-229
Current Year
End of OuarterNear
Balance
(c)
Prior Year
End Balance
12/31
(d)
22,017,833,818
1,000,790,049
23,018,623,867
7,467,085,584
15,551,538,283
o
o
o
o
o
o
o
15,551,538,283
o
o
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
o
84,517,252
o
o
o
4,236,855
o
9,400,334
o
326,627,566
o
84,336,862
o
o
o
6,945,599
o
42,909,107
o
340,247,444.. Cy~"r~ ,r~
o
4,143,415
603,868
1,720
463,002
351,089
352,691,649
62,682,797
7,517,126"--
16,630,240
188,493,087
o
o
186,406,158
o
o
o
o
o
4,238,848
610,43
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
FERC FORM NO.1 (REV. 12-03)Page 110
This Report Is: Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
(2)D A Resubmission 04/18/2011 End of 2010104
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITStontinued)
Name of Respondent
PacifiCorp
Line
No.
....xx w4J//. 7.1..aiî 7e1.......iI.iI.líal-'~
",i?ff iWYlEÂ% Ai' ;: ~g0 Y'" /:t 1m røfl /;tli
33,300,472 35,978,910
230a 0 0
230b 135,566 5,289,133
232 1,737,446,767 1,550,913,652
2,895,724 3,116,069
0 0
0 0
0 0
90,676 89,891
233 86,483,361 67,302,539
0 0
352-353 0 0
11,446,745 13,778,067
234 588,589,916 587,517,758
0 0
2,460,389,227 2,263,986,019
19,857,995,945 18,550,965,133
Ref.
Page No.
(b)
Current Year
End of QuarterlYear
Balance
(c)
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 Processing (164.2-164.3)
Prepayments (165)
Advances for Gas (166-167)
Interest and Dividends Receivable (171)
Rents Receivable (172)
Accrued Utilty Revenues (173)
Miscellaneous Current and Accrued Assets (174)
Derivative Instrument Assets (175)
(Less) Long-Term Portion of Derivative Instrument Assets (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 )
Extraordinary Propert Losses (182.1)
Unrecovered Plant and Regulatory Study Costs (182.2)
Other Regulatory Assets (182.3)
Prelim. Survey and Investigation Charges (Electric) (183)
Preliminary Natural Gas Survey and Investigation Charges 183.1)
Other Preliminary Survey and Investigation Charges (183.2)
Clearing Accounts (184)
Temporary Facilties (185)
Miscellaneous Deferred Debits (186)
Def. Losses frm Disposition of Utilty Pit. (187)
Research, Devel. and Demonstration Expend. (188)
Unamortized Loss on Reaquired Debt (189)
Accumulated Deferred Income Taxes (190)
Unrecovered Purchased Gas Costs (191)
Total Deferred Debits (lines 69 through 83)
TOTAL ASSETS (lines 14-16, 32, 67, and 84)
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
227
o
6,674
1,535,228
205,559,000
o
123,801,642
9,400,334
o
o
1,519,440,869
Prior Year
End Balance
12/31
(d)
o
o
o
o
o
o
o
o
o
8,788
2,772,053
213,989,000
o
151,143,601
42,909,107
o
o
1,465,358,488
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 04/18/2011 2010/Q4
.FOOTNOTE DATA
¡Schedule Page: 110 Line No.: 21 Column: c
Refer to Note 2 of Notes to Financial Statements in this Form NO.1 for discussion of the consolidation of Pacific Minerals, Inc.
("PMI") begining January 1,2010.
¡Schedule Page: 110 Line No.: 43 Column: c
Refer to Note 2 of Notes to Financial Statements in this Form No.1 for discussion of the consolidation of PM I begining Januar 1,
2010.
¡Schedule Page: 110 Line No.: 57 Column: c
As of December 31, 2010, account 165 Prepayments included $344,671,476 in income taes receivable from MidAerican Energy
Holdings Company, PacifiCorp'sindirect parent company. Refer to Note 12 of Notes to Financial Statements in this Form NO.1 for
discussion of bonus de reciation 'dance issued b the Interal Revenue Service in March 201 1.
chedule Pa e: 110 Line No.: 57 Column: d
As of December 31, 2009, account 165 Prepayments included $249,055,093 in income taxes receivable from MidAmerican Energy
Holdings Company, PacifiCorp's indirect parent company.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
PacifiCorp (1 )~An Original (mo, d8, yr)
(2)0 A Resubmission 04/18/2011 end of 2010/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prior Year
No.Ref.End of QuarterlYear End Balance
Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201)250-251 3,417,945,896 3,417,945,8.96
3 Preferred Stock Issued (204)250-251 40,733,100 41,463,300
4 Capital Stock Subscribed (202, 205).0 0
5 Stock Liabilty for Conversion (203, 206)0 0
6 Premium on Capital Stock (207)0 0
7 Other Paid-In Capital (208-211)253 1,102,229,981 1,002,063,956
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 41,284,560 41,288,207
11 Retained Earnings (215, 215.1, 216)118-119 2,792,155,606 2,225,701,346
12 Unappropriated Undistributed Subsidiary Earnings (216.1)118-119 6,232,713 8,330,470
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)-6,961,899 -5,819,577
16 Total Proprietary Capital (lines 2 through 15)7,311,050,837 6,648,397,184
17 LONG-TERM DEBT
18 Bonds (221)256-257 6,357,741,000 6,372,343,000
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)32,845 35,563
23 (Less) Unamortized Discount on Long-Term Debt~Debit (226)14,381,234 15,413,483
24 Total Long-Term Debt (lines 18 through 23)6,343,392,611 6,356,965,080
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent (227)55,883,528 57,295,450
27 Accumulated Provision for Propert Insurance (228.1).0 0
28 Accumulated Provision for Injuries and Damages (228.2)8,499,000 7,487,871
29 Accumulated Provision for Pensions and Benefits (228.3)502,064,476 592,53,110
30 Accumulated Miscellaneous Operating Provisions (228.4)39,343,745 41,878,303
31 Accumulated Provision for Rate Refunds (229)0 0
32 Long-Term Portion of Derivative Instrument Liabilities 399,481,536 409,727,110
33 Long-Term Portion of Derivative Instrument Liabilties - Hedges 0 0
34 Asset Retirement Obligations (230)105,328.,750 102,516,932
35 Total Other Noncurrent Liabilties (lines 26 through 34)1,110,601,035 1,211,448,776
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)36,000,000 0
38 Accounts Payable (232)472,504,319 539,268,266
39 Notes Payable to Associated Companies (233)0 0
40 Accounts Payable to Associated Companies (234)19,893,492 13,729,206
41 Customer Deposits (235)39,611,243 31.895,824
42 Taxes Accrued (236)262-263 48,804,714 46,747,021
43 Interest Accrued (237)115,234,368 111,568,228
44 Dividends Declared (238)512,462 520,947
45 Matured Long-Term Debt (239)0 0
FERC FORM NO.1 (rev. 12-03)Page 112
Name of Respondent This Report is:Date of Report Year/Period of Report
PacifiCorp (1 )~An Original (mo, da, yr)
(2)0 A Resubmission 04/18/2011 end of 2010/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIT(Sntinued)
Line Current Year Prior Year
No.Ref.End of QuarterIYear End Balance
Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
46 Matured Interest (240)0 0
47 Tax Collections Payable (241)16,587,742 15,796,380
48 Miscellaneous Current and Accrued Liabilties (242)64,738,616 63,197,166
49 Obligations Under Capital Leases-Current (243)1,369,860 1,725,318
50 Derivative Instrument Liabilities (244)483,234,721 494,721,339
51 (Less) Long-Term Portion of Derivative Instrument Liabilities 399,481,536 409,727,110
52 Derivative Instrument Liabilties - Hedges (245)0 0
53 (Less) Long-Term Portion of Derivative Instrument liabilities-Hedges 0 0
54 Total Current and Accrued Liabilties (lines 37 through 53)899,010,001 909,442,585
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)18,492,298 20,946,236
57 Accumulated Deferred Investment Tax Credits (255)266-267 41,949,428 45,888,892
58 Deferred Gains from Disposition of Utilty Plant (256)0 0
59 Other Deferred Credits (253)269 51,492,02~40,157,480
60 Other Regulatory Liabilties (254)278 59,611,213 64,164,255
61 Unamortized Gain on Reaquired Debt (257)0 . 0
62 Accum. Deferred Income Taxes-Accel. Amort.(281)272-277 11,642,708 0
63 Accum. Deferred Income Taxes-Other Propert (282)3,330,234,891 2,802,655,179
64 Accum. Deferred Income Taxes-Other (283)680,518,898 450,899,466
65 Total Deferred Credits (lines 56 through 64)4,193,941,461 3,424,711,508
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16,24,35,54 and 65)19,857,995,945 18,550,965,133
~
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 2010/Q4
(2) OA Resubmission 04/18/2011
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 quarter 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 àmounts for other utilty function for the current year quarter.
4. Report in column (h) the quarter to date amounts for èlectric utilty funètion; in COlumn u) the quarter to date amounts for gas utilty, and in column (i) the
quarter to date amounts for other utilty function for the prior year quarter.
5. If additional columns are neeqed, place them in a footnote.
Annualor Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utilty Plant Leased to Others, in another utilty columnin a similar mannèr to
a utilty department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utilty Operating Income, in the same manner as accounts 412 and 413 above.
Line Total Total Current 3 Months Prior 3 Month
No.Current Year to Prior Year to Ended Ended
(Ref.)Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Account Page No.QuarterlY ear QuarterlY ear No 4th Quarter No 4th Quarter
(a)(b)(c) (d) (e) m
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300.301 ~3 Operating Expenses
4 Operation Expenses (401)320.323 2,277,135!354 2,279,099,664 .
5 Maintenance Expenses (402)320.323 -394,816,343
6 Depreciation Expense (403)336-337 BI' O/e 473,163,461
7 Depreciation Expense for Asset Retirement Costs (403.1)336-337 0' .".
8 Amort. & Dept of Utilty Plant (404-405)336-337 34,838,293 32,391,772
9 Amort. of Utilty Plant Acq. Adj. (406)336-337 5,518,393 5,479,353
10 Amort. Propert Losses, Unrecov Plant and Regulatory Study Costs (407)4,523,779 5,149,968
11 Amort. of Conversion Expenses (407)
12 Regulatory Debits (407.3)"¡¡'!i m 1,549,004il *.. il "%
13 (Less) Regulatory Credits (407.4)
14 Taxes Oter Than Income Taxes (408.1)262-263 .""/. ~"123,877,487II
15 Income Taxes - Federal(409.1)262-263 .-472,156,577,.
16 - Other (409.1)262.263 -4,449,586 .2,026,201
17 Provision fot Deferred Income Taxes (410.1)234,272-27 1 ,254,766,756 1,368,522,890
18 (Less) Provision for Deferred Income Taxes-Cr. (411.1)234, 272-27 551,088,560 688,511,583 .
19 Investment Tax Credit Adj. - Net (411.4)266 -1,874,204 .1,874,204
20 (Less) Gains frm Disp. of Utilty Plant (411.6)
21 Losses from Disp. of Utility Plant (411.7)
22 (Less) Gains from Disposition of Allowances (411.8)2,817,551 3,790,891
23 Losses frm Disposition of Allowances (411.9)
24 Accretion Expense (411.10)IW1I
25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)3,549,573,757 3,515,690,486
26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 852,641,628 838,075,894
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for importnt notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utilty's customers or which may result in material refund to the utilty with respec to power or gas purchases. State for each year effected the
gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the
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 frm that reported in prior report.
15. If the columns are insuffcient for reporting additional utilty departments, supply the appropriate accunt 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)0) 0)
OTHER UTILITY
Currnt Year 10 Dale Previous Year 10 Date
(in dollars) (in dollars)(k) (I)Line
No.
-2,004,224 1,549,004
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
2,277,135,354
414,960,789
501,224,256
2,279,099,664
394,816,343
473,163,461
34,838,293
5,518,393
4,523,779
32,391,772
5,479,353
5,149,968
136,550,272
-517,806,480
-4,49,586
1,254,766,756
551,088,560
-1,874,204
123,877,487
-472,156,577
-2,026,201
1,368,522,890
688ß11,583
-1,874,204
2,817,551 3,790,891
96,470
3,549,573,757
852,61,628
3,515,690,486
838,075,894
FERC FORM NO.1 (ED. 12-96)Page 115
Narie of Respondent
PacifiCorp
Line
No.
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
STATEMENT OF INCOME FOR THE YEAR (continued)
TOTAL
YearlPeriod of Report
End of 2010/Q4
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
urrent Months
Ended
Quarterly Only
No 4th Quarter
(e)
Title of Account
(a)
(Ref.)
Page No. Current Year Previous Year(b) (c) (d)
27 Net Utility Operating Income (Carred forward from page 114)
28 Other Income and Deductions
29 Other Income
30 Nonutilty Operating Income
31 Revenues From Merchandising, Jobbing and Contract Work (415)
32 (Less) Costs and Exp. of Merchandising, Job. & Contrct Work (416)
33 Revenues From Nonutilty Operations (417)
34 (Less) Exnses of Nonutilty Operations (417.1)
35 Nonoperating Rental Income (418)
36 Equity in Eamings of Subsidiary Companies (418.1)
37 Interest and Dividend Income (419)
38 Allowance for Other Funds Used During Constrction (419.1)
39 Miscellaneous Nonoperating Income (421)
40 Gain on Disposition of Propert (421.)
41 TOTAL Oter Income (Enter Total of lines 31 thru 40)
42 Other Income Deductions
43 Loss on Disposition of Propert (421.2)
44 Miscellaneous Amortzation (425)
45 Donations (426.1)
46 Life Insurance (426.2)
47 Penalties (426.3)
48 Exp. for Certn Civic, Political & Related Activities (426.4)
49 Other Deductions (426.5)
50 TOTAL Other Income Deductions (Total of lines 43thru 49)
51 Taxes Applic.to Other Income and Deductions
52 Taxes Other Than Income Taxes 408.2)
53 Income Taxes.Federal (409.2)
54 Income Taxes-Other (409.2)
55 Provision for Deferred Inc. Taxes (410.2)
56 (Less) Provision for Deferred Income Taxes-Cr. (411.2)
57 InvestmentTax CrediIAdj.-Net (411.5)
58 (Less) Investment Tax Credits (420)
59 TOTAL Taxes on Other Income and Deductons (Total of lines 52-58)
60 NetOther Income and Deductons (Total of lines 41,50,59)
61 Interest Charges
62 Interest on Long-Term Debt (427)
. 63 Amort. of Debt Disc. and Expense (428)
64 Amortzation of Loss on Reaquired Debt (428.1)
65 (Less) Amort. of Premium on Debt-Credit (429)
66 (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67 Interest on Debt to Assoc. Companies (430)
68 Oter Interest Expense (431)
69 (Less) Allowance for Borrwed Funds Used During Constrction-Cr. (432)
70 Net Interest Charges (Total of lines 62 thru 69)
71 Income Before Extrordinary Items (Total of lines 27, 60 and 70)
72 Exraordinary Items
73 Exraordinary Income (434)
74 (Less) Extaordinary Deductions (435)
75 Net Extraordinary Items (Total of line 73 less line 74)
76 Income Taxes-Federal and Other (409.3)
77 Extrordinary Items After Taxes (line 75 less line 76)
78 Net Income (Total of line 71 and 77)
852,641,628 838,075,894
.~.&/"./".. c"..gr)1.../ / /&~
~d! " 0?'di!f!iif" ~/%W1"tj/ !i;i...iI./'liI, / / 'Ww"'!i'&l" ~ ~ ~./.iii:' "wB'Ji ß ~ 7~",;: midis!r:" iY;W~" ~ ø ¿¿ B,;;ç s i1 W~A~Æ.,is', xi..øi 1,,:y/,',0/~ /~:t
119
1,416,581
1,362,155
247,917
81,037
91,251
-2,097,757
5,077,391
79,298,238
27,081,235
2,617,525
112,289,189
1,526,343
1,518,065
241,243
28,326
74,959
1,811,740
20,556,977
63,955,322
32,225,273
2,267,272
121,112,738~~0:"'i/í~~.WÆ=~.mB!ii'."~
_Ø.l.i£1 \%.?;.!1~1(~ ¡iiw.J_g!J!;¡; ~W0!Ji!i!;¡~
46,470
1,285,816
2,676,885
-4,971,828
-418,323
2,284,308
29,828,972
30,732,300
82,456
1,263,905
2,997,500
.5,605,297
400,132
1,519,511
34,666,110
35,324,317
"$::""~~;~/ x¡~"i;~0ír~r1"~;
262-263 367,905 576,313
262-263 28,723,272 29,005,691
262-263 3,903,016 3,941,391
234, 272-277 85,258,308 99,093,919
234, 272-27 85,411,869 99,416,511
2,065,260 2,065,260
30,775,372 31,135,543
50,781,517 54,652,878~.'J..:/~r~.");%"';Ji~r
,......:,...~.
363,203,396
3,727,614
2,331,323
2,718
12,367,152
44,618,458
337,008,309
566,414,836
262.263
566,414,836 541,846,446
369,236,117
3,786,241
2,785,112
2,718
10,264,106
35,186,532
350,882,326
541,846,446
FERC FORM NO. 1/3.Q (REV. 02-04)Page 117
Name of Respondent This Report is:Date of Report Year/Period of Repor
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) . A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
ISchedule Page: 114 Line No.: 6 Column: c
Depreciation expense associated with transporttion equipment is generally charged to operations and maintenance expense and
constrction work in progress. Durg the years ended December 31, 2010 and 2009, depreciation expense associated with
trsporttion equipment was $14,065,119 and $13,886,246, respectively.
ISchedule Page: 114 Line No.: 7 Column: c
Generally, PacifiCorprecords the depreciation expense of asset retirement obligations as either a regulatory asset or liabili
chedule Page: 114 Line No.: 12 Column: c
For a additional information regarding the Powerdale hydroelectrc generating facility, refer to ImportnfChanges During the
QuarerNear, Item 12 of this Form No.1. The net credit position reflected in account 407.3, Regulatory Debits, priarily represents a
tre-up to regulatory assets based on curently approved state commssion orders for the decommssioning and removal of the
Powerdale h droelectrc eneratin facili.
chedule Pa e: 114 Line No.: 14 Column: c
Payroll taxes are generally charged to operations and maintenance expense and constrction work in progress. Durng the years ended
December31, 2010 and 2009, a 011 taes were $39,760,547 and $38,397,330, res ectivel . .
chedule Pa e: 114 Line No.: 15 Column: c
The following presents PacifiCorp's total income tax expense for the year ended December 31,2010 and 2009. Individual expenses
are referenced back to the respective line number on pages 114 - 117. Refer to Note 12 of Notes to Financial Statements in this Form
NO.1 for discussion of bonus depreciation guidance issued by the Internal Revenue Service in March 201 1.
Line No.
15 Income Taxes - Federal (409.1)16 - Other (409.1)
17 Provision for Deferred Income Taxes (410.1)
18 (Less) Provision for Deferred Income Taxes-Cr. (411.)
19 Investment Tax Credit Adj. - Net (411.4)
53 Income Taxes-Federal (409.2)
54 Income Taxes-Other (409.2)
55 Provision for Deferred Income Taxes (410.2)
56 (Less) Provision for Deferred Income Taxes-Cr (411.2)
58 (Less) Investment Tax Credits (420)
Total Income Tax Expense
Years Ended December 31,2010 2009
$ (517,806,480) (a) $ (472,156,577) (b)
(4,449,586) (a) (2,026,201) (b)
1,254,766,756 1,368,522,890
551,088,560 688,511,583
(1,874,204) (1,874,204)
28,723,272 29,005,691
3,903,016 3,941,391
85,258,308 99,093,919
85,411,869 99,416,511
2,065,260 2,065,260
$ 209,955,393 $ 234,513,555
(a) The net credit position reflected in account 409.1, Income taes is priarly due to bonus depreciation.
(b) The net credit position reflected in account 409.1, Income taes is priarly due to bonus depreciation and repairs deduction.
ISchedule Page: 114 Line No.: 24 Column: c
Generally, Pacificorp records the accretion expense of asset retiment obligations as either a regulatory asset or liability.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-
439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8, Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulatèd.
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 EARNINGS (Account 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Accunt 439)
4
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acct. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Eamings (Acct. 439)
16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
18
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24 Preferred Stock, various series and rates
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Gommon Stock (Accunt 438)
31
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acct. 438)
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1 ,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
39
40
Contra Primary
ccoimt Affected
Current
OuarterlYear
Year to Date
Balance
Previous
QuarterlY ear
Year to Date
Balance
568,512,593 540,034,706
Jat..t~~jl:~ff 7f.;."~~;%4~..
-2,058,333 - ( 2,083,790)..Ja:~:;;_¡i.~.fJ'''4;~''
2,788,579,795
(9,952)
2,222,125,535
FERC FORM NO. 1/3-Q (REV. 02-64)Page 118
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04118/2011
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 eamings account in which recorded (Accounts 433,436-
439.inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in a~unt 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.
Current Previous
QuarterlYear QuarterlYear
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 (Accunt 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 (Accunt
Report only on an Annual Basis, no Quarterly
49 BalanceBeginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52 Transfers to Unappropriated Retained Earnings (Account 216)
53 Balance-End of Year (Total lines 49 thru 52)
8,330,470
-2,097,757
6,508,778
1,811,740
6,232,713
9,952
8,330,470
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2) . A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 118 Line No.: 24 Column: c
Dividends on preferred stock during the year ended December 31, 2010 were as follows:
4.52% Serial Preferred
4.56% Seral Preferred
4.72% Serial Preferred
5.00% Serial Preferred
5.40% Serial Preferred
6.00% Seral Preferred
7:00% Serial Preferred
5.00% Preferred
Shares
2,065
81,326
65,854
41,908
65,959
5,930
18,046
126,243
407,331
Dividend
$ 9,334
374,570
315,593
209,540
356,179
35,580
126,322
631,215
$ 2,058,333
I$chedule Page: 118 Line No.: 24 Column: d
Dividends on preferred stock durng the year ended December 31, 2009 were as follows:
4.52% Serial Preferred
4.56% Serial Preferred
4.72% Serial Preferred
5.00% Serial Preferred
5.40% Serial Preferred
6.00% Serial Preferred
7.00% Serial Preferred
5.00% Preferred
Shares
2,065
84,592
69,890
41,908
65,959
5,930
18,046
126,243
414,633
Dividend
$ 9,334
385,739
329,881
209,540
356,179
35,580
126,322
631,15
$ 2,083,790
I$chedulePage: 118 Line No.: 31 Column: a
For information regarding common stock dividends declared, refer to Importnt Changes Durg the QuarrNear, Item 6 and Note
15 of Notes to Financial Statements in this Form No.1.
¡Schedule Page: 118 Line No.: 47 Column: c
The balance in account 215.1 Appropriated retained earngs - amortation reserve, federal is due to requirements of certin
hydroelectrc relicensing projects.
I$chedule Page: 118 Line No.: 47 Column: d
See footnote for colum (c) line 47.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
This Report Is:
(1) ~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/18/2011
Year/Period of Report
End of 2010/Q4
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-tenn debt; (c) Include commercial paper, and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Infonnation about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation betwen "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 activities 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 capitlized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outfow to acquire other companies. Provide a reconciliation of assets acquired wit liabilities assumed in the Notes
to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a recncilation 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 (Gains)/Losses 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 (Less) Undistributed Eamings 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
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 Other (provide details in footnote):
32
33
Line
No.
Description (See Instruction NO.1 for Explanation of Codes)Currnt Year to Date
QuarterNear
b)
Previous Year to Date
QuarterNear
(c)
-1,892,323
703,524,635
-3,939,464
-13.328,543
-25,822,080
726,000
679,678,715
-3,939,464
-7,140,528
-41,858,225
-130,489,533
8,890,615
-4,813,321
79,298,238
-2,097,757
-90,231,534
-102,246,009
22,143,762
-33,318,429
12,441,383
-6,970,542
63,955,322
1,811,740
-216,306,739
57,400,001
16,989,197
-1,686,214,575 "2,356,195,937
-79,298,238 -63,955,322
34 Cash Outflows for Plant (Total of lines 26 thru 33)
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 Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
-1,606,916,337 -2,292,240,615
-13,402,178
4,643,134. 0/'10 :. ø:..._"~1
-269,354
458,430
FERC FORM NO.1 (ED. 12-96)Page 120
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/18/2011
Year/Period of Report
End of 2010/Q4
This ~ort Is:
(1)~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
(1 Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify'separately such items as
investments; fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and
Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities- Other: Include gains and losses pertining to operating activities 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 cash outfow to acquire other companies. Provide a reconciliation of assets acquired with "abilties assumed in the Notes
to the Firiancial 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)
Current Year to Date
QuarterlYear
(b)
Previous Year to Date
QuarterlYear
(c)
Line
No.
Description (See Instruction NO.1 for Explanation of Codes)
Loans Made or Purchased
Collections on Loans
Net (Increase) Decrease in Receivables
Net (Increase) Decrease in Inventory
Net (Increase) Decrease in Allowances Held for Speculation
Net Increase (Decrease) in Payables and Accrued Expenses
3.540,7572,401,475
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
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 Payments 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
80 Dividends on Preferred Stock
81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
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
100,000,000 125,000,000
35,999,320
135,999,320 1,107,802,997
-1,724,876 -5,811,642
-84,991,027
-2,066,818 -2,083,790
4,608,137 86,010,446
FERCFQRM 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 04/18/2011 2010/Q4
FOOTNOTE DATA .
¡Schedule Page: 120 Line No.: 4 Column: b
Includes depreciation expense associated with transporttion equipment and capital lease assets of$15,789,994 and $19,697,889
durng the years ended December 31, 2010 and 2009, respectively.
I$chedule Page: 120 Line No.: 5 Column: a
Years Ended December 31,
Amortization of softare development & other intagibles
Amortation of hydroelectrc relicensing costs
Amortation of electrc plant acquisition adjustments
Amortization of regulatory assets
2010
$ 34,838,293
1,285,816
5,518,393
2,519,555
$ 44,162,057
2009
$ 32,391,772
1,263,905
5,479,353
6,698,972
$ 45,834,002
I$chedule Page: 120 Line No.: 20 Column: a
Coal & steam depreciation & depletion included in cost of fuel
(Gain)/loss on sale of propert
Write-off of assets under construction
Other
Years Ended December 31,2010 2009
$ 12,685,957 $ 13,212,110
(2,992,914) (2,357,000)
8,670,990 4,489,364
3,779,729 1,644,723
$ 22,143,762 $ 16,989,197
¡Schedule Page: 120 Line No.: 22 Column: c
Certin amounts in the rior ear fiancial statements have been reclassified to conform to the curent ear resentation.
chedule Pa e: 120 Line No.: 37 Column: b
Represents proceeds from disposal of fixed assets.
I$chedule Page: 120 Line No.: 37 Column: c
Represents proceeds from disposal of fixed assets.
I$chedule Page: 120 Line No.: 53 Column: a
Years Ended December 31,2010 2009
$ (371,886) $ 1,020,004(785) (1,062)2,730,061 2,521,815
44,085
$ 2,401,475 $ 3,540,757
Other investments/special funds
Tempora facilities
Restrcted cash
Net cash as a result of consolidation of PM I (I)
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
Date of Report Year/Period of Report
End of 2010/Q4
This Report Is:
(1) (2 An Original
(2) D A Resubmission
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2, Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, inciuding a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a
claim for refund of income taxes of a material amountinitiated by the utility. Give also a brief explanation of any dividends in arrears on .
cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an
explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes suffcient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERc Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters
shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
04/18/2011
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
.
FERC FORM NO.1 (ED. 12-96)Page 122
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
PACIFICORP AN SUBSIDIARIES
NOTES TO FIANCIA STATEMENTS
(1) Organization and Operations
PacifiCorp, which includes PacifiCorp and its subsidiares, is a United States regulated electrc company serving 1.7 million retail
customers, including residential, commercial, industral and other customers in portions of the states of Utah, Oregon, Wyomig,
Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectrc, wid-powered and
geothermal generating facilties, as well as electrc transmission and distrbution assets. PacifiCorp also buys and sells electrcity on
the wholesale market with public and private utilities, energy marketig companies and incorporated municipalities. PacifiCorp is
subject to comprehensive state and federal regulation. PacifiCorp's subsidiares support its electrc utility operations by providig coal
mining and environmental remediation servces. PacifiCorp is an indiect subsidiar of MidAerican Energy Holdigs Company
("MEHC"), a holding company based in Des Moines, Iowa that owns subsidiares pricipally engaged in energy busiesses. MEHC is
a consolidated subsidiar of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2) Summary of Signifcant Accounting Policies
Basis of Presentation
These fmancial statements are prepared in accordance with the requirements of the Federal Energy Regulatory Commssion (the
"FERC") as set fort in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive
basis of accounting other than accounting priciples generally accepted in the United States of America ("GAAP"). These notes
include disclosures required by GAA 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 reportng standards and GAA.
Investments in Subsidiaries
PacifiCorp accounts for its investment in PacifiCorp Environmental Remediation Company ("PERCO") using the equity
method rather than consolidatig the assets, liabilities, revenues and expenses of PERCo as required by GAAP. GAA
requires that entities in which a company holds a controlling financial interest be consolidated. The accounting for the
investment in PERCo using the equity method rather than the consolidation method in accordance with GAA has no effect
on net income or retained earings.
Costs of Removal
Estiated removal costs that are recovered though approved depreciation rates, but that do not meet the requirements of a
legal asset retirement obligation ("ARO"), are reflected in the cost of removal. regulatory liability under GAA and as
accumulated depreciation under the FERC accounting and reportg standads.
Income Taxes
Accumulated deferred income taxes are classified as curent and non-curent on the balance sheet for GAAP. Under the
FERC accounting and reporting stadards, accumulated deferred income taes are classified as gross non-curent assets and
gross non-curent liabilities. Additionally, there are certin presentational differences between FERC and GAA for amounts
related to unecognized tax benefits associated with tempora differences in accordance with FERC Docket
No. AI07-2-000, "Accountig and Financial Reporting for Uncertinty in Income Taxes."
Interest and penalties on income taes for GAA are classified as income ta expense. All such amounts are classified as
interest income, interest expense and penalties under the FERC accounting and reporting standards.
IFERC FORM NO.1 (ED. 12-88)Page 123.1
Name of Respondent \This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Unrealized Gains and Losses on Derivative Instruments
Under the FERC accounting and reporting standards, unealized. gains and losses on derivative instrents that are not
recorded as a net regulatory asset or accumulated other comprehensive income ("AOCI") are presented on a gross basis on
the Statement of Income as miscellaneous nonoperating income for unealized gains and as other deductions for unrealized
losses in accordance with FERC Order 627, "Accountig and Reporting of Financial Instrents, Comprehensive Income,
Derivatives and Hedging Activities. II For GAAP, unrealized gains and losses on energy derivative contracts not held fgr
trading puroses and that are not recorded as a net regulatory asset or AOCI 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 contrcts.
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 the financial statements in conformity with GAA requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and
expenses durng the period. These estimates include, but are not limited to, unbiled revenue; valuation of certin financial assets and
liabilities, including derivative contracts; effects of regulation; accounting for contingencies, including environmental and regulatory
matters; income taxes; AROs; and certin assumptions made in accounting for pension and other postretirement benefits. Actual
results may differ from the estimates used in preparing the financial statements.
Accountingfor the Effects of Certain Types of Regulation
PacifiCorp prepares its financial statements in accordance with authoritative guidace for regulated operations, which recognizes the
economic effects of regulation. Accordingly, PacifiCorp is required to defer the recognition of certin costs or income if it is probable
that, through the ratemaking process, there wil be a corresponding increase or decrease in futue rates.
PacifiCorp continually evaluates the applicability of the guidance for regulated operations and whether its reguatory assets and
liabilities are probable of inclusion in futue rates by considerig factors such as a change in the regulator's approach to settng rates
from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition which could limt
PacifiCorp's ability to recover its costs. Based upon this continuous evaluation, PacifiCorp believes the application of the guidance for
regulated operations is appropriate and its existig regulatory assets and liabilities are probable of inclusion in futue rates. The
evaluation reflects the current political and regulatory climate at both the federal and state levels and is subject to change in the futue.
If it becomes no longer probable that the deferred costs or income wil be included in futue rates, the related regulatory assets and
liabilities wil be written off to net income, retued to customers or re-established as AOCI.
Fair Value Measurements
As defined under GAA, fair valueis the price that would be received to sell an asset or paid to trsfer a liability between market
parcipants in the pricipal market or in the most advantageous market when no principal market exists. Adjustments to transaction
prices or quoted market prices may be required in iliquid or disorderly markets in order to estimate fair value. Different valuation
techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to
transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and wiling to
transact an exchange and not under duress. Nonperformance or credit risk is considered when determning the fair value of assets and
liabilities. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value.
Accordingly, estimates of fair value presented herein are not necessarly indicative of the amounts that could be realized in a curent
or futue market exchange.
IFERC FORM NO.1 (ED. 12-88)Page 123.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
Cash Equivalents and Restricted Cash and Investments
Cash equivalents consist of funds invested in United States Treasur Bils, money maket funds and other investments with a matuty
of thee months or less when purchased. Cash and cash equivalents exclude amounts where availability is restrcted by legal
requin:ments, loan agreements or other contrctual provisions. Restrcted amounts are included in other special fuds and special
deposits on the Comparative Balance Sheet. Total cash and cash equivalents were as follows as of December 31 (in milions):
2010 2009
Total cash and cash equivalents $86
Allowance for Doubtfl Accounts
Accounts receivable are stated at the outstading principal amount, net of estiated allowances for doubtfl accounts. The allowance
for doubtful accounts is based on PacifiCorp's assessment of the collectibility of amounts owed to PacifiCorp by its customers. This
, assessment requires judgment regarding the ability of customers to payor the outcome of any pendig 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 is sumarzed as follows for the years ended December 31 (in milions):
2010 2009
net 12 12
Ending balance
Derivatives
PacifiCorp employs a number of different derivative contracts, including forwards, futues, options, swaps and other agreements, to
manage price risk for electrcity, natural gas and other commodities and interest rate risk. Derivative contracts are recorded on the
Comparative Balance Sheet. as either assets or liabilities and are stated at estimated fair value unless they are designated as normal
purchases or normal sales and qualify for the exception afforded by GAA. Derivative balances reflect offsetting peritted under
master nettg arrangements 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 and normal sales. Normal purchases or normal sales contracts are not marked-to-market
and settled amounts are recognized as operating revenues or operation expenses on the Statement of Income.
For PacifiCorp's derivatives designated as hedging contracts, PacifiCorp formally assesses, at inception and thereafter, whether the
hedging contract is highly effective in offsettg 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) ó An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Changes in the estimated fair value of a denvative contract designated and qualified as a cash flow hedge, to the extent effective, are
included on the Statements of Accumulated Comprehensive Income, Comprehensive Income, and Hedgig Activities as AOCI, net of
tax, until the contract settles and the hedged item is recognized in earnings. PacifiCorp discontinues hedge accounting prospectively.
. when it has determed that a derivative contract no longer qualifies as an effective hedge, or when it is no longer probable that the
hedged forecasted transaction wil occur. When hedge accounting is discontinued because the derivative contract no longer qualifies
as an effective hedge, futue changes in the estiated fair value of the derivative contract are charged to earings. Gains and losses
related to discontinued hedges that were previously recorded in AOCI wil remain in AOCI until the contract settles and the hedged
item is. recognized in earings, unless it becomesprobable that the hedged forecasted trnsaction wil not occur at which time
associated deferred amounts in AOCI wil be immediately recognized in earnings.
For PacifiCorp's derivatives not designated as hedging contracts, the settled amount is generally included in rates. Accordingly,
changes in the fair value of a derivative contract that are probable of inclusion in rates are recorded as net regulatory assets. For a
derivative contract not probable of inclusion in rates and not designated as a hedging contract, changes in the fair value are recognized
in earings.
Inventories
Inventories consist of màterials and supplies, coal stocks, natual gas and fuel oil, which are stated at the lower of average cost or
market.
Net Utilty Plant
General
Additions to utility plant are recorded at cost. PacifiCorp capitalizes all constrction related material, direct labor and contract
services, as well as indirect constrction costs, which include debt and equity allowance for fuds used durg constrction
("AFUDC"). The cost of major additions and betterments are capitalized, while costs incured that do not improve or extend the
useful lives of the related assets are generally expensed.
Depreciation and amortization are generallý computed by applying the composite or straight-line method based on either estimated
useful lives or mandated recovery periods as prescribed by PacifiCorp's varous regulatory authorities. Depreciation studies are
completed to determne the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are
ultimately approved by the various regulatory authorities. Net salvage includes the estimated futue residual values of the assets and
any estiated removal costs recovered though approved depreciation rates. Estimated removal costs are recorded as either
accumulated provision for depreciation or as an ARO liability on the Comparative Balance Sheet, depending on whether the
obligation meets the requirements of an tRO. As actual removal costs are incured, the associated liability is reduced.
Generally when PacifiCorp retires or sells a component of depreciable utility plant, it charges the original costand any net proceeds
from the disposition to accumulated provision for depreciation. Any gain or loss on disposals of all other assets is recorded through
earings.
PacifiCorp records debt and equity AFUDC, which represents the estiated costs of debt and equity fuds necessar to finance
additions to utility plant. AFUDC is capitalized as a component of utility plant, with offsetting credits to the Statement ofIncome.
Afer constrction is completed, PacifiCorp is permitted to ear a retu on these costs as a component of the related assets, as well as
recover these costs though depreciation expense over the useful lives of the related assets.
IFERC FORM NO.1 (ED. 12-88)Page 123.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Asset Retirement Obligations
PacifiCorp recognizes AROs when it has a legal obligation to perform decommssioning, reclamation or removal. activities upon
retirement of an asset. PacifiCorp's AROs are priarily associated with its generatig facilities. The fair value of an ARO liabilty is
recognized in the period in which it is incured, if a reasonable estite of fair value can be made, and is added to the carring
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 origial estimate of undiscounted cash flows (with corresponding
adjustments to utility plant) and for accretion of the ARO liability due to the passage of tie. 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 services are provided. Revenue recognized includes unbiled, as well as biled,
amounts. As of December 31,2010 and 2009, unbiled revenue was $206 million and $214 milion, respectively, and is included in
accrued utility revenues,. net on the Comparative Balance Sheet. . Rates charged are established by regulators or contractual
arangements.
The determination of sales to individual customers is based on the readig 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 estiated, 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 estiation of unbiled energy provided durng the period, the
assignment 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 pattrns, customer usage patterns,. historical
trends, volumes, line losses, retail rate changes and composition of customer classes.
PacifiCorp records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on
a net basis on the Statement of Income.
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 liabilities are based on differences between the financial statement and ta 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 deferred income
ta assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited diectly
to OCi. Changes in deferred income tax assets and liabilities that are associated with income tax benefits related to certin
propert-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 recognized as a net regulatory asset
totaling $426 million and $401 millon as of December 31, 2010 and 2009, respectively, and will be included in rates when the
temporar differences reverse. Other changes in defered income ta assets and liabilties 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
various regulatory jursdictions.
IFERC FORM NO.1 (ED. 12-88)Page 123.5
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued).
In determining PacifiCorp's income taxes, management is required to interpret complex ta laws and regulations, which includes
consideration of regulatory implications imposed by PacifiCorp's various regulatory jursdictions. PacifiCorp's ta retus are subject
to continuous examinations by federal, state and local tax authorities that may give rise to different interpretations of these complex
laws and regUlations. Due to the natue of the examination process, it generally taes yearS before these examinations are completed
and these matters are resolved. PacifiCorp recognizes the tax benefit from an uncertin tax position only if it is more likely than not
that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax
benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than
50% likelihood of being realized upon ultimate settlement. Althoughth-e ultiate resolution ofPacifiCorp's federl, state and local tax
examinations is uncertin, PacifiCorp believes it has made adequate provisions for these tax positions. The aggregate amount of any
additional tax liabilities that may result from these examnations, if any, is not expected to have a material adverse effect on
PacifiCorp's financial results. PacifiCorp's unecognized ta benefits are priarily included in Taxes accrued on the Comparative
Balance Sheet. Estimated interest and penalties, if any, related to uncert tax positions are included in interest income, interest
expense ánd penalties on the Statement of Income.
Segment Information
PacifiCorp curently has one segment, which includes its regulated electrc utility operations.
New Accounting Pronouncements
In Januar 2010, the Financial Accounting Standards Board (the "FASB") issued Accountig Standards Update ("ASU") No. 2010-06
("ASU No. 2010-06"), which amends FASB Accounting Standards Codification ("ASC") Topic 820, "Fair Value Measurements and
Disclosures." 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 transfers and (b) gross presentation of purchases, sales, issuances and settlements in the
Level 3 fair value measurement rollforward. This guidance clarfies that existig fair value measurement disclosures should be
presented for each class of assets and liabilities. The existing disclosures about the valuation technques and inputs used to measure
fair value for both recurng. and nonrecurng fair value measurements have also been clarified to en.sure such disclosures are
presented for the Levels 2 and 3 fair value measurements. PacifiCorp adopted this guidance as of January 1, 2010, with the exception
of the disclosure requirement to present purchases, sales, issuances and settlements gross in the Level 3 fair value measurement
rollforward, which is effective fórfiscal years begining after December 15,2010, and for interi periods within those fiscal years.
The adoption did not have a material impact on PacifiCorp's disclosures included within Notes to Financial Statements.
In June 2009, the FASB issued authoritative guidance (which was codified into ASC Topic 810, "Consolidation" with the issuance of
ASU No. 2009-17) that requires a primarily qualitative analysis to determne if an enterprise is the priar beneficiar of a variable
interest entity. This analysis is based on whether the enterprise has (a) the power to direct the activities of the variable interest entity
that most significantly impact the entity's economic performance and (b) the obligation to absorb losses of the entity or the right to
receive benefits from the entity that could potentially be significant to the variable interest entity. In addition, enterprises are required
to more frequently reassess whether an entity is a varable interest entity and whether the enterprise is the primar beneficiar of the
varable interest entity. Finally, the guidance for consolidation or deconsolidation of a variable interest entity is amended and
disclosure requirements about an enterprise's involvement with a varable interest entity are enhanced. PacifiCorp adopted this
guidance as of Januar 1, 2010 on a prospective basis. As a result, PacifiCorp's coal mining joint ventue, Bridger Coal Company
("Bridger Coal"), was deconsolidated and is being accounted for under the equity method of accountig as the power to direct the
activities that most significantly impact Bridger Coal's economic performance are shared with the joint ventue parter. Bridger Coal
was previously and continues to be accounted for under the equity method for FERC accounting and reportg puroses. Pacific
Minerals, Inc. ("PMI"), a wholly owned subsidiary of PacifiCorp that owns 66.67% of Bridger Coal, was consolidated for FERC
reporting purposes on a prospective basis beginning Januar 1,2010. The consolidation ofPMI did not have a significant impact on
PacifiCorp's financial results.
IFERC FORM NO.1 (ED. 12-88)Page 123.6
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp ! (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(3) Net Utilty Plant
Utility plant, net consists of the following as of December 31 (in millions):
Transmission
848 752
Total utility plant, net $15.552
(1) Computer softar costs included in intangible plantar initially assigned a depreciable life of 5 to 10 year.
Unallocated Acquisition 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 utility servce over their net book value in those assets. These unallocated acquisition
adjustments included in utility plant had an original cost of $159 million and $157 milion as of December 31, 2010 and 2009,
respectively, and accumulated provision for depreciation, amortization and depletion of $102 milion and $96 milion as of
December 31,2010 and 2009, respectively.
IFERC FORM NO.1 (ED. 12-88)Page 123.7
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 25 An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(4) Jointly Owned Utiity Facilties
Under joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly
owned generation, transmission and distrbution facilities and transmission lines. PacifiCorp accounts for its proportonate share of
each facility, and each joint owner has provided financing for its share of each generating facility or transmission line. Operatig 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. Operatig costs and expenses on the Statement ofIncomeinclude 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, 2010
(dollars in milions):
Jim Bridger Nos. 1 - 4(1)
Hunter No. 1
Wyoda(l)
Colstrp Nos. 3 and 4(1)
RunterNo.2
Hermiston(2)
Crag Nos. 1 and 2
Hayden No. 1
Foote Creek
Hayden No. 2
Other transmission and distrbution facilities
Total
PacifCorp
Share
67%
94
80
10
60
50
19
25
79
13
Various
Facilty
in
Service
$ 1,077
348
341
247
193
175
170
46
37
28
181
$ 2.843
(1) Includes tranmission lines and substations.
Accumulated
Depreciation
and
Amortation
510
151
187
132
Construction
Work-in-
Progress$ 29
21
85
2
3
$$ 238
(2) PacifiCorp has contrted to purchase the remaining 50% of the output of the Hennston generating facilty.
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 1(2)A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(5) Regulatory Matters
Regulatory Assets and Liabilties
Regulatory assets represent costs that are expected to be recovered in futue rates. PacifiCorp's regulatory assets reflected on the
Comparative Balance Sheet consist of the followig as of December 31 (in millions):
Employee benefit plans(l)
Unrealized loss on regulated derivative contrcts
Deferred income taxes(2)
Other
Total
Weighted
Average
Remaining
Life
9 yeas
4 years
33 year
Varous
$
2010 2009
595 $576
487 367
448
207 186
1.737 $1.551$
(1) Substantially represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in rates when recognzed.
Amounts ar parially offset by $12 millon and $19 millon of the unortzed porton of net regulatory deferrls related to curilment gains and the
measurement date change transitional adjustment as of Deember 31, 2010 and 2009, resptively.
(2) Represents deferred income ta asets and liabilities that ar assoiated with income ta benefits related to certn proper.related basis differences and
other varous differences that PacifiCorp is required to passon to its customer in most state jursdictions.
PacifiCorp had regulatory assets not earing a retu on investment of $1.575 bilion and $1.385 bilion as of December 31,2010 and
2009, respectively.
Regulatory liabilities represent income to be recognized or amounts to be retued to customers in futue periods. PacifiCorp's
regulatory liabilities reflected on the Comparative Balance Sheet consist of the following as of December 31 (in millions):
Deferred income taes
Other
Tota
Weighted
Average
Remaining
Life
Varous
Various
$
2009$ .. 21 .
43$ 64
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 04/18/2011 2010/Q4 .
NOTES TO FINANCIAL STATEMENTS (Continued)
Rate Matters
Oregon Senate Bil 408
Oregon Senate Bil 408 ("SB 408") requires PacifiCorp and other large regulated, investor-owned utilities that provide electrc or
natual gas service to Oregon customers to fie an annual report each October with the Oregon Public Utility Commssion (the
"OPUC") èomparg income taes collected and income taes paid, as defined by the statute and its administrative rules. If after its
review, the OPUC determines the amount of income taxes collected differs from the amòunt of income taxes paid by more than
$100,000, the OPUC must require the public utility to establish an automatic adjustment clause to accourt for the difference.
The OPUC issued an order in April 2008 approving the recovery of $35 million, plus interest, related to PacifiCorp's 2006 tax report.
This order was challenged by the Industral Customers of Nortwest Utilities ("ICNU"), which petitioned the Oregon Cour of
Appeals for judicial review of, among other things, the application of certin administrative rules considered in the April 2008 order.
In December 2010, the Oregon Court of Appeals affed the OPUC's April 2008 order. The ICNU did not seek fuer judicial
review of the order, and the order is now finaL. The $35 milion, plus interest, was previously recorded and collected from customers.
In October 2009, PacifiCorp fied for a surcharge of $38 million in its 2008 tax report under SB 408. In Januar 2010, PacifiCorp
entered into a stipulation with OPUC staff and the Citiens' Utility Board of Oregon ("CUB"), agreeing to a lower surcharge totaling
$2 million, including interest. In April 2010, the OPUC issued an order adopting the stipulation in its entiety, at which time
PacifiCorp recorded the $2 millon in operating revenue.
In October 2010, PacifiCorp fied its 2009 tax report under SB 408. In January 2011, PacifiCorp entered into a stipulation with the
OPUC staff and the CUB, whereby PacifiCorp, the OPUC staff and the CUB agreed to a surcharge of $13 milion, plus interest. In
April 2011, the OPUC issued an order adopting the stipulation without significant modification. The $13 millon, plus interest, wil be
recorded in operatig revenue in April 2011 and collected over a one-year period begiing in June 2011. The stipulation also
contained an agreement that the OPUC staff wil support PacifiCorp's request to defer resolution of certin aspects of the 2009 tax
report in a separate proceeding, the outcome of which is not expected to have a material impact on PacifiCorp's financial results.
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 (2)A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(6) Fair Value Measurements
The caring value of PacifiCorp's cash, certain cash equivalents, receivables, special fuds, other investments, payables, accrued
liabilities and short-term borrowings approximates fair value because of the short-ter matuty of these instrments. PacifiCorp has
varous financial assets and liabilities that are measured at fair value on the fiancial statements using inputs from the thee levels of
the fair value hierarchy. A fmancial asset or liability classification within the hierachy is determined based on the lowest level input
that is significant to the fair value measurement. The thee levels are as follows:
· Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the
abilty to access at the measurement date.
· Level 2 - Inputs include quoted prices for similar assets or liabilties 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 liability 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 liabilities recognized on the Comparative Balance Sheet and measured at fair
value on a recurng basis (in milions):
As of December 31,2010
Assets:
Commodity derivatives
Investments in available-for-sale securties:
Money maket funds(2)
Input Levels for Fair Value
Measurements
Levell Level 2 Level 3 Other (1) Total
$263 $$(145)$123
2
$(45)$125
$$(405)$(50)$272 $(483)
Liabilties:
Commodity derivatives
As of December 31, 2009
Assets:
Commodity derivatives
Investments in available-for-sale securties:
Money maket fuds (2)
$$285 $6 $(140)
94
$94 $
$$(274)$(86)$165 $(495)
Liabilties:
Commodity derivatives
(1) Represents netting under master netting arrgements and a net cash collaterl receivable of $127 million and $25 millon as of December 31,2010 and
2009, respectively.
(2) Amounts are included in other investments, other special fuds and tempora cah investments on the Comparative Balance Sheet. The fair value of these
money market mutul fuds approximates cost.
IFERC FORM NO.1 (ED. 12-88)Page 123.11
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Derivative contracts are recorded on the Comparative Balance Sheet as either assets or liabilities and are stated at estiated fair value
unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAA. When available, the
fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp
transacts. When quoted prices for identical contrcts are not available, PacifiCorp uses forward price cures. Forward price cures
represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at fue dates.
PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and .commercial
models, with internal and external fudamental data inputs. Market price quotations are obtained from independent energy brokers,
exchanges, diect communication with market participants and actual trsactions executed by PacifiCorp. Market price quotations for
certin major electrcity and natul gas trding hubs are generally readily obtainable for the first six years; therefore, PacifiCorp's
forward price cures for those locations and perods reflect observable market quotes. Market price quotations for other electrcity 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 contrcts that are not actively traded, PacifiCorp uses forward price curves derved from internal models based on
perceived pricing relationships to major trading hubs that are based on significant unobservable inputs. The estiated fair value of
these derivative contracts is a fuction of underlying forward commodity prices, interest rates, curency rates, relate volatiHty,
counterpart creditworthiness and duration of contracts. Refer to Note 7 for further discussion regarding PacifiCorp's risk
management and hedging activities.
Contracts with explicit or embedded optionality are valued by separatig ea.ch contrct into its physical and financial forward, swap
and option components. Forward and swap components are valued against the appropriate forward price cure. Option components
are valued ùsing Black-Scholes-tye models, such as European option, Asian option, spread option and best-of option, with the
appropriate forward price cure and other inputs.
PacifiCorp's investments in money market mutul funds and debt and equity securties are accounted for as available-for-sale
securities. and are. stated at fair value. When available, a readily observable quoted market price or net asset value of an identical
security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical
security, the fair value is determined using pricing models or net asset values based on observable inrket inputs and quoted market
prices of securties with similar characteristics.
The following table reconciles the begining and ending balances ofPacifiCorp's commodity derivative assets and liabilities
measured at fair value on a recurng basis using significant Level 3 inputs for the years ended December 31 (in millons):
2010 2009
assets
Net transfers
PacifiCorp's long-term debt is cared at cost on the financial statements. The fair value of PacifiCorp's long-term debt has been
estimated based upon quoted market prices, where available, or at the present value of futue cash flows discounted at rates consistent
with comparable matuities with similar credit risks. The caring value ofPacifiCorp's varable-rate long-term debt approximates fair
value because of the frequent repricing of these instrents at market rates. The following table presents the caring value and
estimated fair value of PacifiCorp's long-term debt as of December 31 (in millions):
2010 2009
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
IFERC FORM NO.1 (ED. 12-88)Page 123.12
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp Î2) . A Resubmission 04/18/2011 2010/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 pricipally exposed to
electrcity, natual gas, coal and fuel oil commodity price rik as it has an obligation to serve retail customer load in its regulated
service terrtories; PacifiCorp's load and generating facilties represent substatial 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. Commodity prices are subject to wide price swigs as supply and demand are impacted by, among may other
unpredictable items, weather; market liquidity; generatig facility availability; customer usage; storage; and transmission and
trsporttion constraints. Interest rate risk exists on variable-rate short- and long-term debt and future debt issuances. PacifiCorp
does not engage in a material amount of proprietary trding activities.
PacifiCorp has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each
of the varous types of risk involved in its business. To mitigate a porton of its commodity risk, PacifiCorp uses commodity
derivative contracts, includig 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
primarily though the issuance of fixed-rate long-term debt and by monitorig market changes in interest rates. PacifiCorp may from
tie to time enter into interest rate derivative contrcts, such as interest rate swaps or locks, to mitigate 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 unedged porton to changes in market prices.
There have been no significant changes inPacifiCorp's accounting policies related to derivatives. Refer to Notes 2 and 6 for additional
information on derivative contracts.
IFERC FORM NO.1 (ED. 12-88)Page 123.13
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo,Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table, which excludes contracts that qualify for the normal purchases or norml sales exception afforded by GAAP,
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 (in milions):
Derivative Assets Derivative Liabilities
Current Noncurrent Current Noncurrent Total
As of December 31,2010
$185 $13 $34 $36 $
(62)(4)(213)(476)
123 9 (19)(440)
Desigated as ~ash flw hedging contracts(1):
Commodity assets
Commodty liabilties
Total
Total derivatives 123 9 (179)(440)(487)
Ca collateal (pyable) reeivabÌe (9)95 41 127
Total derivatives - net basis $114 $9 $(84)$(399)$(360)
As of December 31, 2009
Not designate as hedgig contracts (1)(2),
Commodity assets $191 $61 $8 $31
Comdity liabilities (29)(17)(142)(472)
Total 162 44 (14)(441)
Designated as cash flow hedging contracts(1):
Commodty asets
Commodity liabilities
Total derivatives 162 44 (134)(441)(369)
Cash collaterl (payable) receivable (54)()49 31 25
Total derivatives - net basis $Hl8 $43 $(85)$(410)$(344)
(i) Derivative contrts withn these categories subject to master netting arrngements are presented on a net basis on the Comparative Balance Sheet.
- (2) PacifiCorp's commodity derivatives not designated as hedging contrcts are generally included in rates and as of December 31,2010 and 2009, a net
regulatory asset of $487 millon and $367 millon, respectively, was recorded related to the net derivatve liabilty of $487 millon and $369 millon,
respectively.
IFERC FORM NO.1 (ED. 12-88)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 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Not Designated as Hedging Contracts
For PacifiCorp's commodity derivatives not designated as hedgig contracts, the settled amount is generally included in rates.
Accordingly, the net unealized gains and losses associated with interi price movements on contracts that are accounted for as
derivatives and probable of inclusion in rates are recorded as net regulatory assets. The following table reconciles the beginning and
ending balances of PacifiCorp's net regulatory assets and sumes the pre-ta gains and losses on commodity derivative cohtracts
recognized in net regulatory assets, as well as amounts relassified to eags for the years ended December 31 (in millions):
2010 2009
Beginnig balance
Changes in fair value recognized in net regulatory assets
Net gains reclassified to earnings - operatig revenues
Net losses reclassified to earings - operation expenses
Endig balnce
$367
90
64
(34)
487
$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
regulatory asset or liability, unrealized gains and losses are recognized on the Statement of Income as miscellaneous nonoperatig
income for unealized gains and as other deductions for unealized losses. The followig table sumarzes the pre-tax gains (losses)
included on the Statement of Income associated with PacifiCorp's dervative contracts not designated as hedging contracts and not
recorded as a net regulatory asset for the year ended December 31 (in millons):
Commodity derivatives:
Miscellaneous non-operatig income
Other deductions .
Total
2010 2009
$16
(6)
$23
(7)
6$$
Designated as Hedging Contracts
PacifiCorp uses derivative contracts accounted for as cash flow hedges to hedge electrcity and natual gas commodity prices. The
following table reconciles the begining and ending balances ofPacifiCorp's AOCI (pre-ta) and sumarzes pre-tax gains and losses
on commodity derivative contrcts designated and qualifyg as cash flow hedges recognized in OCI, as well as amounts reclassified
to earings for the years ended December 31 (in milions):
2010 2009
Beginnig balance
Net (gains) losses recognized in OCI
Net losses reclasifed to earings - operatig revenues
Net losses reclassified to earings - operation expenses
Ending balance
$
(12)
(1)
13
2
(2)
$$
Realized gains and losses on hedges and hedge ineffectiveness are recognized in income as miscellaneous nonoperating income and
other deductions, depending upon the natue of the item being hedged. For the years ended December 31, 2010 and 2009, hedge
ineffectiveness was insignificant. As of December 31, 2010 and 2009, PacifiCorp had no cash flow hedges outstading.
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 I (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Derivative Contract Volumes
The following table summarzes the net notional amounts of outstading derivative contracts with fixed price ter that comprise the
mark-to-market values as of December 31 (in millions):
contracts:
Unit of
Measure 2010 2009
Natual Decatherms
Credit Risk
PacifiCorp extends unsecured credit to other utilities, energy marketing companies, financial institutions and other market partcipants
in conjunction with wholesale sales and purchases activities. Credit risk relates to the risk of loss that might occur as a result of
nonperformance by counterparties on their contractual obligations to make or tae delivery of electrcity, natural gas or other
commodities and to make fiancial settlements of these obligations. Credit risk may be concentrted to the extent that one or more
groups of counterparies have similar economic, industr or other charcteristics that would cause their ability to meet contractual
obligations to be simlarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a
counterpar may default due to circumstances relating directly to it, but also the risk that a counterpar may default due to
circumstances involving other market participants that have a direct or indirect relationship with the counterpar.
PacifiCorp analyzes the financial condition of each significant wholesale counterpar before entering into any trnsactions,
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 arngements that may include margining and cross-product netting agreements and obtains thid-par
guarantees, letters of credit and cash deposits. Counterpartes may be assessed interest fees for delayed payments. If required,
PacifiCorp exercises rights under these arangements, including calling on the counterpart's credit support arangement.
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 onits unsecured debt. These derivative contrcts may either specifically
provide bilateral rights to demand cash or other securty if credit exposures on a net basis exceed specified rating-dependent threshold
levels ("credit-risk-related contigent featues") or provide the right for counterpares to demad "adequate assurance" in the event of
a material adverse change in PacifiCorp's creditwortiness. These rights can var by contract and by counterpart. As of
December 31, 2010, PacifiCorp's credit ratings from the three recognized credit rating agencies were investment grade.
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent featues
totaled $448 milion and $353 milion as of December 31,2010 and 2009, respectively, for whích PacifiCorp had posted collateral of
$136 milion and $80 milion, respectively. If all credit-risk-related contingent features for derivative contrcts in liability positions
had been triggered as of December 31,2010 and 2009, PacifiCorp would have been required to post $129 milion and $159 milion,
respectively, of additional collateraL. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility,
changes in credit ratings, changes in legislation or regulation or other factors.
IFERC 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 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(8) Short-term Debt and Other Financing Agreements
PacifiCorp has two unsecured credit facilities totaling $1.395 bilion, which includes a $635 milion unsecured credit facility that
expires in October 2012 and a $760 millon unecured credit facility that is fully available until July 2011. After July 2011, $720
milion is available until July 2012 and $630 millon is available until July 2013. The credit facilities include a fixed or varable
borrowig option for which rates var based on the borrowing option and PacifiCorp's credit ratings for its senior unsecured
long-term debt securties. These facilities support PacifiCorp's commercial paper program and certin varable-rate tax-exempt bond
obligations. As of December 31, 2010, PacifiCorp had $36 million of commercial paper borrowings outstanding at a
weighted-average interest rate of 0.3% and no borrowings outstading under its credit facilities. As of December 31,2009, PacifiCorp
had no short-term debt outstading.
As of December 31,2010, PacifiCorp had $601 milion of letter of credt issued under commtted arrgements, of which $304
million were issued under the revolving credit agreements. As of December 31, 2009, PacifiCorp had $517 million of letters of credit
issued under commtted arangements, of which $220 million were issued under the revolving credit agreements. These letters of
credit support PacifiCorp's varable-rate ta-exempt bond obligations, are fully available as of December 31, 2010 and 2009,
respectively, and expire periodically though May 2012. In addition, PacifiCorp's credit facilities supported $38 milion of
unenhanced variable-rate tax-exemptbond obligations as of December 31,2009.
Each revolvig credit agreement and letter of credit arrangement requires that PacifiCorp's ratio of debt, includig curent matuties,
to total capitalization at no time exceed 0.65 to 1.0. As of December 31,2010, PacifiCorp was in compliance with the covenants of its
revolving credit agreements and letter of credit arrngements.
The followig table sumarzes PacifiCorp's availability under its two unsecured revolving credit facilities as of December 31 (in
millions):
2010:
Available revolvig credit facilities
Less:
Short-term debt
Lettrs of credit and tax-exempt bond support
Net revolving credit facilities available
2009:
Available revolving credit facilties
Less:
Letters of credit and ta-exempt bond support
Net revolving credit facilities available
$
$J 137
As of December 31, 2010, PacifiCorp had approximately $15 milion of additional letters of credit issued on its behalf to provide
credit support for certain trnsactions as required by third pares. These letters of credit were all fully available as of December 31,
2010 and have provisions that automatically extend the anual expirtion dates for an additional year unless the issuing bank elects
not to renew a letter of credit prior to the expiration date. .
IFERC FORM NO.1 (ED. 12-88)Page 123.17
Name of Respondent This Report is:Date of He port Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifCorp i2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(9) Long-Term Debt and Capital Lease Obligations
PacifiCorp's long-term debt and càpitallease obligations were as follows as of December 31 (in milions):
2010 2009
Average Average
Interest Interest
Amount Rate Amount Rate
$1,040 6.5%$1,054 6.5%
852 5.6 852 5.6
324 7.7 324
100 6.7 100 6.7
798 6.3 798 6.3
2,491 6.1 2,490 6.1
41 0.4 41 0.3
325 0.3 325
221 0.3 176 0.2
68 4.0 113 3.8
71 5.6 71 5.6
13 6.2 13 6.2
6,344 6,357
57 11.4 59 11.7
$6.401 $6.416
First mortgage bonds:
5.0% to 9.2%, due though 2015
5.5% to 8.6%, due 2016 to 2019
6.7% to 8.5%, due 2021 to 2023
6.7% due 2026
5.3% to 7.7% due 2031 to 2035
5.8% to 6.4%, due 2036 to 2039
Tax-exempt bond obligations:
Variable rates, due 2013 (1)
Varble rates, due 2014 to 2025
Variable rates, due 2016 to 2024 (1)(2)
Varable rates, due 2014 to 2025 (1)(2)
5.6% to 5.7%, due 2021 to 2023 (I)
due 2030
Total long-term debt
Capital lease obligations:
8.8% to 14.8%, due though 2036
Total long-term debt and capital lease
obligations
Par Value
$ 1,040
855
324
100
800
2,500
41
325
221
68
71
13
6,358
$ 6.415
Reflected as:
2010 2009
Bonds
Unamortized discount on long-term debt
Obligations under capita11eases - noncurent
Obligations under capital leases - curent
Total long-term debt and capital lease obligations
$6,358
(14)
56
1
6.401
$6,372
(15)
57
2
6416$$
(1) Secured by pledged first mortgage bonds registered to and held by the ta-exempt bond trtee generally with the same interest rates, matuty dates and
redemption provisions as the ta-exempt bond obligations.
(2) Interest rates fixed for a tenn at 3.4% to 4.1 %, with $68 millon scheduled to reset in 2013. In 2010, $45 million reset at a varable rate.
PacifiCorp's long-term debt may include provisions that allow PacifiCorp to redeem the long-term debt in whole or in par at any tie.
These provisions genemlly include make-whole premiums.
In September 2010, PacifiCorp completed a re-offerig of varable-rate tax-exempt bond obligations totaling $38 milion. Letters of
credit totaling $39 milion were issued under one of PacifiCorp's unsecured revolving credit facilities to provide credit enhancement
and liquidity support for these previously unenhanced obligations.
In June 2010, PacifiCorp completed a re-offering of a $45 milion series of tax-exempt bond obligations. The interest rate for this
obligation was previously fixed for a term which, upon scheduled expiration, was converted to a variable rate with credit
enhancement and liquidity support provided by a $46 milion letter of credit issued under one of PacifiCorp's unsecured revolving
credit facilities.
IFERC FORM NO.1 (ED. 12-88) Page 123.18
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
In Januar 2009,PacifiCorp issued $350 milion of its 5.50% First Mortgage Bonds due Januar 15, 2019 and $650 milion of its
6.00% First Mortgage Bonds duè Januar 15,2039. The net proceeds were used to repay short-term debt, to fund capital expenditues
and for general corporate purposes.
The issuance ofPacifiCorp's first mortgage bonds is limted by available propert, earings tests and other provisions ofPacifiCorp's
mortgage. Approximately $21 bilion ofPacifiCorp's eligible propert (based on original cost) was subject to the lien of the mortgage
as of December 31,2010.
PacifiCorp has regulatory authority from the OPUC and the Idao Public Utilities Commission to issue an additional $2.0 billon of
long-term debt. PacifiCorp must make a notice filing with the Washington Utilities and Transporttion Commssion prior to any
futue issuance. Also, in December 2010, PacifiCorp fied a shelf registration statement with the United States Securties and
Exchange Commssion (the "SEC") coverig futue first mortgage bond issuances.
As of December 31, 2010, PacifiCorp had varable-rate tax-exempt bond obligations totaling $587 milion that are supportd by $601
million of letters of credit issued under committed bank arangements.. These letters of credit were fully available as of December 31,
2010 and expire periodically thugh May 2012.
PacifiCorp's letters of credit agreements generally contain similar covenants and default provisions as those contained in PacifiCorp's
revolving credit facilities, 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 do not occur. As of December 31, 2010,
PacifiCorp was in compliance with these covenants.
PacifiCorp has entered into long-term agreements that qualify as capital leases and expire at varous dates through October 2036 for
transportation services, power purchase agreements, real estate and for the use of certain equipment. The transporttion serices
agreements included as capital leases are fór the right to use pipeline facilities to provide natul gas to three of PacifiCorp's
generatig facilities. Net capital lease assets of $57 milion and $59 millon as of December 31, 2010 and 2009, respectively, were
included in net utility plant in the Comparative Balance Sheet.
As of December 31, 2010, the annual matuities of long-term debt and capital lease obligations, excluding unamortzed discounts and
including interest on capital lease obligations, for 201 1 and thereafter are as follows (in milions):
2011
2012
2013
2014
2015
Thereafter
Total
Unamortzed discount
Amounts representing interest (l
Total
Long-Term
Debt$ 587
17
261
253
122
5,118
6,358
(14)
Capital Lease
Obligations$ 8
7
12
8
$
Total
595
24
273
261
129
5,205
6,487
(14)
(72)
6401$ 6344 (72)$ 57 $
(1) Interest expense on capital leae obligations is recorded as rent expese.
IFERC FORM NO.1 (ED. 12-88)Page 123.19
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(10) Asset Retirement Obligations
PacifiCorp estimates its ARO liabilities based upon detailed engineering calculations of the amount and tiing of the futue cash
spending for a third par to pedorm 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 cannot be reasonably estimated. Due to the indetermnate
removal date, the fair value of the associated liabilities on certin transmission, distrbution and other assets cannot curently be
estimated and no amounts are recognized on the financial statements other.than those included in the accumulated provision for
depreciation established via approved depreciation rates aid in aècordance with accepted reguatory practices. These accruals totaled
$782 milion and $755 milion as of December 31,2010 and 2009, respectively.
The following table reconciles the begining and ending balances of PacifiCorp's ARO liability for the years ended December 31
(in millions):
2010 2009
2 19
Ending balance $105
(l) Results from changes in the timng and amounts of estimated cash flows for certin plant and mine reclamtion.
(2) PacifiCorp records the accretion expense of asset retirement obligations as either a regulatory asset or liability.
Certin of PacifiCorp's decommssioning and reclamation obligations relate to jointly owned facilities and mine sites.. PacifiCorp is
committed to pay a proportonate share of the decommssioning or reclamation costs. In the event of a default by any of the other joint
paricipants, PacifiCorp may be obligated to absorb, directly or by paying additional sum to the entity, a proportionate share of the
defaulting par's liability. PacifiCorp's estimated share of the decommssioning and reclamation obligations are primarily recorded as
ARO liabilities.
IFERC FORM NO.1 (ED. 12-88)Page 123.20
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/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
healthcareand life insurance benefits though varous plans for eligible retirees. In addition, PacifiCorp sponsors a defmed
contrbution 401(k) employee savings plan ("40 I (k) Plan"). Non-union employees hired on or after January I, 2008 and cerin union
employees are not eligible to parcipate in the PacifiCorp Retiement Plan ("Retirement Plan"). These employees are eligible to
receive enhanced benefits under the 401(k) Plan.
Pension and Other Postretirement Benefit Plans
PacifiCorp's pension plans include a non-contrbutory defined benefit pension plan, the Retiement Plan; the Supplemental Executive
Retiement Plan ("SERP"); and certin joint trst union plans to which PacifiCorp contrbutes on behalf of certin bargaining units.
All non-union Retirement Plan paricipants that did not elect to receive equivalent fixed contrbutions to the 401(k) Plan effective
January 1, 2009, ear benefits based on a cash balance formula. For most union employees, benefits under the Retirement Plan were
frozen at varous dates from December 31,2007 through March 31, 2010 as they are now being provided with enhanced 401(k) Plan
benefits. Certin union Retirement Plan paricipants contiue to ear benefits under the Retiement Plan based on the employee's
years of service and a fmal average pay formula.
The cost of other postretirement benefits, includig healthcare and life insurance benefits for eligible retirees, is accrued over the
active serice period of employees. PacifiCorp funds these other postretiement benefits though a combination of fuding vehicles.
PacifiCorp also contrbutes to joint trst union plans for postretirement benefits offered to certin bargaining units.
Healthcare Reform Legislation
In March 2010, the President signed into law healthcare reform legislation that included provisions to eliminate the tax deductibility
of other postretiement costs to the extent of retiee drg subsidies received from the federal government beginning after
December 31, 2012. Accordingly, PacifiCorp increased defered income ta liabilities and regulatory assets by $39 million.
PacifiCorp has received authorization from varous state regulatory commssions for deferral of the $16 million of the adjustment that
related to income tax benefits associated with amounts previously recognized as net periodic benefit costs. The remaining $23 milion
of the adjustment relates to income tax benefits that will no longer be realized in the futue when the net periodic benefit cost is
recognized and for which recovery of the resulting higher futue income tax expense wil be addressed through on-going ratemaking
proceedigs.
The new law also contains a provision that requires a 40% excise tax for group health benefits that are provided to employees above
certin premium thesholds begining in 2018. The tax would apply to the amount of premiums in excess of the thresholds. Virally
all major areas of the healthcare reform legislation, including the 40% excise ta, are subject to interpretation and implementation
rules that may take several years to complete. As of December 31, 2010, PacifiCorp's other postretiement benefit obligation increased
by $12 milion as a result of the projected impact of the excise ta on benefits provided to a certin bargaining unit.
Curtailments
In August 2008, non-union employee paricipants in the Retirement Plan were offered the option to continue to receive pay credits in
their curent cash balance pension 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 milion curilment gain. PacifiCorp recorded $36 milion of the curilment
gain representig the amount to be retued to customers in rates as a regulatory deferrl, resultig in a reduction to regulatory assets
as of December 31, 2008. The regulatory deferral is being amorted over a period of thee to 10 years based on agreements with
various state regulatory commssions.
IFERC FORM NO.1 (ED. 12-88)Page 123.21
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 04/18/2011 2010/04
NOTES TO FINANCIAL STATEMENTS (ContinUed)
Effective March 31, 2010, the Utility Workers Union of America Local Union No. 127 (" Local 127") elected to cease parcipation in
the Retiement Plan and paricipate only in the 401(k) Plan with enhanced benefits. As a result of this election, the Local 127
paricipants' Retiement Plan benefits were frozen on March 31, 2010. This change resulted in a $2 millon curailment gain that was
recorded as a regulatory deferral and is being amortzed over periods similar to those required for other recent curilments. Also as a
result of this change, PacifiCorp's pension benefit obligation and regulatory assets each decreased by $14 million.
Net Periodic Benefit Cost
Forpuroses of calculating the expected retu on plan assets, a market-related value isused. The maket-related value of plan assets
is calculated by spreading the difference between expected and actul investment retus over a five-year perod begiing aftr 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):
Pension Other Postretirement
2010 2009 2010 2009
Interest cost 66 71
Net amortization 23 10 14 12
(I) Servce cost excludes $13 million and $11 million of contrbutions to the joint trst union plans durg each of the yeas ended December 31, 2010 and 2009,
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)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
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 millons):
Plan assets at fair value, begning of year
Employer connibutions
Parcipant connibutions
Actul return on plan assets
Benefits paid
Plan assets at fair value, end of year
Pension
2010 200
$825 $692
117 54
102 160
(84)(81)
$960 $825
Other Postretirement
2010 2009
$350
24
9
44
(38)
389
$284
24
9
70
(3)
350$$
The following table is a reconciliation of the benefit obligations for the years ended December 3 i (in millons):
Pension Other Postretirement
2010 2009 2010 2009
Benefit obligtion, begnning of year $1,199 $1,070 $545 $489
Servce cost 12 16 6 5
Intest cost 66 71 31 33
Partcipant connibutions 9 9
Plan amendmts (1)(4)
Curilment (14)
Actual loss 57 124 25 47
Benefits paid, net of Medicare subsidy (84)(81)(35)(34)
Benefit obligation, end of year $1236 $1199 $581 $545
Accumulated benefit obligation, end of year $1230 $1178
The fuded status of the plans and the amounts recognized on the Comparative Balance Sheet as of December 3 i are as follows
(in milions):
Pension Other Postretirement
2010 2009 2010 2009
Plan asets at fair value, end of year $960 $825 $389 $350
Less - Benefit 0 , end of year 1.236 1,99 581 545
Fundeds $(26)$(34)$(192)$(J95)
Amunts recognze on the Coparative Balance Sheet:
Other curent liabilities $(4)$(4)$$
Other long-teo liabilties (272)(30)(92)(195)
Amounts recognized $(26)$(34)$(J92)$(J95)
IFERC FORM NO.1 (ED. 12-88)Page 123.23
Name of Respondent .This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp . (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 surrender 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
$40 milion and $39 million as of December 31, 2010 and 2009, respectively. These assets are not included in the plan assets in the
above table, but are reflected on the Comparative Balance Sheet. The porton of the pension plans'projected benefit obligation related
to the SERP was $56 milion and $55 milion as of December 31,2010 and 2009, respectively.
Unrecognized Amounts
The porton of the funded status of the plans not yet recognized. in net periodic benefit cost as of December 31 is as follows (in
millions):
2010 2009
Other Postretiement2010 2009Pension
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)
PacifCorp 1(2) . A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
A reconciliation of the amounts not yet recognzed as components of net periodic benefit cost for the years ended December 31, 2010
and 2009 is as follows (in millions):
Other Postrtirement
Balance January 1,2009
Net loss arsing durng the year
Pror serce credit arsing dung the year
Trasition obligation arsing durng the year
Net amortzation
Total
Balançe, Deember 31,2009
Net loss ars' -
Regulatory
Asset
,$404
29
(1)
(2)
26
430
27
(14)(1)
$430
Regulatory
Asset
$160
4
(i)
(3)
(14)
(14)
146
ii
23
(15)
19
$165
Acçumulated
Other
Comprehensive
Loss, Net Total
,$4 $408
5 34
(1)
(2)
5 31
9 439
2 29
(14)(3)
2 2
$11 ,$441
9
Net loss arising durg the year
Pror seice credit arsing dug th yea
Net amortization
Total
Balance, December 31,2009
Net loss arising durg the year
Curilment
Net amrtzation
Tota
Biiance, Deçember 31, 2010
Deferred
Inçome
Taxes Total
$20
3
$180
7
(1)
(3)
(14)
(II)
169
ii
3
23
(23)
(23)
$$
Net amortion
Total
Balance, December 31,2010
(15)
(4)
165
(1) Represents adjustments to reguatory assets associated with income ta benefits that wil no longer be realized when the net perodic benefit cost is
recognized as aresult of the healthcare reform legislation.
The net loss, prior service credit, net transition obligation and regulatory deferls that wil be amortzed in 2011 into net periodic
benefit cost are estimated to be as follows (in millions):
Net Prior Servce Net Transition Regulatory
Loss Credit Obligation Deferrals Total
Pension $37 $(8),$$(9)$20
Other postrtirement 6 ii i 18
$43 $(8)$11 $(8)$38
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 I (2) A Resubmission 04/18/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost for the year ended December 31 were as follows:
2010 2009
Other Postretirement2010 2009Pension
Benefit obligations as of December 31:
Discount rae
Rate of compensation increase
5.35%
3.50
5.80"Æi
3.00
5.45%
N/A
5.85%
N/A
Net benefit cost for the years ended:
Discunt rate
Expected retu on plan assets
Rate of compensaon increae
5.80%
7.75
3.00
6.90%
7.75
3.50
5.85%
7.75
N/A
6.90%
7.75
In establishing its assumption as to the expected retu on plan assets, PacifiCorp utilizes the expected asset allocation. and retu
assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
8%
5%
2016
8%
5%
2016
2009
Assumed healthcae cost trend rates as of December 31:
. Healthcare cost trd rate assued for next yeaR~ ro
Year
2010
A one percentage-point change in assumed healthcare cost trend rates would have the following effects (in millions):
Increase (Decrease)
One Percentage-Point One Percentage-Point
Increase Decrease
Effect on total serce mid mtees cost
Effect on other postretirement benefit obligation
$2
41
$(2)
(33)
IFERC FORM NO.1 (ED. 12-88)Page 123.26
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Contributions and Benefit Payments
Employer contrbutions to the pension and other postretirement benefit plans are expected to be $71 millon and $28 millon,
respectively, during 201 1. Funding to PacifiCorp's Retiement Plan trst is based upon the actuarally determed costs of the plan and
the requirements of the Interal Revenue Code, the Employee Retiement Income Securty Act of 1974 and the Pension Protection
Act of 2006, as amended. PacifiCorp considers contrbutig additional amounts from tie to time in order to achieve cerain fuding
levels specified under the Pension Protection Act of 2006, as amended. PacifiCorp's fuding policy for its other postretirement benefit
plans is to contrbute an amount equal to the sum of the net periodic benefit cost and the amount of Medicare subsidies expected to be
earned durng the period.
The expected benefit payments to paricipants in PacifiCorp's pension and other postretiement benefit plans for 2011 though 2015
and for the five years thereafter are sumarzed below (in millions):
Projected Benefit Payments
Other Postrtirement
Pension Gross Medicare Subsidy Net of Suhsidy
2012 99 36 (3)
$
2014 112 42
43
242
(4)38
2016-5.13 (30)212
Plan Assets
Investment Policy and Asset Allocations
PacifiCorp's investment policy for its pension and other postretirement benefit plans is to balance risk and return though a diversified
portfolio of fixed income securties, equity securties and other alternative investments. Matuties for. fixed income securties are
managed to targets consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments
within the parameters outlined by the PacifiCorp Pension Commttee. The investment portolio is managed 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 historical performance for the tyes of assets in which the plans invest.
The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretiement benefit plan assets are as follows
as of December 31,2010:
Pension(l)
%
Other PostretiremenW)
%
Equity 53-57
8-12
0-1Cash and cash equivalents 0-1
(1) PacifiCorp's Retirment Plan trst includes a separte account that is used to fud benefits for the other postrtirement benefit plan. In addtion to this
separate account, the assets for the other postretirement benefit plans are held in two Volunta Employees' Beneficiaries Association (nVEBAn) trsts, each
of which has its own investment allocation strtegies. Target allocations for the other postretirement benefit plans include the separte account of the
Retirement Plan trst and the two VEBA trts.
(2) For puroses of tagét allocation percentages and consistent with the plans' investment policy, investment funds have been allocated based on the underlying
investments in fied-income and equity securties.
IFERC FORM NO.1 (ED. 12-88)Page 123.27
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
.
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defied benefit pension plans (in
milions):
Input Levels for Fair Value Measurements
Level 1(1) 'Level 2(1) Level 3(1) Total
As of December 31. 2010
Cah and cah equivalents $$8 $$8
Fixed-income securties:
United State goverent obligations 20 20
Corporate obligations 52 52
International goverent obligations 81 81
Municipal obligations 4 4
Agency, asset and mortgage-backed obligations 49 49
Equity securties:
United State equity securties 366
International equity securties 7 7
Invesnt fuds (2)109 180
Limited partership interests(3)84 84
Total $502 $374 $84 $960
As of December 31. 2009
Cash and cash equivalents $$8 $$8
Fixed-income securties:
United States governent obligations 20 20
Cororate obligations 44 44
International governent obligations 65 65
Muncipa obligatons 2 2
Agency, asset and mortgage-backed obligations 43 43
Equity securties:
United States equity securties 296
Inteonal equity seurties 4
Investment fuds(2)95 168
Limted paerhip interests(3 80
Total $415 $330 $80 $
(1) Refer to Note 6 for additional discussion regarding the the levels of the fair value hierarchy.
(2) Investment fuds are comprised of mutual fuds and collective trst funds. These investment fuds reresent equity and fixed-income securties as of
December 31, 2010 and 2009, of approximately 60% and 400/ and 61% and 39%, respectively.
(3) Limited partership interests include several private equity fuds tht invest prily in buyout, growt equity and ventue capitaL.
IFERC FORM NO.1 (ED. 12-88)Page 123.28
Name of Respondent This Report is:Date of Report Yea~Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defied benefit other postretirement plan
(in millions):
Input Levels for Fair Value Measurements
Level 1(1) Level 2(1 Level 3(1) Total
December 31,2010
Cah and cah equivalents $2 $$$
Fixed-income securties:
Unite States goverent obligations 2 2
Coiprate obligations 4 4
Interatonal government obligations 7 7
Agency, asset and mo 4 4
Equity secuties:
United States equity securties 134 134
Internatonal equity securties 3
Investment fuds (2)118 107 225
Limite parership interests(3)7 7
Total 123 $7 $389
December 31, 2009
Cash and cah equivalents $$$4
Fixed-income securties:
United State governent obligations 2 2
Corporate obligations 4 4
Inteational governent obligations 6 6
Agency, asset and mortage-backed obligations 4 4
Equity securties:
United States equity securties 115 115
Internatinal equity securties 2 2
Investment fuds(2)101 104 205
Limte parersp interests(3)8 8
Total $224 $ll8 $8 $350
(i) Refer to Note 6 for additional discussion regarding the three levels of the fai value hierchy.
(2) Investment funds are comprised of mutual fuds and collective trt fuds. These investment fuds represent equity and fixed-income securties as of
December 31, 2010 and 2009, ofapproxiintely 47% and 53% and 50% and 50%, respectively.
(3) Limited parership interests include several private equity fuds that invest primarly in buyout, growt equity and ventue capitaL.
When available, a readily observable quoted market price or net asset value of an identical securty in an active market is used to
record the fair value. In the absence of a quoted market price or net asset value of an identical securty, the fair value is determed
using pricing models or net asset values based on observable maket inputs and quoted market prices of securties with similar
characteristics. When observable market data is not available, the fair value is detered using unobservable inputs, such as
estiated futue cash flows, purchase multiples paid in other comparble third-par trnsactions or other information. Investments in
limited parerships are valued at estiated fair value based on the Plan's proportonate share of the parerships' fair value as
recorded in the parterships' most recently available financial statements adjusted for recent activity and forecasted retus. The fair
values recorded in the parerships' financial statements are generally determned based on closing public market prices for publicly
traded securties and as determed by the general parters for other investments based on factors including estiated futue cash
flows, purchase multiples paid in other comparable third-part transactions, comparable public company tring multiples and other
information.
IFERC FORM NO.1 (ED. 12-88)Page 123.29
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table reconciles the begining and ending balances of PacifiCorp's plan assets measured at fair value using significant
Level 3 inputs for the years ended December 31 (in millons):
Limited Partnership Interests
Pension Other Postretirement
on plan assets still held at December 3 i, 2009 5
Balance,
Purchases, sales, distrbutions and settlements
Dermed Contribution Plan
PacifiCorp sponsors a defined contrbution plan covering substantially all employees. PacifiCorp's contrbutions are based priarly
on each parcipant's level of contrbution and caot exceed the maximum allowable for tax puroses. PacifiCorp's contributions to
the 401(k) Plan were $39 milion and $34 milion for the years ended December 31, 2010 and 2009, respectively. As previously
described, certin paricipants now receive enhanced benefits in the 401(k) Plan and no longer accrue benefits in the Retirement Plan.
IFERC FORM NO.1 (ED. 12-88)Page 123.30
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2. An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
NOTESTO FINANCIAL STATEMENTS (Continued)
(12) Income Taxes
Income tax expense consists of the following for the year ended December 31 (in millons):
2010 2009
Current:
Federal
State
Total
$(489)
(1)
(490)
$(443)
2
(441)
Deferre:
Federal
State
Total
675
29
704
Investment tax credits
Total income ta expense $
(4)
210 $
(4)
235
A reconciliation of the federal statutory income tax rate to the effective income ta rate applicable to income before income tax
expense is as follows for the years ended December 31:
2010 2009
Federal statutory ta rate
State taxes, net of federal benefit
Tax credits (I)
Effects of ratemaking
Other
Effective income tax rate
35%
3
(8)
(2)(l
27%
3
(2)
30%
(l) Prmarly attbutable to the impact of federal renewable electrcity production ta credits related to qualifying wind-powered generatig facilities that extend
10 years from the date the facilities were placed in servce.
IFERC FORM NO.1 (ED. 12-88)Page 123.31
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The net deferred income tax liability consists of the following as of December 31 (in milions):
2010 2009
Deferred tax assets:
Employee benefits
Derivative contrcts
Regulatory liabilities
Other
$187
185
26
191
589
$244
140
40
164
588
Deferred tax liabilties:
Propert, plant and equipment
Regulatory assets
Other
(3,342)
(650)
(30)
(4,022)
(3.433)
(2,643)
(576)
(35)
(3,254)
(2,666)Net defered ta liability $$
The sale of PacifiCorp to MEHC on March 21, 2006 trggered certin tax related events that remain unsettled. PacifiCorp does not
believe that the tax, if any, arising from the ultimate settlementpfthese events wil have a material impact on its fmancial results.
The United States Internal Revenue Servce has closed its examination of PacifiCorp's income tax retus though the 2003 tax year.
In most cases, state jursdictions have closed their examinations ofPacifiCorp's income tax retus though 1993.
As of December 31,2010 and 2009, net unecognized tax benefits totaled $70 milion and $75 milion, respectively, which included
$9 milion . and $6 milion, respectively, of tax positions that, if recognized, would have an impact on the effective tax rate. The
remaining unrecognized ta benefits relate to positions for which ultimate deductibility is higWy certin but for which there is
uncertinty as to the timing of such deductibility. Recognition of these ta benefits, other than applicable interest and penalties, would
not affect PacifiCorp's effective tax rate.
In March 2011, the United States Internal Revenue Service released Revenue Procedure 2011-26, which provides guidance regarding
the application of the 100% bonus depreciation provisions that were provided for in the Tax Relief, Unemployment Insurance
Reauthorization, and Job Creation Act of 2010. PacifiCòrp is curently evaluating the impacts of this guidance on its December 31,
2010 income tax provision and expects that income taes receivable from MEHC, which is included Account 165 Prepayments, will
decrease significantly with a concurent decrease in Account 282 Accumulated deferred income taxes - other propert.
IFERC FORM NO.1 (ED. 12-88)Page 123.32
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(13) Commitments and Contingencies
Legal Matters
PacifiCorp is par to a varety of legal actions arsing out of the normal coure of business. Plaintiffs occasionally seek punitive or
exemplar damages. PacifiCorp does not believe that such normal and routie litigation wil have a material impact on its financial
results. PacifiCorp is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines,
penalties and other costs in substatial amounts and are described below.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regaring air and water quality, renewable portfolio stadards,
emissions performance standads, climate change, coal combustion byproducts, 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 all applicable laws and regulations.
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 Environmental Protection Agency ("EPA") has requested from numerous utilities information
and supportng documentation regarding their capital projects for varous generatig facilities. Between 2001 and 2003, PacifiCorp
responded to requests for information relating to its capital projects at its generating facilities, and has been engaged in periodic
discussions with the EPA over several years regardig its historical projects and their compliance with NSR and PSD provisions. A
NSR enforcement case against another utility has been decided by the United States Supreme Court, holdig that an increase in annual
emissions of a generating facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR
permitting. PacifiCorp could be required to install additional emissions controls, and incur additional costs and penalties, in the event
it is determined that PacifiCorp's historical projects did not meet all reguatory requirements. The impact of these additional emissions
controls, costs and penalties, if any, on PacifiCorp's financial results canot be deterined at this time.
Hydroelectric Relicensing
PacifiCorp's hydroelectric portolio consists of 46 generating facilities with an aggregate facility net owned capacity of
1,157megawatts ("MW"). FERC regulates 98% of the net capacity of this portolio through 16 individual licenses, which tyically
have terms of 30 to 50 years. PacifiCorp expects to incur ongoing operatig and maintenance expense and capital expenditues
associated with the terms of its renewed hydroelectrc licenses and settlement agreements, including natul resource enhancements.
PacifiCorp's Klamath hydroelectrc system is curently operatig under annual licenses. Substantially all of PacifiCorp's remaining
hydroelectric generating facilities are operating under licensés that expire between 2030 and 2058.
Klamath Hydroelectric System - Klamath River, Oregon and California
PacifiCorp is curently operating under an annual license for the Klamath hydroelectrc system as par of a relicensing settlement
process that includes possible removal of the system's four mainstem das.
In Februry 2010, PacifiCorp, the United States Deparent of the Interior, the United States Deparent of Commerce, the State of
California, the State of Oregon and various other governental and non-governental settlement partes signed the Klamath
Hydroelectrc Settlement Agreement ("KHSA"). Among other things, the KHSA provides that the United States Departent of the
Interior. conduct scientific and engineering studies to assess whether removal of the Klamath hydroelectrc system's four mainstem
dams is in the public interest and wil advance the Klamath Basin's salmonid fisheries. If it is determined that dam removal should
proceed, dam removal is expected to commence no earlier than 2020.
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 I (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Under the KHSA, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilities. For dam removal to
occur, federal legislation consistent with the KHSA must be enacted to provide, among other things, protection for PacifiCorp from
all liabilities associated with dam removal activities. If Congress does not enact legislation, then PacifiCorp wil resume relicensing at
the FERC. In addition, the KHSA limitsPacifiCorp's contrbution to dam removal costs to no more than $200 million, 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 milion for da removal costs is expected to be raised through a California bond measure or other
appropriate State of California financing mechanism. If dam removal costs exceed $200 million and if the State of California is unable
to raise the additional fuds necessary for dam removal costs, suffcient fuds would need to be provided by an entity other than
PacifiCorp in order for the KHSA and dam removal to proceed.
PacifiCorp has begu collection of sUrcharges. from Oregon customers for their share of dam removal costs, as approved by the
OPUC, and is depositig the proceeds in a trust account maintained by the OPUC. The California Public Utilities Commssion issued
a proposed decision in Februar 201 1 with simlar provisiQnsfor California customers and a final order is pending.
As of December 31, 2010, the net book value of PacifiCorp's Klamath hydroelectrc system generating facilities was $59 milion with
an average remaining depreciable life of 36 years. As of December 31, 2010, relicensing and settlement costs associated with the
Klamath hydroelectrc system totaled $74 milion. PacifiCorp received approval from the OPUC to depreciate its hydroelectrc system
generating facilities and relicensing and settlement costs through the expected dam removal date, and is at varous stages of seeking
similar approval in its remaining jursdictions.
Hydroelectric Commitments
As described above, certain of PacifiCorp's hydroelectrc licenses contain requirements for PacifiCorp to make certin capital and
operating expenditures related to its hydroelectrc facilities. PacifiCorp estiates it is obligated to make capital expenditues of
approximately $321 milion over the next 10 years related to these licenses.
FERC Issues
FERC Investigation
Durng 2007, theWestem Electricity Coordinating Council ("WECC") audited PacifiCorp's compliance with several of the reliability
standads developed by the Nort American Electric Reliability Corporation ("NERC"). In April 2008, PacifiCorp received notice of a
preliminar non-public investigation from the FERC and the NERC to determne whether an outage that occured in PacifiCorp's
transmission system in Februar 2008 involved any violations of reliability standads. In November 2008, PacifiCorp received
preliminary findings from the FERC staff regarding its non-public investigation into the February 2008 outage. Also in
November 2008, in conjunction with the reliability standards review, the FERC assumed control of certin aspects of the WECC's
2007 audit. PacifiCorp has engaged in discussions with FERC staff regarding fmdings related to the non-public investigation, which
includes the WECC's findings that are now being processed by the FERC. PacifiCorp does not believe that the outcome of the
non-public investigation wil have a material impact on its financial results.
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 .(2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Còntinued)
Northwest Re.fnd Case
In June 2003, the FERC termnated its proceeding relatig to the possibilty of requing refuds for wholesale spot-market bilateral
sales in the Pacific Nortwest between December 2000 and June 2001. The FERC concluded that orderig refuds would not be an
appropriate resolution of the matter. In November 2003, the FERC issued its fmal order denying rehearirig. Several market
parcipants, excluding PacifiCorp, fied petitions in the United States Cour of Appeals for the Ninth Circuit ("Ninth Circuit") for
review of the FERC's final order. In August 2007, the Ninth Circuit concluded that the FERC failed to adequately explain how it
considered or examned new evidence showing intentional market manipulation 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 madate order, the Ninth Circuit remaded the case to the FERC to (a)address the new
market manipulation evidence in detail and account for it in any futue order regarding the award or denial of refunds in the
proceedings; (b) include sales to CERS in its analysis; and (c) fuer consider its refud decision in light of related, intervening
opinions of the cour. The Ninth Circuit offered no opinion on. the FERC's findings based on the record established by the
administrtive law judge and did not rule on the merits of the FERC's November 2003 decision to deny refunds. 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 canot predict the futue course of this proceeding and its impact on its financial results, if any, at this time.
Purchase Obligatioris
PacifiCorp has the following purchase obligations that are not reflecte on the Compartive Balance Sheet. Minimum payments as of
December 31, 2010 are as follows (in millons):
2011 2012 2013 2014 2015 Thereafter Total
Fuel 764 604 595 573 472
Transmission 108 97 83 62
Maintenance, service
and other 19 16 12 6
$969 $867 $781 $648
Purchased Electricity
As par of its energy resource portolio, PacifiCorp acquires a porton of its electrcity through long-term purchases and exchange
agreements. PacifiCorp has several power purchase agreements with wind-powered and other generating facilities that are not
included in the table above as the payments are based on the amount of energy generated and there are no minimum payments.
Included in the purchased electrcity payments are any power agreements that meet the definition of an operating lease.
Included in the minimum fixed annual payments for purchased electrcity above are commitments to purchase electrcity from several
hydroelectrc systems under long-term arrangements with public utility 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 operatig expenses and debt service. These costs are
included in operation expenses on the Statement of Income. PacifiCorp is required to pay its portion of operating costs and its portion
of the debt service, whether or not any electrcity is produced. These arangements accounted for less than 5% ofPacifiCorp's 2010
and 2009 energy sources.
IFERC FORM NO.1 (ED. 12-88)Page 123.35
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp ..I (2) A Resubmission 04/18/2011 2010/Q4
.NOTES TO FINANCIAL STATEMENTS (Continued)
Fuel
PacifiCoFP has "take or pay" coal and natul gas contracts that require minimum payments.
Constrction
PacifiCorp has purchase obligations for its ongoing constrcton programs to meet increased electrcity usage, customer growt,
system reliability objectives, develop incremental generating capacity, foster the use of renewable resources, enhance transmission
capabilities and mitigate environmental impacts through the installation of emission reduction technology. The amounts included in
the table above relate to firm commitments. The following discussion describes PacifiCorp's overall commtments and includes
amounts that PacifiCorp is not yet firmly commtted though a purchase order or other agreement.
PacifiCorp has significant futue capital requirements. Capital expenditue needs are reviewed regularly by management and may
change. significantly as a result of such reviews. Estimates may change significantly at any time as a result of, among other factors,
changes in rules and regulations, including environmental; changes in income tax laws; general business conditions; load projections;
system reliability standads; the cost and efficiency of constrction labor, equipment, and materials; and the cost and availabilty of
capitaL.
As part of the March 2006 acquisition of PacifiCorp, MEHC and PacifiCorp made a number of commitments to the state regulatory
commssions in all six states in which PacifiCorp has retail customers. These commitments are generally being implemented over
several years following the acquisition and are subject to subsequent regulatory review and approvaL. As of December 31, 201 0, the
status of the key financÌal commtments was as follows:
. Invest approximately $812 milion in emissions reduction technology for PacifiCorp's existing coal-fired generatig
facilities. Through December 31, 2010, PacifiCorp had spent a total of $ 1.2 bilion, including non-cash equity AFUDC,
on these emissions reduction projects. In June 2010, PacifiCorp fied notification of its completion of this commitment
with the applicable state regulatory commssions.
. Invest in certain transmission and distrbution system projects that would enhance reliability, facilitate the receipt of
renewable resources and enable fuer system optization in an amount that was origially estiated to be
approximately $520 milion at the date of the acquisition. Through December 31, 2010, PacifiCorp had spent a total of
$958 milion in capital expenditues, includig non-cash equity AFUDC, which was in excess of the origial estimate
due to the evolving natue of the projects agreed to in the commitment. This amount includes costs for certin segments
of the transmission expansion program discussed below.
PacifiCorp's Energy Gateway Transmission Expansion Program, which began in 2007, represents a plan to build approximately
2,000 miles. of new high-voltage transmission lines, with an estimated cost exceeding $6 bilion, priarly in Wyoming, Utah, Idaho
and Oregon. The plan includes several transmission line segments that wil: (a) address customer load growt; (b) improve system
reliability; (c) reduce transmission system constraints; (d) provide access to diverse generation resources, including renewable
resources; and (e) improve the flow of electrcity thoughout PacifiCorp's six-state service area.
Transmission
PacifiCorp has agreements for the right to transmit electrcity over other entities' transmission lines to facilitate delivery to
PacifiCorp's custOIi1ers.
IFERC FORM NO.1 (ED. 12-88)Page 123.36
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
Operating Leases and Easements
PacìfiCorp has non-cancelable operatig leases priarly for offce equipment, offce space, certin operatigfacilities, land and
equipment under operating leases that expire at varous dates though the year endig December 31, 2092. These leases generally
require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased propert. Certin leases contain renewal
options for varying periods and escalation clauses for adjustig rent to reflect changes in price indices. PacifiCorp also has
non-cancelable easements for land on which its wind-powered generatig facilities are located. Rent expense on non-cancelable
operating leases totaled $ i 5 milion for 20 i 0 and $13 millon for 2009.
Maintenance, Service and Other Commitments
PacifiCorp has various non-cancelable maintenance, service and other commtments primarly related to tubine and equipment
maintenance and varous other service agreements.
(14) Preferred Stock
PacìfiCorp'spreferred stock was as follows as of December 31 (shares in thousands, dollars in millions, except per share amounts):
Redemption 2010 2009
Price Per Share Shares Amount Shares Amount
Series:
Serial Preferred, $100 stated value,
shares
108 10 108 10
7.00%~on-redeemable 18 2 18 2
407 415 $41
Generally, preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrctions. In the event of
voluntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends.
Upon involuntary liquidation, all preferred stock is entitled to stated value plus accrued dividends. Dividends on all preferred stock
are cumulative. Holders also have the right to elect members to the PacifiCorp Board of Directors in the event dividends payable are
in default in an amount equal to four full quarerly payments.
In May 2010, PacifiCorp received an unsolicited offer to repurchase certin shares of PacifiCorp's preferred stock. As a result,
PacifiCorp purchased and canceled 4,036 shares of its $100 stated value 4.72% Seral Preferred Stock for $318,844, at an average
price per share of $79, and 3,266 shares of its $10Q stated value 4.56% Serial Preferred Stock for $241,684, at an average price per
share of $74.
Dividends declared but not yet due for payment on prefered stock were $1 million as of December 31,2010 and 2009.
IFERC FORM NO.1 (ED. 12-88)Page 123.37
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) X An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(15) Common Shareholder's Equity
In Januar 2011, PacifiCorp declared a dividend of $275 milion, which was paid to PPW Holdings LLC, a direct subsidiar of
MEHC on Februar 28,2011.
In March 2011, PacifiCorp declared a dividend of$275 milion payable to PPW Holdings LLC on April 20, 2011.
Through PPW Holdings LLC, MEHC is the sole shareholder of PacifiCorp's common stock. The state regulatory orders that
authorized MEHC's acquisition ofPacifiCorp 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 dermed capitalization.
As of December 31, 2010, the most restrctive of these commitments prohibits PacifiCorp from making any distrbution to
PPW Holdings LLC or MEHC without prior state regulatory approval to the extent that it would reduce PacifiCorp's common stock
equity below 46.25% of its total capitalization, excluding short-term debt and curent matuties of long-term debt. This minimum
level of common equity declines to 45.25% for the year ending December 31, 2011 and 44% thereafter. The terms of this commitment
treat 50% of PacifiCorp's remaining balance of preferred stock in existence prior to the acquisition of PacifiCorp by MEHC as
common equity. As of December 31, 2010, PacifiCorp's actual common stock equity percentage, as calculated under this measure,
was 55.8%, and PacifiCorp would have been permtted to dividend $2.320 bilion under this commtment.
These commtments also restrict PacifiCorp from making any distrbutions to either PPW Holdings LLC or MEHC if PacifiCorp's
unsecured debt rating is BBB- or lower by Stadard & Poor's Rating Services or Fitch Ratings or Baa or lower by Moody's Investor
Service, as indicated by two of the three ratig services. As of December 31,2010, PacifiCorp's unsecured debt rating was A- by
Standard & Poor's Rating Services, BBB+ by Fitch Ratings and Baal by Moody's Investor Service.
PacifiCorp is also subject to a maximum debt-to-total capitalization percentage under various fiancing agreements as fuer
discussed in Notes 8 and 9.
Appropriated Retained Earnings
In accordance with the requirements of certain hydroelectrc relicensing projects, as of December 31, 2010 and 2009, PacifiCorp had
$4 milion in appropriated retained earnings - amortization reserve, federaL.
(16) Variable-Interest Entities
PacifiCorp holds an undivided interest in 50% of the 474-MW Hermiston generatig facility (refer to Note 4)1 dictates when the
generating facility operates, procures 100% of the natual gas for the generating facility and subsequently receives 100% of the
generated electrcity, 50% of which is acquired through a long-term power purchase agreement. As a result, PacifiCorp holds a
varable interest in the joint owner of the remaining 50% of the facility and is the prima beneficiar.. PacifiCorp has been unable to
obtain the information necessary to consolidate the entity because the entity has not agreed to supply the information due to the lack
of a contractual obligation to do so. PacifiCorp continues to request from the entity the information necessary to perform the
consolidation; however, no information has yet been provided by the entity. Cost of the electrcity purchased from the joint owner was
$37 milion and $36 milion durig the years ended December 31,2010 and 2009, respectively. The entity is operated by the equity
owners and PacifiCorp has no risk of loss in relation to the entity in the event of a disaster.
PacifiCorp holds a two-thirds interest in Bridger Coal, which supplies coal to the Jim Bridger generatig facility that is owned
proportionately by PacifiCorp and PacifiCorp's joint ventue parer in Bridger CoaL. PacifiCorp purchases two-thirds of the coal
produced by Bridger Coal, while the remaining coal is purchased by the joint ventue parer. The power to direct the activities that
most significantly impact Bridger Coal's economic performance are shared with the joint ventue parer. Refer to Note 17 for-
informtion regarding related par transactions with Bridger CoaL.
IFERC FORM NO.1 (ED. 12-88)Page 123.38
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
.NOTES TO FINANCIAL STATEMENTS (Continued)
(17) Related-Part Transactions
PacifiCorp has an intercompany administrtive services agreement with its indiect parent company, MEHC and its subsidiares.
Expenses charged to PacifiCorp under this agreement totaled $9 million durg each of the years ended December 31, 2010 and 2009.
MEHC also pays certain third-part expenses on behalf of PacifiCorp that are reimbursed by PacifiCorp. These reimbursements were
$2 millon and $1 milion durig the years ended December 31, 2010 and 2009, respectively. Payables associated with these
administrative and third-par expenses were $1 millon and $2 millon as of December 31, 2010 and 2009, respectively. PacifiCorp
also receives payments for servces performed by PacifiCorp for MERC and its affliates, as well as for reimbursement of certin
expenses. Services performed by PacifiCorp for MEHC and its affliates prily relate to admistrative and technology services
and direct-assigned employees. Durng the year ended December 31, 2010 and 2009, these services and expense reimburements
were $3milion and $1 million, respectively. Receivables associated with these activities were $1 millon and $- million as of
December 31, 2010 and 2009, respectively.
PacifiCorp also engages in varous trsactions with several subsidiares of MEHC in the ordinary course of business. Services
provided by these affiliates in the ordinar coure of business and charged to PacifiCorp relate to the transportation of natual gas and
relocation services. These expenses totaled $5 millon and $3 millon durng the years ended December 31, 2010 and 2009,
respectively. Payables associated with these expenses were $- million and $1 milion as of December 31, 2010 and 2009, respectively.
PacifiCorp has long-term transporttion contracts with BNSF Railway Company (tlBNSFtl), which became an indirect wholly owned
subsidiary of Berkshire Hathaway, PacifiCorp's ultimate parent company, in February 2010. Transportation costs under these
contracts were $30 milion and $29 million durng the years ended December 31,2010 and 2009, respectively. As of December 31,
2010 and 2009, PacifiCorp had $2 million and $1 millon of accounts payable to BNSF outstanding under these contracts, including
indirect payables related to a jointly owned facility.
PacifiCorp paricipated in a captive insurce program provided by MEHC Insurce Services Ltd. (tlMISLtl), a wholly owned
subsidiary of MEHe. MISL covered significant portions of the propert dage and liability insurance deductibles in many of
PacifiCorp's curent policies, as well as overhead distrbution and transmission line propert damage. PacifiCorp has no equity
interest in MISL and has no obligation to contrbute equity or loan fuds to MISL. Premium amounts were established in March2006
based on a combination of actuaral assessments and market rates to cover loss claims, admnistrative expenses and appropriate
reserves, but as a result of regulatory commitments were capped though December 31, 2010. Certain costs associated with the
program were prepaid and amortzed over the policy coverage period which expired in March 2011. Premium expenses were
$7 milion durg each of the years ended December 31,2010 and 2009. Prepayments to MISLwere $2 million as of December 31,
2010 and 2009. Receivables for claims were $12 milion and $10 millon as of December 31,2010 and 2009, respectively. Proceeds
from cla.ims were $14 milion and $17 million durg the years ended December 31, 2010 and 2009, respectively.
PacifiCorp is par to a tax-sharing agreement and is par of the Berkshir Hathaway United States federal income tax retu. As of
December 31,2010 and 2009, income taxes receivable from MERC were $345 million and $249 million, respectively.
PacifiCorp transacts with its equity investees, Bridger Coal, Trapper Mining Inc. and PERCo. Services provided by PacifiCorp and
charged to its equity investees relate priarly to management services, income taxes and labor. Receivables for these services were
$3 million and $4 million as of December 31, 2010 and 2009, respectively. Services provided by equity investees and charged to
PacifiCorp priarly relate to coal purchases. These payables were $17 milion and $10 milion as of December 31, 2010 and 2009,
respectively. Durng the year ended December 31, 2010 and 2009, coal purchases from PacifiCorp's equity investees totaled
$141 milion and $126 milion, respectively. .
IFERC FORM NO.1 (ED. 12-88)Page 123.39
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/18/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(18) Supplemental Cash Flows Information
The summary of supplemental cash flows information for the years ended December 31 is as follows (in millions):
2010 2009
248Income taxes received, net
disclosure of non-cash investing activities:
$Utility plant additions acquired under capital lease obligations
IFERC FORM NO.1 (ED. 12-88)Page 123.40
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/04
(2) EiA Resubmission 04/18/2011
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1. Report in columns (b);(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accunted for as "fair value hedges., report the accounts affected and the related amounts in a footnote.
4. Report data on a year-to-ate basis.
Line Item Unrealized Gains and Minimum Pension Foreign Currency Other
No.Losses on Available-Liabilty adjustment Hedges Adjustments
for"5ale Securiies (net amount)
(a)(b)(c)(d)(e)
1 Balance of Account 219 at Beginriing of
Preceding Year (130,769)(2,419,911 )
2 Preceding OtrlYr to Date Reclassifications
from Acct 219 to Net Income 191,182
3 Preceding OuarterlYear to Date Changes in
Fair Value (60,413)(3,399,666)
4 Total (lines 2 and 3)130,769 (3,399,666)
5 Balance of Account 219 at End of Preceding
OuarterlYear .
6 Balance of Account 219 at Beginning of
Current Year (5,819,577)
7 Current OtrlYr to Date Reclassifcations
from Acct 219 to Net Income
8 Current OuarterlYear to Date Changes in .
Fair Value (1,142,322)
9 Total (lines 7 and 8)(1,142,322)
10 Balance of Account 219 at End of Current
OuarterlYear -II ~
FERC FORM NO.1 (NEW 06-02)Page 122a
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Year/Period of Report
End of 2010/Q4
Line
No.
Other Cash Flow
Hedges
Interest Rate Swaps
Totals for each
category of items
recorded in
Accunt 219
(h)
( 2,550,680)
191,182
3,460,079)
3,268,897)
5,819,577)
5,819,577)
7,825,262
8,967,584)
1,142,322)
6,961,899)
Other Cash Flow
Hedges
(Specify)
(f)(g)
1
2
3
4
5
6
7
8
9
10
7,825,262
C 7,825,262)
Net InCome (Carried
Forward from
Page 117, Line 78)
Total
Comprehensive
Income
(i)ü)
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 I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 122(a)(b) Line No.: 5 Column: e
Umecognized amounts on retirement benefits of ($9,3 79,000) less ta of $3,559,423 netting to ($5,819,577).
I$chedule Page: 122(a)(b) Line No.: 10 Column: e
Umecognized amounts on retiement benefits of ($11 ,220,000) less ta of $4,258, 1 01 nettng to ($6,961,899).
IFERC FORM NO.1 (ED. 12-87)Page 450.1
IS .epo s:
(1) l!An Original
(2) A Resubmission
SUMMA YOF UTILITY PLANT AND ACCUM LATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (h) common function.
End of
(a)
Total Company for the
Current Yea~Quarter Ended
(b)
Electc
(c)
Line
No.
Classification
Utilty Plant
2 In Service
3 Plant in Service (Classified)
4 Propert Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7)
9 Leased to Others
10 Held for Future Use
11 Construction Work in Progress
12 Acquisition Adjustments
13 Total Utilty Plant (8 thru 12)
14 Accum Prov for Depr. Amort, & Depl
15 Net Utilty Plant (13 less 14)
16 Detail of Accum Prov for Depr, Amort & Depl
17 In Service:
18 Depreciation
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility Plant
22 Total In Service (18 thru 21)
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others (24 & 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31,32)
.p"":' 0j~""-" iff" ./ ~
~ _ 0~,d.X YfWiW_ wØW_$ //0..41.° Ø0 ø!j/: _ ~iHJ0 ,._ ~_:¡_iY "-¡,.. _
21,284,241,062
65,393,121
-4,484,801
495,830,779
21,284,241,062
65,393,121
-4,484,801
495,830,779
21,840,980,161 21,840,980,161
17,678,149
1,000,790,049
159,175,508
23,018,623,867
7,467,085,584
15,551,538,283
17,678,149
1,000,790,049
159,175,508
23,018,623,867
7,467,085,584
15,551,538,283
il_:_ "~:i.~/:_
1 01 ,845,266
7,467,085,584
.r" ~.. / vP£~' .,gß01~"h/."_J"_
1 01,845,266
7,467,085,584
FERC FORM NO.1 (ED. 12-89)Page 200
Name of Respondent
PacifCorp
Gas
Th.iS ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Specify) Other (Specify) Oter (Specify)
Year/Period of Report
End of 2010/Q4
Common
(d)(e)(f)(g)(h)
Line
No.". ", ii...' ............. l'ih v m ~ " ~..íir.)fk "......0/ "................ 1'.., y':. !i øvv .,v&i_.. 00 / i0!"~0% i;U Vl7 WƧ." ..; _;7./"._1.;32:;...& :% v "' '7;;~:#_.
.m.0~'=0_.1 .i~~.iI#¡!; ri_.¡gr;/0"~........-M".._.._..!f~."; .W0r.-_~.._Blr.Ý":i.~ ""' ";;ø%~i! ~.Æf.J;jL ""J$%i"~ ..0.Jr..... ."%/w'. tæ _~.ffl
""~~%l,_.ø!:/ "-"7---"~- ~~..
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) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
!Schedule Page: 200 Line No.: 18
Depreciation is comprised of:
Depreciation
Depletion
Total
Column: c
$6,855,190,564
38,474,141
$6,893,664,705
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent
PacifiCorp
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) En ines 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 Turbogenerator Units
22 (324) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production 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 Electnc Equipment
32 (335) Misc. Power PLant Equipment
33 (336) Roads, Railroads, and Bridges
34 (337) Asset Retirement Costs for Hydraulic Prouction
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
36 D. Other Production Plant
37 (340) Land and Land Rights
38 (341) Structures and Improvements
39 (342) Fuel Holders, Products, and Accessories
40 (343) Prime Movers
41 (344) Generators
42 (345) Accessory 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)
Year/Period of Report
End of 2010/Q4
..ii:i0.o/n;Cnißo/ncP0o/ør.........I.~, ~I!.......îli: 'Ý¿/'W i! '0~J1;: 0tmf ~" %!$E 0% ..0 ',,)J?i øaA "x ;:"
.....ftr;I.-.i1 '..~sl.. 0~ ~
162,527,923
589,907,847
752,435,770
95,879,653
838,579,575
3,124,068,006
832,870,176
366,892,467
29,208,805
37,319,815
5,324,818,497
77,267,612
23;939,123
101,206,735
20,488
4,433,606
576,748,680
80,225,196
18,979,727
863,529
5,965,060
687,236,286
wi.lØi ~. ~ff_~.'" '...
-."' $:;/: -;;p~~(~1
20,209,614
104,317 ,417
314,817,920
111,436,535
59,040,854
2,391,127
15,942,236
628,155,703
5,914,565
8,572,335
14,385,298
2,106,752
759,180
138,551
31,876,681"'I';¡~.if 7770 ;~.~~.
5,394,604
439,916
23,516,708
155,449,405
10,811,674
2,276,086,094
347,539,112
230,222,062
12,179,685
4,031,634
3,059,836,374
9,012,810,574
240,919,747
27,923
4,326,760
1,078,163
252,187,113
971,300,080
FERC FORM NO.1 (REV. 12-65)Page 204
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
ELECTRIC PLANT IN SERVICE (Accunt 101, 102, 103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observnce of the above instructions and the texts of Accounts 101 and 106 wil avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utilty plant accunts. Include also in column (f) the additions or reductions of primary accunt
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offet to the debits or credits distributed in column (f) to primary
account classifications.
8. For Accunt 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccunt classifcation of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the propert purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accunts, give also dateRetirements Adjustments Transfers Balance at LineEndlg)Year No.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
7,008,585
7,008,585
239,795,535
607,856,161
847,651,696
1,017,776
1,017,776..~...JJ..~~~.~~~~~~:tf7t.I~""~""
1,289 95,898,852
889,911 79,423,572 921,546,842
64,329,284 -115,588,486 3,520,898,916
17,358,033 1,248,076 896,985,415
1,493,361 31,588,682 415,967,515
238,492 3,400,178 33,234,020
-938,718 42,346,157
84,310,370 -938,718 72,022 5,926,877,717.-.tftf~~~I,,~f';(.~':".~..l..i..
~~.tf."l."~""'''~
592
661,187
799,257
775,985
470,930
27,742
42,813
26,123,587
113,026,083
326,583,937
112,432,922
60,200,807
2,360,733
16,323,315
797,518
~1,820,024
-334,380
871,703
-2,652
285,341
2,778,506 -202,494 657,051,384&Ý:fI..""."~.i-...~tfJ..tf_;""
84,472
28,911,312
155,973,793
10,811,674
2,513,737,706
346,954,523
234,749,420
12,181,682
5,109,797
3,308,429,907
9,892,359,008
2,854,966
692,131
15,301
732
-413,169
79,619
215,899
2,729
3,563,130
90,652,006 -938,718
-30,450
-160,922
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
ine
No.
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 TOTAL 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) Storage 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)Miscellaneous Regional Transmission and Market Operation Plant
83 (386) Asset 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) Offce Furniture and Equipment
89 (392) Transporttion 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)
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 2010/Q4
78,701,268
18,215,228
290,415,773
375;535,768
102,011,621
164,583,952
47,624
-54,629
63,635
3,342,913,921'&~%;~,/ %: /1'./'-1,029,520,240
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
62,391,252
1,937,045
5,328,574,836
1,229,245
42,850
48,583,269
39,382,964
18,432,598
10,912,103
19,423,783
42,087,257
22,803,407
17,562,522
108,262
1,852,948
IfC:W/%.~~I""Jk'..~?.222,421,208
..%*.;lfu..~..
4,173,919
10,030,590
1,690,843
372,170
997,536
898,197
8,328,313
39,209,034
276,095
65,976,697..
19,645.568,742
Page 206
(a)
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
11,535,068
2,415,883,239
FERC FORM NO.1 (REV. 12-05)
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
Retirements
This ~ort Is: Date of Report
(1 )~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106) (Continued)Adjustments Transfers Balance at
End 9fYear
\g)
Line
No.
44,43
111,471
33,474,957
460,185
2,706,624
4,842,433
1,799,642
18,478,503
-14,044,880
8,112,938
3,829,570
-9,855,548
181,517,465
122,948,592
1,549,843,309
863,436,957
686,565,486
912,469,174
3,259,452
7,475,095
11,598,703
41,640,153 4,339,114,2338,320,225::-=r~Ji'Ji"'~%0;~"Z" r"...~m ø.. !!.~..~" !""j,l~'.
1,273 -798,528 52,837,393
580,354 8,686,881 74,675,982
12,063,046 -8,013,059 817,421,421
1,393,065 .64,739
6,639,749 -512 942,088,822
3,134,824 648,849,674
1,137,011 241,775 302,216,890
1,648,360 -241,263 718,645,076
7,378,770 141,227 1,097,798,842
788,760 581,777,749
25,318,933 179,453,205
116,306 8,801,076
3,307,134 -141,227 60,795,839
1,937,045
63,507,585 -189,445 5,87,299,014'''~''~~'.~''i$$;ii~:';:_'W~\l~~-=.;;.
~_~;;~~~!~~Ji~"';~'~
16,200,395
1 ,399,136 1,238,043 235,540,153
13,176,849 -972,877 77,219,598
3,068,409 98,768,642
321,589 -184,387 13,766,183
1,890,225 -2,605 61,822,342
1,385,370 .7,331 36,594,299
7,227,118 132,526,576
27,006,003 1,456,743 259,841,810
197,284 11,230 6,906,051
55,671,983 1,538,816 939,186,049
ru .
82,952,167 -155,454
285,760,496
4,484,801
285,760,496 -1,094,172 989,727 21,775,587,040
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
FERC FORM NO.1 (REV. 12-05)207Page
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
.
I$chedule Page: 204 Line No.: 97 Column: b
Account Descnption Balance Beginnng of Addtions Retiements Adjustments Balance at End of
Yea Year
(a)(b)(c)(d)(e)(g)
39921 Lad Owned in Fee $2,634,916 $$$$2,634,916
39922 Lad Rights 52,550,647 52,550,647
39930 Strctures 40,641,166 40,641,166
39941 Surace - Plant Equipment 12,156,504 43,312 68,500 12,131,316
39944 Surace - Electrc Power Facilities 3,424,575 3,424,575
39945 Undergound - Coal Mine Equipment 69,683,627 4,141,344 1,372,883 72,452,088
39946 LongWall Shields 17,699,562 15,414,285 17,602,272 15,511,575
39947 LongWall Equipment 10,652,772 1,423,486 7,614,631 4,461,627
39948 Mainline Extension 17,975,045 1,064,141 398,884 18,640,302
39949 Section Extesion 3,896,914 306,616 4,203,530
39951 Vehicles 1,264,591 26,609 1,237,982
39952 Heavy Constrction Equipment 5,159,693 299,00 152,962 5,305,731
39960 Miscellaneous General Equipment 2,165,001 114,458 43,443 2,236,016
39961 Computer - Mainfre 568,271 568,271
39970 Mine Development and Road Extension 37,548,438 603,13 38,151,569
399915 Coal Mine Asset Retirement Obligations 426,236 (155,454)270,782
Total Plant Used in Mining Activities $ 278,447,958 $ 23,40,773 $27,280,184 $(155,454)$ 274,422,093
Column: c
Column: d
Column: e
Column: 9
IFERC FORM NO.1 (ED. 12-87)Page 450.1
This ~ort Is:
(1) ~An Original
A Resubmission
Year/Period of Report
End of 2010/Q4
Name of Respondent
PacifCorp
LineNo.
Group other items of propert held
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 Green Substation
9 Hoggard Substation
10
11 Bend Service Center
12 Legacy Substation
13
14 Miscellaneous, each under $250,000:
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
1977
2007
2007
2007
2008
2009
2009
2009
2010
2.010
953,014
746,268
6,763,094
2,160,207
1,173,276
284,996
254,397
396,020
3,507,£38
722,119-716,920
"~;jA?JEß) '~//~Æl 5R&h %i~"'~~."'§i:nn4~_
47 Total "Jf~";:~~"~17,678,149
Page 214FERC FORM NO.1 (ED. 12-96)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
!Schedule Page: 214 Line No.: 3 Column: c
The Nort Hom Mountain Coal Properties are needed to access futu coal portls and federal coal reserves when existing East
Mountain coal mies are mied out.
¡Schedule Page: 214 Line No.: 5 Column: c
Land purchased for wind fars with an estimated constrction date of 2020 before subject to the timing of completion of the Energy
Gateway Transmission Expansion Project.
¡Schedule Page: 214 Line No.: 6 Column: c
Land purchased for wind fars with an estimated constrction date of 2021. before subject to the tig of completion of the Energy
Gateway Transmission Expansion Project.
¡Schedule Page: 214 Line No.: 10 Column: a 1-
Land reviousl included in Ho ard Substation.
chedule Pa e: 214 Line No.: 14 Column: c
Varous dates and plans.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This 1!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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 progress -
No.Electric (Account 107)
(a)(b)
1 Intangible:
2 Harr Allen Sub Install Transformer 14,508,952
3 Energy Trading Systems 11,654,227
4 Mobile Radio Purch-lmplementVHF Spectrum 2,922,082
5 SAP license and maintenance enhancements 2,590,806
6
7 Production:
8 Naughton U2 Flue Gas Desulfurization System .97,852,693
9 Dave Johnston U4 S02 & PM Emission Control Upgrades 83,434,697
10 Naughton U1 Flue Gas Desulfurization System 71,803,962
11 Wyodak U1 S02 & PM Emission Control Upgrades 69,766,970
12 North Umpqua River System Relicensing Implementation 35,753,200
13 Hunter U2 Clean Air - PM 32,332,081
14 Huntington U1 S02 & PM Emission Control Upgrades 22,684,809
15 Lewis River System Relicensing Implementation 21,663,099
16 Hunter U1 802 & PM Emission Control Upgrades 20,535,338
17 Hunter U2 S02 & PM Emission Control Upgrades 19,658,370
18 Blundell Proofing Well Integration 15,662,505
19 Hunter U2 Turbine Upgrade HP/IP/LP 13,138,382
20 Ashton Dam Seepage Control 11,818,025
21 Wyodak U1 Air Cooled Condenser Replacement 9,861,092
22 Jim Bridger U3 S02 & PM Emission Control Upgrades 8,717,197
23 Hayden Coal Unloading Facilty 7,510,593
24 Jim Bridger U1 Turbine Upgrade HP/IP/LP 7,404,728
25 Hunter U2 Main Controls Replacement 4,055,129
26 Generation Compliance Initiative Hardware 4,051,513
27 Hunter U3 Turbine Upgrade HP/IP/LP 3,917,040
28 Lake Side 2 Development 3,797,498
29 Jim Bridger U3 Turbine Upgrade HP/IP/LP 3,475,741
30 Huntington U2 Turbine Upgrade HP/IP/LP 2,953,717
31 Wyodak U1 OH Clean Air - NOX 2,551,903
32 Hunter U2 Economizer Replacement 2,422,289
33 Wyodak U1 Replacement of Secondary Superheater 2,306,337
34 Rogue River System Relicensing Implementation 2,594,462
35 Slide Creek Overhaul 2,116,993
36 Hunter U2 Low Temp SH Replacement 1,853,869
37 Craig U1 HP-IP Turbine Rotor Replacement 1,688,900
38 Hunter U2 RH Pendant Replacement 1,627,669
39 Klamath River System Interim Implementation Measures 1,545,438
40 Soda Unit 1 Generator Rewind 1,526,445
41 Huntington U2 Boiler Finishing SH Pendants Replacement 1,467,568
42 Craig U2 HP-IP Turbine Rotor Upgrade 1,414,798
43 TOTAL 1,000,790,049
FERC FORM NO.1 (ED. 12-87)Page 216
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
CONSTRUC ION WORK IN PROGRESS - - ELECTRIC (Accunt 107)
1.Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1 ,000,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
1 Huntington U1 Steam Inerting for Coal Mils 1,404,294
2 Currant Creek Block 2 Development 1,379,807
3 Jim Bridger U3 Reheater Outlet Terminal Tubes 11 1,286,788
4 Jim Bridger U4 Turbine Upgrade HPIIPILP 1,135,970.
5 Goodnoe Wind Blade Replacements 1,000,671
6
7 Transmission:
8 Gateway West 500kV Line 45,692,963
9 Mona-Oquirrh 345kV/500kV Line 26,927,521
10 Red Butte Sub SVC and Propert Acquisition 21,446,742
11 Bridger Mona 500kV Line 17,019,304.
12 Sigurd-Red Butte-Crystal 345kV Line 16,355,518
13 Malin Sub Series Capacitor Replacement 16,178,910
14 Populus-Terminal: Double Circuit 345kV Line 10,806,981
15 Oquirrh New 345-138kV Substation .6,265,829
16 Dave Johnston to Casper 230kV No 1 &2 Line Rebuild 5,883,823
17 California-Oregon Intertie Transfer Capabilty Increase .5,366,035
18 Oquirrh-Terminal 345kV Line 4,535,245
19 Chappel Creek 230kV Cimarex Energy 3,664,891
20 Vickers Sub Add 46kV Circuit Breakers 3,145,454
21 Tom McCall Industrial Park 115kV Project 3,027,576
22 Wyoming Transmission Clearance Project 3,017,130
23 Southwest WY Silver Creek Build 138kV Line 2,977,830
24 Wallula-McNary 230kV Line 2,795,752
25 St George-Red Butte 138kV Line 2,637,961
26 TOT 4A-4B Transmission Path Transfer Capacity 2,596,618
27 Line 3 Convert to 115kv 2,510,101
28 Line 37 Convert to 115kV Build Nickel Mt Sub 2,046,439
29 Idaho Transmission Clearance Project .1,716,683
30 West Point-New 138 kV Line & 40 MVA Sub 1,650,483
31 Vantage-Pomona Heights 230kV Line 1,449,273
32 Eastside Transmission Line Ratings Wave Traps 1,394,346
33 Two Elks Intercon at Tri County Switchyard 1,347,235
34 Cameron-Milford 138kV Transmission 1,279,887
35 Dave Johnston U3 GSU Replacement 1,118,268
36 Utah Transmission Clearance Project 1,087,466
37 Hemingway-Captain Jack 500kV Line 1,071,035
38
39 Distribution:
40 Skypark Build New 138-12.5kV Substation 5,471,601
41 Copper Hils New 138-12.5kV Sub 2,937,847
42 Nibley 138-12.5kV Sub 2,622,983
43 TOTAL 1,000,790,049
FERC FORM NO.1 (ED. 12-87)Page 216.1
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2). FiA Resubmission ..04/18/2011
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Acèount 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 Reséarch, 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.
Une Description of Project Construction work in progress -
No.Electric (Accunt 107)
(a)(b)
1 Saratoga Sub Add 2nd Trnsf Rebid Tran Jumper 2,593,830
2 City Creek Center (SLC) New 40 MW Dev for PR~2,430,483
3 Bend Plant Sub Increase Capacity 2,102,256
4 Farmington Sub Add 2nd 138-12.5 kV Transfmr 1,043,448
5
6 Generai:
7 Mobile Radio Replacement Project 25,383,718
8 Deer Creek Mine-Reconstruct Longwall System 14,093,017
9 PCC/SCC Router Replacement TOM 1,823,963
10
11 Miscellaneous Projects each under $1,000,000 90,424,957
12
13
14
15
16
17
18
19
20
21
22
23
24 .
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43 TOTAL 1,000,790,049
FERC FORM NO.1 (ED. 12-87)Page 216.2
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
ACCUMULATED PROVI ION FOR DEPRECIATION OF ELEC RIC 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 1 08 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
ine
No.
em
(a)
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) Expo of Elec. PIt. Leas. to Others
6 Transportation Expenses-Clearing
7 Other Clearing Accunts
8 Other Accounts (Specify, details in footnote):
9
27,690,769
10 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
of lines 12 thru 14)
16 Other Debit or Cr. Items (Describe, details in
footnote):
528,915,025 528,915,025~~~.¡¡-:1M!' /;:/ IX,L-:':,:-; ':., ...:..;;'d..':;__¿1:JiI1g~.~Wø'Æit~¡¡;Sili.
278,227,865
43,273,030
10,644,919
310,855,976
278,227,865
43,273,030
10,644,919
310,855,976
11,708,125
17
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1 ,
10,15,16, and 18)
6,893,664,705 6,893,664,705
Section B. Balances at End of Year According to Functional Classification
20 Steam Production 2,549,642,134 2,549,642,134
21 Nuclear Production
22 Hydraulic Production-Conventional 262,715,132 262,715,132
23 Hydraulic Production-Pumped Storage
24 Other Production 388,889,683 388,889,683
25 Transmission 1,172,814,664 1,172,814,664
26 Distribution 2,072,617,011 2,072,617,011
27 Regional Transmission and Market Operation
28 General 446,986,081 446,986,081
29 TOTAL (Enter Total of lines 20 thru 28)6,893,664,705 6,893,664,705
FERC FORM NO.1 (REV. 12-05)Page 219
Name of Respondent This Report is:Dateof Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 219 Line No.: 4 Column: b
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as either a regulatory asset or liability.
¡Schedule Page: 219 Line No.: 8 Column: b
Depreciation of mining assets included in account 151 Fuel Stock - until consumed
Account 143 Joint Owner Receivable - depreciation expense biled to joint owners
ARO asset amortzation recorded as a regulatory asset or liability
Transporttion depreciation allocated to O&M based on usage activity
Account 503 Blundell depletion
Account 503 Blundell depreciation and amortization
Total other accounts
$9,747,627
168,562
2,424,556
14,065,119
185,368
1,099,537
27,690,769$
I$chedule Page: 219 Line No.: 16 Column: b
Other items including:
- Recover from third parties for asset relocations and damaged propert
- Insurance recoveries
- Adjustments of reserve related to electrc plant sold
- Reclassifications from electrc plant
$11,708,125
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of RespOndent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04118/2011
I NVESTM NTS 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 specifing 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
Account 418.1.~ oe,",'ooofi"~bnt Date Acquired D¡;te Of Amount Of Investment atNo. (a)(b)
MaMity Beginning of Year
(d)1~ %......"~,, %~" . _ _-2/1/1974
2 Partner Capital 161,668,072
3 SUBTOTAL 161,668,072
4
5 PACIFICORP ENVIRONMENTAL REMEDIATION COMPANY 8/19/1994
6 Capital Contributions 14,719,625
7 Undistributed Subsidiary Earnings 8,330,470
8 SUBTOTAL 23,050,095
9
4/15/1992
11 Members' Equity
12 SUBTOTAL
13""-.".
. w~.
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 Total Cost of Account 123.1 $207,210,5211 TOTAL 184,718,167
FERC FORM NO.1 (ED. 12-89)Page 224
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) (2An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
INVESTMENT IN SUBSIDIARY COMPANIES (Accunt 123.1 ) (Continued)
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accunts in a footnote, and state the name of pledgee
and purpose of the pledge,
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the sellng price thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.1
i:quity in ::uDsldiary Kevenues ror year Amount or Investment at ~ain or Loss from Investment LineEarnin~s of Year End tifYear DiSpir~rd of No.e)(f).g)
1
180,989,538 2
180,989,538 3
4
5
14,719,625 6
-2,097,757 6,232,713 7
-2,097,757 20,952,338 8
9
10
11,501,358 11
11,501,358 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
.27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
-2,097,757 213,443,234 42
FERC FORM NO.1 (ED. 12-89)Page 225
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
.FOOTNOTE DATA
I$chedule Page: 224 Line No.: 1 Column: a
Refer to Note 2 of Notes to Financial Statements in this Form NO.1 for discussion of the consolidation of Pacific Minerals, Inc.
("PMJ") begining Januar 1,2010.
I§chedule Page: 224 Line No.: 10 Column: a
In the rior ear, Ira er Minin Inc. was included in Account 123, Investment in Associated Com anies.
chedule Pa e: 224 Line No.: 14 Column: a
PacifiCorp consolidates certain wholly owned subsidiares and as a result those investments are not reflected in Account 123.1,
Investments in Subsidiar Companies. Refer to page 103, Corporations Controlled by Respondent in this Form NO.1 for more
informtion regarding the wholly owned subsidiares that PacifiCorp consolidates.
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
.
This ~ort Is:
(1) ~An Original
(2) DA Resubmission
MATERIALS AND SUPPLIES
Date of Report
(Mo, Da, Yr)
04/18/2011
.
1. For Account 154, report the amount of plant materials and op.erating supplies under the primary functional classifications as indicated in column (a);
estimates of àmounts by function are acceptable. In column (d), designate the department or departments which use the class of materiaL.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or Credits to stores expense
clearing, if applicable.
Line
No.
Account Balance
Beginning of Year
(a)
1 Fuel Stock (Account 151)
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Èxtracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)
8 Transmission Plant (Estimated)
9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote)
12 TOTAL Account 154 (Enter Total of lines 5 thru 11)
13 Merchandise (Accunt 155)
14 Other Materials and Supplies (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
(b)
170,930,143
69,236,794
87,614,292
838,582
16,134,398~~
178,147,022
.
TOTAL Materials and Supplies (Per Balance Sheet)349,077,165
Balance
End of Year
(c)
188,493,087 Electric
Department or
Departments which
Use Material
(d)
71,053,270 Electric
93,357,638
718,031
16,656,313
M .
Electric
Electric
Electric
Electric
FERC FORM NO.1 (REV. 12-05)Page 227
186,406,158
374,899,245
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 227
MiningM&S
General Plant M&S
Line No.: 11 Column: b
$ 4,170,119
152,837
$ 4,322,956
¡Schedule Page: 227
MiningM&S
General Plant M&S
Line No.: 11 Column: c
$ 4,477,840
143,066
$ 4,620,906
IFERC FORM NO.1 (ED. 12':87)Page 450.1
This Report Is: Date of Report
(1) !!An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2011
Allowances (Accunts 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 2011
No. (Account 158.1)
(a)
1 Balance-Beginning of Year
2
3
4
5
6
7
8 PùrchaseslTransfers:
9 Adjustment
10
11
12
13
14
15 Total
16
17
18
19
20
21 Cost of SaleslTransfers:
22 See footnote for details
23
24
25
26
27
28 Total
29 Balance-End of Year
30
31
32
33
34
35
Year/Period of Report
End of 2010/Q4
Name of Respondent
PacifiCorp
Acquired During Year:
Issued (Less Withheld Allow)
Returned by EPA ........¡g~w;E~:wø¡¡A~..r"i:ki¡f"~Wiq~.ib..W'....iiBm ~"7" .~_iÆ~ Bm"JiiifWl~;." A¡ŽiY;;iwLJi Ziilg¡.~~I:""f""f'~~"'."
2.00
Relinquished During Year:
Charges to Account 509
Other:
Sales:
Net Sales Proceeds(Assoc. Co.)
Net Sales Proceeds (Other)
Gains
Losses
Allowances Withheld (Acct 158.2)
36 Balance-Beginning of Year
37 Add: Withheld by EPA
38 Deduct: Returned by EPA
39 Cost of Sales
40 Balance-End of Year
41
42
43
44
45
46
~~~"'~~".F~""~
2,259.00 2,259.00
2,259.00
2,259.00
Sales:
Net Sales Proceeds (Assoc. Co.)
Net Sales Proceeds (Other)
Gains
Losses
FERC FORM NO.1 (ED. 12-95)Page 228a
Name of Respondent
PacifiCorp
Year/Period of Report
2010/04End of
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da. Yr)
(2) DA Resubmission 04/1812011
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 gainsllosses resulting from the EPA's sale or auction of the withheld allowances.
7. Report on Lines 8-14 the n¡:mes of vendors/transferors of allowances acquire and identify associated companies (See "associated
company" under "Definitions" in the Uniform System of Accounts).
8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies.
9. Report the net costs and benefis 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.
(i)
Future YearsNo. Amt.
(k
Line
No.
2.00
FERC FORM NO.1 (ED. 12-95)Page 229a
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 228 Line No.: 22 Column: b.
The names of purchasers/transferees ånd the number of allowances disposed of durg the year ended December 31, 2010 are as
follows:
NRG Power Marketing LLC
Constellation Energy Commodities Group, Inc.
Luminant Energy Company LLC
Sunbury Generation LP
Macquarie Bank Limited
Barclays Bank PLC
25,000
15,000
15,000
12,000
8,000
5,000
80,000
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 2010/Q4
(2) nA Resubmission 04/18/2011
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 Rec;nisedin 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 amortization (mo, yr to mo, yr)J
(a)(b)(c)(d)(e)(f)
21 Unrecovered Plant: Trojan Nuclear 1,809,172 407, 131 1,673,606 135,566
22 Plant located near Portland, OR
23 Date of Retirement: 12/31/1992
24 Date of Commission Authorization:
25 04/20/1993
26 Amortization Period: 01/1993
27 through 01/2011
28
29 Unrecovered Plant: Powerdale 3,479,961 3,479,961~
30 Hydro Electric Plant
31 Date of Retirement: 02/08/2007
32 Date of Commission Authorization:
33 05/14/2007 .
34 Amortization Period: OS/2007
35 through 12/201 0
36 .
37 .
38
39
40
41
42
43
44
45
46
47
48
49 TOTAL 5,289,133 5,153,567 135,566
FERC FORM NO.1 (ED. 12-88)Page 230b
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da,Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 230 Line No.: 29 Column: d
Account 407, Amortization of propert losses, unrecovered plant and regulatory study costs
Account 182.3, Other regulatory assets
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 04/18/2011
Transmission Service and Generation Interconnection Study Costs
1. Report the particulars (details) called for concerning the costs incirred and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. In column (a) provide the name ofthe study.
4. In column (b) report the cost incurred to perform the study at the end of period.
5. In column (c) report the account charged with the cost of the study.
6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
7. In column (e) report the account credited with the reimbursement received for perfrming the study.
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 Incurred During
Period
(b)
Accunt Charged
(c)
Aref 591168
Aref592473
Aref594665
Aref 599599
Aref610299
Aref618363
Aref645170
Aref654674
Aref581025
14,314 5616000
12,687 5616000
9,062 5616000
12,325 5616000
5,869 5616000
8,833 5616000
3,644 5616000
1,618 5616000
21,160 5616000
6,036) 5616000
203 1070000
203 1070000
2,561 1070000
2,529 1070000
4,856 1070000
3,171 1070000
2,477 1070000
8,402 1070000
3,575 1070000
Accruals - Customer Studies
Aref575662
Aref575869
Aref583608
Aref583614
Aref604216
Aref604662
Aref617716
Aref618940
Aref620282
Generation Studies
GIQ0093
GIQ0128
GIQ0169
GIQ0170
GIQ0187
GIQ0187, 188, 189
GIQ0188
GIQ0189
GIQ0193
GIQ0234
GIQ0243
GIQ0247
GIQ0248
GIQ0254
GIQ0255
GIQ0258
GIQ0260, 261, 262, 263
GIQ0268
GIQ0269
319 5617000
136 5617000
90 5617000
90 5617000
1,234 5617000
16,126 5617000
582 5617000
76 5617000
821 5617000
303 5617000
372 5617000
1,571 5617000
60 5617000
2,924 5617000
13,191 5617000
467 5617000
40,691 5617000
8,43 5617000
10,739 5617000
eim ursements
Received During
the Period
(d)
14,314
12,687
9,062
12,325
5,869
8,833
3,644
1,618
319
136
90
90
1,234
16,126
582
76
821
303
372
1,571
60
2,924
13,191
467
40,691
8,443
10,739
Year/Period of Report
End of 2010/04
Account Credited
With Reimbursement
(e)
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
4562000
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 04/18/2011
Transmission Service and Generation Interconnection Study Costs
Year/Period of Report
End of 2010/Q4
(continued)
me
No.Description
(a)
'1 Transmission Studies
2 Aref 621679
3 Aref 624709
4 Aref 626275
5 Aref 630525
6 Aref 635532
7 Aref 637972
8 Aref 637974
9 Aref 637977
10 Aref 637979
11 Aref 648008
12 Aref648013
13
14
15
16
17
18
19
20
21 Generation Studies
22 GIQ0274
23 GIQ0276
24 GIQ0277
25 GIQ0278
26 GIQ0279
27 GIQ0283
28 GIQ0287
29 GIQ0288
30 GIQ0289
31 GIQ0290
32 GIQ0291
33 GIQ0292
34 Gr00293
35 GIQ0294
36 GIQ0295
37 GIQ0296
38 GrQ0297
39 GIQ0298
40 GIQ0299
Costs Incurred During
Period
(b)
Account Charged
(c)
eim ursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)- - - ------- -- -
3,916 1070000
9,244 1070000
4,514 1070000
2,293 1070000
5,789 1070000
1,651 1070000
5,462 1070000
4,233 1070000
4,696 1070000
28,760 1070000
5,004 1070000
120 5617000
36,841 5617000
13,116 5617000
1,052 5617000
1,872 5617000
1,069 5617000
10,565 5617000
435 5617000
41,082 5617000
40,083 5617000
24,928 5617000
16,089 5617000
13,299 5617000
18,348 5617000
30,806 5617000
3,163 5617000
2,679 5617000
6,959 5617000
5,554 5617000
120 4562000
36,841 4562000
13;116 4562000
1,052 4562000
1,872 4562000
1,069 4562000
10,565 4562000
435 4562000
41,082 4562000
40,083 4562000
24,928 4562000
16,089 4562000
13,299 4562000
18,348 4562000
30,806 4562000
3,163 4562000
2,679 4562000
6,959 4562000
5,554 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 04/18/2011
Transmission Service and Generation Interconnection Study Costs
Year/Period of Report
End of 2010/Q4
(continued)
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 Generation Studies
22 GIQ0300
23 GIQ0302
24 GIQ0303
25 GIQ0304
26 GIQ0305
27 GIQ0306
28 GIQ0307
29 GIQ0308
30 GIQ0309
31 GIQ0310
32 GIQ0311
33 GIQ0312
34 GIQ0313
35 GIQ0314
36 GIQ0315
37 GIQ0316
38 GIQ0317
39 GIQ0318
40 GIQ0319
Costs Incurred During
Period
(b)
Accunt Charged
(c)
Account Credited
With Reimbursement
(e)
7,402 5617000
4,699 5617000
7,140 5617000
6,078 5617000
7,719 5617000
30,724 5617000
21,285 5617000
634 5617000
5,360 5617000
13,263 5617000
17,533 5617000
2,816 5617000
43,204 5617000
11,734 5617000
22,995 5617000
23,177 5617000
1,475 5617000
2,041 5617000
20,394 5617000
7,402 4562000
4,699 4562000
7,140 4562000
6,078 4562000
7,719 4562000
30,724 4562000
21,285 4562000
634 4562000
5,360 4562000
13,263 4562000
17,533 4562000
2,816 4562000
43,204 4562000
11,734 4562000
22,995 4562000
23,177 4562000
1,475 4562000
2,041 4562000
20,394 4562000
FERC FORM NO. 1/1.F/3.Q (NEW. 03-07)Page 231.2
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
- (2) A Resubmission 04/18/2011
Transmission Service and Generation Interconnection Study Costs
Year/Period of Report
End of 2010/Q4
(continued)
ine
No.
eim ursements
Received 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
GIQ0320 1,841 5617000 1,841 4562000
GIQ0321 4,206 5617000 4,206 4562000
GIQ0322 15,850 5617000 15,850 4562000
GIQ0323 53,682 5617000 53,682 4562000
GIQ0324 41,214 5617000 41,214 4562000
GIQ0325 1,977 5617000 1,977 4562000
GIQ0326 34,067 5617000 34,067 4562000
GIQ0327 3,078 5617000 3,078 4562000
GIQ0328 1,569 5617000 1,569 4562000
GIQ0329 2,910 5617000 2,910 4562000
GIQ0330 5,612 5617000 5,612 4562000
GIQ0331 1,143 5617000 1,143 4562000
GIQ0332 9,958 5617000 9,958 4562000
GIQ0333 6,844 5617000 6,84 4562000
GIQ0334 2,652 5617000 2,652 4562000
GIQ0335 8,666 5617000 8,666 4562000
GIQ0337 5,829 5617000 5,829 4562000
GIQ0338 622 5617000 622 4562000
GIQ0339 3,552 5617000 3,552 4562000
FERC FORM NO. 1/1-F/3-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 04/18/2011
Transmission Service and Generation Interconnection Study Costs
Year/Period of Report
End of 2010/Q4
(continued)
me
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
GIQ0340 613 5617000 613 4562000
GIQ0341 18,959 5617000 18,959 4562000
GIQ0342 5,547 5617000 5,547 4562000
GIQ0343 9,380 5617000 9,380 4562000
GIQ0344 1,858 5617000 1,858 4562000
GIQ0345 2,506 5617000 2,506 4562000
GIQ0346 6,682 5617000 6,682 4562000
GIQ0347 4,852 5617000 4,852 4562000
GIQ0348 2,709 5617000 2,709 4562000
GIQ0349 10,870 5617000 10,870 4562000
GIQ0350 10,857 5617000 10,857 4562000
GIQ0351 12,468 5617000 12,468 4562000
GIQ0352 2,266 5617000 2,266 4562000
GIQ0353 182 5617000 182 4562000
GIQ0354 2,468 5617000 2,468 4562000
GIQ0355 846 5617000 846 4562000
GIQ0356 1,126 5617000 1,126 4562000
GIQ0357 1,100 5617000 1,100 4562000
GIQ0358 657 5617000 657 4562000
FERC FORM NO.1/1-F/3-Q (NEW. 03-07)Page 231.4
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
Transmission Service and Generation Interconnection Study Costs (continued)
Year/Period of Report
End of 2010/Q4
ine
No.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
Account Charged
(c)---- - ----- -- - - ---
Generation Studies
GIQ0359
GIQ0360
GIQ0361
GIQ0362
GIQ0363
GIQ0364
GIQ0365
2,104 5617000
2,831 5617000
549 5617000
489 5617000
65 5617000
124 5617000
46 5617000
15,847) 5617000
9,875 5617000
12,985 5617000
8,497 5617000
18,577 1070000
41,071 1070000
Accruals - Customer Studies
GIQ0284
GIQ0270
GIQ0271
GIQ0267
GIQ0301
eim ursementsReceived During
the Period
(d)
Account Credited
With Reimbursement
(e)
2,104
2,831
549
489
65
124
46
4562000
4562000
4562000
4562000
4562000
4562000
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) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
o HER 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.
Year/Period of Report
End of 2010/Q4
Line Description and Purpose of
No. Other Regulatory Assets Debit
(a)
DSM Regulatory Asset - CA
DSM Regulatory Asset - ID
DSM Regulatory Asset. UT
DSM Regulatory Asset .WA
DSM Regulatory Asset - WY
DSM Regulatory Assets- Accruals
Alternative Rate For Energy (CARE) - CA
Transition Plan - OR
;1006 Transition Plan - OR (3)
2006 Transition Plan - WA (3)
2006 Transition Plan -ID (3)
2006 Transition Plan - CA
Deferral of Interest on Uncertain Tax Positions.UT
Deferral of Interest on Uncertin Tax Positions-WY
Tax Revenue Requirement Adjustment. WY
Sch 781 Direct Access Shopping Incentive
44 TOTAL
Baanc at
Beginning of
Currnt
QuarterNear
(b)
( 2,09,141)
4,072,036
28,520,678
1,727,139
2,468,965)
4,977,717
1,396,56
2,269,573
318,524
610.195
1,062,22
422,169,290
68,360)
112,218
175.363
2.604,371)
9,970,836
1,539,406
4,364.4011
2,615,813
7,516,382
591,83)
3,441,141
7,11,962
578,447
367,301,591
64.991,572
575.745,416
1.034.108
92.022
54.324
12,573)
1.042.120
61.378
1,550,913,652
(c)
865,247 908
7,547,413 908
47,799,611 908
7,723,507 908, 431
2,809,153 908,431
40,419
71,69 142
19,792 930.2
4,683,761 920
920
920
Balance at end of
Current QuarterN ear
(e)(f)
1.959.697 -3,193,591
6,280.307 5,339,142
74.035,776 2,284,513
8.855,255 595,391
4.341.024 -4,000,836
5,386,136
1.214.280 253,983
2,289,365
1.714,502 2,969,259
318,524
610,195
222,772
1,062,222
448,480,778
1,44,909
372,132
99,955
42,313
112,218
176,578
3,526,084
1,909,644
10.030.176
3.073.730 1,596,942
14,492,513
1.977.054 2,670,016
2.361.551 487,229
11,434,111
1,035,589
1,501,251 8,296,641
163.356 -650,11
9,370,862
1,122,425 6,179,329
52,188 526,259
487,295,264
13,813,374 68,251,011
50,014,094 596,639,721
321,528 738,048
92,022
27.162 27,162
3.928 -16,501
912.358 539,513
17,581 43,797
212,116,361 1,737,446,767
26,311,488
1,444,909
372,132
99,955
110,673 407.3,431
930.2
1,215 254
3,526,064
4,514,015
59,340 555
3,131,266 555
14,492,513
282,664 555
232.967 555
11,434.111
1,035.589
2,281,510 925
105.082 925
5,929.721
183.792 557
456
119.993,673
17,072,813 230
70.908.399_ _
25,68 904
904
904
557
40,751 557
928
398,649,476
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
.OTHER REGULATORY ASSETS (Account 182.3)
1. Report bêlow 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 Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of vvniien OTT uuring vvniien OTT uuring Current QuarterlY ear
Currnt the QuarterlYear the Period
QuarterlY ear Accunt Charged Amount
(a)(b)(c)(d)(e)(f)
1 Deferred Intervenor Funding Grants - OR (175,032)213,506 431 1,392 37,082
2 BPA Idaho Balancing Accunt 2,081,580 603,662 2,685,242
3 Renewable Adjustment Clause (1) - OR 5,196,941 1,918,389~~,6,485,375 629,955
4 Goodnoe Hils Settlement - WY (24)510,000 930.2 21,250 488,750
5 Lake Side Settement - WY (38)1,032,722 930.2 27,627 1,005,095
6 SB 408 Regulatory Asset - OR (1)9,770,616 2,160,057~10,835,128 1,095,545
7 SB 408 Regulatory Asset - MCBIT (22,03)4~"_.582,54 -189,015
8 Chehalis Generating Facilty Deferral- WA (6)18,000,000 3,000,000 15,000,000
9 Powerdale Decommissioning -ID (10)313,766 407.3 9,000 304,766
10 Powerdale Decommissioning - OR (1.5)917,937 407.3 424,921 493,016
11 Powerdale Decommissioning - WA 851,788 ~851,788
12 Powerdale Decommissioning - WY (1)188,11 407.3 153,725 34,392
13 Deferred Advertising Costs . WY 52,198 52,198
14 Major Plant Additions - UT 15,724,521 15,724,521
15 Solar Feed-In Tariff Deferral - OR 226,622 226,622
16 Tax Adj on Pöstretírement Benefits - CA 383,431 383,431
17 Tax Adj on Postretirement Benefits - ID 819,988 819,988
18 Tax Adj on Postretirement Benefits - OR 4,471,64 .4,471,643
19 Tax Adj on Postretirement Benefits - UT 6,284,000 410.1,283 392,750 5,891,250
20 Tax Adj on Postretirement Benefits - WA 1,126,592 1,126,592
21 Tax Adj on Postretirement Benefits - WY 2,121,315 2,121,315
22 Storm Damage Deferral - CA 1,230,000 1,230,000
23 Deferred Overburden Cost - ID 684,923 501 435,826 249,097
24 Deferred Overburden Cost - WY 1,830,954 501 1,165,063 665,891
25 Regulatory Assets - Reclassifications 7,485,673 254 85,73_
v/. , ~ ~ ,"" ._,
26
27 .
28
29
30 .
31
32 .
33
34
35
36
37
38
.
39
40
41
42 ..
43
44 TOTAL 1,550,913,652 398,649,476 212,116,361 1,737,446,767
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 04/18/2011 2010/Q4
FOOTNOTE DATA
!Schedule Page: 232 Line No.: 14 Column: a
Weighted average remaining life is 33 years. Represents deferred income ta assets and liabilities that are associated with income tax
benefits related to certin propert-related basis differences and other varous differences that PacifiCorp is required to' pass on to its
customers in most state 'ursdictions.
chedule Pa e: 232 Line No.: 20 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms and amortzed over a 12-month period.
¡Schedule Page: 232 Line No.: 21 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms and amortzed over a 12-month period.
ISchedule Page: 232 Line No.: 22 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms and amortzed over a 12-month period.
¡Schedule Page: 232 Line No.: 23 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.
!Schedule Page: 232 Line No.: 24 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.
¡Schedule Page: 232 /.ne No.: 25 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.
¡Schedule Page: 232 Line No.: 27 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms and amortzed over a 12-month period.
¡Schedule Page: 232 Line No.: 28 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.
!Schedule Page: 232 Line No.: 29 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms and amortized over a 12-month period.
¡Schedule Page: 232 Line No.: 35 Column: a
W eighted average remaining life is 4 years.
I$chedule Page: 232 . Line No.: 37 Column: a
Weighted average remaining life is 9 years. Substantially represents amounts not yet recognized as a component of net periodic
benefit cost that are expected to be included in rates when recognized.
¡Schedule Page: 232 Line No.: 37 Column: d
Pensions and benefits are associated with labor and generally charged to operations and maintenance expense, constrction work in
ro ess and account 228.3, accumulated rovision for ensions and benefits.
chedule Pa e: 232.1 Line No.: 3 Column: d
Account 440, Residential Sales
Account 442, Commercial and industral sales
Account 444, Public street and highway lighting
¡Schedule Page: 232.1 Line No.: 6 Column: d
Account 440, Residential sales
Account 442, Commercial and industral sales
Account 444, Public street and hi hwa Ii htin
chedule Pa e: 232.1 Line No.: 7 Column: d
Account 440, Residential sales
Account 442, Commercial and industral sales
Account 444, Public street and highway lighting
Account 426.5, Other deductions
¡Schedule Page: 232.1 Line No.: 8 Column: d
Account 440, Residential sales
Account 442, Commercial and industral sales
Account 444, Public street and hi hwa Ii htin
chedule Pa e: 232.1 Line No.: 25 Column: f
The following schedule sumarzes regulatory assets reclassifications:
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 04/18/2011 2010/Q4
FOOTNOTE DATA
December 31, 2010
Reclassìfied from Regulatory Assets to Regulatory Lìabìlìtìes:
DSM Regulatory Asset ~ CA
DSM Regulatory Asset - WY
Deferred Independent Evalulltor Fee - Dr
SB 408 Regulatory Asset - MCBIT
$3,193,591
4,000,836
16,501
189,015
7,399,943$
IFERC FORM NO.1 (ED. 12-87)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 2010/Q4
(2) DA Resubmission 04/18/2011
MISCELLANEOUS DEFFERED DEBITS (Accunt 186)
1.Report below the particulars (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 Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year Ëli1~Amount End of Year
(a)(b)(c)(d (e)(f)
1 Joseph Settlement (20)1,110,495 557 137,381 973,114
2
3 Lacomb Irrigation (24)552,450 557 45,720 .506,730
4
5 Bogus Creek (42)1,241,840 557 41,280 1,200,560
6 .
7 Mead Phoenix Availabilty
8 & Trans Charge (50)14,134,520 565 377,760 13,756,760
9
10 TGS Buyout (23)156,025 557 15,474 140,551
11
12 Hermiston Swap (40)4,564,17'8 557 171,694 4,392,484
13
14 Deferred Longwall Costs 994,128 2,211,852 151 2,100,584 1,105,396
15
16 Point to Point Transmission 2,573,900 2,496,680 142,557 593,680 4,476,900
17
18 Deferred Coal Costs - Wyodak
19 Settlement (22)4,357,363 151 335,181 4,022,182
20
21 Deferred Coal Costs - Arch
22 Settlement (3)1,713,105 151 1,650,075 63,030
23 .
24 Deferred Coal Costs - Naughton
25 Settement (7)8,945,000 151 688,077 .8,256,923
26
27 Deferred Colstrip Plant Costs 1,085,161 416,000 232 1,161 1,500,000
28 .
29 Jim Boyd Hydro Buyout (11)338,345 557 82,860 255,485
30
31 Credit Agreement Costs (5)1,507,772 427,431 456,629 1,051,143
32
33 PCRB LOC/SBBPA Costs (5)473,238 152,493 427 212,602 413,129
34
. 35 PCRB Mode Conversion Costs (10)261,965 270,482 427 118,961 413,486
36
37 '94 Series Restruct. Costs (16)1,105,412 427 116,981 988,431
38
39 Emission Reduction Credits 2,956,980 2,956,980
40
41 LGIA L T Transmission Prepaid 3,228,303 1,218,64 ,.1,360,230 3,086,717
42
43 Lease Incentives (11)1,270,348 454 155,119 1,115,229
44
45 L T Lease Commissions
46 Prepaids (10)739,981 931 90,322 649,659
47 Misc. Work in Progress
48 uererrea Keguiatory i.omm.
Expenses (See pages 350 - 351)
49 TOTAL 67,302,539 86,483,361
FERC FORM NO.1 (ED. 12-94)Page 233
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report ...
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/18/2011
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% 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 Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~çcuni.Amount End of Year Char~ed
(a)(b)(c)(d (e)(f)
1 BPA L T Transmission Prepaid 9,593,309 332,014 232 791,362 9,133,961
2
3 Lake Side Main!. Prepayment 9,477,588 5,243,161 14,720,749
4
5 Chehalis Main!. Prepayment 2,587,071 3,190,535 5,777,606
6
7 Currant Creek Main!. Prepayment 1,167,388 5,645,065 107 1,346,843 5,465,610
8 .
9 Other Deferred Debits with .
10 balances less than $100,000 111,674 various 51,128 60,546
11
12
13
14 .
15
16
17
18
19
20
21
22
23
24
25
26 .
27
28
29
30
31
32
33
34
35
36
37
38
39 .
40
41
42
43
44
45
46
47 Misc. Work in Progress
48 I Deferred Regulatory I,omm.
Expenses (See pages 350 - 351)
49 TOTAL 67,302,539 86,483,361
FERC FORM NO.1 (ED. 12-94)Page 233.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 233 Line No.: 41 Column: d
Account 232 - Accounts payable
Account 419 - Interest and dividend income
Account 549 - Miscellaneous other power generation expenses
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 2010/Q4.
(2) DA Resubmission 04/18/2011
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 uescription and Location ~No.of Year of Year
(a)(b) (c)
1 Electric
2 Employee Benefits 243,734,412 187,114,591
3 Derivative Contracts 139,689,181 184,509,824
4 Regulatory Liabilties 40,091,582 25,903,274
5
6
7 Other 164,002,583 191,062,227
8 TOTAL Electric (Enter Total of lines 2 thru 7)587,517,758 588,589,916
9 Gas
10
11
12 .
13
14
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15
17 Other (Specify)
18 TOTAL (Acct 190) (Total of lines 8, 16 and 17)587,517,758 588,589,916
Notes
FERC FORM NO.1 (ED. 12-88)Page 234
~
Name of Respondent This (!rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011 .
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 incolumn (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (Leo, 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. Entnes in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line Class and Series of Stock and Number of shares Par or Stated Call Price at
No.Name of Stock Series Autorized by Charter Value per share End of Year
(a)(b)(c)(d)
1 Common Stock (Account 201)750,000,000 --Wi
2 MidAmerican Energy Holdings Company
3 indirectly owns all of the shares of
4 PacifiCorp's outstanding common stock.
5 Therefore, there is no public market for
6 PacifiCorp's common stock.
7
8 TotAL COMMON STOCK 750,000,000
9
10
11 Preferred Stock (Account 204):
12 5% Cumulative Preferred 126,533 100.00 110.00
13
14
15 Serial Preferred, Cumulative:3,500,000
16 4.52% Series 100.00 103.50
17 7.00% Series 100.00 "-
18 6.00% Series 100.00 ---'
19 5.00% Series 100.00 100.00
20 5.40% Series 100.00 101.00
21 4.72% Series 100.00 103.50
22 4.56% Series 100.00 102.34
23 No Par Serial Preferred 16,000,000
24
25 TOTAL PREFERRED STOCK 19,626,533
26
27
28 .
29
30
31
32
33
34 %'wø /0 0 ¡a"~ ii..~, ';0 0 p
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED. 12-91)Page 250
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
CAPITAL STOCKS (Account 201 and 204) (Continued)
3. Give particulars (details) conceming 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 (Accunt 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
::hares Amount ::/1ares G9St ::hares Amount
(e)(f)(g)~h)(i)0)
357,060,915 3,417,945,896 1
2
3
4
5
6
7
357,060,915 3,417,945,896 8
9
10
11
126,243 12,624,300 12
13
14
15
2,065 206,500 16
..18,046 1,804,600 17
5,930 593,000 18
41,908 4,190,800 .19
65,959 6,595,900 20..""M!..~21.
..%22y
23
.24
407,331 40,733,100 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) 2Ç An Original .(Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I§chedule Page: 250 Line No.: 1 Column: d
This class of stock is not redeemable.
I$chedule Page: 250 Line No.: 17 Column: d
This series of preferred stock is not redeemable.
Itchedule Page: 250 Line No.: 18 Column: d
This series of preferred stock is not redeemable.
Itchedule Page: 250 Line No.: 21 Column: e
Refer to page 108. Importnt Changes Durg the QuarterNear, Item 6. Financing Activities in this Form NO.1 for a discussion of
PacifiCo's re urchase of certin shares of its referred stock.
chedule Pa e: 250 Line No.: 21 Column: f
See footnote for colum (e) line 19.
Itchedule Page: 250 Line No.: 22 Column: e
See footnote for colum e line 19.
chedule Pa e: 250 Line No.: 22 Column: f
See footnote for colum (e) line 19.
Itchedule Page: 250 Line No.: 34 Column: a I
Authorizations for the issuance of common stock by PacifiCorp to its imediate corporate parent, PPW Holdings LLC are as follows:
Oregon Public Utility Commission, Docket No. UF-4228, Order No. 06-417, dated July 17,2006.
Washington Utilities and Transportation Commission, Docket No. UE-060974, Order No.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, 2010, 30,000,000 shares authorized; 30,000,000 available.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondeht This Reporlls:Date of Repor Year/Period of Report
PacifiCorp (1) !!An Original (Mo,Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/18/2011
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
Report below the balance at the end of the yeàr and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for reconcilation with balance sheet, Page 112. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such
change.
(a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end of
year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Accunt 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.
,~(e ii:r A'lgtnto.
1 Account 211 Miscellaneous Paid-in Capital
2 Additional Paid-in Capital
3 Share based payments
4 Tax benefit from stock option exercises
5 Benefit plan separation *
6 Capital contributions .%~
7 Gain on sale of Scottish Power stock m
8 Qualified production activity tax deduction ,.*
9 Contribution of Intermountain Geothermal .
10 Gain on repurchase of preferred stock %
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 1,102,229,981
FERC FORM NO.1 (ED. 12-87)Page 253
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 253 Line No.: 3 Column: b
Represents the fair value of stock options granted by Scottsh Power plc for which certin pedormance measures were met in March
2005. These options became fully vested in May 2005.
¡Schedule Page: 253 Line No.: 4 Column: b
Represents the income tax deduction attbutable to the exercise of stock options granted by Scottsh Pow.er pIc.
I$chedule Page: 253 Line No;: 5 Column: b
Represents the effect of transferrng benefit plans to PPM Energy, Inc. as a result ofthe 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 MidAmerican Energy Holdings
Company ("MEHC"), of which $100,000,000 were made durng the year ended December 31, 2010.
¡Schedule Page: 253 Line No.: 7 Column: b
Represents a realized gain on stock related to separation of PPM Energy, Inc. paricipants from the deferred compensation plan.
¡Schedule Page: 253 Line No.: 8 Column: b
Represents amounts associated with IRC Section 199 qualified production activities.
¡Schedule Page: 253 Line No.: 9 Column: b
Represents contrbution ofIntermountain Geothermal Company to PacifiCorp from MEHC in March 2006, subsequent to the sale of
PacifiCorp to MEHC. Intermountain Geothermal Company was merged with and into its direct parent, PacifiCorp, on August 31,
2007, with PacifiCorp surviving.
¡Schedule Page: 253 Line No.: 10 Column: b
Refer to page 108, Importnt Changes Dug the QuaerNear, Item 6. Financing Activities in this Form NO.1 for a discussion of
PacifiCorp's repurchase of certain shares of its preferred stock.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:Date of Report YearlPeriod of Report
PacifiCorp (1 )I2An Original (Mo, Da, Yr)End of 2010/04
(2)r=A Resubmission 04/18/2011
CAPITAL STOCK EXPENSE (Account 214)
1.Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line Class and Senes of StOCK Balance at End Of Year
No.. (a)(b)
1 Common Stock 41,101,062
2
3 Preferred Stock:
4 5.00%98,049
5 4.52% Serial 9,676
6 4.72% Serial 28,596
7 4.56% Serial 47,177
8
9
10
11 Refer to page 108, Important Changes During the OuarterlYear, Item 6. Financing Activities
12 and to page 123, Notes to Financial Statements, Note 14. Preferred Stock in this Form NO.1
13 for a discussion of PacifiCorp's repurchase of certain shares of its preferred stock.
14
15 .
16
17
18
19
20
21
22 TOTAL 41,284,560
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 2010/Q4
(2) FiA Resubmission 04/18/2011
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 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 originaiiy 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 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 200,000,000 1,422,659
11 232,000 D
12 4.950% Series due August 15, 2014 200,000,000 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
20 5.500% Series due January 15, 2019 350,000,000 2,515,793
21 2,292,500 D
22 7.700% Series due November 15, 2031 300,000,000 2,874,150
23 864,000 D
24 5.900% Series due August 15, 2034 200,000,000 1,892,365
25 722,000 D
26 5.25% Series due June 15, 2035 300,000,000 2,912,055
27 1,080,000 D
28 6.10% Series due August 1, 2036 350,000,000 2,908,542
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 6,507,262,000 74,175,437
FERC FORM NO.1 (ED. 12-96)Page 256
Name of Respondent
PacifiCorp
YearlPeriod of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
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 yeàr, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and àre nominally outstaning 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 Debtto 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~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?~fent)
(i)
1
2
3
04/15/1992 10/01/2010 04/15/1992 10/01/2010 294,903 4
04/15/1992 10/01/2011 04/15/1992 10/01/2011 412,000 55,667 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 3,590,000 406,050 8
04/15/1992 10/01/2013 04/15/1992 10/01/2013 4,247,000 452,320 9
09/15/2003 09/15/2013 11/15/2001 09/15/2013 200,000,000 10,900,000 10.
11
08/24/2004 08/15/2014 0812412004 08/15/2014 200,000,000 9,900,000 12
13
04/15/1992 10/01/2014 04/15/1992 10/01/2014 9,301,000 935,367 14
04/15/1992 10/01/2015 04/15/1992 10/01/2015 17,918,000 1,660,480 15
04/15/1992 10/01/2016 04/15/1992 10/01/2016 8,318,000 784,835 16
04/15/1992 10/01/2017 04/15/1992 10/01/2017 9,585,000 873,913 17
071172008 07/15/2018 07/17/2008 07/15/2018 500,000,000 28,250,000 18
19
01/08/2009 01/15/2019 01/08/2009 01/15/2019 350,000,000 19,250,000 20
21
11/15/2001 11/15/2031 11/15/2001 11/15/2031 300,000,000 23,100,000 22
23
08/24/2004 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 06/15/2035 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
_l'Ia__0~6,357,741,000 363,203,396 33
FERC FORM NO.1 (ED. 12-96)Page 257
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/18/2011
LONG-TERM DEBT (Account 221,22,223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with 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 öf 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 6.25% Series due October 15, 2037 600,000,000 5,127,281
2 750,0000
3 6.35% Series due July 15, 2038 300,000,000 2,290,333
4 1,671,000. D
5 6.00% Series due January 15, 2039 650,000,000 6,134,687
6 6,175,000 D
7 9.15% Series C Medium-Term Notes due Aug. 9, 2011 8,000,000 75,327
8 8.95% Series C Medium-Term Notes due Sept. 1,2011 25,000,000 175,398
9 8.95% Series C Medium-Term Notes due Sept. 1, 2011 20,000,000 132,118
10 8.92% Series C Medium-Term Notes due Sept. 1,2011 20,000,000 188,318
11 8.29% Series C Medium-Term Notes due Dec. 30, 2011 3,000,000 23,040
12 8.26% Series C Medium-Term Notes due Jan. 10,2012 1,000,000 7,649
13 8.28% Series C Medium-Term Notes due Jan. 10,2012 2,000,000 13,297
14 8.25% Series C Medium-Term Notes due Feb. 1,2012 3,000,000 22,946
15 8.13% Series E Medium-Term Notes due Jan. 22, 2013 10,000,000 75,827
16 8.53% Series C Medium-Term Notes due Dec. 16,2021 15,000,000 115,202
17 8.375% Series C Medium-Term Notes due Dec. 31, 2021 5,000,000 38,400
18 8.26% Series C Medium-Term Notes due Jan. 7, 2022 5,000,000 33,243
19 8.27% Series C Medium-Term Notes due Jan. 10,2022 4,000,000 30,594
20 8.05% Series E Medium-Term Notes due Sept. 1,2022 15,000,000 131,471
21 8.07% Series E Medium-Term Notes due Sept. 9, 2022 8,000,000 70,118
22 8.12% Series E Medium-Term Notes due Sept. 9, 2022 50,000,000 438,238
23 8.11 % Series E Medium-Term Notes due Sept. 9, 2022 12,000,000 105,177
24 8.05% Series E Medium-Term Notes due Sept. 14, 2022 10,000,000 87,648
25 8.08% Series E Medium-Term Notes due Oct. 14, 2022 26,000,000 208,198
26 8.08% Series E Medium-Term Notes due Oct. 14, 2022 25,000,000 200,190
27 8.23% Series E Medium-Term Notes due Jan. 20, 2023 5,000,000 37,914
28 8.23% Series E Medium-Term Notes due Jan. 20, 2023 4,000,000 30,331
29 -81,560 P
30 7.26% Series F Medium-Term Notes due July 21, 2023 27,000,000 246,981
31 7.26% Series F Medium-Term Notes due July 21, 2023 11,000,000 100,622
32 7.23% Series F Medium-Term Notes due Aug. 16,2023 15,000,000 137,211
.
33 TOTAL 6,507,262,000 74,175,437
FERC FORM NO.1 (ED. 12-96)Page 256.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This Report Is: Date of Report
(1) I2An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities Which have been nominally issued and are nominally outstanding at end of year,
describe such securities in a footnote.
15. If interest expense was incUrred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in'a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long~Term Debt and Account:430, Interest on Debtto 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)
resPYh'dent)
(I)
10/03/2007 10/1512037 10/03/2007 10/15/2037 600,000,000 37,500,00q 1
2
07/172008 07/15/2038 07/17/2008 07/15/2038 300,000,000 19,050,000 3
4
01/08/2009 01/15/2039 01/08/2009 01/15/2039 650,000,000 39,000,000 5
6
08/09/1991 08/09/2011 08/09/1991 08/09/2011 8,000,000 732,000 7
08/16/1991 09/01/2011 08/16/1991 09/01/2011 25,000,000 2,237,500 8
08/16/1991 09/01/2011 08/16/1991 09/01/2011 20;000,000 1,790,000 9
08/16/1991 09/01/2011 08/16/1991 09/01/2011 20,000,000 1,784,000 10
12/31/1991 12/30/2011 12/31/1991 12/30/2011 3,000,000 248,700 11
01/09/1992 01/10/2012 01/09/1992 01/10/2012 1,000,000 82,600 12
01/10/1992 01/10/2012 01/10/1992 01/10/2012 2,000,000 165,600 13
01/15/1992 02/01/2012 01/15/1992 02/01/2012 3,000,000 247,500 14
01/20/1993 01/22/2013 01/20/1993 01/22/2013 10,000,000 813,000 15
12/16/1991 12/16/2021 12/16/1991 12/16/2021 15,000,000 1,279,500 16
12/31/1991 12/31/2021 12/31/1991 12/31/2021 5,000,000 418,750 17
01/08/1992 01/07/2022 01/08/1992 01/07/2022 5,000,OÒO 413,000 18
01/09/1992 01/10/2022 01/09/1992 01/10/2022 4,000,000 330,800 19
09/18/1992 09/01/2022 09/18/1992 09/01/2022 15,000,000 1,207,500 20
09/09/1992 09/09/2022 09/09/1992 09/09/2022 8,000,000 645,600 21
09/11/1992 09/09/2022 09/1.1/1992 09/09/2022 50,000,000 4,060,000 22
09/11/1992 09/09/2022 09/11/1992 09/09/2022 12,000,000 973,200 23
09/14/1992 09/14/2022 09/14/1992 09/14/2022 10,000,000 805,000 24
10/15/1992 10/14/2022 10/15/1992 10/14/2022 26,000,000 2,100,800 25
10/15/1992 10/14/2022 10/15/1992 10/14/2022 25,000,000 2,020,000 26
01/20/1993 01/20/2023 01/20/1993 01/20/2023 5,000,000 411,500 27
01/29/1993 01/20/2023 01/29/1993 01/20/2023 4,000,000 329,200 28
29
07/22/1993 07/21/2023 07/22/1993 07/21/2023 27,000,000 1,960,200 30
07/22/1993 07/21/2023 07/22/1993 07/21/2023 11,000,000 798,600 31
08/16/1993 08/16/2023 08/16/1993 08/16/2023 15,000,000 1,084,500 32
..;)~ "':'i7 6,357,741,000 363,203,396 33
FERC FORM NO.1 (ED. 12-96)Page 257.1
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
LONG-TERM DEBT (Accunt 221, 222, 223 and 224)
1. Report by balance sheet accunt 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 accunts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The 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 7.24% Series F Medium-Term Notes due Aug. 16,2023 30,000,000 274,423
2 6.75% Series F Medium-Term Notes due Sept. 14,2023 5,000,000 38,250
3 6.75% Series F Medium-Term Notes due Sept. 14,2023 2,000,000 15,300
4 6.72% Series F Medium-Term Notes due Sept. 14,2023 2,000,000 15,300
5 6.75% Series F Medium-Term Notes due Oct. 26, 2023 20,000,000 152,326
6 6.75% Series F Medium-Term Notes due Oct. 26, 2023 16,000,000 121,861
7 6.75% Series F Medium-Term Notes due Oct. 26, 2023 12,000,000 91,396
8 6.71% Series G Medium-Term Notes due Jan. 15,2026 100,000,000 904,467
9 Subtotal - First Mortgage Bonds 5,768,892,000 59,320,397
10
11 Pollution Control Obligations - Secured by Pledged First Mortgage Bonds:
12
13 Poll Ctrl Rev Refunding Bonds, Moffat County, CO, Series 1994 40,655,000 874,159
14 5-5/8% Poll Ctrl Rev Refunding Bonds, Lincòln County, WY, Series 1993 8,300,000 228,980
15 197,125 D
16 5.65% Poll Ctrl Rev Refunding Bonds, Emery County, Utah, Series 1993A 46,500,000 1,624,793
17 5-5/8% Poll Ctrl Rev Refunding Bonds, Emery County, Utah, Series 1993B 16,400,000 625,551
18 389,500 D
19 Poll Ctrl Rev Refunding Bonds, Sweetwater County, WY, Series 1994 21,260,000 510,479
20 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1994 8,190,000 209,777
21 Poll Ctrl Rev Refunding Bonds, Emery County, UT, Series 1994 121,940,000 3,274,246
22 Poll Ctrl Rev Refunding Bonds, Carbon County, UT, Series 1994 9,365,000 206,519
23 Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1994 15,060,000 422,858
24 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1988 17,000,000 155,970
25 Poll Ctrl Revenue Bonds, Sweetwater County, WY, Series 1984 15,000,000 122,887
26 105,000 D
27 Poll Ctrl Rev Refunding Bonds, Lincoln Cnty, WY, Series 1991 45,000,000 771,836
28 Poll Ctrl Revenue Bonds, City of Forsyth, MT, Series 1986 8,500,000 304,824
29 Environ. Impivmnt Rev Bonds, Converse County, WY, Series 1995 5,300,000 132,043
30 Environ, Impivmnt Rev Bonds, Lincoln County, WY, Series 1995 22,000,000 404,262
31 Subtotal Pollution Control Obligations - Secured by Pledged First Mortgage Bonds 400,470,000 10,560,809
32
33 TOTAL 6,507,262,000 74,175,437
FERC FORM NO.1 (ED. 12-96)Page 256.2
Narie of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
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 explanator (details) for Accounts 223 and 224 of net changes during the year. With respect to long~term
advances, show foreach company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and datesó
13.lf the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year,
describe such securities in a footnote. .
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD us an ln~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?~fent)
(I)
08/16/1993 08/1612023 08/16/1993 08/16/2023 30,000,000 2,172,000 1
09/14/1993 09/14/2023 09/14/1993 09/14/2023 5,000,000 337,500 2
09/14/1993 09/14/2023 09/14/1993 09/14/2023 2,000,000 135,000 3
09/14/1993 09/14/2023 09/14/1993 09/14/2023 2,000,000 134,400 4
10/26/1993 . 10/26/2023 10/26/1993 10/26/2023 20,000,000 1,350,000 5
10/26/1993 10/26/2023 10/26/1993 10/26/2023 16,000,000 1,080,000 6
10/26/1993 10/26/2023 10/26/1993 10/26/2023 12,000,000 810,000 7
01/23/1996 01/15/2026 01/23/1996 01/15/2026 100,000,000 6,710,000 8
5,619,371,000 349,981,485 9
10
11
12
11/17/1994 05/01/2013 11/171994 05/01/2013 40,655,000 353,792 13
11/15/1993 11/01/2021 11/15/1993 11/01/2021 8,300,000 476,835 14
15
11/15/1993 11/01/2023 11/15/1993 11/01/2023 46,500,000 2,683,050 16
11/15/1993 11/01/2023 11/15/1993 11/01/2023 16,400,000 942,180 17
18
11/17/1994 11/01/2024 11/171994 11/01/2024 21,260,000 168,760 19
11/171994 11/01/2024 11/171994 11/01/2024 8,190,000 73,010 20
11/17/1994 11/01/2024 11/17/1994 11/01/2024 121,940,000 1,005,483 21
11/17/1994 11/01/2024 11/17/1994 11/01/2024 9,365,000 74,924 22
11/17/1994 11/01/2024 11/17/1994 11/01/2024 15,060,000 137,933 23
01/01/1988 01/01/2014 01/01/1988 01/01/2014 17,000,000 680,352 24
12/01/1984 12/01/2014 12/01/1984 12101/2014 15,000,000 600,357 25
26
01/17/1991 01/01/2016 01/17/1991 01/01/2016 45,000,000 953,494 27
12/01/1986 12/01/2016 12/01/1986 12101/2016 8,500,000 359,450 28
11/17/1995 11/01/2025 11/17/1995 11/01/2025 5,300,000 224,251 29
11/171995 11/01/2025 11/17/1995 11/01/2025 22,000,000 953,747 30
400,470,000 9,687,618 31
32
,Jr~", &_ "fl"6,357,741,000 363,203,396 33
FERC FORM NO.1 (ED. 12-96)Page 257.2
Name of Respondent This f!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
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 column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1
2 Pollution Control Obligations - Unsecured
3
4 Poll Ctrl Rev Refndng Bonds, SweetwaterCnty, WY, Ser. 1992A 9,335,000 167,524
5 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992B 6,305,000 151,908
6 Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 22,485,000 242,163
7 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988B 11,500,000 84,822
8 Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Ser. 1990A 70,000,000 660,750
9 Poll Ctrl Rev Refndng Bonds, Emery County, UT, Series 1991 45,000,000 872,505
10 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988A 50,000,000 422,443
11 Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Series 1988 45,000,000 380,198
12 Poll Ctrl Rev Refndng Bonds, City of Gilette, WY, Ser. 1988 41,200,000 351,905
13 Environ. Imprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 24,400,000 225,000
14 6.150% Environ. Imprvmnt Rev Bonds, Emery County, UT, Series 1996 12,675,000 556,549
15 178,464 D
16
17 Subtotal - Pollution Control Obligations - Unsecured 337,900,000 4,294,231
18
19
20
21 TOTAL ACCOUNT 221 6,507,262,000 74,175,437
22
23
24 Reacquired Bonds: (Account 222)
25
26
27 Advances from Associated Companies: (Accunt 223)
28
29
30
31 Other Long-Term Debt: (Account 224)
32
33 TOTAL 6,507,262,000 74,175,437
FERC FORM NO.1 (ED. 12-96)Page 256.3
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/18/2011
LONG-TERM DEBT (Account 221,222,223 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long.term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year,
describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD uuisianoin§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)
resP?~fent)
(i)
1
2
3
09/29/1992 12/01/2020 09/29/1992 12101/2020 9,335,000 109,784 4
09/29/1992 12/01/2020 09/29/1992 12/01/2020 6,305,000 74,393 5
09/29/1992 12/01/2020 09/29/1992 12101/2020 22,485,000 263,488 6
01/01/1988 01/01/2014 01/01/1988 01/01/2014 11,500,000 89,883 7
07/25/1990 07/01/2015 07/25/1990 07/01/2015 70,000,000 535,882 8
OS/23/1991 07/01/2015 OS/23/1991 07/01/2015 .45,000,000 365,100 9
01/01/1988 01/01/2017 01/01/1988 01/01/2017 50,000,000 437,603 10
01/01/1988 01/01/2018 01/01/1988 01/01/2018 45,000,000 356,956 11
01/01/1988 01/01/2018 01/01/1988 01/01/2018 41,200,000 323,737 12
12/14/1995 11/01/2025 12114/1995 11/01/2025 24,400,000 197,954 13
09/24/1996 09/01/2030 09/24/1996 09/01/2030 12,675,000 779,513 14
.15
16
337,900,000 3,534,293 17
18
19
20~......Wd 363,203,396 21
22
23
24
25
26
27
28
29
30
31
32
6,357,741,000 363,203,396 33
FERC FORM NO.1 (ED. 12-96)Page 257.3
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
.LONG-TERM DEBT (Account 221, 222, 223 and 224).
1. Report by balance sheet accunt 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 accunts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The 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 TOTAL ACCOUNT 224
2
3
4 " 0 w, , ¡¡
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 TOTAL 6,507,262,000 74,175,437
FERC FORM NO.1 (ED. 12-96)Page 256.4
Name of Respondent Thisworr~:Date of Report Year/PElod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) EjA Resubmission 04/18/2011
.LONG-TERM DEBT (Account 221,222,223 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally oùtstanding at end of year,
describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD ul!iS1Cn~ln~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?~fent)
(i)
1
2
3
4
5
6
7
.8
9
10
11
12
13
14
.15
16
17
18
19
~20
21
22
23
24
25
26
27
28
29
30
31
32
6,357,741,000 363,203,396 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)
PaciñCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
ISchedule Page: 256.3 Line No.: 21 Column: h
Refer to page 108, Importnt Changes Durg the QuaerNear, Item 6, and Notes to Financial Statements of this Form No. i for a
discussion ofPacifiCorp's long-term debt.
ISchedule Page: 256.4 Line No.: 4 Column: a
In December 2010, PacifiCorp filed a shelf registration stateent with the United States Securties and Exchange Commission on
Form S-3 coverig futue first mortgage bond issuaces thugh December 2013.
For authorization for the issuance oflong-ter debt ($2.0 bilion authoried; $2.0 bilion available as of December 31, 2010), refer to
page 108, Importnt Changes Durig the QuarerNear, Item 6, of this Form No.1.
Authorization to borrow the proceeds of pollution control revenue refudig bonds issued (total of $300,345,000 authorized and
available as of December 31, 2010) by the counties of Emery, Utah; Carbon, Utah; Converse, Wyoming; Lincoln, Wyoming;
Sweetwater, Wyoming; and Moffat, Colorado.
Authorization to borrow the proceeds of new pollution control revenue bonds issued (total of $150,000,000 authorized and available
as of December 31,2010) by one or more of the following counties or municipalities: Emery, Uta; 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 Commission, 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 04/18/2011
RECONCILIATION OF REPORTED NET INCOME WITH TAXBLE INCOME FOR FEDERAL INCOME TAXES
Year/Period of Report
End of 2010/Ò4
1. Report the reconcilation 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 furnished on Schedule M-1 of the ta return for
the year. Submit a reconcilation even thougn 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 return, reconcile reported net income with taxable net income as if a separate
return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax
assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the
above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
ine
No.
1 Net Income for the Year (Page 117)
2
3
4 Taxable Income NotReported on Books
5
6
7
8
mount
(b)
566414836
lIýø % 1lø¡¡..%" 11....x 0 7W..W4i: .fîff
B /& ;&BYdfl~1.1..1" B\II. 7 %.;r¿¡~770%.. :W l Ç~MØ/; /4
19 Deductions on Return Not Charged Against Book Income
20
21
22
23
2425 ._iii~..
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 Tax Reserve Changes
33 Renewable Electricity Production Tax Credits
34 Mining Rescue Training Credits
35 Research & Experimentation Credits
36 Foreign Tax Credit
37 Fuel Tax Credit
38
39
40
41 Federal Income Tax Accrual
42
43
44
3,018,805,017
6,881,135
-1,307,059,747
-457,470,911
25,508,786
-1,467,224
-55,464,174
-72,211
-71,195
-29,612
-16,667
FERC FORM NO.1 (ED. 12-96)Page 261
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
!Schedule Page: 261 Line No.: 8 Column: a
Pariculars (Details)
PacifiCorp Minerals, Inc. (PMI) Dividend Gross Up for Foreign Tax Credit
Sec. 481a Adjustment - Repair Deduction
CIAC
Reimbursements
Avoided Costs
Deferred Excess Net Power Costs - WY 08
Deferred Excess Net Power Costs - W A Hydro
OR_RCAC Sep-Dec 07 Deferred
OR SB 408 Recovery
NW Power Act- W A
Regulatory Liability - Tax Revenue Adjustment - UT
Regulatory Liability - W A Low Energy Program
Regulatory Liability - OR BalanceConsol
Reg Liability - Sale of Renewable Energy Credit - OR
Regulatory Liability - OR Energy Conservation Charge
Regulatory Liability - Blue Sky Progrm OR
Regulatory Liability - Blue Sky Program W A
Regulatory Liability - Blue Sky Program UT
Regulatory Liability. Sale of Renewable Energy Credits - WY
DefRegu1atory Asset-Transmission Service Deposit
Bear River Settlement Agreement
Uneared Joint Use Pole Contact Revenue
MCI FOG Wire Lease
Bridger Coal Company GainLoss on Assets Disposed
Bridger Coal Company Reclamation Trust Earings - PMI
BCC Money Market Interest Income - PMI
Equity Earnings in Subsidiaries
Total
Amounts
29,612
16,316,468
46,836,991
6,694,692
73,561,100
9,970,836
1,694,391
4,566,986
8,675,071
579,420
49,234
241,237
2,626,320
3,922,178
1,516,395
248,691
8,148
185,811
3,594,057
419,175
369,257
20,353
668
166,776
1,727,115
8
2,097,757
186,118,747$
ISchedule Page: 261 Line No.: 13 Column: a
Pariculars (Details)
Fed/State Tax Expense
Fed/State Tax Expense-Interest
Capitalized labor and benefits costs for Power ta input - Peranent
Meals & Entertinent
Penalties- PMI
Lobbying expenses
Meals & Entertinent - Bridger Coal
MEHC Insurance Services - Premium
Mining Rescue Training Credit Addback - PacifiCorp
PMI Fuel Tax Cr
Non-deductible post-retirement costs
Mine Rescue Training Credit Addback - PMI
Capitalized labor and benefits costs for Power ta input - Tempora
Book Depreciation
Book Depreciation- PMI
Capitalization of Test Energy
Book Cost Depletion - Addback
May 2000 Transition Plan Costs-OR
Glenrock Excluding Reclamation-UT
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Amounts
209,955,393
2,035,366
805,108
1,050,493
203,437
2,493",024
9,585
6,969,001
44,658
16,667
5,520,000
27,553
13,493,191
566,450,834
17,814,653
555,842
2,152,540
2,269,573
112,218
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Regulatory Asset - Pension Liab Adj.
Reguatory Asset - Post Ret. Liab.
Environmental Costs - W A
Cholla Plant Transaction Costs-APS Amortzation
W A Disallowed Colstrp #3- Write-off
DefRegulatory Asset-OR DefNet Power Costs
Regulatory Asset - Lake Side Liquidation
Goodnoe Hils Liquidation Damages - WY
RTO Grid West Notes Receivable - OR
RTO Grid West Notes Receivable - WY
RTO Grid West Notes Receivable - il
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 MMT -CA
Regulatory Asset-Deferred OR Independent Evaluator Fees
Unrecovered Plant - Powerdale
Deferred UTIndependent Evaluation Fee
il MEHC 2006 Transition Costs
WY - 2006 Transition Severance Costs
W A - Chehalis Plant Revenue Requirement
Deferred Regulatory Expense
Weatherization
Reg Asset - SB 1149 Balance Reclass
Reg Asset - Other - Balance Reclass
Reg Asset - DefNPC Balance Reclass
Trojan Decommissioning Costs - Regulatory
Coal Pile Inventory Adjustment
Prepaid Taxes - OR PUC
Prepaid Taxes - UT PUC
Other Prepaid
RTO Grid West Note Receivable ~ w/o - WA
TGS Buyout
Joseph Settlement
Hermston Swap
Western Coal Carrer Postretiement Benefit Accrual
Derivatives - Curent
Post Merger Loss-Reacquisition Debt - Addback
ARO Regulatory Liabilities
Non-ARO Liability - Regulatory Liability
Regulatory liability BP A balancing accounts
OR Regulatory Asset/iability Consolidation
CA-California Alternative Rate for Energy Program (CAR)
March 2006 Transition Plan Costs - W A
Vacation Accrul- Cash Basis (2.5 months)
Deferred Compensation Accrual - Cash Basis
Derivatives - noncurent
ARO Liability
Distrbution O&M Amortzation of Write-off
PMI-Fuel Cost Adjustment
Bad Debts Allowance - Cash Basis
Deferred Coal Cost - Arch
IFERC FORM NO.1 (ED. 12-87) Page 450.2
20,280,280
14,315,000
58,274
1,122,425
52,188
175,363
27,627
21,250
296,060
92,022
27,162
283,176
249,393
308,642
278,648
17,235
502,606
103,976
3,927
610,194
1,062,222
3,000,000
17,580
28,318,709
68,360
39,320
2,604,370
1,901,813
3,741,527
354,528
288,268
1,096,630
46,941
15,474
137,381
171,693
1,702,000
94,838,151
2,331,323
248,448
26,654,196
756,054
61,152
1,142,586
318,524
815,994
14,958
23,263,199
7,523,374
2,872,313
3,007,257
1,314,913
1,650,075
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 .2010/Q4
FOOTNOTE DATA
Rogue River - Habitat Enhancement Liability
Lewis River Settlement Agreement
Other Environmental Liabilities
N. Umpqua Settlement Agreement
Umpqua Settlement Agreement
Accrued Insurance Premium Tax
Reverse Accrued Final Reclamation
Injures and Damages Accrul - Cash Basis
Post Employment Benefits Book Reserve
Sec. 263A Inventory Change - PMI
Vacation Accrual- PMI
PMI Pre-Strpping Costs
Pension Liabilty - Boilermaker Trust - PMI
Reserve on Pension Boilermaker Trust - PMI
Bridger Coal Company Section 47 i Adjustment - PMI
Bridger Coal Company Extrction Taxes Payable - PMI
Total
15,350
168,368
2,460,845
1,285,817
381,866
176,436
214,463
1,011,129
1,581,001
121,584
17,490
906,977
8,605,606
4,302,803
1,071,313
1,897,245
$ 1,106,402,210
~chedule Page: 261 Line No.: 18 Column: a
Pariculars (Details)
Medicare Subsidy
Bridger Coal Tax Exempt Interest Income
AFUDC
Basis Intangible. Difference
Book Gain/Loss on Land Sales
Regulatory Asset balance reclass
Trojan Decommssioning Costs - VIA
Trojan Decommssioning Costs - OR
781 Shopping Incentive
Trapper Mining Stock Basis
Regulatory Liability -Blue Sky Program CA
Regulatory Liability - Blue Sky Program ID
Regulatory Liability - Blue Sky Program WY
Regulatory Liability - CA Gain on Sale of Asset
SMU Revenue Imputation - UT regulatory liability
UT DSM - SMU Offset
Wilow Wind Account Receivable
DefRegulatory Asset-Foote Creek Contract
Tenant Lease Allow - PSU Call Center
Duke/Hermston Contrct Renegotiation
Deferred Revenue - Citibank
Redding Contract - Prepaid
Umealized GainIoss from Trading Securties
Total
Amounts
(8,123,000)
(25,929)
(118,429,747)
(5,489,877)
(3,034,342)
(2,626,320)
(275,765)
(67,953)
(68,360)
(350,474)
(48,900)
(26,201)
(21,143)
(41,280)
(10,988,748)
(2,850,000)
(7,547)
(137,640)
(48,156)
(754,839)
(500)
(549,996)
004,941)
(154,071,658)$
~chedule Page: 261 Line No.: 25 Column: a
Pariculars (Details)
Book Depreciation Allocated to Medicare and M&E
Tax Percentage Depletion - Blundell Steam Field (Prior IGC)
PPL Pre - 1943 Preferred Stock Div - Deduction
Penalties
Utah Deferred Comp / COLI
IFERC FORM NO.1 (ED. 12-87) Page 450.3
Amounts
(234,743)
(446,104)
(381,063)
(418,323)
(4,170,868)
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
MERC Insurance Services - Receivable
Dividend Received Deduction - PMI
PMI Overrding Coal Royalty % Depletion - PacîfiCorp
Repair Deduction
Tax Depreciation
Depreciation (Tax Depreciation M-1) - PMI
Capitalized Depreciation
§ 1 031 Like Kind Exchange
Mine Safety Sec 179E Election ~PPW
Mine Safety Sec 179E Election ~PMI
Gain / (Loss) on Prop. Disposition
Coal Mine Development
Coal Mine Extension
Removal Costs
Chona SRL-NOPA (Lease Amortation)
ARO - reclass to ARO liabilities
ARO - reclass to regulatory assets/lability & ARO liability
Tax Percentage Depletion- Deduction
Tax Depletion
ARO Regulatory Assets
Environmental Clean-up Accrual
Chona Plant Transaction Costs - APS Amortzation - ID
Chona Plant Transaction Costs - APS Amortzation - OR
Chona Plant Transaction Costs - APS Amortization - W A
Deferred Intervener Funding Grants
Contra Pension Regulatory Asset MMT & CTG - OR
Contra Pension Regulatory Asset MMT & CTG - WY
Contra Pension Regulatory Asset CTG - UT
Contra Pension Regulatory Asset MMT & CTG - CA
Contra Pension Regulatory Asset CTG - W A
Powerdale Decommissioning Reg Asset - ID
Powerdale Decommissioning Reg Asset - OR
Powerdale Decommissioning Reg Asset - W A
CA - January2010 Storm Costs
Powerdale Decommissioning Reg Asset - WY
ID - Deferred Overburden Costs
WY - Deferred Overburden Costs
WY - Deferred Advertising Costs
Reg Asset - Utah MP A
Reg Asset - OR Solar Feed-In Tarff
Deferred Excess Net Power Costs-CA
Deferred Excess Net Power Costs - WY 09 and After
Deferred Excess Net Power Costs - OR
Deferred Excess Net Pòwer Costs - ID 09
OR - MERC Transition Service Costs
Reg Asset MERC Transition Service Costs - CA
Deferred Coal Costs - Naughton Contract Settlement
Idaho Customer Balancing Account
Regulatory asset - Net Derivatives
Prepaid Taxes - ID PUC
Prepaid Taxes - Propert Taxes
WY Joint Water Board Reserve - Deduction
Wasach workers comp reserve
IFERC FORM NO.1 (ED. 12-87)
(16,311,944)
(190,159)
(13,882)
(110,465,957)
(2,462,905,267)
(27,643,239)
(5,038,044)
(15,303)
(1,042,374)
(8,039)
(13,920,178)
(421,752)
(651,766)
(43,232,515)
(82,539)
(6,609,132)
(26,654,196)
(512,714)
(169,961)
(1,162,691)
(6,709,980)
(32,973)
(53,813)
(97,006)
(212,113)
(699,514)
(1,370,277)
(5,067,634)
(37,036)
(865,074)
(304,766)
(493,016)
(851,788)
(1,230,000)
(34,392)
(249,096)
(665,891)
(52,198)
(15,724,521)
(226,622)
(4,514,014)
(14,550,049)
(3,526,084)
(10,341,116)
(2,969,259)
(222,772)
(8,256,923)
(603,662)
(119,993,673)
(25,946)
(4,907,666)
(75,000)
(96,960)
Page 450.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/1812011 2010/Q4
FOOTNOTE DATA
Reg Liability - Tax Revenue Adjustment - WY
OR Rate Refuds
W A Rate Refunds
Regulatory Liability - UT Home Energy Lifeline
Reg Liability - Other - Balance Reclass
Reg Liability - DefNPC Balance Reclass
Reg Liability - SB 1149 Balance Reclass
Oregon Gain on Sale
Propert Insurance (same as Injures & Damages)
Regulatory Liability - Deferred Benefit Arch Settlement
Bonus Liability - Electrc - Cash Basis (2.5 months)
Pension / Retiement Accrual - Cash Basis
Severance Accrual - Cash Basis
Pension Liability
Post-Retirement Liability
SERP Liability
Malin SHL (Tax Int. - Tax Rent + Book Depreciation)
M&S Inventory Write-Off
R & E - Sec.174 Deduction
Accrued Royalties
Misc. Curent and Accrued Liability
Amortzation NOP As 99-00 RA
Coal Mine Extension Costs-PP&E - PMI
Coal Mine Development-PMI
PMI Development Cost Amortzation
Bridger Coal Company Underground Mine Cost Depletion
Bridger Coal Company Mine Reclamation Costs - PMI
Total
(99,955)
(79,965)
(228,659)
(210,493)
(39,320)
(2,604,370)
(68,360)
(385,621)
(109,564)
(1,173,017)
(37,586)
(120,181)
(24,245)
(58,346,300)
(14,431,488)
(697,207)
(3,115)
(168,634)
(2,950,928)
(1,014,993)
(67,024)
(58,446)
(3,951,514)
(55,120)
(3,012,969)
(164,607)
(937,749)
$ (3,018,805,017)
I§chedule Page: 261 Line No.: 41 Column: b I
Berkshire Hathaway Inc. includes PacifiCorp in its United States federal income ta retu. PacifiCorp's provision for income taes has
been computed on a stand-alone basis.
Names of group members who wil fie a consolidated Federal Tax Return:
UnderMEHC:
PPW Holdings LLC Sub-Group:
PacifiCorp
PPW Holdings LLC
PacifiCorp Sub-Group:
Centrlia Mining Company
Energy West Mining Company
Glenrock Coal Company
Interwest Mining Company
Pacific Minerals, Inc.
PacifiCorp Environmental Remediation Company
PacifiCorp Investment Management, Inc.
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 04/18/2011 2010/Q4
FOOTNOTE DATA
MEHC Sub-Group:
Alaska Gas Transmission Company, LLC
Allerton Capital, Ltd
American Pacific Finance Company
American Pacific Finance Company II
Arzona Home Serices, L.L.c.
BG Energy Holding LLC
BG Energy LLC
CalEnergy Generation Operating Company
CalEnergy Holdings, Inc
CalEnergy Imperial Valley Company, Inc.
CalEnergy International Services, Inc
CalEnergy International; Inc
CalEnergy Minerals Development LLC
CalEnergy Minerals LLC
CalEnergy Pacific Holdings Corp
CalEnergy UK Inc
Capitol Intermediary Company
Capitol Land Exchange, Inc
Capitol Title Company
CBEC Railway, Inc
CBSHome Real Estate Company
CBSHome Real Estate of Iowa, Inc
CBSHome Relocation Services, 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 International Investments, Inc
CE Obsidian Energy LLC
CE Obsidian Holding LLC
CE Power, Inc
CE/TALLC
Champion Realty, Inc
Chancellor Title Services, Inc
Cimmed 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 Insurnce, LLC
Edina Realty Referral Network, Inc
Edina Realty Relocation, Inc
Edina Realty Title, Inc
Edina Realty, Inc
Esslinger- Wooten-Maxwell, Inc
E-W-M Referrl Services, Inc.
IFERC FORM NO.1 (ED. 12-87)
FFR, Inc
First Realty, Ltd
First Reserve Insurance, Inc
F or Rent, Inc
HMSV Financial Services, Inc
HN Heritage Title Holdings, LLC
HN Insurance Holdigs, LLC
HN Mortgage, LLC
HN Real Estate Group N.C., Inc.
HN Real Estate Group, LLC
HN Referrl Corporation
HomeServices Financial Holdings, Inc
HomeServices Financial, LLC
HomeServices Financial-Iowa, LLC
HomeServices Insurance, Inc
HomeServices of Alabama, Inc.
HomeServices of America, Inc
HomeServices of California, Inc
HomeServices of Florida, Inc
HomeServices of Ilinois d//a Koenig & Strey GM
HomeServices oflowa, Inc
HomeServices of Kentucky Real Estate Academy, LLC
HomeServices of Kentucky, Inc
HomeSèrvices of Nebraska, Inc
HomeServices of Nevada, Inc
HomeServces of the Carolinas, Inc
HomeServices Referral Network, LLC
HomeServices Relocation, LLC
HSR Equity Funding, Inc
Huff Commercial Group, LLC
Huff Realty Insurnce, LLC
Huff-Drees Realty, Inc.
IMO Company, Inc
InsuranceSouth, LLC
InterCoast Capital Company
InterCoast Energy Company
Iowa Realty Company, Inc
Iowa Realty Insurance Agency, Inc
Iowa Title Company
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 Referral Service, LLC
Kern River Funding Corporation
Kern River Gas Transmission Company
K. Acquisition l, LLC
K. Acquisition 2, LLC
K. Holding, LLC
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 04/18/2011 2010/Q4
FOOTNOTE DATA
MEHC Sub-Group (continued):
Larabee School of Real Estate & Insurance
M & M Ranch Acquisition Company, LLC
M & M Rach Holding Company, LLC
MEC Constrction Services Company
MEHC America Transco, LLC
MEHC Insurance Services Ltd.
MEHC Investment, Inc
MEHC Merger Sub Inc
MEHC Texas Transco, LLC
MHC Investment Company
MHC,Inc
Mid-America Referral Network, Inc.
MidAerican Comercial R.E. Services, Inc
MidAerican Energy Company
MidAerican Energy Holdings Company
MidAerican Energy Machining Services LLC
MidAerican Funding, LLC
MidAerican Nuclear Energy Company, LLC
MidAerican Nuclear Energy Holdings Co., LLC
MidAerican Transmission, LLC
Midland Escrow Services, Inc
Midwest Capital Group, Inc
Midwest Gas Company
MW Capital, Inc
Nebraska Land Title & Abstract Company
NNGC Acquisition, LLC
Northern Aurora Inc
Nortern Natual Gas Company
Pickford Escrow Company, Inc
Pickford Golden State Member LLC
Pickford Holdings LLC
Pickford Real Estate, Inc
Pickford Serices Company, Inc
Plaz Financial Services, L.L.c.
Plaz Mortgage Services, L.L.c.
Prefered Carolinas Realty, Inc
Prefered Carolinas Title Agency, L.L.c.
Professional Referral Organization, Inc
Quad Cities Energy Company
Real Estate Lins, LLC
Real Estate Referral Network, inc
Reece & Nichols Alliance, Inc
Reece & Nichols Realtors, Inc
Referral Company of North Carolina, Inc
RHL Referal Company, L.L.C.
Roberts Brothers, Inc
Roy H. Long Realty Company, Inc
Safe Harbor Holdig Company, LLC
Salton Sea Minerls Corporation
San Diego PCRE, Inc
Semonin Realtors, Inc
Southwest Relocation, LLC
The Escrow Fir
The Referral Company
TitleSouth, LLC
Trinity Mortgage Parers, Inc
Two Rivers, Inc
United Settlement Servces, 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 primarly on the stad-alone method of allocation. The computation includes all tax benefits from tax deductions from costs
borne by utility customers.
Berkshire Hathaway Inc. Sub-Group:
21 SPC, Inc.
21st Communities, Inc.
21st Mortgage Corporation
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 Ochs Brick and Stone
Acme Services Company, L.P.
Adalet/Scott Fetzer Company
AEG Processing Center No. 35, Inc.
AEG Processing Center No. 58, Inc.
IFERC FORM NO.1 (ED. 12-87)
Agile Manufactug, Inc.
AJ Warehouse Distrbutors, Inc.
ALITX Homes, Inc.
Albecca, Inc.
All Bilt Uniform
Alpha Cargo Motor Express, Inc.
Ambucor Health Solutions, Inc.
American All Risk Insurance Services Inc.
American Centennial Insurance Company
American Commercial Claims Administrtors Inc.
American Dair Queen Corporation
American Employers Group, Inc.
American Tile Supply, Inc
Apeks Apparel, Inc.
Applied Group Insurnce Holdings, Inc.
Page 450.7
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group (continued):
. Applied Investigations Inc.
Applied Logistics, Inc.
Applied Premium Finance, Inc.
Applied Risk Services of New York, Inc.
Applied Risk Services, Inc.
Applied Underwriters, Inc.
Atlanta International Insurance Company
AU Captive Risk Assurance Co.
AU Captive Risk Assurance Co., Inc.
AU Holding Company, Inc.
B. Lippman
Bayport Systems, Inc.
Ben Bridge Jeweler, Inc.
Benjamin Moore & Co.
Berkshire Hathaway Assurace Corporation
Berkshire Hathaway Credit Corporation
Berkshire Hathaway Finance Corporation
Berkshire Hathaway Inc. (Common Parent)
Berkshire Hathaway Life Insurance Company of Nebr.
BH Columbia Inc.
BH Finance, Inc.
BH Shoe Holdings, Inc.
BHG Strctued Settlements, Inc.
BRRInc.
BHSF, Inc.
Blue Chip Stamps
BN Leasing Corporation
BNJ NetJets, Inc.
BNSF Communications, Inc.
BNSF Logistics International, Inc.
BNSF Railway Company
BNSF Railway International Services, Inc.
BNSF Spectrm, Inc.
Boat America Corporation
Boat U.S, Inc.
Boat U.S. Travel International, Ltd.
Boot Royalty Company
Borsheim Jewelry Company, Inc.
BR Agency, Inc.
Bricker-Mincolla Uniforms
Brilliant National Services, Inc.
Brooks Sports, Inc.
Brookwood Insurance Company
Buffalo News
Burlington Nortern Railroad Holdings, Inc.
Burlington Nortern Santa Fe British Columbia, Ltd.
Burlington Norter Santa Fe Ins. Company, Ltd.
Burlington Nortern Santa Fe Manitoba, Inc.
Burlington Northern Santa Fe, LLC
Business Wire, Inc.
C & R Insurance Services, Inc.
California Employer Group No. 27, Inc.
IFERC FORM NO.1 (ED. 12-87)
California Insurance Company
Camp Manufactug 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 Servce, Inc.
Chatwell, Inc.
Chippewa Shoe Company
Citadel Insurnce Company
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 Services, Inc.
CMH Set and Finish, Inc.
Cologne Reinsurance Company Of America
Cologne SerVices Corporation
Columbia Inurance Company
Combined Claims Services, Inc.
Commnd Uniforms
Commercial Casualty Insurance Company
Commercial General Indemnity, Inc.
Commonwealth Uniforms Inc.
Complementary Coatings Corporation
Continental Divide Insurance Company
Continental Indemnity Company
Corbond Corporation
Comhusker Casualty Company
Cort Business Services
Coverage Dynamics Group, Inc.
Criterion Insurance Agency
Crowley Garent Mfg Co Inc.
Crowley Shir Mfg Co Inc.
CSI Life Insurance Company
CTB Credit Corp
CTB Inc.
CTB International Corp
CTBIWINC
CTB MN Investments
Cumberland Asset Management, Inc.
Cypress Insurance Company
Dairy Queen Corporate Stores, Inc.
Dair Queen Of Georgia, Inc.
Page 450.8
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group (continued):
Denver Brick Company
Dexter Shoe Company
DQ Fundig Corporation
DQ Joint Ventue Stores, Inc.
DQ Managed Stores, Inc.
DQ Wholly-Owned Stores, Inc.
DQF, Inc.
DQGC, Inc.
Eastern States Life Insurance Co., Ltd.
Eco Color Company
Edmonds Material and Equipment Co.
Elm Street Corporation
Empire Distrbutors of North Carolina, Inc.
Empire Distrbutors, Inc.
Executive Jet Europe, Inc.
Executive Jet Management, Inc.
Expertos en Admnistracion, SA de C.V.
Faireld Insurance Company
Faraday Capital Limited
Farrors, Inc.
FFG Insurnce Company
Finial Holdings, Inc.
Finial Reinsurance Company
First Berkshire Hathaway Life Insurance Company
FlightSafety Capital Corp.
FlightSafety Development Corp.
FlightSafety International Inc.
FlightSafety New York, Inc.
FlightSafety Properties, Inc.
FlightSafety Services Corporation
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.
FreightWise, Inc.
Fruit of the Loom Caribbean, Inc.
Fruit of the Loom Direct, Inc.
Fruit of the Loom Trading Company
Fruit of the Loom, Inc.
Fruit of the Loom, Inc. (Sub)
FSI Delaware Holding Corp.
FTL Regional Sales Co., Inc.
FTL Sales Company, Inc.
Fulton Manufacturig Company
Garan Central America Corp.
Garan Incorporated
Garan Manufacturing Corp.
Garan Services Corp
IFERC FORM NO.1 (ED. 12-87)
Gateway Underwters Agency, Inc.
GEICO Casualty Co.
GEICO Corporation
GEICO General Insurnce Co.
GEICO Indemnity Co.
GEICO Inurce Agency
GEICO Products, Inc.
Gen Re Intermediares Corporation
Generl Re Corporation
General Re Financial Products Corporation
Generl Re New England Asset Management
General Reinsurance Corporation
General Star Indemnity Company
General Sta Management Company
General Sta National Insurance Company
Genesis Indemnity Insurance Company
Genesis Insurace Company
Genesis Underwtig Management Company
Giles Industres, Inc.
Glass Mountain Optics, Inc.
Golden Skillet International, Inc.
Governent Employees Financial Corp.
Goverent Employees Insurance Co.
GRD Holdigs Corporation
Great Plains Uniforms
Griffey Uniforms
H. H. Brown Shoe Company, Inc.
H. H. Brown Shoe Technologies, Inc.
H.J. Justin & Sons, Inc.
Halex/Scott Fetzer Company
Hardy Frames, Inc.
Hars Uniforms
Harson Uniforms
HDS Redevelopment Corporation
HeatPipe Technologies
Helzberg's Diamond Shops, Inc.
Hohman & Barard, Inc.
Homefirst Agency, Inc.
Homemakers Plaza, Inc.
Horizon Wine & Spirts-Chatanooga, Inc.
Horizon Wine & Spirits-Nashville, Inc.
Innovative Buildig Products, Inc.
International America Group Inc.
International American Management Company
International Dair Queen, Inc.
Interntional Insurance Underters, Inc.
Ironwood Plastics Inc
Isabella Shoe Corporation
1.S Justi, Inc.
JME3 CO
Johns Manvile China, Ltd.
Johns Manvile Corporation
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 04/18/2011 2010/Q4
FOOTNOTE DATA _
.
Berkshire Hathaway Inc. Sub-Group (continued):
Johns Manvile, Inc.
Jordan's Furitue, Inc.
Justin Belt Company, Inc.
Justin Boot Company
Justin Brands, Inc.
Justin Industres, Inc.
Kah Ventues, Inc.
Kale Uniforms
Kansas Baners Surety Company
Karmelkorn Shoppes, Inc.
Kay Uniform
L.A. Terminals, Inc.
Laurer Indemnity Company
Leesburg Yar Mils, Inc.
Los Angeles Junction Railway Company
M & C Products, Inc.
Macro Retailing, Inc.
Mapletree Transporttion, Inc.
Marquis Jet Holdings, Inc.
Marquis Jet Parters, Inc.
Marin Manufactung Company
Martin 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 Minnesota, Inc.
McLane New Jersey, Inc.
McLane Southern, Inc.
McLane Suneast, Inc.
McLane Western, Inc.
Medical Protective Corporation
Medical Protective Finance Corporation
Medical Protective Insurance Services, Inc.
MedPro Risk Retention Services, Inc.
Meteor Communications Corporation
Metro Uniforms
MH Transport Inc.
Midland State Life Insurnce Co., Ltd.
Midwest Nortwest Propertes, Inc.
Miler-Sage, Inc.
MiTek Framings, Inc.
MiTek Holdings, Inc.
MiTek Industres, Inc.
MiTek, Inc.
MMX Corporation
Mobile Disaster Strctues, Inc.
IFERC FORM NO.1 (ED. 12-87)
Mossy Oak Apparel Company
Mount Vernon Fire Insurance Company
Mouser Electronics, Inc.
MS Propert Company
National Fire & Mare Insurance Company
National Indemnity Company
National Indemnity Company of Mid-America
National Indemnity Company of the South
National Liabilty & Fire Insurce Company
National Reinurance Corporation
Nationwide Uniforms
Nebraska Furnitue 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 Servces, Inc.
NJA Jets Inc.
NJE Holdings, LLC
NJI Sales, Inc.
Nfl, Inc.
Nocona Boot Company
North American Casualty Co.
North Star Reinsurnce Corporation
Norther States Agency, Inc.
Northland/Scott Fetzer Company
Oak River Insurance Company
Orange Julius Of America
Pan-Am Shoe Co., Inc.
Pima Uniforms
Pine Canyon Lane Company
PJR Management, Inc.
Plaza Financial Services Co.
Plaza Resources Co.
Ponce Fashions, Inc.
Powerex-Iwata Air Technology, Inc.
Precision Brand Products, Inc.
Precision Steel Warehouse -Charlotte SiC
Precision Steel Warehouse - Franklin Park
Priority One Financial Services, Inc.
Pro Installations, Inc.
Professional Datasolutions, Inc.
Promesa Health, Inc.
Queen Caret Corporation
Page 450.10
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group (contiued):
R.C. Wiley Home Furishings
Rabun Apparel, Inc.
Railsplitter Holdings Corporation
Redwood Fire and Casualty Company
RENTCD Trailer Corporation
Resolute Management Inc.
Richline Group, Inc
Rigwalt & Liesche Co.
Robert Men's Shop
Runing with Heels
Rush Air Inc.
Rush Air Services
Russell Athletic Corporation
Salado Sales, Inc.
SantB Fe Pacific Insurance Company
Santa Fe Pacific Pipeline Holdings, Inc.
Santa Fe Pacific Pipelines, Inc.
Santa Fe Pacific Railroad Company
Santa Fe Receivables Corporation
Scott Fetzer Financial Group Inc.
Scottare. Corporation
Seaworty Insurance Company
See's Candies, Inc
Sees Candy Shops, Incorporated
Seventeenth Street Realty, Inc.
Shaw Contract Flooring 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 International Services, Inc.
Shaw Retail Propertes, Inc.
Shaw Transport, Inc.
SHX Flooring, Inc.
SHX Leasing, Inc.
SidePlate Systems, Inc.
Silver State Uniforms
Simon's Incorporated
Simpad, Inc.
Soco West, Inc.
Soff Shoe Company
Sol Fran Uniform Inc.
Somerset Services, Inc
Southern Energy Homes, Inc.
Stahl/Scott Fetzer Company
Star Furitue Company
Star Lake Railroad Company
Stonewall Insurance Company
Strategic Staff Management, Inc.
Technical Coatigs Co.
IFERC FORM NO.1 (ED. 12-87)
The Ben Bridge Corporation
The BN and SF Railway de Mexico, S.A. de C.V.
The BVD Licensing Corporation
The Eagle Company
The Fechheimer Brothers Co.
The Indecor Group, Inc.
The Medical Protective Company
The Pampered Chef, Ltd.
The Scott Fetzer Company
The Zia Company
TM Custom Air Systems, Inc.
Tony Lama Company
Top Five Club, Inc.
Total Quality Apparel Resources
TPC European Holdings, LTD.
TPC Nort America, Ltd.
Trasco, Inc.
TTl, Inc.
US. Investment Corporation.
U.S. Underwters Insurance Co.
Undergarment Fashions, Inc:.
Unified Supply Chain, Inc.
Uniform of Texas
Union Sales, Inc.
Union Underwear Co., Inc
Unione ltaliana ~einsurance Company of America, Inc.
United Consumer Financial Services Company
United Direct Finance, Inc.
United States Aviation Underwters, Inc.
United States Liability Insurance Company
Universal Uniforms
Vanderbilt ABS Corp.
Vanderbilt Mortgage and Finance, Inc.
Vanderbilt Propert & Casualty Insurance Co., Ltd.
Vanderbilt SPC, Inc.
Vanity Fair, Inc.
Vertis Insurnce Group, Inc.
Vessel Assist Association of America, Inc.
Vessel Assist Insurance Services, Inc.
VFI-Mexico, Inc.
Vision Retailing, Inc.
Wayne/Scott Fetzer Company
Waynesburg Shir Company Inc.
Wesco Financial Corporation
Wesco Holdings Midwest, Inc.
Wesco-Financial Insurance Company
West Virginia Uniforms
Western Fruit Express Company
WesternScott Fetzer Company
Whitter, Clark &. Daniels, Inc.
Winona Bridge Railroad Company
WMCCorp.
Page 450.11
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp .(2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Berkshire Hathaway Inc. Sub-Group (contiued):
World Book Encyclopedia
World Book Inc.
World Book/Scott Fetzer Company, Inc.
W orldbook.com, Inc.
X-L-Co., Inc.
XLI, Inc.
XTR, Inc.
XTRA Chassis, Inc.
XTR Companes, Inc.
XTR Corporation
XTRA Finance Corporation
XTRA Intermodal, Inc.
XTRA Intemational Pacific, Ltd.
XTR International, Ltd.
XTRA Mexicana, S.A. de c.v.
Zuckerbergs Uniforms
IFERC FORM NO.1 (ED. 12-87)Page 450.12
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accued ta accounts and show the total taes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accunts to which the taed material was charged. If the actual,
or estimated amounts of such taes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, 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, taes charged to operations and other accunts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taes paid and charged direct to operations or accounts other than
acced and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertined.
ine Kind ofTax BALANCE AT BEGINNING OF YEAR ~~xes le~~S Adjust-C argedNo.(See instruction 5)'. axes Açcruer:~repald Taxes ~nng ~ring ments(Account 236)(Include in Account 165)ear ear
(a)(b)(c)(d)(e)(f)
1 Federal:,
2 Income 15,057,106 243,804,243 -489,083,208 -378,627,466
3 FICA 654,362 40,451,265 40,582,820 .
4 Unemployment 52,902 383,109 391,381
'.-
5 Excise Tax - Coal 167,805 3,121,283 3,126,302
6 Subtotal 15,932,175 243,804,243 .045,127,551 -334,526,963 -208,736
7
8 State:
9 .
10 Arizona:
11 Propert .960,566 2,363,138 2,142,135
12 Income 44,924 26,354
13 Subtotal 960,566 44,924 2,389,492 2,142,135
14
15 California:
16 Propert 2,259,708 2,259,708
17 Unemployment 31,522 30,753
18 Franchise-Income 364,355 148,513 -105,096
19 Use 5,581 179,485 181,784
20 Local Franchise 936,366 1,150,173 1,112,815
21 Subtotal 941,947 364,355 3,769,401 3,479,964
22
23 Colorado:
24 Propert 1,901,000 1,719,136 1,820,136
25 Income 44,000 70 -43,930
26 Subtotal 1,901,000 44,000 1,719,206 1,776,206
27
28 Idaho:
29 Property 2,056,753 4,738,233 4,155,558
30 Income 343,439 438,250 -1,228,209
31 KWh 15,012 26,822 28,158
32 Unemployment 733 ,95,862 94,680
33 Use 837 160,036 146,895
34 Subtotal 2,073,335 343,439 5,459,203 3,197,082
35
36 Montana:
37 Propert 1,399,991 3,275,197 3,042,627
38 Corporate License-Income -153,660 50 67,710
39 Unemployment 1,030 1,030
40 Energy License 33,362 269,226 238,722
41 TOTAL 46,747,021 258,675,803 -286,256,396 -191,003,416 -209,999
FERC FORM NO.1 (ED. 12-96)Page 262
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (I) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accunts 408.1 and 409.1
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utilty departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged tö 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 apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electnc Extraordinary Items . AdJustments to Ket.Other No.ACCO~m236)(Inc!. in Accunt 165)(Accunt 408.1,409.1)(Accunt 409.3)Earnings (Account 439)
(h)(i)ü)(k)(I)
1
13,589,884 352,792,763 -517,806,480 .'727,676 -3,514 .w 3
44,983 . . 4
162,786 !I "5
14,525,329 352,789,249 -517,806,480 72,678,929 6
.7
8
9
10
1,181,569 2,363,138 11
18,570 -14,946 ~1,181,569 18,570 2,348,192 41,300 13
14
15
2,103,347 --769 .. 17
110,746 39,367 ... IW: 18
3,282 w_ 19
973,724 1,150,173 20
977,775 110,746 3,292,887 476,514 21
22
23
1,800,000 1,678,036 ~-648 . 25
1,800,000 1,677,388 41,818 26
27
28
2,639,428 3,139,896 w 29
-1,323,020 197,088 .,:w.30
13,676 26,822 31
1,915 -32
13,978 .-33
2,668,997 -1,323,020 3,363,806 2,095,397 34
35
36
1,632,561 3,275,197 37
-86,000 -26,987 ~._ 39
63,866 269,226 40
48,804,714 355,776,477 -385,705,794 99,449,398 41
FERC FORM NO.1 (ED. 12-96)Page 263
Name of Respondent This f!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) EiA Resubmission 04/18/2011
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taes charged to operations and other accounts during
the year. Do not include gasoline and other sales taes which have been charged. to the accunts 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, taes 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 taes.
3. Include in column (d) taxes charged during the year, taes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to currnt year, and (c) taes paid and charged direct to operations or accounts other than
accrued and prepaid ta accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
i..ine Kind of Tax BALANCE AT BEGINNING OF YEA c1les 1~~faS Adjust-argeNo.(See instruction 5)T axes Accruer:Prepai_d Taxes ~'17g ~e~7g ments
(Accunt 236)(Include in Accunt 165)
(a)(b)(c)(d)(e)(f)
1 Wholesale Energy 23,788 191,815 170,097
2 Subtotal 1,457,141 -153,660 3,737,318 3,520,186
3
4 New Mexico:
5 Propert 8,398 8,398
6 Income 50 50
7 Subtotal 8,448 8,448
8
9 Oregon:
10 Propert 9,620,711 20,348,226 21,470.885
11 Unemployment 38,519 1,841,356 1,829,441
12 Wilsonvile Payroll 288 799 827
13 Excise-Income 922,587 -1,761,300 -2,006,049
14 City of Portland-Income 1,000 -1,679 ~3, 149
15 Department of Energy 357,44 722,590 1,445,179
16 Tri-Met 351,459 863,452 870,961
17 Lane County .1,872 1,872
. 18 Franchise 4,195,671 22,210,008 22,246,753
19 Subtotal 4,943,381 10,544,298 44,225,324 45,856,720
20 .
21 Utah:
22 Propert 398,350 52,353.573 52,281,027
23 Income 3,684,204 -300,165 -11,503,320
24 Unemployment 52,150 203,52 252,986
25 Navajo Nation 804 804
26 Salt Lake Valley Law Enforc 648 648
27 Use 314,915 4,958,116 4,731,43
28 Subtotal 765,415 3,684,204 57,216,518 45,763,588
29
30 Washington:
31 Propert 6,787,000 9,165,928 7,252,928
32 Unemployment 2,611 128,956 125,303
33 Business & Occupation .4,998 33,252 34,870
34 Public Utilty 1,675,000 9,832,285 10,447,279
35 Natural Gas Use Tax 449,559 1,990,456 2,324,198
36 Use 38,923 394,687 385,391
37 Franchise 91,260 91,260
38 Land Tax 63 63
39 Subtotal 8,958,091 21,636,887 20,661,292
40
41 TOTAL 46,747,021 258,675,803 -286,256,396 -191,003,416 -209.999
FERC FORM NO.1 (ED. 12-96)Page 262.1
Name of Respondent This Report Is:Date of Report Year/Periód of Report
PacifiCorp (1) ~An Original (Mo,Da, Yr)End of 2010/Q4
(2) CiA Resubmission .04/18/2011
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 ta year, identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittl of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accunts 408.1 and 409.1
pertining 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 and 409.2. Also shown in column (I) the taxes charged to utilty plant or other balance sheet accounts.
9. For any tax apportoned to more than one utilty department or accunt, state in a footnote tlie basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Exraordinary Items AdjUstments to Ket.Other No.
ACCO~~~ 236)(Inc!. in Account 165)(Account 408.1,409.1)(Account 409.3)Earnings (Accunt 439)
(h)(i)ü)(k)(I)
45,506 191,815 1
1,741,933 -86,000 3,709,251 28,067 2
3
4
.8,398 5
-195 .~8,203 245 .7
..8
9
10,743,370 19,830,171 Wi 10
50,434 Wi 11
260 .12
677,838 -3,555,890 .13
-470 -2,433 .14
365,145 722,590 15
343,950 ..16.17
4,158,926 22,210,008 18
4,553,570 11,785,883 39,204,446 5,020,878 19
20
21
470,896 45,297,821 ~.22
-7,518,951 -1,988,229 w 23
2,706 . 24
804 25
648 ~541,588 ". 27
1,015,190 -7,518,951 43,311,044 13,905,474 28
29
30
8,700,000 8,922,538 31
6,264 32
3,380 31,331 ...i!'33"
1,060,006 9,832,285 34
115,817 mry.35
48,219 -"" ;r 36.
91,260 37
63 38
9,933,686 18,877,477 2,759,410 39
40
48,804,714 355,776,477 -385,705,794 99,449,398 41
FERC FORM NO.1 (ED. 12-96)Page 263.1
.. Name of Respörident This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of ..2010/Q4
(2) DA Resubmission 04/18/2011
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued ta accounts and show the total taes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final 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 accunts through (a) accrals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to currnt year, and (c) taes paid and chargeid 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 ascertained.
L.ine Kind ofTax BALANCE AT BEGINNING OF YEAR ~~xes le~~S Adjust-C argedNo.(See instruction 5)Taxes Accrued ~repaid Taxes ~ei~g ~ring ments
(Accunt 236)(Include in Account 165)ear
(a)(b)(c)(d)(e)(f)
1 Wyoming:
2 Propert 6,544,398 13,744,851 13,099,632
3 Unemployment 2,001 551,149 544,675 ..
4 Franchise 239,100 1,567,954 1,560,054
5 Use 111,294 1,490,853 1,462,238
6 Annual Report 93,853 93,853
7 Subtotal 6,896,793 17,448,660 16,760,452 -1,263
8 ~
9 State Other 1,899,175 903,287
10
11 Miscellaneous:
12 Goshute Possessory 15,079 15,079
13 Sho-Ban Possessory 151,097 151,097
14 Navajo Possessory 18,002 35,877 35,940
15 Ute Possessory 27,349 27,349
16 Crow Possessory 63,720 63,720
17 Umatila Possessory 64,289 64,289
18 Subtotal 1,917,177 1,260,698 357,474
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 46,747,021 258,675,803 -286,256,396 -191,003,416 -209,999
FERC FORM NO.1 (ED. 12-96)Page 262.2
Name of Respondent This 'mortiS:Date of Report Year/Period of Report
PacifiCorp (1) . An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/18/2011
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions.or otherwise pending
transmittl of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accunts 408.1 and 409.1
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utilty departments and
amounts charged to Accunts 408.2 and 409.2. Also shown in column (I) the taxes 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 accrued Prepaid 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)Earnings (Account 439)
(h)(i)u)(k)(I)
1
7,189,617 13,385,487 ~9,738 I~ ~. :
247,000 1,567,954 .
.
139,909 . 5
93,853 6
7,586,264 15,047,294 2,401,366 7
8
2,802,462 903,287 9
10
11
15,079 12
151,097 13
17,939 35,877 14
27,349 15
63,720 16
64,289 17
2,820,401 1,260,698 18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
48,804,714 355,776,477 -385,705,794 99,449,398 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) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
ro ess and fueL.
ro ess and fueL.
Taxes other than income taxes
Constrction
Distrbution expenses - rents
Total
ro ess and fueL.
Taxes other than income taxes
Constrction
Total
Taxes other than income taxes
Constrction
Total
$
ro ess and fueL.
Column: i
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
ro ess and fueL.
ess and fueL.
ess and fueL.
Taxes other than income taes
Fuel stock
Constrction
Total
TO ess and fueL.
Account
408.2
107
589
ro ess and fueL.
Line No.: 35 Column: i
Column: i
Taxes other than income taes
IFERC FORM NO.1 (ED. 12-87)
Column: i
Amount Account
$ 927 408.2
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 04/18/2011 2010/Q4
FOOTNOTE DATA
Constrction 346,998 107
Distrbution expenses - rents 11,439 589Total $ 359,364
!Šchedule Page: 262.2 Line No.: 3 Column: f
Recognition of January 1, 2010 balance for Pacific Minerals, Inc., which was consolidated for FERC reportg puroses on a
prospective basis beginning Januar 1,2010. Refer to Note 2 of Notes to Financial Statements within this FERC Form NO.1 for
fuer discussion.
Išchedule Page: 262.2 Line No.: 3 Column: i
Pa 011 taxes are enerall char ed to 0 erations and maintenance ex ense, constrction work in ro ess and fueL.
chedule Pa e: 262.2 Line No.: 5 Column: i
Charged to same account as related goods.
I FERC FORM NO.1 (ED. 12-87)Page 450.3
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
ACCUMULA ED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utilty and non utility
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 Accunt
No.SUbdl~\SionS of Year Deferred for Year Current Year's Income Adjustments
(b) ACCOUr:t NO. Amount ACCOUr:t NO. AmOUnt ( )(c) (d) (e) (f) 9
1 Electric Utilty
23%
34%
47%
510%37,000,901 ..1,808,76f
610%7,294,222 _. ~.1,624,45
7 Idaho 712,457 411.4 65,43€
8 TOTAL
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10
11
12
13 10%881,312 420 440,80a
14
15 Total Nonutilty 881,312 440,80a
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 266
Name of Respondent
PacifiCorp
ACCUMULATED D
Date of Report
(Mo, Da, Yr)
04/1812011
S (Accunt 255) (continued)
ADJUSTMENT EXPLANATION
Year/Period of Report
End of 2010/Q4
Line
No.
35,192,133
5,669,770
647,021
41,508,924
48.37
30
30
Í0jíf' 0 J?%7M.Ø~W_..IIIIII¡¡ 0,% .~øS. 0... ~//~ ); 0¥1¿ iR t¥Æ; sir%:
..~!t,i.~.diik0l4i;!lI.1I / ...Wi0g1:¿); 0'J,; 0/ //0 iI ;;;; 2?!ært¿
1
2
3
4
5
6
7
8
9
440,504 30
440,504
10
11
12
13
14
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
.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedulePage: 266 Line No.: 5 Column: e
Internal Revenue Code 46(£)2
¡SchedUle Page: 266 Line No.: 6 Column: e
Internal Revenue Code 46(£)1
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
OTHER DEFFERED CREDITS (Accunt 253)
1.Report below the particulars (details) called for concerning ~ther deferrd credits.
2.For any deferred credit being amortized, shoW the period of amortization.
3.Minor items (5% of the Balance End of Year for Accunt 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)
Accunt
(a)(c)(d)(e)(f)
1
2 Working Capital Deposits 3,410,54 974,570 4,385,114
3
4 Reclamation Costs - Trapper Mine 4,499,352 237,270 4,736,622
5
6 Reclamation Costs - Deseret Mine 534,826 131 7,300 527,526
7
8 Reclamation Costs - Trail
9 Mountain Mine 1,090,948 131 3,450 1,087,498
10
11 Deferred Compensation Plan 9,791,441 232, 241,920 2,177,184 2,192,142 9,806,399
12
13 -::( % m,w,WdØw/-m ,-Ø-w.
14 Obligation 232 279,264 9,403,264 i:,124,000
15
16 Transmission ServiCe Deposits 1,893,375 232, 235,456 3,937,100 4,356,275 2,312,550
17
18 MCI F.O.G. wire lease 557,783 454 3,350,037 3,350,705 558,451
19 .
20 Redding Contract (20)3,300,076 456 549,996 2,750,080
21
22 Foote Creek Contract (15)705,302 142 137,640 567,662
23
24 Environmental Liabilities 6,928,295 -;4,379,701 6,840,546 9,389,140.I~ .
25
26 Unearned Joint Use Pole Contact 3,342,497 454 8,295,047 8,315,400 3,362,850
27
28 Deferred Revenue -
29 Hermiston Gas Settlement (5)1,163,710 547,555 754,839 408,871
30
31 Transmission Security Deposits 1,550,000 107, 142,232 1,308,253 1,208,253 1,450,000
32
33 Other deferred credits with
34 balances less than $500,000 1,389,331 various 364,069 1,025,262
35
36
37
38
39 .
40
41
42
43
44
45
46
47 TOTAL 40,157,480 25,543,880 36,878,425 51,492,025
FERC FORM NO.1 (ED. 12-94)Page 269
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubm,ission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 269 Line No.: 13 Column: a
This account was reclassified from FERC account 232 durng the fourh quarer of2010. The amount in colum (d) represents
activi since the transfer date.
Schedule Pa e: 269 Line No.: 24 Column: c
Account 182.3 -Other regulatory assets
Account232 - Accounts payable
Account 557 - Other expenses
Account 923 - Outside services employed
ilFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ItAn Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Accunt 281)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to amortizable
propert.
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line
No.
Account Balance at
Beginning of Year Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Accunt 411.1
(d)(a)
1 Accelerated Amortization (Account 281 )
2 Electric
3 Defense Facilties
4 Pollution Control Facilties
5 Other (provide details in footnote):
6
7
8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilties
11 Pollution Control Facilties
12 Other (provide details in footnote):
13
14
15 TOTAL Gas (Enter Total of lines 10 thru 14)
16
17 TOTAL (Acct 281) (Total of 8,15 and 16)
18 Classification of TOTAL
19 Federal Income Tax
20 State Income Tax
21 Local Income Tax
(b)1:%" / /ial¡~ 05I~ J /,1".
rill" / We / ct.\( ,."i//"" iBw /""J!-': 0..10i....."'14l~:.% ;;:;;;; ;; JjJf;; Jf;; f ";7 ~g;;i0 dtJf ffWiM y "" 0"
13,316,552 1,673,844
13,316,552 1,673,844
13,316,552 1,673,844/~" ,%I;e~.".fMlP"".%I
;?/; ;;;; ;; /:#_1 /:¿~/: .y .;L/~i~~w r.
NOTES
FERC FORM NO.1 (ED. 12-96)Page 272
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
ACCUMULATED DEFERRED INCOME TAXES _ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.2 to Account 411.2
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.
Debits
~~_0;1!V¿"_ !__¿.,~j)ff.
1
2
3
11,642,708 4
5
6
7
11,642,708 8
9
10
11
12
13
14
15
16
11,642,708 17.!.~_~~~'-im;;iØlk¿.%_
19
20
21
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 273
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report(1) ~An Onginal (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
ACCUMULATED 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 property not
subject to acclerated amortization
2. For other (Specify),include deferrls 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
5 TOTAL (Enter Total of lines 2 thru 4)
6 Nonutilty
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 Local Income Tax
- ii, 7jK~ 7......iiiI..dPl."' /ß IfI¡¡if ø;& ~ lfPA dWJJ4WWC stn
2,801,783,463 1,074,973,139 400,329,543
2,801,783,463
871,716
1,074,973,139 400,329,543
2,802,655,179 1,074,973,139 400,329,543~.7ii.W...~!' // 77.........~~ .-..7 - /i1 ~ %i % % iiÆ ø:m xlf3i¡:jj/' /-
2,467,379,311
335,275,868
946.376,315
128,596,824
352,438,944
47,890,599
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This Report Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Accunt 410.2 to Account 411.2
ADJUSTMENTS
Amount
Balance at
End öfYear
Line
No.
Debits
3,330,234,891
3,330,234,891
j¡çí.......~r..." '0'-F"'- - ~ ii=-~ - ilX$ß!l( ";l0!~!r~..."""....."..0Y ;!i!WiI.ií -- WM'ii~- 0 r.... 77ii'..........~~ W#0'..".. .....Æ'.;ø~.¡:lkiz.1 .. ~..?jYi..:_17%al;zt~z%"1 .. 0~'!'"
9,55
1,29
776,98
105,57
152,726,60
20,753,00
24,023,10
3,264,341
2,931,845,74 11
398,389,14 12
13
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 275
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 274 Line No.: 2 Column: g
As of December 31, 2010, $170 milion was reclassified from account 282 Accumulated deferred income taes - other propert to
account 283 Accumulated deferred income taxes - other in order to conform to the curent year presentation. As a result of the
reclassification, accumulated deferred income ta liabilities generted by the gross up for revenue requirement on propert-related
timing differences for which the benefits were previously flowed though to customers and that will be included in rates when the
timing differences reverse are included in account 283, such that account 282 includes only accumulated deferred income tax
liabilities that result directly from propert-related tig differnces.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This Report Is: Date of Report
(1) I2An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Accunt 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.
(a)
Balance at
Beginning of Year
(b)
Line
No.
Account
1 Account 283
2 Electric
3 Regulatory Assets
4
5
416,262,076 51,931,202 65,065,028
6 Other Deferred Liabilties 34,637,390 2,227,685 6,070,503
7
8
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
11
12
13
14
15
16
450,899,466 54,158,887 71,135,531
rr '".læ ytf%'æ ; i~T~!I.r ""ïí.....' .'cr........i..*;,.Vf.AwM; 0.~ Æ2W.7?Æ0'" .."~i?:. "%
17 TOTAL Gas (Total of lines 11 thru 16)
18
19 TOTAL (Acct283) (Enter Total of lines 9,17 and 18)
20 Classification of TOTAL
21 Federal Income Tax
22 State Income Tax
23 Local Income Tax
450,899,466 54,158,887 71,135,531
I.. :.1 "'" ,~C '"" "'y'.....0. .""..............Ii..'0..'::"t:...r....ffi ;;~.Ø%4 ;;/;; ¿;::il% ;; . ø ~ _Ji N:f~ ;m f% "';; wJif :m
396,958,249
53,941,217
47,679,971
6,478,916
62,625,734
8,509,797
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
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 Accunt 410.2 to Accunt 411.2
ADJUSTMENTS
Balanc~ at
End of Year
(k)
Line
No.
190 325,743190 372;360
1
2
3
4
5
30,841,189 6
7
8
680,518,898 9
o
11
12
13
14
15
16
17
18
680,518,898 19
56,437,118 10,898,320 16,474,935 217,532,213~%ll'_"'~~ / ~ 1% / 0/~¡lI;£"~
56,437,118 10,898,320 16,474,935 217,532,213
"/fi¿/JJ~~/Ø/,t~E%.;jj;~ /ž '..,.~~£¡r:~
49,685,662
6,751,456
9,594,577
1,303,743
14,504,072
1,970,863
191,509,282
26,022,931
599,108,781 21
81,410,117 22
23
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) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA .
¡Schedule Page: 276 Line No.: 3 Column: g
Account 182.3 - Other regulatory assets
Account 283 - Accumulated deferred income taes - Other
Account 254 - Other regulatory liabilities
I§chedule Page: 276 Line No.: 3 Column: i
Account 182.3 - Other regulatory assets
Account 190 ~ Accumulated deferred income taxes
Account 282 - Accumulated deferred income taes - Other propert
Account 283 - Accumulated deferred income taxes - Other
As of December 31, 2010, $170 milion was reclassified from account 282 Accumulated deferred income taxes - other propert to
account 283 Accumulated deferred income taxes - other in order to conform to the curent year presentation. As a result of the
reclassification, accumulated deferred income tax liabilities generated by the gross up for revenue requirement on propert-related
timing differences for which the benefits were previously flowed though to customers and that will be included inrates when the
timing differences reverse are included in account 283, such that account 282 includes only accumulated deferred income ta
liabilities that result diectly from propert-related timing differences.
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 2010/04
(2) OA Resubmission 04/18/2011
OTHER REGULATORY LIABILITIES (Accunt 254)
1. Report below the particulars (details) called for concerning other regulatory liabilties, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Accunt 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 amortization.
Balance at Begining DEBITS Balance at End
Line Description and Purpose of of Current of Current No.Other Regulatory Liabilties OuarterlYear ~ccunt Amount Credits OuarterlYearCreited
(a)(b)(c)(d)(e)(f)
1 Income Tax Regulatory Liabilty 20,359,32 190 1,013,976 19,345,346
2 Income Tax Reg. Liab. - WA Flow Through 876,62 1,549.811 2,426,440
3 Gain on Sale of Assets - OR 459,170 -.851,328 465,707 73,549
4 Gain on Sale of Assets. CA 45,03 421.41,279 3,755
5 Propert Insurance Reserve 109,56 228.1,924 109,564
6 SMUD Revenue Imputation (11)22,913,046 400,42 13,956,848 118,100 9,074,298
7 WA Rate Refund 228,659 142 228,728 69
8 Uth Home Energy Lifeline 413,856 142 4,165.060 3.954,566 203,362
9 BPA Washington Balancing Account 903,021 579,420 1,482.441
10 BPA Oregon Balancing Accunt 2,419,002 756,054 3,175.146
11 Asset Retirement Obligations Reg. Difference 4,409,486 230 259.882 257,947 4,407.551
12 Washington Low Income Program (35,188)142 967,554 1,208,791 206,049
13 Misc. Regulatory Liabilities - OR 211,435 182.3 176,623 157,812 192.624
14 Blue Sky- OR 378,243 456 1.077,654 1,326,346 626.935
15 BlueSky-WA 40,285 456 159,322 167,471 48,434
16 Blue Sky- CA 67,399 456 119,651 70,750 18,48
17 Blue Sky. UT 734,895 456 2,475,501 2,661,312 920,706
18 Blue Sky-ID 28,623 456 83,459 57,258 2,422
19 BlueSky-WY 76.129 456 220,683 199,539 54,985
20 OR Energy Conservation Charge 822.596 456 19,538,42 21,054,837 2,338,991
21 Deferred Arch Coal Settement (3)1,217,286 557 1,173,017 44,269
22 Renewable Energy Credit Sales Deferral . OR 3,922.178 3,922,178
23 Renewable Energy Credit Sales Deferrl - WY 3,594,057 3,594,057
24 Tax Revenue Requirement Adj. - UT 49.234 49,234
25 Regulatory Liabilty - Reclassifications 7.485,673 182.3 85,730 _.~
26
27
28
29 ..
30
31
32 .
33
34
35
36
37
38
39
40
41 TOTAL 64,164,255 46,704,301 42,151,259 59,611,213
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) LÇ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04118/2011 2010/Q4
FOOTNOTE DATA
I$chedule PaRe: 278 Line No.: 3 Column: c
Account 440, Residential sales
Account 442, Commercial and industral sales
Account 444, Public street and highway lightig
Account 431, Other interest expense
¡Schedule Page: 278 Line No.: 25 Column: f
The following schedule sumarizes regulatory liabilities reclassifications:
Reclassified from Regulatory Assets to Regulatory Liabilities:
DSM Regulatory Asset - CA
DSM Regulatory Asset - WY
Deferred Independent Evaluator Fee - UT
SB 408 Regulatory Asset - MCBIT
Year Ended
December 31, 2010
$3,193,591
4,000,836
16,501
189,015
7,399,943$
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This l!0rt Is:'Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) EiA Resubmission 04/18/2011
ELECTRIC OPERATING REVENUES (Account 400)
1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (t), ana (g). Un biled revenues and MWH
related to unbiled revenues need not be reported separately as required in the annual version of these pages.
2. Report below operating revenues for. each prescribed account, and manufactured gas revenues in tota.
3. Report number of customers, columns (t) and (g), on the basis of meters, in addition to the number of flat rate accunts; except that whre separate meter readings are
added for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the
close of each month.
4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
50 Disclose amounts of $250,000 or greater in a footnote for accounts 451,456, and 457.2.
Line Title of Account Operating Revenues Year Operating Revenues
No.to Date Quarterly/Annual Previous year (no Quarterly)
(a)(b (c)
1 Sales of Electricity
2 (440) Residential Sales 1,357,826,906 1,346,519,773
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)1,146,322,741 1,120,956,943
5 Large (or Ind.) (See Instr. 4)1,030,052,681 976,991,304
6 (444) Public Street and Highway Lighting 20,610,361 20,913,398
7 (445) Other Sales to Public Authorities 19,770,416 19,032,148
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers 3,574,5831105 3,484,413,566
11 (447) Sales for Resale 501,563,210 643,321,157
12 TOTAL Sales of Electricity 4,076,146,315 4,127,734,723
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Prov: forRefunds 4,076,146,315 4,127,734,723
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues ,.~ .~ /.6,908,893"";¡
18 (453) Sales of Water and Water Power 2,609 12,154
19 (454) Rent from Electric Propert 19,559,096 19,158,931
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues 128,935,328
22 (456.1) Revenues from Transmission of Electricity of Others 67,812,115 63,697,983
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 326,069,070 226,031,657
27 TOTAL Electric Operating Revenues ~~4,353,766,380
FERC FORM NO, 1/3-Q (REV. 12-05)Page 300
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
ELECTRIC OPERATING REVENUES (Account 400)
6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by
the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accunts. Explain basis of
classification in a footnote.)
7. See pages 108-109, Importnt Changes During Period, for important new territory added and important rate increase or decreases.
8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbiled revenue by accunts.
9. Include unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD
Year to Date Quarterly/Annual Amount Previous year (no Quarterty)
(e)
AVG.NO. CUSTOMERS PER MONTH
Current Year (no Quarterly)
(f)
Line
No.
15,969,253 16,194,257 220,171 213,730 4
20,679,453 19,934,268 33,854 34,070 5
145,032 144,765 3,868 3,948 6
427,352 437,595 13 13 7
8
9
53,015,534 52,709,525 1,732,815 1,718,485
11,414,592 12,349,061
64,430,126 65,058,586 1,732,815 1,718,85
13
64,430,126 65,058,586 1,732,815 1,718,485 14
Line 12,column (b) includes $
Line 12, column (d) includes
205,559,000 of unbiled revenues.
3,209,886 MWH relating to un biled 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 (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 300 Line No.: 11 Column: f
For a complete list of the number of customers see pages 310-311 Sales for Resale of this Form NO.1.
I$chedule Page: 300 Line No.: 11 Column: g
For a complete list of the number of customers see pages 310-311 Sales for Resale of this Form NO.1.
I$chedule Page: 300 Line No.: 17 Column: b
(451) Miscellaneous Service Revenues include the following items that were $250,000 or greater for the years ended December 31:
Account service charge - disconnects/reconnects/retued check charges
Customer contract flat rate bilin s
chedule Pa e: 300 Line No.: 21 Column: b
(456) Other Electrc Revenues include the following items that were $250,000 or greater for the years ended December 31:
$
2010
4,070,201
1,756,340
2009
$ 4,609,636
2,188,111
Demand-side management revenue
Renewable energy credit sales, net of deferrals
Energy exchange credits
Wind-based ancilar services
Steam sales
Blue Sky revenue
Flyashly-product sales
Power sale and exchange agreements
Revenue from generation interconnection and transmission service request studies
Phase shifting equipment fee from Western Electrcity Coordinatig Counsel
Maintenance charges for work on transmission facilties
Net profit on sales of materials and supplies inventory
2010 2009
$100,095,141 $50,259,795
93,760,900 50,793,765
7,822,254 8,415,849
~,281,432 7,216,814
5,719,969 4,857,715
4,167,040
2,658,821 3,238,868
1,091,292 1,091,292
991,746 840,474
455,941 1,271,449
494,787 423,133
- (a)361,448
(a) The curent year amount is less than $250,000.
I$chedule Page: 300 Line No.: 27 Column: b
A reconciliation of operating electrc revenues for the year ended December 31,2010 is as follows:
Sales of Electricity
Residential Sales - Account (440)
Commercial and Industral Sales - Account (442)
Small (Commercial)
Large (Industral)
Public Street and Highway Ughting - Account (444)
Other Sales to Public Authorities - Account (445)
Sales to Railroads and Railways - Account (446)
Interdeparental Sales - Account (448)
Page 300 Page 304 Variance
$1,357,826,906 $1,357,826,906 $
1,146,322,741 1,146,322,741
1,030,052,681 1,030,052,681 -(a)
20,610,361 20,610,361
19,770,416 19,770,416
Total Sales to Ultimate Consumers 3,574,583,105 3,574,583,105
Sales for Resale - Account (447)501,563,210 501,563,210 (b)
Total Sales of Electrcity 4,076,146,315 3,574,583,105 501,563,210
(Less) Provision for Rate Refunds - Account (449.1)
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 04/18/2011 2010/Q4
FOOTNOTE DATA
Total Revenues Net of Provisions for Refuds 4,076,146,315 3,574,583,105 501,563,210
Other Operating Revennes
Forfeited Discounts - Account (450)7,411,888 7,411,888
Miscellaneous Service Revenues - Account (451)5,919,271 5,919,271
Sales of Water and Water Power - Account (453)2,609 2,609
Rent from Electrc Propert - Account (454)19,559,096 19,559,096
Interdeparental Rents - Account (455)
Other Electrc Revenues- Account (456)225,364,091 220,074,820 5,289,271 (c)
Revenues from Transmission of Electrcity of Others (456.1)67,812,115 67,812,115 (b)
Total Operating Revenues $4,402,215,385 $3,827,550,789 $574,664,596
(a) The large industral line on page 300 includes industral sales of $943,745,752 and irgation sales of $86,306,929.
(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 tlis Form No. 1.
(c) The varance in Other Electrc Revenues-Account (456) for the year ended December 31,2010 is asfollows:
Page 300 Page 304 Variance
Steam Sales $5,719,969 $$5,719,969
Materials and Supplies Inventory Cost of Sales (430,698)(430,698)
Other Electrc Revenues - Account (456)220,074,820 220,074,820
Total Other Electrc Revenues - Account (456)$225,364,091 $220,074,820 $5,289,271
I$chedule Page: 300 Line No.: 1 Column: $
The followig is a reconciliation of the unbiled revenue accrual at December 31, 2010 and the reversal of the December 31, 2009
unbiled revenue accrual.
December 31, 2010 unbiled revenue accrual
December 31, 2009 unbiled revenue accrual reversal
Change in unbiled revenue accrual
$205,559,000
(213,989,000)
(8,430,000)$
¡Schedule Page: 300 Line No.: 1 Column: MWH
The following is a reconciliation of the unbiled MWh accrual at December 31, 2010 and the reversal of the December 31, 2009
unbiled MW accrual.
December 31, 2010 unbiled MW accrul
December 31, 2009 unbiled MW accrual reversal
Change in unbiled MWh accrual
3,209,886
(3,380,278)
(170,392)
IFERC FORM NO.1 (ED. 12-87)Page 450.2
.
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule 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 sequence followed in "Electric Operating Revenues, n 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 rendere 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 additonal revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
..ine Numoer ana ime or Kate scneauie Mvvn ;:010 M:evenue l\verage l'IUmDer i:wn.oT t;aies K~n'ser:er
No.of c~~)omers Per l~stomer hold
(a)(b)(c).(f)
1 RESIDENTIAL SALES
2 CALIFORNIA
3 06CHCKOOOR-CARES CHECK M 1
4 06LNX00109-REF/NREF ADV+-40
5 06NETMT135-CA RES NET 266 30,174 29 9,172 0.1134
6060AL T015R-OUTD AR LGT SR 339 72,752 368 921 0.2146
7 06RESDOOOD-RES SRVC 196,737 21,997,535 18,812 10,458 0.1118
8 06RESDDL06-CA LOW INCOME 109,576 12,158,912 9,459 11,584 0.1110
9 06RESDDM9M-MUL TIFAMILY 60 6,498 6 10,000 0.1083
10 06RESDODM9-MUL TI FAMILY 178 19,082 8 22,250 0.1072
11 06RESDDS8M-MUL T FAM SBMET 866 77,940 15 57,733 0.0900
12 06RESDDS8M-MUL T FAM SBMET 626 60,969 15 41,733 0.0974
13 REVENUE ADJ. - DEFERRED NPC 1,259,052
14 REV. ACCOUNTING ADJ.-1,024,881
15 SMUD REVENUE IMPUTATIONS 44,729
16 06RESDOODN - CA RES SRVC -96,864 10,717,286 7,463 12,979 0.1106
17 UNBILLED REVENUE -2,551 -399,000 0.1564
18 IDAHO
19 07LNX00010.MNTHL Y 80%GUAR 1,192
20 07LNX00035-ADV 80%MO GUAR 1,520
21 07NETMT135 -10 RESIDENTIAL 1,054 84,42 59 17,864 0.0801
22 070ALC0007-CUST OWN LIGHT 10 3,704 1 10,000 0.3704
23 070ALT07AR-SECURITY AR LG 106 42,548 136 779 0.4014
24 07RESD0001-RES SRVC 423,071 38,736,381 42,306 10,000 0.0916
25 07RESD0001-RES SRVC 6
26 07RESD0036-RES SRVC-OPTIO 284,972 21,122,790 14,789 19,269 0.0741
27 07RESD0036-RES SRVC-OPTIO -2
28 BPA BALANCING ACCOUNT 1,640,993
29 07ZZMERGCR-MERGER CREDITS 1
30 UNBILLED REV - UNCOLLECTIBLE 3,000
31 SMUD REVENUE IMPUTATIONS 74,932
32 UNBILLED REVENUE -4,086 -200,000 0.0489
33 OREGON
34 01CHCKOOOR-RES CHECK MTR 1
35 01COST0004 - 01RESDOOO4 5,240,762 239,182,779 0.0456
36 01 FXRENEWR - Fx Rnw Blue Sky -1
37 01 HABIT004 - 01 RESDOO04 43,891 1,951,428 0.0445
38 01 LNX001 02-lINE EXT 80% G 17,436
39 01 LNX001 05-CNTRCT $ MIN G 42
40 01 LNX001 09-REF/NREF ADV +3,016
41 TOTAL Biled -. !J 1,732,81~30,69 0.0721
42 Total Unbiled Rev.(See Instr. 6)-170,39. "C (0.049~
43 TOTAL 53,015,53~ 3,827,550,78 1,732,81"30,59~O.O72~
FERC FORM NO.1 (ED. 12-95)Page 304
Name of Respondent This !!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/18/2011
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 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 accunt subheading.
ine Numoer ana ime or Kate scneauie Mwn ~oia M:evenue ..verage NumDer ~vvn_OT ~aies M:~~~'$i~er
No.(a)(b)(c)of cu(~)omers Per r~stomer
(f)
1 01NETMT135-NET METERING 404,935 938
2 01NETMT135-NET METERING -40,917
3 01NMTOU135-TOU NET METR 1,707 7
4 01NMTOU135-TOU NET BPA -172
5 010ALT014R-OUTD AR LGT RE 2,480 392,792 2,873 863 0.1584
6 010AL T014R-OUTD AR LGT RE -12,192
7 01 PTOU0004 - 01 RESDOO04 20,792 965,659 0.0464
8 01 RENEW004 - 01 RESDOO04 202,590 8,902,861 0,0439
9 01 RESD0004-RES SRVC 243,376,697 472,158
10 01 RESD0004-RES SRVC -25,696,576
11 01RESD0013-3 PHASE RES SR -18
12 01 RESD004T - RES Time Option 893,181 1,363
13 01 RESD004T - RES Time Opt BPA -97,264
14 01 UPPLOOOR-BASE SCH FALL 4
15 01VIR04136-0R RES VOL INCTV 3,194 19
16 01VIR04136-0R RES VOL INCTV -344
17 BPA BALANCING ACCOUNT -774,369
18 OR GAIN ON SALE OF ASSET 330,826
19 OR SB408 RECOVERY 717,937 .
20 OR SB838 RECOVERY -2,139,500
21 REV. ACCOUNTING ADJ.-24,768
22 SMUD REVENUE IMPUTATIONS 560,635
23 UNBILLED REV - UNCOLLECTIBLE 12,000
24 UNBILLED REVENUE -58,075 -3,992,000 0.0687
25 UTAH
26 08BLSKY01 R-BLUESKY ENERGY -2
27 08CFR00001-MTH FACILITY S 1,265
28 08CHCKOOOR-UT RES CHECK M 1
29 08COOLKPRR-Utah Cool Keeper 90,971
30 08LNX00001-MTHL Y 80% GUAR 3,120
31 08LNX00005- MNTHL Y MIN GUAR 949
32 08LNX00013-80% MTHL Y MIN 30,115
33 08LNX00016-80% annual gty 605
34 08LNX00108-ANN COST MTHL Y 2,604
35 08MHTP0025-MOBILE HOME &12,092 870,739 11 1,099,273 0.0720
36 08NETMT135 - Net Metering 4,538 397,868 571 7,947 0.0877
37 080AL T007R-SECURITY AR LG 2,803 791,092 3,084 909 0.2822
38 08PTLDOOOR-POST TOP LIGHT 2 125 3 667 0.0625
39 08RESD0001-RES SRVC 6,292,269 553,304,441 670,049 9,391 0.0879
40 08RESD0002-RES SRVC-OPTIO 3,069 264,693 352 8,719 0.0862
41 TOTAL Biled ~1,732,81!30,69 0.0721
42 Total Unbiled Rev.(See Instr. 6)-170,39" _ 0 ((O.049~
43 TOTAL 53,015,53 3,827,550,789 1,732,81!30,59~0.072,
FERC FORM NO.1 (ED. 12-95)Page 304.1
c
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifCorp (1) l2An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule 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 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 ina 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 ano ime OT ~aie scneouie Mvvn ;:010 ~evenue Average Numoer --h of Sales ~~~~'s~lderNo.(a)(b).(c)ofC~~omers Per ?~iromer
(f)
1 08RESD0003-L1FELINE PRGRM 257,58€22,409,951 31,622 8,146 0.0870
2 08RESD0150-RES ALL E NOT5 -4
3 08UPPLOOOR-BASE SCH FALL 4
4 REV. ACCOUNTING ADJ.5,572,698
5 SMUD REVENUE IMPUTATIONS 3,386,349
6 UNBILLED REV - UNCOLLECTIBLE -19,000
7 UNBILLED REVENUE -23,209 -1,558,000 0.0671
8 WASHINGTON
9 02NETMT135 - WA RES NET MTR 320 26,121 15 21,333 0.0816
10 02NETMT135 - WA RES NET BPA -1,417
11 020ALTB15R-WA OUTD AR LGT 1,102 156,939 1,184 931 0.1424
12 020ALTB15R-OUTD AR LGT BPA -4,930
13 02RESD0016-WA RES SRVC 1,529,247 116,774,628 99,824 15,319 0.0764
14 02RESD0016-WA RES SRVC -6,774,259
15 02RESD0017 -BILL ASSISTANCE 63,121 4,810,129 3,977 15,872 0.0762
16 02RESD0017-BILL ASSISTANCE -279,723
17 02RESD0018-WA 3 PHASE RES 2,437 204,156 89 27,382 0.0838
18 02RESD0018-WA 3 PHASE RES -10,829
19 02RESD018X-WA 3 PHASE RES 516 42,442 22 23,455 0.0823
20 02RESD018X-WA 3 PHASE RES -2,287
21 02RFNDCENT - CENTRALIA RFND 2
22 02ZMERGCR-MERGER CREDITS 2
23 ACQUISITION COMMIT-A&G CR -43
24 BPA BALANCING ACCOUNT -542,831
25 REV. ACCOUNTING ADJ.-3,928,254
26 SMUD REVENUE IMPUTATIONS 158,816
27 WA - CHEHALIS DEFERRAL -1,320,000
28 UNBILLED REV - UNCOLLECTIBLE -8,000
29 UNBILLED REVENUE 24,434 2,323,000 0.0951
30 WYOMING
31 05BLSKY01 R-BLUE SKY ENERGY -1
32 05LNX00102-L1NE EXT 80% G 152
33 05LNX00109-REF/NREF ADV +129
34 05NETMT135-EXPERIMENTAL 910 76,631 67 13,582 0.0842
35 050AL T015R-OUTD AR LGT SR 930 135,210 1,092 852 0.1454
36 05RESD0002-WY RES SRVC 925,080 77385,266 96,607 9,576 0.0837
37 05RESD018X-RES 3 PHASE SR 11 935 1 11,000 0.0850
38 REV. ACCOUNTING ADJ.16,692
39 SMUD REVENUE IMPUTATIONS 83,234
40 UNBILLED REV - UNCOLLECTIBLE -11,000
41 TOTAL Biled ~1,732,81E 30,69 0.0721
42 Total Unbiled Rev.(See Instr. 6)
53~~:~:~~ "~7,550,78:
((O.049~
43 TOTAL 1,732,81E 30,59f 0.072"
FERC FORM NO.1 (ED. 12-95)Page 304.2
Name of Resp6ndent This (!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/18/2011 .
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 number of bils rendered during the year divided by the number of biling periods during the year (12 if
all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue 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 ,"aie SCneaule ivivvn .,010 ,"evenue l\veragi~~UmDer ~vvn_or ò?aies K~n'seter
No.of cu(~ omers Per '(à\stomer hold
(a)(b)(c)(f)
1 UNBILLED REVENUE 3,889 454,000 0.1167
2 05RËSD0002-WY RES SRVC 132,092 11,040,106 12,608 10,477 0.0836
3 090AL T207R-SECURITY AR LG 78 23,901 92 848 0.3064
4 05NETMT135 - EXPERIMENTAL 205 16,519 10 20,500 0.0806
509RESOO02 2
6 09RESDOO02 -10 -657 4 -2,500 0.0657
7 UNBILLED REVENUE 404 51,000 0.1262
8 LESS MULTIPLE BILLINGS -108,183
9
10 TOTAL RESIDENTIAL SALES 15,794,444 1,357,826,906 1,474,909 10,709 0.0860
11 .
12 COMMERCIAL SALES
13 CALIFORNIA
14 06CHCKOOON-CA NRES CHECK 1
15 06GNSV0025-CA GEN SRVC 58,364 7,902,097 6,854 8,515 0.1354
16 06GNSV025F-GEN SRVC-c: 20 938 141,832 92 10,196 0.1512
17 06GNSVOA32-GEN SRVC-20 KW 81,098 8,985,799 965 84,039 0.1108
18 06LGSV048T-LRG GEN SERV 66,219 4,638,318 13 5,093,769 0.0700
19 06LGSVOA36-LRG GEN SRVC-O 80,706 7,355,985 185 436,249 0.0911
20 06LNX00102-L1NE EXT 80% G 13,662
21 06LNX00105-CNTRCT $ MIN G 4,591
22 06LNX00109-REF/NREF ADV +68,238
23 06LNX00300-80% MTHL Y MIN GU 28,779
24 06LNX00311-L1NE EXT 80% GUAR 3,247
25 06NMT36135-CA GEN SVC NET 373 37,912 1 373,000 0.1016
26 060ALT015N-OUTD AR LGT SR 740 160,277 532 1,391 0.2166
27 06RCFL0042-AIRWAY & ATHLE 204 32,957 38 5,368 0.1616
28 06WHS31025-COMM WTR HEATI 1 125 28 36 0.1250
29 06WHSV0031-COMM WTR HEATI 201 23,108 28 7,179 0.1150
30 06NMT25135-GN SVC NETc:20K 33 4,084 1 33,000 0.1238
31 06NMT32135-GN SVC NET:.20K 296 32,856 2 148,000 0.1110
32 REVENUE ADJ. - DEFERRED NPC 915,488
33 REV. ACCOUNTING ADJ.-663,108
34 SMUD REVENUE IMPUTATIONS 33,005
35 06LNX0011 O-REF/NREF ADV +5,305
36 UNBILLED REVENUE -67 -74,000 1.1045
37 IDAHO
38 07CISH0019-COMM & IND SPA 6,348 437,576 123 51,610 0.0689
39 07GNSV0006-GEN SRVC-LRG P 191,906 12,705,424 947 202,646 0.0662
40 07GNSV0009-GEN SRVC-HI VO 40,080 1,865,169 1 40,080,000 0.0465
.
41 TOTAL Biled ~fi .mw 1,732,81 30,693 0.0721
42 Total Unbiled Rev.(See Instr. 6)-170,39 ~~_.%"",$,(C O.049~%
43 TOTAL 53,015,53~3,827,550,789 1,732,81'30,59~0.072..
FERC FORM NO.1 (ED. 12-95)Page 304.3
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission Q4/1812011
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electcit 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 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 scheduiè), the entries in column (d) for the special scedule 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 additonal 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 ivivvn ;:010 ~evenue l\verage I'lumoer ~vvn.oT ;;aies K~nise.r:er
No.of cu(~~omers Per r~stomer hold
(a)(b)(c)(f)
1 07GNSV0023-GEN SRVC-SML P 129,527 10,399,651 6,299 20,563 0.0803
2 07GNSV0035-GEN SRVCOPTION 515 29,333 2 257,500 0.0570
3 07GNSV006A-GEN SRVC-LRG P 30,126 2,088,256 203 148,404 0.0693
4 07GNSV023A-GEN SRVC-SML P 19,091 1,582,974 1,348 14,162 0.0829
5 07GNSV023F-GEN SRVC SML P 18 2,652 7 2,571 0.1473
6 07LNX00010-MNTHL Y 80%GUAR 6,302
7 07LNX00035-ADV 80%MO GUAR 334,092
8 07LNXOO040-ADV+REFCHG+80%68,273
9 070AL T007N-SECURITY AR LG 239 87,998 182 1,313 0.3682
10 070AL T07 AN-SECURITY AR LG 12 4,710 14 857 0.3925
11 07LNX00312-ID LINE EXT 3,069
12 07NMT23135-NET MTR-SM GEN 50 4,273 4 12,500 0.0855
13 07LNX00015-ANNUAL 80%GUAR 2,262
14 07LNX00311-L1NE EXT 80% GUAR 69,214
15 07LNX00020 -MTHL Y CONTRACT 278
16 07LNX00300-80% MTHL Y MIN GU 6,214
17 BPA BALANCING ACCOUNT 97,039
18 SMUD REVENUE IMPUTATIONS 45,218
19 UNBILLED REVENUE -23,780 -1,500,000 0.0631
20 OREGON
21 01 COST0023-0R GEN SRV-COST 968,227 44,159,121 0.0456
22 01 COST0048 - 01 LGSV0048 716,816 30,152,501 0.0421
23 01COST023F-OR GEN SRV-COST 3,059 147,959 0.0484
24 01 COSTB023-0R GEN SRV-COST 84,379 3,985,038 0.0472
25 01 COSTL030-0R LG GEN SRV 1,043,038 44,636,396 0.0428
26 01 COSTS028-0R GEN SRV -COST 1,913,017 88,237,991 0.0461
27 01 COSTS030-0R GEN SRV -CBS 432 15,272 0.0354
28 01 GNSB0023-BPA DISC-:30kW -399,778
29 01GNSB0023-0R GEN SRV -BPA 5,365,390 14,361
30 01GNSB0028-0R GEN SRV -BPA -585,975
31 01GNSB0028-0R GEN SRV -BPA 2,765,447 537
32 01GNSB023T-OR GEN SRV-TOU 25,212 52
33 01GNSB023T-OR GEN SRVC-TOU -2,360
34 01 GNSV0023-0R GEN SRV -:30kW 40,514,698 57,229
35 01GNSV0028-0R GEN SRV =-30kW 42,000,539 8,971
36 01GNSV023F-OR GEN SRV -FLAT 9,360 1,331,826 801 11,685 0.1423
37 01GNSV023M-OR GEN SRV -MANU 42 3,197 1 42,000 0.0761
38 01GNSV023T-OR GEN SRV-TOU 157,342 232
39 01HABT0023-0R HABITAT BLEND 2,378 109,892 0.0462
40 01HABTB023-0R HABITAT BLEND 209 9,845 0.0471
41 TOTAL Biled -.1,732,8H 30,69 0.0721
42 Total Unbiled Rev.(See Instr. 6)-170,39 " .((0.0495
43 TOTAL 53,015,53~3,827,550,789 1,732,81'30,59~O.072;¿
FERC FORM NO.1 (ED. 12-95)Page 304.4
Name of Respondent This Repòrt Is:Date of Report Year/Period of Report
PacifiCorp (1) ~An Original (Mo, Da, Yr)End of 2010/04
(2) EiA Resubmission 04/18/2011
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 accounf 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 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.
¡LIne Numoer ana ime or Kate scneauie Mvvn ::oia Kevenue Average Numoer . ~~~n?~sf;~;r KW~~~/der
No.(a)(b)(c)
of Cu(~~omers
(f)
1 01 LGSB0030cGEN DEL SRV ::200 -221,985
2 01LGSB0030-GENDEL SRV ::200 797,643 27
3 01 LGSV0030 - OR LRG GEN SRV, ::19,041,024 635
4 01LGSV0048-1000KW AND OVR 8,520,124 97
5 01 LGSV048M-LRG GEN SRVC 1 65,247 3,117,450 1 65,247,000 0.0478
6 01LNX00100-L1NE EXT 60% GUAR 4,918
7 01LNX00102-L1NE EXT 80% GUAR 486,323
8 01LNX00103-L1NE EX 80% GUAR 3,994
9 01LNX00105-CNTRCT $ MIN G 15,726
10 01 LNX00109-REF/NREF ADV +1,789,218
11 01LNX00110-REF/NREF ADV +8,502
12 01 LNX00120-L1NE EXT 60% GUAR 5,165
13 01 LNX00300-L1NE EXT 80% GUAR 124,916
14 01LNX00311-L1NE EXT 80% GUAR 111,367
15 01LNX00314-L1NE EXT 60% GUAR 5,717 .
16 01 LPRS047M-PART REO SRVC 11,335 961,860 3 3,778,333 0.0849
17 01NMT23135 - OR NET MTR, GEN,72,645 100
18 01NMT23135 - OR NET MTR, GEN,.-86
19 010ALT014N-OUTD AR LGT NR 1,555 255,017 1,155 1,346 0.1640
20 010AL T014N-OUTD AR LGT NR -7,588
21 010ALT015N-OUTD AR LGT NR 5,812 809,585 3,061 1,899 0.1393
22 01 PTOU0023, OR GEN SRV, TOU 3,563 163,149 0.0458
23 01PTOUB023, OR GEN SRV, TOU 534 24,295 0.0455
24 01 RCFL0054-REC FIELD LGT 1,087 101,517 104 10,452 0.0934
25 01 RENW0023, OR RENW USAGE 8,142 378,344 0.0465
26 01RENWB023 - OR RENEWABLE 479 23,120 0.0483
27 01 STDA Y023 - OR DAY STD OFR,2,037 126,970 0.0623
28 01STDAY028 - OR DAY STD OFF,7,10~431,998 0.0608
29 01STDAY030 - OR STD DAY OFF,4,350 256,620 0.0590
30 01VIR23136-0R VOLUME INCENTV 45 3
31 01VIR28136-0R VOLUME INCENTV 1,398 2
32 01ZZMERGCR-MERGER CREDITS -1
33 BPA BALANCING ACCOUNT -31,738
34 01 LGSB0048 - LG GEN SVC ::-14,577
35 01 LGSB0048 - LG GEN SVC ::49,026 1
36 01NMT28135 - OR NET MTR, GEN,204,692 41
37 01NMT30135 - OR NET MTR, GEN,246,217 10
38 01LGSV028M - OR LGSV, 0:1000 458 32,451 1 458,000 0.0709
39 01 GNSV030M - OR GEN SRV, 200 1,650 93,399 1 1,650,000 0.0566
40 01 GNSV0728 - OR GEN SVC DIR 255,071 8
41 TOTAL Biled ~1,732,8H 30,69~0.0721
42 Total Unbiled Rev.(See Instr. 6)-170,39 II ~. .((0.049~
43 TOTAL 53,015,53~ 3,827,550,789 1,732,8H 30,59~0.072.
FERC FORM NO.1 (ED. 12-95)Page 304.5
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/18/2011
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 accunt 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 fate schedule having a fuel adjustment clause state in a footnote the estimated additionl revenue biled pursuant thereto. .
6. Report amount of un biled revenue as of end of year for each applicable revenue accunt subheading.
!Une Numoer ana ime or Kate scneoUie Mwn ::010 Kevenue Average. Numoer ~wn_OT ;:aies KR~~is~lder
No.(a)(b)(c)
of C~~\omers Per r~stomer
(f)
1 01GNSV0730 -OR GEN SVC DIR 2,461,768 33
2 01GNSV0748 LG GEN SVC DIR 542,541 2
3 OR GAIN ON SALE OF ASSET 297,113
4 OR SB408 RECOVERY 628,755
5 OR SB 838 RECOVERY -1,592,366
6 REV. ACCOUNTING ADJ.-20,866
7 SMUD REVENUE IMPUTATIONS 496,288
8 UNBILLED REVENUE -63,458 -3,371,000 0.0531
9 UTAH
10 08CFR00051-MTH FAC SRVCHG 39,713
11 08CFR00052-ANN FAC SVCCHG 2
12 08COOLKPRN - Ale DIRECT LOAD 3,554
13 08GNSV0006-GEN SRVC-DISTR 4,771,840 330,746,047 10,914 437,222 0.0693
14 08GNSV0009-GEN SRVC-HI VO 267,105 12,837,629 25 10,684,200 0.0481
15 08GNSV0023-GEN SRVC-DISTR 1,251,393 103,757,349 72,903 17,165 0.0829
16 08GNSV006A-GEN SRVC-ENERG 196,244 18,643,401 1,760 111,502 0.0950
17 08GNSV006B-GEN SRVC-DEM&9,130 620,766 21 434,762 0.0680
18 08GNSV006M-MNL DIST VOL TG 3,463 204,018 7 494,714 0.0589
19 08GNSV009A-GEN SRVC HI VO 24,022 1,239,923 2 12,011,000 0.0516
20 08GNSV023F-GEN SRVC FIXED 1,388 160,765 130 10,677 0.1158
21 08GNSV023M-GNSV DIST VOLT 109 8,869 5 21,800 0.0814
22 08GNSV06AM-MNL ENERGY TOD 795 1
23 08GNSV06MN-GNSV DIST VOLT 26,380 1,726,284 446 59,148 0.0654
24 08LNX00002-MTHL Y 80% GUAR 545,339
25 08LNX00004-ANNUAL 80%GUAR 86,151
26 08LNX00006-FIXD MTHL Y MIN 1,816
27 08LNX00008-ANNUALMIN GUAR 12,167
28 08LNX00014-80% MIN MNTHL Y 2,073,877
29 08LNX00017 -ADV /REF&80%ANN 341,431
30 08LNX00158-ANNUALCOST MTH 34,209
31 08LNX00300 - LINE EXT 80% PLUS 124,444
32 08LNX00310 -IRR, 80% ANNUAL 3,758
33 08LNX00312 UT IRG LINE EXT 10,579
34 08NMT06135 - UT NET MTR, GEN,10,298 739,943 19 542,000 0.0719
35 08NMT08135 -NET METERING GEN 5,751 335,791 1 5,751,000 0.0584
36 08NMT23135 - UT NET MTR, GEN,1,022 85,836 51 20,039 0.0840
37 08NMT6A135-NET METERING GEN 19 3,108 1 19,000 0.1636
38 080AL T007N-SECURITY AR LG 8,639 1,983,135 4,499 1,920 0.2296
39 08POLE0075-POLES W/L1GHT 61 1
40 08PRSV031M-BKUP MNT&SUPPL 10,713 692,801 2 5,356,500 0.0647
41 TOTAL Biled 1,732,81E 30,69 0.0721'170,3Ø142Total Unbiled Rev.(See Instr. 6)I ((0.049f
43 TOTAL 53,015,53~ 3,827,550,789 1,732,81E 30,59f 0.072"
FERC FORM NO.1 (ED. 12-95)Page 304.6
Name of Respondent This 1!0rrls:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of . 2010/Q4
(2) FiA Resubmission 04/18/2011
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 "Electrc 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 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.
i.ine Numoer ana ime or Kate scneoUie Mwn ::oia Kevenue Average Numoer ~vvn_ or ::aies K~n~e~er
of Cu(~\omers Per r~stomer holdNo.(a)(b)(c)(f)
1 08PTLDOOON-POST TOP LIGHT 6 454 2 3,000 0.0757
2 08TOSS015F-TRAFFIC SIG NM 149 15,045 26 5,731 0.1010
3 08TOSS0015-TRAF & OTHER S 1,240 116,009 559 2,218 0.0936
4 08MONL0015-MTR OUTDONIGHT 14,397 1,008,800 371 38,806 0.0701
5 REV. ACCOUNTING ADJ.5,787,624
6 SMUD REVENUE IMPUTATIONS 3,895,349
7 08LNX00311 - LINE EXT 80%210,085
8 08GNSV0008 - UT GEN SVC TOU :;952,000 56,593,171 150 6,346,667 0.0594
9 08GNSV008M - UT GEN SVC TOU :;33,691 2,152,344 5 6,738,200 0.0639
10 UNBILLED REVENUE -5,703 327,000 -0.0573
11 WASHINGTON
12 02GNSB0024-WA GEN SRVC DO 40,251 3,327,361 3,179 12,662 .0,0827
13 02GNSB0024-WA GEN SRVC DO -177,594
14 02GNSB024F-GEN SRVC DOM/F 154 16,065 6 25,667 0.1043
15 02GNSB024F-GEN SRVC DOM/F -4
16 02GNSB24FP-WA GEN SVC 351 114,460 100 3,510 0.3261
17 02GNSB24FP-WA GEN SVC -1,558
18 02GNSV0024-WA GEN SRVC 467,368 35,405,704 14,411 32,431 0.0758
19 02GNSV024F-WA GEN SRVC-FL 1,115 124,826 112 9,955 0.1120
20 02LGSB0036-LRG GEN SVC IRG 82,828 5,227,389 98 845,184 0.0631
21 02LGSB0036-LRG GENSVC IRG -359,983
22 02LGSV0036-WA LRG GEN SRV 680,624 43,770,704 819 831,043 0.0643
23 02LGSV048T-LRG GEN SRVC 1 143,366 8,336,036 26 5,514,077 0.0581
24 02LNX00102-L1NE EXT 80% G 123,739
25 02LNXOÒ103-L1NE EXT 80% G 6,553
26 02LNX00105-CNTRCT $ MIN G 652
27 02LNX00109-REF/NREF ADV +390,446
28 02LNX00110-REF/NREF ADV +14,283
29 02LNX00112-YR INCURRED CH 669
30 02LNX00300-L1NE EXT 80% G 3,070
31 02LNX00310 - IRG, 80%ANNUAL 4,351
32 02LNX00311 - LINE EXT 80%26,159
33 02LNX00312 - WA IRG LINE EXT 2,769
34 020AL T015N-WA OUTD AR LGT 1,650 217,376 856 1,928 0.1317
35 020ALTB15N-WA OUTD AR LGT 603 85,036 523 1,153 0.1410
36 020ALTB15N-WA OUTD AR LGT -2,687
37 02RCFL0054-WA REC FIELD L 278 24,091 29 9,586 0.0867
38 02RFNDCENT - CENTRALIA RFND 175
39 02ZZMERGCR-MERGER CREDITS -23
40 02NMT24135, Net metering, WA 73 6,307 0.0864
41 TOTAL Biled ~1 ,732,81~30,69 0.0721, ,¡¡ ..,.
42 Total Unbiled Rev.(See Instr. 6)-170,39 '_""' ~((0.049
43 TOTAL 53,015,53 3,827,550,789 1,732,81f 30,59~0.072,
FERC FORM NO.1 (ED. 12-95)Pagé 304.7
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/18/2011
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 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 entries in column (d) for the special scedule 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 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 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 ime or Kate scneaUie Mvvn ~oia Kevenue lwerae Numoer ~vvn_oT :;aies t~~~B~ei-er
No.of Cu(~)omers Per 9~stomer hold
(a)(b)(c)(f)
1 02NMT36135-WA NET METER LRG 110 10,388 0.0944
2 ACQUISITION COMMIT-A&G CR -38
3 BPA BALANCING ACCOUNT -31,111
4 REV. ACCOUNTING ADJ.-3,090,281
5 SMUD REVENUE IMPUTATIONS 140,164
6 WA - CHEHALIS DEFERRAL -1,020,000
7 UNBILLED REVENUE -18,246 -924,000 0.0506
8 WYOMING
9 05CHCKOOON-WY NRES 1
10 05GNS28025-GEN SVC 31,513 2,237,603 1,767 17,834 0.0710
11 05GNSC0025 - WY SMALL 269 18,481 25 10,760 0.0687
12 05GNSV0025-WY GEN SRVC 155,755 13,027,409 16,346 9,529 0.0836
13 05GNSV0028-GEN SVC ::15 KW 922,357 66,652,138 4,044 228,080 0.0723
14 05GNSV025F-GEN SRVC-FL RA 974 132,395 190 5,126 0.1359
15 05LGSV0046-WY LRG GEN SRV 222,489 12,532,839 20 11,124,450 0.0563
16 05LGSV046M-WY LRG GEN SERV 23,362 1,317,396 1 23,362,000 0.0564
17 05LGSV048T-LRG GENSRV TIM 9,940 621,563 1 9,940,000 0.0625
18 05LNX00100-L1NE EXT 60% G 102
19 05LNX00102-L1NE EXT 80% G 565,208
20 05LNX00103-L1NE EXT 80%808
21 05LNX00105-CNTRCT $ MIN G 5,343
22 05LNX00109-REF/NREF ADV +612,454
23 05LNX0011 O-REF/NREF ADV+838
24 05LNX00114-TEMP SVC 12MO::5,191
25 05N2825135 - NET METERING 12 1,056 1 12,000 0.0880
26 05NMT25135 - WY NET MTR, GEN,172 11,827 8 21,500 0.0688
27 05NMT28135-NET MTR SMALL 1,283 116,025 7 183,286 0.0904
28 050AL T015N-OUTD AR LGT SR 2,871 420,027 1,749 1,642 0.1463
29 05RCFL0054-WY REC FIELD L 664 49,983 50 13,280 0.0753
30 05LNX00300 - LINE EXT 80%191,062
31 05LNX00311 - LINE EXT 80%63,037
32 REV. ACCOUNTING ADJ.20,691
33 SMUD REVENUE IMPUTATIONS 116,998
34 UNBILLED REVENUE -2,016 -229,000 0.1136
35 05GNS28025-GEN SVC 4,750 342,254 279 17,025 0.0721
36 05GNSC0025 - WY SMALL 42 2,746 3 14,000 0.0654
37 05GNSV0025 - WY GEN SRVC 20,596 1,699,429 2,067 9,964 0.0825
38 05GNSV0028-GEN SVC :: 15 KW 115,540 8,260,171 550 210,073 0.0715
39 05GNSV025F-GEN SRVC-FL RA 195 19,337 32 6,094 0.0992
40 05GNSV028M-GEN SVC::15 KW 1,865 129,994 1 1,865,000 0.0697
41 TOTAL Biled - ,.1,732,81E 30,693 0.0721
42 Total Unbiled Rev.(See Instr. 6)-170,39 !I . ," "((O.049E
43 TOTAL 53,015,53~ 3,827,550,789 1,732,81E 30,59E O.O72~
FERC FORM NO.1 (ED. 12-95)Page 304.8
"
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifCorp (1 )~An Original (Mo, Da, Yr)End of 2010/Q4
(2)DA Resubmission 04/18/2011
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 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.
ine Numoer ana ime or Kate scneauie Mvvn ~OIO t'evenue Average Numoer ~vvn_or :,aies K~~~'$~lër
No.(a)(b)(c)of Cu(~)omers Per '(~stomer
(f)
1 05LNX00102-L1NE EXT 80% G 5,167
2 05LNX00109-REF/NREF ADV +.167,539
3 05LNX00110-REF/NREF ADV +257
4 05LNX00114-TEMP SVC 481
5 09GNSV0025"GEN SVC-SINGLE -9 -816 0.0907
6 05NMT25135 - WY NET MTR, GEN,24 1,734 1 24,000 0.0723
7 05NMT28135-NET MTR SMALL 165 15,516 1 165,000 0.0940
8 090AL T207N-SECURITY AR LG 278 75,336 139 2,000 0.2710
9 09MONL0213-WYMTR OUTDOOR 21 1,738 3 7,000 0.0828
10 05LNX00300 - LINE EXT 80%-34,511
11 05LNX00311 - LINE EXT 80%6,662
12 UNBILLED REVENUE -1,769 -105,000 0.0594
13 LESS MULTIPLE BILLINGS -28,068
14
15 TOTAL COMMERCIAL SALES 15,969,253 1,146,322,741 220,171 72,531 0.0718
16
17 INDUSTRIAL SALES
18 CALIFORNIA
19 06GNSV0025-CA GEN SRVC 728 101,075 96 7,583 0.1388
20 06GNSVOA32-GEN SRVC-20 KW 1,868 231,485 27 69,185 0.1239
21 06LGSV048T-LRG GEN SERV 38,459 2,661,481 5 7,691,800 0.0692
22 06LGSVOA36-LRG GEN SRVC-O 5,103 519,076 14 364,500 0.1017
23 06LNX00109-REF/NREF ADV +236
24 REVENUE ADJ.-DEFERRED NPPC 173,488
25 REV. ACCOUNTING ADJ.-77,920
26 SMUD REVENUE IMPUTATIONS 5,175
27 UNBILLED REVENUE 7 -11,000 -1.5714
28 IDAHO
29 07CFR00001-MTH FACILITY S 2,217
30 07CISH0019-COMM & IND 132 9,564 3 44,000 0.0725
31 07GNSV0006-GEN SRVC-LRG P 91,682 5,170,021 112 818,589 0.0564
32 07GNSV0009-GEN SRVC-HI VO 77,002 3,665,442 11 7,000,182 0.0476
33 07GNSV0023-GEN SRVC-SML P 10,709 835,814 353 30,337 0.0780
34 07GNSV0035-GEN SRVCOPTION 1,192 67,630 1 1,192,000 0.0567
35 07GNSV006A-GEN SRVC-LRG P 4,651 326,841 31 150,032 0.0703
36 07GNSV023A-GEN SRVC-SML P 2,026 187,140 245 8,269 0.0924
37 07GNSV023S-ID TRAFFIC SIGNALS 8 1,055 3 2,667 0.1319
38 07LNX00035-ADV 80%MO GUAR 693
39 07LNX00108-ANN COST MTHL Y 1,996
40 07LNX00300 - 80% MONTHLY MIN 1,876
41 TOTAL Biled .."'1,732,8H 30,69 0.0721%" ., " ~
42 Total Unbiled Rev.(See Instr. 6)-170,39 .((0.049
43 TOTAL 53,015,53 3,827,550,789 1,732,81~30,59~0.072
FERC FORM NO.1 (ED. 12-95)Page 304.9
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
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 number of bils rendere 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.
L.ine NumOer and Iitie or Kate scnedUie Mvvn ;:010 I"evenue 1'verage NumUer ~vvr!.oi ,?aies ~w~~~rirNo.(a)(b)(c)of c~~~omers Per r~stomer
(f)
1 070AL T007N-SECURITY AR LG 13 4,970 17 765 0.3823
2 070ALT07AN-SECURITY AR LG 1 284 2 500 0.2840
3 07SPCLOO01 1,381,900 61,415,663 1 1,381,900,000 0.0444
4 07SPCLOO02 104,026 4,418,677 1 104,026,000 0.0425
5 BPA BALANCING ACCOUNT 14,963
6 SMUD REVENUE IMPUTATIONS 138,631
7 UNBILLED REVENUE -6,118 216,000 . -0.0353
8 OREGON
9 01COST0023, OR GEN SRV, COST 20,565 940,856 0.0458
10 01 COST0048 - 01 LGSV0048 1,558,06E 64,298,860 0.0413
11 01COST023F - OR GEN SRV-2 112 0.0560
12 01 COSTB023 - OR GEN SRV,407 18,984 0.0466
13 01 COSTL030 - OR LRG GEN SRV,189,674 8,158,845 .0.0430
14 01 COSTS028, OR GEN SERV,92,687 4,272,414 0.0461
15 01 GNSB0023 - BPA DISC, " 30 -1,914
16 01GNSB0023, OR GEN SRV, BPA,"27,173 65
17 01 GNSB0028 - OR GEN SRVC,-2,344
18 01GNSB0028, OR GEN SRV, BPA,;:15,778 5
19 01GNSV0023. OR GEN SRV," 30 917,833 1,158
20 01GNSV0028. OR GEN SRV;: 30 2,716,922 493
21 01GNSV023F - OR GEN SRV - FLAT 2 756 2 1,000 0.3780
22 01GNSV023M - OR GEN SRV,40 9,066 .1 40,000 0.2267
23 01GNSV023T, OR GEN SRV, TOU 2,763 4
24 01GNSV0728 - OR GEN SVC DIR 4,386 1
25 01GNSV0748 - OR GEN SVC DIR 544,025 3
26 01 HABT0023 , OR HABITAT 11 518 0.0471
27 01 LGSV0030 - OR LRG GEN SRV, ;:5,269,124 155
28 01 LGSV0048-1OOOKW AND OVR 15,192,976 106
29 01 LGSV048M-LRG GEN SRVC 1 194,954 9,744,333 5 38,990,800 0.0500
30 01LNX00102-L1NE EXT 80% G 18,02
31 01LNX00105-CNTRCT $ MIN 131
32 01LNX00120 - Line Extension 60% G 25,234
33 01 LNX00300 - LINE EXT 80%10,293
34 01 LPRS047M-PART REQ .199,856 9,466,247 3 66,618,667 0.0474
35 01NMT23135 - OR NET MTR, GEN,869 1
36 01NMT28135 - OR NET MTR, GEN,5,790 1
37 010AL T014N-oUTD AR LGT NR 4 640 5 800 0.1600
38 010ALT014N-oUTD AR LGT -22
39 010AL T015N-OUTD AR LGT 320 43,249 143 2,238 0.1352
40 01 PTOU0023, OR GEN SRV, TOU 52 2,403 0.0462
41 TOTAL Biled 1,732,8H 30,69~0.0721
42 Total Unbiled Rev.(See Instr. 6)-170,39 ~ia $I ((O.049f
43 TOTAL 53,015,53~ 3,827,550,789 1.732,8H 30,59f 0.072,
FERC FORM NO.1 (ED. 12-95)Page 304.10
Name of Respondent This wort Is: .Date of Report Year/Period of Report
PacifiCorp (1) . An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
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 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.
Line Numoer ana ime OT t(ate scneauie Mvvn ;:010 t(evenue Averagi)~umoer rivvn_oT ;:aies t(w~~~lër
No.(a)(b)(c)
of cu(~ omers Per '(~stomer
(f)
1 01 RENW0023, OR RENW USAGE 164 7,445 0.0454
2 01RENWB023 - OR RENEWABLE 1 35 0.0350
3 BPA BALANCING ACCOUNT -99
4 01STDAY023 - OR DAY STD OFR,21 1,303 0.0620
5 01STDAY028 - OR DAY STD OFR,165 10,629 0.0644
6 OR GAIN ON SALE OF ASSET 205,340
7 OR SB 408 RECOVERY 405,978
8 OR SB 838 RECOVERY -857,48
9 REV. ACCOUNTING ADJ.-13,854
10 SMUD REVENUE IMPUTATIONS 249,554
11 UNBILLED REVENUE -28,893 -1,026,000 0.0355
12 UTAH
13 08CFR00051-MTH FAC SRVCHG 14,047
14 08EFOP0021-ELEC FURNACE 0 1,733 141,072 2 866,500 0.0814
15 08EFOP021M-ELEC FURNACE 0 1,199 142,548 3 399,667 0.1189
16 08GNSV0006-GEN SRVC-DISTR 687,733 50,759,257 1,181 582,331 0.0738
17 08GNSV0009-GEN SRVC-HI VO 2,643,518 116,750,885 111 23,815,477 0.0442
18 08GNSV0023-GEN SRVC-DISTR 59,315 4,998,451 3,645 16,273 0.0843
19 08GNSV006A-GEN SRVC-ENERG 53,164 5,347,875 244 217,885 0.1006
20 08GNSV006B-GEN 7,397 523,850 8 924,625 0.0708
21 08GNSV009A-GEN SRVC HI VO 17,270 1,164,639 6 2,878,333 0.0674
22 08GNSV009M-MANL HIGH 837,489 34,846,273 11 76,135,364 0.0416
23 08GNSV023F-GEN SRVC FIXED 4 1,892 1 4,000 0.4730
24 08GNSV06MN-GNSV DIST VOLT 1,242 93,158 30 41,400 0.0750
25 08GNSV09AM-MAN TOD HIVOL T 2,072 208,656 1 2,072,000 0.1007
26 08LNX00002-MTHL Y 80% GUAR 28,800
27 08LNX00004-ANNUAL 80%GUAR 753,230
28 08LNX00014-80% MIN 57,387
29 08LNX00017;:ADV /REF&80%ANN 2,944
30 08LNX00311 - LINE EXT 80%2,126
31 08LNX00300 - LINE EXT 80% PLUS 91,742
32 08LNX00310 -IRR, 80% ANNUAL 5,424
33 080AL T007N-SECURITY AR 1,395 292,894 504 2,768 0.2100
34 08TOSS0015-TRAF & OTHER S 26 2,358 10 2,600 0.0907
35 08MONL0015-MTR OUTDONIGHT 11 2,820 6 1,833 0.2564
36 08NMT06135-UT NET MTR,GEN,271 21,751 1 271,000 0.0803
37 08NMT23135-UT NET MTR, GEN,85 5,542 1 85,000 0.0652
38 08PRSV031M-BKUP MNT&SUPP 3,514 516,205 1 3,514,000 0.1469
39 08SPCLOO01 472,728 18,433,648 1 472,728,000 0.0390
40 08SPCLOO02 861,461 25,718,913 1 861,461,000 0.0299
41 TOTAL Biled ~1,732,81 30,69 0.0721
42 Total Unbiled Rev.(See Instr. 6)-17039 f". ¿wil . . ..((0.0495
43 TOTAL 53,015:534 ;,827,550,789 1,732,81'30,59E O.072;¿
..FERC FORM NO.1 (ED. 12-95)Page 304.11
Name of Respondent This 'mort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/18/2011
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electcity 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 th same revenue accunt classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendered during the year divded by the number of billng 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 pursant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue account subheading.
Line Numoer ana Iitie or Kate scneaUie Mwn ::oia ~evenue iwerage I'lumutr ~~~nr~sr;~:r 'lW~~~FcerNo.(a)(b)(c)
of Cu(~~omers
(f)
1 08SPCLOO03 721,792 26,133,414 1 721,792,000 0.0362
2 08SPCLOO05 241,092 9,435,337 1 241,092,000 0.0391
3 REV. ACCOUNTING ADJ.3,576,966
4 SMUD REVENUE IMPUTATIONS 3,923,014
5 08GNSV06AM-MNL ENERGY TOD 348 38,191 2 174,000 0.1097
6 08GNSV0008 - UT GEN SVC TOU ;.918,970 57,686,601 115 7,991,03 0.0628
7 08GNSV008M - UT GEN SVC TOU ;.58,68S 3,626,179 7 8,384,143 0.0618
8 UNBILLED REVENUE 37,497 1,256,000 0.0335
9 WASHINGTON
10 02GNSB0024-WA GEN SRVC 1,885 160,423 95 19,842 0.0851
11 02GNSB0024-WA GEN SRVC DO -8,196
12 02GNSB24FP-WA GEN SVC 7 2,263 1 7,000 0.3233
13 02GNSB24Fp.WA GEN SVC -31
14 02GNSV0024-WA GEN SRVC 16,378 1,264,050 367 44,627 0.0772
15 02GNSV024F-WA GEN 33 6,885 4 8,250 0.2086
16 02LGSV0036-WA LRG GEN SRV 121,064 7,930,744 118 1,025,966 0.0655
17 02LGSV048T-WA LRG GEN SRV 670,44 34,417,221 32 20,951,375 0.0513
18 020ALT015N-WA OUTD AR LGT 122 15,098 42 2,905 0.1238
19 020ALTB15N-WA OUTD AR LGT 30 4,283 17 1,765 0.1428
20 020AL TB15N-WA OUTD AR LGT -135
21 02PRSV47TM-LRG PART REQMT 1,799 257,200 1 1,799,000 0.1430
22 02LGSB0036-LRG GEN SVC IRG 4,093 422,382 29 141,138 0.1032
23 02LGSB0036-LRG GENSVC IRG -18,131
24 ACQUISITION COMMIT-A & G CR -29
25 BPA BALANCING ACCOUNT -2,046
26 REV. ACCOUNTING ADJ.-1,456,657
27 SMUD REVENUE IMPUTATIONS 80,837 .
28 WA - CHEHALIS DEFERRAL -510,000
29 UNBILLED REVENUE -14,562 ~700,OOO 0.0481
30 WYOMING
31 05GNS28025-GEN SVC 7,459 473,749 179 41,670 0.0635
32 05GNSV0025.WY GEN SRVC 14,734 1,114,868 1,033 14,263 0.0757
33 05GNSV0028-GEN SRVC;. 15 KW 264,730 16,740,816 504 525,258 0.0632
34 05GNSV025F-GEN SRVC-FL RA 21 2,568 5 4,200 0.1223
35 05LGSV0046-WY LRG GEN 1,575,373 83,641,666 54 29,173,574 0.0531
36 05LGSV046M-WY LRG GEN 119,548 5,94,882 2 59,774,000 0.0497
37 05LGSV048M-TOU;.1000KW MAN 1,310,345 54,432,211 3 436,781,667 0.0415
38 05LGSV048T-LRG GENSRV TIM 1,308,474 55,771,163 10 130,847,400 0.0426
39 05LNX00100-L1NE EXT 60% G 45,122
40 05LNX00102-L1NE EXT 80% G 228,759
41 TOTAL Biled Ii
. "; % !l
1,732,8H 30,69 0.0721
42 Total Unbiled Rev.(See Instr. 6)-170,39 . .((O.049~
43 TOTAL 53,015,53 3,827,550,789 1,732,8H 30,59~0.072:.
FERC FORM NO.1 (ED. 12-95)Page 304.12
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/18/2011
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effct 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 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 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 Numoer ana iine or Kate scneauie Mvvn ::oia Kevenue Average. Numoer ~vvn_OT ::aies KW~~~/der
No.(a)(b)(c)
of C~~\omers Per ?à)stomer
(f)
1 05LNX00105-CNTRCT $ MIN G 46,426
2 05LNX001 09-REF/NREF ADV +184,865 .
3 050AL T015N-OUTD AR LGT SR 85 11,429 44 1,932 0.1345
4 05PRSV033M-PART SERV REO 870,129 44,191,804 5 174,025,800 0.0508
5 REV. ACCOUNTING ADJ.62,172
6 SMUD REVENUE IMPUTATIONS 523,920
7 05LNX00300 - LINE EXT 80%47,766
8 05LNX00311 - LINE EXT 80%11,623
9 UNBILLED REVENUE 12,655 794,000 0.0627
10 05GNS28025-WY GEN SVC 1,023 71,018 32 31,969 0.0694
11 05GNSV0025-WY GEN SRVC 2,668 224,869 272 9,809 0.0843
12 05GNSV0028-GEN SVC :: 15 KW 34,076 2,255,888 77 442,545 0.0662
13 05GNSV028M -GEN SVC:: 15 KW 4,937 263,562 4 1,234,250 0.0534
14 05LGSV0046-WY LRG GEN SRV 26,215 1,687,664 4 6,553,750 0.0644
15 05LGSV048M-TOU::1 OOOKW MAN 312,528 13,131,323 3 104,176,000 0.0420
16 05LGSV048T-LRG GENSRV 1,099,328 47,549,355 9 122,147,556 0.0433
17 05LNX00102-L1NE EXT 80% G 6,096 ...
18 05LNX001 09-REF/NREF ADV 23
19 05PRSV033M-PART SERV REO 110,469 5,060,947 3 36,823,000 0.0458
20 090AL T207N-SECURITY AR 5 1,120 3 1,667 0.2240
21 UNBILLED REVENUE -1,733 -16,000 0.0092
22 LESS MULTIPLE BILLINGS -1,131
23
24 TOTAL INDUSTRIAL SALES 19,445,864 943,745,752 10,788 1,802,546 0.0485
25
26 IRRIGATION SALES
27 CALIFORNIA
28 06APSV0020-AG PMP SRVC 60,763 6,268,966 1,360 44,679 0.1032
29 06LGSV048T-LRG GEN SERV 800 72,053 1 800,000 0.0901
30 06LNX00102-L1NE EXT 80% G 1,109
31 06LNX00103-L1NE EXT 80% G 5,526
32 06LNX00110-REF/NREF ADV +32,953
33 06LNX00312 - CA IRG LINE EXT 2,261
34 06USBR0020-KLAM IRG ONPRJ 28,501 3,135,630 658 43,315 0.1100
35 06LNX00109-REF/NREF ADV +327
36 IRRIGATION UNBILLED 8 1,000 0.1250
37 REV. ACCOUNTING ADJ.-184,958
38 IDAHO
39 07APSA010L -IRG & Pump Large 432,645 31,523,280 3,253 132,999 0.0729
40 07APSA010S -IRG & PUMP BPA -14
41 TOTAL Biled ~1,732,8H 30,69 0.0721
42 Total Unbiled Rev.(See Instr. 6)-170,39 II . ii ;((O.049~
43 TOTAL 53,015,53~ 3,827,550,789 1,732,81~30,59~0.072,
FERC FORM NO.1 (ED. 12-95)Page 304.13
Name of Respondent This ï!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/18/2011
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 number of bils rendered during the year divided by the number of biling periods during the year (12 if
all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause stte 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.
,-ine Numoer ana ime or Kate scneauie Mvvn ::oia Kevenue Average Numoer ~wn_ or ;;aies ~~~i§~lderNo.(a)(b)(c)
of C~~trmers Per 9~stomer
(f)
1 07APSA010S -IRG & Pump Small 4,763 433,869 409 11,645 0.0911
2 07 APSAL 1 OX - IRG & PUMP - Large 82,903 6,147,887 785 105,609 0.0742
3 07APSAS10X - IRG & PUMP - Small 1,840 180,573 219 8,402 0.0981
4 07APi)VCNLL-LRG LOAD CANAL 31,184 2,037,751 80 389,800 0.0653
5 07APSVCNLS-SML LOAD CANAL 125 13,233 18 6,944 0.1059
6 07BPADEBIT-BPAADJUST FEE 2,982
7 07LNX00015-ANNUAL 80%GUAR 4,532
8 07LNXOO040-ADV+REFCHG+80%211,106
9 07LNX00107-SUBD ADV & AIC 1,097
10 07LNX00310 80% ANNUAL 6,511
11 07LNX00312 -ID LINE EXT 31,387
12 07APSN010L -ID LG IRR & PUMP 3,357 278,453 47 71,426 0.0829
13 07APSN010S - IRRIGATION,320 28,142 20 16,000 0.0879
14 07APSNS10X -IRRIGATION,4 819 2 2,000 0.2048
15 IRRIGATION BPA BAL ACCT -1,149,332
16 UNBILLED REV -IRRIGATION 87 6,00 0.0690
17 OREGON
18 01APSV0041-AG PMP SRVC BP 1,800,072 4,702
19 01APSV0041-AG PMP SRVC BP -175,195
20 01APSV041L-OR Pumping Serv 2,432,864 1,058
21 01 APSV041 L-OR Pumping Serv BPA -294,717
22 01 APSV041T - AGR PUMP SRV -2,480
23 01APSV041T - AGR PUMP 25,685 58
24 01APSV041X-AG PMP SRVC 85,403 256
25 01APSV41XL-OR Pumping Serv no 224,729 63
26 01 BPADEBIT -BPA ADJUST FEE 28,60527' . ~_108,450 4,972,929 0.0459-' "m." 11-
28 01 COST0048 - 01 LGSV0048 6,048 250,337 0.0414
29 01COSTS028, OR GEN SERV,279 12,913 0.0463
30 01 GNSV0028, OR GEN SRV ;: 30 9,124 2
31 01HABIT041 - 01APSV0041 AG 3 141 0.0470
32 01 LGSB0048 - LG GEN SVC ;:-28,365
33 01 LGSB0048 - LG GEN SVC ;:77,312 1
34 01 LNX001 03-L1NE EXT 80% G 15,846
35 01 LNX001 09-REF/NREF ADV +9,901
36 01 LNX0011 O-REF/NREF ADV +155,647
37 01 LNX0031 O-L1NE EXTENSION 2,896
38 01PTOU0041 - 01APSV0041 AG 546 22,668 0.0415
39 01RENEW041 - 01APSV0041 AG 97 4,480 0.0462
40 01SLX00005-KLAMATH FALLS 181,173
~41 TOTAL Biled . ,.1,732,81E 30,69 0.0721
42 Total Un biled Rev.(See Instr. 6)-170,39 '"((O.04ge
43 TOTAL 53,015,53 3,827,550,789 1,732,81E 30,59~O.072¿
FERC FORM NO.1 (ED; 12-95)Page 304.14
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
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 number of bils rendered during the year divided by the number of billing 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 account subheading.
ine Numoer ana ime or Kate scneauie Mvvn ::oia Kevenue Average Numoer ~~~nr~sr;::r K~ven'Se)~er
No.of C~~~omers Wh od
(a)(b)(c)(f)
1 01SLX00013-K FALLS IRG MI 8,626
2 01SLX00014-K FALLS IRG MI 1,556
3 01STDAY041 - Daily Standard Ofer 35 2,162 0.0618
4 01USBGV033-KLAMATH IRG TOU -57
5 01USBOF033-KLAMATH BASIN 43,991 1,485,667 640 68,736 0.0338
6 01USBOF033-KLAMATH BASIN -169,715
7 01USBON033-KLAMATH BASIN 47,229 1,468,399 1,375 34,348 0.0311
8 01USBON033-KLAMATH BASIN -181,356
9 01 USBGV033-IRG TOU W/O BPA 2,008 43,528 10 200,800 0.0217
10 IRRIGATION BPA BAL ACCT 51,940
11 IRRIGATION UNBILLED -118 -11,000 0.0932
12 01LNX00312 - OR IRG LINE EX 13,458
13 01NMT33135 - OR NET MTR-6 174 1 6,000 0.0290
14 01 NMT33135 - NETMTR AG PMP -22
15 01 NMT41135 - NETMTR AG PMP 162 1
16 OR GAIN ON SALE OF ASSET 15,494
17 OR Irrigation - BPA adjustment 11,597
18 OR SB408 RECOVERY 33,130
19 OR SB 838 RECOVERY -84,044
20 REV. ACCOUNTING ADJ.1
21 UTAH
22 08APSV0010-IRR & SOIL DRA 191,267 11,752,335 2,662 71,851 0.0614
23 08APSV10NS-lrg Soil Drain Pump N 15,013 880,706 94 159,713 0.0587
24 08LNX00002-MTHL Y 80% GUAR 842
25 08LNX00004-ANNUAL 80%GUAR 9,123
26 08LNX00014-80% MIN MNTHLY 1,998
27 08LNX00017 -ADV/REF&80%ANN 153,527
28 08LNX00310 -IRR, 80% ANNUAL 11,601
29 08LNX00312 UT IRG LINE EXT 9,728
30 08NMT10135-UT IRR SOIL DRNG 15 1,211 1 15,000 0.0807
31 REV. ACCOUNTING ADJ.138,166
32 UNBILLED REV -IRRIGATION 90 3,000 0.0333
33 WASHINGTON
34 02APSV0040-WA AG PMP SRVC 128,040 9,382,914 4,580 27,956 0.0733
35 02APSV0040-WA AG PMP SRVC -566,728
36 02APSV040X-WA AG PMP SRVC 22,420 1,631,029 703 31,892 0.0727
37 02BPADEBIT-BPA ADJUST FEE 12,958
38 02LNX00102-L1NE EXT 80% G 805
39 02LNX00103-L1NE EXT 80% G 5,541
40 02LNX00105-CNTRCT $ MIN G 30
41 TOTAL Biled 1,732,811 30,69 0.0721
42 Total Unbiled Rev.(See Instr. 6)~((O.04ge
43 TOTAL 53,015,53 3,827,550,789 1,732,81e 30,59~O.072~
FERC FORM NO.1 (ED. 12-95)Page 304.15
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/18/2011
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 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 accunt subheading.
I Line Numoer ana Iitie or Kate scneaUie Mwn :soia Kevenue AVerag~\~umoer Kwn_oT :saies "evenise)rc erofc~~omers Per y~stomer KWh odNo.(a)(b)(c)(f)
1 02LNX0011 O-REF/NREF ADV +129,070
2 02LNX00310-IRG, 80% ANN MIN +1,569
3 02LNX00311 - LINE EXT 80%49
4 02LNX00312 - WA IRG LINE EX 12,626
5 02ZZMERGCR-MERGER CREDITS 6
6 REV. ACCOUNTING ADJ.-356,266
7 WA - CHEHALIS DEFERRAL -120,000
8 IRRIGATION BPA BAL ACCT -2,706
9 IRRIGATION UNBILLED 151 10,000 0.0662
10 WYOMING
11 05APS00040-AG PUMPING SVC 17,447 1,276,733 633 27,562 0.0732
12 05LNX0011 O-REF/NREF ADV +59,697
13 05LNX00103-L1NE EXT 80% G 8,519
14 05LNX00310 - WY IRG LINE EXT 351
15 05LNX00312 - WY IRG LINE EXT 377
16 IRRIGATION UNBILLED .-16 -1,000 0.0625
17 05APS00040-AG PUMPING SVC 28 1,820 1 28,000 0.0650
18 05LNX00103-L1NE EXT 80%G 1,958
19 05LNX00110-REF/NREF ADV +14,667 .
20 09APSV0210-IRR & SOIL DRA 3,260 245,862 70 46,571 0.0754
21 LESS MULTIPLE BILLINGS -697
22
23 TOTAL IRRIGATION SALES 1,233,589 86,306,929 23,066 53,481 0.0700
24
25 PUBLIC STREET & HWY LIGHTING
26 CALIFORNIA .
27 06CUSL053F-SPECIAL CUST 0 1,441 175,930 120 12,008 0.1221
28 06CUSL058F-CUST OWND STR 242 33,988 23 10,522 0.1404
29 06HPSV0051-HI PRESSURE SO 692 171,246 78 8,872 0.2475
30 REV.ACCOUNTING ADJ.-8,830
31 UNBILLED REVENUE -34 -6,000 0.1765
32 IDAHO
33 07GNSV023S-ID TRAFFIC SIGNALS 152 14,967 25 6,080 0.0985
34 07SLC00011-STR LGT CO-OWN 100 44,235 29 3,448 0.4424
35 07SLCU012E-ENGY STR 247 26,286 17 14,529 0.1064
36 07SLCU012F-FULL MNT STR 1,930 364,957 281 6,868 0.1891
37 07SLCU012P-PART MNT STR LGT 192 26,435 16 12,000 0.1377
38 UNBILLED REVENUE -38 -6,000 0.1579
39 OREGON
40 01COSL0052-STR LGT SRVC C 943 122,013 60 15,717 0.1294
41 TOTAL Biled . lI 1,732,81l 30,69 0.0721% . ii .....
42 Total Un biled Rev.(See Instr. 6)I -170,39 . . ..".. ...((O.O49!
43 TOTAL 53,015,53~ 3,827,550,789 1,732,8Ü 30,59~0.0722
FERC FORM NO.1 (ED. 12-95)Page 304.16
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
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 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.
ine NU,moer ana Iitle OT I"are scneouie Mvvn ::oia I"evenue Average Numoer ~VVaOT :,aies I"W~~~/der
No.(a)(b)(c)of c~~)omers Per ?~stomer
(f)
1 01CUSL0053-CUS-OWNED MTRD 815 58,101 70 11,643 0.0713
2 01 CUSL053E-STR LGT SVC 8,441 604,207 166 50,849 0.0716
3 01CUSL053F-STR LGT SRVC C 261 27,956 21 12,429 0.1071
4 01 HPSV0051-HI PRESSURE SO 17,751 3,702,764 699 25,395 0.2086
5 01 LEDSL055-0R LED PlOT 31 1
6 01 MVSL0050-MERC VAPSTR LG 9,422 1,208,653 259 36,378 0.1283
7 010AL T014N-OUTD AR LGT NR 4 793 4 .1,000 0.1983
8 010AL T014N-OUTD AR LGT NR -18
9 010AL T015N-OUTD AR LGT NR 9 1,495 4 2,250 0.1661
10 OR GAIN ON SALE OF ASSET 2,554
11 OR SB408 RECOVERY 5,014
12 OR SB 838 RECOVERY -8,905
13 REV. ACCOUNTING ADJ.1
14 UNBILLED REVENUE -443 -36,000 0.0813
15 UTAH
16 08CFR00012-STR LGTS (CONV 54 )
17 08CFR00051-MTH FAC SRVCHG 4,529
18 08CFR00062-STREET LIGHTS 79
19 080AL T007N-SECURITY AR LG 13 3,759 10 1,300 0.2892
20 08TOSS015F-TRAFFIC SIG NM 1,159 88;101 123 9,423 0.0760
21 08SLC00011-STR LGT CO-OWN 20,490 6,008,760 969 21,146 0.2933
22 08TOSS0015-tRAF & OTHER S 2,911 282,499 1,504 1,936 0.0970
23 08MONL0015-MTR OUTDONIGHT 1,023 81,307 57 17,947 0.0795
24 08SLCU012P-STR LGT CUST-O 5,721 703,896 240 23,838 0.1230
25 08SLCU012F-STR LGT CUST-O 2,706 369,890 121 22,364 0.1367
26 08SLCU012E-DECOR CUST -OWN 45,193 2,967,340 446 101,330 0.0657
27 08THIK0077-STR LIGHT SPEC 141 17,277 1 141,000 0.1225
28 REV. ACCOUNTING ADJ.276,332
29 UNBILLED REVENUE . 1,152 108,000 0.0938
30 WASHINGTON
31 02CFR00012-STR LGTS (CONV 91
32 02COSL0052-WA STR LGT SRV 406 58,221 19 21,368 0.1434
33 02CUSL053F-WA STR LGT SRV 3,589 244,583 105 34,181 0.0681
34 02CUSL053M-WA STR LGT SRV 1,172 78,805 93 12,602 0.0672
35 02HPSV0051-WA HI PRESSURE 3,216 593,553 152 21,158 0.1846
36 02MVSL0057-WA MERC VAPSTR 1,994 236,627 45 44,311 0.1187
37 WA - CHEHALIS DEFERRAL -30,000
38 REV. ACCOUNTING ADJ.-23,544
39 UNBILLED REVENUE 648 79,000 0.1219
40 WYOMING
41 TOTAL Biled -lI.1,732,81E 30,69 0.0721
42 Total Unbiled Rev.(See Instr. 6)-170,39 fu ,.'"),C (0.0495
43 TOTAL 53,015,53~3,827,550,789 1,732,81E 30,59~0.072;¿
FERC FORM NO.1 (ED. 12-95)Page 304.17
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2011
SALES OF ELECTRICITY BY RATE SCHEDULES
Year/Period of Report
End of 2010/Q4
1. Report below for each rate schedule in effect during the year the MWH of electcity 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 account classifcation (such as a general residential
scedule 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 fotnote the estimated additonal revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
I Line Numoer ana Iitie or Kate scneauie Mvvn ~oia t\evenue l\verage l'IumOerNo. (a) (b) (c) of Cu(~~omers
1 05COSL0057-CO-OWND STR LG 317 63,540 21
2 05CUSL058M-CUST OWND STR 74 4,557 11
3 05CUSLOE58-WY CUST OWND 1,083 66,985 314 05CUSLOM58-CUST OWNED 49 3,724 4
5 05HPSV0051-HI PRESSURE SO . 4,808 988,331 156
6 05MVS00053-MERCURY VAPOR 3,843 479,615 2597 REV. ACCOUNTING ADJ. 400
8 UNBILLED REVENUE -160 -26,000
9 09MONL0213-WY MTR OUTDOOR 29 2,197
10 09SLC00211-STR LGT CO-OWN 1,335 389,145
11 09SLCUP212-STR LGT CUST-O 72 11,231
12 09TOSS0213~TRAF & OTHER S 67 2,604
13 UNBILLED REVENUE -146 -51,000
14 LESS MULTIPLE BILLINGS
15
16 TOTAL PUBLIC STREET & HWY
17
18 OTHER SALES TO PUBLIC AUTH
19 UTAH
20 08GNSV0006-GEN. SRVC-DISTR
21 08GNSV0023-GEN SRVC-DISTR
22 08GNSV009M-MANL HIGH VOLT
23 080AL TOO7N-SECURITY AR LG
24 UNBILLED REVENUE
25
26 TOTAL OTHER SALES TO PUBLIC
27
28 FORFEITED DISCOUNTS
29 CALIFORNIA
'Swnßr:;alesPer '(~stomer
15,095
6,727
34,935
12,250
30,821
14,838
Iie:-enu.e i-erKWh Soid
(f)
0.2004
0.0616
0.0619
0.0760
0.2056
0.1248
1
49
9
14
29,000
27,245
8,000
4,786
0.1625
0.0758
0.2915
0.1560
0.0389
0.3493
-2,445
145,032 20,610,361 3,868 37,495 0.1421
.
2,355
29
421,143
18
3,807
153,647
2,855
19,402,446
4,468
207,000
4
3
4
2
588,750
9,667
105,285,750
9,000
0.0652
0.0984
0.0461
0.2482
0.0544
427,352 19,770,416 13 32,873,231 0.0463
30 Late Fees 285,011
31 IDAHO
32 Late Fees 406,930
33 OREGON
34 Late Fees 2,666,385
35 UTAH
36 Late Fees 2,957,255
37 WASHINGTON
38 Late Fees 542,237
39 WYOMING
40 Late Fees 554,070
41
42
43
TOTAL Biled
Total Unbiled Rev.(See Instr. 6)
TOTAL
_.í' __.".
-170,39lR ~ .. ...
53,015,53~ 3,827,550,789
Page 304.18
1,732,81f
(
1,732,81'
30,69
(
30,59~
0.0721
O.049~
0.072
FERC FORM NO.1 (ED. 12-95)
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) CiA Resubmission 04/18/2011
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 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.
ILlne I'lumoer ana ime or Kate scneaUie Mwn::oia M:evenue Average Numoer ~vvn_or ::aies M:Æ~~is~lder
No.(a)(b)(c)
of C~~tlmers Per 9à)stomer
(f)
1
2 TOTAL FORFEITED DISCOUNTS 7,411,888 .
3
4 MISCELLANEOUS SERVICE REV
5 CALIFORNIA
6 06CFR00003-MTH MAINTENANC 1,454
7 06CONN0300-CA RECONNECTIO 32,380
8 06FCBUYOUT 53,332
9 06RCHK0300-CA RET CHK CHR 12,096
10 06TAMP0300-CA TAMP & UNAU 1,050
11 06TEMP0300-CA TEMP SRVC C 1,870
12 06XMTRTAMP-TAMPERING -288
13 Home Comfort 1,003
14 Other -4,185
15 IDAHO
16 07CFR00001-MTH FAC SRVCHG 1,682
17 07CONN0300-ID RECONNECTIO 46,055
18 07RCHK0300-ID RET CHK CHR 37,980
19 07TAMP0300 1,275
20 07TEMP0014-TEMP SRVC CONN 9,380
21 07XMTRTAMP-TAMPERING -121
22 Weatherization Loans ID 146
23 Other 4,350
24 OREGON
25 01CFR00001-MTH FACILITY S 61,661
26 01CFR00003-MTH MAINTENANC 25,964
27 01CFR00004-EMRGNCY ST&BY 22,439
28 01 CFROOO05-INTERMTNT 41,861
29 01CFR00013-MTH MISC CHRG 2,284
30 01CFR00014-YR MISC CHRG 5
31 01CONN0300-RECONNECTION C 316,525
32 01CONTSERV-OR 3RD PARTY 2,093
33 01 DPAC0300-DEMAND PULSE 6,000
34 01 ESSC0600 - ESS charges 90
35 01 FCBUYOUT-FAC CHG BUYOUT 260,885
36 01 LNX001 09-REF/NREF ADV +-34,997
37 01 MTRVR300-METR VERIF FEE 20
38 010RRA0300-0R RETAIL ACCESS 5
39 01 RCHK0300-RETURNED CHECK 290,980
40 01TAMP0300-TAMP & UNAUTH 12,975
~41 TOTAL Billed 1 ,732,81~30,69 0.0721
42 Total Unbiled Rev.(See Instr. 6)-170'lI ((O.049~
43 TOTAL 53,015,5 3,827:550,789 1 ,732,81~30,59~0.072",
FERC FORM NO.1 (ED. 12-95)Page 304.19
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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 accunt subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue accunt classification (such as a general residential
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 additonal revenue biled pursuant thereto.
6. Report amount of un biled revenue as of end of year for each applicable revenue accunt subheading.
ine Number and 1 me OT Kate scneaUie Mvvn ;:010 Kevenue Avei~~umoer ~vvn.oT ,?aies K~~~'s~lder
No.(a)(b)(c)ofC~somers Per r~stomer
(f).
1 01TEMP0300-TEMP SRVC CHRG 77,875
2 01XMTRTAMP-TAMPERING -12,654
3 Other 21,358 .
4 UTAH
5 08CFR00013-MTH MISC CHRG 148,885
6 08CFR00051-MTH FAC SRVCHG 107,746
7 08CFR00052-ANN FAC SVCCHG 424
8 08CFR00053-MTHL Y MAINTFEE 11,272
9 08CFR00063-MTH MISC CHARG 2,408
10 08CFR00064.ANN MISC CHARG 6,660
11 08CONN0300-RECONN&DISCONN 329,135
12 08CONTSERV-3RD PARTY O/S 285,840
13 08FCBUYOUT-FAC CHG BUYOUT 186,556
14 08NCON0300-UT FEE NRES RE 6,760
15 08RCHK0300-UT RET CHK CHR 464,220
16 08RCON0001-CONNECT FEE 1,541,400
17 08TAMP0300-TAMPERING&UNAU 18,000
18 08TEMP0014-TEMP SRVC CONN 297,285
19 08UPPLOOON-BASE SCH FALL -11
20 08XMTRTAMP-TAMPERING -5,705
21 Energy Finanswer 12,000 430
22 Energy Finanswer new Com 23,631
23 Other -31,066
24 08VISIT300 - UT Visit, Service Ca 281,590
25 WASHINGTON
26 02CFR00003-MTH MAINTENANC .1,320
27 02CFR00004-EMRGNCY ST&BY 5,879
28 02CFR00005-INTERMTNT SRVC 4,302
29 02CONN0300-WA RECONNECTIO 58,130
30 02FCBUYOUT - FAC CHG BUYOUT 22,397
31 02RCHK0300-WA RET CHK CHR 57,660
32 02TAMP0300-WA TAMP & UNAU 4,650
33 02TEMP0300-WA TEMP SRVC C 16,325
34 02XMTRTAMP-TAMPERING -2,571
35 Energy Finanswer new Com 2,784
36 Home Comfort 3,148
37 Other -7,674
38 WYOMING
39 05CFR00003-MTH MAINTENANC 7,510
40 05CFR00004-EMRGNCY ST&BY 18,891
41 TOTAL Biled .!l "1,732,8H 30,69~0.0721
42 Total Unbiled Rev.(See Instr. 6)-170,39 "((O.049~0 ,,~, "', ~
43 TOTAL 53,015,53~3,827,550,789 1,732,8H 30,59~0.072,
FERC FORM NO.1 (ED. 12-95)Page 304.20
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifCorp (1) An Original (Mo, Da, Yr)End of 2010/04
(2) EiA Resubmission 04/18/2011
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 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.
I Line Numoer ana Iitie or Kate scneauie Mwn ::oia ~evenue l'verage l'IumUer . 'P~~'9¡sf~::r ~W~~~lderNo.(a)(b)(c)of C~~tlmers
(f)
1 05CFR00005-INTERMTNT SRVC 9,943 ..
2 05CFR00013-MTH MISC CHRG 3.186
3 05CONN0300-WY RECONNECTIO 63,560
4 05FCBUYOUT - FAC CHG BUYOUT 294,099
5 05RCHK0300-WY RET CHK CHR 69,000
6 05SERV0300-WY SRVC CALLS 120
705TAMP0300 1,650
8 05TEMP0300-WY TEMP SRVC C 27,430
9 Other .-2,985
10 05XMTRTAMP-TAMPERING-170
11 09CFR00005-INTERMTNT SRVC 339
12 05CONN0300-WY RECONNECTIO 13,300
13 05FCBUYOUT - FAC CHG BUYOUT 215,167
14 05RCHK0300-WY RET CHK CHR 11,670
1505TAMP0300 150
16 05TEMP0300-WY TEMP SRVC C 1,360
17 05XMTRTAMP-TAMPERING-27
18 09CFR00001-MTH FAC SRVCHG 5,067
19 Energy Finanswer 12,000 301
20
21 TOTAL MISC SERVICE REV 5,919,271
22
23 SAlES OF WATER AND WTR PWR
24 UTAH 1,609
25 WYOMING 1,000
26 TOTAL WATER AND WATER PWR 2,609
27
28 RENT FROM ELEC PROPERTIES
.29 CALIFORNIA ..
30 06CFR00006-MTH RNTAL CHRG 1,710
31 Rent Revenue - Subleases 17,693
32 Joint use 531,229
33 IDAHO
34 07CFR00009-YR LSE CHRG-EQ 730
35 07INVCHGOO-INVEST MNT CHG 178
36 07LOOP0014-MTH FEE PRE-AS 210
37 07POLE0075-STEEL POLES US 276
38 07XTRN0013-RNT/LSE L& PRO 34,369
39 RENT REVENUE-HYDRO 66,682
40 RENT REV-TRANSMISS 900
41 TOTAL Biled ~1,732,81f 30,69 0.0721,,~,1Ow:%,~_ *,
42 Total Unbiled Rev.(See Instr. 6)-170,39 . " . ~((O.049~
43 TOTAL 53,015,53 3,827,550,789 1,732,81f 30,59~0.072.
FERC FORM NO.1 (ED. 12-95)Page 304.21
Name of Respondent This î:0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/18/2011
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 seuence 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 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.
¡Line Num~er ano Iitle or I"ate scneouie Mvvn ;:oia I"evenue Average Numoer ~vvn_or ;:aies twxi~¡nise)lë;e
of C~~)omers Per C(à\stomer K h odNo.(a)(b)(c)(f)
1 RENT REV-DISTRIBUT 300
2 Rent Revenue - Subleases 2,216
3 Joint use 172,973
4 OREGON
5 01CFR00006-MTH RNTAL CHRG 600,081
6 RENTS - COMMON 462,545
7 Rents - Non Common 25
8 MCI FOGWIRE REVENUE 3,350,038
9 Rent Revenue - Subleases 335,325
10 RENT REVENUE-HYDRO 21,068
11 RENT REV-TRANSMISS 230,034
12 RENT REV-DISTRIBUT 50,979
13 RENT REV-GEN(COMM)42,260
14 Joint use 4,492,037
15 UTAH
16 08CFR00056-MTH EQUIP RENT 33
17 08CFR00058-MTH EQUIP LEAS 729,329
18 08INVCHGON-INVEST MNT CHG 4,740
19 08INVCHGOR-INVEST MNT CHG .283
20 08LOOP014N-TEMP SERV CONN 2,736
21 08POLE0075-STEEL POLES US 59,537
22 08XTRN0013-RNT/LSE L& PRO 56,388
23 RENTS - COMMON -20,46
24 Rents - Non Common 9,174
25 RENT REVENUE-STEAM 90,946
26 RENT REVENUE-HYDRO 86,704
27 RENT REV-TRANSMISS 840,373
28 RENT REV-DISTRIBUT 431,916
29 RENT REV-GEN(COMM)6,691
30 Rent Revenue - Subleases 2,464,310
31 Joint use 2,152,980
32 WASHINGTON
33 02CFR00001-MTH FACILITY S 2,104
34 02CFR00006-MTH RNTAL CHRG 29,871
35 RENT REVENUE-HYDRO 641,359
36 RENT REV-DISTRIBUT 17,233
37 RENT REV-GEN(COMM)39,573
38 RENT REV-TRANSMISS 7,517
39 Rent Revenue - Subleases 45,245
- 40 Joint use 999,785
41 TOTAL Biled ~1,732,81~30,69 0.0721"" ," , ¡;
42 Total Unbiled Rev.(See Instr. 6)-170,39 .C (0.049~
43 TOTAL 53,015,534 3,827,550,789 1 ,732,81~30,59~O.072~
FERC FORM NO.1 (ED. 12-95)Page 304.22
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) . An Original (Mo, Da, Yr)End of 2010/04
(2) EiA Resubmission 04/18/2011
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
all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue account subheading.
me Numoer ana ime or Kate scneauie Mwn~oia Kevenue Average Numoer ~~~nr~sf~~:r ~w~isilderNo.(a)(b)(c)of Cu(~~omers
(f)
1 WYOMING
2 05CFR00001-MTH FACILITY S 11,524
3 05CFR00006-MTH RNTAL CHRG 2,482
4 RENT REVENUE-STEAM 66,695
5 RENT REV-TRANSMISS 850
6 RENT REV-DISTRIBUT 7,814
7 RENT REV-GEN(COMM)-6,947
8 Rent Revenue - Subleases 15,912
9 Joint use 309,340
10 09LOOP0214-MTH FEE PRE-AS 62
11 09POLE0075-STEEL POLES US 17,403
12 RENT REVENUE-STEAM 7,062
13 Joint use 14,660
14
15 TOTAL RENT FROM ELEC PROP 19,559,096
16
17 WIND BASED ANCILLARY SVC 7,281,432
18 ELEC INC-OTHR 5,339
19 OTHER ELEC ESTIMATE -597,217
20 RENEWABLE ENERGY CREDIT 93,760,900 .
21 NON-WHEELING SYSTEM 8,951,958
22 Other Elec (exclud Wheel)678,251
23 CALIFORNIA
24 ALL BLUE SKY RES 119,595
25 07XTRN0011-SALE ORDERS 111 .
26 DSM REV-CA SBC OFF 865,247
27 Fish, Wildlife. Recr 6,190
28 IDAHO
29 ALL BLUE SKY RES 83,377
30 DSM REV-ID SBC 5,939,833
31 Other Elec (exclud Wheel)-71
32 OREGON ..
33 ALL BLUE SKY RES 1,110,611
34 M&S INVENTORY REVENUE 67,699
35 3RD PARTY TRANS 281,550
36 DSM REVENUE - OREGON ECC 18,762,568
37 Other Elec (exclud Wheel)1,564,645
38 Other Elec DSR carr chrg 236,371
39 UTAH
40 ALL BLUE SKY RES 2,473,756
41 TOTAL Biled wil 1,732,81e 30,69 0.0721."
42 Total Unbiled Rev.(See Instr. 6)-170,39 ,..,.i'~, "((O.04ge
43 TOTAL 53,015,534\3,827,550,789 1,732,81e 30,591 0.072"
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 2010/Q4
(2) DA Resubmission 04/18/2011
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electcity 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 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 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 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.
¡Line ,'Iumoer ano 'Iiie or Kate scneaUie ivvvn ;:010 ~evenue Average. Numoer i:vvn_OT ;:aies ~Æ~~is~/derNo.(a)(b)(c)
ofc~~omers Per rà)stomer
(f)
1 M&S INVENTORY REVENUE 385,196
2 ELEC INC-CTHR 89,749
3 FL YASH SALES 1,735,998
4 3RD PARTY TRANS 150,755
5 DSM REV-UT SBC OFFSET 62,981,154
6 Fish, Wildlife, Recr 2,280
7 other Elec (exclud Wheel)-828
8 WASHINGTON
9 ALL BLUE SKY RES 159,211
10 DSM REVENUE - WA SBC 8,855,002
11 Other Elec (exclud Wheel)123
12 Fish, Wildlife, Recr 18,060
13 Wash Colstrip 3 -52,188
14 WYOMING
15 ALL BLUE SKY RES 220,490
16 M&S INVENTORY REVENUE 21,493
17 FL YASH SALES 910,611
18 WY Regulatory Recovery Fee 239,529
19 3RD PARTY TRANS 62,482
20 DSM REVENUE - WY SBC - CAT 1 701,985
21 DSM REVENUE - WY SBC - CAT 2 795,949
22 DSM REVENUE - WY SBC - CAT 3 545,133
23 FL YASH SALES 12,212
24 DSMREVENUE - WY SBC - CAT 1 215,502
25 DSM REVENUE - WY SBC - CAT 2 131,341
26 DSM REVENUE - WY SBC - CAT 3 301,427
27 Other Elec (exclud Wheel)9
28 TOTAL OTHER ELEC REVENUE 220,074,820
29
30 .
31
32
33
34
35
36
37
38
39
40
41 TOTAL Biled . m !I li "1,732,81E 30,69 0.0721
42 Total Unbiled Rev.(See Instr. 6)I -170,39 II "c (O.049E
43 TOTAL 53,015,53~3,827,550,789 1,732,81E 30,59E 0.072",
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 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 304.14 Line No.: 27 Column: a
01COST0041 - 01APSV0041 - 01APSV041X AG PMP
~chedule Page: 304 Line No.: 41 Column: b
The following table is a reconciliation of the biled and unbiled MW for the year 2010.
MWh
Total biled in 2010
12/31/2009 unbiled MWh reversal
Total MW eared and biled in 2010
53,185,926
(3,380,278)
49,805,648
12/31/2010 unbiled MW accrual 3,209,886
Total MW (unbiled and biled) in 2010 53,015,534
¡Schedule Page: 304 Line No.: 41 Column: c
The following table is a reconciliation of the biled and unbiled revenue for the year 2010.
Revenue
Total biled in 2010
12/31/2009 unbiled revenue reversal
Total revenue earned and biled in 2010
$3,906,998,905
(213,989,000)
3,693,009,905
12/31/2010 unbiled revenue accrual 205,559,000
Total revenue (unbiled and biled) in 2010 $3,898,568,905
¡Schedule Page: 304 Line No.: 42 Column: c
For fuer discussion on unbiled revenue refer to page 300, Electrc Operating Revenues, line 12, colum(b).
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) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ¡=A Resubmission 04/18/2011
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 electncity ( i.e., trnsactions 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 cotractual 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 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 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 Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly illng l-vera~e Aver~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Requirement Sales
2 Brigham City RQ T-12 19 19 17
3 Deaver, Town of RQ T-4 0.2 0.1 0.1
4 Helper City RQ T-6 1 1 1
5 Helper City Annex RQ T-6 0.7 0.6 0.6_RQ 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 12
10 Accrual True-up RQ NA NA NA NA
11
12 Nonrequirement Sales
13 Anaheim, City of SF T-12 NA NA NA
14 Arizona Public Service 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
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) (KAn Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO" in
column (a). The remaining såles may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter"Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t)o 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 (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g),(h)(i)ü)(k)
1
111,872 1,968,417 2,384,916 4,353,333 2
988 15,734 17,761 33,495 3
6,480 118,283 114,594 232,877 4
3,783 72,379 66,920 139,299 5
1,253 21,717 21,818 43,535 6
8,728 133,792 152,041 285,833 7
11,214 1,021,053 -".1,026,059 8.L ~.."% ~m
74,337 1,287:308 1,576,451 2,863,759 9
2,197 . 'A~fI r.62,547 10
11
12
6,200 238,700 238,700 13
400 .,.,.,12,800 14"~mi ø%/
220,852 3,617,630 5,355,554 67,553 9,040,737
11,193,740 21,018,791 670,763,569 -199,259,887 492,522,473
11,414,592 24,636,421 676,119,123 -199,192,334 501,563,210
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 2010/Q4
(2) i"A Resubmission 04/18/2011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column'(b), enter a Statistical Classification Code based on the onginal contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Leo, 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 RQservice. 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 availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing l\vera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Arizona Public Service Company SF T-12 NA NA NA
2 Avista Corporation SF T-13 NA NA NA
3 Avista Corporation SF T-12 NA NA NA
4 BP EnergyCompany SF T-12 NA NA NA
5 Barclays Bank PLC -T-12 NA NA NA
6 Barclays Bank PLC II T-12 NA NA NA
7 Basin Electric Power Cooperative "". ~
T-11 NA NA NA
8 Basin Electric Power Cooperative T-11 NA NA NA.
9 Basin Electric Power Cooperative r& "T-12 NA NA NAfi .
10 Basin Electric Power Cooperative SF T-11 NA NA NA
11 Basin Electric Power Cooperative SF T-12 NA NA NA
12 Black Hils Power, Inc..441 50 50 48
13 Black Hils Power, Inc.T-12 NA NA NA
14 Black Hils Power, Inc.SF 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 310.1
.-
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) (KAn Original (Mo, Da, Yr)End of 2010/04
(2) r'A Resubmission 04/18/2011
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 - 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 schedulesor tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) inwhich 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 çolumn (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)
25,328 915,108 915,108 1
57 .~2,254 2,,~ ø ,lmwøMW!
51,725 .1,651,335 1,651,335 3
19,368 598,764 598,764 4
409 ." ¡¡20,568 5
620,313 38,439,814 38,439,814 6
2,991 .øw ø ø - -91,095 70
232 --9,766 8
78 3,582 3,582 9
1,116 ~1I:39,915 10
138,207 5,054,254 5,054,254 11
352,993 7,310,280 5,662,460 12,972,740 12
6,037 217,404 217,404 13
82,726 3,104,002 3,104,002 14
220,852 3,617,630 5,355,554 67,553 9,040,737
11,193,740 21,018,791 670,763,569 -199,259,887 492,522,473
11,414,592 24,636,421 676,119,123 .199,192,334 501,563,210
FERC FORM NO.1 (ED. 12.90)Page 311.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 20~0/Q4
(2) r'A Resubmission 04/18/2011
SALES FOR RESALE (Accunt 41 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 reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and 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 Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIling l\vera~e Avera~cation Tarif Number Demand (MW) Monthly NC Demani Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Bonnevile Power Administration 519 NA NA NA
2 Bonnevile Power Administration ,.T-11 NA NA NA
3 Bonnevile Power Administration fM.T-12 N,I NA NA
4 Bonneville Power Administration 368 N,I NA NA!%ø'
5 Bonnevile Power Administration '" .fM ,.T-11 N,I NA NA
6 Bonnevile Power Administration fMll 519 NA NA NA
7 Bonnevile Power Administration SF T-11 N,I NA NA
8 Bonnevile Power Administration SF T-13 N,I NA NA
9 Bonnevile Power Administration SF T-12 NA NA NA1O_SF T-13 NA NA NAW " &jJ,f /', % ~ _11' 'ii%' . ß.' %,.' ._T-12 NA NA NA.ø "it.."/ "%' ........ìi %
12 California Independent System Operator s~..T-12 NA NA NA
13 Cargil Power Markets, LLC _T-12 NA NA NA
14 Cargil Power Markets, LLC SF T-11 NA N.A 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
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatt.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on 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.
Year/Period of Report
End of 2010/Q4
MegaWatt Hours
Sold
Line
No.
REVENUE
Energy Charges
($)
(i)
Other Charges
($)
0)
Demand Charges
($)
(h)(g)
5
1,850
2,571
35,570
1
8
81,992
21
170
408,091
2,022
6,754
220,852
11,193,740
11,414,592
3,617,630
21,018,791
24,636,421
5,355,554
670,763,569
676,119,123
67,553
-199,259,887
-199,192,334
FERC FORM NO.1 (ED. 12-90)Page 311.2
Total ($)
(h+i+j)
(k)
206,336 1
216 2
120,206 3
61,133 4
90,898 5
2,614,039 6
25 7
336 8
2,826,672 9
549 10
112,274 11
12,480,046 12
44,817 13
196,574 . 14
9,040,737
492,522,473
501,563,210
Name of Respondent This ø0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ÕA Resubmission 04/18/2011
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 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 asLF, 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 Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly U1ing Avera~e Averafl
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Cargil Power Markets, LLC .SF T-12 NA NA NA
2 Citigroup Energy, Inc.T-12 NA NA NA
3 Citigroup Energy, Inc.SF T-12 NA NA NA
4 City of Burbank SF T-12 NA NA NA
5 City of Redding SF T-12 NA NA NA
6 Clatskanie People's Utilty District SF T-12 NA NA NA
7 Colorado Springs Utilties T-12 NA NA NA
8 Colqrado Springs Utilties SF T-12 NA NA NA
9 ConocoPhillps Company SF T-12 NA NA NA10_,SF T-11 NA NA NA"j:m 9/ ,';e ø ~' w
11 Constellation Energy Commodities Group SF T-11 NA NA NA
12 Constellation Energy Commodities Group SF T-12 NA NA NA
13 Credit Suisse Energy LLC T-12 NA NA NA
14 Credit Suisse Energy LLC SF 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 310.3
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
.SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote,
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t)o For all other types of service, enter NA in columns (d), (e) and (t)o Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energycharges 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)
1,116,467 42,47,033 42,447,033 1
166 -'¡W il -~"14,111 2
933,729 48,006,404 48,006,404 3
19,800 682,800 682,800 4
15,043 553,579 553,579 5
72 2,712 2,712 6
160 2,960 2,960 7
335 6,478 6,478 8
56,256 2,005,952 2,005,952 9
512 ~17,987 10
55 -.'";.. % "2,064 11
95,659 3,434,253 3,434,253 12
151 _m,~20,012 13
43,400 2,888,900 2,888,900 14
220,852 3,617,630 5,355,554 67,553 9,040,737
11,193,740 21,018,791 670,763,569 -199,259,887 492,522,473
11,414,592 24,636,421 676,119,123 -199,192,334 501,563,210
FERC FORM NO.1 (ED. 12-90)Page 311.3
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04118/2011
SALES FOR RESALE; (Accunt 4'7)
1. Report all sales for resale (Le., salesto 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, étc.) 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 (Leo, 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 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 Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing Avera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f).
1 DB Energy Trading LLC '"T-12 NA NA NA
2 DB Energy Trading LLC SF T-12 NA NA NA
3 Deseret Power Electric Cooperative SF T-11 NA NA NA
4 EDF Trading North America, LLC SF T-12 NA NA NA
5 EI Paso Electric Company SF T-12 NA NA NA
6 Endure Energy, LLC SF T-12 NA NA NA
7 Eugene Water & Electric Board SF T-11 NA NA NA
8 Eugene Water & Electric Board SF T-12 NA NA NA
9 Gila River Power, L.P."T-12 NA NA NA
10 Gila River Power, L.P.SF T-11 NA NA NA
11 Gila River Power, L.P.SF T-12 NA NA NA
12 Glendale, City of SF T-12 NA NA NA
13 Hurricane, City of T-12 NA NA NA
14 Iberdrola Renewables, Inc.T-11 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 310.4
Name of Respondent This 180rt Is: 'Date of Report Year/Period of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) ¡=A Resubmission 04/18/2011
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD- for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in cólumn (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)o For all other types of service, enter NA in columns (d), (e) and (t)o Monthly NCP demand is the maximum
metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column(g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i); and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser..
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)-Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
17 "B -~-ff_136 1im
596,590 35,081,629 35,081,629 2
39 --.1,305 3
423,350 14,962,652 14,962,652 4
12,407 513,122 513,122 5
7,380 294,285 294,285 6
140 ,.~4,707 7
10,995 357,676 357,676 8
-1 ~-9
31 .940 10
105,390 3,743,525 3,743,525 11
3,000 92,000 92,000 12
202 15,150 15,150 13
2,884 _uQ.__-95,640 14
220,852 3,617,630 5,355,554 67,553 9,040,737
11,193,740 21,018,791 670,763,569 -199,259,887 492,522,473
11,414,592 24,636,421 676,119,123 -199,192,334 501,563,210
FERC FORM NO.1 (ED. 12-90)Page 311.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contrctual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Leo, the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
ofRQ 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 Averaße Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule 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 Iberdrola Renewables, Inc.SF T-11 NJl NJl NA
2 Iberdrola Renewables, Inc.SF T-12 NJl NJl NA
3 Idaho Power Company T-11 NJl NJl NA
4 Idaho Power Company SF T-11 NA NJl NA
5 Idaho Power Company SF T-13 NA NJl NA
6 Idaho Power Company SF T-12 NA NA NA
7 Intermountain Renewable Power, LLC Wl"T-11 Nfl NJl NA*'J
8 Intermountain Renewable Power, LLC ø T-11 NJl NJl NA"i-"
9 J. Aron & Company ~T-12 NA NA NA
10 JP Morgan Ventures Energy Corporation T-12 NA NA NA
11 JP Morgan Ventures Energy Corporation SF T-11 NA NA NA12 ..T-12 NA NA NA
13" WA" ~*/" "WAm" % ."" mEl .. .301 NA NA NA,~ _m '% %
14 Los Angeles Dept. of Water & Power SF T-11 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
Name of Respondent This 780rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo,Da, Yr)End of 2010/Q4
(2) r'A Resubmission 04/18/2011
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
. non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups"for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
5. 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 (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on 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 instruction4), 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 expianations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges ~(h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
1,513 ,. ~:ø '51,070 1
287,727 9,679,291 9,679,291 2
2,644 ..90,235 3
3,581 ". '131,365 4",
715 ~.~. .,," ""24,013 5.~~"mm"*"
11,557 425,780 425,780 6
1,411 ~43,199 7::.i17_)W ~ W%
629 -"24,449 8*.;.&ig îl ii,"M iM ßt&t M %o, %
28,981 1,005,662 1,005,662 9
184 -..4,426 10
1,881 _'IWÆ% "53,987 11.a,"'" .ß
145,535 5,911,745 5,911,745 12
564,732 27,947,142 ~.:27,947,142 13
1,693 58,344 14
220,852 3,617,630 5,355,554 67,553 9,040,737
11,193,740 21,018,791 670,763,569 -199,259,887 492,522,473
11,414,592 24,636,421 676,119,123 .199,192,334 501,563,210
FERC FORM NO.1 (ED. 12-90)Page 311.5
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ¡=A Resubmission 04/18/2011
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricit ( 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 (Leo, the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the 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-Schedule or Monthly iIing Avera~e .Avera~cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Los Angeles Dept. of Water & Power SF T-12 .NJl NA NA
2 Macquarie Energy LLC SF T-11 NA NA NA
3 Macquarie Energy LLC SF T-12 NA NA NA~SF T-12 NA NA NAI%
5 Modesto Irrigation District SF T-12 NA NA NA
6 Morgan Stanley Capital Group, Inc.-T-12 NA NA NA
7 Morgan Stanley Capital Group, Inc.SF T-11 NA NA NA
8 Morgan Stanley Capital Group, Inc.SF T-12 NA NA NA
9 Municipal Energy Agency of Nebraska SF T-11 NA NA NA
10 Municipal Energy Agency of Nebraska SF T-12 NA NA NA
11 Nevada Power Company r T-12 NA NA NA
12 NextEra Energy Power Marketing, LLC %' ,.T-11 NA NA NA
13 NextEra Energy Power Marketing, LLC -T-11 NA NA NA
14 NextEra Energy Power Marketing, LLC SF T-11 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 310.6
Name of Respondent This Report Is:Date of Report Year/Periòd of Report
PacifiCorp (1) (8An Original (Mo, Da, Yr)End of 2010/Q4
(2)riA Resubmission 04/18/2011
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 öf 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 "Tötal"
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 tariff 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)o For all other types of service, enter NA in columns (d), (e) and (t)o 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 amegawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
445,890 16,841,099 16.841,099 1
58 ø Wi.' m'"'w'1,526 2
62,553 2,199,869 2,199,869 3
49,975 1,859,359 1,859,359 4
12,240 530,360 530,360 5
2,825 82,161 6
7,656 251,595 7
1,395,927 65,086,374 65,086,374 8
87 ~2,883 9
17,060 629,545 629,545 10
996,819 33,732,523 33,732,523 11
2 ."0'...m"'~"
78 12.,
10,897 347,368 13
275 8,086 14
220,852 3,617,630 5,355,554 67,553 9,040,737
11,193,740 21,018,791 670,763,569 -199,259,887 492,522,473
11,414,592 24,636,421 676,119,123 -199,192,334 501,563,210
FERC FORM NO.1 (ED. 12-90)Page 311.6
Name of Respondent This (80rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/18/2011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this' schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or 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 (Leo, 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 tong4erm service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU -for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and 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-Schedule or Monthly iIing Avera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 NextEra Energy Power Marketing, LLC SF T-12 NA NA NA
2 NorthWestem Corporation SF T-13 NA NA NA
3 NorthWestern Corporation SF T-12 NA NA NA
4 Northern California Power Agency SF T-12 NA NA NA
5 Northpoint Energy Solutions Inc.SF T-12 NA NA NA
6 PPL EnergyPlus, LLC SF T-12 NA NA NA
7 PPL Montana, LLC SF T-11 NA NA NA
8 Pacifc Gas & Electric Company 'ir-T-12 NA NA NA.,,,,,IWM?:r
9 Pacific Gas & Electric Company SF T-12 NA NA NA
10 ii %"~~ ~_SF T-12 NA NJI NAm;ø.w ",,%
11 Pacific Summit Energy LLC SF T-12 NA NI NA
12 Portland General Electric Company SF T-11 NA NA NA
13 Portland General Electric Company SF T-12 NA NA NA
14 Portland General Electric Company 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 310.7
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) IKAn Original (Mo, Da, Yr)End of 2010/Q4
(2)¡=A Resubmission 04/18/2011
SALES FOR RESALE (Accunt 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups. for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The. remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (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 (j). Explain in a footnote all components of the amount shown in column (j. . Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal. RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
1,406 43,428 43,428 1
251 -..8,595 2
554 23,943 23,943 3
2,134 92,460 92,460 4
95 4,175 4,175 5
53,471 1,831,155 1,831,155 6
620 ~..".21,898 7ø,%
653,474 22,907,829 22,907,829 8
4,357 159,704 159,704 9
945 37,325 37,325 10
6,800 203,200 203,200 11
369 -12,044 12¡¡
78,647 2,632,681 2,632,681 13
178 BJ'M % II " ""5,820 14i¡
220,852 3,617,630 5,355,554 67,553 9,040,737
11,193,740 21,018,791 670,763,569 -199,259,887 492,522,473
11,414,592 24,636,421 676,119,123 -199,192,334 501,563,210
FERC FORM NO.1 (ED. 12-90)Page 311.7
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1 )!KAn Original (Mo, Da, Yr)End of 2010/Q4
(2)r"A Resubmission 04/18/2011
SALES FOR RESALE (Account 4'7)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or 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 (Leo, 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 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~e Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly illng Avera~e Averai¥
cation Tariff Number Demand (MW)Monthly NC Deman(Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Powerex Corporation --T-12 NA NA NA
2 Powerex Corporation *~. .T-11 NA NA NA
3 Powerex Corporation SF T-11 NA NA NA
4 Powerex Corporation SF T-12 NA NA NA
5 Public Service Company of Colorado -320 NA NA NA
6 Public Service Company of Colorado .320 71 65 59
7 Public Service Company of Colorado SF T-11 NA NA NA
8 Public Service Company of Colorado SF T-12 NA NA NA
9 Public Service Company of New Mexico SF T-12 NA NA NA~SF T-12 NA NA NA11' . __SF T-13 NA NA NA~ , ß m Wi li" %~12 PUD #2 of Grant County SF T~12 NA NA NA
13 Puget Sound Energy, Inc.SF T-13 NA NA NA
14 Puget Sound Energy, Inc.SF 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 310.8
Name of Respondent This '00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated Units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups. for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter .Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f. For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
31 !i 1,000 1%
14,932 ".
"- "%.477,737 2,.!i %
13,177 ~389,753 3
405,582 11,590,434 11,590,434 4..-"4 -772,626 5%
465,388 9,295,320 21,453,044 30,748,364 6
1,179 ~"35,818 7"
211,07S 6,832,397 6,832,397 8
154,575 5,933,724 5,933,724 9
14,140 511,530 511,530 10
8 rø..A 314 11
15,232 530,880 530,880 12
184 -6,720 13ir,,% ',/
80,059 2,658,692 2,658,692 14
220,852 3,617,630 5,355,554 67,553 9,040,737
11,193,740 21,018,791 670,763,569 -199,259,887 492,522,473
11,414,592 24,636,421 676,119,123 -199,192,334 561,563,210
FERC FORM NO.1 (ED. 12-90)Page 311.8
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1 )(8An Original (Mo, Da, Yr)End of 2010/Q4
(2)DA Resubmission 04/18/2011 .
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 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 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.
.
Statistical FERC Rate Averaße Actual Demand (MW)Line Name of Company or Public Authority
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing l\vera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Rainbow Energy Marketing Corporation SF T-11 NA NA NA
2 Rainbow Energy Marketing Corporation SF T-12 NA NA NA
3 Sacramento Municipal Utilty District lI 250 NA NA NA
4 Sacramento Municipal Utilty District "VÆ II 250 NA NA NA
5 Sacramento Municipal Utilty District . SF T-13 NA NA NA
6 Sacramento Municipal Utilty District :-T-12 NA NA NA
7 Salt River Project " fiA T-12 NA NA NA
8 Salt River Project SF T-11 NA NA NA
9 Salt River Project SF T-12 NA NA NA
10 San Diego Gas & Electric Company -T-12 NA NA NA
11 San Diego Gas & Electric Company -T-12 NA NA NA
12 San Diego Gas & Electric Company SF T-12 NA NA NA
13 Santa Clara, City of SF T-12 NA NA NA
14 Seattle City Light -m T-11 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 310.9
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) !KAn Oiiginal (Mo, Da, Yr)End of 2010/Q4
(2) f"A Resubmission 04/18/2011
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 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). 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)o For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on 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)0)(k)
1,305 .L-36,998 1m
130,568 4,381,839 4,381,839 2~."W .146,668 3
551,131 13,238,167 13,238,167 4
6 ~Alw ."134 5
54,683 1,843,055 1,843,055 6
25 913 ~913 7
708 20,372 8
82,888 2,646,978 2,646,978 9
319 -12,058 10I! I!
341,410 10,831,286 10,831,286 11
3,206 71,045 71,045 12
3,390 69,095 69,095 13
2,249 _fîl!U 69,711 14~"
220,852 3,617,630 5,355,554 67,553 9,040,737
11,193,740 21,018,791 670,763,569 -199,259,887 492,522,473
11,414,592 24,636,421 676,119,123 -199,192,334 501,563,210
FERC FORM NO.1 (ED. 12-90)Page 311.9
Name of Respondent This ÎÊ0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) OA Resubmission 04/18/2011
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 reliaQle 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 asLF 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 ofcommitmEmt 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 avaiiabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU 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 Averaßr Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly illng l\vera~e Avera~
cation Tari Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Seattle City Light SF T-11 NJ!NJl NA
2 Seattle City Light SF T-13 NJ!NA NA
3 Seattle City Light SF T-12 NJ!NJl NA
4 Sempra Energy Trading LLC T-12 NJ!NA NA
5 Sempra Energy Trading LLC SF T-12 NJ!NA NA
6 Sempra Generation SF T-12 NJ!NA NA
7 Shell Energy North America (US), L.P..T-12 NA NA NA
8 Shell Energy North America (US), L.P." !I .T-12 NJ!NA NA
9 Shell Energy North America (US), L.P.SF T-11 NA NA NA
10 Shell Energy North America (US), L.P.SF T-12 NA NA NA
11 Sierra Pacific Power Company -p T-11 NA NA NA;w:.
12 Sierra Pacific Power Company SF T-11 NA NA NA
13 Sierra Pacific Power Company SF T-13 NA NA NA
14 Southern California Edison Company ,'v' ~~M T-12 NA NA NA"
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12.90)Page 310.10
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/18/2011
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other 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 RQlNon-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges .(h+i+j)No.
($)($)($)
(g)(h)(i)')(k)
1 -&1 24 1
1 ....43 2
15,006 488,987 488,987 3
491 ..ii 22,389 4
403,363 .21,197,505 21,197,505 5
14,000 497,016 497,016 6
91 ~IA ;. .w'-,6,798 7
100 4,800 4,800 8
24 .0_875 9m
901,993 41,185,881 41,185,881 10
817 ~,.26,42 11.
84 ....",3,531 12
222 .'Wi!PW M ii ii 8,438 13.il '"M
327,600 11,148,438 11,148,438 14
220,852 3,617,630 5,355,554 67,553 9,040,737
11,193,740 21,018,791 670,763,569 -199,259,887 492,522,473
11,414,592 24,636,421 676,119,123 -199,192,334 501,563,210
FERC FORM NO.1 (ED. 12-90)Page 311.10
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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 ofthe 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 ofthe contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU 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-Schedule or Monthly illng l\vera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)~(f)
1 Southern California Edison Company SF T-11 NA NA NA
2 Southern California Edison Company SF T-11 NA NA NA
3 Southern California Edison Company SF T-12 NA NA NA
4 Southwestern Public Service Company SF T-12 NA NA NA
5 Tacoma Power SF T-13 NA NA NA
6 Tacoma Power SF T-12 NA NA NA
7 The Energy Authority SF T-11 NA NA NA
8 The Energy Authority SF T-12 NA NA NA
9 TransAlta Energy Marketing Inc...We T-12 NA NA NA~
10 TransAlta Energy Marketing Inc.SF T-11 NA NA NA
11 TransAlta Energy Marketing Inc.SF T-12 NA NA NA
12 TransCanada Energy Sales Ltd.SF T-12 NA NA NA13_SF T-11 NA NA NA
14 Tri-State Gen. & Trans. SF T-12 0.4 0.4 0.1
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:Oate of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Oa, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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 - 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)o For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60"minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on 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)ü)(k)
1,526 ~47,259 1- ~
433 .~ ii J" ¡K ii ,...12,832 2_~.W&#".
14,130 . 587,480 587,480 3
45,957 1,764,174 1,764,174 4
7 ~184 5
1,375 25,175 25,175 6
1
.~..h"~39 7
9,937 354,075 354,075 8
1,314,945 46,545,738 ~46,545,738 9
250 9,358 10
225,794 7,921,333 7,921,333 11
15 404 404 12
19 ~AI 645 13
206,863 16,991 6,891,467 6,908,458 14
220,852 3,617,630 5,355,554 67,553 9,040,737
11,193,740 21,018,791 670,763,569 -199,259,887 492,522,473
11,414,592 24,636,421 676,119,123 -199,192,334 501,563,210
FERC FORM NO.1 (ED. 12-90)Page 311.11
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) riA Resubmission 04/18/2011
SALES FOR RESALE (Accunt 447).
1. Report all sales for resale (Leo, 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 reliabilty of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service Which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU 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-Schedule or Monthly iIing Avera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Tucson Electric Power Company SF T-12 NA NA NA
2 Turlock Irrgation District SF T-12 NA NA NA
3 UNS Electric, Inc.SF T-12 NA NA NA
4 Utah Associated Municipal Power Systems Wi.T.12 NA NA NA
5 Utah Associated Municipal Power Systems SF T-11 NA NA NA
6 Utah Associated Municipal Power Systems SF T-12 NA NA .NA
7 Utah Municipal Power Agency _æ 433 34 34 34
8 Utah Municip;:l Power Agency SF T-3 Nfl NA NA
9 Western Area Power Administration ~T-11 N)NA NArø..
10 Western Area Power Administration .1 T-11 Nfl NA NA
11 Western Area Power Administration SF T-11 Nfl NA NA
12 Western Area Power Administration ;-T-12 NA NA NA
13 Test Generation ¡¡NA N)NA NA
14 Bookout Sales AD NA NA NA NA
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.12
Name of Respondent This 180rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/18/2011
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly 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 servìce, 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 (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 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)(j)(k)
136,728 5,217,828 5,217,828 1
7,987 252,416 252,416 2
190,872 6,054,106 6,054,106 3
61,410 1,748,072 1,748,072 4
142 ._!&ø 4,197 5
875 34,941 34,941 6
21S,938 4,396,200 5,018,399 9,414,599 7
1,530 67,900 67,900 8
142 ~."59,501 9m
1,633 ...97,482 10
5,801 l.'"99,338 11"
203,267 8,482,416 8,482,416 12
-41,215 -556,235 13
-5,780.963 -184,282,163 14
220,852 3,617,630 5,355,554 67,553 9,040,737
11,193,740 21,018,791 670,763,569 -199,259,887 492,522,473
11,414,592 24,636,421 676,119,123 -199,192,334 501,563,210
FERC FORM NO.1 (ED. 12-90)Page 311.12
Name of Respondent This Re ort Is:Date of Report Year/Period of Report
PacifiCorp (1) ~An Original (Mo, Da, Yr)End of 2010/Q4
(2)A Resubmission 04/18/2011
SALES FOR RESALE (Account 4'7)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity (Le., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or 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 notbe 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 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 Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing lwera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
.(a)(b)(c)(d)(e)(f)
1 Trade Sales IF NA NA NA NA
2 Accrual True-up NA NA NA NA NA
3 .
4
5
6
7
8
9
10
11
12
13
14
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.13
_.
Name of Respondent This 'r0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariff under
which service, as identified in column (b), is provided.
6. Forrequirements 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 (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be inmegawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k).,~-17,492,110 1.% .".
7,286 _ . "-a"_150,119 2v,~iMiL %. f0 %!
3
4
5
6
7
-8
9
10
11
12
13
14
220,852 3,617,630 5,355,554 67,553 9,040,737
11,193,740 21,018,791 670,763,569 -199,259,887 492,522,473
11,414,592 24,636,421 676,119,123 -199,192,334 501,563,210
FERC FORM NO.1 (ED. 12-90)Page 311.13
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 310 Line No.: 6 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "NAVAJO TRIAL UTIL AUTH (MEXICAN HAT)" ON PAGES
310 - 311: Complete name is Navajo Tribal Utilìty Authority (Mexican Hat).
!§chedule Page: 310 Line No.: 7 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "NAVAJO TRAL UTL AUT (RD MESA)" ON PAGES 310 -
3 I I: Complete name is Navajo Tribal Utìlty Authority (Red Mesa).
!§chedule Page: 310 Line No.: 8 Column: j
Settlement Adjustment
!§chedule Page: 310 Line No.: 10 Column: j I
Represents the difference between actul requirement sales revenues for the period as reflected on the ìndividuallìne ìtems wìthin this
schedule, and the accruals charged to account 447 durin 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.: 5 Column: b
Settlement Adjustment.
!§chedule Page: 310.1 Line No.: 5 Column: j
Settlement Adjustment
!§chedule Page: 310.1 Line No.: 7 Column: b
Settlement Adjustment.
I$chedule Page: 310.1 Line No.: 7 Column: j
Settlement Adjustment
¡Schedule Page: 310.1 Line No.: 8 Column: b
Basìn Electrc Power Company - FERC T-I I (Evergreen Network Transmission Service under the Open Access Transmission Tarff
(S.A. 505)) - Contrct termìnation date: no earlier than 12 months from notice by the customer.
!§chedule Page: 310.1 Line No.: 8 Column: j
Transmission Losses
!§chedule Page: 310.1 Line No.: 9 Column: b
Secondary, Economy and/or non-firm sales, includig some hourly firm trsactions.
¡Schedule Page: 310.1 Line No.: 10 Column: j
Transmission Losses
!§chedule Page: 310.1 Line No.: 12 Column: b
Black Hils Power & Light Company - FERC 441 - Contract termìnation date: December 31, 2023.
!§chediile Page: 310.1 Line No.: 13 Column: b
Seconda, Economy and/or non-firm sales, includìng some hourly fi transactions.
!§chedule Page: 310.2 Line No.: 1 Column: b
Settlement Adjustment.
!§chedule Page: 310.2 Line No.: 1 Column: j
Settlement Adjustment
!§chedule Page: 310.2 Line No.: 2 Column: b
Settlement Adjustment.
!§chedule Page: 310.2 Line No.: 2 Column: j
Settlement Adjustment
¡Schedule Page: 310.2 Line No.: 3 Column: b
Settlement Adjustment.
!§chedule Page: 310.2 Line No.: 3 Column: j
Settlement Adjustment
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, Oa, Yr)
PacifiCorp 1(2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 310.2 Line No.: 4 Column: b
Bonnevile Power Administration - FERC R.S. 368 (Use of Facilities Agreement for the Malin Transformer under the AC Intertie
Agreement with BP A) - Contract termination date: Upon mutual agreement.
¡Schedule Page: 310.2 Line No.: 4 Column: j
Transmission Losses
¡Schedule Page: 310.2 Line No.: 5 Column: b
Bonnevile Power Admnistration - FERC T-ll (Point-to-Point Transmission Service under the Open Access Transmission Tarff
(SA 179)) - Contract termnation date: September 30, 2025.
¡Schedule Page: 310.2 Line No.: 5 Column: j
Transmission Losses
¡Schedule Page: 310.2 Line No.: 6 Column: b
Bonnevile Power Administration - FERC 519 - Contract termnation date: April 22, 2024.
¡Schedule Page: 310.2 Line No.: 7 Column: j
Transmission Losses
¡Schedule Page: 310.2 Line No.: 8 Column: j
Reserve Share
¡Schedule Page: 310.2 Line No.: 10 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "BRITISH COLUMIA TRNSMISSION CORP." ON PAGES 310-
311: Complete name is British Columbia Transmission Corporation.
¡Scheduie Page: 310.2 Line No.: 10 Column: j
Reserve Share
ISchedule Page: 310.2 Line No.: 11 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "CALIFORN INEPENDENT SYSTEM OPERATOR" ON
PAGES 310 - 311: Com lete name is California Inde endent S stem 0 erator Co oration.
chedule Pa e: 310.2 Line No.: 11 Column: b
Settlement Adjustment.
¡Schedule Page: 310.2 Line No.: 11 Column: j
Settlement Adjustment
¡Schedule Page: 310.2 Line No.: 13 Column: b
Settlement Adjustment.
¡Schedule Page: 310.2 Line No.: 13 Column:j
Settlement Adjustment
¡Schedule Page: 310.2 Line No.: 14 Column: j
Transmission Losses
¡Schedule Page: 310.3 Line No.: 2 Column: b
Settlement Adjustment.
¡Schedule Page: 310.3 Line No.: 2 Column: j
Settlement Adjustment
¡Schedule Page: 310.3 Line No.: 7 Column: b
Secondar, Economy and/or non-firm sales, including some hourly firm transactions.
¡Schedule Page: 310.3 Line No.: 10 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "CONSTELLATION ENERGY COMMODITIES GROUP" ON
PAGES 310 - 311: Complete name is Constellation Energ Commodities Group, Inc.
chedule Pa e: 310.3 Line No.: 10 Column: j
Transmission Losses
¡Schedule Page: 310.3 Line No.: 11 Column: j
Unauthorized use charges
¡Schedule Page: 310.3 Line No.: 13 Column: b
Settlement Adjustment.
¡Schedule Page: 310.3 Line No.: 13 Column:j
Settlement Adjustment
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 04/18/2011 2010104
.FOOTNOTE DATA
!Schedule Page: 310.4 Line No.: 1 Column: b
Settlement Adjustment.
'$chedule Page: 310.4 Line No.: 1 Column: j
Settlement Adjustment
'$chedule Page: 310.4 Line No.: 3 Column: j
Transmission Losses
'$chedule Page: 310.4 Line No.: 7 Column:j
Transmission Losses
!Schedule Page: 310.4 Line No.: 9 Column: b
Settlement Adjustment.
¡Schedule Page: 310.4 Line No.: 10 Column: j
Trasmission Losses
'$chedule Page: 310.4 Line No.: 13 Column: b
Hurcane, City of - FERC T -12 - Contract termination date: Augut 31, 2007.
'$chedule Page: 310.4 Line No.: 14 Column: b
Iberdrola Renewables, Inc. - FERC t -11 (Point-to-Point Transmission Service under the Open Access Transmission Tariff (5th
revised S.A. 279))- Contract termation date: April 30, 2014.
'$chedule Page: 310.4 Line No.: 14 Column: j
Transmission Losses
'$chedule Page: 310.5 Line No.: 1 Column: j
Transmission Losses
'$chedule Page: 310.5 Line No.: 3 Column: b
Idaho Power Company - FERC T-ll (Point-to-Point Trasmission Service under the Open Access Transmission Tariff (5th revised
SA 212)) - Contract termination date: May 31, 2012.
!Schedule Page: 310.5 Line No.: 3 Column:j
Transmission Losses
'$chedule Page: 310.5 Line No.: 4 Column: j
Trasmission Losses
'$chedule Page: 310.5 Line No.: 5 Column: j
Reserve Share
'$chedule Page: 310.5 Line No.: 7 Column: b
Intermountain Renewable Power, LLC - FERC T-ll (Point-to-Point Transmission Service under the Open Access Transmission
Tarff (SA 568)) - Contract termnation date: April 30, 2029.
'$chedule Page: 310.5 Line No.: 7 Column: j
Transmission Losses
'$chedule Page: 310.5 Line No.: 8 Column: b
Intermountain Renewable Power, LLC - FERC T -11 (Point-to-Point Trasmission Service under the Open Access Transmission
Tarff (SA 568)) - Contract termation date: April 30, 2029.
!Schedule Page: 310.5 Line No.: 8 Column: j
Unauthorized use charges
!Schedule Page: 310.5 Line No.: 10 Column: b
Settlement Adjustment.
!Schedule Page: 310.5 Line No.: 10 Column: j
Settlement Adjustment
'$chedule Page: 310.5 Line No.: 11 Column:j
Transmission Losses
'$chedule Page: 310.5 Line No.: 13 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "LOS ANGELES DEPT. OF WATER & POWER" ON PAGES 310 -
311: Complete name is Los Angeles Departent of Water and Power.
!Schedule Page: 310.5 Line No.: 13 Column: b
Los Angeles Departent of Water and Power - FERC 301 - Contract teation date: June 15,2027.
IFERC FORM NO.1 (ED. 12-87) Page 450.3
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 04/18/2011 2010/Q4
FOOTNOTE DATA
ISchedule Page: 310.5 Line No.: 14 Column: j
Transmìssion Losses
~chedule Page: 310.6 Line No.: 2 Column: j
Transmission Losses
~chedule Page: 310.6 Line No.: 4 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "METROPOLITAN WATER DISTRICT OF S. CAL." ON PAGES
310 - 311: Complete name is Metropolita Water Distrct of Southern California.
~chedule Page: 310.6 Line No.: 6 Column: b .
Settlement Adjustment.
~chedule Page: 310.6 Line No.: 6 Column: j
Settiement Adjustment
~chedule Page: 310.6 Line No.: 7 Column: j
Transmission Losses
~chedule Page: 310.6 Line No.: 9 Column:j
Transmission Losses
~chedule Page: 310.6 Line No.: 11 Column: b
Nevada Power Company - WSPP - Contract termination date: December 31, 2010
~chedule Page: 310.6 Line No.: 12 Column: b
Settlement Adjustment.
ISchedule Page: 310.6 Line No.: 12 Column: j
Settlement Adjustment
ISchedule Page: 310.6 Line No.: 13 Column: b
NextEra Energy Power Marketing, LLC - FERC T -11 (Point-to-Point Trasmission Service under the Open Access Transmission
Tarff (S.A. 626)) - Contract termination date: December 31, 2011.
ISchedule Page: 310.6 Line No.: 13 Column:j
Transmission Losses
ISchedule Page: 310.6 Line No.: 14 Column: j
Unauthorized use charges
~chedule Page: 310.7 Line No.: 2 Column: j
Reserve Share
ISchedule Page: 310.7 Line No.: 7 Column: j
Transmission Losses
~chedule Page: 310.7 Line No.: 8 Column: b
Pacific Gas & Electrc Company - WSPP - Contract termination date: December 31,2012~chedule Page: 310.7 Line No.: 10 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PACIFIC NORTHWEST GENERATING COOP." ON PAGES 310"'
311: Complete name is Pacific Northwest Generating Cooperative, Inc.
~chedule Page: 310.7 Line No.: 12 Column: j
Transmission Losses
~chedule Page: 310.7 Line No.: 14 Column:j
Reserve Share
~chedule Page: 310.8 Line No.: 1 Column: b
Settlement Adjustment.
~chedule Page: 310.8 Line No.: 1 Column: j
Settlement Adjustment
~chedule Page: 310.8 Line No.: 2 Column: b
PowerEX - FERC T-11 (Point-to-Point Transmission Service under the Open Access Transmission Tariff (4th revised S.A. 169))-
Contract termnation date: September 30,2012.
~chedule Page: 310.8 Line No.: 2 Column: j
Transmission Losses
~chedule Page: 310.8 Line No.: 3 Column: j
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 04/18/2011 2010/Q4
FOOTNOTE DATA
Trasmission Losses
I$chedule Page: 310.8 Line No.: 5 Column: b
Settlement Adjustment.
¡Schedule Page: 310.8 Line No.: 5 Column: j
Settlement Adjustment
¡Schedule Page: 310.8 Line No.: 6 Column: b
Public Service Com an of Colorado - FERC 320 - Contrct termtion date: December 31, 2011.
chedule Pa e: 310.8 Line No.: 7 Column:'
Transmission Losses
~chedule Page: 310.8 Line No.: 10 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PUD #1 OF SNOHOMISH COUNTY' ON PAGES 310- 311:
Complete name is Public Utility Distrct NO.1 of Snohomish County.
~chedule Page: 310.8 Line No.: 11 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PUD #2 OF GRANT COUNTY" ON PAGES 310- 311: Complete
name is Public Utility Distrct NO.2 of Grant County.
¡Schedule Page: 310.8 Line No.: 11 Column:j
Reserve Share
~chedule Page: 310.8 Line No.: 13 Column:j
Reserve Share
~chedule Page: 310.9 Line No.: 1 Column:j
Transmission Losses
~chedule Page: 310.9 Line No.: 3 Column: b
Settlement Adjustment.
~chedule Page: 310.9 Line No.: 3 Column: j
Settlement Adjustment
¡Schedule Page: 310.9 Line No.: 4 Column: b
Sacramento Municipal Utility Distrct - PERC 250 - Contract termination date: December 31, 2014.
~chedule Page: 310.9 Line No.: 5 Column: j
Reserve Share
¡Schedule Page: 310.9 Line No.: 7 Column: b
Salt River Project - WSPP - Contract termination date: December 31, 2009.
¡Schedule Page: 310.9 Line No.: 8 Column: j
Transmission Losses
¡Schedule Page: 310.9 Line No.: 10 Column: b
Settlement Adjustment.
~chedule Page: 310.9 Line No.: 10 Column: j
Settlement Adjustment
¡Schedule Page: 310.9 Line No.: 11 Column: b
San Diego Gas & Electrc Company - WSPP - Contract termnation date: December 31,2010
~chedule Page: 310.9 Line No.: 14 Column: b
Seattle City Light - FERC T-ll (Point-to-Point Tranmission Service under the Open Access Transmission Tarff (7th revised S.A.
289)) - Contract termination date: October 31,2014.
~chedule Page: 310.9 Line No.: 14 Column:j
Transmission Losses
~chedule Page: 310.10 Line No.: 1 Column: j
Transmission Losses
~chedule Page: 310.10 Line No.: 2 Column: j
Reserve Share
~chedule Page: 310.10 Line No.: 4 Column: b
Settlement Adjustment.
~chedule Page: 310.10 Line No.: 4 Column: j
IFERC FORM NO.1 (ED. 12-S7) Page 450.5
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da,Yr)
PacifCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA .
Settlement Adjustment
¡Schedule Page: 310.10 Line No.: 7 Column: b
Settlement Adjustment.
¡Schedule Page: 310.10 Line No.: 7 Column: j
Settlement Adjustment
¡Schedule Page: 310.10 Line No.: 8 Column: b
Seconda, Economy and/or non-firm sales, including some hourly firm transactions.
¡Schedule Page: 310.10 Line No.: 9 Column: j
Transmission Losses
¡Schedule Page: 310.10 Line No.: 11 Column: b
Sierra Pacific Power Company - FERC T-11 (Pavant Capacitor Ownership, Operation and Maintenance Letter Agreement dated
November 9, 2000) - Contract termination date: 90 days notification.
¡Schedule Page: 310.10 Line No.: 11 Column: j
Transmission Losses
¡Schedule Page: 310.10 Line No.: 12 Column: j
Transmission Losses
¡Schedule Page: 310.10 Line No.: 13 Column: j
Reserve Share
¡Schedule Page: 310.10 Line No.: 14 Column: b
Southern California Edison Company - FERC T-12 - Contrct terination date: December 31, 2012
¡Schedule Page: 310.11 Line No.: 1 Column:j
Transmission Losses
¡Schedule Page: 310.11 Line No.: 2 Column: j
Unauthorized use charges
¡Schedule Page: 310.11 Line No.: 5 Column: j
Reserve Share
¡Schedule Page: 310.11 Line No.: 7 Column: j
Transmission Losses
¡Schedule Page: 310.11 Line No.: 9 Column: b
TransAlta Energy Marketing Inc. - FERC T-12 - Contract termination date: December 31,2010.
¡Schedule Page: 310.11 Line No.: 10 Column: j
Transmission Losses
¡Schedule Page: 310.11 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "TR-STATE GEN. & TRS." ON PAGES 310 - 311: Complete
name is Tri.State Generation and Transmission Association, Inc.
¡Schedule Page: 310.11 Line No.: 13 Column:j
Transmission Losses
¡Schedule Page: 310.12 Line No.: 4 Column: b
Secondary, Economy and/or non-firm sales, including some hourly fi transactions.
¡Schedule Page: 310.12 Line No.: 5 Column: j
Transmission Losses
¡Schedule Page: 310.12 Line No.: 7 Column: b
Utah Municipal Power Agency - FERC 433 - Contract termination date: June 30, 2017.
¡Schedule Page: 310.12 Line No.: 9 Column: b
Settlement Adjustment.
¡Schedule Page: 310.12 Line No.: 9 Column: j
Settlement Adjustment¡Schedule Page: 310.12 Line No.: 10 Column: b I
Western Area Power Administration - FERC R.S. 664 (purchase of Capacity in the 230kV Casper-Dave Johnston Trasmission Line-
Use of transmission Service durg times when Western's capacity is de-rated) - Contract termation date: 50 years after commercial
operation of the transmission line.
IFERC FORM NO.1 (ED. 12-S7) 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 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 310.12 Line No.: 10 Column: j
Transmission Losses
I$chedule Page: 310.12 Line No.: 11 Column: j
Transmission Losses
I$chedule Page: 310.12 Line No.: 13 Column: b
Secondary, Economy and/or non-firm sales, including some hourly fi trsactions.
I§chedule Page: 310.12 Line No.: 13 Column: j
The negative revenue reported on this line reflects test energy generated at the Dunlap Ranch I wind-powered generatig facility that
was transferred to constrction. Energy generted durg testig was delivered to PacifiCorp's electrc 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.
I§chedule Page: 310.12 Line No.: 14 Column: j
Recognition and reportng of gains and losses on bookouts under generlly accepted accountig principles.
I§chedule Page: 310.13 Line No.: 1 Column: j
Recognition and reportng of gains and losses on energy tradig contrts under generally accepted accounting principles.
I§chedule Page: 310.13 Line No.: 2 Column: j. . I
Represents the difference between actual requirement sales revenues for the perod as reflected on the individual line items within this
schedule, and the accruals 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 2010/Q4
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
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 Current Year. ~ ~
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 En ineering
16 (511) Maintenance of Structures
17 (512) Maintenance of Boiler Plant
18 (513) Maintenance of Electric Plant
19 (514) Maintenance of Miscellaneous Steam Plant
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering
25 518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr.
30 (523) Electric Expenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
34 Maintenance
35 (528) Maintenance Supervision and Engineering
36 (529) Maintenance of Structures
37 (530) Maintenance of Reactor Plant Equipment
38 (531) Maintenance of Electric Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering
45 (536) Water for Power
46 (537) Hydraulic Expenses
47 (538) Electric Expenses
48 (539) Miscellaneous 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)
4,285,137
48,042,874
338,685
3,904,528
43,559,253
450,415
.lJøØ/~qr".'I:iZf 7...../ x 0//~ BiI!iWA;;,,'/': ~~%%m: W;;_i%d Wff~;%;ø//w; " :t%&¿d:% ,;/;fÆ::¥ÁiJh;;% W 0";("
761,631,219 728,663,307
./ 7!Øf.ll":\%~ÆÍø.jK""""øJ~Y:¡¡~lJl"" ~!lJ"~ .".~;;:~
6,462,258
25,480,955
112,922,881
38,934,338
12,066,167
195,866,599
957,497,818
5,970,114
22,825,065
94,433,581
33,727,522
12,681,273
169,637,555
898,300,862
")f:"":""Æt~¡%;1~;;~.~..'..~.-".....
3,825,666
212,409
3,449,509
9,385,219
290,209
3,518,610
20,295,293
117,398
27,900,275
15,385,413
183,444
28,762,895~i..~~ 0_~0:- ""i.f¡/ ;~....,"~)f3;__.i/~;../Ø0;Ø...
469
1,430,392
1,959,700
1,635,171
2,654,790
7,680,522
35,580,797
84,358
1,207,112
1,600,540
1,515,716
2,539,316
6,947,042
35,709,937
FERC FORM NO.1 (ED. 12-93)Page 320
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This Report Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
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 Current Year. . 00 ~
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 Generation Plant
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)
74 TOTAL Power Production Expenses-Other Power (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 of lines 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-Mónitor and Operate Transmission System
87 (561.3) Load Dispatch-Transmission Service and Scheduling
88 (561.4) Scheduling, System Control and Dispatch Services
89 (561.5) Reliabilty, Planning and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation Interconnection Studies
92 (561.8) Reliabilty, Planning and Standards Development Services
93 (562) Station Expenses
94 (563) Overhead Lines Expenses
95 (564) Underground Lines Expenses
96 (565) Transmission of Electricity by Others
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 Equipment
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance 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)
Amount forPrevious Year
(c)
358,628
432,620,733
14,638,002
18,701,556
3,558,679
469,877,598
316,964
461,743,015
15,739,485
18,635,853
1,861,264
498,296,581
1,240,594
8,996,404
2,196,699
12,433,697
482,311,295
1,544,031
14,986,840
1,321,906
17,852,777
516,149,358_ '.~',. , ;:.jM
380,007,678
877,454
63,870,496
444,755,628
1,920,145,538
456,211,649
1,514,461
49,819,215
507,545,325
1,957,705,482" ;/"%.~Æi~il~Mifr70 W0i~"'.:1
5,041,115 6,088,583
650,305
7,847,328 8,347,455
816,883
83,476 76,671
938,904 899,582
2,124,825 1,506,478
120,209 245,152
136,854,649 117,161,210
4,257,862 2,393,112
1,312,382 1,656,975
160,047,938 138,375,218,;;;'''-'~'ln!l;;~*'''~~.0~
1,334,303
395
36,440
1,065,683
3,567,267
35,453
788
79,505
974,621
3,005,647
10,092,385
19,173,510
36,881
273,467
35,580,331
195,628,269
10,549,624
19,620,066
51,599
182,001
34,499,304
172,874,522
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
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 Current Year. W ~
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supeivision
116 (575.2 Day-Ahead and Real-Time Market Faciltation
117 575.3) Transmission Rights Market Faciltation
118 (575.4) Capacity Market Faciltation
119 (575.5) Ancilary Seivices Market Faciltation
120 (575.6) Market Monitorin and Compliance
121 (575.7) Market Faciltation, Monitoring and Compliance Seivices
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 Supeivision and Engineering
135 (581) Load Dispatching
136 (582) Station 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 Supeivision and Engineenng
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 Distribution Plant
155 TOTAL Maintenance (Total of lines 146 thru 154)
156 TOTAL Distribution Expenses (Total of lines 144 and 155)
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supeivision
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)
Amount forPrevious Year
(c)
L ~'0. ~~'i iw.," ~_~"~¡frW;F" "Wl¡W"
.%~~;z~JI wø."Jj'~&%t¡Wki01
15,625,451
13,735,481
3,812,831
5,762,152
287
209,265
6,564,361
12,634,849
5,887,263
3,253,672
67,485,612
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
5,493,229
1,828,870
12,622,071
84,730,396
22,786,414
883,285
4,084,559
5,890,644
2,745,222
141,064,690
208,550,302
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
Lv0 '!.i¡W. 1?iil//Z/; Z!T~ 'l¡Ww ~.. z" .W" / / /;i'í¡W_..._Ui¿:~ " j¡ g~\f/ .Æt £% %% ,,~ Z Æil iø~
¡w:w wiii.r/ xll!:..!f" .¡w-. ¡¡¡W10 ¡¡r'd%! 0 ¡¡"\I w\fßf......ii~ /:r.";0.~ .Æk/~ _d'$J.,:/&/~.!I&J d!V__
2,497,682
22,553,488
54,938,892
12,590,656
169,927
92,750,645
2,554,096
22,520,219
56,280,326
12,175,795
254,571
93,785,007
FERC FORM NO.1 (ED. 12-93)Page 322
Name of Respondent
PacifCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
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 ~~. W ~
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision
168 (908) Customer Assistance Expenses
169 909) Informational and Instructional Expenses
170 (910) Miscellaneous Customer Service and Informational Expenses
171 TOTAL Customer Service and Information Expenses (Total 167 thru 170)
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision
175 (912) Demonstrating and Sellng Expenses
176 (913) Advertising Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries
182 (921) 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 Pensions and Benefits
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)
Amount forPrevious Year
(c)
263,903
124,155,800
4,435,033
90,169
128,944,905
286,417
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
17,926,840
6,130,867
20,382
16,291;649
6,337,703
123,741,534
16,464,747
3,420,842
35,761
19,659,625
6,199,584
139,422,010
7 77 ~ lW~ /#.. h if"Ji... 1: i1ifi/ 7o/0"".....iíJi?0" " xv '! !!f,
wL ;igiP.~J~ ;; '\,tw %" ~ ;:;it~~7;;0 0/Ai ~", ~ WkØ:A
22,334,950
146,076,484
2,692,096,143
23,197,501
162,619,511
2,673,916,007
FERC FORM NO.1 (ED. 12-93)Page 323
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 320 Line No.: 187 Column: b I
Pensions and benefits expense is associated with labor and generally charged to operations and maintenance expense and constrction
work in progress. Durng the years ended December 31, 2010 and 2009, pensions and benefits expense was $153,429,891 and
$143,975,955, respectively.
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) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
PU~CHAdlED POWER ¡;ccunt 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 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 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.
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)Classifi-Schedule or Monthly Billing Average Average
cation Tariff NU,mber Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Power Purchases
2 Albany, City of LU NA NA NA
3 Alberta Power Pool SF NA NA NA
4 Amy Ranch Hydro LU NA NA NA
5 Anaheim, City of SF NA NA NA
6 Arizona Public Service Company jii NA NA NA
7 Arizona Public Service Company .~.NA NA NAm.
8 Arizona Public Service Company "%".*,.NA NA NA
9 Arizona Public Service Company SF NA NA NA
10 Avista Corporation SF NA NA NA
11 BNP Paribas Energy Trading GP SF NA NA NA
12 BP Corporation North America, Inc.SF NA NA NA
13 BP Energy Company SF NA NA NA
14 Ballard Hog Farms Inc.LU 0.01 0.01 0.01
Total
FERC FORM NO.1 (ED. 12-90)Page 326
Name of Respondent This 780rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
ccuR~~g~~) (t,ontlnUed)
(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 colúmn (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (50-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. 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. Thé
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
~1 ~~~
($1 of Settlement ($)
(g)(h)(i)(I (m)
1
1,22~79,39f 79,398 2
5£1-IJII 1,720 3
1,86¿96.961 96,961 4
1 ~27f 278 5
40C -".33,450 60'~ '"
25€8,21C 8,210 7
83,2ge 2,557,72f 2,557,725 8
69,28€2,396,44€2,396,446 9
128,85C .4,219,641 -.r'4,235.587 10'f
6,00C 207,29(207,290 11-.,-37,170,962 12
32,90~654,037 654,037 13
4e 213 2,44£2,662 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,67S
FERC FORM NO.1 (ED. 12-90)Page 327
Naine of Respondent This 'r0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Oct, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
PU~CHAJiEO POWER ItccuW 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 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 enérgy 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 reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designatedunit.
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 Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Barclays Bank PLC ~=NA NA NA
2 Barclays Bank PLC ~. rtfi NA NA NA
3 Barclays Bank PLC SF NA NA NA
4 Beaver City Corporation ...NA NA NA. II
5 Bell Mountain Hydro, LLC -NA NA NA%. . . HI!
6 Bell Mountain Hydro, LLC LU NA NA NA
7 Big Top, LLC LU NA NA NA
8 Biomass One, L.P.LU 22.5 20.9 13.7
9 Birch Creek Hydro LU NA NA NA
10 Black Hils Power, Inc.-.NA NA NA.'%. % ~
11 Black Hils Power, Inc.LU NA NA NA
12 Black Hils Power, Inc...NA NA NA
13 Black Hils Power, Inc.SF NA NA NA
14 Black Hils Wyoming, Inc.SF 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 2010/Q4
(2) OA Resubmission 04/18/2011
, ~ ,~, '~(í~'- ~g çcoun~~8~~)(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)o 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 shownon 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+1)No.
Received Delivered
~l ~~~~~l
of Settlement ($)
(g)(h)(i)(m).w_.rn'.-4,004 1.iI ~ "
35(.~26,590 2
106,05 4,702,17l ..~~"-63,429,740 3
71 5,99l 5,994 4_.'rø -15,139 5"
99!67,27~67,272 6
2,921 186,911 ~186,911 7
143,00(2,666,250 19,785,32 26,143,254 8
13,841 758,82(758,820 9WI~:25,637 10wt..ß . "
3H _..¡¡..2,848,604 1111.11 ." Milí ""
13(2,99(2,990 12
14,63~459,481 459,485 13
40(8,40(8,400 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,671
FERC FORM NO.1 (ED. 12-90)Page 327.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
PU~CHAJlED POWER hACCUW 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 (Leo, 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 availability and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU 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 Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)
.
(c)(d)(e)(f)
1 Blanding City Corporation NA NA NA
2 Bonnevile Power Administration 575 575 461
3 Bonnevile Power Administration NA NA NA" il
4 Bonnevile Power Administration NA NA NA
5 Bonnevile Power Administration SF NA NA .NA~ø"#r~.rø...SF NA NA NA"4. ø. %, _14
7 Butter Creek Power, LLC LU NA NA NA~NA NA NA
9m /Ø- % % il.f " 'iØff'; 0, ¡r NA NA NA
W (;ifornia Independent sy~e~ o;~ra~r ~F NA NA NA
11 Cameron A. Curtiss .-NA NA NA
12 Cargil Power Markets, LLC t NA NA NA
13 Cargil Power Markets, LLC SF NA NA NA
14 Central Oregon Irrigation District LU 3.6 3.7 2.7
Total
FERC FORM NO.1 (ED. 12.90)Page 326.2
Name of Respondent .This (80rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
ccou~t,~~~L \ ((,ontinuea)(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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the 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 bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other 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 Page401, 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
~1 ~~~\'1
of Settlement ($)
(g)(h)(i)(m)
423 31,75 31,753 1
57,615,000 57,615,000 2.," ?Æ/. .",.~.,1,706,104 3
1,674 -.,70,681 4
90,060 1,757,934 -"1,920,787 5IlL
264 -7,696 6
11,31€717,291 717,291 7
25,56€"39,49~1,396,492 8
-16,611 A ". . m"730,460 9
529,09S 17,865,50C 17,865,500 10
66 3,OOf 3,008 11
1,80e ..141,722 12
637,44~25,047,50C -"""25,450,224 13
22,66C 400,660 2,134,67 2,535,337 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,67f
FERC FORM NO.1 (ED. 12-90)Page 327.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
PU~CHAÆED POWER hAccu1t 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 affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the 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 "intermediate4erm" 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 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 Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Chevron U.S.A. Inc.LU NA NA NA
2 Citigroup Energy, Inc.-NA NA NA
3 Citigroup Energy, Inc.SF NA NA NA
4 City of Burbank SF NA NA NA
5 City of Preston Idaho LU NA NA NA
6 City of Redding SF NA NA NA
7 City of Walla Walla LU 1.1 1.7 1.5
8 Clatskanie People's Utilty District SF NA NA NA
9 Colorado River Commission of Nevada ~NA NA NA%%7_""_
10 Colorado River Commission of Nevada SF NA NA NA
11 Commercial Energy Management, Inc.LU NA NA NA
12 ConocoPhillps Company SF NA NA NA~iI';%~ rflJ'"*-'NA NA NA'wy )'~0W ,'" wr mwl~Æ
14 Constellation Energy Commodities Group SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.3
..
Name of Respondent This Report Is:Date of Rèport Year/Period of Report
PacifiCorp (1) !KAn Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
ccounta~g~§) (i;ontlnUea).
~ .~'" '(íìicíuding 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 (0), (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 U+k+l)No.Received Delivered
~l ~~~~'l
of Settlement ($)
(g)(h)(i)(m)
38,58.:2,076,638 ..2,098,597 1
91 _ im"-3,425 211'%1
249,311 7,356,09E _'mm';'-19,069,089 3
22,80C 974,45C 974,450 4
1,57~77,19 77,193 5
1,01-22,42"22,425 6
12,13f 138,741 1,653,96t 1,792,708 7
1,44'45,11C 45,110 8
9 ~.'7,088 9., ff., ,1 w,
15-13,58€13,588 10
1,62 85,37e 85,375 11
123,36 3,736,21E 3,736,216 12
4,581 237,71e 237,718 13
187,716 9,491,23 ~II 9,454,072 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,67e
FERC FORM NO.1 (ED. 12-90)Page 327.3
Name of Respondent This wort Is:Date of Report Year/Period of Report .
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ÕA Resubmission 04/18/2011
PU~CHAJiED POWER hACCOUßt 555)Inclu 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 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 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 forimbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Cottonwood Hydro LLC IU NA NA NA
2 Credit Suisse Energy LLC --NA NA NA.';*;é:_~.
3 Credit Suisse Energy LLC ~NA NA NA
4 DB Energy Trading LLC NA NA NA
5 DB Energy Trading LLC SF NA NA NA
6 Deschutes Valley Water District LU 5.92 4.5 3.5
7 Deseret Power Electric Cooperative j.100 100 84
8 Deseret Power Electric Cooperative "!I ""NA NA NA
9 Deutsche Bank AG -NA NA NA
10 Deutsche Bank AG SF NA NA NA
11 Douglas County Inc.IU NA NA NA
12 Douglas County Public Works LU 0.2 0.7 0.5
13 Draper Irrigation Company IU NA NA NA
14 Dry Creek LLC LU NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.4
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/18/2011
, .. "' '~ìí""'" ccoun~~~~~)(contlnUed)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, 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 (50-minute integration) demand ina month. Monthly CP demand is the metered demand during
the hour (50-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
50 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/SETILEMENT OF POWER Line
Purchased 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)
2,7()149,62~149,623 1
5(.9,069 2
40(17,32(..c~c -1,542,419 3
1 i .". "869 4"~ %/
205,61 8,339,07'8,339,074 5
31,32 582,894 3,330,04,3,912,936 6
833,31'14,238,038 15,126,801 -"""""my,'w 33,112,063 7%-5,336 8-"0 -3,391 9-~:""-2,633,858 10
1,421 45,92i 45,925 11
4,38f 41,414 523,107 564,521 12
-1,37f -1,378 13
11,98C 618,711 618,711 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,671
FERC FORM NO.1 (ED. 12-90)Page 327.4
Name of Respondent This lË0rt Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
PU~CHA~ED 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 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 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 availability 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 Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 EDF Trading North America, LLC SF NA NA NA
2 Eagle Point Irrigation District LU 0.8 0.5 0.4.
3 EI Paso Electric Company ~-NA NA NA
4 EI Paso Electric Company SF NA NA NA
5 Endure Energy, LLC SF NA NA NA
6 Eugene Water & Electric Board SF NA NA NA
7 Eurus Combine Hils I, LLC LU NA NA NA
8 Evergreen BioPower, LLC LU NA NA NA
9 ExxonMobile Production Company LU NA NA NA
10 Falls Creek HoP. Limited Partnership LU 3.5 3.7 1.6
11 Farmers Irrigation District LU 3.92 3.6 2.9
12 Filmore City il ¡¡NA NA NA7.ff
13 Finley BioEnergy, LLC LU NA NA NA
14 Four Comers Windfarm, LLC LU NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.5
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) ñA Resubmission 04/18/2011
ccou~~~~~L \ (Continued)'Õnch.idlng 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-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 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 Ol"'C~ Tot U.k.')No.
Received Delivered
~l æ ($) of Settlement ($)
(g)(h)(I)(i) (m)
172,839 7,289,824_ .... : w. 6,857,281 1
3,24E 44,501 363,93"408,436 2
1 .-40 3
25,48€950,25C -950,308 4
11,60C 358,55C 358,550 5
18,79€550,261 550,261 6
104,66 3,671,56~3,671,564 7
42,92~2,328,81f 2,328,875 8
652,41C 31,711,27 31,711,273 9
17,30,225,624 1,823,78€2,049,412 10
24,38~338,031 2,589,65~2,927,690 11
18;¿.19,68C 19,680 12
27,071 1,758,94 1,758,942 13
23,146 1,469,25;¿1,469,252 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,67€
FERC FORM NO.1 (ED. 12.90)Page 327.5
Name of Respondent This ø0rt Is:Date of Report ~Year/Period of Report
PacifiCorp (1 ) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
PU~CHAdfED POWER hAccount 555)
(nclu ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electriity (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 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 Average
cation Tariff Number Demand (MW) Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Four Mile Canyon Windfarm, LLC LU NA NA NA
2 General Chemical Corporation ~NA NA NA
3 George DeRuyter & Sons Dairy 0.8 1 0.8
4 Georgetown Irrigation Company LU NA NA NA
5 Gila River Power, LP.~NA NA NA
6 Gila River Power, LP.NA NA NA
7 Gila River Power, LP.SF NA NA NA
8 Glendale, City of SF_NA NA NA
9 Grand Valley Power . "NA NA NA1 m "
10 Grays Harbor Public Utilty District SF NA NA NA
11 HDI Associates V, LP LU 0.35 0.5 0.2
12 Harold Foster & Robert Walker LU NA NA NA
13 Heber Light & Power Company .NA NA NA
14 -""-NA NA NA-~ %. me 0" ¡¡.
Total
FERC FORM NO.1 (ED. 12-90)Page 326.6
Name of Respondent This 180rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ñA Resubmission 04/18/2011
ccou~t.~~~l \ (Continued)(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 allFERC 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 totálled 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 \~~\'l
of Settlement ($)
(g)(h)(i)(m)
21,84S 1,390,12€1,390,126 1
2,58 38,48'38,485 2
.6,691 13,360 410,81,424,172 3
2,11.113,50;113,503 4
671 --' .~"63,592 5ui
15(8,25(8,250 6
53,87 2,134,54!2,134,549 7
1,20(.42,2Oc 42,200 8.
13,23,B7~23,873 9
4,32(62,16(62,160 10
2,28 .37,268 250, 12~287,397 11
84,29,82i 29,827 12
6,03 511 ,07~511,075 13
1 -'" ' ø -238,483 14%"
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,671
FERC FORM NO.1 (ED. 12-90)Page 327.6
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1).. X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
PU~CHAJlED POWER hAccount 5 5)Inclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalance exchanges.
2. Enter the name of the seller or other 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 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.
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. Describethe 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 Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand(a) (b)(c)(d)(e)(f)~LU 240 239 2162 Hil Air Force Base _"NA NA NA3 Hil Air Force Base LU NA NA NA
4 Hurricane, City of j=NA NA NA
5 Iberdrola Renewables, Inc.'...~%'NA NA NAM ,~
6 Iberdrola Renewables, Inc...NA NA NA
7 Idaho Falls, City of ~ ,NA NA NAbÆ'W ii
8 Idaho Falls, City of LU NA NA NA
9 Idaho Power Company SF NA NA NA
10 Intermountain Power Agency LU NA NA NA
11 J. Aron & Company SF NA NA NA
12 JP Morgan Ventures Energy Corporation ~NA NA NA
13 JP Morgan Ventures Energy Corporation SF NA NA NA
14 KEI (USA) Power Management Inc.LU 2.2 4.3 2.1
Total
FERC FORM NO.1 (ED. 12-90)Page 326.7
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp ('!)!KAn Original (Mo, Da, Yr)End of 2010/Q4
(2)OA Resubmission 04/18/2011
ccoun~~g~~/contlnUed)(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 (t)o 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 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
~1 t~~\'1
of Settlement ($)
(g)(h)(i)(m)
1,592,856 35,316,527 59,644,33~.-95,287,591 1.'.".6,533 2
14,18'678,40!678,405 3
1,99.149,371 149,378 4...%4,366 5
480,05 14,588,52 10,377,838 6
-31,788 7
39,81 .'.%2,915,697 8%
1,901 66,18C l Y1 69,496 9m
564,73.27,947,14.27,947,142 10
8,60(256,87(.-1,980,003 11
2(_..~"726 12
142,551 5,165,6~.: .~'6,102,203 13
22,98 288,507 2,559,971 2,848,484 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,6n
FERC FORM NO.1 (ED. 12-90)Page 327.7
Name of Respondent This 00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
PU~CHAJlED POWER ¡rccouW 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 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.
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)Classifi-Schedule or Monthly Billng Average AveragecationTariff Number Demand (MW)Monthly NCP Deman 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 NA4_IF NA NA NAø i:' .iø ,% II
5 Los Angeles Dept. of Water & Power' ,Wi NA NA NA.il
6 Los Angeles Dept. of Water & Power SF NA NA .NA
7 Lower Valley Energy, Inc...NA NA NA
8 Lower Valley Energy, Inc.IU NA NA NA
9 Loyd Fery LU NA NA NA
10 Macquarie Energy LLC SF NA NA NA
11 Marsh Valley Hydro & Electric Company LU NA NA NA~SF NA NA NA_ ia. m ,/!f' ,~13 Middle Fork Irrigation District LU NA NA NA
14 Mink Creek Hydro LU NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.8
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) IKAn Original (Mo, Da, Yr)End of 2010/Q4
(2) ÕA Resubmission 04/18/2011
,ccou~t.~~~L (Continued)'''~(1ncíuding 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)o 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 U+k+l)No.Received Delivered
~l t~~\~l
of Settlement ($)
(g)(h)(i)(m)
169,41A 7,210,87A -,'0 ,'XI: 17,313,737 1
%
1,511 82'9~82,985 2
4,73 165,35 199,181 3WdÆ
23,00(1,149,08C 1,149,080 4
3,15(15,75C .15,750 5
90,57 3,804,02C 3,804,020 6
-1 -~ ,;'"-687 7
5,171 291,32l 291,324 8
23,15,02i 15,020 9
116,13'3,502,71 -"0/~"mr 3,626,089 10.ii
4,551 250,05f 250,058 11
41 1,,w 1,445 12
23,61C 1,267,42~1,267,429 13
8,031 423,84 423,842 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,6n
FERC FORM NO.1 (ED. 12-90)Page 327.8
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) i"A Resubmission 04/18/2011
PU~CHAcrED POWER \tccuW 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 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 ohe 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 ionger. The availabilty and reliability of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU 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)Classifi-Schedule or Monthly Billng Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Modesto Irrigation District SF NA NA NA
2 Monsanto Company IU NA NA NA
3 Morgan City Corporation -'J NA NA NA
4 Morgan Stanley Capital Group, Inc.~NA NA NAit"M'lIa.
5 Morgan Stanley Capital Group, Inc.IF 100 50 50
6 Morgan Stanley Capital Group, Inc...NA NA NA
7 Mountain Wind Power II, LLC NA NA NAWf
8 Mountain Wind Power II, LLC LU NA NA NA
9 Mountain Wind Power, LLC LU NA NA NA
10 Municipal Energy Agency of Nebraska SF NA NA NA
11 Nephi City Corporation ..NA NA NA
12 Nevada Power Company SF NA NA NA
13 NextEra Energy Power Marketing, LLC SF.NA NA NA
14 Nicholson Sunnybar Ranch II NA NA NA"m' ;;
Total
FERC FORM NO.1 (ED. 12-90)Page 326.9
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
ccunt_~~~l. ,((,ontlnUea)(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
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)o 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 O+k+l)No.Received Delivered
~l \~~\~l
of Settlement ($)
(g)(h)(i)(m)
1,20C 47,600 47,600 1-17,705,685 2w.
2~2,90;¿2,902 3
2,831 -101,468 4w".
245,5n 3,057,000 10,682,513 13,739,513 5
1,132,331 52,870,91 30,769,294 6
8,166 7
202,07,13,119,06 13,119,063 8
149,42~8,274,54€8,274,548 9
50C 17,64C 17,640 10
H 1,824 1,824 11
40,96~1,485,79 _mw 1,569,697 12,,74O,"
60C 24,15C 24,150 13
-3f ..~"j!!l"'-2,475 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,67f
FERC FORM NO.1 (ED. 12-90)Page 327.9
Name of Respondent This ø0rt Is:Date of Fteport Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) r"A Resubmission 04/18/2011
PU~CHAclED 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 affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the 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 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 servces which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Nicholson Sunnybar Ranch LU NA NA NA
2 NorthWestern Corporation SF NA NA NA
3 Northpoint Energy Solutions Inc.SF NA NA NA
4 Nucor Corporation IF NA NA NA
5 O.J. Power Company LU NA NA NA~LU 0.01 0 0_ ' ".ø % '" " if"" .
7 Oregon Environmental Industries,LLC LU NA NA NA
8 Oregon Institute ofTechnology LU NA NA NA
9 Oregon Trail Windfarm, LLC LU NA NA NA
10 PPL EnergyPlus, LLC SF NA NA NA
11 Pacifc Canyon Windfarm, LLC LU NA NA NA
12 Pacific Gas & Electric Company SF NA NA NA
13 m- "r-ø ;; VA"%SF NA NA NAi%(%%?f, !0 .il;:
14 Pacific Summit Energy LLC SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.10
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) (KAn Onginal (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
ccu~t_~~~ucontinued )~ ,~... '(íncíuding 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)o 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 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 æ \fl
of Settlement ($)
(g)(h)(i)(m)
1,85 100,42€100,426 1
58f -19,994 2
40C 12,20C 12,200 3.!l%i ""4,885,800 4!1 Wf
7m 35,24~35,249 5
439 A 443 6
20,978 1,123,94E 1,123,946 7
322 5,90.5,902 8
22,05f 1,399,18E 1,399,186 9
52,23~1,573,131 1,573,131 10
16,24L 1,035,08f 1,035,088 11
1,60C 46,00C 46,000 12
10,07~264,08C 264,080 13
12,348 398,79 398,797 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,6n
FERC FORM NO.1 (ED. 12-90)Page 327.10
Name of Respondent This '00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ¡=A Resubmission 04/18/2011
PU~CHAeWED POWER hAccu~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 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 (Leo, 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 deliVèries 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 availability and reliability of the designated unit.
IU - for intermediate-term service from a dèsignated 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 Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Paul Luckey LU NA NA NA
2 Payson City Corporation ~NA NA NA
3 Platte River Power Authority SF NA NA NA
4 Portland General Electric Company "NA NA NA0
5 Portland General Electric Company WI NA NA NA
6 Portland General Electric Company .,..NA NA NAirø::%
7 Portland General Electric Company SF I NA NA NA
8 Powerex Corporation ..NA NA NA
9 Powerex Corporation SF NA NA NA
10 Provo City Corporation NA NA NAw
11 Public Service Company of Colorado NA NA NA
12 Public Service Company of Colorado SF NA NA NA
13 Public Service Company of New Mexico SF NA NA NA14__LU NA NA NA" ,. ,,IN. " W." .
Total
FERC FORM NO.1 (ED. 12-90)Page 326.11
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo,Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
ccount"~~~L \ (LontlnUea)(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
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)o 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 incolumn (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 ~~~\'l
of Settlement ($)
(g)(h)(i)(m)
25~29,309 29,309 1
i 764 764 2
2,77€.%"-~i--77,767 3..." ""-14,939 4
12,001 --141,000 5%
1,200 6
53,24 1,691,17 1,715,659 7
31 -' .,~"1,255 8
150,25 5,866,32€.a 6,032,836 90""%
301 25,40C 25,400 10
2E -885 11
20,72(752,47.:752,474 12
73,10'2,489,68 2,627,367 13.
306,Om 3,964,408 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,67E
FERC FORM NO.1 (ED. 12-90)Page 327.11
This Report Is:
(1) (KAn Original
(2) A Resubmission
PURCHASED POWER IAccour¡t 555)
(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)
04/18/2011
Year/Period of Report
End of 2010/Q4
RQ - for requirements service.. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the supplier
includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must be the
same as, or second only to, the 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 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
No.
Name of Company or Public Authority
(Footnote Affliations)
Statistical
Classifi-
cation
(b)
SF
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Biling
Demand (MW)
(d)
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Demand(e) (f)
NA
NA
NA
NA
NA
NA
NA
NA
NA
14
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.12
Name of Respondent
PacifiCorp
This Report Is: Date of Report
(1) IKAnOriginal (Mo, Da, Yr)
(2) OA Resubmission 04/18/2011
(Including powe~~~~~8~~)(GontlnUed)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
Year/Period of Report
End of 2010/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)o 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 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
Purchased
POWER EXCHANGES
MegaWatt Hours MegaWatt HoursReceived Delivered(h) (i)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges\~~ \'l802,57C~"'"
...fí..ií....wl". "¡if .n"' II -*,f..íf..¡¡....pw..II. ""."% mi. Ml %i%." %;:'~..""".W¡w."
¡¡d.Ø,. ,.
(g)
Demand Charges
~l
43,36C
34,951
198,97(
33,391
79,89C
758,61
1,056,22
2,018,71L
.. '"m. ?~
5,791,02f_
12,896,65c _'w¡ .
956,57C _"':_wzw:~":
243,03L
87,60(
981,80C
32,10
-171
8,10'
94,138
Line
Total O+k+l) No.
of Settlement ($)
(m)
808,015 1
-8,136 2
-68,903 3
-198,867 4
758,612 5
2,958,681 6
1,057,780 7
2,018,714 8
-3,588,743 9
6,203,942 10
20,676,806 11
963,410 12
-7,377 13
243,034 14
11,417,025 -408,270,490 380,007,67!132,576,270 655,701,89814,493,755 14,289,088
FERC FORM NO.1 (ED. 12-90)Page 327.12
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
.(2) riA Resubmission 04/18/2011
PU~CHAJiED POWER hACCUW 555)
(ndu 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. Thesame 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 Affliations)Classifi-Schedule or Monthly Biling Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Puget Sound Energy, Inc.SF NA NA NA
2 Rainbow Energy Marketing Corporation SF NA NA NA
3 Ralphs Ranch, Inc.%,m NA NA NA% m'm
4 Ralphs Ranch, Inc.LU NA NA NA
5 Rock River 1, LLC LU NA NA NA~SF NA NA NA_ f&, % ~ ~,,%!' ,% .
7 Roseburg Forest Products Co.LU NA NA NA
8 Roseburg Forest Products Co.PA NA NA NA
9 Rough & Ready Lumber Company NA NA NA
10 Roush Hydro Inc.LU NA NA NA
11 Sacramento Municipal Utilty District ."NA NA NA
12 Sacramento Municipal Utilty District FI NA NA NA
13 Sacramento Municipal Utilty District SF NA NA NA
14 Salt River Project SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.13
Name of Respondent This wort Is:Date' òfReport Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission .04/18/2011
, v .~, '~(í~'" ccouRt 55~~r;ontlnUed)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)o For all other types of service, enter NA in columns (d), (e) and (t)o 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) 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 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
Purchàsed 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)
167,91~5,547,97 W~"v/.5,575,049 1
75,86~2,531,43A 2,531,434 2
-1E ,,~-2,214 3. . "ii
31 4,42E 4,426 4
138,20~4,903,49'4,903,494 5
5,81E 159,221 159,221 6
168,63E 9,626,85'9,626,855 7
11 14,36~14,362 8
8,46 550,664 550,664 9
23E 15,251 15,257 10
¡¡43,800 11
213,70~3,748,456 .3,748,456 12
21,93C 799,88 802,039 13
98,96E 3,938,38 3,938,513 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,67~
FERC FORM NO.1 (ED. 12-90)Page 327.13
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
PU~C~AJlED POWER \,ACCOUW 5! 5)
n u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for 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 (Leo, the supplier
includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for 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 U= 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 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 Affliations)Classifi-Schedule or Monthly Biling Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 San Diego Gas & Electric Company I~NA NA NA
2 San Diego Gas & Electric Company SF NA NA NA
3 Sand Ranch Windfarm, LLC LU NA NA NA
4 Santiam Water Control District LU 0.2 0.2 0.2
5 Seattle City Light SF NA NA NA
6 Sempra Energy Trading LLC -NA NA NA
7 Sempra Energy Trading LLC SF NA NA NA
8 Sempra Generation ..NA NA NA
9 Shell Energy North America (US), L.P.NA NA NA
10 Shell Energy North America (US), LoP.SF NA NA NA
11 Shoshone Irrigation District LU 2.5 1.4 1
12 Sierra Pacific Power Company SF NA NA NA
13 Sierra Pacific Power Company SF NA NA NA
14 Sierra Pacific Power Company SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.14
Name of Respondent This ø0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/18/2011
, ""'~, '~(í~'" ccou~t,~~~UGontlnUed)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 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 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 total!ed 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 Ql" Ch'~ To,,1 O+k+l)No.Received Delivered ~l \~~
($) of Settlement ($)
(g)(h)(I)(I) (m)
351 _"" 11,387 1
9,50~397,97A 397,974 2
19,88f 1,265,98C 1,265,980 3
1,521 13,632 144,44e 158,071 4
119,53.....w'".iJ~.3,288,222 53,277,97 lI"m
81 348 6
273,91A 13,453,56 -6,542,974 7
1e 52e 525 8
9C -3,028 9
291,44E 10,665,57A _..,.,",-,Z--33,572,457 10
9,71,163,673 391,43'555,108 11
71.-2,336 12
15 --9,154 13
9,72e 382,9ge 382,995 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,678
FERC FORM NO.1 (ED. 12-90)Page 327.14
Name of Respondent This 180rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/18/2011
PU~CHAJlED POWER hACCUW 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 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 availability and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU 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 Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Simplot Phosphates LLC LU 10 13 9
2 Slate Creek Hydro Company, Inc.LU 3.2 2.7 1.8
3 Southern California Edison Company J-NA NA NA
4 Southern California Edison Company SF NA NA NA
5 Southwestern Public Service Company SF NA NA NA
6 Spanish Fork City Corporation i~NA NA NA
7 Spanish Fork Wind Park 2, LLC LU NA NA NA
8 Springvile City Corporation -¡W" w'".NA NA NA
9 Stahlbush Island Farms, Inc.IU NA NA NA
10 Strawberry Electric Service District I-NA NA NA
11 Sunderland Dairy Inc.LU 0.02 0.03 0.02
12 Sunnyside Cogeneration Associates LU 52 53 43
13 Swalley Irrigation District LU NA NA NA
14 Tacoma Power ...NA NA NAø",.Ørø il
Total
FERC FORM NO.1 (ED. 12-90)Page 326.15
Name of Respondent This 1E0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) r'A Resubmission 04/18/2011
ccuRt.~~~i \ (Continued)(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 separáte 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)o 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 O+k+l)No.Received Delivered
~l ~~~~~l
of Settlement ($)
(g)(h)(i)(m)
82,45.444,600 3,501,94C 3,946,540 1
15;28~212,588 1,516,65 1,729,241 2
2,60C 62,20C 62,200 3
37,921 1 ,246,94~1,246,943 4
1,99E 66,88 66,883 5
2~2,776 2,776 6
46,92~2,442,876 2,442,876 7
6C 7,333 ,7,333 8
3,660 243,12C 243,120 9
58 4,921 4,921 10
.109 1,503 3,47£4,982 11
377,72(9,681,949 13,803,144 23,485,093 12
2,225 144,32(144,327 13
21 ....1,239 14.&
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,67~
FERC FORM NO.1 (ED. 12-90)Page 327.15
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
PU~C¿¡A~ED POWER hACCUW 555)
n u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for 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 forservice 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 availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Tacoma Power SF NA NA NA
2 Tesoro Refining and Marketing Company LU NA NA NA
3 Thayn Hydro LLC LU 0.3 0.4 0.3
4 The Energy Authority SF NA NA NA
5 The Town of the City of Buffalo LU 0.23 0.2 0.2
6 Three Buttes Windpower, LLC LU NA NA NA
7 Threemile Canyon Wind i, LLC -.NA NA NAliiØ;tm ii ;;%_
8 Threemile Canyon Wind i, LLC LU NA NA NA
9 Top of The World Wind Energy LLC LU NA NA NA
10 TransAlta Energy Marketing Inc.IF NA NA NA
11 TransAlta Energy Marketing Inc.SF NA NA NA
12 TransCanada Energy Sales Ltd.SF NA NA NA13_..30 29 26
14 Tri-State Gen. & Trans.SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.16
Name of Respondent This 180rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/18/2011
ccunt,~~~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 the FERC Rate Schedule Number orTariff; or, for non-FERC jurisdictional sellers, include an appropriate
designation lor 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)o For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP
demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (50-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
50 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 G+k+l)No.Received Delivered ~l ~~~\~l
of Settlement ($)
(g)(h)(i)(m)
20,89€702,195 -' "706,527 1il
47,654 1,974,079 1,974,079 2
2,525 67,772 188,63 256,415 3
37,08 1,040,58S 1,040,588 4
1,75 30,348 155,069 185,417 5
299,989 '9"17'6~19,497,328 6
153,684 7
20,689 1,338,38~1,338,382 8
188,25 12,172889 ~-12,172,889 9
1,315,20C 44,909,80€44,182,582 10
120,63C 4,207,36C 4,207,360 11
20,60C 1,095,75C 1,095,750 12
169,419 6,861,600 4,460,80.11,322,402 13
26,16€624,161 -949,725 14it:'øffØ,,,!:. ~
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,67S
FERC FORM NO.1 (ED. 12-90)Page 327.16
Name of Respondent This 180rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
PURCHAJiED POWER hACCUW 555)
(Inclu 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 (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 period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliabilty of 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 place in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Tucson Electric Power Company ~NA NA NA
2 Tucson Electric Power Company SF NA NA NA
3 Turlock Irrigation District SF NA NA NA
4 UNS Electric, Inc.SF NA NA NA
5 US Magnesium LLC IU NA NA NA
6 US Magnesium LLC .NA NA NA7_:'-NA NA NA
8 Utah Associated Municipal Power SF NA NA NA
9 Utah Municipal Power Agency SF NA NA NA
10 Wadeland South LLC LU NA NA NA
11 Wagon Trail, LLC LU NA NA NA
12 Ward Butte Windfarm, LLC LU NA NA NA
13 Warm Springs Forest Products LU NA NA NA~..""q",_ø.i_LU NA NA NAz m %!&h m w IW
Total
FERC FORM NO.1 (ED. 12-90)Page 326.17
Name of Respondent This ø0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/18/2011
~ ,~,ccount~~~i \ ((,ontlnUed)''(ncluding 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 (t). For all other types of service, enter NA in columns (d), (e) and (t)o Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (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 (j+k+l)No.
Received Delivered
~1 ~i~\ll
of Settlement ($)
(g)(h)(i).(m)
7'1,42f 1,425 1
37,94 1,229,05~-.1,229,288 2. ,""
815 25.80C --"" ""26,237 3
8.271 188,57~188,579 4
184,521 7,786,27f ~7,786,278 5
4,909,716 6
61,950 2,075,98f 2,075,988 7
33;¿13,25C 13,250 8
590 25,05C 25,050 9
7 77 10
6,31e 402,580 . 402,580 11
15,32 970,618 970,618 12
4E 1,138 1,138 13
56C 28,741 28,747 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701 ,898 -408,270,490 380,007,678
FERC FORM NO.1 (ED. 12-90)Page 327.17
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
PU~CHAJlED POWER IfccouW 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 inan exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In Column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the 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 availability and reliability of
service, aside from transmission constraints, must match the availability. and reliabilty ofthe designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be 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)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Weber County, State of Utah LU NA NA NA
2 Western Area Power Administration -NA NA NA%
3 Western Area Power Administration SF NA NA NA
4 Western Area Power Administration SF NA NA NA
5 Western Area Power Administration SF NA NA NA
6 Whitney, A. C.-NA NA NA
7 Wolverine Creek Energy LLC LU NA NA NA
8 Yakima-Tieton Irrigation District LU NA NA NA
9 Accrual/Net Power Cost Deferrals NA NA NA NA
10 Settlement/Reserves AD NA NA NA
11 Bookout Purchases AD NA NA NA
12 Trade Purchases AD NA NA NA
13
14
Total
FERC FORM NO.1 (ED. 12-90)Page 326.18
Name of Respondent This (80rt Is:Date of Report Year/Period of Repor
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
ccount,~~~L \ t l,ontinuea), ~ w, '~ìínCluding 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 (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 dema.nd 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 ExchangeReceived 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 æ \'l
of Settlement ($)
(g)(h)(i)(m)
3,29~149,OH 149,019 1
8 2
18,451 543,71~543,719 3
4 ..121 4
14,12¿_w~ :'/%'505,597 5., .-1 6'. ..
162,30~8,944,6m 8,944,609 7
5,77 351,21¿351,212 8
-17,674,999 9
1,516,071 10
-5,780,801 "'JI~'-184,282,163 11%_.'~Kt'-17,492,110 12" )i
13
14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,67~
FERC FORM NO.1 (ED. 12-90)Page 327.18
Name of Respondent This '00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ñA Resubmission 04/18/2011
PU~CH~ED 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 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 affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the 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 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.
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)Classifi-Schedule or Monthly Billng Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Power Exchanges
2 Arizona Public Service Company EX 306 NA NA NA
3 Avista Corporation EX 554 NA NA NA
4 Basin Electric Power Cooperative EX T-11 NA NA NA
5 Black Hils Power, Inc.EX 246 NA NA NA
6 Bonnevile Power Administration 1-'237 NA NA NA
7 Bonnevile Power Administration ".-17 NA NA NA¥PAm II
8 Bonnevile Power Administration EX 237 NA NA NA
9 Bonnevile Power Administration EX 256 NA NA NA
10 Bonnevile Power Administration EX 411 NA NA NA
11 Bonnevile Power Administration EX 368 NA NA NA
12 Bonnevile Power Administration EX 554 NA NA NA
13 Bonnevile Power Administration EX -17 NA NA NA
14 Bonnevil.e Power Administration EX T-11 NA NA NA
Total .
FERC FORM NO.1 (ED. 12.90)Page 326.19
Name of Respondent This '00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
ccount~~~L \ (Continued)Tlncluding 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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hbur (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 O+k+l)No.Received Delivered ~i ($~\fi
of Settlement ($)
(g)(h)(i)(k (m)
1
569,935 570,430 .ø " ø .~ "-910,873 2"
1,512 3
9,160 223 ~ '''~291,446 4fM",
50 5
8,969 81,350 6
-896,528 7-ø,.-3,786 8
2,243 2,243 ."w..-17,94 9
1,485,806 1,489,199 ..--170,000 10o if .
242,938 242,939 11
189,270 14,313 ..12
9,292,882 9,292,882 -35,921,147 13
13,246 8,108 166,932 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,67f
FERC FORM NO.1 (ED. 12-90)Page 327.19
Name of Respondent This lË0rt Is:Date of .Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) riA Resubmission 04/18/2011
PU~CHAd1ED POWER hACCUW 555)(nclu ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Leo, 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 "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
eaniest 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 Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Bonnevile Power Administration EX T-12 NA NA NA
2 Bonnevile Power Administration EX T-12 NA NA NA
3 City of Redding EX 364 NA NA NA
4 City of St. George EX 280 NA NA NA
5 Colockum Transmission Company EX T-12 NA NA NA
6 Constellation Energy Commodities Group EX T-11 NA NA NA
7 Deseret Power Electric Cooperative ~280 NA NA NA
8 Deseret Power Electric Cooperative EX 280 NA NA NA
9 Emerald People's Utilty District 1_351 NA NA NA
10 Emerald People's Utilty District EX 351 NA NA NA
11 Eugene Water & Electric Board EX T-12 NA NA NA
12 Iberdrola Renewables, Inc.EX T-11 NA NA NA
13 Idaho Power Company EX 380 NA NA NA
14 Intermountain Renewable Power, LLC EX T.11 NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.20
Name of Respondent This (80rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
ccunt.~~~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 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 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 expianatory 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 æ \~l
of Settlement ($)
(g)(h)(i)(m)
126,893 91,824 ."':":,""'1,390,386 1..:.-74,371 2
116,660 119,121 ..-84,002 3?i
38 -6,164 4"
268,153 5
1,239 583 .,:0 .'"""m¡25,430 6
355 -4,976 _Æ 382,311 7"
29,857 57,629 ...-1,286,349 8Ii diN. W
13 .,--324 9
541 _ø.'ii"w -13,538 10
17,731 17,832 _:-7,138 11
6,352 4,096 -"69,113 12.,
389,768 219,081 13
4,003 1,337 -83,479 141i?i .,",r/ -i/;
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,6n
FERC FORM NO.1 (ED. 12-90)Page 327.20
Name of Respondent This (80rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
PU~C~AJlED POWER Ifccußt 555)nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits fòr 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 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 Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 JP Morgan Ventures Energy Corporation EX T-11 NA NA NA
2 Los Angeles Dept. of Water & Power ~OV-1 NA NA NA
*
3 Los Angeles Dept. of Water & Power EX OV-1 NA NA NA
4 Milford Wind Corridor Phase i, LLC _OV-1 NA NA NA
5 Milford Wind Corridor Phase i, LLC EX OV-1 NA NA NA
6 NextEra Energy Power Marketing, LLC EX T-11 NA NA NA
7 Noble Americas Energy Solutions LLC EX T-11 NA NA NA
8 Portland General Electric Company EX 554 NA NA NA
9 Powerex Corporation EX T-11 NA NA NA
10 Public Service Company of Colorado EX 319 NA NA NA
11 Public Service Company of Colorado EX 320 NA NA NA
12 Public Service Company of Colorado EX T-12 NA NA NA
13 PUD #1 of Chelan County EX 554 NA NA NA
14 PUD #1 of Chelan County EX 555 NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.21
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifCorp (1 )(8An Original (Mo, Da, Yr)End of 2010/Q4
(2)· OA Resubmission 04/18/2011
PI ccount.~~~L \ ~ ~ontinuea)'nricíudlñg' powèr 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 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)o For all other types of service, enter NA in columns (d), (e) and (t)o 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 U+k+l)No.Received Delivered ~l ~~~~'l
of Settlement ($)
(g)(h)(i)(m)
2,408 1,949 1-~M 4,667 1.m -75 2
3,236 _.."id 217,616 3.'.'míll"'75 4. iI %.I¥,"
3,236 .W;'0 -217,616 5m
121,108 95,145 743,856 6
31,487 2,576 875,110 7
140,017 .138,959 8
526 1,277 -'-23,772 9m
8,745 10
875,971 873,663 ra 3,600,000 11
71,480 71,273 -.:-76,258 12
17,655 13
9,024 -""
" -6,151 14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,67S
FERC FORM NO.1 (ED. 12-90)Page 327.21
Name of Respondent This l80rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/18/2011
PU~C~AJlED POWER ¡rccou1t 555)
n u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electncity (Leo, 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 onginal contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Leo, 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
eaniest 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 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
ionger 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 abové'defined categones, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 PUD #1 of Cowlitz County EX 554 NA NA NA
2 Seattle City Light EX 554 NA NA NA
3 Seattle City Light EX T-11 NA NA NA
4 Southem California Edison Company EX T-11 NA NA NA
5 Tri-State Gen. & Trans._319 NA NA NA
6 Tri-State Gen. & Trans.EX 319 NA NA NA
7 Tn-State Gen. & Trans.EX T-11 NA NA NA
8 Utah Associated Municipal Power _T-11 NA NA NA%""_"JI.
9 Utah Associated Municipal Power EX T-11 NA NA .NA
10 Utah Municipal Power Agency EX T-11 NA NA NA
11 Warm Springs Power Enterprises EX T-11 NA NA NA
12 Western Area Power Administration ~_LAS-4 NA NA NA
13 Western Area Power Administration EX LAS-4 NA NA NA
14 System Deviation ~NA NA NA
Total
FERC FORM NO.1 (ED. 12.90)Page 326.22
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) ~~n Original (Mo, Da, Yr)End of 2010/Q4
(2) A Resubmission 04/18/2011
ccunt,~~?L \ ((.ontinuea)(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, 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 (t). For all other types of service, enter NA in columns (d), (e) and (t)o 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 (j+k+l)No.Received Delivered
~l \~~\'l
of Settlement ($)
(g)(h)(i)(m)
213,594 252,784 1
300,994 297,971 --315,670 2~
7,210 5,478 .MI?'%/,' VA 30,845 3
16,851 12,193 ..ii '," ~133,132 4._'li "Wl.19,219 5
8,745 48,050 6
3,028 2,973 8,810 7
-24 -64 -230 8
118,752 68,167 iir ''(Ø-1,755,000 9
45,631 4,272 .." 'iI 1,509,447 10"m
1,991 6,571 -."$j" ~-160,936 11""
265 -3,886 .,.ii'-256,850 12w"
21,802 23,332 .."'-209,558 13
-27,97"14
11,417,025 14,493,755 14,289,088 132,576,270 655,701,898 -408,270,490 380,007,67€
FERC FORM NO.1 (ED. 12-90)Page 327.22
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 326 Line No.: 3 Column: i
Reserve Share.
¡Schedule Page: 326 Line No.: 6 Column: b
Settlement ad'ustment.
chedule Pa e: 326 Line No.: 6 Column: i
Settlement adjustment.
¡Schedule Page: 326 Line No.: 7 Column: b
Secondary, economy and/or non-firm.
¡Schedule Page: 326 Line No.: 8 Column: b
Arzona Public Service Company - Contract Termination Date: October 31, 2020.
¡Schedule Page: 326 Line No.: 10 Column: i
Reserve Share.
¡Schedule Page: 326 Line No.: 12 Column: i
Financial Swap.
¡Schedule Page: 326.1 Line No.: 1 Column: b
Settlement adjustment.
¡Schedule Page: 326.1 Line No.: 1 Column: i
Financial Swap.
¡Schedule Page: 326.1 Line No.: 2 . Column: b
Settlement adjustment.
¡Schedule Page: 326.1 Line No.: 2 Column: i
Settlement adjustment.
¡Schedule Page: 326.1 Line No.: 3 Column: i
Financial Swap.
¡Schedule Page: 326.1 Line No.: 4 Column: b
Under Electrc Service Agreement subject to termination upon timely notification.
¡Schedule Page: 326.1 Line No.: 5 Column: b
Settlement adjustment.
¡Schedule Page: 326.1 Line No.: 5 Column: i
Settlement adjustment.
I$chedule Page: 326.1 Line No.: 8 Column: i
Non-generation agreement.
¡Schedule Page: 326.1 Line No.: 10 Column: b
Settlement adjustment.
¡Schedule Page: 326.1 Line No.: 10 Column: i
Operation and maintenance expense associated with the combustion tubine located in Rapid City, South Dakota.
¡Schedule Page: 326.1 Line No.: 11 Column: i
Operation and maintenance expense associated with the combustion tubine located in Rapid City, South Dakota.
¡Schedule Page: 326.1 Line No.: 12 Column: b
Secondary, economy and/or non- firm.
¡Schedule Page: 326.2 Line No.: 1 Column: b
Blanding City Corporation - Contract Termination Date: March 31, 2012.
¡Schedule Page: 326.2 Line No.: 2 Column: b
Bonnevile Power Admnistration - Contract Termination Date: August 31,2011.
¡Schedule Page: 326.2 Line No.: 3 Column: b
Bonnevile Power Admnistration - Contract Termination Date: 30 days wrttn notice.
¡Schedule Page: 326.2 Line No.: 3 Column: i
Ancilar services.
¡Schedule Page: 326.2 Line No.: 4 Column: b
Secondar, economy and/or non-firm.
IFERC 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 I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 326.2 Line No.: 4 Column: i
Ancillary services.
¡Schedule Page: 326.2 Line No.: 5 Column: i
Reserve Share.
¡Schedule Page: 326.2 Line No.: 6 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "BRITISH COLUMIA TRNSMISSION CORP." ON PAGES 326-
327: Com lete name is British Columbia Transmission Co oration.
chedule Pa e: 326.2 Line No.: 6 Column: i
Reserve Share.
¡Schedule Page: 326.2 Line No.: 9 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "CALIFORNA INEPENDENT SYSTEM OPERATOR" ON
. PAGES 326 - 327: Com lete name is California Inde endent S stem 0 erator Co oration.
chedule Pa e: 326.2 Line No.: 9 Column: b
Settlement adjustment.
¡Schedule Page: 326.2 Line No.: 9 Column: i
Settlement adjustment.
¡Schedule Page: 326.2 Line No.: 12 Column: b
Settlement adjustment.
¡Schedule Page: 326.2 Line No.: 12 Column: i
Settlement adjustment.
¡Schedule Page: 326.2 Line No.: 13 Column: i
Financial Swap.
¡Schedule Page: 326.3 Line No.: 1 Column: i
Compensation for voluntary curilment.
¡Schedule Page: 326.3 Line No.: 2 Column: b
Settlement adjustment.
¡Schedule Page: 326.3 Line No.: 2 Column: i
Settlement adjustment.
¡Schedule Page: 326.3 Line No.: 3 Column: i
Financial Swap.
¡Schedule Page: 326.3 Line No.: 9 Column: b
Settlement adjustment.
¡Schedule Page: 326.3 Line No.: 9 Column: i
Settlement adjustment.
¡Schedule Page: 326.3 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "CONSTELLATION ENERGY COMMODITIES GROUP" ON
PAGES 326 - 327: Complete name is Constellation Energy Commodities Group, Inc.
¡Schedule Page: 326.3 Line No.: 13 Column: b
Seconda, economy and/or non-firm.
¡Schedule Page: 326.3 Line No.: 14 Column: i
Financial Swap.
¡Schedule Page: 326.4 Line No.: 2 Column: b
Settlement ad'ustment.
chedule Pa e: 326.4 Line No.: 2 Column: i
Settlement adjustment.
¡Schedule Page: 326.4 Line No.: 3 Column: i
Financial Swap.
¡Schedule Page: 326.4 Line No.: 4 Column: b
Settlement adjustment.
¡Schedule Page: 326.4 Line No.: 4 Column: i
Settlement adjustment.
IFERC FORM NO.1 (ED. 12-87) Page 450.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 326.4 Line No.: 7 Column: b
Deseret Power Electrc Cooperative - Contract Termation Date: September 30, 2024.
I$chedule Page: 326.4 Line No.: 7 Column: i
Opertion and maintenance expense associated with a coal fired generatig facili located in Vernal, Utah.
chedule Page: 326.4 Line No.: 8 Column: b
Seconda, economy and/or non-firm.
I$chedule Page: 326.4 Line No.: 8 Column: i
Liquidated damages.
I$chedule Page: 326.4 Line No.: 9 Column: b
Settlement adjustment.
I$chedule Page: 326.4 Line No;: 9 Column: i
Financial Swap.
I$chedule Page: 326.4 Line No.: 10 Column: i
Financial Swap.
I§chedule Page: 326.5 Line No.: 1 Column: i
Financial Swap.
I$chedule. Page: 326.5 Line No.: 3 Column: b.
Settlement adjustment.
I$chedule Page: 326.5 Line No.: 3 Column: i
Line loss.
I$chedule Page: 326.5 Line No.: 4 Column: i
Line loss.
I$chedule Page: 326.5 Line No.: 12 Column: b
Under Electrc Service Agreement subject to termination upon tiely notification.
I$chedule Page: 326.6 Line No.: 2 Column: b
Seconda, economy and/or non-firm.
I§chedule Page: 326.6 Line No.: 5 Column: b
Settlement adjustment.
I$chedule Page: 326.6 Line No.: 5 Column: i
Settlement adjustment.
I$chedule Page: 326.6 Line No.: 6 Column: b
Seconda, economy and/or non-firm.
lSchedule Page: 326.6 Line No.: 9 Column: b
Under Electrc Service Agreement subject to termination upon tiely notification.
I$chedule Page: 326.6 Line No.: 13 Column: b
Under Electrc Service Agreement subject to termation upon tiely notification.
I$chedule Page: 326.6 Line No.: 14 Column: a
Hermiston Generating Company, L.P. operates the Hermston Generatig Plant, which is jointly owned. PacifiCorp owns 50% of the
lant. See a e 402.3 column c of this Form NO.1 for fuer information on the Hermiston Generati Plant.
chedule Pa e: 326.6 Line No.: 14 Column: b
Settlement adjustment.
I$chedule Page: 326.6 Line No.: 14 Column: i
Settlement adjustment.
I$chedule Page: 326.7 Line No.: 1 Column: a
Hermston Generating Company, L.P. operates the Hermston Generatig Plant, which is jointly owned. PacifiCorp owns 50% of the
lant. See page 402.3 column (c) of this Form No.1 for fuer information on the Hermiston Generatig Plant.
chedule Page: 326.7 Line No.: 1 Column: i
On peak incentive, supplemental dispatch effciency expense, sta-up charges and commttee settlements.
I$chedule Page: 326.7 Line No.: 2 Column: b
Settlement adjustment.
I$chedule Page: 326.7 Line No.: 2 Column: i
IFERC FORM NO.1 (ED. 12-87) Page 450.3
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010104
FOOTNOTE DATA
Settlement adjustment.
I§chedule Page: 326.7 Line No.: 4 Column: b
Hurcane, City of - Contrct Termation Date: August 31, 2012.
I§chedule Page: 326.7 Line No.: 5 Column: b
Settlement adjustment.
¡Schedule Page: 326.7 Line No.: 5 Column: i
Financial Swap.
I§chedule Page: 326.7 Line No.: 6 Column: i
Financial Swap.
I§chedule Page: 326.7 Line No.: 7 Column: b
Settlement adjustment.
¡Schedule Page: 326.7 Line No.: 7 Column: i
Labor, equipment and administrtion fees associated with hydro project in Idaho Falls, Idaho.
I§chedule Page: 326.7 Line No.: 8 Column: i
Labor, equipment and administration fees associated with hydro project in Idao Falls, Idaho.
I§chedule Page: 326.7 Line No.: 9 Column: i
Reserve Share.
¡Schedule Page: 326.7 Line No.: 11 Column: i
Financial Swap.
I§chedule Page: 326.7 Line No.: 12 Column: b
Settlement adjustment.
I§chedule Page: 326.7 Line No.: 12 Column: i
Settlement adjustment. Financial Swap.
I§chedule Page: 326.7 Line No.: 13 Column: i
Financial Swap.
¡Schedule Page: 326.8 Line No.: 1 Column: i
Compensation for self-generation.
I§chedule Page: 326.8 Line No.: 3 Column: i
Fixed annual payment.~chedule Page: 326.8 Line No.: 4 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "LOS ANGELES DEPT. OF WATER & POWER" ON PAGES 326-
327: Complete name is Los Angeles Deparent of Water and Power.
I§chedule Page: 326.8 Line No.: 5 Column: b
Secondar, economy and/or non-firm.
f$chedule Page: 326.8 Line No.: 7 Column: b
Settlement adjustment.
f$chedule Page: 326.8 Line No.: 7 Column: i
Settlement adjustment.
I§chedule Page: 326.8 Line No.: 10 Column: i
Financial Swap.
f$chedule Page: 326.8 Line No.: 12 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "METROPOLITAN WATER DISTRICT OF S. CAL." ON PAGES
326 - 327: Complete name is Metropolitan Water Distrct of Southern California.
¡Schedule Page: 326.9 Line No.: 2 Column: i
Compensation for interrptible service and operating reserves.
I§chedule Page: 326.9 Line No.: 3 Column: b
Under Electrc Service Agreement subject to termination upon timely notification.
f$chedule Page: 326.9 Line No.: 4 Column: b
Settlement adjustment.
¡Schedule Page: 326.9 Line No.: 4 Column: i
Settlement adjustment.
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 I (2) A Resubmission 04/18/2011 2Q10/04
FOOTNOTE DATA
¡Schedule Page: 326.9 Line No.: 6 Column: i
Financíal Swap.
¡Schedule Page: 326.9 Line No.: 7 Column: b
Settlement adjustment.
¡Schedule Page: 326.9 Line No.: 7 Column: i
Settlement adjustment.
¡Schedule Page: 326.9 Line No.: 11 Column: b
Under Electrc Service Agreement subject to termination upon tiely notification.
¡Schedule Page: 326.9 Line No.: 12 Column: i
Line loss.
¡Schedule Page: 326.9 Line No.: 14 Column: b
Settlement adjustment.
¡Schedule Page: 326.9 Line No.: 14 Column: i
Settement adjustment.
¡Schedule Page: 326.10 Line No.: 2 Column: i
Reserve Share.
¡Schedule Page: 326.10 Line No.: 4 Column: i
Ancilary services.
¡Schedule Page: 326.10 Line No.: 6 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "ODELL CREEK HYROELECTRC INESTORS" ON PAGES
326- 327: Com lete name is Odell Creek H droelectrc Investors, Ltd.
chedule Pa e: 326.10 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PACIFIC NORTHWST GENERATING COOP." ON PAGES 326 -
327: Complete name is Pacific Northwest Generatig Cooperative, Inc.
¡Schedule Page: 326.11 Line No.: 2 Column: b
Under Electrc Service Agreement subject to termation upon timel notification.
chedule Page: 326.11 Line No.: 3 Column: i
Line loss.
¡Schedule Page: 326.11 Line No.: 4 Column: b
Settlement adjustment.
¡Schedule Page: 326.11 Line No.: 4 Column: i
Operation expense plus amortzation of unecovered costs of Cove Project.
¡Schedule Page: 326.11 Line No.: 5 Column: b
Portland General Electrc Company - Contract Termnation Date: Round Butt project no longer operating for power production
puroses.
¡Schedule Page: 326.11 Line No.: 5 Column: i
o eration expense plus amortzation of unecovered costs of Cove Project.
Schedule Pa e: 326.11 Line No.: 6 Column: b
Seconda, economy and/or non-firm.
¡Schedule Page: 326.11 Line No.: 6 Column: i
Liability associated with paper pond at hydro facility located on the Lewis River in the state of Washington.
¡Schedule Page: 326.11 Line No.: 7 Column: i
Reserve Share.
¡Schedule Page: 326.11 Line No.: 8 Column: b
Settlement adjustment.
¡Schedule Page: 326.11 Line No.: 8 Column: i
Settlement adjustment.
¡Scheduie Page: 326.11 Line No.: 9 Column: i
Financial Swap.
¡Schedule Page: 326.11 Line No.: 10 Column: b
Under Electrc Service Agreement subject to termination upon timely notification.
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 04/18/2011 2010/Q4
FOOTNOTE DATA
I
I
I
I
Complete
'$chedule Page: 326.11 Line No.: 11 Column: b
Secondary, economy and/or non-firm.
ISchedulePage: 326.11 Line No.: 11 Column: i
Line loss.
ISchedule Page: 326.11 Line No.: 13 Column: i
Line loss.
I$chedule Page: 326.11 Line No.: 14 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PUD #1 OF CHELAN COUNTY" ON PAGES 326 - 327:
name is Public Utili Distrct No. 1 of Chelan Coun .
chedule Pa e: 326.11 Line No.: 14 Column: i
Operatig expense, bond interest, amortization and taxes.
ISchedule Page: 326.12 Line No.: 1 Column: i
Reserve Share.
I$chedule Page: 326.12 Line No.: 2 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PUD #1 OF COWLITZ COUNTY" ON PAGES 326 - 327: Complete
name is Public Utility Distrct NO.1 of Cowlitz County.
I$chedule Page: 326.12 Line No.: 2 Column: b
Secondary, economy and/or non-firm.
I$chedule Page: 326.12 Line No.: 2 Column: i
Liability associated with paper pond at hydro facility located on the Lewis River in the state of Washington.
I$chedule Page: 326.12 Line No.: 3 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PUD #1 OF DOUGLAS COUNTY" ON PAGES 326 - 327:
Complete name is Public Utility Distrct NO.1 of Douglas County.
I$chedule Page: 326.12 Line No.: 3 Column: b
Settlement adjustment.
I$chedule Page: 326.12 Line No.: 3 Column: i
Settlement adjustment.
ISchedule Page: 326.12 Line No.: 4 Column: b
Settlement adjustment.
ISchedule Page: 326.12 Line No.: 4 Column: i
Operating expense, bond interest, amortization and taes.
I$chedule Page: 326.12 Line No.: 5 Column: b
Public Utility Distrct NO.1 of Douglas County - Contract Termination Date: August 31,2018.
ISchedule Page: 326.12 Line No.: 6 Column: i
Operating expense, bond interest, amortzation and taxes.
I$chedule Page: 326.12 Line No.: 7 Column: i
Reserve Share.
I$chedule Page: 326.12 Line No.: 8 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PUD #1 OF SNOHOMISH COUNY" ON PAGES 326 - 327:
Complete name is Public Utility District NO.1 of Snohomish County.
ISchedule Page: 326.12 Line No.: 9 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PUD #2 OF GRANT COUNTY" ON PAGES 326 - 327: Complete
name is Public Utility Distrct NO.2 of Grant County.
I$chedule Page: 326.12 Line No.: 9 Column: b
Settlement adjustment.
I$chedule Page: 326.12. Line No.: 9 Column: i
Operatig expense, bond interest, amortization and taxes.
I$chedule Page: 326.12 Line No.: 10 Column: b
Public Utility Distrct NO.2 of Grant County - Contract Termination Date: 2 years wrtten notice.
I$chedule Page: 326.12 Line No.: 10 Column: i
Ancilary services.
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, Dai Yr)
PacifCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 326.12 Line No.: 11 Column: i
Operatig expense, bond interest, amortization and taes.
¡Schedule Page: 326.12 Line No.: 12 Column: i
Reserve Share.
¡Schedule Page: 326.12 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PUD #1 OF LEWIS COUN" ON PAGES 326 - 327: Complete
name is Public Utility District No. 1 of Lewis County.
¡Schedule Page: 326.12 Line No.: 13 Column: b
Settlement adjustment.
¡Schedule Page: 326.12 Line No.: 13 Column: i
Settlement adjustment.
¡Schedule Page: 326.12 Line No.: 14 Column: b
Public Utility Distrct NO.1 of Lewis County - Contrct Termation Date: 60 days wrttn. notice.
fSchedule Page: 326.13 Line No.: 1 Column: i
Reserve Share.
¡Schedule Page: 326.13 Line No.: 3 Column: b
Settlement adjustment.
¡Schedule Page: 326.13 Line No.: 3 Column: i
Settlement adjustment.
ISchedulePage: 326.13 Line No.: 6 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "ROCKY MOUNAI GENERATION COOP." ON PAGES 326 -
327: Com lete name is Rocky Mountain Generation Cooperative, Inc.
chedule Pa e: 326.13 Line No.: 8 Column: b
Secondary, economy and/or non-firm.
¡Schedule Page: 326.13 Line No.: 11 Column: b
Settlement adjustment.
¡Schedule Page: 326.13 Line No.: 11 Column: i
Settlement adjustment.
¡Schedule Page: 326.13 Line No.: 12 Column: b
Sacramento Municipal Utility Distrct - Contrct Termation Date: December 31,2014.
ISchedule Page: 326.13 Line No.: 13 Column: i
Reserve Share.
¡Schedule Page: 326,13 Line No.: 14 Column: i
Line loss.
¡Schedule Page: 326.14 Line No.: 1 Column: b
Settlement adjustment.
ISchedule Page: 326.14 Line No.: 1 Column: i
Settlement adjustment.
¡Schedule Page: 326.14 Line No.: 5 Column: i
Reserve Share.
¡Schedule Page: 326.14 Line No.: 6 Column: b
Settlement adjustment.
¡Schedule Page: 326.14 Line No.: 6 Column: i
Settlement adjustment. Financial Swap.
ISchedule Page: 326.14 Line No.: 7 Column: i
Financial Swap.
ISchedule Page: 326.14 Line No.: 9 Column: b
Settlement adjustment.
¡Schedule Page: 326.14 Line No.: 9 Column: i
Settlement adjustment.
¡Schedule Page: 326.14 Line No.: 10 Column: i
IFERC FORM NO.1 (ED. 12-87) Page 450.7
Name of Respondent .This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010104
FOOTNOTE DATA
Financial Swap.
I§chedule Page: 326.14 Line No.: 12 Column: i
Reserve Share.
I§chedule Page: 326.14 Line No.: 13 Column: i
Line loss.
¡Schedule Page: 326.15 Line No.: 3 Column: b
Secondary, economy and/or non-firm.
I§chedule Page: 326.15 Line No.: 6 Column: b
Under Electrc Service Agreement subject to termation upon timely notification.
~chedule Page: 326.15 Line No.: 8 Column: b
Under Electrc Service Agreement subject to termation upon timely notification.
I$chedule Page: 326.15 Line No.: 10 Column: b
Under Electrc Service Agreement subject to termination upon timely notification.
I§chedule Page: 326.15 Line No.: 14 Column: b
Settlement adjustment.
I§chedule Page: 326.15 Line No.: 14 Column: i
Settlement adjustment.
I§chedule Page: 326.16 Line No.: 1 Column: i
Reserve Share.
I§chedule Page: 326.16 Line No.: 6 Column: i
Compensation for volunta curilment.
Ißchedule Page: 326.16 Line No.: 7 Column: b
Settlement adjustment.
Ißchedule Page: 326.16 Line No.: 7 Column: i
Settlement adjustment.
I§chedule Page: 326.16 Line No.: 10 Column: i
Operatig reserve reimbursement.
Ißchedule Page: 326.16 Line No.: 13 Column: a
THS FOOTNOTE APPLIES TO ALL OCCURNCES OF "TRI-STATE GEN. & TRANS." ON PAGES 326 - 327: Complete
name is Tn-State Generation and Transmission Association, Inc.
¡Schedule Page: 326.16 Line No.: 13 Column: b
Tn-State Generation and Transmission Association - Contract Termination Date: December 31,2020.
I§chedule Page: 326.16 Line No.: 14 Column: i
Line loss.
'rchedule Page: 326.17 Line No.: 1 Column: b
Seconda, economy and/or non-firm.
¡Schedule Page: 326.17 Line No.: 2 Column: i
Line loss.
¡Schedule Page: 326.17 Line No.: 3 Column: i
Reserve Share.
Ißchedule Page: 326.17 Line No.: 6 Column: b
US Magnesium LLC - Contract Termation Date: December 31,2014.
I§chedule Page: 326.17 Line No.: 6 Column: i
Ancilar services.
I§chedule Page: 326.17 Line No.: 7 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "UTAH ASSOCIATED MUICIPAL POWER" ON PAGES 326 -
327: Com lete name is Utah Associated Munici al Power S stems.
Schedule Pa e: 326.17 Line No.: 7 Column: b
Secondar, economy and/or non-firm.
I§chedule Page: 326.17 Line No.: 14 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "WASATCH INTEGRATED WASTE MAAGEMENT" ON PAGES
IFERC FORM NO.1 (ED. 12-87) 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 04/18/2011 2010/Q4
FOOTNOTE DATA
326 - 327: Complete name is Wasatch Integrted Waste Management Distrct.
I$chedule Page: 326.18 Line No.: 2 Column: b
Settlement adjustment.
¡Schedule Page: 326.18 Line No.: 4 Column: i
Reserve Share.
I$chedule Page: 326.18 Line No.: 5 Column: i
Line loss.
I$chedule Page: 326.18 Line No.: 6 Column: b
Settlement adjustment.
I$chedule Page: 326.18 Line No.: 6 Column: i
Settlement adjustment.
I$chedule Page: 326.18 Line No.: 9 Column: i
Represents the difference between actual purchase expenses for the period as reflected on the individual line items within this
schedule, and the accruals charged to account 555 durng this period and excess net power cost deferrals.
I$chedule Page: 326.18. Line No.: 10 Column: i
Reserve for potential liabilties associated with curailment on receipt of energy and settlement for unetered megawatt hours.
I$chedule Page: 326.18 Line No.: 11 CQlumn: i .
Reco ition and re ort of ains and losses on bookouts under enerall acce ted accounti rid les.
chedule Pa e: 326.18 Line No.: 12 CQlumn: i
Reco ition and re ortn of ains and losses on ener tradin
chedule Pa e: 326.19 Line No.: 2 Column: i
Exchange energy expense.
I$chedule Page: 326.19 Line No.: 4 Column: i
Imbalance energy.
I$chedule Page: 326.19 Line No.: 6 CQlumn: b
Settlement adjustment.
I$chedule Page: 326.19 Line No.: 6 Column: i
Storage and exchange charges.
I$chedule Page: 326.19 Line No.: 7 Column: b
Settlement adjustment.
¡Schedule Page: 326.19 Line No.: 7 Column: i
Pacific Northwest Electrc Power Planning and Conservation Act, FERC Electrc Tarff, Orginal Volume NO.1.
¡Schedule Page: 326.19 Line No.: 8 Column: i
These megawatt hours represent book entr only. No actual energy trsfer took place.
I$chedule Page: 326.19 Line No.: 9 Column: i
These megawatt hours represent book entr only. No actual energy trsfer took place.
I$chedule Page: 326.19 Line No.: 10 Column: i
Exchange energy expense.
¡Schedule Page: 326.19 Line No.: 13 Column: i
Pacific Nortwest Electrc Power Planning and Conservation Act, FERC Electrc Tarff, Original Volume No. 1.
I$chedule Page: 326.19 Line No.: 14 CQlumn: i
Imbalance energy.
I$chedule Page: 326.20 Line No.: 1 Column: i
Exchange energy expense.
I$chedule Page: 326.20 Line No.: 2 Column: i
Imbalance energy.
I$chedule Page: 326.20 Line No.: 3 Column: i
Exchange energy expense.
I$chedule Page: 326.20 Line No.: 4 Column: i
Imbalance energy.
I$chedule Page: 326.20 Line No.: 6 CQlumn: 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, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Imbalance energy.
¡Schedule Page: 326.20 Line No.: 7 Column: b
Settlement adjustment.
\Schedule Page: 326.20 Line No.: 7 Column: i
Imbalance energy.
¡Schedule Page: 326.20 Line No.: 8 Column: i
Imbalance energy.
\Schedule Page: 326.20 Line No.: 9 Column: b
Settlement adjustment.
¡Schedule Page: 326.20 Line No.: 9 Column: i
Storage and exchange charges.
¡Schedule Page: 326.20 Line No.: 10 Column: i
Storage and exchange charges.
¡Schedule Page: 326.20 Line No.: 11 Column: i
Exchange energy expense.
I§chedule Page: 326.20 Line No.: 12 Column: i
Imbalance energy.
I§chedule Page: 326.20 Line No.: 14 Column: i
Imbalance energy.
¡Schedule Page: 326.21 Line No.: 1 Column: i
Imbalance energy.
I§chedule Page: 326.21 Line No.: 2 Column: b
Settlement adjustment.
rschedule Page: 326.21 Line No.: 2 Column: i
Station service for third part wind project.
I§chedule Page: 326.21 Line No.: 3 Column: i
Station service for third par wind project.
rschedule Page: 326.21 Line No.: 4 Column: b
Settlement adjustment.
¡Schedule Page: 326.21 Line No.: 4 Column: i
Reimbursement for providing station service to third par wind project.
¡Schedule Page: 326.21 Line No.: 5 Column: i
Reimbursement for providing station servce to third part wind project.
I§chedule Page: 326.21 Line No.: 6 Column: i
Imbalance energy.
I§chedule Page: 326.21 Line No.: 7 Column: i
Imbalance energy.
¡Schedule Page: 326.21 Line No.: 9 Column: i
Imbalance energy.
I§chedule Page: 326.21 Line No.: 11 Column: i
Storage and exchange charges.
I§chedule Page: 326.21 Line No.: 12 Column: i
Exchange energy expense.
¡Schedule Page: 326.21 Line No.: 14 Column: i
Storage and exchange charges.
I$chedule Page: 326.22 Line No.: 2 Column: i
Exchange energy expense.
\Schedule Page: 326.22 Line No.: 3 Column: i
Imbalance energy.
I§chedule Page: 326.22 Line No.: 4 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 '2) . AResubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 326.22 Line No.: 5 Column: b
Settlement adjustment.
¡Schedule Page: 326.22 Line No.: 5 Column: i
Imbalance energy.
¡Schedule Page: 326.22 Line No.: 6 Column: i
Imbalance energy.
¡Schedule Page: 326.22 Line No.: 7 Column: i
Imbalance energy.
¡Schedule Page: 326.22 Line No.: 8 Column: b
Settlement adjustment.
¡Schedule Page: 326.22 Line No.: 8 Column: i
Imbalance energy.
¡Schedule Page: 326.22 Line No.: 9 Column: i
Imbalance energy.
¡Schedule Page: 326.22 Line No.: 10 Column: i
Imbalance energy.
¡Schedule Page: 326.22 Line No.: 11 Column: i
Imbalance ener .
chedule Pa e: 326.22 Line No.: 12 Column: b
Settlement adjustment.
¡Schedule Page: 326.22 Line No.: 12 Column: i
Imbalance energy.
¡Schedule Page: 326.22 Line No.: 13 Column: i
Imbalance energy.
¡Schedule Page: 326.22 Line No.: 14 Column: b
Not applicable: adjustment for inadavertent interchange.
IFERC FORM NO.1 (ED. 12-87)Page 450.11
Name of Respondent
PacifiCorp
This ~ort Is:
(1) ~An Original
(2) A Resubmission
Year/Period of Report
End of 2010/Q4
Date of Report
(Mo, Da, Yr)
04/18/2011
ccount
(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 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.
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 Arizona Public. Service Company Arizona Public Service Company
2 Basin Electric Power Cooperative Western Area Power Administration
3 Basin Electric Power Cooperative Western Area Power Administration
4 Basin Electric Power Cooperative Westem Area Power Administration
5 Basin Electric Power Cooperative Western Area Power Administration
6 Basin Electric Power Cooperative
7 Barclay's Bank
8
9 Black Hils/Colorado Electric Utilty Company
10 Black Hils, Inc.
11 Black Hils, Inc.
12 Black Hils, Inc.
13 Black Hils, Inc.
14 Black Hils, Inc.
15 Black Hils, Inc.
16 Black Hils, Inc.
17 Bonnevile Power Administration
18 Bonnevile Power Administration
19 Bonnevile Power Administration Bonnevile Power Administration Bonnevile Power Administration
20 Bonnevile Power Administration Bonnevile Power Administration Bonnevile Power Administration
21 Bonnevile Power Administration Bonnevile Power Administration Bonnevile Power Administration
22 Bonnevile Power Administration Bonnevile Power Administration Bonnevile Power Administration
23 Bonnevile Power Administration Bonnevile Power Administration Umpqua Indian Utilty Cooperative
24 Bonnevile Power Administration Bonnevile Power Administration Umpqua Indian Utilty Cooperative
25 Bonnevile Power Administration Bonnevile Power Administration lI
26 Bonnevile Power Administration Bonnevile Power Administration
27 Bonnevile Power Administration Bonnevile Power Administration
28 Bonnevile Power Administration
29 Bonnevile Power Administration
30 Bonnevile Power Administration Bonnevile Power Administration
31 Bonnevile Power Administration Bonnevile Power Administration Bonnevile Power Administration
32 Bonnevile Power Administration Bonnevile Power Administration Bonnevile Power Administration
33 Bonnevile Power Administration Bonnevile Power Administration Yakama Power
34 Bonnevile Power Administration Bonnevile Power Administration Yakama Power
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328
.
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
OF ELECl KI.I,II Y i-YK l! ! Ht:K~ .v~ccunt 4ooJ\\JontinUed)
(Including transactions raffered to as 'wlieelingÕf
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" trnsmission 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 billng demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY LineSchedule 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)ü)
R.S.436 ~-....Borah/Brady Sub 1
7V11-3,4 Yellowtail Sub Sheridan Substation 2 4,331 4,331 2
7V11-3,4 Yellowtail Sub Sheridan Substation 2 1,633 1,63~3
7V11 Yellowtail Sub Sheridan Substation 11 7,416 7,4H 4
7V11 Yellowtail Sub Sheridan Substation 11 7,602 7,60 5
7V11-8 Various Various 25,789 25,78!6
7V11-8 Various Various 7
7V11-8 Various ..Various 88 81 8
7V11-7 Various Various 90 9(9
7V11 Various Sheridan Substation 43 32,344 32,34'10
7V11 Various Sheridan Substation 43 6,646 6,64l 11
7V11-8 Various Various 12,374 12,37'12
7V11-8 Various Various 816 8H 13
7V11-7 Various Various 16,438 16,431 14
7V11-7 Various Wyodak Substation 50 157,346 157,34l 15
7V11-7 Various Wyodak Substation 50 3,705 3,70!16
R.S.369 Midpoint Substation Summer Lake Sub 17
R.S.237 Various Various 189 1,102,930 1,102,93(18
R.S.237 Various Various 189 115,754 115,75~19
7V11-3,4 _,,S""'latiOO 56 51,289 51 ,28~20
R.S.324 . . .~i Various 167,011 167,011 21
R.S.324 ,. :~ ~,. Various 12,695 12,69f 22
7V11-3,4 Bonnevile Power Adm Gazley Substation 3 23,150 23,15C 23
7V11-3 Bonnevile Power Adm Gazley Substation 3 2,372 2,37.24
7V11-3,4 Bonnevile Power Adm Tieton Substation 2 4,666 4,66E 25
7V11-3,4 Bonnevile Power Adm Tieton Substation 2 937 93 26
7V11-3,4 McNary Substation Hinkle Substation 1 848 84€27
7V11-3,4 McNary Substation Hinkle Substation 1 153 15,28
7V11-7 USBR Green Springs Bonnevile Power Adm 18 52,471 52,471 29
7V11-7 USBR Green Springs Bonnevile Power Adm 18 5,569 5,56~30
R.S.368 Malin Substation Malin Substation 618,730 618.73C 31
R.S.368 Malin Substation Malin Substation 63,710 63,71C 32
7V11-3,4 Bonnevile Power Adm White SwanlToppenish 7 32,925 32,92~33
7V11-3,4 Bonnevile Power Adm White SwanlToppenish 7 3,910 3,91C 34
3,483 13,164,045 13,164,04l
FERC FORM NO.1 (ED. 12-90)Page 329
Name of Respondent
PacifiCorp
This ~ort Is:
(1) IlAn Original
(2) A Resubmission
Year/Period of Report
End of 2010/Q4
Date of Report
(Mo, Da, Yr)
04/18/2011
ccount ontinue
(Including transactions 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 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 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 required data.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energy Charges (Other Charges)($) ($)(I) (m)Total Revenues ($)
(k+l+m)
(n)
ine
No.
9,566
1
33,026 2
3,945 3
13,707 4
13,707 5
118,279 6
152 7
514 8
584 9
625,143 10
55,690 11
74,511 12
4,701 13
65,957 14
1,113,750 15
101,250 16
17
4,232,267 18
384,761 19
340,200 20
208,184 21
26,023 22
187,174 23
16,230 24
19,790 25
2,513 26
9,708 27
1,331 28
400,950 29
36,450 30
246,946 31
22,450 32
115,461 33
25,535 34
9,538
13,707
625,143
1,113,750
4,164,320
340,200
45,398
19,043
400,950
85,621
27,323,230 8,990,099 31,498,786 67,812,115
FERC FORM NO.1 (ED. 12-90)Page 330
Name of Respondent
PacifiCorp
This ~ort Is:
(1) 1lAn Original
(2) A Resubmission
Year/Period of Report
End of 2010/Q4
ccount
(Including transactions referred to as 'wheeling')
1. Report all transmission of electricity, Leo, wheeling, provided for other electric utilities, 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 authority. Do not abbreviate or truncate name or use acronyms. Explain in a föotnote
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, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affliation)
(a)
Bonnevile Power Administration
2 Bonnevile Power Administration
Energy Received From
(Company of Public Authority)
(Footnote Affliation)
(b)
Bonnevile Power Administration
Energy Delivered To
(Company of Public Authority)
(Footnote Affliation)
(c)
Bonnevile Power Administration
Statistical
Classifi-
cation
(d)
3 Bonnevile Power Administration
4 Bonnevile Power Administration
5 Bonnevile Power Administration
6 Bonnevile Power Administration
7. Cargil Power Markets, LLC
8 Cargil Power Markets, LLC
9 Cargil Power Markets, LLC
10 Citigroup
11
Deseret Generation & Trans.
Deseret Generation & Trans.
Deseret Generation & Trans.
Eagle Energy Partners
Endure Energy, LLC.
Enel Cove Fort, LLC
Eugene Water & Electric Board
24 Eugene Water & Electric Board
25 Fall River Rural Electric Cooperative
26 Fall River Rural Electric Cooperative
27 Foote Creek IIi, LLC
28 Foote Creek ILL, LLC
29 Gila River Power, L.P.
30 Iberdrola Renewables Inc.
31 Iberdrola Renewables Inc.
32 Iberdrola Renewables Inc.
33 Iberdrola Renewables Inc.
34 Iberdrola Renewables Inc.
TOTAL
FERC FORM NO.1 (ED. 12.90)Page 328.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ¡=A Resubmission 04/18/2011
! Of ELEC1KI~11 y' FQR ' lAccount 456)(Contlnued)(Including transactions reffered to as 'wfleeling')
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
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY 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)ü)
RS.299 Various Various 160 1,416,059 1 ,416,05~1
RS.299 Various Various 160 208,173 208,17,2
7V11-7 Various Various 24,791 24,791 3
7V11-8 Various Various 4
7V11-3,4 Cardwell-Merwin -24 104,239 104,23~5
7V11-3,4 Cardwell-Merwin -,-24 16,619 16,6H 6
7V11-8 Various Various 149,117 149,111 7
7V11-8 Various Various 7,432 7,43 8
7V11-7 Various Various 11,430 11,43C 9
7V11-8 Various Various 10
7V11-8, 9, 11 Various Various 9,670 9,67C 11
7V11-8 Various Various 4,330 4,33C 12
RS.234 Swift Unit NO.2 Woodland Substation 13
RS.234 Swift Unit NO.2 Woodland Substation 14
RS.280 Various Various 105 438,585 438,58E 15
RS.280 Various Various 105 204,213 204,21 16
RS.590 Various Various 17
RS.590 Various Various 18
7V11-7 Various Various .864 86'19
7V11-8 Various Various 20
7V11-8 Various Various 21
7V11-7 Enel Cove Fort Mona Substation 22
7V11-8 Various Various 2,988 2,98~23
7V11-8 Various Various 1,010 1,01 (24
RS.322 Targhee Substation Goshen Substation 4,346 4,34€25
RS.322 Targhee Substation Goshen Substation 26
SA 130 Foote Creek Sub Various 27
SA 130 Foote Creek Sub Various 28
7V11-8 Various Various 682 68:.29
7V11-8 Various Various 33,286 33,28€30
7V11-8 Various Various 3,010 3,01(31
7V11-5,6,9,11 Wallula Substation Wallula Substation 32
7V11-5,6,9 Wallula Substation Wallula Substation 33
7V11-5,6,9,11 -i:---34
3,483 13,164,045 13,164,04S
FERC FORM NO.1 (ED. 12-90)Page 329.1
Name of Respondent
PacifiCorp
This ~ort Is:
(1) IlAn Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/18/2011
ccunt
(Including transactions 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 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 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.
YearlPeriod of Report
End of 2010/Q4
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energy Charges (Oter Charges)($) ($)(I) (m)"-~"
"""ØJri
887,859
291,796
1 ,561 ,042
608,352
27,323,230 8,990,099 31,498,786 67,812,115
FERC FORM NO.1 (ED. 12-90)Page 330.1
Total Revenues ($) ine
(k+l+m) No.
(n)
1,912,432 1
176,622 2
1,401 3
6 4
314,429 5
30,970 6
1,300,770 7
43,014 8
65,225 9
6 10
91,062 11
32,018 12
75,239 13
36,813 14
1,588,290 15
789,019 16
1,257,296 17
427,560 18
3,348 19
3,733 20
1,168 21
50,625 22
17,690 23
5,898 24
138,699 25
12,609 26
33,168 27
3,015 28
3,291 29
469,369 30
74,297 31
27,553 32
2,939 33
252,362 34
Name of Respondent
PacifiCorp
This ~ort Is:
(1) ~An Original
(2) A Resubmission
Year/Period of Report
End of 2010/Q4
Date of Report
(Mo, Da, Yr)
04/18/2011
ccunt
(Including transactions referred to as 'wheeling')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, 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 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.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affliation)
(a)
1 Iberdrola Renewables Inc.
Energy Received From
(Company of Public Authority)
(Footnote Affliation)
(b)
Iberdrola Renewables Inc.
Exon Mobile
Exon Mobile
Idaho Power Company
Energy Delivered To
(Company of Public Authority)
(Footnote Affliation)
(c)
Statistical
Classifi-
cation
(d)
2 Iberdrola Renewables Inc.
3 Iberdrola Renewables Inc.
4 Idaho Power Company
5 Idaho Power Company
6 Idaho Power Company
7 Idaho Power Company
8 Idaho Power Company
9 Idaho Power Company
10 Idaho Power Company
11 Idaho Power Company
16 Macquarie Energy, LLC
17 Macquarie Energy, LLC
18 Moon Lake Electric Association
19 Moon Lake Electric Association
20 Morgan Stanley Capital Group, Inc.
21 Morgan Stanley Capital Group,. Inc.
22 Morgan Stanley Capital Group, Inc.
23 Municipal Energy Agency of Nebraska
24 NextEra Energy Resources, LLC
25 NextEra Energy Resources, LLC
26 NextEra Energy Resources, LLC
27 Pacific Gas & Electric Company
28 Pacific Gas & Electric Company
29 Pacific Gas & Electric Company
30 Powerex Corporation
31 Powerex Corporation
32 Powerex Corporation
33 Powerex Corporation
34 Powerex Corporation
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.2
Name of Respondent This Re ort Is:Date of Report Year/Period of Report
PacifiCorp (1) ~An Original (Mo, Da, Yr)End of 2010/Q4
(2)A Resubmission 04/18/2011
~':~ "".':" T ~" "' ~"~' ,:-.~~ccunt 40Ö)(I"OntlnUea)
(Including transactions 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 (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 billng demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivere.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY LineSchedule 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)ü)
7V11-5,6,9,11 -~...-1
7V11-7 Trona Substation Red Butte/Mona Sub 30 56,556 56,556 2
7V11-7 Trona Substation Red Butte/Mona Sub 30 7,829 7,829 3
RS.427 Goshen Substation Goshen Substation 4
7V11-7 Red Butte Substation Borah/Brady Sub 75 61,018 61,018 5
7V11-8 Various Various 27,680 27,680 6
7V11-7 Various Various 66,989 66,989 7
RS.257 Antelope Substation Antelope Substation 15,678 15,678 8
RS.257 Antelope Substation Antelope Substation 9
RS.203 Jim Bridger Sub Bridger Pump Station 10
RS.203 Jim Bridger Sub Bridger Pump Station 11
7V11-8 Various Various 36,957 36,957 12
7V11-5,6,9,11 Various Various 13
7V11-8 Various Various 14
7V11-8 Various Various 37,787 37,787 15
7V11-8 Various Various 1,290 1,290 16
7V11-8 Various Various 11 11 17
RS.302 Duchesne Duchesne 3 17,434 17,434 18
RS.302 Duchesne Duchesne 3 1,541 1,541 19
7V11-8 Various Various 159,217 159,21 t 20
7V11-8 Various Various 12,873 12,873 21
7V11-7 Various Various 2,647 2,64t 22
7V11-8 Various Various 1,935 1,93~23
7V11-5,6,9,11 Wallula Substation Wala-MID-C Path 80 255,567 255,56t 24
7V11-5,6,9,11 Wallula Substation Wala-MID-C Path 80 13,863 13,863 25
7V11-8 Various Various 26
RS.607 -...27~,
RS.298 Sigurd-Glen Canyon Pinto-Four Comers 28
7V11-8 Various Various 9 9 29
7V11-7 Bonnevile Power Adm Weed Jct. Substation 80 290,447 290,44t 30
7V11-7 Bonnevile Power Adm Weed Jct. Substation 80 18,922 18,92~31
7V11-5,6,8 Various Various 365,059 365,059 32
7V11-5,6,8 Various Various 9,217 9,211 33
7V11-7 Various Various 948 948 34
3,483 13,164,045 13,164,04f
FERC FORM NO.1 (ED. 12-90)Page 329.2
...
Name of Respondent This ø0rt Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
cLcL; i KI~II Y ~"~. '.' ,~, ':-VhE ccount 40Ö) (L;ontinued)
(Including transactions 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 billng demand reported in column (h). In column (I), providè revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)-iI "~59,727 1¡¡
486,000 182,250 668,250 2...I! ~.60,750 3
4
756,740 756,740 5
159,197 159,197 6
708,750 708,750 7_im.'67,672 8'"--6,152 9¡¡..."14,927 10úf aw---1,357 11
463,390 463,390 12--.'"5,965 13_..I!6 14û
213,028 213,028 159297 II 9,297 16-~~.64 17..~ 'd 18,123 18. .._". .1,677 191.007.429 ~1,007,429 20_;w....::79,431 21
11,675 11,675 22
12,474 12,474 23
1,546,995 --2,508,682 24- ;~...219,921 25
254,642 254,642 26-W~20,000,000 27JPØ-?Ø ø-.".'310,869 280~~"'% ¡;
374 374 29
1,782,000 1,782,000 30..145,161 31
2,494,533__ ~2,514,136 32... ..58,574 33
8,325 8,325 34
27,323,230 8,990,099 31,498,786 67,812,115
FERC FORM NO.1 (ED. 12-90)Page 330.2
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/18/2011
ccount
(Including transactions referred to as 'wheelin ')
1. Report all transmission of electricity, i.e., 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 the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service; OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of coes.
This ~ort Is:
(1) ~An Original
(2) A Resubmission
Year/Period of Report
End of 2010/Q4
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affliation)
(a)
1 PPL Energy Plus, LLC
2 PPL Energy Plus, LLC
3 PPL Energy Plus, LLC4 ..... ø
7 Rainbow Energy Marketing Corporation
8 Rainbow Energy Marketing Corporation
9 Rainbow Energy Marketing Corporation
10 Raser Power Systems, Inc.
11 Raser Power Systems, Inc.
12 Salt River Project
13 Seattle City & Light
14 Seattle City & Light
15 Seattle City & Light
16 Sempra Energy Solutions LLC
17 Sempra Energy Solutions LLC
18 Shell Energy North America
19 Shell Energy North America
20 Sierra Pacific Power Company
21 Sierra Pacific Power Company
22 Sierra Pacific Power Company
23 Sierra Pacific Power Company
24 Southern California Edison
25 Southern California Edison
26 Southern California Edison
27 State of South Dakota
28 State of South Dakota
29 The Energy Authority
30 The Energy Authority
31 TransAlta Energy Marketing Corporation
32 TransAlta Energy Marketing Corporation33 ""i¡Y0i% ¡¡.~
34 Tri-State Generation & Trans.
TOTAL
Energy Received From
(Company of Public Authority)
(Footnote Affliation)
(b). ..rn.. .~..
Statistical
Classifi-
cation
(d)
Energy Delivered To
(Company of Public Authority)
(Footnote Affliation)
(c)
Tri-State Generation & Trans.
Page 328.3FERC FORM NO.1 (ED. 12-90)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
i ~L~i" 1 1'1.':11 Y l:'' '-" '~"~.,~ ccount 40ö)((,ontlnUeO)
(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 (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY LineSchedule 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)u)
7V11-8 Various Various 9,586 9,58€1
7V11-8 Various Various 1,066 1,066 2
7V11-7 Various Various 3,688 3,688 3
7V11-8 Various Various 8,685 8,685 4
7V11-8 Various Various 32 3,.5
7V11-7 Varioús Various 17,628 17,628 6
7V11-8 Various Various 11,260 11,26C 7
7V11-8 Various Various 419 41S 8
7V11-7 Various Various 17,866 17,866 9
7V11-5,6,7,9 South Milford Sub Mona Substation 11 45,680 45,68C 10
7V11-5,6,7,9 South Milford Sub Mona Substation 11 3,892 3,89"11
7V11-8 Various Various 15,803 15,80 12
7V11-5,6,7,9 Wallula Substation Wala-MID-C Path 25 46,496 46,496 13
7V11-5,6,7,9 Wallula Substation Wala-MID-C Path 25 1,883 1,88~14
7V11-8 Various Various 17 1 15
7V11-3,4 Bonnevile Power Adm Various 15 116,828 116,82€16
7V11-3,4 Bonnevile Power Adm Various 15 6,627 6,62 17
7V11-8 Various Various 530 53C 18
7V11-8 Various Various 448 44€19
R.S.674 Sigurd Sub -o.-rJ 20
7V11-8 Various Various 1,891 1,891 21
7V11-8 Various Various 947 94 22
7V11-7 Various Various 1,000 1,00C 23
7V11-5,6,7 Various Various 5,845 5,845 24
7V11-8,9,11 Various Various 16,199 16,199 25
R.S.298 Sigurd-Glen Canyon Pinto-Four Corners 26
7V11-7 Yellowtail Sub Wyodak Substation 4 16,864 16,864 27
7V11-7 Yellowtail Sub Wyodak Substation 4 1,505 1,505 28
7V11-8 Various Various 25 2~29
7V11-8 Various Various 11 11 30
7V11-8 Various Various 5,406 5,406 31
7V11-8 Various Various 1,749 1,74~32
R.S. 123 Various Various 31 144,112 144,11.33
R.S.123 Various Various 31 17,166 17,16€34
3,483 13,164,045 13,164,045
FERC FORM NO.1 (ED. 12-90)Page 329.3
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
Date of Report
(Mo, Da, Yr)
04/18/2011
ccunt ontinue
(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 bils or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Recived 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.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energy Charges (Other Charges)($) ($)(i) (m)
57,841 .¡i
19,180
53,591
Total Revenues ($) ine
(k+l+m) No.
(n)
89,100
57,841 1
7,131 2
19,180 3
53,591 4
23,325 5
102,884 6
74,529 7
2,681 8
92,879 9
278,663 10
25,221 11
113,303 12
762,466 13
50,625 14
1,460 15
251,271 16
9,496 17
4,491 18
2,938 19
68,919 20
11,717 21
4,650 22
5,530 23
36,337 24
900,489 25
310,869 26
89,100 27
8,100 28
146 29
339 30
43,567 31
11,756 32
116,313 33
9,437 34
245,025
718,875
177,344
116,313
27,323,230 8,990,099 31,498,786 67,812,115
FERC FORM NO.1 (ED. 12.90)Page 330.3
Name of Respondent
PacifiCorp
This Report Is:
(1) (8An Original
(2) A Resubmission
Year/Period of Report
End of 2010/Q4
Date of Report
(Mo, Da, Yr)
04/18/2011
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 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 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.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affliation)
(a)
1 Tri-State Generation & Trans.
2 Tri-State Generation & Trans.
3 United States Bureau of Reclamation
4 United States Bureau of Reclamation
5 United States Bureau of Reclamation
6 United States Bureau of Reclamation
7 United States Bureau of Reclamation
8 Utah Associated Municipal Power Systems
9 Utah Associated Municipal Power Systems
10 Utah Associated Municipal Power Systems
11 Utah Municipal Power Agency
12 Utah Municipal Power Agency
13 Warm Springs Power Enterprises
14 Warm Springs Power Enterprises
15 Western Area Power Administration
16 Western Area Power Administration
17 Western Area Power Administration
18 Western Area Power Administration
19 Western Area Power Administration
20 Western Area Power Administration
21 Western Area Power Administration
22 Western Area Power Administration
23 Western Area Power Administration
24 Western Area Power Administration
25 Accrual True-up
26
27
28
29
30
31
32
33
34
Energy Received From
(Company of Public Authority)
(Footnote Affliation)
(b)
Statistical
Classifi-
cation
(d)
Bonnevile Power Administration
Bonnevile Power Administration
Bonnevile Power Administration
Western Area Power Administration
Western Area Power Administration Weber Basin Water Conserv.
'/1l Utah Associated Municipal Power
Utah Associated Municipal Power Utah Associated Municipal Power
Utah Associated Municipal Power Utah Associated Municipal Power
Utah Municipal Power Agency Utah Municipal Power Agency
Utah Municipal Power Agency Utah Municipal Power Agency
Warm Springs Enterprises Portland General Electric Co
Warm Springs Enterprises Portland General Electric Co
Western Area Power Administration
Westem Area Power Administration
Westem Area Power Administration
Western Area Power Administration
Western Area Power Administration
Western Area Power Administration
Western Area Power Administration
Westem Area Power Administration
Western Area Power Administration
Western Area Power Administration Westem Area Power Administration
TOTAL
Page 328.4FERC FORM NO.1 (ED. 12-90)
..c.
Name of Respondent c ThiS~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)A Resubmission 04/18/2011
11"11,,;11 Y ccunt 456)(Contlnued)
(Including transactions reffered to as 'wñeeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and U) the total megawatthours received and delivere.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedule 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)ü)
7V11-8 Various Various 436 43E 1
7V11-3,4 DJ Substation Thermopolis Sub 18 17,613 17,61~2
7V11-3 Walla Walla Sub Burbank Pumps 1 2,195 2,19~3
7V11-3 Walla Walla Sub Burbank Pumps 1 4
RS.67 Redmond Substation Crooked River Pumps 4 7,347 7,341 5
RS.286 Various Various 24,196 24,19E 6
RS.286 Various Various 1,415 1 ,41~7
RS.297 Various Various 338 2,898,693 2,898,69~8
RS.297 Various Various 338 292,993 292,992 9
7V11-8 Various Various 3,174 3,174 10
RS.637 Various Various 101 557,192 557,19~11
RS.637 Various Various 101 52,250 52,25C 12
R.S.591 Pelton Reregulating Round Butte Sub 80,634 80,634 13
RS.591 Pelton Reregulating Round Butte Sub 7,355 7,35~14
RS.262 Various Various 330 1,479,333 1 ,479,33~15
RS.262 Various Various 330 156,206 156,20E 16
RS.263 Various Various 83,483 83,482 17
RS.263 Various Various 8,520 8,52C 18
7V11-8 Various Various 129,311 129,311 19
7V11-8 Various Various 13,208 13,208 20
RS.664 Dave Johnston Sub Various 166,992 166,99~21
RS.664 Dave Johnston Sub Various 11,912 11,91"22
7V11 Wyoming Distribution Wyoming Distribution 1 10,374 10,374 23
7V11 Wyoming Distribution Wyoming Distribution 1 3 2 24
25
26
27
28
29
30
31
32
33
34
3,483 13,164,045 13,164,04~
FERC FORM NO.1 (ED. 12-90)Page 329.4
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/04
This ~ort Is:
(1) ~An Original
(2) A ResubmissionI ccount
(Including transactions 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 billing 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.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Energy Charges (Other Charges)($) ($)(I) (m)Total Revenues ($)
(k+l+m)
(n)
ine
No.
18,733
2,617 1
70,962 2
13,509 3
-23,159 4
12,433 5
24,196 6
1,415 7
7,743,416 8
660,917 9
18,414 10
2,089,989 11
181,181 12
109,725 13
9,975 14
2,607,249 15
226,753 16
43,299 17
3,555 18
527,899 19
141,871 20
17,136 21
3,796 22
56,945 23
5,310 24
-160,122 25
26
27
28
29
30
31
32
33
34
58,905
4,106
12,433
7,085,533
1,991,594
2,057,249
27,323,230 8,990,099 31,498,786 67,812,115
FERC FORM NO.1 (ED. 12-90)Page 330.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/1.8/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 328 Line No.: 1 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I§chedule Page: 328 Line No.: 1 Column: d
Legacy Contrct executed between PacifiCorp and Arona Public Service Company concerning the exchange of transmission
services over agreed-upon facilities (Restated Transmission Agreement Between PacifiCorp and Arzona Public Serice Company
(ltRestated TSAlt), Rate Schedule 436). The contrct termates October 31, 2020. See also FERC Account 565 - Transmission of
Electrci b Others, a e 332 of this Form No. 1.
chedule Pa e: 328 Line No.: 1 Column: f
Glen Canyon/our Comers Substation.
!tchedule Page: 328 . Line No.: 2 Column: d
Network Transmission Servce under the Open Access Trasmission Tarff (1st Revised Serice Agreement 505) terminating no
earlier than l2-months from notice by the customer.
¡Schedule Page: 328 Line No.: 2 Column: m
Distrbution Voltage Service Charge. Primar Delivery Service. Regulation & Frequency Response.
!tchedule Page: 328 Line No.: 3 Column: d
Network Transmission Service under the Open Access Transmission Tarff (1st Revised Service Agreement 505) terminating no
earlier than l2-months from notice by the customer.
!tchedule Page: 328 Line No.: 3 Column: m
Distrbution Voltage Service Charge. Priar Delivery Service. Regulation & Frequency Response. Penalty revenues coverig
imbalance charges per Schedules 4 and 9. December 2009 Service.
!tchedule Page: 328 Line No.: 4 Column: d I
Network Transmission Service under the Open Access Trasmission Tarff (S.A. 505). Load service for this delivery point terminated
Februar 28,2010.¡Schedule Page: 328 Line No.: 5 Column: d I
Network Transmission Service under the Open Access Trasmission Tarff (S.A. 505). Load service for this delivery point termnated
February 28,2010.
!tchedule Page: 328 Line No.: 5 Column: m
December 2009 Service.
!tchedule Page: 328 Line No.: 6 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!tchedule Page: 328 Line No.: 6 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Trasmission Tarffbetween various partes and points.
!tchedule Page: 328 Line No.: 7 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
!tchedule Page: 328 Line No.: 7 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
¡Schedule Page: 328 Line No.: 7 Column: d
Non-Firm or Short-Term Fir Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
!tchedule Page: 328 Line No.: 8 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "BLACK HILLS/COLORAO ELECTRIC UTILITY COMPANY"
ON PAGES 328 - 330:
Complete name is Black Hils/Colorado Electric Utility Company, LP.
!tchedule Page: 328 Line No.: 8 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!tchedule Page: 328 Line No.: 8 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!tchedule Page: 328 Line No.: 8 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Tranmission Tarff between various paries and points.
!tchedule Page: 328 Line No.: 9 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
IFERC 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 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 328 Line No.: 9 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328 Line No.: 9 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.: 10 Column: b
PacifiCorp Energy, a business unit ofPacifiCorp responsible for electrc generation and commodity tradig activities.
¡Schedule Page: 328 Line No.: 10 Column: d
Network Transmission SerVce under the Open Access Transmission Tarff (first revised Service Agreement 347) termnatig onDecember 31,2017. .
¡Schedule Page: 328 Line No.: 11 Column: b
PacifiCorp Energy, a business unit ofPacifiCorp responsible for electrc generation and commodity trding activities.
¡Schedule Page: 328 Line No.: 11 Column: d
Network Transmission Service under the Open Access Trasmission Tariff (first revised Service Agreement 347) termating on
December 31,2017.
¡Schedule Page: 328 Line No.: 11 Column: m
December 2009 Service.
¡Schedule Page: 328 Line No.: 12. Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328 Line No.: 12 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328 Line No.: 12 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various parties and points.
I§chedule Page: 328 Line No.: 13 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328 Line No.: 13 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
I§chedule Page: 328 Line No.: 13 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween various paries and points.
I§chedule Page: 328 Line No.: 13 Column: m
December 2009 Service.
¡Schedule Page: 328 Line No.: 14 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328 Line No.: 14 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328 Line No.: 14 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between varous paries and points.
¡Schedule Page: 328 Line No.: 15 Column: b
PacifiCorp Energy, a business unit ofPacifiCorp responsible for electrc generation and commodity trading activities.
¡Schedule Page: 328 Line No.: 15 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (1st revised Service Agreement 67) terminating on
December 31,2033.
¡Schedule Page: 328 Line No.: 16 Column: b
PacifiCorp Energy, a business unit ofPacifiCorp responsible for electrc generation and commodity trading activities.
¡Schedule Page: 328 Line No.: 16 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (1st revised Service Agreement 67) termatig on
December 31,2033.
¡Schedule Page: 328 Line No.: 16 Column: m
December 2009 Service.
I§chedule Page: 328 Line No.: 17 Column: b
Capacity exchanged and operated by each transmission provider with no recei t or delivery of energy.
chedule Page: 328 Line No.: 17 Column: c
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 I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Capacity exchanged and 0 erated by each transmission provider with no receipt or delivery of energy.
chedule Page: 328 Line No.: 17 Column: d
Legacy Contract executed between PacifiCorp and Bonnevile Power Administrtion concernng the exchange of trnsmission
services over agreed-upon facilities ("Midpoint-Meridian Transmission Agreement", Rate Schedule 369). This agreement runs
concurently with the AC Intertie Agreement, (Rate Schedule 368), which terates when the facilities subject to that agreement are
taken out of service. See also FERC Account 565 - Trasmission of Electrcity by Others, page 332.
I§chedule Page: 328 Line No.: 18 Column: d I
Evergreen Legacy Contract (Rate Schedule 237) executed between PacifiCorp and Bonneville Power Admistration for transmission
service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
¡Schedule Page: 328 Line No.: 18 Column: m
Sole use/direct assigned facilities charge.
I§chedule Page: 328 Line No.: 19 Column: d I
Evergreen Legacy Contrct (Rate Schedule 237) executed between PacifiCorp and Bonnevile Power Administration for transmission
service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
I§chedule Page: 328 Line No.: 19 Column: m
Sole use/direct assigned facilities charge. December 2009 service.
I§chedule Page: 328 Line No.: 20 Column: d I
Point-to-Point Transmission Service under the Open Access Transmission Tarff (Serice Agreement 656) terminating on August 31,
2030.
¡Schedule Page: 328 Line No.: 20 Column: f
Lost Creek Hydro Plant.
I§chedule Page: 328 Line No.: 21 Column: d
Legacy Contract (Rate Schedule 324) executed between PacifiCorp and Bonnevile Power Admistrtion for transmission service
over agreed-upon facilities and/or subject to a sole-use or facilities charge. Contrct terinated September 4,2010.
I§chedule Page: 328 Line No.: 21 Column: f
Lost Creek Hydro Plant.
I§chedule Page: 328 Line No.: 21 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor
and/or ro ortonal use as definedin the contract.
chedule Pa e: 328 Line No.: 22 Column: d
Legacy Contract (Rate Schedule 324) executed between PacifiCorp and Bonnevile Power Admistration for transmission service
over agreed-upon facilities and/or subject to a sole-use or facilities charge. Contrct terminated September 4,2010.
I§chedule Page: 328 Line No.: 22 Column: f
Lost Creek Hydro Plant.
I§chedule Page: 328 Line No.: 22 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor
and/or proportional use as defined in the contrct. December 2009 Service.
I§chedule Page: 328 Line No.: 23 Column: d
Network Transmission Service and Distrbution Delivery Service under the Open Access Transmission Tarff (4th revised Service
Agreement 229) terminating on September 30, 2028.
I§chedule Page: 328 Line No.: 23 Column: m
Distrbution Voltage Service Charge. Primary Delivery Service. Regulation & Frequency Response.
I§chedule Page: 328 Line No.: 24 Column: d
Network Transmission Service and Distrbution Delivery Service under the Open Access Transmission Tarff (4th revised Service
A eement 229 terminatin on Se tember 30,2028.
chedule Pa e: 328 Line No.: 24 Column: m
Distrbution Voltage Service Charge. Priary Delivery Servce. Regulation & Frequency Response. December 2009 Service.
I§chedule Page: 328 Line No.: 25 Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "BENTON REA" ON PAGES 328 - 330:
Complete name is Benton Rural Electrc Association.
I§chedule Page: 328 Line No.: 25 Column: d
IFERC FORM NO.1 (ED. 12-87)Page 450.3
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Network Transmission and Distrbution Delivery Service under the Open Access Transmission Tariff (Service Agreement 539)
termnating on November 30, 2013.
~chedule Page: 328 Line No.: 25 Column: m
Regulation & Frequency Response. Penalty revenues coverig imbalance charges per Schedules 4 and 9.
~chedule Page: 328 Line No.: 26 Column: d
Network Transmission and Distrbution Delivery Serice under the Open Access Trasmission Tariff (Serice Agreement 539)
termnating on November 30, 2013.
¡Schedule Page: 328 Line No.: 26 Column: m
Regulation & Frequency Response. Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2009 Service.
¡Schedule Page: 328 Line No.: 27 Column: c
Umatila Electrc Coo erative Association and Columbia Basin Electrc Coo erative, Inc.
chedule Pa e: 328 Line No.: 27 Column: d
Network Transmission Service under the Open Access Trasmission Tariff (Servce Agreement 538) termating on December 31,
2013.
ISchedule Page: 328 Line No.: 27 Column: m
Regulation & Frequency Response.
~chedule Page: 328 Line No.: 28 Column: c
Umatila Electrc Cooperative Association and Columbia Basin Electrc Cooperative, Inc.
¡Schedule Page: 328 Line No.: 28 Column: d
Network Transmission Service under the Open Access Transmission Tarff (Service Agreement 538) termating on December 31,
2013.
~Chedule Page: 328 Line No.: 28 Column: m
December 2009 Setvice. .
~chedule Page: 328 Line No.: 29 Column: b
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "U.S. BURAU OF RECLAMATION" ON PAGES 328 - 330:
Complete name is United States Bureau of Reclamation. ~chedule Page: 328 Line No.: 29 Column: d I
Point-to-Point Transmission Service under the Open Access Transmission Tarff (first revised Service Agreement 179) terminating on
September 30, 2025.~chedule Page: 328 Line No.: 30 Column: d I
Point-to-Point Transmission Service under the Open Access Transmission Tarff (first revised Service Agreement 179) terminatig on
September 30,2025.
¡Schedule Page: 328 Line No.: 30 Column: m
December 2009 Service.
¡Schedule Page: 328 Line No.: 31 Column: d
Legacy Contract (Rate Schedule 368) executed between PacifiCorp and Bonnevile Power Administration for transmission service
over a eed-u on facilities and/or sub'ect to a sole-use or facilities char e. Sub'ect to termation u on mutual a eement.
chedule Pa e: 328 Line No.: 31 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor
and or ro ortonal use as defined in the contract.
chedule Pa e: 328 Line No.: 32 Column: d
Legacy Contrct (Rate Schedule 368) executed between PacifiCorp and Bonnevile Power Administration for transmission service
over agreed-upon facilities and/or subject to a sole-use or facilities charge. Subject to termation upon mutual agreement.
¡Schedule Page: 328 Line No.: 32 Column; m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor
and or proportional use as defined in the contract. December 2009 Service.
~chedule Page: 328 Line No.: 33 Column: d
Network Transmission Service and Distrbution Delivery Service under the Open Access Transmission Tarff (Service Agreement
328) terminating on September 30, 2011.
¡Schedule Page: 328 Line No.: 33 Column: m
Distrbution Voltage Service Charge. Primar Delivery Service. Regulation & Frequency Response. Penalty revenues coverig
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 1(2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
imbalance charges per Schedules 4 and 9.
¡Schedule Page: 328 Line No.: 34 Column: d
Network Transmission Serice and Distrbution Delivery Service under the Open Access Trasmission Tarff (Service Agreement
328) terminating on September 30, 2011.
¡Schedule Page: 328 Line No.: 34 Column: m
Distrbution Voltage Service Charge. Primar Delivery Service. Regulation & Frequency Response. Penalty revenues coverg
imbalance char es er Schedules 4 and 9. December 2009 Service.
chedule Page: 328.1 Line No.: 1 Column: d
Evergreen Legacy Contract (Rate Schedule 299) executed between PacifiCorp and Bonnevile Power Administration for trsmission
service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
¡Schedule Page: 328.1 Line No.: 1 Column: m
Sole use/direct assigned facilities charge. Charges for load following and opertig reseres.
¡Schedule Page: 328.1 Line No.: 2 Column: d I
Evergreen Legacy Contract (Rte Schedule 299) executed between PacifiCorp and Bonnevile Power Administration for transmission
service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
¡Schedule Page: 328.1 Line No.: 2 Column: m
Sole use/direct assigned facilities charge. Charges for load following and operatig reserves. December 2009 Service.
¡Schedule Page: 328.1 Line No.: 3 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 3 Column:c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 3 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between varous parties and points.
¡Schedule Page: 328.1 Line No.: 4 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
¡Schedule Page: 328.1 Line No.: 4 Column: c
Varous si atories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
chedule Pa e: 328.1 Line No.: 4 Column: d
Non~Firm or Short-Term Firm Transmission Service under the 0 en Access Transmission Tarffbetween various aries and points.
chedule Page: 328.1 Line No.: 5 Column: d
Network Transmission Servce under the Open Access Transmission Tarff (Servce Agreement 370) terminating on December 7,
2012 or with 6 months wrtten notice.
¡Schedule Page: 328.1 Line No.: 5 Column: g
ChelatchieNiew 115 KV.
¡Schedule Page: 328.1 Line No.: 5 Column: m
Regulation & Frequency Response. Penalty revenues coverig imbalance charges per Schedules 4 and 9.
'¡chedule Page: 328.1 Line No.: 6 Column: d
Network Transmission Service under the Open Access Trasmission Tarff (Service Agreement 370) terminating on December 7,
2012 or with 6 months written notice.
¡Schedule Page: 328.1 Line No.: 6 Column: g
ChelatchieNiew 115 KY.
¡Schedule Page: 328.1 Line No.: 6 Column: m
Regulation & Frequency Response. Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2009 Service.
~chedule Page: 328.1 Line No.: 7 Column: b
Various signatories to the 7th Revised Volume i i Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 7 Column: c
Various signatories to the 7th Revised Volume i i Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 7 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between varous pares and points.
¡Schedule Page: 328.1 Line No.: 8 Column: b
Various signatories to the 7th Revised Volume i i Point-to-Point Transmission Tarff.
IFERC FORM NO.1 (ED. 12-87) Page 450.5
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ¿ç An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
!ßchedule Page: 328.1 Line No.: 8 Column: c
V arious signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!ßchedule Page: 328.1 Line No.: 8 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
!ßchedule Page: 328.1 Line No.: 8 Column: m
December 2009 Service.
¡Schedule Page: 328.1 Line No.: 9 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 9 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328.1 Line No.: 9 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various paries and points.
¡Schedule Page: 328.1 Line No.: 10 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 10 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 10 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween varous partes and points.
¡Schedule Page: 328.1 Line No.: 11 Column: a . .
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "CONSTELLATION ENERGY COMMODITIES GROUP" ON
PAGES 328 - 330:
Complete name is Constellation Energy Commodities Group, Inc.
¡Schedule Page: 328.1 Line No.: 11 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 11 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 11 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various pares and points.
¡Schedule Page: 328.1 Line No.: 11 Column: m
Unauthorized Use of Transmission Service. Penalty revenues covering imbalance charges per Schedules 4 and 9.
¡Schedule Page: 328.1 Line No.: 12 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 12 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328.1 Line No.: 12 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween varous paries and points.
¡Schedule Page: 328.1 Line No.: 12 Column: m
Unauthorized Use of Transmission Service. Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2009
Service.
¡Schedule Page: 328.1 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "COWLITZ COUN PUD" ON PAGES 328 - 330:
Complete name is Public Utility Distrct No. 1 of Cowlitz County.
¡Schedule Page: 328.1 Line No.: 13 Column: d
Legacy Contract (Rate Schedule 234) providing for transmission and operation of Swift Hydroelectrc Plant No.2, and for
transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Agreement may be termnated
subsequent to the termnation of the Power Contract as defined in the agreement by the customer providing at least six months wrtten
notice and specifying the date on which the customer wil assume responsibility of operations and maintenance of Swift Hydroelectrc
Plant No. 2.
¡Schedule Page: 328.1 Line No.: 13 Column: m
Charge for transmission service over agreed-upon facilities and/or subject toa sole-use or facilities charge based on a capacity factor
and/or proportonal use as defmed in the contract.
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 I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
~chedule Page: 328.1 Line No.: 14 Column: d
Legacy Contrct (Rate Schedule 234) providig for trmission and operation of Swift Hydroelectrc Plant No.2, and for
transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Agreement may be termnated
subsequent to the termnation of the Power Contrct as defied in the agreement by the customer providig at least six months wrtten
notice and specifying the date on which the customer wil assume responsibility of operations and maintenance of Swift Hydroelectrc
Plant No. 2.
!Schedule Page: 328.1 Line No.: 14 Column:m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilties charge based on a capacity factor
and/or proportonal use as derined in the contract. December 2009 Service.
¡Schedule Page: 328.1 Line No.: 15 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "DESERET GENERATION & TRAS." ON PAGES 328 - 330:
Complete name is Deseret Generation and Transmission Cooperative.
!schedule Page: 328.1 Line No.: 15 Column: d
Legacy Contract executed between PacifiCorp and Deseret Generation and Trasmission Cooperative for transmission service over
agreed-upon facilities (Second Amended and Restated Trasmission Serice and Operating Agreement, Rate Schedule 280).
Agreement subject to termination upon mutual agreement.
¡Schedule Page: 328.1 Line No.: 15 Column: m
Scheduling and loadfollowing charges. Distrbution Voltage Service Charge.
¡Schedule Page: 328.1 Line No.: 16 Column: d
Legacy Contract executed between PacifiCorp and Deseret Generation and Transmission Cooperative for transmission service over
agreed-upon facilities (Second Amended and Restated Transmission Service and Operating Agreement, Rate Schedule 280).
Agreement subject to termination upon mutual agreement.
!schedule Page: 328.1 Line No.: 16 Column: m
Scheduling and load following charges. Distrbution Voltage Servce Charge. December 2009 Service.
!schedule Page: 328.1 Line No.: 17 Column: d
Control Area Servces Agreement(Rate Schedule 590) for charges associated with providing control area support and ancilary
services. Agreement terminating July 2011.
¡Schedule Page: 328.1 Line No.: 17 Column: m
Regulation & Frequency Response. Spinning and/or supplemental reserve services. Meter interrogation charge.
¡Schedule Page: 328.1 Line No.: 18 Column: d
Control Area Services Agreement (Rate Schedule 590) for charges associated with providing control area support and ancilar
services. A eement termnatin Jul 2011.
chedule Pa e: 328.1 Line No.: 18 Column: m
Regulation & Frequency Response. Spinning and/or supplemental reserve services. Meter interrogation charge. December 2009
Service.
¡Schedule Page: 328.1 Line No.: 19 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!schedule Page: 328.1 Line No.: 19 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous pares and points.
!schedule Page: 328.1 Line No.: 20 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
¡Schedule Page: 328.1 Line No.: 20 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.1 Line No.: 20 Column: d
Non-Firm or Short-Term Fir Transmission Service under the Open Access Transmission Tariffbetween varous pares and points.
¡Schedule Page: 328.1 Line No.: 21 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
!schedule Page: 328.1 Line No.: 21 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!schedule Page: 328.1 Line No.: 21 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between varous paries and points.
IFERC FORM NO.1 (ED. 12-87)Page 450.7
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010104
FOOTNOTE DATA
I§chedule Page: 328.1 Line No.: 21 Column: m
December 2009 Service.
I§chedule Page: 328.1 Line No.: 22 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I§chedule Page: 328.1 Line No.: 22 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tarff, (Service Agreement 426) deferred until June 1,
2011. Termnatig April 30, 2043.
I§chedule Page: 328.1 Line No.: 22 Column: m
Extension of commencement date fee.
I§chedule Page: 328.1 Line No.: 23 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I§chedule Page: 328.1 Line No.: 23 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I§chedule Page: 328.1 Line No.: 23 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous paries and
chedule Pa e: 328.1 Line No.: 24 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I§chedule Page: 328.1 Line No.: 24 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
!ßchedule Page: 328.1 Line No.: 24 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between varous parties and points.
¡Schedule Page: 328.1 Line No.: 24 Column: m
December 2009 Service.¡Schedule Page: 328.1 Line No.: 25 Column: d I
Legacy Contract (Rate Schedule 322) executed between PacifiCorp and Fall River Rural Electrc Cooperative for transmission servce
over agreed-upon facilities and/or subject to a sole-use or facilities charge. Termnates July 31,2027.
!ßchedule Page: 328.1 Line No.: 25 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor
and or TO ortonal use as defined in the contract.
chedule Pa e: 328.1 Line No.: 26 Column: d
Legacy Contract (Rate Schedule 322) executed between PacifiCorp and Fall River Rural Electrc Cooperative for transmission service
over agreed-upon facilities and/or subject to a sole-use or facilities charge. Termnates July 31, 2027.
!ßchedule Page: 328.1 Line No.: 26 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor
and or proportional use as dermed in the contract. December 2009 Servce.
¡Schedule Page: 328.1 Line No.: 27 Column: c
PacifiCorp Energy, a business unit ofPacifiCorp responsible for electrc generation and commodity trding activities.
fSchedule Page: 328.1 Line No.: 27 . Column: d
Service Agreement 130 executed between PacifiCorp and Foote Creek II, LLC (Seawest) for trnsmission servce over agreed-upon
facilities and/or subject to a sole-use or facilities charge. Termnating July 2014.
!ßchedule Page: 328.1 Line No.: 27 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
!ßchedule Page: 328.1 Line No.: 28 Column: c
PacifiCorp Energy, a business unit ofPacifiCorp responsible for electrc generation and commodity trading activities.
!ßchedule Page: 328.1 Line No.: 28 Column: d
Service Agreement 130 executed between PacifiCorp and Foote Creek II, LLC (Seawest) for trsmission service over agreed-upon
facilities and/or sub 'ect to asole-use or facilities charge. Termating July 2014.
chedule Pa e: 328.1 Line No.: 28 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. December 2009 Serice.
!ßchedule Page: 328.1 Line No.: 29 Column: b .
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
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 I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
'$chedule Page: 328.1 Line No.: 29 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
'$chedule Page: 328.1 Line No.: 29 Column: d
Non-Firm or Short-Term Firm Transmission Service under the en Access Transmission Tarff between varous paries and points.
chedule Page: 328.1 Line No.: 30 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
'$chedule Page: 328.1 Line No.: 30 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
'$chedule Page: 328.1 Line No.: 30 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Op Access Transmission Tarffbetween various paries and points.
'$chedule Page: 328.1 Line No.: 31 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
'$chedule Page: 328.1 Line No.: 31 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
'$chedule Page: 328.1 Line No.: 31 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between varous paries and points.
¡Schedule Page: 328.1 Line No.: 31 Column: m
December 2009 Service.
'$chedule Page: 328.1 Line No.: 32 Column: d I
Ancilar Services under the Open Access Transmission Tarff (Servce Agreement 475) in effect until superseded. Contract assigned
to JP Morgan Ventues Energy Corporation.'$chedule Page: 328.1. Line No.: 32 Column: m I
Charges for spinning and/or supplemental reserves. Unauthoried Use of Trasmission Service. Penalty revenues coverig imbalance
charges per Schedules 4 and 9.¡Schedule Page: 328.1 Line No.: 33 Column: d I
Ancilar Services under the Open Access Transmission Tarff (Service Agreement 475) in effect until superseded. Contract assigned
to JP Morgan Ventues Energy Corporation.
'$chedule Page: 328.1 Line No.: 33 Column: m
Charges for spining and/or supplemental reserves. Penalty revenues coverig imbalance charges per Schedules 4 and 9. December
2009 Service.
'$chedule Page: 328.1 Line No.: 34 Column: c
Iberdrola Renewables Inc. and Utah Associated Municipal Power Systems.
'$chedule Page: 328.1 Line No.:.34 Column: d
Ancilar Services under the Open Access Transmission Tariff (Service A eement 315) in effect until superseded.
chedule Pa e: 328.1 Line No.: 34 Column: f
Long Hollow, Wyoming Switching Station.
¡Schedule Page: 328.1 Line No.: 34 Column: g
Long Hollow, Wyoming Switching Station.¡Schedule Page: 328.1 Line No.: 34 Column: m I
Charges for spining and/or supplemental reserves. Unauthorized Use of Transmission Service. Penalty revenues covering imbalance
charges per Schedules 4 and 9.
'$chedule Page: 328.2 Line No.: 1 Column: c
Iberdrola Renewables Inc. and Utah Associated Municipal Power Systems.
'$chedule Page: 328.2 Line No.: 1 Column: d
Ancilary Services under the Open Access Transmission Tarff (Service Agreement 315) in effect until supereded.
'$chedule Page: 328.2 Line No.: 1 Column: f
Long Hollow, Wyoming Switching Station.
¡Schedule Page: 328.2 Line No.: 1 Column: g
Long Hollow, Wyoming Switching Station.'$chedule Page: 328.2 Line No.: 1 Column: m I
Charges for spinning and/or supplemental reserves. Unauthorized Use of Transmission Service. Penalty revenues coverig imbalance
I FERC FORM NO.1 (ED. 12-87) Page 450.9 I
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
charges per Schedules 4 and 9. December 2009 Service.
I§chedule Page: 328.2 Line No.: 2 Column: d
PoinHo-Point Transmission Service under the Open Access Transmission Tariff (5th revised Service Agreement 279). Terminates
April 30, 2014.
I§chedule Page: 328.2 Line No.: 3 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tarff (5th revised Service Agreement 279). Terminates
April 30, 2014.
I§chedule Page: 328.2 Line No.: 3 Column: m
December 2009 Service.
!schedule Page: 328.2 Line No.: 4 Column: d
Legacy Contract (Rate Schedule 427) executed between PacifiCorp and Idaho Power Company concerning the exchange of
transmission servces over agreed-upon facilities (Draft Transmission Services Agreement between PacifiCorp and Idao Power
Company, Draft 1 - 5/19/95 ("Goshen Agreement")). Termination of this agreement occurs at the end of the calendar month
following the earlier of the effectiveness of a replacement contract, or upon three years wrtten notice of termnation as long as
PacifiCorp has facilities in place to serve PacifiCorp's Big Grassy load. See also FERC Account 565 - Transmission of Electrcity byOthers, page 332. '
!schedule Page: 328.2 Line No.: 5 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tarff (5th revised Service Agreement 212) terminating
May 31, 2014.
!schedule Page: 328.2 Line No.: 6 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!schedule Page: 328.2 Line No.: 6 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!schedule Page: 328.2 Line No.: 6 Column: d
Non-Fir or Short-Term Fir Transmission Service under the Open Access Transmission Tarffbetween varous pares and points.
!schedule Page: 328.2 Line No.: 7 Column: b ..
Various signatories to the 7th Revised Volume 11 Point-to~Point Transmission Tariff.
!schedule Page: 328.2 Line No.: 7 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
!schedule Page: 328.2 Line No.: 7 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.: 8 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
I$chedule Page: 328.2 Line No.: 8 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
!schedule Page: 328.2 Line No.: 8 Column: d
Legacy Contract (Rate Schedule 257) executed between PacifiCorp and Idaho Power Company for transmission service over
agreed-upon facilities and/or subject to a sole-use or facilities charge for the Antelope Substation terminating coterminous with the
Idaho/USDOE Supply Agreement.
¡Schedule Page: 328.2 Line No.: 8 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
¡Schedule Page: 328.2 . Line No.: 9 Column: b
Operation, maintenace or facility lease services with no receipt or delivery of energy.
¡Schedule Page: 328.2 Line No.: 9 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
¡Schedule Page: 328.2 Line No.: 9 Column: d
Legacy Contract (Rate Schedule 257) executed between PacifiCorp and Idaho Power Company for transmission service over
agreed-upon facilities and/or subject to a sole-use or facilities charge for the Antelope Substation terminatig coterminous with the
Idaho/USDOE Supply Agreement.
I$chedule Page: 328.2 Line No.: 9 c. Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. December 2009 Service.
IFERC FORM NO.1 (ED. 12-87)Page 450.10
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp /2) . A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 328.2 Line No.: 10 Column: b
Operation, maintenance or facility lease servces with no receipt or delivery of energy.
I$chedule Page: 328.2 Line No.: 10 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
I$chedule Page: 328.2 Line No.: 10 Column: d
Legacy Contract (Rate Schedule 203) executed between PacifiCorp and Idaho Power Company for transmission service over
agreed-upon facilities and/or subjectto a sole-use or facilities charge for the Jim Bridger Pump. Ternation upon l2-months wrtten
notice.
I$chedule Page: 328.2 Line No.: 10 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
¡Schedule Page: 328.2 Line No.: 11 Column: b
Operation, maintenance or facility lease services with no receipt or deliver of energy.
I$chedule Page: 328.2 Line No.: 11 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
¡Schedule Page: 328.2 Line No.: 11 Column: d
Legacy Contract (Rate Schedule 203) executed between PacifiCorp and Idaho Power Company for trsmission service over
agreed-upon facilities and/or subject to a sole-use or facilities charge for the Jim Bridger Pump. Termination upon l2-months wrtten
notice.
I$chedule Page: 328.2 Line No.: 11 Column: m
Charge for transmission service over a eed-upon facilities and/or subject to a sole-use or facilities charge. December 2009 Serice.
chedule Pa e: 328.2 Line No.: 12 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "JP MORGAN VENTUS ENERGY CORP." ON PAGES 328-
330: Complete name is JP Morgan Ventures Energy Corporation.
I$chedule Page: 328.2 Line No.: 12 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
I$chedule Page: 328.2 Line No.: 12 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
I$chedule Page: 328.2 Line No.: 12 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various paries and points.
I$chedule Page: 328.2 Line No.: 13 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I$chedule Page: 328.2 Line No.: 13 Column: d
Assignent of Ancilar Services under the Open Access Transmission Tarff (Service Agreement 475) from Iberdrola Renewables,
Inc. Terminated December 20, 2010.I$chedule Page: 328.2 Line No.: 13 Column: m I
Charges for spining and/or supplemental reserves. Unauthoried Use of Trasmission Service. Penalty revenues coverig imbalance
charges per Schedules 4 and 9.
¡Schedule Page: 328.2 Line No.: 14 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I$chedule Page: 328.2 Line No.: 14 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I$chedule Page: 328.2 Line No.: 14 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween various paries and points.
I$chedule Page: 328.2 Line No.: 14 Column: m
December 2009 Service.
¡Schedule Page: 328.2 Line No.: 15 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "LOS ANGELES DEPT OF WATER & POWER" ON PAGES 328 -
330:
Complete name is Los Angeles Departent of Water and Power.
I$chedule Page: 328.2 Line No.: 15 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
IFERC FORM NO.1 (ED. 12-87)Page 450.11
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) . A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 328.2 Line No.: 15 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 15 Column: d
Non-Firm or Short~Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
'ichedule Page: 328.2 Line No.: 16 Column: b
Various signatories to the 7th Revised Volume 11 Point-to..Point Transmission Tarff.
'ichedule Page: 328.2 Line No.: 16 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 16 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
¡Schedule Page: 328.2 Line No.: 17 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
'ichedule Page: 328.2 Line No.: 17 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
'ichedule Page: 328.2 Line No.: 17 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous partes and points.
'ichedule Page: 328.2 Line No.: 17 Column: m
December 2009 Service.
'ichedule Page: 328.2 Line No.: 18 Column: d
Legacy Contract (Rate Schedule 302) executed between PacifiCorp and Moon Lake Electrc Association for transmission and
interconnection service over agreed-upon facilities and/or subjectto a sole~use or facilities charge. Either par may terminate the
a eement at an time after October 14,2011, b rovidin two ears' wrtten notice.
Schedule Pa e: 328.2 Line No.: 18 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor
and/or proportonal use as defined in the contract.
¡Schedule Page: 328.2 Line No.: 19 Column: d
Legacy Contract (Rate Schedule 302) executed between PacifiCorp and Moon Lake Electrc Association for transmission and
interconnection service over agreed-upon facilities and/Qr subject to a sole-use or facilities charge. Either par may terminate the
agreement at any time after October 14,2011, by providing two years' wrtten notice.
'ichedule Page: 328.2 Line No.: 19 Column: m .
Charge for transmission servce over agreed-upon facilities and/or subject to a sole-use or facilties charge based on a capacity factor
and/or proportional use as defined in the contract. December 2009 Service.
¡Schedule Page: 328.2 Line No.: 20 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328.2 Line No.: 20 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
'ichedule Page: 328.2 Line No.: 20 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various pares and points.
'ichedule Page: 328.2 Line No.: 21 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
'ichedule Page: 328.2 Line No.: 21 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328.2 Line No.: 21 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
¡Schedule Page: 328.2 Line No.: 21 Column: m
December 2009 Service.
¡Schedule Page: 328.2 Line No.: 22 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 22 Column: c
Various signtories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 22 Column: d
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)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Non-Firm or Short-Term Fir Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
~chedule Page: 328.2 Line No.: 23 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
~chedule Page: 328.2 Line No.: 23 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
~chedule Page: 328.2 Line No.: 23 Column: d
Non-Fir or Short-Term Firn Transmission Service under the Open Access Trasmission Tarffbetween varous pares and points.
~chedule Page: 328.2 Line No.: 24 Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "GRA COUN PUD" ON PAGES 328 - 330:
Complete name is Grant County Public Utility Distrct.
~chedule Page: 328.2 Line No.: 24 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (Service Agreement 626), assignent from Seattle
City & Light, terminating December 31, 2011.~chedule Page: 328.2 Line No.: 24 Column: m I
Charges for spinning and/or supplemental reserves. Unauthorized Use of Trasmission Service. Penalty revenues coverig imbalance
charges per Schedules 4 and 9.
~chedule Page: 328.2 Line No.: 25 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tarff (Serice Agreement 626), assignent from Seattle
City & Light, terminating December 31, 2011.~chedule Page: 328.2 Line No.: 25 Column: m I
Charges for spinning and/or supplemental reserves. Unauthoried Use of Trasmission Service. Penalty revenues covering imbalance
charges per Schedules 4 and 9. December 2009 Service.
~chedule Page: 328.2 Line No.: 26 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
~chedule Page: 328.2 Line No.: 26 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
~chedule Page: 328.2 Line No.: 26 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween various paries and points.
~chedule Page: 328.2 Line No.: 27 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
~chedule Page: 328.2 Line No.: 27 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
~chedule Page: 328.2 Line No.: 27 Column: d
Legacy Contract (Rate Schedule 607) executed between PacifiCorp and Pacific Gas & Electrc Company for transmission service
over agreed-upon facilities (Malin to Round Mountain) and/or subject to a sole-use or facilities charge. Terminating December 31,
2017. See PacifiCorp, Docket No. ER07-882, et aI, Settlement Agreement, Appendix 2 (fied November 20,2007).
~chedule Page: 328.2 Line No.: 27 Column: f
Malin - Indian Sprigs line segmeni.
~chedule Page: 328.2 Line No.: 27 Column: g
Malin - Indian Sprigs line segment.
~chedule Page: 328.2 Line No.: 27 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
~chedule Page: 328.2 Line No.: 28 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
¡Schedule Page: 328.2 Line No.: 28 Column: c
Operation, maintenance or facility lease servces with no receipt or delivery of ener .
chedule Page: 328.2 Line No.: 28 Column: d
Legacy Contract (Rate Schedule 298) executed between PacifiCorp and Pacific Gas & Electrc Company for transmission service
over agreed-upon facilities and/or subject to a sole-use or facilities charge (phase shiftg transformers at Sigud-Glen Canyon 230kv
transmission line and Pinto-Four Comers 345kv transmission line). Terminating Februry 12,2020.
~chedule Page: 328.2 Line No.: 28 Column: m
IFERC FORM NO.1 (ED. 12-S7) Page 450.13
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifCorp . I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
¡Schedule Page: 328.2 Line No.: 29 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.2 Line No.: 29 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
Itchedule Page: 328.2 Line No.: 29 Column:d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween various paries and points.
Itchedule Page: 328.2 Line No.: 30 Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "CAISO" ON PAGES 328 - 330:
Complete name is California Independent System Operator Corporation.
Itchedule Page: 328.2 Line No.: 30 Column: d I
Point-to-Point Transmission Service under the Open Access Transmission Tariff (4th revised Service Agreement 169) terminatig on
September 30, 2012.
Itchedule Page: 328.2 Line No.: 31 Column: d I
Point-to-Point Transmission Service under the Open Access Transmission Tarff (4th revised Service Agreement 169) termatig on
September 30, 2012.
Itchedule Page: 328.2 Line No.: 31 Column: m
December 2009 Service.
Itchedule Page: 328.2 Line No.: 32 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
Itchedule Page: 328.2 Line No.: 32 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Itchedule Page: 328.2 Line No.: 32 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
Itchedule Page: 328.2 Line No.: 32 Column: m
Charges for spinning and/or supplemental reserves. Penalty revenues coverig imbalance charges per Schedules 4 and 9.
Itchedule Page: 328.2 Line No.: 33 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
Itchedule Page: 328.2 Line No.: 33 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
Itchedule Page: 328.2 Line No.: 33 Column: d
Non-Firm or Short-Ter Firm Transmission Service under the Open Access Transmission Tarffbetween various parties and points.
Itchedule Page: 328.2 Line No.: 33 Column: m
December 2009 Service.
Itchedule Page: 328.2 Line No.: 34 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
Itchedule Page: 328.2 Line No.: 34 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
Itchedule Page: 328.2 Line No.: 34 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween varous paries and points.
¡Schedule Page: 328.3 Line No.: 1 . Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328.3 Line No.: 1 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328.3 Line No.: 1 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
¡Schedule Page: 328.3 Line No.: 2 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
Itchedule Page: 328.3 Line No.: 2 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
Itchedule Page: 328.3 Line No.: 2 Column: d
IFERC FORM NO.1 (ED. 12-S7) Page 450.14
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) AResubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous parties and points.
¡Schedule Page: 328.3 Line No.: 2 Column: m
December 2009 Service.
¡Schedule Page: 328.3 Line No.: 3 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 3 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
¡Schedule Page: 328..3 Line No.: 3 Column: d
Non-Firm or Short-Term Fir Transmission Service under the Open Access Transmission Tarffbetween varous pares and points.
¡Schedule Page: 328.3 Line No.: 4 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PUBLIC SVC. CO. OF CO" ON PAGES 328 - 330:
Complete name is Public Service Company of Colorado.
¡Schedule Page: 328.3 Line No.: 4 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 4 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tranmission Tarff.
¡Schedule Page: 328.3 Line No.: 4 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between various paries and points.
¡Schedule Page: 328.3 Line No.: 5 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
¡Schedule Page: 328.3 Line No.: 5 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 5 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various parties and points.
¡Schedule Page: 328.3 Line No.: 5 Column: m
December 2009 Service.
¡Schedule Page: 328.3 Line No.: 6 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 6 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 6 Column: d
Non-Firm or Short-Term Fir Transmission Service under the Open Access Transmission Tarffbetween varous parties and points.
!ßchedule Page: 328.3 Line No.: 7 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 7 Column: c
Various signtories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
¡Schedule Page: 328.3 Line No.: 7 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
¡Schedule Page: 328.3 Line No.: 8 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 8 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Trasmission Tariff.
I$chedule Page: 328.3 Line No.: 8 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
¡Schedule Page: 328.3 Line No.: 8 Column: m
December 2009 Service.
¡Schedule Page: 328.3 . Line No.: 9 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 9 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 9 Column: d
IFERC FORM NO.1 (ED. 12-87) Page 450.15
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 04/18/2011 2010/Q4
FOOTNOTE DATA
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between various pares and points.
¡Schedule Page: 328.3 Line No.: 10 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tarff (fist revised Service Agreement 568) terminatig
April 30, 2029.
¡Schedule Page: 328.3 Line No.: 10 Column: m
Charges for spinning and/or supplemental reserves. Penalty revenues covering imbalance charges per Schedules 4 and 9.
¡Schedule Page: 328.3 Line No.: 11 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (first revised Service Agreement 568) terminatig
April 30, 2029.
¡Schedule Page: 328.3 Line No.: 11 Column: m
Charges for spining and/or supplemental reserves. Penalty revenues coverig imbalance charges per Schedules 4 and 9. December
2009 Service.
¡Schedule Page: 328.3 Line No.: 12 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328.3 Line No.: 12 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328.3 Line No.: 12 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between varous paries and points.
¡Schedule Page: 328.3 Line No.: 13 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tarff (7th revised Service Agreement 289), terminating
October 31,2014.
¡Schedule Page: 328.3 Line No.: 13 Column: m
Char es for s inin and/or su lemental reserves. Penal revenues coveri imbalance char es er Schedules 4 and 9.
chedule Pa e: 328.3 Line No.: 14 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (7th revised Service Agreement 289), terminating
October 31,2014.
¡Schedule Page: 328.3 Line No.: 14 Column: m
December 2009 Service.
¡Schedule Page: 328.3 Line No.: 15 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 15 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328.3 Line No.: 15 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various paries and points.
¡Schedule Page: 328.3 Line No.: 16 Column: d
Transmission Service under the Open Access Transmission Tarff (Service Agreement 299). Service provided pursuant to rules and
regulations of Oregon Direct Access. Termnation upon notification pursuant to Oregon Direct Access and Open Access Transmission
Tarff.
¡Schedule Page: 328.3 Line No.: 16 Column: m
Regulation & Frequency Response. Penalty revenues coverig imbalance charges per Schedules 4 and 9.
¡Schedule Page: 328.3 Line No.: 17 Column: d
Trasmission Service under the Open Access Transmission Tarff (Service Agreement 299). Service provided pursuant to rules and
regulations of Oregon Direct Access. Termnation upon notification pursuant to Oregon Direct Access and Open Access Transmission
Tarff.
¡Schedule Page: 328.3 Line No.: 17 Column: m
Regulation & Frequency Response. Penalty revenues coverig imbalance charges per Schedules 4 and 9. December 2009 Service.
¡Schedule 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.
¡Schedule Page: 328.3 Line No.: 18 Column: d
IFERC FORM NO.1 (ED. 12-87) Page 450.16
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/1812011 2010/Q4
FOOTNOTE DATA
Non-Firm or Short-Term Firm Transmission Serice under the Open Access Trasmission Tarffbetween varous paries and points.
I$chedule Page: 328.3 Line No.: 19 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
I$chedule Page: 328.3 Line No.: 19 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I$chedule Page: 328.3 Line No.: 19 Column: d
Non-Fir or Short-Term Firm Trasmission Service under the Open Access Transmission Tarffbetween varous paries and points.
~chedule Page: 328.3 Line No.: 19. Column: m
December 2009 Service.
I$chedule Page: 328.3 Line No.: 20 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
I$chedule Page: 328.3 Line No.: 20 Column: c
Operation, maintenance or facility lease servces with no receipt or delivery of energy.
I$chedule Page: 328.3 Line No.: 20 Column: d
Legacy Contract (Rate Schedule 647) executed between PacifiCorp and Sierr Pacific Power Company for transmission service over
agreed-upon facilities and/or subject to a sole-use or facilities charge. Terinatig fort-five years from the date the second
interconnection is placed in service and shall contiue in effect beyond such tie unless terminated by either par though wrtten
notice given to the other par not later than four years in advance of the desired termination date.
I$chedule Page: 328.3 Line No.: 20 Column: g
Utah-Nevada Border
I$chedule Page: 328.3 Line No.: 20 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge.
I$chedule Page: 328.3 Line No.: 21 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
¡Schedule Page: 328.3 Line No.: 21 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I$chedule Page: 328.3 Line No.: 21 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various partes and points.
I$chedule Page: 328.3 Line No.: 22 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
I$chedule Page: 328.3 Line No.: 22 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 22 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween varous paries and points.
I$chedule Page: 328.3 Line No.: 22 . Column: m
December 2009 Service.
I$chedule Page: 328.3 Line No.: 23 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I$chedule Page: 328.3 Line No.: 23 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
I$chedule Page: 328.3 Line No.: 23 Column: d
Non-Firm or Short-Term Firm Transmission Serice under the Open Access Transmission Tarffbetween varous parties and points.
I$chedule Page: 328.3 Line No.: 23 Column: m . .
December 2009 Service.
¡Schedule Page: 328.3 Line No.: 24 Column: b
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 24 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 24 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween various paries and points.
I$chedule Page: 328.3 Line No.: 24 Column: m
IFERC FORM NO.1 (ED. 12-S7) Page 450.17
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Char es for s inin and/or su lemental reserves.
chedule Pa e: 328.3 Line No.: 25 Column: b
V arous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
. ¡Schedule Page: 328.3 Line No.: 25 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 25 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various paries and points.
¡Schedule Page: 328.3 Line No.: 25 Column: m
Unauthorized use of transmission service. Penalty revenues coverig imbalance charges per Schedules 4 and 9.
¡Scheduie Page: 328.3 Line No.: 26 Column: b
Operation, maintenance or facility lease servces with no receipt or delivery of energy.
¡Schedule Page: 328.3 Line No.: 26 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
¡Schedule Page: 328.3 Line No.: 26 Column: d
Use of Facilities Agreement ~ Phase Shiftng Transformers At Sigurd-Glen Canyon 230kv transmission line and Pinto-Four Corners
345kv transmission line (Rate Schedule 298), terminating Februar 12,2020.
¡Schedule Page: 328.3 Line No.: 26 Column: m
Char e for transmission service over aeed-u on facilities and/or sub'ect to a sole-use or facilities char e.
Schedule Pa e: 328.3 Line No.: 27 Column: d
Point-to-Point Trasmission Service under the Open Access Transmission Tariff (Service Agreement 170) terminating on May 31,
2014.
¡Schedule Page: 328.3 Line No.: 28 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tarff (Service Agreement 170) terminatig on May 31,
2014.
¡Schedule Page: 328.3 Line No.: 28 Column: m
December 2009 Service.
¡Schedule Page: 328.3 Line No.: 29 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 29 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 29 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between various paries and points.
¡Schedule Page: 328.3 Line No.: 30 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 30 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 30 Column: d
Non-Firm or Short-Term Firm Trasmission Service under the Open Access Transmission Tariffbetween various parties and points.
¡Schedule Page: 328.3 Line No.: 30 Column: m
December 2009 Service.
¡Schedule Page: 328.3 Line No.: 31 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 31 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 31 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various parties and points.
¡Schedule Page: 328.3 Line No.: 32 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
¡Schedule Page: 328.3 Line No;: 32 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.3 Line No.: 32 Column: d
IFERC FORM NO.1 (ED. 12-87) Page 450.18
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Non-Firm or Short-Term Fir Transmission Service under the Open Access Transmission Tanffbetween varous pares and points.
I§chedule Page: 328.3 Line No.: 32 Column: m
December 2009 Service.
¡Schedule Page: 328.3 Line No.: 33 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "TR-STATE GENERATION & TRNS." ON PAGES 328 - 330:
Complete name is Tn-State Generation and Transmission Association, Inc.
I§chedule Page: 328.3 Line No.: 33 Column: b
Varous signatones to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
I§chedule Page: 328.3 Line No.: 33 Column: d
Legacy Contract (Rate Schedule 123) executed between PacifiCorp and Tn-State Generation and Trasmission Association, Inc. for
transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Termnating October 1, 2014.
I$chedule Page: 328.3 Line No.: 34 Column: b
Various signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I§chedule Page: 328.3 Line No.: 34 Column: d
Legacy Contract (Rate Schedule 123) executed between PacifiCorp and Tn-State Genertion and Transmission Association, Inc. for
trsmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge. Termating October 1,2014.
I$chedule Page: 328.3 Line No.: 34 Column: m
December 2009 Service.
I§chedule Page: 328.4 Line No.: 1 Column: b
Varous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I$chedule Page: 328.4 Line No.: 1 Column: c
Vanous signatones to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
¡Schedule Page: 328.4 Line No.: 1 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access TransmissionTarffbetween varous parties and points.
¡Schedule Page: 328.4 Line No.: 2 Column: b
Varous signatones to the 7th Revised Volume 11 Point-to-Point Transmission Tanff.
!tchedule Page: 328.4 Line No.: 2 Column: d
Network Transmission Service under the Open Access Transmission Tarff (second revised Service Agreement 628) termating on
June 30, 2021.
¡Schedule Page: 328.4 Line No.: 2 Column: m
Regulation & Frequency Response. Penalty revenues covenng imbalance charges per Schedules 4 and 9.
¡Schedule Page: 328.4 Line No.: 3 Column: d
Network Transmission Service and Distrbution Delivery Service under the Open Access Transmission Tanff (Service Agreement
506) terminating upon wntten notification.
¡Schedule Page: 328.4 Line No.: 3 Column: m
Distrbution Voltage Service Charge. Pnmar Delivery Service. Regulation & Frequency Response.
I§chedule Page: 328.4 Line No.: 4 Column: d
Network Transmission Service and Distribution Delivery Service under the Open Access Transmission Tarff (Service Agreement
506) terminating upon wntten notification.
I§chedule Page: 328.4 Line No.: 4 Column: m
Distrbution Voltage Service Charge. Pnmar Delivery Service. Pnar delivery and distrbution adjustments for 2008 and 2009.
December 2009 Service.
I§chedule Page: 328.4 Line No.: 5 Column: d
Legacy Contract (Rate Schedule 67) executed between PacifiCorp and the United States Bureau ofRec1amation Crooked River
Irrigation Distrct for transmission service over agreed-upon facilties and/or subject to a sole-use or facilities charge. Termating
with one year wntten notice.
I§chedule Page: 328.4 Line No.: 6 Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "WEBER BASIN WATER CONSERV." ON PAGES 328 - 330:
Complete name is Weber Basin Water Conservancy Distrct.
I§chedule Page: 328.4 Line No.: 6 Column: d I
Legacy Contract (Rate Schedule 286) executed between PacifiCorp and the United States Bureau of Rec1amation Weber Basin Water
IFERC FORM NO.1 (ED. 12-87) Page 450.19
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010104
.FOOTNOTE DATA
Conservancy Distrct for trnsmission servce over agreed-upon facilities and/or subject to a sole-use or facilities charge for energy
deliveries at or below 138kv. Termnating any time after April!, 2040 with four years wrtten notice.
I§chedule Page: 328.4 Line No.: 6 Column: m
Energy consumption charge for deliveries at and below 138kv.
ISchedule Page: 328.4 Line No.: 7 Column: d I
Legacy Contract (Rate Schedule 286) executed between PacifiCorp and the United States Bureau of Reclamation Weber Basin Water
Conservancy Distrct for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge for energy
deliveries at or below 138kv. Termnating any time after April 1, 2040 with four years wrtten notice.
I§chedule Page: 328.4 Line No.: 7 Column: m
Energy consumption charge for deliveries at and below 138kv. December 2009 Service.
I§chedule Page: 328.4 Line No.: 8 Column: b
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "UTAH ASSOCIATED MUICIPAL POWER" ON PAGES 328-
330:
Complete name is Utah Associated Municipal Power Systems.
ISchedule Page: 328.4 Line No.: 8 Column: d
Legacy Contrct executed between PacifiCorp and Uta Associated Municipal Power Systems for transmission serice over
agreed-upon facilities (Amended and Restated Transmission Service and Operating Agreement, Rate Schedule 297). Subject to
termnation upon mutual agreement and replacement agreements are in effect.
I§chedule Page: 328.4 Line No.: 8 Column: m
Charges for load following, spinning and/or supplemental reserves. Distrbution Voltage Service Charge.
I§chedule Page: 328.4 Line No.: 9 Column: d
Legacy Contract executed between PacifiCorp and Utah Associated Municipal Power Systems for transmission service over
agreed-upon facilities (Amended and Restated Transmission Service and Operating Agreement, Rate Schedule 297). Subject to
termination upon mutual agreement and replacement agreements are in effect.
I§chedule Page: 328.4 Line No.: 9 Column: m
Charges for monitoring, scheduling, load following, spining and/or supplemental reserves. Distrbution Voltage Service Charge.
December 2009 Servce.
I§chedule Page: 328.4 Line No.: 10 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarff between various paries and points.
I§chedule Page: 328.4 Line No.: 11 Column: d I
Legacy Contract (Rate Schedule 637) executed between PacifiCorp and Utah Municipal Power Agency for transmission service over
agreed-upon facilities (Amended and Restated Transmission Service and Operating Agreement). Subject to termination upon mutu
agreement and replacement agreements are in effect.
I§chedule Page: 328.4 Line No.: 11 Column: m
Char es for schedulin and load followin .
chedule Pa e: 328.4 Line No.: 12 Column: d
Legacy Contrct (Rate Schedule 637) executed between PacifiCorp and Uta Municipal Power Agency for transmission service over
agreed-upon facilities (Amended and Restated Transmission Service and Operating Agreement). Subject to termination upon mutul
agreement and replacement agreements are in effect.
I§chedule Page: 328.4 Line No.: 12 Column: m
Charges for scheduling and load following. December 2009 Service.
I§chedule Page: 328.4 Line No.: 13 Column: d
Legacy Contract (Rate Schedule 591) executed between PacifiCorp and Warm Springs Power Enterprises for transmission service
over agreed-upon facilities and/or subject to a sole-use or facilities charge. Termnating Januar 1,2032.
ISchedule Page: 328.4 Line No.: 13 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use or facilities charge based on a capacity factor
and or proportional use as defined in the contract.
ISchedule Page: 328.4 Line No.: 14 Column: d
Legacy Contract (Rate Schedule 591) executed between PacifiCorp and Warm Springs Power Enterprises for transmission service
over agreed-upon facilities.and/or subject to a sole-use or facilities charge. Termnating Januar 1,2032.
ISchedule Page: 328.4 Line No.: 14 Column: m
IFERC FORM NO.1 (ED. 12-87)Page 450.20
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Charge for transmission service over agreed-upon facilties and/or subject to a sole-use or facilities charge based on a capacity factor
and or proportional use as defined in the contrct. December 2009 Serce.
'¡chedule Page: 328.4 Line No.: 15 Column: c
Varous Western Area Power Association Customers in Pacificorp's Control Area.
¡Schedule Page: 328.4 Line No.: 15 Column: d
Legacy Contract (Rate Schedule 262) executed between PacifiCorp and Western Area Power Admistrtion for transmission and
interconnection service over agreed-upon facilities and/or subject to a sole-use or facilities charge for load service to preferential
customers for deliveries of Colorado River Storage Project power and energy. Teration upon thee years after wrtten notice and
mutual consent.
I§chedule Page: 328.4 Line No.: .15 Column: m
Fixed Termnation Fee associated with a contrt cancellation a lied for the durtion of this a eement.
chedule Pa e: 328.4 Line No.: 16 Column: c
Various Western Area Power Association Customers in Pacificorp's Control Area.
I§chedule Page: 328.4 Line No.: 16 Column: d
Legacy Contract (Rate Schedule 262) executed between PacifiCorp and Western Area Power Admistration for transmission and
interconnection service over agreed-upon facilities and/or subject to a sole-use or facilities charge for load service to preferential
customers for deliveries of Colorado River Storage Project power and energy. Termation upon three years after wrtten notice and
mutual consent.
I§chedule Page: 328.4 Line No.: 16 Column: m
Fixed Termination Fee associated with a contract cancellation applied for the duration of this a eement. December 2009 service.
Schedule Pa e: 328.4 Line No.: 17 Column: c
Varous Western Area Power Association Customer in Pacificorp's Control Area.
I§chedule Page: 328.4 Line No.: 17 Column: d
Legacy Contract (Rate Schedule 263) executed between PacifiCorp and Western Area Power Admistration for transmission and
interconnection service over agreed-upon facilities and/or subject to a sole-use or facilities charge for load service to low voltage
customers for deliveries of power and energy from Salt Lake City Area Integrated Projects, including the Colorado River Storage
Pro' ects, to certin munici alities at service below 138kv. Terminationu on thee ears after written notice and mutual consent.
chedule Pa e: 328.4 Line No.: 17 Column: m
Charges for low-voltage transmission of power and energy.
I§chedule Page: 328.4 Line No.: 18 Column: c
Various Western Area Power Association Customers in Pacificorp's Control Area.
¡Schedule Page: 328.4 Line No.: 18 Column: d
Legacy Contract (Rate Schedule 263) executed between PacifiCorp and Western Area Power Administration for transmission and
interconnection service over agreed-upon facilities and/or subject to a sole-use or facilities charge for load service to low voltage
customers for deliveries of power and energy from Salt Lake City Area Integrted Projects, including the Colorado River Storage
Projects, to certin municipalities at service below 138kv. Termnation upon thee years after wrtten notice and mutual consent.
¡Schedule Page: 328.4 Line No.: 18 Column: m
December 2009 Service.
¡Schedule Page: 328.4 Line No.: 19 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
I§chedule Page: 328.4 Line No.: 19 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tarffbetween various parties and points.
'¡chedule Page: 328.4 Line No.: 20 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
¡Schedule Page: 328.4 Line No.: 20 Column: d
Non-Fir or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween various paries and points.
I§chedule Page: 328.4 Line No.: 20 Column: m
December 2009 Service.
I§chedule Page: 328.4 Line No.: 21 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Tramission Tarff.
'¡chedule Page: 328.4 Line No.: 21 Column: d
IFERC FORM NO.1 (ED. 12-S7) Page 450.21
Name of Respondent This Report is:Date of Report Year/Penod of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Legacy Contrct (Rate Schedule 664) executed between PacifiCorp and Western Area Power Admnistration concerning the exchange
of transmission services over agreed-upon facilities. The contract termnates fift years from execution. See also FERC Account 565 ~
Transmission of Electrcity by Others, page 332 of this Form No. 1.
¡Schedule Page: 328.4 Line No.: 22 Column: c
Varous signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tarff.
I$chedule Page: 328.4 Line No.: 22 Column: d I
Legacy Contract (Rte Schedule 664) executed between PacifiCorp and Wester Area Power Admnistration concerning the exchange
of transmission services over agreed-upon facilities. The contract termnates fift years from execution. See also FERC Account 565 -
Tr-nsmission ofElectrci b Others, a e 332 of this Form No. 1.
chedulePa e: 328.4 Line No.: 22 Column: m
Adjustments for 2009 service per terms of the contract.
~chedule Page: 328.4 Line No.: 23 Column: d
Evergreen Network Transmission Service under the Open Access Transmission Tarff (Service Agreement 175).
~chedulePage: 328.4 Line No.: 23 Column: m
Distrbution Voltage Service Charge. Primar Delivery Service.
¡Schedule Page: 328.4 Line No.: 24 Column: d
Evergreen Network Transmission Service under the Open Access Trasmission Tarff (Servce Agreement 175).
¡Schedule Page: 328.4 Line No.: 24 Column: m
Distrbution Voltage Service Charge. Primary Delivery Service. December 2009 Service.
¡Schedule Page: 328.4 Line No.: 25 . Column: m
Represents the difference between actual wheeling revenues for the period as reflected on the individual line items within this
schedule, and the accruals credited to account 456.1 durng the period.
IFERC FORM NO.1 (ED. 12-87)Page 450.22
Name of Respondent
PacifiCorp
This Report Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubission 04/18/2011
TRANSMISSION OF ELECTRICITY BY OTHERS (Accunt 565)
(Including transactons referred to as "wheeling")
1. Report all transmission, i.e. 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 transferrd. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
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 2010/Q4
Line
No. Name of Company or Public Statistical
Authority (Footnote Affliations) Classification. (a) (b)~1a2 Arzona Public Servce .~
3 Arizona Public Servce NF
4 Arizona Public Service as
5 Arzona Public Service SFP
6 Ashland, City of FNS
7 Avista Corporation FNS
ll12 Bonneville Power Admin. II
13 Bonnevile Power Admin. FNS
14 Bonneville Power Admin. .-
15 Bonnevile Power Admin. NF
16 Bonnevile Power Admin. as
TOTAL
TRANSFER OF ENERGY
Magawatt- Magawau-
tiours tioursReceived Delivered(c) (d)
370,348
20,773
18,763
1,769
48,575
12,732
370,348
20,773
18,763
1,769
50,243
12,732
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER~
!lemana .Energy .ymer Total Cost ofCht\¡ies Ch($)Jes Ch($)Jes Transæission
(e) (f) (g) Híj
1,093,316
80,392
6,197
71,146
1,093,316
80,392
9,942
71,146
16,638
217,930
73,464
71,485
181,813
9,021
5,394,463
309,750
5,226,006
17,871,426
.ftft ~
16,638
217,930
73,464
71,485 _:
9,021 9,121 26,121
6,555,934
56,487,763
1,341,217
32,536,797
Page 332
17,000
6,555,934
53,476,903 ~IJ
1,341,217165,008~'"
5,394,463
309,750
5,049,853
17,570,67(
30,813,868
111,398,582 20,780,193 136,854,6494,675,874
FERC FORM NO. 1/3.Q (REV. 02-04)
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
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 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 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 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 bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on 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.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-agawa -nergy er Total Cost ofIioursIioursCharresCharresTrans~SSionAuthonty (Footnote Affliations)Classification Received Delivered ($($
(a)(b)(c)(d)(f)(g)
1 Bonnevile Power Admin.SFP 52,522 52,522 208,244 208,244
-3,756 26,960
1,829,210
533,27 533,27 2,867,483 2,867,483
1,808 1,808 13,415 13,415
168,010 168,010 3,391,570 3,391,570
183,089 183,089 1,327,332 1,327,332
150 150 113 113
200 200 181 181
63,922
175,965
12 Idaho Power Company
13 Idaho Power Company -183,020 514,482
14 Idaho Power Company 6,994 6,994
15 Idaho Power Company ,.WJ 3,206,147 3,257,310 6,121,548 6,121,548
16 Idaho Power Company NF 311,953 365,715 1,050,762 1,050,762
TOTAL 17,570,67 17,871,426 111,398,582 4,675,874 20,780,193 136,854,649
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.1
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
TRANSMISSION OF ELECTRICITY BY OTHE S (Accunt 565)
(Including transactions referred to as ''wheeling")
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 acrnyms. 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.
Year/Period of Report
End of 2010/Q4
Line
No. Name of Company or Public
Authority (Footnote Affliations)
(a)
Idaho Power Company
2 Idaho Power Company
TRANSFER OF ENERGY
Magawatt- agawa -Iìours IìoursReceived Delivered(c) (d)
Statistical
Classification
(b)
as
SFP
FNS
1,032 1,032
41 41
60,588 60,588
79,037 79,037
94,374 94,852
27,233 27,233
173,713 17,713
1,617 1,617
4 Morgan City Corporation
5 Nevada Power Company
6 Nevada Power Company
7 Nevada Power Company. m
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
nergyCharges
($)
(f)
2,180
200,194
214,659
391,630
118,134
966,000
1,759
14 Portand Gen. Electric
15 Portand Gen. Electric
16 Powerex Corporation
TOTAL 17,570,67 17,871,426 136,854,649
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.2
Total Cost ofTrans~tsion
10,767,019
2,180
182,791
434
200,194
69,299
214,659
391,630
26,991
118,134
966,000
15,333
1,759
908
-1,025,820
-1,894,500
111,398,582 20,780,1934,675,874
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
TRANSMISSION OF ELECTRICITY BY OTHE S (Account 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, Le. wheeling or electricity provided by other electric 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 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 bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
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.
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERLine
No. Name of Company or Public
Authority (Footnote Affliations)
(a). ..
TRANSFER OF ENERGY
Magawatt- agawa -tiours tioursReceived Delivered(c) (d)
169,116 17,879
855 855
116,760 116,760
nergyCharges
($)
(f)
160 160
6,480 6,480
499
41,504
203,428 212,197 901,862
249,472 249,472 563,215
218 218 1,093
-1,512 -107,800
89
TOTAL 17,570,67 17,871,426 111,398,582 136,854,649
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.3
erCharges
($)
(g)
4,675,874 20,780,193
Total Cost of
Trans~ssion
901,862
4,524
591,311
21,148
499
41,504
5,986
9,523
901,862
563,215
222,304
1,093
127
.109,300
445
-2,310,796
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
TRANSMISSION OF ELECTRICITY BY OTHEF S (Acount 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, Le. wheeling or electricity pròvided by Other electric utilties, cooperatives, municipalities, other public
authorities, qualifying facilties, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or 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, L,FP - long-Term Firm Point-ta-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 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 ofthe 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 EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
No.Name of Company or Public Statistical Magawatt-Magawau-J:.emano .snergy _~tner Total Cost ofIioursIioursCharresCharresCharresTransoossionAuthority (Footnote Affliations) Classification Received Delivered ($($($(a) (b)(c)(d)(e)(f)(g)
2 Westem Area Power Adm. ."._-311 -311 -6,512 .--7,331
3 Westem Area Power Adm.FNS 4,812,992 4,812,992
4 Western Area Power Adm.r~414,790 414,790 2,220,000 2,220,000
5 Western Area Power Adm.NF 234,189 234,189 594,452 594,452
6 Westem Area Power Adm.OS .,423,870
7 Westem Area Power Adm.SFP 45,948 45,948 80,65 80,650.. ..
z8 Accrual True-up *1,485,559
9
10
11
12
13
14
15
16
TOTAL 17,570,67Ð 17,871,426 111,398,582 4,675,874 20,780,193 136,854,649
FERC FORM NO. 1/3.. (REV. 02-04)Page 332.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I§chedule Page: 332 Line No.: 1 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "ARZONA PUBLIC SERVICE" ON PAGE 332: Complete name is
Arzona Public Service Company.
I§chedule Page: 332 Line No.: 1 Column: b
Legacy Contract executed between PacifiCorp and Arzona Public Service Company concerning the exchange of transmission
services over agreed-upon facilities (Restated Transmission Agreement between PacifiCorp and Arzona Public Service Company,
("Restated TSA"), Rate Schedule 436). The contract termates October 31, 2020. See also FERC Account 456.1 - Transmission of
E1ectrci For Others, a e 328 of this Form No.1.
chedule Pa e: 332 Line No.: 2 Column: b
Arzona Public Service Com an - Contract Termnation Dates: Ma
chedule Pa e: 332 Line No.: 4 Column:
Ancilar Services.
Išchedule Page: 332 Line No.: 9 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "BASIN ELECT. POWER COOP" ON PAGES 332: Complete name is
Basin Electrc Power Cooperative.
¡Schedule Page: 332 Line No.: 9 Column: b
Basin Electric Power Cooperative ~ Contract Termnation Date: One year written notice.Išchedule Page: 332 Line No.: 10 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "BIG HORN RUR ELECTRIC" ON PAGE 332: Complete name is
Big Horn Rural Electrc Cooperative.
¡Schedule Page: 332 Line No.: 10 Column: g
Use of Facilities.
!tchedule Page: 332 Line No.: 11 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "BONNEVILLE POWER ADMIN." ON PAGE 332: Cotnplete name
is Bonnevile Power Administration.
!tchedule Page: 332 Line No.: 11 Column: b
Legacy Contract executed between PacifiCorp and Bonnevile Power Administration concerning the exchange of transmission
services over agreed-upon facilities ("Midpoint-Meridian Transmission Agreement", Rate Schedule 369). This agreement rus
concurently with the AC Intertie Agreement (Rate Schedule 368), which terminates when the facilities subject to that agreement are
taen out of service. See also FERC Account 456.1 - Transmission of Electrci For Others, a e 328 of this Form No. 1.
chedule Pa e: 332 Line No.: 12 Column: b
Settlement Adjustment.
!tchedule Page: 332 Line No.: 14 Column: b
Bonnevile Power Admistration - Contract Termnation Dates: 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.
!tchedule Page: 332 Line No.: 14 Column: g
Ancilary Services.
!tchedule Page: 332 Line No.: 16 Column: g
Ancilar Services. Use of Facilities.
¡Schedule Page: 332.1 Line No.: 2 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "CA IN. SYS. OPERATOR" ON PAGE 332: Complete name is
California Inde endent S stem 0 erator Co oration.
chedule Pa e: 332.1 Line No.: 2 Column: b
Settlement Adjustment.
!tchedule Page: 332.1 Line No.: 2 Column: g
Ancilary Services.
!tchedule Page: 332.1 Line No.: 3 Column: g
Ancilar Services.
¡Schedule Page: 332.1 Line No.: 5 Column: a
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "DESERET PWR ELECT. COOP" ON PAGE 332: Complete name is
Deseret Power Electrc Cooperative.
I§chedule Page: 332.1 Line No.: 5 Column: b
Settlement Adjustment.
I§chedule Page: 332.1 Line No.: 6 Column: b
Deseret Power Electrc Cooperative - Contract Termation Dates: October 31, 2012 and September 1,2018.
I§chedule Page: 332.1 Line No.: 8 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "EL PASO ELECT. CO." ON PAGE 332: Complete name is El Paso
Electrc Company.
I§chedule Page: 332.1 Line No.: 8 Column: b
Settlement Adjustment.
I§chedule Page: 332.1 Line No.: 10 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "FLATHEAD ELECT. COOP." ON PAGE 332: Complete name is
Flathead Electrc Cooperative, Inc.
I§chedule Page: 332.1 Line No.: 10 Column: g
Use of Facilities.
¡Schedule Page: 332.1 Line No.: 11 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "HERMSTON GENERATING CO" ON PAGE 332: Complete name
is Heriston Generating Company, L.P.
I§chedule Page: 332.1 Line No.: 11 Column: g
Use of Facilities.
I§chedule Page: 332.1 Line No.: 12 Column: b
Legacy Contract (Rate Schedule 427) executed between PacifiCorp and Idao Power Company concerning the exchange of
transmission services over agreed-upon facilities (Draft Transmission Services Agreement between PacifiCorp and Idaho Power
Company, Draft 1 - 5/19/95 ("Goshen Agreement"). Termation of this agreement occurs at the end of the calenda month following
the earlier of the effectiveness of a replacement contrct, or upon thee year wrtten notice of termination as long as PacifiCorp has
facilities in place to serve PacifiCorp's Big Grassy load. See also FERC Account 456.1 - Transmission of Electrcity For Others, page
328 of this Form No. 1.
¡Schedule Page: 332.1 Line No.: 13 Column: b
Settlement Adjustment.
I§chedule Page: 332.1 Line No.: 13 Column: g
Use of Facilities. Respondent's porton of specified costs of certin facilities.
I§chedule Page: 332.1 Line No.: 15 Column: b
Idaho Power Company - Contract Termnation Date: April 1,2011.
I§chedule Page: 332.2 Line No.: 1 Column: g
Ancilar Services. Use of Facilities. Respondent's porton of specified costs of certin facilities.
¡Schedule Page: 332.2 Line No.: 3 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "MOON LAK ELECT. ASSOC." ON PAGE 332: Complete name is
Moon Lake Electrc Association.
¡Schedule Page: 332.2 Line No.: 3 Column: g
Use of Facilities.
I§chedule Page: 332.2 Line No.: 4 Column: b
Settlement Adjustment.
¡Schedule Page: 332.2 Line No.: 6 Column: g
Ancilar Services.
I§chedule Page: 332.2 Line No.: 8 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "NORTHWESTERN CORP." ON PAGE 332: Complete name is
NorthWestern Corporation.
I§chedule Page: 332.2 Line No.: 9 Column: g
Ancilar Services.
I§chedule Page: 332.2 Line No.: 11 Column: a
IFERC FORM NO.1 (ED. 12-87) Page 450.2
Name of Respondent .This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
PacifCorp i (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PLATTE RIR POWER" ON PAGE 332: Complete name is Platte
River Power Authority.
¡Schedule Page: 332.2 Line No.: 11 Column: b
Platt River Power Authority - Contrct Termnation Date: October 31,2012.
¡Schedule Page: 332.2 Line No.: 12 Column: g
Ancilary Services.
!sChedule Page: 332.2 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PORTLAND GEN. ELECTRIC" ON PAGE 332: Complete name is
Portland General Electrc Company.
!schedule Page: 332.2 Line No.: 14 Column: g
Ancilar Services. Use of Facilities.
¡Schedule Page: 332.2 Line No.: 15 Column: e
Reassignent of Bonnevile Power Administration transmission.
!schedule Page: 332.2 Line No.: 16 Column: e
Reassignent of Bonnevile Power Administration tranmission.
¡Schedule Page: 332.3 Line No.: 1 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PUBLIC SERVICE CO OF CO" ON PAGE 332: Complete name is
Public Servce Company of Colorado.
!schedule Page: 332.3 Line No.: 1 Column: b
Public Servce Company of Colorado - 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.: 3 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "PUBLIC SERVICE CO OF NM" ON PAGE 332: Complete name is
Public SerVice Company of New Mexico.
!schedule Page: 332.3 Line No.: 3 Column: b
Public Service Company of New Mexico - Contract Termination Date: December 1, 2012.
!schedule Page: 332.3 Line No.: 4 Column: g
Ancilar Services.
¡Schedule Page: 332.3 Line No.: 6 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "SIERR PACIFIC POWER CO" ON PAGE 332: Complete name is
Sierra Pacific Power Company.
!schedule Page: 332.3 Line No.: 7 Column: g
Ancilary Serices.
!schedule Page: 332.3 Line No.: 8 . Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "SURRISE VALLEY ELECTR." ON PAGE 332: Complete name is
Su rise Valle Electrfication Co .
chedule Pa e: 332.3 Line No.: 8 Column: b
Surprise Valley Electrfication Corp. - Contract termination date: Evergreen.
¡Schedule Page: 332.3 Line No.: 8 Column: g
Use of Facilities.
¡Schedule Page: 332.3 Line No.: 9 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "TR-STATE GEN & TRNSM" ON PAGE 332: Complete name is
Tri-State Generation and Transmission Association, Inc.
!schedule Page: 332.3 Line No.: 9 Column: b
Tri-State Generation and Transmission Association, Inc. - Contract Termnation Date: The date that all generating plants comprising
PacifiCorp resources have been retired from service or interests transferred.
!schedule Page: 332.3 Line No.: 11 Column: g
Ancilary Services.
!schedule Page: 332.3 Line No.: 12 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "TUCSON ELECTRIC POWER" ON PAGE 332: Complete name is
Tucson Electrc Power Company.
IFERC FORM NO.1 (ED. 12-87)Page 450.3
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2Ç An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010104
FOOTNOTE DATA
!Schedule Page: 332.3 Line No.: 13 Column: g I
Ancilar Services.
I$chedule Page: 332.3 Line No.: 14 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "UTAH ASSOC MU PWR SYS" ON PAGE 332: Complete name is
Uta Associated Munici al Power S stems.
ehedule Pa e: 332.3 Line No.: 14 Column: b
Settlement Adjustment.
¡Schedule Page: 332.3 Line No.: 14. Column: g
Ancilary Services.
I$chedule Page: 332.3 Line No.: 16 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "WESTPORT FIELD SRV LLC" ON PAGE 332: Complete name is
W es ott Field Services, LLC.
chedule Pa e: 332.3 Line No.: 16 Column: b
W estport Field Services, LLC - Contract Termnation Date: Evergreen.
I$chedule Page: 332.3. Line No.: 16 Column: e
Reimbursement for providing third part servce.
I$chedule Page: 332.4 Line No.: 1 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "WESTERN ARA POWER ADM." ON PAGE 332: Complete name
is Western Area Power Administration.
I$chedule Page: 332.4 Line No.: 1 Column: b I
Legacy Contract (Rate Schedule 664) executed between PacifiCorp and Weste Ara Power Admistration concerning the exchange
of transmission services over agreed-upon facilities. The contrct terates fift years from execution. See also FERC Account
456.1 - Transmission ofElectrci For Others, a e 328 of this Form No.1.
chedule Pa e: 332.4 Line No.: 2 Column: b
Settlement Adjustment.
I$chedule Page: 332.4 Line No.: 2 Column: g
Ancilary Services.
I$chedtlle Page: 332.4 Line No.: 4 Column: b
Western Area Power Administration - Contract Termination Date: May 31, 2022.
I$chedule Page: 332.4 Line No.: 6 Column: g
Ancilar Services. Use of Facilities.
ISchedule Page: 332.4 Line No.: 8 Column: g
Represents the difference between actual wheeling expenses for the period as reflected on the individual line items within this
schedule, and the accruals charged to account 565 durg the period.
IFERC FORM NO.1 (ED. 12-87)Page 450.4
Name of Respondent This wort Is:Date of Report
I
Year/Period ofRêport
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/18/2011
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line DeSCrirtion Amount
No.(a (b)
1 Industry Association Dues 1,329,375
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 & Economic Development and
8 Corporate Memberships and Subscriptions
9 Bend 2030 10,000
10 CCD Business Development Corp 5,00
11 Economic Development Corp of Utah 91,481
12 Idaho Economic Development Association 7,500
13 Governor's Utah Economic Summit 10,000
14 Oregon Economic Development Association 10,000
15 Port Of Columbia 8.00
16 State of Utah 10,000
17 Uintah County Economic Development 5,500
18 Utah Center For Rural Life 5,00
19 Utah Sports Commission 57,072
20 Wyoming Business Council .5,000
21 Americas' SAP User Group 5,000
22 Associated Oregon Industries 28,000
23 Four County Economic Development Corp 25,000
24 Intermountain Electrical Association 9,000
25 Northern Tier Transmission Group 418,088
26 Oregon Business Association 11,000
27 Oregon Business Council 33,228
28 Oregon Solar Energy Industries Association .5,000
29 Oregon Sports Authority Foundation .5,000
30 Pacific Northwest Utilties Conference 69,069
31 Portland Business Allance 39,400
32 Rocky Mountain Electrical League 18,000
33 Salt Lake Area Chamber of Commerce 30,255
34 The Climate Registry 10,000
35 Utah Foundation 20,000
36 Utah Manufacturers Association 6,000
37 Utah Taxpayers Association 20,000
38 Watson & Renner 16,408
39 West Association 28,511
40 Western Electricity Coordinating Council 3,786,077
41 Western Energy Institute 42,004
42 Wyoming Business Allance 5,000
43 Wyoming Taxpayers Association 9,523
44 Yakima County Development 7,500
45 Other 153,729
46 TOTAL 16,291,649
FERC FORM NO.1 (ED. 12-94)Page 335
Name of Respondent
I This ~ort Is:
Date of Rep'ort Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) n A Resubmission 04/18/2011
MISCELLANEOUS GENERAL EXPENSES (Accunt 930.2).(ELECTRIC)
Line DeSCri)tion Amount
No.(a (b)
6
7 Directors Fees - Regional Advisory Boards 16,240
8
9 General:
10 MidAmerican Energy Holdings Company Management Fee 7,470,918
11 Other -689
12
13 Regulatory Asset Amortization:
14 Glenrock Mine Excluding Reclamation - UT 112,218
15 Goodnoe Hils Settlement - WY 21,250
16 Transition Plan - OR 2,289,365
17 Lake Side Settlement - WY 27,627
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 TOTAL 16,291,649
FERC FORM NO.1 (ED. 12-94)Page 335.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/18/2011
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 (Accunt 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account 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 bottom of sectionC 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 most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the
bottom of section C the amounts and nature of the provisions and the plant items to which related.
A.Summary of Depreciation and Amortization Charges
Depreciation Amortization of
Line D~reciation Expense for Asset Limited Term Amortization of
No.Functional Classification xpense Retirement Costs Electric Plant Other Electric Total
(Account 403)(Account 403.1)(Account 404)Plant (Acc 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 31,747,938 31,747,938
2 Steam Production Plant 129,276,321 129,276,321
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 15,836,545 169,186 16,005,731
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 107,805,700 107,805,700
7 Transmission Plant 71,678,696 71,678,696
8 Distribution Plant 142,300,998 142,300,998
9 Regional Transmission and Market Operation
10 General Plant 34,325,996 2,921,169 37,247,165
11 Common Plant-Electric
12 TOTAL -.,"-34,838,293 536,062,549
¡¡
B. Basis for Amortization Charges
The amortization of Limited-Term Electric Plant is based on straight-line amortization over the life of the asset.
FERC FORM NO.1 (REV. 12-03)Page 336
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da. Yr)End of 2010/Q4
(2) FiA Resubmission 04/18/2011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges .
Line uepreClaole i:stimatea .'Iei l\ppiiea Mortlity Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
lal (In Th?~fandS)7~i (perdfnt)(Per~int)Tyie
7~r
12 WIND GENERATION
13 Dunlap Ranch I
14 341.00 WY 366 24.87 -1.00 4.06
15 343.00WY 232,074 24.87 -1.00 4.06
16
17 DISTRIBUTION PLANT
18 364.00 CA 51,952 50.00 -90.00 3.80 R1.5 37.94
19 365.00 CA 32,245 65.00 -55.00 2.35 S-.5 51.70
20 366.00CA 15,315 50.00 -30.00 2.55 R5 34.58
21 367.00CA 16,737 45.00 1.07 S6 29.50
22 368.00 CA 46,821 50.00 -52.00 3.36 R5 32.34
23 369.10CA 8,371 55.00 -5.00 1.56 R1 44.37
24 369.20 CA 14,239 60.00 -5.00 1.50 R4 48.69
25 370.00 CA 3,911 26.00 4.30 R2.5 13.24
26 371.00 CA 271 25.00 -30.00 4.08 LO 13.85
27 373.00 CA 662 35.00 -35.00 3.58 R3 16.36
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. 12-03)Page 337
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 20 1 0/Q4
FOOTNOTE DATA
I$chedule Page: 336 Line No.: 12 Column: b
Depreciation expense associated with transporttion equipment is generally charged to operations and maintenance expense and
constrction work in progress. Durng the year ended December 31, 2010, depreciation expense associated with trsporttion
equipment was $14,065,119.
¡Schedule Page: 336 Line No.: 12 Column: e
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as either a regulatory asset or liability.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This i!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
REGULATORY COMMISSION EXPENSES
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 years amortization of amounts
deferred in previous years.
Line Description Assessed by Expenses Total Deferred
No.(Furnish name of regulatory commission or body the Regulatory of Expense for in Accunt
Current Year 182.3 aldocket or case number and a description of the case)Commission Utilty (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
1 Public Service Commission of Utah:
2 Annual Fee 3,648,134 3,648,134
3 Rate Case 1,343,711 1,343,711
4
5 Public Utilty Commission of Oregon:
6 Annual Fee 2,145,364 2,145,364
7 Rate Case 1,261,788 1,261,788
8
9 Public Service Commission of Wyoming:
10 Annual Fee 1,210,427 1,210,427
11 Rate Case 1,000,801 1,000,801
12
13 Washington Utilties and Transportation
14 Commission:
15 Annual Fee 576,475 576,475
16 Rate Case 646,375 646,375
17
18 Idaho Public Utilties Commission:
19 Annual Fee 353,980 353,980
20 Rate Case 826,933 826,933
21 Other State Regulatory Expenses 17,580 17,580
22
23 Public Utilties Commission of California:
24 Annual Fee 952 952
25 Rate Case 851,318 851,318
26
27 Rate Cases - All States 16,890 16,890
28
29 Federal Energy Regulatory Commission:
30 Annual Fee 1,917,327 1,917,327
31 Annual Land Use Fee 596,587 596,587
32 Transmission Rate Case 762,536 762,536
33 FERC Other Regulatory 704,704 704,704
34
35 Other Regulatory 44,958 44,958
36
37 Deferred Regulatory Commission Expense 61,37~
38
39
40
41
42
43
44
45
46 TOTAL 10,449,246 7,477,594 17,926,840 61,378
FERC FORM NO.1 (ED. 12-96)Page 350
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2Ð11
REGULATORY 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 (t), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other acounts.
5. Minor items (less than $25,000) may be grouped.
Electric
Electric
928
928
AMORTIZED DURING YEAR
Deferred to Contra Amount Deferred in Line
Account 182.3 Account Account 182.3 No.End of Year
(h)(i)ü)(k)(I)
1
3,648,134 2
1,343,711 3
4
5
2,145,364 6
1,261,788 7
8
9
1,210,427 10
1,000,801 11
12
13
14
576,475 15
646,375 16
17
18
353,980 19
826,933 20
17,580 21
22
23
952 24
851,318 25
26
16,890 27
28
29
1,917,327 30
596,587 31
762,536 32
704,704 33
34
44,958 35
36
37,081 928 17,580 80,879 37
38
39
40
41
42
43
44
45
(f)
Electric
Electric
928
928
Electric
Electric
928
928
Electric
Electric
928
928
Electric
Electric
928
928
Electric
Electric
Electric
928
928
928
Electric 928
Electric 928
Electric 928
Electric 928
Electric 928
Electric 928
----17,926,840 37,081
Page 351
17,580 80,879 46
FERC FORM NO.1 (ED. 12-96)
Name of Respondent This l!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and. demonstration (R, D & D)
project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored project.(ldentify
recipient regardless of affliation.) For any R, D & D work carried with others, show separately the respondentscost for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accunts).
2. Indicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, D & D Performed Internally:a. Overhead
(1) Generation b. Underground
a. hydroelectric (3) Distribution
i. Recreation fish and wildlife (4) Regional Transmission and Market Operation
ii Other hydroelectric (5) Environment (other than equipment)
b. Fossil-fuel steam (6) Other (Classify and include items in excess of $50,000.)
c.Internal combustion or gas turbine (7) Total Cost Incurred
d.Nuclear B. Electric, R, D & D Performed Externally:
e. Unconventional generation (1) Research Support to the electcal Resarch Councilor the Electric
f. Siting and heat rejection Power Research Institute
(2) Transmission
Line Classification Description
No.(a)(b)
1 B. Electric R, D & D Performed Externally
2 (1) Research Support Electric Power Research Institute
3 - Membership dues
4 - Seismic studies of substation equipment program
5 - Toxic release inventory reporting for power plants program
6 - Utilty gasification program
7 (4) Research Support National Electric Testing, Research& Applications Center
8 - Membership dues
9 - Partcipation
10 (4) Research Support Solar Electc Power Association
11 - Membership dues
12
13
14 .
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO.1 (ED. 12-87)Page 352
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
(2) Research Support to Edison Electric Institute
(3) Research Support to Nuclear Power Groups
- (4) Research Support to Others (Classify)
(5) Total Cost Incurred
3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $50,000 or more,
briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.).
Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D & D
activit.
4. Show in column (e) the accunt number charged with expenses during the year or the account to which amounts were capitalized during the year,
listing Account 107, Construction Work in Progress, first. Show in C9lumn (f) the amounts related to the account charged in column (e)
5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Accunt 188, Research,
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6. If costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by "Est."
7. Report separately research and related testing facilties operated by the respondent.
Costs Incurred Internally Costs Incurred Externally AMOUNTS CHARGED IN CURRENT YEAR Unamortized Line
currelc~ Year Current Year Account Amount Accumulation No.
(d)(e)(f)(g)
1
2
547,651 930.2 547,651 3
20,000 560 20,000 4
12,000 557 12,000 5
5,000 557 5,000 6
7
23,750 930.2 23,750 8_m 580 4,501 9
10
7,000 930.2 7,000 11
12
13
.14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO.1 (ED. 12-87)Page 353
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 352 Line No.: 9 Column: cEstiate
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wagea for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
1 Electric
2 Operation
3 Production
4 Transmission
5 Regional Market
6 Distribution
7 Customer Accounts
8 Customer Service and Informational
9 Sales
10 Administrative and General
11 TOTAL Operation (Enter Total of lines 3 thru 10)
12 Maintenance
13 Production
14 Transmission
15 Regional Market
16 Distribution
17 Administrative and 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 Accunts
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)
Line
No.
Classification Direct PayrollDistribution Total
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 04/18/2011
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Year/Period of Report
End of 2010/Q4
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 (Lines 35 and 47)
57 Distribution (Lines 36 and 48)
58 Customer Accounts (Line 37)
59 Customer Service and Informational (Line 38)
60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)
63 Other Utilty Departments
64 Operation and Maintenance
65 TOTAL All 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 Construction (Total of lines 68 thru 70)
72 Plant Removal (By Utilty Departments)
73 Electric Plant
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)
77 Other Accounts (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
(a)
Line
No.
Classification
352,150,935 352,150,935~~---- ----~ao f/l1l:t 0: dkw;Jl" A:~
147,587,388 147,587,388
.%::..:/..~::~..£:l:ß147,587,388 147,587,388
9,659,614 9,659,614
9,659,614 9,659,614
27,117,060 27,117,060
429,366 429,366
689,699 689,699
28,236,125
537,634,062
28,236,125
537,634,062
FERC FORM NO.1 (ED. 12-88)Page 355
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/18/2011
PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancilary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related biling determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancilary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancilary services purchased or sold during the
year. Include in a footnote and specify the amount for each type of other ancillary service provided.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Billng Determinant Usage - Related Biling 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 Contrl and Dispatch 144,444
2 Reactive Supply and Voltage
3 Regulation and Frequency Response 57,766,387 MWh 9,242,739 58,287,704 MWh 9,857,432
4 Energy Imbalance -145,195 MWh 4,614,914
5 Operating Reseive - Spinning 65,622,051 MWh 23,896,498 68,807,239 MWh 25,129,384
6 Operating Reseive - Supplement 65,622,051 MWh 23,896,498 68,479,528 MWh 25,007,148
7 Oter -
8 Total (Lines 1 thru 7)189,010,489 57,035,735 195,429,276 55,519,275
FERC FORM NO.1 (New 2-04)Page 398
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 398 Line No.: 7 Column: g
Refud of Emergency Resere service
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 04/18/2011
MONTHLY 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 ü) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the
definition of each statistical classification.
Year/Period of Report
End of 2010/Q4
NAME OF SYSTEM:
Line
No.Month
Other
Service
(a)
1 January
2 February
3 March
4 Total for Quarter 1
5 April
6 May
7 June
Total for Quarter 2
9 July
10 August
11 September
12 Total for Quartr 3
13 October
14 November
15 December
16 Total for Quarter 4
17 Total Year to
DatelYear
Monthly Peak
MW- Total
Oter Long-
Term Firm
Service
Short-Term Firm
Point-to-point
Reseration
(i)
Day of Hour of Firm Network Firm Network Long-Term Firm
Monthly Monthly Service for Self Service for Point-to-point
Peak Peak Others Reservations
(e)(f)(g)(h)(b)
12,314 19,717
1,050
629
1,346
16,2
15,59
15,81
47,67
14,84
14,70
17,38
46,93
18,07
18,29
16,80
53,18
15,94
16,61
15,75
48,321
98,260 64,7011,124
FERC FORM NO. 1/3-Q (NEW. 07-04)Page 400
ü)
1,668
1,588
1,530
4,786
1,489
1,424
1,817
4,730
1,863
1,919
1,686
5,48
1,543
1,587
1,603
4,733
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 400 Line No.: 1 Column: d
PST
¡Schedule Page: 400 Line No.: 2 Column: d
PST
¡Schedule Page: 400 .' Line No.: 3 Column: d
PST
¡Schedule Page: 400 Line No.: 4 Column: e
Reflects actual demands of control area load at time of Trasmission System Peak.
¡Schedule Page: 400 Line No.: 4 Column:f
Reflects actual demands of control area load at time of Transmission System Peak.
¡Schedule Page: 400 Line No.: 4 Column: g
Reflects reservations in OASIS at time of Trasmission S stem Peak.
chedule Pa e: 400 Line No.: 4 Column: i
Reflects reservations in OASIS at time of Transmission S stem Peak.
chedule Pa e: 400 Line No.: 5 Column:d
PDT
¡Schedule Page: 400 Line No.: 6 Column: d
PDT
lSchedule Page: 400 Line No.: 7 Column: d
PDT
¡Schedule Page: 400 Line No.: 8 Column: e
Refer to footnote for line 4 column ( e).
¡Schedule Page: 400 Line No.: 8 Column: f
Refer to footnote for line 4 column (t).
ISchedule Page: 400 Line No.: 8 Column: g
Refer to footnote for line 4 colum (g).
lSchedule Page: 400 Line No.: 8 Column: i
. Refer to footnote for line 4 colum i.
chedule Pa e: 400 Line No.: 9 Column: d
PDT
¡Schedule Page: 400 Line No.: 10 Column: d
PDT
lSchedule Page: 400 Line No.: 11 Column: d
PDT
lSchedule Page: 400 Line No.: 12 Column: e
Refer to footnote for line 4 column (e).
lSchedule Page: 400 Line No.: 12 Column: f
Refer to footnote for line 4 colum ( .
chedule Pa e: 400 Line No.: 12 Column:
Refer to footnote for line 4 column (g).
lSchedule Page: 400 Line No.: 12 Column: i
Refer to footnote for lineA colum i.
Schedule Pa e: 400 Line No.: 13 Column: d
PDT
lSchedule Page: 400 Line No.: 14 Column: d
PST
lSchedule Page: 400 Line No.: 15 Column: d
PST
¡Schedule Page: 400 Line No.: 16 Column: e
Refer to footnote for line 4 colum (e).
I
I
I
I
I
I
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp i2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Column: f
Column:
Column: i
I FERC FORM NO.1 (ED. 12-87)Page 450.2
Name of Respondent
PacifiCorp
This ~ort Is:
(1) ~An Original
(2) A Resubmission
ELECTRIC ENERGY ACCOUNT
Date of Report
(Mo, Da, Yr)
04/18/2011
Year/Period of Report
End of 2010/Q4
Line
No.
Item
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
(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)
r¡...'?!% %%i~~1f a/!ÆYí4
......"¡i~ /j~.t.../Æ #g/$/ xW;
Line
No.
Item MegaWatt Hours
(b)
." ...iI.'ø ,.. l
.Æi wx; ;;.::;;
53,015,534
220,852
11,193,740
4,387,423
68,960,127
FERC FORM NO.1 (ED. 12-90)Page 401a
(a)
21 DISPOSITION OF ENERGY
22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
23 Requirements Sales for Resale (See
instructon 4, page 311.)
24 Non-Requirements Sales for Resale (See
instrcton 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 '00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/18/2011
MONTHLY PEAKS AND OUTPUT
1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
2. Report 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 associated with the sales.
4. Report in column (d) by month the system's monthly maximum megawatt load (60 minute integration) associated with the system.
5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
NAME OF SYSTEM:
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 6,184,473 1,076,008 8,152 7 1800 PST
30 February 5,381,058 878,419 8,002 22 0800 PST
31 March 5,638,659 985,758 7,574 9 1900 PST
32 April 5,371,748 1,034,439 7,264 6 0900 PDT
33 May 5,510,114 1,091,408 7,092 6 0800 PDT
34 June 5,488,340 800,018 8,824 28 1700 PDT
35 July 6,264,414 759,612 9,398 27 1600 PDT
36 August 6,053,365 783,730 9,418 16 1600 PDT
37 September 5,428,087 866,699 8,168 3 1700 PDT
38 October 5,498,485 898,230 7,426 1 1600 PDT
39 November 5,777,818 924,018 8,592 23 1800 PST
40 December 6,363,566 1,095,401 8,402 29 1800 PST
41 TOTAL 68,960,127 11,193,740
FERC FORM NO.1 (ED. 12-90)Page 401b
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 401 Line No.: 26 Column: b
For metered locations only.
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) ~An Original (Mo, Da, Yr)2010/Q4
(2)DA Resubmission 04/18/2011 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 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facilty.4. If net peak demand for 60 minutes is not available, give data which is available, 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: Carbon Name: "~~~AA
(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 Originally 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)175 397
7 Plant Hours Connected to Load 8750 7834
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 69 0
12 Net Generation, Exclusive of Plant Use - KWh 1296004000 2621160000
13 Cost of Plant: Land and Land Rights 956546 2468743
14 Structures and Improvements 15099265 58700214
15 Equipment Costs 103140699 459194385
16 Asset Retirement Costs 6587976 39000
17 Total Cost 125784486 520402342
18 Cost per KW of Installed Capacity (line 17/5) Including 666.9379 1257.0105
19 Production Expenses: Oper, Supv, & Engr 45596 1808025
20 Fuel 20657109 51488605
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 1489090 6994684
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 2113830 1199979
26 Misc Steam (or Nuclear) Power Expenses 4334676 1936373
27 Rents 0 440
28 Allowances 0 0
29 Maintenance Supervision and Engineering .0 1881910
30 Maintenance of Structures 416124 411499
31 Maintenance of Boiler (or reactor) Plant 2448463 7201452
32 Maintenance of Electric Plant 1020130 783588
33 Maintenance of Misc Steam (or Nuclear) Plant 266812 2811384
34 Total Production Expenses 32791830 76517939
35 Expenses per Net KWh 0.0253 0.0292
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal rlJ Composite Coal Oil Composite
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)Tons Barrels Tons Barrels
38 Quantity (Units) of Fuel Burned 595236 1978 0 1461977 3855 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)11941 138000 0 9321 130414 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 33.592 103.502 0.000 32.778 93.395 0.000
41 Average Cost of Fuel per Unit Burned 34.360 103.502 0.000 34.972 93.395 0.000
42 Average Cost of Fuel Bumed per Millon BTU 1.439 17.858 1.452 1.876 17.051 1.888
43 Average Cost of Fuel Burned per KWh Net Gen 0.016 0.000 0.016 0.020 0.000 0.020
44 Average BTU per KWh Net Generation 10968.605 8.845 10977.450 10397.977 8.056 10406.033
FERC FORM NO. 1 (REV. 12-03)Page 402
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2011
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
End of 2010/Q4
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, 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-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 concerning plant type fuel used. fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.Plant Plant PlantName~ ~N.me D""Joh~
Sæam SæamConventional Outdoor Boiler1984 19791986 1980155.60 172.10156 1668759 8738o 0148 165o 0o 01192652000 12803720001355853 13708658269930 36555498158023784 13111755839236 35149217688803 1678452911399.0283 975.277723305 35960512505908 20249991o 0916378 1483108o 0o 030744 6402602096039 133260511536 984o 0244102 632833337249 4657032011204 4374004221939 1340513357053 90589318755457 317854990.0157 0.0248
Composite Coal Oil Composite
Tons Barrels
652589 116
9968 133693
29.993 121.915
30.910 121.915
1.550 21.714
0.016 0.000
10161.294 0.511
Coal
Tons
Oil
Barrels
968
140000
92.012
92.012
15.649
0.000
4.774
o
o
0.000
0.000
1.556
0.016
10161.805
734650
8432
14.581
16.902
1.002
0.010
10387.667
o
o
0.000
0.000
1.009
0.010
10392.441
Line
No.
Coal
Tons
3309283
7956
12.786
12.447
0.782
0.009
11204.623
1m
Barrels
41961
138000
99.452
99.452
17.159
0.001
51.749
Steam
Semi-Outdoor
1959
1972
816.80
739
8760
o
762
o
179
4699767000
10449793
136781636
720141128
11315101
878687658
1075.7684
571600
45364783
o
31079
o
o
o
17884777
37178
o
o
3141444
15993970
10163144
1078857
94266832
0.0201
Composite
o
o
0.000
0.000
0.858
0.010
11256.372
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
FERC FORM NO.1 (REV. 12-03)Page 403
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Onginal (Mo, Da, Yr)2010/Q4(2)DA Resubmission 04/18/2011 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 facility.4. If net peak demand for 60 minutes is not available, give data which is available, specifying penod.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:~~~~Name:~~
(a)
¡¡..
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)81.40 457.70
6 Net Peak Demand on Plant - MW (60 minutes)79 429
7 Plant Hours Connected to Load 8760 7027
8 Net Continuous Plant Capability (Megawatts)0 0
9 When Not Limited by Condenser Water 78 418
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 0 0
12 Net Generation, Exclusive of Plant Use - KWh 658624000 2572955000
13 Cost of Plant: Land and Land Rights 379735 9688975
14 Structures and Improvements 6012420 63087853
15 Equipment Costs 62566079 270326440
16 Asset Retirement Costs 532363 948199
17 Total Cost 69490597 344051467
18 Cost per KW of Installed Capacity (line 17/5) Including 853.6928 751.6965
19 Production Expenses: Oper, Supv, & Engr 230757 0
20 Fuel 12449623 35497583
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 983622 2817013
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 266648 0
26 Misc Steam (or Nuclear) Power Expenses 508004 1630831
27 Rents 0 3850
28 Allowances 0 0
29 Maintenance Supervision and Engineenng 300437 0
30 Maintenance of Structures 255415 2681686
31 Maintenance of Boiler (or reactor) Plant .915621 11140805
32 Maintenance of Electric Plant 358309 4518436
33 Maintenance of Misc Steam (or Nuclear) Plant 332185 165029
34 Total Production Expenses 16600621 58455233
35 Expenses per Net KWh 0.0252 0.0227
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Composite Coal Oil Composite
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)Tons Barrels Tons Barrels
38 Quantity (Units) of Fuel Burned 307335 254 0 1210133 8614 0
39 Avg Heat Cont - Fuel Bumed (btu/indicate if nuclear)11542 137377 0 11272 138000 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 38.449 104.561 0.000 0.000 0.000 0.000
41 Average Cost of Fuel per Unit Burned 40.342 104.561 0.000 28.601 0.000 0.000
42 Average Cost of Fuel Burned per Milion BTU 1.748 18.119 1.755 1.269 17.759 1.299
43 Average Cost of Fuel Burned per KWh Net Gen 0.019 0.000 0.019 0.013 0.000 0.013
44 Average BTU per KWh Net Generation 10771.255 2.225 10773.480 10603.331 19.405 10622.736
FERC FORM NO.1 (REV. 12-03)Page 402.1
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2010/Q4(2)OA Resubmission 04/18/2011 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electrc 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) accunting method for cost of power generated including any excess costs attbuted to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant tye fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant LineName:~Name:Hunter Unit No. 3 Name:~~ No.
(e)
¡¡.r-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
259 470 1132 6
7845 8321 8741 7
0 0 0 8
259 460 1137 9
0 0 0 10
0 0 212 11
1667003000 3296437000 7536395000 12
9688975 10275401 29653351 13
51968521 91113950 206170324 14
157360861 409450822 837138123 15
948199 948199 .2844597 16
219966556 511788372 1075806395 17
746.9153 1032.6642 862.1625 18
0 0 0 19
24501492 4372494 103724019 20
0 ~0 0 21
2809276 2805955 8432244 22
0 0 0 23
0 0 0 24
0 0 0 25
-2612326 3066567 2085072 26
3850 3850 11550 27
0 0 0 28
0 0 0 29
2408766 2140085 7230537 30
5719032 8712884 25572721 31
1407896 2127173 8053505 32
264114 316315 745458 33
34502100 62897773 155855106 34
0.0207 0.0191 0.0207 35
Coal Oil Composite Coal ""-Composite Coal Oil Composite 36. ~0'Ø mlßø",
Tons Barrels Tons Barrels Tons Barrels 37
830460 5116 0 1490676 9850 0 3531269 23580 0 38
11397 138000 0 11179 138000 0 11262 138000 0 39
0.000 0.000 0.000 0.000 0.000 0.000 29.640 103.202 0.000 40
28.875 0.000 0.000 28.645 0.000 0.000 28.684 103.202 0.000 41
1.267 17.612 1.292 1.281 17.947 1.310 1.273 17.806 1.302 42
0.014 0.000 0.014 0.013 0.000 0.013 0.013 0.000 0.013 43
11355.695 17.786 11373.481 10110.225 17.319 10127.54 10554.063 18.134 10572.197 44
FERC FORM NO.1 (REV. 12-03)Page 403.1
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) r!An Original (Mo, Da, Yr)2010/Q4(2)OA Resubmission 04/18/2011 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 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 Met.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 ~(a)(b)
Name: ~ c. ..
1 Kind of Plant (Intemal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor Boiler Semi-outdoor
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 1426
7 Plant Hours Connected to Load 8567 8754
8 Net Continuous Plant Capabilty (Megawatts)0 0
9 When Not Limited by Condenser Water 911 1412
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 163 335
12 Net Generation, Exclusive of Plant Use - KWh 6107379000 9833000000
13 Cost of Plant: Land and Land Rights 2386782 1161925
14 Structures and Improvements 115210321 139527507
15 Equipment Costs 689981960 890582328
16 Asset Retirement Costs 2342186 4557783
17 Total Cost 809921249 1035829543
18 Cost per KW of Installed Capacity (line 17/5) Including 813.1739 670.3964
19 Production Expenses: Oper, Supv, & Engr 25706 16396216
20 Fuel 86524665 171454601
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 8276929 4209728
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 0 5958
26 Misc Steam (or Nuclear) Power Expenses 10696874 -12919410
27 Rents 3311 263196
28 Allowances 0 0
29 Maintenance Supervision and Engineering 1346600 539711
30 Maintenance of Structures 2296785 8534063
31 Maintenance of Boiler (or reactor) Plant 13486036 23962462
32 Maintenance of Electric Plant 4313740 7817940
33 Maintenance ofMisc Steam (or Nuclear) Plant 1237313 2669801
34 Total Production Expenses 128207959 222934266
35 Expenses per Net KWh 0.0210 0.0227
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 2687375 12209 0 5450917 17766 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)11923 138000 0 9227 138000 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 32.847 105.056 0.000 32.259 93.298 0.000
41 Average Cost of Fuel per Unit Burned 31.719 105.056 0.000 31.150 93.298 0.000
42 Average Cost of Fuel Burned per Milion BTU 1.330 18.126 1.349 1.688 16.097 1.703
43 Average Cost of Fuel Burned per KWh Net Gen 0.014 0.000 0.014 0.017 0.000 0.017
44 Average BTU per KWh Net Generation 10492.431 11.587 10504.018 10229.994 10.472 10240.466
FERC FORM NO.1 (REV. 12-03)Page 402.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2010/Q4(2) DA Resubmission 04/18/2011 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Accunt Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Elecric Plant." Indicate plants.
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, 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 other physical and operating characteristics of plant.
Plant ~_t Line
Name: Naughton Name: Name:Gadsby Steam Plant No.
(d)(f)" . " "" ",
Steam Steam Steam 1
Outdoor Boiler Conventional Outdoor 2
1963 1978 1951 3
1971 1978 1955 4
707.20 289.70 251.60 5
708 278 194 6
8760 8025 1661 7
0 0 0 8
700 268 231 9
0 0 0 10
140 59 35 11
5339603000 2047508000 104123000 12
4290826 210526 1252090 13
69837827 50594075 15053899 14
370503279 281199857 63130224 15
11639026 490453 587008 16
456270958 332494911 80023221 17
645,1795 1147.7215 318.0573 18
192179 299719 97491 19
91410507 18768172 12131762 20
0 0 0 21
5648415 0 18 22
0 0 0 23
0 0 0 24
27718 0 0 25
10584401 4081592 3681887 26
1203 3041 0 27
0 0 0 28
1511638 5028 0 29
1441379 515248 209753 30
7944104 7060084 1788302 31
1500466 1683796 955412 32
1182830 289616 124725 33
121444840 32706296 18989350 34
0.0227 0.0160 0.1824 35
Coal -Composite Coal Oil Composite Gas 36
Tons MCF Tons Barrels MCF 0 0 37
2817478 247058 0 1537341 6245 0 1569575 0 0 38
9858 1029 0 7776 138000 0 ' 1049 0 0 39
32.477 7.083 0.000 11.858 98.961 0.000 7.729 0.000 0.000 40
31.823 7.083 0.000 11.806 98.961 0.000 7.729 0.000 0.000 41
1.614 6.886 1.638 0.759 17.074 0.784 7.369 0.000 0.000 42
0.017 0.000 0.017 0.009 0.000 0.009 0.117 0.000 0.000 43
10403.644 47.592 10451.236 11676.499 17.677 11694.176 15811.771 0,000 0.000 44
FERC FORM NO.1 (REV. 12.03)Page 403.2
Name of Respondent This l!0rt Is:-Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2010/Q4(2)DA Resubmission 04/18/2011 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. Indii:te 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 thal' 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 burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name: Litt/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)16 .244
7 Plant Hours Connected to Load 8150 8160
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 100773000 1595689000
13 Cost of Plant: Land and Land Rights 635 842245
14 Structures and Improvements 337028 12844996
15 Equipment Costs 5219987 156205792
16 Asset Retirement Costs 0 214373
17 Total Cost 5557650 170107406
18 Cost per KW of Installed Capacity (line 17/5) Including 347.3531 608.3956
19 Production Expenses: Oper, Supv, & Engr 0 0
20 Fuel 13355445 .58376865
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 971137 6473512
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 177184 0
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 14503766 64850377
35 Expenses per Net KWh 0.1439 0.0406
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 1822511 0 0 11617259 0 0
39 Avg Heat Cont - Fuel Bumed (btu/indicate if nuclear)1044 0 0 1015 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 7.328 0.000 0.000 5.025 0.000 0.000
41 Average Cost of Fuel per Unit Burned 7.328 0.000 0.000 5.025 0.000 0.000
42 Average Cost of Fuel Burned per Milion BTU 7.018 0.000 0.000 4.948 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.133 0.000 0.000 0.037 0.000 0.000
44 Average BTU per KWh Net Generation 18884.155 0.000 0.000 7393.052 0.000 0.000
FERC FORM NO.1 (REV. 12-03)Page 402.3
Name of Respondent This (!0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2010/Q4(2)OA Resubmission 04/18/2011 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 Contrl and Load
Dispatching, and Other Expenses Classifed as Oter 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 Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine 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 attbuted to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant tye fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant LineName:~~Name:~~Name:Chehalis No.
(f)
Y1
m
iw ft
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 28 516 6
8607 7000 3651 7
0 0 0 8
34 22 520 9
0 0 0 10
22 0 17 11
247359000 94061000 1288256000 12
41195596 0 1973791 13
7906027 5733734 23249210 14
68805675 28716806 317858946 15
1336278 0 689117 16
119243576 3450540 343771064 17
3129.7527 560.1714 579.4220 18
56831 0 191030 19
0 0 79197671 20
0 0 0 21
6726 0 0 22
3655727 0 0 23
0 0 0 24
0 7 2392798 25
1739984 0 0 26
6246 0 34243 27
0 0 0 28
0 0 0 29
225755 0 3045 30
164458 0 0 31
721856 505521 1285471 32
64240 0 0 33
6641823 505528 83104258 34
0.0269 0.0054 0.0645 35
Gas 36
MCF 37
0 0 0 0 0 0 9348871 0 0 38
0 0 0 0 0 0 1035 0 0 39
0.000 0.000 0.000 0.000 0.000 0.000 8.471 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.000 8.471 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.000 8.183 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.000 0.061 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.000 7512.959 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)2010/Q4
(2) DA Resubmission 04/18/2011 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 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: Gadsby Gas Peakers Name:Currant Creek
(a)(b)(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine Combined Cycle
2 Type of Constr (Conventional, Outdoor, Boiler, etc)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 NetPeak Demand on Plant - MW (60 minutes)124 567
7 Plant Hours Connected to Load 8760 8480
8 Net Continuous Plant Capabilty (Megawatts)0 0
9 When Not Limited by Condenser Water 120 550
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 0 19
12 Net Generation, Exclusive of Plant Use - KWh 255281000 2536660000
13 Cost of Plant: Land and Land Rights 0 3403277
14 Structures and Improvements 4241952 43827265
15 Equipment Costs 74726370 307413223
16 Asset Retirement Costs 0 134848
17 Total Cost 78968322 354778613
18 Cost per KW of Installed Capacity (line 17/5) Including 436.0482 625.8222
19 Production Expenses: Oper, Supv, & Engr 0 79852
20 Fuel 21345038 131063441
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Stearn From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 1314264 2617822
26 Misc Steam (or Nuclear) Power Expenses 0 0
27 Rents 0 874
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 184471 500930
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 2593345 1246435
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 25437118 135509354
35 Expenses per Net KWh 0.0996 0.0534
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 2903816 0 0 17850615 0 0
39 Avg Heat Cont - Fuel Bumed (btu/indicate if nuclear)1044 0 0 1059 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 7.351 0.000 0.000 7.342 0.000 0.000
41 Average Cost of Fuel per Unit Burned 7.351 0.000 0.000 7.342 0.000 0.000
42 Average Cost of Fuel Burned per Milion BTU 7.040 0.000 0.000 6.931 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.084 0.000 0.000 0.052 0.000 0.000
44 Average BTU per KWh Net Generation 11877508 0.000 0.000 7454.884 0.000 0.000
FERC FORM NO.1 (REV. 12-03)Page 402.4
Name of Respondent This 'mort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2010/Q4(2)OA Resubmission 04/18/2011 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchase Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of 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
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 attbuted 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 tye 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
581 0 0 6
7569 0 0 7
0 0 0 8
558 0 0 9
0 0 0 10
21 0 0 11
2537046000 0 0 12
17296760 0 0 13
27697517 0 0 14
306449096 0 0 15
0 0 0 16
351443373 0 0 17
594.3571 0.0000 0.0000 18
87746 0 0 19
129282273 0 0 20
0 0 0 21
0 0 0 22
0 0 0 23
0 0 0 24
2935756 0 0 25
0 0 0 26
0 0 0 27
0 0 0 28
0 0 0 29
552149 0 0 30
0 0 0 31
1952086 0 0 32
0 0 0 33
134810010 0 0 34
0.0531 .0.0000 0.0000 35
Gas 36
MCF 37
17932546 0 0 0 0 0 0 0 0 38
1030 0 0 0 0 0 0 0 0 39
7.209 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40
7.209 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41
7.002 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42
0.051 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43
7277198 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44
FERC FORM NO.1 (REV. 12-63)Page 403.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/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 100% of Unit NO.4 and 36.66% of common
facilities. Data reported in column (c) represents PacifiCorp's share. PacifiCorp does not have employees at the Cholla Plant.
Column: d
Column: e
Fuel oil is used for sta-uchedule Pa e: 402.1 Column: b
Hayden
The Hayden Plant is operated by Public Service Company of Colorado and is jointly owned. PacifiCorp owns a 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. Data reported in colum
(b) represents PacifiCorp's share. PacifiCorp does not have employees at the Hayden Plant.
Fuel oil is used for sta-uchedule Pa e: 402.1 Column: c
Hunter Plant Unit No.1
Hunter Plant Unit NO.1 is owned by PacifiCorp and Utah Municipal Power Agency with an undivided interest of93.75% and 6.25%,
respectively. Datareported 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 minority owners for the operation and maintenance (excluding fuel) of this unit
for calendar year 2010 were $1.9 million and were primarily 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 %, 25.1 08% 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 2010 were $7.1 million and were priarly charged to
account 506.
Fuel oil is used for star-uSchedule Pa e: 402.1 Column: f
Hunter
Hunter Unit NO.1 is owned by PacifiCorp and Utah Municipal Power Agency with an undivided interest of93.75% 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 of60.31%, 25.108% and 14.582%, respectively. Data in column (f) 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 calenda year 2010 were $9.0 milion and were priarly charged
to account 506.
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 04/18/2011 2010/Q4
FOOTNOTE DATA
Fuel oil is used for sta-uchedule Pa e: 402.2 Column: c
Jim Bridger
The Jim Bridger Plant is operated by PacifiCorp and is jointly owned by PacifiCorp and Idao Power Company with an undivided
interest of 662/3% and 33 113%, respectively. Data reported in colum (c) reresents 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 calenda year 2010 were $25.6 million and were priarily charged to account 506.
Fuel oil is used for sta-uchedule Pa e: 402.2 Column: e
Wyodak
The Wyodak Plant is operated by PacifiCorp and is jointly owned by PacifiCorp and Black Hils Corporation with an undivided
inteest of80% and 20%, respectively. Data in colum (e) 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 calendar year 2010 were $3.9 milion and were priarly charged to account 506.
Fuel oil is used for sta-uchedule Pa e: 402.3 Column: c
Hermiston
The Hermston Plant is operated by Hermiston Generatig Company, L.P. and is jointly owned. PacifiCorp owns a 50.0% share of the
Hermiston Plant. Data reported in colum (c) represents PacifiCorp's share. See Page 326 - Purchased Power of this Form NO.1 for
fuer information on Hermston Generati Com an , L.P. PacifCo does not have em loees at the Hermiston Plant.
chedule Pa e: 402.3 Line No.: -1 Column: d
Blundell
All or some of the renewable energy attibutes associated with generation from this generating facility may be: (a) used in futue years
to comply with renewable portolio stadards ("RPS") or other regulatory requirements or (b) sold to third pares in the form of
renewable ener credits or other environmental commodities.
chedule Pa e: 402.3 Line No.: -1 Column: e
Camas Co-Gen
PacifiCorp owns the steam tubine generator and associated systems directly related to the operation of this unit at Georgia-Pacific
Corporation's Camas, Washington paper mil. Modifications and upgrdes to the existing Camaspaper mil were necessary to supply
steam to the tubine and to ensure continued operation of the unit in the event of mill closure. Georgia-Pacific retained ownership of
these modifications. Georgia-Pacific supplies the fuel and delivers the steam to PacifiCorp's tubine. PacifiCorp is responsible for
major maintenance costs only on the repair of the tubine generator and auxilar 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 MilL.
All or some of the renewable energy attbutes associated with generation from this generating facility may be: (a) used in futue year
to comply with renewable portolio standards ("RPS") or other regulatory requirements or (b) sold to third parties in the form of
renewable energy credits or other environmental commodities. .
I$chedule Page: 402 Line No.: 36 Column: b2
Fuel oil is used for start~u u oses.
chedule Pa e: 402 Line No.: 36 Column: f2
Fuel oil is used for start-up puroses.
I$chedule Page: 402.1 Line No.: 36 Column: e2
Fuel oil is used for sta-up puroses.
I$chedule Page: 402.2 Line No.: 36 Column: b2
Fuel oil is used for start-up purposes.
I$chedule Page: 402.2 Line No.: 36 Column: d2
Natual gas is used for start-up purposes.
IFERC FORM NO.1 (ED. 12-87)Page 450.2
Name of Respondent
PacifiCorp
Year/Period of ReportThis ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2011
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 facility, 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.
End of 2010/Q4
Line
No.
Item
(a)
FERC Licensed Project No. 2082
Plant Name: _".JI
FERC Licensed Project No. 2082
Plant Name: Ii ,. ii
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 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 14thru 19)
21 Cost per KW of Installed Capacity (line 20 / 5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation 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
22
8,445
1925
1925
27.00
27
8,442f/// ¡r:ci: .".//.. '''"''/ft/,/W'..J .)14
28
28
1
67,544,000
34
34
2
88,801,000l/:~~ W'/ .~JI VJ__-."..
180,375
1,605,323
2,645,475
5,157,577
105,42
o
9,694,192
484.7096
20,914
2,227,581
2,954,724
10,376,116
479,588
o
16,058,923
594.7749
~Wji""Ø. .~l%;."""'j/j".; rirg /:.jjif;::~~~
56,118
o
731
o
810,982
296
23
6,721
107,335
34,707
31,315
1,048,228
0.0155
34,346
o
987
o
1,069,662
400
31
17,305
26,905
18,43
27,038
1,195,137
0.0135
FERC FORM NO.1 (REV. 12-03)Page 406
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmission 04/18/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescrbed by the Uniform System of Accunts. Producton Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Exnses 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.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
FERC Licensed Project No. 1927
Plant Name: * "m :":WJ ;:..
FERC Licensed Project No. 1927
Plant Name: r 1"_1 ..
Line
No.
1
Outdoor Outdoor 2
1953 1953 1927 3
1953 1953 1927 4
15.00 26.00 30.00 5
9 17 23 6
8,570 7,982 6,001 7:;.l$~i0~!~":&..~øt:~%7J1.".ml~/;tiwli! / _Jí~~~~
18 31 29 9
18 31 29 10
1 1 3 11
31,476,000 29,705,000 48,987,000 12_;ii ,:&.ii_, 7)b &. /iij ~¥JBA
o
1,222,452
4,547,301
1,188,143
52,034
o
7,009,930
467.3287
o
1,632,875
14,757,082
1,624,689
250,151
o
18,264,797
702.4922
3,505,129 14
3,969,184 15
7,485;343 16
14,550,291 17
572,059 18
o 19
30,082,006 20
1,002.7335 21j//.'_~;.í~.~íl'_~_i1"_"
-10,077 -7,877 -28,846 23
7,953 13,786 0 24
59,664 103,417 39,382 25
0 0 0 26
300,090 518,109 759,667 27
337 584 0 28
17 30 0 29
47,860 46,455 3,663 30
25,264 57,255 40,533 31
22,337 130,785 8,822 32
45,805 74,692 217,199 33
499,250 937,236 1,040,420 34
0.0159 0.0316 0.0212 35
FERC FORM NO.1 (REV. 12.(3)Page 407
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2011
HYDROELECTRIC GENERATING PLANT STATISTI.CS (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.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
Line
No.
Item
(a)
FERC Licensed Project No. 1927
Plant Name: ~~FERC Licensed Project No. 20
Plant Name: 1J m" .
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 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 20 /5)
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation 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
5,825
1908
1923
33.00
30
7,468
..c&~~..i:0 " ..:..j~::_
10
10
1
37,477,000
33
33
3
63,490,000.; ri:.. /07 _f_ i:/" ~jE/':.
o
914,418
12,176,260
1,791,282
533,015
o
15,414,975
1,401.3614
62,169
1,667,210
9,208,496
4,271,582
94,793
o
15,304,250
463.7652..glliøj",:i:r"-~Y/ß.!~"'~!..".
-12,286
5,832
43,753
o
298,775
247
13
29,386
43,522
31,376
32,252
472,870
0.0126
-335,332
o
49,460
o
1,678,486
257
o
31,126
299,114
72,032
117,051
1,912,194
0.0301
FERC FORM NO.1 (REV. 12-03)Page 406.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This Report Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2011
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 Accunts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expnses 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. 2082
Plant Name: r "ID'~FERC Licensed Project No. 2082
Plant Name:
FERC Licensed Project No. 1927 LinePlant Name: "!"~ % _ ~ No.
1
Outdoor Outdoor Outdoor 2
1962 1958 1955 3
1962 1958 1955 4
18.00 97.98 31.99 5
18 83 30 6
8,458 5,336 8,239 7
"" .~:ß w~!.~!..##~...: '%i~#~/;;0% ~1&~;; .""_.~
19 83 32 9
19 83 32 10
1 2 1 11
96,256,000 193,133,000 111,394,000 12
.~.?~~i'7 ///#0 #// " % ¡ø.i% # Vi /wAdØPÁ ø ¥r8tÆ#l..ÁIi~i0;ø_;,.g¡Jii.
341,706 26,277 0 14
4,614,730 2,873,701 2,114,257 15
13,091,301 14,155,361 15,131,501 16
2,404,786 14,890,342 5,896,348 17
1,076,116 886,710 475,419 18
0 0 0 19
21,528,639 32,832,391 23,617,525 20
1,196.0355 335.0928 738.2784 21.,... 00~~"tf":X?00yø'",_i0"'.'~'''_~.'~
367;234
o
658
o
769,556
267
18
639,872
52,214
67,152
18,025
1,914,996
0.0199
298,124
o
3,581
o
657,449
298
112
15,64
32,677
31,089
70,419
1,109,393
0.0057
-46,461 23
16,962 24
127,243 25
o 26
654,914 27
718 28
37 29
84,758 30
80,793 31
139,175 32
158,417 33
1,216,556 34
0.0109 35
FERC FORM NO.1 (REV. 12-03)Page 407.1
Name of Respondent
PacifiCorp
YearlPeriod of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmission 04/18/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Largè 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
(a)
FERC Licensed Project No. 1927
Plant Name: ~_FERC Licensed Project No.
Plant Name: ll
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 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 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 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
1956
1956
33.00
34
8,404
1931
1958
136.00
151
8,670
.~dWg '".#"'!"~:~_;x ""â:'!
34
34
1
138,473,000
151
151
2
559,382,000
...,!.ilf. Y0000...00"..~.0 7?~.!i%","0 0 XC",, "'i'''.."0" 0 .._0/0.. \\ i. #x.-" "&.'00" 0 00 ~t.. ii..
o
3,268,622
22,631,929
11,742,273
1,879,245
o
39,522,069
1,197.6385
1,951,411
41,087,704
9,971,566
16,513,797
2,156,440
o
71,680,918
527.0656_"l~~'!"A)A~¥..""l?"~_"
-43,247
20,414
153,136
o
720,144
864
44
76,756
63,925
17,557
110,475
1,120,068
0.0081
970,245
20,085
587,098
o
1,132,153
24,077
o
18,363
80,444
89,947
257,490
3,179,902
0.0057
FERC FORM NO.1 (REV. 12-03)Page 406.2
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmission 04/1812011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accunts prescribed by the Unifomi System of Accunts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Exnses 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: . ~FERC Licensed Project No.
Plant Name: .
FERC Licensed Project No. 2630 Line
Plant Name: " .ø " "mØ ,. m No.
~;:.Ja=j _":i "._"j":_"f:i_
Conventional
1949
1950
42.50
43
8,298
1915
1920
30.00
25
8,752
Conventional
1928
1928
32.00
36
8,420
45
45
1
188,950,000
28
28
2
28,335,000
36 9
36 10
1 11
225,108,000 12%.~.~,:~"j'_l ,il"" ~ / ststJ;~._
0 36,698 105,168 14
2,210,324 1,406,986 2,946,404 .15
10,706,970 6,475,575 25,003,207 16
3,270,264 5,155,281 3,599,742 17
264,441 503,332 305,071 18
0 0 0 19
16,451,999 13,577,872 31,959,592 20
387.1059 452.5957 998.7373 21_ø :A0_ß.ßJ',~Nst_."!;:~"~~
-60,431 -314,475 212,037 23
22,535 0 20,803 24
169,047 44,963 2,826 25
0 0 0 26
725,356 983,833 685,121 27
954 233 2,706 28
49 0 37 29
68,552 18,692 46,539 30
79,036 0 129,919 31
129,613 71,597 20,553 32
121,953 118,567 50,833 33
1,256,664 923,410 1,171,374 34
0.0067 0.0326 0.0052 35
FERC FORM NO.1 (REV. 12-03)Page 407.2
Name of Respondent
PacifiCorp
YearlPeriod of Report
End of 2010/Q4
This Report Is: Date of Report
(1) (IAn Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2011
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 Licensed Project No.Plant Name: F~20..Line
No.
Item
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 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 20 1 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
Run-of-River
Outdoor
1951
1951
18.00
16
8,689
Storage
Conventional
1924
1924
14.00
9
6,085
_Aí:ladW:::VI& "Wr. wt........c. -'¥jJ
18
18
1
79,059,000
14
14
2
13,592,000: "0:¿... 7/".iísl z / l~.mi w7wi.dir: w...~....%Yi./~/0 ~,mi..i'~.~
0Wjin//yi ' v; w $Wl;:"", 0% 8m:0" _. ~ ~ r" ~~ Wør!dfE ?,:W ~ i.A 0' ;; MWG
o
1,802,822
5,671,411
1,365,045
16,778
o
8,856,056
492.0031
511,083
672,316
6,938,925
2,203,018
o
o
10,325,342
737.5244_.~;¡;:vr.:0';:";.!f:7878~
-30,085
9,544
71,596
o
384,354
404
21
39,094
31,844
9,878
52,146
568,796
0.0072
-134,734
o
20,983
o
558,071
109
o
7,959
-5; 189
27,677
43,766
518,642
0.0382
FERC FORM NO.1 (REV. 12-03)Page 406.3
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accunts or combinations of accunts prescrbe by the Uniform System of Accunts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1927
Plant Name: ~ l II"~
FERC Licensed Project No. 2111 FERC Licensed Project No. 2071PlantName:w p liìJ. PlantName:~Line
No.
,....j(._ji~l"%~¡!t% O% O%%:"7/ ;¡;r..~
Storage (Re-Reg)
Outdoor
1952
1952
11.00
12
8,670
Storage
Conventional
1958
1958
240.00
255
6,235
Storage 1
Conventional 2
1953 3
1953 4
134.00 5
164 6
6,339 7
o "WWtW0. '...11.- n~/0%.j(. WdÍ..'iil 2$.. ¡¡.II.j('!j!71f 0010 /" / %'%..'i.%../ %" .... v......iil
/ //./i¡ Y."'W$% "'JjJAk _.It.,.:I__iw%% ~2'/il / %"0 jil.J_~..wli... .,.
12
12
1
51,896,000
264
263
2
733,951,000
164 9
164 10
2 11
629,932,000 12
-.._iliJl;¡'''.J:%" % vllf&v %j(_
0 7,813,808 8,349,393 14
1,165,632 11,153,113 7,183,730 15
13,609,199 41,214,434 27,489,478 16
2,177,660 16,263,319 14,830,132 17
56,124 1,012,079 1,426,051 18
0 0 0 19
17,008,615 77,456,753 59,278,784 20
1,546.2377 322.7365 442.3790 21
-13,260 1,586,601 886,981 23
5,832 35,43 19,789 24
43,753 1,217,225 578,464 25
0 0 0 26
301,704 1,614,719 968,747 27
247 42,488 23,723 28
13 0 0 29
20,983 51,505 31,812 30
23,370 52,380 84,804 31
25,941 262,701 46,449 32
31,564 438,865 249,043 33
440,147 5,301,927 2,889,812 34
0.0085 0.0072 0.0046 35
FERC FORM NO.1 (REV. 12-03)Page 407.3
Name of Respondent
PacifiCorp
YearlPeriod of Report
End of 2010/Q4
. This Report Is: Date of Report
(1) I!An Original (Mo, Da, Yr)
(2) OA Resubmission 04/18/2011
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. 0
Plant Name: ~ m'" :&a ~
FERC Licensed Project No.
Plant Name:
o
(a)(c)
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 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 20 1 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 23thru 33)
35 Expenses per net KWh
Run-of-River
Conventional
1904
1922
10.30
9
8,740
0.00
o
o
o 0XAX 0lt. . '0_ CW¡¡ X07i7Æd0Alf/ X/ '" ";W......"'Y/ ..Flax """-70f 7/ iVdîÅ'å / !I:i _haM! /7 0 ffd&ff.0\ flk/~ %'/~ayJdi7l1j1
10
10
4
18,451,000
o
o
o
o.~¡ :. i._~::t¡;_00:_'.
o
368,652
529,217
31,914
12,641
o
942,424
91.4975
o
o
o
o
o
o
o
0.0000; /~/ :,....JI .. .'~ Ai /:;.1// .._£/#//1:..
-15,43
o
13,521
o
279,741
o
o
2,626
2,524
3,235
131,459
417,703
0.0226
o
o
o
o
o
o
o
o
o
o
o
o
0.0000
FERC FORM NO.1 (REV. 12-63)Page 406.4
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) OA Resubmission 04/18/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accunts prescribed by the Uniform System of Accunts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expnses 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 License Project No. 0
Plant Name:
Line
No.
(d)(e)
1
2
3
4
0.00 0.00 0.00 5
0 0 0 6
0 0 0 7r~EIl jlØ!::~i.:_..::EEf%~M")ii % // /%0 / 4"(_:~~
o
o
o
o
o
o
o
o
o 9
o 10
o 11
o 12.øl.~~~M.i.¿P// % ¿" ....iB~
,... _r~~w;tI~P0g:/ "ti' il.. M"E.'"_1IE¡¡ø_
o
o
o
o
o
o
o
0.0000
o
o
o
o
o
o
o
0.0000
o 14
o 15
o 16
o 17
o 18
o 19
o 20
0.0000 21
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. 12-03)Page 407.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 406 Line No.: -1 Column: b
Copco No.1
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
Klamath River system for the following projects at December 31,2010 was $74,117,782: Copco No.1, Copco No.2, East Side, Fall
Creek, West Side, IC Boyle, Iron Gate, Keno Regulatig Dam and Upper Klamath Lake.
All or some of the renewable energy attbutes associated with generation from this generatig facility may be: (a) used in futue year "
to comply with renewable portfolio standads or other regulatory requirements or (b) sold to third pares in the form of renewable
energy credits or other environmental commodities.
Refer to Note 13 of Notes to Financial Statements in this Form NO.1 for an update regarding hydroelectrc relicensing for
PacifiCo's Klamath h droelectrc s stem.
chedule Pa e: 406 Line No.: -1 Column: c
Copco No.2
Costs reported for this plant do not include signifcant 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
Klamath River system for the following projects at December 31,2010 was $74,117,782: Copco No.1, Copco No.2, East Side, Fall
Creek, West Side, IC Boyle, Iron Gate, Keno Regulating Dam and Upper Klamath Lake.
All or some of the renewable energy attbutes associated with generation from this generatig facility 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
energy credits or other environmental commodities.
Refer to Note 13 of Notes to Financial Statements in this Form NO.1 for an update regarding hydroelectrc relicensing for
PacifiCo's Klamathh' droelectrc s stem.
chedule Pa e: 406 Line No.: -1 Column: d
Clearwater No.1
Costs reportd for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
Nort Umpqua River system for the following projects at December 31, 2010 was $64,895,766: Lemolo No.1, Lemolo No.2,
Clearwater No.1, Clearater No.2, Toketee, Fish Creek, Soda Springs, Slide Creek and the Nort Umpqua Common Plant.
All or some of the renewable energy attbutes associated with generation from this generatig facility may be: (a) used in futue years
to comply with renewable portolio standards or other regulatory requirements or (b) sold to third partes in the form of renewable
ener credits or other environmental commodities.
Schedule Pa e: 406 Line No.: -1 Column: e
Clearwater No.2
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, 2010 was $64,895,766: Lemolo No.1, Lemolo No.2,
Clearater No.1, Clearater No.2, Toketee, Fish Creek, Soda Springs, Slide Creek and the Nort Umpqua Common Plant.
All or some of the renewable energy attbutes associated with generation from this generatig facility may be: (a) used in futue years
to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third partes in the form of renewable
ener credits or other environmental commodities.
chedule Pa e: 406 Line No.: -1 Column: f
Cutler
Costs reported for this plant do not include significant 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 December 31, 2010 was $963,138.
All or some of the renewable energy attbutes associated with generation from this generating facility may be: (a) used in futue years
IFERC FORM NO.1 (ED. 12-87) Page 450.1 I
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010104
FOOTNOTE DATA
Line No.: 1 Column: e
Line No.: -1 Column: b
All or some of the renewable energy attbutes associated with generation from this generatig facility may be: (a) used in futue year
to comply with renewable portolio standads or other regulatory requirements or (b) sold to third partes 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 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
Bear River system for the following projects at December 31, 2010 was $13,399,062: Grace, Oneida and Soda.
All or some of the renewable energy attbutes associated with generation from this generatig facility may be: (a) used in futue years
to. comply with renewable portfolio standards 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: d
Iron Gate
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
Klamth River system for the following projects at December 31,2010 was $74,117,782: Copco No.1, Copco No.2, East Side, Fall
Creek, West Side, JC Boyle, Iron Gate, Keno Regulating Dam and Upper Klamath Lake.
All or some of the renewable energy attbutes associated with genertion fromthis generatig facility 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
energy credits or other environmental commodities.
Refer to Note 13 of Notes to Financial Statements in this Form NO.1 for an update regarding hydroelectrc relicensing for
PacifiCo's Klamath h droelectrc s stem.
chedule Pa e: 406.1 Line No.: -1 Column: e
JC Boyle
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
Klamath River system for the following projects at December 31,2010 was $74,117,782: Copco No.1, Copco No.2, East Side, Fall
Creek, West Side, JC Boyle, Iron Gate, Keno Regulatig Dam and Upper Klamath Lake.
All or some of the renewable energy attbutes associated with generation from this generatig facility may be: (a) used in futue years
to comply with renewable portolio standards or other regulatory requirements or (b) sold to third paries in the form of renewable
energy credits or other environmental commodities.
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)
PacifCorp I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
Refer to Note 13 of Notes to Financial Statements in this Form No. i for an update regarding hydroelectrc relicensing for
PacifiCo 's Klamath h droelectrc s stem.
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 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, 2010 was $64,895,766: Lemolo No.1, Lemolo No.2,
Clearwater No.1, Clearwater No.2, Toketee, Fish Creek, Soda Springs, Slide Creek and the Nort Umpqua Common Plant.
Line No.: 1 Column: d
Line No.: 1 Column: e
Line No.: -1 Column: b
All or some of the renewable energy attbutes associated with generation from this generatig facility may be: (a) used in future years
to comply with renewable portfolio standards 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: c
Merwn
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, 2010 was $39,672,471: Merwin, Yale, and Swift No.1.
All or some of the renewable energy attbutes associated with generation from this generatig facility may be: (a) used in futue years
to comply with renewable portolio standards 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: d
Toketee
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are rècorded 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, 2010 was $64,895,766: Lemolo No.1, Lemolo No.2,
Clearater No.1, Clearwater No.2, Toketee, Fish Creek, Soda Springs, Slide Creek and the Nort Umpqua Common Plant.
All or some of the renewable energy attbutes associated with generation from this generating facility may be: (a) used in futue years
to comply with renewable portolio standads or other regulatory requirements or (b) sold to third paries in the form of renewable
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 04/18/2011 2010/Q4
FOOTNOTE DATA
.
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 intagible costs due to re1icensing and settlement, which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for re1icensing and settlement on the
Bear River system for the following projects at December 31, 2010 was $13,399,062: Grace, Oneida and Soda.
All or some of the renewable energy attbutes associated with generation from this generatig facility may be: (a) used in futue years
to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third partes 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 signifcant 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
Prospect Unit Nos. 1,2, and 4 at December 31,2010 was $6,987,430.
Line No.: 1 Column: d
Line No.: -1 Column: b
All or some of the renewable energy attbutes associated with generation from this generating facility may be: (a) used in futue years
to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third partes in the form of renewable
ener credits or other environmental commodities.
chedule Pa e: 406.3 Line No.: -1 Column: c
Soda
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
Bear River system for the following projects at December 31,2010 was $13,399,062: Grace, Oneida and Soda.
All or some of the renewable energy attbutes associated with generation from this generatig facility may be: (a) used in futue years
to comply with renewable portolio standards or other regulatory requirements or (b) sold to third pares 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 31,2010 was $64,895,766: Lemolo No.1, Lemolo No.2,
Clearater No.1, Clearwater No.2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
IFERC FORM NO.1 (ED. 12-S7) 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 04/18/2011 2010/Q4
FOOTNOTE DATA
All or some of the renewable energy attbutes associated with generation from this generating facility 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: 406.3 Line No.: -1 Column: e
Swift No.1
Costs reported for this plant do not include significant intagible costs due to relicensing and settlement, which are recorded inFERC
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 31,2010 was $39,672,471: Merwin, Yale, and Swift No. 1.
All or some of the renewable energy attbutes associated with generation from this generating facility may be: (a) used in futu 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 envionmental commodities.
Schedule Pa e: 406.3 Line No.: -1 Column: f
Yale
Costs reportd 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
Lewis River system for the following projects at December 31, 2010 was $39,672,471: Merwin, Yale, and Swift No. 1.
All or some of the renewable energy attbutes associated with generation from this generatig facility may be: (a) used in futue years
to comply with renewable portolio standards or other regulatory requirements or (b) sold to third pares in the form of renewable
energy credits or other environmental commodities.
¡Schedule Page: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 facilities which
PacifiCorp holds title.
All or some of the renewable energy attbutes associated with generation from this generatig facility may be: (a) used in futue years
to comply with renewable portfolio stadards or other regulatory requirements or (b) sold to third partes in the form of renewable
energy credits or other envionmental commodities.
I FERC FORM NO. 1 (ED. 12-87)Page 450.5
Name of Respondent
PacifiCorp
This Report Is: Date of Report
(1) (2An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
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 license from
the Federal Energy Regulatory Commission, or operated as a joint facilty, and give a concise statement of the facts in a fotnote. If licensed project, give
project number in footnote.
Line Net Generation Cost of PlantName of Plant ExcludingNo.Plant Use
(e)(f)
1917 6.85 4.9 22,728,000 8,910,187
1913 1.11 1.0 2,439,000 1,314,472
1910 4.15 4.6 32,262,000 7,207,761
1913 1.00
1913 13.70 15.0 .95,220,000 6,935,270
1957 2.81 2.8 17,206,000 1,795,497
1924 3.20 3.0 4,399,000 1,991,695
1903 2.20 2.0 11,086,000 1,365,095
1922 0.16 0.1 646,000 597,630
1896 2.00 1.2 6,03,000 5,237,598
1917 0.75 0.5 1,527,000 672,853
1983 1.73 1.3 3,232,000 2,802,615
1910 0.72 0.7 2,275,000 416,673
1897 5.00 4.0 15,484,000 10,807,561
1923 6.00 122,396
1912 3.76 4.6 22,455,000 1,731,817
1932 7.20 7.7 35,330,000 7,001,153
194 1.00 0.9 3,917,000 1,596,217
1926 0.80 0.5 1,542,000 933,993
1910 1.18 0.9 3,079,000 992,623
1895 1.00 1.2 5,587,000 1,607,647
1915 0.50 1,337,279
1920 0.50 0.3 1,130,000 875,122
1986 0.74 0.6 1,440,000 1,194,486
1921 1.10 1.0 7,925,000 2,833,031
1911 3.85 2.0 15,316,000 2,848,017
1908 0.60 0.6 288,000 468,574
7,500,010
3,847,005
15,446,611
Year/Period of Report
End of 2010/Q4
1917 -2,784,000 19,198,557-4.50 -3.0
2010 111.00 111.0 102,429,000 238,882,767
1999 32.62 32.6 93,145,000 37,037,356
39 Glenrock 2008 99.00 103.0 287,941,000 199,905,929
40 Glenrock III 2009 39.00 38.0 99,967,000 87,185,602
41 Rollng Hils 2009 99.00 99.0 252,669,000 201,242,950
42 Goodnoe Hils 2008 94.00 95.0 212,268,000 180,512,024
43 Leaning Juniper 1 2006 100.50 102.0 223,558,000 174,536,399
44 Marengo 2007 140.40 137.0 330,943,000 237,368,036
45 Marengo II 2008 70.20 68.0 165,475,000 128,127,213
46 Seven Mile Hil 2008 99.00 102.0 324,123,000 199,246,447
FERC FORM NO.1 (REV. 12-03)Page 410
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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 I-roduction Expenses Fuel Costs (in cents Line
Retire. Costs) Per MW Exc'l. Fuel i-uei Maintenance Kind of Fuel (per Milion Btu)
(g)(h)(i)ü)(k)(I)
No.
1
1,300,757 583,930 45,664 Water 2
1,184,209 148,628 17,542 Water 3
1,736,810 357,653 47,580 Water 4
4,817 2,459 Water 5
506,224 382,803 63,030 Water 6
638,967 266,477 26,623 Water ,7
622,405 309,345 5,827 Water 8
620,498 142,943 70,875 Water 9
3,735,188 32,978 7,685 Water 10
2,618,799 130,753 42,754 Water 11
897,137 42,609 26,682 Water 12
1,620,009 126,034 30,259 Water 13
578,713 58,114 39,669 Water 14
2,161,512 393,203 113,444 Water 15
20,399 74,593 7,778 Water 16
460,590 171,988 26,648 Water 17
972,382 398,584 299,515 Water 18
1,596,217 73,051 21,065 Water 19
1,167,491 43,449 18,605 Water 20
841,206 108,396 23,818 Water 21
1,607,647 117,470 40,962 Water 22
2,674,558 26,946 2,453 Water 23
1,750,244 47,377 160,866 Water 24
1,614,170 42,492 52,594 Water 25
2,575,483 25,876 40,600 Water .26.
739,745 239,831 48,364 Water 27
780,957 44,142 18,192 Water 28
14,745 3,605 29
318,425 27,325 30
31
32
33
-4,266,346 312,143 73,794 Water 34
35
36
2,152,097 583,645 1,996 Wind 37
1,135,19 1,919,055 Wind 38
2,019,252 1,494,484 316,402 Wind 39
2,235,528 365,258 120,223 Wind 40
2,032,757 1,043,021 305,182 Wind 41
1,920,341 2,142,887 487,584 Wind 42
1,736,681 2,526,331 45,278 Wind 43
1,690,656 5,295,498 49,266 Wind 44
1,825,174 1,386,749 24,633 Wind 45
2,012,590 1,877,605 168,426 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 2010/Q4
(2) OA Resubmission 04118/2011
GENERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal 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 a joint facilty, and give a concise statement of the facts in a footnote. If licensed project, give
project number in footnote.
Line Year .i~staii~ l,a~acity ~et I-eaK Net GenerationName of Plant Orig.Name Plate atin Demand Excluding Cost of Plant
No.Const.(In MW)(6~gjn.)Plant Use
(a)(b)(c)(e)(f)
1 Seven Mile Hil II 2008 19.50 19.0 67,722,000 41,819,719
2 High Plains 2009 99.00 98.0 257,349,000 219,300,133
3 McFadden Ridge I 2009 28.50 29.7 77,366,000 56,796,654
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 Report Is:Date of Report Year/Period of Report
PacifiCorp (1) (KAn Original (Mo, Da, Yr)End of 2010/Q4
(2) ¡=A Resubmission 04/18/2011
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 utilized 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 i:xpenses Fuel Costs (in cents LineRetire. Costs) Pèr MW Exc'l. Fuel i-uei Maintenance Kind of Fuel (per Millon Btu)
(g)(h)(i)ü)(k)(I)
No.
2,144,601 353,524 34,025 Wind 1
2,215,153 914,989 1,471,333 Wind 2
1,992,865 254,778 408,712 Wind 3
4
5
6
7
8
9
10
11
12
13
14.
15
16
17
18
19
20
21
22
23
24
25
i 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) 2Ç An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 410 Line No.: 1 Column: a
Common river system costs for the operation of these facilties ar allocated to each plant based upon the unit's name plate rating.
This footnote applies to all hydroelectrc generatig facilties with curent generation. All or some of the renewable energy attbutes
associated with generation from these generating facilities may be: (a) used in futue year to comply with renewable portolio
standads or other regulatory requirements or (b) sold to third pares in the form of renewable energy credits or other environmental
commodities.
I$chedule Page: 410 Line No.: 2 Column: a
Ashton
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 31, 2010 was $318,793.
chedule Pa e: 410 Line No.: 3 Column: a
Bend
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, 2010 was $125,903.
chedulePa e: 410 Line No.: 4 Column: a
Big Fork
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, 2010 was $535,284.
chedule Pa e: 410 Line No.: 5 Column: a
Cline FallsThe Cline Falls h droelectrc eneratin st 2010.
chedule Pa e: 410 Line No.: 6
Condit
In September 1999, a settlement agreement to remove the 14-MW Condit hydroelectrc facility was signed by PacifiCorp, state and
federal agencies and non-governental organizations. In early Februar 2005, the pares agreed to modify the settlement agreement,
establishing a total cost to decommssion not to exceed $21 milion, excluding inflation. In October 2010, the Washington Deparent
of Ecology issued a Clean Water Act 401 certficate, and in December 2010, the FERC issued a surender order for project
decommssioning. In Januar 2011, PacifiCorp fied a request for clarfication and rehearig of the surender order and a motion for
stay with the FERC. In April 2011, a motion for extension of time was filed with the FERC requestig that the FERC allow project
decommissioning to be delayed until 2012 as the FERC has not yet issued an order on PacifiCorp's request for rehearing on the
surender order. PacifiCorp wil consider a 2011 decommssioning provided: (a) the FERC issues an order on rehearing in April 2011
granting all ofPacifiCorp's rehearng requests; (b) PacifiCorp's contractor agrees to a later 'notice to proceed date;' (c) other paries
to the rehearing do not appeal the FERC's order; and (d) PacifiCorp can feasibly manage a 2011 decommissioning. Remaining
ermtt includes a Section404 ermit from the United States Ar Co s of En ineers.
chedule Pa e: 410 Line No.: 8 Column: a
East Side
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
Klamath River system for the following projects at December 31,2010 was $74,117,782: Copco No.1, Copco No.2, East Side, Fall
Creek, West Side, JC Boyle, Iron Gate, Keno Regulatig Dam and Upper Klamath Lake.
Refer to Note 13 of Notes to Financial Statements in this Form NO.1 for an update regardig hydroelectrc relicensing for
PacifiCorp's Klamath hydroelectrc system.
I§chedule Page: 410 Line No.: 9 Column: a
Fall Creek
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
Klamath River system for the following projects at December 31,2010 was $74,117,782: Copco No.1, Copco No.2, East Side, Fall
Creek, West Side, JC Boyle, Iron Gate, Keno Regulating Dam and Upper Klamath Lake.
Refer to Note 13 of Notes to Financial Statements in this Form NO.1 for an update regarding hydroelectrc relicensing for
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This Report is: ...Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
PacifiCorp's Klamath hydroelectrc system.
~chedule Page: 410 Line No.: 12 Column: a
Gunlock
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 31, 2010 was $40,050.
Schedule Pa e: 410 Line No.: 15 Column: a
Pioneer
Costs reportd 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 31,2010 was $109,275.
Schedule Pa e: 410 Line No.: 16 Column: a
Powerdale
In June 2003, PacifiCorp entered into a settlement agreement to decommission the 6-MW Powerdale hydroelectrc facility rather than
pursue a new license, based on an analysis of the costs and benefits of relicensing versus decommssioning. In 2007, the FERC
authorized PacifiCorp to cease generation at the facHity and approved PacifiCorp's proposed accountig entres to defer the remaining
net book value and any additional removal costs of the system as a regulatory asset. PacifiCorp. received approval from its state
regulatory commissions to defer and recover these costs. In April 2010, PacifiCorp initiated removal of the Powerdale dam and
associated system featues as stipulated in the FERC Surender Order. As of October 31, 2010, decommssioning activities, including
dam removal and site restoration, were completed.PacifiCorp wil monitor restored areas until early 2012 when the project land wil
be transfèrred to the Columbia Land Trust, Oregon Deparent of Fish and Wildlife and Hood River County. Removal costs for the
Powerdale da and associated system featues were approximately $4 milion, and additional monitorig costs are not expected to
exceed $1 milion.
The remainin costs in colum r resent land and e ui ment that will be trsferred or sold after the lant is decommssioned.
chedule Pa e: 410 Line No.: 17 Column: a
Prospect 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 at
Pros ect Unit Nos. 1,2, and 4 at December 31, 2010 was $6,987,430.
chedule Pa e: 410 Line No.: 18 Column: a
Prospect No.3
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 NO.3 at December 31, 2010 was
$78,412.
~chedule Page: 410 Line No.: 19 Column: a
Prospect No.4
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 at
Pros ect Unit Nos. 1,2, and 4 at December 31,2010 was $6,987,430.
Schedule Pa e: 410 Line No.: 21 Column: a
Snake Creek
In March 2011, PacifiCorp entered into an agreement for the sale of the Snake Creek hydroelectrc generatig facility with Heber
Light & Power Company. The sale wil close aftr all regulatory approvals have been obtained. PacifiCorp is in the process of filing
applications for approval of the sale with the Oregon Public Utility Commssion, California Public Utilities Commssion and
W omin Public Service Commssion.
chedule Pa e: 410 Line No.: 22 Column: a
Stairs
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 31, 2010 was $85,726.
chedule Pa e: 410 Line No.: 23 Column: a
St. Anthony
Licensed Pro'ect No. 2381 a licable to both Ashton and St. Anthon lants.
chedule Pa e: 410 Line No.: 27 Column: a
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 04/18/2011 2010/Q4
FOOTNOTE DATA
Weber
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, 2010 was $290,688.
chedulePa e: 410 Line No.: 28 Column: a
West Side
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
Klamath River system for the following projects at December 31, 2010 was $74,117,782: Copco No.1, Copco No.2, East Side, Fall
Creek, West Side, JC Boyle, Iron Gate, Keno Regulatig Dam and Upper Klamth Lake.
Column: a
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC
account 302, Frachises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
Klamath River system for the following projects at December 31, 2010 was $74,117,782: Copco No.1, Copco No.2, East Side, Fall
Creek, West Side, JC Boyle, Iron Gate, Keno Regulatig Dam and Upper Klamath Lake.
Column: a
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
Klamath River system for the following projects at December 31,2010 was $74,117,782: Copco No.1, Copco No.2, East Side, Fall
Creek, West Side, JC Boyle, Iron Gate, Keno Regulatig Dam and Upper Klamath Lake.
Column: a
All common roads, employee houses, control equipment,
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 31,2010 was $64,895,766: Lemolo No.1, Lemolo No.2,
Clearwater No.1, Clearater No.2, Toketee, Fish Creek, Soda S ri s, Slide Creek and the Nort Urn ua Common Plant.
chedule Pa e: 410 Line No.: 36 Column: a
This footnote applies to all wind-powered generating facilities. All or some of the renewable energy attbutes associated with
generation from these generating facilties may be: (a) used in futue year to comply with renewable portfolio stadads or other
re lato re uirements or (b) sold to third aries in the form of renewable ener credits or other environmental commodities.
chedule Pa e: 410 Line No.: 38 Column: a
Foote Creek
The Foote Creek wind-powered generating facility is operated by SeaWest Energy and owned by PacifiCorp and Eugene Water and
Electrc Board with an undivided interest of 78.79% and 21.21 %, respectively. Data reported in row 38 represents PacifiCorp's share.
IFERC FORM NO.1 (ED. 12-87)Page 450.3
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of Iin.es, 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 öf Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutilty Propert.
5. Indicate whether the 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 tye 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 ¡IUN \lni ~I Type of LENGJi ~ole Wiles)
(Indicate wliere ~Ilte sdD NumberNo.other than u dergroun Iines
60 cvcle, 30hase\Supporting report circuit miles)Of
un ::tructure unl:jtru~res Circuits~ To Operating Designed Structure of Line o Anot er(a) (b)(c)Desi8nated Line
(d)(e)f)(g)(h)1. PG&E ROUND MTN , CA 500.0e 500.00 SteelTower 47.00 1
2 KLAMATH CO-GEN , OR CAPTAIN JACK, OR 50D.e 500.00 Steel Tower 26.00 1
3 MERIDIAN, OR KLAMATH CO-GEN, OR 500.0e 500.00 Steel Tower 58.00 1
1~:'XONVIUE500'OR
500.Ö(500.00 Steel Tower .58.00 1
5',*''' ,. . ~ MERIDIAN, OR 500.0e 500.00 SteelTower 74:00 1
6 CAPTAIN JACK, OR MALIN, OR 500.0e 500.00 Steel Tower 7.00 1
7 MIDPOINT, OR I MALIN , OR soo.oe 500.00 Steel Tower 447.00 1
8 .ii' .. _Switchyard, MT 500.0e 500.00 Steel Tower 1.00 1
9 . .-*_ BROADVIEW A, MT 500.0e 500.00 SteelTower 112.00 1
10 .!W BROADVIEW B, MT 500.De 500.00 Steel Tower 116.00 1
11 "-" ".-TOWNSEND A, MT 500.0e 500.00 Steel Tower 133.00 1
12 .' .TOWNSEND B, MT 500.0e 500.00 Steel Tower 133.00 1
13 500 kV costs and expenses
14
15 Subtotal 500kV 1,212.00 12
16
17 BEN LOMOND, UT BORAH,ID 345.0(345.00 Wood- H 138.00 1
18 BEN LOMOND, UT CAMP WILLIAMS, UT 345.0e 345.00 Steel SP 70.00 1
19 BEN LOMOND, UT TERMINAL, UT 345.01 345.00 47.00 1
20 EMERY, UT CAMP WILLIAMS, UT 345.01 345.00 Steel Tower 121.00 1
21 CAMP WILLIAMS, UT MONA #3 ,UT 345.01 345.00 Wood- H 47.00 1
22 NINETY SOUTH, UT CAMP WILLIAMS #1, UT 345.0 345.00 Steel SP 11.00 1
23 CAMP WILLIAMS, UT MONA #1 ,UT 345.0(345.00 Wood - H 47.00 1
24 CAMP WILLIAMS, UT MONA #2 ,UT 345.0(345.00 SteelTower 47.00 1
25 SPANISH FORK, UT CAMP WILLIAMS, UT 345.0(345.00 35.00 1
26 TERMINAL, UT CAMP WILLIAMS #2,UT 345.0(345.00 Steel SP 26.00 1
27 TERMINAL, UT CAMP WILLIAMS, UT 345.0(345.00 23.00 1
28 EMERY, UT HUNTINGTON, UT 345.0(345.00 Wood-H 20.00 1
29 EMERY, UT SIGURD #1 , UT 345.0(345.00 Steel-H 7400 1
30 EMERY, UT SIGURD #2 , UT 345.0(345.00 Steel-H 75.00 1
31 FOUR CORNERS, NM PINTO, UT 345.0(345.00 Wood-H 101.00 1
32 GOSHEN,ID KINPORT,ID 345.0(345.00 Wood- H 41.00 1
33 HUNTINGTON, UT PINTO, UT 345.0(345.00 Wood-H 159.00 1
34 HUNTINGTON, UT SPANISH FORK, UT 345.0(345.00 Wood-H 78.00 1
35 TERMINAL, UT NINETY SOUTH, UT 345.0(345.00 SteelSP 16.00 1
36 TOTAL 16,015.00 767.00 250
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Oóginal (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
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 oHhe same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of 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 bok cost at end of year.
\,u:: I UI- LINe (InCIUae in \,oiumn OJ Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing óght-of-way)
Conductor
and Mateóal Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)0)(k)(I)(m)(n)(p)
.1852 ACSR 51/27 1
3-1272 ACSR 36/1 2
3-1272 ACSR 36/1 3
3-1272 ACSR 54/19 4
.1272 ACSR 54/19 5
-2250 AAC /91 6
-1272 ACSR 36/1 7
8
.
9
10
11
12
13,778,58 269,650,316 283,428,901 1,361,408 39,666 1,401,07'13
14
13,778,58 269,650,316 283,428,901 1,361,408 39,666 1,401,07'15
16
-954 ACSR54/7 17
-1272 ACSR 45/7 18
.1272 ACSR 45/7 19
.1272 ACSR 45/7 20
-954 ACSR 45/7 21
-1272 ACSR 45/7 22
-1272 ACSR 45/7 23
-954 ACSR 54/7 24
-1272 ACSR 45/7 25
-1272 ACSR 45/7 26
-1272 ACSR 45/7 27
.954 ACSR 54/7 28
-954 ACSR 54/7 29
-954 ACSR 54/7 30
-795 ACSR 45/7 .31
-795 ACSR 45/7 32
~-795 ACSR 45/7 33
~-1272 ACSR 45/7 34
1?1272 ACSR 45/7 35
165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,33~36
FERC FORM NO.1 (ED. 12-S7)Page 423
Name of Respondent This (!0rt Is:Date of Report 'l.er/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/18/2011
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
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 partíy 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 IUN
(Indicate w~~~Type of LErGJiH ~oie wiles)NumberIn t e sd 0No.other than u dergroun lines Of60 cvcle, 30hase)Supporting report circuit miles)
un ~If1ciure unr'lii:lh~res CircuitsFromToOperatingDesignedStructureof Line ofAl)ot erDesilRatedLine
(a)(b)(c)(d)(e)(g)(h)
1 MONA, UT SIGURD #1 , UT 345.0C 345.00 Steel Tower 69.00 1
2 MONA, UT SIGURD #2 , UT 345.0C 345.00 69.00 1
3 SIGURD, UT UT / NV BORDER, UT 345.0C 345.00 Wood. H 190.00 1
4 JIM BRIDGER, WY BORAH,ID 345.0C 345.00 Steel Tower 240.00 1
5 JIM BRIDGER, WY KINPORT,ID 345.0C 345.00 Steel Tower 234.00 1
6 MONA, UT HUNTINGTON, UT 345.0C 345.00 Steel Tower 60.00 1
7 CURRENT CREEK, UT MONA, UT 345.0C 345.00 Steel SP 1.00 1
8 CAMP WILLIAMS, UT MONA #4 ,UT 345.0C 345.00 Wood-H 5.00 42.00 1
9 BEN LOMOND, UT TERMINAL, UT 345.0C 345.00 SteelSP 47.00 1
10 BEN LOMOND, UT TERMINAL, UT 345.0C 345.00 47.00 1
11 BEN LOMOND,UT POPULUS,ID 345.0C 345.00 82.00 1
12 BEN LOMOND, UT POPULUS,ID 345.0C 345.00 Steel SP 86.00 1
13 90TH SOUTH, UT CAMP WILLIAMS #4, UT 345.0C 345.00 Steel SP 11.00 1
14 90TH SOUTH, UT CAMP WILLIAMS #3, UT 345.0C 345.00 11.00 1
15 345 kV costs and expenses
16
17 Subtotal 345kV 1,987.00 383.00 33
18
19 ANTELOPE, 10 ANACONDA, 10 230.0(230.00 Wood- H 76.00 1
20 ANTELOPE,ID LOST RIVER, 10 230.0(230.00 Wood- H 20.00 1
21 BEN LOMOND, UT NAUGHTON #1 , WY 230.0(230.00 Wood- H 88.00 1
22 BEN LOMOND, UT NAUGHTON #2 , WY 230.0 230.00 Wood- H 88.00 1
23 BIRCH CREEK, UT RAILROAD, WY 230.0 230.00 Wood.H 19.00 1
24 TREASURETON , ID BRADY,ID 230.0 230.00 Wood-H 66.00 1
25 GLEN CANYON, ÄZ SIGURD, UT 230.0 230.00 Wood- H 159.00 1
26 GONDER (ELY) , UT PAVANT, UT 230.0 230.00 Wood. H 98.00 1
27 NAUGHTON, WY TREASURETON , 10 230.0C 230.00 Wood- H 80.00 1
28 PAROWAN VALLEY, UT SIGURD, UT 230.0C 230.00 Wood- H 94.00 1
29 PAROWAN VALLEY, UT WEST CEDAR, UT 230.0C 230.00 Wood- H 26.00 1
30 PAVANT, UT SIGURD, UT 230.0C 230.00 Wood -H 43.00 1
31 ATLANTIC CITY, WY COLUMBIA GENEVA, WY 230.0C 230.00 Wood-H 1.00 1
32 PALISADES SS , WY BLUE RIM ,WY 230.0C 230.00 Wood- H 4.00 1
33 BUFFALO, WY CASPER, WY 230.0C 230.00 Wood- H 107.00 1
34 GOOSE CREEK, WY BUFFALO, WY 230.0C 230.00 Wood- H 43.00 1
35 WYODAK,WY BUFFALO, WY 230.0C 230.00 Wood-H 69.00 1
36 TOTAL 16,015.00 767.00 250
FERC FORM NO.1 (ED. 12-87)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 2010/Q4
(2) FiA Resubmission 04/18/2011
.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 porton 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 trans.rnission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are 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 book cost at end of year.
\,u;: I ut" LIN!: (inClUde in Column (j) 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 LineOther Costs Expenses Expenses (0)Expenses No.(i)ü)(k)(I).(m)(n)(p)
-795 ACSR 45/7 1
.954 ACSR 54/7 2
-954 ACSR 54/7 3
-1272 ACSR 45/7 4
-1272 ACSR 45/7 5
-954 ACSR 54/7 6
-954 ACSR 54/7 7
-954 ACSR 54/7 8
-1272 ACSR 45/7 9
-1272 ACSR 45/7 10
.1272 ACSR 45/7 11
.1272 ACSR 45/7 12
13.14
103,147,34,985,497,683 1,088,645,025 68,343 2,514,264 321,060 2,903,661 15
16
103,147,34,985,497,683 1,088,645,025 68,343 2,514,264 321,060 2,903,661 17
18
1272 ACSR 45/7 19
95 ACSR 45/7 20
-795 ACSR 26/7 21
-795 ACSR 26/7 22
54 ACSR 54/7 23
95 ACSR26/7 24
54 ACSR 45/7 25
95 ACSR 45/7 26
1272 ACSR 45/7 27
95 ACSR45/7 28
95 ACSR 45/7 29
95 ACSR 45/7 30
1272 ACSR 36/1 31
1272 ACSR 36/1 32
1272 ACSR 36/1 33
95 ACSR 26/7 34
1272 ACSR 36/1 35
165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,33!36
FERC FORM NO.1 (ED. 12-87)Page 423.1
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) !!An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/18/2011
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
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 \/ni r ar.i: ,(K\~)LENGJiH ~ole 'riles)
(Indicate wliere Type of ~nt e sero Number
No.other than u dergroun lines Of60 cvcle, 30hasel Supporting report circuit miles)
From
Un~ucIre °gf~~~1WJrs CircuitsToOperatingDesignedStructureof LineDesit;ated Line
(a)(b)(c)(d)(e)(g)(h)
1 JIM BRIDGER, WY DAVE JOHNSTON, WY 230.0(230.00 Wood- H 229.00 1
2 ROCK SPRINGS, WY JIM BRIDGER, WY 230.0(230.00 Wood-H 35.00 1
3 JIM BRIDGER, WY SPENCE, WY 230.0(230.00 Wood.H 149.00 1
4 BRIDGER PUMP, WY MANS FACE, WY 230.0(230.00 Wood-H 1.00 1~DAVEJOHNSTON ,WY 230.0(230.00 Wood-H 33.00 1
6 CASPER, WY RIVERTON, WY 230.0(230.00 Wood- H 110.00 1
7 DAVE JOHNSTON, WY SPENCE, WY 230.0(230.00 Wood- H 31.00 1
8 DAVE JOHNSTON, WY WYODAK, WY 230.0(230.00 Wood.H 70.00 1
9 MONUMENT, WY SHUTE CREEK, WY 230.0 230.00 Wood-H 13.00 1
10 FIREHOLE , WY MONUMENT, WY 230.0(230.00 Wood-H 49.00 1
11 ROCK SPRINGS, WY FLAMING GORGE, UT 230.0 230.00 Wood- H 55.00 1
12 YELLOWTAIL, MT GOOSE CREEK, WY 230.0 230.00 Wood. H 59.00 1
13 NAUGHTON, WY MONUMENT, WY 230.0C 230.00 Wood.H 30.00 1
14 ROCK SPRINGS, WY MONUMENT, WY 230.0C 230.00 Wood-H 41.00 1
15 RIVERTON, WY ROCK SPRINGS, WY 230.0C 230.00 Wood-H 118.00 1
16 RIVERTON, WY THERMOPOLIS, WY 230.0C 230.00 Wood- H 51.00 1
17 THERMOPOLIS, WY YELLOWTAIL, MT 230.0C 230.00 Wood. H 176.00 1
18 CHAPPEL CREEK, WY CRAVEN CREEK, WY 230.0C 230.00 Wood-H 30.00 1
19 CRAVEN CREEK, WY NAUGHTON, WY 230.0(230.00 Wood-H 16.00 1
20 CHAPPEL CREEK, WY JONAH GAS, WY 230.0(230.00 Wood-H 32.00 1
21 CHAPPEL CREEK, WY CHIMNEY BUTTE, WY 230.0(230.00 Steel-SP 14.00 6.00 1
22 MINERS, WY FOOTE CREEK, WY 230.01 230.00 Wood-H 39.00 1
23 POINT OF ROCKS, WY ROCK SPRINGS, WY 230.0(230.00 Wood-H.27.00 1
24 MONUMENT, WY CRAVEN CREEK, WY 230.0(230.00 Wood- H 20.00 1
25 WINDSTAR, WY GLENROCK WIND, WY 230.0(230.00 Wood- H 13.00 1
26 YAM SAY ,OR KLAMATH FALLS, OR 230.01 230.00 Wood-H 63.00 1
27 KLAMATH FALLS, OR MALIN, OR 230.01 230.00 Wood-H 35.00 1
28 LONE PINE, OR KLAMATH FALLS, OR 230.01 230.00 Wood-H 76.00 1
29 LONE PINE, OR MERIDIAN, OR 230.01 230.00 5.00 1
30 GRANTS PASS, OR DIXONVILLE LINE 72, OR 230.0 230.00 Wood. H 62.00 1
31 DIXONVILLE, OR RESTON BPA , OR 230.0(230.00 Wood-H 17.00 1
32 TAP TO HANNA, OR HANNA BPA , OR 230.0(230.00 Wood.H 9.00 1
33 DIXONVILLE 500 , OR DIXONVILLE 230 , OR 230.0(230.00 Wood. H 1.00 1
34 MERIDIAN, OR GRANTS PASS, OR 230.0(230.00 Wood.H 35.00 1
35 MERIDIAN, OR LONE PINE, OR 230.0(230.00 Steel SP 5.00 1
36 TOTAL 16,015.00 767.00 250
FERC FORM NO.1 (ED. 12-S7)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 2010/Q4
(2) DA Resubmission 04/18/2011
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line strcture 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 milesof the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accunted for, and accunts affcted. 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 book cost at end of year.
l;U:: I UI- LIN!: (inciucie in i;oiulln OJ Lanc,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)~nses No.(i)ü)(k)(I)(m)(n)(p)
1272 ACSR 4517 1
1272 ACSR 36/1 2
1272 ACSR 36/1 3
1272 ACSR 36/1 4
b.1272 ACSR 36/1 5
1272 ACSR 36/1 6
1272 ACSR 36/1 7
1272 ACSR 36/1 8
1272 ACSR 36/1 9
1272 ACSR 45/10
1272 ACSR 36/1 11
95 ACSR 2617 12
272 ACSR 36/1 13
1272 ACSR 36/1 14
1272 ACSR 36/1 15
1272 ACSR 36/1 16
1272 ACSR 36/1 17
954 ACSR 5417 18
954 ACSR 5417 19
1272 ACSR 4517 20
1272 ACSR 36/1 21
1272 ACSR 36/1 22
1272 ACSR 36/1 23
1272 ACSR 4517 24
1272 ACSR 4517 25
95 ACSR 2617 26
1272 ACSR 36/1 27
95 ACSR 2617 28
1272 ACSR 36/1 29
1272 ACSR 36/1 30
95 ACSR 2617 31
95 ACSR 2617 32
1272 ACSR 36/1 33
1272 ACSR 36/1 34
1272 ACSR 54/19 35
165,687,254 2,483,388,167 2,649,075,21 120,209 19,173,510 1,308,616 20,602,33 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 2010/Q4
(2) DA Resubmission 04/18/2011
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
ofthe 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 liuN
(Indicate wliere Type of LENGJiH ~ole Wiles)
hill t e Sd 0 NumberNo.other than u dergroun lines
60 cvcle, 30hase)Supporting report circuit miles)Of
From On ::trueture unf~~i~res CircuitsToOperatingDesignedStructureof Line o ot er
(a)(b)(c)Desilnated Line
(d)(e)(g)(h)
1 FAIRVIEW BPA , OR ISTHMUS, OR 230.0(230.00 Wood-H 12.00 1
2 TROUTDALE BPA , OR PGE GRESHAM, OR 230.0(230.00 Steel Tow 6.00 1
3 TROUTDALE BPA , OR LINNEMAN, OR 230.0(230.00 6.00 1
4 SWIFT No.1, WA SWIFT NO.2, WA 230.0(230.00 Wood- H 2.00 1
5 SWIFT NO.2, WA WOODLAND BPA SS , WA 230.0(230.00 Wood- H 23.00 1
6 FRY, OR BETHEL, OR 230.0(230.00 Wood- H 26.00 1
7 FRY, OR ALVEY, OR 230.0(230.00 Wood - H 45.00 1
8 ALVEY, OR DIXONVILLE, OR 230.0(230.00 Wood -H 59.00 1
9 HURRICANE, OR WALLA WALLA, WA 230.0(230.00 Wood-H 78.00 1
10 MCNARY BPA , WA WALLA WALLA, WA 230.0(230.00 Wood-H 56.00 1
11 WALLA WALLA, WA AVISTA LEWISTON, WA 230.0(230.00 Wood-H 45.00 1
12 WALLA WALLA, WA WANAPUM, WA 230.0(230.00 Wood- H 33.00 1
13 TALBOT, WA MARENGO, WA 230.0(230.00 Wood- H 8.00 1
14 UNION GAP, WA MIDWAY BPA, WA 230.0(230.00 Wood- H 39.00 1
15 WANAPUM ,WA POMONA, WA 230.0(230.00 Wood- H 37.00 1
16 POMONA,WA UNION GAP, WA 230.0(230.00 Wood. H 8.00 1
17 230 kV costs and expenses
18
19 Subtotal 230kV 3,302.00 17.00 68
20
21 ID / MT BORDER, ID GOSHEN,ID 161.01 161.00 Wood- H 90.00 1
22 ANTELOPE,ID GOSHEN,ID 161.01 161.00 Wood-H.45.00 1
23 BONNEVILLE, ID EAGLEROCK, ID 161.01 161.00 WoodSP 9.00 1
24 EAGLEROCK , ID SUGARMILL , ID 161.0 161.00 Wood SP 3.00 1
25 GOSHEN,ID GRACE,ID 161.0 161.00 Wood- H 57.00 1
26 GOSHEN,ID RIGBY,ID 161.0(161.00 Wood- H 31.00 1
27 GOSHEN,ID SUGARMILL , ID 161.0(161.00 WoodSP 17.00 1
28 SUGARMILL , ID RIGBY,ID 161.0(161.00 WoodSP 17.00 1
29 EAGLEROCK, ID GOSHEN,ID 161.0(161.00 Wood-H 12.00 1
30 YELLOWTAIL, MT RIMROCK, MT 161.0(161.00 Wood-H 46.00 1
31 RIGBY,ID JEFFERSON, ID 161.0(161.00 Wood SP 18.00 1
32 161 kV costs and expenses
33
34 Subtotal 161 kV 255.00 90.00 11
35
36 TOTAL 16,015.00 767.00 250
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 2010/Q4
(2) ¡=A Resubmission 04/18/2011
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 other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrngement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-wner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted 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 book cost at end of year.
~u:; i ui" LINE (Include in Column ü) 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)
1272 ACSR 36/1 1
54 ACSR 4517 2
00 ACSR 5417 3
54 ACSR 4517 4
54 ACSR 4517 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
1272 ACSR 36/1 11
272 ACSR 36/1 12
95 ACSR 2617 13
54 ACSR4517 14
1272 ACSR 36/1 15
1272 ACSR 36/1 16
12,220,71 332,924,488 345,145,201 6,699 4,553,238 360,603 4,920,54(17
18
12,220,71.:332,924,488 345,145,201 6,699 4,553,238 360,603 4,920,54C 19
20
50HH CU 17 21
97.5 ACSR 2617 22
54 ACSR4517 23
~ACSR4517 24
SOHH CU 17 25
97.5 ACSR 2617 26
97.5 ACSR 2617 27
97.5 ACSR 26/28
1272 ACSR 4517 29
56.5 ACSR 26/7 30
97.5 ACSR 2617 31
623,49(16,514,772 17,138,262 353,885 4,139 358,02¿32
33
623,49 16,514,772 17,138,262 353,885 4,139 358,02¿34
35
165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,33 36
FERC FORM NO.1 (ED. 12-87)Page 423.3
Name of Respondent This (!rt Is:Date of Report Year/Period of Report
PacifiCòrp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/18/2011
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, òr 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 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~~~Type of LENGJiH ~oie Wiles)Number~In t e sd 0
No.other than u dergroun lines
60 cycle, 3 phase)Supporting report circuit miles)Of
I un ::tructure ¡u~"9irres CircuitsFromToOperatingDesignedStructureof Line o not erDesllinatedine
(a)(b)(c)(d)(e)f)(9)(h)
1 WHEELON, ID AMERICAN FALLS, ID 138.0C 138.00 Wood- H 86.00 1
2 OQUIRRH. UT TOOELE, UT 138.0C 138.00 Wood.SP 21.00 1
3 OQUIRRH, UT KCC BARNEY, UT 138.0C 138.00 Wood-H 5.00 1
4 ANSCHTZ CO-GEN, WY RAILROAD, WY 138.0C 138.00 Wood- H 22.00 1
5 ANTELOPE, ID SCOVILLE #1 , ID 138.0C 138.00 Wood- H 1.00 1
6 ANTELOPE ,ID SCOVILLE #2 , ID 138.0C 138.00 Wood-H 1.00 1
7 ASHLEY, UT CARBON, UT 138.0C 138.00 Wood-H 92.00 1
8 ASHLEY, UT VERNAL, UT 138.0C 138.00 Wood-H 12.00 1
9 BEKER INDUST , ID THREEMILE KNOLL. ID 138.0C 138.00 Wood- H 4.00 1
10 BEN LOMOND, UT BRIGHAM CITY, UT 138.0C 138.00 Wood-H 14.00 1
11 BEN LOMOND, UT ELMONTE, UT 138.0C 138.00 Wood-H 14.00 1
12 BEN LOMOND, UT ELMONTE, UT 138.0C 138.00 Wood-H 13.00 1
13 BEN LOMOND, UT HONEYVILLE, UT 138.0C 138.00 22.00 1
14 BEN LOMOND, UT CLINTON. UT 138.0C 138.00 23.00 1
15 BEN LOMOND, UT ANGEL, UT 138.0C 138.00 Wood-SP 28.00 1
16 BEN LOMOND, UT W ZIRCONIUM, UT 138.0 138.00 Wood-SP 14.00 1
17 BEN LOMOND. UT WHEELON, UT 138.00 138.00 Steel Tower 42.00 1
18 BRIGHAM CITY, UT WHEELON, UT 138.00 138.00 Wood-H 24.00 1
19 CAMERON, UT PAROWAN, UT 138.0C 138.00 Wood-H 35.00 1
20 CAMERON, UT SIGURD, UT 138.0C 138.00 Wood- H 64.00 1
21 CARBON. UT HELPER, UT 138.0C 138.00 Wood-H 2.00 1
22 CARBON, UT HELPER. UT 138.0C 138.00 Wood-H 2.00 1
23 CARBON, UT SPANISH FORK, UT 138.0C 138.00 Steel Tower 54.00 1
24 CARBON. UT SPANISH FORK, UT 138.0C 138.00 52.00 1
25 THREEMILE KNOLL, ID GRACE #1 ,ID 138.0C 138.00 Wood.H 17.00 1
26 THREEMILE KNOLL, ID GRACE #2 ,ID 138.0C 138.00 Wood-H 17.00 1
27 THREEMILE KNOLL, ID MONSANTO 1 , ID 138.0C 138.00 Wood- H 2.00 1
28 THREEMILE KNOLL, ID MONSANTO 2 , ID 138.0(138.00 Wood-SP 2.00 1
29 PAINTER, WY CLEAR CREEK, WY 138.0 138.00 Wood-SP 5.00 1
30 COLUMBIA, WY MOUNDS SWRK , UT 138.0 138.00 Wood- H 7.00 1
31 COTTONWOOD, UT MCCLELLAND, UT 138.00 138.00 Wood-SP 6.00 1
32 COTTONWOOD, UT HAMMER, UT 138.00 138.00 Wood-SP 5.00 1
33 COTTONWOOD. UT SILVER CREEK, UT 138.0C 138.00 Wood-SP 29.00 1
34 CUTLER, UT WHEELON, UT 138.0C 138.00 Wood-SP 1.00 1
35 ENTERPRISE, UT MIDDLETON, UT 138.00 138.00 Wood-H 20.00 1
36 TOTAL 16.015.00 767.00 250
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 Oriinal (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/18/2011
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structre 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 porton thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are 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.
COSl ui- LIN!: (InCIUae 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 Expenses
(i)0)(k)(I)(m)(n)(0)(p)No.
050CUHD/12 1
95 ACSR 4517 2
95 ACSR 2617 3
95 ACSR 26/7 4
ß97.5 ACSR 26/7 5
ß97.5 ACSR 2617 6
ß97.5 ACSR 2617 7
ß97.5 ACSR 2617 8
95 ACSR 26/7 9
ß97.5 ACSR 26/7 10
95 ACSR 4517 11
95 ACSR4517 12
50 CUHD 112 13
95 ACSR 45/7 14
95 ACSR 4517 15
95 AAC 137 16
50 CUHD /12 17
95 ACSR 2617 18
97.5 ACSR 2617 19
97.5 ACSR 26/7 20
54 ACSR 5417 .21
56.5 ACSR 2617 22
10COMP 23
95 ACSR 2617 24
5OCUHD/12 25
1272 ACSR 4517 26
1272 ACSR 4517 27
1272 ACSR 45/7 28
95 ACSR 2617 29
66.8 ACSR 26/7 30
95AAC/37 .31
95AAC13 32
1397.5 ACSR 2617 33
1397.5 ACSR 26/7 34
1272 ACSR 4517 35
165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,33~36
FERC FORM NO.1 (ED. 12-87)Page 423.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04118/2011
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of Iin.es, 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 poíe 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
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~~~J Type of LENGJiH ~ole 'Piles)Number~In t e sd 0
No.other than u dergroun lines
60 cycle, 30hase)Supporting report circuit miles)Of
From I un :structure I unf::tru~tures CircuitsToOperatingDesignedStructureot Line o .Ao her
DeslltÏated Line
(a)(b)(c)(d)(e)(g)(h)
1 WEST CEDAR, UT ENTERPRISE VALLEY, UT 138.0C 138.00 Wood-H 33.00 1
2 EVANSTON, WY RAILROAD, WY 138.0C 138.00 Wood.SP 3.00 1
3 FRANKLIN, UT SMITHFIELD, UT 138.0C 138.00 Wood-SP 25.00 1
4 FRANKLIN, ID TREASURETON,ID 138.0C 138.00 Wood- SP 10.00 1
5 JORDAN, UT MCCLELLAND, UT 138.0C 138.00 Wood-SP 5.00 1
6 GADSBY, UT TERMINAL, UT 138.0C 138.00 Wood-SP 6.00 1
7 JORDAN, UT TERMINAL, UT 138.0C 138.00 Wood-SP 6.00 1
8 TIMP, UT HALE, UT 138.0C 138.00 Steel- SP 4.00 1
9 TRI-CITY , UT AMERICAN FORK, UT 138.0C 138.00 Steel- SP 14.00 1
10 ABAJO, UT PINTO, UT 138.0C 138.00 Wood-SP 44.00 1
11 ONEIDA,ID GRACE,ID 138.0C 138.00 Wood-H 19.00 1
12 TREASURETON , ID GRACE 103 , ID 138.0C 138.00 Steel Tower 25.00 1
13 TREASURETON , ID GRACE 104, ID 138.0C 138.00 25.00 1
14 NEBO, UT DRY CREEK, UT 138.0C 138.00 Wood -H 37.00 1
15 WESTFIELD, UT HIGHLAND, UT 138.0 138.00 Wood-H 42.00 1
16 TIMP, UT SPANISH FORK, UT 138.0 138.00 Wood-SP 23.00 1
17 HALE, UT TANNER, UT 138.00 138.00 Wood-H 7.00 1
18 MOUNDS SWRK , UT HELPER, UT 138.00 138.00 Wood-H 29.00 1
19 HONEYVILLE, UT WHEELON, UT 138.0C 138.00 14.00 1
20 HUNTINGTON, UT MCFADDEN, UT 138.0C 138.00 Wood- H 7.00 1
21 TERMINAL, UT KENNECOTT, UT 138.0C 138.00 9.00 1
22 KILN, UT NEBO, UT 138.0C 138.00 Wood-H 30.00 1
23 MCCLELLAND, UT MIDVALLEY, UT 138.0C 138.00 Wood-SP 6.00 1
24 MOUNDS SWRK , UT MOAB, UT 138.0C 138.00 Wood-H 83.00 1
25 MOAB, UT PINTO, UT 138.0C 138.00 Wood-H 68.00 1
26 NAUGHTON, WY NGPL, WY 138.0C 138.00 Wood- H 35.00 1
27 NAUGHTON, WY PAINTER, WY 138.0C 138.00 Wood-H 45.00 1
28 NGPL, WY TAP TO STR204 , WY 138.0(138.00 Wood-H 12.00 1
29 NGPL, WY WHITNEY, WY 138.0(138.00 Wood- H 1.00 1
30 NINETY SOUTH, UT OQUIRRH, UT 138.0 138.00 Wood-SP 10.00 1
31 TAYLORSVILLE, UT NINETY SOUTH, UT 138.00 138.00 Wood-SP 7.00 1
32 MID VALLEY, UT NINETY SOUTH, UT 138.00 138.00 Wood-H 13.00 1
33 NUCOR STEEL, UT WHEELON, UT 138.00 138.00 Wood- H 10.00 1
34 ONEIDA,ID OVID,ID 138.0C 138.00 Wood- H 23.00 1
35 TREASURETON , ID ONEIDA ,ID 138.00 138.00 Wood-H 6.00 1
.
36 TOTAL 16,015.00 767.00 250
FERC FORM NO.1 (ED. 12-87)Page 422.5
Name of Respondent This 'ì0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) EjA Resubmission 04/18/2011
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line strcture 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 portion thereof for which the respondent is not the sole owner. If such propert is leased fr 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 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 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.
\,U::I nciuae in \,oiumri 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)
97.5 ACSR 26/7 1
95 ACSR 26/7 2
97.5 ACSR 26/7 3
95 ACSR 45/7 4
95AAC/37 5
1272 ACSR 45/7 6
1272AAC/61 7
.8
1272 ACSR 45/7 9
97.5 ACSR 26/7 10
5OCUHD/12 11
5OCUHD/12 12
50 CUHD /12 13
1272 ACSR 45/7 14
1272 ACSR 45/7 15
1272 ACSR 45/7 16
272 ACSR 45/7 17
97.5 ACSR 26/7 18
?50CUHD/12 19
397.5 ACSR 26/7 20
1795 ACSR 26/7 21
1397.5 ACSR 26/7 22
1795 ACSR 26/7 23
1397.5 ACSR 26/7 24
1397.5 ACSR 26/7 25
95 ACSR 26/7 26
1272 ACSR 45/7 27
95 ACSR 26/7 28
95 ACSR 26/7 29
1020 ACCCrrW BR.30
95AAC/37 31
1272 ACSR 45/7 32
95 ACSR 45/7 33
1336.4 ACSR 26/7 34
b50 CUHD /12 35
165,687,254 2,483,388,167 2,649,075,421 120,209 19,173,510 1,308,616 20,602,33~36
FERC FORM NO.1 (ED. 12-87)Page 423.5
Name of Respondent This (!0rt Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
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
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 (í~d1~~~~~~Type of LENGJiH ~ole Wiles)Number~Ilt e sdO
No.other than u dergroun lines Of60 cvcle 3 ohase)Supporting report circuit miles)
Ian ::trCtlJre I onf~tr~lmres CircuitsFromToOperatingDesignedStructureof. Line o Anot erDesip;ated Line
(a)(b)(c)(d)(e)(g)(h)
1 PAINTER, WY RAILROAD, WY 138.0C 138.00 Wood- H 7.00 1
2 PAROWAN, UT WEST CEDAR, UT 138.0C 138.00 Wood. H 21.00 1
3 TAP TO ANGEL SOUTH, UT TAP TO PARRISH, UT 138.0C 138.00 13.00 1
4 PARRISH, UT TERMINAL, UT 138.0C 138.00 SteelSP 16.00 1
5 PARRISH, UT TERMINAL, UT 138.0C 138.00 14.00 1
6 RAILROAD, WY WHITNEY, WY 138.0C 138.00 Wood- H 19.00 1
7 BEN LOMOND, UT SYRACUSE, UT 138.0C 230.00 Steel Tower 25.00 1
8 TERMINAL, UT ROWLEY, UT 138.0C 138.00 Wood-H 56.00 1
9 GREEN CANYON, UT WHEELON, UT 138.0C 138.00 Wood-SP 19.00 1
10 SPANISH FORK, UT TANNER, UT 138.0C 138.00 Wood- H 10.00 1
11 TAP TO ANGEL NORTH, UT TAP TO PARRISH, UT 138.0C 138.00 13.00 1
12 TERMINAL, UT MIDVALLEY, UT 138.0 138.00 Wood-H 7.00 1
13 TERMINAL, UT CENT 1 MIDVALLEY, UT 138.00 138.00 Steel-SP 7.00 1
14 TERMINAL, UT TOOELE, UT 138.00 138.00 Wood- H 35,00 1
15 WHEELON #103, UT TREASURETON , ID 138.00 138.00 SteelTower 29.00 1
1.6 WHEELON #104 , UT TREASURETQN , ID 138.00 138.00 29.00 1
17 WHEELON #105 , UT TREASURETON,ID 138.00 138.00 Wood- H 29.00 1
18 KCC BARNEY, UT KCCGRIND , UT 138.00 138.00 Wood-H 1.00 1
19 TERMINAL, UT LAKE PARK, UT 138.0C 138.00 Wood-H 14.00 1
20 OQUIRRH, UT KCC BINGHAM, UT 138.0(138.00 Wood- H 8.00 1
21 WEST CEDAR, UT THREE PEAKS, UT 138.0C 138.00 Wood-SP 20.00 1
22 HALE, UT SPANISH FORK, UT 138.0C 138.00 Wood.H 18.00 1
23 MID VALLEY, UT TAYLORSVILLE, UT 138.0(138.00 Wood-SP 5.00 1
24 PARRISH, UT TERMINAL, UT 138.0C 138.00 Steel- SP 14.00 1
25 COLUMBIA, UT SUNNYSIDE, UT 138.138.00 Wood-H 2.00 1
26 JERUSALM , UT NEBO, UT 138.0C 138.00 Wood-H 26.00 1
27 HALE, UT MIDWAY, UT 138.0C 138.00 Wood- H 19.00 1
28 DIMPLE DELL, UT DUMAS, UT 138.0C 138.00 U/G 4.00 1
29 HONEYVILLE, UT LAMPO, UT 138.0C 138.00 Wood- H 25.00 1
30 GADSBY, UT JORDAN, UT 138.0C 138.00 Wood-SP 1.00 1
31 MID VALLEY, UT COTTONWOOD, UT 138.0C 138.00 Wood-SP 5.00 1
32 NINETY SOUTH, UT SANDY, UT 138.0C 138.00 Steel-SP 1.00 1
33 MICRON, UT CAMP WILLIAMS, UT 138.0C 138.00 9.00 1
34 MCFADDEN, UT BLACKHAWK, UT 138.0C 138.00 Wood-H 11.00 1
35 NINETY SOUTH, UT QUARRY SUBSTATION, UT 138.0C 138.00 Wood-SP 8.00 1
36 TOTAL 16,015.00 767.00 250
FERC FORM NO.1 (ED. 12-87)Page 422.6
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line strcture 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 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 resondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and 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 cot at end of year.
COST v, ..11... i,nclude 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)0)(k)(I)(m)(n)(p)
1272 ACSR 4517 1
97.5 ACSR 2617 2
95AAC/37 3
95 ACSR4517 4
95 ACSR 2617 5
95 ACSR2617 6
95AAC/37 7
95AAC/37 8
36.4 ACSR 2617 9
1272 ACSR 4517 10
95AAC/37 11
272 ACSR 4517 12
1272 AAC /61 13
10 ACSR 6/1 14
50CUHD/12 15
50CUHD/12 16
5OCUHD/12 17
95 ACSR 2617 18
1557.4 ACSRf 19
97.5 ACSR 2617 20
95 ACSR 2617 21
1272 ACSR 4517 22
1272AAC/61 23
95 ACSR4517 24
97.5 ACSR 2617 .25
97.5 ACSR 2617 26
97.5 ACSR 2617 27
1750 KCMIL 28
1397.5 ACSR 26/7 29
1272AAC/61 30
1557.4 ACSRf 31
1795AAC/37 32
95 ACSR 26/7 33
95 ACSR 2617 34
95AAC/37 35
165,687,254 2,483,388,167 2,649,075,421 120,209 19,17,5101 1,308,616 20,602,33!36
FERC FORM NO.1 (ED. 12-87)Page 423.6
Name of Respondent This ~Qr Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of Iin.es, 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. Tránsmission 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 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 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 strctures 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.
LENGJiH ~oie Wiles)Line (Indicate wliere Type of ~In t e sd 0 NumberNo.other than u dergroun lines Of60 cvcle 3 phase)Supporting report circuit miles)
From To Operating Designed
un qtri,cture ugf~~~lliUJrs CircuitsStructureof Line Desilinated Line(a)(b)(c)(d)(e)f)(g)(h)
1 EL MONTE, UT STR30B, UT 138.0C 138.00 Steel- SP 4.00 1
2 EL MONTE, UT PIONEER, UT 138.0C 138.00 Steel- SP 1.00 1
.3 SYRACUSE, UT CLEARFIELD SOUTH, UT 138.0C 138.00 Steel.SP 1.00 1
4 MID VALLEY, UT COTTONWOOD, UT 138.0C 138.00 Steel-SP 5.00 1
5 HAMMER, UT BUTLERVILLE, UT 138.0C 138.00 2.00 1
6 BUTLERVILLE, UT NINETY SOUTH, UT 138.0C 138.00 Steel.SP 9.00 1
7 KEARNS, UT TAYLORSVILLE, UT 138.0C 138.00 Wood-SP 2.00 1
8 SILVER CREEK SUB, UT JORDANELLE SUB, UT 138.0C 138.00 Steel- SP 10.00 1
9 KEARNS, UT WEST VALLEY, UT 138.0C 138.00 Wood-SP 2.00 1
10 RIVERDALE, UT 105 TAP, UT 138.0C 138.00 Steel-SP 21.00 1
11 OQUIRRH, UT SUNRISE / TRI-CITY, UT 138.0C 138.00 Steel-SP 21.00 1
12 OQUIRRH, UT BANGERTER / TRI-CITY, UT 138.0C 138.00 23.00 1
13 DYNAMO, UT TRI-CITY #2 , UT 138.0C 138.00 5.00 1
14 TIMP#2, UT DYNAMO, UT 138.0C 138.00 4.00 1
15 MIDDLETON, UT ST. GEORGE, UT 138.0C 138.00 Wood- H 1.00 1
16 BRIDGERLAND , UT GREEN CANYON, UT 138.0C 138.00 Steel-SP 16.00 1
17 SYRACUSE, UT PARRISH, UT 138.0C 230.00 Steel Tower 12.00 1
18 BONANZA, UT CHAPITA, UT 138.0C 138.00 Wood- H 8.00 1
19 CENTRAL, UT SAINT GEORGE #1, UT 138.0C 345.00 Steel- SP 20.00 1
20 CENTRAL, UT SAINT GEORGE #2, UT 138.0C 345.00 Steel- SP 20.00 1
21 EBAYTAP, UT OQUIRRH, UT 138.0C 138.00 Steel-SP 1.00 1
22 138 kV costs and expenses
23 .
24 Subtotal 138 kV 1,945.00 27700 126
25
26
27 All 115 kV Lines 1,613.00
28 All 69 kV Lines 2,978.00
29 All 57 kV Lines 113.00
30 All 46 kV Lines 2,610.00
31
32
33
34
35
36 TOTAL 16,015.00 767.00 250
FERC FORM NO.1 (ED. 12-87)Page 422.7
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any trnsmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accunted for, and accnts 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- LINt: (inciuae in L;oiumn U) 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)
1272 ACSR 45/7 1
1272 ACSR 45/7 2
1272 ACSR 45/7 3
1557.4ACSRI 4
95 ACSR 26/7 5
95AAC13 6
95 ACSR 26/7 7
95 ACSR 26/7 8
1557.4 ACSRI 9
95 ACSR 26/7 10
1557.4 ACSRI 11
1557.4 ACSRI 12
-795 ACSR 26/7 13
1557.4 ACSRI 14
97.5 ACSR 26/7 15
1272 ACSR 45/7 16
1272 ACSR 45/17
95 ACSR 26/7 18
1272 ACSR 45/7 19
1272 ACSR 45/7 20
95 ACSR 26/7 21
17,348,20 282,541,903 299,890,106 24,825 1,839,250 144,824 2,008,89~22
23
17,348,20 282,541,903 299,890,106 24,825 1,839,250 144,824 2,008,89~24
25
26
4,086,73 151,293,779 155,380,512 2,280 3,526,193 233,226 3,761,69~27
6,375,731 230,690,274 237,066,005 8,920 2,702,093 161,990 2,873,OO~28
45,45 9,679,030 9,724,488 43,553 3,516 47,06~29
8,060,99 204,595,922 212,656,921 9,142 2,279,626 39,592 2,328,36C 30
31
.32
33
34
35
165,687,254 2,483,388,167 2,649,075,421 120,209 19,17,510 1,308,616 20,602,33e 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)!Ç An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
ISchedule Page: 422 Line No.: 1 Column: a
Certain transmission lines reported on pages 422-423 are part of exchange agreements with varous third pares. Refer to the
footnotes on pages 328-330 of this FERC form No.1 for fuer discussion.
ISchedule Page: 422 Line No.: 4 Column: a
The Alvey - Dixonvile 500kV line is jointly owned by the respondent and the Bonnevile Power Adminstrtion ("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 maintenance costs are shared between the two paries and responsibility is as follows: PacifiCorp 58.0% and the
BPA42.0%.
ISchedule Page: 422 Line No.: 5 Column: a
The Dixonvile - Meridian 500kV line is jointly owned by the respondent and the Bonnevile Power Administration ("the BPA").
Ownership of the line is as follows: PacifiCorp 50.0%, the BPA 50.0%. Cost reported for this line reflects the respondent's 50.0%
share. Operation and maintenance costs are shared between the two partes and responsibility is as follows: PacifiCorp 58.0% and the
BPA42.0%.
¡Schedule 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.
I$chedule Page: 422 Line No.: 9 Column: a I
The Colstrp - Broadview A 500kV line is jointly owned by the respondent, NortWester 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 cOl't 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, North Western Corporation, Puget Sound Power & Light,
Washington Water Power Company and Portland General Electrc. Owership ofthe 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, Nort Western Corporation, Puget Sound Power &
Light, Washington Water Power Company and Portland General Electrc. Ownership of the line is as follows: PacifiCorp 8.i %, all
others 91.9%. Plant cost and operation and maintenance costs reported for this line reflects the respondent's share.
I$chedule Page: 422 Line No.: 12 Column: a
The Broadview - Townsend B 500kV line is jointly owned by the respondent, NortWestern Corporation, Puget Sound Power &
Light, Washington Water Power Company and Portland General Electrc. Ownership of the line is as follows: PacifiCorp 8.1 %, all
others 91.9%. Plant cost and operation and maintenance costs reported for this line reflects the respondent's share.
I$chedule Page: 422.1 Line No.: 13 Column: i
2-1557.4 ACSR/TW 36/7
I$chedule Page: 422.1 Line No.: 14 Column: i
2-1557.4 ACSR/TW 36/7
¡Schedule Page: 422.2 Line No.: 5 Column: a I
A 1.5 mile segment of the Casper - Dave Johnston 230kV line is jointly owned by the respodent and Black Hils Power. Ownership of
the line is as follows: PacifiCorp 43.75%, Black Hils Power 56.25%. Plant cost and operation and maintenance costs reported for
this line reflects the respondent's share.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1)!Ç An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 422.5 Line No.: 8 Column: i
1557.4 ACSR/36/7
I FERC FORM NO.1 (ED. 12-87)Page 450.2
Name of Respondent This RePort Is:Date of Report Year/Period of Report
PacifCorp (1) (!An Original (Mo, Da, Yr)End of 2010/Q4
.(2) EiA Resubmission 04/18/2011
.TRANSMISSION LINES ADDED DURING YEAR
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 Line.IKUl,lUKc ~II ~ PER ~TRUCI URLerigth
No.From To In Type Number per Present Ultimate
Miles Miles
(a)(b)(c)(d)(e)(f)(g)~BEN LOMOND, UT 46.60 Steel- SP 9.00 2 2
2 BEN LOMOND, UT POPULUS, 10 85.70 Steel- SP 9.00 2 2
3 NINETY SOUTH, UT CAMP WILLIAMS, UT 10.80 Steel- SP 9.00 2 2~ST. GEORGE, UT 20.10 Steel- SP 8.00 2 2
S STR 169, UT THREE PEAKS, UT 6.40 Wood -SP 12.00 1 1
.. 6 SHIRLEY BASIN, WY DUNLAP WIND, WY 9.00 Wood - H 8.00 1 1
7
8
e .
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 178.60 55.00 10 1(
FERC FORM NO.1 (REV. 12-03)Page 424
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
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 columR (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.
IK~Voltage Line
Size Specification Conf~uration KV Land and Poles, Towers Conductors Asset Total No.
and pacing (Operating)Land Rights and Fixtures and Devices Retire. Costs
(h)(I)(j)(k)(I)(m)(n)(0)(p)
2-1272 ACSR Verleal27'34f 12,897,280 118,199,85f 29,549,96 160,647,099 1
2-1272 ACSR Verleal27'345 52,580,695 29,527,32'74,131,831 423,239,851 2
2-1557.4 ACSR Verleal27'34f 38,194 20,797,84C 5,199,460 26,383,494 3
2.1272 ACSR Verleal27'131 665,571 14,875,6(3,718,900 19,260,071 4
795 ACSR Verleal12'138 130,445 2,789,30 1,314,424 4,234,172 5
1272 ACSR Horizon 20'230 365,952 3,738,71 1,739,258 5,843,929 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
67,026,137 456,928,64,115,653,837 639,608,616 44
FERC FORM NO.1 (REV. 12-03)Page 425
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
!Schedule Page: 424 Line No.: 1 Column: a
PacifiCorp removed from service a 13-mile 230kV single-circuit transmission line between the Ben Lomond substation and the
Termal substation in Utah. In addition, PacifiiCorp removed from service a 13-mile 138kV single-circuit transmission line between
the Syracuse substation and the Terminal substation in Uta.
¡Schedule Page: 424 Line No.: 4 Column: a
PacifiCorp removed from service a 20. I-mile 138kV single-circuit transmission line between the Red Butte substation and the St.
George substation in Utah.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
"
Name of Respondent ThiS~rIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) A Resubmission 04/18/2011
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 distnbution and whether
attended or unattended. At the end of the page, summanze according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 California
2 BELMONT SUB DISTRIBUTION-UNATTEN 69.00 12.47
3 BIG SPRINGS SUB DISTRIBUTION-UNA TTEN 69.00 12.47
4 CANBY#2 DISTRIBUTION-UNATTEN 69.00 2.40
5 CASTELLA SUB DISTRIBUTION-UNA TTEN 69.00 2.40
6 CLEAR LAKE SUB DISTRIBUTION-UNA TTEN 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 GASQUET SUB DISTRIBUTION-UNA TTEN 115.00 12.47
11 GREENHORN SUB DISTRIBUTION-UNA TTEN 69.00 12.47
12 HAMBURG SUB DISTRIBUTION-UNATTEN 69.00 2.40
13 HAPPY CAMP SUB DISTRIBUTION-UNA TTEN 69.00 12.47
14 HORNBROOK SUB DISTRIBUTION-UNATTEN 69.00 12.47
15 INTERNATIONAL PAPER SUB DISTRIBUTION-UNATTEN 69.00 2.40
16 LAKE EARL SUB DISTRIBUTION-UNA TTEN 69.00 12.47
17 LITTLE SHASTA SUB DISTRIBUTION-UNA TTEN 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-UNA TTEN 69.00 12.47
21 MILLER REDWOOD SUB DISTRIBUTION-UNA TTEN 69.00 12.47
22 MONTAGUE SUB DISTRIBUTION-UNA TTEN 69.00 12.47
23 MORRISON CREEK SUB DISTRIBUTION-UNA TTEN 69.00 12.50
24 MOUNT SHASTA SUB DISTRIBUTION-UNA TTEN 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-UNA TTEN 69.00 2.40
29 PATRICKS CREEK SUB DISTRIBUTION-UNA TTEN 115.00 7.20
30 PEREZ SUB DISTRIBUTION-UNA TTEN 69.00 12.47
31 REDWOOD SUB DISTRIBUTION-UNA TTEN 69.00 12.47
32 SCOTT BAR SUB DISTRIBUTION-UNA TTEN 69.00 12.47
33 SEIAD SUB DISTRIBUTION-UNATTEN 69.00 12.47
34 SHASTINA SUB DISTRIBUTION-UNA TTEN 69.00 20.80
35 SHOTGUN CREEK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
36 SMITH RIVER SUB DISTRIBUTION-UNA TTEN 69.00 12.47
37 SNOW BRUSH SUB DISTRIBUTION-UNA TTEN 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-UNA TTEN 69.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426
Name of Respondent This Report Is:Date of Report Year/PeriocJiif Report
PacifiCorp (1 )!KAn Original (Mo, Da, Yr)End of 2010/Q4
(2)nA Resubmission 04/18/2011
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 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
13 1 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 (80rt Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nAResubmission 04/18/2011
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character,but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
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-UNA TTEN 69.00 12.47
4 YUROKSUB DISTRIBUTION-UNA TTEN 69.00 12.47
5 Total 3105.00 468.36
6 Number of Substations- 43
7
8 ALTURAS SUB TID-UNATTENDED 115.00 12.47 69.00
9 FALL CREEK HYDROISUB 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-ATTENDE 115.00 69.00
15 COPCO #1 HYDRO PLANT TRANSMISSION-ATTENDE 69.00 2.30
16 COPCO #2 230 SUB TRANSMISSION-ATTENDE 230.00 115.00
17 COPCO #2 HYDRO PLANT TRANSMISSION-A TTENDE 69.00 6.60
18 COPCO#2 SUB TRANSMISSION-ATTENDE 115.00 69.00
19 CRAG VIEW SUB TRANSMISSION-UNA TTEN 115.00 69.00
20 DEL NORTE SUB TRANSMISSION-UNA TTEN 115.00 69.00
21 IRON GATE HYDRO PLANT TRANSMISSION-UNA TTEN 69.00 6.60
22 WEED JUNCTION SUB TRANSMISSION-UNA TTEN 115.00 69.00
23 Total 1012.00 475.50
24 Number of Substations- 9
25
26 Idaho
27 ALEXANDER DISTRIBUTION-UNA TTEN 46.00 12.47
28 AMMON DISTRIBUTION-UNA TTEN 69.00 12.47
29 ANDERSON DISTRIBUTION-UNATTEN 69.00 12.47
30 ARCO DISTRIBUTION-UNATTEN 69.00 12.47
31 ARIMO DISTRIBUTION-UNA TTEN 46.00 12.47
32 BANCROFT SUB DISTRIBUTION-UNA TTEN 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-UNA TTEN 69.00 12.47
36 CANYON CREEK SUB DISTRIBUTION-UNA TTEN 69.00 24.90
37 CHESTERFIELD SUB DISTRIBUTION-UNA TTEN 46.00 12.47
38 CINDER BUTTE SUB DISTRIBUTION-UNA TTEN 161.00 12.47
39 CLEMENTS SUB DISTRIBUTION-UNA TTEN 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 ø0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
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 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
342 100 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 ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) r'A Resubmission 04/18/2011
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 COVE SUB DISTRIBUTION-UNATTEN 46.00 6.60
2 DOWNEY SUB DISTRIBUTION-UNATTEN 46.00 12.47
3 DUBOIS SUB DISTRIBUTION-UNA TTEN 69.00 12.47
4 EASTMONT SUB DISTRIBUTION-UNA TTEN 69.00 12.47
5 EGIN SUB DISTRIBUTION-UNA TTEN 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-UNATTEN 69.00 12.47
10 HAYES SUB DISTRIBUTION-UNA TTEN 69.00 12.47
11 HENRY SUB DISTRIBUTION-UNATTEN 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-UNATTEN 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-UNA TTEN 46.00 12.47
22 MENAN SUB DISTRIBUTION-UNA TTEN 69.00 12.47
23 MERRILL SUB DISTRIBUTION-UNA TTEN 69.00 12.47
24 MILLER SUB DISTRIBUTION-UNA TTEN 69.00 12.47
25 MONTPELIER SUB DISTRIBUTION-UNA TTEN 69.00 12.47
26 MOODY SUB DISTRIBUTION-UNA TTEN 69.00 24.90
27 NEWDALE SUB DISTRIBUTION-UNA TTEN 69.00 12.47
28 OSGOOD SUB DISTRIBUTION-UNA TTEN 69.00 12.47
29 PRESTON SUB DISTRIBUTION-UNA TTEN 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 DISTRIBUTION-UNA TTEN 69.00 12.47
33 RIRIE SUB DISTRIBUTION-UNATTEN 69.00 12.47
34 ROBERTS SUB DISTRIBUTION-UNA TTEN 69.00 12.47
35 RUDY SUB DISTRIBUTION-UNA TTEN 69.00 12.47
36 SAND CREEK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
37 SANDUNE SUB DISTRIBUTION-UNA TTEN 69.00 24.90
38 SHELLEY SUB DISTRIBUTION-UNA TTEN 46.00 12.47
39 SMITH SUB DISTRIBUTION-UNA TTEN 69.00 12.47
40 SOUTH FORK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.2
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifCorp (1) .li~n Original (Mo, Da, Yr)End of 2010/Q4
(2) A Resubmission 04/18/2011
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)ü)(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
14 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 )lKAn Original (Mo, Da, Yr)End of 2010/Q4
(2)OA Resubmission 04/18/2011
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 SPUD SUB DISTRIBUTION-UNA TTEN 46.00 12.47
2 ST. CHARLES SUB DISTRIBUTION-UNA TTEN 69.00 12.47
3 SUGAR CITY SUB DISTRIBUTION-UNA TTEN 69.00 12.47
4 SUNNYDELL SUB DISTRIBUTION-UNATTEN 69.00 12.47
5 TANNER SUB DISTRIBUTION-UNATTEN 46.00 12.47
6 TARGHEE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
7 THORNTON SUB DISTRIBUTION-UNA TTEN 69.00 12.47
8 UCON SUB DISTRIBUTION-UNA TTEN 69.00 12.47
9 WATKINS SUB DISTRIBUTION-UNA TTEN 69.00 12.47
10 WEBSTER SUB DISTRIBUTION-UNATTEN 69.00 12.47
11 WESTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
12 WINDSPER SUB DISTRIBUTION-UNATTEN 69.00 24.90
13 Total 4163.00 891.73
14 Number of Substations- 66
15
16 MALAD SUB TID-UNATTENDED 138.00 46.00 12.47
17 MUD LAKE SUB TID-UNATTENDED 69.00 12.47
18 RIGBY SUB TID-UNATTENDED 161.00 12.47 69.00
19 SAINT ANTHONY SUB TID-UNATTENDED 69.00 46.00 12.47
20 Total 437.00 116.94 93.94
21 Number of Substations- 4
22
23 GRACE HYDRO TRANSMISSION-ATTENDE 138.00 46.00 6.60
24 AMPS SUB TRANSMISSION-UNA TTEN 230.00 69.00
25 ANTELOPE SUB TRANSMISSION-UNA TTEN 230.00 161.00
26 ASHTON PLANT TRANSMISSION-UNA TTEN 46.00 2.40
27 BIG GRASSY SUB TRANSMISSION-UNA TTEN 161.00 69.00
28 BONNEVILLE SUB TRANSMISSION-UNA TTEN 161.00 69.00
29 CONDASUB TRANSMISSION-UNA TTEN 138.00 46.00
30 FISH CREEK SUB TRANSMISSION-UNA TTEN 161.00 46.00
31 FRANKLIN SUB TRANSMISSION-UNA TTEN 138.00 . 46.00
32 GOSHEN SUB TRANSMISSION-UNA TTEN 345.00 161.00 46.00
33 JEFF¡:RSON SUB TRANSMISSION-UNA TTEN 161.00 69.00
34 LIFTON HYDRO TRANSMISSION-UNA TTEN 69.00 2.30
35 ONEIDA SUB TRANSMISSION-UNA TTEN 138.00 25.00
36 OVID SUB TRANSMISSION-UNATTEN 138.00 69.00
37 SCOVILLE SUB .TRANSMISSION-UNA TTEN 138.00 69.00
38 SUGARMILL SUB TRANSMISSION-UNATTEN 161.00 46.00 69.00
39 THREEMILE KNOLL SUB TRANSMISSION-UNA TTEN 345.00 138.00 46.00
40 TREASURETON SUB TRANSMISSION-UNA TTEN 230.00 138.00
FERC FORM NO.1 (ED. 12-96)Page 426.3
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
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 Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
8 1 1
5 1 2
13 1 3
13 1 4
4 1 5
4 1 6
7 1 7
7 1 8
14 1 9
20 1 10
4 1 11
20 .1 12
777 71 1 13
14
15
71 4 1 16
14 1 17
189 4 18
40 2 19
314 11 1 20
21.
22
115 4 23
75 '2 1 24
250 1 25
25 3 26
67 1 27
67 1 28
67 1 29
25 3 30
75 1 31
763 8 1 32
233 3 33
6 2 34
40 2 35
30 1 36
76 2 37
168 3 38
700 1 39
533 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.3
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
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 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 Total 3128.00 1271.70 167.60
2 Number of Substations- 18
3
4 MONTANA
5 YELLOWTAIL SUB TRANSMISSION-UNATTEN 230.00 161.00
6 Total 230.00 161.00
7 Number of Substations- 1
8
9 Oregon
10 26TH STREET DISTRIBUTION-UNA TTEN 20.80 4.16
11 35TH STREET DISTRIBUTION-UNA TTEN 20.80 2.40
12 AGNESS AVE DISTRIBUTION-UNA TTEN 115.00 12.47
13 ALDERWOOD SUB DISTRIBUTION-UNA TTEN 69.00 12.47
14 ARLINGTON DISTRIBUTION-UNA TTEN 69.00 12.47
15 ATHENA DISTRIBUTION-UNA TTEN 69.00 12.47
16 BANDON TIE SUB DISTRIBUTION-UNA TTEN 20.80 12.47
17 BEACON SUB DISTRIBUTION-UNATTEN 69.00 12.47
18 BEALL LANE SUB DISTRIBUTION-UNATTEN 115.00 12.47
19 BEATTY SUB DISTRIBUTION-UNA TTEN 69.00 12.47
20 BELKNAP SUB DISTRIBUTION-UNA TTEN 69.00 12.47
21 BLALOCK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
22 BLOSS SUB DISTRIBUTION-UNA TTEN 115.00 12.47
23 BLY SUB DISTRIBUTION-UNA TTEN 69.00 12.47
24 BOISE CASCADE SUB DISTRIBUTION-UNA TTEN 69.00 11.00
25 BONANZA SUB DISTRIBUTION-UNA TTEN 69.00 12.47
26 BOND STREET SUB DISTRIBUTION-UNATTEN 69.00 12.50
27 BROOKHURST SUB DISTRIBUTION-UNATTEN 115.00 12.47
28 BROWNSVILLE SUB DISTRIBUTION-UNA TTEN 69.00 20.80
29 BRYANT SUB DISTRIBUTION-UNATTEN 69.00 12.47
30 BUCHANAN SUB DISTRIBUTION-UNA TTEN 115.00 20.80
31 BUCKAROO SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 CAMPBELL SUB DISTRIBUTION-UNA TTEN 115.00 12.47
33 CANNON BEACH SUB DISTRIBUTION-UNA TTEN 115.00 12.47
34 CARNES SUB DISTRIBUTION-UNA TTEN 69.00 12.47
35 CASEBEER SUB DISTRIBUTION-UNA TTEN 69.00 20.80
36 CAVEMAN SUB DISTRIBUTION-UNATTEN 115.00 12.47
37 CHERRY LANE SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 CHILOQUIN MARKET SUB DISTRIBUTION-UNA TTEN 69.00 12.47
39 CHINA HAT SUB DISTRIBUTION-UNA TTEN 69.00 12.47
40 CIRCLE BLVD SUB DISTRIBUTION-UNATTEN 115.00 20.80
FERC FORM NO.1 (ED. 12-96)Page 426.4
Nanie of Respondent This '00rt Is:Date of Report Year/Period of Report
PacifCorp.(1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
.SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co"owner or other part, explain basis of shanng expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of 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)0)(k)
3315 41 2 1
2
3
4
100 1 5
100 1 6
.7..
8
9
5 1 10
30 6 11
25 1 12
25 1 13
5 1 14
9 1 15
8 3 1 16
11 3 17
25 1 18
6 1 19
40 2 20
2 3 21
32 2 22
8 3 23
3 1 24
8 3 25
25 1 26
50 2 27
13 1 28
34 2 29
40 2 30
34 2 31
20 1 32
13 1 33
9 3 34
20 1 35
45 2 36
25 1 37
5 3 38
25 1 39
80 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.4
Name of Respondent This~rtIS:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industnal or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stàtions in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 CLEVELAND AVE SUB DISTRIBUTION-UNATTEN 69.00 12.47
2 CLINE FALLS HYDRO DISTRIBUTION-UNA TTEN 12.47 2.40
3 CLOAKE SUB DISTRIBUTION-UNA TTEN 69.00 20.80
4 COBURG SUB DISTRIBUTION-UNA TTEN 69.00 20.80
5 COLISEUM SUB DISTRIBUTION-UNA TTEN 20.80 4.16
6 COLUMBIA SUB DISTRIBUTION-UNA TTEN 115.00 12.47 57,00
7 COOS RIVER SUB DISTRIBUTION-UNATTEN 115.00 20.80
8 COQUILLE SUB DISTRIBUTION-UNATTEN 115.00 20.80
9 CREEK SUB DISTRIBUTION-UNATTEN 69.00 34.50
10 CROOKED RIVER RANCH SUB DISTRIBUTION-UNATTEN 69.00 20.80
11 CROWFOOT SUB DISTRIBUTION-UNA TTEN 115.00 12.47
12 CULLY SUB.DISTRIBUTION-UNA TTEN 115.00 12.47
13 CULVER SUB DISTRIBUTION-UNA TTEN 69.00 12.47
14 CUTLER CITY SUB DISTRIBUTION-UNA TTEN 20.80 4.16
15 DAIRY SUB DISTRIBUTION-UNATTEN 69.00 12.47
16 DALLAS SUB DISTRIBUTION-UNA TTEN 115.00 20.80
17 DALREEDSUB DISTRIBUTION-UNATTEN 230.00 34.50
18 DESCHUTES SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 DEVILS LAKE SUB DISTRIBUTION-UNA TTEN 115.00 20.80
20 DIXON SUB .DISTRIBUTION-UNA TTEN 115.00 4.16
21 DODGE BRIDGE SUB DISTRIBUTION-UNA TTEN 69.00 20.80
22 DOWELL SUB DISTRIBUTION-UNA TTEN 115.00 12.47
23 EASY VALLEY SUB DISTRIBUTION-UNA TTEN 115.00 12.47
24 EMPIRE SUB DISTRIBUTION-UNA TTEN 115.00 20.80
25 ENTERPRISE SUB DISTRIBUTION-UNA TTEN 69.00 12.47
26 FERN HILL SUB DISTRIBUTION-UNA TTEN 115.00 12.47
27 FIELDER CREEK SUB DISTRIBUTION-UNA TTEN 115.00 20.80
28 FOOTHILLS SUB DISTRIBUTION-UNATTEN 69.00 12.47
29 FRALEY SUB DISTRIBUTION-UNA TTEN 69.00 12.47
30 GARDEN VALLEY SUB DISTRIBUTION-UNATTEN 69.00 20.80
31 GAZLEYSUB DISTRIBUTION-UNATTEN 69.00 12.47
32 GLENDALE SUB DISTRIBUTION-UNA TTEN 230.00 12.47
33 GLENEDEN SUB DISTRIBUTION-UNA TTEN 20.80 4.16
34 GLIDE SUB DISTRIBUTION-UNA TTEN 115.00 12.47
35 GOLD HILL SUB DISTRIBUTION-UNA TTEN 69.00 12.47
36 GORDON HOLLOW SUB DISTRIBUTION-UNA TTEN 69.00 12.47
37 GOSHEN SUB (OR)DISTRIBUTION-UNA TTEN 115.00 20.80
38 GRANT STREET SUB DISTRIBUTION-UNA TTEN 115.00 20.80
39 GRASS VALLEY SUB DISTRIBUTION-UNATTEN 20.80 4.16
40 GREEN SUB DISTRIBUTION-UNATTEN 69.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.5
Name of Respondent This 780rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
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 Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
45 2 1
1 3 2
20 1 3
1 3 4
9 2 5
55 2 1 6
20 1 7
40 2 8
5 1 9
25 2 10
20 1 11
25 1 12
13 1 13
2 3 14
25 1 15
50 2 16
75 3 17
13 1 18
50 2 19
7 1 20
13 1 21
20 1 22
45 2 .23
20 1 24
19 2 25
13 1 26
25 1 27
21 4 28
5 3 29
20 1 30
8 3 31
25 2 32
5 1 33
13 1 34
11 3 35
6 1 36
20 1 37
45 2 38
1 4 39
25 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.5
-
Name of Respondent This 180rt Is:Date of Report Year/Penod of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 GRIFFIN CREEK SUB DISTRIBUTION-UNATIEN 115.00 12.47
2 HAMAKER SUB DISTRIBUTION-UNA TIEN 69.00 12.47
3 HARRISBURG SUB DISTRIBUTION-UNA TIEN 69.00 20.80
4 HENLEY SUB DISTRIBUTION-UNATIEN 69.00 12.47
5 HERMISTON SUB DISTRIBUTION-UNATIEN 69.00 12.47
6 HILLVIEW SUB DISTRIBUTION-UNA TIEN 115.00 20.80
7 HINKLE SUB DISTRIBUTION-UNA TIEN 69.00 12.47
8 HOLLADAY SUB DISTRIBUTION-UNA TIEN 115.00 12.47
9 HOLLYWOOD SUB DISTRIBUTION-UNA TIEN 115.00 12.47
10 HOOD RIVER SUB DISTRIBUTION-UNA TIEN 69.00 12.47
11 HORNET SUB DISTRIBUTION-UNA TIEN 69.00 12.47
12 HUNTERS CIRCLE TEMP SUB DISTRIBUTION-UNA TIEN 69.00 12.47
13 ILLAHEE FLATS SUB DISTRIBUTION-UNA TIEN 115.00 12.47
14 INDEPENDENCE SUB DISTRIBUTION-UNA TIEN 69.00 20.80
15 JACKSONVILLE SUB DISTRIBUTION-UNATIEN .115.00 12.47 69.00
16 JEFFERSON SUB DISTRIBUTION-UNATIEN 69.00 20.80
17 JEROME PRAIRIE SUB DISTRIBUTION-UNATIEN .115.00 12.47
18 JORDAN POINT SUB DISTRIBUTION-UNA TIEN 115.00 12.47
19 JOSEPH SUB DISTRIBUTION-UNA TIEN 20.80 12.47
20 JUNCTION CITY SUB DISTRIBUTION-UNA TIEN 69.00 20.80
21 KENWOOD SUB DISTRIBUTION-UNA TIEN 69.00 12.47
22 KILLINGSWORTH SUB DISTRIBUTION-UNA TIEN 69.00 12.47
23 KNAPPA SVENSEN SUB DISTRIBUTION-UNATIEN 115.00 12.47
24 LAKEPORT SUB DISTRIBUTION-UNATIEN 69.00 12.47
25 LAKEVIEW SUB DISTRIBUTION-UNA TIEN 69.00 12.47
26 LANCASTER SUB DISTRIBUTION-UNA TIEN 69.00 20.80
27 LEBANON SUB DISTRIBUTION-UNATIEN 115.00 20.80
28 LINCOLN SUB ..DISTRIBUTION-UNATIEN 115.00 12.47
29 LOCKHART SUB DISTRIBUTION-UNATIEN 115.00 20.80
30 LYONS$UB DISTRIBUTION-UNA TIEN 69.00 20.80
31 MADRAS SUB DISTRIBUTION-UNA TIEN 69.00 12.47
32 MALLORY SUB DISTRIBUTION-UNA TIEN 115.00 12.47
33 MARYS RIVER SUB DISTRIBUTION-UNA TIEN 115.00 20.80
34 MEDCOSUB DISTRIBUTION-UNA TIEN 115.00 12.47
35 MEDFORD DISTRIBUTION-UNA TIEN 69.00 12.47
36 MERLIN SUB DISTRIBUTION-UNA TIEN 115.00 12.47
37 MERRILL SUB DISTRIBUTION-UNA TIEN 69.00 12.47
38 MINAM SUB DISTRIBUTION-UNATIEN 69.00 12.47
39 MODOC SUB DISTRIBUTION-UNA TIEN 69.00 12.47
40 MOROSUB DISTRIBUTION-UNA TIEN 20.80 2.40
FERC FORM NO.1 (ED. 12-96)Page 426.6
Name of Respondent This ø0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ñA Resubmission 04/18/2011
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) .
20 1 1
8 3 2
13 1 3
6 3 4
40 2 5
45 2 6
20 1 7
75 :3 8
50 2 9
40 2 10
20 1 11
13 1 12
2 1 13
20 1
.14
75 2 15
13 1 16
20 1 17
20 1 18
6 1 1 19
25 2 20
3 3 21
40 2 22
6 1 23
50 2 24
9 3 25
13 3 26
40 2 27
105 3 28
40 2 29
9 1 30
25 2 31
25 1 32
20 1 33
20 1 34
79 14 35
45 2 36
17 6 37
1 38
6 3 39
2 3 40
FERC FORM NO.1 (ED. 12-96)Page 427.6
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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 MURDER CREEK SUB DISTRIBUTION-UNA TTEN 115.00 20.80
2 MYRTLE CREEK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
3 MYRTLE POINT SUB DISTRIBUTION-UNATTEN 115.00 20.80
4 NELSCOTT SUB DISTRIBUTION-UNATTEN 20.80 4.16
5 NEW O'BRIEN SUB DISTRIBUTION-UNA TTEN 115.00 12.47
6 OAK KNOLL SUB DISTRIBUTION-UNA TTEN 115.00 12.47
7 OAKLAND SUB .. DISTRIBUTION-UNATTEN 115.00 12.47
8 OREMETSUB DISTRIBUTION-UNA TTEN 115.00 12.47
9 OVERPASS SUB DISTRIBUTION-UNA TTEN 69.00 12.47
10 PALLETTE SUB DISTRIBUTION-UNATTEN 69.00 20.80
11 PARK STREET SUB DISTRIBUTION-UNATTEN 115.00 12.47
12 PARKROSE SUB DISTRIBUTION-UNA TTEN 57.00 12.47
13 PENDLETON SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 PILOT ROCK SUB DISTRIBUTION-UNATTEN 69.00 12.47
15 POWELL BUTTE SUB DISTRIBUTION-UNA TTEN 115.00 12.47
16 PRINEVILLE SUB DISTRIBUTION-UNA TTEN 115.00 12.47
17 PROVOLTSUB DISTRIBUTION-UNATTEN 69.00 12.47
18 QUEEN AVE SUB DISTRIBUTION-UNA TTEN 69.00 20.80
19 RED BLANKET SUB DISTRIBUTION-UNA TTEN 69.00 4.16
20 REDMOND SUB DISTRIBUTION-UNATTEN 115.00 12.47
21 RIDDLE SUB DISTRIBUTION-UNA TTEN 69.00 12.47
22 RIDDLE VENEER SUB DISTRIBUTION-UNA TTEN 115.00 12.47
23 ROGUE RIVER SUB DISTRIBUTION-UNA TTEN 69.00 . 12.47
24 ROSEBURG SUB DISTRIBUTION-UNA TTEN 115.00 20.80
25 ROSS AVE SUB DISTRIBUTION-UNA TTEN 69.00 12.47
26 ROXY ANN SUB DISTRIBUTION-UNA TTEN 115.00 12.50
27 RUCH SUB DISTRIBUTION-UNA TTEN 69.00 12.47
28 RUNNING Y SUB DISTRIBUTION-UNA TTEN 69.00 20.80
29 RUSSELLVILLE SUB DISTRIBUTION-UNA TTEN 115.00 12.47
30 SAGE ROAD SUB DISTRIBUTION-UNA TTEN 115.00 12.47
31 SCENIC SUB DISTRIBUTION-UNA TTEN 115.00 12.47 69.00
32 SCIOSUB DISTRIBUTION-UNATTEN 69.00 12.47
33 SEASIDE SUB DISTRIBUTION-UNATTEN 115.00 12.47
34 SELMA SUB DISTRIBUTION-UNATTEN 115.00 12.47
35 SHASTA WAY SUB DISTRIBUTION-UNA TTEN 12.47 4.16
36 SHEVLIN PARK SUB DISTRIBUTION-UNA TTEN 69.00 12.50
37 SIMTAG BOOSTER PUMP DISTRIBUTION-UNA TTEN 34.50 4.16
38 SOUTH DUNES SUB DISTRIBUTION-UNATTEN 115.00 12.47
39 SOUTHGATE SUB DISTRIBUTION-UNA TTEN 69.00 20.80
40 SPRAGUE RIVER SUB DISTRIBUTION-UNA TTEN 69.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.7
Name of Respondent This 780rt Is:Date of Report Yéar/Period of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
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)ü)(k)
100 4 1
14 1 2
9 1 3
4 1 4
9 1 5
45 2 6
8 1 7
55 2 8
45 2 9
1 1 1 10
40 2 11
39 2 12
46 7 1 13
22 2 14
6 1 15
50 2 16
11 3 17
50 2 18
2 3 19
50 2 20
. 14 1 21
25 1 1 22
25 2 23
50 2 24
9 3 25
25 1 26
9 1 27
9 1 28
45 2 29
40 2 30
70 3 31
8 1 32
40 2 33
9 1 34
2 3 35
25 1 36
19 2 37
9 1 38
20 1 39
7 3 40
FERC FORM NO.1 (ED. 12-96)Page 427.7
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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 individuai stations in
column (t)o
. Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 STATE STREET SUB DISTRIBUTION-UNA TTEN 115.00 20.80
2 STAYTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
3 STEAMBOAT SUB DISTRIBUTION-UNATTEN 115.00 7.20
4 STEVENS ROAD SUB DISTRIBUTION-UNA TTEN 115.00 20.80
5 SUTHERLIN SUB DISTRIBUTION-UNA TTEN 115.00 12.00
6 SWEET HOME SUB DISTRIBUTION-UNA TTEN 115.00 20.80
7 TAKELMA SUB DISTRIBUTION-UNATTEN 115.00 20.80
8 TALENT SUB DISTRIBUTION-UNATTEN 69.00 12.47
9 TEXUM SUB DISTRIBUTION-UNATTEN 69.00 12.47
10 TILLER SUB DISTRIBUTION-UNA TTEN 115.00 12.47
11 TOLOSUB DISTRIBUTION-UNA TTEN 69.00 12.47
12 TURKEY HILL SUB DISTRIBUTION-UNA TTEN 69.00 12.47
13 UMAPINESUB DISTRIBUTION-UNA TTEN 69.00 12.47
14 UMATILLA SUB DISTRIBUTION-UNA TTEN 69.00 12.47
15 VERNON SUB DISTRIBUTION-UNA TTEN 69.00 12.47
16 VILAS SUB DISTRIBUTION-UNA TTEN 115.00 12.47
17 VILLAGE GREEN SUB DISTRIBUTION-UNA TTEN 115.00 20.80
18 VINE STREET SUB DISTRIBUTION-UNA TTEN 69.00 20.80
19 WALLOWA SUB DISTRIBUTION-UNA TTEN 69.00 12.47
20 WARM SPRINGS SUB DISTRIBUTION-UNATTEN 69.00 20.80
21 WARRENTON SUB DISTRIBUTION-UNA TTEN 115.00 12.47
22 WASCO SUB DISTRIBUTION-UNA TTEN 20.80 4.16
23 WECOMA BEACH SUB DISTRIBUTION-UNA TTEN 20.80 4.16
24 WESTERN KRAFT SUB DISTRIBUTION-UNA TTEN 115.00 12.47
25 WESTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 WESTSIDE HYDROISUB DISTRIBUTION-UNATTEN 69.00 12.47
27 WEYERHAUSER SUB DISTRIBUTION-UNA TTEN 69.00 12.47
28 WHITE CITY SUB DISTRIBUTION-UNA TTEN 115.00 12.47
29 WILLOW COVE SUB .DISTRIBUTION-UNA TTEN 34.50 4.16
30 WINSTON SUB DISTRIBUTION-UNA TTEN 69.00 12.47
31 YEW AVENUE SUB DISTRIBUTION-UNA TTEN 115.00 12.50
32 YOUNGS BAY SUB DISTRIBUTION-UNA TTEN 115.00 12.47
33 Total 15580.54 2522.27 195.00
34 Number of Substations- 183
35
36 ALBINA SUB TID-UNATTENDED 115.00 12.47 69.00
37 APPLEGATE SUB TID-UNATTENDED 115.00 69.00 12.47
38 ASHLAND MTN AVE SUB TID-UNATTENDED 115.00 69.00 12.47
39 BEND PLANT TID-UNATTENDED 69.00 4.16 12.47
40 CAVE JUNCTION SUB TID-UNATTENDED 115.00 12.47 69.00
I
FERC FORM NO.1 (ED. 12-96)Page 426.8
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
penod of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of 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)
40 2 1
55 2 2
1 3
25 1 ,. .4
25 1 5
42 2 6
13 1 7
50 2 8
25 1 9
.1 1 10
11 1 11
13 3 12
13 1 13
25 2 14
50 2 15
25 1 16
40 2 17
22 4 18
7 1 19
13 3 20
25 2 21
3 3 22
3 1 23
50 2 24
22 2 25
23 9 26
40 2 27
60 3 28
28 3 29
23 3 30
25 1 31
37 2 32..
4526 360 6 33
34
35
177 9 36
65 2 37
70 2 38
23 3 39
70 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.8
Name of Respondent This i80rt Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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)o
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 HAZELWOOD SUB TID-UNATTENDED 115.00 69.00 12.47
2 KNOTT SUB TID-UNATTENDED 115.00 12.47 57.00
3 MILE HI SUB TID-UNATTNDED 115.00 69.00 12.47
4 PILOT BUTTE SUB TID-UNATTENDED 230.00 69.00 12.47
5 WINCHESTER SUB TID-UNATTENDED 115.00 12.47 69.00
6 Total 1219.00 399.04 338.2
7 Number of Substations- 10
8
9 CLEARWATER #1 HYDRO PLANT TRANSMISSION-A TTENDE 138.00 6.90
10 FISH CREEK HYDRO TRANSMISSION-A TTENDE 115.00 6.90
11 JC BOYLE HYDRO TRANSMISSION-ATTENDE 230.00 11.00
12 LEMOLO #1 HYDRO TRANSMISSION-A TTENDE 11.30 12.50
13 LEMOLO #2 HYDRO TRANSMISSION-A TTENDE 115.00 12.00
14 PROSPECT 1 HYDRO TRANSMISSION-ATTENDE 69.00 2.30
15 PROSPECT 2 HYDRO TRANSMISSION-A TTENDE 69.00 6.60
16 PROSPECT 3 HYDRO TRANSMISSION-A TTENDE 69.00 12.47
17 TOKETEE HYDRO TRANSMISSION-A TTENDE 115.00 6.90
18 BEND PLANT TRANSMISSION-UNA TTEN 4.16 2.40
19 CALAPOOYA SUB TRANSMISSION-UNA TTEN 230.00 69.00
20 CHILOQUIN SUB TRANSMISSION-UNA TTEN 230.00 115.00 69.00
21 COLD SPRINGS SUB TRANSMISSIONcUNA TTEN 230.00 69.00
22 COVE SUB TRANSMISSION-UNA TTEN 230.00 69.00
23 DAYS CREEK SUB TRANSMISSION-UNA TTEN 115.00 69.00
24 DIAMOND HILL SUB TRANSMISSION-UNA TTEN 230.00 69.00
25 DIXONVILLE 115/230 SUB TRANSMISSION-UNA TTEN 230.00 115.00 69.00~._TRANSMISSION-UNATTEN 500.00 230.00
27 EAGLE POINT HYDRO TRANSMISSION-UNA TTEN 115.00 2.40
28 EAST SIDE HYDRO TRANSMISSION-UNA TTEN 46.00 12.47
29 FISH HOLE SUB TRANSMISSION-UNA TTEN 115.00 69.00
30 FRY SUB TRANSMISSION-UNA TTEN 230.00 115.00
31 GRANTS PASS SUB TRANSMISSION-UNA TTEN 230.00 115.00 69.00
32 GREEN SPRINGS PLANTISUB TRANSMISSION-UNA TTEN 115.00 69.00
33 HURRICANE SUB .TRANSMISSION-UNA TTEN 230.00 69.00 2.40
34 ISTHMUS SUB TRANSMISSION-UNATTEN 230.00 115.00
35 KENNEDY SUB TRANSMISSION-UNA TTEN 69.00 57.00
36 KLAMATH FALLS SUB TRANSMISSION-UNA TTEN 230.00 69.00
37 LONE PINE SUB TRANSMISSION-UNA TTEN 230.00 115.00 69.00~_TRANSMISSION-UNATTEN 500.00 230.00
39 MONPACSUB TRANSMISSION-UNA TTEN 115.00 69.00
40 NICKEL MOUNTAIN TRANSMISSION-UNA TTEN 230.00 115.00
FERC FORM NO.1 (ED. 12-96)Page 426.9
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Onginal (Mo, Da, Yr)End of 2010/Q4
(2) r"A Resubmission 04/18/2011
SUBSTATIONS (Continued)
5. Show in columns (I), (j, 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 petween 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)
132 4 1
187 8 2
39 4 3
400 4 4
75 5 5
1238 43 6
7
8
17 3 9
13 3 10
89 2 1 11
2 3 1 12
40 4 13
5 3 14
40 6 1 15
10 6 16
50 9 17
3 3 18
75 1 19
119 4 20
60 1 21
67 3 22
50 1 23
75 1 24
344 6 25
650 3 1 26
3 1 27
3 3 28
7 3 29
500 2 30
458 4 31
19 3 32
29 2 33
250 1 34
33 1 35
251 6 1 36
733 10 37
1300 6 1 38
50 1 39
114 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.9
Name of Respondent This 'f0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as ofthe 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)o
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 PARRISH GAP SUB TRANSMISSION-UNATTEN 230.00 69.00 12.47
2 PONDEROSA SUB TRANSMISSION-UNA TTEN 230.00 115.00
3 POWERDALE PLANT TRANSMISSION-UNATTEN 69.00 7.20
4 PROSPECT CENTRAL SUB TRANSMISSION-UNATTEN 115.00 69.00
5 ROBERTS CREEK SUB TRANSMISSION-UNA TTEN 115.00 69.00
6 SLIDE CREEK HYDRO TRANSMISSION-UNATTEN 115.00 7.00
7 SODA SPRINGS HYDRO TRANSMISSION-UNATTEN 115.00 7.00
8 TROUTDALE SUB TRANSMISSION-UNA TTEN 230.00 115.00 69.00
9 TUCKER SUB TRANSMISSION-UNATTEN 115.00 69.00
10 WALLOWA FALLS HYDRO TRANSMISSION-UNA TTEN 20.80
11 Total 6970.26 2634.04 359.87
12 Number of Substations- 42
13
14 Utah
15 106TH SOUTH SUB DISTRIBUTION-UNA TTEN 138.00 12.50
16 118TH SOUTH SUB DISTRIBUTION-UNA TTEN 138.00 12.47
17 23RD ST SUB DISTRIBUTION-UNATTEN 46.00 12.47
18 70TH SOUTH SUB DISTRIBUTION-UNA TTEN 138.00 12.47
19 ALTAVIEW SUB DISTRIBUTION-UNA TTEN 46.00 12.47
20 AMALGASUB DISTRIBUTION-UNA TTEN 46.00 12.47
21 AMERICAN FORK SUB DISTRIBUTION-UNA TTEN 138.00 12.47
22 ARAGONITE DISTRIBUTION-UNA TTEN 46.00 7.20
23 AURORA SUB DISTRIBUTION-UNA TTEN 46.00 12.47
24 BANGERTER SUB DISTRIBUTION-UNA TTEN 138.00 12.47
25 BEAR RIVER SUB DISTRIBUTION-UNA TTEN 46.00 12.47
26 BENJAMIN SUB DISTRIBUTION-UNATTEN 46.00 12.47
27 BINGHAM SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 BLUE CREEK DISTRIBUTION-UNA TTEN 46.00 12.47
29 BLUFF SUB DISTRIBUTION-UNA TTEN 69.00 12.47
30 BLUFFDALE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
31 BOTHWELL SUB DISTRIBUTION-UNATTEN 46.00 12.47
32 BOX ELDER SUB DISTRIBUTION-UNA TTEN 46.00 12.47
33 BRIAN HEAD SUB DISTRIBUTION-UNA TTEN 46.00 12.47
34 BRICKYARD SUB DISTRIBUTION-UNA TTEN 46.00 12.47
35 BRIGHTON SUB DISTRIBUTION-UNA TTEN 46.00 24.90
36 BROOKLAWN SUB DISTRIBUTION-UNA TTEN 46.00 12.47
37 BRUNSWICK SUB DISTRIBUTION-UNA TTEN 46.00 12.47
38 BURTON SUB DISTRIBUTION-UNA TTEN 34.50 12.47
39 BUSH SUB DISTRIBUTION-UNA TTEN 46.00 12.47
40 CANNON SUB DISTRIBUTION-UNA TTEN 46.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.10
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
PacifiCorp (1). X An Original (Mo, Da, Yr)End of 2010/Q4
(2) 'MA Resubmission 04/18/2011
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 Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
150 1 1
250 1 2
8 3 1 3
47 4 4
50 1 5
21 3 6
13 3 7
500 3 .8
.100 2 9
2 3 10
6600 130 7 11
12
13.
14
30 1 15
30 1 16
13 1 17
.30 1 18
45 2 19
11 1 20
30 1 21
1 1 22
3 1 23
50 1 24
17 2 25
2 1 26
11 1 27
2 3 28
1 3 29
9 1 30
4 1 31
14 1 32
14 1 33
9 1 34
26 2 35
6 1 36
60 3 37
11 3 38
9 1 39
13 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.10
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission .04/18/2011
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)o
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 CANYONLANDS SUB DISTRIBUTION-UNA DEN 69.00 12.47
2 CAPITOL SUB DISTRIBUTION-UNA DEN 46.00 12.47
3 CARBIDE SUB DISTRIBUTION-UNA DEN 46.00 7.20
4 CARBONVILLE SUB DISTRIBUTION-UNA DEN 46.00 12.47
5 CARLISLE SUB DISTRIBUTION-UNA DEN 138.00 12.50
6 CASTO SUBSTATION DISTRIBUTION-UNA DEN 46.00 12.47
7 CENTENNIAL SUB DISTRIBUTION-UNADEN 138.00 12.47
8 CENTERVILLE SUB DISTRIBUTION-UNA DEN 46.00 12.47
9 CENTRAL SUB DISTRIBUTION-UNADEN 43.80 12.47
10 CHAPEL HILL SUB DISTRIBUTION-UNA DEN 138.00 12.47
11 CHERRYWOOD SUB DISTRIBUTION-UNA DEN 138.00 12.47
12 CIRCLEVILLE SUB DISTRIBUTION-UNA DEN 69.00 12.47
13 CLEAR CREEK SUB DISTRIBUTION-UNA DEN 46.00 12.47
14 CLEAR LAKE SUB DISTRIBUTION-UNADEN 46.00 12.47
15 CLEARFIELD SOUTH SUB DISTRIBUTION-UNA DEN 138.00 12.47
16 CLINTON SUB DISTRIBUTION-UNA DEN 138.00 12.47
17 CLIVE SUB DISTRIBUTION-UNA DEN 46.00 12.47
18 COALVILLE SUB DISTRIBUTION-UNA DEN 46.00 12.47
19 COLD WATER CANYON SUB DISTRIBUTION-UNA DEN 138.00 12.47
20 COLEMAN SUB DISTRIBUTION-UNA DEN 138.00 69,00 12.47
21 COL TON WELL SUB DISTRIBUTION-UNA DEN 46.00 12.47
22 COMMERCE SUB DISTRIBUTION-UNA DEN 138.00 12.50
23 CORINNE SUB DISTRIBUTION-UNA DEN 46.00 12.47
24 COVE FORT SUB DISTRIBUTION-UNA DEN 46.00 12.47
25 COZYDALE SUB .DISTRIBUTION-UNA DEN 138.00 12.50
26 CRESCENT JUNCTION SUB DISTRIBUTION-UNA DEN 46.00 7.20
27 CROSS HOLLOW SUB DISTRIBUTION-UNA DEN 138.00 12.47
28 CUDAHY SUB DISTRIBUTION-UNA DEN 138.00 12.47
29 DAMMERON VALLEY SUB .DISTRIBUTION-UNA DEN 34.50 12.47
30 DECADE SUB DISTRIBUTION-UNA DEN 138.00 12.50
31 DECKER LAKE SUB DISTRIBUTION-UNA DEN 138.00 12.47
32 DELLE SUB DISTRIBUTION-UNA DEN 46.00 12.47
33 DELTA SUB DISTRIBUTION-UNA DEN 46.00 69.00
34 DESERET SUB DISTRIBUTION-UNA DEN 46.00 4.16
35 DEWEYVILLE SUB DISTRIBUTION-UNA DEN 46.00 12.47
36 DIMPLE DELL SUB DISTRIBUTION-UNA DEN 138.00 12.47
37 DIXIE DEER SUB DISTRIBUTION-UNA DEN 34.50 12.47
38 DRAPER SUB DISTRIBUTION-UNADEN 46.00 12.47
39 DUMAS SUB DISTRIBUTION-UNADEN 138.00 12.47
40 EAST BENCH SUB DISTRIBUTION-UNA DEN 138.00 12.47
FERCFORM NO.1 (ED. 12-96)Page 426.11
Name of Respondent This 00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
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 Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
1 1 1
20 1 2
3 1 3
6 1 4
30 1 5
25 1 6
40 2 7.
22 1 8
9 1 9
30 1 10
25 1 11
3 1 12
4 1 13
3 14
60 2 15
50 2 16
4 1 17
20 2 18
30 1 19
106 4 20
1 3 21
30 1 22
3 1 23
2 3 24
30 1 25
1 1 26
22 1 27
30 1 28
42 1 29
60 2 30
55 2 31
6 1 32
48 3 33
2 1 34
4 1 35
60 2 36
2 1 37
23 2 38
60 2 39
30 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.11
Name of Respondent This 180rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/1812011
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).
.
VOLTAGE (In MVa)Line
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 EAST HYRUM SUB DISTRIBUTION-UNA TIEN 46.00 12.47
2 EAST LAYTON SUB DISTRIBUTION-UNATIEN 138.00 12.47
3 EAST MILLCREEK SUB DISTRIBUTION-UNATIEN 46.00 12.47
4 EDEN SUB DISTRIBUTION-UNATIEN 46.00 12.47
5 ELBERTA SUB DISTRIBUTION-UNA TIEN 46.00 12.47
6 ELK MEADOWS SUB DISTRIBUTION-UNA TIEN 46.00 12.47
7 ELSINORE SUB .DISTRIBUTION-UNA TIEN 46.00 12.47
8 EMERY CITY SUB DISTRIBUTION-UNA TIEN 69.00 12.47
9 EMIGRATION SUB DISTRIBUTION-UNA TIEN 46.00 12.47
10 ENOCH SUB DISTRIBUTION-UNATIEN 138.00 12.47
11 ENTERPRISE VALLEY SUB DISTRIBUTION-UNATIEN 138.00 12.47
12 EUREKA SUB DISTRIBUTION-UNATIEN 46.00 12.47
13 FARMINGTON SUB DISTRIBUTION-UNATIEN 138.00 12.47
14 FAYETIESUB DISTRIBUTION-UNATIEN 46.00 12.47
15 FERRON SUB DISTRIBUTION-UNA TIEN 46.00 12.47
16 FIELDING SUB DISTRIBUTION-UNA TIEN 46.00 12.00
17 FIFTH WEST SUB DISTRIBUTION-UNA TIEN 138.00 12.47
18 FLUX SUB DISTRIBUTION-UNATIEN 46.00 12.47
19 FOOL CREEK SUB DISTRIBUTION-UNA TIEN 46.00 12.47
20 FOUNTAIN GREEN SUB DISTRIBUTION-UNA TIEN 46.00 12.47
21 FREEDOM SUBSTATION DISTRIBUTION-UNA TIEN 46.00 7.20
22 FRUIT HEIGHTS SUB DISTRIBUTION-UNA TIEN 46.00 12.47
23 GARDEN CITY SUB DISTRIBUTION-UNA TIEN 69.00 12.47
24 GATEWAY SUB DISTRIBUTION-UNATIEN 69.00 12.47
25 GOLD RUSH SUB DISTRIBUTION-UNATIEN 138.00 12.50
26 GORDON AVENUE SUB DISTRIBUTION-UNA TIEN 138.00 12.50
27 GOSHEN SUB DISTRIBUTION-UNA TIEN 46.00 12.47
28 GRANGER SUB DISTRIBUTION-UNA TIEN 46.00 12.47
29 GRANTSVILLE SUB DISTRIBUTION-UNA TIEN 46.00 12.47
30 GREEN RIVER SUB DISTRIBUTION-UNA TIEN 46.00 12.47
31 GROW SUB DISTRIBUTION-UNA TIEN 138.00 12.47 46.00
32 GUNLOCK HYDRO DISTRIBUTION-UNA TIEN 34.50 2.30
33 GUNNISON SUB DISTRIBUTION-UNA TIEN 46.00 12.47
34 HAMMER SUB DISTRIBUTION-UNA TIEN 138.00 12.47
35 HAVASU SUB DISTRIBUTION-UNA TIEN 69.00 12.47
36 HELPER CITY SUB DISTRIBUTION-UNA TIEN 46.00 4.16
37 HENEFER SUB DISTRIBUTION-UNA TIEN 46.00 12.47
38 HERRIMAN SUB DISTRIBUTION-UNA TIEN 138.00 12.47
39 HIAWATHA SUB DISTRIBUTION-UNA TIEN 46.00 4.16
40 HIGHLAND DIST SUB DISTRIBUTION-UNA TIEN 46.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.12
Name of Respondent This 00rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/18/2011
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 Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
6 1 1
60 2 2
20 1 3
19 2 4
5 1 5
3 1 6
2 1 7
3 3 8
25 1 9
14 1 10
10 1 11
3 1 12
30 1 .13
1 2 14
5 1 15
6 1 16
30 1 17
4 1 18
2 1 19
2 1 20
1 21
22 1 22
13 1 23
28 2 1 24
30 1 25
30 1 26
2 1 27
50 2 28
24 1 29
5 2 30
72 3 31
1 1 32
11 1 33
60 2 34
3 1 35
3 3 36
4 1 37
30 1 38
1 3 39
25 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.12
..
Name of Respondent ThiS~tOrt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2)A Resubmission 04/18/2011
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or .unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 HOGGARD SUB DISTRIBUTION-UNATIEN 138.00 12.47
2 HOGLE SUB DISTRIBUTION-UNATIEN 46.00 12.47
3 HOLDEN SUB DISTRIBUTION-UNA TIEN 46.00 12.47
4 HOLLADAY SUB DISTRIBUTION-UNATIEN 46.00 12.47
5 HUNTER SUB DISTRIBUTION-UNA TIEN 46.00 12.47
6 HUNTINGTON CITY SUB DISTRIBUTION-UNATIEN 69.00 12.47
7 IRON MOUNTAIN SUB DISTRIBUTION-UNA TIEN 34.50 7.20
8 IRON SPRINGS SUB DISTRIBUTION-UNA TIEN 34.50 12.47
9 IRONTON SUB DISTRIBUTION-UNATIEN 46.00 12.47
10 IVINS SUB DISTRIBUTION-UNA TIEN 34.50 12.47
11 JORDAN NARROWS SUB DISTRIBUTION-UNA TIEN 46.00 2.40
12 JORDAN PARK SUB DISTRIBUTION-UNA TIEN 138.00 12.47
13 JORDANELLE SUB DISTRIBUTION-UNA TIEN 138.00 12.47
14 JUAB SUB DISTRIBUTION-UNA TIEN 46.00 12.47
15 JUNCTION SUB DISTRIBUTION-UNA TIEN 69.00 12.47
16 KAIBABSUB DISTRIBUTION-UNA TIEN 69.00 12.47
17 KAMAS SUB DISTRIBUTION-UNA TIEN 46.00 12.47
18 KEARNS SUB DISTRIBUTION-UNA TIEN 138.00 12.47
19 KENSINGTON SUB DISTRIBUTION-UNA TIEN 46.00 4.16
20 LAKE PARK SUB DISTRIBUTION-UNATIEN 138.00 12.47
21 LARK SUB DISTRIBUTION-UNATIEN 46.00 12.47
22 LAYTON SUB DISTRIBUTION-UNA TIEN 46.00 12.47
23 LEGRANDE SUB DISTRIBUTION-UNA TIEN 46.00 12.47
24 LEWISTON SUB DISTRIBUTION-UNA TIEN 46.00 12.47
25 LINCOLN SUB DISTRIBUTION-UNA TIEN 46.00 12.47
26 LINDON SUB DISTRIBUTION-UNA TIEN 46.00 12.47
27 LISBON SUB DISTRIBUTION-UNA TIEN 69.00 12.47
28 L1TILE MOUNTAIN SUB DISTRIBUTION-UNATIEN 46.00 12.47
29 LOAFER SUB DISTRIBUTION-UNA TIEN 46.00 12.47
30 LOGAN CANYON SUB DISTRIBUTION-UNA TIEN 46.00 7.20
31 LONE TREE SUB DISTRIBUTION-UNA TIEN 34.50 12.47
32 LOWER BEAVER SUB DISTRIBUTION-UNA TIEN 46.00 6.60
33 LYNNDYL SUB DISTRIBUTION-UNA TIEN 46.00 12.47
34 MAESERSUB DISTRIBUTION-UNA TIEN 69.00 12.47
35 MAGNA SUB DISTRIBUTION-UNA TIEN 138.00 12.47
36 MANILA SUB DISTRIBUTION-UNA TIEN 46.00 12.47
37 MANTUA SUB DISTRIBUTION-UNA TIEN 46.00 12.47
38 MAPLETON SUB .DISTRIBUTION-UNA TIEN 46.00 12.47
39 MARRIOTISUB DISTRIBUTION-UNA TIEN 46.00 12.47
40 MARYSVALE SUB DISTRIBUTION-UNA TIEN 46.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.13
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 04/18/2011
SUBSTATIONS (Continued)
5. Show in columns (I), (j, 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
óf 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)
50 2 1
22 1 2
4 1 3
32 2 4
22 1 5
13 2 6
1 1 7
5 3 8
2 1 9
22 1 10
13 2 11
30 1 12
30 1 13
2 3 14
3 1 15
5 1 16
7 1 17
60 2 18
7 1 19
53 2 20
6 1 21
40 2 22
2 1 23
14 1 24
20 1 25
20 1 26
4 1 27
20 1 28
1 29
1 1 30
20 1 31
1 3 32
4 1 33
13 1 34
30 1 35
22 1 36
.2 1 37
14 1 38
20 1 39
2 3 40
FERC FORM NO.1 (ED. 12-96)Page 427.13
Name of Respondent This 180rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Oóginal (Mo, Da, Yr)End of 2010/Q4
(2) ¡=A Resubmission 04/18/2011
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 Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 MATHIS SUB DISTRIBUTION-UNATIEN 46.00 12.47
2 MCCORNICK SUB DISTRIBUTION-UNA TIEN 46.00 12.47
3 MCKAY SUB DISTRIBUTION-UNA TIEN 46.00 12.47
4 MEADOWBROOK SUB DISTRIBUTION-UNA TIEN 138.00 12.47 46.00
5 MEDICAL SUB DISTRIBUTION-UNA TIEN 46.00 12.47
6 MELLING SUB DISTRIBUTION-UNA TIEN 34.50 4.16
7 MIDLAND SUB DISTRIBUTION-UNA TIEN 138.00 12.47 .
8 MIDVALE SUB DISTRIBUTION-UNA TIEN 46.00 12.47
9 MILFORD SUB DISTRIBUTION-UNA TIEN 46.00 12.47
10 MILFORD TV SUB DISTRIBUTION-UNA TIEN 46.00 13.20
11 MILLVILLE SUB DISTRIBUTION-UNA TIEN 46.00 12.47
12 MINERSVILLE SUB DISTRIBUTION-UNA TIEN 46.00 12.47
13 MOAB CITY SUB DISTRIBUTION-UNA TIEN 69.00 12.47
14 MONTEZUMA SUB DISTRIBUTION-UNA TIEN 69.00 12.47
15 MOORE SUB DISTRIBUTION-UNATIEN 69.00 12.47
16 MORGAN SUB DISTRIBUTION-UNA TIEN 46.00 4.16
17 MORONI SUB DISTRIBUTION-UNA TIEN 46.00 12.47
18 MORTON COURT SUB DISTRIBUTION-UNA TIEN 138.00 12.47
19 MOSS JUNCTION SUB DISTRIBUTION-UNA TIEN 46.00 12.47
20 MOUNTAIN DELL SUB DISTRIBUTION-UNA TIEN 46.00 12.47
21 MOUNTAIN GREEN SUB DISTRIBUTION-UNA TIEN 46.00 12.47
22 MYTON SUB DISTRIBUTION-UNATIEN 69.00 12.47
23 NEW HARMONY SUB DISTRIBUTION-UNA TIEN 69.00 12.47
24 NEWGATE SUB DISTRIBUTION-UNA TIEN 46.00 12.47
25 NEWTON SUB DISTRIBUTION-UNA TIEN 46.00 12.47
26 NIBLEY SUB DISTRIBUTION-UNA TIEN 46.00 24.90
27 NORTH BENCH SUB DISTRIBUTION-UNA TIEN 46.00 12.47
28 NORTH FIELDS SUB DISTRIBUTION-UNA TIEN 46.00 12.47
29 NORTH LOGAN SUB DISTRIBUTION-UNA TIEN 46.00 12.47
30 NORTH OGDEN SUB DISTRIBUTION-UNA TIEN 46.00 12.47
31 NORTH SALT LAKE SUB DISTRIBUTION-UNATIEN 46.00 13.20
32 NORTHEAST SUB DISTRIBUTION-UNA TIEN 46.00 12.50
33 NORTHRIDGE SUB DISTRIBUTION-UNA TIEN 46.00 12.47
34 OAKLAND AVE SUB DISTRIBUTION-UNA TIEN 46.00 12.47
35 OAKLEY SUB DISTRIBUTION-UNA TIEN 46.00 12.47
36 OLYMPUS SUB DISTRIBUTION-UNA TIEN 46.00 12.47
37 OPHIR SUB DISTRIBUTION-UNA TIEN 46.00 12.47
38 ORANGE SUB DISTRIBUTION-UNA TIEN 46.00 12.47
39 ORANGEVILLE SUB DISTRIBUTION-UNATIEN 69.00 12.47
40 OREM SUB DISTRIBUTION-UNA TIEN 46.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.14
Name of Respondent This i:0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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 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)
9 1 1
6 1 2
20 1 3
42 2 4
58 4 5
5 1 6
30 1 7
25 1 8
14 1 9
1 10
13 1 11
2 1 12
19 2 13
13 1 14
3 1 15
3 1 16
6 1 17
25 1 18
6 3 19
5 1 .20
6 1 21
6 1 22
7 1 23
20 1 24
5 1 25
14 1 26
25 1 27
2 1 28
25 1 29
22 1 30
25 1 31
45 2 32
14 1 33
24 2 34
6 1 35.
22 1 36
3 1 37
20 1 38
14 1 39
48 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.14
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 PACK CREEK RESERVOIR DISTRIBUTION-UNATTEN 46.00 12.47
2 PANGUITCH SUB DISTRIBUTION-UNATTEN 69.00 .12.47
3 PARlETTE SUBSTATION DISTRIBUTION-UNA TTEN 69.00 24.90
4 PARK CITY SUB DISTRIBUTION-UNA TTEN 46.00 12.47
5 PARKWAY SUB DISTRIBUTION-UNATTEN 138.00 12.47
6 PARLEYS SUB DISTRIBUTION-UNA TTEN 46.00 12.47
7 PELICAN POINT SUB DISTRIBUTION-UNA TTEN 46.00 12.47
8 PINE CANYON SUB DISTRIBUTION-UNATTEN 138.00 12.47
9 PINE CREEK SUB DISTRIBUTION-UNA TTEN 46.00 12.47
10 PINNACLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
11 PLAIN CITY SUB DISTRIBUTION-UNA TTEN 138.00 12.47
12 PLEASANT GROVE SUB DISTRIBUTION-UNA TTEN 46.00 12.47.
13 PLEASANT VIEW SUB DISTRIBUTION-UNA TTEN 46.00 12.47
14 PORTER ROCKWELL SUB DISTRIBUTION-UNA TTEN 138.00 12.47
15 PROMONTORY SUB DISTRIBUTION-UNA TTEN 46.00 12.47
16 QUAIL CREEK SUB DISTRIBUTION-UNA TTEN 34.50 12.47
17 QUARRY SUB DISTRIBUTION-UNA TTEN 138.00 12.47
18 QUICHAPA SUB DISTRIBUTION-UNA TTEN 34.50 12.47
19 RAINS SUB DISTRIBUTION-UNA TTEN 46.00 7.20
20 RANDOLPH SUB DISTRIBUTION-UNA TTEN 46.00 12.47
21 RASMUSON SUB DISTRIBUTION-UNA TTEN 46.00 12.47
22 RATTLESNAKE SUB DISTRIBUTION-UNA TTEN 69.00 24.90
23 RED MOUNTAIN SUB DISTRIBUTION-UNA TTEN 69.00 34.50
24 RED ROCK SUB DISTRIBUTION-UNATTEN 69.00 4.16
25 REDWOOD SUB DISTRIBUTION-UNA TTEN 46.00 12.47
26 RESEARCH PARK SUB DISTRIBUTION-UNA TTEN 46.00 12.47
27 RICH SUB DISTRIBUTION-UNA TTEN 69.00 12.47
28 RICHFIELD SUB DISTRIBUTION-UNA TTEN 46.00 12.47
29 RICHMOND SUB DISTRIBUTION-UNA TTEN 46.00 12.47
30 RIDGELAND SUB DISTRIBUTION-UNA TTEN 138.00 12.47
31 RITER SUB DISTRIBUTION-UNA TTEN 46.00 12.47
32 ROCK CANYON SUB DISTRIBUTION-UNA TTEN 69.00 12.47
33 ROCKVILLE SUB DISTRIBUTION-UNA TTEN 34.50 12.47
34 ROCKY POINT DISTRIBUTION-UNA TTEN 138.00 13.20
35 ROSE PARK SUB DISTRIBUTION-UNA TTEN 46.00 12.47
36 ROYAL SUB DISTRIBUTION-UNA TTEN 46.00 4.16
37 SALINA SUB DISTRIBUTION-UNA TTEN 46.00 12.47
38 SANDY SUB DISTRIBUTION-UNA TTEN 138.00 12.47
39 SARATOGA SUB DISTRIBUTION-UNA TTEN 138.00 12.47
40 SCIPIO SUB DISTRIBUTION-UNA TTEN 46.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.15
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifCorp (1 )~An Original (Mo, Da, Yr)End of 2010/Q4
(2)OA Resubmission 04/18/2011
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 Lin~
(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)
4 1 1
5 1 2
4 3 3
35 2 4
50 2 5
16 2 6.
6 1 7
55 2 8
2 1 9
14 1 10
22 1 11
25 1 12
14 1 13
30 1 14
2 1 15
4 1 16
60 2 17
4 1 18
15 1 19
2 1 20
1 3 21
14 1 22
13 1 23
3 1 24
45 2 25
45 2 26
5 1 27
22 2 28
11 1 29
40 2 30
20 1 31
5 1 32
4 1 33
30 1 34
24 3 35
3 36
11 1 37
60 2 38
30 1 39
1 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 2010/Q4
(2)A Resubmission 04/18/2011
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)o
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 SCOFIELD RESERVOIR SUB DISTRIBUTION-UNATIEN 46.00 7.20
2 SCOFIELD SUB DISTRIBUTION-UNA TIEN 46.00 12.47
3 SECOND STREET SUB DISTRIBUTION-UNA TIEN 46.00 12.47
4 SEVEN MILE SUB DISTRIBUTION-UNA TIEN 46.00 12.47
5 SHARON SUB DISTRIBUTION-UNA TIEN 46.00 12.47
6 SHIVWITS SUB DISTRIBUTION-UNA TIEN 34.50 4.16
7 SHORELINE SUB DISTRIBUTION-UNA TIEN 138.00 13.20
8 SIXTH SOUTH SUB DISTRIBUTION-UNATIEN 46.00 12.47
9 SKULL VALLEY SUB DISTRIBUTION-UNATIEN 46.00 12.47
10 SNARR SUB DISTRIBUTION-UNA TIEN 46.00 12.47
11 SNOWVILLE SUB DISTRIBUTION-UNA TIEN 69.00 12.47
12 SNYDERVILLE SUB DISTRIBUTION-UNA TIEN 138.00 12.47
13 SOLDIER SUMMIT SUB DISTRIBUTION-UNA TIEN 69.00 12.47
14 SOUTH JORDAN SUB DISTRIBUTION-UNA TIEN 138.00 12.47
15 SOUTH MILFORD SUB DISTRIBUTION-UNA TIEN 46.00 12.47
16 SOUTH MOUNTAIN SUB DISTRIBUTION-UNA TIEN 138.00 12.47
17 SOUTH OGDEN SUB DISTRIBUTION-UNA TIEN 46.00 12.47
18 SOUTH PARK SUB DISTRIBUTION-UNA TIEN 138.00 12.47
19 SOUTH WEBER SUB DISTRIBUTION-UNA TIEN 138.00 12.47
20 SOUTHEAST SUB DISTRIBUTION-UNA TIEN 138.00 12.47 46.00
21 SOUTHWEST SUB DISTRIBUTION-UNA TIEN 46.00 12.47
22 SPANISH VALLEY SUB DISTRIBUTION-UNA TIEN 69.00 12.47
23 SPRINGDALE SUB DISTRIBUTION-UNA TIEN 34.50 12.47
24 ST. JOHNS SUB DISTRIBUTION-UNA TIEN 46.00 12.47
25 STAIRS SUB DISTRIBUTION-UNA TIEN 12.47 2.40
26 STANSBURY SUB DISTRIBUTION-UNA TIEN 46.00 12.47
27 SUMMIT CREEK SUB DISTRIBUTION-UNA TIEN 138.00 12.47
28 SUMMIT PARK SUB DISTRIBUTION-UNA TIEN 46.00 12.47
29 SUNRISE SUB DISTRIBUTION-UNA TIEN 138.00 12.47
30 SUPERIOR SUB DISTRIBUTION-UNA TIEN 69.00 12.47
31 SUTHERLAND SUB DISTRIBUTION-UNA TIEN 46.00 12.47
32 TAMARISK SUB DISTRIBUTION-UNA TIEN 138.00 12.47
33 TAYLOR SUB DISTRIBUTION-UNA TIEN 46.00 12.47
34 THIEF CREEK SUB DISTRIBUTION-UNA TIEN 138.00 24.90
35 THIRD WEST SUB DISTRIBUTION-UNA TIEN 46.00 12.47
36 THIRTEENTH SOUTH SUB DISTRIBUTION-UNA TIEN 46.00 12.47
37 THOMPSON SUB DISTRIBUTION-UNA TIEN 46.00 4.16
38 TOOELE DEPOT SUB DISTRIBUTION-UNA TIEN 46.00 12.50
39 TOQUERVILLE SUB DISTRIBUTION-UNA TIEN 69.00 12.47 34.50
40 TRI CITY SUB DISTRIBUTION-UNA TIEN 138.00 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.16
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) r=A Resubmission 04/18/2011
...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 Capaci No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
1 1 1
1 3 2
13 2 3
5 3 4
20 1 5
6 1 6
60 2 7
20 1 8
2 1 9
40 2 10
5 1 11
60 2 12
13 1 13
30 1 14
20 2 15
60 2 16
25 1 17
30 1 18
50 1 19
50 2 20
22 2 21
6 1 22
4 1 23
4 1 24
2 1 25
20 1 26
14 1 27
7 1 28
30 1 29
8 1 30
6 1 31
20 1 32
14 1 33
14 1 34
40 2 35
24 2 36
2 1
.37
25 1 38
34 2 39.
30 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.16
Näme of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) ÕA Resubmission 04/18/2011
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be groupe according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize accrding to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 UINTAH SUB DISTRIBUTION-UNA TTEN 46.00 12.47
2 UNION SUB DISTRIBUTION-UNATTEN 46.00 12.47
3 UNIVERSITY SUB DISTRIBUTION-UNATTEN 46.00 4.16
4 VALLEY CENTER SUB DISTRIBUTION-UNATTEN 46.00 12.47
5 VERMILLION SUB DISTRIBUTION-UNATTEN 46.00 12.47
6 VERNAL SUB DISTRIBUTION-UNA TTEN 69.00 12.47
7 VEYO HYDRO DISTRIBUTION-UNATTEN .34.50 2.40
8 VICKERS SUB DISTRIBUTION-UNA TTEN 46.00 12.47
9 VINEYARD SUB DISTRIBUTION-UNA TTEN 46.00 12.47
10 WALLSBURG SUB DISTRIBUTION-UNA TTEN 138.00 12.47
11 WALNUT GROVE SUB DISTRIBUTION-UNA TTEN 138.00 12.50
12 WARREN SUB DISTRIBUTION-UNA TTEN 138.00 12.47
13 WASATCH STATE PARK SUB DISTRIBUTION-UNA TTEN 46.00 12.47
14 WASHAKIE SUB DISTRIBUTION-UNA TTEN 138.00 4.16
15 WELBY SUB DISTRIBUTION-UNA TTEN 46.00 12.47
16 WELFARE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
17 WELLINGTON SUB DISTRIBUTION-UNA TTEN 46.00 12.47
18 WEST COMMERCIAL SUB DISTRIBUTION-UNA TTEN 46.00 12.47
19 WEST JORDAN SUB DISTRIBUTION-UNA TTEN 138.00 12.47
20 WEST OGDEN SUB DISTRIBUTION-UNATTEN 138.00 12.47
21 WEST ROY SUB DISTRIBUTION-UNA TTEN 46.00 12.47
22 WEST TEMPLE SUB DISTRIBUTION-UNA TTEN 46.00 4.16
23 WESTFIELD SUB DISTRIBUTION-UNA TTEN 138.00 12.47
24 WESTWATER SUB DISTRIBUTION-UNA TTEN 69.00 12.47
25 WHITE MESA SUB DISTRIBUTION-UNA TTEN 69.00 12.47
26 WHITE ROCK SUB DISTRIBUTION-UNA TTEN 138.00 12.47
27 WILLOWCREEK SUB DISTRIBUTION-UNA TTEN 46.00 12.47
28'WILLOWRIDGE SUB DISTRIBUTION-UNA TTEN 46.00 12.47
29 WINCHESTER HILLS SUB DISTRIBUTION-UNA TTEN 34.50 12.47
30 WINKLEMAN SUB DISTRIBUTION-UNA TTEN 46.00 7.20
31 WOLF CREEK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
32 WOOD CROSS SUB DISTRIBUTION-UNA TTEN 46.00 12.47
33 WOODRUFF SUB DISTRIBUTION-UNA TTEN 46.00 12.47
34 Total 20756.27 3726.81 184.97
35 Number of Substations- 299
36
37 ANGEL SUB TID-UNATTENDED 138.00 12.47 46.00
38 BDO SUBSTATION TID-UNATTENDED 138.00 12.47
39 BUTLERVILLE SUB TID-UNATTENDED 138.00 46.00 12.47
40 COTTONWOOD SUB TID-UNATTENDED 138.00 12.47 46.00
FERC FORM NO.1 (ED. 12-96)Page 426.17
Name of Respondent This 00rt Is:Date of Report Year/Period of Report
Pacifiorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) DA Resubmission 04/18/2011
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 Servce) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
39 2 1
50 2 2
48 4 3
22 1 4
3 1 5
33 2 6
2 3 7
2 1 8
25 1 9
13 1 10
30 1 11
30 1 12
2 3 13
14 1 14.
22 1 15
5 1 16
4 1 17
22 1 18
28 1 19.
30 1 20
25 1 21
60 3 22
20 1 23
1 3 24
14 1 25
30 1 26
1 1 27
14 1 28
4 1 29
1 30
6 1 31
20 1 32
2 1 33
5620 419 1 34
35
.36
135 3 37
30 1 38
175 3 39
289 7 40
FERC FORM NO.1 (ED. 12-96)Page 427.17
Name of Respondent This 00rt Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a).(b)(c)(d)(e)
1 EMMA PARK SUBSTATION TID-UNATTENDED 138.00 12.47
2 HALE SUB TID-UNATTENDED 138.00 46.00 12.47
3 HIGHLAND SUB TID-UNATTENDED 138.00 12.47 46.00
4 JORDAN SUB TID-UNATTENDED 138.00 46.00 12.47
5 JUDGE SUB TID-UNATTENDED 46.00 12.47
6 MCCLELLAND SUB TID-UNATTENDED 138.00 46.00 12.47
7 OQUIRRH SUB TID-UNATTENDED 345.00 46.00 138.00
8 PARRISH SUB TID-UNATTENDED 138.00 12.47 46.00
9 PIONEER PLANT TID-UNATTENDED 138.00 2.30 46.00
10 RIVERDALE SUB TID-UNATTENDED 138.00 46.00 12.47
11 SEVIER SUB TID-UNATTENDED 138.00 46.00 12.47
12 SILVER CREEK SUB TID-UNATTENDED 138.00 12.47 46.00
13 SPHINX SUB TID-UNATTENDED .46.00 12.47
14 SYRACUSE SUB TID-UNATTENDED 345.00 46.00 138.00
15 TAYLORSVILLE SUB TID-UNATTENDED 138.00 46.00 12.47
16 TERMINAL SUB TID-UNATTENDED 345.00 46.00 138.00
17 TIMP SUB TID-UNATTENDED 138.00 46.00 12.47
18 TOOELE SUB TID-UNATTENDED 138.00 46.00 12.47
19 WEST VALLEY SUB TID-UNATTENDED 138.00 12.47
20 Total 3611.00 679.00 802.23
21 Number of Substations- 23
22
23 EMERY SUB TRANSMISSION-A TTENDE 345.00 138.00 ..69.00
24 GADSBY SUB TRANSMISSION-A TTENDE 138.00 46.00
25 HUNTER PLANT TRANSMISSION-A TTENDE 345.00 23.00
26 HUNTINGTON PLANT TRANSMISSION-A TTENDE 345.00 23.00
27 90TH SOUTH SUB TRANSMISSION-UNA TTEN 345.00 138.00
28 ABAJOSUB TRANSMISSION-UNA TTEN 138.00 69.00
29 ASHLEY SUB TRANSMISSION-UNA TTEN 138.00 46.00
30 BARNEY SUB TRANSMISSION-UNATTEN 138.00 46.00
31 BEN LOMOND SUB TRANSMISSION-UNATTEN 345.00 230.00 138.00
32 BLACKHAWK SUB TRANSMISSION-UNA TTEN 138.00 69.00 46.00
33 BOOKCLIFFS SUB TRANSMISSION-UNA TTEN 69.00 46.00
34 CAMERON SUB TRANSMISSION-UNA TTEN 138.00 46.00
35 CAMP WILLIAMS SUB TRANSMISSION-UNA TTEN 345.00 138.00 12.47
36 CARBON SUB TRANSMISSION-UNA TTEN 138.00
37 COLUMBIA SUB TRANSMISSION-UNA TTEN 138.00 46.00
38 CRANER FLAT SUB TRANSMISSION-UNA TTEN 138.00 12.47
39 CUTLER SUB TRANSMISSION-UNA TTEN 138.00 46.00
40 EL MONTE SUB TRANSMISSION-UNA TTEN 138.00 46.00
FERC FORM NO.1 (ED. 12-96)Page 426.18
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) !KAn Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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 own.ed 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)
8 1 ...1
114 2 2
97 2 3
164 2 4
22 1 5
340 4 6
135 3 7
97 2 8
51 7 9
180 3 10
..34 4 ...11
100 2 12
3 4 3 13
600 5 14
358 4 15
1108 6 2 16
130 2 17
158 3 18
30 1 19
4358 72 5 20
21
22
783 13 1 23
318 2 24
1513 5 1 25
981 4 26
1538 6 1 27
67 1 28
133 2 29
100 1 30
1813 5 31
100 2 32
6 3 1 33
25 3 34
169 2 35
8 1 36
33 1 37
40 2 38
70 2 39
313 3 40
FERC FORM NO.1 (ED. 12-96)Page 427.18
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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)
NQ.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 GARKANE SUB TRANSMISSION-UNATTEN 69.00 46.00
2 GREEN CANYON SUB TRANSMISSION-UNA TTEN 138.00 46.00
3 GRINDING SUB TRANSMISSION-UNATTEN 138.00 13.80
4 HELPER SUB TRANSMISSION-UNATTEN 138.00 46.00
5 HONEYVILLE SUB TRANSMISSION-UNATTEN 138.00 46.00
6 HORSESHOE SUB TRANSMISSION-UNA TTEN 138.00 46.00 12.47
7 HUNTINGTON SUB TRANSMISSION-UNA TTEN 345.00 138.00
8 JERUSALEM SUB TRANSMISSION-UNA TTEN 138.00 46.00
9 LAMPO SUB TRANSMISSION-UNA TTEN 138.00 46.00
10 MCFADDEN SUB TRANSMISSION-UNA TTEN 138.00 46.00
11 MIDDLETON SUB TRANSMISSION-UNA TTEN 138.00 69.00 34.50
12 MIDVALLEY SUB TRANSMISSION-UNATTEN 345.00 138.00
13 MIDWAY CITY SUB TRANSMISSION-UNA TTEN 138.00 46.00
14 MINERAL PRODUCTS SUB TRANSMISSION-UNA TTEN 69.00 .46.00
15 MOAB SUB TRANSMISSION-UNA TTEN .138.00 69.00 .
16 NEBOSUB TRANSMISSION-UNA TTEN 138.00 46.00
17 OLMSTED SUB .TRANSMISSION-UNA TTEN 46.00 2.40
18 PAROWAN VALLEY SUB TRANSMISSION-UNATTEN 230.00 138.00 34.50
19 PAVANT SUB TRANSMISSION-UNA TTEN 230.00 46.00
20 PINTO SUB TRANSMISSION-UNA TTEN 345.00 138.00 69.00
21 RED BUTTE SUB TRANSMISSION-UNA TTEN 230.00 138.00
22 SAND COVE HYDRO TRANSMISSION-UNA TTEN 34.50 2.40
23 SIGURD SUB TRANSMISSION-UNA TTEN 345.00 230.00 138.00
24 SMITHFIELD SUB TRANSMISSION-UNA TTEN 138.00 46.00 12.47
25 SPANISH FORK SUB TRANSMISSION-UNA TTEN 345.00 138.00 46.00
26 ST GEORGE SUB TRANSMISSION-UNA TTEN 138.00 16.50
27 THREE PEAKS SUB TRANSMISSION-UNA TTEN 345.00 138.00
28 WEBER PLANT/SUB TRANSMISSION-UNA TTEN 46.00 2.30
29 WEST CEDAR SUB TRANSMISSION-UNA TTEN 230.00 138.00 34.50
30 Total 8843.50 3315.87 646.91
31 Number of Substations- 47
32
33 Washington
34 ATTAllA SUB DISTRIBUTION-UNA TTEN 69.00 12.47
35 BOWMAN SUB DISTRIBUTION-UNA TTEN 69.00 12.47
36 CASCADE KRAFT SUB DISTRIBUTION-UNA TTEN 69.00 12.47 4.16
37 CLINTON SUB DISTRIBUTION-UNA TTEN 115.00 12.47
38 DAYTON SUB DISTRIBUTION-UNA TTEN 69.00 12.47
39 DODD ROAD SUB DISTRIBUTION-UNA TTEN 69.00 20.80
40 GRANDVIEW SUB DISTRIBUTION-UNA TTEN 115.00 12.47 69.00
FERC FORM NO.1 (ED. 12-96)Page 426.19
Name of Respondent This '00rt Is:Date of Report "Year/Period of Report
PacifiCorp (1) . X An Original (Mo, Da, Yr)End of 2010/Q4
(2) r"A Resubmission 04/18/2011
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)
33 1 1
67 2 2
225 3 3
142 2 4.
35 1 5
80 2 6
270 4 7
67 1 8
75 1 9
45 1 10
141 4 11
900 2 12
67 1 13
13 1 14
67 1 15
67 1 16
15 1 17
.138 2 18
133 2 19
258 3 20
400 1 21
1 22
1124 6 23
63 2 24
1017 5 25
100 3 1 26
450 1 27
7 1 28
131 2 29
14140 116 5 30
31
32
33..25 1 34
45 2 35
117 6 36
25 1 37
23 2 38
25 4 39
56 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.19
Name of Respondent This 'l0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo,Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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)o
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 HOPLAND SUB .DISTRIBUTION-UNATIEN 115.00 12.47
2 MILL CREEK SUB DISTRIBUTION-UNATIEN 69.00 12.47
3 NACHES HYDRO DISTRIBUTION-UNA TIEN 115.00 12.47
4 NOB HILL SUB DISTRIBUTION-UNA TIEN 115.00 12.47
5 NORTH PARK SUB DISTRIBUTION-UNA TIEN 115.00 12.47
6 ORCHARD SUB DISTRIBUTION-UNATIEN 115.00 12.47
7 PACIFIC SUB .DISTRIBUTION-UNA TIEN 115:00 12.47
8 POMEROY SUB DISTRIBUTION-UNA TIEN 69.00 12.47
9 PROSPECT POINT SUB DISTRIBUTION-UNA TIEN 69.00 12.47
.10 PUNKIN CENTER SUB DISTRIBUTION-UNA TIEN 115.00 12.47
11 RIVER ROAD SUB DISTRIBUTION-UNA TIEN 115.00 12.47
12 SELAH SUB DISTRIBUTION-UNA TIEN 115.00 12.47
1.3 SULPHUR CREEK SUB DISTRIBUTION-UNA TIEN 115.00 12.47
14 SUNNYSIDE SUB DISTRIBUTION-UNA TIEN 115.00 12.47
15 TIETON SUB DISTRIBUTION-UNA TIEN 115.00 12.47 34.50
16 TOPPENISH SUB DISTRIBUTION-UNA TIEN 115.00 12.47 .
17 TOUCHET SUB DISTRIBUTION-UNA TIEN 69.00 12.47
18 VOELKER SUB DISTRIBUTION-UNA TIEN 115.00 12.47
19 WAITSBURG SUB DISTRIBUTION-UNA TIEN 69.00 12.47
20 WAPATO SUB DISTRIBUTION-UNA TIEN 115.00 12.47
21 WENASSUB DISTRIBUTION-UNA TIEN 115.00 12.47
22 WHITE SWAN SUB DISTRIBUTION-UNA TIEN 115.00 12.47
23 WILEY SUB DISTRIBUTION-UNA TIEN 115.00 12.47
24 Total 2990.00 382.43 107.66
25 Number of Substations- 30
26
27 CENTRAL SUB T/D-UNA TIENDED 69.00 12.47
28 UNION GAP SUB T/D-UNATIENDED 230.00 115.00 12.47
29 Total 299.00 127.47 12.47
30 Number of Substations- 2
31
32 CONDIT PLANT TRANSMISSION-A TIENDE 69.00 2.30
33 MERWIN PLANT TRANSMISSION-A TIENDE 115.00 13.20
34 YALE PLANT TRANSMISSION-A TIENDE 115.00 13.80
35 OUTLOOK SUB TRANSMISSION-UNA TIEN 230.00 115.00
36 PASCO SUB TRANSMISSION-UNATIEN 115.00 69.00 7.20
37 POMONA HEIGHTS SUB TRANSMISSION-UNATIEN 230.00 115.00
38 WALLA WALLA 230KV SUB TRANSMISSION-UNATIEN 230.00 69.00
39 WALLULA SUB TRANSMISSION-UNATIEN 230.00 69.00
40 WINE COUNTRY SUB TRANSMISSION-UNA TIEN 230.00 115.00
FERC FORM NO.1 (ED. 12-96)Page 426.20
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1 )lKAn Original (Mo, Da, Yr)End of 2010/Q4
(2)¡=A Resubmission 04/18/2011
SUBSTATIONS (Continued)
5. Show in columns (i), (j, and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capaCity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other 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)(j)(k)
50 2 1
45 2 2
20 1 3
42 2 4
45 2 5
50 2 6
28 3 7
9 1 8
40 2 9
20 2 10.
51 4 11
45 2 12
25 1 ..13
45 2 14
29 2 15
50 2 16
6 1 17
25 1 18
9 1 19
45 2 20
25 2 21
22 2 22
45 2 23
1087 61 24
25
26
14 1 27
348 5 28
362 6 29
30
31
13 6 1 32
183 9 1 33
144 3 1 34
125 1 35
39 9 36
300 2 37
300 2 38
120 2 39
250 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.20
Name of Respondent This wort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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 Total 1564.00 581.30 7.20
2 Number of Substations- 9
3
4 Wyoming
5 AIR BASE DISTRIBUTION-UNA TTEN 12.47 2.40
6 ANTELOPE MINE SUB DISTRIBUTION-UNA TTEN 230.00 34.50
7 ASTLE STREET DISTRIBUTION-UNA TTEN 34.50 13.20
8 BAILEY DOME SUB DISTRIBUTION-UNA TTEN 57.00 12.47
9 BARXSUB DISTRIBUTION-UNA TTEN 230.00 34.50
10 BID MUDDY SUB DISTRIBUTION-UNA TTEN 69.00 12.47
11 BIG PINEY SUB DISTRIBUTION-UNA TTEN 69.00 24.90
12 BLACKS FORK SUB DISTRIBUTION-UNATTEN 230.00 34.50
13 BRIDGER PUMP SUB DISTRIBUTION-UNATTEN 230.00 34.50 13.20
14 BRYAN SUB DISTRIBUTION-UNATTEN 115,00 12.47
15 BUFFALO TOWN SUB DISTRIBUTION-UNATTEN 20.80 4.16
16 BYRON SUB DISTRIBUTION-UNA TTEN 34.50 4.16
17 CASSASUB DISTRIBUTION-UNA TTEN 57.00 20.80
18 CENTER STREET SUB DISTRIBUTION-UNA TTEN 115.00 4.16
19 CHAPMAN SUBSTATION DISTRIBUTION-UNA TTEN 46.00 12.47
20 CHATHAM SUB DISTRIBUTION-UNA TTEN 34.50 4.16
21 CHUKARSUB DISTRIBUTION-UNA TTEN 12.47 4.16
22 CHURCH AND DWIGHT SUB DISTRIBUTION-UNA TTEN 34.50 0.48
23 COKEVILLE SUB DISTRIBUTION-UNATTEN 46.00 24.90
24 COLUMBIA-GENEVA SUB DISTRIBUTION-UNA TTEN 230.00 13.80
25 COMMUNITY PARK SUB DISTRIBUTION-UNATTEN 115.00 13.20
26 CROOKS GAP SUB DISTRIBUTION-UNA TTEN 34.50 12.47
27 DEER CREEK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
28 DJ COAL MINE SUB DISTRIBUTION-UNA TTEN 69.00 34.50
29 DOUGLAS SUB DISTRIBUTION-UNA TTEN 57.00 2.30
30 DRY FORK SUB DISTRIBUTION-UNA TTEN 69.00 4.16
31 ELK BASIN SUB DISTRIBUTION-UNA TTEN 34.50 7.20
32 ELK HORN SUB DISTRIBUTION-UNA TTEN 115.00 12.50
33 EMIGRANT SUB DISTRIBUTION-UNA TTEN 115.00 12.47
34 EVANS SUB DISTRIBUTION-UNA TTEN 115.00 12.47
35 EVANSTON SUB DISTRIBUTION-UNA TTEN 138.00 12.47
36 FARMERS UNION SUB DISTRIBUTION-UNA TTEN 34.50 4.16
37 FIREHOLE SUB DISTRIBUTION-UNATTEN 230.00 34.50
38 FORT CASPER SUB DISTRIBUTION-UNA TTEN 69.00 12.47
39 FORT SANDERS SUB DISTRIBUTION-UNA TTEN 115.00 13.20
40 FRANNIE SUB DISTRIBUTION-UNA TTEN 230.00 34.50
FERC FORM NO.1 (ED. 12-96)Page 426.21
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1 )!KAn Original (Mo, Da, Yr)End of 2010/Q4
(2)OA Resubmission 04/18/2011
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 Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
1474 35 3 1
2
3
4
1 3 5
25 1 6
13 1 7
2 1 8
25 1 9
7 1 10
8 1 11
150 2 12
73 4 13
25 1 .14
2 3 15
2 3 16
2 6 1 17
13 1 18
4 1 ,.19
3 20
1 3 21
3 2 22
4 1 23
45 2 24
50 2 25
.5 3 26
9 1 27
13 1 28
6 3 29
9 1 30
5 1 31
25 1 32
13 1 33
9 1 34
40 2 35
2 3 36
50 2 37
25 1 38
20 1 39
50 2 40
FERC FORM NO.1 (ED. 12-96)Page 427.21
Name of Respondent This l80rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/18/2011
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)o
c
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 FRONTIER SUB DISTRIBUTION-UNA TTEN 69.00 4.16
2 GARLAND SUB DISTRIBUTION-UNATTEN 230.00 34.50
3 GLENDO SUB DISTRIBUTION-UNATTEN 57.00 4.16
4 GRASS CREEK SUB DISTRIBUTION-UNA TTEN 230.00 34.50
5 GREAT DIVIDE SUB DISTRIBUTION-UNA TTEN 115.00 34.50
6 GREYBULL SUB DISTRIBUTION-UNA TTEN 34.50 4.16
7 HANNA SUB DISTRIBUTION-UNA TTEN 34.50 12.47
8 JACKALOPE SUB DISTRIBUTION-UNA TTEN 115.00 12.47
9 KEMMERER SUB DISTRIBUTION-UNA TTEN 69.00 24.90
10 KIRBY CREEK PUMPING STATION DISTRIBUTION-UNATTEN 34.50 2.40
11 KIRBY CREEK SUB DISTRIBUTION-UNATTEN 34.50 4.16
12 LANDER SUB DISTRIBUTION-UNATTEN 34.50 12.47
13 LARAMIE SUB DISTRIBUTION-UNATTEN 115.00 13.20
14 LATHAM SUB DISTRIBUTION-UNA TTEN 230.00 34.50
15 LINCH SUB DISTRIBUTION-UNA TTEN 69.00 13.80
16 LITTLE MOUNTAIN SUB DISTRIBUTION-UNA TTEN 230.00 34.50
17 LOVELL SUB DISTRIBUTION-UNA TTEN 34.50 4.16
18 MILL IRON SUB DISTRIBUTION-UNA TTEN 34.50 13.80
19 MILLS SUB DISTRIBUTION-UNA TTEN 12.47 4.16
20 MURPHY DOME SUB DISTRIBUTION-UNA TTEN 34.50 13.20
21 NUGGETTSUB DISTRIBUTION-UNATTEN 69.00 7.20
22 OPAL SUB DISTRIBUTION-UNA TTEN 46.00 24.90
23 ORIN SUB DISTRIBUTION-UNA TTEN 57.00 12.47
24 ORPHASUB DISTRIBUTION-UNA TTEN 57.00 7.20
25 PARADISE SUB DISTRIBUTION-UNA TTEN 69.00 25.00
26 PARCO SUB DISTRIBUTION-UNA TTEN 34.50 12.47
27 PINEDALE SUB DISTRIBUTION-UNA TTEN 69.00 24.90
28 PITCHFORK SUB DISTRIBUTION-UNA TTEN 69.00 24.90
29 POINT OF ROCKS SUB DISTRIBUTION-UNA TTEN 230.00 34.50
30 POISON SPIDER SUB DISTRIBUTION-UNA TTEN 69.00 2.40
31 POLECAT SUB DISTRIBUTION-UNA TTEN 34.50 12.47
32 RAINBOW SUB DISTRIBUTION-UNA TTEN 34.50 13.20
33 RAVEN SUB DISTRIBUTION-UNA TTEN 230.00 34.50
34 RED BUTTE SUB DISTRIBUTION-UNA TTEN 69.00 12.47
35 REFINERY SUB DISTRIBUTION-UNA TTEN 115.00 12.47
36 SAGE HILL SUB DISTRIBUTION-UNA TTEN 34.50 13.20
37 SHOSHONI SUB DISTRIBUTION-UNA TTEN 34.50 2.40
38 SLATE C~EEK SUB DISTRIBUTION-UNA TTEN 69.00 12.47
39 SOUTH CODY SUB DISTRIBUTION-UNA TTEN 69.00 24.90
40 SOUTH ELK BASIN SUB DISTRIBUTION-UNA TTEN 34.50 4.16
FERC FORM NO.1 (ED. 12-96)Page 426.22
Name of Respondent This î80rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
.(2) i:A Resubmission 04/18/2011
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT 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)
6 1 1
45 2 2
3 4 3
25 1 4
20 1 5
I 3 1 6
6 1 7
25 1 8
10 1 9.
3 3 10
2 3 11
25 2 12
50 2 13
25 1 14
13 1 15,
20 1 16
4 3 17
13 1 1 18
1 3 19
5 1 20
1 21
8 1 22
2 3 23
3 3 24
30 1 25
5 1 26
8 1 27
17 9 2 28
25 1 29
3 1 30
2 3 31
13 1 32
200 2 33
20 1 34
45 2 35
6 1 36
2 3 37
1 1 38
14 3 1 39
2 6 40
FERC FORM NO.1 (ED. 12-96)Page 427.22
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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)o
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 SOUTH TRONA SUB DISTRIBUTION-UNATIEN 230.00 34.50
2 SPRING CREEK SUB DISTRIBUTION-UNATIEN 115.00 13.20
3 SVILARSUB DISTRIBUTION-UNATIEN 34.50 4.16
4 TEN MILE STEP DOWN SUB DISTRIBUTION-UNA TIEN 34.50 12.50
5 TEN MILE SUB DISTRIBUTION-UNA TIEN 69.00 34.50
6 THERMOPOLIS TOWN SUB DISTRIBUTION-UNA TIEN 34.50 4.16
7 THUNDER CREEK SUB "DISTRIBUTION-UNA TIEN 57.00 12.47 .
8 VETERANS SUB DISTRIBUTION-UNA TIEN 34.50 13.20
9 WELCH SUB DISTRIBUTION-UNA TIEN 57.00 2.40
10 WERTZ-SINCLAIR SUB DISTRIBUTION-UNA TIEN 57.00 4.16 12.50
11 WEST ADAMS SUB DISTRIBUTION-UNATIEN 34.50 4.16
12 WESTERN CLAY SUB DISTRIBUTION-UNA TIEN 34.50 OA8
13 WESTVACO SUB DISTRIBUTION-UNATIEN 230.00 34.50
14 WORLAND TOWN SUB DISTRIBUTION-UNA TIEN 34.50 4.16
15 WYOPOSUB DISTRIBUTION-UNA TIEN 230.00 34.50
16 WYUTASUB DISTRIBUTION.UNA TIEN 46.00 12.47
17 Total 8161.21 1404.07 25.70
18 Number of Substations- 92
19
20 BUFFALO SUB TID-UNA TIENDED 230.00 20.80
21 HILLTOP SUB T/D-UNATIENDED 115.00 34.50 20.80
22 LABARGE SUB TID-UNA TIENDED 69.00 24.90
23 RIVERTON 230 SUB T/D-UNATIENDED 230.00 12.47 34.50
24 YELLOWCAKE SUB TID-UNA TIENDED 230.00 34.50
25 Total 874.00 127.17 55,30
26 Number of Substations- 5
27~TRNSMISSION-ATTNOE .230.00 115.00 69.0029 TRANSMISSION-ATIENDE 345.00 230.00 34.50
30 JIM BRIDGER UNITS 1-4 TRANSMISSION-ATIENDE 345.00 22.00
TRANSMISSION-A TIENDE 230.00 69.00 138.0032 ""~" _. ¡¡.._TRANSMISSION-A TIENDE 230.00 69.00
33 WYODAK PLANT TRANSMISSION-A TIENDE 230.00 22.00
34 BAIROIL SUB TRANSMISSION-UNA TIEN 115.00 34.50 57.00
35 CASPER SUB TRANSMISSION-UNA TIEN 230.00 115.00 69.00
36 CHAPPELL CREEK SUB TRANSMISSION-UNA TIEN 230.00 69.00.
37 CHIMNEY BUTIE SUB TRANSMISSION-UNA TIEN 230.00 69.00
38 FOOTE CREEK WIND FARM TRANSMISSION-UNA TIEN 230.00 34.50
39 GLENDO AUTO SUB TRANSMISSION-UNA TIEN 69.00 57.00
40 MANSFACE SUB TRANSMISSION-UNATIEN 230.00 34.50
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 2010/Q4
(2) OA Resubmission 04/18/2011
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 Number of Units Total Capacity No.In Service Transformers Type of Equipment
(In MVa)
(f)(g)(h)(i)0)(k)
150 2 1
25 1 2
2 3 3
5 1 4
13 1 5
5 1 6
9 1 7
25 2 8
3 3 9
2 6 10
3 1 11
1 1 12
25 1 13
5 1 14
20 1 1 15
1 16
1739 173 6 17
18
19
20 1 20
45 2 1 21
8 6 22
50 3 23
25 1 24
148 13 1 25
26
27
1358 17 28
1084 22 29
1122 2 30
1232 15 1 31
60 1 32
503 3 1 33
53 3 34
517 6 35
67 1 .36
75 1 37
196 2 38
15 2 39
20 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.23
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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)o
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 MIDWEST SUB TRANSMISSION-UNATTEN 230.00 69.00 34.50
2 MINERS SUB TRANSMISSION-UNATTEN 230.00 115.00 34.50
3 MUSTANG SUB TRANSMISSION-UNA TTEN 230.00 115.00
4 OREGON BASIN SUB TRANSMISSION-UNA TTEN 230.00 34.50 69.00
5 PLATTE SUB TRANSMISSION-UNA TTEN 230.00 115.00 34.50
6 RAILROAD SUB TRANSMISSION-UNA TTEN 230.00 138.00
7 ROCK SPRINGS 230 SUB TRANSMISSION-UNA TTEN 230.00 34.50
8 SAGE SUB TRANSMISSION-UNA TTEN 69.00 46.00
9 THERMOPOLIS SUB .TRANSMISSION-UNA TTEN 230.00 115.00
10 Total 4853.00 1722.50 540.00
11 Number of Substations- 22
12
13 CALIFORNIA
14 Distribution - 43
15 TID - 3
16 Transmission - 9
17
18 IDAHO
19 Distribution - 66
20 TID -4
21 Transmission - 18
22
23 MONTANA
24 Transmission - 1
25
26 OREGON
27 Distribution - 183
28 TID - 10
29 Transmission - 42
30
31 UTAH
32 Distribution - 299
33 TID - 23
34 Transmission - 47
35
36 WASHINGTON
37 Distribution - 30
38 TID -2
39 Transmission - 9
40
FERC FORM NO.1 (ED. 12-96)Page 426.24
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) ~An Original (Mo, Da, Yr)End of 2010/Q4
(2) OA Resubmission 04/18/2011
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 Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
91 4 1
58 4 1 2
200 2 3
65 2 4
165 4 5
400 1 6
50 2 7.
22 1 8
175 2 9
7528 98 3 10
11
12
13
342 14
129 15
696 16
17.
18
777 19
314 20
3315 21
22
23
100 24
25
26
4526 27
1238 .28
6600 29
30
31
5620 32
4358 33
14140 34
35
36
1087 37
362 38
1474 39
40
FERC FORM NO.1 (ED. 12-96)Page 427.24
Name of Respondent This î:0rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) riA Resubmission 0411812011
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 ofLess than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 WYOMING
2 Distribution - 92
3 T/D - 5
4 Transmission - 22
5
6 ALL STATES
7 Distribution - 713
8 T/D - 47
9 Transmission - 148
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 2010/Q4
(2) riA Resubmission 04/18/2011
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(InService) (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
1739 2
148 3
7528 4
5.
6
14091 7
6549 8
33853 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 04/18/2011 2010/Q4
FOOTNOTE DATA
I$chedule Page: 426.9 Line No.: 26 Column: a
The Dixonvile 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%.
¡Schedule Page: 426.9 Line No.: 38 Column: a
The Meridian 500kV Substation is jointly owned by the respondent and the Bonneville Power Administration (the "BP A").
Ownership of the substation is as follows: PacifiCorp 50.0% and the BP A 50.0%. Operation and maintenance costs are shared
between the two paries and responsibility is as follows: PacifiCorp 58.0% and the BPA42.0%.
¡Schedule Page: 426.23 Line No.: 28 Column: a
The Dave Johnston 230kV Substation is jointly owned by the respondent and Black Hils Power. Ownership of the substation is as
follows: PacifiCorp 85.0% and Black Hils Power 15.0%. Operation and maintenance costs are shared between the two pares and
responsibility is as follows: PacifiCorp 85.0% and Black Hils Power 15.0%.
¡Schedule Page: 426.23 Line No.: 29 Column: a
The Jim Bridger 345kV Substation is jointly owned by the respondent and Idao Power Company. Ownership of the substatio.n is as
follows: PacifiCorp 66.7% and Idaho Power Company 33.3%. Opertion and maintenance costs are shared between the two partes
and responsibility is as follows: PacifiCorp 66.7% and Idao Power Company 33.3%.
¡Schedule Page: 426.23 Line No.: 32 Column: a
TheWyoda 230kV Substation is jointly owned by the respondent and Black Hils Power. Ownership ofthe substation is as follows:
PacifiCorp 80.0% and Black Hils Power 20.0%. Operation and maintenance costs are shared between the two partes and
responsibility is as follows: PacifiCorp 80.0% and Black Hils Power 20.0%.
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
Line
No.
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
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 associated/affliated 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.
Name of Account
Assiciated/Affliated Charged orCompany Credited(b) (c)Description of the Non-Power Good or Service
(a)
1 Non-power Goods or Services Provided by Affliated
2 Coal purchases/ support services / materials and
3 supplies
4
5
6
7
Amount
Charged or Credited
(d)j)~"..;r_r"'j(..
Bridger Coal Company
Coal purchases Trapper Mining Inc.151 12,420,218
8
9
10
11
12
13 Charges over cost cap - retained by M EHC
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
1
2
MHC, Inc.
Cal Energy Generation
CE Electric UK Funding
MEHC
930.2, 426.5, 107
930.2, 426.5
930.2
930.2,107
426.5
11,622,757
1,761,257
1,433,272
816,328
5,211
29,152
-6,667,977
Net management fee bilings (sum of 7 - 13)MEHC see above 9,000,000
Non-power Goods or Services Provided for Affliate
Administrative support services! management fee!
royalties
~~~~.,~
Bridger Coal Company 146
Labor and benefits services (primarily IT costs)MEHC 146
Non-power Goods or Services Provided by Affliated
Gas transportation services
FERC FORM NO.1 (New)
FERC FORM NO.1-F (New)
Page 429
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2010/Q4
Line
No.
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2011
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
1. Report below the information called for concerning all non-power goos or services received from or provided to associated (affliated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount biled to the respondent or biled to
an associated/affliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not
attempt to include or aggregate amounts in a nonspecific category such as "general".
3. Where amounts biled to or received from the associated (affliated) company are based on an allocation process, explain in a footnote.
Name of Accunt
AssiciatedlAffliated Charged orCompany Credited(b) (c)Description of the Non-Power Good or Service
(a)
Amount
Charged or Credited
(d)
3
4 Relocation services
5
6
7
8 Rail servicesl right-of-way fees
9
10
11 Financial transactions related to energy hedging
12 activity and banking services
13
14 Water treatment services at generating facilties
15
16
17
18
19
20 Non-power Goods or Services Provided for Affliate
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
1 Non-power Goods or Services Provided by Affliated
2
3
4
Home8ervices 2,053,556
MEHC Insurance Svcs. 924, 925 6,969,001
BNSF Railway Company 151,507,567,589
Nalco Holding Company
28,815,677Wells Fargo & Company
3,225,464
..J~~".~
FERC FORM NO.1 (New)
FERC FORM NO.1.F (New)
Page 429.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 04/18/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 429 Line No.: 2 Column:
Accounts charged for Bridger Coal Company: 232, 500, 501, 511, 553,151.
I$chedule Page: 429 Line No.: 2 Column:
Non-power goods or services provided by Bridger Coal Company are as follows:
Coal purchases
Support services/materials and supplies
$128,741,571
62.454
$ 128,804,025¡Schedule Page: 429 Line No.: 7 Column: I
The amounts in column (d) were the amounts biled by MERC and its affliates to PacifiCorp on the consolidated bil through MERC
under the Intercompany Administrative Services Agreement. The fee was capped at $9 milion for the year ended December 31,
2010. A portion of the services provided by MERC and its affliates were biled based on allocation factors, which are as follows:
Labor and Assets: An equal weighting of each company's labor and assets expressed as a percentage of the whole ((labor % + assets
%) -; 2) determines the portion assigned to each company. Labor is 12 months ended thoughDecember of the prior year. Assets are
total assets at December 31 of the prior year. Five combinations of this allocator are used for allocating services that benefit different
companies within the holding company organization.
Legislative and Regulatory: used to allocate costs incured by the holding company's Legislative & Regulatory groups. The
Legislative & Regulatory groups work on a varety of legislative and regulatory subject matter for select group of companies within
the holding company organization. The Legislative and Regulatory allocation percentages are based on the Legislative & Regulatory
groups' estimation of the time and resources that are being spent on these selected companies.
Plant: This allocator distrbutes costs of managing the corporate insurance function based on assets for each platform.
I$chedule Page: 429 Line No.: 7 Column:
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "MERC" ON PAGE 429: Complete name is MidAerican Energy
Roldings Company.
I$chedule Page: 429 Line No.: 7 Column:
Accounts char ed for MERC: 930.2, 513, 426.5,107.
chedule Pa e: 429 Line No.: 8 Column:
TRIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "MEC" ON PAGE 429: Complete name is MidAerican Energy
Company.
¡Schedule Page: 429 Line No.: 8 Column:
Accounts char ed for MEC: 930.2, 501, 426.5, 146, 107, 143.
chedule Pa e: 429 Line No.: 11 Column:
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "CALENERGY GENERATION" ON PAGE 429: Complete name is
CalEnergy Generation Operating Company.
I$chedule Page: 429 Line No.: 21 Column:
Non-power goods or services provided to Bridger Coal Company are as follows:
Admnistrative support services
Non-MERC management fee
Royalties.
$2,344,729
1,074,000
123,942
3,542,671$
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 04/18/2011 2010/Q4
FOOTNOTE DATA
Labor and Assets: An equal weighting of each company's labor and assets expressed as a percentage of the whole ((labor % + assets
%) -; 2) determnes the portion assigned to each company. Labor is 12 months ended though December of the prior year. Assets are
total assets at December 31 of the prior year. Five combinations of this allocator are used for allocatig services that benefit different
companies within the holdig company organization.
l§chedule Page: 429.1 Line No.: 4 Column:
THIS FOOTNOTE APPLIES TO ALL OCCURNCES OF "HomeServices" ON PAGE 429: Complete name is HomeServices of
America, Inc.
l§chedule Page: 429.1 Line No.: 4 Column:
Accounts charged for HomeServices: 501, 506, 535, 539, 549, 557, 560, 561., 580, 581, 588, 590, 592, 593, 597, 902, 903, 908,
921,935, and clearing accounts.l§chedule Page: 429.1 Line No.: 6 Column: I
Refer to additional discussion regarding transactions with MEHC Insurance Services Ltd. in Note 17 of Notes to Financial Statements
within this FERC Form No. 1.
l§chedule Page: 429.1 Line No.: 8 Column:
Non-power goods or services provided by BNSF Railway Company are as follows:
Rail services
Right-of-way fees
$29,856,898
48,834
29,905,732$
¡Schedule Page: 429.1 Line No.: 17 Column:
PacifiCorp consolidates its wholly owned subsidiares Centrlia Mining Company, Energy West Mining Company, Glenrock Coal
Company, Interwest Mining Company and Pacific Minerals, Inc. Transactions with these entities have been excluded from the
amounts reported on this page. Refer to page 103, Corporations Controlled by Respondent in this Form NO.1 for more information
regarding the wholly owned subsidiares that PacifiCorp consolidates.
IFERC FORM NO.1 (ED. 12-87)Page 450.2
INDEX
Schedule Page No.
Accrued and prepaid taxes ........................................................................ 262-263
Accumulated Deferred Income Taxes .................................................................... 234
272-277
Accumulated provisions for depreciation of
common utility plant ............................................................................. 356
utility plant .................................................................................... 219
utility plant (summary) ...................................................................... 200-201
Advances
from associated companies .............................................................,...... 256-257
Allowances ....................................................................................... 228-229
Amortization
miscellaneous .................................................................................... 340
of nuclear fuel .............................................................................. 202-203
Appropriations of Retained Earnings .............................................................. 118-119
Associated Companies
advances from ................................................................................ 256-257
corporations controlled by respondent ............................................................ 103
control over respondent .......................................................................... 102
interest on debt to .......................................................................... 256-257
Attestation .........................................................~................................... i
Balance sheet
comparative .................................................................................. 110-113
notes to ..................................................................................... 122-123
Bonds ............................................................................................ 256-257
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 information on ....................................................................... 101
CPA Certification, this report form ..............................................................,.. i-ii
FERC FORM NO.1 (ED. 12-93)Index
INDEX (continued)
Schedule
Deferred
credits, other...................................................................... ',' ,........... 269
debits, miscellaneous ............................................................................ 233
income taxes accumulated - accelerated
Page No.
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 .......................................................................... 118-119
Earnings, Retained............................................................................... 118-119
Electric energy account .............................................................................. 401
Expenses
electric operation and maintenance ........................................................... 320-323
electric operation 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) ....................................................................... 408-409
small plants ................................................................................. 410-411
steam-electric (large) ....................................................................... 402-403
Hydro-electric generating plant statistics ....................................................... 406-407
Identification ....................................................................................... 101
Important changes during year ............................;....................................... 108-109
Income
statement of, by departments ................................................................. 114-117
statement of, for the year (see also revenues) ............................................... 114-117
deductions, miscellaneous amortization ........................................................... 340
deductions, other income deduction ............................................................... 340
deductions, other interest charges ............................................................... 340
Incorporation information ............................................................................ 101
FERC FORM NO.1 (ED. 12-95)Index 2
INDEX (continued)
Schedule Page No.
Interest
charges, paid on long-term debt, advances, etc ............................................... 256-257
Investments
nonutili ty 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
Nonutili ty property .................................................................................. 221
Nuc1ear fuel materials ........................................................................... 202-203
Nuclear generating plant, statistics ............................................................. 402-403
Officers and officers' salaries ...................................................................... 104
Operating
expenses-electric ............................................................................ 320-323
expenses-electric (summary) ..................................................................... .323
Other
paid-in capital ................................................................................... 253
donations received from stockholders ............................................................. 253
gains on resale or cancellation of reacquired
capital stock .................................................................................... 253
miscellaneous paid-in capital .................................................................... 253
reduction in par or stated value of capital stock ................................................ 253
regulatory assets ................................................................................ 232
regulatory liabilities ........................................................................... 278
Peaks, monthly, and output ........................................................................... 401
Plant, Common utility
accumulated provision for depreciation ........................................................... 356
acquisition adjustments .......................................................................... 356
allocated to utility departments ................................................................. 356
completed construction not classified ............................................................. 356
construction work in progress .................................................................... 356
expenses ......................................................................................... 356
held for future use .............................................................................. 356
in service ....................................................................................... 356
leased to others ................................................................................. 356
Plant data.................................................................................. .336-337
401-429
FERC FORM NO.1 (ED. 12-95)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
Reseilrch, 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
Taxes ..
accrued and prepaid ......................................................................... 262-263
charged during year ......................................................................... 262-263
on income, deferred and accumulated ............................................................. 234
Page No.
. 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