2011Annual Report.pdf

ROCKYMOUNTAIN
POWER
A DVSION OF PACRCORP
August 30, 2012
VIA OVERNIGHT DELIVERY
RECEIVED
201?AUG30 AM 11:13
DPHO PUJ UTtL1T1S flMMSSION
201 South Main, Suite 2300
Salt Lake City, Utah 84111
Idaho Public Utilities Commission
472 West Washington
Boise, ID 83702-5983
Attention: Jean D. Jewell
Commission Secretary
RE: FERC Form 1
PacifiCorp (d.b.a. Rocky Mountain Power) submits for filing one copy of PacifiCorp's annual
FERC Form 1 report for the year ended December 31, 2011.
PacifiCorp respectfully requests that all data requests regarding this matter be addressed to:
By email (preferred): datareguest(pacificorp.com
By regular mail: Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
Please direct any informal questions to Ted Weston, Regulatory Manager, at [phone]
Sincerely,
Ode ykK arsen
/JfM
Vice President, Regulation & Government Affairs
Enclosure
THIS FILING IS
Item 1: J An Initial (Original) OR nx Resubmission No.
Submission
Form 1 Approved
OMB No.1902-0021
(Expires 12/31/2014)
Form 1-F Approved
OMB No. 1902-0029
(Expires 12/31/2014)
Form 3-0 Approved
OMB No.1902-0205
(Expires 05/31/2014)

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Exact Legal Name of Respondent (Company) Year/Period of Report
PacifiCorp End of 2011/04
FERC FORM No.1/3-Q (REV. 02-04)
INSTRUCTIONS FOR FILING FERC FORM NOS. I and 3-0
GENERAL INFORMATION
I. Purpose
FERC Form No. I (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others
(18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q)is a quarterly regulatory requirement which supplements the
annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and
operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy
Regulatory Commission. These reports are also considered to be non-confidential public use forms.
II. Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission's Uniform System of Accounts
Prescribed for Public Utilities and Licensees Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101),
must submit FERC Form 1(18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).
Note: Major means having, in each of the three previous calendar years, sales or transmission service that
exceeds one of the following:
(1) one million megawatt hours of total annual sales,
(2)100 megawatt hours of annual sales for resale,
(3)500 megawatt hours of annual power exchanges delivered, or
(4)500 megawatt hours of annual wheeling for others (deliveries plus losses).
III. What and Where to Submit
(a)Submit FERC Forms 1 and 3-Q electronically through the forms submission software. Retain one copy of each report
for your files. Any electronic submission must be created by using the forms submission software provided free by the
Commission at its web site: http://www.ferc.qov/docs-filinq/eforms/form-1 /elec-subm-soft.asp . The software is
used to submit the electronic filing to the Commission via the Internet.
(b)The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
(c)Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the
latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to
the Secretary of the Commission at:
Secretary
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
(d)For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report
(not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can
be either eFiled or mailed to the Secretary of the Commission at the address above.
FERC FORM I & 3-Q (ED. 03-07)
The CPA Certification Statement should:
a)Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the
Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the
Chief Accountant's published accounting releases), and
b)Be signed by independent certified public accountants or an independent licensed public accountant
certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18
C.F.R. §§ 41.10-41.12 for specific qualifications.)
Reference Schedules
Comparative Balance Sheet
Statement of Income
Statement of Retained Earnings
Statement of Cash Flows
Notes to Financial Statements
Pages
110-113
114-117
118-119
120-121
122-123
e) The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions,
explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are
reported.
"In connection with our regular examination of the financial statements of for the year ended on which we have
reported separately under date of ,we have also reviewed schedules
of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for
conformity in all material 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 htti)://www.ferc.gov/hel1)/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 hftp://www.ferc.gov/docs-filina/eforms/f `orm-I/f`orm-1.od and
hftp://www.ferc.gov/docs-filing/eforms.asp#3Q-qas.
IV. When to Submit:
FERC Forms 1 and 3-Q must be filed by the following schedule:
FERC FORM I & 3-Q (ED. 03-07)
a)FERC Form I for each year ending December 31 must be filed by April 18 th of the following year (18 CFR § 141. 1),
and
b)FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. §
141.400).
V. Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC Form I collection of information is estimated to average 1,144
hours per response, including the time for reviewing instructions, searching existing data sources, gathering and
maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for
the FERC Form 3-Q collection of information is estimated to average 150 hours per response.
Send comments regarding these burden estimates or any aspect of these collections of information,
including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs,
Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory
Commission). No person shall be subject to any penalty if any collection of information does not display a valid control
number (44 U.S.C. § 3512 (a)).
FERC FORM I & 3-Q (ED. 03-07) 111
GENERAL INSTRUCTIONS
1. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (US0fA). Interpret
all accounting words and phrases in accordance with the USofA.
II. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and
figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements
where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the
statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance
sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the
current year's year to date amounts.
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 filing using the form submission software only. Please explain
the reason for the resubmission in a footnote to the data field.
VIII.Do not make references to reports of previous periods/years or to other reports in lieu of required entries,
except as specifically authorized.
IX.Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based
upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different
figures were used.
Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:
FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission
Service as described in Order No. 888 and the Open Access Transmission Tariff. "Self" means the respondent.
FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as
described in Order No. 888 and the Open Access Transmission Tariff.
LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and" firm"
means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse
conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access
Transmission Tariff. For all transactions identified as LFP, provide in a footnote the
FERC FORM 1 & 3-Q (ED. 03-07) iv
termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.
OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the
terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and "firm" means that service
cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all
transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either
buyer or seller can unilaterally get out of the contract.
SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point
transmission reservations, where the duration of each period of reservation is less than one-year.
NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions.
OS - Other Transmission Service. Use this classification only for those services which can not be placed in the
above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC
Form. Describe the type of service in a footnote for each entry.
AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior
reporting periods. Provide an explanation in a footnote for each adjustment.
)EFINITIONS
Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or
my other Commission. Name the commission whose authorization was obtained and give date of the authorization.
H. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose
behalf the report is made.
FERC FORM I & 3-Q (ED. 03-07) v
EXCERPTS FROM THE LAW
Federal Power Act, 16 U.S.C. § 791 a-825r
Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:
(3)'Corporation' means any corporation, joint-stock company, partnership, association, business trust,
organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the
foregoing. It shall not include 'municipalities, as hereinafter defined;
(4)'Person' means an individual or a corporation;
(5)'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act,
and any assignee or successor in interest thereof;
(7) 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or
agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or
distributing power ......
(11) "project' means. a complete unit of improvement or development, consisting of a power house, all water
conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit,
and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power
there from to the point of junction with the distribution system or with the interconnected primary transmission system, all
miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights,
rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or
appropriate in the maintenance and operation of such unit;
"Sec. 4. The Commission is hereby authorized and empowered
(a) To make investigations and to collect and record data concerning the utilization of the water 'resources of any region
to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and
concerning the location, capacity, development -costs, and relation to markets of power sites; ... to the extent the
Commission may deem necessary or useful for the purposes of this Act."
"Sec. 304. (a) Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the Commission may be rules and regulations or other prescribe as necessary or appropriate to assist
the Commission in the -proper administration of this Act. The Commission may prescribe the manner and FERC Form in
which such reports salt be made, and require from such persons specific answers to all questions upon which the
Commission may need information. The Commission may require that such reports shall include, among other things, full
information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due
and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the
project and other facilities, cost of renewals and replacement of the project works and other facilities, depreciation,
generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such
person to make adequate provision for currently determining such costs and other facts. Such reports shall be made
under oath unless the Commission otherwise specifies*. 10
FERC FORM I & 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 million per day per violation of its rules and regulations. See
FPA § 316(a) (2005), 16 U.S.C. § 8250(a).
FERC FORM I & 3-Q (ED. 03-07) vii
FERC FORM NO. 113-Q:
PFPflRT flF MAJflR Fl F(TRl( 11TH ITIPR I l(FWFF ANn flTWFP
IDENTIFICATION
01 Exact Legal Name of Respondent 02 Year/Period of Report
PacifiCorp End of 20111Q4
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
]
Corporate
06 Title of Contact Person
Henry E. Lay Controller
07 Address of Contact Person (Street, City, State, Zip Code)
825 N.E. Multnomah, Suite 1900, Portland, OR 97232
08 Telephone of Contact Person Including, 09 This Report Is 10 Date of Report
Area Code (1) 0 An Original (2) N A Resubmission (Mo, Da, Yr)
[phone] 06/28/2012
ANNUAL CORPORATE OFFICER CERTIFICATiON
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial Information contained in this report, conform in all material
respects to the Uniform System of Accounts.
01 Name 04 Date Signed
Douglas K Stuver
03 Signatu )
02 Title
Senior VP & Chief Financial Officer Doug as K. Stuver 06/2812012
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM No113-Q (REV. 02-04) Page 1
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)ffjA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
-
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(C)
1 General Information 101
2 Control Over Respondent 102
3 Corporations Controlled by Respondent 103
4 Officers 104
5 Directors 105
6 Information on Formula Rates 106(aXb)
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 Earnings for the Year 118-119
11 Statement of Cash Flows 120-121
12 Notes to Financial Statements 122-123
13 Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b)
14 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-20 1
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 Utility Plant 219
21 Investment of Subsidiary Companies 224-225
22 j Materials and Supplies 227
23 Allowances 228(ab)-229(ab)
24 Extraordinary Property 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. I (ED. 12-96) Page 2
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)gjA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
-
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(C)
37 Other Deferred Credits 269
38 Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273
39 Accumulated Deferred Income Taxes-Other Property 274-275
40 Accumulated Deferred Income Taxes-Other 276-277
41 Other Regulatory Liabilities 278
42 Electric Operating Revenues 300-301
43 Sales of Electricity by Rate Schedules 304
44 j 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 lSO/RTOs 331 N/A
49 Transmission of Electricity by Others 332
50 Miscellaneous General Expenses-Electric 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 Utility Plant and Expenses 356 N/A
56 Amounts included in lSO/RTO Settlement Statements 397
57 j Purchase and Sale of Ancillary 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
FERC FORM NO. I (ED. 12-96) Page 3
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/04
(2)A Resubmission 06128/2012
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No. Page No.
- (a) (b) (C)
67 Transmission Lines Added During the Year 424-425
68 Substations 426-427
69 Transactions with Associated (Affiliated) Companies 429
70 Footnote Data 450
- Stockholders' Reports Check appropriate box:
[] Two copies will be submitted
[J No annual report to stockholders is prepared
FERC FORM NO. 1 (ED. 12-96) Page 4
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacffiCorp X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 2 Line No.: I Column:
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 2 Line No.: 7 Column:
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 2 Line No.: 8 Column:
Amended. in accordance with FERC Order No. AC11-132.
Schedule Page: 2 Line No.: 9 Column:
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 2 Line No.: 10 Column:
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 2 Line No.: 11 Column:
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 2 Line No.: 12 Column:
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 2 Line No.: 21 Column:
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 2 Line No.: 28 Column: .. I Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 2 Line No.: 35 Column: I Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 2 Line No.: 37 Column:
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 2 Line No.: 40 Column: I Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 2 Line No.: 45 Column: I Amended in accordance with FERC Order No. AC11-132.
[Schedule Page: 2 Line No.: 62 Column: I Amended in accordance with FERC Order No. AC11-132.
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr)
(2)RX A Resubmission 06/28/2012 End of 201 1/Q4
GENERAL INFORMATION
1.Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
Douglas K. Stuver, Senior Vice President and Chief Financial Officer
825 N.E. Multnomah, Suite 1900
Portland, OR 97232
2.Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
3.If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not applicable
4.State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
PacifiCorp is a United States regulated, vertically integrated electric company serving 1.7 million
retail customers, including residential, commercial, industrial and other customers in portions of the
states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp delivers electricity to
customers in Utah, Wyoming and Idaho under the trade name Rocky Mountain Power and to customers in
Oregon, Washington and California under the trade name Pacific Power. PacifiCorp's electric generation
and commercial and trading functions are operated under the trade mane PacifiCorp Energy.
Amended in accordance with FERC Order No. AC11-132.
5.Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?
(1)Yes... Enter the date when such independent accountant was initially engaged:
(2)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)
PaciflCorp (2)XA Resubmission 06/2812012 2011/04
FOOTNOTE DATA
Schedule Paw: 101 Line No.: I Column: Item 2
PacifiCorp was initially incorporated in 1910 under the laws of the state of Maine under
the name Pacific Power & Light Company; In 1984, Pacific Power & Light Company changed its
name to PacifiCorp. In 1989, it merged with Utah Power and Light Company, 'a Utah
corporation, in a transaction wherein both corporations merged into a newly formed Oregon
corporation. The resulting Oregon corporation was re-named PacifiCorp, which is the
operating entity today.
IfERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp (1)fl An Original
(2)X A Resubmission
(Mo, Da, Yr)
06/28/2012 End of 2011/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 Holdings LLC (100% controlled by MidAmencan Energy Holdings Company)
PacifiCorp (100% of common stock held by PPW Holdings LLC)
(a) Berkshire Hathaway Inc. owns 89.8%, Walter Scott, Jr. (along with family members and related entities) owns 9.4% and Gregory E.
Abel owns 0.8% of MEHC's common stock.
FERC FORM NO. I (ED. 12-96) Page 102
Name of Respondent
PacifiCo
This Report Is:
(1)EAn Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
CORPORATIONS CONTROLLED BY RESPONDENT
1.Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. if control ceased prior to end of year, give particulars (details) in a footnote.
2.If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3.If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1.See the Uniform System of Accounts for a definition of control.
2.Direct control is that which is exercised without interposition of an intermediary.
3.Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4.Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control -is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual
agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the
Uniform System of Accounts, regardless of the relative voting rights of each party.
Line
No.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent Voting
Stock Owned
(c)
Footnote
Ref.
(d)
1 Mining 100
2 Mining 100
3 Mining 100
4 Mining 100
5 lnterwest Mining Company
6
Management Services 100
WManagement Services 100
7 Bndger Coal Company Mining 66.67
8 PacifiCorp Environmental Remediation Company 1Environmental Services 100
9 Management Services
Mining
100
10 21.40
11 PacifiCorp Foundation foundation
12
12
14
15
16
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO. 1 (ED. 12-96) Page 103
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 103 Line No.: I Column: a
In May 2000, the assets of Centralia Mining Company were sold to TransAlta. The entity is
no longer active.
Schedule Page: 103 Line No.: 2 Column: a
Energy West Mining Company provides coal-mining services to PacifiCorp utilizing
PacifiCorp's assets. Energy West Mining Company's costs are fully absorbed by PacifiCorp.
Schedule Page: 103 Line No.: 3 Column: a
In June 2011, PacifiCorp formed a wholly owned subsidiary, Fossil Rock Fuels, LLC, to
acquire certain coal reserve leases and ultimately provide coal-mining services to
PacifiCoro.
Schedule Page: 103 Line No.: 4 Column: a
Glenrock Coal Company ceased mining operations in October 1999.
Schedule Page: 103 Line No.: 6 Column: a
Pacific Minerals, Inc. is a wholly owned subsidiary of PacifiCorp that holds a 66.67%
ownership interest in Bridger Coal Company, a coal mining joint venture with Idaho Energy
Resources Company, a subsidiary of Idaho Power Company.
Schedule Page: 103 Line No.: 9 Column: a
PacifiCorp Investment Management, Inc. previously performed management services for
PacifiCorp Environmental Remediation Company and is no longer active.
Schedule Page: 103 Line No.: 10 Column: a
PacifiCorp is a minority owner in Trapper Mining Inc., a cooperative. The members are Salt
River Project Agricultural Improvement and Power District (32.10%), Tri-State Generation
and Transmission Association, Inc. (26.57%), PacifiCorp (21.40%) and Platte River Power
Authority (19.93%)
Schedule Page: 103 Line No.: 11 Column: c
The PacifiCorp Foundation is an independent non-profit foundation created by PacifiCorp in
1988. The PacifiCorp Foundation operates as the Rocky Mountain Power Foundation and the
Pacific Power Foundation. Two of the PacifiCorp Foundation's five directors are also
directors of PacifiCorp.
Schedule Page: 103 Line No.: 13 Column: a
In accordance with Federal Energy Regulatory Commission Docket No. AC11-132, PacifiCorp
accounts for its investment in subsidiaries using the equity method as of December 31,
2011. Refer to Important Changes During the Year for further information.
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
OFFICERS
1.Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2.If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
Line
0.
Title
(a)
Name of Officer
(b)
Salary for Year (c)
2 Chairman of the Board of Directors
3 and Chief Executive Officer
4 Senior Vice President and Chief Financial Officer Douglas K. Stuver 239,269
5 President and Chief Executive Officer,
6 Rocky Mountain Power A. Richard Walje 368,000
7 President and Chief Executive Officer, Pacific Power R. Patrick Reiten 291,528
8 President and Chief Executive Officer, PacifiCorp Energy Micheal G. Dunn 278,820
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. I (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)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
ISchedule Pace: 104 Line No.: I Column: a
PacifiCorp sets forth the salary information for its "named executive officers" for the
year ended December 31, 2011, consistent with Item 402 of Regulation S-K promulgated by
the Securities and Exchange Commission, in its Annual Report on Form 10-K. Salary
information of other officers will be provided to the Federal Energy Regulatory Commission
upon request, but the company considers such information personal and confidential to such
officers. See 18 CFR 388.107 (d) , (f)
Schedule Page: 104 Line No.: 3 Column: b
Mr. Abel receives no direct compensation from PacifiCorp. PacifiCorp reimburses
MidAmerican Energy Holdings Company ("MEHC") for the cost of Mr. Abel's time spent on
matters supporting PacifiCorp, including compensation paid to him by MEHC, pursuant to an
intercompany administrative services agreement among MEHC and its subsidiaries. Please
refer to MEHC's Annual Report on Form 10-K for the year ended December 31, 2011 (File No.
001-14881) for executive compensation information for Mr. Abel.
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent
PacifiCo rp
This Report Is:
(1)An Original
(2)ffjA Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
DIRECTORS
1.Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated
titles of the directors who are officers of the respondent.
2.Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
Line
No. Name (and Title) of Director (a) Principal Business Address (b)
Board of Directors as of December 31, 2011:
*(Chairmarn of the Board of Directors and CEO, PaciflCorp) 666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309
4 R. Patrick Reiten
5 (President and CEO, Pacific Power) 825 NE Multnomah, Suite 2000, Portland, Oregon 97232
6 A. Richard Walje
7 (President and CEO, Rocky Mountain Power) 201 South Main, Suite 2300, Salt Lake City, Utah 84111
8 Douglas L. Anderson 666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309
9 Brent E. Gale 825 NE Multnomah, Suite 2000, Portland, Oregon 97232
10 Patrick J. Goodman 666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309
11 Micheal G. Dunn
12 (President and CEO, PacifiCorp Energy) 1407 West North Temple, Suite 320, Salt Lake City, Utah 84116
13 Mark C. Moench
14 (SVP, General Counsel and Corporate Secretary, PacifiCorp) 201 South Main, Suite 2400, Salt Lake City, Utah 84111
15 Natalie L. Hocken
16 (Vice President and General Counsel, Pacific Power) 825 NE Multnomah, Suite 2000, Portland, Oregon 97232
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. I (ED. 12-95) Page 105
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
ISchedule Page: 105 Line No.: 2 Column: a
As of December 31, 2011, PacifiCorp has only one committee, a Compensation Committee, of
which the sole member is Mr. Abel.
IFERC FORM NO. 1 (ED. 12-87) Page 450.1 I
Name of Respondent
PacifiCorp
This Report Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent have formula rates? Yes
E] No
1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No)
accepting the rate(s) or changes in the accepted rate.
Line
No. FERC Rate Schedule or Tariff Number FERC Proceeding
1 ER11-3643
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
FERC FORM NO. I (NEW. 12-08) Page 106
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011 /Q4
FOOTNOTE DATA
Schedule Page: 106 Line No.: I Column: a
As a result of a 2007 multi-party settlement with the Federal Energy Regulatory Commission
(UFERC!!) regarding- long-term shared usage, coordinated operation and maintenance, and
planning of certain 500-kilovolt transmission lines, PacifiCorp agreed to file a Federal
Power Act Section 205 rate change filing for its system-wide transmission service rates no
later than June 1, 2011. In May 2011, PacifiCorp filed its Federal Power Act Section 205
rate case seeking to modify its transmission and ancillary services rates and adopt a
formula transmission rate. In August 2011, the FERC issued an order in Docket- No.
ER11-3643 accepting PacifiCorp's filing and allowing the proposed rates to become
effective December 25, 2011, subject to refund. Billing at the new rates commenced in
early 2012. The FERC established settlement proceedings to encourage the parties to reach
agreement on final rates. If a settlement is not reached, hearings will be held before the
FERC to arrive at final approved -rates. Settlement discussions are underway with the
parties to the case.
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent)
filings containing the inputs to the formula rate(s)? Yes
No
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
Line
No. Accession No.
Document
Date
\ Filed Date Docket No. Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
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. I (NEW. 12-08) Page 106a
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Schedule Page: 1061 Line No.: 1 Column: a
PacifiCorp expects to file its first informational filing on June 1, 2012.
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent
PacifiCorp
This Report Is:
(1 )l An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 billing) 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 inputs differ from amounts reported in Form 1 schedule amounts.
4.Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line
No. Page No(s). Schedule Column Line No
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. I (NEW. 12-08) Page 106b
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp (1) An Original
06/28/2012 End of 2011/Q4
(2) A Resubmission
IMPORTANT CHANGES DURING THE QUARTER/YEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA' where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1.Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2.Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3.Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and
reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were
submitted to the Commission.
4.Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5.Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers
added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new
continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6.Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7.Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8.State the estimated annual effect and nature of any important wage scale changes during the year.
9.State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10.Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Page 104 or 105 of the Annual Report Form No. 1, 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 officers, directors, major security holders and voting powers of the respondent that may have occurred
during the reporting period.
14.In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash
management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO. I (ED. 12-96) Page 108
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
ITEM 1
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 Effective Date Expiration Date Fee
California (1)
None
Idaho (2)
Montpelier 05/12/2011 05/12/2046 -
Ammon 06/08/2011 06/08/2041 3.0%
Lewisville 10/18/2011 10/18/2046 2.0%
McCammon 10/18/2011 10/18/2046 3.0%
St. Anthony 10/18/2011 10/18/2021 1.0%
Oregon (3)
Mosier 09/11/2011 08/25/2021 7.0%
Stayton 09/29/2011 10/06/2021 5.0%
Central Point 12/08/2011 12/08/2021 6.0%
Independence (4) 12/20/2011 03/30/2012 5.0%
Astoria (4) 12/22/2011 12/31/2012 3.5%
Month-to-Month
Warrenton 12/22/2011 Extension 5.0%
Utah (2)
Panguitch 03/08/2011 03/08/2031 2.0%
Holladay 03/14/2011 03/14/2036 6.0%
Wasatch County 04/25/2011 09/28/203 5 -
Centerville 06/07/2011 12/31/2016 5.0%
Hideout 06/22/2011 06/22/2021 6.0%
North Salt Lake 08/24/2011 08/24/2016 6.0%
Tremonton 11/02/2011 11/02/2021 6.0%
Mantua 11/11/2011 11/11/2036 -
Washington (2)
Dayton 02/21/2011 02/21/2021 6.0%
Yakima County 04/19/2011 04/19/2036 -
Wyoming (5)
Lincoln County 06/22/2011 06/22/2036 -
Cowley 10/13/2011 10/13/2036 2.0%
(1)In California, franchise agreement fees are an expense to PaciflCorp and are embedded in rates.
(2)In Idaho, Utah and Washington, PacifiCorp collects franchise agreement fees from customers and remits them directly to the applicable municipalities.
(3)In Oregon, the first 3.5% of the franchise agreement fee is an expense to PaciflCorp and is embedded in rates. Any amount above the 3.5% is collected from
customers and remitted directly to the applicable municipalities.
(4)These franchise agreements represent extensions through the expiration date noted or until a new franchise agreement is granted.
(5)In Wyoming, the first 1.0% of the franchise agreement fee is an expense to PaciflCorp and is embedded in rates. Any amount above the 1.0% is collected
from customers and remitted directly to the applicable municipalities.
IFERC FORM NO. 1 (ED. 12-96) Page 109.1 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
ITEM 2.
For information on the resubmission, refer to Note 2 of Notes to Financial Statements in this Form No. 1.
ITEM 3.
In July 2011, the FERC in Docket No. AC1 1-81-000 approved the journal entries required by the Uniform System of Accounts
("USofA") for the sale of undivided ownership interests in certain of PacifiCorp's transmission facilities to Black Hills Power, Inc.
Accordingly, PaciflCorp cleared account 102, Electric plant purchased or sold, and recorded the sale to the appropriate accounts. For
further discussion, refer to Important Changes During the Quarter/Year, Item 3 of PaciflCorp's annual report on Form No. I for the
year ended December 31, 2010.
In March 2011, PacifiCorp entered into an agreement for the sale of the Snake Creek hydroelectric generating facility with Heber
Light & Power Company. The sale closed in September 2011 and was recorded in account 102, Electric plant purchased or sold. In
February 2012, the FERC in Docket No. AC12-7-000 approved the journal entries required by the USofA for the sale. Accordingly,
PaciflCorp cleared account 102, Electric plant purchased or sold and recorded the sale to the appropriate accounts. Commission
authorizations for the sale were as follows:
• Oregon Public Utility Commission ("OPUC") - Order No. 11-331, effective August 26, 2011.
• California Public Utilities Commission ("CPUC") - Advice Letter 439-E, effective July 28, 2011.
• Wyoming Public Service Commission ("WPSC") -Docket No. 20000-395-EA-11, effective July 8, 2011, pursuant to open
meeting action taken on July 8, 2011.
ITEM 4.
None.
ITEM 5.
During the year ended December 31, 2011, PacifiCorp did not significantly increase or decrease its distribution territory. Refer to
pages 424-425 of this Form No. 1 for additional information regarding transmission lines added or removed during the year.
ITEM 6.
Short-term Debt and Revolving Credit Facilities
Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. PacifiCorp had $688 million of short-term debt outstanding
as of December 31, 2011 at a weighted-average interest rate of 0.5%. PacifiCorp had no outstanding borrowings under its unsecured
revolving credit facilities as of December 31, 2011.
LFERC FORM NO. I (ED. 12-96) Page 109.2 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)- An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/04
IMPORTANT CHANGES DURING THE QUARTERIYEAR (Continued)
Commission authorizations for up to $1.5 billion outstanding at any one time 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 ("WUTC") - Docket No. UE-980404, dated April 8, 1998.
• Idaho Public Utilities Commission ("JPUC") - Case No. PAC-E- 11-09, 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 January 1, 2010 through December 31, 2011.
• FERC - Docket No. ES! 1-51-000, dated November 29, 2011 and errata notice dated November 30, 2011, letter order
effective January 1, 2012 through December 31, 2013.
For further discussion, refer to Note 8 of Notes to Financial Statements in this Form No. 1
Long-term Debt
In March 2012, PaciflCorp issued $100 million of its 2.95% First Mortgage Bonds due February 1, 2022. The net proceeds were used
for the redemption of certain tax-exempt bonds, repayment of short-term debt and general corporate purposes.
In January 2012, PacifiCorp issued $350 million of its 2.95% First Mortgage Bonds due February 1, 2022 and $300 million of its
4.10% First Mortgage Bonds due February 1, 2042. The net proceeds were used to repay short-term debt, fund capital expenditures
and for general corporate purposes.
In May 2011, PaciflCorp issued $400 million of its 3.85% First Mortgage Bonds due June 15, 2021. The net proceeds were used to
fund capital expenditures, repay short-term debt and for general corporate purposes.
PaciflCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $850 million of long-term debt
PacifiCorp must make a notice filing with the WUTC prior to any future issuance. State commission authorizations for the above
issuances and future issuances are as follows:
• OPUC - Docket No. UF-4262, Order No. 10-062, dated February 23, 2010.
. IPUC - Case No. PAC-E-10-02, Order No. 31018, dated March 5, 20 10
PaciflCorp made scheduled repayments on long-term debt totaling $587 million during the year ended December 31, 2011.
As of December 31, 2011, PaciflCorp had $601 million of letters of credit providing credit enhancement and liquidity support for
variable-rate tax-exempt bond obligations totaling $587 million plus interest These letters of credit were fully available at December
31, 2011 and expire periodically through November 2012.
PaciflCorp's Mortgage and Deed of Trust creates a lien on most of PacifiCorp's electric utility property, allowing the issuance of
bonds based on a percentage of utility property additions, bond credits arising from retirement of previously outstanding bonds or
deposits of cash. The amount of bonds that PaciflCorp may issue generally is also subject to a net earnings test. As of December 31,
2011, PacifiCorp estimated it would be able to issue up to $8.2 billion of new first mortgage bonds under the most restrictive issuance
test in the mortgage. Any issuances are subject to market conditions and amounts may be further limited by regulatory authorizations
or commitments or by covenants and tests contained in other financing agreements. PacifiCorp also has the ability to release property
from the lien of the mortgage on the basis of property additions, bond credits or deposits of cash.
IFERC FORM NO. 1 (ED. 12-96) Page 109.3 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
PacifiCorp may from time to time 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 will depend on prevailing market conditions, PacifiCorp's liquidity requirements, contractual restrictions and other
factors. The amounts involved may be material.
Common Shareholder's Equity
In January 2012, PacifiCorp declared a dividend of $50 million, which was paid to PPW Holdings LLC, a wholly owned subsidiary of
MidAmerican Energy Holdings Company ("MEHC") and PacifiCorp's direct parent company, in February 2012.
In March 2011, PacifiCorp declared a dividend of $275 million, which was paid to PPW Holdings LLC in April 2011
In January 2011, PacifiCorp declared a dividend of $275 million, which was paid to PPW Holdings LLC in February 2011.
ITEM 7.
None.
ITEM 8.
PacifiCorp's bargaining unit wage scale changes were as follows:
Estimated Annual
Unions Represented % Increase (1) Effective Date(s) Financial Impact (2)
IBEW 57 Power Delivery (UT, ID & WY) 1.6% 1/26/2011 1,321,959
IBEW 57 Power Supply (UT, ID & WY) 1.6% 1/26/2011 622,877
UWUA 197 (OR) 0.9% 5/26/2011 16,116
IBEW 57 Combustion Turbine (UT) 1.1% 5/26/2011 23,940
IBEW 57 Laramie (WY) 0.8% 6/26/2011 4,622
IBEW 125 (OR, WA) 0.4% 8/26/2011 106,572
IBEW 659 (OR, CA) 0.7% 8/26/2011 223,715
UWUA 127 (WY) 0.4% 9/26/2011 171.741
Total $ 2.491.542
(1)This percentage increase represents the increase in wages from the effective date of the increase to the end of the calendar year as compared to the wage scale
of the prior calendar year.
(2)The estimated annual impact is based on the time period from the effective date of the increase to the end of the calendar year. Some amounts may be
reimbursed by joint owners.
ITEM 9.
PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or
exemplary damages. PacifiCorp does not believe that such normal and routine litigation will 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 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, which includes an update on the USA Power legal matter.
IFERC FORM NO. I (ED. 12-96) Page 109.4 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
In December 2000, Wah Chang, a large industrial customer of PaciflCorp filed an action before the OPUC asserting 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 during
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 tariff. Wah Chang petitioned the Circuit Court for Marion County, Oregon for review of the OPUC's
order. In June 2002, the Circuit Court for Marion County, Oregon granted Wah Chang's motion for review and ordered the OPUC to
reopen the record to allow Wah Chang the opportunity to present new evidence. In September 2009, the OPUC dismissed Wah
Chang's petition and reaffirmed that the rates set by the special tariff were just and reasonable. In October 2009, Wah Chang filed
with the Oregon Court of Appeals a petition for judicial review of the OPUC's September 2009 order denying Wah Chang relief. In
July 2010, the Oregon Court of Appeals accepted judicial review.
In a separate but related proceeding, in December 2000, Wah Chang filed a complaint in the Circuit Court for Linn County, Oregon
asserting that the OPUC-approved special tariff with PacifiCorp is subject to rescission based on theories of mutual mistake of fact,
frustration of purpose and impracticability. In April 2011, Wah Chang's claims were presented during a jury trial, and all claims,
including the claim for punitive damages, were resolved in PacifiCorp's favor. Wah Chang did not appeal this outcome and the
outcome had no impact on PacifiCorp's financial results.
ITEM 10.
In June 2011, PacifiCorp formed a wholly owned subsidiary, Fossil Rock Fuels, LLC ("Fossil Rock"), to acquire certain coal reserve
leases and ultimately provide coal-mining services to PacifiCorp. In conjunction with this formation, PaciflCorp contributed $20
million to Fossil Rock in July 2011 to fund the acquisition of the coal reserve leases.
Refer to page 429, Transactions with Associated (Affiliated) Companies, in this Form No. 1 for additional information regarding
related-party transactions.
There have been no officer, director or security holder transactions during the year ended December 31, 2011.
ITEM 11.
(Reserved)
ITEM 12.
For information regarding general regulation, rate proceedings, environmental laws and regulations, future generation and
conservation, and collateral and contingent features, refer to PacifiCorp's Annual Report on Form 10-K for the year ended December
31, 2011 filed with the United States Securities and Exchange Commission ("SEC").
ITEM 13.
PacifiCorp discloses information for its "named executive officers" consistent with Item 402 of Regulation S-K promulgated by the
SEC in its Annual Report on Form 10-K. There have been no changes in officers or directors during the year ended December 31,
2011.
ITEM 14.
Not applicable.
IFERC FORM NO. 1 (ED. 12-96) Page 109.5 1
Deloitte, D.loltte & Touche LIP
3900 U.S. Bancorp Tower
111 S.W. Fifth Ave.
Portland, OR 97204-3642
USA
Tel; [phone]
Fax [phone]
www.detoftte.com
INDEPENDENT AUDITORS' REPORT
PacifiCorp
Portland, Oregon
We have audited the balance sheet - regulatory basis of PacifiCorp (the "Company") as of December 31,
2011, and the related statements of income - regulatory basis, retained earnings - regulatory basis, and
cash flows - regulatory basis, for the year then ended, included on pages 110 through 123 of the
accompanying Federal Energy Regulatory Commission Form No. 1. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of
America. Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes consideration of
internal control over financial reporting as a basis for designing audit procedures that are appropriate in
the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's
internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our audit provides a reasonable
basis for our opinion.
As discussed in Note 2, these financial statements were prepared in accordance with the accounting
requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System
of Accounts and published accounting releases, which is a comprehensive basis of accounting other than
accounting principles generally accepted in the United States of America.
In our opinion, such regulatory-basis financial statements present fairly, in all material respects, the
assets, liabilities, and proprietary capital of the Company as of December 31, 2011, and the results of its
operations and its cash flows for the year then ended, in accordance with the accounting requirements of
the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and
published accounting releases.
This report is intended solely for the information and use of the board of directors and management of the
Company and for filing with the Federal Energy Regulatory Commission and is not intended to be and
should not be used by anyone other than these specified parties.
T0.s LLP
June 28, 2012
Member of
DeIoitteTouchToIunatsu Limited
Name of Respondent
PacifiCorp
This Report Is:
(1)Ej An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) -
Line
No
-
Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
1 UTILITY PLANT
2 1 Utility Plant (101 -106, 114) 200-201 23,014,228,731 22,017,833,818
3 Construction Work in Progress (107) 200-201 1,203,547,965 1,000,790,049
4 TOTAL Utility Plant (Enter Total of lines 2 and 3) 24,217,776,696 23,018,623,867
5 (Less) Accum. Prov. for Depr. Amort. DepI. (108, 110, 111, 115) 200-201 7,666,665,056 7,467,085,584
6 Net Utility Plant (Enter Total of line 4 less 5) 16,551,111,640 15,551,538,283
7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 202-203 0 0
8 Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 0 0
9 Nuclear Fuel Assemblies in Reactor (120.3) 0 0
10 Spent Nuclear Fuel (120.4) 0 0
11 Nuclear Fuel Under Capital Leases (120.6) 0 0
12 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 202-203 0 0
13 Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 0 0
14 Net Utility Plant (Enter Total of lines 6 and 13) 16,551,111,640 15,551,538,283
15 Utility Plant Adjustments (116) 0 0
16 Gas Stored Underground - Noncurrent (117) 0 0
17 OTHER PROPERTY AND INVESTMENTS
18 Nonutility Property (121) 15,445,648 16,174,139
19 (Less)Accum. Prov. for Depr. and Amort. (122) 1,917,7571 1,214,176
20 Investments in Associated Companies (123) 69,9281 69,9281
21 Investment in Subsidiary Companies (123.1) 224-225 240,956,268
22 (For Cost of Account 123.1, See Footnote Page 224, line 42)
23 Noncurrent Portion of Allowances 228-229 I 01 01
24 Other Investments (124) 83,950,135 84,517,252
25 Sinking Funds (125) 0 0
26 Depreciation Fund (126) 0 0
27 Amortization Fund - Federal (127) 0 0
28 Other Special Funds (128) 6,137,779 4,236,855
29 Special Funds (Non Major Only) (129) 0 0
30 Long-Term Portion of Derivative Assets (175) 4,472,312 9,400,334
31 Long-Term Portion of Derivative Assets - Hedges (176) 0 0
32 TOTAL Other Property and Investments (Lines 18-21 and 23-31) 349,114,313 324,309,131
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds (Non-major Only) (130) 0 0
35
36
Cash (131)
Special Deposits (132-134)
14,846,9
774,146 603,868
37 Working Fund (135) 1,520 1,720
38 Temporary Cash Investments (136) 7,244,794 463,002
39 Notes Receivable (141) 238,519 351,089
40 Customer Accounts Receivable (142) 373,179,1541 352,691,649,
41 Other Accounts Receivable (1 43) 59,610,652
42 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 8,722,7621 7,517,126j
43 Notes Receivable from Associated Companies (145) 13,897,30t
44 Accounts Receivable from Assoc. Companies (146) 7,455,752
45 Fuel Stock (151 ) 227 236,891,2141 188,493,087
46 Fuel Stock Expenses Undistributed (152) 227 0 0
47 Residuals (Elec) and Extracted Products (153) 227 0 0
48 Plant Materials and Operating Supplies (154) 227 196,564,767 186,406,158
49 Merchandise (155) 227 0 0
50 Other Materials and Supplies (156) 227 0 0
51 Nuclear Materials Held for Sale (157) 202-203/227 0 0
52 Allowances (158.1 and 158.2) 228-229 0 0
FERC FORM NO. I (REV. 12-03) Page 110
Name of Respondent
PacifiCorp
This Report Is:
(1)D An Original
(2)J A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBlTS)ontinued)
Line
No.
-
Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(C)
Prior Year
End Balance
12/31
(d)
53 (Less) Noncurrent Portion of Allowances 0 0
54 1 Stores Expense Undistributed (163) 227 1 01 0
55 Gas Stored Underground - Current (164.1) 01 0
56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 0 0
57 Prepayments (165)
58 Advances for Gas (166-167) 0 0
59 Interest and Dividends Receivable (171) 26,887 6,674
60 Rents Receivable (172) 2,237,540 1,535,228
61 Accrued Utility Revenues (173) 236,917,500 205,559,000
62 Miscellaneous Current and Accrued Assets (174) 2,574,464 0
63 Derivative Instrument Assets (1 75) 15,812,193 123,801,642
64 (Less) Long-Term Portion of Derivative Instrument Assets (175) 4,472,312 9,400,334
65 Derivative Instrument Assets - Hedges (176) 0 0
66 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 0 0
67 Total Current and Accrued Assets (Lines 34 through 66) 1,268,581,647 1,513,838,238
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (181) 33,449,341 33,300,472
70 Extraordinary Property Losses (182.1) 230a 0 0
71 Unrecovered Plant and Regulatory Study Costs (182.2) 230b 0 135,566
72 Other Regulatory Assets (182.3) 232 1,874,535,671 1,737,446,767
73 Prelim. Survey and Investigation Charges (Electric) (183) 3,115,357 2,895,724
74 Preliminary Natural Gas Survey and Investigation Charges 183.1) 0 0
75 Other Preliminary Survey and Investigation Charges (183.2) 0 0
76 Clearing Accounts (184) 0 0
77 Temporary Facilities (185) 66,905 90,676
78 Miscellaneous Deferred Debits (186) 233 88,864,23:
79 Def. Losses from Disposition of Utility Pit. (187) 0 0
80 Research, Devel. and Demonstration Expend. (188) 352-353 0 0
81 Unamortized Loss on Reaquired Debt (189) 9,676,901 11,446,745
82 Accumulated Deferred Income Taxes (190) 234 639,645,755 588,589,916
83 Unrecovered Purchased Gas Costs (191) 0 0
84 Total Deferred Debits (lines 69 through 83) 2,649,354,163 2,460,383,961
85 TOTAL ASSETS (lines 14-16, 32, 67, and 84) 20,818,161,763 19,850,069,613
FERC FORM NO. I (REV. 12-03) Page III
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) - An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 110 Line No.: 21 Column: d I
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 110 Line No.: 35 Column: d I
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 110 Line No.: 41 Column: d I
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 110 Line No.: 43 Column: d I
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 110 Line No.: 44 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 110 Line No.: 57 Column: c
As of December 31, 2011, Account 165 Prepayments included $67,080,728 of income taxes
receivable from MidAmerican Energy Holdings Company, PacifiCorps indirect parent company.
lSchedule Page: 110 Line No.: 57 Column: d
As of December 31, 2010, Account 165 Prepayments included $344,671,476 of income taxes
receivable from MidAmerican Energy Holdings Company, PacifiCorp's indirect parent company.
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 110 Line No.: 78 Column: d
Amended in accordance with FERC Order No. AC11-132.
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
PaciflCorp
This Report is:
(1)0 An Original
(2)A Resubmission
Date of Report
(mo, da, yr)
06/28/2012
Year/Period of Report
end of 2011/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line
No.
-
Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201) 250-251 3,417,945,896 3,417,945,896
3 Preferred Stock Issued (204) 250-251 40,733,100 40,733,100
4 Capital Stock Subscribed (202, 205) 0 0
5 Stock Liability 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 1,102,229,981
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 41,284,560j
11 Retained Earnings (215, 215.1, 216) 118-119 2,649,231,261
12 Unappropriated Undistributed Subsidiary Earnings (216.1) 118-119 151,915,641
13 (Less) Reaquired Capital Stock (217) 250-251 0 01
14 Noncorporate Proprietorship (Non-major only) (218) 0 0
15 Accumulated Other Comprehensive Income (219) 122(axb) -9,055,432 -6,961,899
16 Total Proprietary Capital (lines 2 through 15) 7,311,715,892 7,311,050,837
17 LONG-TERM DEBT
18 Bonds (221) 256-257 6,171,055,000 6,357,741,000
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) 30,127 32,845
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 14,072,302 14,381,234
24 Total Long-Term Debt (lines 18 through 23) 6,157,012,825 6,343,392,611
25 OTHER NONCURRENT LIABILITIES -
26 Obligations Under Capital Leases - Noncurrent (227) 53,732,331 55,883,528
27 Accumulated Provision for Property Insurance (228.1) 01 0
28 Accumulated Provision for Injuries and Damages (228.2) 5,468,000 8,499,000
29 Accumulated Provision for Pensions and Benefits (228.3) 580,877,62;
30 Accumulated Miscellaneous Operating Provisions (228.4) 38,369,541
31 Accumulated Provision for Rate Refunds (229) 0 0'
32 Long-Term Portion of Derivative Instrument Liabilities 66,449,954 399,481,536
33 Long-Term Portion of Derivative Instrument Liabilities - Hedges 0 0
34 Asset Retirement Obligations (230) 123,312,479 105,328,750
35 Total Other Noncurrent Liabilities (lines 26 through 34) 868,209,927 1,101,946,192
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231) 688,527,000 36,000,000
38 Accounts Payable (232) 536,085,45
39 Notes Payable to Associated Companies (233) 01 0
40 Accounts Payable to Associated Companies (234) 56,292,85
41 Customer Deposits (235) 36,226,1961 39,611.243
42 Taxes Accrued (236) 262-263 52,714,611
43 Interest Accrued (237) 110,248,092 115,234,368
44 Dividends Declared (238) 512,462 512,462
45 Matured Long-Term Debt (239) 0 0
FERC FORM NO. I (rev. 12-03) Page 112
Name of Respondent
PacifiCorp
This Report is:
(1)El An Original
(2)0 A Resubmission
Date of Report
(mo, da, yr)
06/28/2012
Year/Period of Report
end of 2011/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDlTntinued)
Line
No. Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(C)
Prior Year
End Balance
12/31
(d)
46 Matured Interest (240) 01 01
47 Tax Collections Payable (241) 17,536,
48
49
Miscellaneous Current and Accrued Liabilities (242)
Obligations Under Capital Leases-Current (243)
78,951,
2,156,201 1,369,860
50 Derivative Instrument Liabilities (244) 156,054,864 483,234,721
51 (Less) Long-Term Portion of Derivative Instrument Liabilities 66,449,954 399,481,536
52 Derivative Instrument Liabilities - Hedges (245) 0 0
53 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 0 0
54 Total Current and Accrued Liabilities (lines 37 through 53) 1,668,855,795 899,999,512
55 DEFERRED CREDITS
56 Customer Advances for Construction (252) 25,692,158 18,492,298
57 Accumulated Deferred Investment Tax Credits (255) 266-267 38,010,268 41,949,428
58 Deferred Gains from Disposition of Utility Plant (256) 0 0
59 Other Deferred Credits (253) 269 220,954,06
60 Other Regulatory Liabilities (254) 278 111,258,519 59,611,213
61 Unamortized Gain on Reaquired Debt (257) 0 0
62 Accum. Deferred Income Taxes-Accel. Amort.(281) 272-277 164,676,925 11,642,708
63 Accum. Deferred Income Taxes-Other Property (282) 3,505,053,651 3,330,234,891
64 Accum. Deferred Income Taxes-Other (283) 746,721,740 680,518,898
65 Total Deferred Credits (lines 56 through 64) 4,812,367,324 4,193,680,461
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16,24,35,54 and 65) 20,818,161,763 19,850,069,613
FERC FORM NO. I (rev. 12-03) Page 113
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Schedule Page: 112 Line No.: 11 Column: d
Refer to FERC Order No. AC11-132.
Schedule Page: 112 Line No.: 12 Column: d
Refer to footnote for column (d) line 11.
Schedule Page: 112 Line No.: 29 Column: d
Amended in accordance with FERC Order. No. AC11-132.
Schedule Page: 112 Line No.: 30 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 112 Line No.: 38 Column: d
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 112 Line No.: 40 Column: d
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 112 Line No.: 42 Column: d
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 112 Line No.: 47 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 112 Line No.: 48 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 112 Line No.: 59 Column: d
Amended in accordance with FERC Order No. AC11-132.
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)A Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 utility function; in column (i) the quarter to date amounts for gas utility, and in column (k)
the quarter to date amounts for other utility function for the current year quarter.
4.Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (I) the
quarter to date amounts for other utility function for the prior year quarter.
5.If additional columns are needed, place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6.Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7.Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
Line
No.
-
Title of Account
(a)
(Ref.)
Page No.
(b)
Total
Current Year to
Date Balance for
Quarter/Year
(C)
Total
Prior Year to
Date Balance for
Quarter/Year
(d)
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(t)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400) 300-301 4,553,757,3731 4,402,215,3851
3 Operating Expenses
4 Operation Expenses (401) 320-323 2,304,873,210
5 Maintenance Expenses (402) 320-323 432,482,383 414960,7891
6 Depreciation Expense (403) 336-337 501,224,256
7 Depreciation Expense for Asset Retirement Costs (403.1) 336-337
8 Amon. & Depi. of Utility Plant (404-405) 336-337 I 42,204,359 34,838,293
9 Amort. of Utility Plant Acq. Adj. (406) 336-337 5,523,970 5,518,393
10 Amort, Property Losses, Unrecov Plant and Regulatory Study Costs (407) 135,566 4,523,779
11 Amort. of Conversion Expenses (407)
12 Regulatory Debits (407.3) 1,612,926
13 (Less) Regulatory Credits (407.4) 380,507
±136,550,272 14 Taxes Other Than Income Taxes (408.1) 262-263
15 Income Taxes - Federal (409.1) 262-263 -138,818,714
16 - Other (409.1) 262-263 -7,862,714 -4,449,586
17 Provision for Deferred Income Taxes (410.1) 234, 272-277 782.981,862 1,254,766,756
18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 234, 272-277 424,304,774 551,088,560
19 Investment Tax Credit Adj. - Net (411.4) 266 -1,874,204 -1,874,204
20 (Less) Gains from Disp. of Utility Plant (411.6)
21 Losses from Disp. of Utility Plant (411.7)
22 (Less) Gains from Disposition of Allowances (411.8) 164,750 2,817,551
23 Losses from Disposition of Allowances (411.9)
24 Accretion Expense (411.10) 96,470
25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 3,692,952,492 3,566,960,113
26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pgl 1 7,line 27 860,804,881 835,255,272
FERC FORM NO. 113-Q (REV. 02-04) Page 114
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
STATEMENT OF INCOME FOR THE YEAR (Continued)
9.Use page 122 for important notes regarding the statement of income for any account thereof.
10.Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the
gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the
utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations 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 accounts.
12.If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13.Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14.Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
15.If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY -
Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Line
(in dollars) (in dollars) (in dollars) (in dollars) (in dollars) (in dollars) No.
(9) (h) (I) (j) (k) (I) -
4,553,757,373 4,402,215,385 2
3
2,304,873,210 2,300,047,532 4
432,482,383 414,960,789 5
544,830,198 501,224,256 6
7
42,204,359 34,838,293 8
5,523,970 5,518,393 9
135,566 4,523,779 10
11
• 1 1612,926 -2,004,224 12
380,507 13
151,699,035 136,550,272 14
-138,818,714 -523,332,302 15
-7,862,714 -4,449,586 16
782,981,862 1,254,766,756 17
424,304,774 551,088,560 18
-1,874,204 -1,874,204 19
20
21
164,750 2,817,551 22
23
14,646 96,470 24
3,692,952,492 3,566,960,113 25
860,804,881 835,255,272 26
FERC FORM NO. I (ED. 12-96) Page 115
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)ffjA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011 /Q4
STATEMENT OF INCOME FOR THE YEAR (continued)
Line
No.
-
Title of Account
(a)
(Ref.)
Page No.
(b)
TOTAL Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
Current Year
(c)
Previous Year
(d)
27 Net Utility Operating Income (Carried forward from page 114) 860,804,881 835,255,272
28 Other Income and Deductions
29 Other Income
30 Nonutilty Operating Income
31 Revenues From Merchandising, Jobbing and Contract Work (415) 1,731,641 1,416,581
32 (Less) Costs and Exp. of Merchandising. Job. & Contract Work (416) 2,055,446 1,362,155
33 Revenues From Nonutility Operations (417) 43,686 247,917
34 (Less) Expenses of Nonutility Operations (417.1) 110,939 81,037
35 Nonoperating Rental Income (418) 172,282 91,251
36 Equity in Earnings of Subsidiary Companies (418.1) 119 9,511,469
37 Interest and Dividend Income (419) 6,005,324 5,077,391
38 Allowance for Other Funds Used During Construction (419.1) 46,510,051 79,298,238
39 Miscellaneous Nonoperating Income (421) -954,675 27,081,235
40 Gain on Disposition of Properly (421.1) 508,748 2,617,525
41 TOTAL Other Income (Enter Total of lines 31 thru 40) 61,362,1411 129,639,6
42 Other Income Deductions
43 Loss on Disposition of Property (421.2) 37,115 46,470
44 Miscellaneous Amortization (425) 1,290,244 1.285, 16
45 Donations (426.1) 3,009,414 2,676,885
46 Life Insurance (4262) -3,079,61 -4,971,828
47 Penalties (426.3) 238.09 -418,323
48 Exp. for Certain Civic, Political & Related Activities (426.4) 2,171,126 2,284,308
49 Other Deductions (426.5) 8,456,159 29,828,972
50 TOTAL Other Income Deductions (Total of lines 43 thru 49) 12,122,533 30,732,300
51 Taxes Applic. to Other Income and Deductions
52 Taxes Other Than Income Taxes (408.2) 262-263 306,526 367,905
53 Income Taxes-Federal (409.2) 262-263 -1,538,756 28,723,272
54 Income Taxes-Other (409.2) 262-263 -209,091 3,903,016
55 Provision for Deferred Inc. Taxes (410.2) 234, 272-277 59,177,256 85,258,308
56 (Less) Provision for Deferred Income Taxes-Cr. (411.2) 234, 272-277 60,347.318 85,411,869
57 Investment Tax Credit Adj.-Net (411.5)
58 (Less) Investment Tax Credits (420) 2,064,9561 2,065,260
59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) -4,676,3391 30,775,372
60 Net Other Income and Deductions (Total of lines 41, 50, 59) 53,915,9471 68,132,020
61 Interest Charges
62 Interest on Long-Term Debt (427) 364,553,118 363,203,39
63 Amort. of Debt Disc. and Expense (428) 3,910,675 3,727,61
64 Amortization of Loss on Reaquired Debt (428.1) 1,769,844 2,331,323
65 (Less) Amort. of Premium on Debt-Credit (429) 2,718 2,718
66 (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67 Interest on Debt to Assoc. Companies (430) -15,21
68 Other Interest Expense (431) 14,342,093 12,367,152
69 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 24,643,010 44,618,458
70 Net Interest Charges (Total of lines 62 thru 69) 359,914,789 336,972,456
71 Income Before Extraordinary Items (Total of lines 27, 60 and 70) 554,806,039 566,414,836
72 Extraordinary Items
73 Extraordinary Income (434)
74 (Less) Extraordinary Deductions (435)
75 Net Extraordinary Items (Total of line 73 less line 74)
76 Income Taxes-Federal and Other (409.3) 262-263
77 Extraordinary Items After Taxes (line 75 less line 76)
78 Net Income (Total of line 71 and 77) 554,806,039 566,414,836
I]::
FERC FORM NO. 113-Q (REV. 02-04) Page 117
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 114 Line No.: 4 Column: d
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 114 Line No.: 6 Column: c
Depreciation expense associated with transportation equipment is generally charged to
operations and maintenance expense and construction work in progress. During the years
ended December 31, 2011 and 2010, depreciation expense associated with transportation
equipment was $14,396,524 and $14,065,119, respectively.
Schedule Page: 114 Line No.: 7 Column: c
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as
either a regulatory asset or liability.
Schedule Page: 114 Line No.: 12 Column: d
The net credit position reflected in account 407.3, Regulatory Debits, primarily
represents a true-up to regulatory assets based on currently approved state commission
orders for the decommissioning and removal of the Powerdale hydroelectric generating
facility.
ISchedule Page: 114 Line No.: 14 Column: c
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress. During the years ended December 31, 2011 and 2010, payroll taxes were
$40,298,577 and $39,760,547, respectively.
Schedule Page: 114 Line No.: 15 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 114 Line No.: 24 Column: c
Generally, PacifiCorp records the accretion expense of asset retirement obligations as
either a regulatory asset or liability.
ISchedule Page: 114 Line No.: 36 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 114 Line No.: 67 Column: d
Amended in accordance with FERC Order No. AC11-132.
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06128/2012
Year/Period of Report
End of 20111Q4
STATEMENT OF RETAINED EARNINGS
1.Do not report Lines 49-53 on the quarterly version.
2.Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3.Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436 -
439 inclusive). Show the contra primary account affected in column (b)
4.State the purpose and amount of each reservation or appropriation of retained earnings.
5.List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6.Show dividends for each class and series of capital stock.
7.Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8.Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9.If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
Contra Primary
Account Affected
(b)
Current
Quarter/Year
Year to Date
Balance
(c)
Previous
Quarter/Year
Year to Date
Balance
(d)
- UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period 2,652,408,336
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4 I
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acct. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct. 439)
16 Balance Transferred from Income (Account 433 less Account 418.1) 545,294,570
17 Appropriations of Retained Earnings (Acct. 436)
2
21
22 TOTAL Appropriations of Retained Earnings (Acct. 436) I
23 Dividends Declared-Preferred Stock (Account 437)
24 Preferred Stock, various series and rates I 238
12
2
2
28
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437) I -2,049,846 • ( 2,058,333),
30 Dividends Declared-Common Stock (Account 438)
31 Common Stock 238
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acct. 438) -549,997,605
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1,9,15,16,22,29,36,37) 2,645,655,455 2,652,408,336
- APPROPRIATED RETAINED EARNINGS (Account 215)
39
40
FERC FORM NO. 113-Q (REV. 02-04) Page 118
Name of Respondent This Re ort Is: Data of Report Year/Period of Report
PaciflCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)MA Resubmission 06/28/2012
STATEMENT OF RETAINED EARNINGS
1.Do not report Lines 49-53 on the quarterly version.
2.Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3.Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436 -
439 inclusive). Show the contra primary account affected in column (b)
4.State the purpose and amount of each reservation or appropriation of retained earnings.
5.List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6.Show dividends for each class and series of capital stock.
7.Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8.Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9.If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Current Previous
Quarter/Year Quarter/Year
Contra Primary Year to Date Year to Date
Line Item Account Affected Balance Balance
No. (a) (b) (c) (d)
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)
- APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1) I 3,575,811 I 3,575,811
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) 2,649,231,2661 2,655,984,147
- UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
- Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit) I 142,404,172
50 Equity in Earnings for Year (Credit) (Account 418.1) 9,511,469
51 (Less) Dividends Received (Debit) _
52 Transfers to/from Unappropriated Retained Earnings (Account 216)
53 Balance-End of Year (Total lines 49thru 52) 151,915,641 142,404,172
FERC FORM NO. 113-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)
PaciliCorp (2)X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
ISchedule Page: 118 Line No.: I Column: d I Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 118 Line No.: 16 Column: d I
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 118 Line No.: 24 Column: c I
Outstanding shares of preferred stock as of December 31, 2011 and dividends on preferred
stock during the year ended December 31, 2011 were as follows:
Shares Dividend
4.52% Serial Preferred 2,065 $ 9,334
4.56% Serial Preferred 81,326 370,846
4.72% Serial Preferred 65,854 310,830
5.00% Serial Preferred 41,908 209,540
5.40% Serial Preferred 65,959 356,179
6.00% Serial Preferred 5,930 35,580
7.00% Serial Preferred 18,046 126,322
5.00% Preferred 126,243 631,215
407,331 $2,049,846
Schedule Page: 118 Line No.: 24 Column: d
Outstanding shares of preferred stock as of December 31, 2010 and dividends on pr
stock during the year ended December 31, 2010 were as follows:
Shares Dividend
4.52% Serial Preferred 2,065 $ 9,334
4.56% Serial Preferred 81,326 374,570
4.72% Serial Preferred 65,854 315,593
5.00% Serial Preferred 41,908 209,540
5.40% Serial Preferred 65,959 356,179
6.00% Serial Preferred 5,930 35,580
7.00% Serial Preferred 18,046 126,322
5.00% Preferred 126,243 631,215
407,331 $2,058,333
Schedule Page: 118 Line No.: 31 Column: c
For information regarding common stock dividends declared, refer to Important Changes
During the Quarter/Year, Item 6 and Note 15 of Notes to Financial Statements in this
Form No. 1.
Schedule Page: 118 Line No.: 37 Column: d
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 118 Line No.: 47 Column: c
The balance in Account 215.1, Appropriated retained earnings - amortization reserve,
federal is due to requirements of certain hydroelectric relicensing projects.
Schedule Page: 118 Line No.: 47 Column: d
See footnote for column (C) line 47.
Schedule Page: 118 Line No.: 49 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 118 Line No.: 50 Column: d
Amended in accordance with FEP.0 Order No. AC11-132.
Schedule Page: 118 Line No.: 52 Column: d
Amended in accordance with FERC Order No. AC11-132.
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
PacifiCorp
This Report Is:
(1)LjAn Original
(2)jA Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
STATEMENT OF CASH FLOWS
(1)Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt: (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2)Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and
Cash Equivalents at End of Period" with related amounts on the Balance Sheet
(3)Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be
reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4)Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes
to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the US0fA General Instruction 20; instead provide a reconciliation of
the dollar amount of leases capitalized with the plant cost.
Line
No.
Description (See Instruction No. 1 for Explanation of Codes)
(a)
Current Year to Date
Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
1 Net Cash Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117) 554,806,039 566,414,836
3 1 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion 517,014,250'
5 50,140,2071 44,162,057
6
7 Unrealized Gains on Derivative Contracts 1,116,177 -1,892,323
8 Deferred Income Taxes (Net) 357,507,026 703,524,635
9 Investment Tax Credit Adjustment (Net) -3,939,160 -3,939,464
10 Net (Increase) Decrease in Receivables -60,824,263
11 Net (Increase) Decrease in Inventory -58,556,736 -25,822,080
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Accrued Expenses -34,182,597
14 1 Net (Increase) Decrease in Other Regulatory Assets -62,618,384 8,890,615
15 Net Increase (Decrease) in Other Regulatory Liabilities 39,724,553 -4,813,321
16 (Less) Allowance for Other Funds Used During Construction 46,510,0511 79,298,238
17 (Less) Undistributed Earnings from Subsidiary Companies I 9,511,469
18 Amounts Due To/From Affiliates (Net)
19 Derivative Collateral (Net) I 3,796,008 -102,246,009
20
21
20,520,369 22,14.3,762
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21) 1,625,987,550 1,395,654,911
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel) -1,686,214,575
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construction -46,510,051 -79,298,238
31 Other (provide details in footnote):
32
33
34 Cash Outflows for Plant (Total of lines 26 thru 33) -1,485,539,052 -1,606,916,337
35
36 jAcquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
39 Investments in and Advances to Assoc. and Subsidiary Companies -32,230,537
40 Contributions and Advances from Assoc. and Subsidiary Companies I
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)
FERC FORM NO. 1 (ED. 12-96) . Page 120
Name of Respondent
PacifiCo
This Report Is:
(1)EAn Original
(2)MXA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
STATEMENT OF CASH FLOWS
(1)Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2)Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between 'Cash and
Cash Equivalents at End of Period with related amounts on the Balance Sheet.
(3)Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be
reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4)Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes
to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of
the dollar amount of leases capitalized with the plant cost.
Line
No.
-
Description (See Instruction No. 1 for Explanation of Codes)
(a)
Current Year to Date
Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (Increase) Decrease in Receivables
50 Net (Increase ) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accrued Expenses
53
54
55
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55) .1,516,878,354i -1,594,513,037
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b) 396,249,3881
62 Preferred Stock
63 Common Stock
64 Equity Contribution 100,000,000
65
66 Net Increase in Short-Term Debt (c) 652,437,287 35,999,320
67 Other (provide details in footnote):
68
69
70 Cash Provided by Outside Sources (Total 61 thru 69) 1,048,686,675 135,999,320
71
72 Payments for Retirement of:
73 Long-term Debt (b) -586,686,000 -14,602,000
74 Preferred Stock -560,528
75 Common Stock
76 Other (provide details in footnote):
77 Repayment of Capital Lease Obligations -1,364,856 -1,724,876
78 Net Decrease in Short-Term Debt (c)
79
80 Dividends on Preferred Stock -2,049,846 -2,066,818
81 Dividends on Common Stock -549,997,605
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81) -91,411,632 117,045,098
- I I
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83) 17,697,564 1 -81,813,0281
87
88 Cash and Cash Equivalents at Beginning of Period
89
90 Cash and Cash Equivalents at End of period 22,093,240 4,395,676
FERC FORM NO I (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)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 120 Line No.: 4 Column: b
Includes depreciation expense associated with transportation equipment and capital lease
assets of $15,761,379 and $15,789,994 during the years ended December 31, 2011 and 2010,
respectively.
Schedule Page: 120 Line No.: 5 Column: a
Years Ended December 31,
2011 2010
Amortization of software development & other intangibles $ 43,494,603 $ 36,124,109
Amortization of electric plant acquisition adjustments 5,523,970 5,518,393
Amortization of regulatory assets 1,121,634 2,519,555

$ 50,140,207 $ 44,162,057
Schedule Page: 120 Line No.: 10 Column: c
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 120 Line No.: 13 Column: c
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 120 Line No.: 17 Column: c
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 120 Line No.: 18 Column: b
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 120 Line No.: 18 Column: c
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 120 Line No.: 20 Column: a
Coal & steam depreciation and depletion included
in cost of fuel
Gain on sale of property
Write-off of assets under construction
Other
Years Ended December 31,
2011 2010
$ 11,712,355 $ 12,685,957

(497,935) (2,992,914)

5,085,213 8,670,990

4,220,736 3,779,729
$ 20,520,369 $ 22,143,762
ISchedule Page: 120 Line No.: 26 Column: b
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 120 Line No.: 37 Column: b
Represents proceeds from disposal of fixed assets.
Schedule Page: 120 Line No.: 37 Column: c
Represents proceeds from disposal of fixed assets.
ISchedule Page: 120 Line No.: 39 Column: c
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 120 Line No.: 40 Column: c
Amended in accordance with FERC Order No. AC11-132.
ISchedule Paqe: 120 Line No.: 53 Column: a
Other investments/special funds
Temporary facilities
Restricted cash
Footnote amended in accordance with FERC Order No. AC11-132.
Schedule Page: 120 Line No.: 53 Column: b
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 120 Line No.: 53 Column: c
Amended in accordance with FERC Order No. AC11-132.
Years Ended
2011
$ 919,658
23,771
(1,840,306)
$ (896,877)
December 31,
2010
$ (371,886)
(785)
2,730,061
$ 2,357,390
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)X A Resubmission 0612812012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 120 Line No.: 88 Column: b I
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 120 Line No.: 88 Column: c I
Amended in accordance with FERC Order No. AC11-132.
IFERC FORM NO. I (ED. 12-87) Page 450.2 1
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp (1) An Original
06/28/2012 End of 201 1/04
(2) J A Resubmission
NOTES TO FINANCIAL STATEMENTS
1.Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2.Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a
claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on
cumulative preferred stock.
3.For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4.Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an
explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5.Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6.If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and 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 sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8.For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters
shall be provided even though a significant change since year end may not have occurred.
9.Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO. I (ED. 12-96) Page 122
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
PaciliCorp (2)X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
PACIFICORP
NOTES TO FINANCIAL STATEMENTS
(1)Organization and Operations
PacifiCorp is a United States regulated electric company serving 1.7 million retail customers, including residential, commercial,
industrial and other customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp
owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric
transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with public and private
utilities, energy marketing companies, financial institutions and incorporated municipalities. PacifiCorp is subject to comprehensive
state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining and
environmental remediation services. PacifiCorp is an indirect subsidiary of MidAmerican Energy Holdings Company ("MEHC"), a
holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. MEHC is a
consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2)Summary of Significant Accounting Policies
Restatement
On April 17, 2012, the Federal Energy Regulatory Commission ("FERC") issued an order in response to PacifiCorp's requests in
FERC Docket No. AC! 1-132, requiring certain restatements and revisions in PacifiCorp's accounting practices related to its
accounting for its wholly owned coal mining and management subsidiaries for FERC reporting purposes. Historically, these entities
were consolidated and intercompany profits were eliminated. Under the requirements of the order, PacifiCorp is required to account
for these subsidiaries under the equity method and not eliminate profit on intercompany transactions.
In accordance with the order, PacifiCorp has resubmitted its 2011 and 2010 previously filed Forms No. 1 in order to restate the 2010
and 2009 information on the basis required in the order. The 2011 Form No. 1 reflects the restatement of the 2010 comparative
period. The 2010 Form No. 1 presents the restatements of the 2010 and 2009 periods. These restatements resulted in adjustments to
accounts: 123, Investment in Associated Companies; 123.1, Investment in Subsidiary Companies; 131, Cash; 143, Other Accounts
Receivable; 145, Notes Receivable from Associated Companies; 146, Accounts Receivable from Associated Companies; 165,
Prepayments; 186, Miscellaneous Deferred Debits; 216, Unappropriated Retained Earnings; 216.1, Unappropriated Undistributed
Subsidiary Earnings; 228.3, Accumulated Provision for Pensions and Benefits; 228.4, Accumulated Miscellaneous Operating
Provisions; 232, Accounts Payable; 234, Accounts Payable to Associated Companies; 236, Taxes Accrued; 241, Tax Collections
Payable; 242, Miscellaneous Current and Accrued Liabilities; 253, Other Deferred Credits; 401, Operation Expense; 409.1, Income
Taxes, Utility Operating Income; 418.1, Equity in Earnings of Subsidiary Companies; and 430, Interest on Debt to Associated
Companies. As a result of these adjustments, the following lines in the Statement of Cash Flows for the 2010 and 2009 periods were
restated: Net (Increase) Decrease in Receivables; Net Increase (Decrease) in Payables and Accrued Expenses; Undistributed Earnings
from Subsidiary Companies; Amounts Due To/From Affiliates (Net); Other Operating Activities; Investments in and Advances to
Associated and Subsidiary Companies; Contributions and Advances from Associated and Subsidiary Companies; Other Investing
Activities; Cash and Cash Equivalents at Beginning of Period; and Cash and Cash Equivalents at End of Period. The following lines
in the Statement of Cash Flows for the 2011 period were restated: Amounts Due To/From Affiliates (Net); Gross Additions to Utility
Plant (less nuclear fuel); Other Investing Activities; and Cash and Cash Equivalents at Beginning of Period.
These notes do not include the quantitative impacts of the restatement described above as required by accounting principles generally
accepted in the United States of America ("GAAP").
IFERC FORM NO. 1 (ED. 12-88) Page 123.1 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1 (2)
(Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Basis ofPresentation
These financial statements are prepared in accordance with the requirements of the FERC as set forth in its applicable Uniform
System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than GAAP. These notes
include certain applicable disclosures required by GAAP adjusted to the FERC basis of presentation and include specific information
requested by the FERC.
The following are the significant differences between the FERC accounting and reporting standards and GAAP.
Investments in Subsidiaries
In accordance with FERC Order No. AC1 1-132, PacifiCorp accounts for its investment in subsidiaries using the equity
method for FERC reporting purposes rather than consolidating the assets, liabilities, revenues and expenses of subsidiaries as
required by GAAP. GAAP requires that entities in which a company holds a controlling financial interest be consolidated.
The accounting for the investment in subsidiaries using the equity method rather than the consolidation method in
accordance with GAAP has no effect on net income or the combined retained earnings of PacifiCorp and undistributed
earnings of subsidiaries.
Costs ofRemoval
Estimated removal costs that are recovered through 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 GAAP and as
accumulated depreciation under the FERC accounting and reporting standards.
Income Taxes
Accumulated deferred income taxes are classified as current and non-current on the balance sheet for GAAP. Under the
FERC accounting and reporting standards, accumulated deferred income taxes are classified as gross non-current assets and
gross non-current liabilities. Additionally, there are certain presentational differences between FERC and GAAP for amounts
related to unrecognized tax benefits associated with temporary differences in accordance with FERC Docket
No. A107-2-000, "Accounting and Financial Reporting for Uncertainty in Income Taxes."
Interest and penalties on income taxes for GAAP are classified as income tax expense. All such amounts are classified as
interest income, interest expense and penalties under the FERC accounting and reporting standards.
Reclassifications
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 ofEstimates in Preparation of Financial Statements
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and
expenses during the period. These estimates include, but are not limited to, the effects of regulation; certain assumptions made in
accounting for pension and other postretirement benefits; AROs; income taxes; unbilled revenue; valuation of certain financial assets
and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in
preparing the financial statements.
IFERC FORM NO. I (ED. 12-88) Page 123.2 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Accounting for the Effects of Certain Types of Regulation
PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the
economic effects of regulation. Accordingly, PacifiCorp is required to defer the recognition of certain costs or income if it is probable
that, through the ratemaking process, there will be a corresponding increase or decrease in future rates.
PacifiCorp continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and
liabilities are probable of inclusion in future rates by considering factors such as a change in the regulator's approach to setting rates
from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition which could limit
PacifiCorp's ability to recover its costs. Based upon this continuous evaluation, PacifiCorp believes the application of the guidance for
regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future rates. The
evaluation reflects the current political and regulatory climate at both the federal and state levels and is subject to change in the future.
If it becomes no longer probable that the deferred costs or income will be included in future rates, the related regulatory assets and
liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss)
("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market
participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction
prices or quoted market prices may be required in illiquid 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 willing to
transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. 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 necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Investments
Cash equivalents consist of funds invested in United States Treasury Bills, money market funds and other investments with a maturity
of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal
requirements, loan agreements or other contractual provisions. Restricted amounts are included in other special funds and special
deposits on the Comparative Balance Sheet. Total cash and cash equivalents were as follows as of December 31 (in millions):
2011 2010
Cash (13 1) 15 $ 4
Working funds (13 5)
Temporary cash investments (13 6)
Total cash and cash equivalents 22 $ 4
Investments
Available-for-sale securities are carried at fair value with realized gains and losses, as determined on a specific identification basis,
recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. As of December 31, 2011 and 2010,
PacifiCorp had no unrealized gains and losses on available-for-sale securities.
IFERC FORM NO. I (ED. 12-88) Page 123.3 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/2812012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Allowance for Doubt'ful Accounts
Accounts receivable are stated at the outstanding principal amount, net of estimated allowances for doubtful 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 pay or the outcome of any pending disputes. The change in the
balance of the allowance for doubtful accounts, which is included in accumulated provision for uncollectible accounts on the
Comparative Balance Sheet is summarized as follows for the years ended December 31 (in millions):
2011 2010
Beginning balance
Charged to operating costs and expenses, net
Write-offs, net
Ending balance
Derivatives
$
13
$ 9
7
12
PacifiCorp employs a number of different derivative contracts, including forwards, options, swaps and other agreements, to manage
price risk for electricity, 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 GAAP. Derivative balances reflect offsetting permitted under
master netting arrangements with counterparties 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 or 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 not designated as hedging contracts, the settled amount is generally included in rates. Accordingly, the
net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and
probable of inclusion in rates are recorded as net regulatory assets. For a derivative contract not probable of inclusion in rates,
changes in the fair value are recognized in earnings.
Inventories
Inventories consist of materials and supplies, coal stocks, natural gas and fuel oil, which are stated at the lower of average cost or
market.
Net Utility Plant
General
Additions to utility plant are recorded at cost. PacifiCorp capitalizes all construction related material, direct labor and contract
services, as well as indirect construction costs, which include debt and equity allowance for funds used during construction
("AFUDC"). The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives
of the related assets are generally expensed.
IFERC FORM NO. 1 (ED. 12-88) Page 123.4 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Depreciation and amortization are generally computed on the straight-line method based on composite asset class lives prescribed by
PaciflCorp's various regulatory authorities or over the assets' estimated useful lives. Depreciation studies are completed periodically to
determine the appropriate composite asset class lives, net salvage and depreciation rates. These studies are reviewed and rates are
ultimately approved by the various regulatory authorities. Net salvage includes the estimated future residual values of the assets and
any estimated removal costs recovered through 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 ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally when PaciflCorp retires or sells a component of utility plant, it charges the original cost and any net proceeds from the
disposition to accumulated provision for depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
PaciflCorp records debt and equity AFUDC, which represents the estimated costs of debt and equity funds necessary to finance
additions to utility plant. AFIJIDC is capitalized as a component of utility plant, with offsetting credits to the Statement of Income.
AFTJDC is computed based on guidelines set forth by the FERC. After construction is completed, PaciflCorp is permitted to earn a
return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful
lives of the related assets.
Asset Retirement Obligations
PacifiCorp recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon
retirement of an asset. PacifiCorp's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is
recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying
amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial
recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding
adjustments to utility plant) and for accretion of the ARO liability due to the passage of time. The difference between the ARO
liability, the corresponding ARO asset included in utility plant and amounts recovered in depreciation rates to satisfy such liabilities is
recorded as a regulatory asset or liability.
Revenue Recognition
Revenue is recognized as electricity is delivered or services are provided. Revenue recognized includes billed, as well as unbiled,
amounts. As of December 31, 2011 and 2010, unbilled revenue was $237 million and $206 million, respectively, and is included in
accrued utility revenues, net on the Comparative Balance Sheet Rates charged are established by regulators or contractual
arrangements.
The determination of sales to individual customers is based on the reading of the customer's meter, which is performed on a
systematic basis throughout the month. At the end of each month, energy provided to customers since the date of the last meter
reading is estimated, and the corresponding unbilled revenue is recorded. The estimate is reversed in the following month and actual
revenue is recorded based on subsequent meter readings.
The monthly unbilled revenues of PaciflCorp are determined by the estimation of unbilled energy provided during the period, the
assignment of unbilled energy provided to customer classes and the average rate per customer class. Factors that can impact the
estimate of unbilled energy provided include, but are not limited to, seasonal weather patterns, total volumes supplied to the system,
line losses, economic impacts and composition of customer classes.
PaciflCorp 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.
IFERC FORM NO. 1 (ED. 12-88) Page 123.5 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Income Taxes
Berkshire Hathaway includes PacifiCorp in its United States federal income tax return. Consistent with established regulatory
practice, PacifiCorp's provision for income taxes has been computed on a stand-alone basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and
liabilities using estimated income tax rates expected to be in effect for the year in which the differences are expected to reverse.
Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are
charged or credited directly to OCT. Changes in deferred income tax assets and liabilities that are associated with income tax benefits
related to certain property-related basis differences and other various differences that PacifiCorp is required to pass on to its
customers are charged or credited directly to a regulatory asset or liability. These amounts were recognized as a net regulatory asset
totaling $422 million and $426 million as of December 31, 2011 and 2010, respectively, and will be included in rates when the
temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax
expense.
Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by
various regulatory jurisdictions.
In determining PacifiCorp's income taxes, management is required to interpret complex tax laws and regulations, which includes
consideration of regulatory implications imposed by PacifiCorp's various regulatory jurisdictions. PacifiCorp's tax returns 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 nature of the examination process, it generally takes years before these examinations are completed
and these matters are resolved. PacifiCorp recognizes the tax benefit from an uncertain tax position only if it is more likely than not
that the tax position will be sustained upon 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. Although the ultimate resolution of PacifiCorp's federal, state and
local tax examinations is uncertain, PacifiCorp believes it has made adequate provisions for these tax positions. The aggregate amount
of any additional tax liabilities that may result from these examinations, if any, is not expected to have a material adverse effect on
PacifiCorp's financial results. PacifiCorp's unrecognized tax benefits are primarily included in Taxes accrued on the Comparative
Balance Sheet. Estimated interest and penalties, if any, related to uncertain tax positions are included in interest income, interest
expense and penalties on the Statement of Income.
Segment Information
PacifiCorp currently has one segment, which includes its regulated electric utility operations.
New Accounting Pronouncements
In December 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2011-11,
which amends FASB Accounting Standards Codification ("ASC") Topic 210, "Balance Sheet." The amendments in this guidance
require an entity to provide quantitative disclosures about offsetting financial instruments and derivative instruments. Additionally,
this guidance requires qualitative and quantitative disclosures about master netting agreements or similar agreements when the
financial instruments and derivative instruments are not offset. This guidance is effective for fiscal years beginning on or after January
1, 2013, and for interim periods within those fiscal years. PacifiCorp is currently evaluating the impact of adopting this guidance on
its disclosures included within Notes to Financial Statements.
IFERC FORM NO. I (ED. 12-88) Page 123.6 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PaciflCorp (2)X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
In September 2011, the FASB issued ASU No. 2011-09, which amends FASB ASC Subtopic 715-80, "Compensation-Retirement
Benefits-Multiemployer Plans." The amendments in this guidance require additional disclosures regarding an entity's participation in
multiemployer pension plans and other postretirement benefit plans, as well as certain qualitative and quantitative disclosures
regarding individually significant multiemployer pension plans. PacifiCorp adopted this guidance as of December 31, 2011. Refer to
the additional disclosures required by ASU No. 2011-09 at Note 11.
In May 2011, the FASB issued ASU No. 2011-04, which amends FASB ASC Topic 820, "Fair Value Measurements and
Disclosures." The amendments in this guidance are not intended to result in a change in current accounting. ASU No. 2011-04
requires additional disclosures relating to fair value measurements categorized within Level 3 of the fair value hierarchy, including
quantitative information about unobservable inputs, the valuation process used by the entity and the sensitivity of unobservable input
measurements. Additionally, entities are required to disclose the level of the fair value hierarchy for assets and liabilities that are not
measured at fair value in the balance sheet, but for which disclosure of the fair value is required. This guidance is effective for interim
and annual reporting periods beginning after December 15, 2011. PacifiCorp is currently evaluating the impact of adopting this
guidance on its disclosures included within Notes to Financial Statements.
In January 2010, the FASB issued ASU No. 2010-06, which amends FASB 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 clarifies that existing fair value measurement disclosures should be
presented for each class of assets and liabilities. The existing disclosures about the valuation techniques and inputs used to measure
fair value for both recurring and nonrecurring fair value measurements have also been clarified to ensure 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 PacifiCorp adopted as of January 1, 2011. The adoption of this guidance did not have a material impact on
PacifiCorp's disclosures included within Notes to Financial Statements.
(3)Net Utility Plant
The average depreciation and amortization rate applied to depreciable utility plant was 2.8% for the years ended December 31, 2011
and 2010 and 2.9% for the year ended December 31, 2009.
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 service over their net book value in those assets. These unallocated acquisition
adjustments included in utility plant had an original cost of $159 million as of December 31, 2011 and 2010 and accumulated
provision for depreciation, amortization and depletion of $107 million and $102 million as of December 31, 2011 and 2010,
respectively.
IFERC FORM NO. I (ED. 12-88) Page 123.7 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011 /Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(4)Jointly Owned Utility Facilities
Under joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly
owned generation, transmission and distribution facilities. PaciflCorp accounts for its proportionate share of each facility, and each
joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on
their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the
Statement of Income include PaciflCorp's share of the expenses of these facilities.
The amounts shown in the table below represent PaciflCorp's share in each jointly owned facility as of December 31, 2011
(dollars in millions):
Jim Bridger Nos. 1 - 4
Hunter No. 1
Hunter No. 2
Wyodak
Colstrip Nos. 3 and 4
Hermiston
Craig Nos. 1 and 2
Hayden No. 1
Hayden No. 2
Foote Creek
Transmission and distribution facilities
Total
(5)Regulatory Matters
Facility Accumulated Construction
PacifiCorp in Depreciation and Work-in-
Share Service Amortization Progress
67% $ 1,074 $ 506 $ 21
94 342 147 43
60 291 80 12
80 449 150 1
10 222 119 2
50 171 53 1
19 176 91 -
25 51 25 -
13 32 16 -
79 37 18 -
Various 315 54 1
$ 3,160 $ 1,259 $ 81
PacifiCorp had regulatory assets not earning a return on investment of $1.662 billion and $1 .575 billion as of December 31, 2011 and
2010, respectively.
IFERC FORM NO. 1 (ED. 12-88) Page 123.8 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011 /Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(6) Fair Value Measurements
The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, special funds, other investments, payables, accrued
liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has
various financial assets and liabilities that are measured at fair value on the financial statements using inputs from the three levels of
the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input
that is significant to the fair value measurement. The three levels are as follows:
Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the
ability to access at the measurement date.
Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or
similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset
or 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 participants 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.
IFERC FORM NO. 1 (ED. 12-88) Page 123.9 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table presents PacifiCorp's assets and liabilities recognized on the Comparative Balance Sheet and measured at fair
value on a recurring basis (in millions):
Input Levels for Fair Value
Measurements
Level 1 Level 2 Level 3 Other(1) Total
As of December 31, 2011
Assets:
Commodity derivatives $ - $ 114 $ 1 $ (100) $ 15
Investments in available-for-sale securities -
Money market mutual funds(2)
Liabilities - Commodity derivatives
As of December 31, 2010
Assets:
Commodity derivatives
Investments in available-for-sale securities -
Money market mutual funds(2)
9 - - - 9
$ 9 $ 114 $ 1 $ (100) $ 24
$ - $ (379) $ - $ 223 $ (156)
$ - $ 263 $ 5 $ (145) $ 123
2 - - 2
$ 2 $ 263 $ 5 $ (145) $ 125
Liabilities - Commodity derivatives $ - $ (405) $ (350) $ 272 $ (483)
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $123 million and $127 million as of December 31, 2011 and
2010, respectively.
(2)Amounts are included in other investments, other special funds and temporary cash investments on the Comparative Balance Sheet. The fair value of these
money market mutual funds approximates cost.
IFERC FORM NO. I (ED. 12-88) Page 123.10 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011 IQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Derivative contracts are recorded on the Comparative Balance Sheet as either assets or liabilities and are stated at fair value unless
they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair
value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PaciflCorp
transacts. When quoted prices for identical contracts are not available, PaciflCorp uses forward price curves. Forward price curves
represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates.
PaciflCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial
models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers,
exchanges, direct communication with market participants and actual transactions executed by PaciflCorp. Market price quotations for
certain major electricity and natural gas trading hubs are generally readily obtainable for the first six years; therefore, PacifiCorp's
forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and
natural gas trading hubs are not as readily obtainable for the first six years. Given that limited market data exists for these contracts, as
well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on
perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these
derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility,
counterparty creditworthiness and duration of contracts. Refer to Note 7 for further discussion regarding PaciflCorp's risk
management and hedging activities.
Contracts with explicit or embedded optionality are valued by separating each contract into its physical and financial forward, swap
and option components. Forward and swap components are valued against the appropriate forward price curve. Option components
are valued using Black-Scholes-type models, such as European option, spread option and best-of option, with the appropriate forward
price curve and other inputs.
PacifiCorp's investments in money market mutual funds are accounted for as available-for-sale securities and are stated at fair value.
PaciflCorp uses a readily observable quoted market price or net asset value of an identical security in an active market to record the
fair value.
The following table reconciles the beginning and ending balances of PaciflCorps commodity derivative assets and liabilities
measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):
2011 2010
Beginning balance
Changes in fair value recognized in net regulatory assets
Contracts designated as normal purchases or normal sales
Settlements
Ending balance

(345) $ (380)

132 (38)

168 -

46 73
$ (345)
In December 2011, PacifiCorp elected to designate certain derivative contracts as normal purchases or normal sales, an exception
afforded by GAAP. As a result of making the designation, the fair value of the contracts was frozen as of December 31, 2011 and
$168 million of net derivative liabilities was reclassified from derivative contracts to other assets and liabilities. The frozen liability
and associated regulatory asset will be amortized over the remaining terms of the agreements.
IFERC FORM NO. 1 (ED. 12-88) Page 123.11 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) - An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
PacifiCorp's long-term debt is carried 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 future cash flows discounted at rates consistent
with comparable maturities with similar credit risks. The carrying value of PaciflCorp's variable-rate long-term debt approximates fair
value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and
estimated fair value of PacifiCorp's long-term debt as of December 31 (in millions):

2011 2010
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $ 6,157 $ 7,804 $ 6,344 $ 7,086
(7) Risk Management and Hedging Activities
PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to
electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its regulated
service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to
commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is
purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other
unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and
transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a
material amount of proprietary trading activities.
PacifiCorp has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each
of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity
derivative contracts, which may include forwards, options, swaps and other agreements, to effectively secure future supply or sell
future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates
primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally,
PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate
PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not
hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Notes 2 and 6 for additional
information on derivative contracts.
IFERC FORM NO. I (ED. 12-88) Page 123.12 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011 /Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the
normal purchases or normal sales exception afforded by GAAP, summarizes 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 millions):
Derivative Assets Derivative Liabilities
Current Noncurrent Current Noncurrent Total
As of December 31, 2011
Not designated as hedging contracts(1)(2):
Commodity assets $ 30 $ 7 $ 66 $ 12 $ 115
Commodity liabilities (17) (3) (242) (117) (379)
Total 13 4 (176) (105) (264)
Total derivatives 13 4 (176) (105) (264)
Cash collateral (payable) receivable (2) - 86 39 123
Totalderivatives - netbasis $ 11 $ 4 $ (90) $ (66) $ (141)
As of December 31, 2010
Not designated as hedging contracts(l)(2):
Commodity assets $ 185 $ 13 $ 34 $ 36 $ 268
Commodity liabilities (62) (4) (213) (476) (755)
Total 123 9 (179) (440) (487)
Total derivatives 123 9 (179) (440) (487)
Cash collateral (payable) receivable (9) - 95 41 127
Total derivatives - net basis $ 114 $ 9 $ (84) $ (399) $ (360)
(1)Derivative contracts within these categories subject to master netting arrangements are presented on a net basis on the Comparative Balance Sheet.
(2)PaciflCorp's commodity derivatives are generally included in rates and as of December 31, 2011 and 2010, a net regulatory asset of $264 million and
$487 million, respectively, was recorded related to the net derivative liability of $264 million and $487 million, respectively.
IFERC FORM NO. I (ED. 12-88) Page 123.13 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PaciflCorp (2)XA Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
For PacifiCorp's commodity derivatives, the settled amount is generally included in rates. Accordingly, the net unrealized gains and
losses associated with interim 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 summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as
amounts reclassified to earnings for the years ended December 31 (in millions):
2011 2010
Beginning balance
Changes in fair value recognized in net regulatory assets
Net losses reclassified to unamortized contract value regulatory asset
Net gains reclassified to operating revenue
Net losses reclassified to energy costs
Ending balance
487 $ 367
(2) 90
(168) -
18 64
(71) (34)
$ 264 $ 487
For PaciflCorp's derivatives for which changes in fair value are not recorded as a net regulatory asset, unrealized gains and losses are
recognized on the Statement of Income as miscellaneous nonoperating income for unrealized gains and as other deductions for
unrealized losses. During the years ended December 31, 2011 and 2010, these amounts were insignificant.
Derivative Contract Volumes
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that
comprise the mark-to-market values as of December 31 (in millions):
Commodity contracts:
Electricity sales
Natural gas purchases
Fuel oil purchases
Credit Risk
Unit of
Measure 2011 2010
Megawatt hours (2) (13)
Decatherms 96 159
Gallons 17 16
PacifiCorp extends unsecured credit to other utilities, energy marketing companies, financial institutions and other market participants
in conjunction with its wholesale energy supply and marketing activities. Credit risk relates to the risk of loss that might occur as a
result of nonperformance by counterparties on their contractual obligations to make or take delivery of electricity, natural gas or other
commodities and to make financial settlements of these obligations. Credit risk may be concentrated to the extent that one or more
groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual
obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a
counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to
circumstances involving other market participants that have a direct or indirect relationship with the counterparty.
PacifiCorp analyzes the financial condition of each significant wholesale counterparty before entering into any transactions,
establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of
unsecured credit limits on an ongoing basis. To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp enters
into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party
guarantees, letters of credit and cash deposits. Counterparties may be assessed fees for delayed payments. If required, PacifiCorp
exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
IFERC FORM NO. 1 (ED. 12-88) Page 123.14 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
PaciflCorp (2)X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Collateral and Contingent Features
In accordance with industry practice, certain wholesale derivative contracts contain provisions that require PacifiCorp to maintain
specific credit ratings from one or more of the major credit rating agencies on its unsecured debt. These derivative contracts may
either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified
rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand
"adequate assurance" in the event of a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and
by counterparty. As of December 31, 2011, 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 features
totaled $378 million and $448 million as of December 31, 2011 and 2010, respectively, for which PacifiCorp had posted collateral of
$125 million and $136 million, respectively. If all credit-risk-related contingent features for derivative contracts in liability positions
had been triggered as of December 31, 2011 and 2010, PacifiCorp would have been required to post $155 million and $129 million,
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.
(8) Short-term Debt and Other Financing Agreements
PacifiCorp has a $635 million unsecured credit facility expiring in October 2012 and an unsecured credit facility with $720 million
available until July 2012, and $630 million until July 2013. The credit facilities include a fixed or variable borrowing option for which
rates vary based on the borrowing option and PacifiCorp's credit ratings for its senior unsecured long-term debt securities. These
facilities support PacifiCorp's commercial paper program and certain variable-rate tax-exempt bond obligations. As of December 31,
2011, PacifiCorp had $688 million of commercial paper borrowings outstanding at a weighted-average interest rate of 0.5% and no
borrowings outstanding under its credit facilities. As discussed in Note 9, in January 2012, PacifiCorp issued $650 million of
long-term debt, the proceeds of which were in part used to repay a significant portion of the commercial paper borrowings
outstanding as of December 31, 2011. 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 outstanding under its credit facilities.
As of December 31, 2011 and 2010, PacifiCorp had $601 million of letters of credit issued under committed arrangements, of which
$304 million were issued under the revolving credit agreements. These letters of credit support PacifiCorp's variable-rate tax-exempt
bond obligations, were fully available as of December 31, 2011 and 2010, and expire periodically from May 2012 through November
2012.
Each revolving credit agreement and letter of credit arrangement requires that PacifiCorp's ratio of debt, including current maturities,
to total capitalization at no time exceed 0.65 to 1.0. As of December 31, 2011, PacifiCorp was in compliance with the covenants of its
revolving credit agreements and letter of credit arrangements.
IFERC FORM NO. I (ED. 12-88) Page 123.15 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table summarizes PacifiCorp's availability under its two unsecured revolving credit facilities as of December 31 (in
millions):
2011:
Available revolving credit facilities
Less:
Short-term debt
Letters of credit supporting tax-exempt bond obligations
Net revolving credit facilities available
2010:
Available revolving credit facilities
Less:
Short-term debt
Letters of credit supporting tax-exempt bond obligations
Net revolving credit facilities available
1,355
(688)
(304)
$ 363
$ 1,395
(36)
(304)
$ 1,055
As of December 31, 2011, PacifiCorp had approximately $13 million of additional letters of credit issued on its behalf to provide
credit support for certain transactions as required by third parties. These letters of credit were all undrawn as of December 31, 2011
and have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to
renew a letter of credit prior to the expiration date.
(9) Long-term Debt and Capital Lease Obligations
PacifiCorp's long-term debt may include provisions that allow PacifiCorp to redeem the long-term debt in whole or in part at any time.
These provisions generally include make-whole premiums.
In March 2012, PacifiCorp issued $100 million of its 2.95% First Mortgage Bonds due February 1, 2022. The net proceeds were used
for the redemption of certain tax-exempt bonds, repayment of short-term debt and general corporate purposes.
In January 2012, PacifiCorp issued $350 million of its 2.95% First Mortgage Bonds due February 1, 2022 and $300 million of its
4.10% First Mortgage Bonds due February 1, 2042. The net proceeds were used to repay short-term debt, fund capital expenditures
and for general corporate purposes.
In May 2011, PacifiCorp issued $400 million of its 3.85% First Mortgage Bonds due June 15, 2021. The net proceeds were used to
fund capital expenditures, repay short-term debt and for general corporate purposes.
PacifiCorp currently has regulatory authority from the Oregon Public Utility Commission ("OPUC") and the Idaho Public Utilities
Commission to issue an additional $850 million of long-term debt PacifiCorp must make a notice filing with the Washington Utilities
and Transportation Commission prior to any future issuance. PacifiCorp currently has an effective shelf registration statement filed
with the United States Securities and Exchange Commission expected to provide for future first mortgage bond issuances through
November 2013.
In September 2010, PacifiCorp completed a re-offering of variable-rate tax-exempt bond obligations totaling $38 million. 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.
IFERC FORM NO. I (ED. 12-88) Page 123.16 I
121
(65)
$ 56
7 $ 24
12 273
8 261
7 129
7 64
80 5,541
6,292
(14)
(65)
$ 6,213
2012
2013
2014
2015
2016
Thereafter
Total
Unamortized discount
Amounts representing interest
Total
$ 17 $
261
253
122
57
5,461
6,171
(14)
$ 6,157
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
In June 2010, PacifiCorp completed a re-offering 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 million letter of credit issued under one of PacifiCorp's unsecured revolving
credit facilities.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's
mortgage. Approximately $22 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage
as of December 31, 2011.
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, 2011,
PacifiCorp was in compliance with these covenants.
PacifiCorp has entered into long-term agreements that qualify as capital leases and expire at various dates through October 2036 for
transportation services, power purchase agreements, real estate and for the use of certain equipment. The transportation services
agreements included as capital leases are for the right to use pipeline facilities to provide natural gas to three of PacifiCorp's
generating facilities. Net capital lease assets of $56 million and $57 million as of December 31, 2011 and 2010, respectively, were
included in net utility plant in the Comparative Balance Sheet.
As of December 31, 2011, the annual maturities of long-term debt and capital lease obligations, excluding unamortized discounts and
including interest on capital lease obligations, for 2012 and thereafter are as follows (in millions):
Long-term Capital Lease
Debt Obligations Total
IFERC FORM NO. 1 (ED. 12-88) Page 123.17 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(10) Asset Retirement Obligations
PacifiCorp estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash
spending for a third party to perform 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 indeterminate
removal date, the fair value of the associated liabilities on certain transmission, distribution and other assets cannot currently 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 and in accordance with accepted regulatory practices. These accruals totaled
$782 million as of December 31, 2011 and 2010.
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31
(in millions):
2011 2010
Beginning balance
Change in estimated costs(l)
Additions
Retirements
Accretion
Ending balance
$ 105
2
29
(19)
6
$ 123
$ 103
2
1
(6)
5
$ 105
(1) Results from changes in the timing and amounts of estimated cash flows for certain plant and mine reclamation.
Certain of PacifiCorp's decommissioning and reclamation obligations relate to jointly owned facilities and mine sites. PacifiCorp is
committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other
joint participants, PacifiCorp may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of
the defaulting party's liability. PacifiCorp's estimated share of the decommissioning and reclamation obligations are primarily
recorded as ARO liabilities.
(11) Employee Benefit Plans
PacifiCorp sponsors defined benefit pension and other postretirement benefit plans that cover the majority of its employees, as well as
a defined contribution 401(k) employee savings plan ("401(k) Plan"). PacifiCorp and one of its subsidiaries contribute to
multiemployer pension plans for benefits offered to certain bargaining units.
IFERC FORM NO. I (ED. 12-88) Page 123.18 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Pension and Other Postretirement Benefit Plans
PacifiCorp's pension plans include a non-contributory defined benefit pension plan, the PacifiCorp Retirement Plan ("Retirement
Plan"), and the Supplemental Executive Retirement Plan ("SERF'). The Retirement Plan is closed to employees hired after January 1,
2008 for all non-union employees. The SERP was closed to new participants as of March 21, 2006. All non-union Retirement Plan
participants hired prior to January 1, 2008 that did not elect to receive equivalent fixed contributions to the 401(k) Plan effective
January 1, 2009, earn benefits based on a cash balance formula. In general for union employees, benefits under the Retirement Plan
were frozen at various dates from December 31, 2007 through December 31, 2011 as they are now being provided with enhanced
401(k) Plan benefits. However, certain union Retirement Plan participants continue to earn benefits under the Retirement Plan based
on the employee's years of service and a final average pay formula.
PacifiCorp's other postretirement benefit plan provides healthcare and life insurance benefits to eligible retirees.
Plan Amendments and Curtailments
Effective January 1, 2012, PaciflCorp changed the medical benefits for the majority of Medicare-eligible participants in its other
postretirement benefit plan. Medicare-eligible participants now enroll in individual medical plans, rather than company-sponsored
plans, under which PacifiCorp contributes fixed amounts to the participant's health reimbursement account. As a result of this change,
PacifiCorp's benefit obligation for its other postretirement benefit plan and its related regulatory assets decreased $54 million as of
December 31, 2011.
Effective March 31, 2010, the Utility Workers Union of America Local Union No. 127 ("Local 127") elected to cease participation in
the Retirement Plan and participate only in the 401(k) Plan with enhanced benefits. As a result of this election, the Local 127
participants' Retirement Plan benefits were frozen on March 31, 2010. This change resulted in a $2 million curtailment gain that was
recorded as a regulatory deferral and is being amortized over periods similar to those required for other recent curtailments. Also as a
result of this change, PacifiCorp's pension benefit obligation and regulatory assets each decreased by $14 million as of December 31,
2010.
Healthcare Reform Legislation
In March 2010, the President signed into law healthcare reform legislation that included provisions to reduce the tax deductibility of
other postretirement costs by the amount of retiree drug subsidies received from the federal government beginning after December 31,
2012. As a result of the legislation, PacifiCorp increased deferred income tax liabilities and regulatory assets by $39 million during
the year ended December 31, 2010. PacifiCorp has received authorization from various state regulatory commissions for deferral of
substantially all of the $16 million portion of the adjustment that related to income tax benefits associated with amounts previously
recognized as net periodic benefit costs. The remaining $23 million of the adjustment relates to income tax benefits that will no longer
be realized in the future when the net periodic benefit cost is recognized and for which recovery of the resulting higher future income
tax expense will be addressed through on-going ratemaking proceedings.
The law also contains a provision that requires a 40% excise tax for group health benefits that are provided to employees above
certain premium thresholds beginning in 2018. The tax would apply to the amount of premiums in excess of the thresholds. Virtually
all major areas of the healthcare reform legislation, including the 40% excise tax, are subject to interpretation and implementation
rules that may take several years to complete. As of December 31, 2010, PacifiCorp's other postretirement benefit obligation increased
by $12 million as a result of the projected impact of the excise tax on benefits provided to a certain bargaining unit
IFERC FORM NO. 1 (ED. 12-88) Page 123.19 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Net Periodic Benefit Cost
For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets
is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the
first year in which they occur.
Net periodic benefit cost for the plans included the following components for the years ended December 31 (in millions):
Pension Other Postretirement
2011 2010 2011 2010
Service cost $ 10 $ 12 $ 7 $ 6
Interest cost 63 66 31 31
Expected return on plan assets (75) (74) (30) (30)
Net amortization 29 23 17 14
Net amortization of regulatory deferrals (9) (10) 1 1
Net periodic benefit cost $ 18 $ 17 $ 26 $ 22
Funded Status
The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
Pension Other Postretirement
2011 2010 2011 2010
Plan assets at fair value, beginning of year $ 960 $ 825 $ 389 $ 350
Employer contributions 71 117 28 24
Participant contributions - - 9 9
Actual return on plan assets (13) 102 (4) 44
Benefits paid (87) (84) (38) (38)
Plan assets at fair value, end of year $ 931 $ 960 $ 384 $ 389
IFERC FORM NO. 1 (ED. 12-88) Page 123.20 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
Pension Other Postretirement
2011 2010 2011 2010
Benefit obligation, beginning of year $ 1,236 5 1,199 $ 581 $ 545
Service cost 10 12 7 6
Interest cost 63 66 31 31
Participant contributions - - 9 9
Plan amendments (4) - (54) -
Curtailment - (14) - -
Actuarial loss 73 57 36 25
Benefits paid, net of Medicare subsidy (87) (84) (35) (35)
Benefit obligation, end of year $ 1,291 $ 1,236 $ 575 $ 581
Accumulated benefit obligation, end of year 5 1,289 $ 1,230
The funded status of the plans and the amounts recognized on the Comparative Balance Sheet as of December 31 are as follows
(in millions):
Pension Other Postretirement
2011 2010 2011 2010
Plan assets at fair value, end of year $ 931 $ 960 $ 384 $ 389
Less - Benefit obligation, end of year 1,291 1,236 575 581
Funded status $ (360) $ (276) $ (191) $ (192)
Amounts recognized on the Comparative Balance Sheet:
Other current liabilities $ (4) $ (4) $ - $ -
Other long-term liabilities (356) (272) (191) (192)
Amounts recognized $ (360) $ (276) $ (191) $ (192)
IFERC FORM NO. I (ED. 12-88) Page 123.21 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The SERP has no plan assets; however, PaciflCorp has a Rabbi trust that holds corporate-owned life insurance and other investments
to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in the Rabbi
trust, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was
$41 million and $40 million as of December 31, 2011 and 2010, respectively. These assets are not included in the plan assets in the
above table, but are reflected in noncurrent other assets on the Comparative Balance Sheet The portion of the pension plans' projected
benefit obligation related to the SERP was $58 million and $56 million as of December 31, 2011 and 2010, respectively.
Unrecognized Amounts
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in
millions):
Pension Other Postretirement
2011 2010 2011 2010
Net loss
Prior service credit
Net transition obligation
Regulatory deferrals
Total
630 $ 507 8 206 $ 142
(45) (50) (46) -
- - - 19
(7) (16) 3 4
$ 578 $ 441 $ 163 $ 165
IFERC FORM NO. I (ED. 12-88) Page 123.22 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)- An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2011
and 2010 is as follows (in millions):
Accumulated
Other -
Regulatory Comprehensive
Asset Loss Total
Pension
Balance, December 31, 2009 $ 430 $ 9 $ 439
Net loss arising during the year 27 2 29
Curtailment (14) - (14)
Net amortization (13) - (13)
Total - 2 2
Balance, December 3l,2010 430 11 441
Net loss arising during the year 157 4 161
Prior service credit arising during the year (4) - (4)
Net amortization (19) (1) (20)
Total 134 3 137
Balance, December 31, 2011 $ 564 $ 14 $ 578
Deferred
Regulatory Income
Asset Taxes Total
Other Postretirement
Balance, December 31, 2009 $ 146 $ 23 $ 169
Net loss arising during the year 11 - 11
Income tax benefits no longer realizable (1) 23 (23) -
Net amortization (15) - (15)
Total 19 (23) (4)
Balance, December 31, 2010 165 - 165
Net loss arising during the year 70 - 70
Prior service credit arising during the year (46) - (46)
Reduction in net transition obligation (8) - (8)
Net amortization (18) - (18)
Total (2) - (2)
Balance, December 31, 2011 $ 163 $ - $ 163
(1) Represents adjustments to regulatory assets associated with income tax benefits that will no longer be realized when the net periodic benefit cost is
recognized as a result of the healthcare reform legislation.
IFERC FORM NO. 1 (ED. 12-88) Page 123.23 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The net loss, prior service credit and regulatory deferrals that will be amortized in 2012 into net periodic benefit cost are estimated to
be as follows (in millions):
Net Prior Service Regulatory
Loss Credit Deferrals Total
Pension $ 44 $ (8) $ (2) $ 34
Other postretirement 10 (7) 1 4
Total $ 54 $ (15) $ (1) $ 38
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
Benefit obligations as of December 31:
Discount rate
Rate of compensation increase
Net periodic benefit cost for the years ended December 31:
Pension Other Postretirement
2011 2010 2011 2010

4.90 % 5.35 % 4.95 % 5.45 %

3.50 3.50 N/A N/A
Discount rate 5.35 % 5.80 % 5.45 % 5.85 %
Expected return on plan assets 7.50 7.75 7.50 7.75
Rate of compensation increase 3.50 3.00 N/A N/A
In establishing its assumption as to the expected return on plan assets, PacifiCorp utilizes the expected asset allocation and return
assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
2011 2010
Assumed healthcare cost trend rates as of December 31:
Healthcare cost trend rate assumed for next year 8.50% 8.00%
Rate that the cost trend rate gradually declines to 5.00% 5.00%
Year that the rate reaches the rate it is assumed to remain at 2016 2016
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
Increase (decrease) in:
Total service and interest cost $ 3 $ (2)
Other postretirement benefit obligation 45 (36)
IFERC FORM NO. 1 (ED. 12-88) Page 123.24 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X Resubmission 06/28/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $49 million and $9 million,
respectively, during 2012. Funding to PacifiCorp's Retirement Plan trust is based upon the actuarially determined costs of the plan and
the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 ("ERISA") and the Pension
Protection Act of 2006, as amended ("PPA"). PacifiCorp considers contributing additional amounts from time to time in order to
achieve certain funding levels specified under the PPA. PacifiCorp's funding policy for its other postretirement benefit plan is to
contribute an amount equal to the sum of the net periodic benefit cost and the amount of Medicare subsidies expected to be earned
during the period.
The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2012 through 2016
and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Other Postretirement
Pension Gross Medicare Subsidy Net of Subsidy
2012 5 99 $ 35 5 - $ 35
2013 103 36 (1) 35
2014 104 36 (1) 35
2015 105 37 (1) 36
2016 108 38 (1) 37
2017-2021 492 203 (9) 194
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 through a diversified
portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities 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 Committee. The investment portfolio is managed in line with the investment policy
with sufficient liquidity to meet near-term benefit payments. The return on assets assumption for each plan is based on a
weighted-average of the expected performance for the types of assets in which the plans invest.
IFERC FORM NO. I (ED. 12-88) Page 123.25 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows
as of December 31, 2011:
Pension(l) Other Postretirement(1)
Debt securities(2) 33-37 33-37
Equity securities(2) 53 -57 61 -65
Limited partnership interests 8-12 1-3
Other 0-1 0-1
(1)PacifiCorp's Retirement Plan trust includes a separate account that is used to fund benefits for the other postretirement benefit plan. In addition to this
separate account, the assets for the other postretirement benefit plans are held in two Voluntary Employees' Beneficiary Association ("VEBA") trusts, each of
which has its own investment allocation strategies. Target allocations for the other postretirement benefit plan include the separate account of the Retirement
Plan trust and the two VEBA trusts.
(2)For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds have been allocated based on the underlying
investments in debt and equity securities.
IFERC FORM NO. 1 (ED. 12-88) Page 123.26 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Fair Value Measurements
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit pension plan (in
millions):
Input Levels for Fair Value Measurements
Level 1(1) Level 2(1) Level 3(1) Total
As of December 31, 2011
Cash equivalents $ - $ 9 $ - $ 9
Debt securities:
United States government obligations 21 - - 21
International government obligations - 73 - 73
Corporate obligations - 63 - 63
Municipal obligations - 7 - 7
Agency, asset and mortgage-backed obligations - 45
Equity securities:
United States companies 366 - - 366
International companies 7 - - 7
Investment funds(2) 104 165 - 269
Limited partnership interests(3) - - 71 71
Total $ 498 $ 362 $ 71 $ 931
As of December 31, 2010
Cash equivalents $ - $ 8 $ - $ 8
Debt securities:
United States government obligations 20 - - 20
International government obligations - 81 - 81
Corporate obligations - 52 - 52
Municipal obligations - 4 - 4
Agency, asset and mortgage-backed obligations - 49 - 49
Equity securities:
United States companies 366 - - 366
International equity companies 7 - - 7
Investment funds(2) 109 180 - 289
Limited partnership interests(3) - - 84 84
Total $ 502 $ 374 $ 84 $ 960
(1)Refer to Note 6 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately
59% and 41%, respectively, for 2011 and 60% and 40%, respectively, for 2010. Additionally, these funds are invested in United States and international
securities of approximately 49% and 51%, respectively, for 2011 and 47% and 53%, respectively, for 2010.
(3)Limited partnership interests include several funds that invest primarily in buyout, growth equity and venture capital.
L IFERC FORM NO. 1 (ED. 12-88) Page 123.27 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 06/28/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit other postretirement plan
(in millions):
Input Levels for Fair Value Measurements
Level 10) Level 2(1) Level 3(1) Total
December 31, 2011
Cash and cash equivalents $ 3 $ - $ - $ 3
Debt securities:
United States government obligations 2 - - 2
International government obligations - 5 - 5
Corporate obligations - 5 - 5
Municipal obligations - 1 -
Agency, asset and mortgage-backed obligations - 3 - 3
Equity securities:
United States companies 131 - - 131
International companies 2 - - 2
Investment funds(2) 132 94 - 226
Limited partnership interests(3) - - 6 6
Total $ 270 $ 108 $ 6 $ 384
December 31, 2010
Cash and cash equivalents $ 2 5 1 $ - $ 3
Debt securities:
United States government obligations 2 - - 2
International government obligations - 7 - 7
Corporate obligations - 4 - 4
Agency, asset and mortgage-backed obligations - 4 - 4
Equity securities:
United States companies 134 - - 134
International companies - 3 - - 3
Investment funds(2) 118 107 - 225
Limited partnership interests(3) - - 7 7
Total $ 259 $ 123 5 7 $ 389
(1)Refer to Note 6 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately
48% and 52%, respectively, for 2011, and 47% and 53%, respectively, for 2010. Additionally, these funds are invested in United States and international
securities of approximately 69% and 31%, respectively, for both 2011 and 2010.
(3)Limited partnership interests include several funds that invest primarily in buyout, growth equity and venture capital.
IFERC FORM NO. I (ED. 12-88) Page 123.28 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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 market inputs and quoted market prices of securities with similar
characteristics. When observable market data is not available, the fair value is determined using unobservable inputs, such as
estimated future cash flows, purchase multiples paid in other comparable third-party transactions or other information. Investments in
limited partnership interests are valued at estimated fair value based on the Plan's proportionate share of the partnerships' fair value as
recorded in the partnerships' most recently available financial statements adjusted for recent activity and forecasted returns. The fair
values recorded in the partnerships' financial statements are generally determined based on closing public market prices for publicly
traded securities and as determined by the general partners for other investments based on factors including estimated future, cash
flows, purchase multiples paid in other comparable third-party transactions, comparable public company trading multiples and other
information.
The following table reconciles the beginning and ending balances of PacifiCorp's plan assets measured at fair value using significant
Level 3 inputs for the years ended December 31 (in millions):
Private Equity Funds
Pension Other Postretirement
Balance, December 31, 2009
Actual return on plan assets still held at December 31, 2010
Purchases, sales, distributions and settlements
Balance, December 31, 2010
Actual return on plan assets still held at December 31, 2011
Purchases, sales, distributions and settlements
Balance, December 31, 2011
Multiemployer Plans
$ 80
10
(6) (1)
84 7
(20) (2)
S 71 $ 6
PacifiCorp and one of its subsidiaries contribute to the following two multiemployer pension plans under the terms of collective
bargaining agreements: (a) the United Mine Workers of America 1974 Pension Plan ("UMWA Pension Plan") (plan number 002);
and (b) the PacifiCorp/IBEW Local Union 57 Retirement Trust Fund ("Local 57 Trust Fund") (plan number 001). The risk of
participating in multiemployer pension plans generally differs from single-employer plans in that assets are pooled such that
contributions by one employer may be used to provide benefits to employees of other participating employers and plan assets cannot
revert back to employers. If participating employers withdraw from the plan, the unfunded obligations of the plan may be borne by
the remaining participating employers, including any employers that may have recently withdrawn. If an employer ceases
participation in the plan, the employer may be obligated to pay a withdrawal liability based on the participants' unfunded, vested
benefits in the plan.
IFERC FORM NO. I (ED. 12-88) Page 123.29 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table presents PacifiCorp's and its subsidiary's participation in individually significant multiemployer pension plans for
the years ended December 31 (dollars in millions):
PPA zone status or plan funded status
percentage for plan years beginning
July 1,(1)
Funding
improvement
2011 1 2010 plan
PacifiCorp's contributions(2)
Surcharge Year contributions to plan
imposed exceeded more than 5% of
under PPA 2011 2010 total contributions(5)
Employer
Identification
Plan name Number
UMWA
Pension Plan 52-1050282 Yellow Green (3) Pending None $ 3 $ 3 None
Local 57 At least At least
Trust Fund 87-0640888 80%(6) 80% None None $ 12 $ 9 2010,2009
(1)Among other factors, multiemployer plans in the red zone are generally less than 65 percent funded, multiemployer plans in the yellow zone are at least 65 percent
but less than 80 percent funded and multiemployer plans in the green zone are at least 80 percent funded.
(2)PacifiCorp's minimum contributions to the multiemployer pension plans are based on the number of mining hours worked for the UMWA Pension Plan or the
amount of wages paid to employees covered by the Local 57 Trust Fund collective bargaining agreement, subject to ERISA minimum funding requirements.
(3)The UMWA Pension Plan elected to extend recognition of investment losses incurred during the plan year ended June 30, 2009 pursuant to the Preservation of
Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010. Had the election not been made, the PPA zone status would have been yellow for the
plan year beginning July 1, 2010.
(4)The UMWA Pension Plan elected to retain the green PPA zone status from the plan year beginning July 1, 2008 for the plan year beginning July 1, 2009 pursuant
to Section 204 of the Worker, Retiree and Employer Recovery Act of 2008. Had the election not been made, the PPA zone status would have been yellow for the
plan year beginning July 1, 2009.
(5)For the UMWA Pension Plan, information is for plan year beginning July 1, 2009. Information for the plan years beginning July 1, 2010 and 2011 is not available.
For the Local 57 Trust Fund, information is for plan years beginning July 1, 2010 and 2009. Information for the plan year beginning July 1, 2011 is not yet
available.
(6)The preliminary plan funded status for the plan year beginning July 1, 2011 was at least 80%. PacifiCorp expects the final plan funded status, which is determined
after the plan year end, will be at least 80%.
The current collective bargaining agreements governing the UMWA Pension Plan and the Local 57 Trust Fund expire in January
2013.
Defmed Contribution Plan
PacifiCorp sponsors a defined contribution plan (401(k) plan) covering substantially all employees. PacifiCorp's contributions are
based primarily on each participant's level of contribution and cannot exceed the maximum allowable for tax purposes. PacifiCorp's
contributions to the 401(k) plan were $38 million and $39 million for the years ended December 31, 2011 and 2010, respectively.
IFERC FORM NO. I (ED. 12-88) Page 123.30
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)- An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(12) Income Taxes
Income tax expense consists of the following for the years ended December 31 (in millions):
2011 2010
Current:
Federal $ (140) $ (495)
State (8) (1)
Total (148) (496)
Deferred:
Federal 320 675
State 37 29
Total 357 704
Investment tax credits (4) (4)
Total income tax expense $ 205 $ 204
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax
expense is as follows for the years ended December 31:
2011 2010
Federal statutory income tax rate 35 % 35 °'I°
State income taxes, net of federal benefit 3 3
Tax credits(l) (10) (8)
Effects of ratemaking - (2)
Other (1) (1)
Effective income tax rate 27% 27%
(1) Primarily attributable to the impact of federal renewable electricity production tax credits related to qualif'ing wind-powered generating facilities that extend
10 years from the date the facilities were placed in service.
(FERC FORM NO. 1 (ED. 12-88) Page 123.31 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The net deferred income tax liability consists of the following as of December 31 (in millions):
2011 2010
Deferred tax assets:
Employee benefits $ 210 $ 187
Derivative contracts 100 185
Unamortized contract values 72 -
Regulatory liabilities 43 26
Other 215 191
640 589
Deferred tax liabilities:
Property, plant and equipment (3,670) (3,342)
Regulatory assets (715) (650)
Other (32) (30)
(4,417) (4,022)
Net deferred tax liability $ (3,777) $ (3,433)
The sale of PacifiCorp to MEHC on March 21, 2006 triggered certain tax related events that remain unsettled. PacifiCorp does not
believe that the tax, if any, arising from the ultimate settlement of these events will have a material impact on its financial results.
The United States Internal Revenue Service has closed its examination of PaciflCorp's income tax returns through the 2003 tax year.
In most cases, state jurisdictions have closed their examinations of PaciflCorp's income tax returns through 1993.
As of December 31, 2011 and 2010, net unrecognized tax benefits totaled $64 million and $70 million, respectively, which included
$8 million and $9 million, respectively, of tax positions that if recognized, would have an impact on the effective tax rate. The
remaining unrecognized tax benefits relate to positions for which ultimate deductibility is highly certain but for which there is
uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would
not affect PacifiCorp's effective tax rate.
(13) Commitments and Contingencies
Legal Matters
PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or
exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its financial
results.
IFERC FORM NO. 1 (ED. 12-88) Page 123.32 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PaciliCorp X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
USA Power
On May 21, 2012, the jury reached a verdict in the case of USA Power, LLC et al. vs. PacifiCorp et al. filed in the Third District
Court of Salt Lake County, Utah ("Third District Court") in favor of USA Power, LLC, USA Power Partners, LLC and Spring
Canyon Energy, LLC (collectively, the "Plaintiff') regarding the Plaintiffs claims that PacifiCorp breached a confidentiality
agreement and willfully misappropriated the Plaintiffs trade secrets in regard to the Plaintiffs 2002 and 2003 proposals to build a
natural gas-fueled generating facility in Juab County, Utah. The jury awarded the Plaintiff breach of contract damages of $18 million
and unjust enrichment damages of $113 million against PacifiCorp. On May 24, 2012, the Plaintiff filed a motion seeking exemplary
damages. Under the Utah Uniform Trade Secrets law, the judge may award exemplary damages in an additional amount not to exceed
twice the original award. The Plaintiff also filed a motion to seek recovery of attorneys' fees in an amount equal to 40% of the
amounts awarded in the case. The trial judge stayed briefing on the Plaintiff's motions, pending resolution of PacifiCorp's post-trial
motions. The judge set a schedule for PacifiCorp to file its post-trial motions for a new trial and a judgment notwithstanding the
verdict in the fall of 2012. If the judge grants either of PacifiCorp's motions, then the Plaintiffs motions for exemplary damages and
attorneys' fees will be moot. If the judge does not grant either of PacifiCorp's motions, then the judge will set a schedule for
PacifiCorp to respond to the Plaintiff's motions for exemplary damages and attorneys' fees. In the event the judge does not grant
either of PacifiCorp's motions, PacifiCorp expects a decision on the Plaintiffs motions for exemplary damages and attorneys' fees in
2013, and PacifiCorp expects to appeal the final judgment. The suit was originally filed in 2005, prior to MEHC's ownership of
PacifiCorp. In October 2007, the Third District Court granted PacifiCorp's motion for summary judgment on all counts and dismissed
the Plaintiffs claims in their entirety. In February 2008, the Plaintiff filed a petition requesting consideration by the Utah Supreme
Court on two of its five claims. In May 2010, the Utah Supreme Court reversed and remanded the case back to the Third District
Court for further consideration. PacifiCorp strongly disagrees with the verdict and is aggressively pursuing all options for appeal.
PacifiCorp is currently assessing the range of possible loss.
FERC Investigation
During 2007, the Western Electricity Coordinating Council ("WECC") audited PacifiCorp's compliance with several of the reliability
standards developed by the North American Electric Reliability Corporation ("NERC"). In April 2008, PacifiCorp received notice of a
preliminary non-public investigation from the FERC and the NERC to determine whether an outage that occurred in PacifiCorp's
transmission system in February 2008 involved any violations of reliability standards. 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 certain aspects of the WECC's
2007 audit. In July 2009, PacifiCorp reached a settlement with the WECC for the aspects of the audit that were not assumed by the
FERC. The settlement with the WECC did not have a material impact on PacifiCorp's financial results. In December 2011, the FERC
approved a settlement among PacifiCorp, the FERC and the NERC resolving the WECC audit items that were under the FERC's
control, as well as the inquiry into the February 2008 outage. The results of the settlement did not have a material impact on
PacifiCorp's financial results.
Northwest Refund Case
In October 2011, the FERC issued an order on remand by the United States Court of Appeals for the Ninth Circuit, in which it
determined that additional procedures are needed to address possible unlawful activity that may have influenced prices in the Pacific
Northwest wholesale spot market during the period from December 2000 through June 2001. PacifiCorp was a participant in the
Pacific Northwest wholesale spot market during this period. The FERC ordered an evidentiary, trial-type hearing before an
administrative law judge to permit parties to present evidence of alleged unlawful market activity. However, the FERC held the
hearing in abeyance pending settlement discussions with all parties, which are ongoing. PacifiCorp does not believe that the outcome
of this proceeding will have a material impact on its financial results.
IFERC FORM NO. 1 (ED. 12-88) Page 123.33 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards,
emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected
species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp
believes it is in material compliance with all applicable laws and regulations.
Hydroelectric Relicensing
PacifiCorp's hydroelectric portfolio consists of 44 generating facilities with an aggregate facility net owned capacity of
1,145 megawatts ("MW"). The FERC regulates 98% of the net capacity of this portfolio through 15 individual licenses, which have
terms of 30 to 50 years. PacifiCorp expects to incur ongoing operating and maintenance expense and capital expenditures associated
with the terms of its renewed hydroelectric licenses and settlement agreements, including natural resource enhancements. PacifiCorp's
Klamath hydroelectric system is currently operating under annual licenses. Substantially all of PacifiCorp's remaining hydroelectric
generating facilities are operating under licenses that expire between 2030 and 2058.
Klamath Hydroelectric System - Klamath River, Oregon and California
In February 2010, PacifiCorp, the United States Department of the Interior, the United States Department of Commerce, the State of
California, the State of Oregon and various other governmental and non-governmental settlement parties signed the Klamath
Hydroelectric Settlement Agreement ("KHSA"). Among other things, the KHSA provides that the United States Department of the
Interior conduct scientific and engineering studies to assess whether removal of the Klamath hydroelectric system's four mainstem
dams is in the public interest and will advance restoration of 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.
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 will resume relicensing at
the FERC. In November 2011, bills were introduced in both chambers of the United States Congress that, if passed, would enact the
KHSA and a companion agreement that seeks to resolve other water-related conflicts and restore habitat in the Klamath basin.
PaciflCorp expects that congressional hearings on the legislation may begin in 2012.
In addition, the KHSA limits PacifiCorp's contribution to dam removal costs to no more than $200 million, of which up to
$184 million would be collected from PacifiCorp's Oregon customers with the remainder to be collected from PacifiCorp's California
customers. An additional $250 million for dam 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 funds necessary for dam removal costs, sufficient funds would need to be provided by an entity other than
PacifiCorp in order for the KHSA and dam removal to proceed.
PaciflCorp has begun collection of surcharges from Oregon customers for their share of dam removal costs, as approved by the
OPUC, and is depositing the proceeds in a trust account maintained by the OPUC. PacifiCorp began collection of surcharges from
California customers for their share of dam removal costs as approved by the California Public Utilities Commission ("CPUC") in
January 2012 upon notification from the CPUC that two trust accounts had been established to collect the dam removal surcharge
from California customers. PacifiCorp is authorized to collect the surcharge over the next nine years.
IFERC FORM NO. I (ED. 12-88) Page 123.34 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PaciliCorp (2) X A Resubmission 0612812012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
As of December 31, 2011, PacifiCorp's net utility plant included $124 million of costs associated with the Klamath hydroelectric
system's four mainstem dams and the associated relicensing and settlement costs. PacifiCorp has received approvals from the OPUC,
the CPUC and the Wyoming Public Service Commission to depreciate the Klamath hydroelectric system's four mainstem dams and
the associated relicensing and settlement costs through the expected dam removal date. The depreciation rate changes were effective
January 1, 2011 and will allow for full depreciation of the assets by December 2019 for those jurisdictions. PacifiCorp filed for
consistent ratemaking treatment in the last Idaho general rate case, which was settled in January 2012. PacifiCorp expects to seek
similar approval in Washington. As part of the July 2011 Utah general rate case settlement that was approved by the Utah Public
Service Commission ("UPSC") in August 2011, PacifiCorp and the other parties to the settlement agreed to defer a decision regarding
the acceleration of the depreciation rates for the Klamath hydroelectric system's four mainstem dams to a future rate proceeding, at
which time Utah's $34 million share of associated relicensing and settlement costs would be addressed. In the 2012 Utah general rate
case, PacifiCorp requested approval for Utah's share of accelerated depreciation of the Klamath hydroelectric system's four mainstem
dams and associated relicensing and settlement costs.
Hydroelectric Commitments
As described above, certain of PacifiCorp's hydroelectric licenses contain requirements for PaciflCorp to make certain capital and
operating expenditures related to its hydroelectric facilities. PacifiCorp estimates it is obligated to make capital expenditures of
approximately $205 million over the next 10 years related to these licenses.
Commitments
PacifiCorp has the following firm commitments that are not reflected on the Comparative Balance Sheet. Minimum payments as of
December 31, 2011 are as follows (in millions):
2017 and
2012 2013 2014 2015 2016 Thereafter Total
Purchased electricity contracts $ 245 $ 139 $ 97 $ 99 $ 79 $ 447 $ 1,106
Fuel contracts 677 633 599 503 399 2,390 5,201
Construction commitments 550 247 24 7 8 52 888
Transmission 108 98 84 62 54 702 1,108
Operating leases and easements 11 12 4 3 2 44 76
Maintenance, service and
other contracts 32 22 17 7 4 49 131
Total commitments $ 1,623 $ 1,151 $ 825 $ 681 $ 546 $ 3,684 $ 8,510
Purchased Electricity
As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity 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 electricity payments are any power purchase agreements that meet the definition of an operating lease.
Included in the minimum fixed annual payments for purchased electricity above are commitments to purchase electricity from several
hydroelectric systems under long-term arrangements with public utility districts. These purchases are made on a "cost-of-service"
basis for a stated percentage of system output and for a like percentage of system operating expenses and debt service. These costs are
included in operation expenses on the Statement of Income. PacifiCorp is required to pay its portion of operating costs and its portion
of the debt service, whether or not any electricity is produced. These arrangements accounted for less than 5% of PacifiCorp's 2011
and 2010 energy sources.
IFERC FORM NO. I (ED. 12-88) Page 123.35 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Fuel
PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments.
Construction Commitments
PacifiCorp's construction commitments included in the table above relate to firm commitments and include the following major
construction commitments.
• As part of the March 2006 acquisition of PacifiCorp, MIEHC and PacifiCorp made a commitment to the state regulatory
commissions in all six states in which PacifiCorp has retail customers to invest in certain transmission and distribution
system projects that would enhance reliability, facilitate the receipt of renewable resources and enable further system
optimization. As of December 31, 2011, PacifiCorp had two remaining capital projects to complete associated with this
conmiitment: (a) the 100-mile high-voltage transmission line being built between the Mona substation in central Utah and the
Oquirrh substation in the Salt Lake Valley that is expected to be placed in service in 2013 and (b) another segment of the
Energy Gateway Transmission Expansion Program that is expected to be placed in service prior to 2021, depending on
siting, permitting and construction schedules.
• PacifiCorp is constructing the 637-MW Lake Side 2 combined-cycle combustion turbine natural gas-fueled generating
facility, which is expected to be placed in service in 2014.
Transmission
PacifiCorp has agreements for the right to transmit electricity over other entities' transmission lines to facilitate delivery to
PacifiCorp's customers.
Operating Leases and Easements
PacifiCorp has non-cancelable operating leases primarily for office equipment, office space, certain operating facilities, land and
equipment under operating leases that expire at various dates through the year ending December 31, 2092. These leases generally
require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property. Certain leases contain renewal
options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. PacifiCorp also has
non-cancelable easements for land on which its wind-powered generating facilities are located. Rent expense totaled $18 million for
2011 and $15 million for 2010.
Maintenance, Service and Other Contracts
PacifiCorp has various non-cancelable maintenance, service and other contracts primarily related to turbine and equipment
maintenance and various other service agreements.
Guarantees
PacifiCorp has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not
expected to have a material impact on PacifiCorp's financial results.
IFERC FORM NO. 1 (ED. 12-88) Page 123.36 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)- An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(14)Preferred Stock
Generally, preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrictions. In the event of
voluntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends.
Upon involuntary liquidation, all preferred stock is entitled to stated value plus accrued dividends. Dividends on all preferred stock
are cumulative. Holders also have the right to elect members to the PacifiCorp Board of Directors in the event dividends payable are
in default in an amount equal to four full quarterly payments.
Dividends declared but not yet due for payment on preferred stock were $1 million as of December 31, 2011 and 2010.
(15)Common Shareholder's Equity
In January 2012, PacifiCorp declared a dividend of $50 million, which was paid to PPW Holdings LLC, a direct wholly owned
subsidiary of MEHC and PacifiCorp's direct parent company, in February 2012.
In March 2011, PacifiCorp declared a dividend of $275 million, which was paid to PPW Holdings LLC in April 2011.
In January 2011, PacifiCorp declared a dividend of $275 million, which was paid to PPW Holdings LLC in February 2011.
Through PPW Holdings LLC, MEHC is the sole shareholder of PacifiCorp's common stock. The state regulatory orders that
authorized MEHC's acquisition of PacifiCorp contain restrictions on PacifiCorp's ability to pay dividends to the extent that they would
reduce PacifiCorp's common stock equity below specified percentages of defmed capitalization.
As of December 31, 2011, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to
PPW Holdings LLC or MEHC without prior state regulatory approval to the extent that it would reduce PacifiCorp's common stock
equity below 45.25% of its total capitalization, excluding short-term debt and current maturities of long-term debt This minimum
level of common equity declines to 44% for the year ending December 31, 2012 and 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, 2011, PacifiCorp's actual common stock equity percentage, as calculated under this measure, was 54.2%,
and PacifiCorp would have been permitted to dividend $2.2 billion under this commitment.
These commitments also restrict PaciflCorp from making any distributions to either PPW Holdings LLC or MEHC if PaciflCorp's
unsecured debt rating is BBB- or lower by Standard & Poor's Rating Services or Fitch Ratings or Baa3 or lower by Moody's Investor
Service, as indicated by two of the three rating services. As of December 31, 2011, 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 financing agreements as further
discussed in Notes 8 and 9.
IFERC FORM NO. I (ED. 12-88) Page 123.37 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(16) Supplemental Cash Flows Information
The summary of supplemental cash flows information for the years ended December 31 is as follows (in millions):
Interest paid, net of amounts capitalized $ 358 $ 331
Income taxes received, net(1 ) $ 425 $ 393
(1) Includes amounts that may have arisen from subsidiaries as PacffiCorp files consolidated income tax returns.
Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to utility plant additions $ 230 $ 216
IFERC FORM NO. I (ED. 12-88) Page 123.38 1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCo (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1.Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2.Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3.For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
4.Report data on a year-to-date basis.
Line Item Unrealized Gains and Minimum Pension Foreign Currency Other
No Losses on Available- Liability adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a) (b) (c) (d) (e)
1 Balance of Account 219 at Beginning of
- Preceding Year ( 5,819,577)
2 Preceding Qtr/Yr to Date Reclassifications
- from Acct 219 to Net Income
3 Preceding Quarter/Year to Date Changes in
Fair Value ( 1,142,322)
4 Total (lines 2 and 3) ( 1,142,322)
5 Balance of Account 219 at End of Preceding
- Quarter/Year ( 6,961,899)
6 Balance of Account 219 at Beginning of
- Current Year ( 6,961,899)
7 Current Qtr/Yr to Date Reclassifications
- from Acct 219 to Net Income
8 Current Quarter/Year to Date Changes in
- Fair Value ( 2,093,533)
9 Total (lines 7 and 8) ( 2,093,533)
10 Balance of Account 219 at End of Current
Quarter/Year ( 9,055,432)
FERC FORMNO. I (NEW 06-02) Page 122a
Name of Respondent
PacifiCorp
This Re rt Is:
(1)An Original
(2)XJA Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Line
No.
-
1
2
Other Cash Flow
Hedges
Interest Rate Swaps
(t
Other Cash Flow
Hedges
[Specify]
(g)
( 7,825,262)
Totals for each
category of items
recorded in
Account 219
(h)
( 5,819,577)
( 7,825,262)
Net Income (Carried
Forward from
Page 117, Line 78)
(i)
Total
Comprehensive
Income
U)
3 7,825,262 6,682,940
4 ( 1,142,322) I 566,414,8361 565,272,514
5 ( 6,961,899)
6 ( 6,961,899)
71 193,628 193,628
8 ( 193,628) ( 2,287,161)
9 ( 2,093,533) 554,806,039! 552,712,506
10 ( 9,055,432)
FERC FORM NO. I (NEW 06-02) Page 122b
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) An Original 1 (2)
(Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 122(a)(b) Line No.: I Column: g
Other Cash Flow Hedges relate to commodity derivatives.
IFERC FORM NO. 1 (ED. 12-87) Page 450.1 I
Name of Respondent
PacifiCo
I This Re ort Is:
(1)An Original
(2)MXA Resubmission
I Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED 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.
Line
No.
Classification
(a)
Total Company for the
Current Year/Quarter Ended
(b)
Electric
(c)
1 Utility Plant
2 In Service
3 Plant in Service (Classified) 22,686,831,1141 22,686,831 ,IT41
4 Property Under Capital Leases 65393,121 65,393,121
5 Plant Purchased or Sold -779,590 -779,590
6 Completed Construction not Classified 83,472,458 83,472,458
7 Experimental Plant Unclassified
8 Total (3 thru 7) 22,834,917,103 22,834,917,103
9 Leased to Others
10 Held for Future Use 20,136,120 20,136,120
11 Construction Work in Progress 1,203,547,965 1,203,547,965
12 Acquisition Adjustments 159,175,508 159,175,508
13 Total Utility Plant (8 thru 12) 24,217,776,696 24,217,776,696
14 Accum Prov for Depr, Amort, & DepI 7,666,665,056 7,666,665,056
15 Net Utility Plant (13 less 14) 16,551,111,640 16,551,1 11,640
16 Detail of Accum Prov for Depr, Amort & Dept
17 In Service:
18 Depreciation 7,062,181,013 7,062,181,013
19 Amort & DepI of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility Plant 497,114,8081 497,114,8081
22 Total In Service (18 thru 21) 7,559,295,821 7,559,295,821
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 107,369,235 107,369,235
33 Total Accum Prov (equals 14) (22,26,30,31,32) 7,666,665,056 7,666,665,056
FERC FORM NO. I (ED. 12-89) Page 200
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp (1)EiAn Original (Mo, Da, Yr) End of 2011/04
(2)A Resubmission 06/28/2012
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Gas Other (Specify) Other (Specify) Other (Specify) Common Line
(d) (e) (f) (g) (h) No.
2
4
5
6
7
8
9
10
11
12
13
14
15
16
17
19
20
I l_
22
23
24
25
26
27
28
29
30
31
32
33
FERC FORM NO. I (ED. 12-89) Page 201
Name of Respondent
PaciflCorp
This Re ort Is:
(1)An Original
(2)ffJA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102,103 and 106)
1.Report below the original cost of electric plant in service according to the prescribed accounts.
2.In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account
103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3.Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4.For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5.Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6.Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of
plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)
Line
No.
Account
(a)
Balance
Beginning of Year
(b)
Additions
(c)
1 1. INTANGIBLE PLANT
2 (301) Organization
3 (302) Franchises and Consents 239,795,535 118,978
4 .(303) Miscellaneous Intangible Plant 607,856,1611 50,822,596
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 847,651,6961 50,941 ,574J
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights I 95,898,8521 304,819
9 (311) Structures and Improvements 921,546,842 20,086,365
10 (312) Boiler Plant Equipment 3,520,898,916 491,282,155
11 (313) Engines and Engine -Driven Generators
12 (314) Turbogenerator Units 896,985,415 90,367,508
13 (315) Accessory Electric Equipment 415,967,5151 8,110,618
14 (316) Misc. Power Plant Equipment 33,234,0201 562,115
15 (317) Asset Retirement Costs for Steam Production 42,346,1571 3,606,532
16 1 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 5,926,877,7171 614,320,112
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 26,123,587 11,493
28 (331) Structures and Improvements 113,026,083 28,700,745
29 (332) Reservoirs, Dams, and Waterways 326,583,937 34,977,839
30 (333) Water Wheels, Turbines, and Generators 112,432,922 9,112,227
31 (334) Accessory Electric Equipment 60,200,807 6,820,614
32 (335) Misc. Power PLant Equipment 2,360,7331 46,389
33 (336) Roads, Railroads, and Bridges 16,323,3151 589,496
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 657,051,3841 80,258,803
36 D. Other Production Plant
37 (340) Land and Land Rights 28,911,312 1,380
38 (341) Structures and Improvements 155,973,793 1,561,430
39 (342) Fuel Holders, Products, and Accessories 10,811,674
40 (343) Prime Movers 2,513,737,706 20,819,891
41 (344) Generators 346,954,523 2,579,773
42 (345) Accessory Electric Equipment 234,749,420 2,321,798
43 (346) Misc. Power Plant Equipment 12,181,682 110,841
44 (347) Asset Retirement Costs for Other Production 5,109,797
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 3,308,429,907 27,395,113
46 1 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 9,892,359,008 721,974,028
FERC FORM NO. 1 (REV. 12-05) Page 204
Name of Respondent
PacifiCorp
This Report Is:
(1)An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
ELECTRIC PLANT IN SERVICE (Account 101, 102,103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7.Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8.For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9.For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
Retirements
(d)
Adjustments
(e)
Transfers Balance at
End r'ear
Line
2
51,378 -33,784,715 206,078,420 3
14,415,078 3,120,0211 647,383,7001 4
14,466,456 -30,664,6941
-3,196,0871
853,462,120
93,007,584
5
6
7
8
1,280,750 1,352,126 941,704,583 9
124,477,850 -8,057,173 3,879,646,048 10
11
34,308,816 -358,096 952,686,011 12
1,119,527 5,952,7221 428,911,3281 13
238,599 15,8681 33,573,404 14
-2,922,216 43,030,473 15
161 ,425,542 -2,922,216 -4,290,640 6,372,559,431 16
17
18
19
20
21
22
23
24
1,028 -83,279 26,050,773
25
26
27
611,148 241,325 141,357,005 28
5,233,587 -125,555 356,202,634 29
2,167,793 -127,157 119,250,199 30
583,244 -35,336 66,402,841 31
55,065 2,352,0571 32
67,356 16,845,455 33
34
8,719,221 -130,002 728,460,964
28,912,692
35
36
37
715,094 7,250,184 164,070,313 38
121,339 18,317 10,708,652 39
13,194,416 -24,204,642 2,497,158,539 40
3,221 ,924 6,020,871 352,333,243 41
279,783 12,451,786 249,243,221 42
62,570 166,984 12,396,937 43
5,1 09,797 44
17,595,126 1,703,500 3,319,933,394 45
187,739,889 -2,922,216 -2,717,142 10,420,953,789 46
FERC FORM NO. I (REV. 12-05) Page 205
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)JA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
- ELECTRIC PLANT IN SERVICE (Account 101, 102,103 and 106) (Continued)
No
Line
(a)
Balance
Beginning of Year
(b)
Additions
(c)
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights 181,517,465 6,585,489
49 (352) Structures and Improvements 122,948,592 1889,271
50 (353) Station Equipment 1,549,843,309 120,843,402
51 (354) Towers and Fixtures 863,436,957 121,134,025
52 (355) Poles and Fixtures 686,565,4 -36,751,094
53 (356) Overhead Conductors and Devices 912,469,174 -9,563,095
54 (357) Underground Conduit 3,259,452 166
55 (358) Underground Conductors and Devices 7,475,0
56 (359) Roads and Trails 11,598,7 -12,022
57 (359.1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 4,339,114,2 204,126,142
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights 52,837,393 2,627,987
61 (361) Structures and Improvements 74,675,982 3,939,729
62 (362) Station Equipment 817,421,421 43,613,791
63 (363) Storage Battery Equipment
64 (364) Poles, Towers, and Fixtures 942,088,822 52,031,610
65 (365) Overhead Conductors and Devices 648,849,674 20,286,125
66 (366) Underground Conduit 302,216,890 11,766,173
67 (367) Underground Conductors and Devices 718,645,076 22,802,968
68 (368) Line Transformers 1,097,798,842 46,967,729
69 (369) Services 581,777,749 23,644,523
70 (370) Meters 179,453,205 12,983,820
71 (371) Installations on Customer Premises 8,801,076 83,800
72 (372) Leased Property on Customer Premises
73 (373) Street Lighting and Signal Systems 60,795,839 1,697,847
74 (374) Asset Retirement Costs for Distribution Plant 1,937,045 698,180
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 5,487,299,0141 243,144,282
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 Software
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 16,200,39 3,338,399
87 (390) Structures and Improvements 235,540,153 13,161,250
88 (391) Office Furniture and Equipment 77,219,598 10,829,521
89 (392) Transportation Equipment 98,768,642 8,925,864
90 (393) Stores Equipment 13,766,183 845,084
91 (394) Tools, Shop and Garage Equipment 61,822,342 3,356,837
92 (395) Laboratory Equipment 36,594,299 3,968,841
93 (396) Power Operated Equipment 132,526,576 28,146,900
94 (397) Communication Equipment 259,841,810 32,852,979
95 (398) Miscellaneous Equipment 6,906,051 833,772
96 SUBTOTAL (Enter Total of lines 86 thru 95) 939,186,0491 106,259,447
97 (399) Other Tangible Property
98 (399.1) Asset Retirement Costs for General Plant 39,748
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98) 1,213,647,890 130,551,676
100 TOTAL (Accounts 101 and 106) 21,780,071,841 1,350,737,702
101 (102) Electric Plant Purchased (See lnstr. 8)
102 (Less) (102) Electric Plant Sold (See lnstr. 8) 4,484,80'
103 (103) Experimental Plant Unclassified
104 1 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 21,775,587,040 1,349,958,112
FERC FORM NO. 1 (REV. 12-05) Page 206
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102,103 and 106) (Continued)
Retirements
(d)
22,523
Adjustments
(e)
Transfers
(p
1,467,513
Balance at
End r)Year
189,547,944
Line
_:_.
47
48
199,826 22,694,862 147,332,899 49
21,575,520 -35,984,018 1,613,127,173 50
1,130,245 1,342,202 984,782,939 51
3,223,897 -28,164 646,562,331 52
4,370,716 -1,791,984 896,743,379 53
3,259,618 54
7,475,095 55
11,586,681 56
57
30,522,727
9,436
-12,299,589
245,472
4,500,418,059
55,701,416
_______
58
59
60
144,171 4,644,520 83,116,060 61
5,965,866 -7,416,664 847,652,682 62
63
6,427,662 1,381 987,694,151 64
3,732,883 665,402,916 65
1,751,221 312,231,842 66
2,911,463 738,536,581 67
8,921 ,800 1,135,844,771 68
741,827 604,680,445 69
16,914,183 175,522,842 70
97,819 8,787,057 71
72
1,399,260 61,094,426 73
2,635,225 74
49,017,591 -2.525,291 5,678,900,414 75
76
77
78
79
80
81
82
83
1,354 19,537,440
84
85
86
1,369,001 1,078,952 248,411,354 87
9,298,449 2,133,597 80,884,267 88
3,181 ,266 12,495 104,525,735 89
492,289 5,161 14,124,139 90
2,037,929 -61428 63,134,822 91
2,551,746 17,120 38,028,514 92
9,829,916 140,466 150,984,026 93
2,697,836 8,392,562 298,389,5151 94
452,882 21,914 7,308,855 95
31,912,6681 11,795,839 1,025,328,667
39,748
96
97
98
39,277,565 11,647,189 1,316,569,190 99
321,024,228 -2,922,216 -36,559,527 22,770,303,572 100
101
779,590 102
103
321 024,228 -2,922,216 -32,074,726 22,769,523,982 104
FERC FORM NO. 1 (REV. 12-05) Page 207
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 204 Line No.: 97 Column: b
Balance - Balance
Beginning at End
Account Description of Year Additions Retirements Transfers of Year
(a) (b) (c) (d) (f) (g)
39921 Land Owned in Fee $ 2,634,916 $ - $ - $ - $ 2,634,916
39922 Land Rights 52,550,647 - - - 52,550,647
39930 Structures 40,641,166 380,629 108,636 (637,769) 40,275,390
39941 Surface-plant Equipment 12,131,316 110,971 150,851 644,389 12,735,825
39944 Surface-Electric Power Facilities 3,424,575 - - - 3,424,575
39945 Underground-coal Mine Equipment 72,452,088 4,343,036 3,622,781 - 73,172,343
39946 Longwall Shields 15,511,575 8,970,139 - - 24,481,714
39947 Longwall Equipment 4,461,627 6,034,905 2,631,424 - 7,865,108
39948 Mainline Extension 18,640,302 1,011,392 752,495 - 18,899,199
39949 Section Extension 4,203,530 1,935,527 - - 6,139,057
39951 Vehicles 1,237,982 - - - 1,237,982
39952 Heavy construction Equipment 5,305,731 852,514 (152,962) (152,962) 6,158,245
39960 Miscellaneous General Equipment 2,236,016 147,065 45,082 (6,620) 2,331,379
39961 computers-Mainframe 568,271 26,413 206,590 4,312 392,406
39970 Mine Development and Road Extension 38,151,569 263,308 - - 38,414,877
399915 coal Mine Asset Retirement Obligations 270,782 216,330 - - 487,112
$274,422,093 $24,292,229 $7,364,897 $(148,650) $291,200,775
Schedule Page: 204 Line No.: 97 Column: c
See footnote line 97, column b.
Schedule Page: 204 Line No.: 97 Column: d
See footnote line 97, column b.
Schedule Page: 204 Line No.: 97 Column: f
See footnote line 97, column b.
Schedule Page: 204 Line No.: 97 Column: g
See footnote line 97, column b.
Schedule Page: 204 Line No.: 102 Column: c
Refer to page 108, Important Changes During the Quarter/Year, Item 3, of this Form No. 1.
Schedule Page: 204 Line No.: 102 Column: f
Refer to page 108, Important Changes During the Quarter/Year, Item 3, of this Form No. 1.
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
PacifiCorp
This Re ort Is:
(2) MA Resubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/04
ELECTRIC PLANT FIELD FOR FUTURE USE (Account 105)
1.Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held
for future use.
2.For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line
No. -
1
2
Description and Location
Of Property (a)
Land and Rights:
Date Originally Included
in This Account
(b)
Date Expected to be used
in Utility Service
(c)
Balance at
End of Year (d)
3 North Hom Mountain Coal Properties 1977 953,014
41 Barnes Butte Substation 2007 2023 746,268
5 Wild Horse Wind Plant 2007 6,763,094
6 Twelve Mile Wind Plant 2007 2,160,207
7 Jumbers Point Substation 2008 • 2016 1,173,276
8 Mountain Green Substation 2009 2025 284,996
9 Hoggard Substation 2009 2025 254,397
10 Oquirrh-Terminal 345-kV Transmission Line 2009 2015 396,020
11 Bend Service Center 2010 2021 3,507,838
12 Legacy Substation 2010 2020 562,276
13 Aeolus Substation 2011 2018 1,014,053
14 Anticline Substation 2011 2018 964,505
15 Populus Substation 2011 2021 254,753
2011 2018 253,401
17
18 Miscellaneous, each under $250,000 848,022
19
20
21
22
Other Property:
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Total 20,136,120
FERC FORM NO. I (ED. 12-96) Page 214
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 214 Line No.: 3 Column: c
The North Horn Mountain Coal Properties are needed to access future coal portals and
federal coal reserves when existing East Mountain coal mines are mined out.
Schedule Page: 214 Line No.: 5 Column: c
Land purchased for wind farms with an estimated construction date of 2022, subject to
environmental and economic reviews and the timing of completion of the Energy Gateway
Expansion Program.
Schedule Page: 214 Line No.: 6 Column: c
Land purchased for wind farms with an estimated construction date of 2021, subject to
environmental and economic reviews and the timing of completion of the Energy Gateway
Expansion Program.
ISchedule Page: 214 Line No.: 16 Column: a
In March 2011, Snyderville Substation was transferred from account 101, Electric plant in
service to account 105, Electric plant held for future use.
ISchedule Page: 214 Line No.: 18 Column: c
Various dates and plans.
IFERC FORM NO. 1 (ED. 12-87) Page 450.1 I
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1.Report below descriptions and balances at end of year of projects in process of construction (107)
2.Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3.Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line
No
Description of Project
(a)
Construction work in progress -
Electric (Account 107)
(b)
I Intangible:
2 Klamath River System Relicensing (Utah portion) 34,462,143
3 Mobile Radio Purch-Implement VHF Spectrum 3,153,235
4 Hunter Adobe Wash Regulating Facility 2,919,994
5 SAP license and maintenance enhancements 1,726,242
6 IT-Mobility Upgrade I Click Replacement 1,148,695
7
8 Production:
9 Lake Side 2 Development 187,082,403
10 Naughton UI Flue Gas Desulfurization System 99,062,587
11 Dave Johnston U4 SO2 & PM Emission Control Upgrades 91,410,539
12 North Umpqua River System Relicensing Implementation 62,817,337
13 Lewis River System Relicensing Implementation 55,759,180
14 Hunter Ul S02 & PM Emission Control Upgrades 41,023,226
15 Hunter U3 Turbine Upgrade HPIIPILP 17,109,688
161 Blundell Proofing Well Integration 17,019,286
17 Jim Bridger U2 Turbine Upgrade HP/I P/LP 11,598,127
18 Hunter U2 SO2 & PM Emission Control Upgrades 10,206,741
19 Ashton Dam Seepage Control 7,351,147
20 Naughton U3 Baghouse, FGD Upgrade, SCR System 4,511,391
21 Rogue River System Relicensing Implementation 4,377,509
22 Huntington U2 Steam Inerting for Coal Mills 3,768,239
23 Generation Compliance Initiative Hardware 3,537,516
24 Dave Johnston - Replace Retro Cooling Tower 2,547,145
25 Dave Johnston U4 - Finishing Superheater Replacement 2,157,110
261 Naughton FGD Reagent Loadout Facility 2,104,227
27 Swift I Station Service/Generator Breaker 1,848,236
28 Currant Creek 2 Development 1,824,925
29 Dave Johnston U4 - Platen SSH Replace 1,780,501
30 Dave Johnston - Fire Protection RepI Tripper Deck Booster Pumps 1,430,298
31 Huntington U2 Duct Replacements 1,397,839
32 Hunter U3 Wet Stack Upgrades 1,382,979
33 Merwin Spillway Tainter Gate Rehab 1,016,501
34
35 Transmission:
36 Mona-Oquirrh 345kV/500kV Transmission Line 127,997,118
37 Energy Gateway Preliminary Engineering and Permitting 54,863,681
38 Sigurd-Red Butte-Crystal 345kV Line 28,334,122
39 Aeolus Clover 500kV Line 25,007,520
40 Terminal Substation 345-138kV Trnsf to 700 MVA 19,755,817
41 Southwest WY Silver Creek Build 138kV Line 17,039,715
42 Clover Substation install 345-1 38kV Sub & Lines 11,157,079
43 TOTAL 1,203,547,965
FERC FORM NO. I (ED. 12-87) Page 216
Name of Respondent
PaciflCorp
This Re rt Is:
Resubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
1.Report below descriptions and balances at end of year of projects in process of construction (107)
2.Show items relating to 'research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3.Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line
No
Description of Project
(a)
Construction work in progress -
Electric (Account 107)
(b)
I Line 3 Convert to 11 5k 7,009,435
2 Dave Johnston to Casper 230kV No 1&2 Line Rebuild 6,983,367
3 Line 37 Convert to 11 5k Build Nickel Mt Substation 6,672,433
4 Oquirrh-Terminal 345kV Line 6,032,738
Facebook Data Center Phase 2 Tom McCall Industrial Park - 11 5k Project 5,076,647
6 Wallula-McNary 230kV Line 4,253,558
7 West Point-New 138kV Line & 40 MVA Substation 3,812,628
8,1 TOT 4A-4B Transmission Path Transfer Capacity 3,607,563
9 Vantage-Pomona Heights 230kV Line 2,775,035
10 Cameron-Milford 138kV Transmission 2,756,659
11 Union Gap Pacific 115kV Reconductor 2,449,147
12 Ben Lomond add 2nd 345-139kV Transformer 2,347,658
13 Carbon County System Reinforcement 2,140,114
14 Ashley Substation-Install 3 Stage 29.8 MVAR Cap 2,061,757
15 Three Peaks Substation: Install 345kV Sub 1,773,266
16 Lake Side 2 Interconnect Q0301 1,673,116
17 Powerdale RepI Sub w-69kV Trans Switchyard Station 1516,215
18 Two Elks Intercon at Tri County Switchyard 1,509,017
19 Jordan 2 Instl 138-12.5kv 40 MVATms-Fdr 1,411,261
20 Cove - Cove Tap 69kV 1.9 Miles Trans Line 1,289,271
21 WY-NERC Facility Rating Project-Phase Il 1,257,397
22 UT-NERC Facility Rating Project-Phase II 1,234,159
23
24 Distribution:
25 Nibley 138-12.5kv Substation 13,363,014
26 City Creek Center (SLC) New 40 MW Dev for PRI 8,930,441
27 Farmington Substation add 2nd 138-12.5kV Transfmr 3,756,091
28 Fort Douglas-New 138-12.5kV Substation & Transfmr 1,642,209
29 Deschutes Substation Inc Cap RepI Transformer 1,480,724
30 Smithfield Substation add New Feeder 13 1,370,453
31 Lassen Substation Constr New 115-12.5kV 1,164,562
32
33 General:
34 Mobile Radio Replacement Project 38,033,613
35 Deer Creek Mine-Reconstruct Longwall System 1,203,876
36
37 Miscellaneous Projects each under $1,000,000 101,270,503
38
39
40
41
42
43 TOTAL 1,203,547,965
FERC FORM NO. I (ED. 12-87) Page 216.1
Name of Respondent
PacifiCorp
This Re ort Is: (1)An Original
(2)A Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1.Explain in a footnote any important adjustments during year.
2.Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3.The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4.Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Section A. Balances and Changes During Year
Line
N 0.
Item
(a)
Total (c+d+e)
(b) I Electric Hant in Service (c)
Electric Plant Held for Future Use (d)
Electric FEant Leased to Others
(e)
1 Balance Beginning of Year 6,893,664,705 6,893,664,705 l
2 Depreciation Provisions for Year, Charged to
,83O.198 544,830,198' 3 (403) Depreciation Expense
4
-
(403.1) Depreciation Expense for Asset
Retirement Costs
5 (413) Exp. of Elec. Pit. Leas. to Others
_6 Transportation Expenses-Clearing I 71 Other Clearing Accounts
_8 Other Accounts (Specify, details in footnote): 28,652,845
9
10
-
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
573,483,043 573,483,043
11
12
Net Charges for Plant Retired:
Book Cost of Plant Retired 307,228,919 307,228,919
13 Cost of Removal 78,411,893 78,411,893
14 Salvage (Credit) 9,003,170 9,003,170
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
376,637,642 376,637,642
16 Other Debit or Cr. Items (Describe, details in
footnote):
-28,329,093
17
18 Book Cost or Asset Retirement Costs Retired
19
-
Balance End of Year (Enter Totals of lines 1,
10,15,16, and l8)
7,062,181,013 7,062,181,013
- Section B. Balances at End of Year According to Functional Classification
20 Steam Production 2,465,684,624 2,465,684,624
21 Nuclear Production
22 Hydraulic Production-Conventional 254,117,565 254,117,565
23 Hydraulic Production-Pumped Storage
24 Other Production 480,305,750 480,305,750
25 Transmission 1,224,958,546 1,224,958,546
26 Distribution 2,160,071,159 2,160,071,159
27 Regional Transmission and Market Operation
28 General 477,043,369 477,043,369
29 TOTAL (Enter Total of lines 20 thru 28) 7,062,181,013 7,062,181,013
FERC FORM NO. 1 (REV. 12-05) Page 219
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/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 $ 9,898,481
Account 143 Joint Owner Receivable - depreciation
expense billed to joint owners 181,962
ARO asset depreciation recorded as a regulatory asset or liability 2,892,371
Transportation depreciation allocated to O&M and construction
based on usage activity 14,396,524
Account 503 Blundell depletion 185,368
Account 503 Blundell depreciation 1,098,139
Total other accounts $28,652,845
ISchedule Page: 219 Line No.: 16 Column: b
Represents the reclassification of accrued removal and spend on asset retirement
obligations that were included in lines 3 and 13. $(45,267,623)
Other items including: 16,938,530
- Recovery from third parties for asset relocations and damaged property
- Insurance recoveries
- Adjustments of reserve related to electric plant sold
- Reclassifications from electric plant
Total Other Debit or Cr. Items $(28,329,093)
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
PacifiCorp
This Report Is:
R2'Original
R55ion
Date of Report Year/Period of Report
End of 2011/Q4
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a)Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b)Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
Line Description of Investment
(a)
Date Acquired
(b)
Date Of
maturity
Amountof nvestment at
Beginning of Year
-
2 Common Stock
1973
3 Paid-in Capital In 4 Undistributed Subsidiary Earnings
5 SUBTOTAL 178,668,102
6
7 ENERGY WEST MINING COMPANY 1990
8 Common Stock
9 SUBTOTAL 1,000
10
11 CENTRALIA MINING COMPANY 1990
12 Common Stock
13 SUBTOTAL 1,000
14
15 GLENROCK COAL COMPANY 1991
16 Common Stock
17 SUBTOTAL
18
19 INTERWEST MINING COMPANY 1992
20 Common Stock
21 SUBTOTAL 1,000
22
23 1 TRAPPER MINING INC. 1992 I
24 Members' Equity
25 Undistributed Subsidiary Earnings
26 SUBTOTAL 11,501,358 I
27
28 PACIFICORP ENVIRONMENTAL REMEDIATION COMPANY 1994
29 Paid-in Capital 14,719,625
30 Undistributed Subsidiary Earnings 6,232,713
31 SUBTOTAL 20,952,338
32
33 FOSSIL ROCK FUELS, LLC 2011
34 Paid-in Capital
35 Undistributed Subsidiary Earnings
36 SUBTOTAL
37
38
39
40
41
42 1 ITotal Cost of Account 123.1 $ 89,040,6271 1 TOTAL 211,124,799
FERC FORM NO. I (ED. 12-89) Page 224
Name of Respondent
PaciflCorp
This Report Is:
AResubmlssion
Date of Report
06/28/2012
Year/Period of Report
End of 201 1/Q4
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
4.For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5.If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6.Report column (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 selling price thereof, not including interest adjustment includible
in column (f).
8.Report on Line 42, column (a) the TOTAL cost of Account 123.1
Equity in Subsidiary
Earninsrf Year
Revenues for Year
(f
Amount of Investment at
End Year
Gain or Loss from Investment
Dispsrd of Line
1
47,960,000 3
9,537,656 140,245,757 4
9,537,656 188,205,758 5
6
7
1,000 1
1,000
10
11
1,000
1,000
14
15
1 -
1 -w
18
19
1,000
1,000
22
23
6,038,000 24
422,843 5,886,201 25
422,843 11,924,201 26
-i-
27
28
14,719,625 29
-447,546 5,785,167 30
-447,546 20,504,792 31
32
33
20,320,000 34
-1,484 -1,484 35
-1,484 20,318,516 36
37
38
39
40
41
9,511,469 240,956,268 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)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 224 Line No.: 1 Column: a
Pacific Minerals, Inc. is a wholly owned subsidiary of PacifiCorp that holds a two-thirds
ownership interest in Bridger Coal Company, a coal-mining joint venture with Idaho Energy
Resources Company, a subsidiary of Idaho Power Company.
Schedule Page: 224 Line No.: 2 Column: d
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 224 Line No.: 3 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 224 Line No.: 4 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 224 Line No.: 8 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 224 Line No.: 12 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 224 Line No.: 16 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 224 Line No.: 20 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 224 Line No.: 24 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 224 Line No.: 25 Column: d
Amended in accordance with FERC Order No. AC11-132.
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
PacifiCorp
This Re ort Is:
MA Resubmission
Data of Report
06128/2012
Year/Period of Report
End of 2011/Q4
MATERIALS AND SUPPLIES
1.For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
2.Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
Line
No.
-
Account
(a)
Balance
Beginning of Year
(b)
Balance
End of Year
(c)
Department or
Departments which
Use Material (d)
I Fuel Stock (Account 151) 188,493,087 236,891,214 Electric
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated) 71,053,270 106,787,597 Electric
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated) 93,357,638 65,342,036 Electric
8 Transmission Plant (Estimated) 718,031 507,347 Electric
9 Distribution Plant (Estimated) 16,656,313 17,729,257 Electric
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote) Electric
12 TOTAL Account 154 (Enter Total of lines 5 thru 11) 186,406,158 196,564,767
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15
-
Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163)
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet) 374,899,245 433,455,981
FERC FORM NO. 1 (REV. 12-05) Page 227
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 227 Line No.: 11 Column: b I
Mining materials and supplies $ 4,477,840
General plant materials and supplies 143,066
$ 4,620,906
Schedule Page: 227 Line No.: 11 Column: c I
Mining materials and supplies $ 5,964,328
General plant materials and supplies 234,202
$ 6,198,530
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp 06/28/2012 End of 2011/Q4
Allowances (Accounts 158.1 and 158.2)
1.Report below the particulars (details) called for concerning allowances.
2.Report all acquisitions of allowances at cost.
3.Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General
Instruction No. 21 in the Uniform System of Accounts.
4.Report the allowances transactions by the period they are first eligible for use: the current year's allowances in columns (b)-(c),
allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining
succeeding years in columns (j)-(k).
5.Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
Line S02 Allowances Inventory Current Year 2012
No. (Account 158.1) No. Amt. No. Amt.
- (a) (b) (c) (d) (e)
1 Balance-Beginning of Year 186,325.001 156,647.00
2
3 1 Acquired During Year:
4 Issued (Less Withheld Allow)
5 Returned by EPA
6
7
8 Purchases/Transfers:
9 Adjustments -58.00
10
11
12
13
Total -58.001
17 Relinquished During Year:
18 Charges to Account 509 I 58,004.0 I I
19 Other:
I I I I
21 Cost of Sales/Transfers:
22 See footnote for details
24
25
26
27
28 Total 47,641.00
29 Balance-End of Year I 80,622.001 156,647.00
30
31 Sales:
32 Net Sales Proceeds(Assoc. Co.) I I
33 Net Sales Proceeds (Other)
34 Gains
35 Losses
- Allowances Withheld (Acct 158.2)
36 Balance-Beginning of Year 2,259.00 2,259.00
37 Add: Withheld by EPA
38 Deduct: Returned by EPA
39 Cost of Sales 2,259.00
40 Balance-End of Year I I I 2,259.00
41
42 Sales:
43 Net Sales Proceeds (Assoc. Co.)
44 Net Sales Proceeds (Other)
45 Gains
46 Losses
FERC FORM NO. I (ED. 12-95) Page 228a
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp 2'rs sion 06/28/2012 End of 2011/Q4
Allowances (Accounts 158.1 and 158.2) (Continued)
6.Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA's sales of the withheld allowances. Report on Lines
43-46 the net sales proceeds and gains/losses resulting from the EPA's sale or auction of the withheld allowances.
7.Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated
company" under "Definitions" in the Uniform System of Accounts).
8.Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies.
9.Report the net costs and benefits of hedging transactions on a separate line under 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.
2013 2014 Future Years Totals Line
No. Amt. No. Amt. No. Amt. No. Amt. No.
(f) (g) (h) I (i) (j) 1 (k) (I) (m)
156646.00 156,645.00 4,035,430.00 4,691,693.00 1
2
3
156,644.001 156,644.00 4
5
6
7
I I I 8
-58.00 9
10
11
12
13
14
I -58.00 I 15
16
17
I I I I I I 58,004.001 18
19
I • I 120
21
47,641.00 22
23
24
25
26
27
47,641.001 1 28
156,646.001 1 156,645.001 , 4.192.074.00, , 4,142,634.00 , 29
30
31
I 32
33
34
35
2,259.00 2,259.00 110,921.00 119,957.00 36
4,528.00 4,528.00 37
38
2,269.00 4,528.001 39
2,259.00 2,259.00 113,180.00 119,957.001 I
FERC FORM NO. I (ED. 12-95) Page 229a
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) - An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 228 Line No.: 22 Column: b
The names of purchasers/transferees and the number of allowances disposed of during the
year ended December 31, 2011 are as follows:
Pepco Energy Services, Inc. 1,000
Ohio Valley Electric Corporation 15,515
Constellation Energy Commodities Group, Inc. 20,000
Gulf Power Company 1,126
Duke Energy Commercial Asset Management, Inc. 10,000
47,641
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
PacifiCor p
This Report Is: (1)flAn Original
(2)A Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
UNRECOVERED PLANT AND REGULATORY - STUDY COSTS (182.2)
Line
No.
-
Description of Unrecovered Plant
and Regulatory Study Costs [include
in the description of costs, the date of
Commission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)J
(a)
Total Amount of Charges
(b)
Costs Recognised During Year
(c)
WRITTEN OFF DURING YEAR Balance at
End of Year
(f)
Account Charged
(d)
Amount
(e)
21 lUnrecovered Plant: Trojan Nuclear 135,566 407 135,566
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
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49 TOTAL 135,566 135,566
FERC FORM NO. I (ED. 12-88) Page 230b
Name of Respondent
PacifiCorp
This Report Is:
ARssion
Date of Report (Mo, Da, Yr)
Year/Period of Report
End of 2011/Q4
Transmission Service and Generation Interconnection Study Costs
1.Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2.List each study separately.
3.In column (a) provide the name of the study.
4.In column (b) report the cost incurred to perform the study at the end of period.
5.In column (c) report the account charged with the cost of the study.
6.In column (d) report the amounts received for reimbursement of the study costs at end of period.
7.In column (e) report the account credited with the reimbursement received for performing the study. _________________
Line
-
No. Description
(a)
°' Costs Incurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
1
2
Transmission Studies
AREF 618363 141 561.6 141 456
3 AREF 642592 14,371 561.6 14,371 456
4 AREF 645170 10,648 561.6 10,648 456
5 AREF 654674 19,859 561.6 19,859 456
6 AREF 676490 8,095 561.6 8,095 456
7 AREF 686257 11,678 561.6 11,678 456
81 AREF 688430 7,201 561.6 5,448 456
9 AREF 690566 16,875 561.6 16,875 456
10 AREF 690831 19,418 561.6 19,418 456
11 AREF 709133 11,517 561.6 11,517 456
12 AREF 709137 10,111 561.6 10,111 456
13 1 AREF 719404 6,557 561.6 6,557 456
14 AREF 719406 6,646 561.6 6,646 456
15 AREF 723544 6,438 561.6 6,438 456
16 AREF 723846 10,454 561.6 10,454 456
17 AREF 739339 4,643 561.6 4,643 456
18 Legacy Study #1 4,419 561.6 4,419 456
19 Legacy Study #2 2,653 561.6 2,653 456
20 AREF 637974 122 561.6
21 Generation Studies
29 561.7 29 456 22 GIQ0170
231 G100187 39 561.7 39 456
24 G100187-189 1,006 561.7 1,006 456
25 G1Q0188 14 561.7 14 456
26 G1Q0189 14 561.7 14 456
27 GIQ0190 227 561.7 227 456
281 G1Q0193 14 561.7 14 456
29 GIQ0230 76 561.7 76 456
30 G100255 21,146 561.7 21,146 456
31 G1Q0256 120 561.7 120 456
32 G1Q0260-263 38,173 561.7 38,173 456
331 G1Q0276 10,281 561.7 10,281 456
34 G1Q0289 ( 74) 561.7 ( 74) 456
35 G1Q0290 1,297 561.7 1,297 456
36 GIQ0291 1,631 561.7 1,631 456
37 G1Q0292 13,239 561.7 13,239 456
38 G1Q0295 941 561.7 941 456
39 G1Q0299 5,131 561.7 5,131 456
40 GIQ0303 208 561.7 208 456
FERC FORM NO. 1I1-F13-Q (NEW. 03-07) Page 231
Name of Respondent
act orp
This Report Is:
(1) An Original
(2)] A Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
Transmission Service and Generation Interconnection Study Costs (continued)
Line
No. Description
(a)
Costs Incurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During the Period
(d)
Account Credited
With Reimbursement
(e)
1
2
Transmission Studies
AREF 637977 243 561.6
3 AREF 648013 1,962 561.6
4 AREF 675661 3,990 561.6
5 AREF 675662 3,990 561.6
6 AREF675663 4,066 561.6
7 AREF 675664 3,762 561.6
8 AREF 675665 3,458 561.6
9 AREF 680400 1,093 561.6
10 AREF 683060 2,739 561.6
11 AREF 704328 6,105 561.6
12 AREF 659527 3,728 561.6
13 AREF 673963 3,636 107
14 AREF 659527 2,283 107
15 AREF 681628 4,595 107
16 AREF 684287 3,332 107
17 AREF 686836 3,743 107
18 AREF 709355 5,935 107
19 AREF 728784 5,687 107
20 AREF 740690 2,104 107
21 Generation Studies
12,354 561.7 12,354 456 22 G1Q0306
23 GIQ0310 4,026 561.7 4,026 456
24 GIQ0311 12,474 561.7 12,474 456
25 G1Q0313 2,930 561.7 2,930 456
26 G1Q0314 3,758 561.7 3,758 456
27 GIQ0315 12,405 561.7 12,405 456
28 GIQ0316 2,438 561.7 2,438 456
29 GIQ0322 17,814 561.7 17,814 456
30 GIQ0323 7,579 561.7 7,579 456
31 G1Q0324 6,044 561.7 6,044 456
32 G1Q0326 16,092 561.7 16,092 456
331 G1Q0332 8,411 561.7 8,411 456
34 G1Q0333 10,557 561.7 10,557 456
35 G1Q0334 80 561.7 80 456
36 G1Q0335 4,351 561.7 4,351 456
37 G1Q0341 5,527 561.7 5,527 456
381 G1Q0345 282 561.7 282 456
39 G1Q0346 185 561.7 185 456
40 G1Q0347 5,678 561.7 5,678 456
FERC FORM NO. 1I1-F13-Q (NEW. 03-07) Page 231.1
Name of Respondent
PacifiCorp
This Re ort Is:
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
Transmission Service and Generation Interconnection Study Costs (continued)
Line
No Description
(a)
Costs Incurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
1
2
Transmission Studies
AREF 741886 3,401 107
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
5,955 561.7 5,955 456 22 G100348
23 1 GQ0349 2,774 561.7 2,774 456
24 G1Q0350 7,413 561.7 7,413 456
25 G1Q0351 31,173 561.7 31,173 456
26 G1Q0352 2,527 561.7 2,527 456
27 G1Q0353 1,701 561.7 1,701 456
281 G1Q0354 6,781 561.7 6,781 456
29 G1Q0355 720 561.7 720 456
30 G1Q0356 12,547 561.7 12,547 456
31 G1Q0357 10,594 561.7 10,594 456
32 G1Q0358 707 561.7 707 456
331 G1Q0359 15,109 561.7 15,109 456
34 G1Q0360 18,538 561.7 18,538 456
35 G1Q0361 1,135 561.7 1,135 456
36 G1Q0362 955 561.7 955 456
37 G1Q0363 4,275 561.7 4,275 456
38 G1Q0364 21,228 561.7 21,228 456
39 G100365 4,427 561.7 4,427 456
40 G1Q0366 14,444 561.7 14,444 456
FERC FORM NO. Ill -F13-Q (NEW. 03-07) Page 231.2
Name of Respondent
PacifiCo
This Report Is:
(1)E An Original
(2) 0 A Resubmission
Date of Report
(Mo, Da,Yr)
06/28/2012
Year/Period of Report
End of 2011/04
Transmission Service and Generation Interconnection Study Costs (continued)
No.
-
Description
(a)
Line Costs Incurred During
Period
(b)
Account Charged
(c)
Received During the Period
(d)
Account Credited
With Reimbursement
(e)
1
2
Transmission Studies
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 1 GIQ0367 43,293 561.7 43,293 456
23 GIQ0368 5,334 561.7 5,334 456
24 GIQ0369 1,013 561.7 1,013 456
25 GIQ0370 3,968 561.7 3,968 456
26 GIQ0371 1,517 561.7 1,517 456
271 GIQ0372 17,719 561.7 17,719 456
28 GIQ0373 13,628 561.7 13,628 456
29 G1Q0374 17,835 561.7 17,835 456
30 G100375 25,874 561.7 25,874 456
31 GIQ0376 17,254 561.7 17,254 456
321 G1Q0377 41,870 561.7 41,870 456
33 GIQ0378 15,879 561.7 15,879 456
34 GIQ0379 2,401 561.7 2,401 456
35 GIQ0380 2,272 561.7 2,272 456
36 G100381 2,132 561.7 2,132 456
371 G100382 2,361 561.7 2,361 456
38 G1Q0383 2,413 561.7 2,413 456
39 G1Q0384 13,302 561.7 13,302 456
40 G100385 11,167 561.7 11,167 456
FERC FORM NO. Ill -F/3-Q (NEW. 03-07) Page 231.3
Name of Respondent
P ifiC ac Ofl)
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
Transmission Service and Generation Interconnection Study Costs (continued)
Line
N 0. Description
(a)
Costs Incurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
1
2
Transmission Studies
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
221 G1Q0386 14,972 561.7 14,972 456
23 G1Q0387 2,562 561.7 2,562 456
24 G1Q0388 622 561.7 622 456
25 G100389 13,920 561.7 13,920 456
26 G1Q0390 648 561.7 648 456
27 G1Q0392 7,235 561.7 7,235 456
28 G100393 10,431 561.7 10,431 456
29 G100394 9,003 561.7 9,003 456
30 G1Q0395 11,893 561.7 11,893 456
31 G100396 4,700 561.7 4,700 456
32 G100397 5,386 561.7 5,386 456
33 G1Q0398 5,740 561.7 5,740 456
34 G1Q0399 1,845 561.7 1,845 456
35 GIQ0400 3,357 561.7 3,357 456
36 GIQ0401 4,957 561.7 4,957 456
37 GIQ0403 1,909 561.7 1,909 456
38 G100404 1,675 561.7 1,675 456
39 GIQ0405 1,814 561.7 1,814 456
40 PRE-QUEUE 587 561.7 587 456
FERC FORM NO. 111 -F13-Q (NEW. 03-07) Page 231.4
Name of Respondent
PacifiCorp
This Report Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
Transmission Service and Generation Interconnection Study Costs (continued)
Line
No.
-
Description
(a)
Costs Incurred During
Period
(b)
Account Charged
(c)
Reimbursements Received During the Period
(d)
Account Credited
With Reimbursement
(e)
1
2
Transmission Studies
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
( 3,453) 561.7 22 1 Customer Studies Accruals
23 G1Q1256 27,385 561.7
24 G1Q1293 5,308 561.7
25 GIQ0301 2,751 107
26 G1Q1256 4,486 107
271 G100402 532 107
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. Ill -F13-Q (NEW. 03-07) Page 231.5
Name of Respondent
PacifiCorp
This Report Is:
(1)LJAn Original
(2)FXJA Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
OTHER REGULATORY ASSETS (Account 182.3)
1.Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2.Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3.For Regulatory Assets being amortized, show period of amortization.
Line
No.
-
Description and Purpose of
Other Regulatory Assets
(a)
Balance at
Beginning of
Current
Quarter/Year
(b)
Debits
(c)
CREDITS Balance at end of
Current Quarter/Year
(f)
Written oft During
the Quarter/Year
Account Charged
(d)
Written oft During
the Period
Amount
(e)
11 DSM Regulatory Asset Actuals - CA ( 3,193,591) 1,555,031 908.431 1,368,577 -3,007,137
2 DSM Regulatory Asset Accruals - CA 82.294 165,865 248,159
3 DSM Regulatory Asset Actuals - ID 5,339,142 2,696,505 908 5,682,031 2,353,610
4 DSM Regulatory Asset Accruals - ID 327,201 53,773 380,980
5 DSM Regulatory Asset Actuals - UT 2,284,513 43,653,932 908,431 54,626,479 -8,688,034
6 DSM Regulatory Asset Accruals - UT 4,116,461 908 311,407 3,865,060
7 DSM Regulatory Asset Actuals - WA 595,391 9,195,525 908 8,883,683 907,233
8 DSM Regulatory Asset Accruals - WA 431,214 93,721 530,995
9 DSM Regulatory Asset Actuals - WY ( 4,000,836) 3,863,183 908,431 156,112 -293,765
10 DSM Regulatory Asset Accruals - WY 362,894 69,264 432,158
11 DSM Regulatory Asset Actuals - OR 26,627 26,627
12 Alternative Rate For Energy (CARE) - CA 253,983 78,451 142 570,066 -237,632
13 2006 Transition Plan - OR (2) 2,969,259 38,081 920 2,094,839 912,507
14 2006 Transition Plan - CA (1) 222,112 920 118,218 44,554
15 448,480,778 282,283 4,592,944 443,887,834
161 Deferral of Interest on Uncertain Tax Positions-UT 1444,909 521,718 1,972,627
17 Deferral of Interest on Uncertain Tax Positions-WY 372,132 159,202 531,334
18 Deferral of Interest on Uncertain Tax Positions-ID 271,404 271,404
191 Tax Revenue Requirement Adjustment - WY 99,955 29,424 70,531
20 3,526,084 27,795 555 3,615,312 -61,433
21 1,909,644 1,242,038 555 1,044,586 2,107,096
22 1,596,942 2,840
23 14,492,513 91,585 555 11,335,035 3,249,063
24 32,442,918 32,442,978
251 DefeiredExcess Net PowerCosts-WAHko(3) 2,670,016 139,856 555 1,993,184 816,688
26 487,229 2,244 555 489,413
27 11,434,111 312,829 555 6,757,650 5,049,290
28 1,035,589 17,176,323 18,211,912
29 Deferred Excess Net Power Costs '- UT 61,181,260 67,787,260
30 Deferred Excess REC5 in Rates - UT 456 16,637 -16,637
31 Deferred Excess REC5 in Rates - WA 681,343 681,343
32 Deferred Excess REC5 in Rates - WY 456 517,165 -517,165
33 Environmental Costs (10) 8,296,641 3,1 24,379 925 1,752,910 9,668,110
341 Environmental Costs - WA (10) ( 650,117) 121,889 925 228,059 -750,287
35 Reg Asset - Environmental Costs 9,370,862 3,184,967 12,555,829
36 Cholla Plant Transaction Costs (26) 6,119,329 183,792 557 1,122,424 5,240,697
37 Washington Colstrip#3 (22) 526,259 456 52,188 474,071
38 189.3238431 242,253 2,374,710 186,949,133
39 481,295,264 224,102,593 263,192,671
401 68,251,011 19,292,273 48,958,738
41 596,639,721 168,804,0001 36,946,065 728,497,656
421 RIO Grid West NIR - OR (3) 738,048 10,823 904 393,344 355,527
43 RTO Grid West N/R - ID (5) 27,162 904 21,162
44 TOTAL 1,737,446,767 572,862,336 435,773,432 1,874,535,671
FERC FORM NO. 113-Q (REV. 02-04) Page 232
Name of Respondent
PacifiCo
This Re art Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
OTHER REGULATORY ASSETS (Account 182.3)
1.Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2.Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3.For Regulatory Assets being amortized, show period of amortization.
Line
No.
-
Description and Purpose of
Other Regulatory Assets
(a)
Balance at
Beginning of
Current
Quarter/Year
(b)
Debits
(c)
CREDITS Balance at end of
Current Quarter/Year
(f)
Written oft During
the Quarter/Year
Account Charged
(d)
Written Ott During
the Period
Amount
(e)
1 I Deferred Independent Evaluator Fee - UT ( 16,501) 92,241 75,740
2 Deferred Independent Evaluator Fee - OR (1) 539,513 22,227 557 753,634 -191,894
3 Deterred Intervenor Funding Grants - CA 32,885 32,885
4 Deterred Intervenor Funding Grants - ID (2) 43,191 39,000 928 24,095 58,702
5 Deferred Intervenor Funding Grants - OR 37,082 308,561 345,643
6 BPA Balancing Account - ID 2,685,242 440,442 1,390,488 1,294,754
7 Renewable Adjustment Clause - OR (1) 629,955 4,564 643,335 -8,816
8 Goodnoe Hills Settlement - WY (24) 488,750 930.2 21,250 467,500
9 Lake Side Settlement - WY (39) 1,005,095 930.2 21,919 977,176
10 SB 408 Regulatory Asset - OR (1) 1,095,545 15,147,236 9,934,873 6,907,908
111 SB 408 Regulatory Asset - MCBIT (1) ( 189,015) 242,168 431,426.5 . 102,547 -49,394
12 Chehalis Generating Facility Deferral - WA (6) 15,000,000 3,000,000 12,000,000
13 Powerdale Decommissioning - ID (10) 304,766 25,772 407.3 111,818 212,720
14 Powerdale Decommissioning - OR (1.5) 493,016 407.3 493,016
15 Powerdale Decommissioning - WA (3) 851,788 407.3 212,947 638,841
161 Powerdale Decommissioning - WY (1) 34,392 407.3 34,392
17 Powerdale Decommissioning - CA (2) 70,081 407.3 37,012 33,069
18 Deterred Advertising Costs - WY (1) 52,198 909 52,198
19 Major Plant Additions Deferral - UT (1) 15,724,521 1,696,342 17,420,863
20 Solar Feed-In Tariff Deferral - OR 226,622 1,043,825 1,270,447
21 1 Solar Feed-In Tariff Deferral - CA 380,507 407.3 626,859 -246,352
22 Tax Adj on Postretirement Benefits - CA (3) 383,431 410.1,283 127,808 255,623
23 Tax Adj on Postretirement Benefits - ID (4) 819,988 410.1,283 204,997 614,991
24 Tax Adj on Postretirement Benefits - OR 4,471,643 4,471,643
25 Tax Adj on Postretirement Benefits - UT (4) 5,891,250 410.1,283 1,571,001 4,320,249
26 Tax Adj on Postretirement Benefits - WA 1,126,592 410.1,283 1,126,592
27 Tax Adj on Postretirement Benefits - WY (4) 2,121,315 201,064 410.1,283 644,916 1,677,403
28 Storm Damage Deferral - CA (1) 1.230,000 924 1,164,006 65,994
29 Deferred Overburden Cost- ID 249,097 963,999 501 1,037,0441 176,052
30 Deferred Overburden Cost - WY 665,891 2,671,531 501 2,849,424 487,998
31 Regulatory Assets - Reclassifications 1,399,943 2,145,261
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 1,737,446,757 572,862,336 435,773,432 1,874,535,671
FERC FORM NO. 113-Q (REV. 02-04) Page 2321
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original 1(2) (Mo, Da, Yr)
PaciflCorp X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Schedule Page: 232 Line No.: 15 Column: a
Weighted average remaining life is 33 years. Amounts primarily represent income tax
benefits related to certain property-related basis differences and other various items
that PacifiCorp is required to pass on to its customers.
Schedule Page: 232 Line No.: 19 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 232 Line No.: 20 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms
amortized over a 12-month period.
and
Schedule Page: 232 Line No.: 21 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms
amortized over a 12-month period.
and
Schedule Page: 232 Line No.: 22 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms
amortized over a 12-month period.
and
Schedule Page: 232 Line No.: 23 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms
amortized over a 12-month period.
and
ISchedule Page: 232 Line No.: 24 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms
amortized over a 12-month period.
and
Schedule Page: 232 Line No.: 26 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms
amortized over a 12-month period.
and
Schedule Page: 232 Line No.: 27 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms
amortized over a 12-month period.
and
Schedule Page: 232 Line No.: 28 Column: a
Net power costs are deferred in accordance with established adjustment mechanisms
amortized over a 12-month period.
and
Schedule Page: 232 Line No.: 38 Column: a
Represents frozen values of contracts previously accounted for as derivatives and
at fair value.
recorded
ISchedule Page: 232 Line No.: 39 Column: a
Weighted average remaining life is 1 year.
Schedule Page: 232 Line No.: 39 Column: d
Account 175, Derivative instrument assets
Account 244, Derivative instrument liabilities
Account 182.3, Other regulatory assets
Schedule Page: 232 Line No.: 40 Column: d
Account 108, Accumulated provision for depreciation of electric utility plant
Account 230, Asset retirement obligations
Account 403, Depreciation expense
ISchedule Page: 232 Line No.: 41 Column: a
Weighted average remaining life is 10 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.: 41 Column: d
Pensions and benefits are associated with labor and generally charged to operations and
maintenance expense and construction work in progress.
ISchedule Page: 232.1 Line No.: 7 Column: d
Account 440, Residential sales
IFERC FORM NO. I (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)X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 232.1 Line No.: 10 Column: d S
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
ISchedule Page: 232.1 Line No.: 12 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 232.1 Line No.: 19 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
ISchedule Page: 232.1 Line No.: 31 Column: f
The following schedule summarizes regulatory assets reclassifications:
As of
Reclassified from Regulatory Assets to Regulatory Liabilities: December 31, 2011
DSM Regulatory Asset Actuals - CA $ 3,007,137
DSM Regulatory Asset Accruals - CA (248,159)
DSM Regulatory Asset Actuals- UT 8,688,034
DSM Regulatory Asset Accruals - tJ'12 (3,865,060)
Alternative Rate For Energy (CARE) - CA 237,632
Deferred Excess REC5 in Rates - UT 16,637
Deferred Excess REC5 in Rates - WY 517,165
Deferred Excess Net Power Costs - OR 61,433
Renewable Adjustment Clause - OR 8,816
Deferred Independent Evaluator Fee - OR 191,894
Solar Feed-In Tariff Deferral - CA 246,352
Reclassified from Regulatory Liabilities to Regulatory Assets:
Property Insurance Reserve - UT 683,323
$ 9,545,204
IFERC FORM NO. I (ED. 12-87) Page 450.2 I
Name of Respondent
PacifiCorp
This Re oil Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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
No
-
Description of Miscellaneous
Deferred Debits
(a)
Balance at
Beginning of Year
(b)
Debits
(C)
CREDITS Balance at
End of Year
(f)
Account Charged
(d)
Amount
(e)
1 Joseph Settlement(21) 973,114 557 137,381 835,733
2
31 Lacomb Irrigation (24) 506,730 557 45,720 461,010
4
5 Bogus Creek (41) 1,200,560 557 41,280 1,159,280
6
7 Mead Phoenix Availability and
8 Transmission Charge (50) 13,756,760 565 377,760 13,379,000
9
10 TGS Buyout (23) 140,551 557 1 15,473 125,078
11
12 Point to Point Transmission 4,476,900 748,663 142 2,183,579 3,041,984
13
14 Jim Boyd Hydro Buyout (11) 255,485 557 82,860 172,625
15
16 Hermiston Swap (40) 4,392,484 557 171,693 4,220,791
17
18 LGIA LT Transmission Prepaid 3,086,717 108,389 565,419 1,248,826 1,946,280
19
20 Deferred Longwall Costs 1,105,396 2,992,997 151 3,179,255 919,138
21
22 Deferred Coal Costs - Arch
23 Settlement (3) 63,030 2,934 151 65,964
24
25 Deferred Coal Costs - Wyodak
261 Settlement (22) 4,022,182 151 335,182 3,687,000
27
28 Deferred Coal Costs - Naughton _
29 Settlement (7) 8,256,923 151 1,376,154 6,880,769
30
31 Deferred Colstrip Plant
321 Costs (5) 1,500,000 501 275,000 1,225,000
33
34 LT Lease Commissions
35 Prepaids(10) 649,659 931 92,820 556,839
36
37 RTO Grid West N/R write-off -
381 WA (5) 23,470 904 23,470
39
40 Lake Side Maintenance Prepaids 14,720,749 4,822,317 107 8,415,366 11,127,700
41
42 Chehalis Maintenance Prepaids 5,777,606 1,651,887 7,429,493
43
441 Currant Creek Maint. Prepaids 5,465,610 6,019,326 11,484,936
45
46 Lease Incentives (10) 1,115,229 454 155,120 960,109
47 Misc. Work in Progress
Expenses (See pages 3So-351)
-
-
Deferred Regulatory Comm.
49 TOTAL 86,478,095 88,864,233
FERC FORM NO. I (ED. 12-94) Page 233
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
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) maybe grouped by
classes.
Line
No
Description of Miscellaneous
Deferred Debits
(a)
Balance at
Beginning of Year
(b)
Debits
(c)
CREDITS Balance at
End of Year
(f
Account Charged
(d)
Amount
(e)
2 Credit Agreement Costs (5) 1,051,143 427,431 456,630 594,513
3
4 PCRB LOC/SBBPA Costs (5) 413,129 22,772 427 296,309 139,592
5
6 PCRB Mode Conversion Costs (11) 413,486 427 144,442 269,044
7
8 '94 Series Restruct. Costs (14) 988,431 427 116,981 871,450
9
10 Deferred Financing Costs (13) 1,000 432,936 181 1 433,936
11
12 Deferred S-3 Shelf Regis. Costs 784 25,836 186 26,620
13
14 LT Prepaid IBEW 57 Pension
151 Contribution 5,651,545 5,651,545
16
17 BPA LT Transmission Prepaid 9,133,961 313,382 565 863,304 8,584,039
18
19 Emission Reduction Credits 2,956,980 2,040,000 549 2,365,584 2,631,396
20
211 Unamortized contract values 478,212 478,212
22
23 Sales of Electric Utility
24 Facilities & Properties 271 1,650 1,677
26
27
Other Current Deferred Charges
25
________________
30,000
28 ________________
29 _______________
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Misc. Work in Progress
-
Deferred Regulatory Comm.
Expenses (See pages 350-351)
49 TOTAL 86,478,095 88,864,233
FERC FORM NO. I (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)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 233.1 Line No.: 26 Column: b
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 233.1 Line No.: 26 Column: c
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 233.1 Line No.: 26 Column: d
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 233.1 Line No.: 26 Column: e
Amended in accordance with FERC Order No. AC11-132.
JFERC FORM NO. 1 (ED. 12-87) Page 450.1 I
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)RXA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
1.Report the information called for below concerning the respondent's accounting for deferred income taxes.
2.At Other (Specify), include deferrals relating to other income and deductions.
No
Line and Location
(a)
Balance of Begining of Year
(b)
Balance at End
of Year
(c)
I Electric
2 Employee Benefits 187,114,591 209,587,367
3 Derivative Contracts 184,509,824 99,884,250
4 Regulatory Liabilities 25,903,274 43,186,293
5
6
7 Other 191,062,227 286,987,845
8 TOTAL Electric (Enter Total of lines 2 thru 7) 588,589,916 639,645,755
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) 588,589,916 639,645,755
Notes
FERC FORM NO. I (ED. 12-88) Page 234
Name of Respondent
PacifiCorp
This Re ort Is: (1)An Original
(2)K1A Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
CAPITAL STOCKS (Account 201 and 204)
1.Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series
of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2.Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line
No.
-
Class and Series of Stock and
Name of Stock Series
(a)
Number of shares
Authorized by Charter
(b)
Par or Stated
Value per share
(c)
Call Price at
End of Year
(d)
1 Common Stock (Account 201) 750,000,000
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):
1215% Cumulative Preferred 126,533 100.00 110.00
13
14 Serial Preferred, Cumulative: 3,500,000
15 4.52% Series 100.001 103.50
16 7.00% Series 100.00
17,6.00% Series 100.00
100.00 l 18 5.00% Series 100.00
19 5.40% Series 100.00 101.00
20 4.72% Series 100.00 103.50
21 4.56% Series 100.00 102.34
22 No Par Serial Preferred 16,000,000
231 TOTAL PREFERRED STOCK 19,626533
24
25
26
27
28
29
30
31
32
3
34
35
36
37
38
39
40
41
42
FERC FORM NO. I (ED. 12-91) Page 250
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)JA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
CAPITAL STOCKS (Account 201 and 204) (Continued)
3.Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4.The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5.State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET (Total amount outstanding without reduction
for amounts held by respondent)
HELD BY RESPONDENT Line
No. AS REACQUIRED STOCK (Account 217) IN SINKING AND OTHER FUNDS
Shares (e) Amount (f) Shares (g) Cost (h) Shares (i) Amount a) -
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
2,065 206,500 15
18,046 1,804,600 16
5,930 593,000 17
41,908 4,190,800 18
65,959 6,595,900 19
65,854 6,585,400 20
81,326 8,132,600 21
22
407,331 40,733,100 23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-88) Page 251
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 20111Q4
FOOTNOTE DATA
Schedule Page: 250 Line No.: I Column: d
This class of stock is not redeemable.
Schedule Page: 250 Line No.: 16 Column: d
This series of preferred stock is not redeemable.
Schedule Page: 250 Line No.: 17 Column: d
This series of preferred stock is not redeemable.
Schedule Page: 250 Line No.: 33 Column: a
Authorizations for the issuance of common stock 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, 2011, PacifiCorp had regulatory approval from the aforementioned
commissions for the issuance of 30,000,000 shares of common stock out of the 750,000,000
authorized (357,060,915 outstanding) by PacifiCorp's articles of incorporation.
IFERC FORM NO. 1 (ED. 12-87) Page 450.1 I
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(MO, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such
change.
(a)Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b)Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c)Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end of
year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d)Miscellaneous Paid-in Capital (Account 211)-Classify amounts included in this account according to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
Llipe len ArjJnt
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 ScottishPower stock
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 1(2) (Mo, Da, Yr)
PaciflCorp X Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 253 Line No.: 3 Column: b
Represents the fair value of stock options granted by Scottish Power plc for which certain
performance 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 attributable to the exercise of stock options granted
by Scottish Power plc.
ISchedule Page: 253 Line No.: 5 Column: b
Represents the effect of transferring certain benefit plan obligations and assets to PPM
Energy, Inc. as a result of the sale of PacifiCorp by Scottish Power plc.
Schedule Page: 253 Line No.: 6 Column: b
Represents capital contributions to PacifiCorp (with no shares of stock issued) from its
indirect parent MidAmerican Energy Holdings Company ("MEHC"). No capital contributions
were made by MEl-IC to PacifiCorp during the year ended December 31, 2011.
Schedule Page: 253 Line No.: 7 Column: b
Represents a realized gain on stock related to separation of PPM Energy, Inc. participants
from the deferred compensation plan, which invested in Scottish Power plc stock.
Schedule Page: 253 Line No.: 8 Column: b
Represents amounts associated with IRC Section 199 qualified production activities.
j,Schedule Page: 253 Line No.: 9 Column: b
Represents contribution of Intermountain Geothermal Company to PacifiCorp from MEl-IC 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
Represents gain on PacifiCorp's repurchase of certain shares of its preferred stock in May
2010.
IFERC FORM NO. 1 (ED. 12-87) Page 450.1 I
Name of Respondent
PaciliCorp
This Re ort Is:
(1)An Original
(2)ffjA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 Series of Stock
(a)
Balance at End of Year
(b)
I Common Stock 41,101,062
2
3 Preferred Stock:
4 15.00% 98,049
5 4.52% Serial 9,676
6 4.72% Serial 28,596
7 4.56% Serial 47,177
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22 TOTAL 41,284,560
FERC FORM NO. I (ED. 12-87) Page 254b
Name of Respondent
PaciflCorp -
This Re ort Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
LONG-TERM DEBT (Account 221, 222,223 and 224)
1.Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2.In column (a), for new issues, give Commission authorization numbers and dates.
3.For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4.For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5.For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6.In column (b) show the principal amount of bonds or other long-term debt originally issued.
7.In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8.For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9.Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 Bonds: (Account 221)
2 First Mortgage Bonds:
3
4 7.978% Series due October 1, 2011 4,422,000
5 6.90% Series due November 15, 2011 500,000,000 3,567,009
6 1,735,000 D
7 8.493% Series due October 1, 2012 19,772,000
8 8.797% Series due October 1, 2013 16,203,000
9 5.45% Series due September 15, 2013 200,000,000 1,422,659
10 232,000 D
11 4.95% Series due August 15, 2014 200,000,000 1,442,365
12 728,000 D
13 8.734% Series due October 1, 2014 28,218,000
14 8.294% Series due October 1, 2015 46,946,000
15 8.635% Series due October 1, 2016 18,750,000
16 8.470% Series due October 1, 2017 19,609,000
17 5.65% Series due July 15, 2018 500,000,000 3,067,221
18 905,000 D
19 5.50% Series due January 15, 2019 350,000,000 2,515,793
20
21 400,000,000
2,292,500 D
3,006,612
744,000 D
23 7.70% Series due November 15, 2031 300,000,000 2,874,150
864,000 D
25 5.90% Series due August 16, 2034 200,000,000 1,892,365
26 722,000 D
27 5.25% Series due June 15, 2035 300,000,000 2,912,021
28 1,080,000 D
29 6.10% Series due August 1, 2036 350,000,000 2,907,881
30 1,141,000 D
31 5.75% Series due April 1, 2037 600,000,000 589,216
32 24,000 D
33 TOTAL 6,858,290,000 77,925,354
FERC FORM NO. I (ED. 12-96) Page 256
Name of Respondent
PacifiCo
This Report Is:
(1)DAn Original
(2)ffjA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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.
Nominal Date
of Issue
(d)
Date of
Maturity
(e)
AMORTIZATION PERIOD Outstanding (Total amount outstanding without
reduction for amounts held by
(g)
Interest for Year
Amount
(i)
Line
N O
-
Date From
(0
Date To
2
3
04/15/1992 10/01/2011 0411511992 10/01/2011 24,652 4
11/21/2001 11/15/2011 11/21/2001 11/15/2011 30,187,500 5
6
04/15/1992 10/01/2012 04/15/1992 10/01/2012 1,867,000 268,315 7
04/15/1992 10/01/2013 04/15/1992 10/01/2013 2,949,000 345,062 8
09/08/2003 09/15/2013 09/08/2003 09/15/2013 200,000,000 10,900,000 9
10
08/24/2004 08/15/2014 08/24/2004 08/15/2014 200,000,000 9,900,000 11
12
04115/1992 10/01/2014 04/15/1992 10/01/2014 7,259,000 767,762 13
04/15/1992 10/01/2015 04/15/1992 10/01/2015 14,882,000 1,423,168 14
04/15/1992 10/01/2016 04/15/1992 10/01/2016 7,202,000 694,168 15
04/15/1992 10/01/2017 04/15/1992 10/01/2017 8,526,000 789,425 16
07117/2008 07/1512018 07/17/2008 07/15/2018 500,000,000 28,250,000 17
18
01/08/2009 01/15/2019 01/08/2009 01/15/2019 350,000,000 19,250,000 19
20
05/12/2011 06/15/2021 05/12/2011 06/15/2021 400,000,000 9,753,333 21
22
11/21/2001 11/15/2031 11/21/2001 11/15/2031 300,000,000 23,100,000 23
24
08/24/2004 08/15/2034 08/24/2004 08/15/2034 200,000,000 11,800,000 25
26
06/13/2005 06/15/2035 06/13/2005 06/15/2035 300,000,000 15,750,000 27
28
08/10/2006 08/01/2036 08/10/2006 08/01/2036 350,000,000 21,350,000 29
30
03/14/2007 04/01/2037 03/14/2007 04/01/2037 600,000,000 34,500,000 31
32
6,171,055,000 364,553,118 33
FERC FORM NO. 1 (ED. 12-96) Page 257
Name of Respondent
PaciflCorp
This Re ort Is:
(1) An Original
(2)1A Resubmission
Date of Report
(Mo, Da, Yr)
06/2812012
Year/Period of Report
End of 2011/04
LONG-TERM DEBT (Account 221, 222, 223 and 224)
1.Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2.In column (a), for new issues, give Commission authorization numbers and dates.
3.For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4.For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5.For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6.In column (b) show the principal amount of bonds or other long-term debt originally issued.
7.In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8.For column (C) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (0). 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
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 6.25% Series due October 15, 2037 600,000,000 5,127,281
2 750,000 D
3 6.35% Series due July 15, 2038 300,000,000 2,290,333
4 1,671,000 D
5 6.00% Series due January 15, 2039 650,000,000 6,134,687
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 27,000000 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 6,858,290,000 77,925,354
FERC FORM NO. 1 (ED. 12-96) Page 256.1
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)ffjA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 retiredor reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16.Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Nominal Date
of Issue
(d)
Date of
Maturity
(e)
AMORTIZATION PERIOD Outstanding (Total amount outstanding without
reduction for amounts held by resp dent)
Interest for Year
Amount
(I)
Line
NO
-
_______________
Date From
(f)
_______________
Date To
(g)
10103/2007 10/15/2037 10/03/2007 10/15/2037 600,000,000 37,500,000 1
2
07117/2008 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 443,267 7
08/16/1991 09/01/2011 08/16/1991 09/01/2011 1,491,667 8
08/16/1991 09/01/2011 08/16/1991 09/01/2011 1,193,333 9
08/16/1991 09/01/2011 08/16/1991 09/01/2011 1,189,333 10
12/31/1991 12/30/2011 12/31/1991 12/30/2011 248,009 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 5,000,000 413,000 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 09/11/1992 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
07122/1993 07/21/2023 07/22/1993 07/21/2023 27,000,000 1,960,200 30
07122/1993 07/21/2023 07/22/1993 07/21/2023 11,000,000 798,600 31
08116/1993 08/16/2023 08/16/1993 08/16/2023 15,000,000 1,084,500 32
6,171,055,000 364,553,118 33
FERC FORM NO. I (ED. 12-96) Page 257.1
Name of Respondent
PaciliCorp
This Re ort Is: (1)An Original
(2)ffjA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
LONG-TERM DEBT (Account 221, 222, 223 and 224)
1.Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2.In column (a), for new issues, give Commission authorization numbers and dates.
3.For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4.For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5.For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6.In column (b) show the principal amount of bonds or other long-term debt originally issued.
7.In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8.For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9.Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(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
31 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 6,119,920,000 63,070,314
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, Lincoln County, WY, Series 1993 228,980
15 •1 197,125D
16 5.65% Poll Ctrl Rev Refunding Bonds, Emery County, Utah, Series 1993A 1,624,793
17 5-5/8% Poll Ctrl Rev Refunding Bonds, Emery County, Utah, Series 1993B 625,551
18 I 389,500D
19 Poll Ctrl Rev Refunding Bonds, Sweetwater County, WY, Series 1994 21,260,000 510,479
201 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. lmprvmnt Rev Bonds, Converse County, WY, Series 1995 5,300,000 132,043
30 Environ. lmprvmnt 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 6,858,290,000 77,925,354
FERC FORM NO. I (ED. 12-96) Page 256.2
Name of Respondent
PaciflCorp
This Re ort Is:
(1)An Original
(2)ffjA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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.
Nominal Date
of Issue
Date of
Maturity
AMORTIZATION PERIOD outstanding (Total amount outstanding without
reduction for amounts held by resp dent)
Interest for Year
Amount
Line
N °. _______________
Date From
_______________
Date To
08/16/1993 08/16/2023 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 01115/2026 01/23/1996 01/15/2026 100,000,000 6,710,000 8
5,432,685,000 352,044,744 9
10
11
12
11/17/1994 05/01/2013 11/17/1994 05/01/2013 40,655,000 354,725 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 11101/2023 16,400,000 942,180 17
18
11/17/1994 11/01/2024 11/17/1994 11/01/2024 21,260,000 154,373 19
11/17/1994 11/01/2024 11117/1994 11/01/2024 8,190,000 67,157 20
11/17/1994 11/01/2024 11/17/1994 11/01/2024 121940,000 1,001,333 21
11/17/1994 11/01/2024 11/17/1994 11/01/2024 9,365,000 74,851 22
11/17/1994 11/01/2024 11/17/1994 11/01/2024 15,060,000 138,337 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 12/01/2014 15,000,000 600,357 25
26
01/17/1991 01/01/2016 01/17/1991 01101/2016 45,000,000 458,698 27
12/01/1986 12/01/2016 12/01/1986 12/01/2016 8,500,000 359,450 28
11/17/1995 11/01/2025 11/17/1995 11/01/2025 5,300,000 224,251 29
11/17/1995 11/01/2025 11117/1995 11/01/2025 22,000,000 954,199 30
400,470,000 9,170,148 31
32
6,171,055,000 364,553,118 33
FERC FORM NO. I (ED. 12-96) Page 257.2
Name of Respondent
PaciflCorp
This Report Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
LONG-TERM DEBT (Account 221, 222,223 and 224)
1.Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2.In column (a), for new issues, give Commission authorization numbers and dates.
3.For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4.For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5.For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6.In column (b) show the principal amount of bonds or other long-term debt originally issued.
7.In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8.For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9.Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 Pollution Control Obligations - Unsecured
2
3 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992A 9,335,000 167,524
4 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992B 6,305,000 151,908
5 Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 22,485,000 242,163
6 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988B 11,500,000 84,822
7 Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Ser. 1990A 70,000,000 660,750
81 Poll Ctrl Rev Refndng Bonds, Emery County, UT, Series 1991 45,000,000 872,505
9 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988A 50,000,000 422,443
10 Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Series 1988 45,000,000 380,198
11 Poll Ctrl Rev Refndng Bonds, City of Gillette, WY, Ser. 1988 41,200,000 351,905
12 Environ. lmprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 24,400,0001 225,000
13 6.150% Environ. lmprvmnt Rev Bonds, Emery County, UT, Series 1996 556,549
14 178,464 D
15
16 Subtotal - Pollution Control Obligations - Unsecured 337,900,000 4,294,231
17
18
19 TOTAL ACCOUNT 221 6,858,290,000 77,925,354
20
21 Reacquired Bonds: (Account 222)
22
23 Advances from Associated Companies: (Account 223)
24
25 Other Long-Term Debt: (Account 224)
26
27 TOTAL ACCOUNT 224
28
29
31
32
33 TOTAL 6,858,290,000 77,925,354
FERC FORM NO. I (ED. 12-96) Page 256.3
Name of Respondent
PacifiCorp
This Report Is:
(1)l:lAn Original
(2)ffjA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
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.
Nominal Date
of Issue
Date of
Maturity
AMORTIZATION PERIOD Outstanding . (Total amount outstanding without
reductIonrOjPa?F
held by Interest for Year
Amount
Line
N 0. Date From Date To
09129/1992 12/01/2020 09/29/1992 12/01/2020 9,335,000 87,046 3
09/29/1992 12/01/2020 09/29/1992 12/01/2020 6,305,000 59,766 4
09/29/1992 12/01/2020 09129/1992 12/01/2020 22,485,000 205,414 5
01/01/1988 01/01/2014 01/01/1988 01/01/2014 11,500,000 78,097 6
07/25/1990 07/01/2015 07/25/1990 07/01/2015 70,000,000 499,454 7
05/23/1991 07/01/2015 05/23/1991 07/01/2015 45,000,000 406,008 8
01/01/1988 01/01/2017 01/01/1988 01/01/2017 50,000,000 409,250 9
01101/1988 01/0112018 01/01/1988 01101/2018 45,000,000 337,663 10
01101/1988 01/01/2018 01/01/1988 01/01/2018 41,200,000 300,352 11
12/14/1995 11/01/2025 12/14/1995 11/01/2025 24,400,000 175,663 12
09/24/1996 09/01/2030 09/24/1996 09/01/2030 12,675,000 779,513 13
14
15
337,900,000 3,338,226 16
17
18
364,553,118 19
20
21
22
23
24
25
26
27
28
29
30
31
32
6,171,055,0001 364,553,118 33
FERC FORM NO. I (ED. 12-96) Page 257.3
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)- An Original (Mo, Da, Yr)
PacffiCorp (2)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 256 Line No.: 21 Column: a
In May 2011, PacifiCorp issued $400 million of 3.85% First Mortgage Bonds due June 15,
2021. State commission authorizations for this issuance were as follows:
• Oregon Public Utility Commission ("OPUC") - Docket No. UF-4262, Order No. 10-062,
dated February 23, 2010.
• Idaho Public Utilities Commission ("IPUC") - Case No. PAC-E-10-02, Order No. 31018,
dated March 5, 2010.
ISchedule Page: 256.2 Line No.: 14 Column: b
On March 30, 2012, PacfiCorp redeemed all of the outstanding $8,300,000 principal amount
of the bonds.
Schedule Page: 256.2 Line No.: 16 Column: b
On March 30, 2012, PacfiCorp redeemed all of the outstanding $46,500,000 principal amount
of the bonds.
ISchedule Page: 256.2 Line No.: 17 Column: b 7 On March 30, 2012, PacfiCorp redeemed all of the outstanding $16,400,000 principal amount
of the bonds.
cpedule Page: 256.3 Line No.: 13 Column: b
On March 30, 2012, PacfiCorp redeemed all of the outstanding $12,675,000 principal amount
of the bonds.
ISchedule Page: 256.3 Line No.: 19 Column: h
Refer to page 108, Important Changes During the Quarter/Year, Item 6, and Notes to
Financial Statements of this Form No. 1 for a discussion of PacifiCorp's long-term debt.
Schedule Page: 256.3 Line No.: 30 Column: a
In December 2010, PacifiCorp filed a shelf registration statement with the United States
Securities and Exchange Commission on Form S-3 expected to provide for future first
mortgage bond issuances through November 2013.
For authorization for the issuance of long-term debt ($2.0 billion authorized;
$1.6 billion available as of December 31, 2011), refer to page 108, Important Changes
During the Quarter/Year, Item 6, of this Form No. 1.
Authorization to borrow the proceeds of pollution control revenue refunding bonds issued
(total of $300,345,000 authorized and available as of December 31, 2011) by the counties
of Emery, Utah; Carbon, Utah; Converse, Wyoming; Lincoln, Wyoming; Sweetwater, Wyoming;
and Mof fat,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, 2011) by one or more of the
following counties or municipalities: Emery, Utah; Converse, Wyoming; Lincoln, Wyoming;
Sweetwater, Wyoming; City of Gillette, Wyoming; Navajo County, Arizona; and Routt County,
Colorado is as follows:
• OPUC - Docket No. UF-4250, Order No. 08-382, dated July 29, 2008.
• IPUC - Case No. PAC-E-08-05, Order No. 30606, dated August 4, 2008.
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)FXJA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
1.Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount
2.If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate
return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated 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.
l]iii
N
Particulars (Details)
(a)
Amount
(b)
1 Net Income for the Year (Page 117) 554,806,039
2
3
4 Taxable Income Not Reported on Books
6
7
9 IDeductions Recorded on Books Not Deducted for Return
156,713,696
10
11
12
13
14 lincome Recorded on Books Not Included in Retüm
1,499,707,311
15
16
17
19 Peductiions on Return Not Charged Against Book Income
692,241,881
20
21
22
23
24
25
26 IState Tax Deductions
2,061,727,807
-108,877
27 Federal Tax Net Income -542,851,519
28 Show Computation of Tax:
29
30 Federal Income Tax at 35.00% -189,998,032
31 Provision to Return Adjustment 120,924,543
32 Tax Reserve Changes 763,951
33 Renewable Electricity Production Tax Credits -71,867,651
34 Mining Rescue Training Credits -69,284
35 Research & Experimentation Credits -74,997
36 Hiring Retention Tax Credit -36,000
37
38 Federal Income Tax Accrual
39
40
41
42
43
44
FERC FORM NO I (ED 12-96) Page 261
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Schedule Page: 261 Line No.: 8 Column: a
Particulars (Details) Amounts
Income Tax Interest 179
Sec. 481a Adjustment - Repair Deduction 4,856,357
CIAC 38,665,618
Reimbursements 9,255,805
Avoided Costs 49,883,225
Deferred Excess Net Power Costs - WA Hydro 1,853,327
OR _RCAC Sep-Dec 07 Deferred 638,771
NW Power Act-WA 253,222
Regulatory Liability - Tax Revenue Adjustment - UT 12,462
Regulatory Liability - Tax Revenue Adjustment - WY 29,424
Regulatory Liability - WA Low Energy Program 260,603
Regulatory Liability OR Balance Consol 387,526
Regulatory Liability - Blue Sky Program OR 1,153,478
Regulatory Liability - Blue Sky Program WA 61,438
Regulatory Liability - Blue Sky Program CA 38,414
Regulatory Liability - Blue Sky Program UT 827,581
Regulatory Liability - Blue Sky Program ID 14,058
Regulatory Liability - Blue Sky Program WY 87,849
Regulaotry Liability - OR 2010 Protocol Def 2,431,626
Regulatory Liability - Sale of Renewable Energy Credits 41,298,890
Regulatory Liability - OR Injuries & Damages Reserve 186,354
Regulatory Liability - OR Property Insurance Reserve 2,971,700
Regulatory Liability - ID Property Insurance Reserve 88,212
Regulatory Liability - WY Property Insurance Reserve 271,761
Regulatory Liability - Powerdale Decommissioning Costs Giveback - UT 540,834
Bear River -Settlement Agreement 343,062
Unearned Joint Use Pole Contact Revenue 301,560
MCI FOG Wire Lease 360
Total $156,713,696
Schedule Page: 261 Line No.: 13 Column: a
Particulars (Details) Amounts
Fed/State Tax Expense 205,138,412
Fed/State Tax Expense-Interest (347,404)
Capitalized labor and benefits costs for Power tax input - Permanent 180,232
Meals & Entertainment 1,150,625
Penalties 163,608
Lobbying expenses 2,247,231
MEHC Insurance Services - Premium 1,536,178
Mining Rescue Training Credit Addback - PacifiCorp 69,284
Non-deductible post-retirement costs 6,498,152
Capitalized labor and benefits costs for Power tax input - Temporary 9,141,845
Book Depreciation 617,695,737
ARO - reclass to regulatory assets/liability & ARO liability 243,355
Book Cost Depletion - Addback 1,637,291
Regulatory Asset - FAS 158 Pension Liab Adj. 28,692,000
Regulatory Asset - FAS 158 Post Ret. Liab. 17,426,000
Environmental Costs - WA 100,170
Cholla Plant Transaction Costs-APS Amortization 1,122,425
WA Disallowed Colstrip #3-Write-off 52,188
Regulatory Asset - Lake Side Liquidation 27,919
Goodnoe Hills Liquidation Damages - WY 21,250
RTO Grid West Notes Receivable - OR 382,521
RTO Grid West Notes Receivable - ID 27,162
Regulatory Asset - Pension MMT -UT 283,176
Regulatory Asset - Post -Ret MMT -OR 193,035
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 1 (2)
(Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Regulatory Asset - Post -Ret MMT -WY 308,642
Regulatory Asset - Post - Ret MMT -UT 278,648
Regulatory Asset - Post - Ret MMT -CA 15,467
Regulatory Asset-Deferred OR Independent Evaluator Fees 731,407
Powerdale Decommissioning Reg Asset- ID 92,045
Powerdale Decommissioning Reg Asset - OR 493,016
Powerdale Decommissioning Reg Asset - WA 212,947
CA - January 2010 Storm Costs 1,164,006
Powerdale Decommissioning Reg Asset - WY 34,392
ID - Deferred Overburden Costs 73,045
WY - Deferred Overburden Costs 177,893
WY - Deferred Advertising Costs 52,198
Reg Asset - Utah MPA 15,724,521
Regulatory Asset - CA Solar Feed-in Tariff 246,352
Deferred Excess Net Power Costs - OR 3,587,516
Deferral of Renewable Energy Credit - UT 16,637
Deferral of Renewable Energy Credit - WY 517,165
OR - MEHC Transition Service Costs 2,056,752
WA - Chehalis Plant Revenue Requirement 3,000,000
Reg Asset MEHC Transition Service Costs - CA 178,218
Deferred Coal Costs - Naughton Contract Settlement 1,376,154
Idaho Customer Balancing Account 1,390,489
Weatherization 9,654,869
Trojan Decommissioning Costs - Regulatory 13,316
Regulatory asset - Net Derivatives 224,102,593
Coal Pile Inventory Adjustment 4,081,423
Prepaid Taxes - Property Taxes 4,582,312
RTO Grid West Note Receivable - w/o - WA 23,470
TGS Buyout 15,474
Joseph Settlement 137,381
Hermiston Swap 171,693
Western Coal Carrier Postretirement Benefit Accrual 1,092,000
Derivatives - Current 105,117,145
Post Merger Loss-Reacquisition Debt - Addback 1,769,843
Reg Liability - Other - Balance Reclass 1,162,501
Reg Liability - Def NPC Balance Reclass 595,234
CA-California Alternative Rate for Energy Program (CARE) 491,616
Bonus Liability - Electric - Cash Basis (2.5 months) 202,705
Vacation Accrual - Cash Basis (2.5 months) 880,541
Pension / Retirement Accrual - Cash Basis 19,746
FAS 143 ARO Liability 17,988,698
Bad Debts Allowance - Cash Basis 4,402,986
Current Liability - Frozen MTM 23,495,569
Noncurrent Liability - Frozen MTM 166,506,240
Deferred Coal Cost - Arch 63,030
Rogue River - Habitat Enhancement Liability 5,622
Lewis River Settlement Agreement 150,145
Other Environmental Liabilities 3,215,255
N. Umpqua Settlement Agreement 1,290,244
Umpqua Settlement Agreement 119,572
Accrued Royalties 213,332
Reverse Accrued Final Reclamation 280,840
Unrealized Gain/Loss from Trading Securities 201,976
FAS 112 Book Reserve 2,250,038
Total $1,499,707,311
Schedule Page: 261 Line No.: 18 Column: a I Particulars (Details) Amounts
Utah Deferred Comp / COLI (2,468,699)
IFERC FORM NO. I (ED. 12-87) Page 450.2 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 0612812012 2011/Q4
FOOTNOTE DATA
Medicare Subsidy
AFUDC - Debt
AFUDC - Equity
Basis Intangible Difference
Book Gain/Loss on Land Sales
Reg Asset Utah ECAM
Regulatory Asset - Frozen MTM
Deferral of Renewable Energy Credit - WA
Regulatory Asset balance reclass
Trojan Decommissioning Costs - WA
Trojan Decommissioning Costs - OR
Trapper Mining Stock Basis
NonCurrent Asset - Frozen MTM
Current Asset - Frozen MTM
ARO Regulatory Liabilities
Regulatory liability BPA balancing accounts
Reg Liability - Sale of Renewable Energy Credit -,OR
Regulatory Liab - OR Energy Conservation Charge
Regulatory Liability - Deferred Benefit Arch Settlement
Regulatory Liability - CA Gain on Sale of Asset
Regulatory Liability - Sale of Renewable Energy Credits
Regulatory Liability - UT .Property Insurance Reserve
SMUD Revenue Imputation - UT regulatory liability
Derivatives - noncurrent
Willow Wind Account Receivable
Def Regulatory Asset-Foote Creek Contract
Tenant Lease Allow - PSU Call Center
Duke/Hermiston Contract Renegotiation
Deferred Revenue - Citibank
Redding Contract - Prepaid
Equity Earnings in Subsidiaries
Intercompany Adjustments
Total
(7,078,985)
(23, 812, 185)
(44, 939, 836)
(2,401, 039)
(665, 002)
(67, 787,260)
(186, 949, 133)
(681, 343)
(387, 526)
(22,981)
(5,663)
(676, 356)
(478,212)
(2,574,464)
(17, 828)
(477, 089)
(1,378,118)
(14, 795)
(44, 269)
(3,755)
- WY (3,594,057)
(683, 323)
(2,292, 156)
(328,103,560)
(97, 667)
(137, 640)
(48, 157)
(408,871)
(23, 000)
(549, 996)
(9,511,469)
(3,927,447)
$ (692, 241, 881)
Schedule Page: 261 Line No.: 25 Column: a
Particulars (Details) Amounts
Book Depreciation Allocated to Medicare and M&E (267,291)
Tax Percentage Depletion - Blundell Steam Field (Prior IGC) (448,549)
PPL Pre - 1943 Preferred Stock Div - Deduction (381,063)
MEHC Insurance Services - Receivable (8,945,767)
Dividend Received Deduction - Deferred Compensation (139,230)
PMI Overriding Coal Royalty % Depletion - PacifiCorp (11,748)
Repair Deduction (151,344,053)
Tax Depreciation (1,634,165,916)
Capitalized Depreciation (5,120,793)
Mine Safety Sec 179E Election -PPW (33,504)
Gain / (Loss) on Prop. Disposition (23,913,401)
Coal Mine Development (187,747)
Coal Mine Extension (2,958,831)
Removal Costs (71,456,910)
Cholla SHL-NOPA (Lease Amortization) (97,718)
ARO - reclass to ARO liabilities (3,287,083)
Tax Percentage Depletion - Deduction (399,154)
Tax Depletion (162,730)
ARO Regulatory Assets (14,683,787)
Environmental Clean-up Accrual (4,556,435)
Cholla Plant Transaction Costs - APS Amortization - ID (32,973)
Cholla Plant Transaction Costs - APS Amortization - OR (53,813)
Cholla Plant Transaction Costs - APS Amortization - WA (97,006)
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) X A Resubmission 06/28/2012 2011 /Q4
FOOTNOTE DATA
CA Deferred Intervenor Funding (32,885)
Deferred Intervenor Funding Grants (308,563)
Contra Pension Regulatory Asset MMT & CTG OR (1,014,634)
Contra Pension Regulatory Asset MMT & CTG WY (1,663,914)
Contra Pension Regulatory Asset CTG - UT (5,951,295)
Contra Pension Regulatory Asset MMT & CTG _CA (81,988)
Contra Pension Regulatory Asset CTG - WA (1,017,963)
Unrecovered Plant - Powerdale (279,021)
Powerdale Decommissioning Reg Asset - CA (33,06.9)
Reg Asset - OR Solar Feed-In Tariff (1,043,825)
Deferred Excess Net Power Costs-CA (197,452)
Deferred Excess Net Power Costs - WY 09 and After (19,602,585)
Deferred UT lndependent Evaluation Fee (92,241)
Deferred Excess Net Power Costs - ID 09 (10,304,274)
OR SB 408 Recovery (5,812,362)
Deferred Regulatory Expense (14,904)
Reg Asset - Other - Balance Reclass (1,162,501)
Reg Asset - Def NPC Balance Reclass . . (595,234)
Prepaid Taxes - OR PUC (274,543)
Prepaid Taxes - UT PUC (628,106)
Prepaid Taxes - ID PUC . (47,271)
Other Prepaid (283,083)
LT Prepaid IBEW 57 Pension Contribution (5,651,545)
Wasach workers comp reserve (138,194)
Non-ARO Liability - Regulatory Liability (243,355)
Regulatory Liability - UT Home Energy Lifeline (142,823)
OR Regulatory Asset/Liability Consolidation (52)
Oregon Gain on Sale (33,140)
Deferred Compensation Accrual - Cash Basis (437,171)
Severance Accrual - Cash Basis (18,021)
Pension Liability (49,568,900)
Post-Retirement Liability . (19,355,803)
SERP Liability (781,448)
Distribution O&M Amortization of Write-off . (2,600,530)
PMI-Fuel Cost Adjustment (600,889)
M&S Inventory Write-Off . (126,473)
R & E - Sec.174 Deduction (1,043,765)
Def Regulatory Asset-Transmission Service Deposit (844,425)
BPA Conservation Rate Credit (692,100)
Trail Mountain Accrued Liabilities (559,464)
Misc. Current and Accrued Liability (1,901,611)
Accrued Insurance Premium Tax (711,437)
Amortization NOPAs 99-00 pj (58,446)
Injuries and Damages Accrual -Cash Basis (3,031,000)
Total . $(2,061,727,807)
ISchedule Page: 261 Line No.: 38 Column: b
Berkshire Hathaway Inc. includes Pacificorp in its United States federal income tax return. Pacificorp's
provision for income taxes has been computed on a stand-alone basis.
Names of group members who will file a consolidated Federal Tax Return:
Under MEHC:
PPW Holdings LLC Sub-Group:
PacifiCorp
PPW Holdings LLC
PacifiCorp Sub-Group:
Centralia Mining Company
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 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Energy West Mining Company
Fossil Rock Fuels, LLC
Glenrock Coal Company
Interwest Mining Company
Pacific Minerals, Inc.
PacifiCorp Environmental Remediation Company
PacifiCorp Investment Management, Inc.
MEHC Sub-Group:
Alaska Gas Transmission Company, LLC
Allerton Capital, Ltd
American Pacific Finance Company
American Pacific Finance Company II
Arizona Home Services, LLC
BG Energy Holding LL.0
BG Energy LLC
Bishop Hill II Holdings, LLC
CalEnergy Company, Inc
CalEnergy Generation Operating Company
CalEnergy Holdings, 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 Title Company
CBEC Railway, Inc
CBSH0me Real Estate Company
CBSH0me Real Estate of Iowa, Inc
CBSH0me Relocation Services, Inc
CE Administrative Services, Inc
CE Black Rock Holdings LLC
CE Butte Energy Holdings LLC
CE Butte Energy LLC
CE Electric (NY), Inc
CE Electric, Inc
CE Exploration Company
CE Geothermal, Inc.
CE Indonesia Geothermal, Inc
CE International Investments, Inc
CE Obsidian Energy LLC
CE Obsidian Holding LLC
CE Power, Inc
CE Red Island Energy Holdings LLC
CE Red Island Energy LLC
CE/TA LLC
Champion Realty, Inc
Chancellor Title Services, Inc
Cimmred 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 Referral Network, Inc
Edina Realty Relocation, Inc
Edina Realty Title, -Inc
Edina Realty, Inc
Esslinger-Wooten-Maxwell, Inc
E-W-M Referral Services, Inc.
FFR, Inc
First Realty, Ltd
First Reserve Insurance, Inc
For Rent, Inc
HMSV Financial Services, Inc
RN Insurance Holdings, LLC
RN Mortgage, LLC
RN Real Estate Group N.C., Inc
IFERC FORM NO. 1 (ED. 12-87) Page 450.5 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PaciliCorp X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
HN Real Estate Group, LLC
HN Referral Corporation
HomeServices Financial Holdings, Inc
HomeServices Insurance, Inc
HomeServices of Alabama, Inc.
HomeServices of America, Inc
HomeServices of California, Inc
HomeServices of Florida, Inc
HomeServices of Illinois Holdings, LLC
HomeServices of Iowa, Inc
HomeServices of Kentucky Real Estate Academy, LLC
HomeServices of Kentucky, Inc
HomeServices of Nebraska, Inc
HomeServices of the Carolinas, Inc
HomeServices Relocation, LLC
HomeSvc of IL LLC d/b/a Koenig & Strey GMAC RE
HSR Equity Funding, Inc
Huff Commercial Group, LLC
Huff-Drees Realty, Inc
IMO Company, Inc
Iowa Realty Company, Inc
Iowa Realty Insurance Agency, Inc
Iowa Title Company
J.S. White Associates, Inc
JBRC, Inc
Jim Huff Realty, Inc.
JRBBW Realty, Inc d/b/a/ RealtySouth
Kansas City Title, Inc
Kentucky Residential Referral Service, LLC
Kern River Funding Corporation
Kern River Gas Transmission Company
KR Acquisition 1, LLC
KR Acquisition 2, LLC
KR Holding, LLC
Larabee School of Real Estate & Insurance
M & M Ranch Acquisition Company, LLC
M & M Ranch Holding Company, LLC
MEC Construction Services Company
MEHC America Transco, LLC
MEHC Insurance Services Ltd.
MEHC Investment, Inc
MEHC Texas Transco, LLC
MHC Investment Company
MHC, Inc
Mid-America Referral Network, Inc.
MidAmerican AC Holding, LLC
MidAmerican Energy Company
MidAmerican Energy Holdings Company
MidAmerican Energy Machining Services LLC
MidAmerican Funding, LLC
MidAmerican Geothermal, LLC
MidAmerican Hydro, LLC
MidAmerican Nuclear Energy Company, LLC
MidAmerican Nuclear Energy Holdings Co., LLC
MidAmerican Renewables, LLC
MidAmerican Solar, LLC
MidAmerican Transmission, LLC
MidAmerican Wind, LLC
Midland Escrow Services, Inc
Midwest Capital Group, Inc
Midwest Gas Company
Midwest Power Transmission Illinois LLC
Midwest Power Transmission Iowa LLC
MWR Capital, Inc
Nebraska Land Title & Abstract Company
NNGC Acquisition, LLC
Northern Aurora Inc
Northern Natural Gas Company
Pickford Escrow Company, Inc
Pickford Holdings LLC
Pickford Real Estate, Inc
Pickford Services Company, Inc
IFERC FORM NO. I (ED. 12-87) Page 450.6 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Plaza Financial Services, LLC
Plaza Mortgage Services, LLC
Preferred Carolinas Realty, Inc
Preferred Carolinas Title Agency, L.L.C.
Professional Referral Organization, Inc
Quad Cities Energy Company
Real Estate Links, LLC
Real Estate Referral Network, Inc
Reece & Nichols Alliance, Inc
Reece & Nichols Realtors, Inc
Reece Commercial, Inc.
Referral Company of North Carolina, Inc
RHL Referral Company, LLC
Roberts Brothers, Inc
Roy H. Long Realty Company, Inc
Salton Sea Minerals Corporation
San Diego PCRE, Inc
Semonin Realtors, Inc
Southwest Relocation, LLC
The Escrow Firm
The Referral Company
Title South, LLC
TPZ Holding, LLC
Two Rivers, Inc
United Settlement Services, L.C.
With respect to members of the MEl-IC Sub-Group, MEHC requires all subsidiaries to pay or receive from MEHC an
amount of tax based primarily on the stand-alone method of allocation. The computation includes all tax
benefits from tax deductions from costs borne by utility customers.
Berkshire Hathaway Inc. Sub-Group:
21 SPC, Inc.
21st Communities, Inc.
21st Mortgage Corporation
AAS-Lunken, Inc.
Ace Mailing Service, Inc.
Acme Brick Company
Acme Brick DPW, Inc.
Acme Brick Sales Company
Acme Building Brands, Inc
Acme Investment Company
Acme Management Company
Acme Ochs Brick and Stone, Inc.
Acme Services Company, L.P.
Active Organics, Inc.
Adalet/Scott Fetzer Company
AEG Processing Center No. 35, Inc.
AEG Processing Center No. 58, Inc.
Affordable Housing Partners, Inc.
Agile Manufacturing, Inc.
AJF Warehouse Distributors, Inc.
AL/TEX Homes, Inc.
Albecca, Inc.
Alexander Road Insurance Agency, Inc.
Alexander-Otto Company LLC
All Bilt Uniforms
Alpha Cargo Motor Express, Inc
Ambucor Health Solutions, Inc.
American All Risk Insurance Services Inc.
American Centennial Insurance Company
American Commercial Claims Administrators Inc
American Dairy Queen Corporation
American Employers Group, Inc.
American Tile and Stone, Inc
Apeks Apparel, Inc.
Applied Group Insurance Holdings, Inc.
Applied Investigations Inc.
Applied Logistics, Inc.
Applied Premium Finance, Inc.
Applied Risk Services of New York, Inc.
Applied Risk Services, Inc.
Applied Underwriters Captive Risk Assurance Company, Inc.
IFERC FORM NO. I (ED. 12-87) Page 450.7 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Applied Underwriters, Inc.
Atlanta International Insurance Company
AU Captive Risk Assurance Co.
AU Captive Risk Assurance Co., Inc.
AU Holding Company, Inc.
Bayport Systems, Inc.
Ben Bridge Jeweler, Inc.
Benjamin Moore & Co.
Berkadia Commercial Mortgage Inc.
Berkshire Hathaway Assurance Corporation
Berkshire Hathaway Credit Corporation
Berkshire Hathaway Finance Corporation
Berkshire Hathaway Homestate Insurance Company
Berkshire Hathaway Inc.
Berkshire Hathaway Life Insurance Company of Nebr.
BH Affordable Housing, Inc.
BH Columbia Inc.
BR Finance, Inc.
BH Shoe Holdings, Inc.
BH, LLC
BHG Structured Settlements, Inc.
BHR Inc.
BHSF, Inc.
Blue Chip Stamps
Blue Chip Stamps, Inc
BN Leasing Corporation
BNJ NetJets, Inc.
BNSF Communications, Inc.
BNSF Logistics International, Inc.
BNSF Railway Company
BNSF Railway International Services, Inc.
BNSF Spectrum, Inc.
Boat America Corporation
Boat U.S, Inc.
Boot Royalty Company
Borsheim Jewelry Company, Inc
BR Agency, Inc.
Brick Acquisition Company
Bricker-Mincolla Uniforms
Brilliant National Services, Inc.
Brooks Sports, Inc.
Brookwood Insurance Company
Burlington Northern Railroad Holdings, Inc.
Burlington Northern Santa Fe British Columbia, Ltd.
Burlington Northern Santa Fe Insurance Company, Ltd.
Burlington Northern Santa Fe Manitoba, Inc.
Burlington Northern Santa Fe, LLC
Business Wire, Inc.
C & R Insurance Services, Inc.
C & R Legal Insurance Agency, LLC
California Insurance Company
Camp Manufacturing Company
Campbell Hausfeld/Scott Fetzer Company
Capitol Avenue Real Estate Company
Carefree/Scott Fetzer Company
Cavalier Homes, Inc.
Central Nebraska Publications, Inc.
Central States Indemnity Co. of Omaha
Central States of Omaha Companies, Inc.
CS Service, Inc.
Chatwell, Inc.
Chippewa Shoe Company
Citadel Insurance Company
CJEII
Claims Services, Inc.
Clayton Commercial Buildings, Inc.
Clayton Homes, Inc.
CMH Capital, Inc.
CMH Hodgenville, Inc.
CMH Homes, Inc.
CMH Manufacturing West, Inc.
CMH Manufacturing, Inc.
IFERC FORM NO.1 (ED. 12-87) Page 450.8 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
CMH of KY, Inc.
CMH Parks, Inc.
CMH Services, Inc.
CMH Set and Finish, Inc.
Cologne Services Corporation
Columbia Insurance Company
Combined Claims Services, Inc.
Command Uniforms
Commercial Casualty Insurance Company
Commercial General Indemnity, Inc.
Commonwealth Uniforms Inc.
Complementary Coatings Corporation
Consolidated Health Plans Inc.
Continental Divide Insurance Company
Continental Indemnity Company
Corbond Corporation
Cort Business Services Corporation
Coverage Dynamics Group, Inc.
CPI Engineering Services, Inc.
Criterion Insurance Agency
Cross Creek Apparel, LLC
Crowley Garment Mfg Co Inc.
Crowley Shirt Mfg Co Inc.
CSI Life Insurance Company
CTB Credit Corp
CTB Inc.
CTB International Corp
CTB 1W INC
CTB MN Investments
Cumberland Asset Management, Inc.
Cypress Insurance Company
Dairy Queen Corporate Stores, Inc.
Dairy Queen Of Georgia, Inc.
Denver Brick Company
Dexter Shoe Company
Diedrich Technologies, Inc.
Diversified Mailing, Inc.
Douglas Building, LLC
DQ Funding Corporation
DQ Joint Venture Stores, Inc.
DQ Managed Stores, Inc.
DQ Wholly-Owned Stores, Inc.
DQF, Inc.
DQGC, Inc.
Eco Color Company
Ecodyne Corporation
Edmonds Material and Equipment Co.
Elm Street Corporation
Empire Distributors of North Carolina, Inc.
Empire Distributors, Inc.
Executive Jet Europe, Inc.
Executive Jet Management, Inc.
Expertos en Administracion, S.A. de C.V.
Exsif Worldwide, Inc.
Fairfield Insurance Company
Faraday Capital Limited
Farriors, Inc.
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.
Fontaine Fifth Wheel Company
Fontaine Modification Company
Fontaine Specialized, Inc.
Fontaine Spray Suppression Company
Fontaine Trailer Company
IFERC FORM NO. I (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)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Fontaine Truck Equipment Company
Footwear Investment Company
Forest River Financial Services, Inc.
Forest River Housing, Inc.
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)
FTL Regional Sales Co., Inc.
FTL Sales Company, Inc.
Fulton Manufacturing Company
Garan Central America Corp.
Garan Incorporated
Garan Manufacturing Corp.
Garan Services Corp
Gateway Underwriters Agency, Inc.
GEICO Advantage Insurance Company
GEICO Casualty Co.
GEICO Choice Insurance Company
GEICO Corporation
GEICO General Insurance Co.
GEICO Indemnity Co.
GEICO Insurance Agency
GEICO Products, Inc.
GEICO Secure Insurance Company
Gen Re Intermediaries Corporation
Gen Re Long Ridge LLC
General Re Corporation
General Re Financial Products Corporation
General Re New England Asset Management
General Reinsurance Corporation
General Star Indemnity Company
General Star Management Company
General Star National Insurance Company
Genesis Indemnity Insurance Company
Genesis Insurance Company
Genesis Management and Insurance Services Corporation
Getz Bros. & Co. Zug, Inc.
Giles Industries, Inc.
Golden Skillet International, Inc.
Government Employees Financial Corp.
Government Employees Insurance Co.
Grand Island Independent Real Estate, LLC
Grand Island Publishing Company, Inc.
GRD Holdings 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.
Harris Uniforms
Harrison Uniforms
liDS Redevelopment Corporation
HeatPipe Technology, Inc.
Helzberg's Diamond Shops, Inc.
Hemingford Building, LLC
Henley Holdings, LLC
HG-Power Plant. Inc.
Hohmann & Barnard, Inc.
Homefirst Agency, Inc.
Homemakers Plaza, Inc.
Horizon Wine & Spirits - Chattanooga, Inc.
Horizon Wine & Spirits - Nashville, Inc.
Innovative Building Products, Inc
International America Group Inc.
jFERC 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)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
International American Management Company
International Dairy Queen, Inc.
International Insurance Underwriters, Inc.
Ironwood Plastics Inc
Isabella Shoe Corporation
J.L. Mining Company
J.S Justin, Inc.
JM E3 CO
Johns Manville China, Ltd.
Johns Manville Corporation
Johns Manville, Inc.
Jordan's Furniture, Inc.
Justin Belt Company, Inc.
Justin Boot Company
Justin Brands, Inc.
Justin Industries, Inc.
Kahn Ventures, Inc.
Kale Uniforms
Kansas Bankers Surety Company
Karmelkorn Shoppes, Inc.
Kay Uniforms
Kearney Hub Publishing Company, Inc.
L.A. Terminals, Inc.
Laurier Indemnity Company
LEE Distributing Service, Inc.
Leesburg Yarn Mills, Inc.
Lexington Publishing Company, Inc.
Lockwood Street Urban Renewal Corporation
Los Angeles ,Junction Railway Company
Lubricant Investments, Inc.
Lubrizol Advanced Materials China, Inc.
Lubrizol Advanced Materials FCC, Inc.
Lubrizol Advanced Materials Gibraltar, Inc.
Lubrizol Advanced Materials Holding Corporation
Lubrizol Advanced Materials International, Inc.
Lubrizol Advanced Materials, Inc.
Lubrizol Enterprises, Inc.
Lubrizol Holding, Inc
Lubrizol Inter-Americas Corporation
Lubrizol International Management Corporation
Lubrizol Overseas Trading Corporation
LZ Holding Corporation
M & C Products, Inc.
Macro Retailing, Inc.
Mail Tech, Ltd.
Mapletree Transportation, Inc.
Marathon Suspension Systems, Inc.
Marmon Construction Services, Inc.
Marmon Distribution Services, Inc.
Marmon Flow Products, Inc.
Harmon Holdings, Inc.
Marmon Industrial Companies, Inc.
Harmon Retail Services, Inc.
Harmon Water, Inc.
Harmon Wire & Cable, Inc.
Marmon-Herrington Company
Marquis Jet Holdings, Inc.
Marquis Jet Partners, Inc.
Martin Manufacturing Company
Martin Mills, Inc.
Maryland Ventures, Inc.
McCain Uniform Company Inc.
McCarty-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.
IFERC FORM NO. I (ED. 12-87) Page 450.11 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
McLane Suneast, Inc.
McLane Western, Inc.
Medical Protective Corporation
Medical Protective Finance Corporation
Medical Protective Insurance Services, Inc.
MedPrO Risk Retention Services, Inc.
Merquinsa North America, Inc.
Metro Uniforms
MM Transport, Inc.
Midlands Newspapers, Inc.
Midwest Northwest Properties, Inc.
Miller-Sage, Inc.
MiTek Framings, Inc.
MiTek Holdings, Inc.
MiTek Industries, Inc.
MiTek, Inc.
MMX Corporation
Mobile Disaster Structures, Inc
Morgantown-National Supply, Inc.
Mount Vernon Fire Insurance Company
Mouser Electronics, Inc.
MPP Pipeline Corporation
MS Property Company
National Fire & Marine Insurance Company
National Indemnity Company
National Indemnity Company of Mid-America
National Indemnity Company of the South
National Liability & Fire Insurance Company
National Reinsurance Corporation
Nationwide Uniforms
Nebraska Furniture Mart, 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 Uniforms
NJ Executive Services, Inc.
NJA Jets Inc.
NJE Holdings, LLC
NJI Sales, Inc.
NJI, Inc.
Nocona Boot Company
North American Casualty Co.
North Platte Publishing Company, Inc.
Northern States Agency, Inc.
Northland/Scott Fetzer Company
Noveon Hilton Davis, Inc.
Oak River Insurance Company
Ohio Merger Sub, Inc.
Omaha World-Herald Company
Orange Julius Of America
Pan-Am Shoe Co., Inc.
Penn Coal Land, Inc.
Penn Pocahontas Coal Co.
Perfection Hy-Test Company
Pima Uniforms
Pine Canyon Land Company
PJR Management, Inc.
Plaza Financial Services Co.
Plaza Resources Co.
Ponce Fashions, Inc.
Precision Brand Products, Inc.
Precision Millwork Settings LLC
Precision Steel Warehouse - Charlotte SIC
Precision Steel Warehouse, Inc.
IFERC FORM NO. I (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)
PaciflCorp (2)X A Resubmission 0612812012 201144
FOOTNOTE DATA
Princeton Advertising & Marketing Group, Inc.
Princeton Insurance Company
Princeton Risk Protection, Inc
Priority One Financial Services, Inc.
Pro Installations, Inc.
Procrane Holdings, Inc.
Professional Datasolutions, Inc.
Promesa Health, Inc.
Queen Carpet Corporation
R.C. Willey Home Furnishings
Rabun Apparel, Inc.
.Railserve, Inc.
Railsplitter Holdings Corporation
RCP Investment, Inc.
Redwood Fire and Casualty Insurance Company
RENTCO Trailer Corporation
Resolute Management Inc.
Richline Group, Inc
Ringwalt & Liesche Co.
Riverview Land, LLC
Roberts Men's Shop
Running with Heels, Inc.
Rush Air Inc
Russell Athletic Corporation
Salado Sales, Inc.
Santa 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.
ScottCare Corporation
Scottsbluff Publishing Company, Inc.
Seaworthy Insurance Company
Sees 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 Industries Group, Inc.
Shaw Industries, Inc.
Shaw International Services, Inc.
Shaw Retail Properties, Inc.
Shaw Transport, Inc.
SHX Flooring, Inc.
SHX Leasing, Inc.
Sideplate Systems, Inc.
Silver State Uniforms
Simon's Incorporated
Simpad, Inc.
Soco West, Inc.
Sof ft Shoe Company
Sol Frank Uniforms Inc.
Somerset Services, Inc
Southern Energy Homes, Inc.
Southwest Iowa Newspapers, Inc.
Spectra Contract Flooring Puerto Rico, Inc.
Stahl/Scott Fetzer Company
Star Furniture Company
Star Lake Railroad Company
Stonewall Insurance Company
Strategic Staff Management, Inc.
Strick Mexicana, S.A. de C.V.
Suburban Newspapers, Inc.
The Ben Bridge Corporation
The BN and SF Railway de Mexico, S.A. de C.V.
The Buffalo News, Inc.
The BVD Licensing Corporation
The Eagle Company
IFERC FORM NO. 1 (ED. 12-87) Page 450.13
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 201 1/Q4
FOOTNOTE DATA
The Fecbheimer Brothers Co.
The Indecor Group, Inc.
The Lubrizol Corporation
The Medical Protective Company
The Pampered Chef, Ltd.
The Scott Fetzer Company
The Zia Company
Tiger-Sunbelt Industries, Inc.
TMI Custom Air Systems, Inc.
Tony Lama Company
Top Five Club, Inc.
Total Quality Apparel Resources
TPC European Holdings, LTD.
TPC N.A.S.A., LLC
TPC North America, Ltd.
Transco, Inc.
TRH Holding Corp.
Triangle Suspension Systems, Inc.
TSE Brakes, Inc.
TTI, Inc.
TXFM, Inc.
U.S. Investment Corporation
U.S. Underwriters Insurance Co.
Undergarment Fashions, Inc.
Unified Supply Chain, Inc.
Uni-Form Components Company
Uniforms of Texas
Union Sales, Inc.
Union Tank Car Company
Union Underwear Co., Inc
Unione Italiana Reinsurance Company of America, Inc.
United Consumer Financial Services Company
United Direct Finance, Inc.
United States Aviation Underwriters, Inc.
United States Liability Insurance Company
United Steel Products Company
Universal Uniforms
Vanderbilt ABS Corp.
Vanderbilt Mortgage and Finance, Inc.
Vanderbilt Property & Casualty Insurance Co., Ltd.
Vanderbilt SPC, Inc.
Vanity Fair, Inc.
Veritas Insurance Group, Inc.
Vessel Assist Insurance Services, Inc.
VFI-Mexico, Inc.
Vision Retailing, Inc.
Wayne/Scott Fetzer Company
Waynesburg Shirt Company Inc.
Webb Wheel Products, Inc.
Wesco Financial Corporation
Wesco Holdings Midwest, Inc.
Wesco-Financial Insurance Company
West Virginia Uniforms
Western Fruit Express Company
Western Iowa Newspapers, Inc.
Western Nebraska Newspapers, Inc.
Western/Scott Fetzer Company
Whittaker, Clark & Daniels, Inc.
Winona Bridge Railroad Company
WMC Corp.
World Book Encyclopedia, Inc.
World Book, Inc.
World Book/Scott Fetzer Company
World Broadcasting, Inc.
World Enterprises, Inc.
World Interactive Group, Inc.
World Investments, Inc.
World Marketing, Inc.
World Media Company
World Real Estate Management, LLC
World Technologies, Inc.
Worldbook.com, Inc.
IFERC FORM NO. I (ED. 12-87) Page 450.14 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Worldwide Containers, Inc.
X-L--Co., Inc.
XLI, Inc.
XTR, Inc.
XTRA Chassis, Inc.
XTRA Companies, Inc.
XTRA Corporation
XTRA Finance Corporation
XTRA Intermodal, Inc.
XTRA International Pacific, Ltd.
XTRA International, Ltd.
XTRA Mexicana, S.A. de C.V.
York Publishing Company, Inc.
Zuckerbergs Uniforms
IFERC FORM NO. I (ED. 12-87) Page 450.15 I
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1.Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2.Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3.Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4.List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Line
No.
-
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR J e d
Dunn Year (d)
lf eds
During Year (e)
Adjust-
ments
(f)
Taxes Accrued (Account 236)
(b)
Prepaid Taxes (Include in Account 165)
(c)
1 Federal:
2 Income 13,589,884 352,792,763 -140,504,783 -425,509,841
31 FICA -3,514 36,337,223 36,391,671
4 Unemployment 339,186 338,122
5 Excise Tax - Coal 162,786 3,258,065 3,239,588'
6 Subtotal 14,226,539 352,789,249 -100,570,309 -385,540,460 -5,057,918
7
8 State:
9
10 Arizona:
11 Property 1,181,569 2,609,199 2,486,169
12 Income 18,570 20,312
13 Subtotal 1,181,569 18,570 2,629,511 2,486,169 -9,871
14
15 California:
16 Property 2,202,837 2,202,837
17 Unemployment 769 34,630 33,310
18 Franchise-Income 110,746 186,555 375,870
19 Use 3,282 330,364 293,698 _______________
20 Local Franchise 973,724 1,278,585 1,068,351 _______________
21 Subtotal 977,775 110,746 4,032,971 3,974,066 -9,778
22
23 Colorado:
24 Property 1,800,000 1,829,101 1,869,101
25 Income -389
26 Subtotal 1,800,000 1,828,712 1,869,101 -1,933
27
28 Idaho:
29 Property 2,639,428 5,222,882 4,867,535
30 Income -1,323,020 -71,290 1,490,536
31 KWh 13,676 36,359 49,285
32 Unemployment 1,915 58,468 59,243
33 Use 13,978 143,750 141,576
34 Subtotal 2,668,997 -1,323,020 5,390,169 6,608,175 -24,760
35
36 Montana:
37 Property 1,632,561 2,835,131 3,051,599
38 Corporate License-Income -86,000 -59,547 26,932
39 Unemployment 1,252 1,252
40 Energy License 63,866 200,228 206,530
41 TOTAL 48,501,673 355,776,477 59,788,345 -215,967,798 -5,730,851
FERC FORM NO. I (ED. 12-96) Page 262
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)1A Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5.If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6.Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7.Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8.Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9.For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued
(Ind. in Account 165) (Account 409.1)
Extraordinary Items Earnings n9) Other No.
17,233,393 66,373,297 -138,818,714 2
430,018 11,403 3
5,385 4
181,263 5
17,850,059 66,384,700 -138,818,714 38,248,4051 6
7
8
9
10
1,304,599 2,609,199 11
-11,613 25,874 12
1,304,599 -11,613 2,635,073 -5,5621 13
14
is
____________________ 2,042,871 16
2,089 dog -
17
2909283 192,065 18
39,948 19
1,183,958 1,278,585 20
1,225,995 290,283 3,513,521 519,450 21
22
23
1,760,000 1,725,158 24
-1,544 700 25
1,760,000 -1,544 1,725,858 102,8541 26
27
28
2,994,775 5,078,891 29
214,046 -57,338 30
750 36,359 I I 31
1,140 32
16,152 33
3,012,817 214,046 5,057,912 I 332,257 34
35
36
1,416,093 2,835,131 37
-1,904 -58,204 38
39
57,564 200,228 I 40
52,714,616 78,502,426 5,017,607 54,770,738 41
FERC FORM NO. 1 (ED. 12-96) Page 263
Name of Respondent
PacifiCorp
This Re oil Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1.Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2.Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3.Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (C) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4.List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Line
No.
-
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR Jhaxesd
Dunn g yar
(d)
During Year
(e)
Adjust-
ments
(f)
Taxes Accrued
(Account 236)
(b)
Prepaid Taxes (Include in Account 165)
(c)
1 Wholesale Energy 45,506 142,707 147,162
2 Subtotal 1,741,933 -86,000 3,119,771 3,433,475 -2,383
3
4 New Mexico:
5 Property 7,054 7,054
6 Income -319 50
7 Subtotal 6,735 7,104 -1,836
8
9 Oregon:
10 Property 10,743,370 21,629,033 21,863,586
11 Unemployment 50,434 1,729,458 1,729,165
12 Wilsonville Payroll 260 1,491 1,2171
13 Excise-Income 677,838 -1,176,852 -1,722,276
14 City of Portland-Income -470 -809 1,556
15 Department of Energy 365,145 789,851 849,411'
16 Tn-Met 932,248 937,327
17 Lane County 1,878 1,878
18 Franchise 4,158,926 25,327,096 25,081,450
19 Subtotal 4,553,251 11,785,883 49,233,394 48,743,314 -165,711
20
21 Utah:
22 Property 470,896 56,701,563 56,737,170
23 Income -7,518,951 -5,882,127 1,959,272
24 Unemployment 376,629 371,202
25 Navajo Nation 1,233 1,233
26 Salt Lake Valley Law Enforc 599 599
27 Use 541,588 3,607,277 3,714,157
28 Subtotal 1,014,680 -7,518,951 54,805,174 62,783,633 -154,791
29
30 Washington:
31 Property 8,700,000 9,272,990 8,932,990
32 Unemployment 6,264 98,168 103,395
33 Business & Occupation 3,380 36,596 36,562
34 Wholesaling 3,239 2,868
35 Public Utility 1,060,006 10,525,344 10,485,350
36 Natural Gas Use Tax 115,817 1,264,075 1,194,500
37 Use 48,219 1,007,088 433,184
38 Subtotal 9,933,686 22,207,500 21,188,849
39
40 Wyoming:
41 TOTAL 48,501,673 355,776,477 59,788,345 -215,967,798 -5,730,851
FERC FORM NO. I (ED. 12-96) Page 262.1
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)A Resubmission
I Date of Report
(Mo, Da, Yr)
I 06128/2012
Year/Period of Report
End of 2011/Q4
TAXES ACCRUED, PREPAID AND CHARGED DUFkING YEAR (Continued)
5.If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6.Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7.Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8.Report in columns (I) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9.For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued
Account 236)
(9)
Prepaid Taxes
(Incl. in Account 165)
(h)
Electric
(Account 408.1, 409.1)
(I)
Extraordinary Items
(Account 409.3)
(J)
Adjustments to Ret.
Earnings (Account 439)
(k)
Other
(I)
No
-
41,051 142,707 1
1,514,708 -1,904 3,119,862 -91 2
3
4
7,054 5
-1,467 716 6
-1,467 7,770 -1,0351 7
8
9
10,977,923 20,936,361 10
58,472 7,745 11
534 12
-28,843 -1,085,985 13
-2,559 1,701 14
424,705 789,851 I 15
338,552 16
17
4,404,572 25,327,096 1 18
4,802,130 11,378,971 45,969,024 3,264,370 19
20
21
435,289 52,840,320 22
167,657 -5,794,904 23
7,545 -78 24
1,233 25
599 26
434,708 27
877,542 167,579 47,047,248 7,757,9261 28
29
30
9,040,000 9,070,073 31
1,037 32
3,414 36,596 I
371 34
1,100,000 10,525,344 I
185,392 36
622,123 37
10,952,337 19,632,013 2,575,487! 38
39
40
52,714,616 78,502,426 5,017,607 54,770,738 41
FERC FORM NO. 1 (ED. 12-96) Page 263.1
Name of Respondent
PacifiCorp
This Re port Is:
(1)LjAn Original
(2) VIA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1.Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2.Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3.Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4.List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Line
No.
-
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR Charged Dung Year (d)
Txes
During Year (e)
Adjust-
ments
(f)
Taxes Accrued (Account 236)
(b)
Prepaid Taxes
(Include n Account 165)
(c)
1 Property 7,189,617 14,452,092 14,415,665
2 Unemployment 387,946 385,472
3 Franchise 247,000 1,662,900 1,642000
4 Use 139,909 1,259,796 1,581,508
5 Annual Report 56,536 56,536
6 Subtotal 7,582,842 17,819,270 18,081,181
7
8 State Other 2,802,462 -1,112,441
9
10 Miscellaneous:
11 Goshute Possessory 15,551 15,551
12 Sho-Ban Possessory 182,034 182,034
13 Navajo Possessory 17,939 36,463 36,170
14 Ute Possessory 29,031 29,031
15 Crow Possessory 64,962 64,962
16 Umatilla Possessory 69,847 69,847
17 Subtotal 2,820,401 -714,553 397,595 -301,870
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 48,501,673 355,776,477 59,788,345 -215,967,798 -5,730,851
FERC FORM NO. I (ED. 12.96) Page 262.2
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)ffJA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5.If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6.Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7.Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8.Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9.For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued
Accoqnt 236)
(9)
Prepaid Taxes
(Incl. in Account 165)
(h)
Electric
(Account 408.1, 409.1)
(i)
Extraordinary Items
(Account 409.3)
(J)
Adjustments to Ret.
Earnings (Account 439)
(k)
Other
(I)
No.
7,226,044 14,098,055 1
8,790 2
267,900 1,662,900 1 3
-181,803 4
56,536 1 5
7,320,931 15,817,491 2,001,779 6
7
2,075,266 83,375 -1,087,339 8
9
10
15,551 11
182,034 12
18,232

36,463 13
29,031 14
64,962 15
69,847 16
2,093,498 83,375 -689,451 -25,102 17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
52,714,616 78,502,426 5,017,607 54,770,738 41
FERC FORM NO. I (ED. 12-96) Page 263.2
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 262 Line No.: 2 Column: f
($2,327,176) Account 190, Accumulated deferred income taxes (1)
(2,730,741) Adjustment related to equity investees.
($5,057,917)
(1) Represents the tax benefit of interest reclassified to Account 190
Footnote amended in accordance with FERC Order No. AC11-132.
Schedule Page: 262 Line No.: 2 Column: I
($1,538,756) Account 409.2, Income taxes - Federal (1)
147,313) Account 419, Interest and dividend income (2)
($1,686,069)
(1)Applicable to other income and deductions.
(2)Interest on uncertain tax positions that are effectively settled.
ISchedule Page: 262 Line No.: 3 Column: b I Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 262 Line No.: 3 Column: f I
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 262 Line No.: 3 Column: I I
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 4 Column: b
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 262 Line No.: 4 Column: f
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 262 Line No.: 4 Column: I
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 5 Column: I 1
Account 151, Fuel stock
Schedule Page: 262 Line No.: 12 Column: f
Adjustment related to equity investees.
Footnote amended in accordance with FERC Order No. AC11-132.
Schedule Page: 262 Line No.: 12 Column: I I
Account 409.2, Income taxes - Other, which represents state income tax applicable to other
income and deductions.
Schedule Page: 262 Line No.: 16 Column: I I
$146,195 Account 408.2, Taxes other than income taxes
1,512 Account 589, Rents
12,259 Account 107, Construction work in progress
$159,966
ISchedule Page: 262 Line No.: 17 Column: I I
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 18 Column: f I
See footnote at page 262, line 12, column f.
Schedule Page: 262 Line No.: 18 Column: I
Account 409.2, Income taxes - Other, which represents state income tax applicable to other
income and deductions.
Schedule Page: 262 Line No.: 19 Column: I I
Charged to same account as related goods.
Schedule Page: 262 Line No.: 24 Column: I I
IFERC FORM NO. I (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)XA Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
$ 733 Account 408.2, Taxes other than income taxes
103,210 Account 107, Construction work in progress
$103,943
Schedule Page: 262 Line No.: 25 Column: f
See footnote at paqe 262, line 12, column f.
Schedule Page: 262 Line No.: 25 Column: I
Account 409.2, Income taxes
income and deductions.
- Other, which represents state income tax applicable to other
Schedule Page: 262 Line No.: 29 Column: I
$ 1,380 Account 408.2, Taxes other than income taxes
142,611 Account 107, Construction work in progress
$143,991
Schedule Page: 262 Line No.: 30 Column: f
See footnote at page 262, line 12, column f.
Schedule Page: 262 Line No.: 30 Column: I
Account 409.2, Income taxes
income and deductions.
- Other, which represents state income tax applicable to other
ISchedule Page: 262 Line No.: 32 Column: I
Payroll taxes are generally
work in progress.
charged to operations and maintenance expense and construction
ISchedule Page: 262 Line No.: 33 Column: I
Charged to same account as related goods.
Schedule Page: 262 Line No.: 38 Column: f
See footnote at page 262, line 12, column f.
ISchedule Page: 262 Line No.: 38 Column: I
Account 409.2, Income taxes
income and deductions.
- Other, which represents state income tax applicable to other
ISchedule Page: 262 Line No.: 39 Column: I
Payroll taxes are generally
work in progress.
charged to operations and maintenance expense and construction
Schedule Page: 262.1 Line No.: 6 Column: f
See footnote at page 262, line 12, column f.
Schedule Page: 262.1 Line No.: 6 Column: I
Account 409.2, Income taxes - Other, which represents state income tax applicable to other
income and deductions.
Schedule Page: 262.1 Line No.: 10 Column: I
$ 13,348 Account 408.2, Taxes other than income taxes
133,245 Account 589, Rents
546,079 Account 107, Construction work in progress
$692,672
Schedule Page: 262.1 Line No.: 11 Column: I I
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress. -
Schedule Page: 262.1 Line No.: 12 Column: I
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 13 Column: f
See footnote at page 262, line 12, column f.
Schedule Page: 262.1 Line No.: 13 Column: I
Account 409.2, Income taxes - Other, which represents state income tax applicable to other
income and deductions.
Schedule Page: 262.1 Line No.: 14 Column: f
See footnote at page 262, line 12, column f.
lSchedule Page: 262.1 Line No.: 14 Column: I
Account 409.2, Income taxes - Other, which represents state income tax applicable to other
fRC FORM NO. 1 (ED. 12-87) Page 450.2 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
income and deductions.
Schedule Page: 262.1 Line No.: 16 Column: b
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 262.1 Line No.: 16 Column: f
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 262.1 Line No.: 16 Column: I I Payroll taxes are
work in progress.
generally charged to operations and maintenance expense and construction
Schedule Page: 262.1 Line No.: 17 Column: I
Payroll taxes are
work in progress.
generally charged to operations and maintenance expense and construction
Schedule Page: 262.1 Line No.: 22 Column: I I
$ 45,464 Account 408.2, Taxes other than income taxes
501 Account 589, Rents
2,075,928 Account 107, Construction work in progress
1,739,350 Account 151, Fuel stock
$3,861,243
Schedule Page: 262.1 Line No.: 23 Column: f
See footnote at page 262, line 12, column f.
Schedule Page: 262.1 Line No.: 23 Column: I
Account 409.2, Income taxes - Other, which represents state income tax applicable to other
income and deductions.
Schedule Page: 262.1 Line No.: 24 Column: b
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 262.1 Line No.: 24 Column: f
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 262.1 Line No.: 24 Column: I
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 27 Column: I
Charged to same account as related goods.
Schedule Page: 262.1 Line No.: 31 Column: I
$ 69,188 Account 408.2, Taxes other than income taxes
2,749 Account 589, Rents
130,980 Account 107, Construction work in progress
$202,917
Schedule Page: 262.1 Line No.: 32 Column: I
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
ISchedule Page: 262.1 Line No.: 34 Column: I
Account 151, Fuel stock
ISchedule Page: 262.1 Line No.: 36 Column: I
Account 151, Fuel stock
Schedule Page: 262.1 Line No.: 37 Column: I
Charged to same account as related goods.
Schedule Page: 262.2 Line No.: I Column: I
$ 935 Account 408.2, Taxes other than income taxes
11,887 Account 589, Rents
341,215 Account 107, Construction work in progress
$354,037
LSchedule Page: 262.2 Line No.: 2 Column: b
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 262.2 Line No.: 2 Column: f
Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 262.2 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)X A Resubmission 06/28/2012 201 1 /Q4
FOOTNOTE DATA
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 2622 Line No.: 4 Column: I
Charged to same account as related goods.
Schedule Page: 262.2 Line No.: 8 Column: f
Represents the tax benefit of interest reclassified to Account 190, Accumulated deferred
income taxes.
Schedule Page: 262.2 Line No.: 8 Column: I
Represents interest on uncertain tax positions that are effectively settled, charged to
Account 419, Interest and dividend income.
IFERC FORM NO. I (ED. 12-87) Page 450.4 I
Name of Respondent
PacifiCorp
I This Report Is:

(1) F]An Original
I (2) jA Resubmission
I Date of Report
(Mo, Da, Yr)
I 06/28/2012
Year/Period of Report
End of 20111Q4
ACCUMULAIED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility
operations. Explain by footnote any correction adjustments to the account balance shown in column (g),Include in column (I) the average
period over which the tax credits are amortized.
Line
O•
1
23%
Account
Subdivsions (al
Electric Utility
Balance at Beginning
of Year
(b)
Deferred for Year Allocations to Current Year's Income Adjustments
(g) Account No. (c) Amount (d) Account No. (e) Amount (0
314%
47%
510% 35,192,133 1,808,761
610% 5,669,770 1624,45:
7 Idaho 647,021 411.4 65,431
8
9
—Th
TOTAL
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
41,508,9241
I I I I I
3,498,651
11
12
1310% 440,504 420 440,50
14
15 Total Nonutility 440,504 440,50
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. I (ED. 12-89) Page 266
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)[]A Resubmission
I Date of Report
I (Mo, Da, Yr)
I 06/28/2012
Year/Period of Report
End of 2011/Q4
ACCUMULATED D =-FERRED INVESTMENT TAX CREDI'rS (Account 255) (continued)
Balance at End of Year
(h)
Avera?e Pod of Al ocation to Income
(i)
ADJUSTMENT EXPLANATION Line
-
2
3
4
33,383,365 48.37 5
4,045,318 30 6
581,585 30 7
38,010,2681 8
9
11
12
30
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. I (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)X A Resubmission 0612812012 2011/Q4
FOOTNOTE DATA
lSchedule Page: 266 Line No.: 5 Column: e I
Internal Revenue Code 46(f)2
Schedule Page: 266 Line No.: 6 Column: e
Internal Revenue Code 46(f)l
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent
PacifiCorp
This Report Is:
AResubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
OTHER DEFFERED CREDITS (Account 253)
1.Report below the particulars (details) called for concerning other deferred credits.
2.For any deferred credit being amortized, show the period of amortization.
3.Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) maybe grouped by classes.
Line
No.
-
Description and Other
Deferred Credits
(a)
Balance at
Beginning of Year
(b)
DEBITS
Credits
(e)
Balance at
End of Year
(f)
Contra
Account (c)
Amount
(d)
1 Working Capital Deposits 4,385,114 688,022 5,073,136
2
3 Reclamation Costs - Trapper Mine 4,736,622 272,022 5,008,644
4
5 Reclamation Costs - Deseret Mine 527,526 131,232 10,140 517,386
6
7 Reclamation Costs - Trail
8j Mountain Mine 1,087,498 131 2,820 1,084,678
9
10 Western Coal Carriers Benefits
11 Obligation 9,124,000 131,232 998,479 2,090,479 10,216,000
12
13 Deferred Revenue - Other 421 30,000M 55,000
14
15 Deferred Compensation Plan 232,241,920 2,1 89,08 9,369,229
16
17 Redding Contract (20) 2,750,080 456 549,996 2,200,084
18
191 Foote Creek Contract (15) 567,662 456 137,640 430,022
20
21 Environmental Liabilities 9,389,140 2,248,190 5,463,445 12,604,395
22
23 Unearned Joint Use Pole Contact 3,362,850 454 8,289,184 8,590,744 3,664,410
24
251 Misc. Security Deposits 11,681 2,000 13,681
26
27 Hermiston Gas Settlement (5) 408,871 547,555 408,871
28
29 Lease Incentives (10) 124,403 931 48,156 76,247
30
311 CowlitzlLewis River O&M (1) 97,091 535 254,063 269,096 112,124
32
33 Deferred Credits - Other (1) 23,000 921 23,000
34
35 Employee Housing Security Deposits 6,800 131,232 1,300 9,475 14,975
36
37 Oregon DSM Loans NPV Unearned
38 Income (10) 263,870 456 146,411 117,459
39
40 Cogeneration Bonds-Sunnyside 413,417 413,417
41
42 Transmission Security Deposits 1,450,000 1,450,000
43
44 Transmission Service Deposits 2,312,550 232,235,456 3,703,725 2,859,300 1,468,125
45
46 MCI F.O.G. wire lease (1) 558,451 454 3,352,504 3,352,864 558,811
47 TOTAL 51,231,025 24,577,725 194,300,763 220,954,063
FERC FORM NO. I (ED. 12-94) Page 269
Name of Respondent
PaciflCorp
I This Re ort Is:
I (1)An Original
I (2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06128/2012
Year/Period of Report
End of 2011 /Q4
OTHER DEFFERED CREDITS (Account 253)
1.Report below the particulars (details) called for concerning other deferred credits.
2.For any deferred credit being amortized, show the period of amortization.
3.Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
Line
No.
-
Description and Other
Deferred Credits
(a)
Balance at
Beginning of Year
(b)
DEBITS
Credits
(e)
Balance at
End of Year
(f)
Contra
Account (c)
Amount
(d)
2 Unamortized contract values (5) 182.3, 242 2,184,160 168,690,400 166,506,240
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 TOTAL 51,231,025 24,577,725 194,300,763 220,954,063
FERC FORM NO. 1 (ED. 12-94) Page 269.1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) - An Original 1(2) (Mo, Da, Yr)
PaciflCorp X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 269 Line No.: 13 Column: b
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 269 Line No.: 13 Column: e
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 269 Line No.: 15 Column: b
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 269 Line No.: 15 Column: e
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 269 Line No.: 21 Column: c
Account 182.3, Other regulatory assets
Account 232, Accounts payable
Account 557, Other expenses
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/04
(2)A Resubmission 06/28/2012
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
1.Report the information called for below concerning the respondent's accounting for deferred income taxes rating to amortizable
property.
2.For other (Specify),include deferrals relating to other income and deductions.
- CHANGES DURING YEAR Line Account Balance at Amounts Debited Amounts Credited No. Beginning of Year
to Account 410.1 to Account 411.1
- (a) (b) I (c) (d)
1 Accelerated Amortization (Account 281)
2 Electric
3 Defense Facilities
4 Pollution Control Facilities 11,642,708 83,482,121
5 Other (provide details in footnote):
6
7
8 TOTAL Electric (Enter Total of lines 3 thru 7) 11,642,708 83,482,121
9 Gas
10 Defense Facilities
11 Pollution Control Facilities
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) 11,642,708 83,482,121
18 Classification of TOTAL
19 Federal Income Tax 10,249,915 73,495,327
20 State Income Tax 1,392,793 9,986,794
21 Local Income Tax
NOTES
FERC FORM NO. I (ED. 12.96) Page 272
Name of Respondent
PacifiCorp
This Re ort Is: (1)An Original
(2)A Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
I (k)
I
-
Line
No.
2
I
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 411.2
(f)
I
Debits Credits
Account
Credited
I (g)
I
Amount
(h)
I
Account
Debited
(i)
I
Amount
I
282 69,552,096 164,676,925 4
5
6
7
69,552,096 164,676,925 8
9
10
11
12
13
14
15
16
69,552,096
61,231,722
164,676,925
144976,964
17
18
19
8,320,374 19,699,961 20
21
NOTES (Continued)
FERC FORM NO. I (ED. 12-96) Page 273
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp End of 2011/Q4
AResubmission 06/28/2012
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 accelerated amortization
2.For other (Specify), include deferrals relating to other income and deductions.
- CHANGES DURING YEAR Line Account Balance at Amounts Debited Amounts Credited No. Beginning of Year to Account 410.1 to Account 411.1
(a) (b) (c) (d)
1 Account 282
2 Electric 3,330,234,891 538,055,953 290,835,222
3 Gas
4
5 TOTAL (Enter Total of lines 2 thru 4) 3,330,234,891 538055,953 290,835,222
61 Nonutility
7
8
9 TOTAL Account 282 (Enter Total of lines 5 thru 8) 3,330,234,891 538,055,9531 290,835,222
10 Classification of TOTAL
11 Federal Income Tax 2,931,845,747 473,689,427 256,043,203
121 State Income Tax 398,389,144 64,366,526 34,792,019
13 Local Income Tax
NOTES
FERC FORM NO. I (ED. 12-96) Page 274
Name of Respondent
PacifiCorp
This Re ort Is:
(1)LjAn Original
(2)ffjA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
(k)
3,505,053,651
Line
No.
-
2
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 411.2
(0
Debits Credits
Account
Credited
(g)
182.3, 281
Amount
(h)
72,401,971
Account
Debited
(i)
Amount
(J
3
4
72,401,971 3,505,053,651 5
6
7
8
72,401,971
63,740,672
3,505,053,651
3,085,751,299
9
10
11
8,661,299 419,302,352 12
13
NOTES (Continued)
FERC FORM NO. 1 (ED. 12-96) Page 275
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)ffjA Resubmission
Date of Report
(Mo, Da, -Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
1.Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2.For other (Specify), include deferrals relating to other income and deductions.
-
Line
No.
1
2
3
Account
(a)
Account 283
Electric
Regulatory Assets
Balance at
Beginning of Year
0 I 649,677,709 1
CHANGES DURING YEAR
Amounts Debited
toAcco(ut41O.1
72,759,419
Amounts Credited J toAcco?Jt411.1
53,094,038 1
4
5
6 Other Deferred Liabilities 30,841,189 15,450,208 11,545,400
7
8
9
10
11
TOTAL Electric (Total of lines 3 thru 8)
Gas
680,518,898 88,209,627 64,639,438
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18
19
20
21
TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)
Classification of TOTAL
Federal Income Tax
680,518,898
599,108,781
88,209,627
77,658,333
64,639,438
56,906,755
22 State Income Tax 81,410,117 10,551,294 7,732,683
23 Local Income Tax
NOTES
FERC FORM NO. 1 (ED. 12-96) Page 276
Name of Respondent
PacifiCo
This Report Is:
(1)LjAn Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
3.Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4.Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
(k)
-
Line
No.
Amounts Debited
to Account 410.2
Amounts Credited
to Account 411.2
(f)
Debits Credits
Account
Credited (g)
Amount
(h)
Account Amount
Debited W(j) MW
6,442,9181 2O543O27 4,481,854 6 3,980,458 1 714,741,5851
2
i
5
181,486 5,382,492 190 2,435,164 31,980,155 6
7
8
6,624,404 20,543,027 9,864,346 66,415,622 746,721,740 9
10
11
12
13
14
15
16
17
18
6,624,404
5,831,940
20,543,0271
18,085,507
9,864,3461
8,684,295
66,415,622
58,470,458
746,721,740
657,392,955
19
20
21
792,464 2,457,520 1,180,051 7,945,164 89,328,785 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)_An Original 1 (2)
(Mo, Da, Yr)
PadfiCorp X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Schedule Page: 276 Line No.: 3 Column: g
182.3, Other regulatory assets
190, Accumulated deferred income taxes
Schedule Page: 276 Line No.: 3 Column: i I
182.3, Other regulatory assets
190, Accumulated deferred income taxes
ISchedule Page: 276 Line No.: 6 Column: g I
Account 190, Accumulated deferred income taxes and adjustment related to equity investees.
Footnote amended in accordance with FERC Order No. AC11-132.
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent This Re ort Is:
PacifiCorp (1) An Original
(2) EA Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
OTHER REGULATORY LIABILITIES (Account 254)
1.Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.
2.Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3.For Regulatory Liabilities being amortized, show period of amortization.
-
Line
No.
Description and Purpose of
Other Regulatory Liabilities
(a)
Balance at Begining
of Current
Quarter/Year
(b)
DEBITS
___________ Credits
(e)
__ _________
Balance at End
of Current
Quarter/Year
(f
Account
(c)
Amount
(d)
1 19,345,346 190 1,013,973 18,331,373
2 Income Tax Reg. Liab. - WA flow Through 2,426,440 190 7,751,454 8,669,424 3,344,410
3 Gain on Sale of Assets - OR (1) 73,549
3.755
64,548 31,408 40,409
4 Gain on Sale of Assets - CA 421.1 3,755
5 Injuries & Damage Reserve - OR 186,354 186,354
6 Property Insurance Reserve - OR 924 65,063 3,036,763 2,971,700
7 Property Insurance Reserve - ID 924 7,477 95,689 88,212
8 Property Insurance Reserve - UT 924 683,323 -683,323
9 Property Insurance Reserve -WY 271,761 271,761
10 SMUD Revenue Imputation (11) 9,074,298 440,442 2,338,813 46,657 6,782,142
11 Utah Home Energy Lifeline 203,362 142 2,235,073 2,092,250 60,539
12 BPA Balancing Account - WA 1,482,441 253,222 1,735,663
13 BPA Balancing Account - OR 3,175,146 440,442 477,089 2,698,057
14 Asset Retirement Obligations Req. Difference 4,407,551 7,763,143 12,170,694
15 Washington Low Income Program 206,049 142 902,041 1,162,644 466,652
16 Misc. Regulatory Liabilities - OR 192,624 142 51 192,573
17 BlueSky - OR 626,935 456 690,675 1,844,152 1,780,412
181 BlueSky - WA 48,434 456 99,779 161,217 109,872
19 BlueSky - CA 18,498 456 31,967 70,381 56,912
20 Blue Sky - UT 920,706 456 1,818,924 2,646,505 1,748,287
21 Blue Sky - ID 2,422 456 41,542 55,600 16,480
22 Blue Sky - WY 54,985 456 158,243 246,092 142,834
23 OR Energy Conservation Charge 2,338,991 456 22,316,839 22,302,044 2,324,196
24 Deferred Arch Coal Settlement (3) 44,269 557 44,269
25 Renewable Energy Credit Sales Deferral 7,516,235 456 14,535,730 50,862,445 43,842,950
26 Tax Revenue Requirement Adj. - UT 49,234 12,462 61,696
27 2010 Protocol Deferral - OR 2,431,626 2,431,626
28 Powerdale Decommissioning Costs Giveback - UT (2) 180,278 121,112 540,834
291 Regulatory Liability - Reclassifications 7,399,943 2,145,26
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 59,611,213 55,460,906 107,108,212 111,258.519
FERC FORM NO. 113-Q (REV 02-04) - Page 278
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 20111Q4
FOOTNOTE DATA
Schedule Page: 278 Line No.: I Column: a
Weighted average life is 46 years.
Schedule Page: 278 Line No.: 3 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Account 431, Other interest expense
Schedule Page: 278 Line No.: 28 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Account 445, Other sales to public authorities
ISchedule Page: 278 Line No.: 29 Column: f
The following schedule summarizes regulatory liabilities reclassifications:
As of
Reclassified from Regulatory Assets to Regulatory Liabilities: December 31, 2011
DSM Regulatory Asset Actuals - CA $ 3,007,137
DSM Regulatory Asset Accruals - CA (248,159)
DSM Regulatory Asset Actuals - UT 8,688,034
DSM Regulatory Asset Accruals - UT (3,865,060)
Alternative Rate For Energy (CARE) - CA 237,632
Deferred Excess REC5 in Rates - UT 16,637
Deferred Excess RECs in Rates - WY 517,165
Deferred Excess Net Power Costs - OR 61,433
Renewable Adjustment Clause - OR 8,816
Deferred Independent Evaluator Fee - OR 191,894
Solar Feed-In Tariff Deferral - CA 246,352
Reclassified from Regulatory Liabilities to Regulatory Assets:
Property Insurance Reserve - UT 683,323
$ 9,545,204
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent
PaciflCorp
This Re ort Is:
(1)An Original
(2)ffjA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
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), (f), and (g). Unbilled revenues and MWH
related to unbilled revenues need not be reported separately as required in the annual version of these pages.
2.Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3.Report number of customers, columns (t) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are
added for 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.
5.Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.
Line
No.
-
Title of Account
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no Quarterly)
(c)
1 Sales of Electricity
2 (440) Residential Sales 1,490,664,456 1,357,826,906
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See lnstr. 4) 1,266,280,218 1146,322,741
5 Large (or Ind.) (See lnstr. 4) 1,136,708,521 1,030,052,681
6 (444) Public Street and Highway Lighting 20,409,578 20,610,361
7 (445) Other Sales to Public Authorities 19,305,829 19,770,416
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers 3,933,368,602 3,574,583,105
11 (447)Sales for Resale 351,792,369 501,563,210
12 TOTAL Sales of Electricity 4,285,160,971 4,076,146,315
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Prov. for Refunds 4,285,160,971 4,076,146,315
15 Other Operating Revenues
16 (450) Forfeited Discounts 8,445,905 7,411,888
17 (451) Miscellaneous Service Revenues 5,919,271
18 (453) Sales of Water and Water Power 94,873 2,609
19 (454) Rent from Electric Property 20,180,422 19,559,096
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues 225,364,091
22 (456.1) Revenues from Transmission of Electricity of Others 73,666,512 67,812,115
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 268,596,402 326,069,070
27 TOTAL Electric Operating Revenues 4,553,757,373 4,402,215,385
FERC FORM NO. 1!3-Q (REV. 12-05) Page 300
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)ffjA Resubmission 06/28/2012
ELECTRIC OPERATING REVENUES (Account 400)
6.Commercial and industrial Sales, Account 442, maybe classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by
the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of
classification in a footnote.)
7.See pages 108-109, Important 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 unbilled revenue by accounts.
9.Include unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD AVG.NO . CUSTOMERS PER MONTH Line
Year to Date Quarterly/Annual Amount Previous year (no Quarterly) Current Year no Quarterly) Previous Year no Quarterly) No.
(d) (e) (f) (g)
16,046,111 15,794,444 1,483,134 1,474,90i 2
3
16,489,191 15,969,253 221,634 220,171 4
21,228,737 20,679,453 33,695 33,854 5
144,334 145,032 3,745 3,868 6
398,493 427,352 12 13 7
8
9
54,306,866 53,015,534 1,742,220 1,732,815 10
10,766,697 11,414,59 11
65,073,563 64,430,126 1,742,220 1,732,815 12
13
65,073,563 64,430,126 1,742,220 1,732,815 14
Line 12, column (b) includes $ 236,917,500 of unbilled revenues.
Line 12, column (d) includes 3,270,429 MWH relating to unbilled revenues
FERC FORM NO. 113-Q (REV. 12-05) Page 301
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 20111Q4
FOOTNOTE DATA
ISchedule 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.
ISchedule 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.
Schedule Page: 300 Line No.: 17 Column: b
(461) Miscellaneous service revenues include the following items that were $250,000 or
greater during the years ended December 31:
2011 2010
Account service charges -
disconnects/reconnects/returned check charges $4,155,399 $4,070,201
Customer contract flat rate billings 1,981,186 1,756,340
ISchedule Page: 300 Line No.: 21 Column: b
(456) Other electric revenues include the following items that were $250,000 or greater
during the years ended December 31:
2011 2010
Demand-side management revenue $ 91,535,136 $ 100,095,141
Renewable energy credit sales, net of deferrals
and amortization 37,224,673 93,760,900
Wind-based ancillary services 8,045,284 7,281,432
Energy exchange credits 7,988,197 7,822,254
Steam sales 5,818,520 5,719,969
Flyash/by-product sales 3,135,065 2,658,821
Blue Sky revenue 2,482,644 4,167,040
Power sale and exchange agreements 1,091,292 1,091,292
Revenue from generation interconnection and
transmission service request studies 903,959 991,746
Maintenance charges for work on transmission facilities 684,158 494,787
Phase shifting equipment fee from
Western Electricity Coordinating Council 343,401 455,941
IFERC FORM NO. I (ED. 12-87) Page 450.1 I
Name of Respondent
PaciflCorp
This Re ort Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 201 1 /Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in 'Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and i me ot iate schedule
(a)
MWI1 Sold
(b)
Revenue
(c)
Average Number
of C1sjmers
KWh Ot SalesPer Customer l'çQvnu_ J-'er ic.whoid
1 RESIDENTIAL SALES
2 CALIFORNIA
3 06CHCK000R-CA RES CHECK M 1
4j 06LNX003II-LINE EXT 80% GTY 920
5 06NETMT1 35-CA RES NET MTR 420 54,891 36 11,667 0.1307
6 060ALT015R-OUTDARLGTSR 327 75,663 354 924 0.2314
06RESD000D-RES SRVC 189,835 24,374,160 18,321 10,362 0.1284
8 06RESDDL06-CA LOW INCOME 116,737 14,790,107 10,049 11,617 0.1267
9 O6RGNSVO25-CASM GEN 1 116 28 36 0.1160
10 06RESDODM9-MULTI FAMILY 237 29,367 8 29,625 0.1239
11 06RESDODS8-MULT FAM SBMET 1,631 179,300 16 101,938 0.1099
12 UNBILLED REV - UNCOLLECTIBLE 2,000
13 CA ALT RATE-ENERGY (CARE) -5,085
14 REVENUE ADJ. DEFERRED NPC 30,821
15 REV. ACCOUNTING ADJ. -146,029
16 SMUD REVENUE IMPUTATIONS 40,483
17 06RESDOODN-CA RES SRVC-DEL 93,130 11,852,275 7,251 12,844 0.1273
18 UNBILLED REVENUE -1,589 258,000 -0.1624
19 IDAHO
20 O7LNX0001O-MNTHLY 80%GUAR 1,195
21 07LNX00035-ADV 80% MO GUAR 1,864
22 07NETMT135-BPA-ID RES NET -173
23 07NETMT135-ID RES NET 1,256 117,981 73 17,205 0.0939
24 070ALC0007-CUST OWN LIGHT 10 3,737 1 10,000 0.3737
25 070ALT07AR-SECURITY AR LG 101 40,685 128 789 0.4028
26 070ALT07AR-BPA-SECURITY AR -7
27 07RESD0001-RES SRVC 437,984 44,253,278 43,049 10,174 0.1010
28 07RESD0001-BPA-RE5 SRVC -40,770
29 07RESDO036-RES SRVC-OPTIO 278,605 22,943,676 14,367 19,392 0.0824
30 O7RESD0036-BPA-RES -30,210
31 07RGNSV23A-ID SM GEN 2 266 7 286 0.1330
32 07RGNSV23A-BPA-ID SM GEN -1
33 BPA BALANCING ACCOUNT -425,065
34 UNBILLED REV - UNCOLLECTIBLE -3,000
35 SMUD REVENUE IMPUTATIONS 53,795
36 UNBILLED REVENUE 2,003 616,000 0.3075
37 OREGON
38 O1CHCK000R-RES CHECK MTR 1
39 OICOST0004-01RESD0004 5,285,010 287,893,634 0.0545
40 O1COSTRO23 OR RES GEN SRV 1 85 4,034 0.0475
1 TOTAL Billed 54,246,323 4,091,383,354 1,742,220 31,136 0.075
42 Total Unbilled Rev.(See lnstr. 6) 60,54: 31,358,500 C 0.5181
43 TOTAL 54,306,861 4,122,741,854 1,742,221_ 31,171 0.0751
FERC FORM NO. I (ED. 12-95) Page 304
Name of Respondent
PacifiCorp
This Re ort Is:
(1)LJAn Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers. -
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and I me ot Kate schedule
(a)
MWII bold
(b)
Revenue
(c)
Average Number
of CisImers
KWh oT sales
Per ?Ltomer
nie Per h old
1 01 HABIT004 -01 RESD0004 42,797 2,286,345 0.0534
2 01 LNX001 02-LINE EXT 80% G 17,216
3 01LNX00I05-CNTRCT $ MIN G 15
4 01 LNX001 09-REF/NREF ADV + 1,082
5 01NETMT135-NET METERING 601,270 1,351
6 0INETMT135-BPA-NET METERING -52,447
7 01NMTOU135-TOU NET METR 5,686 10
8 01NMTOU135-BPA-TOU NET -54
9 0IOALT014R-OUTD AR LGT RE 1,177 191,689 2,831 416 0.1629
10 01 OALT014R-BPA-OUTD AR LGT -5,587
11 01OALTB15R-OR OUTD AR LGT 1,316 214,849 2,788 472 0.1633
12 01OALTB15R-BPA-OR OUTD AR -5,928
13 01 PTOU0004 -01 RESD0004 19,776 1,106,591 0.0560
14 01RENEW004 - 01RESD0004 216,907 11,447,223 0.0528
15 01RESD0004-RES SRVC 258,622,678 472,083
16 01 RESD0004-BPA-RES SRVC -25,692,663
17 01 RESDO04T - RES Time Option 878,227 1,290
18 01 RESDO04T-BPA -RES Time Opt -79,236
19 01RGNSB023-SM GEN SVC-RES 4,687 49
20 01RGNSB023-BPA-SMALL GEN -335
21 01UPPL000R-BASE SCH FALL 3
22 01 VIRO41 36-OR RES VOL INCTV 44,995 75
23 01V1R04136-BPA-OR RES VOL -4,020
24 BPA BALANCING ACCOUNT 296,807
25 OR GAIN ON SALE OF ASSET 31,823
26 OR SB 408 RECOVERY 5,794,105
27 OR SB 838 RECOVERY -330,320
28 REV. ACCOUNTING ADJ. -1,133,927
29 SMUD REVENUE IMPUTATIONS 513,496
301 UNBILLED REV - UNCOLLECTIBLE -1,000
31 UNBILLED REVENUE 2,496 4,438,000 1.7780
32 UTAH
33 08CFR00001-MTH FACILITY S 1,055
34 08CHCK000R-UT RES CHECK M 1
35 08COOLKPRR-Utah Cool Keeper 99,694
36 08LNX00001-MTHLY 80% GUAR 3,04
37 08LNX00005- MTHLY MIN GUAR 1,240
38 08LNX000I3-80% MTHLY MIN 25,916
39 08LNX001 08-ANN COST MTHLY 2,604
40 08MHTP0006-MOBILE HM & 3,030 198,793 7 432,857 0.0656
1 TOTAL Billed 54,246,323 4,091,383,354 1,742,221 31,136 0.075
42 Total Unbilled Rev.(See Instr. 6) 60,54 31,358,500 I 0.5181
43 TOTAL 54,306,861 4,122,741,854 1,742,221 31,171 0.0751
FERC FORM NO. I (ED. 12-95) Page 304.1
Name of Respondent
PacifiCorp
This Re ort Is: (1)An Original
(2)ff1A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
No.
Line and I itle ot Kate schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number
of C1scomers
KWfl of Sales
Per ?Ltomer
I.6venu.e ?er Kwh Sold
1 08MHTPOO23-MOBILE HM & 82 6,961 3 27,333 0.0849
=2 08MHTPOO25-MOBILE HM & 8,133 585,512 10 813,300 0.0720
3 O8NETMT135 - Net Metering 6,378 578,839 806 7,913 0.0908
4 080ALT007R-SECURITY AR LG 2,766 781,495 3,026 914 0.2825
5 08PTLD000R-POST TOP LIGHT 2 131 3 667 0.0655
6 08RESD0001-RES SRVC 6,331,128 570,658,484 674,406 9,388 0.0901
7 08RESD0002-RES SRVC-OPTIO 3,003 265,618 331 9,073 0.0885
8 O8RESD0003-LIFELINE PRGRM 258,342 22,973,427 31,741 8,139 0.0889
9 08RGNSVO06-GEN SRVC-RES 11,361 766,867 103 110,301 0.0675
10 08RGNSV023-GEN SRVC-RES 12,088 1,203,959 5,542 2,181 0.0996
11 08RGNSV06A-UTSMGEN 1,101 81,699 14 78,643 0.0742
12 08RNM231 35-UT NET MTR, GEN 55 4,752 10 5,500 0.0864
13 08UPPL000R-BASE SCH FALL 4
14 REV. ACCOUNTING ADJ. 6,820,393
15 REVENUE ADJ-DEFERRED NPC -3,941,200
16 UNBILLED REV - UNCOLLECTIBLE 15,000
17 UNBILLED REVENUE 13,178 4,581,000 0.3476
18 WASHINGTON
19 02LNX00109-REF/NREF ADV+ 19
20 02NETMT1 35-WA RES NET MTR 493 43,260 27 18,259 0.0877
21 02NETMT135-BPA-WA RES NET -2,144
22 020ALTB1 SR-WA OUTD AR LGT 1,080 158,722 1,164 928 0.1470
23 O2OALTB1 5R-BPA-WA OUTD AR -4,771
24 02RESDO016-WA RES SRVC 1,560,018 128,274,965 99,848 15,624 0.0822
25 02RESDO016-BPA-WA RES SRVC -6,823,839
26 02RESDO01 7-BILL ASSISTANCE 64,731 5,283,270 4,022 16,094 0.0816
27 02RESDO01 7-BPA-BILL -283,302
28 O2RESDOO1 8-WA 3 PHASE RES 2,264 204,912 87 26,023 0.0905
29 0RESDO01 8-BPA-WA 3 PHASE -9,920
30 02RESD018X-WA 3 PHASE RES 445 39,690 19 23,421 0.0892
31 02RESD018X-BPA-WA 3 PHASE -1,952
32 02RGNSBO24-WA SM GEN 8 984 35 229 0.1230
33 O2RGNSBO24-BPA-WA SM GEN -34
34 02UPPL000R-BASE SCH FALL 23
35 BPA BALANCING ACCOUNT -133,021
36 REVENUE ADJ.-DEFERRED NPC -1,396,700
37 REV. ACCOUNTING ADJ. -4,022,256
38 SMUD REVENUE IMPUTATIONS 128,419
39 WA - CHEHALIS DEFERRAL -1,320,000
40 UNBILLED REV - UNCOLLECTIBLE 7,000
11 TOTAL Billed 54,246,32 4,091,383,354 1,742,22 31,136 0.075
42 Total Unbilled Rev.(See Instr. 6) 60,54 31,358,500 _ 1 0.518
43 TOTAL 54,306,86 4,122,741,854 1,742,22 31,171 0.075
FERC FORM NO. I (ED. 12-95) Page 304.2
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and I me 01 Fate schedule
(a)
MWfl Sold
(b)
Revenue
(c)
Average Number
of CLsdtrmers
KWh 01 Sales
Per ?Ltomer
RvnLJ.e Per Kwh Sold
I UNBILLED REVENUE -3,302 847,000 -0.2565
2 WYOMING
3 05LNX001 02-LINE EXT 80% G 251
4 05NETMT135-EXPERIMENTAL 1,242 115,087 95 13,074 0.0927
5 050ALT015R-OUTD AR LGT SR 934 135,746 1,084 862 0.1453
6 05RESD0002-WY RES SRVC 947,057 85,092,703 97,464 9,717 0.0898
7 05RESDO18X-RES 3 PHASE SR 1 104 0.1040
8 O5RGNSVO25-WY SM GEN 12 1,130 13 923 0.0942
9 REVENUE ADJ.-DEFERRED NPC -400,562
10 REVENUE ACCOUNTING ADJ. -8,662
11 SMUD REVENUE IMPUTATIONS 63,655
12 UNBILLED REV - UNCOLLECTIBLE 5,000
13 UNBILLED REVENUE -3,426 672,000 -0.1961
14 05LNX001 09-REF/NREF ADV+ 244
15 05RESD0002-WY RES SRVC 135,793 12,280,173 12,512 10,853 0.0904
16 05RGNSVO25-WY SM GEN 39 1
17 090ALT207R-SECURITY AR LG 77 22,193 92 837 0.2882
18 05NETMT135 - EXPERIMENTAL 203 18,746 12 16,917 0.0923
19j 09RES00002 2
20 09RESD0002 4
21 UNBILLED REVENUE -2,420 -98,000 0.0405
22 LESS MULTIPLE BILLINGS -123,218
23
24 TOTAL RESIDENTIAL SALES 16,046,111 1,490,664,456 1,483,134 10,819 0.0929
25
26 COMMERCIAL SALES
27 CALIFORNIA
28 06CHCK000N-CA NRES CHECK 1
29 O6GNSVOO25-CA GEN SRVC 58,329 8,860,337 6,872 8,488 0.1519
30 06GNSVO25F-GEN SRVC-< 20 933 156,820 89 10,483 0.1681
31 06GNSVOA32-GEN SRVC-20 KW 83,279 10,386,699 967 86,121 0.1247
32 06LGSVO48T-LRG GEN SERV 61,254 5,187,557 13 4,711,846 0.0847
33 06LGSVOA36-LRG GEN SRVC-O 77,114 8,206,586 174 443,184 0.1064
34 O6LNXOO1O2-LINE EXT 80% G 11,739
35 O6LNXOO1 03-LINE EXT 80% G 1,018
36 06LNX001 05-CNTRCT $ MIN G 4,585
37 06LNX00I 09-REF/NREF ADV + 64,204
38 06LNX00300-80% MTHLY MIN GU 17,435
39 O6LNX00311-LINE EXT 80% GUAR 5,977
40 06NMT361 35-CA GEN SVC NET 343 42,464 1 343,000 0.1238
41 TOTAL Billed 54,246,32 4,091,383,354 1,742,221 31,131 0.075
42 Total Unbilled Rev.(See lnstr. 6) 60,54 31,358,500 1 _ 0.518
43 TOTAL 54,306,861 4,122,741,854 1,742,221 31,171 0.O75
FERC FORM NO. I (ED. 12-95) Page 304.3
Name of Respondent
PacifiCorp
This Re art Is:
(1)An Original
(2)A Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and Title ot Fate schedule
(a)
MWI1 Sold
(b)
Revenue
(C)
Average Number
of Clfdtrmers
KWfl at Sales Per Customer K.eventte Jer Kwh Sold
I 060ALT01 5N-OUTD AR LGT SR 724 170,425 524 1,382 0.2354
2 06RCFLOO42-AIRWAY & ATHLE 195 35,290 39 5,000 0.1810
3 06WHS31 025-COMM WTR HEATI 64 9,510 28 2,286 0.1486
4 06NMT25135-GN SVC NET<20K 43 6,121 2 21,500 0.1423
06NMT32135-GN SVC NET>20K 306 40,486 3 102,000 0.1323
6 REVENUE ADJ.-DEFERRED NPC 22,411
7 REV. ACCOUNTING ADJ. -88,795
8 SMUD REVENUE IMPUTATIONS 29,045
9 06LNX0011O-REF/NREF ADV + 10,029
10 UNBILLED REVENUE -1,317 109,000 -0.0828
11 IDAHO
12 07CISHOO19-COMM & IND SPA 6,506 488,217 117 55,607 0.0750
13 O7GNSV0006-GEN SRVC-LRG P 192,191 14,295,160 950 202,306 0.0744
14 07GNSV0009-GEN SRVC-HI VO 43,056 2,302,352 1 43,056,000 0.0535
15 07GNSVO023-GEN SRVC-SML P 134,778 11,734,851 6,424 20,980 0.0871
16 07GNSVO035-GEN SRVCOPTION 553 34,208 2 276,500 0.0619
17 07GNSVO06A-GEN SRVC-LRG P 26,890 2,106,252 192 140,052 0.0783
18 O7GNSVOO6A-BPA-GEN SRVC-LRG -3,275
19 07GNSVO23A-GEN SRVC-SML P 20,802 1,865,532 1,463 14,219 0.0897
20 07GNSVO23A-BPA-GEN SRVC SML -2,569
21 07GNSVO23F-GENSRVC-SML P 17 2,720 7 2,429 0.1600
22 07LNX00010-MNTHLY 80%GUAR 4,064
23 07LNX00035-ADV 80%MO GUAR 296,585
24 O7LNX0004O-ADV+REFCHG+80% 75,456
25 070ALT007N-SECURITY AR LG 233 86,805 178 1,309 0.3726
26 070ALT07AN-SECURITYARLG 11 4,477 13 846 0.4070
27 070ALT07AN-BPA-SECURITY AR -1
28 07LNX0031 2-ID LINE EXT 7,912
29 O7NMTO61 35-ID NET MTR-LRG 1,460 114,841 3 486,667 0.0787
30 07NMT231 35-ID NET MTR-SM GEN 383 30,069 9 42,556 0.0785
31 07LNX0001 5-ANNUAL 80%GUAR 1,332
32 O7LNX00311-LINE EXT 80% GUAR 51,759
33 07LNX00300-80% MTHLY MIN GU 10,218
34 BPA BALANCING ACCOUNT 7,870
35 SMUD REVENUE IMPUTATIONS 30,069
36 UNBILLED REVENUE 18,220 1,490,000 0.0818
37 OREGON
38 01COST0023-OR GEN SRV-COST 991,345 53,805,499 0.0543
39 01COST0048-01 LGSVO048 766,124 37,858,384 0.0494
40 01COST023F-OR GEN SRV-COST 3,074 178,070 0.0579
411 TOTAL Billed 54,246,324 4,091,383,354 1,742,22 31,13( 0.075
42 Total Unbilled Rev.(See lnstr. 6) 60,54 31,358,500 1 1 0.518
43 TOTAL 54,306,86 4,122,741,854 1,742,22 31,171 0.075
FERC FORM NO. I (ED. 12-95) Page 304.4
Name of Respondent
PaciflCorp
This Report Is: (1)An Original
(2)A Resubmission
Data of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues, Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and I we ot Kate schedule
(a)
MWI1 Sold
(b)
Revenue
(c)
Average Number of Cimers ISWfl ot Sales Per Customer Kev?nu.e PerKwh Sold
1 O1COSTBO23-OR GEN SRV-CST 84,395 4,742,100 0.0562
2 01COSTLO30-OR LG GEN 1,045,085 52,104,707 0.0499
3 OICOSTS028-OR GEN SRV 1,907,159 103,614,223 0.0543
4 01GNSB0023 -BPA DISC<3OkW -389,391
5 01GNSB0023-BPA-OR GEN SRV 5,915,215 14,351
6 0IGNSB0028-BPA-OR GEN SRV 2,520,647 530
7 01GNSB023T-BPA-OR GEN 22,732 49
8 01GNSVO023-OR GEN SRV<30kW 46,264,827 58,009
9 01GNSVO028-OR GEN SRV>30kW 44,900,970 8,818
10 01GNSV023F-OR GEN SRV-FLAT 10,601 1,571,173 796 13,318 0.1482
11 01GNSV023M-OR GEN SRV-MANU 30 2,789 1 30,000 0.0930
12 01GNSV023T-OR GEN SRV-TOU 170,956 226
13 01HABT0023-OR HABITAT BLEND 2,422 133,526 0.0551
14 01HABTB023-OR HABITAT BLEND 187 10,719 0.0573
15 OILGSB0030-BPA-GEN DEL -209,474
16 O1LGSB0030-GEN DEL SRV>200 841,257 25
17 01LGSVO030-OR LRG GEN 20,457,751 605
18 01 LGSVO048-1 000kW AND OVR 9,248,066 100
19101 LGSVO48M-LRG GEN SRVC 1 59,540 3,271,747 1 59,540,000 0.0550
20 O1LNX00100-LINE EXT 60% GUAR 2,140
21 01 LNX001 02-LINE EXT 80% GUAR 407,241
22 01LNX00103-LINE EXT 80% GUAR 4,078
23 01LNX00105-CNTRCT $ MIN G 14,281
24 01LNX00109-REF/NREF ADV + 1,540,407
25 01 LNX001 1 0-REF/NREF ADV + 3,432
26 01 LNXO01 20-LINE EXT 60% GUAR 266
27 01 LNX00300-LINE EXT 80% GUAR 151,589
28 01LNX00310-1-INE EXT CONTRACT 1,914
29 01LNX00311-LINE EXT 80% GUAR 122,855
30 01LNX00314-LINE EXT 60% GUAR -789
31 01LPRSO47M-PART REQ SRVC 31,078 2,374,000 3 10,359,333 0.0764
32 01 NMT231 35-OR NET MTR 95,249 125
33 01NMT23135-BPA-OR NET MTR -127
34 01OALT014N-OUTD AR LGT NR 753 125,558 1,139 661 0.1667
35 01 OALT0I 4N-BPA-OUTD AR LGT -3,548
36 010ALT0I5N-OUTD AR LGT NR 5,784 867,242 2,992 1,933 0.1499
37 010ALTB15N-OUTD AR LGT NR 825 139,203 1,126 733 0.1687
38 01 OALTB 15N-W/BPA-OUTD AR -3,710
39 01PTOU0023 OR GEN SRV, TOU 3,569 196,327 0.0550
40 01PTOUB023 OR GEN SRV, TOU 422 23,720 0.0562
i TOTAL Billed 54,246,32: 4,091,383,354 1,742,221 31,13 0.075
42 Total Unbilled Rev.(See lnstr. 6) 60,54 31,358,500 ____ _ 0.5181
43 TOTAL 54,306,861 4,122,741,854 1,742,221 31,171 0.075
FERC FORM NO. 1 (ED. 12-95) Page 304.5
Name of Respondent
PacifiCorp
This Report Is:
(1)An Original
(2)ff1A Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
No.
Line and I itle 01 Kate schedule
(a)
MWfl Sold
(b)
Revenue
(c)
Average Number
of C1tsomers
KWh 01 Sales Per C s I'cevncie rer Kwh Sold
1 01RCFLOO54-REC FIELD LGT 1,211 124,018 104 11,644 0.1024
2 01RENW0023 OR RENW USAGE 8,331 460,280 0.0552
3 01RENWB023 OR RENEWABLE 467 26,819 0.0574
4101 STDAY023-OR DAY STD OFR, 2,257 133,476 0.0591
5 01 STDAY028-OR DAY STD OFF, 11,586 666,682 0.0575
6 01STDAY030-OR STD DAY OFF 4,343 237,685 0.0547
7 01V1R23136-OR VOL 17,046 16
8 01V1R23136-BPA-OR VOL -64
9 01V1R28136-OR VOL 75,613 16
10 01V1R28136-BPA-OR VOL -193
11 01V1R30136-OR VOL 36,696 2
12 01V1R48136-OR VOL 15,438 1
13 BPA BALANCING ACCOUNT 327,150
14 O1LGSBOO48-BPA-LG GEN -14,568
15 O1LGSBOO48-LG GEN 53,491 1
16 01 NMT281 35-OR NET MTR 350,560 61
17 01 NMT301 35-OR NET MTR 420,587 13
18 01 NMT481 35-NET MTR GEN 97,472 2
19 01LGSV028M-OR LGSV<1 000 kW 366 29,665 1 366,000 0.0811
20 01 LGSV030M-OR LGSV 200 kW 1,650 118,360 1 1,650,000 0.0717
21 01GNSV0728-OR GEN SVC DIR 190,713 8
22 01GNSV0730-OR GEN SVC DIR 2,783,141 34
23 01GNSV0748 LG GEN SVC DIR 351,512 1
24 OR GAIN ON SALE OF ASSET 23,238
25 OR SB 408 RECOVERY 5,079,948
26 OR SB 838 RECOVERY -211,119
27 REV. ACCOUNTING ADJ. -828,028
28 SMUD REVENUE IMPUTATIONS 451,190
29 UNBILLED REVENUE 25,791 5,869,000 0.2276
30 UTAH
31 08ABL-NRES-APPLICANT BUILT 21,537
32 08CFR00051-MTH FAC SRVCHG 38,902
33 08CFR00052-ANN FAC SVCCHG 2
34 08COOLKPRN - A/C DIRECT LOAD 4,070
35 08GNSV0006-GEN SRVC-DISTR 4,821,904 342,243,542 10,823 445,524 0.0710
36 08GNSV0009-GEN SRVC-Hl VO 320,818 15,689,388 26 12,339,154 0.0489
37 08GNSVO023-GEN SRVC-DISTR 1,252,553 106,619,601 72,954 17,169 0.0851
38 08GNSVO06A-GEN SRVC-ENERG 212,050 20,667,534 1,858 114,128 0.0975
39 08GNSVO06B-GEN SRVC-DEM& 10,245 732,178 23 445,435 0.0715
40 08GNSVO06M-MNL DIST VOLTG 3,598 206,635 7 514,000 0.0574
1 TOTAL Billed 54,246,32 4,091,383,354 1,742,22' 31,131 0.075
42 Total Unbilled Rev.(See Instr. 6) 60,54 31,358,500 I 1 0.518'
43 TOTAL 54,306,86' 4,122741,854 1,742,22' 31,171 0.075
FERC FORM NO. I (ED. 12-95) Page 304.6
Name of Respondent
PaciflCorp
This Re ort Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
No.
Line and I We ot Kate schedule
(a)
MWfl Sold
(b)
Revenue
(c)
Average Number
of Clfdtrmers
KWh of SalesPer tistomer Revenu_e PerKwh bold
1 08GNSVO09A-GEN SRVC HI VO 25,108 1,347,375 2 12,554,000 0.0537
2 08GNSV009M-MANL HI VOLT 1
3 08GNSV023F-GEN SRVC FIXED 1,308 159,213 124 10,548 0.1217
4 08GNSVO23M-GNSV DIST VOLT 109 8,923 5 21,800 0.0819
5 08GNSV06AM-MNL ENERGY TOD 39 16,431 1 39,000 0.4213
6 08GNSV06MN-GNSV DIST VOLT 28,700 1,935,040 457 62,801 0.0674
7 08LNX00002-MTHLY 80% GUAR 453,123
8 O8LNX00004-ANNUAL 80%GUAR 15,466
9 08LNX00006-FIXD MTHLY MIN 4,668
10 08LNX00008-ANNUALMIN GUAR 12,167
11 08LNX00014-80% MIN MNTHLY 2,071,812
12 08LNX0001 7-AD V/REF&80%ANN 238,282
13 08LNX00158-ANNUALCOST MTH 33,793
14 08LNX00300-LINE EXT 80%+MO 138,404
15 08LNX003I0-IRR 80% ANNUAL MIN 56,951
16 08LNX00312 UT IRG LINE EXT 9,230
17 08NMT06135-UT NET MTR GEN 20,590 1,558,526 49 420,204 0.0757
18 O8NMTO81 35-NET METERING GEN 10,014 640,007 2 5,007,000 0.0639
19 08NMT23135 -UT NET MTR 1,480 126,695 76 19,474 0.0856
20 08NMT6AI 35-NET METERING GEN 46 9,206 1 46,000 0.2001
21 080ALT007N-SECURITY AR LG 8,419 1,952,703 4,432 1,900 0.2319
22 08POLE0075-POLES W/LIGHT 84 1
23 O8PRSVO31M-BKUP MNT&SUPPL 19,142 1,266,265 2 9,571,000 0.0662
24 08PTLD000N-POST TOP LIGHT 6 453 2 3,000 0.0755
25 08TOSS015F-TRAFFIC SIG NM 160 15,143 24 6,667 0.0946
26 08TOSS0015-TRAF & OTHERS 1,661 158,903 717 2,317 0.0957
27 08MONLOO15-MTR OUTDONIGHT 14,736 1,048,299 400 36,840 0.0711
28 REV. ACCOUNTING ADJ. 7,083,961
29 REVENUE ADJ-DEFERRED NPC -4,093,313
30 O8LNX003I1-LINE EXT 80% 251,879
31 08GNSV0008-UT GEN SVC 1,002,489 61,082,880 153 6,552,216 0.0609
32 08GNSVO08M-UT GEN SVC 32,868 2,163,552 5 6,573,600 0.0658
33 UNBILLED REVENUE 11,854 3,346,000 0.2823
34 WASHINGTON
35 02GNSBOO24-WA GEN SRVC DO 41,410 3,709,216 3,199 12,945 0.0896
36 02GNSBOO24-W/BPA-WA GEN -181,542
37 02GNSBO24F-GEN SRVC DOM/F 167 18,921 6 27,833 0.1133
38 02GNSB024F-W/BPA-GEN SRVC -4
39 O2GNSB24FP-WA GEN SVC 307 111,414 91 3,374 0.3629
40 02GNSB24FP-W/BPA-WA GEN SVC -1,357
TOTAL Billed 54,246,323 4,091,383,354 1,742,22q 31,136 0.075
421 Total Unbilled Rev.(See Instr. 6) 60,54 31,358,500 I _______________I 0.5181
43 TOTAL 54,306,861 4,122,741,854 1,742,221 31,171 0.0751
FERC FORM NO. 1 (ED. 12-95) Page 304.7
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)VIA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and i we ot late schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number
of C1slrmers
KWh ot Sales Per Customer TeT
Ken Per h o K Mid
1 02GNSVO024-WA GEN SRVC 480,171 39,437,604 14,642 32,794 0.0821
2 02GNSV024F-WA GEN SRVC-FL 1,115 135,672 112 9,955 0.1217
3 O2LGSB0036-LRG GEN SVC IRG 81,441 5,596,611 101 806,347 0.0687
4 02LG5B0036-W/BPA-LRG GENSVC -354,693
5 02LG5V0036-WA LRG GEN SRV 673,418 47,142,457 810 831,380 0.0700
6 02LGSVO48T-LRG GEN SRVC 1 141,957 8,969,763 26 5,459,885 0.0632
7 02LNX001 02-LINE EXT 80% G 164,935
8 02LNX00I 03-LINE EXT 80% G 2,221
9 02LNX00105-CNTRCT $ MIN G 700
10 02LNX00109-REF/NREF ADV + 419,124
11 02LNX0011O-REF/NREFADV+ 5,226
12 02LNX00112-YR INCURRED CH 669
13 02LNX00300-LINE EXT 80% G 8,452
14 O2LNX0031O-IRG 80% ANN 3,575
15 02LNX0031 1 -LINE EXT 80% 42,272
16 02LNX0031 2-WA IRG LINE EXT 4,004
17 020ALT015N-WA OUTD AR LGT 1,642 224,242 851 1,929 0.1366
18 020ALTB15N-WAOUTDARLGT 593 86,766 518 1,145 0.1463
19 O2OALTB15N-W/BPA-WA OUTD AR -2,614
20 02RCFL0054-WA REC FIELD L 244 22,158 28 8,714 0.0908
21 02ZZMERGCR-MERGER CREDITS 1
22 02NMT241 35, Net metering, WA 254 21,873 5 50,800 0.0861
23 02NMT241 35-BPA-Net metering, WA -2
24 02NMT36135-WA NET MTR LRG 105 10,970 1 105,000 0.1045
25 BPA BALANCING ACCOUNT -4,392
26 REVENUE ADJ-DEFERRED NPC -1,154,477
27 REV. ACCOUNTING ADJ. -3,084,534
28 SMUD REVENUE IMPUTATIONS 110,940
29 WA - CHEHALIS DEFERRAL -1,020,000
30 UNBILLED REVENUE -983 606,000 0.6165
31 WYOMING
32 05CHCK000N-WY NRES 1
33 05GNS28025-GEN SVC TRANS -24
34 O5GNSVOO25-WY GEN SRVC 236,772 19,218,400 17,995 13,158 0.0812
35 05GNSV0028-GEN SVC>l5kW 899,070 67,465,273 3,351 268,299 0.0750
36 05GNSV025F-GEN SRVC-FL RA 994 139,421 183 5,432 0.1403
37 05LG5V0046-WY LRG GEN SRV 254,406 15,138,627 20 12,720,300 0.0595
38 05LGSVO48T-LRG GENSRV TIM 10,430 657,345 1 10,430,000 0.0630
39 O5LNXOO1 00-LINE EXT 60% G 68
40 O5LNXOO1 02 -LINE EXT 80% G 548,373
1 TOTAL Billed 54,246,323 4,091,383,354 1,742,221 31,13' 0.075
42 Total Unbilled Rev.(See Instr. 6) 60,54 31,358,500 _ _ 0.5181
43 TOTAL 54,306,861 4,122,741,854 1,742,221 31,171 0.0751
FERC FORM NO. 1 (ED. 12-95) Page 304.8
Name of Respondent
PacifiCorp
This Re ort Is: (1)An Original
(2)MA Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and TItJe of Kate schedule
(a)
MWI-1 Sold
(b)
Revenue
(C)
Average Number
of CLsdt?mers
KWh ot salesPer Customer rer K hbo d
1 05LNX00I 03-LINE EXT 80% G -861
2 05LNX00105-CNTRCT $ MIN G 5,350
3 05LNX00109-REF/NREF ADV + 649,384
4 05LNX001 10-RE F/NREF ADV+ 839
5 05LNX00114-TEMP SVC 12M0> 1,162
6 05N2825135-NET MTRTRANSI 2 119 0.0595
7 05NMT251 35-WY NET MTR 206 15,685 11 18,727 0.0761
8 05NMT28135-NET MTR SM GEN 3,719 314,139 12 309,917 0.0845
9 050ALT015N-OUTD AR LGT SR 2,873 422,498 1,736 1,655 0.1471
10 05RCFLOO54-WY REC FIELD L 738 56,497 51 14,471 0.0766
11 05LNX00300-LINE EXT 80% 76,778
12 O5LNX00311-LINE EXT 80% 76,210
13 REVENUE ADJ-DEFERRED NPC -573,382
141 REV. ACCOUNTING ADJ. -11,704
15 SMUD REVENUE IMPUTATIONS 90,453
16 UNBILLED REVENUE -21,757 -1,013,000 0.0466
17 05GNS28025-GEN SVC -1 -115 0.1150
18 05GNSVO025-WY GEN SRVC 32,067 2,576,558 2,327 13,780 0.0803
19 O5GNSVOO28-GEN SVC>15kW 113,651 8,466,185 447 254,253 0.0745
20 05GNSV025F-GEN SRVC-FL RA 188 19,698 32 5,875 0.1048
21 05GNSV028M-GEN SVC>15kW 1,957 138,245 1 1,957,000 0.0706
22 05LGSVO48T-LRG GEN SRV TIM 40,962 3,084,085 1 40,962,000 0.0753
23 05LNX00I 02-LINE EXT 80% G 7,891
24 05LNX00109-REF/NREF ADV + 160,392
25 05LNX00110-REF/NREF ADV + 135
26 05LNX00114-TEMP SVC 1,054
27 09GN5V0025-GEN SVC-SINGLE -61
28 050ALT015N-OUTDARLGTSR 3 639 2 1,500 0.2130
29 05NMT25135-WY NET MTR 88 5,901 2 44,000 0.0671
30 05NMT28135-NET MTR SMALL 334 28,700 3 111,333 0.0859
31 090ALT207N-SECURITYAR LG 276 69,781 137 2,015 0.2528
32 09MONLO2I 3-WY MTR OUTDOOR 41 2,506 4 10,250 0.0611
33 05LNX00300-LINE EXT 80% 919
34 O5LNX003II-LINE EXT 80% 8,968
35 UNBILLED REVENUE -4,328 -251,000 0.0580
36 LESS MULTIPLE BILLINGS -28,517
a;
38 TOTAL COMMERCIAL SALES 16,489,191 1,266,280,218 221,634 74,398 0.0768
39
40 INDUSTRIAL SALES
i TOTAL Billed 54,246,323 4,091,383,354 1,742,221 31,136. 0075
42 Total Unbilled Rev.(See Instr. 6) 60,54 31,358,500 I 0.5181
43 TOTAL 54,306,861 4,122,741,854 1,742,221 31,171 0.0751
FERC FORM NO. 1 (ED. 12-95) Page 304.9
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and Title or Fate schedule
(a)
MWfl Sold
(b)
Revenue
(c)
Average Number
of CLsc!omers
KWh ot Sales
Per ?Lstomer
<ne er h 010
1 CALIFORNIA
2 06GNSVO025-CA GEN SRVC 644 101,530 93 6,925 0.1577
3 06GNSVOA32-GEN SRVC-20kW 1,974 281,787 26 75,923 0.1427
4 06LGSVO48T-LRG GEN SERV 35,743 3,016,970 5 7,148,600 0.0844
5 06LGSVOA36-LRG GEN SRVC-O 4,287 518,121 11 389,727 0.1209
6 REVENUE ADJ.-DEFERRED NPC 4,248
7 REV. ACCOUNTING ADJ. 127,564
8 SMUD REVENUE IMPUTATIONS 4,638
9 UNBILLED REVENUE -1,841 -83,000 0.0451
10 IDAHO
11 07CFR00001-MTH FACILITY S 2,217
12 07CISHOO1 9-COMM & IND SPA 125 9,942 3 41,667 0.0795
13 O7GNSV0006-GEN SRVC-LRG P 89,034 5,701,081 108 824,389 0.0640
14 07GNSV0009-GEN SRVC-HI VO 78,936 4,324,720 11 7,176,000 0.0548
15 07GNSVO023-GEN SRVC-SML P 11,126 946,962 351 31,698 0.0851
16 07GNSVO035-GEN SRVCOPTION 1,039 58,332 1 1,039,000 0.0561
17 07GNSVO06A-GEN SRVC-LRG P 3,930 314,686 29 135,517 0.0801
18 07GNSVO06A-BPA-GEN SRVC-LRG -510
19 07GNSVO23A-GEN SRVC-SML P 2,120 208,629 243 8,724 0.0984
20 07GNSVO23A-BPA-GEN SRVC-SML -173
21 07GNSVO23S-lD TRAFFIC SIGNALS 9 1,205 3 3,000 0.1339
22 07LNX00035-ADV 80%MO GUAR 850
23 O7LNXOOI 08-ANN COST MTHLY 1,996
24 07LNX00300-80% MONTHLY MIN 1,443
25 070ALT007N-SECURITYAR LG 13 5,019 17 765 0.3861
26 070ALT07AN-SECURITY AR LG 232 1
27 07SPCL0001 1,414,300 66,260,087 1 1,414,300,000 0.0469
28 O7SPCL0002 109,897 5,067,425 1 109,897,000 0.0461
29 BPA BALANCING ACCOUNT 2,784
30 SMUD REVENUE IMPUTATIONS 127,194
31 UNBILLED REVENUE 16,216 914,000 0.0564
32 OREGON
33 01COST0023 OR GEN SRV COST 20,905 1,138,923 0.0545
34 01 COST0048-01 LGSVO048 1,702,342 82,639,777 0.0485
35 01COST023F-OR GEN 1 60 0.0600
36 01COSTBO23-OR GEN SRV 368 20,766 0.0564
37 01COSTLO30-OR LRG GEN SRV 196,781 9,868,456 0.0501
38 01COSTS028 OR GEN SERV 94,394 5,112,529 0.0542
39101 GNSB0023-BPA DISC<30 kW -1,692
40 01GNSB0023-BPA-OR GEN 28,905 66
i TOTAL Billed 54,246,323 4,091,383,354 1,742,22' 31,13 0.075
42 Total Unbilled Rev.(See lnstr. 6) 60,54 31,358,500 I 0.5180
43 TOTAL 54,306,86 4,122,741,854 1,742,22' 31,171 0.075
FERC FORM NO. I (ED. 12-95) Page 304.10
Name of Respondent
PaciliCorp
This Report Is:
(1)LJAn Original
(2)1A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
No.
Line and I itie ot Kate schedule
(a)
MWI1 Sold
(b)
Revenue
(c)
Average Number of Ctsmers
KWh of sales
Per ?Ltomer
FevenLke l-'er Kwh Sold
1 01GNSB0028-BPA-OR GEN 13,273 5
2 01GNSVO023 OR GEN SRV<30kW 1,029,172 1,162
3 01GNSVO028 OR GEN SRV>30kW 2,956,783 479
4 01GNSV023F-OR GEN SR FLAT 2 684 2 1,000 0.3420
5 01GNSV023M-OR GEN SRV 35 7,829 1 35,000 0.2237
6 01 GNSV023T OR GEN SRV TOU 2,988 4
7 01GNSV0728-OR GEN SVC DIR 230
8. 01GNSV0748-OR GEN SVC DIR 38,487 2
9 0IHABT0023 OR HABITAT 12 680 0.0567
10 01LGSVO030-OR LRG GEN 5,877,368 153
11 01LGSVO048-1000kW AND OVR 16,928,484 103 -
12 01LGSVO48M-LRG GEN SRVC1 106,528 6,992,183 4 26,632,000 0.0656
13 01 LNX001 02-LINE EXT 80% G 54,201
14 01 LNX001 20-Line Extension 60% G 3,695
15 01 LNX00300-LINE EXT 80% 7,828
16 01LPRSO47M-PART REQ 106,656 6,043,074 2 53,328,000 0.0567
17 01 NMT231 35-OR NET MTR 163
18 01 NMT281 35-OR NET MTR 14,790 4
19 01 NMT3O1 35-OR NET MTR 1,665 1
20 010ALT014N-OUTD AR LGT NR 2 314 5 400 0.1570
21 01OALT014N-BPA-OUTD AR LGT -10
22 01OALT015N-OUTD AR LGT 328 47,483 140 2,343 0.1448
23 01 OALTB1 SN-OR OUTD AR LGT 3 385 5 600 0.1283
24 01 OALTB1 5N-W/B PA-OR OUTD AR -11
25 0IPTOU0023 OR GEN SRV TOU 49 2,752 0.0562
26 01RENW0023 OR RENW USAGE 142 7,639 0.0538
27 OIRENWBO23-OR RENEWABLE 1 33 0.0330
28 BPA BALANCING ACCOUNT 1,003
29 01 STDAY023-OR DAY STD OFR 20 1,205 0.0603
30 01STDAY028-OR DAY STD OFR 174 10,577 0.0608
31 01V1R23136-OR VOL 325 1
32 01 VIR3O1 36-OR VOL 8,707 1
33 01ZZMERGCR-MERGER CREDITS -1
34 OR GAIN ON SALE OF ASSET 8,262
35 OR SB 408 RECOVERY 2,344,591
36 OR SB 838 RECOVERY -100,849
37 REV. ACCOUNTING ADJ. -294,418
38 SMUD REVENUE IMPUTATIONS 209,836
39 UNBILLED REVENUE -1,286 1,414,000 -1.0995
40 UTAH
1 TOTAL Billed 4,246,32 1 54,246,321- 4,091,383,354 1,742,22 31,13 0.0754
42 Total Unbilled Rev.(See lnstr. 6) 60,54 31,358,501 0.5180 0.5181
43 TOTAL 54,306,86 4,122,741,854 1,742,22 31,171 0.0751
FERC FORM NO. I (ED. 12-95) Page 304.11
Name of Respondent
PaciflCorp
This Re ort Is:
(1)An Original
(2)RXA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
N
Number and I iUe ot Kate schedule
(a)
MWII Sold
(b)
Revenue
(c)
Average Number
Of CLsjomers
icwn or Sales
Per ?istomer
Kevenue ?er Kwh Sold
1 08CFR00051 -MTH FAC SRVCHG 14,047
2 08EFOP0021-ELEC FURNACE 0 1,953 160,634 2 976,500 0.0822
3 08EFOP021M-ELEC FURNACE 0 1,513 150,840 3 504,333 0.0997
4 08GNSV0006-GEN SRVC-DISTR 686,768 51,664,669 1,152 596,153 0.0752
5 08GNSV0009-GEN SRVC-Hl VO 2,783,348 125,859,808 108 25,771,741 - 0.0452
6 08GNSVO023-GEN SRVC-DISTR 58,507 5,037,987 3,536 16,546 0.0861
7 08GNSVO06A-GEN SRVC-ENERG 53,425 5,719,851 257 207,879 0.1071
8 O8GNSVOO6B-GEN SRVC-DEM 7,063 517,917 8 882,875 0.0733
9 08GNSVO09A-GEN SRVC HI VO 19,343 1,306,742 6 3,223,833 0.0676
10 08GNSVO09M-MANL HIGH 855,648 36,978,810 11 77,786,182 0.0432
11 08GNSVO23F-GEN SRVC FIXED 4 2,141 1 4,000 0.5353
12 08GNSV06MN-GNSV DIST VOLT 1,266 97,923 28 45,214 0.0773
13 O8GNSVO9AM-MAN TOD HIVOLT 1,201 103,647 1 1,201,000 0.0863
14 08LNX00002-MTHLY 80% GUAR 30,853
15 08LNX00004-ANNUAL 80%GUAR 8,213
16 08LNX000I4-80% MIN 41,093
17 08LNX0001 7-AD V/REF&80%ANN 3,361
18 O8LNX00311-LINE EXT 80% 4,251
19 08LNX00300-LINE EXT 80% PLUS 51,753
20 08LNX00310-IRR 80% ANNUAL MIN 6,141
21 080ALT007N-SECURITYAR 1,330 271,420 494 2,692 0.2041
22 08TOSS0015-TRAF&OTHERS 21 2,104 11 1,909 0.1002
23 O8MONLOO15-MTR OUTDONIGHT 8 2,954 7 1,143 0.3693
24 08NMT06I 35-UT NET MTR GEN 606 47,136 2 303,000 0.0778
25 08NMT231 35-UT NET MTR GEN<25 59 4,021 1 59,000 0.0682
26 08PRSV031M-BKUP MNT&SUPP 2,929 534,257 1 2,929,000 0.1824
27 08SPCL0001 524,877 22,064,619 1 524,877,000 0.0420
28 O8SPCL0002 897,631 29,293,488 1 897,631,000 0.0326
29 08SPCL0003 985,891 40,053,038 1 985,891,000 0.0406
30 08SPCL0005 250,829 10,081,122 1 250,829,000 0.0402
31 REV. ACCOUNTING ADJ. 4,376,938
32 REVENUE ADJ-DEFERRED NPC -2,528,875
33 08GNSVO6AM-MNL ENERGY TOD 318 34,027 2 159,000 0.1070
34 08GNSV0008-UT GEN SVC 955,113 60,695,848 110 8,682,845 0.0635
35 08GNSVO08M-UT GEN SVC 59,957 3,823,398 7 8,565,286 0.0638
36 UNBILLED REVENUE -7,716 2,436,000 -0.3157
37 WASHINGTON
38 O2GNSBOO24-WA GEN SRVC 1,954 178,547 95 20,568 0.0914
39 02GNSBOO24-W/BPA-WA GEN . -8,572
40 02GNS824FP-WA GEN SVC 5 1,941 1 5,000 0.3882
TOTAL Billed 54,246,323 4,091,383,354 1,742,221 31,131 0.075
42 Total Unbilled Rev.(See lnstr. 6) 60,543 31,358,500 ( 0.5181
43 TOTAL 54,306,866 4,122,741,854 1,742,221 31,1711 0.0751
FERC FORM NO. I (ED. 12-95) Page 304.12
Name of Respondent
PaciflCorp
This Report Is:
(1)An Original
(2)A Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and I itie ot Kate schedule
(a)
MWn Sold
(b)
Revenue
(c)
Average Number
of Cus
KWh ot Sales Per ,istomer KevnLie Per KWh Sold
1 02GNSB24FP-W/BPA-WA GEN SVC -21
2 02GNSVO024-WA GEN SRVC 15,408 1,296,096 360 42,800 0.0841
3 02GNSVO24F-WA GEN SRVC-FL 33 7,513 4 8,250 0.2277
4j 02LGSVO036-WA LRG GEN SRV 114,346 8,188,158 115 994,313 0.0716
5 02LGSVO48T-LRG GEN SRV 1 669,856 37,359,595 32 20,933,000 0.0558
6 020ALT015N-WA OUTD AR LGT 121 15,538 42 2,881 0.1284
7 020ALTB15N-WA OUTD AR LGT 29 4,313 16 1,813 0.1487
8 020ALTBI 5N-W/BPA-WA OUTD AR -130
9 02PRSV47TM-LRG PART REQMT 1,379 234,625 1 1,379,000 0.1701
10 02LGSB0036-LRG GEN SVC IRG 3,633 412,006 26 139,731 0.1134
11 02LGSB0036-W/BPA-LRG GENSVC -16,054
12 BPA BALANCING ACCOUNT -116
13 REVENUE ADJ-DEFERRED NPC -628,612
14 REV. ACCOUNTING ADJ. -1,405,927
15 SMUD REVENUE IMPUTATIONS 63,473
16 WA - CHEHALIS DEFERRAL -510,000
17 UNBILLED REVENUE -8,814 -1 71 ;000 0.0194
18 WYOMING
19 05GNS28025-GEN SVC -9 -653 0.0726
20 05GNSVO025-WY GEN SRVC 21,657 1,642,401 1,143 18,948 0.0758
21 05GNSVO028-GEN SRVC>15 kW 2739549 18,235,853 462 592,097 0.0667
22 05GNSVO25F-GEN SRVC-FL RA 21 2,802 6 3,500 0.1334
23 05LGSVO046-WY LRG GEN 1,609,697 90,489,330 54 29,809,204 0.0562
24 05LGSVO46M-WY LRG GEN 112,857 6,100,642 2 56,428,500 0.0541
25 05LGSVO48M-TOU>1000kW MAN 1,284,140 60,438,382 2 642,070 9000 0.0471
26 05LGSVO48T-LRG GENSRV TIM 1,349,911 64,100,080 10 134,991,100 0.0475
27 05LNX00100-LINE EXT 60% G 46,441
28 05LNX00102-LINE EXT 80% G 253,102
21 05LNX00105-CNTRCT $ MIN G 43,462
30 05LNX00I09-REF/NREF ADV+ 206,298
31 050ALT015N-OUTDARLGTSR 85 11,495 44 1,932 0.1352
32 05PRSVO33M-PART SERV REQ 834,631 45,495,832 5 166,926,200 0.0545
33 05RFNDCENT-CENTRALIA RFND 9,264
34 05UPPL000N-BASE SCH FALL 3,289
35 REVENUE ADJ-DEFERRED NPC -2,687,500
36 REV. ACCOUNTING ADJ. -38,480
37 SMUD REVENUE IMPUTATIONS 423,320
38 05LNX00300-LINE EXT 80% 29,250
39 O5LNX0031 1-LINE EXT 80% 24,552
40 UNBILLED REVENUE 31,489 4,914,000 0.1561
Ti TOTAL Billed 54,246,323 4,091,383,354 1,742,22C 31,136 0.075
421 Total Unbilled Rev.(See Instr. 6) 1 60,54: 31,358,500 _ 1 0.518(
43 TOTAL 54,306,861 4,122,741,854 1,742,221 31,171 0.075c
FERC FORM NO. I (ED. 12-95) Page 304.13
Name of Respondent
PaciflCorp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and I itle ot Kate schedule
(a)
MWI1 Sold
(b)
Revenue
(c)
Average Number
of C1sdtmers
KWh ot sales
Per ?Lstomer
KvnIe Per h old
1 05GNSVO025-WY GEN SVC 4,100 331,493 297 13,805 0.0809
2 05GNSVO028-GEN SVC>15 kW 36,600 2,508,450 66 554,545 0.0685
3 05GNSV028M-GEN SVC>15 kW 5,747 319,762 4 1,436,750 0.0556
4 05LGSVO046-WY LRG GEN SRV 26,050 1,622,793 3 8,683,333 0.0623
5 05LGSVO48M-TOU>1000kW MAN 284,131 13,134,121 3 94,710,333 0.0462
6 05LGSVO48T-LRG GENSRV 1,120,092 54,148,346 10 112,009,200 0.0483
7 05LNX00102-LINE EXT 80% G 6,096
8 05LNX00109-REF/NREF ADV + 652,620
9 05PRSV033M-PART SERV REQ 109,250 5,486,597 3 36,416,667 0.0502
10 090ALT207N-SECURITYAR 5 1,048 3 1,667 0.2096
11 UNBILLED REVENUE 2,477 456,000 0.1841
12 LESS MULTIPLE BILLINGS -989
13
14 TOTAL INDUSTRIAL SALES 20,041,331 1,042,747,140 10,616 1,887,842 0.0520
15
16 IRRIGATION SALES
17 CALIFORNIA
18 06APSVO020-AG PMP SRVC 59,227 7,099,551 1,372 43,168 0.1199
19 O6LGSVO48T-LRG GEN SERV 2,272 207,024 1 2,272,000 0.0911
20 06LNX00102-LINE EXT 80% G 737
21 06LNX00I03-LINE EXT 80% G 4,085
22 06LNX0011O-REF/NREF ADV + 36,328
23 96LNX00310-IRG 80% ANN 1,631
24 06LNX00312-CA IRG LINE EXT 1,189
25 06USBROO20-KLAM IRG ONPRJ 21,872 2,953,055 658 33,240 0.1350
26 06LNX001 09-REF/NREF ADV + 200
27 IRR DEMAND CHG ACCR 3,800
28 IRRIGATION UNBILLED 32 3,000 0.0938
29 REV. ACCOUNTING ADJ. -73,869
30 IDAHO
31 07APSA01OL-IRG & Pump Large 476,465 38,093,923 3,547 134,329 0.0800
32 07APSA01OS-BPA-IRG & PUMP -4
33 07APSA01OS-IRG & Pump Small 4,920 494,033 475 10,358 0.1004
34 07APSAL1OX-IRG & PUMP-Large 33,664 2,822,897 493 68,284 0.0839
35 07APSAS1OX-IRG & PUMP-Small 1,529 161,155 166 9,211 0.1054
36 07APSVCNLL-LRG LOAD CANAL 25,099 1,821,971 78 321,782 0.0726
37 07APSVCNLS-SML LOAD CANAL 129 14,582 18 7,167 0.1130
38 07LNX00015-ANNUAL 80% 6,768
39 O7LNX0004O-ADV+REFCHG+80% 178,482
40 07LNX00310 80% ANN GTY 176
TOTAL Billed 54,246,32q 4,091,383,354 1,742,22( 31,131 0.075
42 Total Unbilled Rev.(See Instr. 6) 60,54 31,358,500 ( I 0.518(
43 TOTAL 54,306,861 4,122,741,854 1,742,221 31,171 0.075I
FERC FORM NO. 1 (ED. 12-95) Page 304.14
Name of Respondent
PacifiCorp
This Re ort Is: (1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 20111Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and 1 itle ot Kate scheaule
(a)
MWfl Sold
(b)
Revenue
(c)
Average Number
of CLsjrmers
KWh ot Sales Per Customer KnIl.e Per hoId
I 07LNX00312 -ID LINE EXT 27,008
2 07APSN0IOL-ID LG IRR & PUMP 3,680 328,138 47 78,298 0.0892
3 07APSNO1OL-BPA-ID LG IRR 3 PH -9
41 07APSNOIOS-IRR SMALL 3PHASE 318 29,021 22 14,455 0.0913
5 07APSNS1OX-IRR SMALL 3PHA 3 724 1 3,000 0.2413
6 IRRIGATION BPA BAL ACCT -778,726
7 UNBILLED REV - IRRIGATION -91 -6,000 0.0659
8 OREGON
9 01APSVO04I-AG PMP SRVC BP 2,083,375 4,725
10 01APSVO041-BPA-AG PMP SRVC -191,561
11 01APSVO41L-OR Pumping Serv 2,801,862 1,023
12 01APSVO4IL-BPA-OR Pumping -298,727
13 0IAPSVO41T-BPA- AGR PUMP SRV -2,662
14 0IAPSVO41TAGR PUMP SRV-TOU 28,900 59
15 0IAPSVO41X-AG PMP SRVC 85,514 244
16101 APSV41 XL-OR Pump Srv no BPA 235,513 54
17101 BPADEBIT-BPA ADJUST FEE 34,645
1 113,183 5,924,955 0.0523
19 01 COSTOO48-01 LGSVOO48 7,400 363,700 0.0491
20 01COSTS028 OR GEN SERV 297 16,271 0.0548
21 01GNSVO028 OR GEN SRV>30 kW 11,241 3
22 01HABIT041-01APSVO041 AG PMP 5 256 0.0512
23 01 LGSB0048-BPA-LG GEN -34,625
24101 LGSB0048-LG GEN 84,551 1
25 01 LNX001 03-LINE EXT 80% G 29,317
26 01LNX00109-REF/NREF ADV + 10,182
27 01LNX0011O-REF/NREF ADV + 165,779
28 O1LNX003I0-LINE EXTENSION 9,946
29 01PTOU0041-01APSVO041 AG PMP 588 28,667 0.0488
30101 RENEW041 -01 APSVO041 AG 96 5,031 0.0524
31 01SLX00005-KLAMATH FALLS 340,123
32 0ISLX00013-K FALLS IRG MI 16,183
33 01SLX00014-K FALLS IRG MI 128
34 O1STDAYO41-Daily Standard Offer 114 6,717 0.0589
35 01 USBGV033-KLAMATH IRG TOU -44
36 O1USBOF033-KLAMATH BASIN 38,584 1,818,716 628 61,439 0.0471
37 01 USBOFO33-BPA-KLAMATH -159,573
38 O1USBONO33-KLAMATH BASIN 48,112 2,141,154 1,359 35,403 0.0445
39 01 USBONO33-BPA-KLAMATH -197,000
40 01 V1R331 36-OR VOL INCENT USB 613 27,244 11 55,727 0.0444
TOTAL Billed 54,246,323 4,091,383,354 1,742,220 31,136 0.075
42 Total Unbilled Rev.(See lnstr. 6) 60,543 31,358,500 _ _______________I 05180
43 TOTAL 54,306,86 4,122,741,852 1,742,22 31,171 0.075t
FERC FORM NO. 1 (ED. 12-95) Page 304.15
Name of Respondent
PaciliCorp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and I itie ot Fate schedule
(a)
MWfl Sold
(b)
Revenue
(c)
Average Number
of Ciomers
KWh ot Sales Per Customer vnue Per Kwh Sold
1 01V1R33136-BPA-OR VOL INCENT -2,515
201 V1R41136-OR VOL INCENTAGRI 3,300 2
01V1R41136-BPA-OR VOL INCENT -297
4j 301 461-IRR DEMAND CHG 200
5 O1USBGV033-IRG TOU W/O BPA 2,175 69,806 9 241,667 0,0321
6 IRRIGATION BPA BAL ACCT 228,908
7 IRRIGATION UNBILLED 46 3,000 0.0652
8 01LNX00312-OR IRG LINE EXT 22,124
9 01NMT33135-OR NET 39 1,757 2 19,500 0.0451
10 01NMT33135-BPA-OR NET -163
11 01NMT41135-BPA-NETMTRAG 1,050 3
12 OR GAIN ON SALE OF ASSET 839
13 OR Irrigation - BPA adjustment 21,670
14 OR SB 408 RECOVERY 215,595
15 OR SB 838 RECOVERY 168
16 REV. ACCOUNTING ADJ. -29,901
17 UTAH
18 08APSVO010-IRR & SOIL DRA 156,284 10,052,314 2,718 57,500 0.0643
19 O8APSV1ONS-Irg Soil Drain Pump 18,547 1,119,632 118 157,178 0.0604
20 O8LNX00002-MTHLY 80% GUAR 594
21 08LNX00004-ANNUAL 80%GUAR 9,058
22 08LNX00014-80% MIN MNTHLY 1,746
23 08LNX0001 7-ADV/REF&80%ANN 179,401
24 08LNX00310-IRR 80% ANNUAL 12,103
25 08LNX00312 UT IRG LINE EXT 8,075
26 08NMT10135-UT IRR_SOIL DRNG 12 711 1 12,000 0.0593
27 REV. ACCOUNTING ADJ. 169,168
28 UNBILLED REV - IRRIGATION 66 3,000 0.0455
29 WASHINGTON
30 O2APSVOO4O-WA AG PMP SRVC 140,895 11,481,265 4,848 29,063 0.0815
31 02APSVO040-BPA-WA AG PMP -622,998
32 02APSVO40X-WA AG PMP SRVC 8,902 661,241 405 21,980 0.0743
33 02BPADEBIT-BPA ADJUST FEE 24,238
34 02LNX00103-LINE EXT 80% G 4,534
35 O2LNXOO1O5-CNTRCT $ MIN G 72
36 O2LNXOO11O-REF/NREF ADV + 159,591
37 02LNX00310-IRG 80% ANN 1,429
38 02LNX003I 1-LINE EXT 80% 841
39 02LNX00312-WA IRG LINE EXT 18,935
40 IRR DEMAND CHG ACCR 500
TOTAL Billed 54,246,324 4,091,383,354 1,742,221 31,131 0.075
42 Total Unbilled Rev.(See Instr. 6) 60,54 31,358,500 _____I ________________ 0.5180
43 TOTAL 54,306,861 4,122,741,854 1,742,221 31,171 0.0751
FERC FORM NO. I (ED. 12-95) Page 304.16
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)ff1A Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
No.
Line and I itle of Fate schedule
(a)
MWI1 Sold
(b)
Revenue
(c)
Average Number
of CLsdtrmers
KWh ot Sales
Per ?tomer
I'tQvQntje rer Kwh bold
1 REV. ACCOUNTING ADJ. -348,912
2 WA - CHEHALIS DEFERRAL -120,000
3 IRRIGATION BPA BAL ACCT 3,846
4 IRRIGATION UNBILLED 282 17,000 0.0603
5 WYOMING
6 05APS00040-AG PUMPING SVC 18,704 1,406,349 638 29,317 0.0752
7 05LNX001 1 0-REF/NREF ADV + 55,039
8 O5LNXOO1 03-LINE EXT 80% G 8,033
9 05LNX00310 WY IRG LINE EXT 330
10 IRRIGATION UNBILLED 15 1,000 0.0667
11 REV ACCOUNTING ADJ -233
12 05AP500040-AG PUMPING SVC 51 3,477 1 51,000 0.0682
13 O5LNXOO1O3-LINE EXT 80% GTY 1,414
14 05LNX001 10-REF/NREF ADV + 18,102
15 05LNX00312-WY IRRG LINE EXT 1,283
16 09APSV0210-IRR & SOIL DRA 3,277 277,014 73 44,890 0.0845
17 LESS MULTIPLE BILLINGS -724
18
19 TOTAL IRRIGATION SALES 1,187,406 93,961,381 23,079 51,450 0.0791
20
21 PUBLIC STREET & HWY LIGHTING
22 CALIFORNIA
23 O6CUSLO53F-SPECIAL CUST 0 1,455 208,491 116 12,543 0.1433
24 O6CUSLO58F-CUST OWND STR 242 38,789 23 10,522 0.1603
25 06HPSV0051-F1l PRESSURE 50 697 183,229 78 8,936 0.2629
26 REV.ACCOUNTING ADJ. -5,915
27 UNBILLED REVENUE 48 9,000 0.1875
28 IDAHO
29 O7GNSVO23S-ID TRAFFIC SIGNALS 165 17,308 25 6,600 0.1049
30 07SLC000I1-STR LGT CO-OWN 93 41,955 29 3,207 0.4511
31 07SLCU012E-ENGYSTR 310 33,888 19 16,316 0.1093
32 07SLCU012F-FULL MNT STR 1,920 370,467 281 6,833 0.1930
33 07SLCU012P-PART MNT STR LGT 195 27,710 16 12,188 0.1421
34 UNBILLED REVENUE 41 7,000 0.1707
351 OREGON
36 0ICOSLOO52-STR LGT SRVC C 609 92,754 50 12,180 0.1523
37 01CUSL0053-CUS-OWNED MTRD 822 62,902 71 11,577 0.0765
38 01CUSL053E-STR LGT SVC 8,650 663,079 168 51,488 0.0767
39 01CUSL053F-STR LGT SRVC C 201 22,949 17 11,824 0.1142
40 O1HPSVOO51-HI PRESSURE SO 18,737 3,916,753 695 26,960 0.2090
41 TOTAL Billed 54,246,323 4,091,383,354 1,742,220 31,136 0.075
42 Total Unbilled Rev.(See lnstr. 6) 60,54 31,358,5001 _______________I 0.5181
43 TOTAL 54,306,86 4,122,741,854 1,742,22 31,171 0.0751
FERC FORM NO. I (ED. 12-95) Page 304.17
Name of Respondent
PaciflCorp
This Re ort Is:
(1)An Original
(2)VIA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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.
I Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
aiie
No.
Number and 1 We ot Kate schedule
(a)
MWI1 Sold
(b)
Revenue
(c)
Average Number of C1sj)omers KWh ot Sales Per Customer KynLe rer h od
1 01LEDSLO55-OR LED PILOT 5 1,395 4 1,250 0.2790
2 0IMVSLOO50-MERC VAPSTR LG 9,038 1,230,796 250 36,152 0.1362
3 01OALT014N-OUTD AR LGT NR 1 223 3 333 0.2230
4j 01OALT014N-BPA-OUTD AR LGT -5
5 0IOALT015N-OUTD AR LGT NR 15 2,363 6 2,500 0.1575
6 010ALTB15N-OR OUTD LGT NR 1 234 2 500 0.2340
7 01OALTBI5N-W/BPA-OR OUTD -5
8 OR GAIN ON SALE OF ASSET 387
9. OR SB 408 RECOVERY 40,424
101 OR SB 838 RECOVERY -1,215
11 REV. ACCOUNTING ADJ. -13,801
12 UNBILLED REVENUE -175 -13,000 0.0743
13 UTAH
14 08CFR00012-STR LGTS (CONV 54
15 O8CFR00051 -MTH FAC SRVCHG 4,529
16 08CFR00062-STREET LIGHTS 79
17 080ALT007N-SECURITYAR LG 22 5,694 13 1,692 0.2588
18 08TOSS015F-TRAFFIC SIG NM 1,007 90,508 123 8,187 0.0899
19 08SLC00011-STR LGT CO-OWN 18,758 5,585,069 919 20,411 0.2977
20 O8TOSSOO15-TRAF & OTHERS 2,854 286,876 1,487 1,919 0.1005
21 08MONLOO15-MTR OUTDONIGHT 862 65,995 59 14,610 0.0766
22 08SLCU012P-STR LGT CUST-O 5,488 677,415 239 22,962 0.1234
23 08SLCU012F-STR LGT CUST-O 2,251 306,573 113 19,920 0.1362
24 08SLCUO12E-DECOR CUST-OWN 47,992 3,120,862 457 105,015 0.0650
25 08TH1K0077-STR LIGHT SPEC 141 17,277 1 141,000 0.1225
26 REV. ACCOUNTING ADJ. 12,501
27 UNBILLED REVENUE -485 -55,000 0.1134
28 WASHINGTON
29 02CFR0001 2-STR LGTS (CONV 90
30 02CO5L0052-WA STIR LGT SRV 324 52,183 18 18,000 0.1611
31 02CUSLO53F-WA STR LGT SRV 3,528 249,808 109 32,367 0.0708
32 02CUSLO53M-WA STIR LGT SRV 1,149 80,217 96 11,969 0.0698
33 02HPSVO051-WA HI PRESSURE 3,314 665,246 155 21,381 0.2007
34 02MVSLOO57-WA MERC VAPSTR 1,964 241,205 41 47,902 0.1228
35 WA - CHEHALIS DEFERRAL -30,000
361 REV. ACCOUNTING ADJ. -22,054
37 UNBILLED REVENUE -26 -9,000 0.3462
38 WYOMING
39 05COSLOO57-CO-OWND STR LG 290 58,992 18 16,111 0.2034
40 05CUSLO58M-CUST OWND STR 81 5,140 11 7,364 0.0635
41 TOTAL Billed 54,246,32A 4,091,383,354 1,742,221 31,13k 0.075
42 Total Unbilled Rev.(See lnstr. 6) 60,54 31,358,500 _ ( 0.518
43 TOTAL 54,306,86 4,122,741,854 1,742,22' 31,171 0.075
FERC FORM NO. I (ED. 12-95) Page 304.18
Name of Respondent
PaciflCorp
This Re ort Is:
(1)An Original
(2)ff1A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues,' Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
No.
Line and I itle 01 Kate schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number
of C1sdIrmers
ISWh 01 Sales Per Customer
KvenIe re Wh 0 d
1 05CUSLOE58-WY CUST OWND 1,079 67,909 30 35,967 0.0629
2 05CUSLOM58-CUST OWNED 45 3,449 4 11,250 0.0766
3 05HPSV0051-Hl PRESSURE SO 4,973 1,025,677 158 31,475 0.2062
4j 05MVS00053-MERCURY VAPOR 3,805 480,826 264 14,413 0.1264
5 050ALT01 5N-OUT AR LGT SR 1
6 REV. ACCOUNTING ADJ. -587
7 UNBILLED REVENUE -15 -1,000 0.0667
8 050ALT015N-OUTD AR LGT SR 3
9 O9MONLO213-WY MTR OUTDOOR 25 1,931 1 25,000 0.0772
10 09SLCO021 1-STR LGT CO-OWN 1,481 406,275 48 30,854 0.2743
11 09SLCUP212-STRLGTCUST-0 77 11,288 9 8,556 0.1466
12 09TOSS021 3-WY TRAF & 0TH SIG 63 2,393 14 4,500 0.0380
13 UNBILLED REVENUE 217 63,000 0.2903
14 LESS MULTIPLE BILLINGS -2,496
15
16 TOTAL PUBLIC STREET & HWY 144,334 20,409,578 3,745 38,540 0.1414
17
18 OTHER SALES TO PUBLIC AUTH
19 UTAH
20 08GNSV0006-GEN SRVC-DISTR 2,188 150,625 4 547,000 0.0688
21 08GNSVO023-GEN SRVC-DISTR 38 3,533 3 12,667 0.0930
22 08GNSVO09M-MANL HIGH VOLT 380,709 17,729,560 3 126,903,000 0.0466
23 08OALT007N-SECURITY AR LG 16 4,103 2 8,000 0.2564
24 08PRSV031M-BKUP MNT&SUPPL 19,899 1,135,234 1 19,899,000 0.0570
25 REV. ACCOUNTING ADJ. 325,774
26 UNBILLED REVENUE -4,357 -43,000 0.0099
27 LESS MULTIPLE BILLIINGS -1
2
29 TOTAL OTHER SALES TO PUBLIC 398,493 19,305,829 12 33,207,750 0.0484
30
31 FORFEITED DISCOUNTS
32 CALIFORNIA
33 Late Fees 313,339
34 IDAHO
35 Late Fees 416,071
36 OREGON
37 Late Fees 3,488,530
38 UTAH
39 Late Fees 2,983,753
40 WASHINGTON
•j TOTAL Billed 54,246,321 4,091 ,383,35 1,742,22 31,13 0.075
421 Total Unbilled Rev.(See Instr. 6) 60,54: 31,358,500 _ _ 0.518
43 TOTAL 54,306,861 4,122,741,85 1,742,221 31,171 0.0751
FERC FORM NO. I (ED. 12.95) Page 304.19
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and I itle ot gate schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number
of CLtSdt?mers
KWh of Sales Per Customer venu_e Fer Kwh Sold
1 Late Fees 627,834
2 WYOMING
3 Late Fees 616,378
4
5 TOTAL FORFEITED DISCOUNTS 8,445,905
6
7 MISCELLANEOUS SERVICE REV
8 CALIFORNIA
9 O6CFR00003-MTH MAINTENANC 1,454
10 06CONNO300-CA RECONNECTIO 31,890
11 06FCBUYOUT 14,091
12 06RCHKO300-CA RET CHK CHR 13,488
13 06TAM P0300-CA TAMP & UNAU 1,200
14 O6TEMPO300-CA TEMP SRVC C 2,155
15 06XMTRTAMP-TAMPERING - 295
16 Home Comfort 826
17 IDAHO
18 07CFR00001 -MTH FAC SRVCHG 1,646
19 O7CONNO300-ID RECONNECTIO 48,340
20 07RCHKO300-ID RET CHK CF-JR 37,120
21 07TAMP0300 525
22 07TEMPOO14-TEMP SRVC CONN 10,880
23 07XMTRTAMP-TAMPERING - 80
24 Other -2,730
25 OREGON
26 01CFR00001-MTH FACILITY 5 84,712
27 01CFR00003-MTH MAINTENANC 25,964
28 01CFR00004-EMRGNCY ST&BY
29 01CFR00005-INTERMTNT 42,247
30 0ICFR00013-MTH MISC CHRG 2,284
31 01CFR00014-YRMISCCHRG 5
32 0ICONNO300-RECONNECTION C 341,110
33 01CONTSERV-OR 3RD PARTY 9,815
34 01ESSC0600 - ESS charges 3,180
35 OIFCBUYOUT-FAC CHG BUYOUT 302,961
36 01 MTRVR300-METR VERIF FEE 40
37 01RCHK0300-RETURNED CHECK 319,040
38 01 TAMPO300-TAMP & UNAUTH 15,675
39 01TEMP0300-TEMP SRVC CHRG 76,175
40 01XMTRTAMP-TAMPERING - 3,287
TOTAL Billed 54,246,32a 4,091,383,354 1,742,220. 31,136 0.0754
42 Total Unbilled Rev.(See lnstr. 6) 60,543 31,358,500 1 0.51 8(
43 TOTAL 54,306,86 4,122,741,854 1,742,22 31,171 0.075c
FERC FORM NO. 1 (ED. 12-95) Page 304.20
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
No.
Line and I we ot Rate schedule
(a)
MWh bola
(b)
Revenue
(c)
Average Number
of CLsj)omers
KWfl ot Sales Per Customer FQventLe J'er Kwh bold
1 Other -32,708
2 TAMPERING FEE 75
3UTAH
4 O8CFR00013-MTH MISC CHRG 146,885
5 08CFR00051-MTH FAC SRVCHG 93,501
6 08CFR00052-ANN FAC SVCCHG 424
7 08CFR00053-MTHLY MAINTFEE 16,913
8 08CFR00063-MTH MISC CHARG 2,401
9 08CFR00064-ANN MISC CHARG 6,660
10 08CONNO300-RECONN&DISCONN 382,195
11 08CONTSERV-3RD PARTY 0/S 280,072
12 08FCBUYOUT-FAC CHG BUYOUT 563,871
13 08METRO300-UT FEE MTR TES 60
14 O8NCONO300 -UT FEE NRES RE 6,355
15 08RCHKO300-UT RET CHK CHR 482,936
16 08RCON0001-CONNECT FEE 1,507,930
17 08TAMP0300-TAMPERING&UNAU 14,850
18 08TEMPOO14-TEMP SRVC CONN 304,125
19 O8XMTRTAMP-TAMPERING - 2,534
20 Energy Finanswer new Com 19,119
21 Other 3,692
22 08VISIT300 - UT Visit, Service Ca 235,210
23 WASHINGTON
24 02CFR00003-MTH MAINTENANC 1,320
25 02CFR00004-EMRGNCY ST&BY 5,901
26 02CFR00005-INTERMTNT SRVC 4,302
27 02CONNO300-WA RECONNECTIO 75,420
28 02RCI-lKO300-WA RET CHK CHR 63,940
29 02TAMP0300-WA TAMP & UNAU 3,075
30 02TEMP0300-WA TEMP SRVC C 17,625
31 02XMTRTAMP-TAMPERING - 637
32 Energy Finanswer new Com 1,323
33 Home Comfort 2,493
34 Other -654
35 WYOMING
36 05CFR00003-MTH MAINTENANC 1,768
37 05CFR00004-EMRGNCY ST&BY 18,953
38 05CFR00005-INTERMTNT SRVC 10,263
39 O5CFR00013-MTH MISC CHRG 3,186
40 05CONNO300-WY RECONNECTIO 69,740
1 TOTAL Billed 54,246,323 4,091,383,354 1742,220 31,136 0.075
421 Total Unbilled Rev.(See Instr. 6) 1 60,543 31,358,500 _ _ 0.5181
43 TOTAL 54,3O6,8 4,122,741,85 1,742,221 31,171 0.075
FERC FORM NO. I (ED. 12-95) Page 304.21
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)MA Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 20111Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and I tie ot Kate schedule
(a)
MWfl Sold
(b)
Revenue
(C)
Average Number
of Ctomers
KWh Ot SalesPer Customer nie rer h 0 d
1 05FCBUYOUT - FAC CHG BUYOUT 137,997
2 05RCHKO300-WY RET CHK CHR 69,540
3 05SERV0300-WY SRVC CALLS 120
4 05TAMP0300 525
5 05TEM P0300-WY TEMP SRVC C 31,450
6 Other 1,208
7 05XMTRTAMP-TAMPERING - 175
8 09CFR00005-INTERMTNT SRVC 339
9 05CONNO300-WY RECONNECTIO 11,560
10 05FCBUYOUT - FAC CHG BUYOUT 202,126
11 05RCHKO300-WY RET CHK CHR 12,300
12 05TEMP0300-WY TEMP SRVC C 1,475
13 09CFR00001 MTH FAC SRV CHG 5,067
14 09CFR00014-YR MISC CHRG 3
15 Energy Finanswer 12,000 228
16
17 TOTAL MISC SERVICE REV 6,203,507
18
19 SALES OF WATER AND WTR PWR
20 UTAH 89,567
21 WYOMING 5,306
22
23 TOTAL WATER AND WATER PWR 94,873
24
25 RENT FROM ELEC PROPERTIES
26 CALIFORNIA
27 O6CFR00006-MTH RNTAL CHRG 1,659
28 RENT REVENUE-HYDRO 200
29 RENT REVENUE-TRANSMISSION 55
30 Rent Revenue - Subleases 16,879
31 Joint use 547,446
32 IDAHO
33 O7CFR00009-YR LSE CHRG-EQ 794
34 07INVCHGOO-INVEST MNT CHG 182
35 07POLE0075-STEEL POLES US 275
36 RENT REVENUE-HYDRO 68,732
37 RENT REV-TRANSMISS 400
38 Rent Revenue - Subleases 2,216
39 Joint use 194,566
40 OREGON
41 TOTAL Billed 54,246,32q 4,091,383,354 1,742,22C 31,136 0.075
42 Total Unbilled Rev.(See lnstr. 6) 60,54 31,358,500 ______ 1 0.518
43 TOTAL 54,306,86' 4,122,741,854 1,742,22 31,171 0.075
FERC FORM NO. 1 (ED. 12-95) Page 304.22
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)LKA Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and I tie ot Rate schedule
(a)
MWI1 Sold
(b)
Revenue
(c)
Average Number
of CttsOmers
KWh ot sales Per Customer Revqnu_p Kwh Sod
1 01CFR00006-MTH RNTAL CHRG 657,955
2 OIXTRNOOI 3-RNT/LSE L&PRO 52,993
3 RENTS - COMMON 465,700
4 Rents - Non Common 125
MCI FOGWIRE REVENUE 3,352,504
6 Rent Revenue - Subleases 345,368
7 RENT REVENUE-CSS NON FLT -52,993
I RENT REVENUE-HYDRO 32,722
9 RENT REV-TRANSMISS 239,908
10 RENT REV-DISTRIBUT 56,572
11 RENT REV-GEN(COMM) 43,100
12 Joint use 4,453,879
13 UTAH
14 08CFR00056-MTH EQUIP RENT 33
15 08CFR00058-MTH EQUIP LEAS 750,028
16 08INVCHGON-INVEST MNT CHG 4,447
17 08INVCHGOR-INVEST MNT CHG 271
18 08LOOP014N-TEMP SERV CONN 78
19 08P0LE0075-STEEL POLES US 56,960
20 RENTS - COMMON -1,736
21 Rents -Non Common 16,440
22 RENT REVENUE-STEAM 102,122
23 RENT REVENUE-HYDRO 96,718
241 RENT REV-TRANSMISS 994,104
25 RENT REV-DISTRIBUT 428,828
26 RENT REV-GEN(COMM) -5,374
27 Rent Revenue - Subleases 2,556,839
28 Affiliated Rent Revenue 11,057
29 Joint use 2,227,437
30 WASHINGTON
31 02CFR00001-MTH FACILITY S 2,104
32 02CFR00006-MTH RNTAL CHRG 30,308
33 RENT REVENUE-HYDRO 608,308
34 RENT REV-DISTRIBUT 18,876
35 RENT REV-GEN(COMM) 32,674
36 RENT REV-TRANSMISS 16,089
37 Rent Revenue - Subleases 46,811
38 Joint use 1,057,961
39 WYOMING
40 05CFR0000I-MTI-I FACILITY S 11,521
411 TOTAL Billed 54,246,323. 4,091,383,354 1,742,22C 31,136 0.075
421 Total tJnbilled Rev.(See Instr. 6) 60,54 31,358,500 C C 0.5181
43 TOTAL 54,306,861 4,122,741,854 1,742,221 31,171 0.0759
FERC FORM NO. I (ED. 12-95) Page 304.23
Name of Respondent
PacifiCorp
This Report Is: (1)LjAn Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and I itle ot late schedule
(a)
MWI1 Sold
(b)
Revenue
(c)
Average Number
of CLsjrmers
lc.Wfl ot Sates Per cstomer FenIe Per K h old
1 05CFR00006-MTH RNTAL CHRG 2,482
2 RENT REVENUE-STEAM 161,219
3 RENT REV-HYDRO 39,304
4 RENT REV-TRANSMISS 250
5 RENT REV-DISTRIBUT 21,502
6 RENT REV-GEN(COMM) 8,726
7 Rent Revenue - Subleases 17,716
8 Joint use 358,139
9 09POLE0075-STEEL POLES US 19,230
10 RENT REVENUE-STEAM 7,710
11
12 TOTAL RENT FROM ELEC PROP 20,180,422
13
14 WIND BASED ANCILLARY SVC 8,045,284
15 OTHER ELEC ESTIMATE 83,442
16 RENEWABLE ENERGY CREDIT 24,633,026
17 NON-WHEELING SYSTEM 9,117,901
18 Other Elec (exclud Wheel) 1,600
19 RENEWABLE ENGY CR AMORT 12,591,648
20 CALIFORNIA
21 ALL BLUE SKY RES 31,968
22 3RD PARTY TRANS O&M 47,850
23 DSM REV-CA SBC OFF 1,785,661
24 Fish, Wildlife, Recr 7,281
25 IDAHO
26 ALL BLUE SKY RES 41,542
27 DSM REV-ID SBC 5,356,975
28 3RD PARTY TRANS O&M 98,043
29 OREGON
30 ALL BLUE SKY RES 373,485
31 DSM REV-OR ECC 22,316,839
32 3RD PARTY TRANS 193,660
33 Other Elec (exclud Wheel) 1244,655
34 Other Elec DSR carry chrg 169,156
35 UTAH
36 ALL BLUE SKY RES 1,818,926
37 O8XTRNOO11-SALE ORDERS 8,602
38 M&S INVENTORY REVENUE 264,638
39 ELEC INC-OTHR 249,497
40 FLYASH SALES 2,237,553
41 TOTAL Billed 54,246,32: 4,091,383,354 1,742,220 31,136 0.075
421 Total Unbilled Rev.(See lnstr. 6) 60,54 31,358,500 I 0.5181
43 TOTAL 54,306,861 4,122,741,854 1,742,221 31,1711 0.0751
FERC FORM NO. I (ED. 12-95) Page 304.24
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)EKJA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in"Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3.Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4.The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5.For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6.Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
Number and Titie ot Kate schedule
(a)
MWh sold
(b)
Revenue
(c)
Average Number
of C1sdtrmers
KWh ot sales Per Customer Fevnu_e ?er Kwh Sold
1 3RD PARTY TRANS 287,415
2 DSM REV-UT SBC OFFSET 49,303,455
3 Fish, Wildlife, Recr 2,380
4 WASHINGTON
5 ALL BLUE SKY RES 99,779
6 3RD PARTY TRANS 3,370
7 DSM REV-WA SBC 8,883,682
8 Fish, Wildlife, Recr 6,483
9 Wash Colstrip 3 -52,188
10 WYOMING
11 ALL BLUE SKY RES 116,944
12 M&S INVENTORY REVENUE 9,420
13 O5XTRNOOII-SALES ORDERS INV 964
14 ELEC INC-OTHER 17
15 FLYASH SALES 874,779
16 WY Regulatory Recovery Fee 227,739
17 3RD PARTY TRANS 53,819
18 DSM REVENUE-WY SBC-CAT 1 1,787,088
19 DSM REVENUE-WY SBC-CAT 2 897,775
20 DSM REVENUE-WY SBC-CAT 3 1,179,265
21 FLYASH SALES 22,732
22 DSM REVENUE-WY SBC-CAT 1 -412
23 DSM REVENUE-WY SBC-CAT 2 606
24 DSM REVENUE -WY SBC-CAT 3 24,201
25
26 TOTAL OTHER ELEC REVENUE 154,448,545
27
28
29
30
31
32
33
34
35
36
37
38
39
40
11 TOTAL Billed 54,246,323 4,091 ,383,35 1,742,221 31,13 0.075
42 Total Unbilled Rev.(See Instr. 6) 60,54 31,358,500 I 0.51 80
43 TOTAL 54,306,861 4,122,741,854 1,742,221 31,171 0.0751
FERC FORM NO. I (ED. 12-95) Page 304.25
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 304.15 Line No.: 18 Column: a
01COST0041 - 01APSVO041 - 01APSVO41X AG PMP
IFERC FORM NO. I (ED. 12-87) 1 Page 450.1 1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)LJAn Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 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 Averag Actual Demand (MW)
Average
Monthly NCI5 Deman Average Monthly CP9Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (C) (d) (e) (f)
1 Requirement Sales
2 Brigham City Corporation RQ T-12 18 17 16
3 Deaver, Town of RQ T-4 0.2 0.1 0.1
4 Helper City RQ T-6 1 1 1
5 1 Helper CityAnnex 1RQ T-6 0.7 0.6 0.6
6 RQ T-6 0.2 0.2 0.2
7 RQ T-6 1 1 1
I Portland General Electric Company •RQ 147 NA NA NA
9 Price City Corporation RQ T-12 25 12 11
10 Accrual RQ NA NA NA NA
11
12 Nonrequirement Sales
13 Arizona Pubc Service Company SF T-12 NA NA NA
14 Avista Corporation SF T-12 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCo rr' (1)An Original (Mo, Da, Yr) End of 2011 /Q4
(2)EjA Resubmission 06/28/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (I) (k) -
95,952 2,060,955 2,329,498 4,653,163 2
799 12,695 14,318 27,013 3
6,096 116,457 107,843 224,300 4
3,822 71,502 67,607 139,109 5
1,139 18,842 19,846 38,688 6
9,149 138,555 159,374 297,929 7
11,076 1,012,660 1,017,392 8
71,652 1,417,928 1,730,495 3,310,374 9
2,763 -9,544 10
I -
12
79,287 2,739,683 2,739,683 13
51,218 1,379,006 1,379,006 14
202,448 3,836,934 5,441,641 419,849 9,698,424
10,564,249 16,086,186 500,177,279 -174,169,520 342,093,945
10,766,697 19,923,120 505,618,920 -173,749,671 351,792,369
FERC FORM NO. I (ED. 12-90) Page 311
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/04 (2)A Resubmission 06/28/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 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 Averag Actual Demand (MW)
Average
Monthly NC Deman Average Monthly CPMDemand No. (Footnote Affiliations) Classill-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Avista Corporation SF T-13 NA NA NA
2 BNP Paribas Energy Trading GP SF T-12 NA NA NA
3 BP Energy Company SF T-12 NA NA NA
4 Barclays Bank PLC T-12 NA NA NA
5 Barclays Bank PLC SF T-12 NA NA NA
6 Basin Electric Power Cooperative SF T-1 1 NA NA NA
7 Basin Electric Power Cooperative SF T-12 NA NA NA
8 Black Hills Power, Inc. 441 50 55 50
9 Black Hills Power, Inc. T-12 NA NA NA
10 Black Hills Power, Inc. SF T-11 NA NA NA
11 Black Hills Power, Inc. SF T-12 NA NA NA
12 Black Hills Wyoming, Inc. SF T-12 NA NA NA
13 Bonneville Power Administration 519 NA NA NA
14 Bonneville Power Administration 1-11 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 310.1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr) End of 2011/04
2) A Resubmission 06/28/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (U. Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQINon-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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (j) (k) -
64 2,016 1
8,800 404,8001 404,800 2
179,960 5,079,222 5,079,222 3
9 _____________________ 722 4
312,230 13,946,2371 13,946,237 5
51 1 1,257 6
24,270 847,8821 847,882 7
330,354 7,374,306 5,131,1021 12,505,408 8
760 24,145 24,145 9
3 15610
220,717 5,694,0961 5,694,096 11
67 2,305 2,305 12
144,770 13
-938 -30,147 14
202,448 3,836,934 5,441,641 419,849 9,698,424
10,564,249 16,086,186 500,177,279 -174,169,520 342,093,945
10,766,697 19,923,120 505,618,920 -173,749,671 351,792,369 -
FERC FORM NO. 1 (ED. 12-90) Page 311.1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)IZ]A Resubmission 06/28/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 reliability of designated unit.
lU - 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 Average Actual Demand (MW)
Average
Monthly NCP Deman Average
Monthly CP1)emand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (c) (d) (e) (f)
1 Bonneville Power Administration 368 NA NA NA
2 Bonneville Power Administration T-1 1 NA NA NA
3 Bonneville Power Administration 'LU 519 NA NA NA
4 Bonneville Power Administration SF T-1 1 NA NA NA
5 Bonneville Power Administration SF T-12 NA NA NA
6 1 Bonneville Power Administration SF T-1 3 NA NA NA
7 SF T-13 NA NA NA
8 T-12 NA NA NA
9 Califomia Independent System Operator 1SF T-12 NA NA NA
10 Cargill Power Markets, LLC T-12 NA NA NA
11 Cargill Power Markets, LLC SF T-1 1 NA NA NA
12 Cargill Power Markets, LLC SF T-12 NA NA NA
13 Citigroup Energy Inc. T-12 NA NA NA
14 Citigroup Energy Inc. IF T-12 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.2
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp (1)IJAn Original (Mo, Da, Yr) End of 2011/04
(2)A Resubmission 06/28/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature 01
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (U. Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) U) (k)
2,199 55,794 1
14,629 396,867 2
40,125 2924,7111 1 2,924,711 3
1,374 39,310 4
96,686 2,139,5701 2,139,570 5
110 2,916 6
2 687
275 27,531 8
774,061 20,312,3631 I 20,312,363 9
728 17,320 10
9,225 241,297 11
708,776 23,700,7791 1 23,700,779 12
835 33,424 13
29,939 2,047,828 2,047,828 14
202,448 3,836,934 5,441,641 419,849 9,698,424
10,564,249 16,086,186 500,177,279 -174,169,520 342,093,945 -
10,766,697 19,923,120 505,618,920 -173,749,671 351,792,369
FERC FORM NO. 1 (ED. 12-90) Page 311.2
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term' means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 reliability of designated unit.
lU - 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 Averag Actual Demand (MW)
Averacle
Monthly NCR Demanc Average
Monthly No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (C) (d) (e) (f)
1 Citigroup Energy Inc. SF 1-12 NA NA NA
2 City of Anaheim SF 1-12 NA NA NA
3 City of Burbank SF T-1 2 NA NA NA
4 City of Glendale SF 1-12 NA NA NA
5 City of Hurricane 1-12 NA NA NA
6 City of Redding SF T-12 NA NA NA
7 City of Santa Clara SF T-1 2 NA NA NA
8 Clatskanie People's Utility District SF T-12 NA NA NA
9 Colorado River Commission of Nevada SF 1-12 NA NA NA
10 3F
SF
T-1 1 NA NA NA
11 Constellation Energy Commodities Group T-1 1 NA NA NA
12 Constellation Energy Commodities Group SF T-12 NA NA NA
13 DB Energy Trading LLC T-12 NA NA NA
14 DB Energy Trading LLC SF • T-1 2 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 Re ort Is: Date of Report Year/Period of Report
PacifiCo (1)LJAn Original (Mo, Da, Yr) End of 2011/Q4
(2)jA Resubmission 06/28/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (j) (k) -
1,993,699 64,910,506 64,910,506 1
14,614 487,542 487,542 2
53,578 1,440,678 1,440,678 3
11,800 378,856 378,856 4
216 16,200 16,200 5
27,169 636,792 636,792 6
5,269 38,805 38,805 7
508 14,2051 14,205 8
56,357 1,990,7561 1,990,756 9
5,106 142,791 10
35 1,209 11
544,922 17,214,738' 17,214,738 12
10 224 13
325,446 11,136,767 11,136,767 14
202,448 3,836,934 5,441,641 419,849 9,698,424
10,564,249 16,086,186 500,177,279 -174,169,520 342,093,945 -
10,766,697 19,923,120 505,618,920 -173,749,671 351,792,369
FERC FORM NO. I (ED. 12-90) Page 311.3
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PaciliCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the suppliers service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 reliability of designated unit.
lU - 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 AveraQ! Actual Demand (MW)
Average Monthly NCP Demanc Average Monthly CVDemand No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number
Monthly Billing
Demand (MW) - (a) (b) (6) (d) (e) (0
1 = SF 1-11 NA NA NA
2 EDF Trading North America, LLC SF 1-1 1 NA NA NA
3 EDF Trading North America, LLC SF 1-12 NA NA NA
4 El Paso Electric Company SF T-12 NA NA NA
5 Eugene Water & Electric Board SF 1-1 1 NA NA NA
6 Eugene Water & Electric Board SF T-12 NA NA NA
7 Exelon Power Team SF 1-12 NA NA NA
8 Gila River Power LLC SF T-12 NA NA NA
9 Iberdrola Renewables, Inc. T-1 I NA NA NA
10 lberdrola Renewables, Inc. SF T-11 NA NA NA
11 lberdrola Renewables, Inc. SF T-12 NA NA NA
12 Idaho Power Company T-1 1 NA NA NA
13 Idaho Power Company SF T-1 1 NA NA NA
14 Idaho Power Company SF T-12 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.4
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp (1)DAn Original (Mo, Da, Yr) End of 2011/Q4
(2)MA Resubmission 06/28/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (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 ROJN0n-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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) U) (k) -
43 748 1
32 1,180 2
258,033 8,602,2101 I 8,602,210 3
38,784 1,105,489 1,105,489 4
500 16,188 5
15,419 379,325 379,325 6
4,800 167,500 167,500 7
31,276 862,3941 862,394 8
3,451 88,838 9
431 9,554 10
336,117 9,030,5321 I 9,030,532 11
397 12,879 12
3,998 126,259 13
76,358 1,625,4181 1 1,625,418 14
202,448 3,836,934 5,441,641 419,849 9,698,424
10,564,249 16,086,186 500,177,279 -174,169,520 342,093,945 -
10,766,697 19,923,120 505,618,920 -173,749,671 351,792,369
FERC FORM NO. I (ED. 12-90) Page 311.4
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PaciflCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)MA Resubmission 06/28/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the suppliers service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 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 Average Actual Demand (MW)
Average
Monthly NCR Demanc Averaae Monthly CP1)emand No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I Idaho Power Company SF T-1 3 NA NA NA
2 Intermountain Renewable Power, LLC 1-11 NA NA NA
3 J. Aron & Company SF T-12 NA NA NA
4 J.P. Morgan Ventures Energy Corporation SF 1-11 NA NA NA
5 J.P. Morgan Ventures Energy Corporation SF 1-12 NA NA NA
6 301 NA NA NA
7 Los Angeles Dept. of Water & Power SF 1-11 NA NA NA
8 Los Angeles Dept. of Water & Power SF T-12 NA NA NA
9 Macquarie Energy LLC SF T-1 1 NA NA NA
10 Macquarie Energy LLC SF T-12 NA NA NA
11 Modesto irrigation District SF T-12 NA NA NA
12 Morgan Stanley Capital Group, Inc. 1-12 NA NA NA
13 Morgan Stanley Capital Group, Inc. SF T-11 NA NA NA
14 Morgan Stanley Capital Group, Inc. SF 1-12 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.5
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (I) (k) -
218 6,526 1
2,235 58,346 2
135,999 4,826,7461 4,826,746 3
3,921 93,915 4
101,853 2,425,7971 2,425,797 5
571,555 27,759,5981 27,759,598 6
5,312 126,308 7
56,891 1,171,5011 1,171,501 8
2 709
164,735 4,548,3931 4,548,393 10
45,079 1,509,2031 1,509,203 11
704 28,228 12
11,322 294,514 13
1,922,634 58,345,5181 58,345,518 14
202,448 3,836,934 5,441,641 419,849 9,698,424
10,564,249 16,086,186 500,177,279 -174,169,520 342,093,945
10,766,697 19,923,120 505,618,920 -173,749,671 351,792,369
FERC FORM NO. 1 (ED. 12-90) Page 311.5
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)fA Resubmission 06/28/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 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 Averag Actual Demand (MW)
Average
Monthly NC P Demanc Averaqe Monthly CP'Demand No. N . (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Billing Monthly
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Municipal Energy Agency of Nebraska SF T-1 I NA NA NA
2 Municipal Energy Agency of Nebraska SF T-12 NA NA NA
3 j NaturEner Power Watch, LLC SF T-13 NA NA NA
4 Nevada Power Company IF T-12 NA NA NA
5 Nevada Power Company 1SF T-1 I NA NA NA
6 NextEra Energy Power Marketing, LLC T-1 1 NA NA NA
7 NextEra Energy Power Marketing, LLC T-1 1 NA NA NA
8 NextEra Energy Power Marketing, LLC 1SF T-1 1 NA NA NA
9 NextEra Energy Power Marketing, LLC SF T-12 NA NA NA
10 NorthWestern Corporation SF T-1 3 NA NA NA
11 Northern California Power Agency SF T-12 NA NA NA
12 PPL EnergyPlus, LLC SF T-12 NA NA NA
13 PPL Montana, LLC SF T-1I NA NA NA
14 Pacific Gas & Electric Company IF T-12 N/ NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.6
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (I) (k) -
4 79 1
113,080 2678,9491 2,678,949 2
52 1,028 3
916,116 25,051,0981 I 25,051,098 4
5 179 5
529 17,400 6
10,107 255,278 7
23 5,499 8
170 7,3951 1 7,395 9
126 3,417 10
6,526 132,4261 1 132,426 11
83,110 2,018,910 2,018,910 12
640 20,320 13
287,202 6,784,113 6,784,113 14
202,448 3,836,934 5,441,641 419,849 9,698,424
10,564,249 16,086,186 500,177,279 -174,169,520 342,093,945
10,766,697 19,923,120 505,618,920 -173,749,671 351,792,369 -
FERC FORM NO. I (ED. 12-90) Page 311.6
Name of Respondent This Rport Is: Date of Report Year/Period of Report
PacifiCorp (1)jAn Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06128/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 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 Averag Actual Demand (MW)
Average
Monthly NCP Deman Average
Monthly CPemand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Pacific Gas & Electric Company SF 1-12 NA NA NA
P3 "Pacific
T-12 NA NA NA
Summit Energy LLC SF 1-12 NA NA NA
4 Portland General Electric Company SF T-1 1 NA NA NA
5 Portland General Electric Company SF T-12 NA NA NA
6 Portland General Electric Company ,SF 1-13 NA NA NA
7 Powerex Corporation T-1 1 NA NA NA
8 Powerex Corporation T-1 I NA NA NA
9 Powerex Corporation SF T-1 1 NA NA NA
10 Powerex Corporation SF T-1 1 NA NA NA
11 Powerex Corporation SF T-12 NA NA NA
12 Public Service Company of Colorado 320 NA NA NA
13 Public Service Company of Colorado T-1 2 NA NA NA
14 Public Service Company of Colorado 320 36 36 29
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 Re ort Is: Data of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column U). 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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (j) (k) -
367,445 9,847,770 9,847,770 1
195 4,070 4,070 2
890 23,1401 23,140 3
147 2,4434
85,842 2,001 ,528 2,001,528 5
91 2,214 6
21 585 7
26,044 690,665 8
19,441 516,834 9
29 782 10
411,678 10,031,5601 I 10,031,560 11
340,579 12
2 4513
236,495 4,315,680 13,733,6351 18,049,315 14
202,448 3,836,934 5,441,641 419,849 9,698,424
10,564,249 16,086,186 500,177,279 -174,169,520 342,093,945 -
10,766,697 19,923,120 505,618,920 -173,749,671 351,792,369
FERC FORM NO. I (ED. 12-90) Page 311.7
Name of Respondent This Re ort Is: Data of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 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 Averag Actual Demand (MW)
Average
Monthly NCI5 Deman Average
Monthly Cp9Demafld No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I Public Service Company of Colorado SF T-1 1 NA NA NA
2 Public Service Company of Colorado SF T-12 NA NA NA
3 Public Service Company of New Mexico SF T-12 NA N? NA
4 5F 1-12 NA NA NA
DouglasCàunty 1-13 NA NA NA
*PUD
SF T-12 NA NA NA
T-12 NA NA NA
Grant County 1SF 1-13 NA NA NA
9 Puget Sound Energy, Inc. SF T-12 NA NA NA
10 Puget Sound Energy, Inc. SF T-1 3 NA NA NA
11 Rainbow Energy Marketing Corporation SF T-1 1 NA NA NA
12 Rainbow Energy Marketing Corporation 1SF 1-12 NA NA NA
13 Sacramento Municipal utility District 250 NA NA NA
14 Sacramento Municipal utility District 250 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.8
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)[FjA Resubmission 06/28/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column ). 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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (j) (k) -
9 53 1
74,122 2,176,203 2,176,203 2
187,062 5,774,257 5,774,257 3
1,870 48,950 48,950 4
2 605
20,750 555,8201 555,820 6
16,556 406,638 406,638 7
22 612 8
78,449 1,903 ,7051 I 1,903,705 9
57 1,512 10
1,465 38,320 11
19,136 577,938' 577,938 12
-66,136 13
569,382 13,818,901 13,818,901 14
202,448 3,836,934 5,441,641 419,849 9,698,424 -
10,564,249 16,086,186 500,177,279 -174,169,520 342,093,945 -
10,766,697 19,923,120 505,618,920 j -173,749,671 351,792,369
FERC FORM NO. I (ED. 12-90) Page 311.8
Name of Respondent This Re ort Is: Data of Report Year/Period of Report
PacifiCo (1)An Original (Mo, Da, Yr) End of 20111Q4
(2)A Resubmission 06/28/2012
SALES FOR RESALE (A( 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 affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm' means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 reliability of designated unit.
lU - 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 Averag Actual Demand (MW)
Averaqe
Monthly NCR Deman Averacie
Monthly CP'Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (C) (d) (e) (f)
1 Sacramento Municipal Utility District SF T-12 NA NA NA
2 Sacramento Municipal Utility District SF T-13 NA NA NA
3 Salt River Project SF T-12 NA NA NA
4 San Diego Gas & Electric Company T-12 NA NA NA
5 San Diego Gas & Electric Company SF T-1 2 NA NA NA
6 Seattle City Light T-1 1 NA NA NA
7 Seattle City Light SF T-12 NA NA I NA
8 Sempra Energy Trading LLC T-12 NA NA NA
9 Sempra Generation SF T-12 NA NA NA
10 Shell Energy North America (US), L.P. T-12 NA NA NA
11 Shell Energy North America (US), L.P. SF T-1 1 NA NA NA
12 Shell Energy North America (US), L.P. SF T-12 NA NA NA
13 Sierra Pacific Power Company T-1 1 NA NA NA
14 Sierra Pacific Power Company SF T-1 1 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORK NO. I (ED. 12-90) Page 310.9
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a): The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (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 RQJN0n-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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (j) (k) -
46,827 1,324,9511 1,324,951 1
31 280 2
256,185 7,490,8681 7,490,868 3
125 1,141 4
2,398 60,6511 60,651 5
2,838 64,989 6
12,747 265,5701 1 265,570 7
24 1,158 8
74,200 2,074,994 2,074,994 9
500 14,0001 1 14,000 10
181 4,767 11
684,397 28,174,5131 1 28,174,513 12
956 25,359 13
275 7,355 14
202,448 3,836,934 5,441,641 419,849 9,698,424 -
10,564,249 16,086,186 500,177,279 -174,169,520 342,093,945 -
10,766,697 19,923,120 505,618,920 -173,749,671 351,792,369
FERC FORM NO. I (ED. 12-90) Page 311.9
Name of Respondent This Re ort Is: Data of Report Year/Period of Report
PaciflCorp (1)LJAn Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser. -
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 reliability of designated unit.
lU - 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 Averag Actual Demand (MW)
Average
Monthly NCP Demanc Averane Monthly CP1)emand No. (Footnote Affiliations) - Classifi-
cation
Schedule or Tariff Number
Billing Monthly
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Sierra Pacific Power Company SF T-1 3 NA NA NA
2 Southern California Edison Company IF T-12 NA NA NA
3 Southern California Edison Company SF T-11 NA NA NA
4 Southern California Edison Company SF T-11 NA NA NA
5 Southern California Edison Company SF T-12 NA NA NA
6 Southwestern Public Service Company SF T-12 NA NA NA
7 Tacoma Power SF T-12 NA NA NA
8 Tenaska Power Services Co. SF T-1 1 NA NA NA
9 The Energy Authority, Inc. SF T-12 NA NA NA
10 TransAlta Energy Marketing (U.S.) Inc. SF T-1 1 NA NA NA
11 TransAlta Energy Marketing (U.S.) Inc. SF T-12 NA NA NA
12 TransCanada Energy Sales Ltd. SF T-12 NA NA NA
1 3F T-11 NA NA NA
14 Tri-State Gen. & Trans. 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 310.10
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 20111Q4 (2)A Resubmission 06/28/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQINon-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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (j) (k) -
269 7,749 1
327,600 9,272,8441 9,272,844 2
14,849 374,868 3
20 545 4
66,878 2,663,971' I 2,663,971 5
171,928 5,294,3491 1 5,294,349 6
9,384 244,281 244,281 7
847 16,475 8
7,274 223,3621 1 223,362 9
1,638 50,339 10
168,781 4,308,3011 1 4,308,301 11
2,000 65,700 65,700 12
1,102 34,933 13
157,557 4,470,695 4,470,695 14
202,448 3,836,934 5,441,641 419,849 9,698,424
10,564,249 16,086,186 500,177,279 -174,169,520 342,093,945 -
10,766,697 19,923,120 505,618,920 -173,749,671 351,792,369 -
FERC FORM NO. I (ED. 12-90) Page 311.10
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)EjA Resubmission 06/28/2012
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 reliability of designated unit.
lU - 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 Average Actual Demand (MW)
Averaoe
Monthly NC Deman Average
Monthly CP9Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Tucson Electric Power Company SF T-12 NA NA NA
2 Turlock Irrigation District SF T-12 NA NA NA
3 UNS Electric, Inc. SF T-12 NA NA NA
4 Utah Associated Municipal Power Systems T-12 NA NA NA
5 Utah Associated Municipal Power Systems SF T-12 NA NA NA
6 Utah Municipal Power Agency 433 34 34 34
7 Utah Municipal Power Agency 1SF T-3 NA NA NA
8 Western Area Power Administration T-1 1 NA NA NA
9 Western Area Power Administration T-1 1 NA NA NA
10 Western Area Power Administration 1SF T-11 NA NA NA
11 Western Area Power Administration SF T-12 NA NA NA
12 Netting - Bookouts AD NA NA NA NA
13 Netting - Trading AD NA - NA NA NA
14 Accrual NA NA NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.11 -
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 201 1/Q4
(2)JA Resubmission 06/28/2012
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter 'Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6.For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7.Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8.Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column ). 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
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (j) (k)
259,218 8,082,228 8,082,228 1
11,206 296,280 296,280 2
346,463 10,013,028 10,013,028 3
7,765 211,034 211,034 4
11,437 309,527 309,527 5
194,954 4,396,200 4,530,731 8,926,931 6
8,080 69,360 69,360 7
63 4,995 8
515 14,819 9
8,218 237,133 10
161,327 6,1 39,8371 I 6,139,837 11
-5,703,900 -167,137,516 12
-11,500,014 13
-4,444 -151,741 14
202,448 3,836,934 5,441,641 419,849 9,698,424 -
10,564,249 16,086,186 500,177,279 -174,169,520 342,093,945 -
10,766,697 19,923,120 505,618,920 -173,749,671 351,792,369
FERC FORM NO. I (ED. 12-90) Page 311.11
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 310 Line No.: 2 Column:j
Settlement Adjustment
Schedule Page: 310 Line No.: 6 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "NAVAJO TRIBAL UTIL AUTH (MEXICAN HAT)" ON
PAGES 310 - 311: Complete name is Navajo Tribal Utility Authority (Mexican Hat).
Schedule Page: 310 Line No.: 7 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "NAVAJO TRIBAL tYTIL AUTH (RED MESA)" ON PAGES
310-311: Complete name is Navajo Tribal Utility Authority (Red Mesa).
Schedule Page: 310 Line No.: 8 Column:j
Settlement Adjustment
Schedule Page: 310 Line No.: 9 Column: j
Settlement Adjustment
Schedule Page: 310 Line No.: 10 Column:j I
Represents the difference between actual requirement sales revenues for the period as
reflected on the individual line items within this schedule, and the accruals charged to
account 447 during the period.
ISchedule Page: 310.1 Line No.: I Column: j I
Reserve Share
Schedule Page: 310.1 Line No.: 4 Column: b I
Settlement Adjustment.
Schedule Page: 310.1 Line No.: 4 Column:j I
Settlement Adjustment
Schedule Page: 310.1 Line No.: 6 Column: j
Transmission Losses
ISchedule Page: 310.1 Line No.: 8 Column: b I
Black Hills Power, Inc. - FERC 441 - Contract termination date: December 31, 2023.
ISchedule Page: 310.1 Line No.: 9 Column: b I
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
Schedule Page: 310.1 Line No.: 10 Column:j
Transmission Losses
ISchedule Page: 310.1 Line No.: 13 Column: b
Settlement Adjustment.
Schedule Page: 310.1 Line No.: 13 Column:j
Settlement Adjustment
Schedule Page: 310.1 Line No.: 14 Column: b I
Settlement Adjustment.
Schedule Page: 310.1 Line No.: 14 Column:j I
Settlement Adjustment
lSchedule Page: 310.2 Line No.: I Column: b I
Bonneville Power Administration - FERC, 5th revised R.S. 368 [Use of Facilities Agreement
for the Malin Transformer under the AC Intertie Agreement with BPA] - Contract termination
date: Upon mutual agreement.
Schedule Page: 310.2 Line No.: I Column:j
Transmission Losses
Schedule Page: 310.2 Line No.: 2 Column: b I
Bonneville Power Administration - FERC T-ll [Point-to-Point Transmission Service under the
Open Access Transmission Tariff (1st revised S.A. 179)] - Contract termination date:
September 30, 2025 and (S.A. 656) - Contract termination date: August 31, 2030.
Schedule Page: 310.2 Line No.: 2 Column: I
Transmission Losses
Schedule Page: 310.2 Line No.: 4 Column:j
Transmission Losses
Schedule Page: 310.2 Line No.: 6 Column: I I
IFERC FORM NO. I (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)
PaciflCorp (2)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Reserve Share
ISchedule Page: 310.2 Line No.: 7 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "BRITISH COLUMBIA TRANSMISSION CORP." ON PAGES
310-311: Complete name is British Columbia Transmission Corporation.
Schedule Page: 310.2 Line No.: 7 Column:j
Reserve Share
Schedule Page: 310.2 Line No.: 8 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "CALIFORNIA INDEPENDENT SYSTEM OPERATOR" ON
PAGES 310-311: Complete name is California Independent System Operator Corporation.
Schedule Page: 310.2 Line No.: 8 Column: b
Settlement Adjustment.
Schedule Page: 310.2 Line No.: 8 Column:j
Settlement Adjustment
Schedule Page: 310.2 Line No.: 10 Column: b
Settlement Adjustment.
Schedule Page: 310.2 Line No.: 10 Column:j
Settlement Adjustment
Schedule Page: 310.2 Line No.: 11 Column: j I
Transmission Losses
ISchedule Page: 310.2 Line No.: 13 Column: b
Settlement Adjustment.
[Schedule Page: 310.2 Line No.: 13 Column: j I Settlement Adjustment
Schedule Page: 310.3 Line No.: 5 Column: b I
City of Hurricane - FERC T-12 - Contract termination date: August 31, 2007.
Schedule Page: 310.3 Line No.: 10 Column: a
THIS FOOTNOTE APPLIES TO ALL
PAGES 310-311: Complete name
OCCURRENCES OF "CONSTELLATION ENERGY COMMODITIES GROUP"
is Constellation Energy Commodities Group, Inc.
ON
Schedule Page: 310.3 Line No.: 10 Column: j Transmission Losses
ISchedule Page: 310.3 Line No.: 11 Column:j
Unauthorized use charges
[Schedule Page: 310.3 Line No.: 13 Column: b
Settlement Adjustment.
ISchedule Page: 310.3 Line No.: 13 Column:j
Settlement Adjustment
Schedule Page: 310.4 Line No.: I Column: a
THIS FOOTNOTE APPLIES TO ALL
PAGES 310-311: Complete name
OCCURRENCES OF "DESERET GENERATION & TRANSMISSION COOP."
is Deseret Generation and Transmission Cooperative.
ON
ISchedule Page: 310.4 Line No.: I Column:j
Transmission Losses
Schedule Page: 310.4 Line No.: 2 Column:j
Transmission Losses
Schedule Page: 310.4 Line No.: 5 Column:j
Transmission Losses
Schedule Page: 310.4 Line No.: 9 Column: b
Iberdrola Renewables, Inc. - FERC T-ll [Point-to-Point Transmission Service under the
Access Transmission Tariff (5th revised S.A. 279)] - Contract termination date: April
2014.
Open
30,
Schedule Page: 310.4 Line No.: 9 Column:j
Transmission Losses
Schedule Page: 310.4 Line No.: 10 Column: I Transmission Losses
Schedule Page: 310.4 Line No.: 12 Column: b
IFERC FORM NO. I (ED. 12-87) Page 450.2 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Idaho Power Company FERC T-ll [Point-to-Point Transmission Service under the Open Access
Transmission Tariff (5th revised S.A. 212)] - Contract termination date: May 31, 2014.
Schedule Page: 310.4 Line No.: 12 Column:j
Transmission Losses
ISchedule Page: 310.4 Line No.: 13 Column:j
Transmission Losses
ISchedule Page: 310.5 Line No.: I Column:j
Reserve Share
Schedule Page: 310.5 Line No.: 2 Column: b
Intermountain Renewable Power, LLC - FERC T-11 [Point-to-Point Transmission Service under
the Open Access Transmission Tariff (S.A. 568)] - Contract termination date: April 30,
2029.
Schedule Page: 310.5 Line No.: 2 Column: I
Transmission Losses
Schedule Page: 310.5 Line No.: 4 Column: j
Transmission Losses
Schedule Page: 310.5 Line No.: 6 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "LOS ANGELES DEPT. OF WATER & POWER" ON PAGES
310-311: Complete name is Los Angeles Department of Water and Power.
Schedule Page: 310.5 Line No.: 7 Column: I Transmission Losses
Schedule Page: 310.5 Line No.: 9 Column:j
Transmission Losses
Schedule Page: 310.5 Line No.: 12 Column: b
Settlement Adjustment.
Schedule Page: 310.5 Line No.: 12 Column: I
Settlement Adjustment
chedule Page: 310.5 Line No.: 13 Column:j
Transmission Losses
Schedule Page: 310.6 Line No.: I Column:j
Transmission Losses
Schedule Page: 310.6 Line No.: 3 Column:j
Reserve Share
Schedule Page: 310.6 Line No.: 5 Column:j
Transmission Losses
çedule Page: 310.6 Line No.: 6 Column: b
Settlement Adjustment.
Schedule Page: 310.6 Line No.: 6 Column:j
Settlement Adjustment
Schedule Page: 310.6 Line No.: 7 Column: b
NextEra Energy Power Marketing, LLC - FERC T-ll [Point-to-Point Transmission Service under
the Open Access Transmission Tariff (S.A. 626)] - Contract termination date: December 31,
2011.
Schedule Page: 310.6 Line No.: 7 Column:j
Transmission Losses
Schedule Page: 310.6 Line No.: 8 Column: j
Unauthorized use charges
ISchedule Page: 310.6 Line No.: 10 Column:j
Reserve Share
Schedule Page: 310.6 Line No.: 13 Column:j
Transmission Losses
Schedule Page: 310.7 Line No.: 2 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "PACIFIC NORTHWEST GENERATING COOP." ON PAGES
310-311: Complete name is Pacific Northwest Generating Cooperative, Inc.
IFERC FORM NO. I (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)X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Schedule Page: 310.7 Line No.: 4 Column: j
Transmission Losses
ISchedule Page: 310.7 Line No.: 6 Column:j
Reserve Share
Schedule Page: 310.7 Line No.: 7 Column: b I
Settlement Adjustment.
Schedule Page: 310.7 Line No.: 7 Column:j
Settlement Adjustment
cheduIe Page: 310.7 Line No.: 8 Column: b I
Powerex Corporation - FERC T-ll
Transmission Tariff (5th revised
[Point-to-Point
S.A. 169)]
Transmission Service under the Open Access
- Contract termination date: October 31, 2020.
Schedule Page: 310.7 Line No.: 8 Column: I I
Transmission Losses
ISchedule Page: 310.7 Line No.: 9 Column:j I
Transmission Losses
ISchedule Page: 310.7 Line No.: 10 Colurnn:j I Unauthorized use charges -
Schedule Page: 310.7 Line No.: 12 Column: b I
Settlement Adjustment.
Schedule Page: 310.7 Line No.: 12 Column:j I
Settlement Adjustment
Schedule Page: 310.7 Line No.: 13 Column: b I
Settlement Adjustment.
Schedule Page: 310.7 Line No.: 13 Column:j I
Settlement Adjustment
Schedule Page: 310.7 Line No.: 14 Column: b I
Public Service Company
2011.
of Colorado - FERC 320 - Contract termination date: December 31,
Schedule Page: 310.8 Line No.: I Column:j I
Transmission Losses
Schedule Page: 310.8 Line No.: 4 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF
Complete name is Public Utility District No.
"PUD #1 OF DOUGLAS COUNTY" ON PAGES 310-311:
1 of Douglas County.
Schedule Page: 310.8 Line No.: 5 Column:j
Reserve Share
Schedule Page: 310.8 Line No.: 6 Column: a I THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF
Complete name is Public Utility District No.
"PUD #1 OF SNOHOMISH COUNTY" ON PAGES 310-311:
1 of Snohomish County.
Schedule Page: 310.8 Line No.: 7 Column: a
THIS FOOTNOTE APPLIES TO ALL
Complete name is Public Utility
OCCURRENCES OF
District No.
"PtJD #2 OF GRANT COUNTY" ON PAGES 310-311:
2 of Grant County.
Schedule Page: 310.8 Line No.: 8 Column:j
Reserve Share
Schedule Page: 310.8 Line No.: 10 Column:j
Reserve Share
Schedule Page: 310.8 Line No.: 11 Column:j
Transmission Losses
Schedule Page: 310.8 Line No.: 13 Column: b I
Settlement Adjustment.
ISchedule Page: 310.8 Line No.: 13 Column: j Settlement Adjustment
Schedule Page: 310.8 Line No.: 14 Column: b I
Sacramento Municipal Utility
2014.
District - FERC 250 - Contract termination date: December 31,
IFERC FORM NO. I (ED. 12-87) Page 450.4 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)- An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 201 1/Q4
FOOTNOTE DATA
ISchedule Page: 310.9 Line No.: 2 Column: I Reserve Share
ISchedule Page: 310.9 Line No.: 4 Column: b
Settlement Adjustment.
ISchedule Page: 310.9 Line No.: 4 Column:j
Settlement Adjustment
ISchedule Page: 310.9 Line No.: 6 Column: b
Seattle City Light FERC T-ll [Point-to-Point Transmission Service under the Open Access
Transmission Tariff (7th revised S.A. 289)] - Contract termination date: October 31, 2014.
Schedule Page: 310.9 Line No.: 6 Column: j
Transmission Losses
Schedule Page: 310.9 Line No.: 8 Column: b
Settlement Adjustment.
Schedule Page: 310.9 Line No.: 8 Column: I
Settlement Adjustment
Schedule Page: 310.9 Line No.: 10 Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
ISchedule Page: 310.9 Line No.: 11 Column:j
Transmission Losses
lSchedule Page: 310.9 Line No.: 13 Column: b
Sierra Pacific Power Company - FERC T-ll [Pavant Capacitor Ownership, Operation and
Maintenance Letter Agreement dated November 9, 2000] - Contract termination date: 90 days
notification.
Schedule Page: 310.9 Line No.: 13 Column:j
Transmission Losses
Schedule Page: 310.9 Line No.: 14 Column:j
Transmission Losses
ISchedule Page: 310.10 Line No.: I Column:j
Reserve Share
Schedule Page: 310.10 Line No.: 3 Column:j
Transmission Losses
ISchedule Page: 310.10 Line No.: 4 Column:j
Unauthorized use charges
Schedule Page: 310.10 Line No.: 8 Column:j
Transmission Losses
Schedule Page: 310.10 Line No.: 10 Column:j
Transmission Losses
Schedule Page: 310.10 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "TRI-STATE GEN. & TRANS." ON PAGES 310-311:
Complete name is Tri-State Generation and Transmission Association, Inc.
Schedule Page: 310.10 Line No.: 13 Column:j
Transmission Losses
ISchedule Page: 310.11 Line No.: 4 Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
Schedule Page: 310.11 Line No.: 6 Column: b
Utah Municipal Power Agency - FERC 433 - Contract termination date: June 30, 2017.
Schedule Page: 310.11 Line No.: 8 Column: b
Settlement Adjustment.
ISchedule Page: 310.11 Line No.: 8 Column: j
Settlement Adjustment
[Schedule Page: 310.11 Line No.: 9 Column: b
Western Area Power Administration - FERC R.S. 664 [Purchase of Capacity in the 230kv
Casper-Dave Johnston Transmission Line - Use of transmission service during times when
Western's capacity is de-rated] - Contract termination date: 50 years after commercial
IFERC FORM NO. I (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)X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
operation of the transmission line.
Schedule Page: 310.11 Line No.: 9 Column: I Transmission Losses
Schedule Page: 310.11 Line No.: 10 Column:j
Transmission Losses
ISchedule Page: 310.11 Line No.: 12 Column:j
Reflects transactions that did not physically settle.
Schedule Page: 310.11 Line No.: 13 Column:j
Reflects transactions that did not physically settle.
ISchedule Page: 310.11 Line No.: 14 Column:j
Represents the difference between actual non-requirement sales revenues for the period as
reflected on the individual line items within this schedule, and the accruals charged to
account 447 during the period.
IFERC FORM NO. I (ED. 12-87) Page 450.6 I
Name of Respondent
PacifiCorp
This Report Is:
(1)LjAn Original
(2)EKIA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
N 0.
Account
(a)
Amount for Current Year
(b)
Ampunt for Previous Year
(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering 19,391,6121 20.107,0301
5 (501) Fuel 722,758,588
6 (502) Steam Expenses 38,138,1031 38,472,0211
7 (503) Steam from Other Sources 3,583,830 3,655,727
8 (Less) (504) Steam Transferred -Cr.
9 (505) Electric Expenses 4,190,528 4,285,137
10 (506) Miscellaneous Steam Power Expenses 52,707,1591 48,042,874
11 (507) Rents 277,6541 338,685
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12) 841,047,4741 784,543,397
14 Maintenance
15 (510) Maintenance Supervision and Engineering 6,365,300 6,462,258
16 (511) Maintenance of Structures 23,596,390 25,480,95,r-
17 (512) Maintenance of Boiler Plant 109,128,194 112,922,881
18 (513) Maintenance of Electric Plant 39,898,808 38,934,338
19 (514) Maintenance of Miscellaneous Steam Plant 13,319,308 12,066,167
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19) 192,308,0001 195,866,599
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 1,033,355,4741 980.409,9961
22 1 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) (52 2) 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 1 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 1 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 3,787,003 3,825,666
45 (536) Water for Power 257,504 212,409
46 (537) Hydraulic Expenses 3,696,681 3,449,509
47 (538) Electric Expenses
48 (539) Miscellaneous Hydraulic Power Generation Expenses 21,669,423 20,295,293
49 (540) Rents 117,398
50 TOTAL Operation (Enter Total of Lines 44 thru 49) 29,006,1071 27,900,275
51 C. Hydraulic Power Generation (Continued)
52 1 Maintenance
53 (541) Mainentance Supervision and Engineering 1,891 469
54 (542) Maintenance of Structures 1,030,119 1,430,392
55 (543) Maintenance of Reservoirs, Dams, and Waterways 2,430,112 1,959,700
56 (544) Maintenance of Electric Plant 2,553,749 1,635,171
57 (545) Maintenance of Miscellaneous Hydraulic Plant 2,961,681 2,654,790
58 1 TOTAL Maintenance (Enter Total of lines 53 thru 57) 8,977,552 7,680,522
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 37,983,659 35,580,797
FERC FORM NO. 1 (ED. 12-93) Page 320
Name of Respondent
PaciflCorp
This Re oil Is:
(1)An Original
(2)jA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount for Current Year
(b)
Amount for Previous Year
(c)
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering 429,8111 358,6281
63 (547) Fuel 367,320,902 432,620,733
64 (548) Generation Expenses 15,368,434 14,638,002
65 (549) Miscellaneous Other Power Generation Expenses 21,289,631 18,701,556
66 (550) Rents 4,253,868 3,558.679
67 TOTAL Operation (Enter Total of lines 62 thru 66) 1 408,662,6461 469,877.5
68 Maintenance
69 (551) Maintenance Supervision and Engineering
70 (552) Maintenance of Structures 2,938,948 1,240.594
71 (553) Maintenance of Generating and Electric Plant 10,918,597 8,996,404
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 4,783,736 2,196,6
73 TOTAL Maintenance (Enter Total of lines 69 thru 72) 18,641,281 12,433,697
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 427,303,9271 482,311.2
75 1 E. Other Power Supply Expenses
76 (555) Purchased Power 398,261,268 380,007,6
77 (556) System Control and Load Dispatching 1,744,114 877,454
78 (557) Other Expenses 60,776,842 63,870,496
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 460,782,224 444,755,628
80 TOTAL Power Production Expenses (Total of lines 21,41,59,74 & 79) 1,959,425,2841 1,943,057,7161
81 2. TRANSMISSION EXPENSES
82 1 Operation
83 (560) Operation Supervision and Engineering 5,689,6571 5,041,1151
84 (561) Load Dispatching 650,305
85 (561.1) Load Dispatch-Reliability
86 (561.2) Load Dispatch-Monitor and Operate Transmission System 7,794,035 7,847,328
87 (561.3) Load Dispatch-Transmission Service and Scheduling
88 (561.4) Scheduling, System Control and Dispatch Services
89 (561.5) Reliability, Planning and Standards Development 984,307 816,883
90 (561.6) Transmission Service Studies 206,982 83,476
91 (561.7) Generation Interconnection Studies 763,228 938,904
92 (561.8) Reliability, Planning and Standards Development Services
93 (562) Station Expenses 2,647,395 2,124,825
94 (563) Overhead Lines Expenses 259,051 120,209
95 (564) Underground Lines Expenses
96 (565) Transmission of Electricity by Others 138,234,854 136,854,649
97 (566) Miscellaneous Transmission Expenses 3,568,851 4,257,862
98 (567) Rents 2,549,5531 1,312,382
99 TOTAL Operation (Enter Total of lines 83 thru 98) 162,697,9131 160,047,938
100 Maintenance
101 (568) Maintenance Supervision and Engineering 2,060,726 1,334,303
102 (569) Maintenance of Structures 300 395
103 (569.1) Maintenance of Computer Hardware 103,365 36,440
104 (569.2) Maintenance of Computer Software 1,119,442 1,065,683
105 (569.3) Maintenance of Communication Equipment 3,356,135 3,567,267
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment 11,231,343 10,092,385
108 (571) Maintenance of Overhead Lines 22,369,881 19,173,510
109 (572) Maintenance of Underground Lines 169,531 36,881
110 (573) Maintenance of Miscellaneous Transmission Plant 1,607,372 273,467
111 TOTAL Maintenance (Total of lines 101 thru 110) 42,018,095 35,580,331
112 TOTAL Transmission Expenses (Total of lines 99 and 111) 204,716,008 195,628,269
FERC FORM NO. I (ED. 12-93) Page 321
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)FXJA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
0.
Account
(a)
Amount for Current Year
(b)
Ampunt for Previous Year
(c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Day-Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Rights Market Facilitation
118 (575.4) Capacity Market Facilitation
119 (575.5) Ancillary Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Facilitation, Monitoring and Compliance Services
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)
124 Maintenance
125 (576.1) Maintenance of Structures and Improvements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Software
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129) 1
131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering 14,865,204 15,625,451 1
135 (581) Load Dispatching 13,254,105 13,735,481
136 (582) Station Expenses 4,206,539 3,812,831
137 (583) Overhead Line Expenses 6,624,463 5,762,152
138 (584) Underground Line Expenses 1,186 287
139 (585) Street Lighting and Signal System Expenses 231,056 209,265
140 (586) Meter Expenses 7,978,791 6,564,361
141 (587) Customer Installations Expenses 13,297,857 12,634,849
142 (588) Miscellaneous Expenses 5,452,451 5,887,263
143 (589) Rents 3,011,807 3,253,672
144 TOTAL Operation (Enter Total of lines 134 thru 143) 1 68,923,4591 67,485,612
145 Maintenance
146 1 (590) Maintenance Supervision and Engineering 4,424,569 5,493,229
147 (591) Maintenance of Structures 2,476,425 1,828,870
148 (592) Maintenance of Station Equipment 14,330,166 12,622,071
149 (593) Maintenance of Overhead Lines 89,892,555 84,730,396
150 (594) Maintenance of Underground Lines 22,649,570 22,786,414
151 (595) Maintenance of Line Transformers 893,541 883,285
152 (596) Maintenance of Street Lighting and Signal Systems 4,076,102 4,084,559
153 (597) Maintenance of Meters 5,647,204 5,890,644
154 (598) Maintenance of Miscellaneous Distribution Plant 1,787,180 2,745,222
155 TOTAL Maintenance (Total of lines 146 thru 154) 146,177,312 141,064,690
156 TOTAL Distribution Expenses (Total of lines 144 and 155) 215,100,771 208,550,302
157 5. CUSTOMER ACCOUNTS EXPENSES
158 1 Operation
159 (901) Supervision I 2,930,3131 2,497,682 1
160 (902) Meter Reading Expenses 21,907,551 22,553,488
161 (903) Customer Records and Collection Expenses 56,314,393 54,938,892
162 (904) Uncollectible Accounts 14,586,410 12,590,656
163 (905) Miscellaneous Customer Accounts Expenses 205,123 169,927
164 1 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 95,943,790 92,750,645
FERC FORM NO. I (ED. 12-93) Page 322
Name of Respondent
PacifiCorp
This Report Is:
(1)DAn Original
(2)ffjA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
N °.
Account
(a)
Amount for Current Year
(b)
Amount for Previous Year
(C)
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision I 302,255 263,903
168 (908) Customer Assistance Expenses 103,945,691 124,155,800
169 (909) Informational and Instructional Expenses 5,081,263 4,435,033
170 (910) Miscellaneous Customer Service and Informational Expenses 183,174 90,169
171 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 109,512,383 128,944,905
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision I
175 (912) Demonstrating and Selling Expenses
176 (913) Advertising Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177) I
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 1 Operation
181 (920) Administrative and General Salaries 68,148,776 66,458,826
182 (921) Office Supplies and Expenses 9,330,613 9,973,883
183 (Less) (922) Administrative Expenses Transferred-Credit 29,007,646 28,375,128
184 (923) Outside Services Employed 10,190,059 9,404,30
185 (924) Property Insurance 24,984,814 23,341,43
186 (925) Injuries and Damages 7,284,8491 8,492,514
187 (926) Employee Pensions and Benefits
188 (927) Franchise Requirements
189 (928) Regulatory Commission Expenses 21,857,100 17,926,84
190 (929) (Less) Duplicate Charges-Cr. 6,822,162 6,130,867
191 (930.1) General Advertising Expenses 5,360 20,38
192 (930.2) Miscellaneous General Expenses 15,710,771 16,291,64
Rents 6,614,680 6,337,70
TOTAL Operation (Enter Total of lines 181 thru 193) 123,741,534

196
(931)
128,297,214
k
Maintenance
(935) Maintenance of General Plant 24,360,143 22,334,950
TOTAL Administrative & General Expenses (Total of lines 194 and 196) 152,657,357 146,076,484
198 1 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 2,737,355,593 2,715,008,321
FERC FORM NO. I (ED. 12-93) Page 323
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
Pacif'iCorp X A Resubmission 06/28/2012 2011 /Q4
FOOTNOTE DATA
Schedule Page: 320 Line No.: 5 Column: c
Amended in accordance with FERC Order No. AC11-132.
Schedule Page: 320 Line No.: 49 Column: b
Represents differences between accrued and actual rents.
Schedule Page: 320 Line No.: 187 Column: b
Pensions and benefits expense is associated with labor and generally charged to operations
and maintenance expense and construction work in progress. During the years ended December
31, 2011 and 2010, pensions and benefits expense was $156,716,703 and $153,429,891,
respectively.
IFERC FORM NO. 1 (ED. 12-87) Page 450.1 I
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
PUICHA$ED POWER (Account 555) (Including power excnanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 availability and reliability of the designated unit.
lU - 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)
Average
Monthly NCP Deman
Average
Monthly CP Demand N 0. (Footnote ia 0fl5) Affil Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (1)
1 Power Purchases
2 Arizona Public Service Company NA NA NA
3 Arizona Public Service Company SF NA NA NA
4 Avista Corporation SF NA NA NA
5 BNP Paribas Energy Trading GP SF NA NA NA
6 BP Corporation North America, Inc. SF NA NA NA
7 BP Energy Company SF NA NA NA
8 Ballard Hog Farms Inc. Lu 0.01 0.01 0.01
9 Barclays Bank PLC SF NA NA NA
10 Beaver City Corporation NA NA NA
11 Bell Mountain Hydro, LLC NA NA NA
12 Bell Mountain Hydro, LLC LU NA NA NA
13 Big Top, LLC NA NA NA
14 Big Top, LLC LU NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326
Name of Respondent This Re ort Is: Data of Report Year/Period of Report
PaciliCo I (1) LJAn Original (Mo, Da, Yr) End of 2011/Q4
(2) MA Resubmission 06/28/2012
PUkCHASED PQWER(Account 555) (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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on 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 U) 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 Megawatt Hours MegaWatt Hours ______________ Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No Received Delivered ($) ($) ($) of Settlement($)
(9) (h) (i)
22,901 615,29E 615,298 2
94,87-1 3,506,47E 3,524,045 3
135,311 2,823,76 2,829,950 4
24,001 424,13 424,130 5
-22,230,890 6
535,00 11,435,427 11,435,427 7
5 270 1,872 2,142 8
196,391 5,837,52 -10,091,117 9
61 5,781 5,781 10
2,129 11
1,057 80,165 80,165 12
- -228 13
3,819 240,206 240,206 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,26
FERC FORM NO. 1 (ED. 12-90) Page 327
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4 (2)A Resubmission 06/28/2012
PUICHA$ED POWER (Account 555) (Including power excflanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Deman
Average
Monthly CP Demand N 0. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Biomass One, L.P. LU 22.5 20.9 13.7
2 Birch Power Company, Inc. LU NA NA NA
3 Black Hills Power, Inc. NA NA NA
4 Black Hills Power, Inc. LU NA NA NA
5 Black Hills Power, Inc. SF NA NA NA
6 Black Hills Wyoming, Inc. SF NA NA NA
7 Blanding City Corporation NA NA NA
8 Bonneville Power Administration 575 575 337
9 Bonneville Power Administration NA NA NA
10 Bonneville Power Administration NA NA NA
11 Bonneville Power Administration SF NA NA NA
12 Box Canyon Limited Partnership NA NA NA
13 Box Canyon Limited Partnership LU 4.4 4.7 2.7
14 Butter Creek Power, LLC _______ NA NA NA
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.1
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
PacifiCo (1) An Original (Mo, Da, Yr) End of 2011/Q4
1(2) AResubmission 06/28/2012
PUECHA PQWER(Account 555) (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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on 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 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 MegaWatt Hours Megawatt Hours Demand Charges
______________
Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) $) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
111,001 2,133,000 15,646,91 26,105,987 I
13,019 727,137 727,137 2
-1 5a 234,785 3
187 2,866,004 4
23,841 1,010,786 1,010,786 5
1,264 70,644 70,544 6
42C 31,469 31,469 7
38,410,000 38,410,000 8
683,756 9
1,561 54,153 10
692,986 9,707,36 9,764,892 11
1 12
25,830 423,218 2,962,22 3,385,446 13
-11 -704 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,261
FERC FORM NO. 1 (ED. 12-90) Page 327.1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCo (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
PURCHASED POWER(Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Demanc
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Butter Creek Power, LLC LU NA NA NA
2 CDM Hydroelectric Company LU NA NA NA
3 CER Generation II, LLC LU 200 NA NA
NA NA NA
5 California Independent System Operator SF NA NA NA
6 Cameron A. Curtiss LU NA NA NA
7 Cargill Power Markets, LLC I NA NA NA
8 Cargill Power Markets, LLC SF NA NA NA
9 Cargill, Incorporated LU NA NA NA
10 Central Oregon Irrigation District NA NA NA
11 Central Oregon Irrigation District LU 3.5 4.4 3.3
12 Chevron U.S.A. Inc. LU NA NA NA
13 Citigroup Energy Inc. NA NA NA
14 1 Citigroup Energy Inc. SF NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.2
Name of Respondent This Re ort Is: Data of Report Year/Period of Report
PacifiCo I (1) LJAn Original (Mo, Da, Yr) End of 2011/Q4
(2) ffJA Resubmission 06/28/2012
PUICHA$b PQWER(Account 555) (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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on 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 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.
Mega Watt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER ______________ Line Megawatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges Total (j+k+I) Purchased No Received Delivered ($) $ M of Settlement($)
(g) (h)
13,778 862,108 862,108 1
29,782 1,665,176 1,665,175 2
77,732 1,455,484 5,652,959 3
534 27,033 4
407,897 13,048,834 13,048,834 5
151 7,469 7,469 6
920 289,508 7
405,361 12,574,34 11,953,032 8
3,312 179,536 179,536 9
-63 10
42,12 400,660 3,670,02 4,070,680 11
48,82: 2,724,35 2,724,350 12
25f 280 13
1,424,459 41,925,41 24,013,934 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,26
FERC FORM NO. I (ED. 12-90) Page 327.2
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCo (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
PUICHASED POWER (Account 555) (Including power excrianges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Deman
Average
Monthly CP Demand N 0. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 City of Albany LU NA NA NA
2 City of Anaheim SF NA NA NA
3 City of Burbank SF NA NA NA
4 City of Glendale SF NA NA NA
5 City of Hurricane NA NA NA
6 City of Preston Idaho NA NA NA
7 City of Preston Idaho LU NA NA NA
8 City of Redding SF NA NA NA
9 City of Walla Walla LU 2.0 1.8 1.5
10 Clatskanie People's Utility District SF NA NA NA
11 Colorado River Commission of Nevada SF NA NA NA
12 Commercial Energy Management Inc. LU NA NA NA
13 3F NA NA NA
14 Cottonwood Hydro, LLC IU NA NA NA
Total
FERC FORM NO I (ED. 1240) Page 326.3
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
P ifiCo ac I (1) An Original (Mo, Da, Yr) End of 2011/Q4
(2) A Resubmission 06/2812012
PUCHASED PQWER(Accourit 555) (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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on 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 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 ($) ($) of Settlement($)
(g) (h) (i)
1,607 102,91 102,912 1
42 10,33 2
31,20 1,337,461 1,337,466 3
22E 7,271 7,270 4
1,881 141,34I 141,345 5
-64 6
1,55 77,72z 77,724 7
870 16,76C 16,760 8
13,254 139,222 1,866,12f 2,005,350 9
2,845 95,511 95,510 10
201 10,471 10,476 11
2,215 117,291 117,291 12
301,265 12,988,361 12,927,842 13
3,284 186,371 186,378 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,261
FERC FORM NO. I (ED. 12-90) Page 327.3
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
PURCHA$ED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Demanc
Average
Monthly CP Demand N0. (Footnote en Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 DB Energy Trading LLC NA NA NA
2 DB Energy Trading LLC SF NA NA NA
3 1 Deschutes Valley Water District 1LU 5.9 4.3 2.9
4 100 100 98
5 J Deseret Generation & Transmission Coop NA NA NA
6 Deutsche Bank AG SF • NA NA NA
7 Douglas County LU 0.9 1.2 0.8
8 Douglas County, Inc. NA NA NA
9 Douglas County, Inc. LU NA NA NA
10 Draper Irrigation Company IU NA NA NA
11 Dry Creek LLC LU NA NA NA
12 Duane Wiggins Hydro, Inc. NA NA NA
13 Duane Wiggins Hydro, Inc. IU NA NA NA
14 EDF Trading North America, LLC SF NA NA NA
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.4
Name of Respondent This Rport Is: Date of Report Year/Period of Report
PacifiCo I (1)LJAn Original (Mo, Da, Yr) End of 2011/Q4
(2)VIA Resubmission 06/28/2012
PUkCHASED PQWER(Accourit 555) (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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on 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 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 MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No Received Delivered ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
10 219 1
234,336 6,050,630 6,050,630 2
29,734 584,749 3,252,874 3,837,623 3
772,254 14,629,584 14,403,911 32,874,400 4
1,850 5
-3,041,389 6
7,77 92,668 952,895 1,045,563 7
2 765 8
80: 17,06: 17,063 9
80 31,981 31,985 10
11,797 622,88 622,883 11
252 12
29 1,432 1,432 13
485,801 17,358,456 17,217,889 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,26
FERC FORM NO. I (ED. 12-90) Page 327.4
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCo (1)An Original (Mo, Da, Yr) End of 201 1/Q4
(2)EKIA Resubmission 06/28/2012
PURCHA$ED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 availability and reliability of the designated unit.
PU - 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)
Average
Monthly NCP Deman
Average
Monthly CP Demand No. (Footnote Affiliations) Classil'i-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (c) (d) (e) (f)
I Eagle Point Irrigation District LU 0.7 0.6 0.4
2 El Paso Electric Company NA NA NA
3 El Paso Electric Company SF NA NA NA
4 Eugene Water & Electric Board SF NA NA NA
5 Eurus Combine Hills I, LLC LU NA NA NA
6 Evergreen BioPower, LLC LU NA NA NA
7 Exelon Power Team SF NA NA NA
8 ExxonMobil Production Company LU NA NA NA
9 Falls Creek H.P. Limited Partnership LU 3.2 3.4 1.8
10 Farmers Irrigation District NA NA NA
11 Farmers Irrigation District LU NA NA NA
12 Fillmore City Corporation NA NA NA
13 Finley BioEnergy, LLC LU NA NA NA
14 Flathead Electric Cooperative, Inc. NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.5
Name of Respondent I This Re ort Is: Data of Report Year/Period of Report
PacifiCo (1)An Original (Mo, Da, Yr) End of 2011/04
(2)IA Resubmission 06/28/2012
PUkCHASED PQWER(Accourlt 555) (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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on 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 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 MegaWatt Hours Megawatt Hours Demand Charges
______________
Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) of Settlement($)
(g) (h) (I) (j) (k) (I) (m) -
3,909 50,185 450,017 500,202 1
-1 -80 2
8,791 258,191 258,190 3
50,405 1,449,621 1,449,625 4
118,643 4,814,53' 4,814,534 5
41,69' 2,377,781 2,377,780 6
13,40 455,781 455,780 7
620,80 29,219,061 29,219,060 8
16,71. 205,013 1,818,46: 2,023,475 9
1,291 138,611 10
25,13 1,504,83C 1,504,830 11
18: 19,68C 19,680 12
27,55 1,760,35E 1,760,359 13
49 11,668 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,26
FERC FORM NO. I (ED. 12-90) Page 327.5
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp (1)LJAn Original (Mo, Da, Yr) End of 20111Q4
(2) A Resubmission 06/28/2012
PURCF-IAED POWER(Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 availability and reliability of the designated unit.
lU - 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)
Average
Monthly NCP Dernan
Average
Monthly CP Demand N 0. . 00 no e I iaions1 Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I Four Corners Windfarm, LLC NA NA NA
2 Four Corners Windfarm, LLC LU NA NA NA
3 Four Mile Canyon Windfarrn, LLC NA NA NA
4 Four Mile Canyon Windfarrn, LLC LU NA NA NA
5 George DeRuyter & Sons Dairy LU 0.7 1.0 0.6
6 Georgetown Irrigation Company LU NA NA NA
7 Gila River Power LLC SF NA NA NA
8 Grand Valley Power NA NA NA
9 GrowPro, Inc. IU NA NA NA
10 Harold Foster & Robert Walker LU I NA NA NA
II Heber Light & Power Company NA NA NA
12 Hermiston Generating Company, L.P. NA NA NA
13 LU 240 227 156
141 Iberdrola Renewables, Inc. 'SF NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.6
Name of Respondent I This Report Is: Date of Report Year/Period of Report
PacifiCo (1) DAn Original (Mo, Da, Yr) End of 2011/Q4 I (2) MA Resubmission 06/28/2012
PUICHAPQWER(Account 555) (Continued) (ln uding 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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on .a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on 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 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 MegaWatt Hours MegaWatt Hours Demand Charges
______________
Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) of Settlement($)
(g) (h) (i)
21 1,355 1
30,30q 1,898,820 1,898,820 2
-2 -1,489 3
27,146 1,706,620 1,706,620 4
6,267 12,848 384,431 397,279 5
2,414 132,486 132,485 6
129,598 4,819,281 4,819,284 7
101 18,63 18,632 8
1 139
753 27,17 27,179 10
3,427 283,97' 283,970 11
1 -234,592 12
1,157,11 35,700,425 60,085,319 96,217,474 13
1,152,472 28,802,826 24,511,559 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,261
FERC FORM NO. 1 (ED. 12.90) Page 327.6
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011 /Q4
(2)A Resubmission 06/28/2012
PURCHASED POWER(Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 availability and reliability of the designated unit.
lU - 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)
Average
Monthly NCP Demanc
Average
Monthly CP Demand No. (FootnoteAffiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Idaho Falls, City of NA NA NA
2 Idaho Falls, City of LU NA NA NA
3 Idaho Falls, City of SF NA NA NA
4 Idaho Power Company SF NA NA NA
5 Ingram Warm Springs Ranch Partnership LU NA NA NA
6 Intermountain Power Agency LU NA NA NA
7 J. Aron & Company SF NA NA NA
8 JP Morgan Ventures Energy Corporation SF NA NA NA
9 Jake Amy LU NA NA NA
10 Kennecott Utah Copper LLC LU NA NA NA
11 Lacomb Irrigation District LU NA NA NA
12 SF NA NA NA
l 3 l Logan clty I NA NA NA
14 NA NA NA
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.7
Name of Respondent This Report Is: Data of Report Year/Period of Report
PaciliCo rp 1(1 ) An Original (Mo, Da,Yr) End of 2011/Q4 I (2) MA Resubmission 06/28/2012
PUICHAO PQWER(Accourlt 555) (Continued) (Including power excnanges)
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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (I) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other 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 MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
-295,099 1
48,56d 2,725,881 2
4,011 140,07q 140,070 3
131,261 2,082,0011 2,086,977 4
1,201 66,78 66,783 5
571,551 27,759,59 27,759,598 6
42,401 1,585,19 -16,638,838 7
285,91 8,122,77, -6,922,651 8
1,94" 103,64 103,648 9
33,36 1,375,47 4,635,177 10
4,631 114,99f 149,801 11
131,592 12
698 69813
1,701 42,500 42,500 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,261
FERC FORM NO. 1 (ED. 12-90) Page 327.7
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PaciliCo (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
PUFCHA$ED POWER (Account 555) (including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Deman
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Los Angeles Dept. of Water & Power SF NA NA NA
2 Lower Valley Energy, Inc. IU NA NA NA
3 Loyd Fery LU NA NA NA
4 Macquarie Energy LLC SF NA NA NA
5 Marsh Valley Hydro Electric Company LU NA NA NA
6 Middle Fork Irrigation District LU NA NA NA
7 Mink Creek Hydro LLC LU NA NA NA
8 Monsanto Company lU NA NA NA
9 Morgan City Corporation NA NA NA
10 Morgan Stanley Capital Group, Inc. NA NA NA
11 Morgan Stanley Capital Group, Inc. IF 100 0 0
12 Morgan Stanley Capital Group, Inc. SF NA NA NA
13 Mountain Wind Power II, LLC LU NA NA NA
14 Mountain Wind Power, LLC LU NA NA NA
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.8
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
PacifiCo 1(1) An Original (Mo, Da, Yr) End of 2011/Q4
(2) MXA Resubmission 06/28/2012
PUkCHASED PQWER(Account 555) (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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on 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 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 MegaWatt Hours MegaWatt Hours Demand Charges
_______________
Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m)
80,424 4,050,357 4,050,357 1
7,32q 492,361 492,369 2
33 21,86: 21,863 3
322,62d 6,876,411 6,641,351 4
5,92 329,49: 329,493 5
24,23 1,374,45$ 1,374,459 6
11,168 608,55C 608,550 7
17,109,978 8
21 2,226 2,226 9
1,191 44,445 10
3,150,000 . 3,150,000 11
1,654,32E 51,266,046 6,427,294 12
240,841 15,439,121 15,439,121 13
186,50 10,367,567 10,367,567 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261 ,26t
FERC FORM NO. 1 (ED. 12-90) Page 327.8
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Pacif'iCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
PUICHA$ED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 reliability of requirement service must be the
same as, or second only to, the suppliers 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 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)
Average
Monthly NCP Deman
Average
Monthly CP Demand N 0. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Nephi City Corporation NA NA NA
2 Nevada Power Company NA NA NA
3 Nevada Power Company SF NA NA NA
4 NextEra Energy Power Marketing, LLC SF NA NA NA
5 Nicholson's Sunny Bar Ranch LU NA NA NA
6 Noble Americas Gas & Power Corp. SF NA NA NA
7 NorthWestern Corporation SF NA NA NA
8 Nucor Corporation IF NA NA NA
9 O.J. Power Company NA NA NA
10 O.J. Power Company LU NA NA NA
11 Oregon Environmental Industries, LLC LU NA NA NA
12 Oregon Institute of Technology NA NA NA
13 Oregon Institute of Technology LU NA NA NA
14 Oregon State University LU NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.9
Name of Respondent This Report Is: Data of Report Year/Period of Report
PacifiCo I (1)An Original (Mo, Da, Yr) End of 2011/Q4
I (2)3A Resubmission 06/28/2012
PUICHA) POWER(Accourit 555) (Continued) (Including power excnanges)
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 (U. Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other 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
MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No.
Received Delivered ($) ($) ($) of Settlement($)
(g) (Ii) (I) (j) (k) (I) (m) -
17 1,828 1,828 1
101 3,201 3,200 2
60,02: 2,213,50 2,268,366 3
4,45l 107,171 107,170 4
1,991 110,151 110,156 5
1,591 49,30,r 49,305 6
29E 1,25C 8,370 7
4,998,000 8
-11 -9299
84 43,80 43,809 10
23,657 1,339,091 1,339,099 11
-11 -525 12
1 1 - Th
87 1,496 1,498 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,26
FERC FORM NO. I (ED. 12-90) Page 327.9
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp (1)LJAn Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
PUFCHAED POWER (Account 555) (Including power exthanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 availability and reliability of the designated unit.
lU - 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)
Average
Monthly NCP Deman
Average
Monthly CP Demand N 0. (Footnote ia ions1 Affil Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Oregon Trail Windfarm, LLC NA NA NA
2 Oregon Trail Windfarm, LLC LU NA NA NA
3 PPL EnergyPlus, LLC SF NA NA NA
4 Pacific Canyon Windfarm, LLC NA NA NA
5 Pacific Canyon Windfarm, LLC LU NA NA NA
6 Pacific Gas & Electric Company SF NA NA NA
7 3F NA NA NA
8 Paul Luckey LU NA NA NA
9 Payson City Corporation NA NA NA
10 Platte River Power Authority NA NA NA
11 Portland General Electric Company NA NA NA
12 Portland General Electric Company
RSF
NA NA NA
13 Portland General Electric Company NA NA NA
14 Portland General Electric Company NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.10
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCo I (1) LJAn Original (MO, Da, Yr) End of 2011/Q4
(2) A Resubmission 06/28/2012
PUICHA PQWER(Account 555) (Continued) (Including power excnanges)
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 monnthty (or longer) basis, enter the
monthly average bilfing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other 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
MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+I) Purchased No Received Delivered ($) of Settlement ($)
-21 -1,317 1
27,231 1,717,74E 1,717,749 2
118,74E 3,313,871 3,313,878 3
-11 -1,241 4
20,11 1,266,421 1,266,425 5
10,801 209,501 209,500 6
1,601 50,301 50,300 7
27E 36,801 36,807 8
119 1,701 1,709 9
3,411 1 99,438 10
2,748 11
12,001 345,000 12
2,400 13
52,78: 1,419,598 1,427,685
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,26
FERC FORM NO. I (ED. 12-90) Page 327.10
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp (1)LJAn Original (Mo, Da, Yr) End of 2011/Q4 (2)OA Resubmission 06/28/2012
PURCHASED POWER (Account 555) (Including power excnanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Demanc
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (c) (d) (e) (f)
1 Power County Wind Park North, LLC LU NA NA NA
2 Power County Wind Park South, LLC LU NA NA NA
3 Powerex Corporation SF NA NA NA
4 Provo City Corporation NA NA NA
5 Public Service Company of Colorado SF NA NA NA
6 Public Service Company of New Mexico SF NA NA NA
F
7.
"PUD
LU NA NA NA
8 1 of Chelan County NA NA NA
9 1 RiD #1 of Chelan County SF NA NA NA
10 NA NA NA
11P1JD#1ofCowIICounty I NA NA NA
12 NA NA NA
13 PUD 01 of Douglas County NA NA NA
14 PUD #1 of Douglas County NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.11
Name of Respondent I This Re ort Is: Data of Report Year/Period of Report
PacifiCo (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)MXA Resubmission 06/28/2012
PUICHASED PQWER(Accourit 555) (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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on 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 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
MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No Received Delivered ($) ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m)
2,941 147,460 147,460 1
2,910 156,693 156,693 2
247,796 8,598,651 8,629,062 3
101 9,641 9,647 4
26,774 550,21 550,218 5
164,296 5,305,54 5,447,362 6
358,993 3,495,315 7
1,200 8
43,081 1,050,81 C 1,052,942 9
-38,499 10
-509 11
-104,836 12
-118,185 13
69,941 1,803,976 1,803,976 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,26
FERC FORM NO. I (ED. 12-90) Page 327.11
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCo (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
PUFCHAED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 availability and reliability of the designated unit.
lU - 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)
Average
Monthly NCP Demanc
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
I PUD #1 of Douglas County LU NA NA NA
2 1 PUD #1 of Douglas County SF NA NA NA
3 NA NA NA
I NA NA NA
5
4I;PUD1M -&Lr&bCou*
NA NA NA
6 NA NA NA
7 Grant County 14 NA NA
8 PUD #2 of Grant County LU NA NA NA
9 PUD #2 of Grant County SF NA NA NA
10 Puget Sound Energy, Inc. SF NA NA NA
11 Rainbow Energy Marketing Corporation SF NA NA NA
12 Ralphs Ranch, Inc. NA NA NA
13 Ralphs Ranch, Inc. LU NA NA NA
14 Rock River 1, LLC LU NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.12
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
PacifiCo (1) An Original (MO, Da, Yr) End of 2011/04 I (2) 1A Resubmission 06/28/2012
PUICHA PQWER(Accoupt 555) (Continued) (Including power excnanges)
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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other 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 dehvered 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.
Mega Watt Hours POWER EXCHANGES _____________ COST/SETTLEMENT OF POWER Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) of Settlement($)
(g) (h) (i) (I) (k) (I) (m)
254,786 3,266,126 1
32,29E 921,75 922,195 2
I 8,502 3
911 27,915 27,915 4
44,161 781,72C 781,720 5
-16,915 6
87,601 185,558 5,860,350 6,367,535 7
427,30 9,504,82c1 3,110,996 8
45,29 1,054,36E 1,057,569 9
246,931 6,776,141 6,785,776 10
43,12 1,501,853 1,501,853 11
-11 -713 12
21 28,046 28,046 13
136,071 4,828,071 4,828079 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261 ,26
FERC FORM NO. I (ED 12-90) Page 327.12
Name of Respondent This Report Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4 (2)A Resubmission 06/28/2012
PURCHASED POWER (Account 555) (including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Demanc
Average
Monthly CP Demand N No. (Footnote e iauonsj 'F Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 SF NA NA NA
2 Roseburg Forest Products Company LU NA NA NA
3 Roseburg Forest Products Company NA NA NA
4 Rough & Ready Lumber Company LU NA NA NA
5 Roush Hydro Inc. LU NA NA NA
6 Sacramento Municipal Utility District NA NA NA
7 Sacramento Municipal Utility District NA NA NA
8 Sacramento Municipal Utility District 1SF 1 NA NA NA
9 Salt River Project SF NA NA NA
10 San Diego Gas & Electric Company NA NA NA
11 San Diego Gas & Electric Company SF NA NA NA
12 Sand Ranch Windfarm, LLC NA NA NA
13 Sand Ranch Windfarm, LLC LU NA NA NA
14 Santiam Water Control District LU 0.2 0.2 0.2
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.13
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PaciflCo I (1)An Original (Mo, Da, Yr) End of 2011/Q4
I (2)[A Resubmission 06/28/2012
PUkCHAS!f PQWER(Account 555) (Continued) (Including power excnange)
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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other 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.
Mega Watt Hours POWER EXCHANGES ______________ COST/SETTLEMENT OF POWER Line MegaWatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased d C No. Received Delivered ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
5,336 124,292 124,292 1
96,781 5,491,82q 5,491,820 2
39,61 E 2,112,297 2,112,297 3
8,811 663,395 563,395 4
329 21,301 21,306 5
-21,371 6
200,731 3,629,211 3,629,216 7
3,565 83,951 83,951 8
121,348 4,788,151 4,789,343 9
251
801 26,000 26,000 11
-1,459 12
24,15: 1,518,431 1,518,431 13
1,60 13,632 147,531 161,168 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,26
FERC FORM NO. I (ED. 12-90) Page 327.13
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PaciflCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4 (2)A Resubmission 06/28/2012
PUICHASED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Deman
Average
Monthly CP Demand N 0. (Footnote ia IOflS1 Affil Classifl-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Seattle City Light SF NA NA NA
2 Sempra Energy Trading LLC SF NA NA NA
3 Sempra Generation SF NA NA NA
4 Shell Energy North America (US), L.P. NA NA NA
5 Shell Energy North America (US), L.P. SF NA NA NA
6 Shoshone Irrigation District LU 2.5 1.4 1.1
7 Sierra Pacific Power Company SF NA NA NA
8 Sierra Pacific Power Company SF NA NA NA
9 Simplot Phosphates LLC LU 10 12 9
10 Slate Creek Hydra Company, Inc. NA NA NA
11 Slate Creek Hydro Company, Inc. LU 3.7 2.3 1.6
12 Southern California Edison Company SF NA NA NA
13 Southwestern Public Service Company SF NA NA NA
14 Spanish Fork City Corporation NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.14
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCo (1)An Original (Mo, Da, Yr) End of 2011/Q4 (2)MA Resubmission 06/28/2012
PUkCHAD PQWER(Accourit 555) (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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on 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 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 MegaWatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m)
187,077 4,175,98k 4,179,847 1
14,833,291 2
50 15,841 15,844
500 4
383,32: 9,774,871J -26,844,382 5
9,571 170,763 397,102 567,866 6
20,94C 899,45 901,829 7
2,78 172,206 8
73,36 296,400 3,325,03 3,621,435 9
66,812 10
14,810 202,903 1,517,786 1,720,689 11
65,801 2,086,341 2,086,341 12
4,008 124,797 124,797 13
-325 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,26
FERC FORM NO. I (ED. 12-90) Page 327.14 :
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PaciflCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)MA Resubmission 06128/2012
PUCHA$ED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Demanc
Average
Monthly CP Demand N 0. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Spanish Fork Wind Park 2, LLC LU NA NA NA
2 Sprague Hydro, LLC LU 0.4 0.7 0.4
3 Springville City Corporation NA NA NA
4 Stahlbush Island Farms, Inc. Iii NA NA NA
5 Strawberry Electric Service District NA NA NA
6 Sunnyside Cogeneration Associates LU 52 53 52
7 Swalley Irrigation District LU NA NA NA
8 Tacoma Power SF NA NA NA
9 Tata Chemicals (Soda Ash) Partners NA NA NA
10 Tesoro Refining and Marketing Company LU NA NA NA
11 Thayn Hydro LLC LU 0.2 0.4 0.2
12 The Energy Authority, Inc. SF NA NA NA
13 The Town of the City of Buffalo NA NA NA
14 The Town of the City of Buffalo LU 0.2 0.2 0.2
Total
FERC FORM NO. I (ED. 12-90) Page 326.15
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCo (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)JA Resubmission 06/28/2012
PUCHAt PQWER(Accoupt 555) (Continued) (Including power excnanges)
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 (1). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
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 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 MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased d C No. Received Delivered ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
47,380 2,424,027 2,424,027 1
3,1271 46,919 359,241 406,168 2
41 6,137 6,137 3
7,831 429,137 429,137 4
57 4,985 4,985 5
419,308 10,576,481 15,591,998 26,168,479 6
2,362 151,061 151,069 7
24,312 545,461 546,878 8
2,54 37,90 37,903 9
32,43 1,259,111 1,259,118 10
2,04 58,498 162,041 220,544 11
29,59 707,671 707,676 12
13
1,849 31,896 172,176 204,072 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,26
FERC FORM NO. I (ED. 12-90) Page 327.15
Name of Respondent This Report Is: Data of Report Year/Period of Report
PacifiCorp (1)UAn Original (Mo, Da, Yr) End of 2011/Q4
(2)ZIA Resubmission 06/28/2012
PURCHA$ED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Demanc
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Three Buttes Windpower, LLC LU NA NA NA
2 Threemile Canyon Wind I, LLC NA NA NA
3 Threemile Canyon Wind I, LLC LU NA NA NA
4 lop of The World Wind Energy LLC LU NA NA NA
5 TransAlta Energy Marketing (U.S.) Inc. SF NA NA NA
6 TransCanada Energy Sales Ltd. SF NA NA NA
7 ________ 25 25 20
8 Tn-State Gen. & Trans. SF NA NA NA
9 Tucson Electric Power Company SF NA NA NA
10 UNS Electric, Inc. SF NA NA NA
11 US Magnesium LLC NA NA NA
12 LUS Magnesium LLC LU NA NA NA
13 LU NA NA NA
14 NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.16
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCo rp I (1) An Original (Mo, Da, Yr) End of 2011/Q4 (2) A Resubmission 06/28/2012
PUkCHASED PQWER(Account 555) (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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on 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 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.
Mega Watt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
MegaWatt Hours MegaWatt Hours
______________
Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased h d No Received Delivered ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
359,80C 22,902,276 22,902,276 1
24 2
25,147 1,604,816 1,604,816 3
685,448 45,239,581 45,239,588 4
112,313 3,342,811 3,342,811 5
201 11,00( 11,000 6
131,441 6,051,000 3,199,396 9,250,396 7
33,961 743,835 1,053,975 8
51,031 1,621,015 1,621,957 9
180,544 5,344 5,344,287 10
5,262,758 11
155,597 6,233,791 6,233,791 12
14,381 709,264 709,264 13
4,444 153,090 153,090 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,26
FERC FORM NO. I (ED. 12-90) Page 327.16
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)JA Resubmission 06/28/2012
PUICHA$ED POWER (Account 555) (induding power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Demanc
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Utah Associated Municipal Power SF NA NA NA
2 Utah Municipal Power Agency SF NA NA NA
3 Wagon Trail, LLC NA NA NA
4 Wagon Trail, LLC LU NA NA NA
5 Ward Butte Windfarm, LLC NA NA NA
6 Ward Butte Windfarm, LLC LU NA NA NA
7 Warm Springs Forest Products LU NA NA NA
8 LU
LU
NA NA NA
9 Weber County NA NA NA
10 Western Area Power Administration NA NA NA
11 Western Area Power Administration SF NA NA NA
12 Western Area Power Administration SF NA NA NA
13 Wolverine Creek Energy, LLC NA NA NA
14 Wolverine Creek Energy, LLC LU NA NA NA
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.17
Name of Respondent I This Report Is: Data of Report Year/Period of Report
PacifiCo (
1
)LJAn Original (Mo, Da, Yr) End of 2011/Q4
(2) IA Resubmission 06/28/2012
PUkCHASED PQWER(Account 555) (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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on 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 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
Megawatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
14,615 454,461 454,461 1
100 4,OOC 4,000 2
93 6,344 3
7,644 480,667 480,567 4
-1 -8935
18,864 1,181,371 1,181,376 6
ii 10___
447 22,27 22,273 8
4,846 224,041 224,046 9
-84 -21,562 10
27,12 764,490 11
4,70 90,93 90,965 12
-16 -9,063 13
198,62 11,052,65E 11,052,658 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,19 -411,145,301 398,261,261
FERC FORM NO. I (ED. 12-90) Page 327.17
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/04
(2)A Resubmission 06/28/2012
PURCHASED POWER(Account 555) (Including power excnanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Demanc
Average
Monthly CP Demand N 0. (Footnote ia ions1 Affil Classili-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Yakima-Tieton Irrigation District LU NA NA NA
2 Settlement/Reserves AD NA NA NA
3 Netting - Trading AD NA NA NA
4 Netting - Bookouts AD NA NA NA
5 Net Power Cost/REC Deferrals AD NA NA NA
6 Accrual NA
71 1
8 Power Exchanges
9 Arizona Public Service Company EX 306 NA NA NA
10 Avista Corporation EX 554 NA NA NA
11 Basin Electric Power Cooperative EX T-1 1 NA NA NA
12 Black Hills Power, Inc. EX 246 NA NA NA
13 Bonneville Power Administration 237 NA NA NA
14 Bonneville Power Administration EX 237 NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.18
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
PacifiCo 1(1) An Original (Mo, Da, Yr) End of 2011/Q4
(2) EJA Resubmission 06/28/2012
PUICHASED PQWER(Account 555) (Continued) (Including power excnanges)
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 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 ), 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.
Mega Watt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER _____________ Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No Received Delivered ($) ($) of Settlement($)
(g) (h) (i) (j) k5 (I) (m) -
5,876 355,706 355,706 1
-2,675,134 2
-11,500,014 3
-5,705,30 -167,137,515 4
-94,016,281 5
-534,465 6
-
8
565,323 571,256 906,764 9
1,789 10
9,697 206 251,795 11
92
4,466 -11,164 13
32,799 -79,890 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,26 il
FERC FORM NO. I (ED. 12-90) Page 327.18
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PaciflCo (1)An Original (Mo, Da, Yr) End of 2011/04
(2)jA Resubmission 06/28/2012
PURCHA$ED POWER(Account 555) (Including power excrianges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Demanc
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Bonneville Power Administration EX 256 NA NA NA
2 Bonneville Power Administration EX 368 NA NA NA
3 Bonneville Power Administration EX 411 NA NA NA
4 Bonneville Power Administration EX 554 NA NA NA
5 Bonneville Power Administration EX NA NA NA
6 Bonneville Power Administration EX T-1 1 NA NA NA
7 1 Bonneville Power Administration EX T-12 NA NA NA
8 City of Redding EX 364 NA NA NA
9 Colockum Transmission Company EX T-12 NA NA NA
10 Constellation Energy Commodities Group EX T-1 1 NA NA NA
11 Deseret Generation & Transmission Coop 280 NA NA NA
12 Deseret Generation & Transmission Coop EX 280 NA NA NA
13 Deseret Generation & Transmission Coop EX 21 NA NA NA
14 Emerald People's Utility District 351 NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.19
Name of Respondent This Re ort Is: Data of Report Year/Period of Report
PacifiCo I (1)An Original (Mo, Da, Yr) End of 2011/Q4
I (2)A Resubmission 06/28/2012
PUkCHAS PQWER(Accoupt 555) (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 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 (U. 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 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 Megawatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No Received Delivered ($) ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
259 5,698 1
249,993 249,992 1,500,000 2
941,4501 963,256 -660,000 3
207,703 17,056 I I
-36,755,000 5
11,606 9,465 40,948 6
156,020 111,559 1,421,058 7
115,883 117,207 -104,223 8
102,511 I
806 53 11,656 10
460 -2,301 100,992 11
30,459 66,687 -1,364,551 12
1,690 I 13
-6 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,26
FERC FORM NO. I (ED. 12-90) Page 327.19
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)LJAn Original (Mo, Da, Yr) End of 2011/Q4
(2)A Resubmission 06/28/2012
PUFCHA$ED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 availability and reliability of the designated unit.
lU - 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)
Average
Monthly NCP Deman
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (c) (d) (e) (f)
I Emerald People's Utility District EX 351 NA NA NA
2 Eugene Water & Electric Board EX T-12 NA NA NA
3 lberdrola Renewables, Inc. EX T-11 NA NA NA
4 Idaho Power Company EX 380 NA NA NA
5 Intermountain Renewable Power, LLC EX T-1 1 NA NA NA
6 JP Morgan Ventures Energy Corporation EX T-1 I NA NA NA
7 Los Angeles Dept. of Water & Power EX OV-1 NA NA NA
8 Milford Wind Corridor Phase I, LLC EX OV-1 NA NA NA
9 Milford Wind Corridor Phase II, LLC EX OV-1 NA NA NA
10 NextEra Energy Power Marketing, LLC EX T-1 1 NA NA NA
11 Noble Americas Energy Solutions LLC EX T-1 1 NA NA NA
12 Portland General Electric Company EX 554 NA NA NA
13 Powerex Corporation EX T-1 1 NA NA NA
14 Public Service Company of Colorado EX 319 NA NA NA
Total
FERC FORM NO. I (ED. 12-90) Page 326.20
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCo 1(1 ) An Original (Mo, Da,Yr) End of 2011/Q4
(2) K1A Resubmission 06/28/2012
PUICHASEQ PQWER(Accourit 555) (Continued) (lncudIng power excflange)
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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other 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 MegaWatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
571 -14,270 1
20,002 19,933 4,148 2
5,097 558 116,340 3
416,278 299,783 I
2,502 1,845 16,774 5
2,170 1,604 14,199 6
2,275 164,407 7
1,592 -134,454 8
683 -57,633 9
130,212 87,913 512,208 10
3,239 5,450 -99,324 11
132,557 131,551 12
656 3,270 -61,606 13
5,460 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,261
FERC FORM NO. I (ED. 12-90) Page 327.20
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)OA Resubmission 06/28/2012
PURCHASED POWER (Account 555) (Including power excnanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 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.
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)
Average
Monthly NCP Deman
Average
Monthly CP Demand No. (FootnoteAffiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 Public Service Company of Colorado EX 320 NA NA NA
2 Public Service Company of Colorado EX T-12 NA NA NA
3 PUD #1 of Chelan County EX 1554 NA NA NA
4 PUD #1 of Cowlitz County EX 1554 NA NA NA
5 Seattle City Light T-1 1 NA NA NA
6 Seattle City Light EX 554 NA NA NA
7 Seattle City Light EX T-1 1 NA NA NA
8 Southern California Edison Company EX T-1 1 NA NA NA
9 Tri-State Gen. & Trans. 319 NA NA NA
10 Tri-State Gen. & Trans. T-1 1 NA NA NA
11 Tri-State Gen. & Trans. I EX 1319 NA NA NA
12 Tri-State Gen. & Trans. EX T-11 NA NA NA
13 Utah Associated Municipal Power r-i 1 NA NA NA
14 Utah Associated Municipal Power EX 1-11 NA NA NA
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.21
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
PaciflCo (1)LJAn Original (Mo, Da, Yr) End of 2011/Q4
(2)EKIA Resubmission 06/28/2012
PUkCHASED PQWER(Accourit 555) (Continued) (Induding 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 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 (U. Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7.Report demand charges in column (j), energy charges in column (k), and the total of any other 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
Megawatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
1,095,097 1,090,347 4,500,000 1
78,842 79,999 -203,681 2
94,164 103,920 -92,421 3
228,957 264,313 I
-5,031 5
356,254 352,058 -223,712 6
10,120 8,661 34,148 7
66,972 60,015 121,641 8
7,358 9
-1 37 -1,019 10
5,465 10,456 11
15,493 1,834 390,906 12
4,664 -7,001 379,950 13
119,482 52,183 1,784,393 14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,261,261
FERC FORM NO. 1 (ED. 12-90) Page 327.21
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
aci I orp fC (1)LJAn Original (Mo, Da, Yr) End of 2011/Q4
(2)MA Resubmission 06/28/2012
PUFCHA$ED POWER (Account 555) (Including power exchanges)
1.Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2.Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or 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 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 availability and reliability of the designated unit.
lU - 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)
Average
Monthly NCP Demanc
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
i Utah Municipal Power Agency EX T-1 1 NA NA NA
2 Warm Springs Power Enterprises EX T-1 I NA NA NA
3 Western Area Power Administration LAS-4 NA NA NA
4 Western Area Power Administration EX LAS-4 NA NA NA
5 System Deviation NA NA NA
6
7
8
9
10
11
12
13
14
Total
FERC FORM NO. I (ED. 12-90) Page 326.22
Name of Respondent This Re ort Is: Data of Report Year/Period of Report
PacifiCo (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)EA Resubmission 06/28/2012
PURCHASED PQWER(Accourit 555) (Continued) (Induding 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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6.Report in column (g) the megawatthours shown on 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 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.
Mega Watt Hours POWER EXCHANGES ______________ COST/SETTLEMENT OF POWER Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m) -
38,727 7,508 964,955 1
2,174 10,673 -240,238 2
-15,466 12,058 -336,370 3
1,292 57,648 -704,044 4
6,730 5
6
7
8
9
10
11
12
13
14
14,094,451 14,561,771 14,342,455 115,021,376 694,385,193 -411,145,301 398,26126
FERC FORM NO. I (ED. 12-90) Page 327.22
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Schedule Page: 326 Line No.: 2 Column: b
Arizona Public Service Company - Contract Termination Date: October 31, 2020.
Schedule Page: 326 Line No.: 3 Column: I I
Line loss.
Schedule Page: 326 Line No.: 4 Column: I I
Reserve Share.
Schedule Page: 326 Line No.: 6 Column: I
Financial Swap.
Schedule Page: 326 Line No.: 9 Column: I I
Financial Swap.
Schedule Page: 326 Line No.: 10 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
ISchedule Page: 326 Line No.: 11 Column: b I
Settlement adjustment.
ISchedule Page: 326 Line No.: 11 Column: I
Settlement adjustment.
ISchedule Pace: 326 Line No.: 13 Column: b I
Settlement adjustment.
Schedule Page: 326 Line No.: 13 Column: I I
Settlement adjustment.
Schedule Page: 326.1 Line No.: I Column: I I
Non-generation agreement.
Schedule Page: 326.1 Line No.: 3 Column: b I
Settlement adjustment.
ISchedule Page: 326.1 Line No.: 3 Column: I I
Operation and maintenance expense associated with the combustion turbine located in Rapid
City, South Dakota.
Schedule Page: 326.1 Line No.: 4 Column: I I
Operation and maintenance expense associated with the combustion turbine located in Rapid
City, South Dakota.
Schedule Page: 326.1 Line No.: 7 Column: b I
Blanding City Corporation - Contract Termination Date: March 31, 2012.
Schedule Page: 326.1 Line No.: 8 Column: b
Bonneville Power Administration - Contract Termination Date: August 31, 2011.
Schedule Page: 326.1 Line No.: 9 Column: b I
Bonneville Power Administration - Contract Termination Date: 30 days written notice.
ISchedule Paae: 326.1 Line No.: 9 Column: I I
Ancillary services.
ISchedule Page: 326.1 Line No.: 10 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.1 Line No.: 10 Column: I
Ancillary services.
Schedule Page: 326.1 Line No.: 11 Column: I
Reserve Share.
Schedule Page: 326.1 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.1 Line No.: 12 Column: I
Settlement adjustment.
Schedule Page: 326.1 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.1 Line No.: 14 Column: I
Settlement adjustment.
lSchedule Page: 326.2 Line No.: 3 Column: I
IFERC FORM NO. 1 (ED. 12-87) Page 450.1
Name of Respondent This Report is: Date of Report Yea Period of Report
(1) _An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06128/2012 2011/Q4
FOOTNOTE DATA
Variable operating, maintenance and fuel expense associated with gas facility located in
West Valley, Utah.
ISchedule Page: 326.2 Line No.: 4 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "CALIFORNIA INDEPENDENT SYSTEM OPERATOR" ON
PAGES 326-327: Complete name is California Independent System Operator Corporation.
Schedule Page: 326.2 Line No.: 4 Column: b
Settlement adjustment.
lSchedule Page: 326.2 Line No.: 4 Column: I
Settlement adjustment.
Schedule Page: 326.2 Line No.: 7 Column: b
Settlement adjustment.
ISchedule Page: 326.2 Line No.: 7 Column: I
Settlement adjustment.
Schedule Page: 326.2 Line No.: 8 Column: I
inanciai. Swap.
Schedule Page: 326.2 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.2 Line No.: 10 Column: I
Settlement adjustment.
Schedule Page: 326.2 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.2 Line No.: 13 Column: I
Settlement adjustment.
LSchedule Page: 326.2 Line No.: 14 Column: I
Financial Swap.
ISchedule Page: 326.3 Line No.: 5 Column: b
City of Hurricane - Contract Termination Date: August 31, 2012.
Schedule Page: 326.3 Line No.: 6 Column: b
Settlement adiustment.
Schedule Page: 326.3 Line No.: 6 Column: I
Settlement adjustment.
Schedule Page: 326.3 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES 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: I
Financial Swap.
ISchedule Page: 326.4 Line No.: I Column: b
Settlement adjustment.
Schedule Page: 326.4 Line No.: I Column: I
Settlement adjustment.
Schedule Page: 326.4 Line No.: 4 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "DESERET GENERATION & TRANSMISSION COOP" ON
PAGES 326-327: Complete name is Deseret Generation and Transmission Cooperative.
Schedule Page: 326.4 Line No.: 4 Column: b
Deseret Generation and Transmission Cooperative - Contract Termination Date: September 30,
2024.
Schedule Page: 326.4 Line No.: 4 Column: I
Purchased power charges reimbursing counterparty for coal fired generation unit operation
and maintenance costs.
Schedule Page: 326.4 Line No.: 5 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.4 Line No.: 5 Column: I
Liquidated damages.
Schedule Page: 326.4 Line No.: 6 Column: I
IFERC FORM NO. I (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) X A Resubmission 06/28/2012 2011 /Q4
FOOTNOTE DATA
Financial Swap.
Schedule Page: 326.4 Line No.: 8 Column: b I
Settlement adjustment.
Schedule Page: 326.4 Line No.: 8 Column: I I
Settlement adjustment.
ISchedule Page: 326.4 Line No.: 12 Column: b I
Settlement adjustment.
lSchedule Page: 326.4 Line No.: 12 Column: I 1
Settlement adjustment.
Schedule Page: 326.4 Line No.: 14 Column: I I
Financial Swap.
Schedule Page: 326.5 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 326.5 Line No.: 2 Column: I I
Line loss.
ISchedule Page: 326.5 Line No.: 10 Column: b I
Settlement adjustment.
Schedule Page: 326.5 Line No.: 10 Column: I I
Settlement adjustment.
Schedule Page: 326.5 Line No.: 12 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.5 Line No.: 14 Column: b I
Flathead Electric Cooperative, Inc. - Contract Termination Date: September 30, 2016.
Schedule Paae: 326.5 Line No.: 14 Column: I I
Line loss.
Schedule Page: 326.6 Line No.: I Column: b
Settlement adjustment.
ISchedule Page: 326.6 Line No.: I Column: I
Settlement adjustment.
Schedule Page: 326.6 Line No.: 3 Column: b
Settlement adjustment.
ISchedule Page: 326.6 Line No.: 3 Column: I
Settlement adjustment.
Schedule Page: 326.6 Line No.: 8 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.6 Line No.: 11 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.6 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.6 Line No.: 12 Column: I
Settlement adjustment.
Schedule Page: 326.6 Line No.: 13 Column: a
Hermiston Generating Company, L.P. operates the Hermiston Generating Plant, which is
jointly owned. PacifiCorp owns 50% of the plant. See -page 402.3 column (c) of this Form
No. 1 for further information on the Hermiston Generating Plant.
lSchedule Page: 326.6 Line No.: 13 Column: I
On peak incentive, supplemental dispatch efficiency expense, start-up charges and
committee settlements.
Schedule Page: 326.6 Line No.: 14 Column: I
Financial Swap.
Schedule Page: 326.7 Line No.: I Column: b
Settlement adjustment.
Schedule Page: 326.7 Line No.: I Column: I
Labor, equipment and administration fees associated with hydro project in Idaho Falls,
IFERC FORM NO.1 (ED. 12-87) Page 450.3
Name of Respondent
PacifiCorp
This Report is:
(1)_An Original 1 (2) X A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
2011/04
FOOTNOTE DATA
Idaho.
ISchedule Page: 326.7 Line No.: 2 Column: I
Labor, equipment and administration fees associated with hydro project in Idaho Falls,
Idaho.
Schedule Page: 326.7 Line No.: 4 Column: 1 ,
Reserve Share.
Schedule Page: 326.7 Line No.: 7 Column: I
Financial Swap.
Schedule Page: 326.7 Line No.: 8 Column: I
Financial Swap.
Schedule Page: 326.7 Line No.: 10 Column: I
Compensation for self-generation.
Schedule Page: 326.7 Line No.: 11 Column: I
Fixed annual payment.
Schedule Page: 326.7 Line No.: 12 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "LEHMAN BROTHERS COMMODITY SERVICES" ON PAGES
326-327: Complete name is Lehman Brothers Commodity Services, Inc.
Schedule Page: 326.7 Line No.: 12 Column: I
Termination settlement.
Schedule Page: 326.7 Line No.: 13 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.7 Line No.: 14 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "LOS ANGELES DEPT. OF WATER & POWER" ON PAGES
326-327: Complete name is Los Angeles Department of Water and Power.
Schedule Page: 326.7 Line No.: 14 Column: b
Secondary, economy and/or non-firm.
Schedule Paqe: 326.8 Line No.: 4 Column: I
Financial Swap.
Schedule Page: 326.8 Line No.: 8 Column: I
Compensation for interruptible service and operating reserves.
jçpdule Page: 326.8 Line No.: 9 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.8 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.8 Line No.: 10 Column: I
Settlement adjustment.
Schedule Page: 326.8 Line No.: 12 Column: I
Financial Swap.
Schedule Page: 326.9 Line No.: I Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.9 Line No.: 2 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.9 Line No.: 3 Column: I
Line loss.
cedule Page: 326.9 Line No.: 7 Column: I I Reserve Share.
Schedule Page: 326.9 Line No.: 8 Column: I
Ancillary services.
Schedule Page: 326.9 Line No.: 9 Column: b I Settlement adjustment.
çhedule Page: 326.9 Line No.: 9 Column: I I Settlement adjustment.
Schedule Page: 326.9 Line No.: 12 Column: b
Settlement adjustment.
IFERC FORM NO. 1 (ED. 12-87) Page 450.4 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PaciliCorp (2)X A Resubmission 06/2812012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 326.9 Line No.: 12 Column: I
Settlement adjustment.
Schedule Page: 326.10 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 326.10 Line No.: I Column: I
Settlement ad -iustment.
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "PACIFIC NORTHWEST GENERATING COOP." ON PAGES
326-327: Complete name is Pacific Northwest Generating Cooperative, Inc.
Schedule Page: 326.10 Line No.: 9 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Paae: 326.10 Line No.: 10 Column: I
Line loss.
Schedule Page: 326.10 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 326.10 Line No.: 11 Column: I
Operation expense plus amortization of unrecovered costs of Cove
Schedule Page: 326.10 Line No.: 12 Column: b
Portland General Electric Company - Contract Termination Date: R
longer operating for power production purposes.
Schedule Page: 326.10 Line No.: 12 Column: I
Operation expense plus amortization of unrecovered costs of Cove
Schedule Page: 326.10 Line No.: 13 Column: b
Secondary, economy and/or non-firm.
Butte project no
ect.
ISchedule Page: 326.10 Line No.: 13 Column: I
Liability associated with paper pond at hydro facility located on the Lewis River in the
state of Washington.
Schedule Page: 326.10 Line No.: 14 Column: I
Reserve Share.
Schedule Page: 326.11 Line No.: 3 Column: I
Financial Swap.
ISchedule Page: 326.11 Line No.: 4 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.11 Line No.: 6 Column: I
Line loss.
Schedule Page: 326.11 Line No.: 7 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "PUD #1 OF CHELAN COUNTY" ON PAGES 326-327:
Complete name is Public Utility District No. 1 of Chelan County.
Schedule Page: 326.11 Line No.: 7 Column: I
Operating expense, bond interest, amortization and taxes.
ISchedule Page: 326.11 Line No.: 8 Column: b
Secondary, economy and/or non-firm.
lSchedule Page: 326.11 Line No.: 8 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.: 9 Column: I
Reserve Share.
Schedule Paae: 326.11 Line No.: 10 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "PUD #1 OF COWLITZ COUNTY" ON PAGES 326-327:
Complete name is Public Utility District No. 1 of Cowlitz County.
IFERC FORM NO. I (ED. 12-87) Page 450.5 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 326.11 Line No.: 10 Column: b
Settlement adjustment.
ISchedule Page: 326.11 Line No.: 10 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.: 11 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.11 Line No.: 11 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.: 12 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "PUD #1 OF DOUGLAS COUNTY" ON PAGES 326-327:
Complete name is Public Utility District No. 1 of Douglas County.
Schedule Page: 326.11 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.11 Line No.: 12 Column: I
Settlement adjustment.
Schedule Page: 326.11 Line No.: 13 Column: b
Settlement adjustment.
lSchedule Page: 326.11 Line No.: 13 Column: I
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.11 Line No.: 14 Column: b
Public Utility District
2018.
No. 1 of Douglas County - Contract Termination Date: August 31,
Schedule Page: 326.12 Line No.: I Column: I
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.12 Line No.: 2 Column: I
Reserve Share.
Schedule Page: 326.12 Line No.: 3 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "PUD #1 OF LEWIS COUNTY"
Complete name is Public Utility District No. 1 of Lewis County.
ON PAGES 326-327:
Schedule Page: 326.12 Line No.: 3 Column: b
Settlement adjustment.
ISchedule Page: 326.12 Line No.: 3 Column: I
Settlement adjustment.
lSchedule Page: 326.12 Line No.: 4 Column: b
Public Utility District
notice.
No. 1 of Lewis County - Contract Termination Date: 60 days written
Schedule Page: 326.12 Line No.: 5 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "PUD #1 OF SNOHOMISH COUNTY" ON PAGES 326-327:
Complete name is Public Utility District No. 1 of Snohomish County.
Schedule Page: 326.12 Line No.: 6 Column: a
THIS FOOTNOTE APPLIES TO
Complete name is Public
ALL OCCURRENCES OF "PUD #2 OF GRANT COUNTY"
Utility District No. 2 of Grant County.
ON PAGES 326-327:
Schedule Page: 326.12 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.12 Line No.: 6 Column: I
Settlement adjustment.
Schedule Page: 326.12 Line No.: 7 Column: b
Public Utility District
2012.
No. 2 of Grant County - Contract Termination Date: August 15,
Schedule Page: 326.12 Line No.: 7 Column: I
Ancillary services.
Schedule Page: 326.12 Line No.: 8 Column: I
IFERC FORM NO. 1 (ED. 12-87) Page 450.6 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Operating expense, bond interest, amortization and taxes.
ISchedule Page: 326.12 Line No.: 9 Column: I
Reserve Share.
Schedule Page: 326.12 Line No.: 10 Column: I
Reserve Share.
Schedule Page: 326.12 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.12 Line No.: 12 Column: I
Settlement adiustment.
Schedule Page: 326.13 Line No.: I Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "ROCKY MOUNTAIN GENERATION COOP." ON PAGES
326-327: Complete name is Rocky Mountain Generation Cooperative, Inc.
Schedule Page: 326.13 Line No.: 3 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.13 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.13 Line No.: 6 Column: I
Settlement adjustment.
Schedule Page: 326.13 Line No.: 7 Column: b
Sacramento Municipal Utility District - Contract Termination Date: December 31, 2014.
Schedule Page: 326.13 Line No.: 9 Column: I
Line loss.
Schedule Page: 326.13 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.13 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.13 Line No.: 12 Column: I
Settlement adjustment.
Schedule Pace: 326.14 Line No.: I Column: I
Reserve Share.
Schedule Page: 326.14 Line No.: 2 Column: I
Financial Swap.
Schedule Page: 326.14 Line No.: 4 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.14 Line No.: 4 Column: I
Liability associated with paper pond at hydro facility located on the Lewis River in the
state of Washington.
Schedule Page: 326.14 Line No.: 5 Column: I
Financial Swap.
[Schedule Page: 326.14 Line No.: 7 Column: I
Reserve Share.
ISchedule Page: 326.14 Line No.: 8 Column: I
Line loss.
[Schedule Page: 326.14 Line No.: 10 Column: b
Settlement adjustment.
[Schedule Page: 326.14 Line No.: 10 Column: I
Settlement adiustment.
Schedule Page: 326.14 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.14 Line No.: 14 Column: I
Settlement adjustment.
Schedule Page: 326.15 Line No.: 3 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.15 Line No.: 5 Column: b
IFERC FORM NO. I (ED. 12-87) Page 450.7 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.15 Line No.: 8 Column: I
Reserve Share.
Schedule Page: 326.15 Line No.: 9 Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.15 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.16 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 326.16 Line No.: 2 Column: I
Settlement adjustment.
Schedule Page: 326.16 Line No.: 7 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "TRI-STATE GEN. & TRANS." ON PAGES 326-327:
Complete name is Tr i -State Generation and Transmission Association, Inc.
ISchedule Page: 326.16 Line No.: 7 Column: b
Tri-State Generation and Transmission Association, Inc. - Contract Termination Date:
December 31, 2020.
Schedule Page: 326.16 Line No.: 8 Column: I
Line loss.
Schedule Page: 326.16 Line No.: 9 Column: I
Line loss.
Schedule Page: 326.16 Line No.: 11 Column: b
US Magnesium LLC - Contract Termination Date: December 31, 2014.
Schedule Page: 326.16 Line No.: 11 Column: I
Ancillary services.
Schedule Page: 326.16 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "UNITED STATES AIR FORCE AT HILL BASE!! ON
PAGES 326-327: Complete name is United States Air Force at Hill Air Force Base.
Schedule Page: 326.16 Line No.: 14 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "UTAH ASSOCIATED MUNICIPAL POWER" ON PAGES
326-327: Complete name is Utah Associated Municipal Power Systems.
Schedule Page: 326.16 Line No.: 14 Column: b
secondary, economy and/or non-tirm.
ISchedule Page: 326.17 Line No.: 3 Column: b
Settlement adjustment.
ISchedule Page: 326.17 Line No.: 3 Column: I
Settlement adjustment.
Schedule Page: 326.17 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 326.17 Line No.: 5 Column: I
Settlement adjustment.
Schedule Page: 326.17 Line No.: 8 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "WASATCH INTEGRATED WASTE MANAGEMENT" ON PAGES
326 - 327: Complete name is Wasatch Integrated Waste Management District.
Schedule Page: 326.17 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.17 Line No.: 10 Column: I
Line loss.
ISchedule Page: 326.17 Line No.: 11 Column: I I Line loss.
Schedule Page: 326.17 Line No.: 12 Column: I
Reserve Share.
Schedule Page: 326.17 Line No.: 13 Column: b
Settlement adjustment.
IFERC FORM NO. 1 (ED. 12-87) Page 450.8 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 326.17 Line No.: 13 Column: I
Settlement adjustment.
Schedule Page: 326.18 Line No.: 2 Column: I
Release of reserve for potential liabilities associated with curtailment on receipt of
energy and settlement for unmetered megawatt hours.
Schedule Page: 326.18 Line No.: 3 Column: I
Reflects transactions that did not physically settle.
ISchedule Page: 326.18 Line No.: 4 Column: I
Reflects transactions that did not physically settle.
ISchedule Page: 326.18 Line No.: 5 Column: I
Regulatory net power cost and renewable energy credit deferrals.
ISchedule Page: 326.18 Line No.: 6 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
during this period.
Schedule Page: 326.18 Line No.: 9 Column: I
Exchanqe enerqy expense.
Schedule Pace: 326.18 Line No.: 11 Column: I
Imbalance energy.
Schedule Page: 326.18 Line No.: 13 Column: b I
Settlement adjustment.
Schedule Page: 326.18 Line No.: 13 Column: I I
Storaqe and exchanae charoes.
Schedule Page: 326.18 Line No.: 14 Column: I
Storage and exchange charges.
Schedule Page: 326.19 Line No.: I Column: I
Exchange energy expense. Storage and exchange charges.
Schedule Page: 326.19 Line No.: 2 Column: I
Settlement for historical billing dispute.
Schedule Page: 326.19 Line No.: 3 Column: I
Exchanqe enerqy expense.
ISchedule Page: 326.19 Line No.: 5 Column: c
Pacific Northwest Electric Power Planning and Conservation Act, FERC Electric Tariff,
Original Volume No. 1.
Schedule Page: 326.19 Line No.: 5 Column: h I
These megawatt hours represent book entry only. No actual energy transfer took place.
Schedule Page: 326.19 Line No.: 5 Column: i I
These megawatt hours represent book entry only. No actual energy transfer took place.
Schedule Page: 326.19 Line No.: 5 Column: I
Pacific Northwest Electric Power Planning and Conservation Act, FERC Electric Tariff,
Original Volume No. 1.
Schedule Page: 326.19 Line No.: 6 Column: I I
Imbalance enerov.
Schedule Page: 326.19 Line No.: 7 Column: I I
Exchange energy expense. Imbalance energy.
Schedule Page: 326.19 Line No.: 8 Column: I
Imbalance energy.
Schedule Page: 326.19 Line No.: 10 Column: I I
Imbalance energy.
Schedule Page: 326.19 Line No.: II Column: b 1
Settlement adjustment.
cheduIe Page: 326.19 Line No.: 11 Column: I I
Imbalance energy.
lSchedule Page: 326.19 Line No.: 12 Column: I I
IFERC FORM NO. 1 (ED. 12-87) Page 450.9 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Imbalance ene
ISchedule Page: 326.19 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.19 Line No.: 14 Column: I
Storage and exchange charges.
ISchedule Page: 326.20 Line No.: I Column: I
Storage and exchange charges.
ISchedule Page: 326.20 Line No.: 2 Column: I
Exchange energy expense.
Schedule Page: 326.20 Line No.: 3 Column: I
Imbalance energy.
Schedule Page: 326.20 Line No.: 5 Column: I
Imbalance energy.
Schedule Page: 326.20 Line No.: 6 Column: I
Imbalance energy.
Schedule Page: 326.20 Line No.: 7 Column: I
Station service for third party wind project.
Schedule Page: 326.20 Line No.: 8 Column: I
Reimbursement for providing station service to third party wind project.
Schedule Page: 326.20 Line No.: 9 Column: I
Reimbursement for providing station service to third party wind project.
Schedule Page: 326.20 Line No.: 10 Column: I
Imbalance enerqy.
ISchedule Paqe: 326.20 Line No.: 11 Column: I I
Imbalance energy.
Schedule Page: 326.20 Line No.: 13 Column: I
Imbalance energy.
Schedule Page: 326.21 Line No.: I Column: I
Storage and exchange charges.
Schedule Page: 326.21 Line No.: 2 Column: I
Exchange energy expense.
Schedule Page: 326.21 Line No.: 3 Column: I
Storage and exchange charges.
Schedule Page: 326.21 Line No: 5 Column: b
Settlement adjustment.
ISchedule Page: 326.21 Line No.: 5 Column: I
Imbalance energy.
[Schedule Page: 326.21 Line No.: 6 Column: I
Exchanqe enerqy expense.
ISchedule Paqe: 326.21 Line No.: 7 Column: I I
Imbalance energy.
lSchedule Page: 326.21 Line No.: 8 Column: I
Imbalance energy.
Schedule Page: 326.21 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.21 Line No.: 9 Column: I
Imbalance energy.
Schedule Page: 326.21 Line No.: 10 Column: b
Settlement adi ustment.
Schedule Page: 326.21 Line No.: 10 Column: I
Imbalance energy.
Schedule Paae: 326.21 Line No.: 11 Column: I
Imbalance energy.
Schedule Page: 326.21 Line No.: 12 Column: I
IFERC FORM NO. I (ED. 12-87) Page 450.10
Name of Respondent This Report is: ert Year/Period of Report
(1)An Original
DL06/28/20
, Yr
01P20) PadfiCorp (2)X A Resubmission 2011/Q4
FOOTNOTE DATA
Imbalance energy.
Schedule Page: 326.21 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.21 Line No.: 13 Column: I
Imbalance energy.
Schedule Page: 326.21 Line No.: 14 Column: I
Imbalance energy.
Schedule Page: 326.22 Line No.: I Column: I
Imbalance energy.
ISchedule Page: 326.22 Line No.: 2 Column: I
Imbalance energy.
Schedule Page: 326.22 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.22 Line No.: 3 Column: I
Imbalance energy.
Schedule Page: 326.22 Line No.: 4 Column: I
Imbalance energy.
Schedule Page: 326.22 Line No.: 5 Column: b
Not applicable: adjustment for inadvertent interchange.
IFERC FORM NO.1 (ED. 12-87) Page 450.11 I
Name of Respondent
PacifiCorp
This Re ort Is:
I (1) An Original

(2) MA Resubmission
I Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (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 affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission 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
N 0.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To Statistical
(Company of Public Authority) Classifi-
(Footnote Affiliation) cation
(c) (d)
1 Arizona Public Service Company Arizona Public Service Company
2 Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation
3 Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation
4 Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation
I Basin Electric Power Cooperative , Western Area Power Administration
8
P71B'Iack Electric Utility Company
Black Hills Corporation Montana-Dakota Utilities
Montana-Dakota Utilities
Black Hills, Inc.
Black Hills, Inc.
9 Black Hills Corporation
10
11
12
13
14
Black Hills Corporation
Black Hills Corporation
Black Hills Corporation
Black Hills Corporation
Black Hills Corporation
15 Black Hills Corporation
16
17
Bonneville Power Administration
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
18 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
19 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
20 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
21 Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative
22 Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative
23 Bonneville Power Administration Bonneville Power Administration
24 Bonneville Power Administration Bonneville Power Administration Bentoñ.REA
25 Bonneville Power Administration Bonneville Power Administration
26 Bonneville Power Administration Bonneville Power Administration Umatilla Elec & Columbia
27 Bonneville Power Administration Bonneville Power Administration
28 Bonneville Power Administration U.S. Bureau of Reclamation Bonneville Power Administration
29 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
30 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
31 Bonneville Power Administration Bonneville Power Administration Yakama Power
32 Bonneville Power Administration Bonneville Power Administration Yakama Power
33 1 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
34 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr) End of 2011/Q4 aci IfC Ofl (2) JA Resubmission 06128/2012
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
(Including transactions reffered to as wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.
-
MegaWatt Hours
Received (i)
MegaWatt Hours
Delivered a)
R.S. 436 orah/Brady Sub 1
7V1 1-3 YellowtaIl Sub Sheridan Sub 1 3,914 3,91 2
7V11-3 Yellowtail Sub Sheridan Sub 1 555 551, 3
7V11-7 Various Various 960 961 4
7V11-8 Various Various 170 171 5
7V11-8 Various Various 372 37 6
7V11-7 Various Various 2,475 2,47 7
7V1 1 Various Sheridan Sub 44 24,247 24,24 8
7V1 1 Various Sheridan Sub 44 380 381 9
7V11-8 Various Various 15,177 15,17 10
7V11-8 Various Various 346 341 11
7V11-7 Various Various 65,945 65,94F, 12
7V11-7 Various Various 525 52,9
7V11-7 Various Wyodak Substation 50 226,138 226,13E 14
7V1 1-7 Various Wyodak Substation 50 17,850 17,851 15
R.S. 369 Midpoint Substation Summer Lake Sub 16
R.S. 237 Various Various 319 1,230,813 1,230,81: 17
R.S.237 1Various 1Various 319 113,739 113,73! 18
7V11-7
7V11-3,4
7V11-3,4
AIvey Substation
Alvey Substation
Gazley Substation
56 268,555
28,678
22,793
268,55f
28,67q
22,79:
19
20
21
56
3
7V1 1-3 IBonneville Power Adm 'Gazley Substation 3 2,319 2,31 22
7V1 1-3 Bonneville Power Adm Tieton Substation 1 5,676 5,671 23
7V1 1-3 Bonneville Power Adm Tieton Substation 1 933 932 24
7V11-3 McNary Substation Hinkle Substation 1 702 702 25
7V11-3 McNary Substation Hinkle Substation 1 137 137 26
7V11-7 USBR Green Springs Bonneville Power Adm 18 62,183 62,18: 27
7V11-7 USBR Green Springs Bonneville Power Adm 18 4,919 4,91! 28
R.S. 368 Malin Substation Malin Substation 641,015 641,01 29
R.S. 368 Malin Substation Mali Substation I 58,722 58,722 30
7V11-3,4 Bonneville Power Adm 6 32,545 32,54 31
7V11-3,4 Bonneville Power Adm 6 3,099 3,09 32
R.S. 299 Various Various 211 1,324,863 1,324,86 33
R.S. 299 Various lVarious 211 206,938 206,934 34
I I
FERC FORM NO. I (ED. 12-90) Page 329
Name of Respondent
PacifiCorp
This Re ort Is:
IKIARssion
Date of Report
06/28/2012
Year/Period of Report
End of 201 1/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
(Including transactions reffered to as 'wheeling')
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 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 bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (1101 1) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges) Total Revenues ($)
($) (k+I+m)
(m) (n)
Line
No.
-
9,456 29,593 2
2,618 3
3,7201 1 3,720 4
993 993 5
2,260 2,260 6
14,839 14,839 7
644,061 644,061 8
58,818 9
99,978 99,978 10
15,318 11
377,285 377,285 12
3,066 13
1,113,750 1,113,750 14
101,250 15
3,876,613 3,944,560 17
357,239 18
1,247,400 I I 1,247,400 19
113,400 20
47,684 191,721 21
17,849 22
8,365 9,273 23
775 24
1,632 1,744 25
127 26
400,950 I I 400,950 27
36,450 28
246,945 29
22,450 30
82,388 167,541 31
15,776 32
953,831 1,978,404 33
171,168 34
27,647,272 12,953,809 33,065,431 73,666,512
FERC FORM NO. I (ED. 12-90) Page 330
Name of Respondent
P fiC aci orp
I This Report Is:
(1)LJAn Original
(2)EA Resubmission
I Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
(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 affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission 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
N °.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
Energy Delivered To Statistical
(Company of Public Authority) Classifi-
(Footnote Affiliation) cation
(a) (b) (c) (d)
1 Bonneville Power Administration
2 Bonneville Power Administration
3 Bonneville Power Administration Bonneville Power Administration Clark Public Utilities
4 Bonneville Power Administration Bonneville Power Administration Clark Public Utilities
5 Cargill Power Markets, LLC
6 Cargill Power Markets, LLC
7 Cargill Power Markets, LLC
8 CEP Funding, LLC J CEP Funding. LLC CEP Funding, LW
9
F 0 Constellation Energy Commodities Group
11 Constellation Energy Commodities Group
12 Cowlitz County PUD Bonneville Power Administration
13 Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration
14 Cyrq Energy, Inc.
15 Cyrq Energy, Inc.
16 Deseret Generation & Trans. Deseret Generation & Trans.
17 J Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans.
18 Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans.
19 Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans.
20 Deseret Generation & Trans. Deseret Generation & Trans.
21 Eagle Energy Partners
22 Eagle Energy Partners
23 Enel Cove Fort, LLC Enei Cove Fort, LLC
24 Enel Cove Fort, LLC Enei Cove Fort, LLC
25 Eugene Water & Electric Board
26 Eugene Water & Electric Board
27 Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company
28 Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company
29 Foote Creek Ill, LLC Foote Creek Ill, LLC
30 Foote Creek III, LLC Foote Creek Ill, LLC
31 lberdrola Renewables Inc.
32 lberdrola Renewables Inc.
33 Iberdrola Renewables Inc. J lberdrola Renewables Inc.
34 lberdrola Renewables Inc. lberdrola Renewables Inc.
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328.1
Name of Respondent
PacifiCorp
This Report Is:
(2) A Resubmission
Date of Report
/2
Year/Period of Report
End of 2011/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456xContinued)
(Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and ) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(9)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.
-
MegaWatt Hours
Received (i)
MegaWatt Hours
Delivered a)
7V1 1-7 Various Various 30,413 30,41 1
7V1 1-8 Various 1Various 246 24f 2
7V11-3,4 Cardwell-Merwin 20 115,194 115,19 3
7V11-3,4 Cardwell-Merwin 20 13,688 13,68 4
7V11-8 Various IVarious I 205,321 205,321 5
7V11-8 Various Various 2,647 2,647 6
7V11-7 Various Various 600 600 7
7V11-7 Midpoint Sub BPAT.PACW 100 8
7V11-8,9,11 Various Various 10,777 10,777 9
7V11-8,9,11 Various Various 20 20 10
7V11-5,6,7 Various Various 85,588 85,588 11
R.S. 234 Swift Unit No. 2 Woodland Sub 12
R.S. 234 Swift Unit No. 2 Woodland Sub 13
7V11-5,6,7,9 South Milford Mona Substation 11 45,413 45,411 14
7V1 1-5,6,7,9 South Milford Mona Substation 11 4,539 4,539 15
R.S.280 Various Various 95 481,897 481,897 16
R.S. 280 Various Various 95 48,654 48,654 17
R.S. 590 Various Various 18
R.S. 590 Various Various 19
7V11-7 Various Various 960 96C 20
7V11-8 Various Various 292 29 21
7V11-7 Various Various 425 42F, 22
7V1 1-7 Enel Cove Fort Mona Substation 23
7V1 1-7 Enel Cove Fort Mona Substation 24
7V11-8 Various Various 11,171 11,171 25
7V11-8 Various Various 149 149 26
R.S. 322 Targhee Substation Goshen Substation 54,545 54,545 27
R.S. 322 Targhee Substation Goshen Substation 28
S.A. 130 Foote Creek Sub Various 29
S.A. 130 Foote Creek Sub Various 30
7V11-8 Various lVarious 7,024 7,024 31
7V11-8 1Various 1Various 192 192 32
7V11-5,6,9,11 2,472 2,472 33
7V11-5,6,9,11 115 115 34
I I
3,991 14,698,484 14,582,697 1
-
FERC FORM NO. I (ED. 12-90) Page 329.1
Name of Respondent
PacifiCorp
This Report Is:
MA Resubmission
Date of Report
06128/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling')
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 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 bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges) Total Revenues ($)
($) (k+l+m)
(m) (n)
Line
No.
-
91,06c
1,4371
93,953 1
1,437 2
285,313 307,438 3
31,048 4
1,359,6711 1,359,671 5
17,588 6
2,325 2,325 7
248,226 823,860 8
59,368 93,340 9
987 10
1,670 224,795 11
107,537 12
9,741 13
245,025 280,255 14
25,780 15
1,949,032 2,285,389 16
568,322 17
1,640,820 18
159,190 19
3,7201 3,720 20
1,752 1,752 21
4,077 4,077 22
50,625 23
-81,000 24
65,470J I 65,470 25
870 26
138,699 27
12,609 28
33,168 29
3,015 30
43,820 ! I 43,820 31
1,150 32
320,127 33
32,976 34
27,647,272 12,953,809 33,065,431 73,666,512
FERC FORM NO. 1 (ED. 12-90) Page 330.1
Name of Respondent This Re ort Is: I Data of Report Year/Period of Report
PacifiCo I rp (1)An Original I (Mo, Da, Yr) End of 20111Q4
(2)MA Resubmission I 0612812012
TRANSMISION OF ELECTRICITY FOR OTHES (Account 456.1) (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 affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission 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 Affiliation) (Footnote Affiliation) (Footnote Affiliation) cation
(a) (b) (C) (d)
1 lberdrola Renewables Inc. Exxon Mobile Nevada Power Company
2 1 lberdrola Renewables Inc. Exxon Mobile Nevada Power Company
3 Idaho Power Company Idaho Power Company Idaho Power Company
4 Idaho Power Company Nevada Power Company 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
k
L2
13 JP Morgan Ventures Energy Corp..
14
15 ILos Angeles Dept of Water & Power
16 Macquarie Energy LLC
17 Moon Lake Electric Association Moon Lake ElecUic Association Moon Lake Electilo Association
18 Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electilc Association.
19 Morgan Stanley Capital Group, Inc.
20 Morgan Stanley Capital Group, Inc.
21 Morgan Stanley Capital Group, Inc.
22 Municipal Energy Agency of Nebraska
23 Nevada Power Company
24 NextEra Energy Resources, LLC NextEra Energy Resources, LLC
25 NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD
26 NextEra Energy Resources, LLC
27 NextEra Energy Resources, LLC
28 Noble Americas Energy Solutions LLC Bonneville Power Administration Oregon Direct Access
29 Noble Americas Energy Solutions LLC Bonneville Power Administration I Oregon Direct Access
30 Pacific Gas & Electric Company
31 Pacific Gas & Electric Company
32 Pacific Gas & Electric Company
33
Portland General Electric
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328.2
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)fflA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456xContinued) (Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No. MegaWatt Hours
Received (i)
MegaWatt Hours
Delivered a)
7V11-7 Trona Substation Red Butte/Mona Sub 30 69,735 69,736 1
7V11-7 Trona Substation Red Butte/Mona Sub 30 7,254 7,254 2
R.S. 427 Goshen Substation Goshen Substation 3
7V1 1-7 Red Butte Substation Borah/Brady Sub 75 8,866 8,866 4
7V11-8 Various Various 41,000 41,00 5
7V11-8 Various Various 960 96 6
7V11-7 Various Various 47,327 47,32 7
R.S. 257 Antelope Substation Antelope Substation 188,132 188,13 8
R.S. 257 Antelope Substation Antelope Substation 9
R.S. 203 Jim Bridger Sub Bridger Pump Station 10
R.S. 203 Jim Bridger Sub Bridger Pump Station 11
7V11-8,9,11 Various Various 91,393 91,39 12
7V11-8,9,11 Various Various 5,040 5,04 13
7V11-8 Various Various 118,576 118,57 14
7V11-8 Various Various 15
7V11-8 Various Various 54 64 16
R.S. 302 Duchesne Duchesne 3 15,191 15,191 17
R.S. 302 Duchesne Duchesne 3 1,376 1,376 18
7V11-8 Various Various 224,302 224,302 19
7V11-8 Various Various 12,404 12,404 20
7V11-7 Various Various 15,956 15,956 21
7V1 1-8 Various Various 91 91 22
7V11-8 Various Various 105 105 23
7V11-5,6,9,11 Wallula Substation Wala-MIDC Path 80 242,862 242,86 24
7V11-5,6,9,11 Wallula Substation WaIa-MIDC Path 80 21,666 21,66E 25
7V11-8 Various Various 1,740 1,74C 26
7V1 1-8 Various Various 27
7V11-3,4 Bonneville Power Adm Various 14 87,262 87,26 28
7V11-3,4 Bonneville Power Adm 1Various 14 9,792 9,792 29
R.S. 607 30
R.S. 607
R.S. 298 Sigurd-Glen Canyon IPinto-Four Corners
31
32
7V1 1-7 Various Various 3,273 3,273 33
7V1 1-7 Various Various 8,235 8,23 34
__ 3,991 14,698,484 14,582,69
FERC FORM NO. I (ED. 12-90) Page 329.2
Name of Respondent
PacifiCo m
This Re it Is:
(1)An Original
(2)[A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
(Including transactions reffered to as 'wheeling')
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 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 bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10.The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges) Total Revenues ($)
($) (k+I+m)
(m) (a)
Line
No.
-
668,250 668,250 1
60,750 2
3
670,660 670,660 4
188,074 188,074 5
5,606 6
646,043 659,838 7
67,672 8
6,152 9
14,927 10
1,357 11
804,474 806,260 12
72,309 13
574,8661 574,866 '
584 15
3151 31516
19,406 17
1,623 18
1 ,342,7931 I 1,342,793
80,439 20
75,437 88,109 21
753 753 22
613 613 23
1,366,875 2,453,460 24
255,593 25
51 355,465 26
21,538 27
106,069 122,162 2 8
18,527 29
113,9501

18,333,333 30
1,666,667 31
292,930 32
I 13,950 33
33,908 34
27,647,272 12,953,809 33,065,431 73,666,512
FERC FORM NO. I (ED. 12-90) Page 330.2
Name of Respondent This Re ort Is: I Date of Report Year/Period of Report
PacifiCo j (1) An Original I (Mo, Da, Yr) End of 2011/Q4
(2) MA Resubmission 06/28/2012
TRANSMISSION OF ELECTRICITY FOR OTHES (Account 456.1) (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 affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission 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
N 0. (Company of Public Authority) (Company of Public Authority) (Company of Public Authority) Classifi-
(Footnote Affiliation) (Footnote Affiliation) (Footnote Affiliation) cation
- (a) (b) (C) (d)
1 Powerex Corporation Bonneville Power Administration
2 Powerex Corporation Bonneville Power Administration CAISO
3 Powerex Corporation
4 Powerex Corporation
5 Powerex Corporation
6 Powerex Corporation
7 Powder River Energy Corporation Western Area Power Administration
8 Powder River Energy Corporation Western Area Power Administration Sheridan-Johnson Rural Elect.
9 PPL Energy Plus, LLC
10 PPL Energy Plus, LLC
il 1 PPL Energy Plus, LLC
12
13
14 Rainbow Energy Marketing Corporation
15 Rainbow Energy Marketing Corporation
16 Seattle City Light FPL Energy Vansycle, LLC Grant County PUD
17 Seattle City Light FPJ. Energy Vansycle, LLC Grant County PUD
18 Shell Energy North America (U.S.) L.P.
19
20 Sierra Pacific Power Company d/b!a NV
21 Sierra Pacific Power Company d/b/a NV
22
23 Southern California Edison
24 Southern California Edison
25 Southern California Edison
26 Southern California Edison
27 State of South Dakota Western Area Power Administration Black Hills Corporation
28 State of South Dakota Western Area Power Administration Black Hills Corporation
29 Tenaska Power Services Co.
30 Tenaska Power Services Co.
31 TransAlta Energy Marketing
32 1 lransAlta Energy Marketing
33
34 I Tri-State Generation & Trans. Tri-State Generation & Trans.
ITOTAL
FERC FORM NO. 1 (ED. 12-90) Page 328.3
Name of Respondent
ad oq •flC
This Re ort Is:
(1)An Original
(2)MA Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456xContinued) (Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No. MegaWatt Hours
Received (i)
MegaWatt Hours
Delivered
7V11-7 Bonneville Power Adm CRAG View 80 584,370 584,370 1
7V11-7 Bonneville Power Adm CRAG View 80 41,858 41,85E 2
7V11-8,9,11 Various Various 378,887 378,88 3
7V11-8 Various Various 18,620 18,62 4
7V11-5,6,7 Various Various 36,663 36,66 5
7V11-7 Various Various 6
R.S. 123 Various Buffalo Substation 7
R.S. 123 Various Buffalo Substation 8
7V11-8 Various Various 10,096 10,096 9
7V1 1-8 Various Various 572 572 10
7V11-7 Various Various 4,139 4,13 11
7V11-7 Various Various 200 20C 12
7V11-8 Various Various 13
7V11-8 Various Various 29,890 29,89C 14
7V11-7 Various Various 2,722 2,722 15
7V11-5,6,7,9 Wallula Substation Wala-MIDC Path 25 60,705 60,705 16
7V11-5,6,7,9 Wallula Substation Wala-MIDC Path 25 3,707 3,707 17
7V11-8 Various Various 4,035 4,035 18
R.S. 674 Sigurd Substation Utah-Nevada Border 19
R.S. 674 Sigurd Substation Utah-Nevada Border 20
7V11-8 Various Various 6,138 6,13f 21
7V11-5,6,7 Various Various 1,097 1,091 22
7V11-5,6,7 Various Various 290 29 23
7V11-8,9,11 Various Various 311,986 311,986 24
7V11-8,9,11 Various Various 223 223 25
R.S. 298 Sigurd-Glen Canyon Pinto-Four Corners 26
7V11-7 Yellowtail Sub Wyodak Substation 4 17,651 17,651 27
7V11-7 Yellowtail Sub Wyodak Substation 4 1,528 1,521 28
7V11-8 Various Various 18,844 18,844 29
7V11-7 Various Various 65 66 30
7V11-8 Various Various 36,227 36,227 31
7V11-8 Various Various 180 18( 32
7V11-8 Various Various 14,641 14,641 33
R.S. 123 Various Various 23 131,860 131,860 34
3,991 14,698,484 14,582,69
FERC FORM NO. I (ED. 12-90) Page 329.3
Name of Respondent
PacifiCorp
I This Report Is:
(2) AResubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as wheeling)
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 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 bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10.The total amounts in columns (i) and U) 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
($)
(k)
Energy Charges
($)
(I)
(Other Charges) Total Revenues ($)
($) (k+I+m)
(m) (n)
Litie
No.
-
1,747,279 1,747,279 1
162,000 2
30 2,968,356 3
111,616 4
t78,210 147,110 5
-18,399 6
290 7
14 8
72,9501 72,950 9
3,346 10
25,488 25,488 11
1,168 1,168 12
6 613
95,469, 95,469 14
54,699 58,759 15
556,875 616,482 16
54,965 17
28,1311 28,131
62,654 19
12,531 20
36,8361 36,836
9,450 10,959 22
7,290 23
2,059,926 2,355,611 24
75,954 25
292,930 26
89,100 I 89,100 27
8,100 28
143,882 143,882 29
2,705 2,705 30
281,346 281,346 31
1,051 32
96,221 96,221 33
117,754 117,754 34
27,647,272 12,953,809 33,065,431 73,666,512
FERC FORM NO. I (ED. 12-90) Page 330.3
Name of Respondent
PacifiCo
I This Re oct Is:

(1) An Original
I (2) f]A Resubmission
I Date of Report
I (Mo, Da, Yr)
06/28/2012
'Year/Period of Report
End of 2011/Q4
TRANSMISION OF ELECTRICITY FOR OTHERS (Account 456.1)
(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 affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4.In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission 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
N 0.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To Statistical
(Company of Public Authority) Classill-
(Footnote Affiliation) cation
(c) (d)
1 Tri-State Generation & Trans. Tn-State Generation & Trans.
2 [Tri-State Generation & Trans. Tri-State Generation & Trans.
3 Tn-State Generation & Trans. Tri-State Generation & Trans.
4 Tri-State Generation & Trans. Tn-State Generation & Trans.
5 U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation
6 U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation
7 U.S. Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District
8 U.S. Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District
9 U.S. Bureau of Reclamation Western Area Power Administration
10 U.S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.
11 Utah Associated Municipal Power Utah Associated Municipal Power
12 Utah Associated Municipal Power Utah Associated Municipal Power Utah Associated Municipal Power
13 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency
14 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency
15 Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric
16 Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric
17 Western Area Power Administration Western Area Power Administration
18 1 Western Area Power Administration Western Area Power Administration
19 Western Area Power Administration Western Area Power Administration
20 Western Area Power Administration Western Area Power Administration
21 Western Area Power Administration Western Area Power Administration
22 Western Area Power Administration Western Area Power Administration
23 Western Area Power Administration Western Area Power Administration
24 Western Area Power Administration Western Area Power Administration
Western Area Power Administration 25 Western Area Power Administration Western Area Power Administration
26 Western Area Power Administration Western Area Power Administration Western Area Power Administration
27 Accrual
28
29
30
31
32
33
34
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328.4
Name of Respondent
PacifC I orp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456Xpontinued) (Including transactions reffered to as 'wheeling')
5.In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6.Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7.Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8.Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
TRANSFER OF ENERGY Line
No.
(h)
MegaWatt Hours
Received
Megawatt Hours
Delivered
R.S. 123 Various Various 23 14,530 14,53C 1
7V1 1-7 Various Various 9,940 9,941 2
7V11-3,4 Dave Johnston Sub Thermopolis Sub 18 99,842 99,842 3
7V1 1-3,4 Dave Johnston Sub Thermopolis Sub 10,377 10,377 4
7V1 1-3 Walla Walla Sub Burbank Pumps 1 2,277 2,27 5
7V1 1-3 Walla Walla Sub Burbank Pumps 1 6
R.S. 67 Redmond Sub Crooked River Pumps 4 9,057 9,061 7
R.S. 67 Redmond Sub Crooked River Pumps 4 8
R.S. 286 Various Various 14,019 14,01l 9
R.S. 286 Various Various 939 93l 10
R.S. 297 Various Various 362 2,707,686 2,707,68( 11
R.S. 297 Various Various 362 276,212 276,21 12
R.S. 637 Various Various 105 498,829 498,829 13
R.S. 637 Various Various 105 49,381 49,381 14
R.S. 591 Pelton Reregulating Round Butte Sub 85,647 85,647 15
R.S. 591 Pelton Reregulating Round Butte Sub 8,195 8,195 16
R.S. 262 Various Various 331 1,905,327 1,798,55 17
R.S. 262 Various Various 331 159,252 150,23 18
R.S. 263 Various Various 115,654 115,65 19
R.S. 263 Various Various 7,608 7,60f 20
7V1 1-8 Various Various 67,050 67,05 21
7V11-7 Various Various 112,392 112,39, 22
R.S. 664 Dave Johnston Sub Various 68,629 68,62 23
R.S. 664 Dave Johnston Sub Various 36,864 36,861 24
7V1 I Wyoming Distribution Wyoming Distribution 1 8,962 8,96 25
7V1 1 Wyoming Distribution Wyoming Distribution 1 4 4 26
27
28
29
30
31
32
33
34
3,9911 14,698,484 14,582,69
FERC FORM NO. 1 (ED. 12-90) Page 329.4
Name of Respondent
PacifiCorp
This Re ort Is:
(1)
(2)ffJA Resubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
(Including transactions reffered to as 'wheeling')
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 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 bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10.The total amounts in columns (i)and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges (Other Charges) Total Revenues ($)
($) ($) (k+I+m)
(I) (m) (n)
Line
No.
-
3,809 1
50,6251 50,625 2
261,145 319,421 3
25,313 4
4,054 13,283 5
1,168 6
11,036 1 I 11,036 7
-682 8
13,167 9
939 10
6,745,146 7,511,755 11
670,058 12
2,071,697 2,170,092 13
171,988 14
109,725 15
• 9,975 16
2,099,021 2,649,021 17
• 223,897 18
70,951 19
5,825 20
327,1531 327,153 21
457,078 457,078 22
61,499 61,499 23
2,517 24
18,585 55,223 25
26 4,940
102,018 27
I -
29
30
31
32
33
34
27,647,272 12,953,809 33,065,431 73,666,512
FERC FORM NO. 1 (ED. 12-90) Page 330.4
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Schedule Page: 328 Line No.: I Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: I Column: d
Legacy Contract executed between PacifiCorp and Arizona Public Service Company concerning
the exchange of transmission services over agreed-upon facilities (Restated Transmission
Agreement between PacifiCorp and Arizona Public Service Company ("Restated TSA"), Rate
Schedule 436). The contract terminates October 31, 2020. See also FERC Account 565,
Transmission of electricity by others, page 332 of this Form No. 1.
Schedule Page: 328 Line No.: I Column: f
Glenn Canyon/Four Corners Substation.
Schedule Page: 328 Line No.: 2 Column: d
Network Transmission Service under the Open Access Transmission Tariff (1st Revised
Service Agreement 505) terminating no earlier than 12 months from notice by customer.
Schedule Page: 328 Line No.: 2 Column: m
Distribution voltage service charge. Primary delivery service. Regulation and frequency
resnonse.
Schedule Page: 328 Line No.: 3 Column: d
Network Transmission Service under the Open Access Transmission Tariff (1st Revised
Service Agreement 505) terminating no earlier than 12 months from notice by customer.
Schedule Page: 328 Line No.: 3 Column: m
Distribution voltage service charge. Primary delivery service. Regulation and frequency
response. December 2010 service.
Schedule Page: 328 Line No.: 4 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 5 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 5 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
ISchedule Page: 328 Line No.: 6 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "BLACK HILLS/COLORADO ELECTRIC UTILITY
COMPANY" ON PAGES 328 - 330:
Complete name is Black Hills/Colorado Electric Utility Company, L.P.
ISchedule Page: 328 Line No.: 6 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 6 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 6 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 7 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 7 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
lSchedule Page: 328 Line No.: 7 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 8 Column: b
PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and
commodity trading activities.
Schedule Page: 328 Line No.: 8 Column: d
Network Transmission Service under the Open Access Transmission Tariff (1st Revised
Service Agreement 347) terminating on December 31, 2017.
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 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Schedule Page: 328 Line No.: 9 Column: b
PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and
commodity trading activities.
Schedule Page: 328 Line No.: 9 Column: d
Network Transmission Service under the Open Access Transmission Tariff (1st Revised
Service Agreement 347) terminating on December 31, 2017.
Schedule Page: 328 Line No.: 9 Column: m
December 2010 service.
Schedule Page: 328 Line No.: 10 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 10 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 10 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 11 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 11 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 11 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 11 Column: m
Unauthorized use of transmission service from 2009. December 2010 service.
Schedule Page: 328 Line No.: 12 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 12 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 12 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 13 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 13 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 13 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
lSchedule Page: 328 Line No.: 13 Column: m
December 2010 service.
Schedule Page: 328 Line No.: 14 Column: b
PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and
commodity trading activities.
Schedule Page: 328 Line No.: 14 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (1st Revised
Service Agreement 67) terminating on December 31, 2023.
Schedule Page: 328 Line No.: 15 Column: b
Pacificorp Energy, a business unit of PacifiCorp responsible for electric 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, 2023.
ISchedule Page: 328 Line No.: 15 Column: m
December 2010 service.
IFERC FORM NO. 1 (ED. 12-87) Page 450.2 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 328 Line No.: 16 Column: b
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of enerqv.
Schedule Page: 328 Line No.: 16 Column: c I
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of enerqy.
Schedule Page: 328 Line No.: 16 Column: d
Legacy Contract executed between PacifiCorp and Bonneville Power Administration concerning
the exchange of transmission services over agreed-upon facilities ("Midpoint-Meridian
Transmission Agreement", Rate Schedule 369). This agreement runs concurrently with the AC
Intertie Agreement (Rate Schedule 368), which terminates when the facilities subject to
that agreement are taken out of service. See also FERC Account 565, Transmission of
electricity by others, page 332 of this Form No. 1.
ISchedule Page: 328 Line No.: 17 Column: d
Legacy Contract (2nd Revised Rate Schedule 237) executed between PacifiCorp and Bonneville
Power Administration ("BPA") for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Contract subject to termination upon the
earlier of the termination of the "Exchange Agreement" between PacifiCorp and BPA or the
time of the termination of all deliveries as defined in the agreement.
Schedule Page: 328 Line No.: 17 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a
sole-use/direct assigned facilities charge.
Schedule Page: 328 Line No.: 18 Column: d
Legacy Contract (2nd Revised Rate Schedule 237) executed between PacifiCorp and Bonneville
Power Administration ("BPA") for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Contract subject to termination upon the
earlier of the termination of the "Exchange Agreement" between PacifiCorp and EPA Or the
time of the termination of all deliveries as defined in the agreement.
cedule Page: 328 Line No.: 18 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a
sole-use/direct assigned facilities charge. December 2010 service.
Schedule Page: 328 Line No.: 19 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (Service
Agreement 656) terminating on August 31, 2030.
Schedule Page: 328 Line No.: 19 Column: f
Lost Creek Hydro Plant.
Schedule Page: 328 Line No.: 20 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (Service
Agreement 656) terminating on August 31, 2030.
ISchedule Page: 328 Line No.: 20 Column: f
Lost Creek Hydro Plant.
Schedule Page: 328 Line No.: 20 Column: m
December 2010 service.
lSchedule Page: 328 Line No.: 21 Column: d
Network Transmission Service and Distribution Delivery Service under the Open Access
Transmission Tariff (4th Revised Service Agreement 229) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 21 Column: f
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "BONNEVILLE POWER ADM" ON PAGES 328 - 330:
Complete name is Bonneville Power Administration.
Schedule Page: 328 Line No.: 21 Column: m
Distribution voltage service charge. Primary delivery service. Regulation and frequency
response. Penalty revenues coverincT imbalance charges per Schedules 4 and 9.
Network Transmission Service and Distribution Delivery Service under the Open Access
Transmission Tariff (4th Revised Service Agreement 229) terminating on September 30, 2028.
IFERC FORM NO. I (ED. 12-87) Page 450.3 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 328 Line No.: 22 Column: m
Distribution voltage service charge. Primary delivery service: Regulation and frequency
response. Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2010
service.
Schedule Page: 328 Line No.: 23 Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "BENTON REA" ON PAGES 328 - 330:
Complete name is Benton Rural Electric Association.
Schedule Page: 328 Line No.: 23 Column: d
Network Transmission and Distribution Delivery Service under the Open Access Transmission
Tariff (Service Agreement 539) terminating on November 30, 2013.
ISchedule Page: 328 Line No.: 23 Column: m
Regulation and frequency response.
Schedule Page: 328 Line No.: 24 Column: d
Network Transmission and Distribution Delivery Service under the Open Access Transmission
Tariff (Service Agreement 539) terminating on November 30, 2013.
Schedule Page: 328 Line No.: 24 Column: m
Regulation and frequency response. December 2010 service.
ISchedule Page: 328 Line No.: 25 Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "tJMATILLA ELEC & COLUMBIA!! ON PAGES 328 - 330:
Complete name is Umatilla Electric Coop. and Columbia Basin Electric Coop.
Schedule Page: 328 Line No.: 25 Column: d
Network Transmission Service under the Open Access Transmission Tariff (Service Agreement
538) terminating on December 31, 2013.
Schedule Page: 328 Line No.: 25 Column: m
Regulation and frequency response.
Schedule Page: 328 Line No.: 26 Column: d
Network Transmission Service Delivery Service under the Open Access Transmission Tariff
(Service Agreement 538) terminating on December 31, 2013.
Schedule Page: 328 Line No.: 26 Column: m
Regulation and frequency response. December 2010 service.
ISchedule Page: 328 Line No.: 27 Column: b
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "U.S.BUREAU OF RECLAMATION" ON PAGES 328 -
330:
Complete name is United States Department of the Interior Bureau of Reclamation.
Schedule Page: 328 Line No.: 27 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (1st Revised
Service Agreement 179) terminating on September 30, 2025.
Schedule Page: 328 Line No.: 28 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (1st Revised
Service Agreement 179) terminating on September 30, 2025.
ISchedule Page: 328 Line No.: 28 Column: m
December 2010 service.
ISchedule Page: 328 Line No.: 29 Column: d
Legacy Contract (5th Revised Rate Schedule 368) executed between PacifiCorp and Bonneville
Power Administration for transmission service over agreed-upon facilities and/or subject
to a sole-use or facilities charge. Subject to termination upon mutual agreement.
ISchedule Page: 328 Line No.: 29 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.
I$chedule Page: 328 Line No.: 30 Column: d
Legacy Contract (5th Revised Rate Schedule 368) executed between PacifiCorp and Bonneville
Power Administration for transmission service over agreed-upon facilities and/or subject
to a sole-use or facilities charge. Subject to termination upon mutual agreement.
IFERC FORM NO. I (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)XA Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Schedule Page: 328 Line No.: 30 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 2010 service.
Schedule Page: 328 Line No.: 31 Column: d I
Network Transmission Service and Distribution Delivery Service under the Open Access
Transmission Tariff (2nd Revised Service Agreement 328) terminating on July 31, 2012.
Schedule Page: 328 Line No.: 31 Column: g I
White Swan/Toppenish Substation.
Schedule Page: 328 Line No.: 31 Column: m I
Distribution voltage service charge. Primary delivery service. Regulation and frequency
response. Penalty revenues covering imbalance charges per Schedules 4 and 9.
Schedule Page: 328 Line No.: 32 Column: d I
Network Transmission Service and Distribution Delivery Service under the Open Access
Transmission Tariff (2nd Revised Service Agreement 328) terminating on July 31, 2012.
Schedule Page: 328 Line No.: 32 Column: g I
White Swan/Toppenish Substation.
Schedule Page: 328 Line No.: 32 Column: m I
Distribution voltage service charge. Primary delivery service. Regulation and frequency
response. Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2010
service.
ISchedule Page: 328 Line No.: 33 Column: d
Legacy Contract (1st Revised Rate Schedule 299) executed between PacifiCorp and Bonneville
Power Administration ("BPA") for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Contract terminates with three years notice by
BPA or five years notice by PacifiCorp. PacifiCorp provided notice of termination in June
2011.
Schedule Page: 328 Line No.: 33 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a
sole-use/direct assigned facilities charge. Charges for scheduling and operating reserves.
Schedule Page: 328 Line No.: 34 Column: d
Legacy Contract (1st Revised Rate Schedule 299) executed between PacifiCorp and Bonneville
Power Administration ("BPA") for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Contract terminates with three years notice by
EPA or five years notice by PacifiCorp. PacifiCorp provided notice of termination in June
2011.
Schedule Page: 328 Line No.: 34 Column: m I
Charge for transmission service over agreed-upon facilities and/or subject to a
sole-use/direct assigned facilities charge. Charges for scheduling and operating reserves.
December 2010 service.
ISchedule Page: 328.1 Line No.: I Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.1 Line No.: I Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: I Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: I Column: m
Penalty revenues covering imbalance charges per Schedules 4 and 9.
ISchedule Page: 328.1 Line No.: 2 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 2 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 2 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
IFERC FORM NO. I (ED. 12-87) Page 450.5 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
between various parties and points.
ISchedule Page: 328.1 Line No.: 3 Column: d
Network Transmission Service under the Open Access Transmission Tariff (Service
Agreement 370) terminating on December 7, 2012 or with six months written notice.
Schedule Page: 328.1 Line No.: 3 Column: g
Chelatchie/View 115kv.
Schedule Page: 328.1 Line No.: 3 Column: m
Regulation and frequency response. Penalty revenues covering imbalance charges per
Schedules 4 and 9.
Schedule Page: 328.1 Line No.: 4 Column: d
Network Transmission Service under the Open Access Transmission Tariff (Service
Agreement 370) terminating on December 7, 2012 or with six months written notice.
Schedule Page: 328.1 Line No.: 4 Column: g
Chelatchie/View 115kv.
Schedule Page: 328.1 Line No.: 4 Column: m
Regulation and frequency response. Penalty revenues covering imbalance charges per
Schedules 4 and 9. December 2010 service.
Schedule Page: 328.1 Line No.: 5 Column: b
Various signatories to the 7th Revised volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 5 Column: c
Various signatories to the 7th Revised volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 5 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 6 Column: b
Various signatories to the 7th Revised volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 6 Column: c
Various signatories to the 7th Revised volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 6 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 6 Column: m
December 2010 service.
Schedule Page: 328.1 Line No.: 7 Column: b
various signatories to the 7th Revised volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 7 Column: c
Various signatories to the 7th Revised volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 7 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 8 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (Service
Agreement 662) terminating May 31, 2019.
Schedule Page: 328.1 Line No.: 8 Column: m
Transmission resales, amount paid by seller.
Schedule Page: 328.1 Line No.: 9 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "CONSTELLATION ENERGY COMMODITIES GROUP" ON
PAGES 328 - 330:
Complete name is Constellation Energy Commodities Group, Inc.
lSchedule Page: 328.1 Line No.: 9 Column: b
various signatories to the 7th Revised volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.1 Line No.: 9 Column: c
various 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 Tariff
IFERC FORM NO. I (ED. 12-87) Page 450.6
Name of Respondent This Report is: Date of Report Year/Period of Report
(1 ) _ An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
between various parties and points.
Schedule Page: 328.1 Line No.: 9 Column: m
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Schedules 4 and 9.
Schedule Page: 328.1 Line No.: 10 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 10 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.1 Line No.: 10 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
ISchedule Page: 328.1 Line No.: 10 Column: m
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Schedules 4 and 9. December 2010 service.
Schedule Page: 328.1 Line No.: 11 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 11 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
[Schedule Page: 328.1 Line No.: 11 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 11 Column: m
Charges for spinning and/or supplemental reserves. Transmission resales, purchase of
point-to-point transmission.
Schedule Page: 328.1 Line No.: 12 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "COWLITZ COUNTY PUD" ON PAGES 328 - 330:
Complete name is Public Utility District No. 1 of Cowlitz County.
Schedule Page: 328.1 Line No.: 12 Column: d
Legacy Contract (Rate Schedule 234) providing for transmission and operation of Swift
Hydroelectric Plant No. 2, and for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Agreement maybe terminated subsequent to the
termination of the Power Contract as defined in the agreement by the customer providing at
least six months written notice and specifying the date on which the customer will assume
responsibility of operations and maintenance of Swift Hydroelectric Plant No. 2.
Schedule Page: 328.1 Line No.: 12 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.
Schedule Page: 328.1 Line No.: 13 Column: d
Legacy Contract (Rate Schedule 234) providing for transmission and operation of Swift
Hydroelectric Plant No. 2, and for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Agreement may be terminated subsequent to the
termination of the Power Contract as defined in the agreement by the customer providing at
least six months written notice and specifying the date on which the customer will assume
responsibility of operations and maintenance of Swift Hydroelectric Plant No. 2.
Schedule Page: 328.1 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. December 2010 service.
Schedule Page: 328.1 Line No.: 14 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 14 column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 14 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (1st Revised
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)X A Resubmission 0612812012 2011/Q4
FOOTNOTE DATA
Service Agreement 568) terminating April 30, 2029.
Schedule Page: 328.1 Line No.: 14 Column: m
Charges for spinning and/or supplemental reserves. Penalty revenues covering imbalance
charges per Schedules 4 and 9.
Schedule Page: 328.1 Line No.: 15 Column: b I
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 15 Column: c I
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 15 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (1st Revised
Service Agreement 568) terminating April 30, 2029.
Schedule Page: 328.1 Line No.: 15 Column: m I
Charges for spinning and/or supplemental reserves. Penalty revenues covering imbalance
charges per Schedules 4 and 9. December 2010 service.
Schedule Page: 328.1 Line No.: 16 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "DESERET GENERATION & TRANS." ON PAGES 328 -
330:
Complete name is Deseret Generation and Transmission Co-operative.
ISchedule Page: 328.1 Line Not: 16 Column: d I
Legacy Contract executed between PacifiCorp and Deseret Generation and Transmission
Co-operative for transmission service over agreed-upon facilities (3rd 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 I
Scheduling and load following charges. Distribution voltage service charge. Charges for
spinning and/or supplemental reserves.
Schedule Page: 328.1 Line No.: 17 Column: d
Legacy Contract executed between PacifiCorp and Deseret Generation and Transmission
Co-operative for transmission service over agreed-upon facilities (3rd Amended and
Restated Transmission Service and Operating Agreement, Rate Schedule 280) . Agreement
subject to termination upon mutual agreement.
Schedule Page: 328.1 Line No.: 17 Column: m
Scheduling and load following charges. Distribution voltage service charge. Charges for
spinning and/or supplemental reserves including spinning and/or supplemental reserves
covering 2009 to 2010. December 2010 service.
[Schedule Page: 328.1 Line No.: 18 Column: d I
Control Area Services Agreement (Rate Schedule 590) for charges associated with providing
control area support and ancillary services. Agreement terminated and was replaced by the
1st Amended and Restated Control Area Services Agreement (Rate Schedule 590 Rev. 1), which
incorporates provisions in the previous agreement. Agreement terminated January 31, 2012.
Schedule Page: 328.1 Line No.: 18 Column: m I
Charges for spinning and/or supplemental reserves. Regulation and frequency response.
Meter interrrogation charge. Charges for control area services.
ISchedule Page: 328.1 Line No.: 19 Column: d I
Control Area Services Agreement (Rate Schedule 590) for charges associated with providing
control area support and ancillary services. Agreement terminated and was replaced by the
1st Amended and Restated Control Area Services Agreement (Rate Schedule 590 Rev. 1), which
incorporates provisions in the previous agreement. Agreement terminated January 31, 2012.
Schedule Page: 328.1 Line No.: 19 Column: m I
Charges for spinning and/or supplemental reserves. Regulation and frequency response.
Meter interrrogation charge. Charges for control area services. December 2010 service.
Schedule Page: 328.1 Line No.: 20 Column: c I
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 20 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
IFERC FORM NO. I (ED. 12-87) Page 450.8 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
between various parties and points.
Schedule Page: 328.1 Line No.: 21 Column: b
Various 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 Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 22 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.1 Line No.: 22 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 22 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 23 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 23 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff, (1st Revised
Service Agreement 706) deferred until November 1, 2012. Terminating April 30, 2043.
ISchedule Page: 328.1 Line No.: 23 Column: m
Extension of Commencement Date Fee.
Schedule Page: 328.1 Line No.: 24 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.1 Line No.: 24 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff, (1st Revised
Service Agreement 706) deferred until November 1, 2012. Terminating April 30, 2043.
Schedule Page: 328.1 Line No.: 24 Column: m
Partial refund of Extension of Commencement Date Fee.
Schedule Page: 328.1 Line No.: 25 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 25 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 25 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
chedule Page: 328.1 Line No.: 26 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 26 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 26 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 26 Column: m
December 2010 service.
lSchedule Page: 328.1 Line No.: 27 Column: d
Legacy Contract (Rate Schedule 322) executed between PacifiCorp and Fall River Rural
Electric Cooperative for transmission service over agreed-upon facilities and/or subject
to a sole-use or facilities charge. Terminating on July 31, 2027.
Schedule 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 based on a capacity factor and/or proportional use as defined in the
contract.
Schedule Page: 328.1 Line No.: 28 Column: d
Legacy Contract (Rate Schedule 322) executed between PacifiCorp and Fall River Rural
IFERC FORM NO. I (ED. 12-871 Paae 450.9
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011 /Q4
FOOTNOTE DATA
Electric Cooperative for transmission service over agreed-upon facilities and/or subject
to a sole-use or facilities charge. Terminating on July 31, 2027.
Schedule Page: 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 based on a capacity factor and/or proportional use as defined in the
contract. December 2010 service.
Schedule Page: 328.1 Line No.: 29 Column: c
PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and
commodity trading activities.
ISchedule Page: 328.1 Line No.: 29 Column: d
Service Agreement 130 executed between PacifiCorp and Foote Creek III, LLC (Seawest) for
transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge. Terminating July 2014.
Schedule Page: 328.1 Line No.: 29 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
ISchedule Page: 328.1 Line No.: 30 Column: c
PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and
commodity trading activities.
Schedule Page: 328.1 Line No.: 30 Column: d
Service Agreement 130 executed between PacifiCorp and Foote Creek III, LLC (Seawest) for
transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge. Terminating July 2014.
Schedule Page: 328.1 Line No.: 30 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2010 service.
Schedule Page: 328.1 Line No.: 31 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.1 Line No.: 31 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 31 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 32 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 32 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 32 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 32 Column: m
December 2010 service.
Schedule Page: 328.1 Line No.: 33 Column: c
Iberdrola Renewables Inc. and Utah Associated Municipal Power Systems.
Schedule Page: 328.1 Line No.: 33 Column: d
Ancillary Services under the Open Access Transmission Tariff (1st Revised Service
Agreement 476) in effect until superseded.
Schedule Page: 328.1 Line No.: 33 Column: f
Long Hollow, Wyoming Switching Station.
ISchedule Page: 328.1 Line No.: 33 Column: g
Long Hollow, Wyoming Switching Station.
Schedule Page: 328.1 Line No.: 33 Column: m
Charges for spinning and/or supplemental reserves. Unauthorized use of transmission
service. Penalty revenues covering imbalance charges per Schedules 4 and 9.
lSchedule Page: 328.1 Line No.: 34 Column: c
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)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Iberdrola Renewables Inc. and Utah Associated Municipal Power Systems.
Schedule Page: 328.1 Line No.: 34 Column: d
Ancillary Services under the Open Access Transmission Tariff (1st Revised Service
Agreement 476) in effect until superseded.
ISchedule Page: 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.
ISchedule Page: 328.1 Line No.: 34 Column: m
Charges for spinning and/or supplemental reserves. Unauthorized use of transmission
service. Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2010
service.
Schedule Page: 328.2 Line No.: I Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (5th Revised
Service Agreement 279) . Agreement terminating April 30, 2014.
Schedule Page: 328.2 Line No.: 2 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (5th Revised
Service Agreement 279). Agreement terminating April 30, 2014.
Schedule Page: 328.2 Line No.: 2 Column: m
December 2010 service.
Schedule Page: 328.2 Line No.: 3 Column: d
Legacy Contract (Rate Schedule 427) executed between PacifiCorp and Idaho 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")) . 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 written notice of termination as long as PacifiCorp has facilities in
place to serve PacifiCorpTs Big Grassy load. See also FERC Account 565, Transmission of
electricity by others, page 332 of this Form No. 1.
Schedule Page: 328.2 Line No.: 4 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (5th Revised
Service Agreement 212) terminating May 31, 2014.
Schedule Page: 328.2 Line No.: 5 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 5 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 5 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.: 6 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.2 Line No.: 6 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 6 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.: 6 Column: m
December 2010 service.
Schedule Page: 328.2 Line No.: 7 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.2 Line No.: 7 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 7 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
IFERC FORM NO. 1 (ED. 12-87) Page 450.11
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 201 1 /Q4
FOOTNOTE DATA
Schedule Page: 328.2 Line No.: 7 Column: m
Transmission resales, amount paid by seller.
Schedule Page: 328.2 Line No.: 8 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule 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 Power
Company/United States Department of Energy 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.
ISchedule Page: 328.2 Line No.: 9 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
ISchedule 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 terminating coterminous with the Idaho Power
Company/United States Department of Energy Supply Agreement.
Schedule Page: 328.2 Line No.: 9 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2010 service.
Schedule Page: 328.2 Line No.: 10 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 10 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule 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 subject to a sole-use or
facilities charge (Service Agreement 203) for the Jim Bridger Pump. Agreement terminates
upon 12-month written notice.
Schedule Page: 328.2 Line No.: 10 Column: m
Charge for transmission servcie 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 delivery of energy.
Schedule Page: 328.2 Line No.: 11 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
ISchedule Page: 328.2 Line No.: 11 Column: d
Legacy Contract (Rate Schedule 203) executed between PacifiCorp and Idaho Power Company
for transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge (Service Agreement 203) for the Jim Eridger Pump. Agreement terminates
upon 12-month written notice.
Schedule Page: 328.2 Line No.: 11 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2010 service.
Schedule Page: 328.2 Line No.: 12 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "JP MORGAN VENTURES ENERGY CORP." ON PAGES
328 - 330:
Complete name is JP Morgan Ventures Energy Corporation.
Schedule Page: 328.2 Line No.: 12 Column: b
IFERC FORM NO. I (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 (2)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 12 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 12 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.: 12 Column: m
Penalty revenues covering imbalance charges per Schedules 4 and 9.
Schedule Page: 328.2 Line No.: 13 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 13 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 13 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.: 13 Column: m
Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2010 service.
ISchedule Page: 328.2 Line No.: 14 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "LOS ANGELES DEPT OF WATER & POWER" ON PAGES
328 - 330:
Complete name is Los Angeles Department of Water and Power.
Schedule Page: 328.2 Line No.: 14 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 14 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 14 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.: 15 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 15 Column: c F
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 15 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.: 15 Column: m
December 2010 service.
ISchedule Page: 328.2 Line No.: 16 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 16 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 16 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
ISchedule Page: 328.2 Line No.: 17 Column: d
Legacy Contract (2nd Revised Rate Schedule 302) executed between PacifiCorp and Moon Lake
Electric Association for transmission and interconnection service over agreed-upon
facilities and/or subject to a sole-use or facilities charge. Either party may terminate
the agreement at any time after October 14, 2011, by providing two years' written notice.
Schedule Page: 328.2 Line No.: 17 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.
Schedule Page: 328.2 Line No.: 18 Column: d
Legacy Contract (2nd Revised Rate Schedule 302) executed between PacifiCorp and Moon Lake
IFERC FORM NO. I (ED. 12-87) Page 450.13
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Electric Association for transmission and interconnection service over agreed-upon
facilities and/or subject to a sole-use or facilities charge. Either party may terminate
the agreement at any time after October 14, 2011, by providing two years' written notice.
Schedule Page: 328.2 Line No.: 18 Column: m I
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 2010 service.
Schedule Page: 328.2 Line No.: 19 Column: b I
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 19 Column: c I
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 19 Column: d I
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.: 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 Tariff.
Schedule Page: 328.2 Line No.: 20 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.: 20 Column: m
December 2010 service.
Schedule Page: 328.2 Line No.: 21 Column: b I
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 21 Column: c I
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 21 Column: d I
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 I
Transmission resales, purchase of point-to-point transmission.
Schedule Page: 328.2 Line No.: 22 Column: b I
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 22 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 22 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.: 23 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 23 Column: c I
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 23 Column: d I
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.: 24 Column: c I
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "GRANT COUNTY PUD" ON PAGES 328 - 330:
Complete name is Grant County Public Utility District.
ISchedule Page: 328.2 Line No.: 24 Column: d I
Point-to-Point Transmission Service under the Open Access Transmission Tariff (Service
Agreement 626) assignment from Seattle City & Light, terminating December 31, 2011.
Customer executed extension of service through assignment from Seattle City & Light
(Service Agreement 708) through October 31, 2014.
Schedule Page: 328.2 Line No.: 24 Column: m
IFERC FORM NO. I (ED. 12-87) Page 450.14 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Charges for spinning and/or supplemental reserves. Unauthorized use of transmission
service. Penalty revenues covering imbalance charges per Schedules 4 and 9. Transmission
resales, amount paid by seller.
Schedule Page: 328.2 Line No.: 25 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (Service
Agreement 626) assignment from Seattle City & Light, terminating December 31, 2011.
Customer executed extension of service through assignment from Seattle City & Light
(Service Agreement 708) through October 31, 2014.
Schedule Page: 328.2 Line No.: 25 Column: m
Charges for spinning and/or supplemental reserves. Unauthorized use of transmission
service. Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2010
service.
Schedule Page: 328.2 Line No.: 26 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 26 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 26 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.: 27 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
[Schedule Page: 328.2 Line No.: 27 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.2 Line No.: 27 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
ISchedule Page: 328.2 Line No.: 27 Column: m
December 2010 service.
Schedule Page: 328.2 Line No.: 28 Column: d
Transmission Service under the Open Access Transmission Tariff (2nd Revised Service
Agreement 299). Service provided pursuant to rules & regulations of Oregon Direct Access.
Agreement termination upon notification pursuant to Oregon Direct Access and Open Access
Transmission Tariff.
Schedule Page: 328.2 Line No.: 28 Column: m
Regulation and frequency response. Penalty revenues covering imbalance charges per
Schedules 4 and 9.
Schedule Page: 328.2 Line No.: 29 Column: d
Transmission Service under the Open Access Transmission Tariff (2nd Revised Service
Agreement 299) . Service provided pursuant to rules & regulations of Oregon Direct Access.
Agreement termination upon notification pursuant to Oregon Direct Access and Open Access
Transmission Tariff.
Schedule Page: 328.2 Line No.: 29 Column: m
Regulation and frequency response. Penalty revenues covering imbalance charges per
Schedules 4 and 9. December 2010 service.
ISchedule Page: 328.2 Line No.: 30 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 30 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 30 Column: d
Legacy Contract (Rate Schedule 607) executed between PacifiCorp and Pacific Gas & Electric
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 al, Settlement Agreement, Appendix 2 (filed
November 20, 2007).
Schedule Page: 328.2 Line No.: 30 Column: f
IFERC FORM NO. I (ED. 12-87) Page 450.15
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Malin to Indian Springs line segment.
Schedule Page: 328.2 Line No.: 30 Column: g
Malin to Indian Springs line segment.
Schedule Page: 328.2 Line No.: 30 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.: 31 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 31 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 31 Column: d
Legacy Contract (Rate Schedule 607) executed between PacifiCorp and Pacific Gas & Electric
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 al, Settlement Agreement, Appendix 2 (filed
November 20, 2007)
Schedule Page: 328.2 Line No.: 31 Column: f
Malin to Indian Springs line segment.
Schedule Page: 328.2 Line No.: 31 Column: g
Malin to Indian Springs line segment.
Schedule Page: 328.2 Line No.: 31 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2010 service.
Schedule Page: 328.2 Line No.: 32 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 32 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 32 Column: d
Legacy Contract (Rate Schedule 298) executed between PacifiCorp and Pacific Gas & Electric
Company for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge (phase shifting transformers at Sigurd-Glen Canyon 230-kV
transmission line and Pinto-Four Corners 345-kV transmission line) . Terminating
February 12, 2020.
ISchedule Page: 328.2 Line No.: 32 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge;
ISchedule Page: 328.2 Line No.: 33 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "PORTLAND GENERAL ELECTRIC" ON PAGES 328 -
330:
Complete name is Portland General Electric Company.
Schedule Page: 328.2 Line No.: 33 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 33 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 33 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.: 34 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 34 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 34 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.: 34 Column: m
(FERC FORM NO. I (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)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
December 2010 service.
Schedule Page: 328.3 Line No.: I Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "CAISO" ON PAGES 328 - 330:
Complete name is California Independent System Operator Corporation.
çpduIe Page: 328.3 Line No.: I Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (5th Revised
Service Agreement 169) terminating on October 31, 2020.
Schedule Page: 328.3 Line No.: 2 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (5th Revised
Service Agreement 169) terminating on October 31, 2020.
Schedule Page: 328.3 Line No.: 2 Column: m
December 2010 service.
Schedule Page: 328.3 Line No.: 3 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.3 Line No.: 3 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 3 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 3 Column: m
Charges for spinning and/or supplemental reserves. Unauthorized use of transmission
service. Penalty revenues covering imbalance charges per Schedules 4 and 9.
Schedule Page: 328.3 Line No.: 4 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.3 Line No.: 4 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 4 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 4 Column: m
December 2010 service.
Schedule Page: 328.3 Line No.: 5 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 5 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 5 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 5 Column: m
Charges for spinning and/or supplemental reserves. Transmission resales, purchase of
point-to-point transmission.
ISchedule Page: 328.3 Line No.: 6 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 6 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 6 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 6 Column: m
Refund of spinning and supplemental reserves for 2009 and 2010.
Schedule Page: 328.3 Line No.: 7 Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "SHERDIAN-JOHNSON RURAL ELECT." ON PAGES 328 -
330:
Complete name is Sheridan-Johnson Rural Electric Association.
Schedule Page: 328.3 Line No.: 7 Column: d
FERC FORM NO. 1 (ED. 12-87) Paqe 450.17
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PaciflCorp X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Agreement providing for transmission service from Western Area Power Administration's
Casper Substation in Wyoming and Yellowtail Substation in Montana to Sheridan-Johnson
Rural Electric Association's load at PacifiCorp's Buffalo Substation in Wyoming.
Schedule Page: 328.3 Line No.: 7 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Schedule Page: 328.3 Line No.: 8 Column: d
Agreement providing for transmission service from Western Area Power Administration's
Casper Substation in Wyoming and Yellowtail Substation in Montana to Sheridan-Johnson
Rural Electric Association's load at PacifiCorp's Buffalo Substation in Wyoming.
Schedule Page: 328.3 Line No.: 8 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2010 service.
Schedule Page: 328.3 Line No.: 9 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 9 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 9 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
[Schedule Page: 328.3 Line No.: 10 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 10 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.3 Line No.: 10 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
ISchedute Page: 328.3 Line No.: 10 Column: m
December 2010 service.
ISchedule Page: 328.3 Line No.: 11 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 11 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 11 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 12 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "PUBLIC SERVICE CO. OF CO" ON PAGES 328 - 330:
Complete name is Public Service Company of Colorado.
ISchedule Page: 328.3 Line No.: 12 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 12 Column: c
Various 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 Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "PUGET SOUND P&L" ON PAGES 328 - 330:
Complete name is Puget Sound Power & Light Company.
Schedule Page: 328.3 Line No.: 13 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 13 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 13 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
IFERC FORM NO. I (ED. 12-87) Page 450.18
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
between various parties and points.
Schedule Page: 328.3 Line No.: 14 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 14 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 14 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
ISchedule Page: 328.3 Line No.: 15 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 15 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
çhedule Page: 328.3 Line No.: 15 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 15 Column: m
Transmission resales, purchase of point-to-point transmission.
Schedule Page: 328.3 Line No.: 16 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (8th Revised
Service Agreement 289) terminating October 31, 2014.
Schedule Page: 328.3 Line No.: 16 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.: 17 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (8th Revised
Service Agreement 289) terminating October 31, 2014.
Schedule Page: 328.3 Line No.: 17 Column: m
Charges for spinning and/or supplemental reserves. Penalty revenues covering imbalance
charges per Schedules 4 and 9. December 2010 service.
Schedule Page: 328.3 Line No.: 18 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.3 Line No.: 18 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 18 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
ISchedule Page: 328.3 Line No.: 19 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "SIERRA PACIFIC POWER COMPANY d/b/a NV" ON
PAGES 328 - 330:
Complete name is Sierra Pacific Power Company d/b/a NV Energy.
Schedule Page: 328.3 Line No.: 19 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 19 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 19 Column: d
Legacy Contract (Rate Schedule 674) executed betweeen PacifiCorp and Sierra Pacific Power
Company d/b/a NV Energy for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Terminating May 19, 2016.
Schedule Page: 328.3 Line No.: 19 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
lSchedule Page: 328.3 Line No.: 20 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 20 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
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) X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 328.3 Line No.: 20 Column: d I
Legacy Contract (Rate Schedule 674) executed betweeen PacifiCorp and Sierra Pacific Power
Company d/b/a NV Energy for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Terminating May 19, 2016.
Schedule Page: 3283 Line No.: 20 Column: m I
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. November and December 2010 service.
Schedule Page: 328.3 Line No.: 21 Column: b I
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 21 Column: c I
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.3 Line No.: 21 Column: d I
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
ISchedule Page: 328.3 Line No.: 22 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "SOUTHERN CALIFORNIA EDISON" ON PAGES 328 -
330:
Complete name is Southern California Edison Company.
ISchedule Page: 328.3 Line No.: 22 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 22 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 22 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 22 Column: m I
Charges for spinning and/or supplemental reserves.
Schedule Page: 328.3 Line No.: 23 Column: b I
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 23 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
[Schedule Page: 328.3 Line No.: 23 Column: d I
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 23 Column: m I
Charges for spinning and/or supplemental reserves. December 2010 service.
Schedule Page: 328.3 Line No.: 24 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 24 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 24 Column: d I
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 24 Column: m I
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Schedules 4 and 9.
Schedule Page: 328.3 Line No.: 25 Column: b 7=1
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 25 Column: c I
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 25 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
FS—chedule Page: 328.3 Line No.: 25 Column: m I
Charges for spinning and/or supplemental reserves. Unauthorized use of transmission
IFERC FORM NO. I (ED. 12-871 Paae 450.20 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2) X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
service (including refunds). Penalty revenues covering imbalance charges per Schedules 4
and 9. December 2010 service.
ISchedule Page: 328.3 Line No.: 26 Column: b
Operation, maintenance or facility lease services 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.
ISchedule Page: 328.3 Line No.: 26 Column: d
Use of Facilities Agreement-Phase Shifting Transformers at Sigurd-Glen Canyon 230-kV
transmission line and Pinto-Four Corners 345-kV transmission line (Rate Schedule 298),
terminating February 12, 2020.
Schedule Page: 328.3 Line No.: 26 Column: in
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Schedule Page: 328.3 Line No.: 27 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (9th Revised
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 Tariff (9th Revised
Service Agreement 170) terminating on May 31, 2014.
ISchedule Page: 328.3 Line No.: 28 Column: m
December 2010 service.
ISchedule Page: 328.3 Line No.: 29 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.3 Line No.: 29 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ScheduIe Page: 328.3 Line No.: 29 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 30 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 30 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 30 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 31 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.3 Line No.: 31 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 31 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between 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 Tariff.
Schedule Page: 328.3 Line No.: 32 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
ISchedule Page: 328.3 Line No.: 32 Column: m
December 2010 service.
Schedule Page: 328.3 Line No.: 33 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "TRI-STATE GENERATION & TRANS." ON PAGES 328 -
330:
Complete name is Tri-State Generation and Transmission Association, Inc.
IFERC FORM NO. 1 (ED. 12-87) Page 450.21
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06128/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 328.3 Line No.: 33 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 33 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 33 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
ISchedule Page: 328.3 Line No.: 34 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 34 Column: d
Legacy Contract (2nd Revised Rate Schedule 123) executed between PacifiCorp and Tri-State
Generation and Transmission Association, Inc. for transmission service over agreed-upon
facilities and/or subject to a sole-use or facilities charge. Terminating October 1, 2014.
ISchedule Page: 328.4 Line No.: I Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: I Column: d
Legacy Contract (2nd Revised Rate Schedule 123) executed between PacifiCorp and Tri-State
Generation and Transmission Association, Inc. for transmission service over agreed-upon
facilities and/or subject to a sole-use or facilities charge. Terminating October 1, 2014.
ISchedule Page: 328.4 Line No.: I Column: m
December 2010 service.
ISchedule Page: 328.4 Line No.: 2 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 2 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 3 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 3 Column: d
Network Transmission Service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 628) terminating on June 30, 2021.
Schedule Page: 328.4 Line No.: 3 Column: m
Regulation and frequency response. Penalty revenues covering imbalance charges per
Schedules 4 and 9.
Schedule Page: 328.4 Line No.: 4 Column: b
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.4 Line No.: 4 Column: d
Network Transmission Service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 628) terminating on June 30, 2021.
Schedule Page: 328.4 Line No.: 4 Column: m
Regulation and frequency response. Penalty revenues covering imbalance charges per
Schedules 4 and 9. December 2010 service.
Schedule Page: 328.4 Line No.: 5 Column: d
Network Transmission Service and Distribution Delivery Service under the Open Access
Transmission Tariff (Service Agreement 506) terminating upon written notification.
Schedule Page: 328.4 Line No.: 5 Column: m
Distribution voltage service charge. Primary delivery service. Regulation and frequency
resDonse.
Schedule Page: 328.4 Line No.: 6 Column: d
Network Transmission Service and Distribution Delivery Service under the Open Access
Transmission Tariff (Service Agreement 506) terminating upon written notification.
lSchedule Page: 328.4 Line No.: 6 Column: m
Distribution voltage service charge. Primary delivery service. Regulation and frequency
response. December 2010 service.
Schedule Page: 328.4 Line No.: 7 Column: d
IFERC FORM NO. I (ED. 12-87) Pacie 450.22 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Legacy Contract (3rd Amended Rate Schedule 67) executed between PacifiCorp and United
States Department of the Interior Bureau of Reclamation Crooked River Irrigation District
for transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge. Agreement termination with one year written notice.
Schedule Page: 328.4 Line No.: 8 Column: d
Legacy Contract (3rd Amended Rate Schedule 67) executed between PacifiCorp and United
States Department of the Interior Bureau of Reclamation Crooked River Irrigation District
for transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge. Agreement termination with one year written notice.
Schedule Page: 328.4 Line No.: 8 Column: m
2010 Transmission usage refund.
Schedule Page: 328.4 Line No.: 9 Column: c
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "WEBER BASIN WATER CONSERV." ON PAGES 328 -
330:
Complete name is Weber Basin Water Conservancy District.
Schedule Page: 328.4 Line No.: 9 Column: d
Legacy Contract (2nd Revised Rate Schedule 286) executed between PacifiCorp and United
States Department of the Interior Bureau of Reclamation for transmission service over
agreed-upon facilities and/or subject to a sole-use or facilities charge for energy
deliveries at and below 138 kV. Agreement terminates any time after April 1, 2040 with
four years written notification.
Schedule Page: 328.4 Line No.: 9 Column: m
Energy consumption charge for deliveries at and below 138 kV.
Schedule Page: 328.4 Line No.: 10 Column: d
Legacy Contract (2nd Revised Rate Schedule 286) executed between PacifiCorp and United
States Bureau of Reclamation Weber Basin Water Conservancy District for transmission
service over agreed-upon facilities and/or subject to a sole-use or facilities charge for
energy deliveries at and below 138 kV. Agreement termination any time after April 1, 2040
with four years written notification.
Schedule Page: 328.4 Line No.: 10 Column: m
Energy consumption charge for deliveries at and below 138 kV. December 2010 service.
Schedule Page: 328.4 Line No.: 11 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "UTAH ASSOCIATED MUNICIPAL POWER" ON PAGES
328 - 330:
Complete name is Utah Associated Municipal Power Systems.
ISchedule Page: 328.4 Line No.: 11 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) . Agreement subject to termination upon
mutual agreement and replacement agreements are in effect.
Schedule Page: 328.4 Line No.: 11 Column: m
Charge for scheduling and load following. Charges for spinning and/or supplemental
reserves. Distribution voltage service charge.
Schedule Page: 328.4 Line No.: 12 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) . Agreement subject to termination upon
mutual agreement and replacement agreements are in effect.
Schedule Page: 328.4 Line No.: 12 Column: m
Charge for scheduling and load following. Charges for spinning and/or supplemental
reserves. Distribution voltage service charge. December 2010 service.
Schedule Page: 328.4 Line No.: 13 Column: d
Legacy Contract (1st Revised 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 mutual
agreement and replacement agreements are in effect.
IFERC FORM NO.1 (ED. 12-87) Page 450.23
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)- An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011 /Q4
FOOTNOTE DATA
Schedule Page: 328.4 Line No.: 13 Column: m
Charges for scheduling and load following.
Schedule Page: 328.4 Line No.: 14 Column: d
Legacy Contract (1st Revised 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 mutual
agreement and replacement agreements are in effect.
Schedule Page: 328.4 Line No.: 14 Column: m
Charges for scheduling and load following. December 2010 service.
[Schedule Page: 328.4 Line No.: 15 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
sole-use or facilities charge. Agreement terminating January 31, 2032.
Schedule Page: 328.4 Line No.: 15 Column: m
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
contract.
Schedule Page: 328.4 Line No.: 16 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
sole-use or facilities charge. Agreement terminating January 31, 2032.
ISchedule Page: 328.4 Line No.: 16 Column: m
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
contract. December 2010 service.
ISchedule Page: 328.4 Line No.: 17 Column: c
Various Western Area Power Administration customers in PacifiCorp's Control Area.
Schedule Page: 328.4 Line No.: 17 Column: d
Legacy Contract (Rate Schedule 262) 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 preferential
customers for deliveries of Colorado River Storage Project power and energy. Agreement
termination upon three years after written notice and mutual consent.
Schedule Page: 328.4 Line No.: 17 Column: m
Fixed termination fee associated with a contract cancellation applied for the duration of
this agreement.
lSchedule Page: 328.4 Line No.: 18 Column: c
Various Western Area Power Administration customers in PacifiCorp's Control Area.
Schedule -Page: 328.4 Line No.: 18 Column: d
Legacy Contract (Rate Schedule 262) 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 preferential
customers for deliveries of Colorado River Storage Project power and energy. Agreement
termination upon three years after written notice and mutual consent.
Schedule Page: 328.4 Line No.: 18 Column: m
Fixed termination fee associated with a contract cancellation applied for the duration of
this agreement. December 2010 service.
Schedule Page: 328.4 Line No.: 19 Column: c
Various Western Area Power Administration customers in PacifiCorp's Control Area.
ISchedule Page: 328.4 Line No.: 19 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 Integrated Projects,
including the Colorado River Storage Projects, to certain municipalities at service below
138kv. Agreement termination upon three years after written notice and mutual consent.
IFERC FORM NO. I (ED. 12-87) Page 450.24
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)- An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
Schedule Page: 328.4 Line No.: 19 Column: m
Charges for low-voltage transmission of power and energy.
ISchedule Page: 328.4 Line No.: 20 Column: c
Various Western Area Power Administration customers in PacifiCorp's Control Area.
Schedule Page: 328.4 Line No.: 20 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 Integrated Projects,
including the Colorado River Storage Projects, to certain municipalities at service below
138kv. Agreement termination upon three years after written notice and mutual consent.
Schedule Page: 328.4 Line No.: 20 Column: m
Charges for low-voltage transmission of power and energy. December 2010 service.
Schedule Page: 328.4 Line No.: 21 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 22 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.4 Line No.: 22 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 23 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 23 Column: d
Legacy Contract (Rate Schedule 664) executed between PacifiCorp and Western Area Power
Administration concerning the exchange of transmission services over agreed-upon
facilities. The contract terminates 50 years from execution. See also FERC Account 565,
Transmission of electricity by others, page 332 of this Form No. 1.
Schedule Page: 328.4 Line No.: 24 Column: c
Various signatories to the 7th Revised Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 24 Column: d
Legacy Contract (Rate Schedule 664) executed between PacifiCorp and Western Area Power
Administration concerning the exchange of transmission services over agreed-upon
facilities. The contract terminates 50 years from execution. See also FERC Account 565,
Transmission of electricity by others, page 332 of this Form No. 1.
Schedule Page: 328.4 Line No.: 24 Column: m
December 2010 service.
Schedule Page: 328.4 Line No.: 25 Column: d
Evergreen Network Transmission Service under the Open Access Transmission Tariff (2nd
Revised Service Agreement 175).
Schedule Page: 328.4 Line No.: 25 Column: m
Distribution voltage service charge. Primary delivery service.
Schedule Page: 328.4 Line No.: 26 Column: d
Evergreen Network Transmission Service under the Open Access Transmission Tariff (2nd
Revised Service Agreement 175).
Schedule Page: 328.4 Line No.: 26 Column: m
Distribution voltage service charge. Primary delivery service. December 2010 service.
Schedule Page: 328.4 Line No.: 27 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 FERC Account
456.1, Revenues from transmission of electricity of others, during the period.
IFERC FORM NO. 1 (ED. 12-87) Page 450.25 1
Name of Respondent This Re ort Is: Data of Report Year/Period of Report
PacifiCorp (1)LJAn Original (Mo, Da, Yr) End of 2011/Q4 (2)A Resubmission 06/28/2012
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling")
1.Report all transmission, i.e. wheeling or electricity provided by other electric 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 affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3.In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General 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 Maawatt- hours Maawatt- ours mand
($r? Ces 1
Total Cost of
ranssston Authority (Footnote Affiliations) Classification Received Delivered ($ ($
• (a) (b) (c) (d) (e) (f) (g) (h)
1 -17 -17
2'Arizona Public Service 321,682 321,682 1,113,528 1,113,528
3 Arizona Public Service • NE 46,297 46,297 229,279 1 1 229,279
4 Arizona Public Service OS 5,607
5 Arizona Public Service
6 Arizona Public Service SEP 46,633 46,633 156,040 156,040
7 Ashland, City of ENS 1,808 1,808 16,893 16,893
8 Avista Corporation FNS 56,2791 59,445 228,253 228,253
9 1 Avista Corporation NE 110,440 110,440 570,509 570,509
10 NE I 87,327 87,327 130117 1 1 130,117
11 189,925
41,832 40,784 12
13 Bonneville Power Admin. • FNS 5,803,565 I 5,803,565
14 Bonneville Power Admin. 5,485,314 5,485,314 53,528,422 53,528,422
15 Bonneville Power Admin. • • NF 533,654 533,654 2,310,228 2,310,228
16 Bonneville Power Admin, 2,571,894 2,783,711 30,771,444 30,882,204
TOTAL 15,490,63 15,878,375 113,594,586 5,089,725 19,550,543 138,234,854
FERC FORM NO. 113-Q (REV. 02-04) Page 332
Name of Respondent This Re ort Is: Data of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/04
(2)A Resubmission 06/28/2012
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling")
1.Report all transmission, i.e. wheeling or electricity provided by other electric 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 affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3.In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General 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
Authority (Footnote Affiliations)
Statistical
Classification
Maawatt hours Received
Maawatt- hg ours
Delivered
8ia ha ($ ($ Cs
($
Total Cost of
ransssion
- (a) (b) (c) (d) (e) (0 (g) (h)
1 Bonneville Power Admin. OS 15,131 15,131 46,676 4,465,737
2 1 Bonneville Power Admin.
3 Bonneville Power Admin. SFP 54,376 54,376 94,616 94,616
4 -141,583 -168,748
5 CA Ind. Sys. Operator 05 1971,448
6 C Ind. Sys. Operator SEP 408,125 408,125 2,631,930 2,631,930
7 1,503 1,503 11,012 11,012
8 Deseret Gen & Trans 218,291 218,291 4,209,870 4,209,870
9 Deseret Gen & Trans NF J 329,460 329,460 2,033,478 2,033,478
-300 -300 -226 -226
OS 51,696
H13 pIdahoPower
OS 178,852
Company 93,981
14 Idaho Power Company FNS 8,834 8,834
15 Idaho Power Company 2,903,953 2,974,739 6,271,673 6,271,673
16 Idaho Power Company NE 114,339 206,917 618,221 618,221
TOTAL 15,490,63 15,878,375 113,594,586 5,089,725 19,550,543 138,234,854
FERC FORM NO. 113-0 (REV. 02-04) Page 332.1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)LjAn Original (Mo, Da, Yr) End of 2011/Q4
(2)MA Resubmission 06/28/2012
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as 'wheeling")
1.Report all transmission, i.e. wheeling or electricity provided by other electric 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 affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3.In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
ENS - Firm Network Transmission Service for Self, LEP - Long-Term Firm Point-to-Point Transmission Reservations. OLE - Other
Long-Term Firm Transmission Service, SEP - Short-Term Firm Point-to- Point Transmission Reservations, NE - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4.Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5.Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on 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 Maawatt- hours
Magawa I hours Derriano
Chies; &r%s es Total Cost of
Authority (Footnote Affiliations) Classification Received Delivered ($) ($T ($T Transission
- (a) (b) (c) (d) (e) (f) (g) (h)
1 Idaho Power Company Os 11867,609
2 Idaho Power Company
3 Idaho Power Company SFP 9,000 9,000 24,013 I 24,013
-62,123
Moon Lake Elect. Assoc. FNS 5 260,381
6 Morgan City Corporation 81 81 8481 848
SEP -144,285
81 Nevada Power Company NE 21,576 21,576 59,254 59,254
9 Nevada Power Company OS 51,307
10 Nevada Power Company SEP 102,336 102,336 226,733 226,733
11 NE 13,430 13,430 58,147 58,147
05 4,181 12 NorthWestern Corp.
131 NorthWestern Corp. SEP 5,832 5,832 25,248 25,248
II 189,427 189,427 966,000 966,000
15 1 Platte River Power NE 160 160 600 600
16 Platte River Power 05 12,388
TOTAL 15,490,63 15,878,375 113,594,586 5,089,725 19,550,543 138,234,854
FERC FORM NO. 113-Q (REV. 02-04) Page 332.2
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCo (1)An Original (Mo, Da, Yr) End of 2011/04
(2)ffJA Resubmission 06/28/2012
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling")
1.Report all transmission, i.e. wheeling or electricity prävided 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 affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3.In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General 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
Authority (Footnote Affiliations)
Statistical
Classification
MaawaU- hours Received
Maawatt- hg ours
Delivered ($
rg%5
($?
CJes Total Cost of
ra sssion
(a) (b) (c) (d) (e) (f) (g) h
1 600 600 500 510
2 Portland Gen. Electric 880
3 Powerex Corporation SFP 1,618,092
4 99,874 103,789 919,899 919,899
5 115,746 115,746 686,220 686,220
6 Public Service Co of NM OS 21,120
7 Salt River Project NF 1,900 1,900 4,598 4,598
8 SEP -378,450
9 NF 73,208 73,208 383,925 383,925
10 Sierra Pacific Power Co OS 98,738
11 Sierra Pacific Power Co SEP , 57,720 57,720 259,163 259,163
12 I 9,780
13 SEP -36,288
14 SEP -693,675
15 121,670 127,146 F 919,899 919,899
16 Tri-State Gen & Transm • NF 275,817 275,817 693,936 693,936
TOTAL 15,490,63 15,878,375 113,594,586 5,089,725 19,550,543 138,234,854
FERC FORM NO. 113-Q (REV. 02-04) Page 332.3
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PaciflCorp (1) An Original (Mo, Da, Yr) End of 2011/04
(2)1A Resubmission 06/28/2012
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) (Including transactions referred to as "wheeling")
1.Report all transmission, i.e. wheeling or electricity provided by other electric 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 affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3.In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General 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 OTHERES
No. Name of Company or Public Statistical MajaWatt Ma U- ir%s CZ?qes Total cost of
Authority (Footnote Affiliations) Classification Received Delivered ($? ($T ($ rans
- (a) (b) (C) (d) (e) (f) (g) h)
1 Tn-State Gen & Transrn Os 191.624
2 NF 28 281 87 87
3 Tucson Electric Power OS 466
4 1 Electric Power SEP 1.200 1,200 5,200 5,200
5 -3,129,096
6 11,604 11,604 50,375 30,362
7 1Westem Area Power Adm.. FNS 5,064,438 5,064,438
8 Western Area Power Adm. 377.707 377,707 2,180,000 2,180,000
9 Western Area Power Adm. NE 540,274 540,274 1,223,659 1,223,659
10 Western Area Power Adm. 05 556,622
11 Western Area Power Adm.
12 Western Area Power Adm. SFP 165,241 165,241 259,689 259,689
13 Accrual -448,372
14
15
16
TOTAL 15,490,63 15,878,375 113,594,586 5,089,725 19,550,543 138,234,854
FERC FORM NO. 113-Q (REV. 02-04) Page 332.4
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 332 Line No.: I Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "ARIZONA PUBLIC SERVICE" ON PAGE 332: Complete
name is Arizona Public Service Company.
Schedule Page: 332 Line No.: I Column: b
Settlement Adjustment.
Schedule Page: 332 Line No.: 2 Column: b
Arizona Public Service Company - Contract Termination Dates: May 1, 2013, August 31, 2013,
January 11, 2041 and May 31, 2047.
Schedule Page: 332 Line No.: 4 Column: e I
Credit for unreserved use.
Schedule Page: 332 Line No.: 4 Column: g I
Ancillary Services.
Schedule Page: 332 Line No.: 5 Column: b
Legacy Contract executed between PacifiCorp and Arizona Public Service Company concerning
the exchange of transmission services over agreed-upon facilities (Restated Transmission
Agreement between PacifiCorp and Arizona Public Service Company ("Restated TSA"), Rate
Schedule 436) . The contract terminates October 31, 2020. See also FERC Account 456.1,
Transmission of electricity for others, page 328 of this Form No. 1.
Schedule Page: 332 Line No.: 10 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "BASIN ELECT. POWER COOP" ON PAGES 332:
Complete name is Basin Electric Power Cooperative.
Schedule Page: 332 Line No.: 11 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "BIG HORN RURAL ELECTRIC" ON PAGE 332:
Complete name is Big Horn Rural Electric Company.
Schedule Page: 332 Line No.: 11 Column: b
Big Horn Rural Electric Company - Contract Termination Date: March 10, 2012.
Schedule Page: 332 Line No.: 11 Column: g
Use of Facilities.
Schedule Page: 332 Line No.: 12 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "BONNEVILLE POWER ADMIN." ON PAGE 332:
Complete name is Bonneville Power Administration.
ISchedule Page: 332 Line No.: 12 Column: b
Settlement Adjustment.
Schedule Page: 332 Line No.: 12 Column: g
Ancillary Services. Use of Facilities.
Schedule Page: 332 Line No.: 14 Column: b
Bonneville Power Administration - Contract Termination Dates: December 1, 2011, April 1,
2012, July 1, 2012, November 1, 2012, September 1, 2013, October 1, 2013, December 1,
2013, January 1, 2014, November 1, 2014, November 1, 2015, July 1, 2016, December 1, 2016,
October 1, 2027, November 1, 2033 and evergreen.
Schedule Page: 332 Line No.: 16 Column: b
Bonneville Power Administration - Contract Termination Dates: October 3, 2014, December
31, 2018, September 30, 2027 and evergreen.
Schedule Page: 332 Line No.: 16 Column: g
Use of Facilities.
Schedule Page: 332.1 Line No.: I Column: g
Ancillary Services. Use of Facilities.
Schedule Page: 332.1 Line No.: 2 Column: b
Legacy Contract executed between PacifiCorp and Bonneville Power Administration concerning
the exchange of transmission services over agreed-upon facilities ("Midpoint-Meridian
Transmission Agreement", Rate Schedule 369) . This agreement runs concurrently with the AC
Intertie Agreement (Rate Schedule 368), which terminates when the facilities subject to
that agreement are taken out of service. See also FERC Account 456.1, Transmission of
electricity for others, page 328 of this Form No.1.
IFERC FORM NO. I (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)XA Resubmission 0612812012 2011/04
FOOTNOTE DATA
Schedule Page: 332.1 Line No.: 4 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "CA IND. SYS. OPERATOR" ON PAGE 332: Complete
name is California Independent System Operator Corporation.
Schedule Page: 332.1 Line No.: 4 Column: b
Settlement Adjustment.
Schedule Paae: 332.1 Line No.: 4 Column: a
Ancillary Services.
Schedule Page: 332.1 Line No.: 5 Column: a
Ancillary Services.
ISchedule Page: 332.1 Line No.: 7 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "DESERET GEN & TRANS" ON PAGE 332: Complete
name is Deseret Generation and Transmission Cooperative.
Schedule Page: 332.1 Line No.: 7 Column: b
Settlement Adjustment.
Schedule Page: 332.1 Line No.: 8 Column: b I
Deseret Generation and Transmission Cooperative - Contract Termination Dates:
2012 and September 1, 2018.
October 31,
Schedule Page: 332.1 Line No.: 10 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "EL PASO ELECT. CO ." ON PAGE 332:
name is El Paso Electric Company.
Complete
ISchedule Page: 332.1 Line No.: 10 Column: b I
Settlement Adjustment.
ISchedule Page: 332.1 Line No.: 11 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "FLATHEAD ELECT. COOP." ON PAGE 332: Complete
name is Flathead Electric Cooperative, Inc.
Schedule Page: 332.1 Line No.: 11 Column: g I
Use of Facilities.
Schedule Page: 332.1 Line No.: 12 Column: a I
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "HERI'IISTON GENERATING CO" ON PAGE
Complete name is Hermiston Generating Company, L.P.
332:
Schedule Page: 332.1 Line No.: 12 Column: g
Use of Facilities.
Schedule Page: 332.1 Line No.: 13 Column: b I
Settlement Adjustment.
ISchedule Page: 332.1 Line No.: 13 Column: e
Credit for unreserved use.
Schedule Page: 332.1 Line No.: 13 Column: g
Respondent's portion of specified costs of certain facilities.
Schedule Page: 332.1 Line No.: 15 Column: b
Idaho Power Company - Contract Termination Date: April 1, 2025 and July 1, 2025.
Schedule Page: 332.2 Line No.: I Column: e
Credit for unreserved use.
ISchedule Page: 332.2 Line No.: I Column: g
Ancillary Services. Use of Facilities. Respondent's portion of specified costs of certain
facilities.
Schedule Page: 332.2 Line No.: 2 Column: b
Legacy Contract (Rate Schedule 427) executed between PacifiCorp and Idaho 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")). 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 written 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
electricity for others, page 328 of this Form No. 1.
Schedule Page: 332.2 Line No.: 4 Column: a
IFERC FORM NO. I (ED. 12-87) Paqe 450.2 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "MOON LAKE ELECT. ASSOC." ON PAGE 332:
Complete name is Moon Lake Electric Association.
Schedule Page: 332.2 Line No.: 4 Column: b
Settlement Adiustment.
Schedule Page: 332.2 Line No.: 4 Column: g
Use of Facilities.
Schedule Page: 332.2 Line No.: 5 Column: g
Use of Facilities.
Schedule Page: 332.2 Line No.: 6 Column: b
Settlement Adjustment.
Schedule Page: 332.2 Line No.: 7 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "MORGAN STANLEY CAPITAL" ON PAGE
name is Morgan Stanley Capital Group, Inc.
332: Complete
Schedule Page: 332.2 Line No.: 7 Column: e
Reassignment of Bonneville Power Administration Transmission.
Schedule Page: 332.2 Line No.: 9 Column: g
Ancillary Services.
Schedule Page: 332.2 Line No.: 11 Column: a
THIS FOOTNOTE APPLIES TO ALL
name is NorthWestern Corporation.
OCCURRENCES OF "NORTHWESTERN CORP." ON PAGE 332: Complete
Schedule Page: 332.2 Line No.: 12 Column: g
Ancillary Services.
[Schedule Page: 332.2 Line No.: 14 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "PLATTE RIVER POWER" ON PAGE 332:
name is Platte River Power Authority.
Complete
Schedule Page: 332.2 Line No.: 14 Column: b
Platte River Power Authority - Contract Termination Date: October 31, 2012.
Schedule Page: 332.2 Line No.: 16 Column: g
Ancillary Services.
lSchedule Page: 332.3 Line No.: I Column: a
THIS FOOTNOTE APPLIES TO ALL
name is Portland General Electric
OCCURRENCES OF "PORTLAND GEN. ELECTRIC" ON PAGE
Company.
332: Complete
Schedule Page: 332.3 Line No.: I Column: b
Settlement Adjustment.
Schedule Page: 332.3 Line No.: I Column: g
Ancillary Services.
Schedule Page: 332.3 Line No.: 2 Column: b
Portland General Electric Company Contract Termination Date: Upon two years
notice.
written
Schedule Page: 332.3 Line No.: 2 Column: g
Use of Facilities.
Schedule Page: 332.3 Line No.: 3 Column: e
Reassignment of Bonneville Power Administration Transmission.
[Schedule Page: 332.3 Line No.: 4 Column: a
THIS FOOTNOTE APPLIES TO ALL
Complete name is Public Service
OCCURRENCES OF "PUBLIC SERVICE CO OF CO" ON PAGE
Company of Colorado.
332:
Schedule Page: 332.3 Line No.: 4 Column: b
Public Service Company of Colorado - Contract Termination Date: The date that all
generating plants comprising PacifiCorp resources associated with this agreement have been
retired from service or interests transferred.
lSchedule Page: 332.3 Line No.: 5 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "PUBLIC SERVICE CO OF NM" ON PAGE
Complete name is Public Service Company of New Mexico.
332:
lSchedule Page: 332.3 Line No.: 5 Column: b
Public Service Company of New Mexico - Contract Termination Date: December 1, 2012.
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)
PaeifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 332.3 Line No.: 6 Column: g
Ancillary Services.
Schedule Page: 332.3 Line No.: 8 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "SHELL ENERGY NORTH AMER" ON PAGE 332:
Complete name is Shell Energy North America (US), L.P.
Schedule Page: 332.3 Line No.: 8 Column: e
Reassignment of Bonneville Power Administration Transmission.
Schedule Page: 332.3 Line No.: 9 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "SIERRA PACIFIC POWER CO" ON PAGE 332:
Complete name is Sierra Pacific Power Company.
Schedule Page: 332.3 Line No.: 10 Column: g
Ancillary Services.
Schedule Page: 332.3 Line No.: 12 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "SURPRISE VALLEY ELECTR." ON PAGE 332:
Complete name is Surprise Valley Electrification Corp.
Schedule Page: 332.3 Line No.: 12 Column: b
Surprise Valley Electrification Corp. - Contract Termination Date: Evergreen.
Schedule Page: 332.3 Line No.: 12 Column: g
Use of Facilities.
Schedule Page: 332.3 Line No.: 13 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "THE ENERGY AUTHORITY" ON PAGE 332: Complete
name is The Energy Authority, Inc.
Schedule Page: 332.3 Line No.: 13 Column: e
Reassignment of Bonneville Power Administration Transmission.
Schedule Page: 332.3 Line No.: 14 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "TRANSALTA ENERGY MKTG" ON PAGE 332: Complete
name is TransAlta Energy Marketing (U.S.) Inc.
Schedule Page: 332.3 Line No.: 14 Column: e
Reassignment of Bonneville Power Administration Transmission.
Schedule Page: 332.3 Line No.: 15 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "TRI-STATE GEN & TRANSM" ON PAGE 332: Complete
name is Tri -State Generation and Transmission Association, Inc.
Schedule Page: 332.3 Line No.: 15 Column: b
Tri-State Generation and Transmission Association, Inc. - Contract Termination Date: The
date that all generating plants comprising PacifiCorp resources associated with this
agreement have been retired from service or interests transferred.
ISchedule Page: 332.4 Line No.: I Column: g
Ancillary Services.
ISchedule Page: 332.4 Line No.: 2 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "TUCSON ELECTRIC POWER" ON PAGE 332: Complete
name is Tucson Electric Power Company.
ISchedule Page: 332.4 Line No.: 3 Column: g
Ancillary Services.
Schedule Page: 332.4 Line No.: 5 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "WESTPORT FIELD SRV LLC" ON PAGE 332: Complete
name is Westport Field Services, LLC.
Schedule Page: 332.4 Line No.: 5 Column: b
Westport Field Services, LLC - Contract Termination Date: Evergreen.
Schedule Page: 332.4 Line No.: 5 Column: e
Reimbursement for providing third party service.
ISchedule Page: 332.4 Line No.: 6 Column: a
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "WESTERN AREA POWER ADM." ON PAGE 332:
Complete name is Western Area Power Administration.
Schedule Page: 332.4 Line No.: 6 Column: b
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)
PaciflCorp (2)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 332.4 Line No.: 6 Column: g
Ancillary Services. Use of Facilities.
Schedule Page: 332.4 Line No.: 8 Column: b
Western Area Power Administration - Contract Termination Date: May 31, 2022.
Schedule Page: 332.4 Line No.: 10 Column: g
Ancillary Services. Use of Facilities.
[Schedule Page: 332.4 Line No.: 11 Column: b
Legacy Contract (Rate Schedule 664) executed between PacifiCorp and Western Area Power
Administration concerning the exchange of transmission services over agreed-upon
facilities. The contract terminates 50 years from execution. See also FERC Account 456.1,
Transmission of electricity for others, page 328 of this Form No. 1.
Schedule Page: 332.4 Line No.: 13 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 FERC Account
565, Transmission of electricity by others, during the period.
IFERC FORM NO. I (ED. 12-87) Page 450.5 1
Name of Respondent
PaciflCorp
This Rort Is: Mn 2r:1r::ssion
Date of Report
/212
Year/Period of Report
End of 2011/Q4
MISCELLANEOUS - GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line Description
(a)
Amount
(b)
1 Industry Association Dues 2,003,108
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist Info to Stkhldrs ... expn servicing outstanding Securities
5 0th Expn >5,000 show purpose, recipient, amount. Group if < $5,000
6
7 Community & Economic Development and
8 Corporate Memberships & Subscriptions:
9 Bend 2030 10,000
10 Carbon County Economic Development Corporation 5,000
11 Clatsop Economic Development 5,000
12 Economic Development Corporation of Utah 11,600
13 Linn-Benton Community College 5,000
14 Utah Governor's Economic Summit 10,000
15 Oregon Economic Development Association 10,000
16 Port of Columbia 5,000
17 Siskiyou County Economic Development 10,000
18 Southeast Utah Community Development Corporation 6,750
19 Southern Oregon Regional Economic Development Inc 6,500
20 State of Oregon 10,000
21 State of Utah 10,000
22 Uintah County Economic Development 5,000
23 Wyoming Economic Development Association 10,000
24 Associated Oregon Industries 28,000
25 Economic Development For Central Oregon 7,500
26 Four County Economic Development Corp 25,000
27 Intermountain Electrical Association 9,000
28 Northern Tier Transmission Group 209,044
29 Oregon Business Association 12,250
30 Oregon Business Council 30,206
31 Oregon Sports Authority Foundation 5,000
32 Oregon State University 15,000
33 Pacific Northwest Utilities Conference 69,069
34 Portland Business Alliance 39,400
35 Redmond Economic Development 5,000
36 Rocky Mountain Electrical League 18,000
37 Salt Lake Area Chamber Of Commerce 30,555
38 South Coast Development Council Inc 15,000
39 1 Utah Foundation 26,650
40 Utah Information Technologies 5,500
41 Utah Manufacturers Association 12,000
42 Utah Taxpayers Association 20,000
43 Watson & Renner 50,208
44 Western Electricity Coordinating Council 3,113,443
45 Western Energy Institute 42,977
46 TOTAL 15,710,771
FERC FORM NO. I (ED. 12-94) Page 335
Name of Respondent
PacifiCorp
This Report Is:
(1)Li An Original
(2)A Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
- MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line
No. Descrii,tion
(a)
Amount
(b)
6 Wyoming Business Alliance 5,000
7 Wyoming Taxpayers Association 8,000
8 Yakima County Development 7,500
9 Other 195,877
10
11 Director's Fees - Regional Advisory Boards 22,444
12
13 General:
14 MidAmerican Energy Holdings Company Affiliate Svcs. 7,998,043
15 1 Western Coal Carrier Liability 1,367,188
16 Settlement Fees 92,500
17 Internal Revenue Service
18 Pollution Control Request Fee 14,000
19 Other 38,172
20
21 Regulatory Asset Amortization:
22 Goodnoe Hills Settlement - WY 21,250
23 Lakeside Settlement - 27,919
24 Other 1,118
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 15,710,771
FERC FORM NO. I (ED. 12-94) Page 335.1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr) End of 2011/Q4
(2)ffjA Resubmission 06/2812012
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403,404,4(5)
(Except amortization of aquisition adjustments)
1.Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) 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 section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as 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 Depreciation Expense for Asset Limited Term Amortization of
0. Functional Classification Expense Retirement Costs Electric Plant Other Electric Total
(Account 403) (Account 403.1) (Account 404) Plant (Acc 405)
- (a) (b) (c) (d) (e) (f)
I Intangible Plant 38,609,300 38,609,300
2 Steam Production Plant 139,598,874 139,598,874
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 19,021,804 254,126 19,275,930
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 115,518,950 115,518,950
7 Transmission Plant 84,271,946 84,271,946
8 Distribution Plant 150,336,410 150,336,410
9 Regional Transmission and Market Operation
10 General Plant 36,082,214 3,340,933 39,423,147
11 Common Plant-Electric
12 TOTAL 42,204,359 587,034,557
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. I (REV. 12-03) Page 336
Name of Respondent
PacifiCorp
This Re ort Is:
(
1 )
An Original
(2) VIA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No
-
Account No.
(a)
uepreciable
Plant Base
(In Thousands)
(b)
Estimated
Avg. Service
Life
(c)
Net
Salvage
(Percent)
(d)
Applied
Depr. rates
(Percent)
(e)
Mortality
Curve
Type
(0
Average
Remaining
Life
(ci)
12 HYDRAULIC PROD.
13 Stairs
14 336.00 UT 6 6.78 14.70
15
1€
17 330.20 OR/CA 41 -0.95 8.00
18 330.40 OR/CA 1 -1.12 8.00
19 331.00 OR/CA 13,562 8.58 8.00
20 332.00 OR/CA 33,572 5.89 8.00
21 333.00 OR/CA 17,754 7.41 8.00
22 334.00 OR/CA 15,030 9.61 8.00
23 335.00 OR/CA 172 4.80 8.00
24 336.00 OR/CA 2,548 6.69 8.00
25
26 WIND GENERATION
27 Dunlap Ranch I
28 344.00 WY 5,565 24.87 -1.00 4.06
29 345.00 WY 12,296 24.87 -1.00 4.06
30 346.00 WY 149 24.87 -1.00 4.06
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. I (REV. 12-03) Page 337
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 336 Line No.: 12 Column: b
Depreciation expense associated with transportation equipment is generally charged to
operations and maintenance expense and construction work in progress. During the year
ended December 31, 2011, depreciation expense associated with transportation equipment was
$14,396,524.
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.
Icfedule Page: 336 Line No.: 16 Column: a
The depreciation rate changes are for the Klamath hydroelectric system's four mainstem
dams (JC Boyle, Iron Gate, Copco No. 1 and Copco No. 2) . For further discussion, refer to
Note 13 of Notes to Financial Statements in this Form No. 1.
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
PaciliCo
This Re ort Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 party.
2.Report in columns (b) and (c), only the current years expenses that are not deferred and the current years amortization of amounts
deferred in previous years.
Line
No.
-
Description
(Furnish name of regulatory commission or body th e
docket or case number and a description of the case)
(a)
Assessed by
Regulatory
Commission
(b)
Expenses
of
Utility
(c)
Total Expense for
Current Year
(b) + (c)
(d)
Deferred
in Account
18 3 at Beginning of Year
(e)
1 Utah Public Service Commission:
2 Annual Fee 3,987,973 3,987,973
3 Rate Case 2,250,421 2,250,421
4
5 Oregon Public Utility Commission:
6 Annual Fee 2,614,463 2,614,463
7 Rate Case 1,261,104 1,261,104
8 Deferrred Intervenor Funding Grants 37,082
9
10 Wyoming Public Service Commission:
11 Annual Fee 1,316,982 1,316,982
12 Rate Case 1,557,480 1,557,480
13
14 Washington Utilities and Transportation
15 Commission:
16 Annual Fee 536,458 536,458
17 Rate Case 1,208,962 1,208,962
18
19 Idaho Public Utilities Commission:
20 Annual Fee 427,197 427,197
21 Rate Case 1,130,233 1,130,233
22 Deferred Intervenor Funding Grants (2) 24,095 24,095 43,79
23
241 California Public Utilities Commission:
25 Annual Fee 869 869
26 Rate Case 743,153 743,153
27 Deferred Intervenor Funding Grants
28
29 California Environmental Protection Agency:
30 Industry Compliance Fee 191,375 191,375
31
32 Rate Cases - All States 110,831 110,831
33
34 Federal Energy Regulatory Commission:
35 Annual Fee 1,846,171 1,846,171
36 Transmission Rate Case 1,336,313 1,336,313
37 FERC Other Regulatory 1,003,171 1,003,171
38
39 Other Regulatory 79,736 79,736
40
41 Charges for services from MidAmerican Energy
42 Holdings Company and its affiliates:
43 Utah - Rate Case 175 175
44 Washington - Rate Case 43,196 43,196
45 FERC - Other Regulatory 186,742 186,742
461 TOTAL 10,921,4881 10,935,6121 21,857,100 80,879
FERC FORM NO. 1 (ED. 12-96) Page 350
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)EKIA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5.Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to
Account 182.3
(I)
Contra
Account
(j)
Amount
(k)
Deferred in Account 182.3
(I)
Line
No.
-
Department
(f)
AcDunt 0.
(g)
Amount
(h)
Electric 928 3,987,973 2
Electric 928 2,250,421 3
4
5
Electric 928 2,614,463 6
Electric 928 1,261,104 7
Electric 928 308,561 345,643 8
9
10
Electric 928 1,316,982 11
Electric 928 1,557,480 12
13
14
15
Electric 928 536,458 16
Electric 928 1,208,962 17
18
19
Electric 928 427,197 20
Electric 928 1,130,233 21
Electric 928 24,095 39,000 928 24,095 58,702 22
23
24
Electric 928 869 25
Electric 928 743,153 26
32,885 32,885 27
28
29
Electric 928 191,375 30
31
Electric 928 110,831 32
33
34
Electric 928 1,846,171 35
Electric 928 1,336,313 36
Electric 928 1,003,171 37
38
Electric 928 79,736 39
40
41
42
Electric 928 175 43
Electric 928 43,196 44
Electric 928 186,742 45
21,857,1001 380,446 24,0951 437,230 46
FERC FORM NO. I (ED. 12-96) Page 351
Name of Respondent
PacifiCo
This Re oil Is:
(1)An Original
(2)ffJA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 projects.(ldentify
recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accounts).
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 electrical Research Council or the Electric
f.Siting and heat rejection Power Research Institute
(2) Transmission
Line
No.
Classification
(a)
Description
(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 - Utility Gasification Association
7 - Prism 2.0 Regional Energy and Economic Model Development
8 (2) Research Support Edison Electric Institute
9 - Utility Solid Waste Activities Group - membership dues
10 - Avian Power Line Interaction Committee - membership dues
11 (4) Research Support National Electric Energy Testing, Research & Applications Center
12 - Membership dues
13 - Participation
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. I (ED. 12-87) Page 352
Name of Respondent
PacifiCorp
This Report Is:
(1)LJAn Original
(2)LKA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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
activity.
4.Show in column (e) the account 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 column (f) the amounts related to the account charged in column (e)
5.Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research,
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6.If costs have not been segregated for R, 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 facilities operated by the respondent.
Costs Incurred Internally
Current Year
Costs Incurred Externally
Current Year
(d)
AMOUNTS CHARGED IN CURRENT YEAR Unamortized
Accumulation
(g)
Line
No. - Account
(e)
Amount
(f)
2
275,871 930.2 275,871 3
20,000 930.2 20,000 4
12,000 557 12,000 5
5,000 557 5,000 6
281,032 930.2 281,032 7
8
56,000 930.2 56,000 9
2,500 930.2 2,500 10
11
71,250 930.2 71,250 12
580 16,352 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. I (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 (2) X A Resubmission 06/28/2012 20111Q4
FOOTNOTE DATA
Schedule Page: 352 Line No.: 13 Column: c
Estimate
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Line
No.
Classification
(a)
Direct Payroll Payroll J for Total
CleannAccounts
(b) ?c) (d)
I
2
3
Electric
Operation
Production 1 90,552,812
4 Transmission 9,559,334
5 Regional Market
6 Distribution 42,801,340
7 Customer Accounts 40,029,642
8 Customer Service and Informational 5,939,230
9 Sales
10 Administrative and General 39,882,825
11 TOTAL Operation (Enter Total of lines 3 thru 10) I 228,765,183
12
13
14
15
Maintenance
Production
Transmission
Regional Market
46,830,499
13,148,569
16 Distribution 66,402,294
17 Administrative and General 2,067,090
18 TOTAL Maintenance (Total of lines 13 thru 17) 128,448,452
19
20
Total Operation and Maintenance
Production (Enter Total of lines 3 and 13) I 137,383,311
21 Transmission (Enter Total of lines 4 and 14) 22,707,903
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16) 109,203,634
24 Customer Accounts (Transcribe from line 7) 40,029,642
25 Customer Service and Informational (Transcribe from line 8) 5,939,230
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17) 41,949,915
28 TOTAL Oper. and Maint. (Total of lines 20 thru 27) I 357,213,6351 I 357,2139635
29
30
31
Gas
Operation
Production-Manufactured Gas I
32 Production-Nat. Gas (Including Expl. and Dev.)
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42
43
Maintenance
Production-Manufactured Gas
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
FERC FORM NO. I (ED. 12-88) Page 354
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Line
No.
-
Classification
(a)
Direct Payroll
(b)
Payroll i for Total
Clearing Accounts c) (d)
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49) I
51
52
Total Operation and Maintenance
Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (Including ExpI. 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 Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64) I 357,213,6351 357,213,635 k
66
67
68
Utility Plant
Construction (By Utility Departments)
Electric Plant 151,718,9451 I 151 ,718,945I
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70) 151,718,945 151,718,945
72
73
Plant Removal (By Utility Departments)
Electric Plant 10,828,888 10,828,888
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75) 10,828,888 10,828,888
77 Fuel Stock 2,361,594 2,361,594
78 Miscellaneous Other Income Deductions 522,628 522,628
79 Charges to Affiliates 676,800 676,800
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts 3,561,022 3,561,022
96 TOTAL SALARIES AND WAGES 523,322,490 523,322,490
FERC FORM NO. I (ED. 12-88) Page 355
Name of Respondent
PacifiCorp
This Report Is:
(1)LjAn Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for
Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for
purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining
whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and
separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line
No
Description of Item(s)
(a)
Balance at End of
Quarter 1
(b)
Balance at End of
Quarter 2
(c)
Balance at End of
Quarter 3
(d)
Balance at End of
Year
(e)
1 Energy
2 Net Purchases (Account 555) 3,904,370 8,321,702 11,068,144 13,075,867
3 1 Net Sales (Account 447) ( 3,091,739) ( 5,730,428) ( 12,748,467) ( 20,339,894)
4 Transmission Rights
5 Ancillary Services
6 Other Items (list separately)
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 TOTAL 812,631 2,591,274 ( 1,680,3231 ( 7,264,027)
FERC FORM NO. 113-Q (NEW. 12-05) Page 397
I Name of Respondent I This Reoort Is: I Date of Report I Year/Period of Report I (1) An Original (Mo, Da, Yr) I End of 2011/Q4 PacifiCorp I (2) [1A Resubmission 06/28/2012 I
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
(1)On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary 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 ancillary 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 Billing Determinant
-
Usage - Related Billing Determinant
Line
No
Type of Ancillary Service
(a)
Number of Units
(b)
Unit of
Measure
(c)
Dollars
(d)
Number of Units
(e)
Unit of
Measure
(f)
Dollars
(g)
1 Scheduling, System Control and Dispatch i
2 Reactive Supply and Voltage
3 Regulation and Frequency Response 58,667,591 MWh 9,386,815 59,261,270 MWh 10,014,042
4 Energy Imbalance -145,875 MWh -2,969,136
5 Operating Reserve - Spinning 63,248,409 MWh 22,934,366 67,800,550 MWh 24,678,648
6 Operating Reserve - Supplement 63,248,409 MWh 22,934,366 67,695,838 MWh 24,639,578
7 Other 494 MWh
8 Total (Lines 1 thru 7) 185,164,409 55,255,5471 194,612,277 56,516,180
FERC FORM NO. I (New 2-04) Page 398
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PaciliCorp (2) X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 398 Line No.: 7 Column: g
Emergency Reserve Energy Provided
IFERC FORM NO. 1 (ED. 12-87) Page 450.1 1
Name of Respondent
PacifiCo
I This Report Is:
(1)EJAn Original
(2)MA Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 U) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the
definition of each statistical classification.
NAME OF SYSTEM:
Line
No.
-
Month
(a)
Monthly Peak
MW - Total
(b)
Day of
Monthly
Peak
(c)
Flour of Firm Network
Monthly Service for Self
Peak
(d) (e)
Firm Network
Service for
Others
(f)
Long-Term Firm
Point-to-point
Reservations
(g)
Other Long-
Term Firm
Service
(h)
Short-Term Firm
Point-to-point
Reservation
(i)
Other
Service
U)
1 January 16,56 11 8,682 118 5,2491 1 840 1,680
2 February 17,59 8,602 118 5,249 1,947 1,674
3 March 1534 7,731 100 5,249 838 1,428
4
5
Total for Quarter 1
April
49,50
16,01 7,5121 941 5,2491 1,731 1,424
6 May 15,35 1 7.087 82 5,417 1,432 1,338
7 June 18,15 211 8,613 95 5,880 1,822 1,746
8
9
Total for Quarter 2
July
49,521
19,61 9,2611
9,431
101
110
5.880
5,880
2,645 1,727
10 August 19.18 2 1.881 1,878
11 September 17,30 8,510 98 5,267 1.702 1,729
121
13
Total for Quarter 3
October
56.1
15,061 2 7,543 429 1,396 93 5.603
14 November 15.12 2 7.827 86 4.962 743 1,507
15 December 15.67 1 8,786 96 4,962 215 1,619
16
17
Total for Quarter 4
Total Year to
Date/Year
45,86,
201,00t
I I I
99.591 1,191 64,847 16,225 19,146
FERC FORM NO. 113-0 (NEW. 07-04) Page 400
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 0612812012 201 1 IQ4
FOOTNOTE DATA
Schedule Page: 400 Line No.: I Column: d
Pacific Standard Time.
Schedule Page: 400 Line No.: 2 Column: d I
Pacific Standard Time.
Schedule Page: 400 Line No.: 3 Column: d I
Pacific Standard Time.
Schedule Page: 400 Line No.: 4 Column: e
1st Quarter 2011 Net System Load information was compiled using metering and/or scheduling
data. Reflects actual peak net system load for self at time of Transmission System Peak.
Schedule Page: 400 Line No.: 4 Column: f
1st Quarter 2011 Net System Load information was compiled using metering and/or scheduling
data. Reflects actual peak of customers' load at time of Transmission System Peak.
Schedule Page: 400 Line No.: 4 Column: g
1st Quarter 2011 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak. Long-term firm point-to-point reservations have been
adjusted so that the monthly megawatt reservations represent an amount at system input as
measured by the transmission system loss factor established in FERC Docket No. ER11-3643.
This adjustment has been made to ensure that transmission rates are designed fairly and in
a non-discriminatory manner and is consistent with the system input measurement utilized
for other long-term firm users of PacifiCorp's transmission system, including network
service.
Schedule Page: 400 Line No.: 4 Column: i I
1st Quarter 2011 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak.
Schedule Page: 400 Line No.: 4 Column:j I
1st Quarter 2011 Net System Load information was compiled using metering, scheduling
and/or contractual data. Reflects actual peak and/or contractual demands of customers'
load at time of Transmission System Peak.
ISchedule Page: 400 Line No.: 5 Column: d I
Pacific Daylight Time.
Schedule Page: 400 Line No.: 6 Column: d I
Pacific Daylight Time.
Schedule Page: 400 Line No.: 7 Column: d I
Pacific Daylight Time.
Schedule Page: 400 Line No.: 8 Column: e I
2nd Quarter 2011 Net System Load information was compiled using metering and/or scheduling
data. Reflects actual peak net system load for self at time of Transmission System Peak.
Schedule Page: 400 Line No.: 8 Column: f
2nd Quarter 2011 Net System Load information was compiled using metering and/or scheduling
data. Reflects actual peak of customers' load at time of Transmission System Peak.
Schedule Page: 400 Line No.: 8 Column: g I
2nd Quarter 2011 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak. Long-term firm point-to-point reservations have been
adjusted so that the monthly megawatt reservations represent an amount at system input as
measured by the transmission system loss factor established in FERC Docket No. ER11-3643.
This adjustment has been made to ensure that transmission rates are designed fairly and in
a non-discriminatory manner and is consistent with the system input measurement utilized
for other long-term firm users of PacifiCorp's transmission system, including network
service.
lSchedule Page: 400 Line No.: 8 Column: i
2nd Quarter 2011 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak.
jçpdule Page: 400 Line No.: 8 Column:j I
2nd Quarter 2011 Net System Load information was compiled using metering, scheduling
IFERC FORM NO. 1 (ED. 12-87) Page 450.1 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/2812012 2011/Q4
FOOTNOTE DATA
and/or contractual data. Reflects actual peak and/or contractual demands of customers'
load at time of Transmission System Peak.
Schedule Page: 400 Line No.: 9 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 10 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 11 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 12 Column: e
3rd Quarter 2011 Net System Load information was compiled using metering and/or scheduling
data. Reflects actual peak net system load for self at time of Transmission System Peak.
ISchedule Page: 400 Line No.: 12 Column: f
3rd Quarter 2011 Net System Load information was compiled using metering and/or scheduling
data. Reflects actual peak of customers' load at time of Transmission System Peak.
Schedule Page: 400 Line No.: 12 Column: g
3rd Quarter 2011 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak. Long-term firm point-to-point reservations have been
adjusted so that the monthly megawatt reservations represent an amount at system input as
measured by the transmission system loss factor established in FERC Docket No. ER11-3643.
This adjustment has been made to ensure that transmission rates are designed fairly and in
a non-discriminatory manner and is consistent with the system input measurement utilized
for other long-term firm users of PacifiCorp's transmission system, including network
service.
Schedule Page: 400 Line No.: 12 Column: i
3rd Quarter 2011 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak.
Schedule Page: 400 Line No.: 12 Column:j
3rd Quarter 2011 Net System Load information was compiled using metering, scheduling
and/or contractual data. Reflects actual peak and/or contractual demands of customers'
load at time of Transmission System Peak.
ISchedule Page: 400 Line No.: 13 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 14 Column: d
Pacific Standard Time.
Schedule Page: 400 Line No.: 15 Column: d
Pacific Standard Time.
Schedule Page: 400 Line No.: 16 Column: e
4th Quarter 2011 Net System Load information was compiled using metering and/or scheduling
data. Reflects actual peak net system load for self at time of Transmission System Peak.
ISchedule Page: 400 Line No.: 16 Column: f
4th Quarter 2011 Net System Load information was compiled using metering and/or scheduling
data. Reflects actual peak of customers' load at time of Transmission System Peak.
Schedule Page: 400 Line No.: 16 Column: g
4th Quarter 2011 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak. Long-term firm point-to-point reservations have been
adjusted so that the monthly megawatt reservations represent an amount at system input as
measured by the transmission system loss factor established in FERC Docket No. ER11-3643.
This adjustment has been made to ensure that transmission rates are designed fairly and in
a non-discriminatory manner and is consistent with the system input measurement utilized
for other long-term firm users of PacifiCorp's transmission system, including network
service.
ISchedule Page: 400 Line No.: 16 Column: i
4th Quarter 2011 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak.
Schedule Page: 400 Line No.: 16 Column:j
IFERC FORM NO. I (ED. 12-87) Page 450.2 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 201 1 /Q4
FOOTNOTE DATA
4th Quarter 2011 Net System Load information was compiled using metering, scheduling
and/or contractual data. Reflects actual peak and/or contractual demands of customers'
load at time of Transmission System Peak.
IFERC FORM NO. I (ED. 12-87) Page 450.3 I
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line
No.
Item
(a)
MegaWatt Hours
(b)
Line
No.
Item
(a)
MegaWatt Hours
(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use): 22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
54,306,866
3 Steam I 42,751,0961
4 Nuclear 23 Requirements Sales for Resale (See
instruction 4, page 311.)
202,448
5 Hydro-Conventional 4,687,360
6 Hydro-Pumped Storage -2,356 24 Non-Requirements Sales for Resale (See
instruction 4, page 311.)
10,564,249
7 Other 7,996,881
81
9
Less Energy for Pumping
Net Generation (Enter Total of lines 3
through 8)
55,432,981
25
26
Energy Furnished Without Charge
Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
10 Purchases 14,094,451 27 Total Energy Losses 4,247,4341
11 Power Exchanges: 28
-
TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
69,474,797
12 Received 14,561,771
13 Delivered 14,342,45f
14 Net Exchanges (Line 12 minus line 13) 219,31C
15 Transmission For Other (Wheeling)
16 Received 14,698,484
17 Delivered 14,582,697
18 Net Transmission for Other (Line 16 minus
line 17)
115,787
19 Transmission By Others Losses -387,73f
20 TOTAL (Enter Total of lines 9, 10,14,18
and 19)
69,474,79
FERC FORM NO. 1 (ED. 12-90) Page 401a
Name of Respondent
PaciflCorp
This Re ort Is:
(2) E]A Resubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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
No.
-
Month
(a)
Total Monthly Energy
(b)
Monthly Non-Requirments
Sales for Resale &
Associated Losses
(C)
MONTHLY PEAK
Megawatts (See lnstr. 4)
(d)
Day of Month
(e)
Hour
(f)
29 January 6,145,245 829,592 8,682 11 1800 PST
30 February 5,486,873 787,993 8,602 2 0800 PST
31 March 5,593,923 695,388 7,731 3 0800 PST
32 April 5,452,744 912,780 7,518 8 0900 PDT
33 May 5,372,546 858,111 7,087 17 1000 POT
34 June 5,478,568 834,335 8,615 28 1500 PDT
351 July 6,175,679 797,371 9,261 6 1700 PDT
36 August 6,273,514 945,911 9,431 23 1700 POT
37 September 5,651,630 962,343 8,510 7 1700 PDT
38 October 5,754,137 1,112,061 7,543 27 0800 PDT
39 November 5,767,930 932,317 8,018 29 1800 PST
40 December 6,322,008 896,047 8,786 13 1800 PST
411 TOTAL 69,474,797 10,564,249
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)
PaciflCorp (2)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 401 Line No.: 26 Column: b
For metered locations only.
IFERC FORM NO.1 (ED. 12-87) Page 450.1 I
Name of Respondent
PacifiCorp
This Re ort Is: (1)An Original
(2)A Resubmission
Date of Report (Mo, Da, Yr)
06128/2012
Year/Period of Report
End of 2011/Q4
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 facility. 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
No.
-
Item
(a)
Plant
Name: Carbon
(b)
Plant
Name:
c)
1 Kind of Plant (Internal 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) 176 386
7 Plant Hours Connected to Load 8760 8150
8 Net Continuous Plant Capability (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 6
12 Net Generation, Exclusive of Plant Use - KWh 1332218000 2688370000
13 Cost of Plant: Land and Land Rights 956546 2468743
14 Structures and Improvements 15338483 59823657
15 Equipment Costs 103948678 462802607
16 Asset Retirement Costs 6676303 39000
17 Total Cost 126920010 525134007
18 Cost per KW of Installed Capacity (line 17/5) Including 672.9587 1268.4396
19 Production Expenses: Oper, Supv, & Engr 44274 2321461
20 Fuel 20346469 54754988
21 Coolants and Water (Nuclear Plants Only) 0 0
22 Steam Expenses 1629639 8463931
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr) 0 0
25 Electric Expenses 2111880 1143719
26 Misc Steam (or Nuclear) Power Expenses 4213408 1678311
27 Rents 0 623
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 2009197
30 Maintenance of Structures 325434 645306
31 Maintenance of Boiler (or reactor) Plant 2483678 4986755
32 Maintenance of Electric Plant 623477 692107
33 Maintenance of Misc Steam (or Nuclear) Plant 274457 2069412
34 Total Production Expenses 32052716 78765810
35 Expenses per Net KWh 0.0241 0.0293
35 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Coal Composite Coal Composite
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Tons Barrels Tons Barrels
38 Quantity(Units)of Fuel Burned 622119 946 0 1525966 1358 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 11896 138000 0 9255 130677 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 31.638 127.607 0.000 34.339 68.717 0.000
41 Average Cost of Fuel per Unit Burned 32.511 127.607 0.000 35.821 68.717 0.000
42 Average Cost of Fuel Burned per Million BTU 1.366 22.016 1.374 1.935 12.521 1.938
43 Average Cost of Fuel Burned per KWh Net Gen 0.015 0.000 0.015 0.020 0.000 0.020
44 Average BTU per KWh Net Generation 11110.245 4.117 11114.362 10506.464 2.772 110509.236
FERC FORM NO. I (REV. 12-03) Page 402
Name of Respondent
PaciflCorp
This Re port Is:
(2) E]A Resubmission
Date of Report
06/28/2012
Year/Period of Report
End of 201 1/Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "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
Name:
(d)
Plant
Name:
(e)
Plant
Name: Dave Johnston
(f)
Line
No.
Steam Steam Steam 1
Conventional Outdoor Boiler Semi-Outdoor 2
1984 1979 1959 3
1986 1980 1972 4
155.60 172.10 816.80 5
158 167 739 6
8733 8594 8760 7
0 0 0 -
148 166 762 9
0
1024321000
0
1238973000
0
184
5059927000
11
12
1355853 137086 10449793 13
58963335 36736994 138397193 14
160108957 138115179 727062666 15
39236 35149 11315101 16
220467381 175024408 887224753 17
1416.8855 1016.9925 1086.2203 18
32071 318592 527243 19
14374159 20121375 55295019 20
O 0 0
1011088 1470143 157589 22
0 0
0 0 0 24
61416 539914 0 25
1290085 1164872 17485536 26
19524 0 6135 27
0 0 oi
242125 697719 0 29
441300 343860 1824395 30
3191174 4569823 10764964 31
391 818 2096100 6678185 32
427374 787463 1650053 33
21482134 32109861 94389119 34
0.0210 0.0259 0.0187 35
Coal - Composite Coal Composite Coal Composite 36
Tons Barrels Tons Barrels Tons Barrels 37
636245 1678 0 630050 131 0 3590793 22751 0 38
8451 140000 0 9920 133693 0 7947 138000 0 39
19.706 113.969 0.000 122.081 0.000 14.365 126.447 0.000 40
22.292 113.969 0.000 31.772 122.081 0.000 14.598 126.447 0.000 41
1.319 19.383 1.335 01 21.750 1.610 0.919 21.816 0.967 42
0.014 0.000 0.014 16
t
0.000 0.016 0.010 0.001 0.011 43
10498.343 9.633 10507.976 088.714 0.595 10089.309 11278.589 26.061 11304.650 44
FERC FORM NO. 1 (REV. 12-03) Page 403
Name of Respondent
PacifiCorp
This Report Is:
(1)An Original
(2)[]A Resubmission
Date of Report
(Mo, Da, Yr)
06/2812012
Year/Period of Report
End of 2011 /Q4
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 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
No.
-
Item
(a)
Plant
lame:
(b)
Plant
Name:
(C)
1 Kind of Plant (internal Comb, Gas Turb, Nuclear Steam Steam
2 IType 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) 79 434
7 Plant Hours Connected to Load 86571 8026
8 Net Continuous Plant Capability (Megawatts) 0 0
9 When Not Limited by Condenser Water 78 418
10
11
12
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh
01
561914000
0
2845170000
13 Cost of Plant: Land and Land Rights 684554 9688975
14 Structures and Improvements 17564005 63175797
15 Equipment Costs 63820005 270958555
16 Asset Retirement Costs 532363 431476
17 Total Cost 82600927 344254803
18 Cost per KW of Installed Capacity (line 17/5) Including 101 4.7534 752.1407
19 Production Expenses: Oper, Supv, & Engr 223582 92
20 Fuel 11038425 45927126
21 Coolants and Water (Nuclear Plants Only) 0 0
22 Steam Expenses 1043948 3066089
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr) 0 0
25 Electric Expenses 306825 0
26 Misc Steam (or Nuclear) Power Expenses 453333 2416651
27 Rents 0 3338
28 Allowances 0 0
29 Maintenance Supervision and Engineering 342384 0
30 Maintenance of Structures 284067 2179362
31 Maintenance of Boiler (or reactor) Plant 1247074 5596812
32 Maintenance of Electric Plant 519493 1371394
33 Maintenance of Misc Steam (or Nuclear) Plant 413283 205484
34 Total Production Expenses 15872414 60766348
35 Expenses per Net KWh 0.0282 0.0214
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Coal Composite Coal Composite
37 Unit (Coal-tons/OiI-barrel/Gas-mcf/Nuclear-indicate) Tons Barrels Tons Barrels
38 Quantity(Units)of Fuel Burned 272751 592 0 1277765 4134 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 11698 136997 0 11590 138000 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 37.320 19.099 0.000 0.000 0.000 0.000
41 Average Cost of Fuel per Unit Burned 40.080 119.099 0.000 35.498 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 1.713 20.697 1.729 1.531 23.754 1.549
43 Average Cost of Fuel Burned per KWh Net Gen 0.019 0.000 0.019 0.016 0.000 0.016
44 Average BTU per KWh Net Generation 11356.161 6.059 11362.220 10410.258 8.421 10418.679
FERC FORM NO. 1 (REV. 12-03) Page 402.1
Name of Respondent
PacifiCorp
This Report Is: Date of Report
06/28/2012
Year/Period of Report
End of 2011/04
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "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
Name:
(d)
Plant
Name: Hunter Unit No. 3
(e)
Plant
Name:
(I)
Line
No.
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
280 461 1149 6
6932 7880 8740 7
0 0 0
269 460 1147 9
0
1613030000
0
2986883000
213
7445083000
oii
11
12
9688975 10275401 29653351 13
51994484 91277571 206447852 14
239661036 410640791 921260382 15
431476 431476 1294428 16
301775971 512625239 1158656013 17
1024.7062 1034.3528 928.5591 18
59 101 252 19
25913796 49631646 121472568 20
0 0 0 !
2014131 3311933 8392153 22
0 0 0 23
0 0 0
0 0 0__
-1773864 2579207 3221994 26
2341 3673 9352 27
0 0 0
0 0 0
2232392 2136616 6548370 30
8996195 9448392 24041399 31
4119736 1794468 7285598 32
164934 412053 782471 33
41 669720 69318089 171754157 34
0.0258 0.0232 0.0231 35
Coal Composite Coal Composite Coal Composite 36
Tons Barrels Tons Barrels Tons Barrels 37
713870 3562 0 1343957 14267 0 3335592 21963 0 38
11577 138000 0 11413 138000 0 11516 138000 0 39
0.000 0.000 0.000 0.000 0.000 0.000 38.413 136.519 0.000 40
35.619 0.000 0.000 35.484 0.000 0.000 35.518 136.519 0.000 41
1.538 23.562 1.566 1.555 23.494 1.614 1.542 23.554 1.579 42
0.016 0.000 0.016 0.016 0.001 0.017 0.016 0.000 0.016 43
10246.984 12.799 10259.783 10270.174 27.686 10297.860 10318.684 17.098 10335.782 44
FERC FORM NO. I (REV. 12-03) Page 403.1
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)jA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 201 1 /Q4
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 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
No.
-
Item
(a)
Plant
Name: Huntington
(b)
Plant
Name:
(C)
1 Kind of Plant (Internal 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) 934 1421
7 Plant Hours Connected to Load 8276 8760
8 Net Continuous Plant Capability (Megawatts) 0 0
9 When Not Limited by Condenser Water 909 1412
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 163 331
12 Net Generation, Exclusive of Plant Use - KWh 5961371000 8905672000
13 Cost of Plant: Land and Land Rights 2386782 1161925
14 Structures and Improvements 115439586 140256251
15 Equipment Costs 698035416 912532257
16 Asset Retirement Costs 1320578 5049612
17 Total Cost 817182362 1059000045
18 Cost per KW of Installed Capacity (line 17/5) Including 820.4642 685.3926
19 JProduction Expenses: Oper, Supv, & Engr 13687 15431407
20 Fuel 94465053 205181742
21 Coolants and Water (Nuclear Plants Only) 0 0
22 Steam Expenses 7704010 3732333
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr) 0 0
25 Electric Expenses 0 15495
26 Misc Steam (or Nuclear) Power Expenses 12330552 -12200227
27 Rents 1000 227829
28 Allowances 0 0
29 Maintenance Supervision and Engineering 1299908 430025
30 Maintenance of Structures 2441557 8264038
31 Maintenance of Boiler (or reactor) Plant 12135022 25851801
32 Maintenance of Electric Plant 3934986 8293459
33 Maintenance of Misc Steam (or Nuclear) Plant 1146487 3573047
34 Total Production Expenses 135472262 258800949
35 Expenses per Net KWh 0.0227 0.0291
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Coal Composite Coal MComposite
37 Unit (Coal-tons/Oil-barrel/Gas-rncf/Nuclear-indicate) Tons Barrels Tons Barrels
38 Quantity (Units) of Fuel Burned 2457036 14459 0 4987635 19395 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 11682 138000 0 9209 138000 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 35.048 135.969 0.000 117.187 0.000
41 Average Cost of Fuel per Unit Burned 37.647 135.969 0.000 40.682 117.187 0.000
42 Average Cost of Fuel Burned per Million BTU 1.611 23.459 1.643 2.209 20.219 2.231
43 Average Cost of Fuel Burned per KWh Net Gen 0.016 0.000 0.016 0.023 0.000 10.023
44 Average BTU per KWh Net Generation 9629.811 14.058 9643.869 10315.263 112.622 110327.885
FERC FORM NO. 1 (REV. 12-03) Page 402.2
Name of Respondent
Pacif'iCorp
This Report Is: Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "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
Name: Naughton
(d)
Plant
Name:
(e)
Plant
Name: Gadsby Steam
(f)
Line
No. -
Steam Steam Steam 1
Outdoor Boiler Conventional Outdoor 2
1963 1978 1951 3
1971 1978 1955 4
707.20 289.70 251.60 5
710 279 196 6
8760 6079 1228 7
0 0 0 8
700 268 231 9
0 0 0
146 65 3411
5102251 000 1457709000 69094000 12
1094739 210526 1252090 13
70184754 50872324 15095198 14
545628764 391262775 64530281 15
14207864 490453 587008 16
631116121 442836078 81464577 17
892.4153 1528.6023 323.7861 18
89488 302145 45847 19
101169233 15125638 9413917 20
0 0 0 i
4470634 13169 0 22
0 0 0!
0 0 0___
11279 0 0 25
13043071 4158309 3660485 26
1243 5701 0 27
0 0 0__
1343942 0 0 29
1286755 412626 257733 30
10693418 8086379 904380 31
3658603 4195535 1260907 32
1616276 238999 305328 33
137383942 32538501 15848597 34
0.0269 0.0223 0.2294 35
Coal Composite Coal Composite Gas 36
Tons MCF Tons Barrels MCF 37
2761016 134829 0 1163685 11714 0 1111436 0 0 38
9755 1030 0 7789 138000 0 1029 0 0 39
36.236 8.667 0.000 12.264 131.751 0.000 8.470 0.000 0.000 40
36.219 8.667 0.000 11.672 131.751 0.000 8.470 0.000 0.000 41
1.857 8.418 1.873 0.749 22.731 0.831 8.229 0.000 0.000 42
0.020 0.000 0.020 0.009 10.001 0.010 0.136 0.000 0.000 43
10557.037 27.209 10584.246 12435.966 146.577 12482.543 16556.749 0.000 0.000 44
FERC FORM NO. I (REV. 12-03) Page 403.2
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)JA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
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 period. 5. If any employees attend
more than one plant, report online 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
No.
Item
(a)
Plant
Name:
(b)
Plant
Name:
(C)
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) 16 243
7 Plant Hours Connected to Load 45531 7179
8 Net Continuous Plant Capability (Megawatts) 0
9 When Not Limited by Condenser Water 141 237
10 When Limited by Condenser Water 0 0
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - KWh 58348000 1161094000
13 Cost of Plant: Land and Land Rights 635 842245
14 Structures and Improvements 337028 12844996
15 Equipment Costs 1394634 156966194
16 Asset Retirement Costs 0 214373
17 Total Cost 1732297 170867808
18 Cost per KW of Installed Capacity (line 17/5) Including 108.2686 611.1152
19 Production Expenses: Oper, Supv, & Engr 0 0
20 Fuel 12500058 59623564
21 Coolants and Water (Nuclear Plants Only) 0 0
22 Steam Expenses 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr) 0 0
25 Electric Expenses 933523 6950632
26 Misc Steam (or Nuclear) Power Expenses 0 0
27 Rents 228838 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 976359 0
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 14638778 66574196
35 Expenses per Net KWh 0.2509 0.0573
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 1611369 0 0 8798228 0 0
39 Avg Heat Cont- Fuel Burned (btu/indicate if nuclear) 1039 0 0 1013 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 7.757 0.000 0.000 6.777 0.000 0.000
41 Average Cost of Fuel per Unit Burned 7.757 0.000 0.000 6.777 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 7.469 0.000 0.000 6.693 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.214 0.000 0.000 0.051 0.000 0.000
44 Average BTU per KWh Net Generation 28684.582 0.000 0.000 7672.944 0.000 0.000
FERC FORM NO. I (REV. 12-03) Page 402.3
Name of Respondent
PacifiCorp
This Report Is:
AResubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "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
Name:
Plant
Name:
Plant
Name: Chehalis
Line
No.
Steam - Geothermal Steam Combined Cycle 1
Indoor Outdoor Boiler Outdoor 2
1984 1996 2003 3
2007 1996 2003 4
38.10 61.50 593.30 5
39 26 514 6
8586 6535 2219 7
0 0 0 -
34 14 520 9
0 0 0
22 18 11
278079000 89501000 664323000 12
41195596 0 1973791 13
8005940 5733734 23249210 14
68821 997 28716806 318404262 15
1443379 0 689117 16
119466912 34450540 344316380 17
3135.6145 560.1714 580.3411 18
41563 0 129916 19
0 0 45556011 20
0 0
49466 0 0 22
3583830 0 0 23
0 o 0
0 87940 2781650 25
2207430 0 0 26
6247 0 36263 27
0 0__
0 0
520949 2721 30
172327 0 0 31
268540 0 1753886 32
34658 0 033
6885010 87940 50260447 34
0.0248 0.0010 0.0757 35
Gas 36
MCF 37
0 0 0 0 0 0 4969662 0 0 38
0 0 0 0 0 0 1032 0 0 39
0.000 0.000 0.000 0.000 0.000 0.000 9.167 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.000 9.167 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.000 8.884 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.000 0.069 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.000 771 8.590 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403.3
Name of Respondent
PaciflCorp
This Re ort Is:
(1)An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011 /Q4
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 period. 5. If any employees attend
more than one plant, report on line lithe 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
No.
-
Item
(a)
Plant
Name: Gadsby Peakers
(b)
Plant
Name: Currant Creek
(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine Combined Cycle
2 IType of Constr (Conventional, Outdoor, Boiler, etc) Outdoor Outdoor
3 Year Originally Constructed 2002 200
4 Year Last Unit was Installed 2002 200
5 Total Installed Cap (Max Gen Name Plate Ratings-Mw) 181.10 566.9
6 Net Peak Demand on Plant - MW (60 minutes) 132 56
7 Plant Hours Connected to Load 2591 8560
8 Net Continuous Plant Capability (Megawatts) 01 0
9 When Not Limited by Condenser Water 120 550
10 When Limited by Condenser Water 0
11 Average Number of Employees I
12 Net Generation, Exclusive of Plant Use - KWh 125295000 239714200
13 Cost of Plant: Land and Land Rights 0 3403277
14 Structures and Improvements 4240304 43915462
15 Equipment Costs 74912221 307655824
16 Asset Retirement Costs 0 134848
17 Total Cost 79152525 355109411
18 Cost per KW of Installed Capacity (line 17/5) Including 437.0653 626.4057
19 Production Expenses: Oper, Supv, & Engr 0 96501
20 Fuel 11760826 133088264
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 948474 3039306
26 Misc Steam (or Nuclear) Power Expenses 0 0
27 Rents 0 1363
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 148930 249281
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 1192213 1297526
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 14050443 137772241
35 Expenses per Net KWh 0.1121 0.0575
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 1477183 0 0 17032691 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 1036 0 0 1051 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 7.962 0.000 0.000 7.814 0.000 0.000
41 Average Cost of Fuel per Unit Burned 7.962 0.000 0.000 7.814 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 7.688 0.000 0.000 7.436 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.094 0.000 0.000 0.056 0.000 10.000
44 Average BTU per KWh Net Generation 12209.186 0.000 0.000 7466.425 0.000 10.000
FERC FORM NO. 1 (REV. 12-03) Page 402.4
Name of Respondent
PacifiCorp
This Report Is: Date of Report
06/28/2012
Year/Period of Report
End of 2011/04
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 'Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, '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
Name: Lake Side
(d)
Plant
Name:
(e)
Plant
Name:
(t)
Line
No.
-
Combined Cycle 1
Outdoor 2
2007 3
2007 4
591.30 0.00 0.00 5
561 0 0 6
5842 0 07
0 0 0
558 0 09
0 0 0 10
23 0 011
1845528000 0 0 12
17296760 0 0 13
27840392 0 0 14
311579774 0 0 15
0 0 0
356716926 0 0 17
603.2757 0 0 18
203394 0 0 19
104792180 0 0 20
0 0 0
!
0 0 0 22
0 0 0 2
0 0
4323244 0 0 25
0 oi
8047 0 0 27
0 0 0 28
0 0 0 29
2538016 0 0 30
0 0 0 31
3719493 0 0 32
0
115584374 0 0 34
0.0626 0.0000 0.0000 35
Gas 36
MCF 37
13386308 0 0 0 0 0 0 0 0 38
1022 0 0 0 0 0 0 0 0 39
7.828 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40
7.828 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41
7.657 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42
0.057 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43
7416.014 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44
FERC FORM NO. I (REV. 12-03) Page 403.4
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 402 Line No.: -1 Column: c
Cholla
The Cholla Plant is operated by Arizona Public Service Company and is jointly owned.
PacifiCorp owns 100% of Unit No. 4 and 36.66% of common facilities. Data reported in
column (c) represents PacifiCorp's share.
Schedule Page: 402 Line No.: -1 Column: d
Colstrip
The Colstrip Plant is operated by PPL Montana, LLC and is jointly owned. PacifiCorp owns a
10.0% share of Colstrip Plant Units No. 3 and No. 4. Data reported in column (d)
represents PacifiCorp's share.
Schedule Page: 402 Line No.: -1 Column: e
Craig
The Craig Plant is operated by Tri-State Generation and Transmission Association and is
jointly owned. PacifiCorp owns a 19.28% share of Craig Plant Units No. 1 and No. 2 and
12.86% of common facilities. Data in column (e) represents PacifiCorps share.
Schedule Page: 402 Line No.: 11 Column: c
Cholla - PacifiCorp does not have employees at the Cholla Plant.
ISchedule Page: 402 Line No.: 11 Column: d
Coistrip - PacifiCorp does not have employees at the Colstrip Plant.
çdule Page: 402 Line No.: 11 Column: e
Craig - PacifiCorp does not have employees at the Craig Plant.
lSchedule Page: 402.1 Line No.: -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 column (b) represents
PacifiCorpTs share.
Schedule Page: 402.1 Line No.: -1 Column: c
Hunter Unit No. 1
The Hunter Plant Unit No. 1 is owned by PacifiCorp and Utah Municipal Power Agency with an
undivided interest of 93.75% and 6.25%, respectively. Data reported in column (c)
represents Pacificorp's share. Costs that were billed to minority owners for the operation
and maintenance (excluding fuel) of this unit for calendar year 2011 were $1.1 million and
were primarily credited to Account 506, Miscellaneous steam power expenses.
ISchedule Page: 402.1 Line No.: -1 Column: d
Hunter Unit No. 2
The Hunter Plant Unit No. 2 is owned by PacifiCorp, Deseret Power Electric Cooperative and
Utah Associated Municipal Power Systems, each with an undivided interest of 60.31%,
25.108% and 14.5821, respectively. Data reported in column (d) represents PacifiCorp's
share. Costs that were billed to minority owners for the operation and maintenance
(excluding fuel) of this unit for calendar year 2011 were $10.3 million and were primarily
credited to Account 506, Miscellaneous steam power expenses.
ISchedule Page: 402.1 Line No.: -1 Column: f
Hunter - Total Plant
Refer to plant statistics for each Hunter Units Nos. 1, 2 and 3 on page 402.1 and 4031.
Schedule Page: 402.1 Line No.: 11 Column: b
Hayden - PacifiCorp does not have employees at the Hayden Plant.
Schedule Page: 402.1 Line No.: 11 Column: c
Hunter Unit No. 1 - Refer to the Hunter - Total Plant on page 403.1 for the average number
of employees.
Schedule Page: 402.1 Line No.: 11 Column: d
Hunter Unit No. 2 - Refer to the Hunter - Total Plant on page 403.1 for the average number
of employees.
Schedule Page: 402.1 Line No.: 11 Column: e
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) X A Resubmission 06/28/2012 20111Q4
FOOTNOTE DATA
Hunter Unit No. 3 - Refer to the Hunter - Total Plant on page 403.1 for the average number
of employees.
ISchedule Page: 402.2 Line No.: -1 Column: c
Jim Bridger
The Jim Bridger Plant is operated by PacifiCorp and is jointly owned by PacifiCorp and
Idaho Power Company with an undivided interest of 66 2/3% and 33 1/3%, respectively. Data
reported in column (c) represents PacifiCorp's share. Costs that were billed to minority
owners for the operation and maintenance (excluding fuel) of this plant for calendar year
2011 were $27.6 million and were primarily credited to Account 506, Miscellaneous steam
power expenses.
Schedule Page: 402.2 Line No.: -1 Column: e
Wyodak
The Wyodak Plant is operated by PacifiCorp and is jointly owned by PacifiCorp and Black
Hills Corporation with an undivided interest of 80% and 20%, respectively. Data in column
(e) represents PacifiCorp's share. Costs that were billed to minority owners for the
operation and maintenance (excluding fuel) of this plant for calendar year 2011 were $4.7
million and were primarily credited to Account 506, Miscellaneous steam power expenses.
ISchedule Page: 402.3 Line No.: -1 Column: b
Little Mountain
The turbine and generator assets at Little Mountain were retired in 2011 as the plant no
longer produces electricity. The remaining plant costs represent assets used to produce
steam under a steam supply contract that terminates July 31, 2012 or later, based on
extension options.
[Schedule Page: 402.3 Line No.: -1 Column: c
Hermiston
The Hermiston Plant is operated by Hermiston Generating Company, L.P. and is jointly
owned. PacifiCorp owns a 50.0% share of the Hermiston Plant. Data reported in column (c)
represents PacifiCorp's share. See Page 326 - Purchased Power of this Form No. 1 for
further information on Hermiston Generating Company, L.P.
ISchedule Page: 402.3 Line No.: -1 Column: d
Blundell
All or some of the renewable energy attributes associated with generation from this
generating facility may be: (a) used in future years to comply with RPS or other
regulatory requirements or (b) sold to third parties in the form of renewable energy
credits or other environmental commodities.
[Schedule Page: 402.3 Line No.: -1 Column: e
Camas Co-Gen
PacifiCorp owns the steam turbine generator and associated systems directly related to the
operation of this unit at Georgia-Pacific Corporation's Camas, Washington paper mill.
Modifications and upgrades to the existing Camas paper mill were necessary to supply steam
to the turbine 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 turbine. PacifiCorp is responsible for major
maintenance costs only on the repair of the turbine generator and auxiliary equipment.
None of the facilities are jointly owned. Each asset is wholly owned, either by PacifiCorp
or Georgia-Pacific Corporation.
All or some of the renewable energy attributes associated with generation from this
generating facility may be: (a) used in future years to comply with RPS or other
regulatory requirements or (b) sold to third parties in the form of renewable energy
credits or other environmental commodities.
Schedule Page: 402.3 Line No.: 11 Column: c I
Hermiston - PacifiCorp does not have employees at the Hermiston Plant.
Schedule Page: 402.3 Line No.: 11 Column: e I
Camas Co-Gen - PacifiCorp does not have employees at the Camas Paper Mill.
lSchedule Page: 402.4 Line No.: 11 Column: b
IFERC FORM NO. I (ED. 12-87) Page 450.2 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) - An Original (Mo, Da, Yr)
PaciflCorp (2)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Gadsby Peakers - Refer to the Gadsby Steam Plant on page 403.2 for the average number of
employees.
Schedule Page: 402 Line No.: 36 Column: b2
Carbon - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 36 Column: c2
Cholla - Fuel oil is used for start-ut DurDoses.
ISchedule Page: 402 Line No.: 36 Column: d2 I
Coistrip - Fuel oil is used for start-up purposes.
ISchedule Page: 402 Line No.: 36 Column: e2 I
Craig - Fuel oil is used for start-up purposes.
ISchedule Page: 402 Line No.: 36 Column: f2 I
Dave Johnston - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 40 Column: el I
Craig - Amended in accordance with FERC Order No. AC11-132.
ISchedule Page: 402.1 Line No.: 36 Column: b2 I
Hayden - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: c2 I
Hunter Unit No. 1 - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: d2 I
Hunter Unit No. 2 - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: e2
Hunter Unit No. 3 - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: f2 I
Hunter - Total Plant - Fuel oil is used for start-up purposes.
Schedule Page: 402.2 Line No.: 36 Column: b2 I
Huntington - Fuel oil is used for start-up purposes.
Schedule Page: 402.2 Line No.: 36 Column: c2
Jim Bridger - Fuel oil is used for start-up purposes.
Schedule Page: 402.2 Line No.: 36 Column: d2
Naughton - Natural gas is used for start-up purposes.
Schedule Page: 402.2 Line No.: 36 Column: e2
Wyodak - Fuel oil is used for start-up purposes.
Schedule Page: 402.2 Line No.: 40 Column: ci
Jim Bridger - Amended in accordance with FERC Order No. AC11-132.
IFERC FORM NO. I (ED. 12-87) Page 450.3 I
Name of Respondent
PacifiCorp
This Re ort Is:
2ssi on
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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.It 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 lithe approximate average number of employees assignable to each
plant.
Line
No.
-
Item
(a)
FERC Licensed Project No. 2082
Plant Name:
(b)
FERC Licensed Project No. 2082
Plant Name: Copco No. 2
(c)
1 Kind of Plant (Run-of-River or Storage) Run-of-River
2 Plant Construction type (Conventional or Outdoor) I Conventional' Conventional
3 Year Originally Constructed 1918 1925
4 Year Last Unit was Installed 1922 1925
5 Total installed cap (Gen name plate Rating in MW) 20.00 27.00
6 Net Peak Demand on Plant-Megawatts (60 minutes) 26 33
7
8
9
Plant Hours Connect to Load
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
8,645
28
8,345
34
10 (b) Under the Most Adverse Oper Conditions 28 34
11 Average Number of Employees 1 3
12
13
14
Net Generation, Exclusive of Plant Use - Kwh
Cost of Plant
Land and Land Rights
113,105,000
107,019
142,876,000
20,914
15 Structures and Improvements 1,617,856 2,240,353
16 Reservoirs, Dams, and Waterways 2,855,309 2,954,724
17 Equipment Costs 5,169,115 10,336,290
18 Roads, Railroads, and Bridges 105,442 479,588
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19) 9,854,741 16,031,869
21
22
23
Cost per KW of Installed Capacity (line 20 / 5)
Production Expenses
Operation Supervision and Engineering
492.7371
-39,865
593.7729
-36,851
24 Water for Power 0 0
25 Hydraulic Expenses 2,945 3,976
26 Electric Expenses 1 0 0
27 Misc Hydraulic Power Generation Expenses 1,345,967 1,772,458
28 Rents 3,153 1,623
29 Maintenance Supervision and Engineering 92 125
30 Maintenance of Structures 12,826 22,382
31 Maintenance of Reservoirs, Dams, and Waterways 47,102 112,306
32 Maintenance of Electric Plant 231,505 238,814
33 Maintenance of Misc Hydraulic Plant 20,931 38,543
34 Total Production Expenses (total 23 thru 33) 1,624,656 2,153,376
35 Expenses per net KWh 0.0144 0.0151
FERC FORM NO. I (REV. 12.03) Page 406
Name of Respondent
PacifiCorp
This Re ort Is: Date of Report
06128/2012
Year/Period of Report
End of 2011/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5.The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6.Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1927
Plant Name: Clearwater No. I
(d)
FERC Licensed Project No. 1927
Plant Name: Clearwater No. 2
(e)
FERC Licensed Project No. 2420
Plant Name: Cutler
(f)
Line
No.
-
Outdoor Outdoor
Storage
Conventional
1
2
1953 1953 1927 3
1953 1953 1927 4
15.00 26.00 30.00 5
12 20 29 6
8,3111
18
8,733
31
8,270
29
7
8
9
18 31 29 10
1 1 311
43,500,000
0
56,329,000
0
158,075,000
3,505,129
12
13
14
1,222,452 1,632,875 3,968,892 15
4,526,756 14,763,237 7,529,121 16
1,188,143 1,635,739 14,555,560 17
50,817 250,151 572,059 18
0 0 0
6,988,168 18,282,002 30,130,761 20
465.8779 703.1539 1004.3587 21
-25,475 -45,372 -65,863
22
23
9,684 16,786 0 24
56,677 98,240 54,686 25
0 0 0
392,897 523,610 837,252 27
-20,374 -159 28
69 120 029
57,831 36,724 15,336 30
18,966 33,312 41,325 31
98,561 22,266 33,113 32
45,038 74,187 233,527 33
642,494 739,499 1,149,217 34
0.0148 0.0131 0.0073 35
FERC FORM NO. I (REV. 12-03) Page 407
Name of Respondent
PacifiCorp
This Re ort Is:
EA Resubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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 lithe approximate average number of employees assignable to each
plant.
Line
No.
-
Item
(a)
FERC Licensed Project No. 1927
Plant Name: Fish Creek
(b)
FERC Licensed Project No. 20
Plant Name: Grace
(c)
1 Kind of Plant (Run-of-River or Storage) Storage
2 Plant Construction type (Conventional or Outdoor) Outdoor Conventional
3 Year Originally Constructed 1952 1908
4 Year Last Unit was Installed 1952 1923
5 Total installed cap (Gen name plate Rating in MW) 11.00 33.00
6 Net Peak Demand on Plant-Megawatts (60 minutes) 10 29
7
8
9
Plant Hours Connect to Load
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
5,7301
10
8,484
33
10 (b)Under the Most Adverse Oper Conditions 10 33
ii Average Number of Employees 1 3
12
13
14
Net Generation, Exclusive of Plant Use - Kwh
Cost of Plant
Land and Land Rights
46,160,000
0
163,373,000
62,169
15 Structures and Improvements 914,418 1,767,508
16 Reservoirs, Dams, and Waterways 12,176,001 10,885,301
17 Equipment Costs 1,790,164 4,274,112
18 Roads, Railroads, and Bridges 533,015 94,793
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19) 15,413,598 17,083,883
21
22
23
Cost per KW of Installed Capacity (line 20 / 5)
Production Expenses
Operation Supervision and Engineering
1,401.2362
-18,149
517.6934
-409,794
24 Water for Power 7,102 0
25 Hydraulic Expenses 41,563 60,715
26 Electric Expenses 0 0
27 Misc Hydraulic Power Generation Expenses 351,274 1,896,430
28 Rents -8,620 3,991
29 Maintenance Supervision and Engineering 51 0
30 Maintenance of Structures 17,360 39,377
31 Maintenance of Reservoirs, Dams, and Waterways 44,034 319,732
32 Maintenance of Electric Plant 19,596 64,174
33 Maintenance of Misc Hydraulic Plant 43,558 101,709
34 Total Production Expenses (total 23 thru 33) 497,769 2,076,334
35 Expenses per net KWh 0.0108 0.0127
FERC FORM NO. I (REV. 12-03) Page 406.1
Name of Respondent
PacifiCorp
This Re ort Is:
(2) E]A Resubmission
Date of Report
06/2812012
Year/Period of Report
End of 2011/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5.The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6.Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment
FERC Licensed Project No. 2082
Plant Name: Iron Gate
(d)
FERC Licensed Project No. 2082
Plant Name: JC Boyle
(e)
FERC Licensed Project No. 1927
Plant Name: Lemolo No. 1
(f)
Line
No.
-
Outdoor Outdoor Outdoor 2
1962 1958 1955 3
1962 1958 1955 4
18.00 97.98 31.99 5
19 83 326
8,3851
19
6,678
83
8,589
32
7
8
9
19 83 3210
1 2 111
119,843,000
341,706
335,014,000
26,277
168,158,000
0
12
13
14
6,586,042 3,118,097 2,117,062 15
13,274,563 14,487,097 15,174,982 16
2,460,471 14,989,026 6,059,746 17
1,076,116 886,710 484,728 18
0 0 0
23,738,898 33,507,207 23,836,518 20
1,318.8277
1,091,878
341.9801
293,295
745.1240
-48,405
21
22
23
0 0 20,653 24
33,634 14,430 120,873 25
0 0 0___
1,209,642 713,604 659,403 27
1,226 -901 -25,068 28
83 452 148 29
4,224 13,244 48,126 30
15,198 66,266 115,630 31
252,088 162,703 24,353 32
15,058 65,017 91,279 33
2,623,031 1,328,110 1,006,992 34
0.0219 0.0040 0.0060 35
FERC FORM NO. I (REV. 12-03) Page 407.1
Name of Respondent
PacifiCorp
This Re ort Is:
2:ssion
Date of Report
06/28/2012
Year/Period of Report
End of 2011/04
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.
Line
No.
-
Item
(a)
FERC Licensed Project No. 1927
Plant Name: Lemolo No. 2
(b)
FERC Licensed Project No. 935
Plant Name: Merwin
(c)
1 Kind of Plant (Run-of-River or Storage) Storage (Re-Reg)
2 Plant Construction type (Conventional or Outdoor) Outdoor Conventional
3 Year Originally Constructed 1956 1931
4 Year Last Unit was Installed 1956 1958
5 Total installed cap (Gen name plate Rating in MW) 38.50 136.00
6 Net Peak Demand on Plant-Megawatts (60 minutes) 34 139
7 Plant Hours Connect to Load 8,0921 8,759
8
9
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions 39 151
10 (b) Under the Most Adverse Oper Conditions 39 151
11 Average Number of Employees 1 2
12
13
14
Net Generation, Exclusive of Plant Use - Kwh
Cost of Plant
Land and Land Rights
182,966,000
0
576,030,000
1,962,905
15 Structures and Improvements 3,773,652 44,188,188
16 Reservoirs, Dams, and Waterways 31,682,299 11,656,735
17 Equipment Costs 11,736,506 17,986,931
18 Roads, Railroads, and Bridges 1,879,202 2,148,089
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19) 49,071,659 77,942,848
21
22
23
Cost per KW of Installed Capacity (line 20 / 5)
Production Expenses
Operation Supervision and Engineering
1,274.5885
-55,033
573.1092
778,698
24 Water for Power 24,856 19,597
25 Hydraulic Expenses 145,471 648,649
26 Electric Expenses 0 0
27 Misc Hydraulic Power Generation Expenses 751,145 1,131,169
28 Rents -30,169 -77,088
29 Maintenance Supervision and Engineering 178 0
30 Maintenance of Structures 69,888 149,101
31 Maintenance of Reservoirs, Dams, and Waterways 145,813 104,392
32 Maintenance of Electric Plant 96,033 137,493
33 Maintenance of Misc Hydraulic Plant 117,042 312,967
34 Total Production Expenses (total 23 thru 33) 1,265,224 3,204,978
35 Expenses per net KWh 0.0069 0.0056
FERC FORM NO. I (REV. 12-03) Page 406.2
Name of Respondent
PacifiCorp
This Re ort Is:
2t'r:ssion
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5.The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6.Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment
FERC Licensed Project No. 1927
Plant Name: Toketee
(d)
FERC Licensed Project No. 20
Plant Name: Oneida
(e)
FERC Licensed Project No. 2630
Plant Name: Prospect No. 2
(f)
Line
No.
-
Conventional
Storag
Conventional Conventional
1
2
1949 1915 1928 3
1950 1920 1928 4
42.50 30.00 32.00 5
44 23 36 . 6
8,755 8,7601 8,373 7
8
45 28 369
45 28 36 10
1 2 111
263,816,000
0
77,321,000
36,698
251,221,000
105,168
12
13
14
2,228,536 1,934,364 2,949,451 15
10,730,142 6,065,660 24,998,656 16
3,285,502 5,185,586 3,834,999 17
264,441 503,332 287,997 18
01 0 19 1
16,508,6211 13,725,640 32,176,271 20
388.43811 457.5213 1,005.5085 21
22
-73,100 -378,124 270,681 23
27,438 0 36,925 24
160,585 55,196 11,433 25
0 0 0__
726,392 1,006,504 550,234 27
-33,304 2,537 3,507 28
196 0 14829
61,154 9,030 53,010 30
131,754 5,549 157,137 31
88,478 84,952 43,393 32
121,268 115,315 86,578 33
1,210,861 900,959 1,213,046 34
0.0046 0.0117 0.0048 35
FERC FORM NO. I (REV. 12-03) Page 407.2
Name of Respondent
PaciflCorp
This Re ort Is:
2'ssi on
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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 lithe approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 1927
Plant Name: Slide Creek
(b)
FERC Licensed Project No. 20
Plant Name: Soda
(c)
1 j Kind of Plant (Run-of-River or Storage) Run-of-River Storage
2 Plant Construction type (Conventional or Outdoor) Outdoor Conventional
3 Year Originally Constructed 1951 1924
4 Year Last Unit was Installed 1951 1924
5 Total installed cap (Gen name plate Rating in MW) 18.00 14.00
6 Net Peak Demand on Plant-Megawatts (60 minutes) 17 8
7
8
9
Plant Hours Connect to Load
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
3,059
18
8,350
14
10 (b) Under the Most Adverse Oper Conditions 18 14
ii Average Number of Employees 1 2
12
13
14
Net Generation, Exclusive of Plant Use - Kwh
Cost of Plant
Land and Land Rights
37,135,000
0
35,155,000
511,083
15 Structures and Improvements 1,805,693 675,249
16 Reservoirs, Dams, and Waterways 13,887,672 8,266,187
17 Equipment Costs 9,307,477 5,305,392
18 Roads, Railroads, and Bridges 474,194 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19) 25,475,036 14,757,911
21
22
23
Cost per KW of Installed Capacity (line 20 /5)
Production Expenses
Operation Supervision and Engineering
1,415.2798
-31,242
1,054.1365
-157,778
24 Water for Power 14,121 0
25 Hydraulic Expenses 68,012 25,758
26 Electric Expenses 0 0
27 Misc Hydraulic Power Generation Expenses 364,257 601,475
28 Rents -14,105 1,184
29 Maintenance Supervision and Engineering 83 0
30 Maintenance of Structures 26,116 462
31 Maintenance of Reservoirs, Dams, and Waterways 177,004 1,911
32 Maintenance of Electric Plant 33,131 37,022
33 Maintenance of Misc Hydraulic Plant 160,135 42,990
34 Total Production Expenses (total 23 thru 33) 797,512 553,024
35 Expenses per net KWh 0.0215 0.0157
FERC FORM NO. I (REV. 12-03) Page 406.3
Name of Respondent
PacifiCorp
This Re ort Is:
AResubmission
Date of Report
06/28/2012
Year/Period of Report
End of 201 1/04
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5.The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.
6.Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1927
Plant Name: Soda Springs
(d)
FERC Licensed Project No. 2111
Plant Name: Swift No. I
(e)
FERC Licensed Project No. 2071
Plant Name: Yale
(f)
Line
No.
-
Storage (Re-Reg) Storage Storage 1
Outdoor Conventional Conventional 2
1952 1958 1953 3
1952 1958 1953 4
11.00 240.00 134.00 5
12 2571 163 6
8,749
12
6,410
264
6,627
1649
7
8
12 263 164 10
1 2 211
70,977,000 791,748,000 661,211,000 12
13
0 7,813,808 8,349,393 14
1,165,632 31,891,473 7,680,925 15
13,609,716 42,715,637 27,653,817 16
2,177,660 16,789,892 14,832,272 17
56,124 1,012,079 1,439,462 18
0 0 0
17,009,132 100,222,889 59,955,869 20
1,546.2847
-7,982
417.5954
1,346,620
447.4319
763,873
21
22
23
7,102 34,584 19,309 24
41,563 1,278,034 639,110 25
0 0 0 26
289,766 1,602,699 991,015 27
-8,620 -136,038 -75,955 28
51 0 029
16,149 35,542 40,796 30
17,328 63,120 79,510 31
12,258 170,448 212,959 32
31,387 490,818 348,809 33
399,002 4,885,827 3,019,426 34
0.0056 0.0062 0.0046 35
FERC FORM NO. I (REV. 12-03) Page 407.3
Name of Respondent
PacifiCorp
This Re ort Is: Date of Report
06,28/2012
Year/Period of Report
End of 2011/04
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 lithe approximate average number of employees assignable to each
plant.
Line
No.
-
Item
(a)
FERC Licensed Project No. 0
Plant Name:
(b)
FERC Licensed Project No. 0
Plant Name:
(c)
1 1 Kind of Plant (Run-of-River or Storage) Run-of-River
2 Plant Construction type (Conventional or Outdoor) Conventional
3 Year Originally Constructed 1904
4 Year Last Unit was Installed 1922
5 Total installed cap (Gen name plate Rating in MW) 10.30 0.00
6 Net Peak Demand on Plant-Megawatts (60 minutes) 10 0
7
8
9
Plant Hours Connect to Load
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
8,7401
10
0
0
10 (b)Under the Most Adverse Oper Conditions 10 0
11 Average Number of Employees 3 0
12
13
14
Net Generation, Exclusive of Plant Use - Kwh
Cost of Plant
Land and Land Rights
45,255,000
0
0
0
15 Structures and Improvements 368,652 0
16 Reservoirs, Dams, and Waterways 529,217 0
17 Equipment Costs 31,914 0
18 Roads, Railroads, and Bridges 12,641 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19) 942,424 0
21
22
23
Cost per KW of Installed Capacity (line 20 I 5)
Production Expenses
Operation Supervision and Engineering
91.4975
-23,072
0.0000
0
24 Water for Power 0 0
25 Hydraulic Expenses 18,775 0
26 Electric Expenses 0 0
27 Misc Hydraulic Power Generation Expenses 327,521 0
28 Rents -54 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 2,065 0
31 Maintenance of Reservoirs, Dams, and Waterways 1,229 0
32 Maintenance of Electric Plant 13,335 0
33 Maintenance of Misc Hydraulic Plant 145,068 0
34 Total Production Expenses (total 23 thru 33) 484,867 0
35 Expenses per net KWh 0.0107 0.0000
FERC FORM NO. I (REV. 12-03) 1 Page 406.4
Name of Respondent
PacifiCorp
This Re oil Is:
(1)An Original
. (2)JA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
d 2011/Q4 En 0
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5.The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6.Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 0
Plant Name:
(d)
FERC Licensed Project No. 0
Plant Name:
(e)
FERC Licensed Project No. 0
Plant Name:
(f)
Line
No.
-
2
3
4
0.00 0.00 0.00
0 0 0 6
0
0
0
0
01
o
71
8
0 0 0
0 0 0 ii.
6mm 0
0
0
0
0
0
13
0 0 0 15
0 0 0 16
0 0 0
0 0 01 18
0 0 0
0 0 0
0.0000
0
0.0000
0
0.0000
oii
22
0 0 0
0 0 0__
0 0 0
0 0 0
0 0 0___
0 0 0
0 0 0__.
0 0 0
0 0 0___
0 0 0
0 0 0_±
0.0000 0.0000 0.0000 35
FERC FORM NO. I (REV. 12-03)- Page 407.4
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) _An Original 1(2) (Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 406 Line No.: -1 Column: b
This footnote applies to all hydroelectric generating facilities with current generation.
All or some of the renewable energy attributes associated with generation from these
generating facilities may be: (a) used in future years to comply with RPS or other
regulatory requirements or (b) sold to third parties in the form of renewable energy
credits or other environmental commodities.
Schedule Page: 406 Line No.: 1 Column: b
Copco No. 1
Pondage for peaking - storage, Upper Klamath Lake
ISchedule Page: 406 Line No.: I Column: d
Clearwater No. 1
Forebay for peaking
chedule Page: 406 Line No.: I Column: e
Clearwater No. 2
Forebay for peaking
Schedule Page: 406 Line No.: 28 Column: d
This footnote applies to all instances of credit amounts in Rents. The credit amounts
represent differences between accrued and actual rents.
Schedule Page: 406.1 Line No.: I Column: b
Fish Creek
Forebay for peaking
ISchedule Page: 406.1 Line No.: I Column: d
Iron Gate
Storage for regulation
Schedule Page: 406.1 Line No.: I Column: e
JC Boyle
Pondage for peaking - storage, Upper Klamath Lake
Schedule Page: 406.1 Line No.: I Column: f
Lemolo No. 1
Storage, Lemolo Lake
ISchedule Page: 406.2 Line No.: I Column: b
Lemolo No. 2
Storage, Lemolo Lake
Schedule Page: 406.2 Line No.: I Column: d
Toketee
Pondage for peaking - storage, Lemolo Lake
Schedule Page: 406.2 Line No.: I Column: f
Prospect No. 2
Forebay for peaking
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 beginning in 1990. PacifiCorp operates the plant and takes all of the
generation. The cost of the Olmsted plant includes leasehold improvements and facilities
to which PacifiCorp holds title.
IFERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)jA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 facility, and give a concise statement of the facts in a footnote. If licensed project, give
project number in footnote.
Line
No.
-
Name of Plant
(a)
Year
Orig. Const.
(b)
Installed Capacity
Name Plate atin
(In MW)
(c)
Net Peak Demand
(6t9n) (3
Net Generation
Excluding
Plant Use
(e)
Cost of Plant
(f)
2 Ashton 2381 1917 6.70 6.6 18,071,000 18,738,643
3 Bend 1913 1.11 1.0 2,115,000 1,335,093
2652 • 1910 4.15 4.6 34,671,000 7,337,583
*Eagle
1913 1.00
1913 13.70 15.0 88,226,000 1,515,294
t 1957 2.81 2.8 18,508,000 1,817,948
8 East Side 2082 1924 3.20 1,991,695
9 Fall Creek 2082 1903 2.20 2.0 11,651,000 1,368,783
10 Fountain Green 1922 0.16 0.1 69,000 597,630
11 Granite 1896 2.00 1.2 8,377,000 5,234,157
12 Gunlock 1917 0.75 0.4 2,198,000 683,159
13 Last Chance 1983 1.73 1.4 6,943,000 2,802,615
14 Paris 1910 0.72 0.7 3,126,000 438,870
15 Pioneer 2722 18971 5.00 4.0 28,634,000 10,923,580
16 t 1923 6.00 66,518
17 Prospect No. 1 2630 1912 3.76 4.6 24,770,000 1,795,629
18 Prospect No. 3 2337 1932 7.20 7.7 46,679,000 7,012,132
19 Prospect No.4 2630 1944 1.00 0.9 4,925,000 1,735,569
20 Sand Cove 1926 0.80 0.5 2,304,000 933,722
21 1910 1.18 1.0 3,539,000
22 StaIrs 597 1895 1.00 1.2 7,356,000 1,621,161
23 1915 0.50 1,337,279
24 Veyo 1920 0.50 0.3 1,359,000 875,122
25 Viva Naughton 1986 0.74 0.6 773,000 1,194,486
26 Wallowa Falls 308 1921 1.10 1.0 7,892,000 2,833,542
27 Weber 1744 1911 3.85 2.0 23,866,000 2,957,569
28 West Side 2082 1908 0.60 0.6 2,040,000 468,574
29 7,529,514
30 3,847,587
31 15,790,442
321
33 Pumping Plant:
34 Lifton 1917 -4.50 -2.0 -2,356,000 19,246,861
35
36
37 DuiilapRanchl 2010 111.00 112.0 421,086,000 239,610,220
38 1999 32.62 32.0 105,082,000 36,513,348
39 Glenrock 2008 99.00 103.0 340,863,000 200,963,100
40 Glenrock III 2009 39.00 38.0 130,197,000 87,208,182
41 Rolling Hills 2009 99.00 103.0 309,180,000 201,322,304
42 Goodnoe Hills 2008 94.00 95.0 239,431,000 181,825,142
43 Leaning Juniper 1 2006 100.50 102.0 234,789,000 174,811,148
44 Marengo 2007 140.40 139.0 403,408,000 237,829,066
45 Marengo II 2008 70.20 69.0 194,378,000 128,272,296
46 Seven Mile Hill 2008 99.00 100.0 381,679,000 199,452,559
FERC FORM NO. I (REV. 12-03) Page 410
Name of Respondent
PacifiCorp
This Re ort Is:
(2) E]A Resubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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 (IncI Asset
Retire. Costs) Per MW
(g)
Operation
Exc'I. Fuel
(h)
Production Expenses
Kind of Fuel
(k)
Fuel Costs (in cents
(per Million Btu)
(I)
me
Fuel
(i)
Maintenance
U)
2,796,812 430,337 88,851 Water 2
1,202,786 65,032 92,127 Water 3
1,768,092 345,945 151,153 Water 4
2,842 494 Water 5
110,605 209,397 40,064 Water 6
646,957 233,734 97,402 Water 7
622,405 -28,259 9,989 Water 8
622,174 175,143 104,368 Water 9
3,735,1 88 21,797 5,808 Water 10
2,617,079 143,210 25,155 Water 11
910,879 63,876 41,721 Water 12
1,620,009 105,552 29,285 Water 13
609,542 62,906 33,944 Water 14
2,184,716 297,559 125,685 Water 15
11,086 28,411 5,624 Water 16
477,561 205,274 36,778 Water 17
973,907 309,200 339,943 Water 18
1,735,569 121,086 31,308 Water 19
1,167,153 64,358 53,637 Water 20
81,443 17,063 Water 21
1,621,161 175,080 80,317 Water 22
2,674,558 58,950 2,578 Water 23
1,750,244 72,728 136,045 Water 24
1,614,1 70 120,554 27,458 Water 25
2,575,947 54,602 32,888 Water 26
768,200 275,584 60,819 Water 27
780,957 46,788 13,871 Water 28
8,088 1,673 29
340,976 26,082 30
31
32
33
-4,277,080 346,764 56,364 Water 34
35
36
2,158,651 2,206,801 108,206 Wind 37
1,119,355 1,916,623 106,885 Wind 38
2,029,930 1,009,112 458,098 Wind 39
2,236,107 358,639 168,292 Wind 40
2,033,559 1,084,314 427,203 Wind 41
1,934,310 1,329,935 1,497,159 Wind 42
1,739,414 2,151,942 418,786 Wind 43
1,693,939 5,574,816 172,606 Wind 44
1,827,241 2,741,761 19,894 Wind 45
2,014,672 1,622,325 512,371 Wind 46
FERC FORM NO. I (REV. 12-03) Page 411
Name of Respondent
PacifiCorp
This Re ort Is:
EKAResubmission
Data of Report
06/8/201
Year/Period of Report
End of 2011/04
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 facility, and give a concise statement of the facts in a footnote. If licensed project, give
project number in footnote.
Line
No.
-
Name of Plant
(a)
Year
Orig. Const
(b)
Installed Capacity
Name Plate Rahn
(In MW)
(C)
Net Peak Demand
'6l 9n'
' (3 '
Net Generation
Excluding
Plant Use
(e)
Cost of Plant
(f)
1 Seven Mile Hill Il 2008 19.50 20.0 83,613,000 41,854,410
2 High Plains 2009 99.00 98.0 335,463,000 219,125,791
3 McFadden Ridge I 2009 28.50 29.0 102,595,000 56,802,683
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. I (REV. 12-03) Page 410.1
Name of Respondent
PacifiCorp
This Re ort Is: j 2'rssion
Date of Report
06/28/2012
Year/Period of Report
End of 2011/04
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 (IncI Asset
Retire. Costs) Per MW
(g)
Operation
Exc'I. Fuel
(h)
Production Expenses
Kind of Fuel
(k)
Fuel Costs (in cents
(per Million Btu)
(I)
Line
Fuel
(i)
Maintenance
(j)
2,146,380 304,785 103,509 Wind I
2,213,392 995,588 2,138,787 Wind 2
1,993,077 276,012 631,060 Wind 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. I (REV. 12-03) Page 411.1
IName of Respondent This Report is: Date of Report Year/Period of Report
I (1)_An Original (Mo, Da, Yr)
Pacjccorp (2) X A Resubmission 06/28/2012 2011 /Q4
FOOTNOTE DATA
Schedule Page: 410 Line No.: I Column: a
Common river system costs for the operation of these facilities are allocated to each
plant based upon the unit's name plate rating.
This footnote applies to all hydroelectric generating facilities with current generation.
All or some of the renewable energy attributes associated with generation from these
generating facilities may be: (a) used in future years to comply with RPS or other
regulatory requirements or (b) sold to third parties in the form of renewable energy
credits or other environmental commodities.
ISchedule Page: 410 Line No.: 5 Column: a
Cline Falls
The Cline Falls hydroelectric generating facility was retired in August 2010.
Schedule Page: 410 Line No.: 6 Column: a
Condit
In September 1999, a settlement agreement to remove the 14-MW Condit hydroelectric
generating facility was signed by PacifiCorp, state and federal agencies and
non-governmental organizations. In early February 2005, the parties agreed to modify the
settlement agreement, establishing a total cost to decommission not to exceed $21 million,
excluding inflation. In October 2010, the Washington Department of Ecology issued a Clean
Water Act 401 certificate, and in December 2010, the FERC issued a surrender order for
project decommissioning modifying PacifiCorp's proposed decommissioning plans and
directing a 2011 decommissioning. In January 2011, PacifiCorp filed a request for
clarification and rehearing of the surrender order and a motion for stay with the FERC
requesting reinstatement of PacifiCorp's decommissioning proposal. In April 2011, the FERC
issued an order on rehearing, granting PacifiCorp nearly all of the changes it requested,
but did not shorten the required agency consultation and FERC approval periods. In June
2011, PacifiCorp formally notified the FERC of its acceptance of the terms and conditions
of the orders that govern the surrender of the project license. PacifiCorp commenced
on-site decommissioning activities in June 2011 and the dam was breached in late October
2011 as planned. Post breach, near-term activities will focus on sediment monitoring as
material moves downstream into the Columbia River. Removal of project facilities commenced
in January 2012, and complete dam removal is expected by August 2012.
ISchedule Page: 410 Line No.: 16 Column: a
Powerdale
The Powerdale hydroelectric generating facility was decommissioned in October 2010.
Schedule Page: 410 Line No.: 21 Column: a
Snake Creek
The Snake Creek hydroelectric generating facility was sold to Heber Light & Power Company
in September 2011 and was recorded in Account 102, Electric plant purchased or sold.
Schedule Page: 410 Line No.: 23 Column: a
St. Anthony
Licensed Project No. 2381 applicable to both Ashton and St. Anthony plants.
Schedule Page: 410 Line No.: 29 Column: a
Keno Regulating Dam
Used in regulating the release of water from Klamath Lake and in maintaining proper water
surface level in the Klamath River between Klamath Falls and Keno, Oregon.
Schedule Page: 410 Line No.: 30 Column: a
Upper Klamath Lake
Storage reservoir for six plants on the Klamath River (Copco No. 1, Copco No. 2, East
Side, West Side, JC Boyle and Iron Gate).
Schedule Page: 410 Line No.: 31 Column: a
North Umpqua
Represents facilities that support the North Umpqua River system projects. All common
roads, employee houses, control equipment, etc. are in this account.
Schedule Page: 410 Line No.: 36 Column: a
IFERC FORM NO. I (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)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
This footnote applies to all wind-powered generating facilities with current generation.
All or some of the renewable energy attributes associated with generation from these
generating facilities may be: (a) used in future years to comply with RPS or other
regulatory requirements or (b) sold to third parties in the form of renewable energy
credits or other environmental commodities.
Schedule Page: 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 Electric Board with an undivided interest of 78.79% and
21.21%, respectively. Data reported in row 38 represents PacifiCorp's share.
I
IFERC FORM NO. I (ED. 12-87) Page 450.2 I
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)ffjA Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
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 (t) 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
No.
DESIGNATION VOLTAGE (KV)(Indicate where other than
60 cycle, 3 phase)
Type 0
Supporting
Structure
(e)
LENGTH (Pole miles) ln the cas or u dergrounu lines report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
Ofl Structure
De L?ed
f)
Ontrucures of jotner
(g)
I PG&E ROUND MTN , CA
CAPTAIN JACK, OR
500.01 500.00 Steel Tower 47.00 1
2 500.01 500.00 Steel Tower 26.00 1
3 AMATH CO-GEN , OR
DIXONVILLE 500, OR
500.01 500.00 Steel Tower 58.00 1
4 500.01 500.00 Steel Tower 58.00 1
5 MERIDIAN, OR 500.01 500.00 Steel Tower 74.00 1
6
7
MALIN , OR 500.01 500.00 Steel Tower 7.00 1
MALIN , OR
Switchyard, MT
BROADVIEW A, MT
500.01 500.00 Steel Tower 447.00 1
8
9
500.01 500.00 Steel Tower 1.00 1
500.01 500.00 Steel Tower 112.00 1
10
11
12
BROADVIEW B, MT 500.0( 500.00 Steel Tower 116.00 1
TOWNSEND A, MT
TOWNSEND B, MT
500.0c 500.00 Steel Tower 133.00 1
500.00 500.00 Steel Tower 133.00 1
131500 kV costs and expenses I
14
15 Subtotal 500kV 1.21 2.00 12
16
17 BEN LOMOND, UT BORAH, ID 345.01 345.00 Wood - H 138.00 1
18 BEN LOMOND, UT TERMINAL, UT 345.01 345.00 47.00 1
191 BEN LOMOND, UT CAMP WILLIAMS, UT 345.0 345.00 Steel SP 69.00 1
20 EMERY, UT CAMP WILLIAMS, UT 345.0 345.00 Steel Tower 121.00 1
21 CAMP WILLIAMS, UT MONA #3, UT 345.0 345.00 Wood - H 47.00 1
22 NINETY SOUTH, UT CAMP WILLIAMS #1, UT 345.0 345.00 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 Steel Tower 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
345.0(1
345.00 Wood - H 20.00 1
29 EMERY, UT SIGURD #1, UT 345.0 345.00 Steel - H 74.00 1
30 EMERY, UT SIGURD, #2 UT 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 Steel Tower 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 Steel Tower 78.00 1
35
1
TERMINAL, UT NINETY SOUTH, UT 345.0 345.00 16.00
1 1
1
36 TOTAL 15,957.00 806.00 264
FERC FORM NO. I (ED. 12-87) Page 422
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)jA Resubmission
Date of Report
(Mo, Da,Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, 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 party is
an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
Conductor
and Material
(i)
COST OF LINE (Include in Column (j) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
(j)
Construction and
Other Costs (k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses
(p)
-1852 ACSR 51/27 1
-1272 ACSR36/1 2
-1272 ACSR 36/1 3
-1272 ACSR 54/19 4
-1272 ACSR 54/19 5
-2250 AAC/91
3-1272 ACSR 36/1
8
9
10
11
12
14,275,676 269,729,474 284,005,150 1,409,233 275,506 1,684,739 13
14
14,275,676 269,729,474 284,005,150 1,409,233 275,506 1,684,73 15
16
-954 ACSR 45/7 11
-1272 ACSR 455 18
-1272 ACSR 45/7 19
-1272 ACSR 45/7 20
2-954 ACSR 45/7 21
-1272 ACSR 455 22
-1272ACSR45/7 23
-954 ACSR 45/7 24
-1272 ACSR 455 25
-1272 ACSR 455 26
-1272 ACSR 455 21
-954 ACSR 45/7 28
-954 ACSR 45/7 29
-954 ACSR 54/7 30
2-795 ACSR 455 31
2-795 ACSR 26/1 32
2-795 ACSR 45/1
2-1272 ACSR 45/7
2-1272 ACSR 455
173,359,503 2,552,922,302 2,126,281,805 259,051 22,369,881 2,549,553 25,118,48 36
FERC FORM NO. I (ED. 12-87) Page 423
From
(a)
MONA, UT
MONA, UT
SIGURD, UT
JIM BRIDGER, WY
JIM BRIDGER, WY
MONA, UT
CURRENT CREEK, LIT
CAMP WILLIAMS, UT
POPULUS#1, ID
POPULUS#2, ID
BEN LOMOND, UT
BEN LOMOND, UT
90TH SOUTH, UT
90TH SOUTH, UT
345 kV costs and expenses
To
(b)
SIGURD #1, UT
SIGURD #2, UT
UT I NV BORDER, UT
BORAH, ID
KINPORT, ID
HUNTINGTON, UT
MONA, UT
MONA#4 UT
BEN LOMOND, UT
BEN LOMOND, UT
TERMINAL #1, UT
TERMINAL #2, UT
CAMP WILLIAMS #4, UT
CAMP WILLIAMS #3, UT
Line
No.
Subtotal 345kV
report Zircuit miles) Of
;tructure On itwcures Circuits Line of Another ignated Line
(f) (g) (h)

69.00 1
69.00 1

190.00 ill
234.00 1
60.00
5.00 42.00 1
82.00 1
86.00 1
47.00 1
_0 1
11.00 1
11.00 1
1,986.00 383.001 33
I Name of Respondent I This Recort Is: I Date of Report I Year/Period of Report I
PaciflCorp I (1) An Original I (Mo, Da, Yr) I End of 2011/Q4 I I (2) r)-(JA Resubmission I 06/28/2012 I
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
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.
ther than
0 cycle, 3 phase)
Type of
Supporting
Structure
(e)
Operating
(c)
Designed
(d)
345.01 345.00 Wood . H
345.01 345.00 Steel Tower
345.1 345.00 Steel Tower
345.1 345.00 Steel Tower
345.0 345.00 Steel Tower
345.0 345.00 Wood - H
345.0 345.00 Steel SP
345.0 345.00 Steel SP
345.0 345.00
345.0 345.00 Steel SP
345.0 345.00
345.0( 345.00 Steel SP
345.0 345.00
345.01 345.00 Steel SP
ANTELOPE, ID
ANTELOPE, ID
BEN LOMOND, UT
BEN LOMOND, UT
BIRCH CREEK, UT
TREASURETON, ID
GLEN CANYON, AZ
GONDER (ELY), UT
NAUGHTON, WY
PAROWAN VALLEY, UT
PAROWAN VALLEY, UT
PAVANT, UT
ATLANTIC CITY, WY
PALISADES SS, WY
BUFFALO, WY
GOOSE CREEK, WY
WYODAK, WY
ANACONDA, ID - MT
LOST RIVER, ID
NAUGHTON #1, WY
NAUGHTON #2, WY
RAILROAD, WY
BRADY, ID
SIGURD, UT
PAVANT, UT
TREASURETON, ID
SIGURD, UT
WEST CEDAR. UT
SIGURD, UT
COLUMBIA GENEVA, WY
BLUE RIM, WY
CASPER, WY
BUFFALO, WY
BUFFALO, WY
r!1
H
II
I
107
U
U
U
U U
U
U U
U
U
U U
El
15.957 264
FERC FORM NO. I (ED. 12-87) Page 422.1
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
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 property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, 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 party is
an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
Conductor
and Material
0)
COST OF LINE (Include in Column (j) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
No.
Land
(j)
Construction and
Other Costs
(k)
Total Cost
(I)
Operation
Expenses
(rn)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses (p)
-795 ACSR 45/7
-954 ACSR 45/7 2
-954 ACSR 54/7 3
-1272 ACSR 3611 4
-1272 ACSR 36/1
-954 ACSR 5417 6
-954 ACSR 5417 7
-954 ACSR 45/7 8
-1272 ACSR 45/7 9
-1272 ACSR 4517 10
-1272 ACSR 45/7 11
-1272 ACSR 45/7 12
13
14
105,594,04C 985,695,543 1,091,289,583 3,032,050 828,712 3,860,762 15
16
105,594,04C 985,695,543 1,091,289,583 3,032,050 828,712 3,860,762 17
18
1272 ACSR 45/7 19
795 ACSR 45/7 20
795 ACSR 26/7 21
795 ACSR 26/7 22
54 ACSR 54/7 23
795 ACSR 26/7 24
54 ACSR 45/7 25
95ACSR45/7 26
272 ACSR 4517 27
795 ACSR 45/7 28
795 ACSR 45/7 29
795 ACSR 45/7 30
1272 ACSR 36/1 31
272 ACSR 36/1 32
1272 ACSR 36/1 33
795 ACSR 26/7 34
1272 ACSR 36/1 35
173,359,503 2,552,922,302 2,726,281,805 259,051 22369,881 2,549,553 25,178,48 36
FERC FORM NO. I (ED. 12-87) Page 423.1
Name of Respondent
PacifiCorp
This Report Is:
(1)An Original
(2)1A Resubmission
Date of Report
(Mo, Da, Yr)
06/2812012
Year/Period of Report
End of 2011/Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
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 (9) 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
No.
-
DESIGNATION VOLTAGE (Ky) (Indicate where other than
60 cycle, 3 phase)
Type 0 f
Supporting
Structure
(e)
LENGTH (Pole miles) (In tne case of undergrouna lines report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
On Structure
D?ed
Ontrucures of i12orner
(g)
1 JIM BRIDGER, WY DAVE JOHNSTON, WY 230.00 230.00 Wood - H 218.00 1
21 BITTER CREEK, WY MON ELL, WY 230.00 230.00 Wood - H 3.00 1
3 SHIRLEY BASIN, WY DUNLAP RANCH, WY 230.0 230.00 Wood - H 12.00 1
4 ROCK SPRINGS, WY JIM BRIDGER, WY 230.0 230.00 Wood - H 35.00 1
5 JIM BRIDGER, WY SPENCE, WY 230.0 230.00 Wood - H 149.00 1
61 BRIDGER PUMP, WY MANS FACE, WY 230.0 230.00 Wood - H 1.00 1
8 CASPER, WY
)AVE JOHNSTON, WY
RIVERTON, WY
230.0 230.00 Wood H 36.00 1
230.0 230.00 Wood - H 110.00 1
9 DAVE JOHNSTON, WY SPENCE, WY 230.0 230.00 Wood - H 31.00 1
10 DAVE JOHNSTON, WY WYODAK, WY 230.0 230.00 Wood - H 69.00 1
11 MONUMENT, WY EXXON, WY 230.0 230.00 Wood - H 13.00 1
12 FIREHOLE, WY MONUMENT, WY 230.0 230.00 Wood - H 49.00 1
13 ROCK SPRINGS, UT FLAMING GORGE, UT 230.0 230.00 Wood - H 55.00 1
14 YELLOWTAIL, MT GOOSE CREEK, WY 230.Oq 230.00 Wood - H 59.00 1
15 NAUGHTON, WY MONUMENT, WY 230.0 230.00 Wood - H 30.00 1
16 LIMA, WY ROBERSON, WY 230.0 230.00 Wood - H 2.00 1
17 ROCK SPRINGS, WY MONUMENT, WY 230.0 230.00 Wood - H 41.00 1
18 RIVERTON, WY ROCK SPRINGS, WY 230.0 230.00 Wood - H 118.00 1
19 RIVERTON, WY THERMOPOLIS, WY 230.0 230.00 Wood - H 51.00 1
20 THERMOPOLIS, WY YELLOWTAIL, MT 230.0 230.00 Wood - H 176.00 1
21 CHAPPEL CREEK, WY CRAVEN CREEK, WY 230.0 230.00 Steel - SP 30.00 1
221 NAUGHTON, WY WILLIAMS OPAL, WY 230.0 230.00 Wood - H 16.00 1
23 CHAPPEL CREEK, WY JONAH GAS, WY 230.0 230.00 Wood - H 32.00 1
24 MINERS, WY HIGH PLAINS, WY 230.0 230.00 Wood - H 39.00 1
25 POINT OF ROCKS, WY ROCK SPRINGS, WY 230.0 230.00 Wood - H 27.00 1
26 MONUMENT, WY CRAVEN CREEK, WY 230.0 230.00 Wood - H 20.00 1
27 OREGON BASIN (PAC), WY OR BASIN (MART OIL), WY 230.01 230.00 Wood H 1.00 1
28 WINDSTAR, WY GLENROCK, WY 230.0 230.00 Wood - H 13.00 1
29 CHAPPEL CREEK, WY RILEY RIDGE, WY 230.0 230.00 Wood - H 29.00 6.00 1
30 YAMSAY, OR KLAMATH FALLS, OR 230.0 230.00 Wood - H 63.00 1
31 KLAMATH FALLS, OR MALIN, OR 230.0 230.00 Wood - H 35.00 1
32 LONE PINE, OR KLAMATH FALLS, OR 230.0 230.00 Wood - H 76.00 1
33 LONE PINE, OR MERIDIAN, OR 230.0 230.00 Steel SP 5.00 1
34 GRANTS PASS, OR DIXONVILLE LINE 72, OR 230.0 230.00 Wood - H 62.00 1
35 DIXONVILLE, OR RESTON BPA, OR 230.0 230.00 Wood - H 17.00 1
1 361 TOTAL 15,957.00 806.00 264
FERC FORM NO. I (ED. 12-87) Page 422.2
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)A Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, 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 party is
an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns 0) to (I) on the book cost at end of year.
Size of
Conductor
and Material
(i)
COST OF LINE (Include in Column U) Land,
Land rights, and cleating right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
No.
Land
U)
Construction and
Other Costs
(k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses
(p)
1272 ACSR 36/1 1
95 ACSR 2617 2
795 ACSR 26/7 T
1272 ACSR 3611 4
1272 ACSR 36/1 5
6
7
tACSR
8
9
10
1272 ACSR 36/1 11
1272 ACSR 45/7 12
1272 ACSR 36/1 13
95ACSR2617 14
272 ACSR 3611 15
272 ACSR 45/7 16
272 ACSR 3611 17
272 ACSR 3611 18
1272 ACSR 36/1 19
1272 ACSR 36/1 20
954 21
954 22
1272 ACSR 45/7 23
72ACSR455 24
1272 ACSR 45/7 25
1272 26
1272 AçsR 45/7 27
1272 ACSR 45/7 28
1272 ACSR 45/7 29
795 ACSR 265 30
272 ACSR 3611 31
95ACSR26/7 32
1272 ACSR 36/1 33
1272 ACSR 3611 34
95 ACSR 26/7 35
173,359,503 2,552,922,302 2,726,281,805 259,051 22,369,881 2,549,553 25,178,48 36
FERC FORM NO. I (ED. 12-87) Page 423.2
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/2812012
Year/Period of Report
End of 2011/Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
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
No.
-
DESIGNATION VOLTAGE (Ky) (Indicate where other than
60 cycle, 3 phase)
Type of
Supporting
Structure
(e)
LENGTH (Pole miles) (l the ease of unaergrouna lines
report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
On Structure
Da?ed
On Structures ofjother
(g)
I TAP TO HANNA, OR NICKEL MOUNTAIN, OR 230.01 230.00 Wood - H 9.00 1
21 DIXONVILLE 500, OR DIXONVILLE 230, OR 230.01 230.00 Wood - K 1.00 1
3 MERIDIAN, OR GRANTS PASS, OR 230.01 230.00 Wood - H 35.00 1
4 MERIDIAN, OR LONE PINE, OR 230.01 230.00 Wood - H 5.00 1
5 FAIRVIEW BPA, OR ISTHMUS, OR 230.01 230.00 Wood - H 12.00 1
6 TROUTDLE-LINNEMN, OR TROUTDALE PP&L, OR 230.01 230.00 Wood - H 1.00 1
7 TROUTDALE BPA, OR GRESHAM PGE, OR 230.0 230.00 Steel Tower 6.00 1
8 TROUTDALE BPA, OR LINNEMAN PGE, OR 230.0 230.00 6.00 1
9 SWIFT No. 1, WA SWIFT No. 2, WA 230.0 230.00 Wood - H 2.00 1
10 SWIFT No. 2, WA WOODLAND BPA SS, WA 230.0 230.00 Wood - H 23.00 1
11 FRY, OR BETHEL, OR 230.0 230.00 Wood- H 26.00 1
12 FRY, OR ALVEY, OR 230.0 230.00 Wood - H 45.00 1
13 ALVEY, OR DIXONVILLE, OR 230.0 230.00 Wood - H 59.00 1
14 HURRICANE, OR WALLA WALLA, WA 230.0 230.00 Wood - H 78.00 1
15 MCNARY BPA, WA WALLA WALLA, WA 230.0 230.00 Wood- H 56.00 1
16 WALLA WALLA, WA AVISTA LEWISTON, ID 230.0 230.00 Wood - H 45.00 1
17 WALLA WALLA, WA WANAPUM (GPUD), WA 230.0 230.00 Wood - H 33.00 1
18 TALBOT, WA MARENGO II, WA 230.0 230.00 Wood - H 7.00 1
19 JONES CANYON (BPA), OR LEANING JUNIPER, OR 230.0 230.00 Wood - H 1.00 1
20 ROCK CREEK (BPA), WA GOODNOE HILLS, WA 230.0 230.00 Wood - H 1.00 1
21 UNION GAP, WA MIDWAY BPA, WA 230.0 230.00 Wood - H 39.00 1
22 WANAPUM, WA POMONA, WA 230.0 230.00 Wood - H 37.00 1
23 POMONA, WA UNION GAP, WA 230.0 230.00 Wood - H 8.00 1
24 230 kV costs and expenses
25
26 Subtotal 230kV 3,328.00 17.00 75
27
28 ANACONDA, ID- MT JEFFERSON PH, ID 161.0 161.00 Wood - H 90.00 1
29 ANTELOPE, ID GOSHEN, ID 161.0 161.00 Wood - H 45.00 1
30 BONNEVILLE, ID EAGLEROCK, ID 161.0 161.00 Wood SP 9.00 1
31 EAGLEROCK, ID SUGARMILL, ID 161.0 161.00 Wood SP 3.00 1
32 GOSI-IEN, ID GRACE, ID 161.0 161.00 Wood - H 57.00 1
33 GOSHEN, ID RIGBY, ID 161.0 161.00 Wood - H 31.00 1
34 GOSHEN, ID SUGAR MILL, ID 161.0 161.00 Wood SP 17.00 1
35 SUGARMILL, ID RIGBY, ID 161.0 161.00 Wood SP 17.00 1
36 TOTAL 15,957.00 806.00 264
FERC FORM NO. 1 (ED. 12-87) Page 422.3
Name of Respondent
PacifiCorp
This Re oil Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
Conductor
and Material
(I)
COST OF LINE (Include in Column (j) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
No.
Land
(j)
Construction and
Other Costs (k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses
(p)
795 ACSR 26/7
1272 ACSR 36/1 2
1272 ACSR 36/1 3
272 ACSR 54/19 4
1272 ACSR 36/1 5
1272 ACSR 36/1 6
54 ACSR 45/1 1
900 ACSR 54/1 8
54 ACSR 45/7 9
954 ACSR 45/7 10
1272 ACSR 36/1 U
1272 ACSR 36/1 12
1272 ACSR 36/1 13
1272 ACSR 36/1
1272 ACSR 36/1 15
1272 ACSR 36/1 16
1212 ACSR 36/1 11
95 ACSR 26/7 18
1272 ACSR 45/7 19
1272 ACSR 45/7 20
54 ACSR 45/7 21
1272 ACSR 36/1
1272 ACSR 36/1 23
15,529,412 349,202,441 364,731,853 23,014 5,295,061 476,724 5,794,799 24
25
15,529,412 349,202,441 364,731 .853 23,014 5,295,061 476,724 5,794,799 26
27
50HH CU /7 28
97.5 ACSR 26/7 29
54 ACSR 45/7 30
54 ACSR 45/7 31
250HHCUI1 32
397.5 ACSR 26/7 33
795 AAC /37 34
397.5 ACSR 26/7 35
173,359,503 2,552,922,302 2,726,281,805 259,051 22,369,881 2,549,553 25,178,48 36
FERC FORM NO. 1 (ED. 12-87) Page 423.3
Name of Respondent
PaciflCorp
This Report Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 201 1/Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5.Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) I-I-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 (9) 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
No.
-
DESIGNATION VOLTAGE (KV) (Indicate where other than
60 cycle, 3 phase)
Type of
Supporting
Structure
(e)
LENGTH (Pole njiles) In the Ras u dergrounu lines
report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
On Structure
De L?ed
f)

On trucures

of ner
(g)
1 EAGLEROCK, ID GOSHEN, ID 161.0 161.00 Wood - H 12.00 1
2 YELLOWTAIL, MT RIMROCK, MT 161.00 161.00 Wood - H 46.00 1
3 RIGBY, ID JEFFERSON, ID 161.01]. 161.00 Wood SP 18.00 1
4 161 kV costs and expenses
6 Subtotal 161kV 255.00 90.00 11
7
WHEELON, UT AMERICAN FALLS, ID 138.00 138.00 Wood - H 82.00 1
9 OQUIRRH, UT TOOELE, UT 138.0' 138.00 Wood - SP 21.00 1
10 OQUIRRH, UT BARNEY, UT 138.0' 138.00 Wood - H 5.00 1
11 ANSCHTZ CO-GEN, WY EVANSTON, WY 138.0' 138.00 Wood - H 22.00 1
12 ANTELOPE, ID SCOVILLE#1, ID 138.0' 138.00 Wood - H 1.00 1
13 ANTELOPE, ID SCOVILLE #2, ID 138.0 138.00 Wood - H 1.00 1
14 ASHLEY, UT CARBON, UT 138,0 138.00 Wood - H 92.00 1
15 ASHLEY, UT VERNAL, UT 138.0 138.00 Wood - H 12.00 1
16 BEKER IND, ID THREEMILE KNOLL, ID 138.0 138.00 Wood - H 4.00 1
17 BEN LOMOND, UT BRIGHAM CITY, UT 138.0 138.00 Wood - H 14.00 1
18 BEN LOMOND #1, UT EL MONTE, UT 138.0 138.00 Steel - SP 14.00 1
19 BEN LOMOND #2, UT EL MONTE, UT 138.0 138.00 13.00 1
20 BEN LOMOND, UT HONEYVILLE, UT 138.0 138.00 22.00 1
21 BEN LOMOND, UT CLINTON, UT 138.0 138.00 13.00 1
22 BEN LOMOND, UT ANGEL, UT 138.0 138.00 Steel - SP 28.00 1
23 BEN LOMOND, UT W ZIRCONIUM, UT 138.0 138.00 Wood - SP 14.00 1
24 BEN LOMOND, UT WHEELON, UT 138.0 138.00 Steel Tower 42.00 1
25 BRIGHAM CITY, UT WHEELON, UT 138.0 138.00 Wood - H 24.00 1
26 CAMERON, UT PAROWAN, UT 138.01 138.00 Wood - H 35.00 1
27 CAMERON, UT SIGURD, UT 138.0 138.00 Wood - H 64.00 1
28 CARBON, UT HELPER #11, UT 138.0 138.00 Wood - H 2.00 1
29 CARBON, UT HELPER #2, UT 138.0 138.00 Wood - H 2.00 1
30 CARBON #1, UT SPANISH FORK, UT 138.0 138.00 Steel Tower 54.00 1
31 CARBON #2, UT SPANISH FORK, UT 138.01 138.00 52.00 1
32 THREEMILE KNOLL, ID GRACE #1, ID 138.01 138.00 Wood - H 17.00 1
33 THREEMILE KNOLL, ID GRACE #2, ID 138.01 138.00 Wood- H 17.00 1
34 THREEMILE KNOLL, ID MONSANTO 1, ID 138.01 138.00 Wood - H 2.00 1
35 THREEMILE KNOLL, ID MONSANTO 2, ID 138.01 138.00 Wood - SP 2.00 1
TOTAL 15,957.00 806.00 264
FERC FORM NO. I (ED. 12-87) Page 422.4
Name of Respondent
PacifiCorp
This Re art Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/2812012
Year/Period of Report
End of 2011/Q4
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 property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, 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 party is
an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
Conductor
and Material
W
COST OF LINE (Include in Column (j) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
No.
Land
(j)
Construction and
Other Costs
(k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses
(p)
1272 ACSR 45/7
56.5 ACSR 26/7 2
397.5 ACSR 26/7 3
623,49C 20,224,837 20,848,327 581,180 2,788 583,966 4
5
623,49C 20,224,837 20,848,327 581,180 2,788 583,966 6
7
250CUHD/12 8
795 ACSR 45/7 9
795 ACSR 265 10
795 ACSR 26/7 11
97.5 ACSR 26/7 12
397.5 ACSR 26/7 13
397.5 ACSR 26/7 14
197.5 ACSR 26/7 15
97.5 ACSR 26/7 16
1272 ACSR 45/7 17
95 ACSR 45/7 18
95 ACSR 45/7 19
250CUHD112 20
250 CUHD/12 21
397.5 ACSR 2617 22
795AAC/37 23
50CURD/12 24
795 ACSR 265 25
397.5 ACSR 265 26
397.5 ACSR 26/7 27
954 ACSR 54/7 28
556.5 ACSR 26/7 29
95ACSR26/7 30
1272 ACSR 45/7 31
50CUHD/12 32
1272 ACSR 455 33
1272 AAC/61 34
1272ACSR455 35
173,359,503 2,552,922,302 2,726,281,805 259,051 22,369,881 2,549,553 25,178,48 36
FERC FORM NO. I (ED. 12-87) Page 423.4
Name of Respondent
PaciflCorp
This Re ort Is:
(1)An Original
(2)ffjA Resubmission
Date of Report
(Mo, Da, Yr)
06/2812012
Year/Period of Report
End of 2011/Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
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 (9) 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 (9). 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
No.
-
DESIGNATION VOLTAGE (KV) (Indicate where other than
60 cycle, 3 phase)
Type of
Supporting
Structure
(e)
LENGTH (Pole miles) (In the ease Ot undergrouna lines report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
On Structure of De L?ed
f)
On trucures of FJotner
(g)
1 CLEAR CREEK, WY PAINTER, WY 138.01 138.00 Wood. SP 5.00 1
2 COLUMBIA, UT MOUNDS SWRK, UT 138.01 138.00 Wood - H 7.00 1
3 TAP TO SOUTHEAST, UT SOUTHEAST, UT 138.01 138.00 Wood SP 6.00 1
4 COTTONWOOD, UT HAMMER, UT 138.0l 138.00 Wood - SP 5.00 1
5 COTTONWOOD, UT SILVER CREEK, UT 138.01 138.00 Wood - SP 29.00 1
6 CUTLER, UT WHEELON, UT 138.01 138.00 Wood - SP 1.00 1
71 WEST CEDAR, UT ENTERPRISE VALLEY, UT 138.01 138.00 Wood - H 33.00 1
8 EVANSTON, WY RAILROAD, WY 138.01 138.00 Wood - SP 3.00 1
9 FRANKLIN, UT SMITHFIELD, UT 138.01 138.00 Wood - SP 25.00 1
10 FRANKLIN, ID TREASURETON, ID 138.01 138.00 Wood - SP 10.00 1
11 JORDAN, UT MCCLELLAND, UT 138.01 138.00 Wood - SP 5.00 1
12 GADSBY, UT TERMINAL, UT 138.01 138.00 Wood - SP 6.00 1
13 JORDAN, UT TERMINAL, UT 138.01 138.00 Wood - SP 6.00 1
14 TIMP, UT HALE, UT 138.01 138.00 Steel - SP 4.00 1
15 ABAJO, UT PINTO, UT 138.01 138.00 Wood - H 44.00 1
16 ONIEDA, ID GRACE, ID 138.01 138.00 Wood - H 19.00 1
17 TREASURETON, ID GRACE, ID 138.01 138.00 Steel Tower 25.00 1
18 TREASURETON, ID GRACE, ID 138.01 138.00 25.00 1
19 NEBO, UT DRY CREEK, UT 138.01 138.00 Wood - H 37.00 1
20 WESTFIELD, UT HALE, UT 138.01 138.00 Wood - H 13.00 1
21 NINETY SOUTH, UT DUMAS, UT 138.01 138.00 Wood - SP 6.00 1
22 DUMAS, UT WESTFIELD, UT 138.01 138.00 Wood - SP 18.00 1
23 TRI-CITY, UT AMERICAN FORK, UT 138.01 138.00 Wood - H 15.00 1
24 TIMP, UT SPANISH FORK, UT 138.01 138.00 Wood - H 23.00 1
25 HALE, UT TANNER, UT 138.01 138.00 Wood - H 7.00 1
26 MOUNDS SWRK, UT HELPER, UT 138.01 138.00 Wood - H 29.00 1
27 HONEYVILLE, UT WHEELON, UT 138.01 138.00 14.00 1
28 HUNTINGTON, UT MCFADDEN, UT 138.01 138.00 Wood - H 7.00 1
29 TERMINAL, UT KENNECOTT, UT 138.01 138.00 Steel - SP 9.00 1
30 KILN, UT NEBO, UT 138.01 138.00 Wood - H 30.00 1
31 MCCLELLAND, UT MIDVALLEY, UT 138.01 138.00 Wood - SP 6.00 1
32 MOUNDS SWRK, UT MOAB, UT 138.01 138.00 Wood - H 83.00 1
33 MOAB, UT PINTO, UT 138.01 138.00 Wood - H 68.00 1
34 NAUGHTON, WY NGPL, WY 138.01 138.00 Wood - H 36.00 1
35 NAUGHTON, WY PAINTER, WY 138.01 138.00 Wood - H 46.00 1
36 TOTAL 15,957.00 806.00 264
FERC FORM NO. 1 (ED. 12-87) Page 422.5
Name of Respondent
PacifiCorp
This Report Is:
(1)flAn Original
(2)RXA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
Conductor
and Material
(I)
COST OF LINE (Include in Column (j) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
No.
Land
(j)
Construction and
Other Costs
(k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses
(p)
795 ACSR 26/7
66.8 ACSR 26/7 2
795 ACSR 26/7 3
795 AAC /37 4
97.5 ACSR 2617 5
250CUHD112 6
97.5 ACSR 26/7 1
795 ACSR 26/7 8
397.5 ACSR 26/7 9
95 ACSR 45/7 10
795 MC 137 11
1272 ACSR 45/7 12
1272 AAC /61 13
14
397.5 ACSR 26/7 15
250CUHD/12 16
25OCUND/12
50CUHD/12 18
272 ACSR 45/7 19
795 ACSR 26/7 20
795 MC /37 21
795 ACSR 2617 22
1272 ACSR 45/7 23
1272 ACSR 45/7 24
1272 ACSR 45/7 25
397.5 ACSR 26/7 26
250CUHD/12 27
397.5 ACSR 26/7 28
795ACSR2617 29
97.5 ACSR 26/7 30
795 ACSR 26/7 31
397.5 ACSR 26/7 32
97.5 ACSR 26/7 33
795 ACSR 26/7 34
795 ACSR 26/7 35
173,359,503 2,552,922,302 2,726,281,805 259,051 22,369,881 2,549,553 25,178,48 36
FERC FORM NO. I (ED. 12-87) Page 423.5
Name of Respondent
PacifiCorp
This Re ort Is: (1)An Original
(2)ffjA Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
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 (9). 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
No.
-
DESIGNATION VOLTAGE (Ky) (Indicate where other than 60 cycle. 3 phase)
Type o
Supporting
Structure
(e)
LENGTH (Pole miles) (In the ease ot undergrouna lines report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
On Structure
DLa?ed a)
Ontruçures ofotner
(g)
I NGPL, WY TAP TO STR 204, WY 138.0 138.00 Wood - H 12.00 1
_2 CANYON COMPRESS, WY WHITNEY, WY 138.0 138.00 Wood - H 1.00 1
3 NINETY SOUTH, UT OQUIRRH, UT 138.0 138.00 Wood - SP 10.00 1
4 TAYLORSVILLE, UT NINETY SOUTH, UT 138.0 138.00 Wood - SP 6.00 2.00 1
5 MID VALLEY, UT NINETY SOUTH, UT 138.0 138.00 Wood - H 9.00 1
6 NUCOR STEEL, UT WHEELON, UT 138.0 138.00 Wood -H 14.00 1
71 ONEIDA, ID OVID, ID 138.0 138.00 Wood - H 23.00 1
8 TREASURETON, ID ONEIDA, ID 138.0 138.00 Wood - H 6.00 1
9 PAINTER, WY RAILROAD, WY 138.0 138.00 Wood - H 7.00 1
10 PAROWAN, UT WEST CEDAR, UT 138.0 138.00 Wood. H 21.00 1
11 TAP TO ANGEL SOUTH, UT TAP TO PARRISH, UT 138.0 138.00 13.00 1
12 PARRISH #1, UT TERMINAL, UT 138.0 138.00 Steel SP 16.00 1
13 PARRISH #2, UT TERMINAL, UT 138.0 138.00 14.00 1
14 RAILROAD, WY WHITNEY, WY 138.0 138.00 Wood - H 16.00 1
15 ROY STR, UT ANGEL, UT 138.0 138.00 10.00 1
16 BEN LOMOND, UT SYRACUSE, UT 138.0 230.00 Steel Tower 25.00 1
17 TERMINAL, UT ROWLEY, UT 138.0 138.00 Wood - H 56.00 1
18 GREEN CANYON, UT WHEELON, UT 138.0 138.00 Wood - SP 19.00 1
19 SPANISH FORK, UT TANNER, UT 138.0 138.00 Wood - H 10.00 1
20 TAP TO ANGEL NORTH, UT TAP TO PARRISH, UT 138.0 138.00 13.00 1
21 TERMINAL, UT MIDVALLEY, UT 138.0 138.00 Wood - H 7.00 1
22 TERMINAL, UT MIDVALLEY, UT 138.0 138.00 Steel - SP 7.00 1
23 TERMINAL, UT TOOELE, UT 138.1 138.00 Wood , H 24.00 6.00 1
24 WHEELON #103, UT TREASURETON, ID 138.0 138.00 Steel Tower 29.00 1
25 WHEELON #104, UT TREASURETON, ID 138.1 138.00 29.00 1
26 WHEELON #105, UT TREASURETON, ID 138.1 138.00 Wood - H 29.00 1
27 KCC BARNEY, UT KCCGRIND, UT 138.0 138.00 Wood - H 1.00 1
28 TERMINAL, UT LAKE PARK, UT 138.0 138.00 Wood - H 3.00 - 1
29 LAKE PARK, UT WEST VALLEY, UT 138.0 138.00 Wood - H 3.00 1
30 WEST VALLEY, UT OQUIRRH, UT 138.0 138.00 Wood - H 7.00 1
31 OQUIRRH,UT KCC BINGHAM, UT 138.0 138.00 Wood - H 8.00 1
32 WEST CEDAR, UT THREE PEAKS, UT 138.0 138.00 Wood - SP 20.00 1
33 HALE, UT SPANISH FORK, UT 138.0 138.00 Wood - H 18.00 1
34 MID VALLEY, UT TAYLORSVILLE, UT 138.00 138.00 Wood - SP 4.00 2.00 1
35 PARRISH #105, UT TERMINAL, UT 138.00 138.00 Steel - SP 14.00 1
TOTAL 15,957.00 806.00 264
FERC FORM NO. I (ED. 12-87) Page 422.6
Name of Respondent
PaciflCorp
This Re ort Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, 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 party is
an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
Conductor
and Material
(I)
COST OF LINE (Include in Column (j) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
N 0.
Land
(j)
Construction and
Other Costs
(k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses
(p)
95 ACSR 26/1
95 ACSR 26/1 2
95 ACSR 26/7 3
95AAC/37 T
1272ACSR4511 5
97.5 ACSR 26/7 6
336.4 ACSR 26/7 7
50CUHD/12 B
272 ACSR 4517 9
97.5ACSR2617 10
95AAC/37 11
95 ACSR 45/1 12
95 ACSR 26/7 13
95 ACSR 26/7 14
95AAC137 15
95 AAC /37 16
95AAC/37 17
97.5 ACSR 26/7 16
1272 ACSR 45/7 19
95AAC/37 20
1272 ACSR 455 21
1272AAC/61 22
397.5 ACSR 26/7 23
250 CUHD/12 24
250 CUHD/12 25
250 CUHD/12 26 1795 ACSR 265
ACSR 26,7 32
1272 ACSR 45/7 33
272AAC/61 34
795 ACSR 455 35
173,359,503 2,552,922,302 2,726,281,805 259,051 22,369,881 2,549,553 25,118,48 36
FERC FORM NO. 1 (ED. 12-87) Page 423.6
Name of Respondent
PaciflCorp
This Report Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/2812012
Year/Period of Report
End of 2011/Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
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 (9) 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
No.
-
DESIGNATION VOLTAGE (KV) (Indicate where
other than
60 cycle, 3 phase)
Type °
Supporting
(e)
LENGTH (Pole miles) (In the ease ot undergrouna lines
report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
Structure On Structure
DesLine
f)

On trucures

of otner
(g)
1 COLUMBIA, UT SUNNYSIDE, UT 138.01 138.00 Wood-H 2.00 1
_2 JERUSALM, UT NEBO, UT 138.01 138.00 Wood - H 26.00 1
3 HALE, UT MIDWAY, UT 138.01 138.00 Wood - H 19.00 1
4 QUARRY TAP, UT DUMAS, UT 138.01 138.00 U/G 5.00 1
5 HONEYVILLE, UT LAMPO, UT 138.01 138.00 Wood - H 25.00 1
6 GADSBY, UT JORDAN, UT 138.01 138.00 Wood - SP 1.00 1
7 MID VALLEY, UT COTTONWOOD, UT 138.01 138.00 Wood - SP 5.00 1
8j NINETY SOUTH, UT SANDY, UT 138.01 138.00 Steel - SP 1.00 1
9 MICRON, UT CAMP WILLIAMS, UT 138.01 138.00 9.00 1
10 MCFADDEN, UT BLACKHAWK, UT 138.01 138.00 Wood - H 11.00 1
11 TAP TO SANDY (STR 60), UT SANDY, UT 138.01 138.00 Steel - SP 6.00 1
12 EL MONTE, UT STIR 30B, UT 138.01 138.00 Steel - SP 4.00 1
13 EL MONTE, UT PIONEER, UT 138.01 138.00 Steel - SP 1.00 1
14 SYRACUSE, UT CLEARFIELD SOUTH, UT 138.01 138.00 Steel - SP 1.00 1
15 MID VALLEY, UT COTTONWOOD, UT 138.01 138.00 Steel- SP 5.00 1
16 HAMMER, UT BUTLERVILLE, UT 138.01 138.001 2.00 1
17 BUTLERVILLE, UT NINETY SOUTH, UT 138.01 138.00 Steel - SP 9.00 1
18 KEARNS, UT TAYLORSVILLE, UT 138.01 138.00 Wood - SP 2.00 1
19 SILVER CREEK SUB, UT JORDANELLE SUB, UT 138.01 138.00 Wood - SP 10.00 1
20 KEARNS, UT WEST VALLEY, UT 138.01 138.00 Wood - SP 2.00 1
21 RIVERDALE, UT 105 TAP, UT 138.01 138.00 Steel- SP 21.00 1
22 OQUIRRH, UT SUNRISE - TRI CITY, UT 138.0l 138.00 Steel - SP 25.00 1
23 BANGERTER, UT TRI-CITY, UT 138.01 138.00 23.00 1
24 DYNAMO, UT TRI-CITY#1, UT 138.01 138.00 Steel - SP 2.00 1
25 TIMP#1, UT DYNAMO, UT 138.0i 138.00 Steel - SP 2.00 1
26 DYNAMO, UT TRI-CITY#2, UT 138.01 138.00 3.00 1
27 TIMP #2, UT DYNAMO, UT 138.01 138.001 2.00 1
28 MIDDLETON, UT IST. GEORGE, UT 138.01 138.00 Wood - H 1.00 1
29 BRIDGERLAND, UT GREEN CANYON, UT 138.01 138.00 Wood - SP 16.00 1
301 SYRACUSE, UT PARRISH, UT 138.01 230.00 Steel Tower 15.00 1
311 BONANZA, UT CHAPITA, UT 138.01 138.00 Wood - H 8.00 1
32 ST GEORGE #1, UT 138.01 345.00 Steel - SP 20.00 1
33 ST GEORGE #2, UT 138.01 345.00 20.00 1
34EBAYTAP,UT 1OQUIRRH,UT 138.0 138.00 Wood - SP 1.00 1
35 PARRISH, UT TAP TO NSALT LAKE, UT 138.01 138.00 Steel - SP 8.00 1
36 i TOTAL 15,957.00 806.00 264
FERC FORM NO. 1 (ED. 12-87) Page 422.7
Name of Respondent
PacifiCorp
This Report Is:
(1)LAn Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
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 (9)
8.Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.
Size of
Conductor
and Material
(i)
COST OF LINE (Include in Column (j) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
No.
Land
(j)
Construction and
Other Costs (k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses
(p)
391.5 ACSR 26/7 1
97.5 ACSR 2617 2
397.5 ACSR 26/7 3
1750ALXLPEUG 4
397.5 ACSR 26/7 5
1212AAC/61 6
95 AAC 137
7
8
95 ACSR 265 9
795 ACSR 26/7 10
95AAC137 11
1272 ACSR 45/7 12
1272 ACSR 4517 13
1272 ACSR 45/7 14
15
795 ACSR 2617 16
795AAC/37 17
500AAC/19 18
795 ACSR 26/7 19
795 ACSR 2617
20
22
23
f795AcSR26I7 1 24
25
95 ACSR 2617 26
27
397.5 ACSR 26/7 28
1272 ACSR 45/7 29
1272 ACSR 45/7 30
795 ACSR 26/7 31
-1272 ACSR 45/7 32
2-1272 ACSR 45/7 33
795 ACSR 26/7 34
795 ACSR 26/7 35
173,359,503 2,552,922,302 2,726,281,805 259,051 22,369,881 2,549,553 25,178,48 36
FERC FORM NO. 1 (ED. 12-87) Page 423.7
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
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
No.
DESIGNATION VOLTAGE (KV)
(Indicate where other than
60 cycle, 3 phase)
Type 0
Supporting
Structure
(e)
LENGTH (Pole Tiles) ln the case ot u dergroun lines
report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
On Structure
D'?ed
On Structures otI2other
(g)
ne
1 138 kV costs and expenses
2
3 Subtotal 138kV 1,887.00 316.00 133
4
5 All 115kV Lines 1,603.00
6 All 69kV Lines 3,000.00
7 All 57kV Lines 113.00
8 All 46kV Lines 2,573.00
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 TOTAL 15,957.00 806.00 264
FERC FORM NO. 1 (ED. 12-87) Page 422.8
Name of Respondent
PacifiCorp
This Report Is:
(1)An Original
(2)nXA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
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 property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, 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 party is
an associated company.
9.Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns 0) to (I) on the book cost at end of year.
Size of
Conductor
and Material
0)
COST OF LINE (Include in Column (j) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
'10.
Land
(j)
Construction and
Other Costs (k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses (p)
18,064,04C 313,621,849 331,685,889 29,945 2,238,892 137,999 2,406,831 1
2
18,064,04 313,621,849 331,685,889 29,945 2,238,892 137,999 2,406,831 3
4
4,145,00 156,245,499 160,390,504 95,468 4,052,628 555,244 4,703,341 5
6,485,64 237,525,550 244,011,193 16,020 3,283,339 204,569 3,503,928 6
45,45E 9,799,269 9,844,727 74,537 3,585 78,122 7
8,596,739 210,877,840 219,474,579 94,604 2,402,961 64,426 2,561,991 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
173,359,503 2,552,922,302 2,726,281,805 259,051 22,369,881 2,549,553 25,178,48 36
FERC FORM NO. 1 (ED. 12-87) Page 423.8
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 0612812012 201 1 IQ4
FOOTNOTE DATA
Schedule Page: 422 Line No.: I Column: a I
Certain transmission lines reported on pages 422-423 are part of exchange agreements with
various third parties. Refer to the footnotes on pages 328-330 of this FERC Form No.1 for
further discussion.
ISchedule Page: 422 Line No.: 2 Column: a
The Meridian - Klamath Co-Gen, Klamath Co-Gen - Captain Jack, Captain Jack - Malin and
Midpoint - Malin 500-kV lines comprise what is referred to as the Midpoint to Meridian
transmission project.
Schedule Page: 422 Line No.: 3 Column: a
See Footnote on page 422 for column (a) line 2.
ISchedule Page: 422 Line No.: 4 Column: a
The Alvey - Dixonville 500-kV line is jointly owned by the respondent and the Bonneville
Power Administration ("the BPA"). Ownership of the line is as follows: PacifiCorp 50.0%,
the BPA 50.0%. Plant cost reported for this line reflects the respondent's 50.0% share.
Operation and maintenance costs are shared between the two parties and responsibility is
as follows: PacifiCorp 58.0% and the BPA 42.0%.
Schedule Page: 422 Line No.: 5 Column: a
The Dixonville - Meridian 500-kV line is jointly owned by the respondent and the
Bonneville Power Administration ("the BPA") . Ownership of the line is as follows:
PacifiCorp 50.0%, the BPA 50.0%. Plant cost reported for this line reflects the
respondent's 50.0% share. Operation and maintenance costs are shared between the two
parties and responsibility is as follows: PacifiCorp 58.0% and the BPA 42.0%.
Schedule Page: 422 Line No.: 6 Column: a
See Footnote on page 422 for column (a) line 2.
Schedule Page: 422 Line No.: 7 Column: a
See Footnote on page 422 for column (a) line 2.
Schedule Page: 422 Line No.: 8 Column: a
The Colstrip 4 - Switchyard 500-kV line is jointly owned by the respondent, NorthWestern
Corporation, Puget Sound Power & Light, Washington Water Power Company and Portland
General Electric. Ownership of the line is as follows: PacifiCorp 6.8%, all others 93.2%.
Plant cost and operation and maintenance costs reported for this line reflects the
respondent 's share.
Schedule Page: 422 Line No.: 9 Column: a
The Colstrip - Broadview A 500-kV line is jointly owned by the respondent, NorthWestern
Corporation, Puget Sound Power & Light, Washington Water Power Company and Portland
General Electric. 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.
lSchedule Page: 422 Line No.: 10 Column: a
The Colstrip - Broadview B 500-kV line is jointly owned by the respondent, NorthWestern
Corporation, Puget Sound Power & Light, Washington Water Power Company and Portland
General Electric. 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.
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)XA Resubmission 06/2812012 2011/Q4
FOOTNOTE DATA
Schedule Page: 422 Line No.: 11 Column: a
The Broadview - Townsend A 500-kV line is jointly owned by the respondent, NorthWestern
Corporation, Puget Sound Power & Light, Washington Water Power Company and Portland
General Electric. Ownership of the line is as follows: PacifiCorp, 8.1%, all others 91.9%.
Plant cost and operation and maintenance costs reported for this line reflects the
respondent's share.
Schedule Page: 422 Line No.: 12 Column: a
The Broadview - Townsend B 500-kV line is jointly owned by the respondent, NorthWestern
Corporation, Puget Sound Power & Light, Washington Water Power Company and Portland
General Electric. Ownership of the line is as follows: PacifiCorp 8.1%, all others 91.9%.
Plant cost and operation and maintenance costs reported for this line reflects the
respondent's share.
Schedule Page: 422.1 Line No.: 13 Column: i
2-1557.4 ACSR/TW 36/7
ISchedule Page: 422.1 Line No.: 14 Column: i
2-1557.4 ACSR/TW 36/7
Schedule Paqe: 422.2 Line No.: 7 Column: a
A 1.5 mile segment of the Casper - Dave Johnston 230-kV line is jointly owned by the
respondent and Black Hills Power. Ownership of the line is as follows: PacifiCorp 43.75%,
Black Hills Power 56.25%. Plant cost and operation and maintenance costs reported for
this line reflects the respondent's share.
Schedule Page: 422.2 Line No.: 7 Column: i
1557 ACSS/TW 45/7
Schedule Page: 422.5 Line No.: 14 Column: i
1557.4 ACSR/TW 36/7
lSchedule Page: 422.6 Line No.: 28 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 29 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 30 Column: i
1557.4 ACSR/TW 36/7
ISchedule Page: 422.6 Line No.: 31 Column: I
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 7 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 15 Column: i
1557.4 ACSR/TW 36/7
lSchedule Page: 422.7 Line No.: 20 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 22 Column: i I
IFERC FORM NO. I (ED. 12-87) Paae 450.2 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)XA Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 23 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 25 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 27 Column: i
1557.4 ACSR/TW 36/7
ISchedule Page: 422.7 Line No.: 32 Column: a
The Central - St. George transmission line operating at 138 kV is jointly owned by the
respondent and Utah Associated Municipal Power Systems ("UAMPS"). Ownership of the line is
as follows: PacifiCorp 54.62%, UAMPS 45.38%. Plant cost and operation and maintenance
costs reported for this line reflects the respondent's share.
Schedule Page: 422.7 Line No.: 33 Column: a
See Footnote on page 422.7 for column (a) line 35.
IFERC FORM NO. I (ED. 12-87) Page 450.3 I
Name of Respondent
PacifiCorp
This Report Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 (o), it is permissible to report in these columns the
Line
No.
LINE DESIGNATION Length
in Miles
(C)
SUPPORTING STRUCTURE CIRCUITS PER STRUCTUR
From
(a)
To
(b)
Type
(d)
Average
Number per
Miles
(e)
Present
(f)
Ultimate
(g)
1 PARRISH TAP, UT SKYPARK, UT 7.00 Steel - SP 9.00 2 2
21 LIMA, WY ROBERSON, WY 2.00 Wood - H 12.00
3 CHIMNEY BUTTE TAP, WY RILEY RIDGE, WY 12.00 Wood - H 12.00
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
441 TOTAL 21.00 33.00 4
FERC FORM NO. 1 (REV. 12-03) Page 424
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)LKA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
TRANSMISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (I) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate
such other characteristic.
CONDUCTORS voltage
KV
(Operating) (k)
LINE COST Line
No.
-
Size
(h)
Specification
(i)
Configuration
and Spacing
(j)
Land and
Land Rights
(I)
Poles, Towers
and Fixtures
(m)
Conductors
and Devices (n)
Asset
Retire. Costs (o)
Total
(p)
795 ACSR Vertical 12 138 839,114 209,778 1,048892 1
1272 ACSR Horizon 20' 230 •26 -183 -443 _2
1272 ACSR Horizon 20' 230 1,936,956 1,805,231 3,742,187 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
2,775,801 2,014,826 4,790,631 44
FERC FORM NO. I (REV. 12-03) Page 425
Name of Respondent
P ifiC ac Ofl
This Report Is:
(1)EAn Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
N °
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 CALIFORNIA
2 BELMONT SUB DISTRIBUTION-UNATTEN 69.00 12.47
3 BIG SPRINGS SUB DISTRIBUTION-UNATTEN 69.00 12.47
4 CANBY #2 DISTRIBUTION-UNATTEN 69.00 2.40
5 CASTELLA SUB DISTRIBUTION-UNATTEN 69.00 2.40
6 CLEAR LAKE SUB DISTRIBUTION-UNATTEN 69.00 12.47
7 DOG CREEK SUB DISTRIBUTION-UNATTEN 69.00 2.40
8 DORRIS SUB DISTRIBUTION-UNATTEN 69.00 12.47
9 FORT JONES SUB DISTRIBUTION-UNATTEN 69.00 12.47
10 GASQUET SUB DISTRIBUTION-UNATTEN 115.00 12.47
11 GREENHORN SUB DISTRIBUTION-UNATTEN 69.00 12.47
12 HAMBURG SUB DISTRIBUTION-UNATTEN 69.00 2.40
13 HAPPY CAMP SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 HORNBROOK SUB DISTRIBUTION-UNATTEN 69.00 12.47
15 INTERNATIONAL PAPER SUB DISTRIBUTION-UNATTEN 69.00 2.40
16 LAKE EARL SUB DISTRIBUTION-UNATTEN 69.00 12.47
17 LITTLE SHASTA SUB DISTRIBUTION-UNATTEN 69.00 7.20
18 LUCERNE SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 MACDOEL SUB DISTRIBUTION-UNATTEN 69.00 20.80
20 MCCLOUD SUB DISTRIBUTION-UNATTEN 69.00 12.47
21 MILLER REDWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
22 MONTAGUE SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 MORRISON CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.50
24 MOUNT SHASTA SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 NEWELL SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 NORTH DUNSMUIR SUB DISTRIBUTION-UNATTEN 69.00 12.47
27 NORTHCREST SUB DISTRIBUTION-UNATTEN 69.00 12.47
28 NUTGLADE SUB DISTRIBUTION-UNATTEN 69.00 2.40
29 PATRICKS CREEK SUB DISTRIBUTION-UNATTEN 115.00 7.20
30 PEREZ SUB DISTRIBUTION-UNATTEN 69.00 12.47
31 REDWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 SCOTT BAR SUB DISTRIBUTION-UNATTEN 69.00 12.47
33 SEIAD SUB DISTRIBUTION-UNATTEN 69.00 12.47
34 SHASTINA SUB DISTRIBUTION-UNATTEN 69.00 20.80
35 SHOTGUN CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 SMITH RIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47
37 SNOW BRUSH SUB DISTRIBUTION-UNATTEN 69.00 7.20
38 SOUTH DUNSMUIR SUB DISTRIBUTION-UNATTEN 69.00 4.16
39 TULELAKE SUB DISTRIBUTION-UNATTEN 69.00 12.47
40 TUNNEL SUB DISTRIBUTION-UNATTEN 69.00 12.47
FERC FORM NO. 1 (ED. 12-96) Page 426
Name of Respondent
PacifiCorp
This Re ort Is:
AResubmsion
Date of Report
06/28/2012
Year/Period of Report
End of 2011/04
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(9)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No. - Type of Equipment
(i)
Number of Units ) Total Capacity
(k)
25 1 2
6 1 3
1 3 4
1 3
4 3 6
-7
7 3 8
6 1
9 1 - 12 1
1 1
8 3
4 .3 14
9 3
12 1 16
2 3
4 1
31 2
6 1 20
4 3 21
6 1
14 1
16 4 24
12 1
6 6
20 4
2 3
1 1 - 2 3
9 3
2 3
2 _ 3
6 3
1 1 - 5 3 36
1 3
1 3
20 1
6 6
FERC FORM NO. I (ED. 12-96) Page 427
Name of Respondent
PacifiCorp
This Re ort Is:
(2) [flA Resubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(C)
Secondary
(d)
Tertiary
(e)
1 WALKER BRYAN SUB DISTRIBUTION-UNATTEN 69.00 12.47
2 WEED SUB DISTRIBUTION-UNATTEN 115.00 12.47
3 YUBA SUB DISTRIBUTION-UNATTEN 69.00 12.47
4 YUROK SUB DISTRIBUTION-UNATTEN 69.00 12.47
5 Total 3105.00 468.36
6 Number of Substations-43
7
8 ALTURAS SUB T/D-UNATTENDED 115.00 12.47 69.00
9 FALL CREEK HYDRO/SUB T/D-UNATTENDED 69.00 2.30
10 YREKA SUB T/D-UNATTENDED 115.00 12.47 69.00
11 Total 299.00 27.24 138.00
12 Number of Substations-3
13
14 AGER SUB TRANSMISSION-ATTENDE 115.00 69.00
15 COPCO #1 HYDRO PLANT TRANSMISSION-ATTENDE 69.00 2.30
16 COPCO #2230 SUB TRANSMISSION-ATTENDE 230.00 115.00
17 COPCO #2 HYDRO PLANT TRANSMISSION-ATTENDE 115.00 69.00 12.47
18 COPCO #2 SUB TRANSMISSION-ATTENDE 115.00 69.00 12.47
19 CRAG VIEW SUB TRANSMISSION-UNATTEN 115.00 69.00
20 DEL NORTE SUB TRANSMISSION-UNATTEN 115.00 69.00
21 IRON GATE HYDRO PLANT TRANSMISSION-UNATTEN 69.00 6.60
22 WEED JUNCTION SUB TRANSMISSION-UNATTEN 115.00 69.00
23 Total 1058.00 537.90 24.94
24 Number of Substations-9
25
26 IDAHO
27 ALEXANDER DISTRIBUTION-UNATTEN 46.00 12.47
28 AMMON DISTRIBUTION-UNATTEN 69.00 12.47
29 ANDERSON DISTRIBUTION-UNATTEN 69.00 12.47
30 ARCO DISTRIBUTION-UNATTEN 69.00 12.47
31 ARIMO DISTRIBUTION-UNATTEN 46.00 12.47
32 BANCROFT SUB DISTRIBUTION-uNATTEN 46.00 12.47
33 BELSON SUB DISTRIBUTION-UNATTEN 69.00 12.47
34 BERENICE SUB DISTRIBUTION-uNATTEN 69.00 12.47
35 CAMAS SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 CANYON CREEK SUB DISTRIBUTION-UNATTEN 69.00 24.90
37 CHESTERFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 CLEMENTS SUB DISTRIBUTION-UNATTEN 69.00 12.47
39 CLIFTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 COVE SUB DISTRIBUTION-UNATTEN 46.00 12.47
FERC FORM NO. I (ED. 12-96) Page 426.1
Name of Respondent
PacifiCorp
This Re ort Is:
2:ssion
Data of Report Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(9)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(J)
Total Capacity
(k)
8 3 1
25 1 2
3 3 3
4 3 4
324 102
6
7
31 4 8
4 3 9
95 2 10
130 9 11
12
13
5 3
27 6 2
375 2 16
122 5 1 17
51 4 18
19 3
150 2
19 1 21
37 3 22
805 29 3
24
25
26
4 1
14 1
20 1
6 1 30
8 1
4 1 32
13 1
11 1
14 1
20 1
5 1 -
5 1 5
4 1
6 1
FERC FORM NO. I (ED. 12-96) Page 427.1
Name of Respondent
fic aci orp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06128/2012
Year/Period of Report
End of 2011/Q4
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
N0.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(C)
Secondary
(d)
Tertiary
(e)
1 DOWNEY SUB DISTRIBUTION-UNATTEN 46.00 12.47
2 DUBOIS SUB DISTRIBUTION-UNATTEN 69.00 12.47
3 EASTMONT SUB DISTRIBUTION-UNATTEN 69.00 12.47
4 EGIN SUB DISTRIBUTION-UNATTEN 69.00 12.47
5 EIGHT MILE SUB DISTRIBUTION-UNATTEN 46.00 12.47
6 GEORGETOWN SUB DISTRIBUTION-UNATTEN 69.00 12.47
7 GRACE CITY SUBSTATION DISTRIBUTION-UNATTEN 46.00 12.47
8 HAMER SUB DISTRIBUTION-UNATTEN 69.00 12.47
9 HAYES SUB DISTRIBUTION-UNATTEN 69.00 12.47
10 HENRY SUB DISTRIBUTION-UNATTEN 46.00 12.47
11 HOLBROOK SUB DISTRIBUTION-UNATTEN 69.00 12.47
12 HOOPES SUB DISTRIBUTION-UNATTEN 69.00 12.47
13 HORSLEY SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 IDAHO FALLS SUB DISTRIBUTION-UNATTEN 46.00 12.47
15 INDIAN CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
16 JEFFCO SUB DISTRIBUTION-UNATTEN 69.00 24.90
17 KETTLE SUB DISTRIBUTION-UNATTEN 69.00 24.90
18 LAVA SUB DISTRIBUTION-UNATTEN 46.00 12.47
19 LUND SUB DISTRIBUTION-UNATTEN 46.00 12.47
20 MCCAMMON SUB DISTRIBUTION-UNATTEN 46.00 12.47
21 MENAN SUB DISTRIBUTION-UNATTEN 69.00 12.47
22 MERRILL SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 MILLER SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 MONTPELIER SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 MOODY SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 NEWDALE SUB DISTRIBUTION-UNATTEN 69.00 12.47
27 OSGOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
28 PRESTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
29 RAYMOND SUB DISTRIBUTION-UNATTEN 69.00 12.47
30 RENO SUB DISTRIBUTION-UNATTEN 69.00 12.47
31 REXBURG SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 RIRIE SUB DISTRIBUTION-UNATTEN 69.00 12.47
33 ROBERTS SUB DISTRIBUTION-UNATTEN 69.00 12.47
34 RUBY SUB DISTRIBUTION-UNATTEN 69.00 12.47
35 SAND CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 SANDUNE SUB DISTRIBUTION-UNATTEN 69.00 24.90
37 SHELLEY SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 SMITH SUB DISTRIBUTION-UNATTEN 69.00 12.47
39 SOUTH FORK SUB DISTRIBUTION-UNATTEN 69.00 12.47
40 SPUD SUB DISTRIBUTION-UNATTEN 46.00 12.47
FERC FORM NO. I (ED. 12-98) Page 426.2
Name of Respondent
PacifiCorp
This Re ort Is:
tIARssion
Date of Report
06/281212
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total CaPaCrtY
(k)
5 1 1
12 1 2
14 1 3
14 1
2 1
6 1 6
5 1
14 1 8
9 1
2 1
6 1 U
9 1 -
4 1
20 1 14
2 1
22
_
1
14 1
2 1
5 1 -
3 1 20
11 1
20 1
5 1 -
7 1
14 1
20 1 26
20 1 27
13 1
2 1 29
20 1 30
32 2
9 1
7 1
7 1 -
40 2
20 1
20 1
20 1
14 1
7 1
FERC FORM NO. I (ED. 12-96) Page 427.2
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)A Resubmission
Data of Report
(Mo, Da, Yr)
06128/2012
Year/Period of Report
End of 2011/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 ST. CHARLES SUB DISTRIBUTION-UNATTEN 69.00 12.47
2 SUGAR CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47
3 SUF4NYDELL SUB DISTRIBUTION-UNATTEN 69.00 12.47
4 TANNER SUB DISTRIBUTION-UNATTEN 46.00 12.47
5 TARGHEE SUB DISTRIBUTION-UNATTEN 46.00 12.47
6 THORNTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
7 UCON SUB DISTRIBUTION-UNATTEN 69.00 12.47
8 WATKINS SUB DISTRIBUTION-UNATTEN 69.00 12.47
9 WEBSTER SUB DISTRIBUTION-UNATTEN 69.00 12.47
10 WESTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
11 WINDSPER SUB DISTRIBUTION-UNATTEN 69.00 24.90
12 Total 4002.00 872.70
13 Number of Substations-65
14
15 CINDER BUTTE SUB T/D-UNATTENDED 161.00 12.47
16 MALAD SUB T/D-UNATTENDED 138.00 46.00 12.47
17 MUD LAKE SUB T/D-UNATTENDED 69.00 12.47
18 RIGBY SUB T/D-UNATTENDED 161.00 12.47 69.00
19 SAINT ANTHONY SUB T/D-UNATTENDED 69.00 46.00 12.47
20 Total 598.00 129.41 93.94
21 Number of Substations-5
22
23 GRACE HYDRO TRANSMISSION-ATTENDE 138.00 46.00 6.60
24 AMPS SUB TRANSMISSION-UNATTEN 230.00 69.00 12.47
25 ANTELOPE SUB TRANSMISSION-UNATTEN 230.00 161.00 12.47
26 ASHTON PLANT TRANSMISSION-UNATTEN 46.00 2.40 12.47
27 BIG GRASSY SUB TRANSMISSION-UNATTEN 161.00 69.00
28 BONNEVILLE SUB TRANSMISSION-UNATTEN 161.00 69.00
29 CONDA SUB TRANSMISSION-UNATTEN 138.00 46.00
30 FISH CREEK SUB TRANSMISSION-UNATTEN 161.00 46.00
31 FRANKLIN SUB TRANSMISSION-UNATTEN 138.00 46.00
32 GOSHEN SUB TRANSMISSION-UNATTEN 345.00 161.00 46.00
33 JEFFERSON SUB TRANSMISSION-UNATTEN 161.00 69.00
34 LIFTON HYDRO TRANSMISSION-UNATTEN 69.00 2.30
35 ONEIDA SUB TRANSMISSION-UNATTEN 138.00 25.00
36 OVID SUB TRANSMISSION-UNATTEN 138.00 69.00
37 SCOVILLE SUB TRANSMISSION-UNATTEN 138.00 69.00
38 SUGARMILL SUB TRANSMISSION-UNATTEN 161.00 46.00 69.00
39 THREEMILE KNOLL SUB TRANSMISSION-UNATTEN 345.00 138.00 46.00
40 TREASURETON SUB TRANSMISSION-UNATTEN 230.00 138.00
FERC FORM NO. 1 (ED. 12-96) Page 426.3
Name of Respondent
PacifiCorp
This Report Is:
(2) ff]A Resubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
5 1 1
13 1 2
13 1 3
4 1
4 1 5
7 1 6
7 1
14 1 8
20 1 9
4 1
20 1 11
723 67
13
14
60 2 1 15
71 4 1 16
14 1
189 4
40 2
374 13 2 20
21
22
115 4
75 1 1 24
445 3 25
18 3
67 1 27
67 1 28
67 1
25 3 30
75 1
763 8 1 32
233 3
6 2 34
40 2 35
30 1 36
76 2 37
169 3
700 1 39
533 2
FERC FORM NO. 1 (ED. 12-96) Page 427.3
Name of Respondent
PacifiCo
This Report Is:
(1)I:JAn Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Total 3128.00 1271.70 205.01
2 Number of Substations-1 8
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-UNATTEN 20.80 4.16
ii 35TH STREET DISTRIBUTION-UNATTEN 20.80 2.40
12 AGNESS AVE DISTRIBUTION-UNATTEN 115.00 12.47
13 ALDERWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 ARLINGTON DISTRIBUTION-UNATTEN 69.00 12.47
15 ATHENA DISTRIBUTION-UNATTEN 69.00 12.47
16 BANDON TIE SUB DISTRIBUTION-UNATTEN 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-UNATTEN 69.00 12.47
20 BELKNAP SUB DISTRIBUTION-UNATTEN 69.00 12.47
21 BLALOCK SUB DISTRIBUTION-UNATTEN 69.00 12.47
22 BLOSS SUB DISTRIBUTION-UNATTEN 115.00 12.47
23 BLY SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 BOISE CASCADE SUB DISTRIBUTION-UNATTEN 69.00 11.00
25 BONANZA SUB DISTRIBUTION-UNATTEN 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-UNATTEN 69.00 20.80
29 BRYANT SUB DISTRIBUTION-UNATTEN 69.00 12.47
30 BUCHANAN SUB DISTRIBUTION-UNATTEN 115.00 20.80
31 BUCKAROO SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 CAMPBELL SUB DISTRIBUTION-UNATTEN 115.00 12.47
33 CANNON BEACH SUB DISTRIBUTION-UNATTEN 115.00 12.47
34 CARNES SUB DISTRIBUTION-UNATTEN 69.00 12.47
35 CASEBEER SUB DISTRIBUTION-UNATTEN 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-UNATTEN 69.00 12.47
39 CHINA HAT SUB DISTRIBUTION-UNATTEN 69.00 12.47
40 CIRCLE BLVD SUB DISTRIBUTION-UNATTEN 115.00 20.80
FERC FORM NO. 1 (ED. 12-96) Page 426.4
Name of Respondent
PacifiCorp
This Re ort Is:
MA Resubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(1)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
3504 42 2 1
2
3
4
100 1 5
100 1 6
7
8
9
5 1
30 6
25 1
45 2 13
5 1
9 1
8 3 1 16
11 3 17
25 1 18
6 1
40 2
2 3
32 2
8 3
3 1 24
8 3 25
25 1 26
50 2
13 1 28
34 2 29
40 2
34 2 31
20 2
13 1
9 3 34
20 1
45 2
25 1
5 3 38
25 1 39
80 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.4
Name of Respondent
aci I Ofl
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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
N 0.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
I CLEVELAND AVE SUB DISTRIBUTION-UNATTEN 69.00 12.47
2 CLINE FALLS HYDRO DISTRIBUTION-UNATTEN 12.47 2.40
3 CLOAKE SUB DISTRIBUTION-UNATTEN 69.00 20.80
4 COBURG SUB DISTRIBUTION-UNATTEN 69.00 20.80
5 COLISEUM SUB DISTRIBUTION-UNATTEN 20.80 4.16
6 COLUMBIA SUB DISTRIBUTION-UNATTEN 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-UNATTEN 115.00 12.47
12 CULLY SUB DISTRIBUTION-UNATTEN 115.00 12.47
13 CULVER SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 CUTLER CITY SUB DISTRIBUTION-UNATTEN 20.80 4.16
15 DAIRY SUB DISTRIBUTION-UNATTEN 69.00 12.47
16 DALLAS SUB DISTRIBUTION-UNATTEN 115.00 20.80
17 DALREED SUB DISTRIBUTION-UNATTEN 230.00 34.50
18 DESCHUTES SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 DEVILS LAKE SUB DISTRIBUTION-UNATTEN 115.00 20.80
20 DIXON SUB DISTRIBUTION-UNATTEN 115.00 4.16
21 DODGE BRIDGE SUB DISTRIBUTION-UNATTEN 69.00 20.80
22 DOWELL SUB DISTRIBUTION-UNATTEN 115.00 12.47
23 EASY VALLEY SUB DISTRIBUTION-UNATTEN 115.00 12.47
24 EMPIRE SUB DISTRIBUTION-UNATTEN 115.00 20.80
25 ENTERPRISE SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 FERN HILL SUB DISTRIBUTION-UNATTEN 115.00 12.47
27 FIELDER CREEK SUB DISTRIBUTION-UNATTEN 115.00 20.80
28 FOOTHILLS SUB DISTRIBUTION-UNATTEN 69.00 12.47
29 FRALEY SUB DISTRIBUTION-UNATTEN 69.00 12.47
30 GARDEN VALLEY SUB DISTRIBUTION-UNATTEN 69.00 20.80
31 GAZLEY SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 GLENDALE SUB DISTRIBUTION-UNATTEN 230.00 12.47
33 GLENEDEN SUB DISTRIBUTION-UNATTEN 20.80 4.16
34 GLIDE SUB DISTRIBUTION-UNATTEN 115.00 12.47
35 GOLD HILL SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 GORDON HOLLOW SUB DISTRIBUTION-UNATTEN 69.00 12.47
37 GOSHEN SUB DISTRIBUTION-UNATTEN 115.00 20.80
38 GRANT STREET SUB DISTRIBUTION-UNATTEN 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. I (ED. 12-96) Page 426.5
Name of Respondent
PaciflCorp
This Re ort Is:
AResubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
45 2 1
1 3 2
20 1 3
10 3
9 2
55 2 1 6
20 1 7
40 2 8
5 1
25 2
20 1
25 1
13 1
2 3
25 1
50 2
75 3 17
13 1 18
50 2
7 1 20
13 1
20 1
45 2
20 1 24
19 2
13 1
25 1
21 4
5 3 29
20 1
8 4
25 2
5 1 -
13 1
11 3
6 1
20 1
45 2 38
1 4
25 1 40
FERC FORM NO. I (ED. 12-96) Page 427.5
Name of Respondent
P fiC aci om
This Re ort Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(C)
Secondary
(d)
Tertiary
(e)
1 GRIFFIN CREEK SUB DISTRIBUTION-UNATTEN 115.00 12.47
2 HAMAKER SUB DISTRIBUTION-UNATTEN 69.00 12.47
3 HARRISBURG SUB DISTRIBUTION-UNATTEN 69.00 20.80
4 HENLEY SUB DISTRIBUTION-UNATTEN 69.00 12.47
5 HERMISTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
6 HILLVIEW SUB DISTRIBUTION-UNATTEN 115.00 20.80
7 HINKLE SUB DISTRIBUTION-UNATTEN 69.00 12.47
8 HOLLADAY SUB DISTRIBUTION-UNATTEN 115.00 12.47
9 HOLLYWOOD SUB DISTRIBUTION-UNATTEN 115.00 12.47
10 HOOD RIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47
11 HORNET SUB DISTRIBUTION-UNATTEN 69.00 12.47
12 HUMBUG CREEK SUB DISTRIBUTION-UNATTEN 67.00 12.50
13 HUNTERS CIRCLE TEMP SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 ILLAHEE FLATS SUB DISTRIBUTION-UNATTEN 115.00 12.47
15 INDEPENDENCE SUB DISTRIBUTION-UNATTEN 69.00 20.80
16 JACKSONVILLE SUB DISTRIBUTION-UNATTEN 115.00 12.47 69.00
17 JEFFERSON SUB DISTRIBUTION-UNATTEN 69.00 20.80
18 JEROME PRAIRIE SUB DISTRIBUTION-UNATTEN 115.00 12.47
19 JORDAN POINT SUB DISTRIBUTION-UNATTEN 115.00 12.47
20 JOSEPH SUB DISTRIBUTION-UNATTEN 20.80 12.47
21 JUNCTION CITY SUB DISTRIBUTION-UNATTEN 69.00 20.80
22 KENWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 KILLINGWORTH SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 KNAPPA SVENSEN SUB DISTRIBUTION-UNATTEN 115.00 12.47
25 LAKEPORT SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 LANCASTER SUB DISTRIBUTION-UNATTEN 69.00 20.80
27 LEBANON SUB DISTRIBUTION-UNATTEN 115.00 20.80
28 LINCOLN SUB DISTRIBUTION-UNATTEN 115.00 12.47
29 LOCKHART SUB DISTRIBUTION-UNATTEN 115.00 20.80
30 LYONS SUB DISTRIBUTION-UNATTEN 69.00 20.80
31 MADRAS SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 MALLORY SUB DISTRIBUTION-UNATTEN 115.00 12.47
33 MARYS RIVER SUB DISTRIBUTION-UNATTEN 115.00 20.80
34 MEDCO SUB DISTRIBUTION-UNATTEN 115.00 12.47
35 MEDFORD DISTRIBUTION-UNATTEN 69.00 12.47
36 MERLIN SUB DISTRIBUTION-UNATTEN 115.00 12.47
37 MERRILL SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 MINAM SUB DISTRIBUTION-UNATTEN 69.00 12.47
39 MODOC SUB DISTRIBUTION-UNATTEN 69.00 12.47
40 MORO SUB DISTRIBUTION-UNATTEN 20.80 2.40
FERC FORM NO. I (ED. 12-96) Page 426.6
Name of Respondent
PacifiCorp
This Re ort Is:
2Isskn
Date of Report
06/28t2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
20 1 1
8 3 2
13 1 3
6 3
40 1 5
45 2 6
20 1
75 3 8
50 2 9
40 2 10
20 1 11
9 1
13 1 13
2 1
20 1
75 2 16
13 1
20 1 18
20 1
6 1 1 20
25 2 21
3 3 22
40 2 23
6 1 24
50 2 25
13 3 26
40 2
105 3 28 1
40 2 29
9 2
25 2
25 1
20 1 33
20 1 34
67 8 35
45 2 36
17 6
1 -
6 3 39
2 3 40
FERC FORM NO. I (ED. 12-96) Page 427.6
Name of Respondent
aci I Or
This Re ort Is:
(1)An Original
(2)jA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
N °.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 MURDER CREEK SUB DISTRIBUTION-UNATTEN 115.00 20.80
2 MYRTLE CREEK SUB DISTRIBUTION-UNATTEN 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-UNATTEN 115.00 12.47
6 OAK KNOLL SUB DISTRIBUTION-UNATTEN 115.00 12.47
7 OAKLAND SUB DISTRIBUTION-UNATTEN 115.00 12.47
8 OREMET SUB DISTRIBUTION-UNATTEN 115.00 12.47
9 OVERPASS SUB DISTRIBUTION-UNATTEN 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-UNATTEN 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-UNATTEN 115.00 12.47
16 PRINEVILLE SUB DISTRIBUTION-UNATTEN 115.00 12.47
17 PROVOLT SUB DISTRIBUTION-UNATTEN 69.00 12.47
18 QUEEN AVE SUB DISTRIBUTION-UNATTEN 69.00 20.80
19 RED BLANKET SUB DISTRIBUTION-UNATTEN 69.00 4.16
20 REDMOND SUB DISTRIBUTION-UNATTEN 115.00 12.47
21 RIDDLE SUB DISTRIBUTION-UNATTEN 69.00 12.47
22 RIDDLE VENEER SUB DISTRIBUTION-UNATTEN 115.00 12.47
23 ROGUE RIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 ROSEBURG SUB DISTRIBUTION-UNATTEN 115.00 20.80
25 ROSS AVE SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 ROXY ANN SUB DISTRIBUTION-UNATTEN 115.00 12.50
27 RUCH SUB DISTRIBUTION-UNATTEN 69.00 12.47
28 RUNNING Y SUB DISTRIBUTION-UNATTEN 69.00 20.80
29 RUSSELLVILLE SUB DISTRIBUTION-UNATTEN 115.00 12.47
30 SCENIC SUB DISTRIBUTION-UNATTEN 115.00 12.47 69.00
31 SCIO SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 SEASIDE SUB DISTRIBUTION-UNATTEN 115.00 12.47
33 SELMA SUB DISTRIBUTION-UNATTEN 115.00 12.47
34 SHASTA WAY SUB DISTRIBUTION-UNATTEN 12.47 4.16
35 SHEVLIN PARK SUB DISTRIBUTION-UNATTEN 69.00 12.50
36 SIMTAG BOOSTER PUMP DISTRIBUTION-UNATTEN 34.50 4.16
37 SOUTH DUNES SUB DISTRIBUTION-UNATTEN 115.00 12.47
38 SOUTHGATE SUB DISTRIBUTION-UNATTEN 69.00 20.80
39 SPRAGUE RIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47
40 STATE STREET SUB DISTRIBUTION-UNATTEN 115.00 20.80
FERC FORM NO. I (ED. 12-96) Page 426.7
Name of Respondent
P fiCo aci
This Report Is:
(1)EAn Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06128/2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(0
Number of
Transformers
In Service
(9)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(I)
Number of Units
(1)
Total Capacity
(k)
100 4 1
14 1 2
9 1 -
4 1 4
9 1 -
45 2 6
8 1 7
75 2 8
45 2
1 1 1
40 2 11
39 2
46 7 1 13
22 2 14
6 1
50 2 16
11 3
50 2 18
1 3
50 2 20
14 1 21
25 1 1
25 2
50 2 24
9 3 25
25 1
9 1 7
9 1
45 2
70 3
8 1
40 2 32
9 1 -
1 3
25 1 35
18 2 36
9 1 -
20 1 38
6 3
40 2 40
FERC FORM NO. I (ED. 12-96) Page 427.7
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 withcapacities 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
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 STAYTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
2 STEAMBOAT SUB DISTRIBUTION-UNATTEN 115.00 7.20
3 STEVENS ROAD SUB DISTRIBUTION-UNATTEN 115.00 20.80
4 SUTHERLIN SUB DISTRIBUTION-UNATTEN 115.00 12.00
5 SWEET HOME SUB DISTRIBUTION-UNATTEN 115.00 20.80
6 TAKELMA SUB DISTRIBUTION-UNATTEN 115.00 20.80
7 TALENT SUB DISTRIBUTION-UNATTEN 69.00 12.47
8 TEXUM SUB DISTRIBUTION-UNATTEN 69.00 12.47
9 TILLER SUB DISTRIBUTION-UNATTEN 115.00 12.47
10 TOLO SUB DISTRIBUTION-UNATTEN 69.00 12.47
11 TURKEY HILL SUB DISTRIBUTION-UNATTEN 69.00 12.47
12 UMAPINE SUB DISTRIBUTION-UNATTEN 69.00 12.47
13 UMATILLA SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 VERNON SUB DISTRIBUTION-UNATTEN 69.00 12.47
15 VILAS SUB DISTRIBUTION-UNATTEN 115.00 12.47
16 VILLAGE GREEN SUB DISTRIBUTION-UNATTEN 115.00 20.80
17 VINE STREET SUB DISTRIBUTION-UNATTEN 69.00 20.80
18 WALLOWA SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 WARM SPRINGS SUB DISTRIBUTION-UNATTEN 69.00 20.80
20 WARRENTON SUB DISTRIBUTION-UNATTEN 115.00 12.47
21 WASCO SUB DISTRIBUTION-UNATTEN 20.80 4.16
22 WECOMA BEACH SUB DISTRIBUTION-UNATTEN 20.80 4.16
23 WESTERN KRAFT SUB DISTRIBUTION-UNATTEN 115.00 12.47
24 WESTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 WESTSIDE HYDRO/SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 WEYERHAUSER SUB DISTRIBUTION-UNATTEN 69.00 12.47
27 WHITE CITY SUB DISTRIBUTION-UNATTEN 115.00 12.47
28 WILLOW COVE SUB DISTRIBUTION-UNATTEN 34.50 4.16
29 WINSTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
30 YEW AVENUE SUB DISTRIBUTION-UNATTEN 115.00 12.50
31 YOUNGS BAY SUB DISTRIBUTION-UNATTEN 115.00 12.47
32 Total 15463.54 2509.83 195.00
33 Number of Substations-11 82
34
35 ALBINA SUB T/D-UNATTENDED 115.00 12.47 69.00
36 APPLEGATE SUB T/D-UNATTENDED 115.00 69.00 12.47
37 ASHLAND MTN AVE SUB T/D-UNATTENDED 115.00 69.00 12.47
38 BEND PLANT SUB T/D-UNATTENDED 69.00 13.09 12.47
39 CAVE JUNCTION SUB T/D-UNATTENDED 115.00 12.47 69.00
40 HAZELWOOD SUB T/D-UNATTENDED 115.00 69.00 12.47
FERC FORM NO. 1 (ED. 12-96) Page 426.8
Name of Respondent
PacifiCo
This Report Is:
(1)flAn Original
(2)jA Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(I)
Number of Units
(j)
Total Capacity
(k)
55 2 1
1 -
50 2 3
25 1
42 2
12 1 6
50 2 7
25 1 8
1 1 -
10 1
13 3
20 1 12
25 2 13
50 2 14
25 1 15
40 2 16
20 1 17
6 1
12 3
25 2 20
2 3
3 1
50 2 23
22 2 24
22 9
40 2 26
60 3
28 3
22 3
25 1 30
36 2
4541 351 6
33
34
177 9 35
65 2 36
70 2 37
31 3 38
70 2
133 4 40
FERC FORM NO. I (ED. 12-96) Page 427.8
Name of Respondent
aci OrP
This Report Is:
(1)jEAn Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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
N° Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 KNOTT SUB T/D-UNATTENDED 115.00 12.47 57.00
2 MILE HI SUB T/D-UNATTENDED 115.00 69.00 12.47
3 PILOT BUTTE SUB T/D-UNATTENDED 230.00 69.00 12.47
4 SAGE ROAD SUB T/D-UNATTENDED 115.00 12.47
5 WINCHESTER SUB T/D-UNATTENDED 115.00 12.47 69.00
6 Total 1334.00 420.44 338.82
7 Number of Substations-il
8
9 CLEARWATER#1 HYDRO PLANT TRANSMISSION-ATTENDE 138.00 6.90
10 FISH CREEK HYDRO TRANSMISSION-ATTENDE 115.00 6.90
11 JC BOYLE HYDRO TRANSMISSION-ATTENDE 230.00 11.00
12 LEMOLO#1 HYDRO TRANSMISSION-ATTENDE 11.30 12.50
13 LEMOLO#2 HYDRO TRANSMISSION-ATTENDE 115.00 12.00
14 PROSPECT 1 HYDRO TRANSMISSION-ATTENDE 69.00 2.30
15 PROSPECT 2 HYDRO TRANSMISSION-ATTENDE 69.00 6.60
16 PROSPECT 3 HYDRO TRANSMISSION-ATTENDE 69.00 12.47
17 TOKETEE HYDRO TRANSMISSION-ATTENDE 115.00 6.90
18 BEND HYDRO PLANT TRANSMISSION-UNATTEN 4.16 2.40
19 CALAPOOYA SUB TRANSMISSION-UNATTEN 230.00 69.00
20 CHILOQUIN SUB TRANSMISSION-UNATTEN 230.00 115.00 69.00
21 COLD SPRINGS SUB TRANSMISSION-UNATTEN 230.00 69.00 2.40
22 COVE SUB TRANSMISSION-UNATTEN 230.00 69.00
23 DAYS CREEK SUB TRANSMISSION-UNATTEN 115.00 69.00
24 DIAMOND HILL SUB TRANSMISSION-UNATTEN 230.00 69.00
25 DIXONVILLE 115/230 SUB TRANSMISSION-UNATTEN 230.00 115.00 69.00
2€ rRANSMISSI0N-UNPCrTEN 500.00 230.00
27 EAGLE POINT HYDRO TRANSMISSION-UNATTEN 115.00 2.40
28 EAST SIDE HYDRO TRANSMISSION-UNATTEN 46.00 12.47
29 FISH HOLE SUB TRANSMISSION-UNATTEN 115.00 69.00
30 FRY SUB TRANSMISSION-UNATTEN 230.00 115.00
31 GRANTS PASS SUB TRANSMISSION-UNATTEN 230.00 115.00 69.00
32 GREEN SPRINGS PLANT/SUB TRANSMISSION-UNATTEN 115.00 69.00
33 HURRICANE SUB TRANSMISSION-UNATTEN 230.00 69.00 2.40
34 ISTHMUS SUB TRANSMISSION-UNATTEN 230.00 115.00
35 KENNEDY SUB TRANSMISSION-UNATTEN 69.00 57.00
36 KLAMATH FALLS SUB TRANSMISSION-UNATTEN 230.00 69.00
37 1 LONE PINE SUB TRANSMISSION-UNATTEN 230.00 115.00 69.00
38 TRANSMISSION-UNATTEN 500.00 230.00
39 MONPAC SUB TRANSMISSION-UNATTEN 115.00 69.00
40 NICKEL MOUNTAIN SUB TRANSMISSION-UNATTEN 230.00 115.00
FERC FORM NO. 1 (ED. 12-96) Page 426.9
Name of Respondent
PacifiCorp
This Re ort Is:
2rssion
Data of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
SUBSTATIONS (Con!inued)
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondents books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(9)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(I)
Total Capacity
(k)
162 5 1
39 4 2
400 4 3
40 2
75 5 5
1262 42 6
7
8
17 3
13 3 10
89 2 1 11
2 3 1 12
40 4
5 3
40 6 1 15
10 6 16
50 9
30 3 18
75 1 - 19
119 4 20
66 2 21
67 3
50 1
75 1
344 6
650 3 1 26
3 1 27
3 3 28
7 3 29
500 2
473 5 31
19 3 32
29 2 33
250 1 34
33 1 35
251 6 1
732 10
1300 6 1 38
50 1
114 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.9
Name of Respondent
Pa ifiC C OrP
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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
N0.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(C)
Secondary
(d)
Tertiary
(e)
1 PARRISH GAP SUB TRANSMISSION-UNATTEN 230.00 69.00 12.47
2 PONDEROSA SUB TRANSMISSION-UNATTEN 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-UNATTEN 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-UNATTEN 230.00 115.00 69.00
9 TUCKER SUB TRANSMISSION-UNATrEN 115.00 69.00
10 WALLOWA FALLS HYDRO TRANSMISSION-UNATTEN 20.80
11 Total 6970.26 2634.04 362.27
12 Number of Substations-42
13
14 UTAH
15 106TH SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.50
16 118TH SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.47
17 23RD ST SUB DISTRIBUTION-UNATTEN 46.00 12.47
18 70TH SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.47
19 ALTAVIEW SUB DISTRIBUTION-UNATTEN 46.00 12.47
20 AMALGA SUB DISTRIBUTION-UNATTEN 46.00 12.47
21 AMERICAN FORK SUB DISTRIBUTION-UNATTEN 138.00 12.47
22 ARAGONITE DISTRIBUTION-UNATTEN 46.00 7.20
23 AURORA SUB DISTRIBUTION-UNATTEN 46.00 12.47
24 BANGERTER SUB DISTRIBUTION-UNATTEN 138.00 12.47
25 BEAR RIVER SUB DISTRIBUTION-UNATTEN 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-UNATTEN 46.00 12.47
29 BLUFF SUB DISTRIBUTION-UNATTEN 69.00 12.47
30 BLUFFDALE SUB DISTRIBUTION-UNATTEN 46.00 12.47
31 BOTHWELL SUB DISTRIBUTION-UNATTEN 46.00 12.47
32 BRIAN HEAD SUB DISTRIBUTION-UNATTEN 46.00 12.47
33 BRICKYARD SUB DISTRIBUTION-UNATTEN 46.00 12.47
34 BRIGHTON SUB DISTRIBUTION-UNATTEN 46.00 24.90
35 BROOKLAWN SUB DISTRIBUTION-UNATTEN 46.00 12.47
36 BRUNSWICK SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 BURTON SUB DISTRIBUTION-UNATTEN 34.50 12.47
38 BUSH SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 CANNON SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 CANYONLANDS SUB DISTRIBUTION-UNATTEN 69.00 12.47
FERC FORM NO. I (ED. 12-96) Page 426.10
Name of Respondent
P ifiC ac orp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
(g)
Number of
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
150 1 1
250 1 2
8 3 1 3
46 4
50 1 5
21 3 6
13 3
500 3 8
100 2
1 3
6645 132 7 11
12
13
14
30 1 15
30 1 16
12 1
30 1 18
45 2
11 1 -
30 1 21
1 1 -
3 1
50 2 24
17 2
2 1
11 1 -
2 3
1 3
9 1 30
4 1
14 1
9 1
26 2
6 1 35
60 3
11 3 37
9 1
12 1
1 1 -
FERC FORM NO. 1 (ED. 12-96) Page 427.10
Name of Respondent
P fiC ad Orp
This Re ort Is:
(1)An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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
N 0.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 CAPITOL SUB DISTRIBUTION-UNATTEN 46.00 12.47
2 CARBIDE SUB DISTRIBUTION-UNATTEN 46.00 7.20
3 CARBONVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
4 CARLISLE SUB DISTRIBUTION-UNATTEN 138.00 12.50
5 CASTO SUBSTATION DISTRIBUTION-UNATTEN 46.00 12.47
6 CENTERVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
7 CENTRAL SUB DISTRIBUTION-UNATTEN 43.80 12.47
8 CHAPEL HILL SUB DISTRIBUTION-UNATTEN 138.00 12.47
9 CHERRYW000 SUB DISTRIBUTION-UNATTEN 138.00 12.47
10 CIRCLEVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47
11 CLEAR CREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47
12 CLEAR LAKE SUB DISTRIBUTION-UNATTEN 46.00 12.47
13 CLEARFIELD SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.47
14 CLINTON SUB DISTRIBUTION-UNATTEN 138.00 12.47
15 CLIVE SUB DISTRIBUTION-UNATTEN 46.00 12.47
16 COALVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 COLD WATER CANYON SUB DISTRIBUTION-UNATTEN 138.00 12.47
18 COLEMAN SUB DISTRIBUTION-UNATTEN 138.00 69.00 12.47
19 COLTON WELL SUB DISTRIBUTION-UNATTEN 46.00 12.47
20 COMMERCE SUB DISTRIBUTION-UNATTEN 138.00 12.50
21 COPPER HILLS SUB DISTRIBUTION-UNATTEN 138.00 12.47
22 CORINNE SUB DISTRIBUTION-UNATTEN 46.00 12.47
23 COVE FORT SUB DISTRIBUTION-UNATTEN 46.00 12.47
24 COZYDALE SUB DISTRIBUTION-UNATTEN 138.00 12.50
25 CROSS HOLLOW SUB DISTRIBUTION-UNATTEN 138.00 12.47
26 CUDAHY SUB DISTRIBUTION-UNATTEN 138.00 12.47
27 DAMMERON VALLEY SUB DISTRIBUTION-UNATTEN 34.50 12.47
28 DECKER LAKE SUB DISTRIBUTION-UNATTEN 138.00 12.47
29 DELLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
30 DELTA SUB DISTRIBUTION-UNATTEN 46.00 69.00
31 DESERET SUB DISTRIBUTION-UNATTEN 46.00 4.16
32 DEWEYVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
33 DIMPLE DELL SUB DISTRIBUTION-UNATTEN 138.00 12.47
34 DIXIE DEER SUB DISTRIBUTION-UNATTEN 34.50 12.47
35 DRAPER SUB DISTRIBUTION-UNATTEN 46.00 12.47
36 EAST BENCH SUB DISTRIBUTION-UNATTEN 138.00 12.47
37 EAST HYRUM SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 EAST LAYTON SUB DISTRIBUTION-UNATTEN 138.00 12.47
39 EAST MILLCREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 EDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
FERC FORM NO. I (ED. 12-96) Page 426.11
Name of Respondent
PacifiCorp
This Re art Is:
2R' Resubmission
Data of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(9)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
20 1 1
3 1 2
6 1 3
30 1 4
25 1
22 1 6
9 1
30 1 8
50 2 9
3 1
4 1
3
60 2 13
50 2 14
4 1
20 2 16
30 1
106 4
1 3
30 1 20
30 1
3 1
2 3
30 1 24
22 1 25
30 1 26
42 1
55 2
6 1
48 3
2 1
4 1
60 2
2 1
23 2
30 1
6 1 37
60 2 38
20 1 39
19 2 40
FERC FORM NO. I (ED. 12-96) Page 427.11
Name of Respondent
fic act Ofl
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report (Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
N0. Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(C)
Secondary
(d)
Tertiary
(e)
1 ELBERTA SUB DISTRIBUTION-UNATTEN 46.00 12.47
2 ELK MEADOWS SUB DISTRIBUTION-UNATTEN 46.00 12.47
3 ELSINORE SUB DISTRIBUTION-UNATTEN 46.00 12.47
4 EMERY CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47
5 EMIGRATION SUB DISTRIBUTION-UNATTEN 46.00 12.47
6 ENOCH SUB DISTRIBUTION-UNATTEN 138.00 12.47
7 ENTERPRISE VALLEY SUB DISTRIBUTION-UNATTEN 138.00 12.47
8 EUREKA SUB DISTRIBUTION-UNATTEN 46.00 12.47
9 FARMINGTON SUB DISTRIBUTION-UNATTEN 138.00 12.47
10 FAYETTE SUB DISTRIBUTION-UNATTEN 46.00 12.47
11 FERRON SUB DISTRIBUTION-UNATTEN 46.00 12.47
12 FIELDING SUB DISTRIBUTION-UNATTEN 46.00 1200
13 FIFTH WEST SUB DISTRIBUTION-UNATTEN 138.00 12.47
14 FLUX SUB DISTRIBUTION-UNATTEN 46.00 12.47
15 FOOL CREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47
16 FOUNTAIN GREEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 FREEDOM SUBSTATION DISTRIBUTION-UNATTEN 46.00 7.20
18 FRUIT HEIGHTS SUB DISTRIBUTION-UNATTEN 46.00 12.47
19 GARDEN CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47
20 GATEWAY SUB DISTRIBUTION-UNATTEN 69.00 12.47
21 GOLD RUSH SUB DISTRIBUTION-UNATTEN 138.00 12.50
22 GORDON AVENUE SUB DISTRIBUTION-UNATTEN 138.00 12.50
23 GOSHEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
24 GRANGER SUB DISTRIBUTION-UNATTEN 46.00 12.47
25 GRANTSVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
26 GUNLOCK HYDRO DISTRIBUTION-UNATTEN 34.50 2.30
27 GUNNISON SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 HAMMER SUB DISTRIBUTION-UNATTEN 138.00 12.47
29 HAVASU SUB DISTRIBUTION-UNATTEN 69.00 12.47
30 HELPER CITY SUB DISTRIBUTION-UNATTEN 46.00 4.16
31 HENEFER SUB DISTRIBUTION-UNATTEN 46.00 12.47
32 HERRIMAN SUB DISTRIBUTION-UNATTEN 138.00 12.47
33 HIAWATHA SUB DISTRIBUTION-UNATTEN 46.00 4.16
34 HIGHLAND DIST SUB DISTRIBUTION-UNATTEN 46.00 12.47
35 HOGGARD SUB DISTRIBUTION-UNATTEN 138.00 12.47
36 HOGLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 HOLDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 HOLLADAY SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 HUNTER SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 HUNTINGTON CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47
FERC FORM NO. 1 (ED. 12-96) Page 426.12
Name of Respondent
PacifiCorp
This Re ort Is:
(2) MA Resubmission
Date of Report
06/28/212
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondents books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(9)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT tine
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
5 1 1
3 1 2
2 1 3
3 3 4
25 1 5
14 1 6
10 1 7
3 1 8
30 1 9
1 2
5 1
6 1
50 2 13
4 1
2 1
7 1
1 -
22 1 18
13 1 19
28 1 1 20
30 1 21
30 1 22
1
50 2 24
24 1 25
1 1
11 2
60 2 28
3 1
3 3 30
4 1
30 1 32
4 3 33
25 1 34
50 2
22 1 36
4 1
32 2
22 1
13 2 40
FERC FORM NO. I (ED. 12-96) Page 427.12
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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
No.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
I IRON MOUNTAIN SUB DISTRIBUTION-UNATTEN 34.50 7.20
2 IRON SPRINGS SUB DISTRIBUTION-UNATTEN 34.50 12.47
3 IRONTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
4 IVINS SUB DISTRIBUTION-UNATTEN 34.50 12.47
5 JORDAN NARROWS SUB DISTRIBUTION-UNATTEN 46.00 2.40
6 PORDAN PARK SUB DISTRIBUTION-UNATTEN 138.00 12.47
7 JORDANELLE SUB DISTRIBUTION-UNATTEN 138.001 12.47
8 JUAB SUB DISTRIBUTION-UNATTEN 46.00 12.47
9 JUNCTION SUB DISTRIBUTION-UNATTEN 69.00 12.47
10 KAIBAB SUB DISTRIBUTION-UNATTEN 69.00 12.47
11 KAMAS SUB DISTRIBUTION-UNATTEN 46.00 12.47
12 KEARNS SUB DISTRIBUTION-UNATTEN 138.00 12.47
13 KENSINGTON SUB DISTRIBUTION-UNATTEN 46.00 4.16
14 LAKE PARK SUB DISTRIBUTION-UNATTEN 138.00 12.47
15 LARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
16 LAYTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 LEGRANDE SUB DISTRIBUTION-UNATTEN 46.00 12.47
18 LEWISTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
19 LINCOLN SUB DISTRIBUTION-UNATTEN 46.00 12.47
20 LINDON SUB DISTRIBUTION-UNATTEN 46.00 12.47
21 LISBON SUB DISTRIBUTION-UNATTEN 69.00 12.47
22 LITTLE MOUNTAIN SUB DISTRIBUTION-UNATTEN 46.00 12.47
23 LOAFER SUB DISTRIBUTION-UNATTEN 46.00 12.47
24 LOGAN CANYON SUB DISTRIBUTION-UNATTEN 46.00 7.20
25 LONE TREE SUB DISTRIBUTION-UNATTEN 34.50 12.47
26 LOWER BEAVER SUB DISTRIBUTION-UNATTEN 46.00 6.60
27 LYNNDYL SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 MAESER SUB DISTRIBUTION-UNATTEN 69.00 12.47
29 MAGNA SUB DISTRIBUTION-UNATTEN 138.00 12.47
30 MANILA SUB DISTRIBUTION-UNATTEN 46.00 12.47
31 MANTUA SUB DISTRIBUTION-UNATTEN 46.00 12.47
32 MAPLETON SUB DISTRIBUTION-UNATTEN 46.00 12.47
33 MARRIOTT SUB DISTRIBUTION-UNATTEN 46.00 12.47
34 MARYSVALE SUB DISTRIBUTION-UNATTEN 46.00 12.47
35 MATI-IIS SUB DISTRIBUTION-UNATTEN 46.00 12.47
36 MCCORNICK SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 MCKAY SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 MEADOWBROOK SUB DISTRIBUTION-UNATTEN 138.00 12.47 46.00
39 MEDICAL SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 MIDLAND SUB DISTRIBUTION-UNATTEN 138.00 12.47
FERC FORM NO. 1 (ED. 12-96) Page 426.13
Name of Respondent
PacifiCorp
This Report Is:
2'rSsIOn
Date of Report
g2a;;I;r)
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transfonners
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
I 1 I
5 3 2
2 1
22 1
13 - 2
30 1 6
30 1
2 3 8
2 1 9
5 1 -
7 1
60 2 12
7 1
53 2
6 1
40 2 16
1 1 -
14 1
20 1 19
20 1
4 1
20 1 22
1 -
1 1 -
20 1
1 1 -
4 1 -
12 1 28
30 1 29
22 1
2 1
14 1
20 1
3 1
9 1
6 1 36
20 1
42 2
57 4 39
30 1 40
FERC FORM NO. I (ED. 12-96) Page 427.13
Name of Respondent
aci fiC
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da,Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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
N0.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 MIDVALE SUB DISTRIBUTION-UNATTEN 46.00 12.47
2 MILFORD SUB DISTRIBUTION-UF4ATTEN 46.00 12.47
3 MILFORD TV SUB DISTRIBUTION-UNATTEN 46.00 13.20
4 MILLVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
5 MINERSVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
6 MOAB CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47
7 MONTEZUMA SUB DISTRIBUTION-UNATTEN 69.00 12.47
8 MOORE SUB DISTRIBUTION-UNATTEN 69.00 12.47
9 MORGAN SUB DISTRIBUTION-UNATTEN 46.00 4.16
10 MORONI SUB DISTRIBUTION-UNATTEN 46.00 12.47
11 MOSS JUNCTION SUB DISTRIBUTION-UNATTEN 46.00 12.47
12 MOUNTAIN DELL SUB DISTRIBUTION-UNATTEN 46.00 12.47
13 MOUNTAIN GREEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 MYTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
15 NEW HARMONY SUB DISTRIBUTION-UNATTEN 69.00 12.47
16 NEWGATE SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 NEWTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
18 NIBLEY SUB DISTRIBUTION-UNATTEN 46.00 24.90
19 NORTH BENCH SUB DISTRIBUTION-UNATTEN 46.00 12.47
20 NORTH FIELDS SUB DISTRIBUTION-UNATTEN 46.00 12.47
21 NORTH LOGAN SUB DISTRIBUTION-UNATTEN 46.00 12.47
22 NORTH OGDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
23 NORTH SALT LAKE SUB DISTRIBUTION-UNATTEN 46.00 13.20
24 NORTHEAST SUB DISTRIBUTION-UNATTEN 46.00 12.50
25 NORTHRIDGE SUB DISTRIBUTION-UNATTEN 46.00 12.47
26 OAKLAND AVE SUB DISTRIBUTION-UNATTEN 46.00 12.47
27 OAKLEY SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 OLYMPUS SUB DISTRIBUTION-UNATTEN 46.00 12.47
29 OPHIR SUB DISTRIBUTION-UNATTEN 46.00 12.47
30 ORANGE SUB DISTRIBUTION-UNATTEN 46.00 12.47
31 ORANGEVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 OREM SUB DISTRIBUTION-UNATTEN 46.00 12.47
33 PACK CREEK RESERVOIR DISTRIBUTION-UNATTEN 46.00 12.47
34 PANGUITCH SUB DISTRIBUTION-UNATTEN 69.00 12.47
35 PARIETTE SUBSTATION DISTRIBUTION-UNATTEN 69.00 24.90
36 PARK CITY SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 PARKWAY SUB DISTRIBUTION-UNATTEN 138.00 12.47
38 PARLEYS SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 PELICAN POINT SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 PINE CANYON SUB DISTRIBUTION-UNATTEN 138.00 12.47
FERC FORM NO. 1 (ED. 12-96) Page 426.14
Name of Respondent
PacifiCorp
This Re ort Is:
(2) OA Resubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(I)
Number of Units
U)
Total Capacity
(k)
25 1 1
14 1 2
1
12 1 4
2 1 5
19 2 6
13 1
3 1
7 2
6 1
6 3
5 1
6 1 13
6 1 14
7 1
20 1 16
5 1 -
14 1 18
25 1 19
2 1
25 1 21
22 1 22
25 1
45 2 24
14 1
24 2 26
6 1 27
22 1 28
2 1
20 1 30
14 1
48 2 32
4 1
5 1 -
4 3 35
35 2
50 2
16 2
6 1 39
55 2
FERC FORM NO. I (ED. 12-96) Page 427.14
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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
N0.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 PINE CREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47
2 PINNACLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
3 PLAIN CITY SUB DISTRIBUTION-UNATTEN 138.00 12.47
4 PLEASANT GROVE SUB DISTRIBUTION-UNATTEN 46.00 12.47
5 PLEASANT VIEW SUB DISTRIBUTION-UNATTEN 46.00 12.47
6 PORTER ROCKWELL SUB DISTRIBUTION-UNATTEN 138.00 12.47
7 PROMONTORY SUB DISTRIBUTION-UNATTEN 46.00 12.47
8 QUAIL CREEK SUB DISTRIBUTION-UNATTEN 34.50 12.47
9 QUARRY SUB DISTRIBUTION-UNATTEN 138.00 12.47
10 QUICHAPA SUB DISTRIBUTION-UNATTEN 34.50 12.47
11 RAINS SUB DISTRIBUTION-UNATTEN 46.00 7.20
12 RANDOLPH SUB DISTRIBUTION-UNATTEN 46.00 12.47
13 RASMUSON SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 RATTLESNAKE SUB DISTRIBUTION-UNATTEN 69.00 24.90
15 RED MOUNTAIN SUB DISTRIBUTION-UNATTEN 69.00 34.50
16 RED ROCK SUB DISTRIBUTION-UNATTEN 69.00 4.16
17 REDWOOD SUB DISTRIBUTION-UNATTEN 46.00 12.47
18 RESEARCH PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
19 RICH SUB DISTRIBUTION-UNATTEN 69.00 12.47
20 RICHFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47
21 RICHMOND SUB DISTRIBUTION-UNATTEN 46.00 12.47
22 RIDGELAND SUB DISTRIBUTION-UNATTEN 138.00 12.47
23 RITER SUB DISTRIBUTION-UNATTEN 46.00 12.47
24 ROCK CANYON SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 ROCKVILLE SUB DISTRIBUTION-UNATTEN 34.50 12.47
26 ROCKY POINT DISTRIBUTION-UNATTEN 138.00 13.20
27 ROSE PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 ROYAL SUB DISTRIBUTION-UNATTEN 46.00 4.16
29 SALINA SUB DISTRIBUTION-UNATTEN 46.00 12.47
30 SANDY SUB DISTRIBUTION-UNATTEN 138.00 12.47
31 SARATOGA SUB DISTRIBUTION-UNATTEN 138.00 12.47
32 SCIPIO SUB DISTRIBUTION-UNATTEN 46.00 12.47
33 SCOFIELD RESERVOIR SUB DISTRIBUTION-UNATTEN 46.00 7.20
34 SCOFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47
35 SECOND STREET SUB DISTRIBUTION-UNATTEN 46.00 12.47
36 SEVEN MILE SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 SHARON SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 SHIVWITS SUB DISTRIBUTION-UNATTEN 34.50 4.16
39 SHORELINE SUB DISTRIBUTION-UNATTEN 138.00 13.20
40 SIXTH SOUTH SUB DISTRIBUTION-UNATTEN 46.00 12.47
FERC FORM NO. I (ED. 12-96) Page 426.15
Name of Respondent
PacifiCorp
This Re ort Is:
AResubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(0
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
U)
Total Capacity
(k)
2 1 1
14 1 2
22 1
25 1
14 1
30 1 6
2 1
4 1 8
60 2 9
4 1
15 1 11
2 1
1 3
14 1 14
12 1 15
2 1
45 2
45 2
5 1
22 2 20
11 1
40 2
20 1
5 1 -
4 1
30 1
24 3
3 28
10 1 -.
60 2
60 2 31
1 3
1 1 -
1 3
13 2
1 -
20 1
6 1
60 2 39
20 1 40
FERC FORM NO. I (ED. 12-96) Page 427.15
Name of Respondent
PacifiCor p
This Re ort Is:
(1)An Original
(2)IKIA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 SKULL VALLEY SUB DISTRIBUTION-UNATTEN 46.00 12.47
2 SKYPARK SUB DISTRIBUTION-UNATTEN 138.00 12.50 12.50
3 SNARR SUB DISTRIBUTION-UNATTEN 46.00 12.47
4 SNOWVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47
5 SNYDERVILLE SUB DISTRIBUTION-UNATTEN 138.00 12.47
6 SOLDIER SUMMIT SUB DISTRIBUTION-UNATTEN 69.00 12.47
7 SOUTH JORDAN SUB DISTRIBUTION-UNATTEN 138.00 12.47
8 SOUTH MILFORD SUB DISTRIBUTION-UNATTEN 46.00 12.47
9 SOUTH MOUNTAIN SUB DISTRIBUTION-UNATTEN 138.00 12.47
10 SOUTH OGDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
11 SOUTH PARK SUB DISTRIBUTION-UNATTEN 138.00 12.47
12 SOUTH WEBER SUB DISTRIBUTION-UNATTEN 138.00 12.47
13 SOUTHWEST SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 SPANISH VALLEY SUB DISTRIBUTION-UNATTEN 69.00 12.47
15 SPRINGDALE SUB DISTRIBUTION-UNATTEN 34.50 12.47
16 51'. JOHNS SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 STAIRS SUB DISTRIBUTJON-UNATTEN 12.47 2.40
18 STANSBURY SUB DISTRIBUTION-UNATTEN 46.00 12.47
19 SUMMIT CREEK SUB DISTRIBUTION-UNATTEN 138.00 12.47
20 SUMMIT PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
21 SUNRISE SUB DISTRIBUTION-UNATTEN 138.00 12.47
22 SUPERIOR SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 SUTHERLAND SUB DISTRIBUTION-UNATTEN 46.00 12.47
24 TAMARISK SUB DISTRIBUTION-UNATTEN 138.00 12.47
25 TAYLOR SUB DISTRIBUTION-UNATTEN 46.00 12.47
26 THIEF CREEK SUB DISTRIBUTION-UNATTEN 138.00 24.90
27 THIRD WEST SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 THIRTEENTH SOUTH SUB DISTRIBUTION-UNATTEN 46.00 12.47
29 THOMPSON SUB DISTRIBUTION-UNATTEN 46.00 4.16
30 1 TOOELE DEPOT SUB DISTRIBUTION-UNATTEN 46.00 12.50
31 TOQUERVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47 34.50
32 UINTAH SUB DISTRIBUTION-UNATTEN 46.00 12.47
33 UNION SUB DISTRIBUTION-UNATTEN 46.00 12.47
34 UNIVERSITY SUB DISTRIBUTION-UNATTEN 46.00 7.20 12.50
35 VALLEY CENTER SUB DISTRIBUTION-UNATTEN 46.00 12.47
36 VERMILLION SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 VERNAL SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 VEYO HYDRO DISTRIBUTION-UNATTEN 34.50 2.40
39 VICKERS SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 VINEYARD SUB DISTRIBUTION-UNATTEN 46.00 12.47
FERC FORM NO. 1 (ED. 12-96) Page 426.16
Name of Respondent
PacifiCorp
This Re ort Is:
AOn
(2) E]A Resubmission
Date of Report
.Da,) 1 06/28/2012
Year/Period of Report
End of 201 1/Q4
SUBSTATIONS (Continued)
5.Show in columns (I), O) and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(I)
Number of Units
(j)
Total Capacity
(k)
2 1 1
40 1 2
40 2 3
5 1
60 2 5
12 1 6
60 2
20 2 8
60 2
25 1 10
30 1 11
22 1
22 2 13
6 1 14
4 1
4 1
2 1
20 1 18
14 1
7 1 20
60 2 21
8 1 22
6 1 23
20 1 24
14 1 25
14 1 26
40 2 27
24 2 28
2 1 29
25 1
34 2 31
39 2 32
50 2
29 2 34
22 1 35
3 1 36
33 2 37
2 3 38
2 1
25 1 5
FERC FORM NO. 1 (ED. 12-96) Page 427.16
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 WALLSBURG SUB DISTRIBUTION-UNATTEN 138.00 12.47
2 WALNUT GROVE SUB DISTRIBUTION-UNATTEN 138.00 12.50
3 WARREN SUB DISTRIBUTION-UNATTEN 138.00 12.47
4 WASATCH STATE PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
5 WASHAKIE SUB DISTRIBUTION-UNATTEN 138.00 4.16
6 WELBY SUB DISTRIBUTION-UNATTEN 46.00 12.47
7 WELFARE SUB DISTRIBUTION-UNATTEN 46.00 12.47
8 WEST COMMERCIAL SUB DISTRIBUTION-UNATTEN 46.00 12.47
9 WEST JORDAN SUB DISTRIBUTION-UNATTEN 138.00 12.47
10 WEST OGDEN SUB DISTRIBUTION-UNATTEN 138.00 12.47
11 WEST ROY SUB DISTRIBUTION-UNATTEN 46.00 12.47
12 WEST TEMPLE SUB DISTRIBUTION-UNATTEN 46.00 4.16
13 WESTWATER SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 WHITE MESA SUB DISTRIBUTION-UNATTEN 69.00 12.47
15 WHITE ROCK SUB DISTRIBUTION-UNATTEN 138.00 12.47
16 WILLOWCREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 WILLOWRIDGE SUB DISTRIBUTION-UNATTEN 46.00 12.47
18 WINCHESTER HILLS SUB DISTRIBUTION-UNATTEN 34.50 12.47
19 WINKLEMAN SUB DISTRIBUTION-UNATTEN 46.00 7.20
20 WOLF CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
21 WOOD CROSS SUB DISTRIBUTION-UNATTEN 46.00 12.47
22 WOODRUFF SUB DISTRIBUTION-UNATTEN 46.00 12.47
23 Total 19709.77 3606.26 117.97
24 Number of Substations-288
25
26 90TH SOUTH SUB T/D-UNATTENDED 345.00 138.00 12.47
27 ANGEL SUB T/D-UNATTENDED 138.00 12.47 46.00
28 BDO SUBSTATION T/D-UNATTENDED 138.00 12.47
29 BUTLERVILLE SUB T/D-UNATTENDED 138.00 46.00 12.47
30 CENTENNIAL SUB T/D-UNATTENDED 138.00 12.47
31 COTTONWOOD SUB T/D-UNATTENDED 138.00 12.47 46.00
32 DECADE SUB T/D-UNATTENDED 138.00 12.50
33 DUMAS SUB T/D-UNATTENDED 138.00 12.47
34 EMMA PARK SUBSTATION T/D-UNATTENDED 138.00 12.47
35 GROW SUB T/D-UNATTENDED 138.00 12.47 46.00
36 HALE SUB T/D-UNATTENDED 138.00 46.00 12.47
37 HIGHLAND SUB T/D-UNATTENDED 138.00 12.47 46.00
38 JORDAN SUB lID-UNATTENDED 138.00 46.00 12.47
39 JUDGE SUB TID-UNATTENDED 46.00 12.47
40 MCCLELLAND SUB TID-UNATTENDED 138.00 46.00 12.47
FERC FORM NO. I (ED. 12-96) Page 426.17
Name of Respondent
PacifiCorp
This Report Is:
AResubrnission
Pate of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
12 1 1
30 1 2
30 1 3
2 3
14 1
42 2 6
5 1
22 1 8
28 1
60 2 10
25 1
60 3
5 1
14 1 14
30 1 15
1 1
14 1 17
4 1 18
1 -
6 1 20
20 1
2 1
5441 400 1
24
25
1571 5 1 26
135 3
30 1 28
205 4
40 2
289 7 31
60 2
60 2
8 1
72 3
114 2 36
97 2
164 2
22 1
340 3 40
FERC FORM NO. I (ED. 12-96) Page 427.17
Name of Respondent
PacifiCo
This Re ort Is:
(1)LjAn Original
(2)EKIA Resubmission
Data of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
N 0.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(C)
Secondary
(d)
Tertiary
(e)
1 MORTON COURT SUB T/D-UNATTENDED 138.00 12.47
2 OQUIRRH SUB T/D-UNATTENDED 345.00 46.00 138.00
3 PARRISH SUB T/D-UNATTENDED 138.00 12.47 46.00
4 PIONEER PLANT T/D-UNATTENDED 138.00 2.30 46.00
5 RIVERDALE SUB T/D-UNATTENDED 138.00 46.00 12.47
6 1 SEVIER SUB T/D-UNATTENDED 138.00 46.00 12.47
7 SILVER CREEK SUB T/D-UNATTENDED 138.00 12.47 46.00
8 SOUTHEAST SUB T/D-UNATTENDED 138.00 12.47 46.00
9 SPHINX SUB T/D-UNATTENDED 46.00 12.47
10 SYRACUSE SUB T/D-UNATTENDED 345.00 46.00 138.00
11 TAYLORSVILLE SUB T/D-UNATTENDED 138.00 46.00 12.47
12 TERMINAL SUB T/D-UNATTENDED 345.00 46.00 138.00
13 TIMP SUB T/D-UNATTENDED 138.00 46.00 12.47
14 TOOELE SUB T/D-UNATTENDED 138.00 46.00 12.47
15 TRI CITY SUB T/D-UNATTENDED 138.00 12.47
16 WEST VALLEY SUB l/D-UNATTENDED 138.00 12.47
17 WESTFIELD SUB T/D-UNATTENDED 138.00 12.47
18 Total 5060.00 916.79 906.70
19 Number of Substations-32
20
21 EMERY SUB TRANSMISSION-ATTENDE 345.00 138.00 69.00
22 GADSBY SUB TRANSMISSION-ATTENDE 138.00 46.00
23 HUNTER PLANT TRANSMISSION-ATTENDE 345.00 23.00
24 HUNTINGTON PLANT TRANSMISSION-ATTENDE 345.00 23.00
25 ABAJO SUB TRANSMISSION-UNATTEN 138.00 69.00
26 ASHLEY SUB TRANSMISSION-UNATTEN 138.00 46.00
27 BARNEY SUB TRANSMISSION-UNATTEN 138.00 46.00
28 BEN LOMOND SUB TRANSMISSION-UNATTEN 345.00 230.00 138.00
29 BLACKHAWK SUB TRANSMISSION-UNATTEN 138.00 69.00 46.00
30 BOOKCLIFFS SUB TRANSMISSION-UNATTEN 69.00 46.00
31 CAMERON SUB TRANSMISSION-UNATTEN 138.00 46.00
32 CAMP WILLIAMS SUB TRANSMISSION-UNATTEN 345.00 138.00 12.47
33 CARBON SUB TRANSMISSION-UNATTEN 138.00
34 COLUMBIA SUB TRANSMISSION-UNATTEN 138.00 46.00 12.47
35 CRANER FLAT SUB TRANSMISSION-UNATTEN 138.00 12.47
36 CUTLER SUB TRANSMISSION-UNATTEN 138.00 46.00
37 EL MONTE SUB TRANSMISSION-UNATTEN 138.00 46.00
38 GARKANE SUB TRANSMISSION-UNATTEN 69.00 46.00
39 GREEN CANYON SUB TRANSMISSION-UNATTEN 138.00 46.00
40 GRINDING SUB TRANSMISSION-UNATTEN 138.00 13.80
FERC FORM NO. 1 (ED. 12-96) Page 426.18
Name of Respondent
PacifiCorp
This Re oil Is:
2SSO E nd
Date of Report Year/Period of Report
of 2011/Q4
SUBSTATIONS (Continued)
5.Show in columns (I), U) and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
Number of
Transformers
In Service
Number of
Spare
Transformers
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No. Type of Equipment Number of Units Total Capacity
65 2 1
135 3 2
97 2
51 7
180 3
34 4 6
100 2 7
50 2 8
3 1 3
600 5 10
358 4
1108 6 2 12 1
130 2 13
159 3
30 1 15
30 1 16
20 1 17
6357 89 6 18
19
20
783 13 1 21
318 2 22
1513 5 1 23
981 4 24
67 1 25
133 2 26
100 1 27 1
1813 5
100 2
6 3 1
25 4
169 2
8 1
71 2
40 2 35
70 2 36
312 3
33 1
67 2 39
225 3 40
FERC FORM NO. I (ED. 12-96) Page 427.18
Name of Respondent
ad I orp
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
N°. Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(C)
Secondary
(d)
Tertiary
(e)
1 HELPER SUB TRANSMISSION-UNATTEN 138.00 46.00
2 HONEYVILLE SUB TRANSMISSION-UNATTEN 138.00 46.00
3 HORSESHOE SUB TRANSMISSION-UNATTEN 138.00 46.00 12.47
4 HUNTINGTON SUB TRANSMISSION-UNATTEN 345.00 138.00
5 JERUSALEM SUB TRANSMISSION-UNATTEN 138.00 46.00
6 LAMPO SUB TRANSMISSION-UNATTEN 138.00 46.00
7 MCFADDEN SUB TRANSMISSION-UNATTEN 138.00 46.00
8 MIDDLETON SUB TRANSMISSION-UNATTEN 138.00 69.00 34.50
9 MIDVALLEY SUB TRANSMISSION-UNATTEN 345.00 138.00
10 MIDWAY CITY SUB TRANSMISSION-UNATTEN 138.00 46.00
11 MINERAL PRODUCTS SUB TRANSMISSION-UNATTEN 69.00 46.00
12 MOAB SUB TRANSMISSION-UNATTEN 138.00 69.00
13 NEBO SUB TRANSMISSION-UNATTEN 138.00 46.00
14 OLMSTED SUB TRANSMISSION-UNATTEN 46.00 2.40
15 PAROWAN VALLEY SUB TRANSMISSION-UNATTEN 230.00 138.00 34.50
16 PAVANT SUB TRANSMISSION-UNATTEN 230.00 46.00
17 PINTO SUB TRANSMISSION-UNATTEN 345.00 138.00 69.00
18 RED BUTTE SUB TRANSMISSION-UNATTEN 230.00 138.00
19 SAND COVE HYDRO TRANSMISSION-UNATTEN 34.50 2.40
20 SIGURD SUB TRANSMISSION-UNATTEN 345.00 230.00 138.00
21 SMITHFIELD SUB TRANSMISSION-UNATTEN 138.00 46.00 12.47
22 SPANISH FORK SUB TRANSMISSION-UNATTEN 345.00 138.00 46.00
23 ST GEORGE SUB TRANSMISSION-UNATTEN 138.00 16.50
24 THREE PEAKS SUB TRANSMISSION-UNATTEN 345.00 138.00
25 WEBER PLANT/SUB TRANSMISSION-UNATTEN 46.00 2.30
26 WEST CEDAR SUB TRANSMISSION-UNATTEN 230.00 138.00 34.50
27 Total 8498.50 3177.87 659.38
28 Number of Substations-46
29
30 WASHINGTON
31 ATTALIA SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 BOWMAN SUB DISTRIBUTION-UNATTEN 69.00 12.47
33 CASCADE KRAFT SUB DISTRIBUTION-IJNATTEN 69.00 12.47 4.16
34 CLINTON SUB DISTRIBUTION-UNATTEN 115.00 12.47
35 DAYTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 DODD ROAD SUB DISTRIBUTION-UNATTEN 69.00 20.80
37 GRANDVIEW SUB DISTRIBUTION-UNATTEN 115.00 12.47 69.00
38 HOPLAND SUB DISTRIBUTION-UNATTEN 115.00 12.47
39 NACHES HYDRO DISTRIBUTION-UNATTEN 115.00 12.47
40 NOB HILL SUB DISTRIBUTION-UNATTEN 115.00 12.47
FERC FORM NO. 1 (ED. 12-96) Page 426.19
Name of Respondent
PacifiCorp
This Re ort Is:
IKjARubssion
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
SUBSTATIONS (Continued)
5.Show in columns (I), O) and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6.Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
TIrnforTers
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line No.
-
Type of Equipment
(i)
Number of Units
U)
Total Capacity
(k)
142 2 1
35 1 2
80 2
270 4
67 1 5
75 1 6
45 1
141 4 8
900 2
67 1 10
12 1
67 1 12
67 1 13
15 1 14
138 2
133 2
258 3 17 1
400 1 18
1
1124 6 20
63 2 21
1017 5 22 1
100 3 1 23
450 1 24
7 1
262 .3
12769 113 4
28
29
30
25 1 31
45 2
117 6 33 1
25 1
23 2
25 4
42 2
50 2 38
20 1
42 2 40
FERC FORM NO. I (ED. 12-96) Page 427.19
Name of Respondent
T I orp aci C
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06128/2012
Year/Period of Report
End of 2011/Q4
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
N O
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 NORTH PARK SUB DISTRIBUTION-UNATTEN 115.00 12.47
2 ORCHARD SUB DISTRIBUTION-UNATTEN 115.00 12.47
3 PACIFIC SUB DISTRIBUTION-UNATTEN 115.00 12.47
4 POMEROY SUB DISTRIBUTION-UNATTEN 69.00 12.47
5 PROSPECT POINT SUB DISTRIBUTION-UNATTEN 69.00 12.47
6 PUNKIN CENTER SUB DISTRIBUTION-UNATTEN 115.00 12.47
7 RIVER ROAD SUB DISTRIBUTION-UNATTEN 115.00 12.47
8 SELAH SUB DISTRIBUTION-UNATTEN 115.00 12.47
9 SULPHUR CREEK SUB DISTRIBUTION-UNATTEN 115.00 12.47
10 SUNNYSIDE SUB DISTRIBUTION-UNATTEN 115.00 12.47
11 TIETON SUB DISTRIBUTION-UNATTEN 115.00 12.47 34.50
12 TOPPENISH SUB DISTRIBUTION-UNATTEN 115.00 12.47
13 TOUCHET SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 VOELKER SUB DISTRIBUTION-UNATTEN 115.00 12.47
15 WAITSBURG SUB DISTRIBUTION-UNATTEN 69.00 12.47
16 WAPATO SUB DISTRIBUTION-UNATTEN 115.00 12.47
17 WENAS SUB DISTRIBUTION-UNATTEN 115.00 12.47
18 WHITE SWAN SUB DISTRIBUTION-UNATTEN 115.00 12.47
19 WILEY SUB DISTRIBUTION-UNATTEN 115.00 12.47
20 Total 2921.00 369.96 107.66
21 Number of Substations-29
22
23 CENTRAL SUB T/D-UNATTENDED 69.00 12.47
24 MILL CREEK SUB l/D-UNATTENDED 69.00 12.47
25 UNION GAP SUB l/D-UNATTENDED 230.00 115.00 12.47
26 Total 368.00 139.94 12.47
27 Number of Substations-3
28
29 CONDIT PLANT TRANSMISSION-ATTENDE 69.00 2.30
30 MERWIN HYDRO PLANT TRANSMISSION-ATTENDE 115.00 13.20
31 YALE PLANT TRANSMISSION-ATTENDE 115.00 13.80
32 OUTLOOK SUB TRANSMISSION-UNATTEN 230.00 115.00
33 PASCO SUB TRANSMISSION-UNATTEN 115.00 69.00 7.20
34 POMONA HEIGHTS SUB TRANSMISSION-UNATTEN 230.00 115.00
35 WALLA WALLA 230KV SUB TRANSMISSION-UNAITEN 230.00 69.00
36 WALLULA SUB TRANSMISSION-UNAITEN 230.00 69.00
37 WINE COUNTRY SUB TRANSMISSION-UNATTEN 230.00 115.00
38 Total 1564.00 581.30 7.20
39 Number of Substations-9
40
FERC FORM NO. I (ED. 12-96) Page 426.20
Name of Respondent
PacifiCorp
This Re ort Is:
AResubmussion
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
45 2 1
50 2 2
28 3 3
9 1 4
40 2
20 2 6
51 4
45 2 8
25 1 9
45 2 10
29 2 11
50 2
6 1
25 1 14
10 1 15
45 2 16
25 2 17
22 2 18
45 2 19
1029 59 20
21
22
14 1 23
45 2 24
348 5 25
407 8
27
28
13 6 1
183 9 1 30
143 3 1 31
125 1 32
39 9 33
300 2
300 2 35
120 2
250 1
1473 35 3 38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.20
Name of Respondent
T I orp acC
This Report Is:
(1)EAn Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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
No.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
I WYOMING
2 ANTELOPE MINE SUB DISTRIBUTION-UNATTEN 230.00 34.50
3 ASTLE STREET DISTRIBUTION-UNATTEN 34.50 13.20
4 BAILEY DOME SUB DISTRIBUTION-UNATTEN 57.00 12.47
5 BAR X SUB DISTRIBUTION-UNATTEN 230.00 34.50
6 BIG MUDDY SUB DISTRIBUTION-UNATTEN 69.00 12.47
7 BIG PINEY SUB DISTRIBUTION-UNATTEN 69.00 24.90
8 BLACKS FORK SUB DISTRIBUTION-UNATTEN 230.00 34.50
9 BRIDGER PUMP SUB DISTRIBUTION-UNATTEN 230.00 34.50 13.20
10 BRYAN SUB DISTRIBUTION-UNATTEN 115.00 12.47
11 BUFFALO TOWN SUB DISTRIBUTION-UNATTEN 20.80 4.16
12 BYRON SUB DISTRIBUTION-UNATTEN 34.50 4.16
13 CASSA SUB DISTRIBUTION-UNATTEN 57.00 20.80 12.47
14 CENTER STREET SUB DISTRIBUTION-UNATTEN 115.00 4.16
15 CHAPMAN SUBSTATION DISTRIBUTION-UNATTEN 46.00 12.47
16 1 CHUKAR SUB DISTRIBUTION-UNATTEN 12.47 4.16
17 CHURCH AND DWIGHT SUB DISTRIBUTION-UNATTEN 34.50 0.48
18 COKEVILLE SUB DISTRIBUTION-UNATTEN 46.00 24.90
19 COLUMBIA-GENEVA SUB DISTRIBUTION-UNATTEN 230.00 13.80
20 COMMUNITY PARK SUB DISTRIBUTION-UNATTEN 115.00 13.20
21 CROOKS GAP SUB DISTRIBUTION-UNATTEN 34.50 12.47
22 DEER CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 DJ COAL MINE SUB - DISTRIBUTION-UNATTEN 69.00 34.50
24 DOUGLAS SUB DISTRIBUTION-UNATTEN 57.00 2.30
25 DRY FORK SUB DISTRIBUTION-UNATTEN 69.00 4.16
26 ELK BASIN SUB DISTRIBUTION-UNATTEN 34.50 7.20
27 EMIGRANT SUB DISTRIBUTION-UNATTEN 115.00 12.47
28 EVANS SUB DISTRIBUTION-UNATTEN 115.00 12.47
29 EVANSTON SUB DISTRIBUTION-UNATTEN 138.00 12.47
30 FORT CASPER SUB DISTRIBUTION-UNATTEN 69.00 12.47
31 FORT SANDERS SUB DISTRIBUTION-UNATTEN 115.00 13.20
32 FRANNIE SUB DISTRIBUTION-UNATTEN 230.00 34.50
33 FRONTIER SUB DISTRIBUTION-UNATTEN 69.00 4.16
34 GARLAND SUB DISTRIBUTION-UNATTEN 230.00 34.50
35 GLENDO SUB DISTRIBUTION-UNATTEN 57.00 4.16
36 GRASS CREEK SUB DISTRIBUTION-UNATTEN 230.00 34.50
37 GREAT DIVIDE SUB DISTRIBUTION-UNATTEN 115.00 34.50
38 GREYBULL SUB DISTRIBUTION-UNATTEN 34.50 4.16
39 HANNA SUB DISTRIBUTION-UNATTEN 34.50 12.47
40 JACKALOPE SUB DISTRIBUTION-UNATTEN 115.00 12.47
FERC FORM NO. 1 (ED. 12-96) Page 426.21
Name of Respondent
PacifiCorp
This Re ort Is:
EJARssion
Date of Report Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
25 1 2
13 1 3
2 1
25 1 5
7 1 6
8 1
150 2 8
73 4 9
25 1 10
2 3
2 3
2 6 1
13 1 14
4 1
1 3
3 2
4 1
45 2
50 2 20
5 3
9 1 -
13 1 23
6 3
9 1
5 1
13 1
9 1
40 2 29
25 1
20 1
50 2
6 1
45 2
3 4 35
25 1
20 1
3 1
6 1 39
25 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.21
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4.Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
N °.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(C)
Secondary
(d)
Tertiary
(e)
I KEMMERER SUB DISTRIBUTION-UNATTEN 69.00 24.90
2 KIRBY CREEK PUMPING STATION DISTRIBUTION-UNATTEN 34.50 2.40
3 KIRBY CREEK SUB DISTRIBUTION-UNATTEN 34.50 4.16
4 LANDER SUB DISTRIBUTION-UNATTEN 34.50 12.47
5 LARAMIE SUB DISTRIBUTION-UNATTEN 115.00 13.20
6 LATHAM SUB DISTRIBUTION-UNATTEN 230.00 34.50
7 LINCH SUB DISTRIBUTION-UNATTEN 69.00 13.80
8 LITTLE MOUNTAIN SUB DISTRIBUTION-UNATTEN 230.00 34.50
9 LOVELL SUB DISTRIBUTION-UNATTEN 34.50 4.16
10 MILL IRON SUB DISTRIBUTION-UNATTEN 34.50 13.80
11 MILLS SUB DISTRIBUTION-UNATTEN 12.47 4.16
12 MURPHY DOME SUB DISTRIBUTION-UNATTEN 34.50 13.20
13 NUGGETT SUB DISTRIBUTION-UNATTEN 69.00 7.20
14 OPAL SUB DISTRIBUTION-UNATTEN 69.00 24.90
15 ORIN SUB DISTRIBUTION-UNATTEN 57.00 12.47
16 ORPHA SUB DISTRIBUTION-UNATTEN 57.00 7.20
17 PARADISE SUB DISTRIBUTION-UNATTEN 69.00 25.00
18 PARCO SUB DISTRIBUTION-UNATTEN 34.50 12.47
19 PINEDALE SUB DISTRIBUTION-UNATTEN 69.00 24.90
20 PITCHFORK SUB DISTRIBUTION-UNATTEN 69.00 24.90
21 POISON SPIDER SUB DISTRIBUTION-UNATTEN 69.00 2.40
22 POLECAT SUB DISTRIBUTION-UNATTEN 34.50 12.47
23 RAINBOW SUB DISTRIBUTION-UNATTEN 34.50 13.20
24 RAVEN SUB DISTRIBUTION-UNATTEN 230.00 34.50
25 RED BUTTE SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 REFINERY SUB DISTRIBUTION-UNATTEN 115.00 12.47
27 SAGE HILL SUB DISTRIBUTION-UNATTEN 34.50 13.20
28 SHOSHONI SUB DISTRIBUTION-UNATTEN 34.50 2.40
29 SLATE CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
30 SOUTH CODY SUB DISTRIBUTION-UNATTEN 69.00 24.90
31 SOUTH ELK BASIN SUB DISTRIBUTION-UNATTEN 34.50 4.16
32 SOUTH TRONA SUB DISTRIBUTION-UNATTEN 230.00 34.50
33 SPRING CREEK SUB DISTRIBUTION-UNATTEN 115.00 13.20
34 SVILAR SUB DISTRIBUTION-UNATTEN 34.50 4.16
35 TEN MILE STEP DOWN SUB DISTRIBUTION-UNATTEN 34.50 12.50
36 TEN MILE SUB DISTRIBUTION-UNATTEN 69.00 34.50
37 THERMOPOLIS TOWN SUB DISTRIBUTION-UNATTEN 34.50 4.16
38 THUNDERCREEKSUB DISTRIBUTION-UNATTEN 57.00 12.47
39 VETERANS SUB DISTRIBUTION-UNATTEN 34.50 13.20
40 WELCH SUB DISTRIBUTION-UNATTEN 57.00 2.40
FERC FORM NO. I (ED. 12.96) Page 42622
Name of Respondent
PacifiCorp
This Re ort Is:
2't'ssion
Date of Report Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
U)
Total Capacity
(k)
10 1 1
3 3 2
1 3
25 2 4
50 2
25 1 6
12 1 7
20 1 8
4 1
12 1 1 10
1 3
5 1
1 -
7 1
1 3
3 3
30 1 17
5 1 -
7 1
17 9 2
3 1
1 3
12 1
200 2 24
20 1 25
45 2
6 1 27
1 3
1 1 29
14 3 1 30
2 6
150 2
25 1
2 3
5 1 -
12 1
5 1 -
9 1
25 2
2 3
FERC FORM NO. 1 (ED. 12-96) Page 427.22
Name of Respondent
PacifiCo
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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
N 0.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(C)
Secondary
(d)
Tertiary
(e)
1 WERTZ-SINCLAIR SUB DISTRIBUTION-UNATTEN 57.00 4.16 12.50
2 WEST ADAMS SUB DISTRIBUTION-UNATTEN 34.50 4.16
3 WESTVACO SUB DISTRIBUTION-UNATTEN 230.00 34.50
4 WORLAND TOWN SUB DISTRIBUTION-UNATTEN 34.50 4.16
5 WYOPO SUB DISTRIBUTION-UNATTEN 230.00 34.50
6 WYUTA SUB DISTRIBUTION-UNATTEN 46.00 12.47
7 Total 7493.24 1311.37 38.17
8 Number of Substations-85
9
10 BUFFALO SUB T/D-UNATTENDED 230.00 20.80
11 ELK HORN SUB T/D-UNATTENDED 115.00 12.50
12 FIREHOLE SUB T/D-UNATTENDED 230.00 34.50
13 HILLTOP SUB T/D-UNATTENDED 115.00 34.50 20.80
14 LABARGE SUB T/D-UNATTENDED 69.00 24.90
15 POINT OF ROCKS SUB T/D-UNATTENDED 230.00 34.50
16 RIVERTON 230 SUB T/D-UNATTENDED 230.00 12.47 34.50
17 YELLOWCAKE SUB T/D-UNATTENDED 230.00 34.50
18 Total 1449.00 208.67 55.30
19 Number of Substations-8
20
21 TRANSMISSION-ATTENDE 230.00 115.00 69.00
22 TRANSMISSION-ATTENDE 345.00 230.00 34.50
23 [JIM BRIDGER UNITS 1-4 [TRANSMISSION-ATTENDE 345.00 22.00
24 1 NAUGHTON SUB TRANSMISSION-ATTENDE 230.00 69.00 138.00
25 TRANSMISSION-ATTENDE 230.00 69.00
26 WYODAK PLANT TRANSMISSION-ATTENDE 230.00 22.00
27 BAIROIL SUB TRANSMISSION-UNATTEN 115.00 34.50 57.00
28 CASPER SUB TRANSMISSION-UNATTEN 230.00 115.00 13.20
29 CHAPPELL CREEK SUB TRANSMISSION-UNATTEN 230.00 69.00
30 CHIMNEY BUTTE SUB TRANSMISSION-UNATTEN 230.00 69.00
31 FOOTE CREEK WIND FARM TRANSMISSION-UNATTEN 230.00 34.50
32 GLENDO AUTO SUB TRANSMISSION-UNATTEN 69.00 57.00
33 MANSFACE SUB TRANSMISSION-UNATTEN 230.00 34.50
34 MIDWEST SUB TRANSMISSION-UNATTEN 230.00 69.00 34.50
35 MINERS SUB TRANSMISSION-UNATTEN 230.00 115.00 34.50
36 MUSTANG SUB TRANSMISSION-UNATTEN 230.00 115.00
37 OREGON BASIN SUB TRANSMISSION-UNATTEN 230.00 34.50 69.00
38 PLATTE SUB TRANSMISSION-UNATTEN 230.00 115.00 34.50
39 RAILROAD SUB TRANSMISSION-UNATTEN 230.00 138.00
40 ROCK SPRINGS 230 SUB TRANSMISSION-UNATTEN 230.00 34.50
FERC FORM NO. I (ED. 12-96) Page 426.23
Name of Respondent
PacifiCorp
This Re ort Is:
(2) E]A Resubmission
Date of Report
Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
2 6 1
3 1 2
25 1
5 1 4
20 1 1
1 -
1624 157 6
8
9
20 1 10
25 1 11
50 2 12
45 2 1 13
7 6
25 1 15
75 4 16
25 1 17
272 18 1 18
19
20
1358 16 21
1084 22 22
1122 2 23
1232 15 1 24
230 3 25
503 3 1
53 3 27
517 5 28
67 1 29
75 1 30
196 2 31
15 2 32
20 1 33
90 4 34
58 4 1
200 2 36
65 2
140 3 38
400 1 39
50 2 40
FERC FORM NO. I (ED. 12-96) Page 427.23
Name of Respondent
PacifiCorp
This Re ort Is:
AResubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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
N 0.
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 SAGE SUB TRANSMISSION-UNATTEN 69.00 46.00
2 THERMOPOLIS SUB TRANSMISSION-UNATTEN 230.00 115.00
3 Total 4853.00 1722.50 484.20
4 Number of Substations-22
5
6 CALIFORNIA
7 Distribution -43
8 T/D-3
9 Transmission - 9
10
11 IDAHO
12 j Distribution -65
13 T/D-5
14 Transmission - 18
15
16 MONTANA
17 Transmission - 1
18
19 OREGON
20 Distribution-182
21 T/D-11
22 Transmission - 42
23
24 UTAH
25 Distribution -288
26 T/D-32
27 Fransmission -46
28
29 WASHINGTON
30 Distribution -29
31 T/D-3
32 Transmission -9
33
34 WYOMING
35 Distribution - 85
36 T/D-8
37 Transmission - 22
38
39
40
FERC FORM NO. I (ED. 12-96) Page 426.24
Name of Respondent
PaciflCorp
This Re ort Is:
OA
Date of Report Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Number of Capacity of Substation
(In Service) (In MVa)
(f)
Transformers
In Service
(9)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
22 1 1
175 2 2
7672 97 3
4
5
6
324
130 8
805
10
11
723
374 13
3504
15
16
100
18
19
4541
1262
6645
23
24
5441
6357
12769
28
29
1029
407
1473
33
34
1624
272
7672
38
39
40
FERC FORM NO. I (ED. 12-96) Page 427.24
Name of Respondent
PacifiCorp
This Re ort Is:
2'::ssion
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 ALL STATES
2 Distribution -692
3 T/D-62
4 Transmission -147
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 426.25
Name of Respondent
PacifiCorp
This Re ort Is:
KIAResubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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 party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(In Service) (In MVa)
(0
Number of
Transformers
In Service
(9)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
13682 2
8802
32968
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.25
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original (Mo, Da, Yr)
PaciliCorp (2) X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
Schedule Page: 426.9 Line No.: 26 Column: a
The Dixonville 500kv Substation is jointly owned by the respondent and Bonneville Power
Administration (°BPA"). Ownership of the substation is as follows: PacifiCorp 50.0% and
BPA 50.0%. Operation and maintenance costs are shared between the two parties and
responsibility is as follows: PacifiCorp 58.0% and EPA 42.0%.
Schedule Page: 426.9 Line No.: 38 Column: a
The Meridian 500kv Substation is jointly owned by the respondent and BPA. Ownership of the
substation is as follows: PacifiCorp 50.0% and BPA 50.0%. Operation and maintenance costs
are shared between the two parties and responsibility is as follows: PacifiCorp 58.0% and
BPA 42.0%.
ISchedule Page: 426.23 Line No.: 21 Column: a
The Dave Johnston 230kv Substation is jointly owned by the respondent and Black Hills
Power. Ownership of the substation is as follows: PacifiCorp 85.0% and Black Hills Power
15.0%. Operation and maintenance costs are shared between the two parties based on a fixed
amount derived as a factor of the percentage owned of the original installed substation.
ISchedule Page: 426.23 Line No.: 22 Column: a
The Jim Bridger 345kv Substation is jointly owned by the respondent and Idaho Power
Company. Ownership of the substation is as follows: PacifiCorp 66.7% and Idaho Power
Company 33.3%. Operation and maintenance costs are shared between the two parties and
responsibility is as follows: PacifiCorp 66.7% and Idaho Power Company 33.3%.
Schedule Page: 426.23 Line No.: 25 Column: a
The Wyodak 230kv Substation is jointly owned by the respondent and Black Hills Power.
Ownership of the substation is as follows: PacifiCorp 80.0% and Black Hills Power 20.0%.
Operation and maintenance costs are shared between the two parties and responsibility is
as follows: PacifiCorp 80.0% and Black Hills Power 20.0%.
(FERC FORM NO. I (ED. 12-87) Page 450.1 1
Name of Respondent
PacifiCorp
This Re ort Is:
(2) MA Resubmission
Date of Report
06/28/2012
Year/Period of Report
End of 2011/Q4
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 (affiliated) companies.
2.The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to
an associated/affiliated 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 billed to or received from the associated(affiliated) company are based on an allocation process, explain in a footnote.
Line
No.
-
Description of the Non-Power Good or Service
(a)
Name of
Associated/Affiliated
Company
(b)
Account
Charged or
Credited
(c)
Amount
Charged or
Credited
(d)
1
2
Non-power Goods or Services Provided by Affiliated
Coal purchases I support services / materials and
3 supplies Bndger Coal Company 151, 501, 553
4
Coal mining services Energy West Mining Company 151
6
7 Coal purchases Trapper Mining Inc. 151 14,778,879
8
g Administrative support services Interwest Mining Company 230, 426.5, 55
10
11
12
13
-
MHC, Inc.
I
146,426.5,930.2
I
730,726
14 Charges over cost cap - retained by MEHC MEHC 146 -62,823
15
16
171 1
18
20
21
Non-power Goods or Services Provided for Affiliate
Information technology & royalties Bridger Coal Company l 146
23 Financial and administrative support services Interwest Mining Company 14€
24
25 Information technology support services Energy West Mining Company 146 337,787
26
27
28 Information technology support and insurance and
29 risk management services MEC 146 862,267
30
31 Legal, resource and construction development
32 1 and information technology support services MEHC 146
33
34
35
36
37 -
38
39
40
41
42
1
2
Non-power Goods or Services Provided by Affiliated
FERC FORM NO. I (New) Page 429
FERC FORM NO. 1-F (New)
Name of Respondent
PacifiCorp
This Re ort Is:
(1)An Original
(2)KA Resubmission
Date of Report
(Mo, Da, Yr)
06/28/2012
Year/Period of Report
End of 2011/Q4
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
1.Report below the information called for conceming all non-power goods or services received from or provided to associated (affiliated) companies.
2.The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to
an associated/affiliated 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 billed to or received from the associated(affiliated) company are based on an allocation process, explain in a footnote.
Line
No.
-
Description of the Non-Power Good or Service
(a)
Name of
Associated/Affiliated
Company
(b)
Account
Charged or
Credited
(c)
Amount
Charged or
Credited
(d)
3
4 Gas transportation services 501,547 3,212,163
5
6 Relocation services 2,490,590
7
8 MEHC Insurance Svcs. 924,925 1,536,178
9
10 Installation of radio equipment Racom Corporation 981,255
11
Financial transactions related to energy hedging
13 activity and banking services Wells Fargo & Company 47,748,748
14
15 Rail services / right-of-way fees BNSF Railway Company 151,507,567,589
16
17 Installation of transmission cable Marmon Utility LLC 509,231
18
19
20
21
Non-power Goods or Services Provided for Affiliate
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
1
2
Non-power Goods or Services Provided by Affiliated
1 Computer hardware and software and computer
3 systems consulting and maintenance services International Business Machines 903, 923, 935 315,951
4
FERC FORM NO. I (New) Page 429.1
FERC FORM NO. 1-F (New)
Name of Respondent
PacifiCorp
This Re ort Is:
(2) VIA Resubmission
Date of Report Year/Period of Report
End of 2011/Q4
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 (affiliated) companies.
2.The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to
an associated/affiliated 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 billed to or received from the associated(affiliated) company are based on an allocation process, explain in a footnote.
Line
No.
-
Description of the Non-Power Good or Service
(a)
Name of
Associated/Affiliated
Company
(b)
Account
Charged or
Credited
(c)
Amount
Charged or
Credited
(d)
5 Rating agency fees Moody's Investors Service 921 306,137
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Non-power Goods or Services Provided for Affiliate
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. I (New) Page 429.2
FERC FORM NO. I-F (New)
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)_An Original 1 (2)
(Mo, Da, Yr)
PacifiCorp X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
ISchedule Page: 429 Line No.: 3 Column: d
Non-power goods or services provided by Bridger Coal Company are as follows:
Coal purchases $ 129,772,184
Support services/materials and supplies 37,164
$ 129,809,348
ISchedule Page: 429 Line No.: 5 Column: d
Under the terms of the coal mining agreement between PacifiCorp and Energy West Mining
Company, Energy West Mining Company provides coal mining services to PacifiCorp that are
absorbed directly by PacifiCorp.
Schedule Page: 429 Line No.: 9 Column: d
Interwest Mining Company manages PacifiCorp's mining operations and charges management
services to Pacific Minerals, Inc., Eridger Coal Company, Energy West Mining Company and
Fossil Rock Fuels, LLC. Interest Mining Company also charges PacifiCorp for administrative
support services. All costs incurred by Interwest Mining Company are absorbed by
PacifiCorp, Pacific Minerals, Inc., Bridger Coal Company, Energy West Mining Company and
Fossil Rock Fuels, LLC.
Schedule Page: 429 Line No.: 11 Column: a
The amounts in column (d) were the amounts billed by MEHC and its affiliates to PacifiCorp
under the Intercompany Administrative Services Agreement. The fee was capped at $2,250,000
through March 20, 2011. Amounts in excess of the cap have been included on lines 12 and 13
and adjusted out on line 14. A portion of the services provided by MEHC and its affiliates
were billed 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 through December 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.
Processes: This allocator distributes costs of electronic data interchange software and
services based on the process count within each platform using such software or services.
Legislative and Regulatory: used to allocate costs incurred by the holding company's
legislative & regulatory groups. The legislative & regulatory groups work on a variety of
legislative and regulatory subject matter for a 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 spent
on these selected companies.
Plant: This allocator distributes costs of managing the corporate insurance function based
on assets for each platform.
Schedule Page: 429 Line No.: 11 Column: b I
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "MEHC" ON PAGE 429: Complete name is
MidAmerican Energy Holdings Company.
Schedule Page: 429 Line No.: 11 Column: c I
Accounts charged for MEHC: 107, 165, 426.4, 426.5, 921, 924, 925, 928, 930.2.
ISchedule Page: 429 Line No.: 11 Column: d
Included on this line are "convenience" payments made to vendors by one entity on behalf
of, and charged to, other entities within the MEHC group. These convenience payments
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)X A Resubmission 06/28/2012 2011/04
FOOTNOTE DATA
primarily consist of software license costs. Such affiliate charges reflect the ability to
obtain price discounts as a result of larger purchasing power.
Convenience payments made by MEHC on behalf of PacifiCorp during the year ended December
31, 2011 were $1,740,504.
Excluded from this line are reimbursements by MEHC for payments made by PacifiCorp to its
employees under a long-term incentive plan ("LTIP") maintained by MEHC and annual
incentive payments associated with transferred employees. Amounts charged to PacifiCorp
for LTIP awards granted to PacifiCorp employees are included in the MEHC affiliate
services amount included on page 429, line 11.
The convenience payments, the LTIP reimbursements and the annual incentive payments
associated with transferred employees do not constitute "services" as required by this
page.
Schedule Page: 429 Line No.: 12 Column: b
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "MEC" ON PAGE 429: Complete name is
MidAmerican Energy Company.
Schedule Page: 429 Line No.: 12 Column: c
Accounts charged for MEC: 107, 143, 146, 165, 426.4, 426.5, 921, 928, 929, 930.2.
Schedule Page: 429 Line No.: 12 Column: d
Included on this line are "convenience" payments made to vendors by one entity on behalf
of, and charged to, other entities within the MEHC group. These convenience payments
primarily consist of software license costs. Such affiliate charges reflect the ability to
obtain price discounts as a result of larger purchasing power.
Convenience payments made by MEC on behalf of PacifiCorp during the year ended December
31, 2011 were $359,713.
The convenience payments do not constitute "services" as required by this page.
Schedule Page: 429 Line No.: 21 Column: d
Non-power goods or services provided to Bridger Coal Company are as follows:
Information technology $ 420,803
Royalties 126,915
$ 547,718
Schedule Page: 429 Line No.: 23 Column: d
PacifiCorp provides Interwest Mining Company with financial and administrative support and
technical services. These costs are charged to Interwest Mining Company and are included
in the management services that Interwest Mining Company provides to Pacific Minerals,
Inc., Bridger Coal Company, Energy West Mining Company and Fossil Rock Fuels, LLC.
Schedule Page: 429 Line No.: 32 Column: d
A portion of the services provided to MEHC and its affiliates were billed based on the
following allocation factors:
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 through December 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.
Information Technology Infrastructure: - Allocates costs related to shared information
technology infrastructure owned by the affiliate to other benefited affiliates based on an
aggregation of various measures of usage of such infrastructure including storage capacity
IFERC FORM NO. I (ED. 12-87) Page 450.2 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
PacifiCorp (2)X A Resubmission 06/28/2012 2011/Q4
FOOTNOTE DATA
utilized, number of servers utilized, server processing times, etc.
Schedule Page: 429.1 Line No.: 4 Column: b
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "KERN RIVER GAS" ON PAGE 429: Complete name is
Kern River Gas Transmission Company.
Schedule Page: 429.1 Line No.: 6 Column: b
THIS FOOTNOTE APPLIES TO ALL OCCURRENCES OF "HomeServices" ON PAGE 429: Complete name is
HomeServices of America, Inc.
Schedule Page: 429.1 Line No.: 6 Column: c
Accounts charged for HomeServices: 501, 506, 514, 535, 539, 548, 549, 553, 556, 557, 560,
561.2, 580, 581, 588, 590, 593, 595, 597, 901, 902, 903, 908, 921, 935 and clearing
accounts.
Schedule Page: 429.1 Line No.: 8 Column: a
MEHC Insurance Services Ltd. provided certain insurance coverage under a policy that
expired March 20, 2011 and that will not be renewed. Proceeds from claims were $16 million
durino 2011.
Schedule Page: 429.1 Line No.: 10 Column: c
Accounts charged for Racom Corporation: 500, 506, 511, 513, 514, 545, 588, 593.
Schedule Page: 429.1 Line No.: 13 Column: c
Accounts charged for Wells Fargo & Company: 501, 547, 557, 588, 903, 921, 181, 228.3, 419,
427.
Schedule Page: 429.1 Line No.: 15 Column: d
Non-power goods or services provided by BNSF Railway Company are as follows:
Rail services $ 33,223,956
Right-of-way fees 25,963
$ 33,249,919
Included in the rail services are amounts related to a jointly-owned plant that are paid
indirectly to BNSF Railway Company.
Schedule Page: 429.1 Line No.: 17 Column: c I
Accounts charged for Marmon Utility LLC: 107, 154, 236, 571, 590, 593.
IFERC FORM NO. I (ED. 12-87) Page 450.3 1
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
utilityplant ....................................................................................219
utility plant (summary) ......................................................................200-201
Advances
fromassociated companies ....................................................................256-257
Allowances.......................................................................................228-229
Amortization
miscellaneous....................................................................................340
ofnuclear fuel ..............................................................................202-203
Appropriations of Retained Earnings ..............................................................118-119
Associated Companies
advancesfrom ................................................................................256-257
corporations controlled by respondent ............................................................103
controlover respondent ..........................................................................102
interest on debt to ..........................................................................256-257
Attestation............................................................................................i
Balance sheet
comparative...................................................................................110-113
notesto ... ................................................................................ 122-123
Bonds............................................................................................256-257
CapitalStock ........................................................................................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
overrespondent ..................................................................................102
Corporation
controlledby ....................................................................................103
incorporated ..................................................................................... 101
CPA, background information on .......................................................................101
CPACertification, this report form .................................................................i-u
FERC FORM NO. I (ED. 12-93) Index I
INDEX (continued)
Schedule Pacie No.
Deferred
credits, other ................................................................................... 269
debits, miscellaneous ............................................................................. 233
income taxes accumulated - accelerated
amortization property ........................................................................ 272-273
income taxes accumulated - other property .................................................... 274-275
income taxes accumulated - other ............................................................. 276-277
income taxes accumulated - pollution control facilities .......................................... 234
Definitions, this report form ........................................................................ iii
Depreciation and amortization
ofcommon utility plant .......................................................................... 356
ofelectric plant ................................................................................ 219
336-337
Directors............................................................................................ 105
Discount - premium on long-term debt ............................................................. 256-257
Distributionof salaries and wages ................................................... ............ 354-355
Dividend appropriations .......................................................................... 118-119
Earnings, Retained ............................................................................... 118-119
Electric energy account ............................................................................... 401
Expenses
electric operation and maintenance ........................................................... 320-323
electricoperation and maintenance, summary ...................................................... 323
unamortizeddebt ................................................................................. 256
Extraordinary property losses ......................................................................... 230
Filing requirements, this report form
Generalinformation .................................................................................. 101
Instructions for filing the FERC Form 1 ............................................................. i-iv
Generating plant statistics
hydroelectric (large) ........................................................................ 406-407
pumped storage (large) ....................................................................... 408-409
smallplants ................................................................................. 410-411
steam-electric (large) ........................................................................ 402-403
Hydro-electric generating plant statistics ....................................................... 406-407
Identification....................................................................................... 101
Important changes during year .................................................................... 108109
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
Incorporationinformation ............................................................................ 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
nonutilityproperty .............................................................................. 221
subsidiary companies ......................................................................... 224-225
Investment tax credits, accumulated deferred ..................................................... 266-267
Law, excerpts applicable to this report form .......................................................... iv
Listof schedules, this report form .................................................................. 2-4
Long-term debt ................................................................................... 256-257
Losses-Extraordinary property ........................................................................ 230
Materialsand supplies ............................................................................... 227
Miscellaneousgeneral 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
Nonutilityproperty .................................................................................. 221
Nuclear fuel materials ........................................................................... 202-203
Nuclear generating plant, statistics ............................................................. 402-403
Officersand 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
capitalstock ....................................................................................253
miscellaneous paid-in capital ....................................................................253
reduction in par or stated value of capital stock .................................................253
regulatory assets ................................................................................232
regulatoryliabilities ...........................................................................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
heldfor future use ..............................................................................356
inservice .......................................................................................356
leasedto others .................................................................................356
Plantdata ...................................................................................336-337
401-429
FERC FORM NO. I (ED. 12-95) Index 3
INDEX (continued)
Schedule Page No.
Plant - electric
accumulated provision for depreciation ........................................................... 219
construction work in progress .................................................................... 216
heldfor future use .............................................................................. 214
inservice .................................................................................... 204-207
leasedto others ................................................................................. 213
Plant - utility and accumulated provisions for depreciation
amortization and depletion (summary) ............................................................. 201
Pollution control facilities, accumulated deferred
incometaxes ..................................................................................... 234
PowerExchanges .................................................................................. 326-327
Premium and discount on long-term debt ............................................................... 256
Premiumon capital stock ............................................................................. 251
Prepaidtaxes .................................................................................... 262-263
Property - losses, extraordinary ...................................................................... 230
Pumped storage generating plant statistics ....................................................... 408-409
Purchased power (including power exchanges) ...................................................... 326-327
Reacquired capital stock ............................................................................. 250
Reacquiredlong -term debt ........................................................................ 256-257
Receiverscertificates .......................................................................... 256-257
Reconciliation of reported net income with taxable income
from Federal income taxes ...................................................................... 261
Regulatorycommission expenses deferred .............................................................. 233
Regulatory commission expenses for year .......................................................... 350-351
Research, development and demonstration activities ............................................... 352-353
Retained Earnings
amortizatioi reserve Federal ..................................................................... 119
appropriated................................................................................. 118-119
statement of, for the year ................................................................... 118-119
unappropriated............................................................................... 118-119
Revenues - electric operating .................................................................... 300-301
Salaries and wages
directorsfees ................................................................................... 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
Statementof Cash Flows .......................................................................... 120-121
Statement of income for the year ................................................................. 114-117
Statement of retained earnings for the year ...................................................... 118-119
Steam-electric generating plant statistics ....................................................... 402-403
Substations.......................................................................................... 426
Supplies - materials and .............................................................................227
FERC FORM NO. 1 (ED. 12-90) Index 4
INDEX (continued)
Schedule Page No.
Taxes
accruedand prepaid .........................................................................262-263
chargedduring year .........................................................................262-263
onincome, deferred and accumulated .............................................................234
272-277
reconciliation of net income with taxable income for ............................................261
Transformers, line - electric ........................................................................429
Transmission
linesadded during year ......................................................................424-425
lines statistics ............................................................................422-423
of electricity for others ...................................................................328-330
of electricity by others ........................................................................332
Unamortized
debtdiscount ...............................................................................256-257
debtexpense ...... . .......................................................................... 256-257
premium on debt ...............................................................................256-257
Unrecovered Plant and Regulatory Study Costs ........................................................230
FERC FORM NO. 1 (ED. 12-90) Index 5