2012Annual Report.pdf

ROCKY MOUNTAIN
POWER
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201 South Main, Suite 2300
Salt Lake City, Utah 84111&i{ 9' 38
May 31,2013
VA OVERNIGHT DELIWRY
Idaho Public Utilities Commission
472West 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 I report for the year ended December 31,2012.
PacifiCorp respectfully requests that all data requests regarding this matter be addressed to:
By email (preferred): [e-mail]
By regular mail:Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR97232
Please direct any informal questions to Ted Weston, Regulatory Manager, at [phone].
Sincerely,
9r//%-tlH,,^-7r*
Jeffrey K. Larsen
Vice President, Regulation & Government Affairs
Enclosure
THIS FILING IS
Item 1:An Initial (Original)OR Resubmission No.
Submission
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Form 1 Approved
0MB No.1902-0021
(Expires 12/31/2014)
Form 1-F Approved
0MB No.1902-0029
(Expires 12/31/2014)
Form 3-Q Approved
0MB 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
m FERC FORM No.113-Q (REV.02-04)
INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q
GENERAL INFORMATION
I. Purpose
FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others
(18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q)is a quarterly regulatory requirement which supplements the
annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and
operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy
Regulatory Commission. These reports are also considered to be non-confidential public use forms.
II. Who Must Submit
Each Major electric 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.gov/docs-filing/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 1 & 3-Q (ED. 03-07) i
The CPA Certification Statement should:
a) Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the
Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the
Chief Accountant's published accounting releases), and

b) Be signed by independent certified public accountants or an independent licensed public accountant
certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18
C.F.R. §§ 41.10-41.12 for specific qualifications.)
Reference Schedules Pages
Comparative Balance Sheet 110-113
Statement of Income 114-117
Statement of Retained Earnings 118-119
Statement of Cash Flows 120-121
Notes to Financial Statements 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 http://www.ferc.gov/help/how-to.asp.
(g) Federal, State and Local Governments and other authorized users may obtain additional blank copies of
FERC Form 1 and 3-Q free of charge from http://www.ferc.gov/docs-filing/eforms/form-1/form-1.pdf and
http://www.ferc.gov/docs-filing/eforms.asp#3Q-gas .
IV. When to Submit:

FERC Forms 1 and 3-Q must be filed by the following schedule:
FERC FORM 1 & 3-Q (ED. 03-07) ii
a) FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1),
and
b) FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. §
141.400).
V. Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,144
hours per response, including the time for reviewing instructions, searching existing data sources, gathering and
maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for
the FERC Form 3-Q collection of information is estimated to average 150 hours per response.
Send comments regarding these burden estimates or any aspect of these collections of information,
including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs,
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 1 & 3-Q (ED. 03-07) iii
GENERAL INSTRUCTIONS
I. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret
all accounting words and phrases in accordance with the USofA.
II. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and
figures per unit where cents are 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.
DEFINITIONS
I. Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or
any other Commission. Name the commission whose authorization was obtained and give date of the authorization.
II. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose
behalf the report is made.
FERC FORM 1 & 3-Q (ED. 03-07) v
EXCERPTS FROM THE LAW
Federal Power Act, 16 U.S.C. § 791a-825r
Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:
(3) ’Corporation' means any corporation, joint-stock company, partnership, association, business trust,
organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the
foregoing. It shall not include 'municipalities, as hereinafter defined;
(4) 'Person' means an individual or a corporation;
(5) 'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act,
and any assignee or successor in interest thereof;
(7) 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or
agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or
distributing power; ......
(11) "project' means. a complete unit of improvement or development, consisting of a power house, all water
conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit,
and all storage, diverting, or fore bay reservoirs 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 1 & 3-Q (ED. 03-07) vi
"Sec. 309. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind
such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among
other things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may
prescribe the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the
Commission, the information which they shall contain, and the time within which they shall be field..."
General Penalties
The Commission may assess up to $1 million per day per violation of its rules and regulations. See
FPA § 316(a) (2005), 16 U.S.C. § 825o(a).
FERC FORM 1 & 3-Q (ED. 03-07) vii
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LIST OF SCHEDULES (Electric Utility)
PacifiCorp X
/ /
2012/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
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".
101General Information 1
102Control Over Respondent 2
103Corporations Controlled by Respondent 3
104Officers 4
105Directors 5
106(a)(b)Information on Formula Rates 6
108-109Important Changes During the Year 7
110-113Comparative Balance Sheet 8
114-117Statement of Income for the Year 9
118-119Statement of Retained Earnings for the Year 10
120-121Statement of Cash Flows 11
122-123Notes to Financial Statements 12
122(a)(b)Statement of Accum Comp Income, Comp Income, and Hedging Activities 13
200-201Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 14
N/A202-203Nuclear Fuel Materials 15
204-207Electric Plant in Service 16
N/A213Electric Plant Leased to Others 17
214Electric Plant Held for Future Use 18
216Construction Work in Progress-Electric 19
219Accumulated Provision for Depreciation of Electric Utility Plant 20
224-225Investment of Subsidiary Companies 21
227Materials and Supplies 22
228(ab)-229(ab)Allowances 23
N/A230Extraordinary Property Losses 24
230Unrecovered Plant and Regulatory Study Costs 25
231Transmission Service and Generation Interconnection Study Costs 26
232Other Regulatory Assets 27
233Miscellaneous Deferred Debits 28
234Accumulated Deferred Income Taxes 29
250-251Capital Stock 30
253Other Paid-in Capital 31
254Capital Stock Expense 32
256-257Long-Term Debt 33
261Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 34
262-263Taxes Accrued, Prepaid and Charged During the Year 35
266-267Accumulated Deferred Investment Tax Credits 36
FERC FORM NO. 1 (ED. 12-96) Page 2
LIST OF SCHEDULES (Electric Utility) (continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /
2012/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
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".
269Other Deferred Credits 37
272-273Accumulated Deferred Income Taxes-Accelerated Amortization Property 38
274-275Accumulated Deferred Income Taxes-Other Property 39
276-277Accumulated Deferred Income Taxes-Other 40
278Other Regulatory Liabilities 41
300-301Electric Operating Revenues 42
N/A302Regional Transmission Service Revenues (Account 457.1) 43
304Sales of Electricity by Rate Schedules 44
310-311Sales for Resale 45
320-323Electric Operation and Maintenance Expenses 46
326-327Purchased Power 47
328-330Transmission of Electricity for Others 48
N/A331Transmission of Electricity by ISO/RTOs 49
332Transmission of Electricity by Others 50
335Miscellaneous General Expenses-Electric 51
336-337Depreciation and Amortization of Electric Plant 52
350-351Regulatory Commission Expenses 53
352-353Research, Development and Demonstration Activities 54
354-355Distribution of Salaries and Wages 55
N/A356Common Utility Plant and Expenses 56
397Amounts included in ISO/RTO Settlement Statements 57
398Purchase and Sale of Ancillary Services 58
400Monthly Transmission System Peak Load 59
N/A400aMonthly ISO/RTO Transmission System Peak Load 60
401Electric Energy Account 61
401Monthly Peaks and Output 62
402-403Steam Electric Generating Plant Statistics 63
406-407Hydroelectric Generating Plant Statistics 64
N/A408-409Pumped Storage Generating Plant Statistics 65
410-411Generating Plant Statistics Pages 66
FERC FORM NO. 1 (ED. 12-96) Page 3
LIST OF SCHEDULES (Electric Utility) (continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /
2012/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
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".
422-423Transmission Line Statistics Pages 67
424-425Transmission Lines Added During the Year 68
426-427Substations 69
429Transactions with Associated (Affiliated) Companies 70
450Footnote Data 71
Stockholders' Reports Check appropriate box:
X Two copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO. 1 (ED. 12-96) Page 4
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
GENERAL INFORMATION
PacifiCorp X
/ /2012/Q4
Douglas K. Stuver, Senior Vice President and Chief Financial Officer
825 N.E. Multnomah, Suite 1900
Portland, OR 97232
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.
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.
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
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) NoX
Not applicable.
PacifiCorp is a United States regulated, vertically integrated electric utility company serving 1.8
million retail customers, including residential, commercial, industrial, irrigation 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 name PacifiCorp Energy.
FERC FORM No.1 (ED. 12-87) PAGE 101
Schedule Page: 101 Line No.: 1 Column: Item 2
PacifiCorp was initially incorporated in 1910 under the laws of the state of Maine under
the name Pacific Power & Light Company. In 1984, Pacific Power & Light Company changed its
name to PacifiCorp. In 1989, it merged with Utah Power and Light Company, a Utah
corporation, in a transaction wherein both corporations merged into a newly formed Oregon
corporation. The resulting Oregon corporation was re-named PacifiCorp, which is the
operating entity today.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
CONTROL OVER RESPONDENT
PacifiCorp X
/ /2012/Q4
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 ("MEHC") (100%)
PPW Holdings LLC (100% controlled by MEHC)
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.
Page 102FERC FORM NO. 1 (ED. 12-96)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CORPORATIONS CONTROLLED BY RESPONDENT
PacifiCorp X
/ /
2012/Q4
Line
No.
Name of Company Controlled Kind of Business Percent Voting
Stock Owned(c)(b)(a)
Footnote
Ref.(d)
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.
Mining 100 1 Centralia Mining Company
Mining 100 2 Energy West Mining Company
Mining 100 3 Fossil Rock Fuels, LLC
Mining 100 4 Glenrock Coal Company
Management Services 100 5 Interwest Mining Company
Management Services 100 6 Pacific Minerals, Inc.
Mining 66.67 7 Bridger Coal Company
Environmental Services 100 8 PacifiCorp Environmental Remediation Company
Management Services 100 9 PacifiCorp Investment Management, Inc.
Mining 21.40 10 Trapper Mining Inc.
Non-profit foundation 11 PacifiCorp Foundation
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO. 1 (ED. 12-96) Page 103
Schedule Page: 103 Line No.: 1 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.: 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.
Schedule Page: 103 Line No.: 7 Column: a
Bridger Coal Company is a coal mining joint venture with Idaho Energy Resources Company, a
subsidiary of Idaho Power Company, and is jointly controlled by Pacific Minerals, Inc. and
Idaho Energy Resources Company.
Schedule Page: 103 Line No.: 8 Column: a
Effective July 1, 2012, PacifiCorp Environmental Remediation Company ("PERCo"), a wholly
owned subsidiary of PacifiCorp, was dissolved, and all assets and liabilities of PERCo
were assumed by PacifiCorp.
Schedule Page: 103 Line No.: 9 Column: a
PacifiCorp Investment Management, Inc. ("PIMI") previously performed management services
for PERCo. Effective July 1, 2012, PIMI was dissolved.
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OFFICERS
PacifiCorp X
/ /
2012/Q4
Line
No.
Title Name of Officer Salaryfor Year(c)(b)(a)
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.
Executive Officers as of December 31, 2012: 1
Chairman of the Board of Directors 2
and Chief Executive Officer Gregory E. Abel 3
Senior Vice President and Chief Financial Officer 244,055Douglas K. Stuver 4
President and Chief Executive Officer, 5
Rocky Mountain Power 368,000A. Richard Walje 6
President and Chief Executive Officer, Pacific Power 300,000R. Patrick Reiten 7
President and Chief Executive Officer, PacifiCorp Energy 300,000Micheal G. Dunn 8
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FERC FORM NO. 1 (ED. 12-96) Page 104
Schedule Page: 104 Line No.: 1 Column: a
PacifiCorp sets forth the salary information for its "named executive officers" for the
year ended December 31, 2012, 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, 2012 (File No.
001-14881) for executive compensation information for Mr. Abel.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DIRECTORS
PacifiCorp X
/ /
2012/Q4
Line Name (and Title) of Director Principal Business Address(b)(a)No.
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.
PacifiCorp Board of Directors as of December 31, 2012: 1
Gregory E. Abel 2
666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309(Chairman of the Board of Directors and CEO, PacifiCorp) 3
R. Patrick Reiten 4
825 NE Multnomah, Suite 2000, Portland, Oregon 97232(President and CEO, Pacific Power) 5
A. Richard Walje 6
201 South Main, Suite 2300, Salt Lake City, Utah 84111(President and CEO, Rocky Mountain Power) 7
666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309Douglas L. Anderson 8
825 NE Multnomah, Suite 2000, Portland, Oregon 97232Brent E. Gale 9
666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309Patrick J. Goodman 10
Micheal G. Dunn 11
1407 West North Temple, Suite 320, Salt Lake City, Utah 84116(President and CEO, PacifiCorp Energy) 12
Mark C. Moench 13
201 South Main, Suite 2400, Salt Lake City, Utah 84111(SVP, General Counsel and Corporate Secretary, PacifiCorp) 14
Natalie L. Hocken 15
825 NE Multnomah, Suite 1600, Portland, Oregon 97232(SVP, Transmission and System Operations, PacifiCorp) 16
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FERC FORM NO. 1 (ED. 12-95) Page 105
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
INFORMATION ON FORMULA RATES
PacifiCorp X
/ /2012/Q4
Line
No.FERC Rate Schedule or Tariff Number FERC Proceeding
Does the respondent have formula rates?Yes
No
X
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.
FERC Rate Schedule/Tariff Number FERC Proceeding
ER11-3643FERC Electric Tariff Volume No. 11, Attachment H-1 1
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FERC FORM NO. 1 (NEW. 12-08) Page 106
Schedule Page: 106 Line No.: 1 Column: a
As a result of a 2007 multi-party settlement with the Federal Energy Regulatory Commission
("FERC") regarding long-term shared usage, coordinated operation and maintenance, and
planning of certain 500-kV 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 to adopt a
formula transmission rate. In August 2011, the FERC issued an order accepting PacifiCorp's
filing and allowing the proposed rates to become effective December 25, 2011, subject to
refund. Billing using the new rates commenced in early 2012. The FERC established
settlement proceedings to encourage the parties to reach agreement on final rates. In
February 2013, agreement with the parties was reached and PacifiCorp filed a settlement
agreement with the FERC resolving all issues in the transmission rate case. The settlement
agreement is subject to FERC approval and includes modifications to the formula used to
determine transmission rates. The FERC approved interim rates for real power loss factors
and certain ancillary services effective March 1, 2013 and for a new reactive power
service rate to be effective May 1, 2013. The transmission rates will continue to be
updated every June according to the formula rate process.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.\ Filed DateAccession No.
Date
Docket No. Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
INFORMATION ON FORMULA RATES
Does the respondent file with the Commission annual (or more frequent)Yes
No
X
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
FERC Rate Schedule/Tariff Number FERC Proceeding
filings containing the inputs to the formula rate(s)?
Document
05/31/201220120531-5390 ER11-3643 1
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FERC FORM NO. 1 (NEW. 12-08) Page 106a
Schedule Page: 1061 Line No.: 1 Column: d
Informational Filing of 2012 Transmission Formula Rate Annual Update
Schedule Page: 1061 Line No.: 1 Column: e
PacifiCorp's Volume No. 11 Open Access Transmission Tariff
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.Page No(s). Schedule Column Line No
INFORMATION ON FORMULA RATES
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
Formula Rate Variances
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.
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FERC FORM NO. 1 (NEW. 12-08) Page 106b
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report Year/Period of Report
End of
IMPORTANT CHANGES DURING THE QUARTER/YEAR
PacifiCorp X / /2012/Q4
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
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.
FERC FORM NO. 1 (ED. 12-96) Page 108
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)
Dubois 03/15/2012 03/15/2047 10.0%
Bloomington 05/29/2012 05/29/2042 10.0%
Downey 06/01/2012 06/01/2042 -
Malad 08/13/2012 08/13/2032 -
Oregon (3)
Echo 02/13/2012 02/13/2037 3.5%
Stanfield 03/26/2012 03/26/2032 5.5%
Independence 04/16/2012 04/16/2022 7.0%
Medford 06/21/2012 06/21/2022 7.0%
Redmond 07/12/2012 07/12/2017 7.0%
Aumsville 08/13/2012 08/13/2022 7.0%
Mill City 09/12/2012 09/12/2032 5.0%
Utah (2)
Woodruff 01/18/2012 01/18/2022 6.0%
Randolph 01/18/2012 01/18/2022 5.0%
Vernal 01/26/2012 01/26/2032 6.0%
Laketown 02/16/2012 02/16/2032 -
Garden City 02/27/2012 02/27/2027 -
Alta 03/12/2012 03/12/2017 4.0%
Weber County 03/20/2012 03/20/2022 -
Scofield 12/05/2012 12/05/2037 -
Washington (2)
Benton County 03/09/2012 02/28/2022 -
Moxee 07/31/2012 07/31/2032 6.0%
Wyoming (4)
LaBarge 11/09/2012 11/09/2037 1.0%
(1) In California, franchise agreement fees are an expense to PacifiCorp and are embedded in rates.
(2) In Idaho, Utah and Washington, PacifiCorp collects franchise agreement fees or associated taxes 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 PacifiCorp and is embedded in rates. Any amount above the 3.5% is collected from
customers and remitted directly to the applicable municipalities.
(4) In Wyoming, the first 1.0% of the franchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 1.0% is collected
from customers and remitted directly to the applicable municipalities.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.1
ITEM 2.
None.
ITEM 3.
In February 2012, the Federal Energy Regulatory Commission ("FERC") in Docket No. AC12-7-000 approved the journal entries
required by the Uniform System of Accounts ("USofA") for the sale of the Snake Creek hydroelectric generating facility to Heber
Light & Power Company. Accordingly, PacifiCorp 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 PacifiCorp’s annual
report on Form No. 1 for the year ended December 31, 2011.
In October 2012, PacifiCorp received approval from the FERC in Docket No. EC12-136-000, pursuant to Section 203 of the Federal
Power Act, for the acquisition from Brigham City Corporation ("Brigham") of certain 138-kilovolt electric transmission facilities at
Brigham’s East Substation in Utah and accompanying rights and property. In November 2012, the purchase was recorded in account
102, Electric plant purchased or sold, and PacifiCorp filed for approval with the FERC the journal entries required by the USofA. In
March 2013, the FERC in Docket No. AC13-18-000 approved the journal entries for the acquisition. Accordingly, PacifiCorp cleared
account 102, Electric plant purchased or sold, and recorded the purchase to the appropriate accounts.
In December 2012, PacifiCorp entered into an agreement for the sale of the St. Anthony hydroelectric generating facility with St.
Anthony Hydro LLC, which is subject to regulatory approvals by the FERC, the Idaho Public Utilities Commission ("IPUC") and the
Wyoming Public Service Commission. Also in December 2012, PacifiCorp entered into a power purchase agreement with St.
Anthony Hydro LLC for all of the net output of the St. Anthony hydroelectric generating facility, which is to become effective after
the closing of the sale and approval by the IPUC.
ITEM 4.
In October 2012, PacifiCorp entered into an agreement with RBS Asset Finance, Inc. to lease the 2-megawatt Black Cap Solar
generating facility located near Lakeview, Oregon. The lease has a 16-year term from October 2012 to October 2028 and is accounted
for as an operating lease. Annual rent payments are $337,383. PacifiCorp also pays for certain executory costs. PacifiCorp received
the necessary FERC approval in Docket No. EC12-86-000, pursuant to Section 203 of the Federal Power Act.
ITEM 5.
During the year ended December 31, 2012, 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 no short-term debt outstanding as of
December 31, 2012. PacifiCorp had no outstanding borrowings under its unsecured revolving credit facilities as of December 31,
2012. For further discussion, refer to Note 6 of Notes to Financial Statements in this Form No. 1.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.2
Long-term Debt
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 March 2012, PacifiCorp issued an additional $100 million of its 2.95% First Mortgage Bonds
due February 1, 2022. The net proceeds were used to redeem $84 million of tax-exempt bond obligations prior to scheduled maturity
with a weighted average interest rate of 5.72%, to repay short-term debt and for general corporate purposes.
PacifiCorp currently has regulatory authority from the Oregon Public Utility Commission ("OPUC") and the IPUC 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. 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, 2010.
PacifiCorp made scheduled repayments on long-term debt totaling $17 million during the year ended December 31, 2012.
As of December 31, 2012, PacifiCorp 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, 2012 and expire periodically through November 2013.
For further discussion, refer to Note 6 of Notes to Financial Statements in this Form No. 1.
PacifiCorp'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 PacifiCorp may issue generally is also subject to a net earnings test. As of December 31,
2012, PacifiCorp estimated it would be able to issue up to $7.8 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.
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 2013, PacifiCorp declared and paid a dividend of $150 million to PPW Holdings LLC, a wholly owned subsidiary of
MidAmerican Energy Holdings Company and PacifiCorp’s direct parent company.
In 2012, PacifiCorp declared and paid dividends of $200 million to PPW Holdings LLC.
ITEM 7.
None.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.3
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) 1.87% 1/26/2012 $ 1,547,483
IBEW 57 Power Supply (UT, ID & WY) 1.85% 1/26/2012 720,115
IBEW 125 (OR, WA) 1.42% 1/26/2012 389,756
IBEW 659 (OR, CA) 1.30% 4/26/2012 449,430
IBEW 57 Combustion Turbine (UT) 1.05% 5/26/2012 24,025
UWUA 197 (OR) 1.20% 5/26/2012 21,075
IBEW 57 Laramie (WY) 0.77% 6/26/2012 4,618
UWUA 127 (WY) 0.53% 9/26/2012 230,184
Total $ 3,386,686
(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. Refer to Note 13 of Notes to Financial Statements in this Form No. 1 for information
regarding legal proceedings, including the USA Power litigation.
ITEM 10.
In July 2012, PacifiCorp Environmental Remediation Company ("PERCo"), a wholly owned subsidiary of PacifiCorp, was dissolved,
and all assets and liabilities of PERCo were assumed by PacifiCorp.
Refer to page 429, Transactions with Associated (Affiliated) Companies, in this Form No. 1 for information regarding related-party
transactions.
There have been no officer, director or security holder transactions during the year ended December 31, 2012 other than common
and preferred stock dividends declared.
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, 2012 filed with the United States Securities and Exchange Commission ("SEC").
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.4
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.
In September 2012, Natalie L. Hocken, director of PacifiCorp, accepted the position of Senior Vice President, Transmission and
System Operations of PacifiCorp. Ms. Hocken’s previous role was Vice President and General Counsel of Pacific Power. There was
no change in Ms. Hocken’s role as director of PacifiCorp.
ITEM 14.
Not applicable.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.5
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
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)
PacifiCorp / /2012/Q4
UTILITY PLANT 1
23,971,186,312 23,014,228,731200-201Utility Plant (101-106, 114) 2
1,250,513,185 1,203,547,965200-201Construction Work in Progress (107) 3
25,221,699,497 24,217,776,696TOTAL Utility Plant (Enter Total of lines 2 and 3) 4
8,018,360,420 7,666,665,056200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5
17,203,339,077 16,551,111,640Net Utility Plant (Enter Total of line 4 less 5) 6
0 0202-203Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 7
0 0Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 8
0 0Nuclear Fuel Assemblies in Reactor (120.3) 9
0 0Spent Nuclear Fuel (120.4) 10
0 0Nuclear Fuel Under Capital Leases (120.6) 11
0 0202-203(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 12
0 0Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 13
17,203,339,077 16,551,111,640Net Utility Plant (Enter Total of lines 6 and 13) 14
0 0Utility Plant Adjustments (116) 15
0 0Gas Stored Underground - Noncurrent (117) 16
OTHER PROPERTY AND INVESTMENTS 17
16,067,385 15,445,648Nonutility Property (121) 18
3,461,732 1,917,757(Less) Accum. Prov. for Depr. and Amort. (122) 19
69,928 69,928Investments in Associated Companies (123) 20
239,062,484 240,956,268224-225Investment in Subsidiary Companies (123.1) 21
(For Cost of Account 123.1, See Footnote Page 224, line 42) 22
0 0228-229Noncurrent Portion of Allowances 23
84,847,739 83,950,135Other Investments (124) 24
0 0Sinking Funds (125) 25
0 0Depreciation Fund (126) 26
0 0Amortization Fund - Federal (127) 27
19,796,604 6,137,779Other Special Funds (128) 28
0 0Special Funds (Non Major Only) (129) 29
1,367,457 4,472,312Long-Term Portion of Derivative Assets (175) 30
0 0Long-Term Portion of Derivative Assets – Hedges (176) 31
357,749,865 349,114,313TOTAL Other Property and Investments (Lines 18-21 and 23-31) 32
CURRENT AND ACCRUED ASSETS 33
0 0Cash and Working Funds (Non-major Only) (130) 34
23,522,354 14,846,926Cash (131) 35
139,866 774,146Special Deposits (132-134) 36
0 1,520Working Fund (135) 37
55,313,879 7,244,794Temporary Cash Investments (136) 38
102,892 238,519Notes Receivable (141) 39
388,339,929 373,179,154Customer Accounts Receivable (142) 40
49,311,318 59,610,652Other Accounts Receivable (143) 41
8,884,148 8,722,762(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42
0 13,897,305Notes Receivable from Associated Companies (145) 43
4,537,480 7,455,752Accounts Receivable from Assoc. Companies (146) 44
265,591,187 236,891,214227Fuel Stock (151) 45
0 0227Fuel Stock Expenses Undistributed (152) 46
0 0227Residuals (Elec) and Extracted Products (153) 47
202,524,644 196,564,767227Plant Materials and Operating Supplies (154) 48
0 0227Merchandise (155) 49
0 0227Other Materials and Supplies (156) 50
0 0202-203/227Nuclear Materials Held for Sale (157) 51
0 0228-229Allowances (158.1 and 158.2) 52
FERC FORM NO. 1 (REV. 12-03) Page 110
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
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)
PacifiCorp / /2012/Q4
(Continued)
0 0(Less) Noncurrent Portion of Allowances 53
0 0227Stores Expense Undistributed (163) 54
0 0Gas Stored Underground - Current (164.1) 55
0 0Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 56
45,371,059 113,503,388Prepayments (165) 57
0 0Advances for Gas (166-167) 58
16,988 26,887Interest and Dividends Receivable (171) 59
1,773,869 2,237,540Rents Receivable (172) 60
250,650,000 236,917,500Accrued Utility Revenues (173) 61
481,065 2,574,464Miscellaneous Current and Accrued Assets (174) 62
9,253,434 15,812,193Derivative Instrument Assets (175) 63
1,367,457 4,472,312(Less) Long-Term Portion of Derivative Instrument Assets (175) 64
0 0Derivative Instrument Assets - Hedges (176) 65
0 0(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 66
1,286,678,359 1,268,581,647Total Current and Accrued Assets (Lines 34 through 66) 67
DEFERRED DEBITS 68
34,752,802 33,449,341Unamortized Debt Expenses (181) 69
0 0230aExtraordinary Property Losses (182.1) 70
4,126,549 0230bUnrecovered Plant and Regulatory Study Costs (182.2) 71
1,821,244,610 1,874,535,671232Other Regulatory Assets (182.3) 72
4,377,278 3,115,357Prelim. Survey and Investigation Charges (Electric) (183) 73
0 0Preliminary Natural Gas Survey and Investigation Charges 183.1) 74
0 0Other Preliminary Survey and Investigation Charges (183.2) 75
0 0Clearing Accounts (184) 76
46,898 66,905Temporary Facilities (185) 77
86,782,863 88,864,233233Miscellaneous Deferred Debits (186) 78
0 0Def. Losses from Disposition of Utility Plt. (187) 79
0 0352-353Research, Devel. and Demonstration Expend. (188) 80
9,502,793 9,676,901Unamortized Loss on Reaquired Debt (189) 81
648,219,005 639,645,755234Accumulated Deferred Income Taxes (190) 82
0 0Unrecovered Purchased Gas Costs (191) 83
2,609,052,798 2,649,354,163Total Deferred Debits (lines 69 through 83) 84
21,456,820,099 20,818,161,763TOTAL ASSETS (lines 14-16, 32, 67, and 84) 85
FERC FORM NO. 1 (REV. 12-03) Page 111
Schedule Page: 110 Line No.: 57 Column: d
As of December 31, 2011, Account 165, Prepayments, included $67,080,728 of income taxes
receivable from MidAmerican Energy Holdings Company, PacifiCorp's indirect parent company.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Year/Period of ReportName of Respondent This Report is:
(1) An Original
(2) A Resubmission
x
Date of Report
(mo, da, yr)
end of
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)
PacifiCorp / /2012/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
PROPRIETARY CAPITAL 1
3,417,945,8963,417,945,896Common Stock Issued (201) 2 250-251
40,733,10040,733,100Preferred Stock Issued (204) 3 250-251
00Capital Stock Subscribed (202, 205) 4
00Stock Liability for Conversion (203, 206) 5
00Premium on Capital Stock (207) 6
1,102,229,9811,102,229,981Other Paid-In Capital (208-211) 7 253
00Installments Received on Capital Stock (212) 8 252
00(Less) Discount on Capital Stock (213) 9 254
41,284,56041,284,560(Less) Capital Stock Expense (214) 10 254b
2,649,231,2662,979,135,293Retained Earnings (215, 215.1, 216) 11 118-119
151,915,641157,299,053Unappropriated Undistributed Subsidiary Earnings (216.1) 12 118-119
00(Less) Reaquired Capital Stock (217) 13 250-251
00 Noncorporate Proprietorship (Non-major only) (218) 14
-9,055,432-12,003,821Accumulated Other Comprehensive Income (219) 15 122(a)(b)
7,311,715,8927,644,054,942Total Proprietary Capital (lines 2 through 15) 16
LONG-TERM DEBT 17
6,171,055,0006,820,029,000Bonds (221) 18 256-257
00(Less) Reaquired Bonds (222) 19 256-257
00Advances from Associated Companies (223) 20 256-257
00Other Long-Term Debt (224) 21 256-257
30,127102,179Unamortized Premium on Long-Term Debt (225) 22
14,072,30214,074,076(Less) Unamortized Discount on Long-Term Debt-Debit (226) 23
6,157,012,8256,806,057,103Total Long-Term Debt (lines 18 through 23) 24
OTHER NONCURRENT LIABILITIES 25
53,732,33148,633,502Obligations Under Capital Leases - Noncurrent (227) 26
00Accumulated Provision for Property Insurance (228.1) 27
5,468,00041,118,850Accumulated Provision for Injuries and Damages (228.2) 28
580,877,623621,638,182Accumulated Provision for Pensions and Benefits (228.3) 29
38,369,54038,367,730Accumulated Miscellaneous Operating Provisions (228.4) 30
06,578,797Accumulated Provision for Rate Refunds (229) 31
66,449,95426,416,841Long-Term Portion of Derivative Instrument Liabilities 32
00Long-Term Portion of Derivative Instrument Liabilities - Hedges 33
123,312,479127,418,688Asset Retirement Obligations (230) 34
868,209,927910,172,590Total Other Noncurrent Liabilities (lines 26 through 34) 35
CURRENT AND ACCRUED LIABILITIES 36
688,527,0000Notes Payable (231) 37
536,085,457440,465,394Accounts Payable (232) 38
011,109,978Notes Payable to Associated Companies (233) 39
56,292,85337,303,255Accounts Payable to Associated Companies (234) 40
36,226,19634,640,410Customer Deposits (235) 41
52,714,61687,443,808Taxes Accrued (236) 42 262-263
110,248,092114,528,244Interest Accrued (237) 43
512,462512,462Dividends Declared (238) 44
00Matured Long-Term Debt (239) 45
FERC FORM NO. 1 (rev. 12-03) Page 112
Year/Period of ReportName of Respondent This Report is:
(1) An Original
(2) A Resubmission
x
Date of Report
(mo, da, yr)
end of
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)
PacifiCorp / /2012/Q4
(continued)COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
00Matured Interest (240) 46
17,536,76217,617,882Tax Collections Payable (241) 47
78,951,24674,650,810Miscellaneous Current and Accrued Liabilities (242) 48
2,156,2016,482,626Obligations Under Capital Leases-Current (243) 49
156,054,86474,922,884Derivative Instrument Liabilities (244) 50
66,449,95426,416,841(Less) Long-Term Portion of Derivative Instrument Liabilities 51
00Derivative Instrument Liabilities - Hedges (245) 52
00(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 53
1,668,855,795873,260,912Total Current and Accrued Liabilities (lines 37 through 53) 54
DEFERRED CREDITS 55
25,692,15819,569,969Customer Advances for Construction (252) 56
38,010,26834,331,017Accumulated Deferred Investment Tax Credits (255) 57 266-267
00Deferred Gains from Disposition of Utility Plant (256) 58
220,954,063333,027,535Other Deferred Credits (253) 59 269
111,258,519102,737,542Other Regulatory Liabilities (254) 60 278
00Unamortized Gain on Reaquired Debt (257) 61
164,676,925208,722,047Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277
3,505,053,6513,796,825,280Accum. Deferred Income Taxes-Other Property (282) 63
746,721,740728,061,162Accum. Deferred Income Taxes-Other (283) 64
4,812,367,3245,223,274,552Total Deferred Credits (lines 56 through 64) 65
20,818,161,76321,456,820,099TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 66
FERC FORM NO. 1 (rev. 12-03) Page 113
Schedule Page: 112 Line No.: 42 Column: c
As of December 31, 2012, Account 236, Taxes accrued, included $55,318,498 of income taxes
payable to MidAmerican Energy Holdings Company, PacifiCorp's indirect parent company.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF INCOME
PacifiCorp X
/ /2012/Q4
Line
(c)(b)(a)
Title of Account
No.
Total
Current Year to
Date Balance for
Quarter/Year
(d)
(Ref.)
Page No.
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 (l) 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.
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
Total
Prior Year to
Date Balance for
Quarter/Year
UTILITY OPERATING INCOME 1
4,849,485,873 4,553,757,373300-301Operating Revenues (400) 2
Operating Expenses 3
2,512,486,745 2,304,873,210320-323Operation Expenses (401) 4
427,348,788 432,482,383320-323Maintenance Expenses (402) 5
571,953,425 544,830,198336-337Depreciation Expense (403) 6
336-337Depreciation Expense for Asset Retirement Costs (403.1) 7
44,350,044 42,204,359336-337Amort. & Depl. of Utility Plant (404-405) 8
5,523,970 5,523,970336-337Amort. of Utility Plant Acq. Adj. (406) 9
507,060 135,566Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10
Amort. of Conversion Expenses (407) 11
337,452 1,612,926Regulatory Debits (407.3) 12
380,507(Less) Regulatory Credits (407.4) 13
160,882,952 151,699,035262-263Taxes Other Than Income Taxes (408.1) 14
-106,857,967 -138,818,714262-263Income Taxes - Federal (409.1) 15
-785,331 -7,862,714262-263 - Other (409.1) 16
770,193,169 782,981,862234, 272-277Provision for Deferred Income Taxes (410.1) 17
419,882,524 424,304,774234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.1) 18
-1,851,300 -1,874,204266Investment Tax Credit Adj. - Net (411.4) 19
(Less) Gains from Disp. of Utility Plant (411.6) 20
Losses from Disp. of Utility Plant (411.7) 21
49,887 164,750(Less) Gains from Disposition of Allowances (411.8) 22
Losses from Disposition of Allowances (411.9) 23
7,758 14,646Accretion Expense (411.10) 24
3,964,164,354 3,692,952,492TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25
885,321,519 860,804,881Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 26
FERC FORM NO. 1/3-Q (REV. 02-04) Page 114
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF INCOME FOR THE YEAR (Continued)
PacifiCorp X
/ /2012/Q4
Line Previous Year to Date
(in dollars)
(k)(j)(g)
ELECTRIC UTILITY
No.Current Year to Date
(in dollars)
OTHER UTILITY
(l)
GAS UTILITY
Previous Year to Date
(in dollars)
Current Year to Date
(in dollars)
Previous Year to Date
(in dollars)
Current Year to Date
(in dollars)
(h) (i)
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.
1
4,849,485,873 4,553,757,373 2
3
2,512,486,745 2,304,873,210 4
427,348,788 432,482,383 5
571,953,425 544,830,198 6
7
44,350,044 42,204,359 8
5,523,970 5,523,970 9
507,060 135,566 10
11
337,452 1,612,926 12
380,507 13
160,882,952 151,699,035 14
-106,857,967 -138,818,714 15
-785,331 -7,862,714 16
770,193,169 782,981,862 17
419,882,524 424,304,774 18
-1,851,300 -1,874,204 19
20
21
49,887 164,750 22
23
7,758 14,646 24
3,964,164,354 3,692,952,492 25
885,321,519 860,804,881 26
FERC FORM NO. 1 (ED. 12-96) Page 115
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF INCOME FOR THE YEAR (continued)
PacifiCorp X
/ /2012/Q4
Line
Previous Year
(c)(b)(a)
Title of Account
No.
Current Year
TOTAL
(d)
(Ref.)
Page No.
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
885,321,519 860,804,881Net Utility Operating Income (Carried forward from page 114) 27
Other Income and Deductions 28
Other Income 29
Nonutilty Operating Income 30
3,143,641 1,731,641Revenues From Merchandising, Jobbing and Contract Work (415) 31
3,064,403 2,055,446(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32
651,778 43,686Revenues From Nonutility Operations (417) 33
130,325 110,939(Less) Expenses of Nonutility Operations (417.1) 34
-9,703 172,282Nonoperating Rental Income (418) 35
11,211,230 9,511,469119Equity in Earnings of Subsidiary Companies (418.1) 36
6,422,547 6,005,324Interest and Dividend Income (419) 37
58,494,261 46,510,051Allowance for Other Funds Used During Construction (419.1) 38
602,865 -954,675Miscellaneous Nonoperating Income (421) 39
896,553 508,748Gain on Disposition of Property (421.1) 40
78,218,444 61,362,141TOTAL Other Income (Enter Total of lines 31 thru 40) 41
Other Income Deductions 42
71,235 37,115Loss on Disposition of Property (421.2) 43
1,292,207 1,290,244Miscellaneous Amortization (425) 44
2,491,665 3,009,414 Donations (426.1) 45
-5,124,160 -3,079,618 Life Insurance (426.2) 46
719,036 238,093 Penalties (426.3) 47
1,497,850 2,171,126 Exp. for Certain Civic, Political & Related Activities (426.4) 48
129,377,724 8,456,159 Other Deductions (426.5) 49
130,325,557 12,122,533TOTAL Other Income Deductions (Total of lines 43 thru 49) 50
Taxes Applic. to Other Income and Deductions 51
315,476 306,526262-263Taxes Other Than Income Taxes (408.2) 52
-1,654,653 -1,538,756262-263Income Taxes-Federal (409.2) 53
-224,840 -209,091262-263Income Taxes-Other (409.2) 54
84,103,300 59,177,256234, 272-277Provision for Deferred Inc. Taxes (410.2) 55
129,629,658 60,347,318234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.2) 56
Investment Tax Credit Adj.-Net (411.5) 57
1,827,951 2,064,956(Less) Investment Tax Credits (420) 58
-48,918,326 -4,676,339TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59
-3,188,787 53,915,947Net Other Income and Deductions (Total of lines 41, 50, 59) 60
Interest Charges 61
355,713,688 364,553,118Interest on Long-Term Debt (427) 62
3,835,726 3,910,675Amort. of Debt Disc. and Expense (428) 63
1,797,595 1,769,844Amortization of Loss on Reaquired Debt (428.1) 64
8,949 2,718(Less) Amort. of Premium on Debt-Credit (429) 65
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 66
-12,665 -15,213Interest on Debt to Assoc. Companies (430) 67
12,226,166 14,342,093Other Interest Expense (431) 68
28,756,114 24,643,010(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69
344,795,447 359,914,789Net Interest Charges (Total of lines 62 thru 69) 70
537,337,285 554,806,039Income Before Extraordinary Items (Total of lines 27, 60 and 70) 71
Extraordinary Items 72
Extraordinary Income (434) 73
(Less) Extraordinary Deductions (435) 74
Net Extraordinary Items (Total of line 73 less line 74) 75
262-263Income Taxes-Federal and Other (409.3) 76
Extraordinary Items After Taxes (line 75 less line 76) 77
537,337,285 554,806,039Net Income (Total of line 71 and 77) 78
FERC FORM NO. 1/3-Q (REV. 02-04) Page 117
Schedule 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, 2012 and 2011, depreciation expense associated with transportation
equipment was $15,898,715 and $14,396,524, 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.: 14 Column: c
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress. During the years ended December 31, 2012 and 2011, payroll taxes were
$40,291,150 and $40,298,577, respectively.
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF RETAINED EARNINGS
PacifiCorp X
/ /
2012/Q4
Line
Current
Quarter/Year
Year to Date
Balance
(c)(b)(a)
Item
Contra Primary
No.
Account Affected
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.
Previous
Quarter/Year
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
2,652,408,336 2,645,655,455 1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4
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)
545,294,570 526,126,055 16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
-1,225,845215.1 18 Appropriation of excess earnings at certain hydroelectric generating facilities
19
20
21
-1,225,845 22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
( 2,049,846) -2,049,846238 24 Preferred Stock, various series and rates
25
26
27
28
( 2,049,846) -2,049,846 29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
( 549,997,605) -200,000,000238 31 Common Stock
32
33
34
35
( 549,997,605) -200,000,000 36 TOTAL Dividends Declared-Common Stock (Acct. 438)
5,827,818 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
2,645,655,455 2,974,333,637 38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
39
40
FERC FORM NO. 1/3-Q (REV. 02-04)Page 118
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF RETAINED EARNINGS
PacifiCorp X
/ /
2012/Q4
Line
Current
Quarter/Year
Year to Date
Balance
(c)(b)(a)
Item
Contra Primary
No.
Account Affected
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.
Previous
Quarter/Year
Year to Date
Balance
(d)
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
3,575,811 4,801,656 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
3,575,811 4,801,656 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
2,649,231,266 2,979,135,293 48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
142,404,172 151,915,641 49 Balance-Beginning of Year (Debit or Credit)
9,511,469 11,211,230 50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
-5,827,818 52 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
151,915,641 157,299,053 53 Balance-End of Year (Total lines 49 thru 52)
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
Schedule Page: 118 Line No.: 24 Column: c
Outstanding shares of preferred stock as of December 31, 2012 and dividends on preferred
stock during the year ended December 31, 2012 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, 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.: 31 Column: c
For information regarding common stock dividends declared, refer to Important Changes
During the Quarter/Year, Item 6, in this Form No. 1.
Schedule Page: 118 Line No.: 37 Column: c
For information regarding the dissolution of PacifiCorp Environmental Remediation Company,
refer to Important Changes During the Quarter/Year, Item 10, of this Form No.1.
Schedule 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
(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.
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF CASH FLOWS
PacifiCorp X
/ /2012/Q4
Line Description (See Instruction No. 1 for Explanation of Codes)Current Year to Date
Quarter/Year
(b)(a)No.
Previous Year to Date
Quarter/Year
(c)
1 Net Cash Flow from Operating Activities:
554,806,039 537,337,285 2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
560,591,577 589,168,608 4 Depreciation and Depletion
50,140,207 51,502,307 5 Amortization:
6
7
357,507,026 304,784,287 8 Deferred Income Taxes (Net)
-3,939,160 -3,679,251 9 Investment Tax Credit Adjustment (Net)
-60,824,263 -14,624,273 10 Net (Increase) Decrease in Receivables
-58,556,736 -34,659,850 11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
-34,182,597 57,856,504 13 Net Increase (Decrease) in Payables and Accrued Expenses
-62,618,384 17,169,240 14 Net (Increase) Decrease in Other Regulatory Assets
39,724,553 -15,997,931 15 Net Increase (Decrease) in Other Regulatory Liabilities
46,510,051 58,494,261 16 (Less) Allowance for Other Funds Used During Construction
9,511,469 5,383,412 17 (Less) Undistributed Earnings from Subsidiary Companies
313,928,254 110,233,418 18 Amounts Due To/From Affiliates (Net)
3,796,008 68,250,000 19 Derivative Collateral (Net)
21,636,546 25,993,723 20 Other Operating Activities:
21
1,625,987,550 1,629,456,394 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
-1,532,049,103 -1,398,801,462 26 Gross Additions to Utility Plant (less nuclear fuel)
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
-46,510,051 -58,494,261 30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33
-1,485,539,052 -1,340,307,201 34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
1,788,112 739,512 37 Proceeds from Disposal of Noncurrent Assets (d)
38
-32,230,537 39 Investments in and Advances to Assoc. and Subsidiary Companies
21,169,399 40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
FERC FORM NO. 1 (ED. 12-96) Page 120
(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.
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF CASH FLOWS
PacifiCorp X
/ /2012/Q4
Line Description (See Instruction No. 1 for Explanation of Codes)Current Year to Date
Quarter/Year
(b)(a)No.
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
-896,877 -13,553,729 53 Other Investing Activities:
54
55
56 Net Cash Provided by (Used in) Investing Activities
-1,516,878,354 -1,331,952,019 57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
399,256,000 748,786,000 61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
652,437,287 66 Net Increase in Short-Term Debt (c)
11,107,806 67 Other (provide details in footnote):
68
69
1,051,693,287 759,893,806 70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
-586,686,000 -101,026,000 73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
-3,006,612 -7,826,267 76 Other (provide details in footnote):
-1,364,856 -1,316,468 77 Repayment of Capital Lease Obligations
-688,436,607 78 Net Decrease in Short-Term Debt (c)
79
-2,049,846 -2,049,846 80 Dividends on Preferred Stock
-549,997,605 -200,000,000 81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
-91,411,632 -240,761,382 83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
17,697,564 56,742,993 86 (Total of lines 22,57 and 83)
87
4,395,676 22,093,240 88 Cash and Cash Equivalents at Beginning of Period
89
22,093,240 78,836,233 90 Cash and Cash Equivalents at End of period
FERC FORM NO. 1 (ED. 12-96) Page 121
Schedule Page: 120 Line No.: 4 Column: b
Includes depreciation expense associated with transportation equipment and capital lease
assets of $17,215,183 and $15,761,379 during the years ended December 31, 2012 and 2011,
respectively.
Schedule Page: 120 Line No.: 5 Column: a
Years Ended December 31,
2012 2011
Amortization of software development & other intangibles $ 45,642,251 $ 43,494,603
Amortization of electric plant acquisition adjustments 5,523,970 5,523,970
Amortization of regulatory assets 336,086 1,121,634
$ 51,502,307 $ 50,140,207
Schedule Page: 120 Line No.: 20 Column: a
Years Ended December 31,
2012 2011
Depreciation and depletion included in cost of fuel $ 12,461,354 $ 11,712,355
Gain on sale of property (1,063,591) (497,935)
Write-off of assets under construction 10,606,163 5,085,213
Unrealized losses on derivative contracts - 1,116,177
Other 3,989,797 4,220,736
$ 25,993,723 $ 21,636,546
Schedule Page: 120 Line No.: 22 Column: c
Certain prior period amounts have been reclassified. These reclassifications had no effect
on net cash provided by (used in) operating activities.
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.
Schedule Page: 120 Line No.: 53 Column: a
Years Ended December 31,
2012 2011
Other investments/special funds $ (369,775) $ 919,658
Temporary facilities 20,007 23,771
Restricted cash (13,203,961) (1,840,306)
$(13,553,729) $ (896,877)
Schedule Page: 120 Line No.: 67 Column: b
Intercompany borrowing from subsidiary company, Pacific Minerals, Inc.
Schedule Page: 120 Line No.: 76 Column: a
Long-term debt issuance and other financing costs.
Schedule Page: 120 Line No.: 83 Column: c
Certain prior period amounts have been reclassified. These reclassifications had no effect
on net cash provided by (used in) financing activities.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report Year/Period of Report
End of
NOTES TO FINANCIAL STATEMENTS
PacifiCorp X / /2012/Q4
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
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.
FERC FORM NO. 1 (ED. 12-96) Page 122
PACIFICORP
NOTES TO FINANCIAL STATEMENTS
(1) Organization and Operations
PacifiCorp is a United States regulated electric company serving retail customers, including residential, commercial, industrial,
irrigation 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 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

Basis of Presentation
These financial statements are prepared in accordance with the requirements of the Federal Energy Regulatory Commission ("FERC")
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 ("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. AC11-132, 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.
Also in accordance with FERC Order No. AC11-132, PacifiCorp does not eliminate intercompany profit on transactions with
equity investees as would be required under GAAP. The accounting treatment described above has no effect on net income
or the combined retained earnings of PacifiCorp and undistributed earnings of subsidiaries.
Costs of Removal
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. AI07-2-000, "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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.1
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 of Estimates 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.

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 defers 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. Regulatory assets and liabilities are
established to reflect the impacts of these deferrals, which are recognized in earnings in the periods the corresponding changes in rates
occur.

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 that could limit
PacifiCorp's ability to recover its costs. 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. 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.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.2
Cash Equivalents and Restricted Cash and Investments

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills 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):
2012 2011
Cash (131)$24 $15
Working funds (135) — —
Temporary cash investments (136) 55 7
Total cash and cash equivalents $79 $22
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, 2012 and 2011,
PacifiCorp had no unrealized gains and losses on available-for-sale securities.
Allowance for Doubtful Accounts

Accounts receivable are stated at the outstanding principal amount, net of an estimated allowance 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):

2012 2011
Beginning balance $9 $8
Charged to operating costs and expenses, net 14 13
Write-offs, net (14) (12)
Ending balance $9 $9
Derivatives

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 agreements 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 derivative 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 regulatory assets. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized
in earnings.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.3
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.

Depreciation and amortization are generally computed on the straight-line method based on composite asset class lives prescribed by
PacifiCorp'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 accumulated provision for depreciation or
ARO liability is reduced.

Generally when PacifiCorp retires or sells a component of utility plant, it charges the original cost, net of any proceeds from the
disposition, to accumulated provision for depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.

PacifiCorp records debt and equity AFUDC, which represents the estimated costs of debt and equity funds necessary to finance
additions to utility plant. AFUDC is capitalized as a component of utility plant, with offsetting credits to the Statement of Income.
AFUDC is computed based on guidelines set forth by the FERC. After construction is completed, PacifiCorp 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 unbilled,
amounts. As of December 31, 2012 and 2011, unbilled revenue was $251 million and $237 million, respectively, and is included in
accrued utility revenues 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.4
The monthly unbilled revenues of PacifiCorp 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.

PacifiCorp records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on
a net basis on the Statement of Income.

Income Taxes

Berkshire Hathaway includes PacifiCorp in its United States federal income 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 OCI. 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. As of December 31, 2012 and 2011, these amounts were
recognized as regulatory assets of $456 million and $444 million, respectively, and regulatory liabilities of $21 million and
$22 million, 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. Changes in deferred income tax assets and liabilities
attributable to changes in enacted income tax rates are charged or credited to income tax expense in the period of enactment.
Valuation allowances are established for certain deferred income tax assets where realization is not likely.

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 income 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 income 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 is
more likely than not of being realized upon ultimate settlement. Although the ultimate resolution of PacifiCorp's federal, state and
local income tax examinations is uncertain, PacifiCorp believes it has made adequate provisions for these income tax positions. The
aggregate amount of any additional income 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.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.5
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. In January 2013, the FASB issued ASU No. 2013-01, which also amends
FASB ASC Topic 210 to clarify that the scope of ASU No. 2011-11 only applies to derivative instruments, repurchase agreements,
reverse purchase agreements and securities borrowing and securities lending transactions that are either being offset or are subject to
an enforceable master netting arrangement or similar agreement. ASU No. 2013-01 is also 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.
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 adopted ASU No. 2011-04 on January 1, 2012. 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 each of the years ended
December 31, 2012 and 2011.
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, 2012 and 2011 and accumulated
provision for depreciation, amortization and depletion of $113 million and $107 million as of December 31, 2012 and 2011,
respectively.
(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. PacifiCorp 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 PacifiCorp's share of the expenses of these facilities.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.6
The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility as of December 31, 2012
(dollars in millions):
Facility Accumulated Construction
PacifiCorp in Depreciation and Work-in-
Share Service Amortization Progress
Jim Bridger Nos. 1 - 4 67% $ 1,087 $ 519 $ 33
Hunter No. 1 94 391 144 19
Hunter No. 2 60 301 81 —
Wyodak 80 450 155 2
Colstrip Nos. 3 and 4 10 223 122 1
Hermiston 50 172 58 1
Craig Nos. 1 and 2 19 177 95 4
Hayden No. 1 25 55 25 1
Hayden No. 2 13 32 16 —
Foote Creek 79 37 20 —
Transmission and distribution facilities Various 325 65 1
Total $3,250 $1,300 $62
(5) Regulatory Matters
PacifiCorp had regulatory assets not earning a return on investment of $1.618 billion and $1.662 billion as of December 31, 2012 and
2011, respectively.
(6) Short-term Debt and Other Financing Agreements
The following table summarizes PacifiCorp's availability under its revolving credit facilities as of December 31 (in millions):
2012:
Available revolving credit facilities $ 1,230
Less:
Short-term debt —
Letters of credit supporting tax-exempt bond obligations and collateral requirements of commodity contracts (602)
Net revolving credit facilities available $628
2011:
Available revolving credit facilities $ 1,355
Less:
Short-term debt (688)
Letters of credit supporting tax-exempt bond obligations (304)
Net revolving credit facilities available $363
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.7
In June 2012, PacifiCorp replaced its existing $635 million unsecured revolving credit facility with a $600 million unsecured
revolving credit facility expiring in June 2017. This facility is for general corporate purposes including supporting PacifiCorp's
commercial paper program and provides for the issuance of letters of credit. Additionally, as of December 31, 2012, PacifiCorp had
an unsecured revolving credit facility, which had $720 million available until July 2012 and had $630 million available until July
2013, which supported PacifiCorp's commercial paper program and certain variable-rate tax-exempt bond obligations. During March
2013, PacifiCorp replaced the $630 million unsecured revolving credit facility with a $600 million unsecured credit facility expiring
in March 2018. These credit facilities have a variable interest rate based on the London Interbank Offered Rate or a base rate, at
PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities. As
of December 31, 2011, the weighted-average interest rate on commercial paper borrowings outstanding was 0.51%. The credit
facilities require that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0
as of the last day of each quarter for each of the two $600 million credit facilities or at any time for the $630 million credit facility. As
of December 31, 2012, PacifiCorp was in compliance with the covenants of its revolving credit facilities.
As of December 31, 2012 and 2011, PacifiCorp had $602 million and $601 million, respectively, of letters of credit issued under
committed arrangements, of which $602 million and $304 million, respectively, were issued under the revolving credit facilities.
These letters of credit support PacifiCorp's variable-rate tax-exempt bond obligations and certain collateral requirements of
commodity contracts, and were fully available as of December 31, 2012 and 2011. Certain of these letters of credit were replaced
during March 2013 and all letters of credit currently expire periodically from November 2013 through March 2015.
As of December 31, 2012, PacifiCorp had approximately $14 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, 2012
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.
(7) 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
through the payment of a make-whole premium. Variable-rate tax-exempt bond obligations are generally redeemable at par value.
In January 2012, PacifiCorp issued $350 million of its 2.95% First Mortgage Bonds due February 2022 and $300 million of its 4.10%
First Mortgage Bonds due February 2042. The net proceeds were used to repay short-term debt, fund capital expenditures and for
general corporate purposes. In March 2012, PacifiCorp issued an additional $100 million of its 2.95% First Mortgage Bonds due
February 2022. The net proceeds were used to redeem $84 million of tax-exempt bond obligations prior to scheduled maturity with a
weighted average interest rate of 5.72%, to 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.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's
mortgage. Approximately $23 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage
as of December 31, 2012.
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 $55 million and $56 million as of December 31, 2012 and 2011, respectively, were
included in net utility plant in the Comparative Balance Sheet.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.8
As of December 31, 2012, the annual maturities of long-term debt and capital lease obligations, excluding unamortized discounts and
including interest on capital lease obligations, for 2013 and thereafter are as follows (in millions):
Long-term Capital Lease
Debt Obligations Total
2013 $ 261 $ 12 $ 273
2014 253 8 261
2015 122 7 129
2016 57 7 64
2017 52 11 63
Thereafter 6,075 70 6,145
Total 6,820 115 6,935
Unamortized discount (14) — (14)
Amounts representing interest —(60)(60)
Total $6,806 $55 $6,861
(8) Income Taxes
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2012 2011
Current:
Federal $ (108) $ (140)
State (1)(8)
Total (109)(148)
Deferred:
Federal 273 320
State 32 37
Total 305 357
Investment tax credits (4)(4)
Total income tax expense $192 $205
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:
2012 2011
Federal statutory income tax rate 35% 35%
State income taxes, net of federal income tax benefit 3 2
Federal income tax credits(1)(9) (10)
Effects of ratemaking (1) —
Other (2) —
Effective income tax rate 26%27%
(1) Primarily attributable to the impact of federal renewable electricity production tax credits related to qualifying wind-powered generating facilities that
extend 10 years from the date the facilities were placed in service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.9
The net deferred income tax liability consists of the following as of December 31 (in millions):
2012 2011
Deferred income tax assets:
Employee benefits $ 217 $ 210
State carryforwards 69 62
Unamortized contract values 63 72
Derivative contracts 46 100
Regulatory liabilities 40 43
Other 213 153
648 640
Deferred income tax liabilities:
Property, plant and equipment (4,005) (3,670)
Regulatory assets (696) (715)
Other (32) (32)
(4,733)(4,417)
Net deferred income tax liability $(4,085)$(3,777)
As of December 31, 2012, PacifiCorp has available $69 million of state carryforwards, principally for net operating losses, which
expire at various intervals between 2013 and 2032.
The United States Internal Revenue Service has closed its examination of PacifiCorp's income tax returns through the March 31, 2006
tax year. State jurisdictions have closed their examinations of PacifiCorp's income tax returns through 1993.
As of December 31, 2012 and 2011, net unrecognized tax benefits totaled $47 million and $64 million, respectively, which included
$- million and $8 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.
(9) 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"). In addition, PacifiCorp contributes to a joint trustee pension
plan and a subsidiary contributes to a multiemployer pension plan for benefits offered to certain bargaining units.
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 ("SERP"). The Retirement Plan is closed to all non-union employees hired
after January 1, 2008. 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 limited 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.10
Plan Amendment
Effective January 1, 2012, PacifiCorp 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.
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
2012 2011 2012 2011
Service cost $ 7 $ 10 $ 7 $ 7
Interest cost 61 63 28 31
Expected return on plan assets (74) (75) (30) (30)
Net amortization 34 20 4 18
Net periodic benefit cost $28 $18 $9 $26
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
2012 2011 2012 2011
Plan assets at fair value, beginning of year $ 931 $ 960 $ 384 $ 389
Employer contributions 49 71 9 28
Participant contributions — — 7 9
Actual return on plan assets 120 (13) 52 (4)
Benefits paid (88) (87) (28) (38)
Plan assets at fair value, end of year $1,012 $931 $424 $384
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
Pension Other Postretirement
2012 2011 2012 2011
Benefit obligation, beginning of year $ 1,291 $ 1,236 $ 575 $ 581
Service cost 7 10 7 7
Interest cost 61 63 28 31
Participant contributions — — 7 9
Plan amendments — (4) — (54)
Actuarial loss 120 73 43 36
Benefits paid, net of Medicare subsidy (88)(87)(28)(35)
Benefit obligation, end of year $1,391 $1,291 $632 $575
Accumulated benefit obligation, end of year $1,390 $1,289
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.11
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
2012 2011 2012 2011
Plan assets at fair value, end of year $ 1,012 $ 931 $ 424 $ 384
Less - Benefit obligation, end of year 1,391 1,291 632 575
Funded status $(379)$(360)$(208)$(191)
The SERP has no plan assets; however, PacifiCorp 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
$44 million and $41 million as of December 31, 2012 and 2011, respectively. These assets are not included in the plan assets in the
above table, but are reflected in other investments on the Comparative Balance Sheet.
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
2012 2011 2012 2011
Net loss $ 660 $ 630 $ 214 $ 206
Prior service credit (37) (45) (40) (46)
Regulatory deferrals
(5) (7) 3 3
Total $618 $578 $177 $163
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.12
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2012
and 2011 is as follows (in millions):
Accumulated
Other
Regulatory Comprehensive
Asset Loss Total
Pension
Balance, December 31, 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
Net loss arising during the year 68 6 74
Net amortization (33) (1) (34)
Total 35 5 40
Balance, December 31, 2012 $599 $19 $618
Regulatory
Asset
Other Postretirement
Balance, December 31, 2010 $165
Net loss arising during the year 70
Prior service credit arising during the year (46)
Reduction in net transition obligation (8)
Net amortization (18)
Total (2)
Balance, December 31, 2011 163
Net loss arising during the year 18
Net amortization (4)
Total 14
Balance, December 31, 2012 $177
The net loss, prior service credit and regulatory deferrals that will be amortized in 2013 into net periodic benefit cost are estimated to
be as follows (in millions):
Net Prior Service Regulatory
Loss Credit Deferrals Total
Pension $ 57 $ (8) $ (1) $ 48
Other postretirement 15 (7)1 9
Total $72 $(15)$—$57
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.13
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
Pension Other Postretirement
2012 2011 2012 2011
Benefit obligations as of December 31:
Discount rate 4.05% 4.90% 4.10% 4.95%
Rate of compensation increase 3.00 3.50 N/A N/A
Net periodic benefit cost for the years ended December 31:
Discount rate 4.90% 5.35% 4.95% 5.45%
Expected return on plan assets 7.50 7.50 7.50 7.50
Rate of compensation increase 3.50 3.50 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.
2012 2011
Assumed healthcare cost trend rates as of December 31:
Healthcare cost trend rate assumed for next year 8.00% 8.50%
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 2018 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 48 (38)
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $64 million and $13 million,
respectively, during 2013. 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.14
The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2013 through 2017
and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Other Postretirement
Pension Gross Medicare Subsidy
2013 $ 100 $ 36 $ —
2014 102 37 —
2015 104 37 —
2016 106 39 (1)
2017 103 41 (1)
2018 - 2022 482 207 (4)
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 equity and debt 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 long-term performance for the types of assets in which the plans invest.
The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows
as of December 31, 2012:
Pension(1)Other Postretirement(1)
% %
Equity securities(2)53 - 57 61 - 65
Debt securities(2)33 - 37 33 - 37
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 plan are held in 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 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.15
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, 2012
Cash equivalents $ 1 $ 8 $ — $ 9
Debt securities:
United States government obligations 48 — — 48
International government obligations — 67 — 67
Corporate obligations — 64 — 64
Municipal obligations — 7 — 7
Agency, asset and mortgage-backed obligations — 34 — 34
Equity securities:
United States companies 383 — — 383
International companies 7 — — 7
Investment funds(2)112 185 — 297
Limited partnership interests(3)——96 96
Total $551 $365 $96 $1,012
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 — 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
(1) Refer to Note 12 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
60% and 40%, respectively, for 2012 and 59% and 41%, respectively, for 2011. Additionally, these funds are invested in United States and international
securities of approximately 42% and 58%, respectively, for 2012 and 49% and 51%, respectively, for 2011.
(3) Limited partnership interests include several funds that invest primarily in buyout, growth equity, venture capital and real estate.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.16
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 1(1)Level 2(1)Level 3(1)Total
As of December 31, 2012
Cash and cash equivalents $ 4 $ — $ — $ 4
Debt securities:
United States government obligations 4 — — 4
International government obligations — 5 — 5
Corporate obligations — 5 — 5
Municipal obligations — 1 — 1
Agency, asset and mortgage-backed obligations — 3 — 3
Equity securities:
United States companies 137 — — 137
International companies 3 — — 3
Investment funds(2)152 103 — 255
Limited partnership interests(3)——7 7
Total $300 $117 $7 $424
As of 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 — 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
(1) Refer to Note 12 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 2012 and 2011. Additionally, these funds are invested in United States and international securities of approximately 66% and
34%, respectively, for 2012 and 69% and 31%, respectively, for 2011.
(3) Limited partnership interests include several funds that invest primarily in buyout, growth equity, venture capital and real estate.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.17
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. Most
investments in limited partnership interests are valued at estimated fair value based on the Retirement Plan's proportionate share of the
partnerships' fair value as recorded in the partnerships' most recently available financial statements adjusted for recent activity and
estimated 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. One of the limited partnerships is valued at the unit price calculated by the general partner primarily
based on independent appraised values of the underlying property holdings.
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):
Limited Partnership Interests
Pension Other Postretirement
Balance, December 31, 2010 $ 84 $ 7
Actual return on plan assets still held at December 31, 2011 7 1
Purchases, sales, distributions and settlements (20) (2)
Balance, December 31, 2011 71 6
Actual return on plan assets still held at December 31, 2012 7 —
Purchases, sales, distributions and settlements 18 1
Balance, December 31, 2012 $96 $7
Multiemployer and Joint Trustee Pension Plans
PacifiCorp contributes to the PacifiCorp/IBEW Local 57 Retirement Trust Fund ("Local 57 Trust Fund") (plan number 001) and a
subsidiary contributes to the United Mine Workers of America 1974 Pension Plan ("UMWA Pension Plan") (plan number 002).
Contributions to these pension plans are based on the terms of collective bargaining agreements.
The Local 57 Trust Fund is a joint trustee plan such that the board of trustees is represented by an equal number of trustees from
PacifiCorp and the union. The Local 57 Trust Fund was established pursuant to the provisions of the Taft-Hartley Act and was formed
with the ability for other employers to participate in the plan.
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 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. 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. Furthermore, to the extent a participating employer defaults on its obligation to the plan, the remaining employers
may be allocated a share of the defaulting employer's obligation for unfunded vested benefits. Under the terms of the UMWA Pension
Plan, in the event the mining operations cease, PacifiCorp's subsidiary may be subject to a withdrawal liability.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.18
The following table presents PacifiCorp's and its subsidiary's participation in individually significant joint trustee and multiemployer
pension plans for the years ended December 31 (dollars in millions):
PPA zone status or planfunded status percentagefor plan years beginningJuly 1,(1)Contributions(2)
Plan name
EmployerIdentificationNumber 2012 2011
Fundingimprovementplan
Surchargeimposedunder PPA 2012 2011
Year contributions to planexceeded more than 5% oftotal contributions(3)
UMWA
Pension
Plan 52-1050282 Orange Orange Implemented None $3 $3 None
Local 57
Trust Fund 87-0640888
At least
80%
At least
80%None None $ 12 $ 12 2011, 2010
(1) Among other factors, multiemployer plans in the red zone are generally less than 65 percent funded; multiemployer plans in the yellow zone either (a) are at
least 65 percent but less than 80 percent funded or (b) have an accumulated funding deficiency for such plan year, or are projected to have such an
accumulated funding deficiency for any of the six succeeding plan years; multiemployer plans in the orange zone meet both of the criteria for yellow zone;
and multiemployer plans in the green zone are at least 80 percent funded. Multiemployer plans in the red, yellow, orange or green zones are also referred to
as being in critical, endangered, seriously endangered or neither endangered nor critical status, respectively.
(2) PacifiCorp's and its subsidiary's minimum contributions to the plans are based on the amount of wages paid to employees covered by the Local 57 Trust
Fund collective bargaining agreement and the number of mining hours worked for the UMWA Pension Plan, respectively, subject to ERISA minimum
funding requirements.
(3) For the UMWA Pension Plan, information is for plan year beginning July 1, 2010. Information for the plan years beginning July 1, 2012 and 2011 is not
available. For the Local 57 Trust Fund, information is for plan years beginning July 1, 2011 and 2010. Information for the plan year beginning July 1, 2012
is not yet available.
Although the collective bargaining agreements governing the UMWA Pension Plan and the Local 57 Trust Fund expired in January
2013, operations will continue under the provisions of the agreements until such time that new agreements are reached or the existing
agreements are terminated.
Defined 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 $36 million and $38 million for the years ended December 31, 2012 and 2011, respectively.
(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 in accordance with accepted regulatory practices. These accruals totaled $810
million and $782 million as of December 31, 2012 and 2011, respectively.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.19
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31
(in millions):
2012 2011
Beginning balance $ 123 $ 105
Change in estimated costs(1)17 2
Additions 4 29
Retirements (22) (19)
Accretion 5 6
Ending balance $127 $123
(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) 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 12 for
additional information on derivative contracts.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.20
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):
Current Long-term Current Long-term
Assets Assets Liabilities Liabilities Total
As of December 31, 2012
Not designated as hedging contracts(1):
Commodity assets $ 10 $ 3 $ 18 $ 1 $ 32
Commodity liabilities (2)(2) (122) (27) (153)
Total 8 1 (104)(26)(121)
Total derivatives 8 1 (104) (26) (121)
Cash collateral receivable ——55 —55
Total derivatives - net basis $8 $1 $(49)$(26)$(66)
As of December 31, 2011
Not designated as hedging contracts(1):
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
Total derivatives - net basis $11 $4 $(90)$(66)$(141)
(1) PacifiCorp's commodity derivatives are generally included in rates and as of December 31, 2012 and 2011, a regulatory asset of $121 million and
$264 million, respectively, was recorded related to the net derivative liability of $121 million and $264 million, respectively.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.21
The following table reconciles the beginning and ending balances of PacifiCorp's regulatory assets and summarizes the pre-tax gains
and losses on commodity derivative contracts recognized in regulatory assets, as well as amounts reclassified to earnings for the years
ended December 31 (in millions):
2012 2011
Beginning balance $ 264 $ 487
Changes in fair value recognized in regulatory assets 45 (2)
Net losses reclassified to unamortized contract value regulatory asset — (168)
Net gains reclassified to operating revenue 38 18
Net losses reclassified to energy costs (226) (71)
Ending balance $121 $264
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):
Unit of
Measure 2012 2011
Electricity sales Megawatt hours (1) (2)
Natural gas purchases Decatherms 74 96
Fuel oil purchases Gallons 16 17
Credit Risk
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.
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, 2012, PacifiCorp's credit ratings from the three recognized credit rating agencies were
investment grade.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.22
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features
totaled $153 million and $378 million as of December 31, 2012 and 2011, respectively, for which PacifiCorp had posted collateral of
$56 million and $125 million, respectively, in the form of cash deposits and letters of credit. If all credit-risk-related contingent
features for derivative contracts in liability positions had been triggered as of December 31, 2012 and 2011, PacifiCorp would have
been required to post $73 million and $155 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.
(12) Fair Value Measurements
The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, other 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.23
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, 2012
Assets:
Commodity derivatives $ — $ 32 $ — $ (23 ) $ 9
Money market mutual funds(2)73 ———73
$73 $32 $—$(23 )$82
Liabilities - Commodity derivatives $—$(153)$—$78 $(75)
As of December 31, 2011
Assets:
Commodity derivatives $ — $ 114 $ 1 $ (100 ) $ 15
Money market mutual funds(2)9 ———9
$9 $114 $1 $(100 )$24
Liabilities - Commodity derivatives $—$(379)$—$223 $(156)
(1) Represents netting under master netting arrangements and a net cash collateral receivable of $55 million and $123 million as of December 31, 2012 and
2011, 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.
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 PacifiCorp
transacts. When quoted prices for identical contracts are not available, PacifiCorp 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.
PacifiCorp 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 PacifiCorp. 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 11 for further discussion regarding PacifiCorp's risk
management and hedging activities.

PacifiCorp's investments in money market mutual funds are accounted for as available-for-sale securities and are stated at fair value.
PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market to record the
fair value.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.24
The following table reconciles the beginning and ending balances of PacifiCorp's 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):
2012 2011
Beginning balance $1 $(345)
Changes in fair value recognized in regulatory assets 1 132
Contracts designated as normal purchases or normal sales — 168
Settlements (2)46
Ending balance $—$1
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 were reclassified from derivative contracts to other assets and liabilities. The frozen liability
and associated regulatory asset are being amortized over the remaining terms of the agreements.
PacifiCorp's long-term debt is carried at cost on the financial statements. The fair value of PacifiCorp's long-term debt is a Level 2 fair
value measurement and 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 PacifiCorp'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):
2012 2011
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $6,806 $8,350 $6,157 $7,804
(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. 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.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.25
USA Power
In October 2005, prior to MEHC's ownership of PacifiCorp, PacifiCorp was added as a defendant to a lawsuit originally filed in
February 2005 in the Third District Court of Salt Lake County, Utah ("Third District Court") by USA Power, LLC, USA Power
Partners, LLC and Spring Canyon Energy, LLC (collectively, the "Plaintiff"). The Plaintiff's complaint alleged that PacifiCorp
misappropriated confidential proprietary information in violation of Utah's Uniform Trade Secrets Act and accused PacifiCorp of
breach of contract and related claims in regard to the Plaintiff's 2002 and 2003 proposals to build a natural gas-fueled generating
facility in Juab County, Utah. In October 2007, the Third District Court granted PacifiCorp's motion for summary judgment on all
counts and dismissed the Plaintiff's claims in their entirety. In February 2008, the Plaintiff filed a petition requesting consideration by
the Utah Supreme Court. In May 2010, the Utah Supreme Court reversed summary judgment and remanded the case back to the Third
District Court for further consideration, which led to a trial that began in April 2012. In May 2012, the jury reached a verdict in favor
of the Plaintiff on its claims. The jury awarded damages to the Plaintiff for breach of contract and misappropriation of a trade secret in
the amounts of $18 million for actual damages and $113 million for unjust enrichment. In May 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 all amounts ultimately awarded in the case. In October 2012, PacifiCorp filed post-trial motions for a judgment
notwithstanding the verdict and a new trial (collectively, "PacifiCorp's post-trial motions"). The trial judge stayed briefing on the
Plaintiff's motions, pending resolution of PacifiCorp's post-trial motions. As a result of a hearing in December 2012, the trial judge
denied PacifiCorp's post-trial motions with the exception of reducing the aggregate amount of damages to $113 million. In January
2013, the Plaintiff filed a motion for prejudgment interest. In January and February 2013, PacifiCorp filed its responses to the
Plaintiff's post-trial motions for exemplary damages, attorneys' fees and prejudgment interest. A judgment was rendered in April
2013, where the trial judge denied the Plaintiff's motions for exemplary damages and prejudgment interest and ruled that PacifiCorp
must pay the Plaintiff's attorneys' fees based on applying a reasonable rate to hours worked rather than the Plaintiff's request for an
amount equal to 40% of all amounts ultimately awarded. PacifiCorp strongly disagrees with the jury's verdict and plans to vigorously
pursue all appellate measures. As of December 31, 2012, PacifiCorp accrued $113 million, plus estimated obligations for the
Plaintiff's motions, and believes the likelihood of any additional material loss is remote; however, any additional awards against
PacifiCorp could also have a material effect on the financial results. Any payment of damages will be at the end of the appeal process,
which could take as long as several years.
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. PacifiCorp engaged in settlement discussions with certain of the
parties to the proceeding, which have been approved by the FERC. The outcome of such settlements did not have a material impact on
PacifiCorp's financial results.
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.26
Hydroelectric Relicensing
PacifiCorp's Klamath hydroelectric system is currently operating under annual licenses with the FERC. 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 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
with the FERC. In November 2011, bills were introduced in both chambers of the 112th 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. These bills are pending re-introduction into the 113th United States Congress.
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.
PacifiCorp 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 into trust accounts maintained by the OPUC. PacifiCorp has begun collection of surcharges
from California customers for their share of dam removal costs, as approved by the California Public Utilities Commission ("CPUC"),
and is depositing the proceeds into trust accounts maintained by the CPUC. PacifiCorp is authorized to collect the surcharges through
2019.

As of December 31, 2012, PacifiCorp's assets included $115 million of costs associated with the Klamath hydroelectric system's
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 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 Idaho and Washington general rate cases, which were settled in January 2012 and March 2012, respectively, without a
decision on this matter. As part of the September 2012 Utah general rate case order, the Utah Public Service Commission approved
recovery of Utah's share of costs associated with the Klamath hydroelectric system's mainstem dams and the associated relicensing
and settlement costs through December 31, 2022.
Hydroelectric Commitments
Certain of PacifiCorp's hydroelectric licenses contain requirements for PacifiCorp to make certain capital and operating expenditures
related to its hydroelectric facilities. PacifiCorp estimates it is obligated to make capital expenditures of approximately $184 million
over the next 10 years related to these licenses.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.27
Commitments
PacifiCorp has the following firm commitments that are not reflected on the Comparative Balance Sheet. Minimum payments as of
December 31, 2012 are as follows (in millions):
2013 2014 2015 2016 2017 2018 andThereafter Total
Contract type:
Purchased electricity contracts $ 178 $ 112 $ 113 $ 94 $ 69 $ 450 $ 1,016
Fuel contracts 666 646 525 411 389 1,978 4,615
Construction commitments 408 158 25 13 10 60 674
Transmission 105 97 75 68 61 671 1,077
Operating leases and easements 6 5 4 3 2 44 64
Maintenance, service and
other contracts 31 22 12 8 12 71 156
Total commitments $1,394 $1,040 $754 $597 $543 $3,274 $7,602
Purchased Electricity Contracts
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. Rent
expense related to those power purchase agreements that meet the definition of an operating lease totaled $19 million for 2012 and
$28 million for 2011.
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 2012
and 2011 energy sources.
Fuel Contracts
PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.28
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, MEHC 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, 2012, PacifiCorp had the following remaining capital projects to complete associated with
this commitment: (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 mid-2013 and (b) another
segment of the Energy Gateway Transmission Expansion Program that is expected to be placed in service within the next
several years, depending on siting, permitting and construction schedules.
PacifiCorp is constructing the 645-megawatt 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 certain operating facilities, office space, land and equipment 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 $14 million for 2012 and $18 million for 2011.
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.
(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, 2012 and 2011.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.29
(15) Common Shareholder's Equity
In January 2013, PacifiCorp declared and paid a dividend of $150 million to PPW Holdings LLC, a direct wholly owned subsidiary of
MEHC and PacifiCorp's direct parent company.
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 equity below specified percentages of defined capitalization. As of December 31, 2012, 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 equity below 44% of its total capitalization,
excluding short-term debt and current maturities of long-term debt. 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, 2012,
PacifiCorp's actual common equity percentage, as calculated under this measure, was 53.7%, and PacifiCorp would have been
permitted to dividend $2.5 billion under this commitment.
These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings LLC or MEHC if PacifiCorp's
unsecured debt rating is BBB- or lower by Standard & Poor's Rating Services or Fitch Ratings or Baa3 or lower by Moody's Investor
Service, as indicated by two of the three rating services. As of December 31, 2012, PacifiCorp's unsecured debt rating was A- by
Standard & Poor's Rating Services, BBB+ by Fitch Ratings and Baa1 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 Note 6.
(16) Supplemental Cash Flow Disclosures
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
2012 2011
Interest paid, net of amounts capitalized $ 330 $ 358
Income taxes received, net $209 $425
Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to utility plant additions $167 $230

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.30
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
PacifiCorp X
/ /2012/Q4
Line
No.
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.
Other
Adjustments
(e)
Foreign Currency
Hedges
(d)
Minimum Pension
Liability adjustment
(net amount)
(c)
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Item
(a)
( 6,961,899)
Balance of Account 219 at Beginning of
Preceding Year
1
215,312
Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
2
( 2,308,845)
Preceding Quarter/Year to Date Changes in
Fair Value
3
( 2,093,533)Total (lines 2 and 3) 4
( 9,055,432)
Balance of Account 219 at End of Preceding
Quarter/Year
5
( 9,055,432)
Balance of Account 219 at Beginning of
Current Year
6
317,072
Current Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
7
( 3,265,461)
Current Quarter/Year to Date Changes in
Fair Value
8
( 2,948,389)Total (lines 7 and 8) 9
( 12,003,821)
Balance of Account 219 at End of Current
Quarter/Year
10
FERC FORM NO. 1 (NEW 06-02)Page 122a
Other Cash Flow
Hedges
[Specify]
(g)
Other Cash Flow
Hedges
Interest Rate Swaps
(f)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
PacifiCorp X
/ /2012/Q4
Line
No.
Total
Comprehensive
Income
(j)
Net Income (Carried
Forward from
Page 117, Line 78)
(i)
Totals for each
category of items
recorded in
Account 219
(h)
( 6,961,899) 1
408,940 193,628 2
( 2,502,473)( 193,628) 3
554,806,039 552,712,506( 2,093,533) 4
( 9,055,432) 5
( 9,055,432) 6
317,072 7
( 3,265,461) 8
537,337,285 534,388,896( 2,948,389) 9
( 12,003,821) 10
FERC FORM NO. 1 (NEW 06-02)Page 122b
Schedule Page: 122(a)(b) Line No.: 1 Column: g
Other Cash Flow Hedges relate to commodity derivatives.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
PacifiCorp X
/ /2012/Q4
Line
No.(b)(a)
Classification Electric
(c)
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Total Company for the
Current Year/Quarter Ended
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.
Utility Plant 1
In Service 2
23,667,394,313 23,667,394,313Plant in Service (Classified) 3
55,116,128 55,116,128Property Under Capital Leases 4
124,000 124,000Plant Purchased or Sold 5
66,718,983 66,718,983Completed Construction not Classified 6
Experimental Plant Unclassified 7
23,789,353,424 23,789,353,424Total (3 thru 7) 8
Leased to Others 9
22,657,380 22,657,380Held for Future Use 10
1,250,513,185 1,250,513,185Construction Work in Progress 11
159,175,508 159,175,508Acquisition Adjustments 12
25,221,699,497 25,221,699,497Total Utility Plant (8 thru 12) 13
8,018,360,420 8,018,360,420Accum Prov for Depr, Amort, & Depl 14
17,203,339,077 17,203,339,077Net Utility Plant (13 less 14) 15
Detail of Accum Prov for Depr, Amort & Depl 16
In Service: 17
7,404,667,421 7,404,667,421Depreciation 18
Amort & Depl of Producing Nat Gas Land/Land Right 19
Amort of Underground Storage Land/Land Rights 20
500,799,794 500,799,794Amort of Other Utility Plant 21
7,905,467,215 7,905,467,215Total In Service (18 thru 21) 22
Leased to Others 23
Depreciation 24
Amortization and Depletion 25
Total Leased to Others (24 & 25) 26
Held for Future Use 27
Depreciation 28
Amortization 29
Total Held for Future Use (28 & 29) 30
Abandonment of Leases (Natural Gas) 31
112,893,205 112,893,205Amort of Plant Acquisition Adj 32
8,018,360,420 8,018,360,420Total Accum Prov (equals 14) (22,26,30,31,32) 33
FERC FORM NO. 1 (ED. 12-89) Page 200
(g)
Common
(h)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
PacifiCorp X
/ /2012/Q4
Line
No.
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Gas Other (Specify)
(d) (e) (f)
Other (Specify)Other (Specify)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
FERC FORM NO. 1 (ED. 12-89) Page 201
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
PacifiCorp X
/ /2012/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
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)
1. INTANGIBLE PLANT 1
(301) Organization 2
(302) Franchises and Consents 206,078,420 236,195 3
(303) Miscellaneous Intangible Plant 647,383,700 27,221,314 4
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 853,462,120 27,457,509 5
2. PRODUCTION PLANT 6
A. Steam Production Plant 7
(310) Land and Land Rights 93,007,584 156,573 8
(311) Structures and Improvements 941,704,583 11,249,443 9
(312) Boiler Plant Equipment 3,879,646,048 376,881,774 10
(313) Engines and Engine-Driven Generators 11
(314) Turbogenerator Units 952,686,011 40,722,959 12
(315) Accessory Electric Equipment 428,911,328 4,056,478 13
(316) Misc. Power Plant Equipment 33,573,404 959,463 14
(317) Asset Retirement Costs for Steam Production 43,030,473 10,781,638 15
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 6,372,559,431 444,808,328 16
B. Nuclear Production Plant 17
(320) Land and Land Rights 18
(321) Structures and Improvements 19
(322) Reactor Plant Equipment 20
(323) Turbogenerator Units 21
(324) Accessory Electric Equipment 22
(325) Misc. Power Plant Equipment 23
(326) Asset Retirement Costs for Nuclear Production 24
TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 25
C. Hydraulic Production Plant 26
(330) Land and Land Rights 26,050,773 5,473,318 27
(331) Structures and Improvements 141,357,005 42,078,860 28
(332) Reservoirs, Dams, and Waterways 356,202,634 102,698,860 29
(333) Water Wheels, Turbines, and Generators 119,250,199 442,910 30
(334) Accessory Electric Equipment 66,402,841 9,249,705 31
(335) Misc. Power PLant Equipment 2,352,057 19,494 32
(336) Roads, Railroads, and Bridges 16,845,455 853,224 33
(337) Asset Retirement Costs for Hydraulic Production 34
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 728,460,964 160,816,371 35
D. Other Production Plant 36
(340) Land and Land Rights 28,912,692 74,986 37
(341) Structures and Improvements 164,070,313 344,225 38
(342) Fuel Holders, Products, and Accessories 10,708,652 199,161 39
(343) Prime Movers 2,497,158,539 29,049,193 40
(344) Generators 352,333,243 1,775,103 41
(345) Accessory Electric Equipment 249,243,221 656,562 42
(346) Misc. Power Plant Equipment 12,396,937 139,098 43
(347) Asset Retirement Costs for Other Production 5,109,797 3,962,218 44
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 3,319,933,394 36,200,546 45
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 10,420,953,789 641,825,245 46
Page 204FERC FORM NO. 1 (REV. 12-05)
(f)
Transfers Balance atEnd of Year
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
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
1
2
206,314,615 3
648,104,811 664,060 27,164,263 4
854,419,426 664,060 27,164,263 5
6
7
93,164,157 8
1,004,588,118 53,319,616 1,685,524 9
4,091,983,619 -97,940,222 66,603,981 10
11
966,966,274 -14,585 26,428,111 12
475,506,492 43,747,695 1,209,009 13
34,367,481 165,386 14
53,698,542 -113,569 15
6,720,274,683 -887,496 -113,569 96,092,011 16
17
18
19
20
21
22
23
24
25
26
31,389,764 -131,184 3,143 27
181,647,007 -936,864 851,994 28
453,238,675 -430,858 5,231,961 29
120,151,371 636,059 177,797 30
74,757,801 -641,287 253,458 31
2,358,351 1,238 14,438 32
17,635,627 -49,086 13,966 33
34
881,178,596 -1,551,982 6,546,757 35
36
29,096,571 126,970 18,077 37
164,387,266 -77 27,195 38
10,801,123 106,690 39
2,512,410,690 -464 13,796,578 40
353,390,092 264 718,518 41
249,559,251 -63,913 276,619 42
12,476,182 53 59,906 43
9,072,015 44
3,341,193,190 62,833 15,003,583 45
10,942,646,469 -2,376,645 -113,569 117,642,351 46
Page 205FERC FORM NO. 1 (REV. 12-05)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
3. TRANSMISSION PLANT 47
(350) Land and Land Rights 189,547,944 8,885,370 48
(352) Structures and Improvements 147,332,899 3,547,184 49
(353) Station Equipment 1,613,127,173 161,767,856 50
(354) Towers and Fixtures 984,782,939 7,293,362 51
(355) Poles and Fixtures 646,562,331 42,144,868 52
(356) Overhead Conductors and Devices 896,743,379 24,195,286 53
(357) Underground Conduit 3,259,618 56,007 54
(358) Underground Conductors and Devices 7,475,095 14,084 55
(359) Roads and Trails 11,586,681 56
(359.1) Asset Retirement Costs for Transmission Plant 57
TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 4,500,418,059 247,904,017 58
4. DISTRIBUTION PLANT 59
(360) Land and Land Rights 55,701,416 4,172,303 60
(361) Structures and Improvements 83,116,060 1,773,758 61
(362) Station Equipment 847,652,682 46,485,145 62
(363) Storage Battery Equipment 63
(364) Poles, Towers, and Fixtures 987,694,151 35,859,072 64
(365) Overhead Conductors and Devices 665,402,916 17,097,660 65
(366) Underground Conduit 312,231,842 11,904,186 66
(367) Underground Conductors and Devices 738,536,581 23,037,978 67
(368) Line Transformers 1,135,844,771 38,119,095 68
(369) Services 604,680,445 25,185,585 69
(370) Meters 175,522,842 4,187,547 70
(371) Installations on Customer Premises 8,787,057 133,085 71
(372) Leased Property on Customer Premises 72
(373) Street Lighting and Signal Systems 61,094,426 1,366,327 73
(374) Asset Retirement Costs for Distribution Plant 2,635,225 74
TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 5,678,900,414 209,321,741 75
5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT 76
(380) Land and Land Rights 77
(381) Structures and Improvements 78
(382) Computer Hardware 79
(383) Computer Software 80
(384) Communication Equipment 81
(385) Miscellaneous Regional Transmission and Market Operation Plant 82
(386) Asset Retirement Costs for Regional Transmission and Market Oper 83
TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 84
6. GENERAL PLANT 85
(389) Land and Land Rights 19,537,440 58,406 86
(390) Structures and Improvements 248,411,354 4,353,138 87
(391) Office Furniture and Equipment 80,884,267 9,086,454 88
(392) Transportation Equipment 104,525,735 2,136,448 89
(393) Stores Equipment 14,124,139 718,756 90
(394) Tools, Shop and Garage Equipment 63,134,822 1,497,809 91
(395) Laboratory Equipment 38,028,514 687,313 92
(396) Power Operated Equipment 150,984,026 13,001,121 93
(397) Communication Equipment 298,389,515 46,031,518 94
(398) Miscellaneous Equipment 7,308,855 306,015 95
SUBTOTAL (Enter Total of lines 86 thru 95) 1,025,328,667 77,876,978 96
(399) Other Tangible Property 291,200,775 9,443,628 97
(399.1) Asset Retirement Costs for General Plant 39,748 98
TOTAL General Plant (Enter Total of lines 96, 97 and 98) 1,316,569,190 87,320,606 99
TOTAL (Accounts 101 and 106) 22,770,303,572 1,213,829,118 100
(102) Electric Plant Purchased (See Instr. 8) 124,000 101
(Less) (102) Electric Plant Sold (See Instr. 8) 779,590 102
(103) Experimental Plant Unclassified 103
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 22,769,523,982 1,213,953,118 104
Page 206FERC FORM NO. 1 (REV. 12-05)
(f)
Transfers Balance atEnd of Year
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
47
198,218,069 -69,602 145,643 48
170,949,185 20,490,710 421,608 49
1,735,328,437 -23,622,335 15,944,257 50
992,008,798 67,503 51
686,214,770 2,492,429 52
919,805,558 1,133,107 53
3,312,843 2,782 54
7,489,179 55
11,586,681 56
57
4,724,913,520 -3,201,227 20,207,329 58
59
59,625,027 -246,105 2,587 60
89,144,237 4,390,800 136,381 61
884,422,143 -3,949,798 5,765,886 62
63
1,015,605,530 7,947,693 64
679,910,311 2,590,265 65
322,706,767 1,429,261 66
759,050,565 2,523,994 67
1,165,115,776 8,848,090 68
628,986,472 879,558 69
176,687,115 3,023,274 70
8,827,913 92,229 71
72
60,443,784 2,016,969 73
2,459,448 -175,777 74
5,852,985,088 194,897 -175,777 35,256,187 75
76
77
78
79
80
81
82
83
84
85
19,478,606 -117,240 86
227,482,706 -13,139,214 12,142,572 87
89,904,683 12,234,166 12,300,204 88
103,227,297 55,057 3,489,943 89
14,568,536 49,303 323,662 90
62,887,623 -459,744 1,285,264 91
37,053,335 180,897 1,843,389 92
155,194,085 8,791,062 93
344,747,037 2,708,373 2,382,369 94
7,929,038 414,955 100,787 95
1,062,472,946 1,926,553 42,659,252 96
296,636,099 -53,137 -303,740 3,651,427 97
39,748 98
1,359,148,793 1,873,416 -303,740 46,310,679 99
23,734,113,296 -2,845,499 -593,086 246,580,809 100
124,000 101
-779,590 102
103
23,734,237,296 -2,065,909 -593,086 246,580,809 104
Page 207FERC FORM NO. 1 (REV. 12-05)
Schedule Page: 204 Line No.: 97 Column: b
Balance Balance
Beginning at End
Account Description of Year Additions Retirements Adjustments Transfers of Year (a) (b) (c) (d) (e) (f) (g)
39921 Land Owned in Fee $ 2,634,916 $ - $ - $ - $ - $ 2,634,916
39922 Land Rights 52,550,647 - - - - 52,550,647
39930 Structures 40,275,390 156,436 78,228 - (8,922) 40,344,676
39941 Surface-Plant Equipment 12,735,825 1,216,339 398,134 - - 13,554,030
39944 Surface-Electric Power Facil 3,424,575 - - - - 3,424,575
39945 Underground-Coal Mine Equip 73,172,343 3,211,528 3,019,969 - - 73,363,902
39946 Longwall Shields 24,481,714 4,974 - - - 24,486,688
39947 Longwall Equipment 7,865,108 1,250,804 - - - 9,115,91239948 Mainline Extension 18,899,199 1,069,011 - - - 19,968,210
39949 Section Extension 6,139,057 1,154,829 - - - 7,293,886
39951 Vehicles 1,237,982 41,884 - - (44,215) 1,235,651
39952 Heavy Construction Equip 6,158,245 - - - - 6,158,245
39960 Miscellaneous General Equip 2,331,379 337,401 148,802 - - 2,519,97839961 Computers-Mainframe 392,406 12,461 6,294 - - 398,573
39970 Mine Development and Road Ext 38,414,877 443,161 - - - 38,858,038
39915 Coal Mine ARO 487,112 544,800 - (303,740) - 728,172
$291,200,775 $9,443,628 $3,651,427 $(303,740) $(53,137) $296,636,099
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: e
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.: 101 Column: c
Refer to Important Changes During the Quarter/Year, Item 3, of this Form No. 1.
Schedule Page: 204 Line No.: 102 Column: f
Refer to Important Changes During the Quarter/Year, Item 3, of this Form No. 1.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
PacifiCorp X
/ /2012/Q4
Line Description and Location Date Originally Included Balance atEnd of Year(c)(b)(a)Of Property in This Account Date Expected to be usedin Utility Service (d)No.
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.
Land and Rights: 1
2
1977North Horn Mountain Coal Properties 953,0142023-2028 3
2007Barnes Butte Substation 746,2682023 4
2007Wild Horse Wind Plant 6,763,0942023 5
2007Twelve Mile Wind Plant 2,160,2072021 6
2008Jumbers Point Substation 1,173,2762020 7
2009Mountain Green Substation 284,9962025 8
2009Hoggard Substation 254,3972025 9
2009Oquirrh-Terminal 345-kV Transmission Line 396,0202016 10
2010Bend Service Center 3,507,8382021 11
2010Legacy Substation 562,2762025 12
2011Aeolus Substation 1,014,0532018 13
2011Anticline Substation 964,5052018 14
2011Populus Substation 254,7532021 15
2011Snyderville Substation 253,4012018 16
2012Lassen Substation 683,3182019 17
2012Old Mill Substation 1,837,9422020 18
19
Miscellaneous, each under $250,000 848,022 20
Other Property: 21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-96) Page 214
47 Total 22,657,380
Schedule 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 2023, subject to
environmental and economic reviews and the timing of completion of the Energy Gateway
Transmission 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
Transmission Expansion Program.
Schedule 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.
Schedule Page: 214 Line No.: 20 Column: c
Various dates and plans.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
PacifiCorp X
/ /2012/Q4
Line
No.
Description of Project Construction work in progress -
(b)(a)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.
Intangible: 1
2,056,236IT-Mobility Upgrade / Click Replacement 2
1,294,424Call Center Automated Call Distribution Replacement Project 3
4
Production: 5
434,091,679Lake Side 2 Development 6
47,808,833Lewis River System Relicensing Implementation 7
21,741,404Jim Bridger U2 Turbine Upgrade HP/IP/LP 8
18,578,016Blundell Proofing Well Integration 9
18,329,457Hunter U1 Clean Air - Particulate Matter Emissions 10
2,744,421North Umpqua Coating Projects 11
2,709,148Merwin Spillway Tainter Gate Rehab 12
2,078,208Currant Creek 2 Build 13
1,915,430Blundell U1 Turbine Exhaust Casing 14
1,321,147Hayden U1 Selective Catalytic Reducer Installation 15
1,151,720Swift 1 Trunnion Improvements 16
1,129,037Jim Bridger U2 Replace Cooling Tower 17
18
Transmission: 19
300,034,261Mona-Oquirrh 345kV/500kV Transmission Line 20
71,642,657Energy Gateway Preliminary Engineering and Permitting 21
47,503,892Sigurd-Red Butte-Crystal 345kV Line 22
35,748,021Aeolus Clover 500kV Line 23
12,889,716Southwest WY Silver Creek Build 138kV Line 24
9,681,638Boardman - Hemingway - 500kV Line 25
8,830,060Lake Side 2 Interconnect Q0301 26
8,029,016Oquirrh-Terminal 345kV Line 27
6,114,428Carbon County System Reinforcement 28
5,191,766West Point-New 138kV Line & 40 MVA Substation 29
4,495,330TOT 4A-4B Transmission Path Transfer Capacity 30
4,352,705Vantage-Pomona Heights 230kV Line 31
4,066,860Cameron-Milford 138kV Transmission 32
3,854,410Clover Substation install 345-138kV Sub & Lines 33
3,551,291Black Rock New 230-69kV Substation 34
3,317,749Wallula-McNary 230kV Line 35
2,965,423Dave Johnston U3 GSU Transformer 36
2,924,684Jim Bridger U1 Replace / Rewind GSU 37
2,717,860Facebook Data Center Phase 2 Tom McCall Industrial Park - 115kV Project 38
2,596,348COPCO II 230-115kV Transformer - TPL002 39
2,569,936Line 37 Convert to 115kV Build Nickel Mt Substation 40
2,451,088Terminal Substation 345-138kV Trnsf to 700 MVA 41
2,141,572Line 3 Convert to 115kV 42
FERC FORM NO. 1 (ED. 12-87) Page 216
43 TOTAL 1,250,513,185
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
PacifiCorp X
/ /2012/Q4
Line
No.
Description of Project Construction work in progress -
(b)(a)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.
1,867,897UT-NERC Line Rating Project-Medium Priority Lines 1
1,815,737Whetstone 230-115kV Sub Phase 1 2
1,794,746Wyodak U1 - Generator Step-up Transformer Spare 3
1,787,373Three Peaks Substation: Install 345kV Sub 4
1,624,967Two Elks Intercon at Tri County Switchyard 5
1,370,972West of Populus Transmission Path Upgrades 6
1,369,534Malin Sub: Replace 500kV Circuit Switcher 11L2 7
1,111,631Union Gap Pacific 115kV Reconductor 8
1,058,885OR-NERC Line Rating Project-Medium Priority Lines 9
10
Distribution: 11
5,986,249Fort Douglas-New 138-12.5kV Substation & Transfmr 12
1,192,472WA Avian Protect Walla-Walla 13
14
General: 15
19,393,567Mobile Radio Replacement Project 16
3,638,756Cottonwood Prep Plant-Improvements 17
2,517,871Data Center Switch Replacement 18
1,393,387Starvout - Fort Rock Microwave Replacement 19
1,177,613Spores Point - Starveout Microwave Replacement 20
1,124,346Blowhard - Beaver Dam Microwave Replacement 21
1,055,692Deer Creek - 1 Continuous Miner 22
23
94,611,619Miscellaneous Projects each under $1,000,000 24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-87) Page 216.1
43 TOTAL 1,250,513,185
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
PacifiCorp X
/ /2012/Q4
Line
No.
Item Total
(c)(b)(a)(d)
Section A. Balances and Changes During Year
(c+d+e)Electric Plant inService Electric Plant Held for Future Use Electric PlantLeased to Others(e)
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.
Balance Beginning of Year 1 7,062,181,013 7,062,181,013
Depreciation Provisions for Year, Charged to 2
(403) Depreciation Expense 3 571,953,425 571,953,425
(403.1) Depreciation Expense for Asset
Retirement Costs
4
(413) Exp. of Elec. Plt. Leas. to Others 5
Transportation Expenses-Clearing 6
Other Clearing Accounts 7
Other Accounts (Specify, details in footnote): 8 33,676,768 33,676,768
9
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
10 605,630,193 605,630,193
Net Charges for Plant Retired: 11
Book Cost of Plant Retired 12 218,137,370 218,137,370
Cost of Removal 13 68,875,093 68,875,093
Salvage (Credit) 14 6,631,943 6,631,943
TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
15 280,380,520 280,380,520
Other Debit or Cr. Items (Describe, details in
footnote):
16 17,236,735 17,236,735
17
Book Cost or Asset Retirement Costs Retired 18
Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
19 7,404,667,421 7,404,667,421
Steam Production 20
Section B. Balances at End of Year According to Functional Classification
2,505,658,617 2,505,658,617
Nuclear Production 21
Hydraulic Production-Conventional 22 264,903,753 264,903,753
Hydraulic Production-Pumped Storage 23
Other Production 24 579,208,388 579,208,388
Transmission 25 1,285,912,340 1,285,912,340
Distribution 26 2,268,075,733 2,268,075,733
Regional Transmission and Market Operation 27
General 28 500,908,590 500,908,590
TOTAL (Enter Total of lines 20 thru 28) 29 7,404,667,421 7,404,667,421
Page 219FERC FORM NO. 1 (REV. 12-05)
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 $10,733,499
Account 143, Other accounts receivable, - depreciation
expense billed to joint owners 202,129
Asset retirement obligation asset depreciation recorded
as a regulatory asset or liability 5,558,918
Transportation depreciation allocated to O&M and construction
based on usage activity 15,898,715
Account 503, Steam from other sources, - Blundell depletion 185,368
Account 503, Steam from other sources, - Blundell depreciation 1,098,139
Total other accounts $33,676,768
Schedule Page: 219 Line No.: 16 Column: b
Reclassification of accrued removal and spend on asset
retirement obligations that were included in lines 3 and 13. $12,287,596
Other items include: 4,949,139
- 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 $17,236,735
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
PacifiCorp X
/ /2012/Q4
Line
No.
Description of Investment Date Acquired
(c)(b)(a)
Amount of Investment atBeginning of YearDate Of Maturity (d)
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.
1973PACIFIC MINERALS, INC. 1
1 Common Stock 2
47,960,000 Paid-in Capital 3
140,245,757 Undistributed Subsidiary Earnings 4
188,205,758 SUBTOTAL 5
6
1990ENERGY WEST MINING COMPANY 7
1,000 Common Stock 8
1,000 SUBTOTAL 9
10
1990CENTRALIA MINING COMPANY 11
1,000 Common Stock 12
1,000 SUBTOTAL 13
14
1991GLENROCK COAL COMPANY 15
1 Common Stock 16
1 SUBTOTAL 17
18
1992INTERWEST MINING COMPANY 19
1,000 Common Stock 20
1,000 SUBTOTAL 21
22
1992TRAPPER MINING INC. 23
6,038,000 Members' Equity 24
5,886,201 Undistributed Subsidiary Earnings 25
11,924,201 SUBTOTAL 26
27
1994PACIFICORP ENVIRONMENTAL REMEDIATION COMPANY 28
14,719,625 Paid-in Capital 29
5,785,167 Undistributed Subsidiary Earnings 30
20,504,792 SUBTOTAL 31
32
2011FOSSIL ROCK FUELS, LLC 33
20,320,000 Paid-in Capital 34
-1,484 Undistributed Subsidiary Earnings 35
20,318,516 SUBTOTAL 36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89) Page 224
42 Total Cost of Account 123.1 $TOTAL 240,956,268 81,763,431
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
Equity in Subsidiary Earnings of Year Revenues for Year Amount of Investment atEnd of Year Gain or Loss from InvestmentDisposed of(e) (f) (g) (h)
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
1
1 2
47,960,000 3
151,388,983 11,143,226 4
199,348,984 11,143,226 5
6
7
1,000 8
1,000 9
10
11
1,000 12
1,000 13
14
15
1 16
1 17
18
19
1,000 20
1,000 21
22
23
6,038,000 24
5,916,977 30,776 25
11,954,977 30,776 26
27
28
29
5,827,818 42,651 30
5,827,818 42,651 31
32
33
27,762,429 34
-6,907 -5,423 35
27,755,522 -5,423 36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89) Page 225
42 11,211,230 239,062,484 5,827,818
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.: 30 Column: h
Effective July 1, 2012, PacifiCorp Environmental Remediation Company ("PERCo")was
dissolved, and all assets and liabilities of PERCo were assumed by PacifiCorp.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MATERIALS AND SUPPLIES
PacifiCorp X
/ /2012/Q4
Line
No.
Account Balance Balance
(c)(b)(a)
Department orDepartments which
(d)
Beginning of Year End of Year Use Material
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.
236,891,214 Electric 265,591,187 1 Fuel Stock (Account 151)
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
106,787,597 Electric 83,816,884 5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
65,342,036 Electric 98,097,803 7 Production Plant (Estimated)
507,347 Electric 750,972 8 Transmission Plant (Estimated)
17,729,257 Electric 13,817,380 9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant
(Estimated)
6,198,530 Electric 6,041,605 11 Assigned to - Other (provide details in footnote)
196,564,767 202,524,644 12 TOTAL Account 154 (Enter Total of lines 5 thru 11)
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
433,455,981 468,115,831 20 TOTAL Materials and Supplies (Per Balance Sheet)
Page 227FERC FORM NO. 1 (REV. 12-05)
Schedule Page: 227 Line No.: 11 Column: b
Mining materials and supplies $ 5,964,328
General plant materials and supplies 234,202
$ 6,198,530

Schedule Page: 227 Line No.: 11 Column: c
Mining materials and supplies $ 5,910,897
General plant materials and supplies 130,708
$ 6,041,605

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Allowances (Accounts 158.1 and 158.2)
PacifiCorp X
/ /2012/Q4
Line
No.
SO2 Allowances Inventory Current Year
(b)(a)(Account 158.1)No. Amt.(c)No.(d)Amt.(e)
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.
2013
237,269.00 156,646.00Balance-Beginning of Year 1
2
Acquired During Year: 3
Issued (Less Withheld Allow) 4
Returned by EPA 5
6
7
Purchases/Transfers: 8
9
10
11
12
13
14
Total 15
16
Relinquished During Year: 17
43,287.00 Charges to Account 509 18
Other: 19
20
Cost of Sales/Transfers: 21
80,134.00Luminant Energy Co. LLC 22
23
24
25
26
27
80,134.00Total 28
113,848.00 156,646.00Balance-End of Year 29
30
Sales: 31
Net Sales Proceeds(Assoc. Co.) 32
Net Sales Proceeds (Other) 33
Gains 34
Losses 35
Allowances Withheld (Acct 158.2)
2,259.00 2,259.00Balance-Beginning of Year 36
Add: Withheld by EPA 37
Deduct: Returned by EPA 38
2,259.00Cost of Sales 39
2,259.00Balance-End of Year 40
41
Sales: 42
Net Sales Proceeds (Assoc. Co.) 43
Net Sales Proceeds (Other) 44
Gains 45
Losses 46
FERC FORM NO. 1 (ED. 12-95) Page 228a
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Allowances (Accounts 158.1 and 158.2)
PacifiCorp X
/ /2012/Q4
Line
No.(f) (j)No. Amt.(g)No.(h)Amt.(i)No. Amt. No. Amt.(k) (l) (m)
Future Years Totals
(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.
2014 2015
1 4,055,608.00 136,466.00 156,645.00 4,742,634.00
2
3
4 156,645.00 156,645.00
5
6
7
8
9
10
11
12
13
14
15
16
17
18 43,287.00
19
20
21
22 80,134.00
23
24
25
26
27
28 80,134.00
29 4,212,253.00 136,466.00 156,645.00 4,775,858.00
30
31
32
33
34
35
36 110,921.00 2,259.00 2,259.00 119,957.00
37 4,528.00 4,528.00
38
39 2,269.00 4,528.00
40 113,180.00 2,259.00 2,259.00 119,957.00
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-95) Page 229a
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
PacifiCorp X
/ /2012/Q4
Line
No.
(c)(b)(a)(d)
Description of Unrecovered Plant Total Amount of Charges
CostsRecognisedDuring Year
WRITTEN OFF DURING YEAR
AccountCharged Amount
Balance at
End of Year
(f)(e)
and Regulatory Study Costs [Includein the description of costs, the date ofCommission Authorization to use Acc 182.2and period of amortization (mo, yr to mo, yr)]
Unrecovered Plant:21
UT-Naughton Unit #3 environmental22
upgrades 3,415,498 407 401,958 3,013,54023
Plant located near Evanston, WY24
Date of Retirement: 10/12/201225
Date of Commission Authorization:26
09/19/201227
Amortization Period: 10/12/201228
through 08/31/201429
30
Unrecovered Plant:31
WY-Naughton Unit #3 environmental32
upgrades 1,218,111 407 105,102 1,113,00933
Plant located near Evanston, WY34
Date of Retirement: 10/22/201235
Date of Commission Authorization:36
10/8/201237
Amortization Period: 10/22/201238
through 12/31/201439
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-88)Page 230b
49 TOTAL 4,633,609 507,060 4,126,549
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2012/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
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.
the Period
Transmission Studies 1
6,322AREF 690566 561.6 6,322 456 2
3,155AREF 690831 561.6 3,155 456 3
6,091AREF 709133 561.6 6,091 456 4
2,883AREF 709137 561.6 2,883 456 5
1,828AREF 723846 561.6 1,828 456 6
35,509AREF 739339 561.6 35,509 456 7
7,886AREF 754172 561.6 7,886 456 8
13,917AREF 784538 561.6 13,917 456 9
18,208AREF 792853 561.6 18,208 456 10
3,968Legacy Study #1 561.6 3,968 456 11
2,379AREF's 752193,752219,752241,752243 561.6 12
4,527AREF 758483 561.6 13
13,641AREF 759777 561.6 14
5,338AREF 759779 561.6 15
4,263AREF 760025 561.6 16
( 2,054)AREF 648008 561.6 17
1,234Integrated Resource Planning Agrmt 107 18
918AREF 468352 107 19
693AREF 728784 107 20
Generation Studies 21
57GIQ0187 561.7 57 456 22
278GIQ0217 561.7 278 456 23
265GIQ0252 561.7 265 456 24
4,658GIQ0255 561.7 4,658 456 25
490GIQ0306 561.7 490 456 26
21GIQ0310 561.7 21 456 27
15,832GIQ0311 561.7 15,832 456 28
3,147GIQ0313 561.7 3,147 456 29
21GIQ0314 561.7 21 456 30
495GIQ0315 561.7 495 456 31
2,689GIQ0316 561.7 2,689 456 32
1,608GIQ0322 561.7 1,608 456 33
1,742GIQ0332 561.7 1,742 456 34
2,078GIQ0333 561.7 2,078 456 35
3,900GIQ0335 561.7 3,900 456 36
1,923GIQ0341 561.7 1,923 456 37
1,058GIQ0356 561.7 1,058 456 38
9,805GIQ0367 561.7 9,805 456 39
40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2012/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
929AREF 740690 107 2
1,084AREF 741886 107 3
1,896AREF 752491 107 4
151AREF 758483 107 5
15,108AREF 781578 107 6
5,983AREF 802603 107 7
3,559AREF 805002 107 8
1,818AREF 806561 107 9
1,855AREF 806544 107 10
1,855AREF 806494 107 11
1,818AREF 807115 107 12
1,969AREFS 809254 & 809362 107 13
1,174AREFS 809252 & 890367 107 14
1,060AREFS 809397 & 809398 107 15
1,212AREFS 809337 & 809374 107 16
1,212AREFS 809340 & 809375 107 17
1,022AREFS 809357 & 809382 107 18
1,060AREFS 809355 & 809380 107 19
947AREFS 809353 & 809378 107 20
Generation Studies 21
33,102GIQ0372 561.7 33,102 456 22
1,207GIQ0373 561.7 1,207 456 23
147GIQ0374 561.7 147 456 24
10,420GIQ0375 561.7 10,420 456 25
8,252GIQ0377 561.7 8,252 456 26
10,606GIQ0384 561.7 10,606 456 27
240GIQ0386 561.7 240 456 28
3,153GIQ0389 561.7 3,153 456 29
3,330GIQ0392 561.7 3,330 456 30
23,065GIQ0393 561.7 23,065 456 31
6,118GIQ0395 561.7 6,118 456 32
204GIQ0396 561.7 204 456 33
15,727GIQ0397 561.7 15,727 456 34
1,736GIQ0398 561.7 1,736 456 35
319GIQ0400 561.7 319 456 36
21,175GIQ0401 561.7 21,175 456 37
25,820GIQ0403 561.7 25,820 456 38
16,067GIQ0404 561.7 16,067 456 39
873GIQ0405 561.7 873 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2012/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
795AREFS 809347 & 809376 107 2
3,408AREF 812779 107 3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
6,841GIQ0406 561.7 6,841 456 22
36,624GIQ0407 561.7 36,624 456 23
4,261GIQ0408 561.7 4,261 456 24
52,114GIQ0409 561.7 52,114 456 25
328GIQ0410 561.7 328 456 26
45,492GIQ0411 561.7 45,492 456 27
4,164GIQ0412 561.7 4,164 456 28
13,048GIQ0413 561.7 13,048 456 29
23,787GIQ0414 561.7 23,787 456 30
10,658GIQ0415 561.7 10,658 456 31
783GIQ0416 561.7 783 456 32
10,954GIQ0417 561.7 10,954 456 33
2,681GIQ0418 561.7 2,681 456 34
2,472GIQ0419 561.7 2,472 456 35
17,419GIQ0420 561.7 17,419 456 36
1,639GIQ0421 561.7 1,639 456 37
10,939GIQ0422 561.7 10,939 456 38
3,687GIQ0423 561.7 3,687 456 39
2,247GIQ0424 561.7 2,247 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2012/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
28,015GIQ0425 561.7 28,015 456 22
10,864GIQ0426 561.7 10,864 456 23
18,573GIQ0427 561.7 18,573 456 24
391GIQ0428 561.7 391 456 25
720GIQ0429 561.7 720 456 26
14,642GIQ0430 561.7 14,642 456 27
9,560GIQ0431 561.7 9,560 456 28
9,777GIQ0432 561.7 9,777 456 29
7,607GIQ0433 561.7 7,607 456 30
727GIQ0434 561.7 727 456 31
1,008GIQ0435 561.7 1,008 456 32
4,351GIQ0436 561.7 4,351 456 33
2,395GIQ0437 561.7 2,395 456 34
2,657GIQ0438 561.7 2,657 456 35
2,510GIQ0439 561.7 2,510 456 36
3,057GIQ0440 561.7 3,057 456 37
1,789GIQ0441 561.7 1,789 456 38
7,272GIQ0442 561.7 7,272 456 39
5,039GIQ0443 561.7 5,039 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2012/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
916GIQ0444 561.7 916 456 22
876GIQ0445 561.7 876 456 23
1,101GIQ0446 561.7 1,101 456 24
2,364Customer Studies Accrual 561.7 25
623GIQ0267 107 26
8,444GIQ1497 107 27
822GIQ1256 107 28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER REGULATORY ASSETS (Account 182.3)
PacifiCorp X
/ /
2012/Q4
Line
No.
Description and Purpose of Debits CREDITS
Written off During the
Quarter /Year Account
Charged (d)(c)(a)
Balance at end of
Current Quarter/Year
(e)
Other Regulatory Assets Written off During
the Period Amount
(f)
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.
Balance at Beginning
of Current
Quarter/Year
(b)
( 2,758,978) -765,482 133,534908,431 2,127,030DSM Regulatory Asset - CA 1
2,734,590 511,241 5,599,309908,431 3,375,960DSM Regulatory Asset - ID 2
( 4,822,974) -8,206,230 49,051,923908,431 45,668,667DSM Regulatory Asset - UT 3
1,438,228 1,428,381 10,089,223908 10,079,376DSM Regulatory Asset - WA 4
138,393 591,995 3,439,874908,431 3,893,476DSM Regulatory Asset - WY 5
26,627 47,164908 20,537DSM Regulatory Asset - OR 6
( 237,632) -621,982 450,039142,431 65,689Alternative Rate For Energy (CARE) - CA 7
912,507 917,369920,254 4,8622006 Transition Plan - OR (2) 8
44,554 44,5549202006 Transition Plan - CA (1) 9
443,887,834 455,760,491 11,872,657Deferred Income Taxes Electric 10
1,972,627 1,972,627431Deferral of Interest on Uncertain Tax Positions-UT 11
531,334 531,334431Deferral of Interest on Uncertain Tax Positions-WY 12
271,404 271,404431Deferral of Interest on Uncertain Tax Positions-ID 13
70,531 70,531Tax Revenue Requirement Adjustment - WY 14
2,107,096 1,612,339 495,101555,431 344Deferred Excess Net Power Costs/ECAC - CA (1) 15
1,078,176 1,078,176Deferred Excess Net Power Costs/ECAC - CA 2012 16
3,249,063 3,755,610555 506,547Deferred Excess Net Power Costs - WY 2010 (1) 17
32,442,978 19,840,990 12,962,759555,182.3 360,771Deferred Excess Net Power Costs - WY 2011 (3) 18
16,158,619 16,158,619Deferred Excess Net Power Costs - WY 2012 19
816,688 -103,748 928,405555 7,969Deferred Excess Net Power Costs - WA Hydro (3) 20
5,049,290 5,059,085555,182.3 9,795Deferred Excess Net Power Costs - ID 2010 (1) 21
10,484,722 2,990,916 10,597,959555 3,104,153Deferred Excess Net Power Costs - ID 2011 (1) 22
7,213,116 5,080,104 2,178,687555 45,675Deferred Excess NPC - ID 2011 Monsanto (3) 23
514,074 235,069 281,825555 2,820Deferred Excess NPC - ID 2011 Agrium (3) 24
8,099,210 8,099,210Deferred Excess Net Power Costs - ID 2012 25
5,904,771 5,904,771Deferred Excess NPC - ID 2012 Monsanto 26
433,113 433,113Deferred Excess NPC - ID 2012 Agrium 27
205,171 205,171Deferred Excess Net Power Costs - ID 2013 28
150,215 150,215Deferred Excess NPC - ID 2013 Monsanto 29
10,991 10,991Deferred Excess NPC - ID 2013 Agrium 30
59,188,678 47,673,941 11,514,737555,431Deferred Excess NPC - UT Pre Oct 2011 (3) 31
8,598,582 9,519,590 921,008Deferred Excess NPC - UT Oct 2011-Dec2011 32
15,927,630 15,927,630Deferred Excess Net Power Costs - UT 2012 33
( 371,950) 1,412,675182.3 1,784,625Deferred Excess RECs in Rates - UT 2010-Aug 2011 34
355,313 1,767,988456,419 1,412,675Deferred Excess RECs in Rates - UT Sep'11-Dec2011 35
-2,753,648 2,753,648456,419Deferred Excess RECs in Rates/RBA - UT 2012 36
681,343 1,436,507456 755,164Deferred Excess RECs in Rates - WA 37
1,342,787 2,982,609182.3 1,639,822Deferred Excess RECs in Rates - WY 2010-2011 (1) 38
( 1,859,952) 828,583 1,330,409456 4,018,944Deferred Excess RECs in Rates - WY 2011-2012 (1) 39
587,013 587,013Deferred Excess RECs/SO2 in Rates/RRA - WY 2012 40
9,668,110 11,758,980 1,870,953925 3,961,823Environmental Costs (10) 41
( 750,287) -905,335 293,244925 138,196Environmental Costs - WA (10) 42
12,555,829 21,662,558 9,106,729Reg Asset - Environmental Costs 43
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER REGULATORY ASSETS (Account 182.3)
PacifiCorp X
/ /
2012/Q4
Line
No.
Description and Purpose of Debits CREDITS
Written off During the
Quarter /Year Account
Charged (d)(c)(a)
Balance at end of
Current Quarter/Year
(e)
Other Regulatory Assets Written off During
the Period Amount
(f)
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.
Balance at Beginning
of Current
Quarter/Year
(b)
5,240,697 4,302,064 1,122,425557 183,792Cholla Plant Transaction Costs (26) 1
474,071 421,883 52,188456Washington Colstrip #3 (22) 2
186,949,133 166,028,027 20,921,106242Unamortized Contract Values 3
263,192,671 120,369,451 142,823,220175,244Derivative Net Regulatory Asset 4
48,958,738 55,451,404 6,492,666Asset Retirement Obligations Regulatory Difference 5
728,497,656 775,965,726 39,343,723 86,811,793Pension/Other Postretirement 6
355,527 -6,035 363,836904 2,274RTO Grid West N/R - OR (3) 7
75,740 -114,940 272,592557 81,912Deferred Independent Evaluator Fee - UT (1) 8
( 191,894) 97,200 522419 289,616Deferred Independent Evaluator Fee - OR (1) 9
32,885 32,952 67Deferred Intervenor Funding Grants - CA 10
58,702 69,206 39,201928 49,705Deferred Intervenor Funding Grants - ID (2) 11
345,643 585,536 239,893Deferred Intervenor Funding Grants - OR 12
1,294,754 257,230 1,037,524440,442BPA Balancing Account - ID 13
( 70,249) 45,978 116,227Renewable Adjustment Clause - OR (1) 14
467,500 446,250 21,250930.2Goodnoe Hills Settlement - WY (24) 15
977,176 949,747 27,429930.2Lake Side Settlement - WY (39) 16
6,907,908 -11,834 6,940,921 21,179SB 408 Regulatory Asset - OR (1) 17
( 49,394) 930 145431 50,469SB 408 Regulatory Asset - MCBIT (1) 18
12,000,000 9,000,000 3,000,000Chehalis Generating Facility Deferral - WA (6) 19
212,720 193,631 24,315407.3 5,226Powerdale Decommissioning - ID (10) 20
638,841 354,912 283,929407.3Powerdale Decommissioning - WA (3) 21
33,069 33,069407.3Powerdale Decommissioning - CA (2) 22
1,270,447 2,751,487 851,297 2,332,337Solar Feed-In Tariff Deferral - OR (1) 23
( 246,352) -354,070 1,009,460 901,742Solar Feed-In Tariff Deferral - CA 24
-867,043 953,696 86,653Solar Incentive Program - UT 25
255,623 127,813 127,810283,410.1Tax Adj on Postretirement Benefits - CA (3) 26
614,991 409,994 204,997283,410.1Tax Adj on Postretirement Benefits - ID (4) 27
4,471,643 4,471,643Tax Adj on Postretirement Benefits - OR 28
4,320,249 2,749,250 1,570,999283,410.1Tax Adj on Postretirement Benefits - UT (4) 29
1,677,403 1,118,269 559,134283,410.1Tax Adj on Postretirement Benefits - WY (4) 30
65,994 65,994924Storm Damage Deferral - CA (1) 31
176,052 169,233 532,342501 525,523Deferred Overburden Cost - ID 32
487,998 466,888 1,479,092501 1,457,982Deferred Overburden Cost - WY 33
8,226,541 1,093,000 9,319,541Postemployment Costs 34
102,043 102,043Naughton Unit No. 3 Environmental Costs 35
478,988 478,988Naughton Unit No. 3 Environmental Costs - ID 36
34,709,389 988,285404 35,697,674Klamath Hydroelectric Relicensing Costs - UT (10) 37
9,545,204 17,526,652 7,981,448Regulatory Assets - Reclassifications 38
39
40
41
42
43
1,874,535,671TOTAL :44 1,821,244,610 359,960,034 306,668,973
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232.1
Schedule Page: 232 Line No.: 10 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: 232.1 Line No.: 3 Column: a
Weighted average remaining life is 9 years. Represents frozen values of contracts
previously accounted for as derivatives and recorded at fair value.
Schedule Page: 232.1 Line No.: 4 Column: a
Weighted average remaining life is 1 year.
Schedule Page: 232.1 Line No.: 6 Column: a
Weighted average remaining life is 9 years. Substantially represents amounts not yet
recognized as a component of net periodic benefit cost that are expected to be included in
rates when recognized.
Schedule Page: 232.1 Line No.: 6 Column: d
Pensions and benefits are associated with labor and generally charged to operations and
maintenance expense and construction work in progress.
Schedule Page: 232.1 Line No.: 14 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Account 431, Other interest expense
Schedule Page: 232.1 Line No.: 17 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
Schedule Page: 232.1 Line No.: 23 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Account 445, Other sales to public authorities
Schedule Page: 232.1 Line No.: 24 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Account 445, Other sales to public authorities
Schedule Page: 232.1 Line No.: 25 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Account 445, Other sales to public authorities
Schedule Page: 232.1 Line No.: 34 Column: a
Weighted average remaining life is 6 years.
Schedule Page: 232.1 Line No.: 34 Column: d
Pensions and benefits are associated with labor and generally charged to operations and
maintenance expense and construction work in progress.
Schedule Page: 232.1 Line No.: 38 Column: f
The following schedule summarizes regulatory assets reclassifications:
As of
Reclassified from Regulatory Assets to Regulatory Liabilities: December 31, 2012
DSM Regulatory Asset - CA $ 765,482
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
DSM Regulatory Asset - UT 8,206,230
Alternative Rate For Energy (CARE) - CA 621,982
Deferred Excess Net Power Costs - WA Hydro 103,748
Deferred Excess RECs in Rates/RBA - UT 2012 2,753,648
RTO Grid West N/R - OR 6,035
Deferred Independent Evaluator Fee - UT 114,940
SB 408 Regulatory Asset - OR and MCBIT 10,904
Solar Feed-In Tariff Deferral - CA 354,070
Solar Incentive Program - UT 867,043
Reclassified from Regulatory Liabilities to Regulatory Assets:
Injuries & Damage Reserve - OR 614,814
Property Insurance Reserve - OR 3,107,756
$ 17,526,652
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MISCELLANEOUS DEFFERED DEBITS (Account 186)
PacifiCorp X
/ /2012/Q4
Line
No.
Description of Miscellaneous Debits CREDITS
Account
(c)(b)(a)
Balance at
End of Year
(d)
Deferred Debits Amount
(e)
Balance at
Beginning of Year
(f)Charged
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.
835,733 698,352 137,381557Joseph Settlement (21) 1
2
461,010 415,290 45,720557Lacomb Irrigation (24) 3
4
1,159,280 1,118,000 41,280557Bogus Creek (41) 5
6
Mead Phoenix Availability and 7
13,379,000 13,001,240 377,760565Transmission Charge (50) 8
9
125,078 109,604 15,474557TGS Buyout (23) 10
11
3,041,984 2,779,963 1,233,569 971,548 142Point to Point Transmission 12
13
172,625 89,765 82,860557Jim Boyd Hydro Buyout (11) 14
15
4,220,791 4,049,098 171,693557Hermiston Swap (40) 16
17
1,946,280 2,012,614 66,334 565LGIA LT Transmission Prepaid 18
19
919,138 1,135,424 3,803,406 4,019,692 151Deferred Longwall Costs 20
21
Deferred Coal Costs - Wyodak 22
3,687,000 3,351,818 335,182151Settlement (22) 23
24
Deferred Coal Costs - Naughton 25
6,880,769 5,504,615 1,376,154151Settlement (7) 26
27
Deferred Coal Costs - Jim 28
2,916,673 2,916,673Bridger Plant 29
30
Deferred Colstrip Plant 31
1,225,000 925,000 300,000501Costs (5) 32
33
Deferred Royalty Reduction - 34
742,039 742,039Craig Plant 35
36
LT Lease Commissions 37
556,839 464,020 92,819931Prepaids (10) 38
39
11,127,700 18,058,649 6,930,949Lake Side Maintenance Prepaid 40
41
7,429,493 9,718,670 2,289,177Chehalis Maintenance Prepaid 42
43
11,484,936 812,932 16,200,336 5,528,332 107Currant Creek Maint. Prepaid 44
45
960,109 804,990 155,119454Lease Incentives (10) 46
FERC FORM NO. 1 (ED. 12-94) Page 233
49 TOTAL
47 Misc. Work in Progress
48 Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
88,864,233 86,782,863
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MISCELLANEOUS DEFFERED DEBITS (Account 186)
PacifiCorp X
/ /2012/Q4
Line
No.
Description of Miscellaneous Debits CREDITS
Account
(c)(b)(a)
Balance at
End of Year
(d)
Deferred Debits Amount
(e)
Balance at
Beginning of Year
(f)Charged
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.
1
594,513 1,917,712 697,735 2,020,934 427,431Credit Agreement Costs (5) 2
3
139,592 203,282 322,136 385,826 427PCRB LOC/SBBPA Costs 4
5
269,044 145,615 123,429427PCRB Mode Conversion Costs 6
7
871,450 754,468 116,982427'94 Series Restruct. Costs 8
9
LT Prepaid IBEW 57 Pension 10
5,651,545 5,934,114 282,569Contribution 11
12
8,584,039 8,017,011 863,304 296,276 565BPA LT Transmission Prepaid 13
14
2,631,396 2,631,396Emission Reduction Credits 15
16
478,212 421,569 56,643174Unamortized contract values 17
18
Sales of Electric Utility 19
1,677 61,554 13,448 73,325 539Facilities & Properties 20
21
30,000 30,000131Other Current Deferred Charges 22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-94) Page 233.1
49 TOTAL
47 Misc. Work in Progress
48 Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
88,864,233 86,782,863
Schedule Page: 233.1 Line No.: 4 Column: a
Weighted average life is 2 years.
Schedule Page: 233.1 Line No.: 6 Column: a
Weighted average life is 8 years.
Schedule Page: 233.1 Line No.: 8 Column: a
Weighted average life is 16 years.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
PacifiCorp X
/ /2012/Q4
Line
No.
Description and Location Balance of Begining
(c)(b)(a)
Balance at Endof Year of Year
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.
Electric 1
216,807,008 209,587,367Employee Benefits 2
69,029,182 62,018,522State Carryforwards 3
63,351,855 72,107,587Unamortized Contract Values 4
45,681,407 99,884,250Derivative Contracts 5
39,958,098 43,186,293Regulatory Liabilities 6
213,391,455 152,861,736Other 7
648,219,005 639,645,755TOTAL Electric (Enter Total of lines 2 thru 7) 8
Gas 9
10
11
12
13
14
Other 15
TOTAL Gas (Enter Total of lines 10 thru 15 16
Other (Specify) 17
648,219,005 639,645,755TOTAL (Acct 190) (Total of lines 8, 16 and 17) 18
Notes
FERC FORM NO. 1 (ED. 12-88) Page 234
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CAPITAL STOCKS (Account 201 and 204)
PacifiCorp X
/ /2012/Q4
Line
No.
Class and Series of Stock and Number of shares
(c)(b)(a)
Call Price at
End of Year
Par or Stated
Value per share
(d)
Name of Stock Series Authorized by Charter
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.
750,000,000Common Stock (Account 201) 1
MidAmerican Energy Holdings Company 2
indirectly owns all of the shares of 3
PacifiCorp's outstanding common stock. 4
Therefore, there is no public market for 5
PacifiCorp's common stock. 6
7
750,000,000TOTAL COMMON STOCK 8
9
10
Preferred Stock (Account 204): 11
110.00 100.00 126,5335% Cumulative Preferred 12
13
3,500,000Serial Preferred, Cumulative: 14
103.50 100.004.52% Series 15
100.007.00% Series 16
100.006.00% Series 17
100.00 100.005.00% Series 18
101.00 100.005.40% Series 19
103.50 100.004.72% Series 20
102.34 100.004.56% Series 21
16,000,000No Par Serial Preferred 22
19,626,533TOTAL PREFERRED STOCK 23
24
25
26
27
28
29
30
31
32
Authorized and Unissued Capital Stock 33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-91) Page 250
AS REACQUIRED STOCK (Account 217)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CAPITAL STOCKS (Account 201 and 204) (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT
IN SINKING AND OTHER FUNDS
Shares(g)Cost(h)Shares SharesAmount
(Total amount outstanding without reductionfor amounts held by respondent)
Amount(e) (f)(i) (j)
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.
3,417,945,896 357,060,915 1
2
3
4
5
6
7
3,417,945,896 357,060,915 8
9
10
11
12,624,300 126,243 12
13
14
206,500 2,065 15
1,804,600 18,046 16
593,000 5,930 17
4,190,800 41,908 18
6,595,900 65,959 19
6,585,400 65,854 20
8,132,600 81,326 21
22
40,733,100 407,331 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
Schedule Page: 250 Line No.: 1 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, 2012, 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line Item Amount(b)(a)
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
No.
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.
Account 211 Miscellaneous Paid-in Capital 1
Additional Paid-in Capital 2
1,973,218Share based payments 3
14,422,979Tax benefit from stock option exercises 4
-3,575,760Benefit plan separation 5
1,089,950,000Capital contributions 6
136,208Gain on sale of Scottish Power plc stock 7
-1,275,241Qualified production activity tax deduction 8
432,552Contribution of Intermountain Geothermal 9
166,025Gain on repurchase of preferred stock 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
FERC FORM NO. 1 (ED. 12-87) Page 253
40 TOTAL 1,102,229,981
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.
Schedule 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 MEHC to PacifiCorp during the year ended December 31, 2012.
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 Internal Revenue Code Section 199 qualified production
activities.
Schedule Page: 253 Line No.: 9 Column: b
Represents contribution of Intermountain Geothermal Company to PacifiCorp from MEHC in
March 2006, subsequent to the sale of PacifiCorp to MEHC. Intermountain Geothermal Company
was merged with and into its direct parent, PacifiCorp, on August 31, 2007, with
PacifiCorp surviving.
Schedule Page: 253 Line No.: 10 Column: b
Represents gain on PacifiCorp's repurchase of certain shares of its preferred stock in May
2010.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CAPITAL STOCK EXPENSE (Account 214)
PacifiCorp X
/ /2012/Q4
Line
No.
Class and Series of Stock Balance at End of Year(b)(a)
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.
41,101,062Common Stock 1
2
Preferred Stock: 3
98,0495.00% 4
9,6764.52% Serial 5
28,5964.72% Serial 6
47,1774.56% Serial 7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
FERC FORM NO. 1 (ED. 12-87) Page 254b
22 TOTAL 41,284,560
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224)
PacifiCorp X
/ /2012/Q4
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
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.
Bonds: (Account 221) 1
First Mortgage Bonds: 2
3
19,772,000 8.493% Series due October 1, 2012 4
16,203,000 8.797% Series due October 1, 2013 5
1,422,659 200,000,000 5.45% Series due September 15, 2013 6
232,000 7 D
1,442,365 200,000,000 4.95% Series due August 15, 2014 8
728,000 9 D
28,218,000 8.734% Series due October 1, 2014 10
46,946,000 8.294% Series due October 1, 2015 11
18,750,000 8.635% Series due October 1, 2016 12
19,609,000 8.470% Series due October 1, 2017 13
3,067,221 500,000,000 5.65% Series due July 15, 2018 14
905,000 15 D
2,515,793 350,000,000 5.50% Series due January 15, 2019 16
2,292,500 17 D
3,007,139 400,000,000 3.85% Series due June 15, 2021 18
744,000 19 D
2,423,808 350,000,000 2.95% Series due February 1, 2022 20
308,000 21 D
254,129 100,000,000 2.95% Series due February 1, 2022 22
-81,000 23 P
2,874,150 300,000,000 7.70% Series due November 15, 2031 24
864,000 25 D
1,892,365 200,000,000 5.90% Series due August 15, 2034 26
722,000 27 D
2,912,021 300,000,000 5.25% Series due June 15, 2035 28
1,080,000 29 D
2,907,881 350,000,000 6.10% Series due August 1, 2036 30
1,141,000 31 D
32
FERC FORM NO. 1 (ED. 12-96)Page 256
33 TOTAL 7,027,868,000 78,659,157
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.Nominal Dateof Issue Date ofMaturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding withoutreduction for amounts held byrespondent)
Interest for YearAmount(d) (e) (f) (g) (h) (i)
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.
1
2
3
118,92310/01/201204/15/199210/01/201204/15/1992 4
1,536,000 228,34810/01/201304/15/199210/01/201304/15/1992 5
200,000,000 10,900,00009/15/201309/08/200309/15/201309/08/2003 6
7
200,000,000 9,900,00008/15/201408/24/200408/15/201408/24/2004 8
9
5,038,000 585,50610/01/201404/15/199210/01/201404/15/1992 10
11,594,000 1,166,13610/01/201504/15/199210/01/201504/15/1992 11
5,989,000 595,70710/01/201604/15/199210/01/201604/15/1992 12
7,377,000 697,82210/01/201704/15/199210/01/201704/15/1992 13
500,000,000 28,250,00007/15/201807/17/200807/15/201807/17/2008 14
15
350,000,000 19,250,00001/15/201901/08/200901/15/201901/08/2009 16
17
400,000,000 15,400,00006/15/202105/12/201106/15/202105/12/2011 18
19
350,000,000 9,799,19002/01/202201/06/201202/01/202201/06/2012 20
21
100,000,000 2,799,76802/01/202203/06/201202/01/202203/06/2012 22
23
300,000,000 23,100,00011/15/203111/21/200111/15/203111/21/2001 24
25
200,000,000 11,800,00008/15/203408/24/200408/15/203408/24/2004 26
27
300,000,000 15,750,00006/15/203506/13/200506/15/203506/13/2005 28
29
350,000,000 21,350,00008/01/203608/10/200608/01/203608/10/2006 30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 257
33 6,820,029,000 355,713,688
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224)
PacifiCorp X
/ /2012/Q4
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
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.
589,216 600,000,000 5.75% Series due April 1, 2037 1
24,000 2 D
5,127,281 600,000,000 6.25% Series due October 15, 2037 3
750,000 4 D
2,290,333 300,000,000 6.35% Series due July 15, 2038 5
1,671,000 6 D
6,134,687 650,000,000 6.00% Series due January 15, 2039 7
6,175,000 8 D
2,737,549 300,000,000 4.10% Series due February 1, 2042 9
987,000 10 D
7,649 1,000,000 8.26% Series C Medium-Term Notes due Jan. 10, 2012 11
13,297 2,000,000 8.28% Series C Medium-Term Notes due Jan. 10, 2012 12
22,946 3,000,000 8.25% Series C Medium-Term Notes due Feb. 1, 2012 13
75,827 10,000,000 8.13% Series E Medium-Term Notes due Jan. 22, 2013 14
115,202 15,000,000 8.53% Series C Medium-Term Notes due Dec. 16, 2021 15
38,400 5,000,000 8.375% Series C Medium-Term Notes due Dec. 31, 2021 16
33,243 5,000,000 8.26% Series C Medium-Term Notes due Jan. 7, 2022 17
30,594 4,000,000 8.27% Series C Medium-Term Notes due Jan. 10, 2022 18
131,471 15,000,000 8.05% Series E Medium-Term Notes due Sept. 1, 2022 19
70,118 8,000,000 8.07% Series E Medium-Term Notes due Sept. 9, 2022 20
438,238 50,000,000 8.12% Series E Medium-Term Notes due Sept. 9, 2022 21
105,177 12,000,000 8.11% Series E Medium-Term Notes due Sept. 9, 2022 22
87,648 10,000,000 8.05% Series E Medium-Term Notes due Sept. 14, 2022 23
208,198 26,000,000 8.08% Series E Medium-Term Notes due Oct. 14, 2022 24
200,190 25,000,000 8.08% Series E Medium-Term Notes due Oct. 14, 2022 25
37,914 5,000,000 8.23% Series E Medium-Term Notes due Jan. 20, 2023 26
30,331 4,000,000 8.23% Series E Medium-Term Notes due Jan. 20, 2023 27
-81,560 28 P
246,981 27,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 29
100,622 11,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 30
137,211 15,000,000 7.23% Series F Medium-Term Notes due Aug. 16, 2023 31
274,423 30,000,000 7.24% Series F Medium-Term Notes due Aug. 16, 2023 32
FERC FORM NO. 1 (ED. 12-96)Page 256.1
33 TOTAL 7,027,868,000 78,659,157
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.Nominal Dateof Issue Date ofMaturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding withoutreduction for amounts held byrespondent)
Interest for YearAmount(d) (e) (f) (g) (h) (i)
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.
600,000,000 34,500,00004/01/203703/14/200704/01/203703/14/2007 1
2
600,000,000 37,500,00010/15/203710/03/200710/15/203710/03/2007 3
4
300,000,000 19,050,00007/15/203807/17/200807/15/203807/17/2008 5
6
650,000,000 39,000,00001/15/203901/08/200901/15/203901/08/2009 7
8
300,000,000 12,129,16702/01/204201/06/201202/01/204201/06/2012 9
10
2,06501/10/201201/09/199201/10/201201/09/1992 11
4,14001/10/201201/10/199201/10/201201/10/1992 12
20,62502/01/201201/15/199202/01/201201/15/1992 13
10,000,000 813,00001/22/201301/20/199301/22/201301/20/1993 14
15,000,000 1,279,50012/16/202112/16/199112/16/202112/16/1991 15
5,000,000 418,75012/31/202112/31/199112/31/202112/31/1991 16
5,000,000 413,00001/07/202201/08/199201/07/202201/08/1992 17
4,000,000 330,80001/10/202201/09/199201/10/202201/09/1992 18
15,000,000 1,207,50009/01/202209/18/199209/01/202209/18/1992 19
8,000,000 645,60009/09/202209/09/199209/09/202209/09/1992 20
50,000,000 4,060,00009/09/202209/11/199209/09/202209/11/1992 21
12,000,000 973,20009/09/202209/11/199209/09/202209/11/1992 22
10,000,000 805,00009/14/202209/14/199209/14/202209/14/1992 23
26,000,000 2,100,80010/14/202210/15/199210/14/202210/15/1992 24
25,000,000 2,020,00010/14/202210/15/199210/14/202210/15/1992 25
5,000,000 411,50001/20/202301/20/199301/20/202301/20/1993 26
4,000,000 329,20001/20/202301/29/199301/20/202301/29/1993 27
28
27,000,000 1,960,20007/21/202307/22/199307/21/202307/22/1993 29
11,000,000 798,60007/21/202307/22/199307/21/202307/22/1993 30
15,000,000 1,084,50008/16/202308/16/199308/16/202308/16/1993 31
30,000,000 2,172,00008/16/202308/16/199308/16/202308/16/1993 32
FERC FORM NO. 1 (ED. 12-96)Page 257.1
33 6,820,029,000 355,713,688
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224)
PacifiCorp X
/ /2012/Q4
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
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.
38,250 5,000,000 6.75% Series F Medium-Term Notes due Sept. 14, 2023 1
15,300 2,000,000 6.75% Series F Medium-Term Notes due Sept. 14, 2023 2
15,300 2,000,000 6.72% Series F Medium-Term Notes due Sept. 14, 2023 3
152,326 20,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 4
121,861 16,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 5
91,396 12,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 6
904,467 100,000,000 6.71% Series G Medium-Term Notes due Jan. 15, 2026 7
63,804,117 6,289,498,000Subtotal - First Mortgage Bonds 8
9
Pollution Control Obligations - Secured by Pledged First Mortgage Bonds: 10
11
874,159 40,655,000 Poll Ctrl Rev Refunding Bonds, Moffat County, CO, Series 1994 12
228,980 8,300,000 5-5/8% Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1993 13
197,125 14 D
1,624,793 46,500,000 5.65% Poll Ctrl Rev Refunding Bonds, Emery County, Utah, Series 1993A 15
625,551 16,400,000 5-5/8% Poll Ctrl Rev Refunding Bonds, Emery County, Utah, Series 1993B 16
389,500 17 D
510,479 21,260,000 Poll Ctrl Rev Refunding Bonds, Sweetwater County, WY, Series 1994 18
209,777 8,190,000 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1994 19
3,274,246 121,940,000 Poll Ctrl Rev Refunding Bonds, Emery County, UT, Series 1994 20
206,519 9,365,000 Poll Ctrl Rev Refunding Bonds, Carbon County, UT, Series 1994 21
422,858 15,060,000 Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1994 22
155,970 17,000,000 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1988 23
122,887 15,000,000 Poll Ctrl Revenue Bonds, Sweetwater County, WY, Series 1984 24
105,000 25 D
771,836 45,000,000 Poll Ctrl Rev Refunding Bonds, Lincoln Cnty, WY, Series 1991 26
304,824 8,500,000 Poll Ctrl Revenue Bonds, City of Forsyth, MT, Series 1986 27
132,043 5,300,000 Environ. Imprvmnt Rev Bonds, Converse County, WY, Series 1995 28
404,262 22,000,000 Environ. Imprvmnt Rev Bonds, Lincoln County, WY, Series 1995 29
10,560,809 400,470,000Subtotal Pollution Control Obligations - Secured by Pledged First Mortgage Bonds 30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 256.2
33 TOTAL 7,027,868,000 78,659,157
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.Nominal Dateof Issue Date ofMaturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding withoutreduction for amounts held byrespondent)
Interest for YearAmount(d) (e) (f) (g) (h) (i)
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.
5,000,000 337,50009/14/202309/14/199309/14/202309/14/1993 1
2,000,000 135,00009/14/202309/14/199309/14/202309/14/1993 2
2,000,000 134,40009/14/202309/14/199309/14/202309/14/1993 3
20,000,000 1,350,00010/26/202310/26/199310/26/202310/26/1993 4
16,000,000 1,080,00010/26/202310/26/199310/26/202310/26/1993 5
12,000,000 810,00010/26/202310/26/199310/26/202310/26/1993 6
100,000,000 6,710,00001/15/202601/23/199601/15/202601/23/1996 7
6,165,534,000 346,277,447 8
9
10
11
40,655,000 343,07005/01/201311/17/199405/01/201311/17/1994 12
117,91211/01/202111/15/199311/01/202111/15/1993 13
14
663,35711/01/202311/15/199311/01/202311/15/1993 15
232,98311/01/202311/15/199311/01/202311/15/1993 16
17
21,260,000 191,71211/01/202411/17/199411/01/202411/17/1994 18
8,190,000 64,37711/01/202411/17/199411/01/202411/17/1994 19
121,940,000 955,58111/01/202411/17/199411/01/202411/17/1994 20
9,365,000 72,20111/01/202411/17/199411/01/202411/17/1994 21
15,060,000 136,21311/01/202411/17/199411/01/202411/17/1994 22
17,000,000 680,35201/01/201401/01/198801/01/201401/01/1988 23
15,000,000 600,35712/01/201412/01/198412/01/201412/01/1984 24
25
45,000,000 521,61601/01/201601/17/199101/01/201601/17/1991 26
8,500,000 359,45012/01/201612/01/198612/01/201612/01/1986 27
5,300,000 224,25111/01/202511/17/199511/01/202511/17/1995 28
22,000,000 958,71511/01/202511/17/199511/01/202511/17/1995 29
329,270,000 6,122,147 30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 257.2
33 6,820,029,000 355,713,688
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224)
PacifiCorp X
/ /2012/Q4
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
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.
Pollution Control Obligations - Unsecured 1
2
84,822 11,500,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988B 3
660,750 70,000,000 Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Ser. 1990A 4
872,505 45,000,000 Poll Ctrl Rev Refndng Bonds, Emery County, UT, Series 1991 5
422,443 50,000,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988A 6
380,198 45,000,000 Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Series 1988 7
351,905 41,200,000 Poll Ctrl Rev Refndng Bonds, City of Gillette, WY, Ser. 1988 8
167,524 9,335,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992A 9
151,908 6,305,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992B 10
242,163 22,485,000 Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 11
225,000 24,400,000 Environ. Imprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 12
556,549 12,675,000 6.150% Environ. Imprvmnt Rev Bonds, Emery County, UT, Series 1996 13
178,464 14 D
15
4,294,231 337,900,000Subtotal - Pollution Control Obligations - Unsecured 16
17
18
78,659,157 7,027,868,000TOTAL ACCOUNT 221 19
20
Reacquired Bonds: (Account 222) 21
22
Advances from Associated Companies: (Account 223) 23
24
Other Long-Term Debt: (Account 224) 25
26
TOTAL ACCOUNT 224 27
28
29
Long-Term Debt Authorized but Unissued 30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 256.3
33 TOTAL 7,027,868,000 78,659,157
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.Nominal Dateof Issue Date ofMaturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding withoutreduction for amounts held byrespondent)
Interest for YearAmount(d) (e) (f) (g) (h) (i)
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.
1
2
11,500,000 106,24701/01/201401/01/198801/01/201401/01/1988 3
70,000,000 638,71207/01/201507/25/199007/01/201507/25/1990 4
45,000,000 496,61407/01/201505/23/199107/01/201505/23/1991 5
50,000,000 493,24601/01/201701/01/198801/01/201701/01/1988 6
45,000,000 402,88501/01/201801/01/198801/01/201801/01/1988 7
41,200,000 375,21101/01/201801/01/198801/01/201801/01/1988 8
9,335,000 93,88212/01/202009/29/199212/01/202009/29/1992 9
6,305,000 64,39712/01/202009/29/199212/01/202009/29/1992 10
22,485,000 221,84412/01/202009/29/199212/01/202009/29/1992 11
24,400,000 228,34311/01/202512/14/199511/01/202512/14/1995 12
192,71309/01/203009/24/199609/01/203009/24/1996 13
14
15
325,225,000 3,314,094 16
17
18
6,820,029,000 355,713,688 19
20
21
22
23
24
25
26
27
28
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 257.3
33 6,820,029,000 355,713,688
Schedule Page: 256 Line No.: 20 Column: a
In January 2012, PacifiCorp issued $350 million of its 2.95% First Mortgage Bonds due
February 1, 2022. 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.
Schedule Page: 256 Line No.: 22 Column: a
In March 2012, PacifiCorp issued $100 million of its 2.95% First Mortgage Bonds due
February 1, 2022. State commission authorizations for this issuance were as follows:
OPUC - Docket No. UF-4262, Order No. 10-062, dated February 23, 2010.
IPUC - Case No. PAC-E-10-02, Order No. 31018, dated March 5, 2010.
Schedule Page: 256.1 Line No.: 9 Column: a
In January 2012, PacifiCorp issued $300 million of its 4.10% First Mortgage Bonds due
February 1, 2042. State commission authorizations for this issuance were as follows:
OPUC - Docket No. UF-4262, Order No. 10-062, dated February 23, 2010.
IPUC - Case No. PAC-E-10-02, Order No. 31018, dated March 5, 2010.
Schedule Page: 256.2 Line No.: 13 Column: a
In March 2012, PacifiCorp redeemed: the 5-5/8% Pollution Control Revenue Refunding Bonds,
Lincoln County, WY, Series 1993; the 5.65% Pollution Control Revenue Refunding Bonds,
Emery County, Utah, Series 1993A; the 5-5/8% Pollution Control Revenue Refunding Bonds,
Emery County, Utah, Series 1993B; and the 6.150% Environmental Improvement Revenue Bonds,
Emery County, Utah, Series 1996. PacifiCorp transferred the unamortized debt expense and
unamortized discount associated with these obligations to Account 189, Unamortized loss on
reacquired debt.
Schedule Page: 256.2 Line No.: 15 Column: a
See footnote on page 256.2 for column (a) line 13.
Schedule Page: 256.2 Line No.: 16 Column: a
See footnote on page 256.2 for column (a) line 13.
Schedule Page: 256.3 Line No.: 13 Column: a
See footnote on page 256.2 for column (a) line 13.
Schedule Page: 256.3 Line No.: 19 Column: h
Refer to Important Changes During the Quarter/Year, Item 6, and Notes to Financial
Statements, Note 7, of this Form No. 1 for a discussion of PacifiCorp's long-term debt.
Schedule Page: 256.3 Line No.: 19 Column: i
Amount represents interest expense charged to Account 427, Interest on long-term debt, and
does not include any amount charged to Account 430, Interest on debt to associated
companies, as such associated debt is included in Account 233, Notes payable to associated
companies.
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-3ASR 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; $850
million available as of December 31, 2012), refer to Important Changes During the
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
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, 2012) by the counties
of Emery, Utah; Carbon, Utah; Converse, Wyoming; Lincoln, Wyoming; Sweetwater, Wyoming;
and Moffat, Colorado and authorization to borrow the proceeds of new pollution control
revenue bonds issued (total of $150,000,000 authorized and available as of December 31,
2012) 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
PacifiCorp X
/ /2012/Q4
Particulars (Details)(b)(a)Amount LineNo.
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.
537,337,285Net Income for the Year (Page 117) 1
2
3
Taxable Income Not Reported on Books 4
5
6
7
51,249,086Other 8
Deductions Recorded on Books Not Deducted for Return 9
10
11
12
1,240,796,851Other 13
Income Recorded on Books Not Included in Return 14
15
16
17
143,683,817Other 18
Deductions on Return Not Charged Against Book Income 19
20
21
22
23
24
1,728,327,545Other 25
-781,504State Tax Deductions 26
-43,409,644Federal Tax Net Income 27
Show Computation of Tax: 28
29
-15,193,375Federal Income Tax at 35.00% 30
-23,310,753Provision to Return Adjustment 31
-3,125,404Tax Reserve Changes 32
-1,500,000Contingency Reserve 33
-65,383,088Renewable Electricity Production Tax Credits 34
35
-108,512,620Federal Income Tax Accrual 36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96)Page 261
Schedule Page: 261 Line No.: 8 Column: a
Particulars (Details) Amounts
CIAC $ 42,046,191
Reimbursements 1,070,419
OR SB 408 Recovery 6,919,741
Federal Benefit of Federal Interest - IRHI 430,600
Federal Benefit of State Interest - IRHI 642,887
State Benefit of Federal Interest - IRHI 55,856
State Benefit of State Interest - IRHI 83,392
Total $ 51,249,086
Schedule Page: 261 Line No.: 13 Column: a
Particulars (Details) Amounts
Fed/State Tax Expense $ 191,582,246
Book Depreciation Allocated to Medicare and M&E 49,253
Meals & Entertainment 865,355
Penalties 599,682
Lobbying expenses 1,739,242
Medicare Subsidy 3,006,171
Capitalized labor and benefits costs for Power tax input - Temporary 8,840,481
Book Depreciation 647,597,336
Avoided Costs 52,720,950
UT Klamath Relicensing Costs 35,306,774
Book Cost Depletion - Addback 2,040,779
Regulatory Asset - FAS 158 Pension Liability Adj. 35,309,000
Regulatory Asset - FAS 158 Post Ret. Liability 3,678,000
Environmental Costs - WA 155,047
Regulatory Asset - Utah ECAM 19,248,068
Cholla Plant Transaction Costs-APS Amortization 1,122,425
WA Disallowed Colstrip #3 - Write-off 52,188
Regulatory Asset - Lake Side Liquidation 27,429
Goodnoe Hills Liquidation Damages - WY 21,250
RTO Grid West Notes Receivable - OR 361,562
Regulatory Asset - Pension MMT - UT 283,176
Regulatory Asset - Post - Ret MMT - OR 193,035
Regulatory Asset - Post - Ret MMT - UT 278,648
Regulatory Asset - Post - Ret MMT - CA 17,488
Regulatory Asset - Powerdale Decommissioning - CA 33,069
Regulatory Asset - Powerdale Decommissioning - ID 19,089
Regulatory Asset - Powerdale Decommissioning - WA 283,929
CA - January 2010 Storm Costs 65,994
ID - Deferred Overburden Costs 6,819
WY - Deferred Overburden Costs 21,109
Regulatory Asset - CA Solar Feed-in Tariff 107,718
Regulatory Asset - UT - Solar Incentive Program 867,043
Deferred Excess Net Power Costs - WA Hydro 920,436
Deferred UT Independent Evaluation Fee 190,680
Deferral of Renewable Energy Credits 3,418,354
Deferred Excess Net Power Costs - ID 09 151,642
OR - MEHC Transition Service Costs 912,507
WA - Chehalis Plant Revenue Requirement 3,000,000
Regulatory Asset - MEHC Transition Service Costs - CA 44,554
Deferred Coal Costs - Naughton Contract Settlement 1,376,154
Contra Regulatory Asset - Naughton Unit #3 - OR 2,044,913
Contra Regulatory Asset - Naughton Unit #3 - WA 629,112
Idaho Customer Balancing Account 1,037,524
Weatherization 3,195,980
Prepaid Taxes - UT PUC 80,195
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
TGS Buyout 15,474
Joseph Settlement 137,381
Hermiston Swap 171,693
Western Coal Carrier Postretirement Benefit Accrual 861,000
Post Merger Loss - Reacquisition Debt - Addback 174,109
Regulatory Liability - UT Home Energy Lifeline 390,090
Regulatory Liability - WA Low Energy Program 334,199
OR Regulatory Asset/Liability Consolidation 90,182
CA - California Alternative Rate for Energy Program (CARE) 384,350
Regulatory Liability - Blue Sky Program OR 858,685
Regulatory Liability - Blue Sky Program WA 103,873
Regulatory Liability - Blue Sky Program CA 40,165
Regulatory Liability - Blue Sky Program UT 976,702
Regulatory Liability - Blue Sky Program ID 39,099
Regulatory Liability - Blue Sky Program WY 86,570
Regulatory Liability - CA GHG Allowance Revenues 2,434,345
Regulatory Liability - ID Property Insurance Reserve 113,544
Regulatory Liability - UT Property Insurance Reserve 1,230,954
Regulatory Liability - WY Property Insurance Reserve 349,810
Reg. Liab. - OR 2012 GRC outcome related to emission control equip. invest 17,000,000
Pension / Retirement Accrual - Cash Basis 33,837
Severance Accrual - Cash Basis 265,807
Distribution O&M Amortization of Write-off 3,113,202
R & E - Sec.174 Deduction 12,411
Bear River Settlement Agreement 312,552
USA Power litigation and certain fire and other damage claims 155,910,850
Lewis River Settlement Agreement 122,036
North Umpqua Settlement Agreement 1,292,207
Umpqua Settlement Agreement 21,695
Deferred Revenue - Citibank 334,699
Environmental Liability - Regulated 21,277,848
FAS 112 Book Reserve 8,779,723
Intercompany Adjustments 25,353
Total $1,240,796,851
Schedule Page: 261 Line No.: 18 Column: a
Particulars (Details) Amounts
Fed/State Tax Expense - Interest $ (2,431,029)
Utah Deferred Comp / COLI (4,672,626)
Non-deductible post-retirement costs (129,004)
Capitalized labor costs for PowerTax input - Medicare subsidy - Temporary (862,862)
AFUDC - Equity (57,888,665)
Gain / (Loss) on Property Disposition (18,544,545)
Book Gain / Loss on Land Sales (1,063,591)
Trapper Mining Stock Basis (176,714)
Regulatory liability - BPA balancing accounts (905,356)
Oregon Gain on Sale (5,248)
Regulatory Liability - Sale of Renewable Energy Credits (26,252,717)
Regulatory Liability - OR 2010 Protocol Def (2,209,549)
Regulatory Liability - Powerdale Decommissioning Costs Giveback - UT (360,556)
NW Power Act - WA (669,786)
Regulatory Liability - SMUD Revenue Imputation - UT (2,667,282)
Def Regulatory Asset - Foote Creek Contract (137,640)
Tenant Lease Allow - PSU Call Center (48,156)
Other Environmental Liabilities (12,424,383)
Redding Contract - Prepaid (549,996)
Unrealized Gain / Loss from Trading Securities (472,882)
Equity Earnings in Subsidiaries (11,211,230)
Total $(143,683,817)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 261 Line No.: 25 Column: a
Particulars (Details) Amounts
Tax Percentage Depletion - Deer Creek $ (3,014,768)
Tax Percentage Depletion - Blundell Steam Field (Prior IGC) (462,728)
PPL Pre - 1943 Preferred Stock Div - Deduction (381,063)
MEHC Insurance Services - Receivable (2,022,305)
Dividend Received Deduction - Deferred Compensation (128,428)
Income Tax Interest (19,781)
PMI Overriding Coal Royalty % Depletion - PacifiCorp (4,707)
Repair Deduction (136,511,650)
Tax Depreciation (1,275,554,480)
Capitalized Depreciation (5,681,113)
AFUDC - Debt (28,473,727)
Basis Intangible Difference (887,984)
Coal Mine Development (309,400)
Coal Mine Extension (1,899,484)
Removal Costs (68,875,093)
Cholla SHL-NOPA (Lease Amortization) (115,687)
Tax Percentage Depletion - Deduction (3,779,983)
Tax Depletion (167,874)
Regulatory Asset - Post-Employment Costs (8,226,541)
Environmental Clean-up Accrual (11,197,600)
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)
CA Deferred Intervenor Funding (67)
Deferred Intervenor Funding Grants (239,892)
Contra Pension Regulatory Asset MMT & CTG - OR (1,014,634)
Contra Pension Regulatory Asset MMT & CTG - CA (91,920)
Contra Pension Regulatory Asset CTG - WA (1,017,963)
Regulatory Asset - Deferred OR Independent Evaluator Fees (289,093)
Unrecovered Plant - Powerdale (80,564)
Regulatory Asset - OR Solar Feed-In Tariff (1,481,040)
Deferred Excess Net Power Costs - CA (583,419)
Deferred Excess Net Power Costs - WY 09 and After (307,568)
Deferred Excess Net Power Costs - UT (24,581,969)
Deferred Excess Net Power Costs - OR (61,433)
Deferral of Renewable Energy Credits (1,932,761)
OR _RCAC Sep-Dec 07 Deferred (8,816)
Regulatory Asset - Naughton Unit #3 Costs (2,776,068)
Regulatory Asset - UT - Naughton U3 Costs (3,013,540)
Regulatory Asset - WY - Naughton U3 Costs (1,113,009)
Regulatory Asset - ID - Naughton U3 Costs (478,988)
Deferred Regulatory Expense (10,505)
Regulatory Asset - UT - Klamath Hydro Relicensing Costs (34,709,389)
Trojan Decommissioning Costs - Regulatory (99,553)
Coal Pile Inventory Adjustment (8,076,666)
Prepaid Taxes - OR PUC (86,205)
Prepaid Taxes - ID PUC (32,110)
Other Prepaid (364,096)
Prepaid Taxes - Property Taxes (3,793,091)
Wasach workers comp reserve (348,094)
Regulatory Liability - OR Energy Conservation Charge (4,947)
Regulatory Liability - OR Injuries & Damages Reserve (801,169)
Regulatory Liability - OR Property Insurance Reserve (6,079,456)
LT Prepaid IBEW 57 Pension Contribution (282,568)
Bonus Liability - Electric - Cash Basis (2.5 months) (49,539)
Vacation Accrual - Cash Basis (2.5 months) (1,009,771)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Deferred Compensation Accrual - Cash Basis (1,168,924)
Pension Liability (68,246,000)
Post-Retirement Liability (4,285,686)
SERP Liability (818,472)
PMI-Fuel Cost Adjustment (1,888,126)
M&S Inventory Write-Off (484,494)
Bad Debts Allowance - Cash Basis (3,423,593)
Def Regulatory Asset - Transmission Service Deposit (614,690)
Rogue River - Habitat Enhancement Liability (4,781)
Unearned Joint Use Pole Contact Revenue (965,355)
Accrued Royalties (157,057)
Misc. Current and Accrued Liability (2,243,351)
Federal Benefit of State Tax - IRHI (48,734)
Environmental Liability - Non-Regulated (299,102)
Reverse Accrued Final Reclamation (902,046)
Amortization NOPAs 99-00 RAR (58,446)
MCI FOG Wire Lease (597)
Total $(1,728,327,545)
Schedule Page: 261 Line No.: 36 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 United States Federal Income Tax
Return:
Under MidAmerican Energy Holdings Company ("MEHC"):
PPW Holdings LLC Sub-Group:
PacifiCorp
PPW Holdings LLC
PacifiCorp Sub-Group:
Centralia Mining Company
Energy West Mining Company
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
American Pacific Finance Company
American Pacific Finance Company II
Arizona HomeServices, LLC
AVSP 1A, LLC
AVSP 1B, LLC
AVSP 2A, LLC
AVSP 2B, LLC
AVSP Holding, LLC
BG Energy Holding Company LLC
BG Energy LLC
Bishop Hill Energy II, LLC
Bishop Hill II Holdings, LLC
CalEnergy Company, Inc
CalEnergy Generation Operating Company
CalEnergy Holdings, Inc
CalEnergy International Services, Inc
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
CalEnergy International, Inc
CalEnergy Minerals Development, LLC
CalEnergy Minerals LLC
CalEnergy Pacific Holdings Corp
CalEnergy UK Inc
Capitol Title Company
CBEC Railway, Inc
CBSHome Commercial, LLC
CBSHome Real Estate Company
CBSHome Real Estate of Iowa, Inc
CBSHome 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
Century Development LLC
Champion Realty, Inc
Chancellor Title Services, Inc
Cimmred Leasing Company
Columbia Title of Florida, Inc
Connecticut Referral Group, L.L.C.
Cordova Energy Company, LLC
Cordova Funding Corporation
CTHM, L.L.C.
CTRE, L.L.C.
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
Fort Dearborn Land & Title Company
HMSV Financial Services, Inc
HN Real Estate Group N.C., Inc
HN Real Estate Group, LLC
HN Referral Corporation
HomeServices Financial Holdings, Inc
HomeServices Insurance, Inc
HomeServices of Alabama, Inc.
HomeServices of America, Inc
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
HomeServices of California, Inc
HomeServices of Connecticut, LLC
HomeServices of Florida, Inc
HomeServices of Illinois Holdings, LLC
HomeServices of Iowa, Inc
HomeServices of Kentucky, Inc
HomeServices of Nebraska, Inc
HomeServices of Oregon, LLC
HomeServices of the Carolinas, Inc
HomeServices of Washington, LLC
HomeServices Real Estate Academy
HomeServices Referral Network, LLC
HomeServices Relocation, LLC
HomeSvc of IL LLC d/b/a Koenig & Strey GMAC RE
HS Franchise Holding, LLC
HSR Equity Funding, Inc
Huff Commercial Group, LLC
Huff-Drees Realty, Inc
IMO Company, Inc
InsuranceSouth, LLC
Iowa Realty Company, Inc
Iowa Realty Insurance Agency, Inc
Iowa Title Company
J.S. White Associates, Inc
JBRC, Inc
Jim Huff Realty, Inc.
JRHBW Realty, Inc d/b/a/ RealtySouth
Kansas City Title, Inc
Kentucky Residential Referral, 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, Inc
M & M Ranch Acquisition Company LLC
M & M Ranch Holding Company LLC
MEC Construction Services Company
MEHC America Transco LLC
MEHC Canada, LLC
MEHC Insurance Services Ltd.
MEHC Investment, Inc
MEHC Merger Sub Inc
MEHC Texas Transco LLC
MHC Investment Company
MHC, Inc
Mid-America Referral Network, Inc.
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 Renewables, LLC
MidAmerican Solar, LLC
MidAmerican Transmission, LLC
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
MidAmerican Wind, LLC
Midland Escrow Services, Inc
Midwest Capital Group, Inc
MWR Capital, Inc
Nebraska Land Title & Abstract Company
Nebraska Referral, Inc.
NMA, LLC
NNGC Acquisition LLC
Northern Aurora Inc
Northern Natural Gas Company
NW Referral Services, LLC
PCRE, L.L.C.
Pickford Escrow Company, Inc
Pickford Holdings, LLC
Pickford Real Estate, Inc
Pickford Services Company, Inc
Pilot Butte, LLC
Pinyon Pines I Holding Company, LLC
Pinyon Pines II Holding Company, LLC
Pinyon Pines Wind I, LLC
Pinyon Pines Wind II, LLC
PNW Referral, LLC
Preferred Carolinas Realty, Inc
Preferred Carolinas Title Agency, LLC
Professional Referral Organization, Inc
Quad Cities Energy Company
Real Estate Knowledge Services, L.L.C.
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
Referral Network of IL LLC
Relocation Advantage Partners, LLC
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
TitleSouth, LLC
Topaz Solar Farms, LLC
TPZ Holding, LLC
Two Rivers, Inc
Wailuku Investment LLC
Wm Broughton, LLC
With respect to members of the MEHC 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
121 Acquisition Co., LLC
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
21 SPC, Inc.
21st Communities, Inc.
21st Mortgage Corporation
Acme Brick Company
Acme Brick DFW, Inc.
Acme Brick Sales Company
Acme Building Brands, Inc
Acme Investment Company
Acme Management Company
Acme Ochs Brick and Stone, 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.
Affiliated Agency Operations Co.
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
AmGUARD Insurance Company
Anderson Retail, Inc.
Apeks Apparel, Inc.
Applied Group Insurance Holdings, Inc.
Applied Investigations Inc.
Applied Logistics, Inc.
Applied Premium Finance, Inc.
Applied Processing Center No. 60, Inc.
Applied Risk Services of New York, Inc.
Applied Risk Services, Inc.
Applied Underwriters Captive Risk Assurance Company, Inc.
Applied Underwriters, Inc.
Atlanta International Insurance Company
AU Captive Risk Assurance Co.
AU Holding Company, Inc.
B. Lippman
Bayport Systems, Inc.
Ben Bridge Jeweler, Inc.
Benjamin Moore & Co.
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 Columbia Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
BH Finance, Inc.
BH Shoe Holdings, Inc.
BH, LLC
BHG Life Insurance Company
BHG Structured Settlements, Inc.
BHSF, Inc.
Blue Chip Stamps
BN Leasing Corporation
BNJ NetJets, Inc.
BNSF Communications, Inc.
BNSF Logistics International, Inc.
BNSF Railway Company
BNSF Railway International Services, Inc.
BNSF Spectrum, Inc.
Boat America Corporation
Boat Owners Association of the United States
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.
California Insurance Company
Camp Manufacturing Company
Campbell Hausfeld/Scott Fetzer Company
Carefree/Scott Fetzer Company
Cavalier Homes, Inc.
Central States Indemnity Co. of Omaha
Central States of Omaha Companies, Inc.
Cerro Plumbing Retail, Inc.
Cerro Wire Distribution, Inc.
CG Service, Inc.
Chatwell, Inc.
Chippewa Shoe Company
Citadel Insurance Company
CJE II
Claims Services, Inc.
CLAL U.S. Holdings, Inc.
Clayton Commercial Buildings, Inc.
Clayton Homes, Inc.
CMH Capital, Inc.
CMH Hodgenville, Inc.
CMH Homes, Inc.
CMH Manufacturing West, Inc.
CMH Manufacturing, Inc.
CMH of KY, Inc.
CMH Parks, Inc.
CMH Services, Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
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
Crowley Garment Mfg Co Inc.
Crowley Shirt Mfg Co Inc.
CSI Life Insurance Company
CTB Credit Corp
CTB Inc.
CTB International Corp
CTB IW INC
CTB MN Investments
Cumberland Asset Management, Inc.
Cypress Insurance Company
Dairy Queen Corporate Stores, Inc.
Dairy Queen Of Georgia, Inc.
Delta Wholesale Liquors, Inc.
Denver Brick Company
Dexter Shoe Company
DQ Funding Corporation
DQ Joint Venture Stores, Inc.
DQ Managed Stores, Inc.
DQ Wholly-Owned Stores, Inc.
DQF, Inc.
DQGC, Inc.
EastGUARD Insurance Company
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.
Exsif Worldwide, Inc.
Fairfield Insurance Company
Faraday Capital Limited
Farriors, Inc.
Finial Holdings, Inc.
Finial Reinsurance Company
First American Carriers, Inc.
First Berkshire Hathaway Life Insurance Company
FlightSafety Capital Corp.
FlightSafety Development Corp.
FlightSafety International Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
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
Fontaine Truck Equipment Company
Fontana Wood Products of Oregon, Inc.
Fontana Wood Products, Inc.
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 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.
GRD Holdings Corporation
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.11
Great Plains Uniforms
Griffey Uniforms
GUARD Financial Group, Inc.
GUARD Insurance Group, Inc.
GUARDco, Inc.
H. H. Brown Shoe Company, Inc.
H. H. Brown Shoe Technologies, LLC
H.J. Justin & Sons, Inc.
Halex/Scott Fetzer Company
Hardy Frames, Inc.
Harris Uniforms
Harrison Uniforms
HDS Redevelopment Corporation
HeatPipe Technology, Inc.
Helzberg's Diamond Shops, Inc.
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.
Illinois Insurance Company
Innovative Building Products, Inc
InterGUARD, Ltd.
International America Group Inc.
International American Management Company
International Dairy Queen, Inc.
International Insurance Underwriters, Inc.
International Traders, Inc.
Intrepid JSB, Inc.
Ironwood Plastics Inc
Isabella Shoe Corporation, LLC
J.L. Mining Company
J.S Justin, Inc.
JDS Properties, 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
L.A. Terminals, Inc.
Leesburg Yarn Mills, Inc.
Lipotec Group Corp.
LMG Ventures, LLC
Lockwood Street Urban Renewal Corporation
Los Angeles Junction Railway Company
Lubricant Investments, Inc.
Lubrizol Advanced Materials China, Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.12
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, LLC
Mapletree Transportation, Inc.
Marathon Suspension Systems, Inc.
Marmon Crane Services, Inc.
Marmon Distribution Services, Inc.
Marmon Flow Products, Inc.
Marmon Holdings, Inc.
Marmon Industrial Companies, Inc.
Marmon Natural Resource & Transportation Service
Marmon Retail Home Improvement Products, Inc.
Marmon Retail Services, Inc.
Marmon Water, Inc.
Marmon 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 Beverage Distribution, Inc.
McLane Beverage Holding, Inc.
McLane Company, Inc.
McLane Eastern, Inc.
McLane Express, Inc.
McLane Foodservice, Inc.
McLane Mid-Atlantic, Inc.
McLane Midwest, Inc.
McLane Minnesota, Inc.
McLane New Jersey, Inc.
McLane Southern, Inc.
McLane Suneast, Inc.
McLane Western, Inc.
Meadowbrook Meat Company, Inc.
Medical Protective Corporation
Medical Protective Finance Corporation
Medical Protective Insurance Services, Inc.
MedPro Risk Retention Services, Inc.
Metro Uniforms
MH Transport, Inc.
Midwest Northwest Properties, Inc.
Miller-Sage, Inc.
MiTek Framings, Inc.
MiTek Holdings, Inc.
MiTek Industries, Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.13
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
Nationwide Uniforms
Nebraska Furniture Mart, Inc.
NetJets Aviation, Inc.
NetJets Europe Holdings, LLC
NetJets Inc.
NetJets International, Inc.
NetJets Large Aircraft, Inc.
NetJets M.E., Inc.
NetJets Sales, Inc.
NetJets Services, Inc.
NetJets U.S., Inc.
NFM of Kansas, Inc.
NFM Services, LLC
Nick Bloom Uniforms
NJ Executive Services, Inc.
NJE Holdings, LLC
NJI Sales, Inc.
NJI, Inc.
Nocona Boot Company
NorGUARD Insurance Company
North American Casualty Co.
Northern States Agency, Inc.
Noveon Hilton Davis, Inc.
Oak River Insurance Company
Omaha World-Herald Company
Orange Julius Of America
Pan-Am Shoe Company, LLC
Penn Coal Land, Inc.
Penn Pocahontas Coal Co.
Pennsylvania Insurance Company
Perfection Hy-Test Company
Pima Uniforms
Pine Canyon Land Company
PJR Management, Inc.
Plaza Financial Services Co.
Plaza Resources Co.
Precision Brand Products, Inc.
Precision Millwork Settings LLC
Precision Steel Warehouse - Charlotte S/C
Precision Steel Warehouse, Inc.
Princeton Advertising & Marketing Group, Inc.
Princeton Insurance Company
Princeton Risk Protection, Inc.
Priority One Financial Services, Inc.
Pro Installations, Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.14
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.
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
Scott Fetzer Financial Group, Inc.
ScottCare Corporation
Seaworthy Insurance Company
See's Candies, Inc
Sees Candy Shops, Incorporated
Seventeenth Street Realty, Inc.
Shaw Contract Flooring Installation Services, Inc.
Shaw Contract Flooring Services, Inc.
Shaw Diversified Services, Inc.
Shaw Floors, Inc.
Shaw Funding Company
Shaw 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.
Sofft Shoe Company, LLC
Sol Frank Uniforms Inc.
Somerset Services, Inc
Southern Energy Homes, 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.
The Ben Bridge Corporation
The BN and SF Railway de Mexico, S.A. de C.V.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.15
The Buffalo News, Inc.
The BVD Licensing Corporation
The Eagle Company
The Fechheimer 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.
TransGUARD, Ltd.
TRH Holding Corp.
Triangle Suspension Systems, Inc.
TSE Brakes, Inc.
TTI, Inc.
TXFM, Inc.
U.S. Investment Corporation
U.S. Underwriters Insurance Co.
Unified Supply Chain, Inc.
Uni-Form Components Co.
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, Incorporated
United States Liability Insurance Company
United Steel Products Company
Universal Uniforms
UTLX Company, Inc.
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 Association of America, Inc.
VFI-Mexico, Inc.
Vision Retailing, Inc.
Wayne/Scott Fetzer Company
Waynesburg Shirt Company Inc.
Webb Wheel Products, Inc.
Wells Lamont Retail, Inc.
Wesco Financial Corporation
Wesco Holdings Midwest, Inc.
Wesco-Financial Insurance Company
West Virginia Uniforms
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.16
Western Fruit Express Company
Western/Scott Fetzer Company
WestGUARD Insurance Company
Whittaker, Clark & Daniels, Inc.
Winona Bridge Railroad Company
WMC Corp.
World Book Encyclopedia, Inc.
World Book, Inc.
World Book/Scott Fetzer Company
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.
Zuckerbergs Uniforms
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.17
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2012/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a) (b) (c) (d) (e) (f)
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.
Federal: 1
-208,990,602 96,987 -108,512,620 66,373,297 17,233,393 Income 2
36,450,728 36,461,124 11,403 430,018 FICA 3
253,736 252,682 5,385 Unemployment 4
3,573,955 3,471,497 181,263 Excise Tax - Coal 5
-168,712,183 96,987 -68,327,317 66,384,700 17,850,059Subtotal 6
7
State: 8
9
Arizona: 10
2,732,068 2,854,938 1,304,599 Property 11
-44,924 148,893 -11,613 Income 12
2,687,144 3,003,831 -11,613 1,304,599Subtotal 13
14
California: 15
2,195,452 2,195,452 Property 16
35,886 33,917 2,089 Unemployment 17
-20,099 132,061 290,283 Franchise-Income 18
153,690 127,080 39,948 Use 19
1,169,205 1,240,533 1,183,958 Local Franchise 20
3,534,134 3,729,043 290,283 1,225,995Subtotal 21
22
Colorado: 23
1,795,949 1,945,949 1,760,000 Property 24
583 -1,544 Income 25
1,795,949 1,946,532 -1,544 1,760,000Subtotal 26
27
Idaho: 28
5,323,123 5,468,390 2,994,775 Property 29
343,708 -44,387 584,571 214,046 Income 30
29,123 31,373 750 KWh 31
57,384 57,700 1,140 Unemployment 32
117,639 116,755 16,152 Use 33
5,870,977 -44,387 6,258,789 214,046 3,012,817Subtotal 34
35
Montana: 36
3,194,779 3,554,804 1,416,093 Property 37
100 780 -1,904 Corporate License-Income 38
1,307 1,307 Unemployment 39
228,127 230,563 57,564 Energy License 40
78,502,426
FERC FORM NO. 1 (ED. 12-96)Page 262
TOTAL41 110,821,300 9,902,728 -276,749 52,714,616
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEARPrepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)(g) (h) (i) (j) (k) (l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
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 (l) 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 (l) 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 (l) 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.
1
-1,654,653 -106,857,967 51,241,091 2
36,461,124 2,832 431,843 3
252,682 4,331 4
3,471,497 78,805 5
38,530,650 -106,857,967 2,832 51,756,070 6
7
8
9
10
2,854,938 1,427,469 11
-4,572 153,465 205,430 12
-4,572 3,008,403 1,632,899 13
14
15
128,434 2,067,018 16
33,917 45 165 17
-5,818 137,879 -138,123 18
127,080 13,338 19
1,240,533 1,255,286 20
283,613 3,445,430 45 1,130,666 21
22
23
67,429 1,878,520 1,910,000 24
-805 1,388 2,127 25
66,624 1,879,908 1,912,127 26
27
28
155,265 5,313,125 3,140,042 29
-14,750 599,321 71,204 30
31,373 3,000 31
57,700 1,456 32
116,755 15,268 33
314,970 5,943,819 3,230,970 34
35
36
3,554,804 1,776,118 37
-1,390 2,170 2,584 38
1,307 39
230,563 60,000 40
FERC FORM NO. 1 (ED. 12-96)Page 263
41 12,036,297 53,239,654 57,581,646 87,443,808
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2012/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a) (b) (c) (d) (e) (f)
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.
162,927 164,498 41,051 Wholesale Energy 1
3,587,240 3,951,952 -1,904 1,514,708Subtotal 2
3
New Mexico: 4
6,721 6,721 Property 5
50 536 -1,467 Income 6
6,771 7,257 -1,467Subtotal 7
8
Oregon: 9
23,213,399 22,575,991 10,977,923 Property 10
1,671,754 1,653,470 7,745 58,472 Unemployment 11
2,217 2,358 534 Wilsonville Payroll 12
184,991 -204,909 35,298 -28,843 Excise-Income 13
347 -59,737 -55,011 -2,559 City of Portland-Income 14
827 -39,463 -37,138 Multnomah County 15
827,343 838,377 424,705 Department of Energy 16
925,873 968,660 338,552 Tri-Met 17
2,173 2,173 Lane County 18
26,910,471 26,908,113 4,404,572 Franchise 19
53,739,395 -304,109 52,892,291 11,378,971 4,802,130Subtotal 20
21
Utah: 22
61,581,025 61,064,550 435,289 Property 23
-322,213 -137 19,121 167,657 Income 24
390,840 387,846 -78 7,545 Unemployment 25
608 608 Navajo Nation 26
4,057,485 3,909,249 434,708 Use 27
217,772 217,772 Franchise 28
65,925,517 -137 65,599,146 167,579 877,542Subtotal 29
30
Washington: 31
9,349,015 9,709,015 9,040,000 Property 32
63,966 64,954 1,037 Unemployment 33
35,336 35,435 3,414 Business & Occupation 34
1,060 689 371 Wholesaling 35
11,678,221 11,678,221 1,100,000 Public Utility 36
1,343,621 1,202,887 185,392 Natural Gas Use Tax 37
687,323 675,875 622,123 Use 38
500 500 Franchise 39
23,159,042 23,367,576 10,952,337Subtotal 40
78,502,426
FERC FORM NO. 1 (ED. 12-96)Page 262.1
TOTAL41 110,821,300 9,902,728 -276,749 52,714,616
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEARPrepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)(g) (h) (i) (j) (k) (l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
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 (l) 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 (l) 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 (l) 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.
164,498 42,622 1
-83 3,952,035 1,881,324 2
3
4
6,721 5
-1,058 1,594 1,953 6
-1,058 8,315 1,953 7
8
9
785,587 21,790,404 11,615,331 10
1,653,470 4,418 36,861 11
2,358 675 12
-102,266 137,564 84,059 13
-2,004 -53,007 6,938 14
-37,138 1,498 15
838,377 413,671 16
968,660 381,339 17
2,173 18
26,908,113 4,402,214 19
3,307,978 49,584,313 12,033,420 4,913,584 20
21
22
6,531,733 54,532,817 -81,186 23
-92,177 111,298 173,814 24
387,846 4,629 25
608 26
3,909,249 286,472 27
217,772 28
10,736,651 54,862,495 383,729 29
30
31
529,070 9,179,945 9,400,000 32
64,954 2,025 33
35,435 3,513 34
689 35
11,678,221 1,100,000 36
1,202,887 44,658 37
675,875 610,675 38
500 39
2,473,475 20,894,101 11,160,871 40
FERC FORM NO. 1 (ED. 12-96)Page 263.1
41 12,036,297 53,239,654 57,581,646 87,443,808
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2012/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a) (b) (c) (d) (e) (f)
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.
1
Wyoming: 2
14,725,027 15,011,602 7,226,044 Property 3
1,390,284 Wind generation tax 4
405,152 404,959 8,790 Unemployment 5
1,797,429 1,836,929 267,900 Franchise 6
770,777 1,107,801 -181,803 Use 7
63,274 63,274 Annual Report 8
17,761,659 19,814,849 7,320,931Subtotal 9
10
130,444 -25,103 -1,839,865 83,375 2,075,266State Other 11
12
Miscellaneous: 13
22,367 22,367 Goshute Possessory 14
196,697 196,697 Sho-Ban Possessory 15
37,041 37,618 18,232 Navajo Possessory 16
31,353 31,353 Ute Possessory 17
65,772 65,772 Crow Possessory 18
63,409 63,409 Umatilla Possessory 19
547,083 -25,103 -1,422,649 83,375 2,093,498Subtotal 20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
78,502,426
FERC FORM NO. 1 (ED. 12-96)Page 262.2
TOTAL41 110,821,300 9,902,728 -276,749 52,714,616
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEARPrepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)(g) (h) (i) (j) (k) (l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
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 (l) 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 (l) 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 (l) 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.
1
2
360,638 14,650,964 7,512,619 3
1,390,284 1,390,284 4
404,959 8,597 5
1,836,929 307,400 6
1,107,801 155,221 7
63,274 8
1,873,398 17,941,451 9,374,121 9
10
-1,839,865 46,685 11
12
13
22,367 14
196,697 15
37,618 18,809 16
31,353 17
65,772 18
63,409 19
-1,422,649 65,494 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 263.2
41 12,036,297 53,239,654 57,581,646 87,443,808
Schedule Page: 262 Line No.: 2 Column: f
$(147,313) Account 237, Interest accrued (1)
244,300 Account 123.1, Investment in subsidiary companies (2)
$ 96,987
(1) Represents interest on uncertain tax positions and corrections reclassified from
Account 165, Prepayments, to Account 237.
(2) Represents the transfer of PacifiCorp Environmental Remediation Company's ("PERCo")
taxes accrued balance as of June 30, 2012 from Account 123.1 due to the dissolution of
PERCo on July 1, 2012.
Schedule Page: 262 Line No.: 2 Column: l
Account 409.2, Income tax, other income and deductions, which represents federal income
tax applicable to other income and deductions.
Schedule Page: 262 Line No.: 3 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 4 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 5 Column: l
$3,471,014 Account 151, Fuel stock
483 Account 426.3, Penalties
$3,471,497
Schedule Page: 262 Line No.: 12 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262 Line No.: 16 Column: l
$110,219 Account 408.2, Taxes other than income taxes, other income and deductions
1,569 Account 589, Rents
16,646 Account 107, Construction work in progress
$128,434
Schedule Page: 262 Line No.: 17 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 18 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262 Line No.: 19 Column: l
Charged to same account as related goods.
Schedule Page: 262 Line No.: 24 Column: l
$ 633 Account 408.2, Taxes other than income taxes, other income and deductions
66,796 Account 107, Construction work in progress
$67,429
Schedule Page: 262 Line No.: 25 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262 Line No.: 29 Column: l
$ 1,301 Account 408.2, Taxes other than income taxes, other income and deductions
153,964 Account 107, Construction work in progress
$155,265
Schedule Page: 262 Line No.: 30 Column: f
Represents the transfer of PERCo's taxes accrued balance as of June 30, 2012 from Account
123.1, Investment in subsidiary companies, due to the dissolution of PERCo on July 1,
2012.
Schedule Page: 262 Line No.: 30 Column: l
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262 Line No.: 32 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 33 Column: l
Charged to same account as related goods.
Schedule Page: 262 Line No.: 38 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262 Line No.: 39 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 6 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262.1 Line No.: 10 Column: l
$ 11,129 Account 408.2, Taxes other than income taxes, other income and deductions
167,547 Account 589, Rents
606,911 Account 107, Construction work in progress
$785,587
Schedule Page: 262.1 Line No.: 11 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 12 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 13 Column: f
Represents the transfer of PERCo's taxes accrued balance as of June 30, 2012 from Account
123.1, Investment in subsidiary companies, due to the dissolution of PERCo on July 1,
2012.
Schedule Page: 262.1 Line No.: 13 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262.1 Line No.: 14 Column: f
Represents the transfer of PERCo's taxes accrued balance as of June 30, 2012 from Account
123.1, Investment in subsidiary companies, due to the dissolution of PERCo on July 1,
2012.
Schedule Page: 262.1 Line No.: 14 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262.1 Line No.: 15 Column: f
Represents the transfer of PERCo's taxes accrued balance as of June 30, 2012 from Account
123.1, Investment in subsidiary companies, due to the dissolution of PERCo on July 1,
2012.
Schedule Page: 262.1 Line No.: 17 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 18 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 23 Column: l
$ 30,763 Account 408.2, Taxes other than income taxes, other income and deductions
547 Account 589, Rents
4,554,955 Account 107, Construction work in progress
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
1,945,468 Account 151, Fuel stock
$6,531,733
Schedule Page: 262.1 Line No.: 24 Column: f
$(6,611) Account 123.1, Investment in subsidiary companies (1)
6,474 Account 456, Other electric revenues (2)
$ (137)
(1) Represents the transfer of PERCo's taxes accrued balance as of June 30, 2012 from
Account 123.1 due to the dissolution of PERCo on July 1, 2012.
(2) Represents the transfer of the refund from the Utah withholding tax to Account 456.
Schedule Page: 262.1 Line No.: 24 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262.1 Line No.: 25 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 27 Column: l
Charged to same account as related goods.
Schedule Page: 262.1 Line No.: 32 Column: l
$134,190 Account 408.2, Taxes other than income taxes, other income and deductions
3,181 Account 589, Rents
391,699 Account 107, Construction work in progress
$529,070
Schedule Page: 262.1 Line No.: 33 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 35 Column: l
Account 151, Fuel stock
Schedule Page: 262.1 Line No.: 37 Column: l
Account 151, Fuel stock
Schedule Page: 262.1 Line No.: 38 Column: l
Charged to same account as related goods.
Schedule Page: 262.2 Line No.: 3 Column: l
$ 953 Account 408.2, Taxes other than income taxes, other income and deductions
9,694 Account 589, Rents
349,991 Account 107, Construction work in progress
$360,638
Schedule Page: 262.2 Line No.: 5 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.2 Line No.: 7 Column: l
Charged to same account as related goods.
Schedule Page: 262.2 Line No.: 11 Column: f
Represents interest on uncertain tax positions and corrections reclassified from Account
165, Prepayments, to Account 237, Interest accrued.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
PacifiCorp X
/ /2012/Q4
Line
No.
Account Balance at Beginning
(c)(b)(a)
of YearSubdivisions AdjustmentsDeferred for Year Allocations toCurrent Year's IncomeAccount No. Amount Account No. Amount(d) (e) (f)(g)
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.
Electric Utility 1
3% 2
4% 3
7% 4
10% 33,383,365 411.4 1,808,768 5
10% 4,045,318 420 1,624,396 6
Idaho -203,555 581,585 411.4 42,532 7
TOTAL -203,555 38,010,268 3,475,696 8
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
9
10
11
12
10% 13
14
Total Nonutility 15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-89) Page 266
Balance at End
(i)(h)
of Year
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued)
PacifiCorp X
/ /2012/Q4
Line
No.ADJUSTMENT EXPLANATIONAverage Periodof Allocationto Income
1
2
3
4
31,574,597 48.37 5
2,420,922 30 6
335,498 30 7
34,331,017 8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-89) Page 267
Schedule Page: 266 Line No.: 5 Column: e
Internal Revenue Code 46(f)2
Schedule Page: 266 Line No.: 6 Column: e
Internal Revenue Code 46(f)1
Schedule Page: 266 Line No.: 7 Column: g
Represents an adjustment to the prior year balance that was credited to Account 420,
Investment Tax Credits.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER DEFFERED CREDITS (Account 253)
PacifiCorp X
/ /2012/Q4
Line
No.
Description and Other DEBITS
Credits
Account(c)(b)(a)
Balance at
End of Year
(d)
Deferred Credits Amount
(e)
Balance at
Beginning of Year Contra
(f)
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.
5,073,136Working Capital Deposits 5,997,934 924,798 1
2
5,008,644Reclamation Costs - Trapper Mine 5,258,748 250,104 3
4
517,386Reclamation Costs - Deseret Mine 476,006 7,820 49,200232 5
6
Reclamation Costs - Trail 7
1,084,678 Mountain Mine 1,084,678230 8
9
Western Coal Carriers Benefits 10
10,216,000 Obligation 11,077,000 1,705,413 844,413131 11
12
Bank Card Incentives (5) 334,699 472,516 137,817921 13
14
55,000Deferred Revenue - Other (5) 25,000 30,000421 15
16
9,369,229Deferred Compensation Plan 8,200,305 684,207 1,853,131131,232,241 17
18
2,200,084Redding Contract (20) 1,650,088 549,996456 19
20
430,022Foote Creek Contract (15) 292,382 137,640456 21
22
12,604,395Environmental Liabilities 26,769,085 16,837,518 2,672,828 23
24
Unearned Joint Use Pole 25
3,664,410Contact (1) 2,699,055 6,284,361 7,249,716454 26
27
13,681Misc. Security Deposits 2,875 250 11,056172 28
29
76,247Lease Incentives (10) 28,090 48,157931 30
31
112,124Cowlitz/Lewis River O&M (1) 115,085 276,203 273,242539 32
33
14,975Employee Housing Security Deposits 15,775 1,600 800131 34
35
Oregon DSM Loans NPV Unearned 36
117,459 Income (10) 15,734 101,725456 37
38
413,417Cogeneration Bonds-Sunnyside 413,417 39
40
1,450,000Transmission Security Deposits 667,243 3,764,500 4,547,257232,107 41
42
1,468,125Transmission Service Deposits 853,435 273,795 888,485232,456 43
44
558,811MCI F.O.G. wire lease (1) 558,214 3,349,286 3,349,883454 45
46
FERC FORM NO. 1 (ED. 12-94) Page 269
47 TOTAL 156,183,542 44,110,070 333,027,535 220,954,063
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER DEFFERED CREDITS (Account 253)
PacifiCorp X
/ /2012/Q4
Line
No.
Description and Other DEBITS
Credits
Account(c)(b)(a)
Balance at
End of Year
(d)
Deferred Credits Amount
(e)
Balance at
Beginning of Year Contra
(f)
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.
166,506,240Unamortized contract values 146,226,194 20,280,046242 1
2
Loss contingency accrual 120,260,000 120,260,000 3
4
Accrued Right-of-Way Obligations 1,091,171 1,091,171 5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-94) Page 269.1
47 TOTAL 156,183,542 44,110,070 333,027,535 220,954,063
Schedule Page: 269 Line No.: 23 Column: c
Account 131, Cash
Account 232, Accounts payable
Account 426.5, Other deductions
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
PacifiCorp X
/ /2012/Q4
Line
No.Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
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.
1 Accelerated Amortization (Account 281)
2 Electric
3 Defense Facilities
44,045,122 164,676,925 4 Pollution Control Facilities
5 Other (provide details in footnote):
6
7
44,045,122 164,676,925 8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilities
11 Pollution Control Facilities
12 Other (provide details in footnote):
13
14
15 TOTAL Gas (Enter Total of lines 10 thru 14)
16
44,045,122 164,676,925 17 TOTAL (Acct 281) (Total of 8, 15 and 16)
18 Classification of TOTAL
38,776,096 144,976,964 19 Federal Income Tax
5,269,026 19,699,961 20 State Income Tax
21 Local Income Tax
FERC FORM NO. 1 (ED. 12-96)Page 272
NOTES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES _ ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of YearDebitsCreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 AccountCredited Amount DebitedAccount Amount
(e)(f)(h)(j)(k)(g)(i)
3. Use footnotes as required.
1
2
3
208,722,047 4
5
6
7
208,722,047 8
9
10
11
12
13
14
15
16
208,722,047 17
18
183,753,060 19
24,968,987 20
21
FERC FORM NO. 1 (ED. 12-96)Page 273
NOTES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
PacifiCorp X
/ /2012/Q4
Line
No.Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
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.
Account 282 1
Electric 3,505,053,651 607,024,609 322,537,869 2
Gas 3
4
TOTAL (Enter Total of lines 2 thru 4) 3,505,053,651 607,024,609 322,537,869 5
Nonutility 6
7
8
TOTAL Account 282 (Enter Total of lines 5 thru 8) 3,505,053,651 607,024,609 322,537,869 9
Classification of TOTAL 10
Federal Income Tax 3,085,751,299 531,715,511 284,081,357 11
State Income Tax 419,302,352 75,309,098 38,456,512 12
Local Income Tax 13
FERC FORM NO. 1 (ED. 12-96)Page 274
NOTES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of YearDebitsCreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 AccountCredited Amount DebitedAccount Amount
(e)(f)(h)(j)(k)(g)(i)
3. Use footnotes as required.
1
123.1 3,796,825,280 81,976182.3 7,366,865 2
3
4
3,796,825,280 81,976 7,366,865 5
6
7
8
3,796,825,280 81,976 7,366,865 9
10
3,339,798,865 72,170 6,485,582 11
457,026,415 9,806 881,283 12
13
FERC FORM NO. 1 (ED. 12-96)Page 275
NOTES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
PacifiCorp X
/ /2012/Q4
Line
No.Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited to Account 410.1 to Account 411.1
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.
Account 283 1
Electric 2
40,063,783 48,834,143 714,741,585Regulatory Assets 3
4
5
1,689,764 2,583,924 31,980,155Other 6
7
8
41,753,547 51,418,067 746,721,740TOTAL Electric (Total of lines 3 thru 8) 9
Gas 10
11
12
13
14
15
16
TOTAL Gas (Total of lines 11 thru 16) 17
18
41,753,547 51,418,067 746,721,740TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19
Classification of TOTAL 20
36,758,652 45,267,030 657,392,955Federal Income Tax 21
4,994,895 6,151,037 89,328,785State Income Tax 22
Local Income Tax 23
FERC FORM NO. 1 (ED. 12-96)Page 276
NOTES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
Debits CreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 AccountCredited Amount DebitedAccount Amount
(e) (f) (h) (j) (k)(g) (i)
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.
1
2
695,709,590 37,451,735182.3 69,998,994 7,856,386 3,111,482 3
4
5
32,351,572 293,220190 815,963 6
7
8
728,061,162 37,744,955 70,814,957 7,856,386 3,111,482 9
10
11
12
13
14
15
16
17
18
728,061,162 37,744,955 70,814,957 7,856,386 3,111,482 19
20
640,964,707 33,229,604 62,343,510 6,916,542 2,739,262 21
87,096,455 4,515,351 8,471,447 939,844 372,220 22
23
FERC FORM NO. 1 (ED. 12-96)Page 277
NOTES (Continued)
Schedule Page: 276 Line No.: 3 Column: i
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER REGULATORY LIABILITIES (Account 254)
PacifiCorp X
/ /2012/Q4
Line
No.
Description and Purpose of DEBITS
CreditsAccount
(d)(c)(a)
Balance at End
of Current
Quarter/Year
(e)
Other Regulatory Liabilities Amount
(f)
Credited
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.
Balance at Begining
of Current
Quarter/Year
(b)
18,331,373 1,124,468 17,206,905Investment Tax Credit Regulatory Liability 190 1
3,344,410 3,785,659 441,249Income Tax Reg. Liab. - WA Flow Through 2
40,409 246,635 35,161 241,387Gain on Sale of Assets - OR (1) 3
186,354 801,168 -614,814Injuries & Damage Reserve - OR 925 4
2,971,700 11,356,804 -3,107,756 5,277,348Property Insurance Reserve - OR 924 5
88,212 201,756 113,544Property Insurance Reserve - ID 6
( 683,323) 921,282 547,631 2,152,236Property Insurance Reserve - UT 924 7
271,761 621,571 349,810Property Insurance Reserve - WY 8
6,782,142 2,679,837 4,114,860 12,555SMUD Revenue Imputation (11) 440,442 9
60,539 32,973 450,629 423,063Utah Home Energy Lifeline 142 10
1,735,663 669,786 1,065,877BPA Balancing Account - WA 440,442 11
2,698,057 905,356 1,792,701BPA Balancing Account - OR 440,442 12
12,170,694 12,259,337 88,643Asset Retirement Obligations Reg. Difference 13
466,652 305,814 800,851 640,013Washington Low Income Program 142 14
192,573 282,755 90,182Misc. Regulatory Liabilities - OR 15
1,780,412 907,013 2,639,097 1,765,698Blue Sky - OR 440,442 16
109,872 54,198 213,744 158,070Blue Sky - WA 440,442 17
56,912 27,628 97,076 67,792Blue Sky - CA 440,442 18
1,748,287 1,617,518 2,724,989 2,594,220Blue Sky - UT 440,442 19
16,480 15,503 55,579 54,602Blue Sky - ID 440,442 20
142,834 124,143 229,404 210,713Blue Sky - WY 440,442 21
2,324,196 24,562,034 2,319,249 24,557,087OR Energy Conservation Charge 22
43,842,950 33,284,995 17,590,233 7,032,278Renewable Energy Credit Sales Deferral 456 23
61,696 61,696Tax Revenue Requirement Adj. - UT 24
2,431,626 2,229,485 222,077 19,9362010 Protocol Deferral - OR (1) 25
540,834 360,556 180,278Powerdale Decommissioning Costs Giveback - UT (2) 26
2,434,345 2,434,345Green House Gas Allowance Revenues - CA 27
17,000,000 17,000,0002012 GRC Invest. in Emission Control Equip. - OR 28
9,545,204 17,526,652 7,981,448Regulatory Liability - Reclassifications 29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/3-Q (REV 02-04) Page 278
41 TOTAL 73,706,219 82,227,196 102,737,542 111,258,519
Schedule Page: 278 Line No.: 1 Column: a
Weighted average life is 47 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
Schedule Page: 278 Line No.: 22 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
Schedule Page: 278 Line No.: 25 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 278 Line No.: 26 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
Schedule Page: 278 Line No.: 28 Column: a
Represents a one-time credit to be provided to Oregon customers in 2013 as a result of the
2012 Oregon general rate case outcome pertaining to PacifiCorp's investments in certain
emissions control equipment at its coal-fueled generating facilities.
Schedule Page: 278 Line No.: 29 Column: f
The following schedule summarizes regulatory liabilities reclassifications:
As of
Reclassified from Regulatory Liabilities to Regulatory Assets: December 31, 2012
Injuries & Damage Reserve - OR $ 614,814
Property Insurance Reserve - OR 3,107,756
Reclassified from Regulatory Assets to Regulatory Liabilities:
DSM Regulatory Asset - CA 765,482
DSM Regulatory Asset - UT 8,206,230
Alternative Rate For Energy (CARE) - CA 621,982
Deferred Excess Net Power Costs - WA Hydro 103,748
Deferred Excess RECs in Rates/RBA - UT 2012 2,753,648
RTO Grid West N/R - OR 6,035
Deferred Independent Evaluator Fee - UT 114,940
SB 408 Regulatory Asset - OR and MCBIT 10,904
Solar Feed-In Tariff Deferral - CA 354,070
Solar Incentive Program - UT 867,043
$ 17,526,652
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC OPERATING REVENUES (Account 400)
PacifiCorp X
/ /2012/Q4
Line
No.Title of Account
(c)(b)(a)
Operating Revenues Year
to Date Quarterly/Annual
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 (f) 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.
Operating Revenues
Previous year (no Quarterly)
Sales of Electricity 1
1,490,664,456(440) Residential Sales 1,611,369,814 2
(442) Commercial and Industrial Sales 3
1,266,280,218Small (or Comm.) (See Instr. 4) 1,376,215,099 4
1,136,708,521Large (or Ind.) (See Instr. 4) 1,247,618,388 5
20,409,578(444) Public Street and Highway Lighting 19,998,454 6
19,305,829(445) Other Sales to Public Authorities 16,263,330 7
(446) Sales to Railroads and Railways 8
(448) Interdepartmental Sales 9
3,933,368,602TOTAL Sales to Ultimate Consumers 4,271,465,085 10
351,792,369(447) Sales for Resale 330,569,624 11
4,285,160,971TOTAL Sales of Electricity 4,602,034,709 12
(Less) (449.1) Provision for Rate Refunds 13
4,285,160,971TOTAL Revenues Net of Prov. for Refunds 4,602,034,709 14
Other Operating Revenues 15
8,445,905(450) Forfeited Discounts 9,445,744 16
6,203,507(451) Miscellaneous Service Revenues 6,413,143 17
94,873(453) Sales of Water and Water Power 860 18
20,180,422(454) Rent from Electric Property 18,875,927 19
(455) Interdepartmental Rents 20
160,005,183(456) Other Electric Revenues 136,299,293 21
73,666,512(456.1) Revenues from Transmission of Electricity of Others 76,416,197 22
(457.1) Regional Control Service Revenues 23
(457.2) Miscellaneous Revenues 24
25
268,596,402TOTAL Other Operating Revenues 247,451,164 26
4,553,757,373TOTAL Electric Operating Revenues 4,849,485,873 27
Page 300FERC FORM NO. 1/3-Q (REV. 12-05)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC OPERATING REVENUES (Account 400)
PacifiCorp X
/ /2012/Q4
Line
No.
MEGAWATT HOURS SOLD
Previous Year (no Quarterly)Current Year (no Quarterly)
AVG.NO. CUSTOMERS PER MONTH
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)
(d) (e) (f) (g)
6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by
the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of 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.
1
16,046,111 1,483,134 1,504,514 15,968,423 2
3
16,489,191 221,634 211,986 16,828,774 4
21,228,737 33,695 33,553 21,316,760 5
144,334 3,745 3,636 142,675 6
398,493 12 3 292,709 7
8
9
54,306,866 1,742,220 1,753,692 54,549,341 10
10,766,697 11,869,789 11
65,073,563 1,742,220 1,753,692 66,419,130 12
13
65,073,563 1,742,220 1,753,692 66,419,130 14
Page 301
Line 12, column (b) includes $ of unbilled revenues.
Line 12, column (d) includes MWH relating to unbilled revenues
250,650,000
3,304,764
FERC FORM NO. 1/3-Q (REV. 12-05)
Schedule Page: 300 Line No.: 11 Column: f
For a complete list of the number of customers see pages 310-311, Sales for Resale, of
this Form No. 1.
Schedule 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
Account 451, Miscellaneous service revenues, includes the following items that were
$250,000 or greater during the years ended December 31:
2012 2011
Account service charges -
disconnects/reconnects/returned check charges $4,448,063 $4,155,399
Customer contract flat rate billings 1,907,528 1,981,186
Schedule Page: 300 Line No.: 21 Column: b
Account 456, Other electric revenues, includes the following items that were $250,000 or
greater during the years ended December 31:
2012 2011
Renewable energy credit sales and amortization of
deferrals, net of established deferrals $ 106,970,144 $ 37,224,673
Wind-based ancillary services 12,186,449 8,045,284
Energy exchange credits 7,178,646 7,988,197
Steam sales 3,708,368 5,818,520
Flyash/by-product sales 3,234,313 3,135,065
Power sale and exchange agreements 1,091,292 1,091,292
Maintenance charges for work on transmission facilities 783,876 684,158
Revenue from generation interconnection and
transmission service request studies 715,380 903,959
Phase shifting equipment fee from
Western Electricity Coordinating Council 338,147 343,401
Service territory fixed cost recovery fee 262,676 -
Demand-side management revenue (1) - 91,535,136
Blue Sky revenue (1) - 2,482,644
(1) Beginning January 1, 2012, demand-side management revenue and Blue Sky revenue are
included in Account 440, Residential sales; Account 442, Commercial and industrial sales;
Account 444, Public street and highway lighting; and/or Account 445, Other sales to public
authorities.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
1 RESIDENTIAL SALES
2 CALIFORNIA
1,666 3 06LNX00311-LINE EXT 80% GTY
581 71 8,183 0.1352 78,551 4 06NETMT135-CA RES NET MTR
319 343 930 0.2345 74,799 5 06OALT015R-OUTD AR LGT SR
180,463 18,153 9,941 0.1316 23,742,090 6 06RESD000D-RES SRVC
113,166 10,077 11,230 0.1290 14,600,959 7 06RESDDL06-CA LOW INCOME
334 136 2,456 0.1911 63,843 8 06RGNSV025-CA SMALL GEN
237 8 29,625 0.1276 30,246 9 06RESD0DM9 - MULTI FAMILY
1,370 15 91,333 0.1070 146,538 10 06RESD0DS8-MULT FAM SBMET
89,992 7,310 12,311 0.1303 11,726,283 11 06RESD00DN-RES SVC-DEL NORT
44,051 12 SMUD REVENUE IMPUTATIONS
-140 -0.6357 89,000 13 UNBILLED REVENUE
1,000 14 UNBILLED REV - UNCOLLECTIBLE
1,062,663 15 DSM - RESIDENTIAL
25,660 16 BLUE SKY - RESIDENTIAL
31,141 17 REVENUE - ACCOUNTING ADJ
-432,286 18 OTHER REV ADJ - DEFERRAL
407,769 19 OTHER REV ADJ - REALIZED
20
21 IDAHO
-1 22 07BLSKY01R-BLUESKY ENERGY
1,269 23 07LNX00010-MNTHLY 80%GUAR
1,904 24 07LNX00035-ADV 80%MO GUAR
-2,416 25 07NETMT135-BPA-ID RES NET
1,313 82 16,012 0.1030 135,222 26 07NETMT135-ID RES NET MTR
10 1 10,000 0.3786 3,786 27 07OALCO007-CUST OWN LIGHT
96 121 793 0.4078 39,144 28 07OALT07AR-SECURITY AR LG
-180 29 07OALT07AR-BPA-SECURITY AR
420,404 43,752 9,609 0.1087 45,700,923 30 07RESD0001-RES SRVC
-780,324 31 07RESD0001-BPA-RES SRVC
255,948 14,097 18,156 0.0910 23,285,776 32 07RESD0036-RES SRVC-OPTIO
-463,776 33 07RESD0036-BPA-RES SRVC-O
1,505 266 5,658 0.1144 172,166 34 07RGNSV23A-ID SM GEN SVC
-2,767 35 07RGNSV23A-BPA-ID SM GEN SVC
60,784 36 SMUD REVENUE IMPUTATIONS
-488,934 37 BPA BALANCING ACCOUNT
-3,621 0.0177 -64,000 38 UNBILLED REVENUE
-2,000 39 UNBILLED REV - UNCOLLECTIBLE
1,784,647 40 DSM - RESIDENTIAL
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
15,182 1 BLUE SKY - RESIDENTIAL
2
3 OREGON
5,112,560 0.0579 296,056,922 4 01COST0004 - 01RESD0004
10,226 0.0608 621,953 5 01COSTR023-RES GEN SRV CST
-1 6 01FXRENEWR-Fixed Renewable
39,782 0.0568 2,258,005 7 01HABIT004 - 01RESD0004
13 0.0643 836 8 01HABTR023-RES GEN SVC HAB
11,593 9 01LNX00102-LINE EXT 80% G
8 10 01LNX00105-CNTRCT $ MIN G
1,618 11 01LNX00109-REF/NREF ADV +
2,015 813,064 12 01NETMT135-NET METERING
-60,684 13 01NETMT135-BPA-NET METERING
14 6,904 14 01NMTOU135-TOU NET MTR
-551 15 01NMTOU135-BPA-TOU NET MTR
2,400 2,737 877 0.1670 400,909 16 01OALTB15R-OUTD AR LGT RE
-9,253 17 01OALTB15R-BPA-OUTD AR LGT
18,662 0.0596 1,112,957 18 01PTOU0004 - 01RESD0004
218,211 0.0561 12,233,790 19 01RENEW004 - 01RESD0004
35 0.0620 2,171 20 01RENWR023-RENEW USAGE
472,432 251,294,802 21 01RESD0004-RES SRVC
-21,149,919 22 01RESD0004-BPA-RES SRVC
1,247 828,849 23 01RESD004T-RES Time Option
-62,573 24 01RESD004T-BPA-RES Time Opt
2,479 842,064 25 01RGNSB023-SM GEN SVC-RES
-39,764 26 01RGNSB023-BPA-SM GEN SVC
144 94,644 27 01VIR04136-OR RES VOL INCTV
-7,001 28 01VIR04136-BPA-OR RES VOL
3 29 01ZZMERGCR-MERGER CREDITS
121,591 30 OR GAIN ON SALE OF ASSET
-2,199 31 OR SB 838 RECOVERY
557,876 32 SMUD REVENUE IMPUTATIONS
761,848 33 BPA BALANCING ACCOUNT
3,687 0.4372 1,612,000 34 UNBILLED REVENUE
3,000 35 UNBILLED REV - UNCOLLECTIBLE
13,939,319 36 DSM - RESIDENTIAL
242,851 37 BLUE SKY - RESIDENTIAL
-6,159,864 38 REVENUE - ACCOUNTING ADJ
-349,346 39 OTHER REV ADJ - DEFERRAL
663,985 40 OTHER REV ADJ - REALIZED
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.1
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
1
2 UTAH
-5 3 08BLSKY01R-BLUESKY ENERGY
1,041 4 08CFR00001-MTH FACILITY S
103,667 5 08COOLKPRR - Utah Cool Keeper
3,680 6 08LNX00001-MTHLY 80% GUAR
2,983 7 08LNX00005-MTHLY MIN GUAR
22,938 8 08LNX00013-80% MNTHLY MIN
2,604 9 08LNX00108-ANN COST MTHLY
10,668 7 1,524,000 0.0700 746,320 10 08MHTP0006-MOBILE HOME &
329 3 109,667 0.0880 28,937 11 08MHTP0023-MOBILE HOME &
8,071 1,171 6,892 0.1016 820,131 12 08NETMT135-Net Metering
2,753 2,994 920 0.2848 783,971 13 08OALT007R-SECURITY AR LG
2 3 667 0.0655 131 14 08PTLD000R-POST TOP LIGHT
6,418,576 682,151 9,409 0.0998 640,419,931 15 08RESD0001-RES SRVC
2,748 335 8,203 0.0979 268,929 16 08RESD0002-RES SRVC-OPTIO
248,294 31,065 7,993 0.0979 24,311,215 17 08RESD0003-LIFELINE PRGRM
-50 18 08RESD0150-RES ALL E NOT5
69,560 190 366,105 0.0721 5,013,264 19 08RGNSV006-GEN SRVC-RES
77,725 10,509 7,396 0.1044 8,113,921 20 08RGNSV023-GEN SRVC-RES
5,185 19 272,895 0.0790 409,870 21 08RGNSV06A-UT SM GEN SVC
257 16 16,063 0.0970 24,941 22 08RNM23135-UT NET MTR, GEN
7,736 0.3926 3,037,000 23 UNBILLED REVENUE
-14,000 24 UNBILLED REV - UNCOLLECTIBLE
18,864,721 25 DSM - RESIDENTIAL
1,239,315 26 BLUE SKY - RESIDENTIAL
100,943 27 REVENUE - ACCOUNTING ADJ
-3,945,012 28 REVENUE ADJ - DEFERRED NPC
-360,127 29 OTHER REV ADJ - DEFERRAL
30,721 30 OTHER REV ADJ - REALIZED
31
32 WASHINGTON
-1 33 02BLSKY01R-BLUESKY ENERGY
807 34 02LNX00109-REF/NREF ADV +
813 54 15,056 0.0902 73,345 35 02NETMT135-WA RES NET MTR
-3,334 36 02NETMT135-BPA-WA RES NET
1,066 1,148 929 0.1492 159,048 37 02OALTB15R-WA OUTD AR LGT
-4,354 38 02OALTB15R-BPA-WA OUTD AR
1,517,350 100,004 15,173 0.0862 130,723,549 39 02RESD0016-WA RES SRVC
-6,221,189 40 02RESD0016-BPA-WA RES SRVC
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.2
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
62,672 4,074 15,383 0.0857 5,372,522 1 02RESD0017-BILL ASSISTANCE
-256,957 2 02RESD0017-BILL ASSISTANCE
2,200 85 25,882 0.0947 208,437 3 02RESD0018-WA 3 PHASE RES
-9,022 4 02RESD0018-BPA-WA 3 PHASE
426 18 23,667 0.0931 39,661 5 02RESD018X-WA 3 PHASE RES
-1,747 6 02RESD018X-BPA-WA 3 PHASE
1 7 02RFNDCENT-CENTRALIA RFND
2,409 558 4,317 0.1180 284,327 8 02RGNSB024-WA SM GEN SVC
-9,878 9 02RGNSB024-BPA-WA SM GEN
-1,320,000 10 WASHINGTON-CHEHALIS
165,843 11 SMUD REVENUE IMPUTATIONS
554,748 12 BPA BALANCING ACCOUNT
9,339 0.0962 898,000 13 UNBILLED REVENUE
-6,000 14 UNBILLED REV - UNCOLLECTIBLE
4,387,387 15 DSM - RESIDENTIAL
-4,387,387 16 REVENUE - ACCOUNTING ADJ
44,537 17 BLUE SKY - RESIDENTIAL
-2,175,835 18 REVENUE ADJ - DEFERRED NPC
19
20 WYOMING
-2 21 05BLSKY01R-BLUESKY ENERGY
256 22 05LNX00102-LINE EXT 80% G
1,251 111 11,270 0.1066 133,418 23 05NETMT135-EXPERIMENTAL
199 12 16,583 0.1033 20,556 24 05NETMT135-EXPERIMENTAL
917 1,069 858 0.1584 145,209 25 05OALT015R-OUTD AR LGT SR
914,432 98,451 9,288 0.0997 91,179,438 26 05RESD0002-WY RES SRVC
123,685 12,478 9,912 0.1010 12,490,077 27 05RESD0002-WY RES SRVC
2,479 383 6,473 0.1092 270,661 28 05RGNSV025-WY SM GEN SVC
84 28 3,000 0.1562 13,124 29 05RGNSV025-WY SM GEN SVC
890 30 05LNX00109-REF/NREF ADV +
77 92 837 0.2989 23,016 31 09OALT207R-SECURITY AR LG
-6 4 -1,500 0.0738 -443 32 09RESD0002
2 33 09RFNDCENT-CENTRALIA RFND
75,922 34 SMUD REVENUE IMPUTATIONS
9,062 0.1281 1,161,000 35 UNBILLED REVENUE
511 0.1585 81,000 36 UNBILLED REVENUE
-17,000 37 UNBILLED REV - UNCOLLECTIBLE
1,035,447 38 DSM - RESIDENTIAL
135,819 39 DSM - RESIDENTIAL
3,374 40 DSM - RESIDENTIAL GEN SVC
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.3
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
290 1 DSM - RESIDENTIAL GEN SVC
92,194 2 BLUE SKY - RESIDENTIAL
19,482 3 BLUE SKY - RESIDENTIAL
-1,671,522 4 REVENUE ADJ - DEFERRED NPC
5
-121,685 6 LESS MULTIPLE BILLINGS
7
15,968,423 1,504,514 10,614 0.1009 1,611,369,814 8 TOTAL RESIDENTIAL SALES
9
10 COMMERCIAL SALES
11 CALIFORNIA
55,923 6,779 8,249 0.1556 8,700,280 12 06GNSV0025-CA GEN SRVC
943 85 11,094 0.1709 161,136 13 06GNSV025F-GEN SRVC-<20
82,698 979 84,472 0.1278 10,568,721 14 06GNSV0A32-GEN SRVC-20 KW
61,135 13 4,702,692 0.0869 5,310,167 15 06LGSV048T-LRG GEN SERV
74,786 169 442,521 0.1084 8,107,038 16 06LGSV0A36-LRG GEN SRVC-O
12,625 17 06LNX00102-LINE EXT 80% G
-1,018 18 06LNX00103-LINE EXT 80% G
4,582 19 06LNX00105-CNTRCT $ MIN G
72,874 20 06LNX00109-REF/NREF ADV +
8,389 21 06LNX00300-80% MTHLY MIN GU
10,661 22 06LNX00311-LINE EXT 80% GUAR
366 1 366,000 0.1309 47,906 23 06NMT36135-CA GEN SVC NET
712 515 1,383 0.2385 169,816 24 06OALT015N-OUTD AR LGT SR
185 38 4,868 0.1852 34,266 25 06RCFL0042-AIRWAY & ATHLE
57 4 14,250 0.1499 8,543 26 06NMT25135-GN SVC NET<20K
421 5 84,200 0.1413 59,471 27 06NMT32135-GN SVC NET>20K
8,226 28 06LNX00110-REF/NREF ADV +
31,034 29 SMUD REVENUE IMPUTATIONS
-3,506 0.1155 -405,000 30 UNBILLED REVENUE
684,411 31 DSM - COMMERCIAL
10 1,869 32 BLUE SKY - COMMERCIAL
19,145 33 REVENUE - ACCOUNTING ADJ
-406,696 34 OTHER REV ADJ - DEFERRAL
362,783 35 OTHER REV ADJ - REALIZED
36
37 IDAHO
5,548 112 49,536 0.0828 459,209 38 07CISH0019-COMM & IND SPA
198,219 939 211,096 0.0797 15,794,793 39 07GNSV0006-GEN SRVC-LRG P
44,082 2 22,041,000 0.0583 2,568,970 40 07GNSV0009-GEN SRVC-HI VO
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.4
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
133,815 6,433 20,801 0.0942 12,605,805 1 07GNSV0023-GEN SRVC-SML P
514 2 257,000 0.0800 41,137 2 07GNSV0035-GEN SRVCOPTION
28,150 191 147,382 0.0841 2,368,392 3 07GNSV006A-GEN SRVC-LRG P
-51,767 4 07GNSV006A-BPA-GEN SRVC-LRG
20,621 1,342 15,366 0.0962 1,984,378 5 07GNSV023A-GEN SRVC-SML P
-37,960 6 07GNSV023A-BPA-GEN SRVC-SML
18 7 2,571 0.1714 3,086 7 07GNSV023F-GEN SRVC SML P
2,435 8 07LNX00010-MNTHLY 80%GUAR
258,986 9 07LNX00035-ADV 80%MO GUAR
80,404 10 07LNX00040-ADV+REFCHG+80%
231 176 1,313 0.3770 87,083 11 07OALT007N-SECURITY AR LG
11 12 917 0.3970 4,367 12 07OALT07AN-SECURITY AR LG
-20 13 07OALT07AN-BPA-SECURITY AR
6,884 14 07LNX00312-ID LINE EXT
1,652 4 413,000 0.0865 142,897 15 07NMT06135-ID NET MTR-LG GEN
601 14 42,929 0.0802 48,211 16 07NMT23135-ID NET MTR-SM GEN
1,349 17 07LNX00015-ANNUAL 80%GUAR
41,307 18 07LNX00311-LINE EXT 80% GUAR
9,162 19 07LNX00300-80% MTHLY MIN GU
36,916 20 SMUD REVENUE IMPUTATIONS
-30,696 21 BPA BALANCING ACCOUNT
3,664 0.1179 432,000 22 UNBILLED REVENUE
937,651 23 DSM - COMMERCIAL
24 1,461 24 BLUE SKY - COMMERCIAL
25
26 OREGON
984,116 0.0579 57,019,063 27 01COST0023-OR GEN SRV-COST
845,831 0.0526 44,523,226 28 01COST0048 - 01LGSV0048
2,927 0.0617 180,696 29 01COST023F-OR GEN SRV-COST
76,109 0.0601 4,571,795 30 01COSTB023-OR GEN SRV-COST
1,005,511 0.0535 53,767,532 31 01COSTL030-OR LG GEN SRV
1,914,253 0.0580 111,073,925 32 01COSTS028-OR GEN SERV-COST
-297,504 33 01GNSB0023-BPA DISC <30kW
12,813 5,326,746 34 01GNSB0023-BPA GEN SRV<30kW
-500,569 35 01GNSB0028-BPA GEN SRV>30kW
532 3,001,416 36 01GNSB0028-BPA GEN SRV>30kW
51 25,814 37 01GNSB023T-BPA-OR GEN SRV
-1,686 38 01GNSB023T-BPA-OR GEN SRV
-15 57,401 -3,056.7955 45,851,932 39 01GNSV0023-OR GEN SRV<30kW
8,793 44,743,588 40 01GNSV0028-OR GEN SRV>30kW
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.5
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
9,875 783 12,612 0.1525 1,505,957 1 01GNSV023F-OR GEN SRV-FLAT
44 1 44,000 0.0921 4,051 2 01GNSV023M-OR GEN SRV-MANU
219 162,887 3 01GNSV023T-OR GEN SRV-TOU
2,459 0.0588 144,478 4 01HABT0023-OR HABITAT BLEND
177 0.0613 10,842 5 01HABTB023-OR HABITAT BLEND
-172,737 6 01LGSB0030-GEN DEL SRV >200
25 800,530 7 01LGSB0030-GEN DEL SRV >200
582 19,478,372 8 01LGSV0030-LG GEN SRV >1000
98 9,420,201 9 01LGSV0048-1000kW AND OVR
60,473 1 60,473,000 0.0584 3,534,592 10 01LGSV048M-LRG GEN SRVC 1
2,685 11 01LNX00100-LINE EXT 60% G
278,561 12 01LNX00102-LINE EXT 80% G
3,207 13 01LNX00103-LINE EXT 80% G
14,263 14 01LNX00105-CNTRCT $ MIN G
1,463,865 15 01LNX00109-REF/NREF ADV +
1,500 16 01LNX00110-REF/NREF ADV +
463 17 01LNX00120-LINE EXT 60% G
168,655 18 01LNX00300-LINE EXT 80% GUAR
807 19 01LNX00310-LINE EXT CONTRACT
134,757 20 01LNX00311-LINE EXT 80% G
37,762 3 12,587,333 0.0842 3,181,372 21 01LPRS047M-PART REQ SRVC
158 122,581 22 01NMT23135-NET MTR GEN <30
-304 23 01NMT23135-BPA-NET MTR GEN
5,638 2,950 1,911 0.1540 868,120 24 01OALT015N-OUTD AR LGT NR
1,558 1,120 1,391 0.1714 266,977 25 01OALTB15N-OUTD AR LGT NR
-6,003 26 01OALTB15N-BPA OUTD AR LGT
3,356 0.0590 198,167 27 01PTOU0023-OR GEN SRV-TOU
443 0.0594 26,320 28 01PTOUB023-OR GEN SRV-TOU
1,170 102 11,471 0.1050 122,795 29 01RCFL0054-REC FIELD LGT
8,262 0.0592 489,096 30 01RENW0023-OR RENW USAGE
372 0.0617 22,950 31 01RENWB023-OR RENEWABLE
2,458 0.0551 135,392 32 01STDAY023-DAY STD OFR SCH
13,198 0.0539 710,897 33 01STDAY028-DAY STD OFF SCH
4,503 0.0510 229,573 34 01STDAY030-STD DAY OFF SCH
40 52,077 35 01VIR23136-VOL INCTV <=30 kW
-211 36 01VIR23136-BPA-VOL INCTV <=30
40 190,273 37 01VIR28136-VOL INCTV >30 kW
-4,059 38 01VIR28136-BPA-VOL INCTV >30
2 57,792 39 01VIR30136-VOL INCTV >200 kW
1 74,576 40 01VIR48136-VOL INCTV >1000 kW
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.6
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
-12,019 1 01LGSB0048-LG GEN SVC >1000
1 51,988 2 01LGSB0048-LG GEN SVC >1000
83 485,981 3 01NMT28135-NET MTR GEN >30
-1,973 4 01NMT28135-BPA-NET MTR GEN
16 555,955 5 01NMT30135-NET MTR GEN >200
3 150,125 6 01NMT48135-NET MTR GEN
1,369 1 1,369,000 0.0734 100,451 7 01LGSV028M-LGSV <1000 kW
1,750 1 1,750,000 0.0742 129,817 8 01GNSV030M-GEN SRV 200 kW
18 337,512 9 01GNSV0728-GEN SVC DIR ACC
44 4,339,075 10 01GNSV0730-GEN SVC DIR ACC
2 476,218 11 01GNSV0748-LG GEN SVC DIR
88,789 12 OR GAIN ON SALE OF ASSET
-1,852 13 OR SB 838 RECOVERY
496,407 14 SMUD REVENUE IMPUTATIONS
34,108 15 BPA BALANCING ACCOUNT
-7,061 0.2505 -1,769,000 16 UNBILLED REVENUE
9,186,357 17 DSM - COMMERCIAL
263 489,409 18 BLUE SKY - COMMERCIAL
-5,861,385 19 REVENUE - ACCOUNTING ADJ
-297,896 20 OTHER REV ADJ - DEFERRAL
639,906 21 OTHER REV ADJ - REALIZED
22
23 UTAH
-386 24 08ABL-NRES - APPLICANT BUILT
38,771 25 08CFR00051-MTH FAC SRVCHG
2 26 08CFR00052-ANN FAC SVCCHG
4,919,845 10,716 459,112 0.0779 383,174,517 27 08GNSV0006-GEN SRVC-DISTR
392,567 27 14,539,519 0.0528 20,733,806 28 08GNSV0009-GEN SRVC-HI VO
1,211,696 65,700 18,443 0.0920 111,447,731 29 08GNSV0023-GEN SRVC-DISTR
217,596 1,903 114,344 0.1078 23,458,617 30 08GNSV006A-GEN SRVC-ENERG
7,716 33 233,818 0.0851 656,720 31 08GNSV006B-GEN SRVC-DEM&
3,007 6 501,167 0.0643 193,416 32 08GNSV006M-MNL DIST VOLTG
22,556 2 11,278,000 0.0601 1,354,868 33 08GNSV009A-GEN SRVC HI VO
122,825 1 122,825,000 0.0488 5,993,706 34 08GNSV009M-MANL HIGH VOLT
1,305 125 10,440 0.1332 173,883 35 08GNSV023F-GEN SRVC FIXED
168 5 33,600 0.0834 14,006 36 08GNSV023M-GNSV DIST VOLT
306 1 306,000 0.1303 39,862 37 08GNSV06AM-MNL ENERGY TOD
32,674 470 69,519 0.0720 2,353,827 38 08GNSV06MN-GNSV DIST VOLT
407,684 39 08LNX00002-MTHLY 80% GUAR
23,196 40 08LNX00004-ANNUAL 80%GUAR
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.7
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
4,668 1 08LNX00006-FIXD MTHLY MIN
8,171 2 08LNX00008-ANNUALMIN GUAR
1,906,691 3 08LNX00014-80% MIN MNTHLY
612,542 4 08LNX00017-ADV/REF&80%ANN
32,666 5 08LNX00158-ANNUALCOST MTH
133,021 6 08LNX00300-LINE EXT 80% PLUS
43,065 7 08LNX00310-IRR 80% ANNUAL MIN
3,963 8 08LNX00312-UT IRG LINE EXT
39,666 73 543,370 0.0783 3,105,773 9 08NMT06135-UT NET MTR GEN
14,924 3 4,974,667 0.0683 1,019,201 10 08NMT08135-NET MTR GEN SVC
1,985 104 19,087 0.0953 189,106 11 08NMT23135-NET MTR GEN <25
660 5 132,000 0.1187 78,355 12 08NMT6A135-NET MTR GEN SVC
8,354 4,362 1,915 0.2325 1,942,657 13 08OALT007N-SECURITY AR LG
2 161 14 08POLE0075-POLES W/LIGHT
10,144 2 5,072,000 0.0808 820,061 15 08PRSV031M-BKUP MNT&SUPPL
6 2 3,000 0.0753 452 16 08PTLD000N-POST TOP LIGHT
182 23 7,913 0.0872 15,867 17 08TOSS015F-TRAFFIC SIG NM
1,842 782 2,355 0.1030 189,783 18 08TOSS0015-TRAF &amp; OTHER
16,179 425 38,068 0.0711 1,150,465 19 08MONL0015-MTR OUTDONIGHT
265,892 20 08LNX00311-LINE EXT 80% GUAR
1,014,138 154 6,585,312 0.0677 68,685,707 21 08GNSV0008-GEN SVC TOU >1000
31,800 5 6,360,000 0.0731 2,325,389 22 08GNSV008M-GEN SVC TOU
37,483 0.1124 4,213,000 23 UNBILLED REVENUE
16,792,152 24 DSM - COMMERCIAL
130 288,234 25 BLUE SKY - COMMERCIAL
96,488 26 REVENUE - ACCOUNTING ADJ
-4,133,094 27 REVENUE ADJ - DEFERRED NPC
-250,383 28 OTHER REV ADJ - DEFERRAL
22,686 29 OTHER REV ADJ - REALIZED
30
31 WASHINGTON
40,619 3,010 13,495 0.0927 3,766,988 32 02GNSB0024-GEN SRVC DO
-166,539 33 02GNSB0024-BPA-GEN SRVC DO
141 6 23,500 0.1187 16,731 34 02GNSB024F-GEN SRVC DOM/F
-4 35 02GNSB024F-BPA-GEN SRVC
1,138 87 13,080 0.1411 160,625 36 02GNSB24FP-GEN SVC SEASON
-4,664 37 02GNSB24FP-BPA-GEN SVC SEAS
480,239 14,426 33,290 0.0856 41,095,765 38 02GNSV0024-WA GEN SRVC
1,111 111 10,009 0.1268 140,900 39 02GNSV024F-WA GEN SRVC-FL
81,156 99 819,758 0.0712 5,779,187 40 02LGSB0036-LRG GEN SVC IRG
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.8
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
-332,740 1 02LGSB0036-BPA-LRG GENSVC
695,604 808 860,896 0.0724 50,356,813 2 02LGSV0036-WA LRG GEN SRV
146,912 27 5,441,185 0.0656 9,632,374 3 02LGSV048T-LRG GEN SRVC 1
-124,423 4 02LNX00102-LINE EXT 80% G
23,433 5 02LNX00103-LINE EXT 80% G
1,844 6 02LNX00105-CNTRCT $ MIN G
-1,789 7 02LNX00109-REF/NREF ADV +
7,640 8 02LNX00110-REF/NREF ADV +
652 9 02LNX00112-YR INCURRED CH
11,661 10 02LNX00300-LINE EXT 80% G
-1,130 11 02LNX00310-IRG 80% ANNUAL
45,865 12 02LNX00311-LINE EXT 80% GUAR
2,814 13 02LNX00312-WA IRG LINE EXT
1,612 843 1,912 0.1383 222,933 14 02OALT015N-WA OUTD AR LGT
588 518 1,135 0.1488 87,470 15 02OALTB15N-WA OUTD AR LGT
-2,402 16 02OALTB15N-BPA-WA OUTD AR
286 29 9,862 0.0907 25,950 17 02RCFL0054-WA REC FIELD L
493 8 61,625 0.0873 43,024 18 02NMT24135-Net metering WA
-19 19 02NMT24135-BPA-Net metering WA
101 1 101,000 0.1114 11,252 20 02NMT36135-NET MTR LG SVC
44,992 21 BPA BALANCING ACCOUNT
144,750 22 SMUD REVENUE IMPUTATIONS
-1,020,000 23 WASHINGTON - CHEHALIS
-2,524 0.0674 -170,000 24 UNBILLED REVENUE
3,608,078 25 DSM - COMMERCIAL
4 9,614 26 BLUE SKY - COMMERCIAL
-1,681,199 27 REVENUE ADJ - DEFERRED NPC
-3,608,078 28 REVENUE - ACCOUNTING ADJ
29
30 WYOMING
227,445 17,907 12,701 0.0908 20,648,775 31 05GNSV0025-WY GEN SRVC
33,984 2,350 14,461 0.0880 2,989,773 32 05GNSV0025-WY GEN SRVC
896,386 3,365 266,385 0.0788 70,629,077 33 05GNSV0028-GEN SVC >15 kW
106,904 431 248,037 0.0777 8,309,982 34 05GNSV0028-GEN SVC >15 kW
999 182 5,489 0.1825 182,283 35 05GNSV025F-GEN SRVC-FL RA
195 32 6,094 0.1167 22,761 36 05GNSV025F-GEN SRVC-FL RA
263,942 19 13,891,684 0.0625 16,487,623 37 05LGSV0046-WY LRG GEN SRV
10,122 1 10,122,000 0.0694 702,133 38 05LGSV048T-LRG GENSRV TIM
11,081 39 05LNX00100-LINE EXT 60% G
572,603 40 05LNX00102-LINE EXT 80% G
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.9
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
10,738 1 05LNX00102-LINE EXT 80% G
1,646 2 05LNX00103-LINE EXT 80% G
5,368 3 05LNX00105-CNTRCT $ MIN G
688,657 4 05LNX00109-REF/NREF ADV +
217,862 5 05LNX00109-REF/NREF ADV +
559 6 05LNX00110-REF/NREF ADV +
3,300 7 05LNX00110-REF/NREF ADV +
3,578 8 05LNX00114-TEMP SVC 12MO>
227 9 05LNX00114-TEMP SVC 12MO>
269 17 15,824 0.0858 23,067 10 05NMT25135-NET MTR GEN <25
21 2 10,500 0.0930 1,952 11 05NMT25135-NET MTR GEN <25
5,177 13 398,231 0.0910 470,963 12 05NMT28135-NET MTR SM GEN
525 3 175,000 0.0829 43,531 13 05NMT28135-NET MTR SM GEN
2,830 1,725 1,641 0.1605 454,280 14 05OALT015N-OUTD AR LGT SR
2 2 1,000 0.2435 487 15 05OALT015N-OUTD AR LGT SR
713 51 13,980 0.0826 58,863 16 05RCFL0054-WY REC FIELD L
60,157 17 05LNX00300-LINE EXT 80% GUAR
87,823 18 05LNX00311-LINE EXT 80% GUAR
-3 0.0693 -208 19 05GNS28025-GEN SVC
1,219 1 1,219,000 0.0764 93,135 20 05GNSV028M-GEN SVC >15 kW
-22 0.0808 -1,777 21 09GNSV0025-GEN SVC-SINGLE
275 139 1,978 0.2600 71,487 22 09OALT207N-SECURITY AR LG
44 4 11,000 0.0621 2,733 23 09MONL0213-WY MTR OUTDOOR
2,029 24 05LNX00300-LINE EXT 80% GUAR
743 25 05LNX00311-LINE EXT 80% GUAR
2 26 09RFNDCENT-CENTRALIA RFND
110,121 27 SMUD REVENUE IMPUTATIONS
3,519 0.0912 321,000 28 UNBILLED REVENUE
29,744 0.0863 2,566,000 29 UNBILLED REVENUE
742,332 30 DSM - SMALL COMMERCIAL
90,930 31 DSM - SMALL COMMERCIAL
190,705 32 DSM - LARGE COMMERCIAL
42 4,941 33 BLUE SKY - COMMERCIAL
14 1,202 34 BLUE SKY - COMMERCIAL
-2,392,691 35 REVENUE ADJ - DEFERRED NPC
36
-23,355 37 LESS MULTIPLE BILLINGS
38
16,828,774 211,986 79,386 0.0818 1,376,215,099 39 TOTAL COMMERCIAL SALES
40
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.10
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
1 INDUSTRIAL SALES
2 CALIFORNIA
684 92 7,435 0.1595 109,064 3 06GNSV0025-CA GEN SRVC
2,198 26 84,538 0.1478 324,972 4 06GNSV0A32-GEN SRVC-20 kW
14,543 5 2,908,600 0.0976 1,418,727 5 06LGSV048T-LRG GEN SERV
4,624 11 420,364 0.1182 546,463 6 06LGSV0A36-LRG GEN SRVC-O
4,580 7 SMUD REVENUE IMPUTATIONS
489 0.1656 81,000 8 UNBILLED REVENUE
84,434 9 DSM - INDUSTRIAL
83 10 BLUE SKY - INDUSTRIAL
-26,751 11 OTHER REV ADJ - DEFERRAL
23,893 12 OTHER REV ADJ - REALIZED
8,216 13 REVENUE - ACCOUNTING ADJ
14
15 IDAHO
2,217 16 07CFR00001-MTH FACILITY S
123 3 41,000 0.0856 10,529 17 07CISH0019-COMM & IND SPA
88,451 107 826,645 0.0690 6,102,815 18 07GNSV0006-GEN SRVC-LRG P
79,529 13 6,117,615 0.0600 4,775,393 19 07GNSV0009-GEN SRVC-HI VO
11,963 345 34,675 0.0913 1,092,590 20 07GNSV0023-GEN SRVC-SML P
669 1 669,000 0.0757 50,660 21 07GNSV0035-GEN SRVCOPTION
4,197 28 149,893 0.0847 355,552 22 07GNSV006A-GEN SRVC-LRG P
-7,722 23 07GNSV006A-BPA-GEN SRVC-LRG
2,191 226 9,695 0.1044 228,829 24 07GNSV023A-GEN SRVC-SML P
-4,033 25 07GNSV023A-BPA-GEN SRVC-SML
8 3 2,667 0.1488 1,190 26 07GNSV023S-IDAHO TRAFFIC
2,119 27 07LNX00035-ADV 80%MO GUAR
1,996 28 07LNX00108-ANN COST MTHLY
13 17 765 0.3911 5,084 29 07OALT007N-SECURITY AR LG
1 235 30 07OALT07AN-SECURITY AR LG
-1 31 07OALT07AN-BPA-SECURITY AR
1,396,100 1 1,396,100,000 0.0524 73,155,283 32 07SPCL0001
106,739 1 106,739,000 0.0519 5,536,230 33 07SPCL0002
145,404 34 SMUD REVENUE IMPUTATIONS
-4,501 35 BPA BALANCING ACCOUNT
-7,106 -0.0674 479,000 36 UNBILLED REVENUE
330,511 37 DSM - INDUSTRIAL
38
39 OREGON
20,987 0.0582 1,221,397 40 01COST0023-GEN SRV CST BSD
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.11
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
1,688,428 0.0520 87,874,870 1 01COST0048 - 01LGSV0048
1 0.0640 64 2 01COST023F-GEN SRV CST BSD
343 0.0606 20,791 3 01COSTB023-GEN SRV CST BSD
213,225 0.0537 11,446,447 4 01COSTL030-LG GEN SRV CST
90,352 0.0578 5,224,877 5 01COSTS028-GEN SRV COST >30
-1,333 6 01GNSB0023-BPA DISC <30 kW
59 26,391 7 01GNSB0023-GEN SRV BPA <30
-2,360 8 01GNSB0028-GEN SRV BPA >30
6 21,106 9 01GNSB0028-GEN SRV BPA >30
1,144 1,033,120 10 01GNSV0023-OR GEN SRV <30 kW
461 2,797,617 11 01GNSV0028-OR GEN SRV >30 kW
2 2 1,000 0.3275 655 12 01GNSV023F-GEN SRV - FLAT
22 1 22,000 0.3247 7,144 13 01GNSV023M-GEN SRV MANUAL
4 2,668 14 01GNSV023T-GEN SRV TOU Option
2 1,474,599 15 01GNSV0748-LG GEN SVC DIR
8 0.0595 476 16 01HABT0023-OR HABITAT BLEND
153 5,946,069 17 01LGSV0030-LG GEN SRV >1000
95 16,136,355 18 01LGSV0048-1000kW AND OVR
94,465 4 23,616,250 0.0705 6,658,782 19 01LGSV048M-LRG GEN SRVC 1
44,302 20 01LNX00102-LINE EXT 80% G
6,764 21 01LNX00300-LINE EXT 80% GUAR
17,954 2 8,977,000 0.0851 1,527,781 22 01LPRS047M-PART REQ SRVC
4 16,051 23 01NMT28135-NET MTR GEN >30
1 20,044 24 01NMT30135-NET MTR GEN >200
301 135 2,230 0.1508 45,382 25 01OALT015N-OUTD AR LGT NR
5 5 1,000 0.1428 714 26 01OALTB15N-OR OUTD AR LGT
-17 27 01OALTB15N-BPA-OR OUTD AR
39 0.0621 2,420 28 01PTOU0023-OR GEN SRV TOU
114 0.0559 6,368 29 01RENW0023-OR RENW USAGE
1 0.0670 67 30 01RENWB023-OR RENEWABLE
19 0.0572 1,086 31 01STDAY023-DAY STD OFR SCH
187 0.0563 10,531 32 01STDAY028-DAY STD OFF SCH
1 964 33 01VIR23136-VOL INCTV <=30 kW
1 23,801 34 01VIR30136-VOL INCTV >200 kW
31,569 35 OR GAIN ON SALE OF ASSET
-1,223 36 OR SB 838 RECOVERY
223,928 37 SMUD REVENUE IMPUTATIONS
265 38 BPA BALANCING ACCOUNT
-3,795 0.0464 -176,000 39 UNBILLED REVENUE
819,513 40 DSM - INDUSTRIAL
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.12
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
25 174,495 1 BLUE SKY - INDUSTRIAL
-195,400 2 OTHER REV ADJ - DEFERRAL
371,387 3 OTHER REV ADJ - REALIZED
-2,485,626 4 REVENUE - ACCOUNTING ADJ
5
6 UTAH
14,723 7 08CFR00051-MTH FAC SRVCHG
2,298 2 1,149,000 0.0940 216,120 8 08EFOP0021-ELEC FURNACE O
1,484 3 494,667 0.1095 162,496 9 08EFOP021M-ELEC FURNACE O
673,345 1,130 595,881 0.0821 55,264,840 10 08GNSV0006-GEN SRVC-DISTR
2,977,464 111 26,824,000 0.0506 150,568,143 11 08GNSV0009-GEN SRVC-HI VO
56,790 3,436 16,528 0.0935 5,311,761 12 08GNSV0023-GEN SRVC-DISTR
60,752 260 233,662 0.1130 6,866,481 13 08GNSV006A-GEN SRVC-ENERG
5,599 6 933,167 0.0761 426,339 14 08GNSV006B-GEN SRVC-DEM&
18,355 6 3,059,167 0.0755 1,386,133 15 08GNSV009A-GEN SRVC HI VO
802,449 10 80,244,900 0.0478 38,348,879 16 08GNSV009M-MANL HIGH VOLT
4 1 4,000 0.6023 2,409 17 08GNSV023F-GEN SRVC FIXED
1,161 26 44,654 0.0855 99,255 18 08GNSV06MN-GNSV DIST VOLT
1,372 1 1,372,000 0.0934 128,160 19 08GNSV09AM-MAN TOD HIVOLT
162,757 20 08LNX00002-MTHLY 80% GUAR
6,031 21 08LNX00004-ANNUAL 80%GUAR
20,100 22 08LNX00014-80% MIN MNTHLY
2,284 23 08LNX00017-ADV/REF&80%ANN
2,552 24 08LNX00311-LINE EXT 80% GUAR
38,641 25 08LNX00300-LINE EXT 80% PLUS
6,356 26 08LNX00310-IRR 80% ANNUAL MIN
1,239 482 2,571 0.2182 270,391 27 08OALT007N-SECURITY AR LG
20 11 1,818 0.1100 2,199 28 08TOSS0015-TRAF & OTHER S
14 7 2,000 0.2391 3,347 29 08MONL0015-MTR OUTDONIGHT
2,041 5 408,200 0.0923 188,344 30 08NMT06135-NET MTR GEN SVC
48 2 24,000 0.0849 4,077 31 08NMT23135-NET MTR GEN <25
8,899 1 8,899,000 0.0973 866,245 32 08PRSV031M-BKUP MNT&SUPPL
565,835 1 565,835,000 0.0463 26,175,000 33 08SPCL0001
1,013,366 1 1,013,366,000 0.0371 37,589,515 34 08SPCL0002
1,139,836 1 1,139,836,000 0.0429 48,922,487 35 08SPCL0003
22,888 0.0421 963,688 36 08SPCL0005
299 2 149,500 0.1184 35,402 37 08GNSV06AM-MNL ENERGY TOD
987,027 108 9,139,139 0.0693 68,354,707 38 08GNSV0008-GEN SVC TOU >1000
61,538 7 8,791,143 0.0697 4,286,737 39 08GNSV008M-GEN SVC TOU
-49,134 0.0196 -962,000 40 UNBILLED REVENUE
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.13
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
7,711,490 1 DSM - INDUSTRIAL
12 89,938 2 BLUE SKY - INDUSTRIAL
69,996 3 REVENUE - ACCOUNTING ADJ
-2,587,942 4 REVENUE ADJ - DEFERRED NPC
-312,268 5 OTHER REV ADJ - DEFERRAL
31,271 6 OTHER REV ADJ - REALIZED
7
8 WASHINGTON
2,169 96 22,594 0.0948 205,697 9 02GNSB0024-WA GEN SRVC DO
-8,891 10 02GNSB0024-BPA-WA GEN SRVC
4 1 4,000 0.5820 2,328 11 02GNSB24FP-WA GEN SVC
-15 12 02GNSB24FP-BPA-WA GEN SVC
15,959 353 45,210 0.0867 1,383,737 13 02GNSV0024-WA GEN SRVC
33 4 8,250 0.2362 7,794 14 02GNSV024F-WA GEN SRVC-FL
107,706 114 944,789 0.0752 8,094,316 15 02LGSV0036-WA LRG GEN SRV
679,303 32 21,228,219 0.0580 39,389,889 16 02LGSV048T-LRG GEN SRVC 1
122 42 2,905 0.1294 15,783 17 02OALT015N-WA OUTD AR LGT
29 16 1,813 0.1508 4,372 18 02OALTB15N-WA OUTD AR LGT
-121 19 02OALTB15N-BPA-WA OUTD AR
1,923 1 1,923,000 0.1574 302,650 20 02PRSV47TM-LRG PART REQMT
3,001 24 125,042 0.1233 370,150 21 02LGSB0036-LRG GEN SVC IRG
-12,305 22 02LGSB0036-BPA-LRG GENSVC
-510,000 23 WASHINGTON - CHEHALIS
81,494 24 SMUD REVENUE IMPUTATIONS
2,215 25 BPA BALANCING ACCOUNT
21,110 0.0587 1,239,000 26 UNBILLED REVENUE
1,611,692 27 DSM - INDUSTRIAL
-840,365 28 REVENUE ADJ - DEFERRED NPC
-1,611,692 29 REVENUE - ACCOUNTING ADJ
30
31 WYOMING
22,515 1,124 20,031 0.0826 1,859,239 32 05GNSV0025-WY GEN SRVC
4,893 292 16,757 0.0851 416,284 33 05GNSV0025-WY GEN SRVC
271,460 476 570,294 0.0684 18,557,362 34 05GNSV0028-GEN SVC >15 kW
42,836 71 603,324 0.0727 3,113,193 35 05GNSV0028-GEN SVC >15 kW
26 8 3,250 0.1564 4,066 36 05GNSV025F-GEN SRVC-FL RA
1,667,804 56 29,782,214 0.0597 99,503,539 37 05LGSV0046-WY LRG GEN SRV
32,498 3 10,832,667 0.0649 2,109,768 38 05LGSV0046-WY LRG GEN SRV
118,456 2 59,228,000 0.0575 6,810,735 39 05LGSV046M-WY LRG GEN SRV
393,753 1 393,753,000 0.0506 19,908,156 40 05LGSV048M-TOU>1000KW MAN
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.14
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
1,366,401 10 136,640,100 0.0530 72,468,118 1 05LGSV048T-LRG GENSRV TIM
42,682 2 05LNX00100-LINE EXT 60% G
213,474 3 05LNX00102-LINE EXT 80% G
34,892 4 05LNX00105-CNTRCT $ MIN G
218,126 5 05LNX00109-REF/NREF ADV +
1,963,720 6 05LNX00109-REF/NREF ADV +
85 43 1,977 0.1458 12,394 7 05OALT015N-OUTD AR LGT SR
1,236,679 6 206,113,167 0.0608 75,251,585 8 05PRSV033M-PART SERV REQ
11,677 9 05LNX00300-LINE EXT 80% GUAR
28,164 10 05LNX00311-LINE EXT 80% GUAR
5,954 4 1,488,500 0.0689 410,338 11 05GNSV028M-GEN SVC >15 kW
261,938 3 87,312,667 0.0538 14,087,059 12 05LGSV048M-TOU>1000KW MAN
1,276,261 12 106,355,083 0.0556 71,006,734 13 05LGSV048T-LRG GENSRV TIM
-5 0.0776 -388 14 09GNSV0025-GEN SVC-SINGLE
118,949 3 39,649,667 0.0585 6,953,188 15 05PRSV033M-PART SERV REQ
5 3 1,667 0.2156 1,078 16 09OALT207N-SECURITY AR LG
2 17 09RFNDCENT-CENTRALIA RFND
500,726 18 SMUD REVENUE IMPUTATIONS
21,670 0.0752 1,630,000 19 UNBILLED REVENUE
-23,911 -0.0018 42,000 20 UNBILLED REVENUE
155,554 21 DSM - SMALL INDUSTRIAL
31,622 22 DSM - SMALL INDUSTRIAL
516,277 23 DSM - LARGE INDUSTRIAL
275,869 24 DSM - LARGE INDUSTRIAL
1 6,312 25 BLUE SKY - INDUSTRIAL
-11,214,783 26 REVENUE ADJ - DEFERRED NPC
27
-1,007 28 LESS MULTIPLE BILLINGS
29
19,832,688 10,411 1,904,974 0.0566 1,122,586,536 30 TOTAL INDUSTRIAL SALES
31
32 IRRIGATION SALES
33 CALIFORNIA
69,691 1,369 50,907 0.1195 8,328,576 34 06APSV0020-AG PMP SRVC
1,750 1 1,750,000 0.1005 175,950 35 06LGSV048T-LRG GEN SERV
175 1 175,000 0.1170 20,471 36 06NMT20135-AGRICULTURAL
2,746 37 06LNX00103-LINE EXT 80% G
39,298 38 06LNX00110-REF/NREF ADV +
1,858 39 06LNX00310-IRG 80% ANNUAL MIN
1,780 40 06LNX00312-CA IRG LINE EXT
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.15
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
26,196 656 39,933 0.1341 3,513,432 1 06USBR0020-KLAM IRG ONPRJ
333 2 06LNX00109-REF/NREF ADV +
-3,800 3 IRRIGATION DEMAND CHARGE
-36 0.0833 -3,000 4 UNBILLED REVENUE
152,794 5 DSM - IRRIGATION
16 6 BLUE SKY - IRRIGATION
-46 7 REVENUE - ACCOUNTING ADJ
-138,403 8 OTHER REV ADJ - DEFERRAL
102,769 9 OTHER REV ADJ - REALIZED
10
11 IDAHO
-840,436 12 07APSA010L-IRG & Pump BPA
456,227 3,035 150,322 0.0842 38,421,587 13 07APSA010L-IRG & Pump Large
-9,130 14 07APSA010S-IRG & Pump BPA
4,959 404 12,275 0.1031 511,518 15 07APSA010S-IRG & Pump Small
233,875 1,056 221,473 0.0823 19,248,856 16 07APSAL10X-IRG & PUMP-Large l
3,298 249 13,245 0.1059 349,149 17 07APSAS10X-IRG & PUMP-Small l
-31,882 18 07APSVCNLL-BPA-LRG LOAD
18,015 70 257,357 0.0762 1,371,881 19 07APSVCNLL-LRG LOAD CANAL
-76 20 07APSVCNLS-BPA-SML LOAD
41 17 2,412 0.1319 5,409 21 07APSVCNLS-SML LOAD CANAL
303,953 22 07BPADEBIT-BPA ADJUST FEE
194 23 07LNX00015-ANNUAL 80%GUAR
174,581 24 07LNX00040-ADV+REFCHG+80%
296 25 07LNX00311-LINE EXT 80% GUAR
16,923 26 07LNX00312-ID LINE EXT
2,645 35 75,571 0.0929 245,796 27 07APSN010L-ID LG IRR & PUMP
-4,868 28 07APSN010L-BPA-ID LG IRR 3 PH
24 7 3,429 0.1508 3,620 29 07APSN010S-IRR SM 3 PH
-45 30 07APSN010S-BPA-IRR SM 3 PH
227 10 22,700 0.0996 22,598 31 07APSNS10X-IRR SM 3 PHASE
-18 32 07ZZMERGCR-MERGER CREDITS
-513,394 33 BPA BALANCING ACCOUNT
8 34 UNBILLED REVENUE
1,809,432 35 DSM - IRRIGATION
1 23 36 BLUE SKY - IRRIGATION
37
38 OREGON
4,767 2,169,473 39 01APSV0041-AG PMP SRVC
-174,499 40 01APSV0041-BPA-AG PMP SRVC
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.16
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
1,055 3,164,186 1 01APSV041L-Pumping Serv >30 kW
-292,068 2 01APSV041L-BPA-Pumping Serv
-2,328 3 01APSV041T-BPA-AGR PUMP SRV
59 31,097 4 01APSV041T-AGR PUMP SRV-TOU
176 58,021 5 01APSV041X-AG PMP SRVC
31 140,571 6 01APSV41XL-Pumping Serv no BPA
32,296 7 01BPADEBIT-BPA ADJUST FEE
125,514 0.0556 6,976,694 8 01COST0041
8,500 0.0524 445,331 9 01COST0048 - 01LGSV0048
330 0.0585 19,302 10 01COSTS028-GEN SRV CST >30
3 12,191 11 01GNSV0028-GEN SRV >30 kW
5 0.0572 286 12 01HABIT041-01APSV0041 AG PMP
-32,895 13 01LGSB0048-LG GEN SVC >1000
1 90,261 14 01LGSB0048-LG GEN SVC >1000
38,987 15 01LNX00103-LINE EXT 80% G
-23,235 16 01LNX00109-REF/NREF ADV +
135,783 17 01LNX00110-REF/NREF ADV +
10,354 18 01LNX00310-LINE EXTENSION
635 0.0536 34,025 19 01PTOU0041 - 01APSV0041 AG
131 0.0559 7,324 20 01RENEW041 - 01APSV0041 AG
362,930 21 01SLX00005-KLAMATH FALLS
9,049 22 01SLX00013-K FALLS IRG MI
113 23 01SLX00014-K FALLS IRG MI
131 0.0526 6,893 24 01STDAY041-Daily Standard Offer
-41 25 01USBGV033-KLAMATH IRG TOU
44,259 597 74,136 0.0684 3,029,511 26 01USBOF033-KLAMATH BASIN
-161,570 27 01USBOF033-BPA-KLAMATH
51,380 1,325 38,777 0.0662 3,400,208 28 01USBON033-KLAMATH BASIN
-185,451 29 01USBON033-BPA-KLAMATH
2,491 33 75,485 0.0660 164,389 30 01VIR33136-VOL INCTV USB
-9,068 31 01VIR33136-BPA-VOL INCTV USB
5 14,332 32 01VIR41136-VOL INCTV-AGRI
-1,300 33 01VIR41136-BPA-VOL INCTV-AG
2,111 9 234,556 0.0491 103,608 34 01USBGV033-IRG TOU W/O BPA
14,524 35 01LNX00312-OR IRG LINE EXT
49 2 24,500 0.0661 3,237 36 01NMT33135-NET MTR - PROJECT
-178 37 01NMT33135-BPA-NET MTR
4 2,577 38 01NMT41135-NETMTR AG PMP
-165 39 01NMT41135-BPA-NETMTR AG
3,206 40 OR GAIN ON SALE OF ASSET
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.17
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
-55 1 OR SB 838 RECOVERY
109,382 2 BPA BALANCING ACCOUNT
17,594 3 OR IRRIGATION - BPA ADJ
-200 4 IRRIGATION DEMAND CHARGE
-63 -0.2540 16,000 5 UNBILLED REVENUE
462,527 6 DSM - IRRIGATION
4 257 7 BLUE SKY - IRRIGATION
-243,017 8 REVENUE - ACCOUNTING ADJ
-6,951 9 OTHER REV - DEFERRAL
13,212 10 OTHER REV ADJ - REALIZED
11
12 UTAH
210,866 2,746 76,790 0.0676 14,246,232 13 08APSV0010-IRR & SOIL DRA
33,078 169 195,728 0.0626 2,070,249 14 08APSV10NS-Irg Soil Drain Pump N
330 15 08LNX00002-MTHLY 80% GUAR
7,178 16 08LNX00004-ANNUAL 80%GUAR
16,620 17 08LNX00014-80% MIN MNTHLY
166,897 18 08LNX00017-ADV/REF&80%ANN
12,525 19 08LNX00310-IRR 80% ANNUAL MIN
9,004 20 08LNX00312-UT IRG LINE EXT
30 1 30,000 0.0731 2,193 21 08NMT10135-UT IRR SOIL DRNG
-8 22 UNBILLED REVENUE
469,480 23 DSM - IRRIGATION
31 24 BLUE SKY - IRRIGATION
2,106 25 REVENUE - ACCOUNTING ADJ
-7,297 26 OTHER REV ADJ - DEFERRAL
672 27 OTHER REV ADJ - REALIZED
28
29 WASHINGTON
151,697 5,077 29,879 0.0821 12,461,740 30 02APSV0040-WA AG PMP SRVC
-621,963 31 02APSV0040-BPA-WA AG PMP
5,128 180 28,489 0.0815 417,905 32 02APSV040X-WA AG PMP SRVC
25,280 33 02BPADEBIT-BPA ADJUST FEE
4,075 34 02LNX00103-LINE EXT 80% G
81 35 02LNX00105-CNTRCT $ MIN G
3,539 36 02LNX00109-REF/NREF ADV +
146,400 37 02LNX00110-REF/NREF ADV +
1,704 38 02LNX00310-IRG 80% ANNUAL MIN
1,022 39 02LNX00311-LINE EXT 80% GUAR
23,753 40 02LNX00312-WA IRG LINE EXT
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.18
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
-120,000 1 WASHINGTON - CHEHALIS
-500 2 IRRIGATION DEMAND CHARGE
67,966 3 BPA BALANCING ACCOUNT
-144 -0.1250 18,000 4 UNBILLED REVENUE
455,453 5 DSM - IRRIGATION
-455,453 6 REVENUE - ACCOUNTING ADJ
2 46 7 BLUE SKY - IRRIGATION
8
9 WYOMING
26,014 650 40,022 0.0736 1,913,730 10 05APS00040-AG PUMPING SVC
41 1 41,000 0.0748 3,066 11 05APS00040-AG PUMPING SVC
46,719 12 05LNX00110-REF/NREF ADV +
18,809 13 05LNX00110-REF/NREF ADV +
6,769 14 05LNX00103-LINE EXT 80% G
1,664 15 05LNX00103-LINE EXT 80% G
442 16 05LNX00310-LINE EXTENSION
3,341 17 05LNX00312-WY IRG LINE EXT
-279 18 05LNX00312-WY IRG LINE EXT
4,796 78 61,487 0.0715 342,744 19 09APSV0210-IRR & SOIL DRA
6 0.3333 2,000 20 UNBILLED REVENUE
16,969 21 DSM - IRRIGATION
3,148 22 DSM - IRRIGATION
11 23 BLUE SKY - IRRIGATION
24
-744 25 LESS MULTIPLE BILLINGS
26
1,484,072 23,142 64,129 0.0842 125,031,852 27 TOTAL IRRIGATION SALES
28
29 PUBLIC STREET & HWY LIGHTING
30 CALIFORNIA
1,432 110 13,018 0.1464 209,706 31 06CUSL053F-SPECIAL CUST O
239 23 10,391 0.1635 39,077 32 06CUSL058F-CUST OWND STR
683 80 8,538 0.2669 182,306 33 06HPSV0051-HI PRESSURE SO
-49 0.1837 -9,000 34 UNBILLED REVENUE
9,501 35 DSM REVENUE - PSHL
-5,324 36 OTHER REV ADJ - DEFERRAL
4,528 37 OTHER REV ADJ - REALIZED
-2 38 REVENUE - ACCOUNTING ADJ
39
40 IDAHO
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.19
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
154 24 6,417 0.1131 17,424 1 07GNSV023S-IDAHO TRAFFIC
70 30 2,333 0.4477 31,339 2 07SLCO0011-STR LGT CO-OWN
328 21 15,619 0.1114 36,532 3 07SLCU012E-ENGY STR LGT
1,886 238 7,924 0.1965 370,529 4 07SLCU012F-FULL MNT STR
194 16 12,125 0.1442 27,984 5 07SLCU012P-PART MNT STR LGT
17 0.1176 2,000 6 UNBILLED REVENUE
12,580 7 DSM REVENUE - PSHL
8
9 OREGON
557 46 12,109 0.1601 89,180 10 01COSL0052-STR LGT SRVC C
814 73 11,151 0.0780 63,471 11 01CUSL0053-CUS-OWNED MTRD
8,577 161 53,273 0.0780 668,994 12 01CUSL053E-STR LGT SVC
184 15 12,267 0.1179 21,688 13 01CUSL053F-STR LGT SRVC C
18,968 702 27,020 0.2182 4,138,439 14 01HPSV0051-HI PRESSURE SO
18 11 1,636 0.2693 4,848 15 01LEDSL055-LED PILOT ST LIGHT
8,773 251 34,952 0.1390 1,219,545 16 01MVSL0050-MERC VAPSTR LG
18 6 3,000 0.1528 2,751 17 01OALT015N-OUTD AR LGT NR
2 2 1,000 0.2070 414 18 01OALTB15N-OR OUTD AR LGT
-8 19 01OALTB15N-BPA-OR OUTD AR
1,480 20 OR GAIN ON SALE OF ASSET
-11 21 OR SB 838 RECOVERY
625 0.1792 112,000 22 UNBILLED REVENUE
154,319 23 DSM REVENUE - PSHL
-20,623 24 REVENUE - ACCOUNTING ADJ
-1,695 25 OTHER REV ADJ - DEFERRAL
-760,278 26 OTHER REV ADJ - REALIZED
27
28 UTAH
54 29 08CFR00012-STR LGTS (CONV
4,529 30 08CFR00051-MTH FAC SRVCHG
79 31 08CFR00062-STREET LIGHTS
25 13 1,923 0.2403 6,007 32 08OALT007N-SECURITY AR LG
1,159 123 9,423 0.0847 98,192 33 08TOSS015F-TRAFFIC SIG NM
17,058 844 20,211 0.2999 5,116,046 34 08SLCO0011-STR LGT CO-OWN
2,792 1,504 1,856 0.1099 306,979 35 08TOSS0015-TRAF & OTHER S
686 56 12,250 0.0835 57,280 36 08MONL0015-MTR OUTDONIGHT
5,328 231 23,065 0.1258 670,359 37 08SLCU012P-STR LGT CUST-O
1,792 103 17,398 0.1389 248,853 38 08SLCU012F-STR LGT CUST-O
50,157 503 99,716 0.0666 3,340,033 39 08SLCU012E-DECOR CUST-OWN
30 1 30,000 0.1216 3,647 40 08THIK0077-STR LIGHT SPEC
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.20
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
-1,951 0.1307 -255,000 1 UNBILLED REVENUE
280,745 2 DSM REVENUE - PSHL
1,630 3 REVENUE - ACCOUNTING ADJ
-7,815 4 OTHER REV ADJ - DEFERRAL
829 5 OTHER REV ADJ - REALIZED
6
7 WASHINGTON
91 8 02CFR00012-STR LGTS (CONV
264 16 16,500 0.1685 44,471 9 02COSL0052-WA STR LGT SRV
3,490 117 29,829 0.0719 250,920 10 02CUSL053F-WA STR LGT SRV
1,184 104 11,385 0.0710 84,114 11 02CUSL053M-WA STR LGT SRV
3,381 157 21,535 0.1989 672,635 12 02HPSV0051-WA HI PRESSURE
1,952 42 46,476 0.1246 243,299 13 02MVSL0057-WA MERC VAPSTR
-30,000 14 WASHINGTON - CHEHALIS
-163 0.0123 -2,000 15 UNBILLED REVENUE
26,614 16 DSM REVENUE - PSHL
-26,614 17 REVENUE - ACCOUNTING ADJ
18
19 WYOMING
268 18 14,889 0.2214 59,345 20 05COSL0057-CO-OWND STR LG
78 11 7,091 0.0681 5,313 21 05CUSL058M-CUST OWND STR
1,057 30 35,233 0.0679 71,740 22 05CUSL0E58-CUST OWND ST LT
45 4 11,250 0.0814 3,664 23 05CUSL0M58-CUST OWND ST LT
5,041 164 30,738 0.2241 1,129,655 24 05HPSV0051-HI PRESSURE SO
3,798 260 14,608 0.1367 519,270 25 05MVS00053-MERCURY VAPOR
1 1 1,000 0.1110 111 26 05OALT015N-OUTD AR LGT SR
27 1 27,000 0.0774 2,091 27 09MONL0213-WY MTR OUTDOOR
1,420 48 29,583 0.2824 401,009 28 09SLCO0211-STR LGT CO-OWN
77 9 8,556 0.1456 11,213 29 09SLCUP212-CUST OWND ST LT
68 14 4,857 0.0391 2,660 30 09TOSS0213-TRAFFIC & OTHER
146 0.1644 24,000 31 UNBILLED REVENUE
-25 0.3600 -9,000 32 UNBILLED REVENUE
14,314 33 DSM REVENUE - PSHL
3,398 34 DSM REVENUE - PSHL
35
-2,547 36 LESS MULTIPLE BILLINGS
37
142,675 3,636 39,240 0.1402 19,998,454 38 TOTAL PUBLIC STREET & HWY
39
40 OTHER SALES TO PUBLIC AUTH
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.21
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
1 UTAH
255,203 2 127,601,500 0.0522 13,315,246 2 08GNSV009M-MANL HIGH VOLT
48,750 1 48,750,000 0.0614 2,993,179 3 08PRSV031M-BKUP MNT&SUPPL
-11,244 0.0408 -459,000 4 UNBILLED REVENUE
420,300 5 DSM REVENUE - OPSA
2,942 6 REVENUE - ACCOUNTING ADJ
-9,812 7 OTHER REV ADJ - DEFERRAL
475 8 OTHER REV ADJ - REALIZED
9
292,709 3 97,569,667 0.0556 16,263,330 10 TOTAL OTHER SALES TO PUBLIC
11
12 FORFEITED DISCOUNTS
13 CALIFORNIA
336,161 14 06LPAY0300-LATEFEE
15
16 IDAHO
485,995 17 07LPAY0300-LATEFEE
18
19 OREGON
3,818,384 20 01LPAY0300-LATEFEE
21
22 UTAH
3,437,324 23 08LPAY0300-LATEFEE
24
25 WASHINGTON
677,733 26 02LPAY0300-LATEFEE
27
28 WYOMING
419,804 29 05LPAY0300-RES-LATEFEE
145,270 30 05LPAY0300-COM-LATEFEE
116,508 31 05LPAY0300-IND-LATEFEE
8,565 32 05LPAY0300-Other-LATEFEE
33
9,445,744 34 TOTAL FORFEITED DISCOUNTS
35
36 MISCELLANEOUS SERVICE REV
37 CALIFORNIA
1,454 38 06CFR00003-MTH MAINTENANC
33,315 39 06CONN0300-CA RECONNECTIO
101,378 40 06FCBUYOUT
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.22
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
12,528 1 06RCHK0300-CA RET CHK CHR
1,650 2 06TAMP0300-CA TAMP & UNAU
1,815 3 06TEMP0300-CA TEMP SRVC C
30 4 06TRBL0300-CA TROUBLE CAL
494 5 06XMTRTAMP-TAMPERING -
558 6 HOME COMFORT
7
8 IDAHO
1,682 9 07CFR00001-MTH FAC SRVCHG
55,320 10 07CONN0300-ID RECONNECTIO
3,187 11 07FCBUYOUT-FAC CHG BUYOUT
32,800 12 07RCHK0300-ID RET CHK CHR
825 13 07TAMP0300
12,580 14 07TEMP0014-TEMP SRVC CONN
83 15 07XMTRTAMP-TAMPERING -
83 16 OTHER
17
18 OREGON
137,453 19 01CFR00001-MTH FACILITY S
25,964 20 01CFR00003-MTH MAINTENANC
26,390 21 01CFR00004-EMRGNCY ST&BY
40,109 22 01CFR00005-INTERMTNT SRVC
2,284 23 01CFR00013-MTH MISC CHRG
5 24 01CFR00014-YR MISC CHRG
388,565 25 01CONN0300-RECONNECTION C
20,054 26 01CONTSERV-3RD PRTY OUTSIDE
7,782 27 01ESSC0600-ESS charges
501,161 28 01FCBUYOUT-FAC CHG BUYOUT
10,500 29 01DPAC0300-DEMAND PULSE
292,620 30 01RCHK0300-RETURNED CHECK
16,875 31 01TAMP0300-TAMP & UNAUTH
97,840 32 01TEMP0300-TEMP SRVC CHRG
3,547 33 01XMTRTAMP-TAMPERING -
-22,912 34 OTHER
35
36 UTAH
147,885 37 08CFR00013-MTH MISC CHRG
90,237 38 08CFR00051-MTH FAC SRVCHG
424 39 08CFR00052-ANN FAC SVCCHG
10,984 40 08CFR00053-MTHLY MAINTFEE
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.23
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
2,386 1 08CFR00063-MTH MISC CHARG
6,660 2 08CFR00064-ANN MISC CHARG
466,810 3 08CONN0300-RECONN&DISCONN
274,310 4 08CONTSERV-3RD PARTY O/S
277,713 5 08FCBUYOUT-FAC CHG BUYOUT
-22,500 6 08MONL0015-MTR OUTDONIGHT
40 7 08INFO0300-CUST/3RD P REQ
4,390 8 08NCON0300-UT FEE NRES RE
479,200 9 08RCHK0300-UT RET CHK CHR
1,562,681 10 08RCON0001-CONNECT FEE
11,550 11 08TAMP0300-TAMPERING&UNAU
421,385 12 08TEMP0014-TEMP SRVC CONN
1,051 13 08XMTRTAMP-TAMPERING -
195,820 14 08VISIT300-UT Visit Service Call
488 15 MISC SERV - ACCT SERV CHRG
13,728 16 ENERGY FINANSWER NEW COM
-68,885 17 OTHER
18
19 WASHINGTON
1,320 20 02CFR00003-MTH MAINTENANC
5,815 21 02CFR00004-EMRGNCY ST&BY
4,291 22 02CFR00005-INTERMTNT SRVC
83,990 23 02CONN0300-WA RECONNECTIO
2,205 24 02DPAC0300-DEMAND PULSE
9,737 25 02FCBUYOUT - FAC CHG BUYOUT
56,340 26 02RCHK0300-WA RET CHK CHR
3,075 27 02TAMP0300-WA TAMP & UNAU
15,645 28 02TEMP0300-WA TEMP SRVC C
912 29 02XMTRTAMP-TAMPERING -
1,969 30 HOME COMFORT
167 31 ENERGY FINANSWER NEW COM
-24,147 32 OTHER
33
34 WYOMING
1,768 35 05CFR00003-MTH MAINTENANC
18,610 36 05CFR00004-EMRGNCY ST&BY
10,049 37 05CFR00005-INTERMTNT SRVC
3,186 38 05CFR00013-MTH MISC CHRG
83,830 39 05CONN0300-WY RECONNECTIO
240,716 40 05FCBUYOUT-FAC CHG BUYOUT
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.24
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
67,680 1 05RCHK0300-WY RET CHK CHR
600 2 05TAMP0300
35,960 3 05TEMP0300-WY TEMP SRVC C
188 4 05XMTRTAMP-TAMPERING -
339 5 09CFR00005-INTERMTNT SRVC
16,720 6 05CONN0300-WY RECONNECTIO
80,753 7 05FCBUYOUT-FAC CHG BUYOUT
8,760 8 05RCHK0300-WY RET CHK CHR
150 9 05TAMP0300
425 10 05TEMP0300-WY TEMP SRVC C
5,067 11 09CFR00001-MTH FAC SRVCHG
3 12 09CFR00014-YR MISC CHRG
129 13 ENERGY FINANSWER 12,000
-7,485 14 OTHER
15
6,413,143 16 TOTAL MISC SERVICE REV
17
18 SALES OF WATER AND WTR PWR
455 19 UTAH
405 20 WYOMING
21
860 22 TOTAL WATER AND WATER PWR
23
24 RENT FROM ELEC PROPERTIES
115 25 INTERCOMPANY RENT REVENUE
26
27 CALIFORNIA
1,709 28 06CFR00006-MTH RNTAL CHRG
1,245 29 RENT REVENUE - HYDRO
17,411 30 RENT REVENUE - SUBLEASES
501,882 31 JOINT USE
32
33 IDAHO
739 34 07CFR00009-YR LSE CHRG-EQ
180 35 07INVCHG00-INVEST MNT CHG
275 36 07POLE0075-STEEL POLES US
400 37 RENT REV - TRANSMISSION
300 38 RENT REV - DISTRIBUTION
74,792 39 RENT REVENUE - HYDRO
2,216 40 RENT REVENUE - SUBLEASES
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.25
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
161,725 1 JOINT USE
2
3 OREGON
665,408 4 01CFR00006-MTH RNTAL CHRG
497,198 5 RENTS - COMMON
3,349,883 6 MCI FOGWIRE REVENUE
259,766 7 RENT REVENUE - SUBLEASES
250,469 8 RENT REV - TRANSMISSION
57,814 9 RENT REV - DISTRIBUTION
22,455 10 RENT REVENUE - HYDRO
52,775 11 RENT REV - GEN(COMM)
3,519,023 12 JOINT USE
13
14 UTAH
33 15 08CFR00056-MTH EQUIP RENT
679,523 16 08CFR00058-MTH EQUIP LEAS
4,415 17 08INVCHG0N-INVEST MNT CHG
244 18 08INVCHG0R-INVEST MNT CHG
56,963 19 08POLE0075-STEEL POLES US
1,736 20 RENTS - COMMON
4,200 21 RENTS - NON COMMON
111,624 22 RENT REVENUE - STEAM
1,067,789 23 RENT REV - TRANSMISSION
480,594 24 RENT REV - DISTRIBUTION
77,589 25 RENT REVENUE - HYDRO
6,505 26 RENT REV - GEN(COMM)
2,619,506 27 RENT REVENUE - SUBLEASES
2,206,197 28 JOINT USE
29
30 WASHINGTON
2,103 31 02CFR00001-MTH FACILITY S
24,836 32 02CFR00006-MTH RNTAL CHRG
16,765 33 RENT REV - TRANSMISSION
18,844 34 RENT REV - DISTRIBUTION
548,491 35 RENT REVENUE - HYDRO
35,997 36 RENT REV - GEN(COMM)
49,280 37 RENT REVENUE - SUBLEASES
949,023 38 JOINT USE
39
40 WYOMING
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.26
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
11,524 1 05CFR00001-MTH FACILITY S
2,481 2 05CFR00006-MTH RNTAL CHRG
18,314 3 09POLE0075-STEEL POLES US
4,925 4 RENT REVENUE - STEAM
58,852 5 RENT REVENUE - STEAM
250 6 RENT REV - TRANSMISSION
150 7 RENT REV - DISTRIBUTION
20,430 8 RENT REV - GEN(COMM)
18,199 9 RENT REVENUE - SUBLEASES
340,703 10 JOINT USE
62 11 JOINT USE
12
18,875,927 13 TOTAL RENT FROM ELEC PROP
14
15 OTHER ELECTRIC REVENUE
12,186,449 16 WIND BASED ANCILLARY SVC
75,018,594 17 RENEWABLE ENERGY CREDIT
31,951,550 18 RENEWABLE ENERGY CR AMORT
8,308,350 19 NON-WHEELING SYSTEM
-293,811 20 OTHER ELECTRIC ESTIMATE
-27,103 21 OTHER ELECTRIC (EXCL
22
23 CALIFORNIA
32,890 24 3RD PARTY TRANS O&M
8,704 25 FISH, WILDLIFE, RECR
26
27 IDAHO
133,191 28 3RD PARTY TRANS O&M
29
30 OREGON
335,406 31 3RD PARTY TRANS O&M
111,851 32 OTHER ELECTRIC DSR CARRY
1,106,982 33 OTHER ELECTRIC (EXCL WHL
34
35 UTAH
221,497 36 3RD PARTY TRANS O&M
2,465 37 FISH, WILDLIFE, RECR
2,125,776 38 FLYASH SALES
30,069 39 M&S INVENTORY REVENUE
87,375 40 ELECTRIC INCOME - OTHER
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.27
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2012/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
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.
1
2 WASHINGTON
-3,370 3 3RD PARTY TRANS O&M
5,190 4 FISH, WILDLIFE, RECR
-52,188 5 WA - COLSTRIP 3
6
7 WYOMING
64,262 8 3RD PARTY TRANS O&M
1,060,156 9 FLYASH SALES
48,382 10 FLYASH SALES
262,676 11 WY-REGULATORY RECOVERY
13 12 ELECTRIC INCOME - OTHER
13
132,725,356 14 TOTAL OTHER ELEC REVENUE
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
54,549,341 4,438,926,115 1,753,692 31,105 0.0814
34,335 13,732,500 0 0 0.4000
54,515,006 4,425,193,615 1,753,692 31,086 0.0812
FERC FORM NO. 1 (ED. 12-95) Page 304.28
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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.
Requirement Sales 1
Brigham City Corporation 192020T-12RQ 2
Deaver, Town of 0.10.10.2T-4RQ 3
Helper City 111T-6RQ 4
Helper City Annex 0.60.70.7T-6RQ 5
Navajo Tribal Util Auth (Mexican Hat)0.10.20.2T-6RQ 6
Navajo Tribal Util Auth (Red Mesa)111T-6RQ 7
Portland General Electric Company NANANA147RQ 8
Price City Corporation 121225T-12RQ 9
Accrual NANANANARQ 10
11
Nonrequirement Sales 12
Arizona Public Service Company NANANAT-12SF 13
Avista Corporation NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
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.
1
3,168,536 2,515,797 5,684,333 121,534 2
13,398 11,041 24,439 748 3
114,825 119,751 234,576 6,492 4
65,987 72,298 138,285 3,731 5
16,872 19,378 36,250 968 6
159,808 138,461 298,269 9,174 7
1,045,532 1,045,532 11,110 8
1,896,583 1,565,215 3,461,798 73,002 9
-158,949 -158,949 -2,772 10
11
12
756,389 756,389 29,298 13
930,998 930,998 57,191 14
FERC FORM NO. 1 (ED. 12-90) Page 311
6,481,541
482,835,347
489,316,888
223,987
11,645,802
11,869,789
-158,949 10,764,533
-174,721,835
-174,880,784
319,805,091
330,569,624
4,441,941
11,691,579
16,133,520
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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.
Avista Corporation NANANAT-13SF 1
BNP Paribas Energy Trading GP NANANAT-12SF 2
BP Energy Company NANANAT-12SF 3
Barclays Bank PLC NANANAT-12SF 4
Basin Electric Power Cooperative NANANAT-11SF 5
Basin Electric Power Cooperative NANANAT-12SF 6
Black Hills Power, Inc.485450441LF 7
Black Hills Power, Inc.NANANAT-12SF 8
Bonneville Power Administration NANANA368LF 9
Bonneville Power Administration NANANAT-11LF 10
Bonneville Power Administration NANANA519LU 11
Bonneville Power Administration NANANAT-11SF 12
Bonneville Power Administration NANANAT-12SF 13
Bonneville Power Administration NANANAT-13SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.1
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
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.
1,605 1,605 73 1
2,602,600 2,602,600 61,600 2
1,747,996 1,747,996 123,131 3
21,729,489 21,729,489 428,445 4
53 53 3 5
523,676 523,676 17,618 6
5,207,984 7,295,379 12,503,363 295,480 7
5,717,672 5,717,672 275,431 8
53,973 53,973 2,342 9
327,905 327,905 13,985 10
2,399,681 2,399,681 32,332 11
6,377 6,377 120 12
3,558,253 3,558,253 174,382 13
990 990 40 14
FERC FORM NO. 1 (ED. 12-90) Page 311.1
6,481,541
482,835,347
489,316,888
223,987
11,645,802
11,869,789
-158,949 10,764,533
-174,721,835
-174,880,784
319,805,091
330,569,624
4,441,941
11,691,579
16,133,520
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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.
British Columbia Hydro & Power NANANAT-13SF 1
British Columbia Transmission Corp.NANANAT-13SF 2
Brookfield Energy Marketing L.P.NANANAT-12SF 3
California Independent System Operator NANANAT-12AD 4
California Independent System Operator NANANAT-12SF 5
Calpine Energy Services, L.P.NANANAT-12SF 6
Cargill Power Markets, LLC NANANAT-12IF 7
Cargill Power Markets, LLC NANANAT-11SF 8
Cargill Power Markets, LLC NANANAT-12SF 9
Citigroup Energy Inc.NANANAT-12AD 10
Citigroup Energy Inc.NANANAT-12IF 11
Citigroup Energy Inc.NANANAT-12SF 12
City of Anaheim NANANAT-12SF 13
City of Burbank NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.2
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
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.
251 251 19 1
529 529 54 2
16,000 16,000 800 3
-157,319 -157,319 -3,438 4
12,425,345 12,425,345 546,589 5
7,989,434 7,989,434 282,299 6
16,385,278 16,385,278 243,196 7
211,078 211,078 10,648 8
9,385,270 9,385,270 354,712 9
27 27 10
3,252,420 3,252,420 47,550 11
42,388,305 42,388,305 1,504,865 12
391,617 391,617 16,018 13
3,089,871 3,089,871 114,045 14
FERC FORM NO. 1 (ED. 12-90) Page 311.2
6,481,541
482,835,347
489,316,888
223,987
11,645,802
11,869,789
-158,949 10,764,533
-174,721,835
-174,880,784
319,805,091
330,569,624
4,441,941
11,691,579
16,133,520
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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.
City of Glendale NANANAT-12SF 1
City of Hurricane NANANAT-12LF 2
City of Redding NANANAT-12SF 3
City of Santa Clara NANANAT-12SF 4
Clatskanie People's Utility District NANANAT-12SF 5
Colorado River Commission of Nevada NANANAT-12SF 6
Constellation Energy Commodities Group NANANAT-11SF 7
Constellation Energy Commodities Group NANANAT-12SF 8
Cyrg Energy NANANAT-11LF 9
DB Energy Trading LLC NANANAT-12SF 10
EDF Trading North America, LLC NANANAT-11SF 11
EDF Trading North America, LLC NANANAT-12SF 12
El Paso Electric Company NANANAT-12SF 13
Eugene Water & Electric Board NANANAT-11SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.3
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
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.
1,241,084 1,241,084 38,258 1
15,760 15,760 220 2
369,768 369,768 18,790 3
1,580,508 1,580,508 57,168 4
5,192 5,192 238 5
4,561,883 4,561,883 173,588 6
104,703 104,703 4,767 7
15,484,564 15,484,564 572,220 8
53,832 53,832 2,338 9
5,063,347 5,063,347 180,688 10
1,737 1,737 115 11
22,877,088 22,877,088 744,551 12
1,449,308 1,449,308 53,556 13
9 9 14
FERC FORM NO. 1 (ED. 12-90) Page 311.3
6,481,541
482,835,347
489,316,888
223,987
11,645,802
11,869,789
-158,949 10,764,533
-174,721,835
-174,880,784
319,805,091
330,569,624
4,441,941
11,691,579
16,133,520
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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.
Eugene Water & Electric Board NANANAT-12SF 1
Exelon Power Team NANANAT-12SF 2
Gila River Power LLC NANANAT-12SF 3
Iberdrola Renewables, LLC NANANAT-11LF 4
Iberdrola Renewables, LLC NANANAT-11SF 5
Iberdrola Renewables, LLC NANANAT-11SF 6
Iberdrola Renewables, LLC NANANAT-12SF 7
Idaho Power Company NANANAT-11LF 8
Idaho Power Company NANANAT-11SF 9
Idaho Power Company NANANAT-12SF 10
Idaho Power Company NANANAT-13SF 11
J. Aron & Company NANANAT-12SF 12
J.P. Morgan Ventures Energy Corporation NANANAT-11SF 13
J.P. Morgan Ventures Energy Corporation NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.4
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
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.
218,824 218,824 10,268 1
21,100 21,100 800 2
1,829,305 1,829,305 71,852 3
92,228 92,228 3,980 4
299,342 299,342 12,903 5
661 661 22 6
17,214,140 17,214,140 558,753 7
34,381 34,381 1,272 8
70,114 70,114 3,036 9
142,900 142,900 5,300 10
6,782 6,782 363 11
2,178,835 2,178,835 69,050 12
86,162 86,162 4,018 13
1,904,802 1,904,802 81,467 14
FERC FORM NO. 1 (ED. 12-90) Page 311.4
6,481,541
482,835,347
489,316,888
223,987
11,645,802
11,869,789
-158,949 10,764,533
-174,721,835
-174,880,784
319,805,091
330,569,624
4,441,941
11,691,579
16,133,520
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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.
Los Angeles Dept. of Water & Power NANANAT-12AD 1
Los Angeles Dept. of Water & Power NANANA301LU 2
Los Angeles Dept. of Water & Power NANANAT-11SF 3
Los Angeles Dept. of Water & Power NANANAT-12SF 4
Macquarie Energy LLC NANANAT-12SF 5
Modesto Irrigation District NANANAT-12SF 6
Morgan Stanley Capital Group, Inc.NANANAT-11SF 7
Morgan Stanley Capital Group, Inc.NANANAT-12SF 8
Municipal Energy Agency of Nebraska NANANAT-12SF 9
NaturEner Power Watch, LLC NANANAT-13SF 10
Nevada Power Company NANANAT-12IF 11
NextEra Energy Power Marketing, LLC NANANAT-11AD 12
NextEra Energy Power Marketing, LLC NANANAT-11LF 13
NextEra Energy Power Marketing, LLC NANANAT-11SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.5
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
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.
-481 -481 -26 1
27,777,196 27,777,196 469,313 2
6,381 6,381 270 3
814,725 814,725 31,903 4
6,091,229 6,091,229 219,183 5
386,288 386,288 14,544 6
248,416 248,416 10,163 7
63,584,013 63,584,013 2,038,512 8
4,121,843 4,121,843 178,610 9
180 180 8 10
27,203,434 27,203,434 1,092,071 11
224 12
223,366 223,366 9,829 13
336 336 15 14
FERC FORM NO. 1 (ED. 12-90) Page 311.5
6,481,541
482,835,347
489,316,888
223,987
11,645,802
11,869,789
-158,949 10,764,533
-174,721,835
-174,880,784
319,805,091
330,569,624
4,441,941
11,691,579
16,133,520
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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.
NextEra Energy Power Marketing, LLC NANANAT-11SF 1
NextEra Energy Power Marketing, LLC NANANAT-12SF 2
Noble Americas Gas & Power Corp.NANANAT-12SF 3
NorthWestern Corporation NANANAT-13SF 4
Northern California Power Agency NANANAT-12SF 5
Northpoint Energy Solutions Inc.NANANAT-12SF 6
PPL EnergyPlus, LLC NANANAT-12SF 7
PPL Montana, LLC NANANAT-11SF 8
Pacific Gas & Electric Company NANANAT-11SF 9
Pacific Gas & Electric Company NANANAT-12SF 10
Portland General Electric Company NANANAT-11SF 11
Portland General Electric Company NANANAT-12SF 12
Portland General Electric Company NANANAT-13SF 13
Powerex Corporation NANANAT-11LF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.6
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
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.
499 499 24 1
13,032 13,032 418 2
367,010 367,010 12,044 3
1,539 1,539 77 4
109,601 109,601 6,982 5
-1,250 -1,250 5,600 6
1,024,865 1,024,865 45,067 7
7,881 7,881 297 8
25 25 2 9
14,335,970 14,335,970 657,600 10
365 365 12 11
2,282,929 2,282,929 127,035 12
3,687 3,687 142 13
502,053 502,053 22,348 14
FERC FORM NO. 1 (ED. 12-90) Page 311.6
6,481,541
482,835,347
489,316,888
223,987
11,645,802
11,869,789
-158,949 10,764,533
-174,721,835
-174,880,784
319,805,091
330,569,624
4,441,941
11,691,579
16,133,520
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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.
Powerex Corporation NANANAT-11SF 1
Powerex Corporation NANANAT-12SF 2
Public Service Company of Colorado NANANA320AD 3
Public Service Company of Colorado NANANAT-12SF 4
Public Service Company of New Mexico NANANAT-12SF 5
PUD #1 of Chelan County NANANAT-13SF 6
PUD #1 of Douglas County NANANAT-12SF 7
PUD #1 of Snohomish County NANANAT-12SF 8
PUD #2 of Grant County NANANAT-12SF 9
PUD #2 of Grant County NANANAT-13SF 10
Puget Sound Energy, Inc.NANANAT-12SF 11
Puget Sound Energy, Inc.NANANAT-13SF 12
Rainbow Energy Marketing Corporation NANANAT-11SF 13
Rainbow Energy Marketing Corporation NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.7
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
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.
1,362,160 1,362,160 61,961 1
5,683,666 15,000 5,698,666 353,378 2
353,200 353,200 3
4,512,251 4,512,251 191,207 4
4,224,013 4,224,013 176,961 5
391 391 9 6
3,600 3,600 175 7
75,050 75,050 3,870 8
245,240 245,240 15,067 9
1,023 1,023 50 10
1,357,600 1,357,600 76,488 11
1,408 1,408 74 12
39,644 39,644 2,292 13
828,072 828,072 39,110 14
FERC FORM NO. 1 (ED. 12-90) Page 311.7
6,481,541
482,835,347
489,316,888
223,987
11,645,802
11,869,789
-158,949 10,764,533
-174,721,835
-174,880,784
319,805,091
330,569,624
4,441,941
11,691,579
16,133,520
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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.
Sacramento Municipal Utility District NANANA250AD 1
Sacramento Municipal Utility District NANANA250LF 2
Sacramento Municipal Utility District NANANAT-12SF 3
Sacramento Municipal Utility District NANANAT-13SF 4
Salt River Project NANANAT-12SF 5
San Diego Gas & Electric Company NANANAT-12SF 6
Seattle City Light NANANAT-12SF 7
Seattle City Light NANANAT-13SF 8
Sempra Generation NANANAT-12SF 9
Shell Energy North America (US), L.P.NANANAT-12IF 10
Shell Energy North America (US), L.P.NANANAT-11SF 11
Shell Energy North America (US), L.P.NANANAT-12SF 12
Sierra Pacific Power Company NANANAT-11LF 13
Sierra Pacific Power Company NANANAT-11SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.8
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
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.
1,246,947 1,246,947 1
13,612,773 13,612,773 529,268 2
1,053,108 1,053,108 56,249 3
86 86 7 4
2,550,811 2,550,811 102,393 5
19,200 19,200 800 6
191,890 191,890 23,695 7
925 925 58 8
955,834 955,834 34,211 9
2,175,737 2,175,737 60,783 10
8,371 8,371 308 11
11,699,910 11,699,910 492,878 12
9,379 9,379 459 13
23,102 23,102 973 14
FERC FORM NO. 1 (ED. 12-90) Page 311.8
6,481,541
482,835,347
489,316,888
223,987
11,645,802
11,869,789
-158,949 10,764,533
-174,721,835
-174,880,784
319,805,091
330,569,624
4,441,941
11,691,579
16,133,520
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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.
Sierra Pacific Power Company NANANAT-13SF 1
Southern California Edison Company NANANAT-12IF 2
Southern California Edison Company NANANAT-11SF 3
Southern California Edison Company NANANAT-11SF 4
Southern California Edison Company NANANAT-12SF 5
Southern California Public Power Author NANANAT-11SF 6
Southwestern Public Service Company NANANAT-12SF 7
Tacoma Power NANANAT-12SF 8
Tenaska Power Services Co.NANANAT-11SF 9
Tenaska Power Services Co.NANANAT-12SF 10
The Energy Authority, Inc.NANANAT-11SF 11
The Energy Authority, Inc.NANANAT-12SF 12
TransAlta Energy Marketing (U.S.) Inc.NANANAT-11SF 13
TransAlta Energy Marketing (U.S.) Inc.NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.9
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
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.
13,231 13,231 596 1
8,058,380 8,058,380 327,783 2
368,406 368,406 16,135 3
1,261 1,261 50 4
4,000,732 4,000,732 155,342 5
415 415 21 6
1,839,944 1,839,944 76,515 7
129,918 129,918 7,287 8
35,801 35,801 1,387 9
1,016,581 1,016,581 45,204 10
1,192 1,192 82 11
393,992 393,992 16,154 12
24,892 24,892 1,347 13
6,396,748 6,396,748 297,782 14
FERC FORM NO. 1 (ED. 12-90) Page 311.9
6,481,541
482,835,347
489,316,888
223,987
11,645,802
11,869,789
-158,949 10,764,533
-174,721,835
-174,880,784
319,805,091
330,569,624
4,441,941
11,691,579
16,133,520
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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.
TransCanada Energy Sales Ltd.NANANAT-12SF 1
Tri-State Gen. & Trans.NANANAT-11SF 2
Tri-State Gen. & Trans.NANANAT-12SF 3
Tucson Electric Power Company NANANAT-12SF 4
Turlock Irrigation District NANANAT-12SF 5
Twin Eagle Resource Management, LLC NANANAT-12SF 6
UNS Electric, Inc.NANANAT-12SF 7
Utah Associated Municipal Power Systems NANANAT-11SF 8
Utah Associated Municipal Power Systems NANANAT-12SF 9
Utah Municipal Power Agency 343434433LF 10
Utah Municipal Power Agency NANANAT-3SF 11
Western Area Power Administration NANANAT-11SF 12
Western Area Power Administration NANANAT-12SF 13
Western Area Power Administration NANANAT-13SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.10
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
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.
42,488 42,488 1,989 1
58,159 58,159 2,292 2
7,578,373 7,578,373 322,926 3
5,611,895 5,611,895 230,961 4
159,520 159,520 6,960 5
260,886 260,886 8,538 6
8,458,036 8,458,036 315,864 7
11,637 11,637 436 8
143,206 143,206 5,448 9
4,654,444 4,396,200 9,050,644 200,921 10
411,289 411,289 18,676 11
40,999 40,999 2,019 12
19,722,589 19,722,589 690,070 13
37 37 2 14
FERC FORM NO. 1 (ED. 12-90) Page 311.10
6,481,541
482,835,347
489,316,888
223,987
11,645,802
11,869,789
-158,949 10,764,533
-174,721,835
-174,880,784
319,805,091
330,569,624
4,441,941
11,691,579
16,133,520
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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.
Netting - Bookouts NANANANA 1
Reserve for potential refunds NANANANA 2
Netting - Trading NANANANA 3
Accrual NANANANA 4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 310.11
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
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.
-177,742,246 -177,742,246 -5,563,059 1
-634,716 -634,716 2
-2,036,446 -2,036,446 3
-115,760 -115,760 -7,326 4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 311.11
6,481,541
482,835,347
489,316,888
223,987
11,645,802
11,869,789
-158,949 10,764,533
-174,721,835
-174,880,784
319,805,091
330,569,624
4,441,941
11,691,579
16,133,520
Schedule Page: 310 Line No.: 6 Column: a
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
This footnote applies to all occurrences of “Navajo Tribal Util Auth (Red Mesa)” on pages
310–311. Complete name is Navajo Tribal Utility Authority (Red Mesa).
Schedule Page: 310 Line No.: 10 Column: j
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, Sales for resale, during the period.
Schedule Page: 310.1 Line No.: 1 Column: j
Reserve share.
Schedule Page: 310.1 Line No.: 5 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 7 Column: b
Black Hills Power, Inc. - FERC 441 - contract termination date: December 31, 2023.
Schedule Page: 310.1 Line No.: 9 Column: b
Bonneville Power Administration - FERC, 5th revised R.S. 368 [Use of Facilities Agreement
for the Malin Transformer under the AC Intertie Agreement with Bonneville Power
Administration] - contract termination date: Upon mutual agreement.
Schedule Page: 310.1 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 10 Column: b
Bonneville Power Administration - FERC T-11 [Point-to-Point Transmission Service under the
Open Access Transmission Tariff (2nd revised S.A. 179)] - Contract termination date:
September 30, 2025 and (1st revised S.A. 656) - contract termination date: August 31,
2030.
Schedule Page: 310.1 Line No.: 10 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 12 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 14 Column: j
Reserve share.
Schedule Page: 310.2 Line No.: 1 Column: a
This footnote applies to all occurrences of “British Columbia Hydro & Power” on pages
310–311. Complete name is British Columbia Hydro and Power Authority.
Schedule Page: 310.2 Line No.: 1 Column: j
Reserve share.
Schedule Page: 310.2 Line No.: 2 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.: 2 Column: j
Reserve share.
Schedule Page: 310.2 Line No.: 4 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.: 4 Column: b
Settlement adjustment.
Schedule Page: 310.2 Line No.: 4 Column: j
Settlement adjustment.
Schedule Page: 310.2 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.2 Line No.: 10 Column: b
Settlement adjustment.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 310.2 Line No.: 10 Column: j
Settlement adjustment.
Schedule Page: 310.3 Line No.: 2 Column: b
City of Hurricane - FERC T-12 - contract termination date: August 31, 2007.
Schedule Page: 310.3 Line No.: 7 Column: a
This footnote applies to all occurrences of “Constellation Energy Commodities Group” on
pages 310–311. Complete name is Constellation Energy Commodities Group, Inc.
Schedule Page: 310.3 Line No.: 7 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 9 Column: b
Cyrg Energy - FERC T-11 [Point-to-Point Transmission Service under the Open Access
Transmission Tariff (2nd revised S.A. 568)] - contract termination date: August 30, 2029.
Schedule Page: 310.3 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 4 Column: b
Iberdrola Renewables, LLC - FERC T-11 [Point-to-Point Transmission Service under the Open
Access Transmission Tariff (6th revised S.A. 279)] - contract termination date: April 30,
2014.
Schedule Page: 310.4 Line No.: 4 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 5 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 6 Column: j
Unauthorized use charges.
Schedule Page: 310.4 Line No.: 8 Column: b
Idaho Power Company - FERC T-11 [Point-to-Point Transmission Service under the Open Access
Transmission Tariff (6th revised S.A. 212)] - contract termination date: May 31, 2014.
Schedule Page: 310.4 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 11 Column: j
Reserve share.
Schedule Page: 310.4 Line No.: 13 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 1 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.: 1 Column: b
Settlement adjustment.
Schedule Page: 310.5 Line No.: 1 Column: j
Settlement adjustment.
Schedule Page: 310.5 Line No.: 3 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 7 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 10 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 12 Column: b
Settlement adjustment.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 310.5 Line No.: 13 Column: b
NextEra Energy Power Marketing, LLC - FERC T-11 [Point-to-Point Transmission Service under
the Open Access Transmission Tariff (S.A. 626)] - contract termination date: October 31,
2014.
Schedule Page: 310.5 Line No.: 13 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 1 Column: j
Unauthorized use charges.
Schedule Page: 310.6 Line No.: 4 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 13 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 14 Column: b
Powerex Corporation - FERC T-11 [Point-to-Point Transmission Service under the Open Access
Transmission Tariff (7th revised S.A. 169)] - contract termination date: October 31, 2020.
Schedule Page: 310.6 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.7 Line No.: 1 Column: j
Transmission losses.
Schedule Page: 310.7 Line No.: 2 Column: j
Pond sales.
Schedule Page: 310.7 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 310.7 Line No.: 3 Column: j
Settlement adjustment.
Schedule Page: 310.7 Line No.: 6 Column: a
This footnote applies to all occurrences of “PUD #1 of Chelan County” on pages 310–311.
Complete name is Public Utility District No. 1 of Chelan County.
Schedule Page: 310.7 Line No.: 6 Column: j
Reserve share.
Schedule Page: 310.7 Line No.: 7 Column: a
This footnote applies to all occurrences of “PUD #1 of Douglas County” on pages 310–311.
Complete name is Public Utility District No. 1 of Douglas County.
Schedule Page: 310.7 Line No.: 8 Column: a
This footnote applies to all occurrences of “PUD #1 of Snohomish County” on pages 310–311.
Complete name is Public Utility District No. 1 of Snohomish County.
Schedule Page: 310.7 Line No.: 9 Column: a
This footnote applies to all occurrences of “PUD #2 of Grant County” on pages 310–311.
Complete name is Public Utility District No. 2 of Grant County.
Schedule Page: 310.7 Line No.: 10 Column: j
Reserve share.
Schedule Page: 310.7 Line No.: 12 Column: j
Reserve share.
Schedule Page: 310.7 Line No.: 13 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 1 Column: b
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Settlement adjustment.
Schedule Page: 310.8 Line No.: 1 Column: j
Settlement adjustment.
Schedule Page: 310.8 Line No.: 2 Column: b
Sacramento Municipal Utility District - FERC 250 - contract termination date: December 31,
2014.
Schedule Page: 310.8 Line No.: 4 Column: j
Reserve share.
Schedule Page: 310.8 Line No.: 8 Column: j
Reserve share.
Schedule Page: 310.8 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 13 Column: b
Sierra Pacific Power Company - FERC T-11 [Pavant Capacitor Ownership, Operation and
Maintenance Letter Agreement dated November 9, 2000] - contract terminated September 2012.
Schedule Page: 310.8 Line No.: 13 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.9 Line No.: 1 Column: j
Reserve share.
Schedule Page: 310.9 Line No.: 3 Column: j
Transmission losses.
Schedule Page: 310.9 Line No.: 4 Column: j
Unauthorized use charges.
Schedule Page: 310.9 Line No.: 6 Column: j
Unauthorized use charges.
Schedule Page: 310.9 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.9 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.9 Line No.: 13 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 2 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.: 2 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 10 Column: b
Utah Municipal Power Agency - FERC 433 - contract termination date: June 30, 2017.
Schedule Page: 310.10 Line No.: 12 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 14 Column: j
Reserve share.
Schedule Page: 310.11 Line No.: 1 Column: j
Reflects transactions that did not physically settle.
Schedule Page: 310.11 Line No.: 2 Column: j
Transmission losses.
Schedule Page: 310.11 Line No.: 3 Column: j
Reflects transactions that did not physically settle.
Schedule Page: 310.11 Line No.: 4 Column: j
Represents the difference between actual non-requirement sales revenues for the period as
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
reflected on the individual line items within this schedule, and the accruals charged to
Account 447, Sales for resale, during the period.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
1. POWER PRODUCTION EXPENSES 1
A. Steam Power Generation 2
Operation 3
(500) Operation Supervision and Engineering 4 19,391,612 19,142,283
(501) Fuel 5 722,758,588 768,997,788
(502) Steam Expenses 6 38,138,103 41,809,206
(503) Steam from Other Sources 7 3,583,830 3,937,027
(Less) (504) Steam Transferred-Cr. 8
(505) Electric Expenses 9 4,190,528 3,896,688
(506) Miscellaneous Steam Power Expenses 10 52,707,159 56,759,531
(507) Rents 11 277,654 396,587
(509) Allowances 12
TOTAL Operation (Enter Total of Lines 4 thru 12) 13 841,047,474 894,939,110
Maintenance 14
(510) Maintenance Supervision and Engineering 15 6,365,300 6,378,884
(511) Maintenance of Structures 16 23,596,390 25,384,395
(512) Maintenance of Boiler Plant 17 109,128,194 107,992,173
(513) Maintenance of Electric Plant 18 39,898,808 35,012,328
(514) Maintenance of Miscellaneous Steam Plant 19 13,319,308 12,158,343
TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 192,308,000 186,926,123
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 1,033,355,474 1,081,865,233
B. Nuclear Power Generation 22
Operation 23
(517) Operation Supervision and Engineering 24
(518) Fuel 25
(519) Coolants and Water 26
(520) Steam Expenses 27
(521) Steam from Other Sources 28
(Less) (522) Steam Transferred-Cr. 29
(523) Electric Expenses 30
(524) Miscellaneous Nuclear Power Expenses 31
(525) Rents 32
TOTAL Operation (Enter Total of lines 24 thru 32) 33
Maintenance 34
(528) Maintenance Supervision and Engineering 35
(529) Maintenance of Structures 36
(530) Maintenance of Reactor Plant Equipment 37
(531) Maintenance of Electric Plant 38
(532) Maintenance of Miscellaneous Nuclear Plant 39
TOTAL Maintenance (Enter Total of lines 35 thru 39) 40
TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 41
C. Hydraulic Power Generation 42
Operation 43
(535) Operation Supervision and Engineering 44 3,787,003 4,711,673
(536) Water for Power 45 257,504 134,519
(537) Hydraulic Expenses 46 3,696,681 4,265,329
(538) Electric Expenses 47
(539) Miscellaneous Hydraulic Power Generation Expenses 48 21,669,423 18,412,058
(540) Rents 49 -404,504 661,711
TOTAL Operation (Enter Total of Lines 44 thru 49) 50 29,006,107 28,185,290
C. Hydraulic Power Generation (Continued) 51
Maintenance 52
(541) Mainentance Supervision and Engineering 53 1,891 388
(542) Maintenance of Structures 54 1,030,119 825,279
(543) Maintenance of Reservoirs, Dams, and Waterways 55 2,430,112 2,088,303
(544) Maintenance of Electric Plant 56 2,553,749 1,974,573
(545) Maintenance of Miscellaneous Hydraulic Plant 57 2,961,681 2,936,126
TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 8,977,552 7,824,669
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 37,983,659 36,009,959
FERC FORM NO. 1 (ED. 12-93) Page 320
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
D. Other Power Generation 60
Operation 61
(546) Operation Supervision and Engineering 62 429,811 369,904
(547) Fuel 63 367,320,902 364,507,540
(548) Generation Expenses 64 15,368,434 17,430,953
(549) Miscellaneous Other Power Generation Expenses 65 21,289,631 9,147,157
(550) Rents 66 4,253,868 3,662,580
TOTAL Operation (Enter Total of lines 62 thru 66) 67 408,662,646 395,118,134
Maintenance 68
(551) Maintenance Supervision and Engineering 69
(552) Maintenance of Structures 70 2,938,948 2,291,254
(553) Maintenance of Generating and Electric Plant 71 10,918,597 25,781,191
(554) Maintenance of Miscellaneous Other Power Generation Plant 72 4,783,736 1,966,376
TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 18,641,281 30,038,821
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 427,303,927 425,156,955
E. Other Power Supply Expenses 75
(555) Purchased Power 76 398,261,268 535,586,277
(556) System Control and Load Dispatching 77 1,744,114 1,546,050
(557) Other Expenses 78 60,776,842 62,779,248
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 460,782,224 599,911,575
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 1,959,425,284 2,142,943,722
2. TRANSMISSION EXPENSES 81
Operation 82
(560) Operation Supervision and Engineering 83 5,689,657 5,532,584
84
(561.1) Load Dispatch-Reliability 85
(561.2) Load Dispatch-Monitor and Operate Transmission System 86 7,794,035 6,733,470
(561.3) Load Dispatch-Transmission Service and Scheduling 87
(561.4) Scheduling, System Control and Dispatch Services 88 239,500
(561.5) Reliability, Planning and Standards Development 89 984,307 850,396
(561.6) Transmission Service Studies 90 206,982 127,861
(561.7) Generation Interconnection Studies 91 763,228 617,977
(561.8) Reliability, Planning and Standards Development Services 92
(562) Station Expenses 93 2,647,395 2,984,932
(563) Overhead Lines Expenses 94 259,051 285,237
(564) Underground Lines Expenses 95
(565) Transmission of Electricity by Others 96 138,234,854 142,125,115
(566) Miscellaneous Transmission Expenses 97 3,568,851 3,696,068
(567) Rents 98 2,549,553 1,497,301
TOTAL Operation (Enter Total of lines 83 thru 98) 99 162,697,913 164,690,441
Maintenance 100
(568) Maintenance Supervision and Engineering 101 2,060,726 2,486,358
(569) Maintenance of Structures 102 300 1,145
(569.1) Maintenance of Computer Hardware 103 103,365 203,102
(569.2) Maintenance of Computer Software 104 1,119,442 1,001,012
(569.3) Maintenance of Communication Equipment 105 3,356,135 3,270,838
(569.4) Maintenance of Miscellaneous Regional Transmission Plant 106
(570) Maintenance of Station Equipment 107 11,231,343 11,423,719
(571) Maintenance of Overhead Lines 108 22,369,881 20,575,947
(572) Maintenance of Underground Lines 109 169,531 82,622
(573) Maintenance of Miscellaneous Transmission Plant 110 1,607,372 2,748,898
TOTAL Maintenance (Total of lines 101 thru 110) 111 42,018,095 41,793,641
TOTAL Transmission Expenses (Total of lines 99 and 111) 112 204,716,008 206,484,082
FERC FORM NO. 1 (ED. 12-93) Page 321
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
3. REGIONAL MARKET EXPENSES 113
Operation 114
(575.1) Operation Supervision 115
(575.2) Day-Ahead and Real-Time Market Facilitation 116
(575.3) Transmission Rights Market Facilitation 117
(575.4) Capacity Market Facilitation 118
(575.5) Ancillary Services Market Facilitation 119
(575.6) Market Monitoring and Compliance 120
(575.7) Market Facilitation, Monitoring and Compliance Services 121
(575.8) Rents 122
Total Operation (Lines 115 thru 122) 123
Maintenance 124
(576.1) Maintenance of Structures and Improvements 125
(576.2) Maintenance of Computer Hardware 126
(576.3) Maintenance of Computer Software 127
(576.4) Maintenance of Communication Equipment 128
(576.5) Maintenance of Miscellaneous Market Operation Plant 129
Total Maintenance (Lines 125 thru 129) 130
TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 131
4. DISTRIBUTION EXPENSES 132
Operation 133
(580) Operation Supervision and Engineering 134 14,865,204 14,093,118
(581) Load Dispatching 135 13,254,105 13,036,839
(582) Station Expenses 136 4,206,539 4,078,201
(583) Overhead Line Expenses 137 6,624,463 5,526,165
(584) Underground Line Expenses 138 1,186 249
(585) Street Lighting and Signal System Expenses 139 231,056 222,740
(586) Meter Expenses 140 7,978,791 7,071,031
(587) Customer Installations Expenses 141 13,297,857 12,473,499
(588) Miscellaneous Expenses 142 5,452,451 4,562,147
(589) Rents 143 3,011,807 3,366,940
TOTAL Operation (Enter Total of lines 134 thru 143) 144 68,923,459 64,430,929
Maintenance 145
(590) Maintenance Supervision and Engineering 146 4,424,569 4,472,548
(591) Maintenance of Structures 147 2,476,425 1,310,306
(592) Maintenance of Station Equipment 148 14,330,166 10,993,806
(593) Maintenance of Overhead Lines 149 89,892,555 88,718,266
(594) Maintenance of Underground Lines 150 22,649,570 20,313,015
(595) Maintenance of Line Transformers 151 893,541 957,612
(596) Maintenance of Street Lighting and Signal Systems 152 4,076,102 3,704,762
(597) Maintenance of Meters 153 5,647,204 6,749,398
(598) Maintenance of Miscellaneous Distribution Plant 154 1,787,180 2,027,649
TOTAL Maintenance (Total of lines 146 thru 154) 155 146,177,312 139,247,362
TOTAL Distribution Expenses (Total of lines 144 and 155) 156 215,100,771 203,678,291
5. CUSTOMER ACCOUNTS EXPENSES 157
Operation 158
(901) Supervision 159 2,930,313 2,603,420
(902) Meter Reading Expenses 160 21,907,551 20,679,578
(903) Customer Records and Collection Expenses 161 56,314,393 53,770,351
(904) Uncollectible Accounts 162 14,586,410 14,337,468
(905) Miscellaneous Customer Accounts Expenses 163 205,123 142,188
TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 95,943,790 91,533,005
FERC FORM NO. 1 (ED. 12-93) Page 322
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 165
Operation 166
(907) Supervision 167 302,255 301,706
(908) Customer Assistance Expenses 168 103,945,691 103,156,102
(909) Informational and Instructional Expenses 169 5,081,263 3,294,390
(910) Miscellaneous Customer Service and Informational Expenses 170 183,174 204,557
TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 109,512,383 106,956,755
7. SALES EXPENSES 172
Operation 173
(911) Supervision 174
(912) Demonstrating and Selling Expenses 175
(913) Advertising Expenses 176
(916) Miscellaneous Sales Expenses 177
TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 178
8. ADMINISTRATIVE AND GENERAL EXPENSES 179
Operation 180
(920) Administrative and General Salaries 181 68,148,776 74,368,102
(921) Office Supplies and Expenses 182 9,330,613 8,706,781
(Less) (922) Administrative Expenses Transferred-Credit 183 29,007,646 27,128,855
(923) Outside Services Employed 184 10,190,059 13,277,918
(924) Property Insurance 185 24,984,814 16,404,849
(925) Injuries and Damages 186 7,284,849 48,931,701
(926) Employee Pensions and Benefits 187
(927) Franchise Requirements 188
(928) Regulatory Commission Expenses 189 21,857,100 22,965,972
(929) (Less) Duplicate Charges-Cr. 190 6,822,162 4,869,262
(930.1) General Advertising Expenses 191 5,360 4,948
(930.2) Miscellaneous General Expenses 192 15,710,771 7,338,998
(931) Rents 193 6,614,680 6,720,354
TOTAL Operation (Enter Total of lines 181 thru 193) 194 128,297,214 166,721,506
Maintenance 195
(935) Maintenance of General Plant 196 24,360,143 21,518,172
TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 152,657,357 188,239,678
TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 2,737,355,593 2,939,835,533
FERC FORM NO. 1 (ED. 12-93) Page 323
Schedule Page: 320 Line No.: 49 Column: c
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, 2012 and 2011, pensions and benefits expense was $144,687,083 and $156,716,703,
respectively.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
Power Purchases: 1
NANANAArizona Electric Power Cooperative SF 2
NANANAArizona Public Service Company AD 3
NANANAArizona Public Service Company LF 4
NANANAArizona Public Service Company SF 5
NANANAAvista Corporation SF 6
NANANABNP Paribas Energy Trading GP SF 7
NANANABP Corporation North America, Inc. SF 8
NANANABP Energy Company SF 9
0.010.010.01Ballard Hog Farms Inc. LU 10
NANANABarclays Bank PLC SF 11
NANANABasin Electric Power Cooperative SF 12
NANANABeaver City Corporation LF 13
NANANABell Mountain Hydro, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
1
1,355 1,355 2 70
94,281 94,281 3
1,657,766 1,657,766 4 60,856
4,515,580 75,593 4,591,173 5 150,602
1,858,822 4,303 1,863,125 6 71,221
242 242 7 6
-9,393,174 -9,393,174 8
9,468,834 -1,093,562 8,375,272 9 528,965
302 2,431 2,733 10 60
12,466,592 -356,180 12,110,412 11 283,278
18,415 18,415 12 1,011
6,250 6,250 13 75
76,989 76,989 14 1,027
FERC FORM NO. 1 (ED. 12-90) Page 327
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANABig Top, LLC LU 1
NANANABiomass One, L.P. LU 2
NANANABirch Power Company, Inc. LU 3
NANANABlack Cap Solar, LLC OS 4
NANANABlack Hills Power, Inc. AD 5
NANANABlack Hills Power, Inc. LU 6
NANANABlack Hills Power, Inc. SF 7
NANANABlanding City Corporation LF 8
NANANABonneville Power Administration LF 9
NANANABonneville Power Administration OS 10
NANANABonneville Power Administration SF 11
1.63.82.9Box Canyon Limited Partnership LU 12
NANANAButter Creek Power, LLC LU 13
NANANAC Drop Hydro, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.1
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
260,709 260,709 1 3,844
8,725,321 3,047,953 11,773,274 2 127,571
888,603 888,603 3 15,362
10,026 10,026 4 377
199,875 199,875 5 -103
504,302 504,302 6 10
402,055 402,055 7 12,751
29,453 29,453 8 393
875,251 875,251 9
69,557 69,557 10 1,786
9,914,969 42,511 9,957,480 11 541,849
271,905 1,843,813 2,115,718 12 15,586
888,593 888,593 13 13,093
135,034 135,034 14 2,619
FERC FORM NO. 1 (ED. 12-90) Page 327.1
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANACDM Hydroelectric Company LU 1
36166200CER Generation II, LLC IU 2
NANANACalifornia Independent System Operator AD 3
NANANACalifornia Independent System Operator SF 4
NANANACalpine Energy Services, L.P. SF 5
NANANACameron A. Curtiss LU 6
NANANACargill Power Markets, LLC IF 7
NANANACargill Power Markets, LLC SF 8
NANANACargill, Incorporated LU 9
NANANACentral Oregon Irrigation District AD 10
4.25.15.9Central Oregon Irrigation District LU 11
NANANAChevron U.S.A. Inc. LU 12
NANANACitigroup Energy Inc. SF 13
NANANACity of Albany LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.2
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
1,634,850 1,634,850 1 28,427
5,208,000 12,478,140 17,686,140 2 272,791
-64,752 -64,752 3 -2,059
6,600,374 6,600,374 4 275,609
17,866,171 17,866,171 5 667,881
5,284 5,284 6 101
17,621,558 17,621,558 7 240,949
2,799,857 869,476 3,669,333 8 138,468
292,708 292,708 9 4,946
-11,677 -11,677 10
608,150 4,846,859 5,455,009 11 52,300
2,894,381 2,894,381 12 45,768
31,348,541 -9,175,508 22,173,033 13 1,044,875
57,170 57,170 14 829
FERC FORM NO. 1 (ED. 12-90) Page 327.2
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANACity of Anaheim SF 1
NANANACity of Burbank SF 2
NANANACity of Glendale SF 3
NANANACity of Hurricane LF 4
NANANACity of Portland, Water Bureau LU 5
NANANACity of Preston Idaho LU 6
NANANACity of Redding SF 7
1.51.92.0City of Walla Walla LU 8
NANANAClatskanie People's Utility District SF 9
NANANAColorado River Commission of Nevada SF 10
NANANACommercial Energy Management Inc. LU 11
NANANAConstellation Energy Commodities Group SF 12
NANANACottonwood Hydro, LLC AD 13
NANANACottonwood Hydro, LLC IU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.3
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
38 38 1 2
568,963 568,963 2 14,323
67,520 67,520 3 1,570
138,717 138,717 4 1,928
2,015 2,015 5 49
135,558 135,558 6 2,557
-800 -800 7 20
138,980 1,986,857 2,125,837 8 13,637
13,240 13,240 9 1,840
4,021 4,021 10 128
100,966 100,966 11 1,877
3,718,576 -65,547 3,653,029 12 143,664
-3,275 -3,275 13 -60
141,210 141,210 14 2,994
FERC FORM NO. 1 (ED. 12-90) Page 327.3
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANADB Energy Trading LLC SF 1
3.34.15.8Deschutes Valley Water District LU 2
91100100Deseret Generation & Transmission Coop LF 3
NANANADeutsche Bank AG SF 4
0.71.20.8Douglas County LU 5
NANANADouglas County, Inc. LU 6
NANANADraper Irrigation Company AD 7
NANANADraper Irrigation Company IU 8
NANANADry Creek LLC LU 9
NANANADuane Wiggins Hydro, Inc. IU 10
NANANAEDF Trading North America, LLC SF 11
0.40.50.8Eagle Point Irrigation District LU 12
NANANAEl Paso Electric Company SF 13
NANANAEugene Water & Electric Board SF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.4
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
9,614,090 9,614,090 1 467,915
567,894 3,232,576 3,800,470 2 28,734
15,031,898 13,026,114 3,936,927 31,994,939 3 679,693
-4,248,587 -4,248,587 4
83,226 905,218 988,444 5 7,179
177,038 177,038 6 10,143
14,283 14,283 7 485
2,698 2,698 8 63
552,993 552,993 9 10,268
787 787 10 15
21,971,661 1,138,781 23,110,442 11 735,474
45,865 423,858 469,723 12 3,574
290,598 28 290,626 13 10,200
914,420 914,420 14 51,931
FERC FORM NO. 1 (ED. 12-90) Page 327.4
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANAEurus Combine Hills I, LLC LU 1
NANANAEvergreen BioPower, LLC LU 2
2.03.83.6Falls Creek H.P. Limited Partnership LU 3
NANANAFarmers Irrigation District LU 4
NANANAFillmore City Corporation LF 5
NANANAFinley BioEnergy, LLC LU 6
NANANAFlathead Electric Cooperative, Inc. LF 7
NANANAFour Corners Windfarm, LLC LU 8
NANANAFour Mile Canyon Windfarm, LLC LU 9
0.81.00.8George DeRuyter & Sons Dairy LU 10
NANANAGeorgetown Irrigation Company LU 11
NANANAGila River Power LLC SF 12
NANANAGrand Valley Power LF 13
NANANAGrowPro, Inc. IU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.5
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
4,922,879 4,922,879 1 108,721
2,158,175 2,158,175 2 34,659
255,074 2,197,882 2,452,956 3 19,554
1,578,289 1,578,289 4 24,377
19,680 19,680 5 182
2,342,922 2,342,922 6 34,089
8,974 8,974 7 478
1,926,532 1,926,532 8 28,521
1,758,543 1,758,543 9 25,965
14,014 416,932 430,946 10 6,710
114,462 114,462 11 2,023
4,011,092 4,011,092 12 127,206
14,415 14,415 13 74
12 12 14
FERC FORM NO. 1 (ED. 12-90) Page 327.5
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANAHarold Foster & Robert Walker LU 1
NANANAHermiston Generating Company, L.P. AD 2
172223223Hermiston Generating Company, L.P. LU 3
NANANAIberdrola Renewables, LLC OS 4
NANANAIberdrola Renewables, LLC SF 5
NANANAIdaho Falls, City of AD 6
NANANAIdaho Falls, City of LU 7
NANANAIdaho Power Company OS 8
NANANAIdaho Power Company SF 9
NANANAIngram Warm Springs Ranch Partnership LU 10
NANANAIntermountain Power Agency LU 11
NANANAJ Bar 9 Ranch, Inc. AD 12
NANANAJ Bar 9 Ranch, Inc. LU 13
NANANAJ. Aron & Company SF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.6
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
31,620 31,620 1 857
61,431 61,431 2 1
36,089,626 48,441,607 455,927 84,987,160 3 1,146,891
96,055 96,055 4
29,103,013 686,013 29,789,026 5 1,207,842
-10,524 -10,524 6
2,900,829 2,900,829 7 68,969
1,500 1,500 8 100
1,201,467 3,017 1,204,484 9 54,027
70,730 70,730 10 1,224
27,777,196 27,777,196 11 469,313
63 63 12 4
1,607 1,607 13 67
648,830 -5,544,603 -4,895,773 14 15,613
FERC FORM NO. 1 (ED. 12-90) Page 327.6
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANAJP Morgan Ventures Energy Corporation SF 1
NANANAJake Amy LU 2
NANANAJoseph Community Solar LLC AD 3
NANANAJoseph Community Solar LLC LU 4
NANANAKennecott Utah Copper LLC LU 5
NANANALacomb Irrigation District LU 6
NANANALos Angeles Dept. of Water & Power AD 7
NANANALos Angeles Dept. of Water & Power SF 8
NANANALower Valley Energy, Inc. AD 9
NANANALower Valley Energy, Inc. IU 10
NANANALower Valley Energy, Inc. LU 11
NANANALoyd Fery LU 12
NANANAMacquarie Energy LLC SF 13
NANANAMarsh Valley Hydro Electric Company LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.7
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
7,790,916 -4,772,593 3,018,323 1 386,822
94,429 94,429 2 1,724
1,916 1,916 3 44
20,484 20,484 4 667
1,921,698 1,824,932 3,746,630 5 56,610
75,330 35,812 111,142 6 3,642
2,300 2,300 7 61
3,810,498 13 3,810,511 8 86,912
3,244 3,244 9
396,577 396,577 10 5,822
58,928 58,928 11 1,107
22,539 22,539 12 348
7,984,850 -42,022 7,942,828 13 295,486
292,280 292,280 14 5,083
FERC FORM NO. 1 (ED. 12-90) Page 327.7
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANAMeadow Creek Project Company LLC LU 1
NANANAMiddle Fork Irrigation District LU 2
NANANAMink Creek Hydro LLC LU 3
NANANAMonsanto Company IU 4
NANANAMorgan City Corporation LF 5
NANANAMorgan Stanley Capital Group, Inc. AD 6
NANANAMorgan Stanley Capital Group, Inc. SF 7
NANANAMountain Energy, Inc. LU 8
NANANAMountain Wind Power II, LLC LU 9
NANANAMountain Wind Power, LLC LU 10
NANANAMunicipal Energy Agency of Nebraska SF 11
NANANANaturEner Power Watch, LLC SF 12
NANANANephi City Corporation LF 13
NANANANevada Power Company SF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.8
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
1,509,603 1,509,603 1 29,683
1,572,734 1,572,734 2 25,232
493,901 493,901 3 8,861
18,255,735 18,255,735 4
2,551 2,551 5 25
6
58,506,762 -1,437,314 57,069,448 7 1,871,743
6,574 6,574 8 96
14,574,484 14,574,484 9 227,793
9,522,713 9,522,713 10 171,518
2,200 2,200 11 100
23 23 12 1
1,865 1,865 13 16
5,538,726 304,867 5,843,593 14 170,658
FERC FORM NO. 1 (ED. 12-90) Page 327.8
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANANextEra Energy Power Marketing, LLC SF 1
NANANANicholson's Sunny Bar Ranch LU 2
NANANANoble Americas Gas & Power Corp. SF 3
NANANANorthWestern Corporation SF 4
NANANANucor Corporation IF 5
NANANAO.J. Power Company LU 6
NANANAOregon Environmental Industries, LLC LU 7
NANANAOregon Institute of Technology LU 8
NANANAOregon State University LU 9
NANANAOregon Trail Windfarm, LLC LU 10
NANANAPPL EnergyPlus, LLC SF 11
NANANAPacific Canyon Windfarm, LLC LU 12
NANANAPacific Gas & Electric Company SF 13
NANANAPaul Luckey LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.9
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
170,675 170,675 1 10,070
107,012 107,012 2 1,870
240,680 240,680 3 14,000
4,336 4,336 4 190
5,446,800 5,446,800 5
36,019 36,019 6 684
1,376,978 1,376,978 7 22,079
8
9,984 9,984 9 386
1,763,384 1,763,384 10 26,111
2,650,126 2,650,126 11 131,134
1,344,769 1,344,769 12 19,839
520,976 520,976 13 20,000
38,030 38,030 14 282
FERC FORM NO. 1 (ED. 12-90) Page 327.9
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANAPayson City Corporation LF 1
NANANAPlatte River Power Authority SF 2
NANANAPortland General Electric Company AD 3
NANANAPortland General Electric Company LF 4
NANANAPortland General Electric Company SF 5
NANANAPower County Wind Park North, LLC AD 6
NANANAPower County Wind Park North, LLC LU 7
NANANAPower County Wind Park South, LLC AD 8
NANANAPower County Wind Park South, LLC LU 9
NANANAPowerex Corporation SF 10
NANANAProvo City Corporation LF 11
NANANAPublic Service Company of Colorado SF 12
NANANAPublic Service Company of New Mexico SF 13
NANANAPUD No. 1 of Chelan County AD 14
FERC FORM NO. 1 (ED. 12-90) Page 326.10
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
1,988 1,988 1 17
88,370 88,370 2 3,693
-230,124 -230,124 3
270,000 270,000 4 12,024
967,018 5,439 972,457 5 58,728
5,685 5,685 6 197
3,979,854 3,979,854 7 70,382
461 461 8 16
3,664,717 3,664,717 9 64,743
5,132,828 -29,792 5,103,036 10 171,142
4,397 4,397 11 51
225,180 225,180 12 5,446
4,717,802 114,789 4,832,591 13 168,082
9,540 9,540 14
FERC FORM NO. 1 (ED. 12-90) Page 327.10
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANAPUD No. 1 of Chelan County SF 1
NANANAPUD No. 1 of Cowlitz County OS 2
NANANAPUD No. 1 of Douglas County AD 3
NANANAPUD No. 1 of Douglas County AD 4
NANANAPUD No. 1 of Douglas County LF 5
NANANAPUD No. 1 of Douglas County LU 6
NANANAPUD No. 1 of Douglas County SF 7
NANANAPUD No. 1 of Snohomish County SF 8
NANANAPUD No. 2 of Grant County AD 9
NANA14PUD No. 2 of Grant County LF 10
NANANAPUD No. 2 of Grant County LU 11
NANANAPUD No. 2 of Grant County SF 12
NANANAPuget Sound Energy, Inc. SF 13
NANANARES Ag - Oak Lea LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.11
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
403,690 2,434 406,124 1 23,323
-93,738 -93,738 2
-110,579 -110,579 3
-150,834 -150,834 4
2,367,669 2,367,669 5 88,266
3,263,025 3,263,025 6 245,509
645,995 460 646,455 7 34,255
707,610 707,610 8 45,205
-817,762 -817,762 9
104,746 4,028,260 206,201 4,339,207 10 58,852
-4,695,046 -4,695,046 11 135,994
946,381 1,894 948,275 12 43,157
2,524,103 6,220 2,530,323 13 116,892
41,694 41,694 14 1,015
FERC FORM NO. 1 (ED. 12-90) Page 327.11
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANARainbow Energy Marketing Corporation SF 1
NANANARalphs Ranch, Inc. LU 2
NANANARiverside, City of SF 3
NANANARock River 1, LLC LU 4
NANANARocky Mountain Generation Coop SF 5
NANANARoseburg Forest Products Company AD 6
NANANARoseburg Forest Products Company LU 7
NANANARoseburg Forest Products Company OS 8
NANANARoseburg LFG Energy, LLC AD 9
NANANARoseburg LFG Energy, LLC LU 10
NANANARough & Ready Lumber Company LU 11
NANANARoush Hydro Inc. AD 12
NANANARoush Hydro Inc. LU 13
NANANASacramento Municipal Utility District AD 14
FERC FORM NO. 1 (ED. 12-90) Page 326.12
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
3,627,229 3,627,229 1 130,326
28,892 28,892 2 215
900 900 3 100
4,793,270 4,793,270 4 135,098
183,357 183,357 5 11,925
6 292
1,559,074 1,559,074 7 36,743
905,655 905,655 8 16,274
8,370 8,370 9 170
592,655 592,655 10 11,411
559,319 559,319 11 8,196
-512 -512 12 -8
20,510 20,510 13 297
148,541 148,541 14
FERC FORM NO. 1 (ED. 12-90) Page 327.12
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANASacramento Municipal Utility District LF 1
NANANASacramento Municipal Utility District SF 2
NANANASalt River Project SF 3
NANANASan Diego Gas & Electric Company SF 4
NANANASand Ranch Windfarm, LLC LU 5
0.20.20.2Santiam Water Control District LU 6
NANANASeattle City Light AD 7
NANANASeattle City Light SF 8
NANANASempra Generation SF 9
NANANAShell Energy North America (US), L.P. AD 10
NANANAShell Energy North America (US), L.P. IF 11
NANANAShell Energy North America (US), L.P. SF 12
1.41.42.6Shoshone Irrigation District LU 13
NANANASierra Pacific Power Company SF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.13
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
4,132,209 4,132,209 1 218,983
25,029 25,029 2 1,234
3,375,854 6,322 3,382,176 3 98,339
46,951 46,951 4 1,047
1,646,437 1,646,437 5 24,317
13,632 152,919 166,551 6 1,609
300,000 300,000 7
3,476,780 2,906 3,479,686 8 196,711
4,962,788 4,962,788 9 172,625
19 19 10
2,538,336 2,538,336 11 60,720
6,900,844 -1,382,028 5,518,816 12 368,953
188,293 434,781 623,074 13 10,185
535,735 2,013 537,748 14 17,200
FERC FORM NO. 1 (ED. 12-90) Page 327.13
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANASierra Pacific Power Company SF 1
71310Simplot Phosphates LLC LU 2
NANANASlate Creek Hydro Company, Inc. AD 3
0.81.82.4Slate Creek Hydro Company, Inc. LU 4
NANANASolwatt LLC LU 5
NANANASouthern California Edison Company SF 6
NANANASouthwestern Public Service Company SF 7
NANANASpanish Fork Wind Park 2, LLC LU 8
0.20.50.5Sprague Hydro, LLC LU 9
NANANASpringville City Corporation LF 10
NANANAStahlbush Island Farms, Inc. IU 11
NANANAStrawberry Electric Service District LF 12
435352Sunnyside Cogeneration Associates LU 13
NANANASwalley Irrigation District LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.14
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
381,704 381,704 1 5,915
494,000 3,991,543 4,485,543 2 79,938
76,747 76,747 3
120,921 844,985 965,906 4 7,970
15,862 15,862 5 443
94,188 94,188 6 7,949
133,964 133,964 7 5,013
2,555,950 2,555,950 8 48,703
55,233 304,346 359,579 9 2,577
6,891 6,891 10 56
428,422 428,422 11 8,213
5,217 5,217 12 61
10,621,050 15,945,696 26,566,746 13 418,433
145,570 145,570 14 2,115
FERC FORM NO. 1 (ED. 12-90) Page 327.14
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANATacoma Power SF 1
NANANATata Chemicals (Soda Ash) Partners OS 2
NANANATenaska Power Services Co. SF 3
NANANATesoro Refining and Marketing Company LU 4
0.30.40.3Thayn Hydro LLC LU 5
NANANAThe Energy Authority, Inc. SF 6
0.20.20.2The Town of the City of Buffalo LU 7
NANANAThree Buttes Windpower, LLC LU 8
NANANAThreemile Canyon Wind I, LLC LU 9
NANANATop of The World Wind Energy LLC LU 10
NANANATransAlta Energy Marketing (U.S.) Inc. SF 11
182525Tri-State Gen. & Trans. LF 12
NANANATri-State Gen. & Trans. SF 13
NANANATuana Springs Energy, LLC OS 14
FERC FORM NO. 1 (ED. 12-90) Page 326.15
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
999,435 1,235 1,000,670 1 61,980
40,614 40,614 2 2,726
189,403 189,403 3 5,740
845,991 845,991 4 25,014
83,116 231,688 314,804 5 2,768
3,887,037 3,887,037 6 166,324
23,310 185,095 208,405 7 1,888
21,681,288 21,681,288 8 340,033
1,566,514 1,566,514 9 22,740
43,898,356 43,898,356 10 665,128
3,084,125 3,084,125 11 148,691
6,351,000 2,894,270 9,245,270 12 113,858
212,851 260,675 473,526 13 16,775
77,340 77,340 14
FERC FORM NO. 1 (ED. 12-90) Page 327.15
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANATucson Electric Power Company SF 1
NANANAUNS Electric, Inc. SF 2
NANANAUS Magnesium LLC LF 3
NANANAUS Magnesium LLC LU 4
NANANAUnited States Air Force at Hill Base LU 5
NANANAWagon Trail, LLC LU 6
NANANAWard Butte Windfarm, LLC LU 7
NANANAWarm Springs Forest Products LU 8
NANANAWasatch Integrated Waste Management AD 9
NANANAWasatch Integrated Waste Management LU 10
NANANAWeber County LU 11
NANANAWestern Area Power Administration LF 12
NANANAWestern Area Power Administration SF 13
NANANAWestern Area Power Administration SF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.16
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
668,593 13,531 682,124 1 24,050
1,169,883 1,169,883 2 41,144
6,194,167 6,194,167 3
5,154,841 5,154,841 4 128,736
654,845 654,845 5 14,227
520,842 520,842 6 7,682
1,194,858 1,194,858 7 17,718
20,961 20,961 8 772
-13,661 -13,661 9
32,530 32,530 10 948
238,529 238,529 11 5,022
215,517 215,517 12 7,065
532,255 532,255 13 18,750
82,720 52 82,772 14 5,006
FERC FORM NO. 1 (ED. 12-90) Page 327.16
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANAWolverine Creek Energy, LLC LU 1
1.01.21.6Yakima-Tieton Irrigation District LU 2
NANANAOregon Solar Incentive AD 3
NANANAOregon Solar Incentive LU 4
NANANASettlement/Reserves 5
NANANANetting - Trading 6
NANANANetting - Bookouts 7
NANANANet Power Cost Deferrals 8
NANANAAccrual 9
10
Power Exchanges: 11
NANANAArizona Public Service Company 307EX 12
NANANAAvista Corporation 554EX 13
NANANABasin Electric Power Cooperative T-11EX 14
FERC FORM NO. 1 (ED. 12-90) Page 326.17
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
10,027,514 10,027,514 1 178,431
17,281 251,416 268,697 2 6,864
18,454 18,454 3 447
111,774 111,774 4 3,551
50,000 50,000 5
-2,036,446 -2,036,446 6
-177,742,246 -177,742,246 7 -5,564,193
-3,516,448 -3,516,448 8
-1,715,009 -1,715,009 9
10
11
571,392 570,868 948,211 948,211 12
1,662 13
174 9,598 217,190 217,190 14
FERC FORM NO. 1 (ED. 12-90) Page 327.17
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANABlack Hills Power, Inc. 246EX 1
NANANABonneville Power Administration 256AD 2
NANANABonneville Power Administration T-11AD 3
NANANABonneville Power Administration T-12AD 4
NANANABonneville Power Administration 237AD 5
NANANABonneville Power Administration 237EX 6
NANANABonneville Power Administration 256EX 7
NANANABonneville Power Administration 368EX 8
NANANABonneville Power Administration 519EX 9
NANANABonneville Power Administration 554EX 10
NANANABonneville Power Administration EX 11
NANANABonneville Power Administration T-11EX 12
NANANABonneville Power Administration T-12EX 13
NANANACity of Redding 364EX 14
FERC FORM NO. 1 (ED. 12-90) Page 326.18
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
12 1
259 -7,770 -7,770 2
32 -957 -957 3
50 1,098 1,098 4
1,120 -2,801 -2,801 5
1,087 22,026 22,026 6
942 942 -7,536 -7,536 7
237,568 237,568 8
100,008 94,224 -182,270 -182,270 9
15,677 211,819 10
8,995,977 8,995,977 -32,166,509 -32,166,509 11
12,146 9,007 -63,545 -63,545 12
24,848 713,697 713,697 13
118,594 118,433 135,707 135,707 14
FERC FORM NO. 1 (ED. 12-90) Page 327.18
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANACyrg Energy T-11EX 1
NANANADeseret Generation & Transmission Coop 280AD 2
NANANADeseret Generation & Transmission Coop 21EX 3
NANANADeseret Generation & Transmission Coop 280EX 4
NANANAEmerald People's Utility District 351EX 5
NANANAEugene Water & Electric Board T-12EX 6
NANANAIberdrola Renewables, LLC T-11EX 7
NANANAIdaho Power Company 380EX 8
NANANAJP Morgan Ventures Energy Corporation T-11EX 9
NANANALos Angeles Dept. of Water & Power OV-1EX 10
NANANAMilford Wind Corridor Phase I, LLC OV-1EX 11
NANANAMilford Wind Corridor Phase II, LLC OV-1EX 12
NANANANextEra Energy Power Marketing, LLC T-11EX 13
NANANANoble Americas Energy Solutions LLC T-11EX 14
FERC FORM NO. 1 (ED. 12-90) Page 326.19
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
1,828 1,925 3,692 3,692 1
-21,180 18,360 1,215,556 1,215,556 2
8,516 3
31,087 52,460 564,102 564,102 4
516 -12,896 -12,896 5
16,308 16,123 -7,628 -7,628 6
4,754 6,601 46,174 46,174 7
286,540 458,105 8
1,154 1,850 14,167 14,167 9
2,212 153,851 153,851 10
1,263 -119,272 -119,272 11
949 -76,099 -76,099 12
64,756 94,624 569,623 569,623 13
5,679 7,919 63,894 63,894 14
FERC FORM NO. 1 (ED. 12-90) Page 327.19
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANAPortland General Electric Company 554EX 1
NANANAPublic Service Company of Colorado 319EX 2
NANANAPublic Service Company of Colorado 334EX 3
NANANAPublic Service Company of Colorado T-12EX 4
NANANAPUD No. 1 of Cowlitz County 554EX 5
NANANASeattle City Light 554AD 6
NANANASeattle City Light 554EX 7
NANANASouthern California Edison Company T-11EX 8
NANANASouthern California Public Power Auth. T-11EX 9
NANANATri-State Gen. & Trans. 319AD 10
NANANATri-State Gen. & Trans. 319EX 11
NANANATri-State Gen. & Trans. T-11EX 12
NANANAUtah Associated Municipal Power T-11AD 13
NANANAUtah Associated Municipal Power T-11EX 14
FERC FORM NO. 1 (ED. 12-90) Page 326.20
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
130,520 131,521 1
3,280 2
1,313,022 1,316,441 5,400,000 5,400,000 3
69,885 72,277 82,575 82,575 4
298,583 237,832 5
384 6
365,189 384,214 421,517 421,517 7
61,293 78,983 332,014 332,014 8
1,249 1,887 14,316 14,316 9
1,375 1,375 10
3,280 -11,692 -11,692 11
6,803 2,997 -66,805 -66,805 12
-763 380 43,526 43,526 13
68,884 98,610 941,455 941,455 14
FERC FORM NO. 1 (ED. 12-90) Page 327.20
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2012/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(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.
NANANAUtah Municipal Power Agency T-11AD 1
NANANAUtah Municipal Power Agency T-11EX 2
NANANAWarm Springs Power Enterprises T-11EX 3
NANANAWestern Area Power Administration LAS-4AD 4
NANANAWestern Area Power Administration LAS-4EX 5
NANANASystem Deviation NA 6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 326.21
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
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 (l). Explain in a footnote all components of the amount shown in column (l). 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 (l)
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.
-884 -862 212 212 1
13,988 21,839 276,814 276,814 2
3,768 8,795 118,701 118,701 3
2,350 53 -263,846 -263,846 4
33,234 248 -571,991 -571,991 5
6 22,051
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 327.21
13,716,836 13,296,962 12,824,651 76,387,516 643,504,514 -184,305,753 535,586,277
Schedule Page: 326 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326 Line No.: 3 Column: l
Line loss.
Schedule Page: 326 Line No.: 4 Column: b
Arizona Public Service Company - contract termination date: October 31, 2020
Schedule Page: 326 Line No.: 5 Column: l
Line loss.
Schedule Page: 326 Line No.: 6 Column: l
Reserve share.
Schedule Page: 326 Line No.: 8 Column: l
Financial swap.
Schedule Page: 326 Line No.: 9 Column: l
Financial swap.
Schedule Page: 326 Line No.: 11 Column: l
Financial swap.
Schedule Page: 326 Line No.: 13 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.1 Line No.: 2 Column: l
Non-generation agreement.
Schedule Page: 326.1 Line No.: 4 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.1 Line No.: 4 Column: k
PacifiCorp has entered into an agreement with RBS Asset Finance, Inc. to lease the Black
Cap Solar generating facility. The lease has a 16-year term from October 2012 to October
2028 and is accounted for as an operating lease. This amount represents test energy
purchased prior to the October 2012 effective date of the operating lease. For more
information, refer to Important Changes During the Year, Item 4, in this FERC Form 1.
Schedule Page: 326.1 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 326.1 Line No.: 5 Column: l
Operation and maintenance expense associated with the combustion turbine located in Rapid
City, South Dakota.
Schedule Page: 326.1 Line No.: 6 Column: l
Operation and maintenance expense associated with the combustion turbine located in Rapid
City, South Dakota.
Schedule Page: 326.1 Line No.: 8 Column: b
Blanding City Corporation - contract termination date: March 31, 2013
Schedule Page: 326.1 Line No.: 9 Column: b
Bonneville Power Administration - contract termination date: 30 days written notice
Schedule Page: 326.1 Line No.: 9 Column: l
Ancillary services.
Schedule Page: 326.1 Line No.: 10 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.1 Line No.: 10 Column: l
Ancillary services.
Schedule Page: 326.1 Line No.: 11 Column: l
Reserve share.
Schedule Page: 326.2 Line No.: 2 Column: l
Variable operating, maintenance and fuel expense associated with gas facility located in
West Valley, Utah.
Schedule Page: 326.2 Line No.: 3 Column: a
This footnote applies to all occurrences of "California Independent System Operator" on
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
pages 326-327. Complete name is California Independent System Operator Corporation.
Schedule Page: 326.2 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.2 Line No.: 3 Column: l
Settlement adjustment.
Schedule Page: 326.2 Line No.: 8 Column: l
Financial swap.
Schedule Page: 326.2 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.2 Line No.: 10 Column: l
Settlement adjustment.
Schedule Page: 326.2 Line No.: 13 Column: l
Financial swap.
Schedule Page: 326.3 Line No.: 4 Column: b
City of Hurricane - contract termination date: August 31, 2017
Schedule Page: 326.3 Line No.: 5 Column: a
This footnote applies to all occurrences of "City of Portland, Water Bureau" on pages
326-327. Complete name is City of Portland, Portland Water Bureau.
Schedule Page: 326.3 Line No.: 12 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.: 12 Column: l
Financial swap.
Schedule Page: 326.3 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.3 Line No.: 13 Column: l
Settlement adjustment.
Schedule Page: 326.4 Line No.: 3 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.: 3 Column: b
Deseret Generation and Transmission Cooperative - contract termination date: September 30,
2024
Schedule Page: 326.4 Line No.: 3 Column: l
Reimbursement to counterparty for operation and maintenance costs at coal fired generating
facility located in Vernal, Utah.
Schedule Page: 326.4 Line No.: 4 Column: l
Financial swap.
Schedule Page: 326.4 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.4 Line No.: 7 Column: l
Settlement adjustment.
Schedule Page: 326.4 Line No.: 11 Column: l
Financial swap.
Schedule Page: 326.4 Line No.: 13 Column: l
Line loss.
Schedule Page: 326.5 Line No.: 5 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.5 Line No.: 7 Column: b
Flathead Electric Cooperative, Inc. - contract termination date: September 30, 2016
Schedule Page: 326.5 Line No.: 7 Column: l
Line loss.
Schedule Page: 326.5 Line No.: 13 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 326.6 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 326.6 Line No.: 2 Column: l
Settlement adjustment.
Schedule Page: 326.6 Line No.: 3 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 (b) of this Form
No. 1 for further information on the Hermiston Generating Plant.
Schedule Page: 326.6 Line No.: 3 Column: l
On peak incentive, supplemental dispatch efficiency expense, start-up charges and
committee settlements.
Schedule Page: 326.6 Line No.: 4 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.6 Line No.: 4 Column: l
Purchase of renewable energy credit certificates for Washington renewable portfolio
standard requirements.
Schedule Page: 326.6 Line No.: 5 Column: l
Financial swap.
Schedule Page: 326.6 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.6 Line No.: 6 Column: l
Labor, equipment and administration fees associated with hydro project in Idaho Falls,
Idaho.
Schedule Page: 326.6 Line No.: 7 Column: l
Labor, equipment and administration fees associated with hydro project in Idaho Falls,
Idaho.
Schedule Page: 326.6 Line No.: 8 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.6 Line No.: 9 Column: l
Reserve share.
Schedule Page: 326.6 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.6 Line No.: 12 Column: l
Settlement adjustment.
Schedule Page: 326.6 Line No.: 14 Column: l
Financial swap.
Schedule Page: 326.7 Line No.: 1 Column: l
Surprise Valley Electrification Corp. - contract termination date: Evergreen
Schedule Page: 326.7 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.7 Line No.: 3 Column: l
Settlement adjustment.
Schedule Page: 326.7 Line No.: 5 Column: l
Compensation for self-generation.
Schedule Page: 326.7 Line No.: 6 Column: l
Fixed annual payment.
Schedule Page: 326.7 Line No.: 7 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.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.7 Line No.: 7 Column: l
Settlement adjustment.
Schedule Page: 326.7 Line No.: 8 Column: l
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Line loss.
Schedule Page: 326.7 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.7 Line No.: 9 Column: l
Settlement adjustment.
Schedule Page: 326.7 Line No.: 13 Column: l
Financial swap.
Schedule Page: 326.8 Line No.: 4 Column: l
Compensation for interruptible service and operating reserves.
Schedule Page: 326.8 Line No.: 5 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.8 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.8 Line No.: 7 Column: l
Financial swap.
Schedule Page: 326.8 Line No.: 12 Column: l
Reserve share.
Schedule Page: 326.8 Line No.: 13 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.8 Line No.: 14 Column: l
Line loss.
Schedule Page: 326.9 Line No.: 4 Column: l
Reserve share.
Schedule Page: 326.9 Line No.: 5 Column: l
Ancillary services.
Schedule Page: 326.10 Line No.: 1 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.10 Line No.: 2 Column: l
Line loss.
Schedule Page: 326.10 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.10 Line No.: 3 Column: l
Operation expense plus amortization of unrecovered costs of Cove project.
Schedule Page: 326.10 Line No.: 4 Column: b
Portland General Electric Company - contract termination date: Round Butte project no
longer operating for power production purposes.
Schedule Page: 326.10 Line No.: 4 Column: l
Operation expense plus amortization of unrecovered costs of Cove project.
Schedule Page: 326.10 Line No.: 5 Column: l
Reserve share.
Schedule Page: 326.10 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.10 Line No.: 6 Column: l
Settlement adjustment.
Schedule Page: 326.10 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 326.10 Line No.: 8 Column: l
Settlement adjustment.
Schedule Page: 326.10 Line No.: 10 Column: l
Financial swap.
Schedule Page: 326.10 Line No.: 11 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.10 Line No.: 13 Column: l
Line loss.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 326.10 Line No.: 14 Column: a
This footnote applies to all occurrences of "PUD No. 1 of Chelan County" on pages 326-327.
Complete name is Public Utility District No. 1 of Chelan County.
Schedule Page: 326.10 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.10 Line No.: 14 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.11 Line No.: 1 Column: l
Reserve share.
Schedule Page: 326.11 Line No.: 2 Column: a
This footnote applies to all occurrences of "PUD No. 1 of Cowlitz County" on pages
326-327. Complete name is Public Utility District No. 1 of Cowlitz County.
Schedule Page: 326.11 Line No.: 2 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.11 Line No.: 2 Column: l
Liability associated with paper pond at hydro facility located on the Lewis River in
Washington.
Schedule Page: 326.11 Line No.: 3 Column: a
This footnote applies to all occurrences of "PUD No. 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.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.11 Line No.: 3 Column: l
Settlement adjustment.
Schedule Page: 326.11 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 326.11 Line No.: 4 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.11 Line No.: 5 Column: b
Public Utility District No. 1 of Douglas County - contract termination date: August 31,
2018
Schedule Page: 326.11 Line No.: 6 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.11 Line No.: 7 Column: l
Reserve share.
Schedule Page: 326.11 Line No.: 8 Column: a
This footnote applies to all occurrences of "PUD No. 1 of Snohomish County" on pages
326-327. Complete name is Public Utility District No. 1 of Snohomish County.
Schedule Page: 326.11 Line No.: 9 Column: a
This footnote applies to all occurrences of "PUD No. 2 of Grant County" on pages 326-327.
Complete name is Public Utility District No. 2 of Grant County.
Schedule Page: 326.11 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.11 Line No.: 9 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.11 Line No.: 10 Column: b
Public Utility District No. 2 of Grant County - contract termination date: August 15, 2012
Schedule Page: 326.11 Line No.: 10 Column: l
Ancillary services.
Schedule Page: 326.11 Line No.: 11 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.11 Line No.: 12 Column: l
Reserve share.
Schedule Page: 326.11 Line No.: 13 Column: l
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Reserve share.
Schedule Page: 326.12 Line No.: 5 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: 326.12 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.12 Line No.: 8 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.12 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.12 Line No.: 9 Column: l
Settlement adjustment.
Schedule Page: 326.12 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.12 Line No.: 12 Column: l
Settlement adjustment.
Schedule Page: 326.12 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.12 Line No.: 14 Column: l
Settlement adjustment.
Schedule Page: 326.13 Line No.: 1 Column: b
Sacramento Municipal Utility District - contract termination date: December 31, 2014
Schedule Page: 326.13 Line No.: 3 Column: l
Line loss.
Schedule Page: 326.13 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.13 Line No.: 7 Column: l
Settlement of Pacific Northwest Refund case.
Schedule Page: 326.13 Line No.: 8 Column: l
Reserve share.
Schedule Page: 326.13 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.13 Line No.: 10 Column: l
Financial swap.
Schedule Page: 326.13 Line No.: 12 Column: l
Financial swap.
Schedule Page: 326.13 Line No.: 14 Column: l
Reserve share.
Schedule Page: 326.14 Line No.: 1 Column: l
Line loss.
Schedule Page: 326.14 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.14 Line No.: 3 Column: l
Settlement adjustment.
Schedule Page: 326.14 Line No.: 10 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.14 Line No.: 12 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.15 Line No.: 1 Column: l
Reserve share.
Schedule Page: 326.15 Line No.: 2 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.15 Line No.: 12 Column: a
This footnote applies to all occurrences of "Tri-State Gen. & Trans." on pages 326-327.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
Complete name is Tri-State Generation and Transmission Association, Inc.
Schedule Page: 326.15 Line No.: 12 Column: b
Tri-State Generation and Transmission Association, Inc. - contract termination date:
December 31, 2020
Schedule Page: 326.15 Line No.: 13 Column: l
Line loss.
Schedule Page: 326.15 Line No.: 14 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.15 Line No.: 14 Column: l
Purchase of renewable energy credit certificates for state of Washington renewable
portfolio standard requirements.
Schedule Page: 326.16 Line No.: 1 Column: l
Line loss.
Schedule Page: 326.16 Line No.: 3 Column: b
US Magnesium LLC - contract termination date: December 31, 2014
Schedule Page: 326.16 Line No.: 3 Column: l
Ancillary services.
Schedule Page: 326.16 Line No.: 5 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.: 9 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: 326.16 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.16 Line No.: 9 Column: l
Settlement adjustment.
Schedule Page: 326.16 Line No.: 12 Column: b
Western Area Power Administration - contract termination date: May 31, 2022
Schedule Page: 326.16 Line No.: 12 Column: l
Westport Field Services, LLC - contract termination date: Evergreen
Schedule Page: 326.16 Line No.: 13 Column: l
Line loss.
Schedule Page: 326.16 Line No.: 14 Column: l
Reserve share.
Schedule Page: 326.17 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.17 Line No.: 3 Column: l
Settlement adjustment.
Schedule Page: 326.17 Line No.: 5 Column: l
Reserve for liabilities associated with the Pacific Northwest Refund case.
Schedule Page: 326.17 Line No.: 6 Column: l
Reflects transactions that did not physically settle.
Schedule Page: 326.17 Line No.: 7 Column: l
Reflects transactions that did not physically settle.
Schedule Page: 326.17 Line No.: 8 Column: l
Deferrals and associated amortization under various energy cost adjustment mechanisms.
Schedule Page: 326.17 Line No.: 9 Column: l
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,
Purchased power, during this period.
Schedule Page: 326.17 Line No.: 12 Column: l
Exchange energy expense.
Schedule Page: 326.17 Line No.: 14 Column: l
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
Imbalance energy.
Schedule Page: 326.18 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 326.18 Line No.: 2 Column: l
Exchange energy expense.
Schedule Page: 326.18 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.18 Line No.: 3 Column: l
Imbalance energy.
Schedule Page: 326.18 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 326.18 Line No.: 4 Column: l
Imbalance energy.
Schedule Page: 326.18 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 326.18 Line No.: 5 Column: l
Storage and exchange charges.
Schedule Page: 326.18 Line No.: 6 Column: l
Storage and exchange charges.
Schedule Page: 326.18 Line No.: 7 Column: l
Storage and exchange charges.
Schedule Page: 326.18 Line No.: 9 Column: l
Exchange energy expense.
Schedule Page: 326.18 Line No.: 11 Column: c
Pacific Northwest Electric Power Planning and Conservation Act, FERC Electric Tariff,
Original Volume No. 1.
Schedule Page: 326.18 Line No.: 11 Column: h
These megawatt hours represent book entry only. No actual energy transfer took place.
Schedule Page: 326.18 Line No.: 11 Column: i
These megawatt hours represent book entry only. No actual energy transfer took place.
Schedule Page: 326.18 Line No.: 11 Column: l
Pacific Northwest Electric Power Planning and Conservation Act, FERC Electric Tariff,
Original Volume No. 1.
Schedule Page: 326.18 Line No.: 12 Column: l
Imbalance energy.
Schedule Page: 326.18 Line No.: 13 Column: l
Imbalance energy.
Schedule Page: 326.18 Line No.: 14 Column: l
Exchange energy expense.
Schedule Page: 326.19 Line No.: 1 Column: l
Imbalance energy.
Schedule Page: 326.19 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 326.19 Line No.: 2 Column: l
Imbalance energy.
Schedule Page: 326.19 Line No.: 4 Column: l
Imbalance energy.
Schedule Page: 326.19 Line No.: 5 Column: l
Storage and exchange charges.
Schedule Page: 326.19 Line No.: 6 Column: l
Exchange energy expense.
Schedule Page: 326.19 Line No.: 7 Column: l
Imbalance energy.
Schedule Page: 326.19 Line No.: 9 Column: l
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
Imbalance energy.
Schedule Page: 326.19 Line No.: 10 Column: l
Station service for third party wind project.
Schedule Page: 326.19 Line No.: 11 Column: l
Reimbursement for providing station service to third party wind project.
Schedule Page: 326.19 Line No.: 12 Column: l
Reimbursement for providing station service to third party wind project.
Schedule Page: 326.19 Line No.: 13 Column: l
Imbalance energy.
Schedule Page: 326.19 Line No.: 14 Column: l
Imbalance energy.
Schedule Page: 326.20 Line No.: 3 Column: l
Storage and exchange charges.
Schedule Page: 326.20 Line No.: 4 Column: l
Exchange energy expense.
Schedule Page: 326.20 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.20 Line No.: 7 Column: l
Exchange energy expense.
Schedule Page: 326.20 Line No.: 8 Column: l
Imbalance energy.
Schedule Page: 326.20 Line No.: 9 Column: a
This footnote applies to all occurrences of "Southern California Public Power Auth." on
pages 326-327. Complete name is Southern California Public Power Authority.
Schedule Page: 326.20 Line No.: 9 Column: l
Imbalance energy.
Schedule Page: 326.20 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.20 Line No.: 10 Column: l
Imbalance energy.
Schedule Page: 326.20 Line No.: 11 Column: l
Imbalance energy.
Schedule Page: 326.20 Line No.: 12 Column: l
Imbalance energy.
Schedule Page: 326.20 Line No.: 13 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: 326.20 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.20 Line No.: 13 Column: l
Imbalance energy.
Schedule Page: 326.20 Line No.: 14 Column: l
Imbalance energy.
Schedule Page: 326.21 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 326.21 Line No.: 1 Column: l
Imbalance energy.
Schedule Page: 326.21 Line No.: 2 Column: l
Imbalance energy.
Schedule Page: 326.21 Line No.: 3 Column: l
Imbalance energy.
Schedule Page: 326.21 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 326.21 Line No.: 4 Column: l
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
Imbalance energy.
Schedule Page: 326.21 Line No.: 5 Column: l
Imbalance energy.
Schedule Page: 326.21 Line No.: 6 Column: b
Not applicable - adjustment for inadvertent interchange.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX / /2012/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
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.
Alpental Energy Partners, LLC Alpental Energy Partners, LLC LFP 1
Arizona Public Service Company Arizona Public Service Company OS 2
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation FNO 3
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation AD 4
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation SFP 5
Black Hills/Colorado Electric Utility Company NF 6
Black Hills/Colorado Electric Utility Company SFP 7
Black Hills Corporation Montana-Dakota Utilities FNO 8
Black Hills Corporation Montana-Dakota Utilities AD 9
Black Hills Corporation NF 10
Black Hills Corporation AD 11
Black Hills Corporation SFP 12
Black Hills Corporation AD 13
Black Hills Corporation Black Hills Corporation LFP 14
Black Hills Corporation Black Hills Corporation AD 15
Bonneville Power Administration OS 16
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 17
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 18
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration LFP 19
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 20
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative FNO 21
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative AD 22
Bonneville Power Administration Bonneville Power Administration Benton REA FNO 23
Bonneville Power Administration Bonneville Power Administration Benton REA AD 24
Bonneville Power Administration Bonneville Power Administration Umatilla Electric & Columbia FNO 25
Bonneville Power Administration Bonneville Power Administration Umatilla Electric & Columbia AD 26
Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration LFP 27
Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration AD 28
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 29
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 30
Bonneville Power Administration Bonneville Power Administration Yakama Power FNO 31
Bonneville Power Administration Bonneville Power Administration Yakama Power AD 32
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 33
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 34
FERC FORM NO. 1 (ED. 12-90) Page 328
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2012/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
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.
South Milford SubV11-7 Mona Substation 3 1
R.S. 436 Borah/Brady Sub 2
Yellowtail SubV11-1,2,3 Sheridan Substation 3,921 3,921 3
Yellowtail SubV11-3 Sheridan Substation 1 456 456 4
VariousV11-1,2 Various 50 50 5
VariousV11-1,2 Various 1,674 1,674 6
VariousV11-1,2 Various 381 381 7
VariousV11-1,2 Sheridan Substation 44 6,516 6,516 8
VariousV11 Sheridan Substation 44 2,732 2,732 9
VariousV11-1,2,8 Various 7,636 7,636 10
VariousV11 Various 24 24 11
VariousV11-1,2,7 Various 18,785 18,785 12
VariousV11-7 Various 522 522 13
VariousV11-1,2,7 Wyodak Substation 53 185,511 185,511 14
VariousV11-7 Wyodak Substation 50 14,039 14,039 15
Midpoint SubstationR.S. 369 Summer Lake Sub 16
VariousR.S. 237 Various 305 1,083,128 1,083,128 17
VariousR.S. 237 Various 322 121,322 121,322 18
Lost Creek Hydro PltV11-2,7 Alvey Substation 59 183,831 183,831 19
Lost Creek Hydro PltV11-7 Alvey Substation 56 15,731 15,731 20
Bonneville Power AdmV11-1,2,3,4 Gazley Substation 3 23,452 23,452 21
Bonneville Power AdmV11 -3 Gazley Substation 3 2,317 2,317 22
Bonneville Power AdmV11-1,2,3 Tieton Substation 1 5,849 5,849 23
Bonneville Power AdmV11-3 Tieton Substation 1 889 889 24
McNary SubstationV11-1,2,3 Hinkle Substation 1 999 999 25
McNary SubstationV11-3 Hinkle Substation 1 190 190 26
USBR Green SpringsV11-2,7 Bonneville Power Adm 19 62,636 62,636 27
USBR Green SpringsV11-7 Bonneville Power Adm 18 4,176 4,176 28
Malin SubstationR.S. 368 Malin Substation 511,114 511,114 29
Malin SubstationR.S. 368 Malin Substation 57,817 57,817 30
Bonneville Power AdmV11-1,2,3,4 White Swan/Toppenish 5 32,223 32,223 31
Bonneville Power AdmV11-3,4 White Swan/Toppenish 5 3,186 3,186 32
VariousR.S. 299 Various 214 1,011,575 1,011,575 33
VariousR.S. 299 Various 212 197,504 197,504 34
FERC FORM NO. 1 (ED. 12-90) Page 329
4,227 13,731,215 13,615,562
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
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.
6,231 6,231 1
2
7,827 21,632 13,805 3
2,895 2,895 4
160 11 149 5
1,171 77 1,094 6
206 14 192 7
1,003,007 1,074,118 71,111 8
59,131 59,131 9
16,845 1,090 15,755 10
140 140 11
79,501 5,522 73,979 12
707 707 13
1,188,180 1,272,444 84,264 14
101,250 101,250 15
16
3,755,126 3,823,073 67,947 17
349,970 349,970 18
1,330,762 1,392,208 61,446 19
113,400 113,400 20
70,996 223,451 152,455 21
16,882 16,882 22
14,738 18,182 3,444 23
1,144 1,144 24
2,917 3,603 686 25
248 248 26
427,745 447,496 19,751 27
36,450 36,450 28
246,944 246,944 29
22,450 22,450 30
116,528 234,900 118,372 31
14,982 14,982 32
886,376 1,910,949 1,024,573 33
-64,126 -64,126 34
FERC FORM NO. 1 (ED. 12-90) Page 330
31,456,537 76,416,197 28,939,781 16,019,879
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX / /2012/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
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.
Bonneville Power Administration NF 1
Bonneville Power Administration AD 2
Bonneville Power Administration SFP 3
Bonneville Power Administration Bonneville Power Administration Clark Public Utilities FNO 4
Bonneville Power Administration Bonneville Power Administration Clark Public Utilities AD 5
Cargill Power Markets, LLC NF 6
Cargill Power Markets, LLC AD 7
Cargill Power Markets, LLC SFP 8
Constellation Energy Commodities Group NF 9
Constellation Energy Commodities Group AD 10
Constellation Energy Commodities Group SFP 11
Coral Power NF 12
Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration OS 13
Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration AD 14
Cyrq Energy, Inc.LFP 15
Cyrq Energy, Inc.AD 16
Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans.OS 17
Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans.AD 18
Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans.OS 19
Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans.AD 20
EDF Trading North America, LLC NF 21
EDF Trading North America, LLC SFP 22
Eugene Water & Electric Board NF 23
Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company OS 24
Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company AD 25
Foote Creek III, LLC Foote Creek III, LLC OS 26
Foote Creek III, LLC Foote Creek III, LLC AD 27
Iberdrola Renewables, LLC Iberdrola Renewables, LLC Iberdrola Renewables, LLC LFP 28
Iberdrola Renewables, LLC Iberdrola Renewables, LLC Iberdrola Renewables, LLC LFP 29
Iberdrola Renewables, LLC Iberdrola Renewables, LLC Iberdrola Renewables, LLC LFP 30
Iberdrola Renewables, LLC Iberdrola Renewables, LLC Iberdrola Renewables, LLC LFP 31
Iberdrola Renewables, LLC Iberdrola Renewables, LLC Iberdrola Renewables, LLC LFP 32
Iberdrola Renewables, LLC NF 33
Iberdrola Renewables, LLC AD 34
FERC FORM NO. 1 (ED. 12-90) Page 328.1
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2012/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
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.
VariousV11-1,2,8 Various 2,100 2,100 1
VariousV11-8 Various 3 3 2
VariousV11-1,2,7 Various 299 299 3
Cardwell-MerwinV11-1,2,3,4 16 108,019 108,019 4
Cardwell-MerwinV11-3,4 19 15,255 15,255 5
VariousV11-1,2,3,8 Various 206,647 206,647 6
VariousV11-8 Various 7
VariousV11-1,2,7 Various 4,695 4,695 8
VariousV11-1-3,5-8 Various 95,346 95,346 9
VariousV11-8 Various 18,403 18,403 10
VariousV11-1,2,3,5,6,7 Various 11
VariousV11-1-3,8 Various 6,059 6,059 12
Swift Unit No. 2R.S. 234 Woodland Substation 13
Swift Unit No. 2R.S. 234 Woodland Substation 14
South Milford SubV11-1-3,5-7,9 Mona Substation 12 42,383 42,383 15
South Milford SubV11-5,6,7 Mona Substation 11 4,482 4,482 16
VariousR.S. 280 Various 90 706,217 706,217 17
VariousR.S. 280 Various 93 48,600 48,600 18
VariousR.S. 590 Various 19
VariousR.S. 590 Various 20
VariousV11-1,2,8 Various 1,908 1,908 21
VariousV11-1,2,7 Various 400 400 22
VariousV11-1,2,8 Various 8 8 23
Targhee SubstationR.S. 322 Goshen Substation 22,332 22,332 24
Targhee SubstationR.S. 322 Goshen Substation 2,907 2,907 25
Foote Creek SubS.A. 130 Various 26
Foote Creek SubS.A. 130 Various 27
Malin 500 SubstationV11-7 Round Mountain Sub 12 28
Malin 500 SubstationV11-7 Round Mountain Sub 38 29
Malin 500 SubstationV11-7 Round Mountain Sub 37 30
Malin 500 SubstationV11-7 Round Mountain Sub 37 31
Lakeview SubstationV11-7 Round Mountain Sub 26 32
VariousV11-1,2,8,9,11 Various 230,440 230,440 33
VariousV11-8,9,11 Various 132 132 34
FERC FORM NO. 1 (ED. 12-90) Page 329.1
4,227 13,731,215 13,615,562
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
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.
40,771 2,782 37,989 1
18 18 2
1,960 130 1,830 3
359,396 445,355 85,959 4
28,197 28,197 5
1,218,160 78,540 1,139,620 6
2,025 2,025 7
28,754 1,784 26,970 8
242,723 239,718 3,005 9
7,761 7,761 10
114 31 83 11
37,572 2,770 34,802 12
109,498 109,498 13
9,869 9,869 14
261,400 358,992 97,592 15
25,623 25,623 16
2,078,706 3,342,456 1,263,750 17
229,243 229,243 18
136,753 136,753 19
142,733 142,733 20
18,944 1,256 17,688 21
10,605 630 9,975 22
29 2 27 23
138,699 138,699 24
12,609 12,609 25
33,167 33,167 26
3,015 3,015 27
24,300 24,300 28
76,950 76,950 29
74,925 74,925 30
74,925 74,925 31
52,650 52,650 32
2,231,931 237,974 1,993,957 33
2,969 2,969 34
FERC FORM NO. 1 (ED. 12-90) Page 330.1
31,456,537 76,416,197 28,939,781 16,019,879
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX / /2012/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
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.
Iberdrola Renewables, LLC Iberdrola Renewables, LLC OS 1
Iberdrola Renewables, LLC Iberdrola Renewables, LLC AD 2
Iberdrola Renewables, LLC Exxon Mobil Nevada Power Company LFP 3
Iberdrola Renewables, LLC Exxon Mobil Nevada Power Company AD 4
Idaho Power Company Idaho Power Company Idaho Power Company OS 5
Idaho Power Company OS 6
Idaho Power Company AD 7
Idaho Power Company OS 8
Idaho Power Company AD 9
Idaho Power Company NF 10
Idaho Power Company AD 11
Idaho Power Company SFP 12
Idaho Power Company Exxon Mobil Nevada Power Company LFP 13
JP Morgan Ventures Energy Corp.NF 14
JP Morgan Ventures Energy Corp.AD 15
JP Morgan Ventures Energy Corp.SFP 16
Los Angeles Dept of Water & Power NF 17
Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association OS 18
Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association AD 19
Morgan Stanley Capital Group, Inc.NF 20
Morgan Stanley Capital Group, Inc.AD 21
Morgan Stanley Capital Group, Inc.SFP 22
NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD LFP 23
NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD AD 24
NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD NF 25
NextEra Energy Resources, LLC AD 26
Nevada Power Company AD 27
Noble Americas Energy Solutions LLC Bonneville Power Administration Oregon Direct Access FNO 28
Noble Americas Energy Solutions LLC Bonneville Power Administration Oregon Direct Access AD 29
Pacific Gas & Electric Company OS 30
Pacific Gas & Electric Company AD 31
Pacific Gas & Electric Company NextEra Energy Resources, LLC Grant County PUD NF 32
Pacific Gas & Electric Company OS 33
Portland General Electric Company OS 34
FERC FORM NO. 1 (ED. 12-90) Page 328.2
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2012/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
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.
V11-5,6 1
V11-5,6 2
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 32 70,563 70,563 3
Trona SubstationV11-7 Red Butte/Mona Sub 30 7,303 7,303 4
Goshen SubstationR.S. 427 Goshen Substation 5
Antelope SubstationR.S. 257 Antelope Substation 181,868 181,868 6
Antelope SubstationR.S. 257 Antelope Substation 22,638 22,638 7
Jim Bridger SubR.S. 203 Bridger Pump Sub 29,746 29,746 8
Jim Bridger SubR.S. 203 Bridger Pump Sub 9
VariousV11-1,2,8 Various 51,784 51,784 10
VariousV11-8 Various 905 905 11
VariousV11-1,2,7 Various 7,438 7,438 12
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 79 25,450 25,450 13
VariousV11-1,2,3,8,9 Various 71,193 71,193 14
VariousV11-8,9 Various 3,474 3,474 15
VariousV11-1,2,7 Various 25 25 16
VariousV11-1,2,8 Various 5,392 5,392 17
DuchesneR.S. 302 Duchesne 3 18,808 18,808 18
DuchesneR.S. 302 Duchesne 3 1,598 1,598 19
VariousV11-1,2,3,8 Various 147,443 147,443 20
VariousV11-8 Various 12,455 12,455 21
VariousV11-1,2,7 Various 25,458 25,458 22
Wallula Substation Wala-MIDC Path 84 157,291 157,291 23
Wallula SubstationV11-5,6,7,9,11 Wala-MIDC Path 80 58 58 24
VariousV11-1,2,3,8 Various 647 647 25
VariousV11-8 Various 26
VariousV11-8 Various 27
Bonneville Power AdmV11-1,2,3,4 Various 27 189,509 189,509 28
Bonneville Power AdmV11-1,2,3,4 Various 12 7,692 7,692 29
R.S. 607 30
R.S. 607 31
VariousV11-1,2,8 Various 34 34 32
Sigurd-Glen CanyonR.S. 298 Pinto-Four Corners 33
Dalreed SubstationR.S. 137 Dalreed Substation 34
FERC FORM NO. 1 (ED. 12-90) Page 329.2
4,227 13,731,215 13,615,562
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
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.
233,786 233,786 1
17,152 17,152 2
712,908 763,467 50,559 3
60,750 60,750 4
5
67,672 67,672 6
6,152 6,152 7
14,927 14,927 8
1,357 1,357 9
317,896 19,934 297,962 10
5,928 5,928 11
81,010 5,210 75,800 12
807,975 865,069 57,094 13
1,089,739 207,165 882,574 14
81,088 81,088 15
166 11 155 16
50,347 3,050 47,297 17
19,576 19,576 18
1,845 1,845 19
898,755 59,804 838,951 20
62,766 62,766 21
447,289 16,575 430,714 22
1,504,251 2,990,349 1,486,098 23
189,325 189,325 24
35,200 5,924 29,276 25
7,493 7,493 26
6 6 27
341,913 428,796 86,883 28
10,199 10,199 29
15,125,000 15,125,000 30
1,375,000 1,375,000 31
522 34 488 32
284,922 284,922 33
3,314 3,314 34
FERC FORM NO. 1 (ED. 12-90) Page 330.2
31,456,537 76,416,197 28,939,781 16,019,879
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX / /2012/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
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.
Powder River Energy Corporation Western Area Power Administration Sheridan-Johnson Rural Elect.OS 1
Powder River Energy Corporation Western Area Power Administration Sheridan-Johnson Rural Elect.AD 2
Powerex Corporation Bonneville Power Administration CAISO LFP 3
Powerex Corporation Bonneville Power Administration CAISO AD 4
Powerex Corporation Powerex Corporation CAISO LFP 5
Powerex Corporation Powerex Corporation CAISO LFP 6
Powerex Corporation Powerex Corporation CAISO LFP 7
Powerex Corporation NF 8
Powerex Corporation AD 9
Powerex Corporation SFP 10
PPL Energy Plus, LLC NF 11
PPL Energy Plus, LLC AD 12
PPL Energy Plus, LLC SFP 13
Puget Sound P&L AD 14
Rainbow Energy Marketing Corporation NF 15
Rainbow Energy Marketing Corporation SFP 16
Sacramento Municipal Utility District LFP 17
Seattle City Light FPL Energy Vansycle, LLC Grant County PUD LFP 18
Seattle City Light FPL Energy Vansycle, LLC Grant County PUD AD 19
Sierra Pacific Power Company d/b/a NV OS 20
Sierra Pacific Power Company d/b/a NV AD 21
Sierra Pacific Power Company d/b/a NV NF 22
Sierra Pacific Power Company d/b/a NV SFP 23
Southern California Edison Company SFP 24
Southern California Edison Company AD 25
Southern California Edison Company NF 26
Southern California Edison Company AD 27
Southern California Edison Company OS 28
Southern California Public Power Powerex Corporation Southern California Public Power OS 29
State of South Dakota Western Area Power Administration Black Hills Corporation LFP 30
State of South Dakota Western Area Power Administration Black Hills Corporation AD 31
Tenaska Power Services Co.NF 32
Tenaska Power Services Co.SFP 33
The Energy Authority, Inc.NF 34
FERC FORM NO. 1 (ED. 12-90) Page 328.3
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2012/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
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.
VariousR.S. 123 Buffalo Substation 1
VariousR.S. 123 Buffalo Substation 2
Bonneville Power AdmV11-1,2,7 CRAG View Substation 84 425,204 425,204 3
Bonneville Power AdmV11-7 CRAG View Substation 80 14,453 14,453 4
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 5
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 6
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 7
VariousV11-1,2,8 Various 1,114,384 1,114,384 8
VariousV11-8 Various 1,546 1,546 9
VariousV11-1,2,7 Various 116,395 116,395 10
VariousV11-1,2,8 Various 4,906 4,906 11
VariousV11-8 Various 40 40 12
VariousV11-1,2,7 Various 935 935 13
VariousV11-8 Various 14
VariousV11-1,2,8 Various 39,492 39,492 15
VariousV11-1,2,7 Various 6,346 6,346 16
V11-7 60 17
Wallula SubstationV11-1,2,3,5,6,7 Wala-MIDC Path 6 18
Wallula SubstationV11-5,6,7,9 Wala-MIDC Path 25 2,638 2,638 19
Sigurd SubstationR.S. 674 Utah-Nevada Border 20
Sigurd SubstationR.S. 674 Utah-Nevada Border 21
VariousV11-1,2,8 Various 8,150 8,150 22
VariousV11-1,2,7 Various 11,304 11,304 23
VariousV11-1-3,5-7 Various 46,852 46,852 24
VariousV11-5,6,7 Various 9,030 9,030 25
VariousV11-1-3,8,9,11 Various 235,094 235,094 26
VariousV11-8,9 Various 9,791 9,791 27
Sigurd-Glen CanyonR.S. 298 Pinto-Four Corners 28
Tieton SubstationV11-9,11 Various 322 322 29
Yellowtail SubV11-1,2,7 Wyodak Substation 4 18,209 18,209 30
Yellowtail SubV11-7 Wyodak Substation 4 1,638 1,638 31
VariousV11-1,2,8 Various 14,272 14,272 32
VariousV11-1-2, 3-6,7 Various 13,478 13,478 33
VariousV11-1,2,8 Various 1,219 1,219 34
FERC FORM NO. 1 (ED. 12-90) Page 329.3
4,227 13,731,215 13,615,562
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
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.
327 327 1
30 30 2
1,902,096 1,926,171 24,075 3
162,000 162,000 4
822,000 861,200 39,200 5
822,000 861,200 39,200 6
822,000 861,200 39,200 7
5,675,564 379,752 5,295,812 8
18,086 18,086 9
1,883,097 102,420 1,780,677 10
28,569 1,871 26,698 11
234 234 12
5,097 337 4,760 13
6 6 14
167,229 10,561 156,668 15
32,552 1,986 30,566 16
121,500 121,500 17
26,006 35,670 9,664 18
54,044 54,044 19
68,919 68,919 20
6,265 6,265 21
49,656 3,222 46,434 22
52,487 3,250 49,237 23
567,974 155,680 412,294 24
106,861 106,861 25
2,141,661 621,721 1,519,940 26
87,854 87,854 27
284,922 284,922 28
14,922 14,922 29
95,054 101,795 6,741 30
8,100 8,100 31
73,802 4,582 69,220 32
58,795 4,085 54,710 33
4,623 306 4,317 34
FERC FORM NO. 1 (ED. 12-90) Page 330.3
31,456,537 76,416,197 28,939,781 16,019,879
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX / /2012/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
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.
TransAlta Energy Marketing NF 1
TransAlta Energy Marketing AD 2
Tri-State Generation & Trans. Tri-State Generation & Trans.OS 3
Tri-State Generation & Trans. Tri-State Generation & Trans AD 4
Tri-State Generation & Trans. Tri-State Generation & Trans.FNO 5
Tri-State Generation & Trans. Tri-State Generation & Trans AD 6
Tri-State Generation & Trans.NF 7
Tri-State Generation & Trans.AD 8
Tri-State Generation & Trans.SFP 9
U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation FNO 10
U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation AD 11
U.S. Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District OS 12
U.S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.OS 13
U.S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.AD 14
Utah Associated Municipal Power Utah Associated Municipal Power Utah Associated Municipal Power OS 15
Utah Associated Municipal Power Utah Associated Municipal Power Utah Associated Municipal Power AD 16
Utah Associated Municipal Power NF 17
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency OS 18
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency AD 19
Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric OS 20
Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric AD 21
Western Area Power Administration Western Area Power Administration OS 22
Western Area Power Administration Western Area Power Administration AD 23
Western Area Power Administration Western Area Power Administration OS 24
Western Area Power Administration Western Area Power Administration AD 25
Western Area Power Adm. CO MO Western Area Power Adm. CO MO NF 26
Western Area Power Adm. CO MO Western Area Power Adm. CO MO SFP 27
Western Area Power Adm. CO MO Western Area Power Adm. CO MO AD 28
Western Area Power Administration Western Area Power Administration OS 29
Western Area Power Administration Western Area Power Administration Western Area Power Administration FNO 30
Western Area Power Administration Western Area Power Administration Western Area Power Administration AD 31
Western Area Power Adm. CO River Western Area Power Adm. CO River NF 32
Western Area Power Adm. CO River Western Area Power Adm. CO River AD 33
Yakima-Tieton Irrigation District Yakima-Tieton Irrigation District Yakima-Tieton Irrigation District LFP 34
FERC FORM NO. 1 (ED. 12-90) Page 328.4
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2012/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
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.
VariousV11-1,2,8 Various 26,103 26,103 1
VariousV11-8 Various 339 339 2
VariousR.S. 123 Various 36 158,202 158,202 3
VariousR.S. 123 Various 38 15,952 15,952 4
Dave Johnston SubV11-1,2,3,4 Thermopolis Sub 9 65,771 65,771 5
Dave Johnston SubV11-3,4 Thermopolis Sub 17 350 350 6
VariousV11-1,2,8 Various 44,066 44,066 7
VariousV11-8 Various 20 20 8
VariousV11-1,2,7 Various 1,773 1,773 9
Walla Walla SubV11-1,2,3 Burbank Pumps 1 2,198 2,198 10
Walla Walla SubV11-3 Burbank Pumps 1 3 3 11
Redmond SubstationR.S. 67 Crooked River Pumps 7 9,819 9,819 12
VariousR.S. 286 Various 20,488 20,488 13
VariousR.S. 286 Various 986 986 14
VariousR.S. 297 Various 348 2,219,634 2,219,634 15
VariousR.S. 297 Various 317 156,293 156,293 16
VariousV11-1,2,3,8 Various 8,716 8,716 17
VariousR.S. 637 Various 113 541,292 541,292 18
VariousR.S. 637 Various 100 44,850 44,850 19
Pelton ReregulatingR.S. 591 Round Butte Sub 84,469 84,469 20
Pelton ReregulatingR.S. 591 Round Butte Sub 7,872 7,872 21
VariousR.S. 262 Various 330 1,682,325 1,582,726 22
VariousR.S. 262 Various 330 208,005 195,920 23
VariousR.S. 263 Various 86,344 81,078 24
VariousR.S. 263 Various 13,902 13,112 25
VariousV11-1,2,8 Various 9,765 9,765 26
VariousV11-1,2,7 Various 30,405 30,405 27
Various7V11-7 Various 3,988 3,988 28
Dave Johnston SubR.S. 664 Various 29
Wyoming DistributionV11-1,2 Wyoming Distribution 2 12,299 12,299 30
Wyoming DistributionV11 Wyoming Distribution 1 2 2 31
VariousV11-1,2,8 Various 198 198 32
VariousV11-8 Various 2 2 33
Tieton-MidC PathV11-7 Enterprise 3 34
FERC FORM NO. 1 (ED. 12-90) Page 329.4
4,227 13,731,215 13,615,562
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
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.
181,136 11,686 169,450 1
2,272 2,272 2
124,763 124,763 3
13,541 13,541 4
197,065 253,274 56,209 5
29,491 29,491 6
227,820 13,787 214,033 7
117 117 8
19,738 1,272 18,466 9
7,159 19,125 11,966 10
1,189 1,189 11
11,319 11,319 12
23,815 23,815 13
1,839 1,839 14
7,305,957 8,559,281 1,253,324 15
592,202 592,202 16
57,510 10,569 46,941 17
2,439,363 2,997,933 558,570 18
185,170 185,170 19
109,725 109,725 20
9,975 9,975 21
1,973,539 2,523,539 550,000 22
230,167 230,167 23
53,320 53,320 24
7,722 7,722 25
45,975 2,826 43,149 26
122,747 7,771 114,976 27
19,530 19,530 28
29
37,465 89,152 51,687 30
5,099 5,099 31
1,285 86 1,199 32
140 140 33
6,075 6,075 34
FERC FORM NO. 1 (ED. 12-90) Page 330.4
31,456,537 76,416,197 28,939,781 16,019,879
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX / /2012/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
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.
Accrual 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.5
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2012/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
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.
63,493 65,580 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.5
4,227 13,731,215 13,615,562
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
PacifiCorp X / /2012/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
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.
-2,561,996 -2,561,996 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.5
31,456,537 76,416,197 28,939,781 16,019,879
Schedule Page: 328 Line No.: 1 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 1 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 669) terminating on December 31, 2032. Customer subsequently terminated
contract effective May 29, 2012.
Schedule Page: 328 Line No.: 1 Column: m
Extension of commencement date fee.
Schedule Page: 328 Line No.: 2 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 2 Column: d
Legacy contract executed between PacifiCorp and Arizona Public Service Company concerning
the exchange of transmission services over agreed-upon facilities (Restated Transmission
Service Agreement between PacifiCorp and Arizona Public Service Company, Rate Schedule
436). The contract terminates October 31, 2020. See also page 332, Transmission of
electricity by others, of this Form No. 1.
Schedule Page: 328 Line No.: 2 Column: f
Glen Canyon/Four Corners Substation.
Schedule Page: 328 Line No.: 3 Column: d
Network transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 505) terminating no earlier than 12 months from notice by the customer.
Schedule Page: 328 Line No.: 3 Column: m
Distribution voltage service charge. Primary delivery service. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Regulation and
frequency response service.
Schedule Page: 328 Line No.: 4 Column: d
Network transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 505) terminating no earlier than 12 months from notice by the customer.
Schedule Page: 328 Line No.: 4 Column: m
Distribution voltage service charge. Primary delivery service. Regulation and
frequency response service. December 2011 service.
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.
Schedule Page: 328 Line No.: 5 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule 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.
Schedule Page: 328 Line No.: 6 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 6 Column: c
Various signatories to the 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.: 6 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 7 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 7 Column: c
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule 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.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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 (2nd Revised
Service Agreement 347) terminating on December 31, 2017.
Schedule Page: 328 Line No.: 8 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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 (2nd Revised
Service Agreement 347) terminating on December 31, 2017.
Schedule Page: 328 Line No.: 9 Column: m
December 2011 service.
Schedule Page: 328 Line No.: 10 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 10 Column: c
Various signatories to the 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.: 10 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 11 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 11 Column: c
Various signatories to the 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
December 2011 service.
Schedule Page: 328 Line No.: 12 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 12 Column: c
Various signatories to the 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.: 12 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 13 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 328 Line No.: 13 Column: c
Various signatories to the 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.
Schedule Page: 328 Line No.: 13 Column: m
December 2011 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 (2nd Revised
Service Agreement 67) terminating on December 31, 2023.
Schedule Page: 328 Line No.: 14 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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 (2nd Revised
Service Agreement 67) terminating on December 31, 2023.
Schedule Page: 328 Line No.: 15 Column: m
December 2011 service.
Schedule Page: 328 Line No.: 16 Column: b
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.
Schedule Page: 328 Line No.: 16 Column: c
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.
Schedule Page: 328 Line No.: 16 Column: d
Legacy contract executed between PacifiCorp and Bonneville Power Administration ("BPA")
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 page 332,
Transmission of electricity by others, of this Form No. 1.
Schedule Page: 328 Line No.: 17 Column: d
Legacy contract (2nd Revised Rate Schedule 237) executed between PacifiCorp and 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
or facilities charge.
Schedule Page: 328 Line No.: 18 Column: d
Legacy contract (2nd Revised Rate Schedule 237) executed between PacifiCorp and 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.: 18 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2011 service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 328 Line No.: 19 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 656) terminating on August 31, 2030.
Schedule Page: 328 Line No.: 19 Column: m
Reactive supply and voltage control service.
Schedule Page: 328 Line No.: 20 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 656) terminating on August 31, 2030.
Schedule Page: 328 Line No.: 20 Column: m
December 2011 service.
Schedule Page: 328 Line No.: 21 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (6th 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. Penalty revenues covering
imbalance charges per Schedules 4 and 9. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Regulation and frequency response service.
Schedule Page: 328 Line No.: 22 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (6th Revised Service Agreement 229) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 22 Column: m
Distribution voltage service charge. Primary delivery service. Regulation and frequency
response service. December 2011 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 service and distribution delivery service under the Open Access
Transmission Tariff (1st Revised Service Agreement 539) terminating on November 30, 2013.
Schedule Page: 328 Line No.: 23 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service.
Schedule Page: 328 Line No.: 24 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (1st Revised Service Agreement 539) terminating on November 30, 2013.
Schedule Page: 328 Line No.: 24 Column: m
Regulation and frequency response service. December 2011 service.
Schedule Page: 328 Line No.: 25 Column: c
This footnote applies to all occurrences of "Umatilla Electric & Columbia" on pages 328 -
330. Complete name is Umatilla Electric Cooperative Association and Columbia Basin
Electric Cooperative, Inc.
Schedule Page: 328 Line No.: 25 Column: d
Network transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 538) terminating on December 31, 2013.
Schedule Page: 328 Line No.: 25 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service.
Schedule Page: 328 Line No.: 26 Column: d
Network transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 538) terminating on December 31, 2013.
Schedule Page: 328 Line No.: 26 Column: m
Regulation and frequency response service. December 2011 service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule 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 (2nd Revised
Service Agreement 179) terminating on September 30, 2025.
Schedule Page: 328 Line No.: 27 Column: m
Reactive supply and voltage control service.
Schedule Page: 328 Line No.: 28 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 179) terminating on September 30, 2025.
Schedule Page: 328 Line No.: 28 Column: m
December 2011 service.
Schedule 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.
Schedule 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.
Schedule 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.
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 2011 service.
Schedule Page: 328 Line No.: 31 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (4th Revised Service Agreement 328) terminated on June 25, 2022.
Schedule Page: 328 Line No.: 31 Column: m
Distribution voltage service charge. Primary delivery service. Penalty revenues covering
imbalance charges per Schedules 4 and 9. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Regulation and frequency response service.
Schedule Page: 328 Line No.: 32 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (4th Revised Service Agreement 328) terminated on June 25, 2022.
Schedule Page: 328 Line No.: 32 Column: m
Distribution voltage service charge. Primary delivery service. Penalty revenues covering
imbalance charges per Schedules 4 and 9. Regulation and frequency response service.
December 2011 service.
Schedule Page: 328 Line No.: 33 Column: d
Legacy contract (1st Revised Rate Schedule 299) executed between PacifiCorp and 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
or 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 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
by PacifiCorp. PacifiCorp provided notice of termination in June 2011.
Schedule Page: 328 Line No.: 34 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. Charges for scheduling and operating reserves. Refunds of
transmission service covering prior years. December 2011 service.
Schedule Page: 328.1 Line No.: 1 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 1 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 1 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.: 1 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 2 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 2 Column: c
Various signatories to the 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
between various parties and points.
Schedule Page: 328.1 Line No.: 2 Column: m
December 2011 service.
Schedule Page: 328.1 Line No.: 3 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 3 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 3 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 4 Column: d
Network transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 370) terminated on December 7, 2012.
Schedule Page: 328.1 Line No.: 4 Column: g
Chelatchie/View 115kV
Schedule Page: 328.1 Line No.: 4 Column: m
Penalty revenues covering imbalance charges per Schedules 4 and 9. Scheduling, system
control and dispatch service. Reactive supply and voltage control service. Regulation and
frequency response service.
Schedule Page: 328.1 Line No.: 5 Column: d
Network transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 370) terminated on December 7, 2012.
Schedule Page: 328.1 Line No.: 5 Column: g
Chelatchie/View 115kV
Schedule Page: 328.1 Line No.: 5 Column: m
Penalty revenues covering imbalance charges per Schedules 4 and 9. Regulation and
frequency response service. December 2011 service.
Schedule Page: 328.1 Line No.: 6 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 6 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.1 Line No.: 7 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 7 Column: c
Various signatories to the 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.: 7 Column: m
December 2011 service.
Schedule Page: 328.1 Line No.: 8 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 8 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 8 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: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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.
Schedule Page: 328.1 Line No.: 9 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 9 Column: c
Various signatories to the 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
between various parties and points.
Schedule Page: 328.1 Line No.: 9 Column: m
Transmission resales, purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Generation regulation
and frequency response service. Operating reserve - spinning reserve service. Operating
reserve - supplemental reserve service.
Schedule Page: 328.1 Line No.: 10 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 10 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule 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.
Schedule Page: 328.1 Line No.: 10 Column: m
Transmission resales, purchase of point-to-point transmission. December 2011 service.
Schedule Page: 328.1 Line No.: 11 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 11 Column: c
Various signatories to the 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
between various parties and points.
Schedule Page: 328.1 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.
Schedule Page: 328.1 Line No.: 12 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 12 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 12 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.1 Line No.: 13 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.: 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.
Schedule Page: 328.1 Line No.: 14 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.: 14 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 2011 service.
Schedule Page: 328.1 Line No.: 15 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 15 Column: c
Various signatories to the 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 (2nd Revised
Service Agreement 568) terminating on April 30, 2029.
Schedule Page: 328.1 Line No.: 15 Column: m
Penalty revenues covering imbalance charges per Schedules 4 and 9. Scheduling, system
control and dispatch service. Reactive supply and voltage control service. Generation
regulation and frequency response service. Operating reserve - spinning reserve service.
Operating reserve - supplemental reserve service.
Schedule Page: 328.1 Line No.: 16 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 16 Column: c
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 16 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 568) terminating on April 30, 2029.
Schedule Page: 328.1 Line No.: 16 Column: m
Operating reserve - spinning reserve service. Operating reserve - supplemental reserve
service. December 2011 service.
Schedule Page: 328.1 Line No.: 17 Column: a
This footnote applies to all occurrences of "Deseret Generation & Trans." on pages 328 -
330. Complete name is Deseret Generation and Transmission Co-operative.
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 (5th 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
Meter interrogation services. Penalty revenues covering imbalance charges per Schedules 4
and 9. Scheduling, system control and dispatch service. Reactive supply and voltage
control service. Generation regulation and frequency response service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.
Schedule Page: 328.1 Line No.: 18 Column: d
Legacy contract executed between PacifiCorp and Deseret Generation and Transmission
Co-operative for transmission service over agreed-upon facilities (5th Amended and
Restated Transmission Service and Operating Agreement, Rate Schedule 280). Agreement
subject to termination upon mutual agreement.
Schedule Page: 328.1 Line No.: 18 Column: m
Scheduling and load following charges. Distribution voltage service charge. Charges for
spinning and/or supplemental reserves. December 2011 service.
Schedule Page: 328.1 Line No.: 19 Column: d
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 on January 31,
2012.
Schedule Page: 328.1 Line No.: 19 Column: m
Charges for spinning and/or supplemental reserves. Regulation and frequency response.
Meter interrogation service. Charges for control area services.
Schedule Page: 328.1 Line No.: 20 Column: d
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 on January 31,
2012.
Schedule Page: 328.1 Line No.: 20 Column: m
Charges for spinning and/or supplemental reserves. Regulation and frequency response.
Meter interrogation service. Charges for control area services. December 2011 service.
Schedule Page: 328.1 Line No.: 21 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 21 Column: c
Various signatories to the 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.: 21 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
Schedule Page: 328.1 Line No.: 22 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 22 Column: c
Various signatories to the 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.: 22 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 23 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 23 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 23 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: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 24 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.: 24 Column: m
Sole use of facilities charge based on a capacity factor and/or proportional use as
defined in the contract. Customer capacity is 10 megawatts ("MW").
Schedule Page: 328.1 Line No.: 25 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.: 25 Column: m
Sole use of facilities charge based on a capacity factor and/or proportional use as
defined in the contract. Customer capacity is 10 MW. December 2011 service.
Schedule Page: 328.1 Line No.: 26 Column: c
PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and
commodity trading activities.
Schedule Page: 328.1 Line No.: 26 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.: 26 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Schedule Page: 328.1 Line No.: 27 Column: c
PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and
commodity trading activities.
Schedule Page: 328.1 Line No.: 27 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.: 27 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2011 service.
Schedule Page: 328.1 Line No.: 28 Column: d
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 653) deferred until January 1, 2013 and terminating on December 31,
2017.
Schedule Page: 328.1 Line No.: 28 Column: m
Extension of commencement date fee.
Schedule Page: 328.1 Line No.: 29 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 697) deferred until January 1, 2013 and terminating on December 31, 2017.
Schedule Page: 328.1 Line No.: 29 Column: m
Extension of commencement date fee.
Schedule Page: 328.1 Line No.: 30 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 698) deferred until January 1, 2013 and terminating on December 31, 2017.
Schedule Page: 328.1 Line No.: 30 Column: m
Extension of commencement date fee.
Schedule Page: 328.1 Line No.: 31 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 699) deferred until January 1, 2013 and terminating on December 31, 2017.
Schedule Page: 328.1 Line No.: 31 Column: m
Extension of commencement date fee.
Schedule Page: 328.1 Line No.: 32 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 655) deferred until January 1, 2013 and terminating on December 31,
2017.
Schedule Page: 328.1 Line No.: 32 Column: m
Extension of commencement date fee.
Schedule Page: 328.1 Line No.: 33 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 33 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 33 Column: m
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Schedules 4 and 9. Scheduling, system control and dispatch service. Reactive supply and
voltage control service. Generation regulation and frequency response service.
Schedule Page: 328.1 Line No.: 34 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 34 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 34 Column: m
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Schedules 4 and 9. December 2011 service.
Schedule Page: 328.2 Line No.: 1 Column: c
Iberdrola Renewables, LLC and Utah Associated Municipal Power Systems.
Schedule Page: 328.2 Line No.: 1 Column: d
Ancillary services under the Open Access Transmission Tariff (1st Revised Service
Agreement 476) in effect until superseded.
Schedule Page: 328.2 Line No.: 1 Column: f
Long Hollow, Wyoming Switching Station.
Schedule Page: 328.2 Line No.: 1 Column: g
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.11
Long Hollow, Wyoming Switching Station.
Schedule Page: 328.2 Line No.: 1 Column: m
Operating reserve - spinning reserve service. Operating reserve - supplemental reserve
service.
Schedule Page: 328.2 Line No.: 2 Column: c
Iberdrola Renewables, LLC and Utah Associated Municipal Power Systems.
Schedule Page: 328.2 Line No.: 2 Column: d
Ancillary services under the Open Access Transmission Tariff (1st Revised Service
Agreement 476) in effect until superseded.
Schedule Page: 328.2 Line No.: 2 Column: f
Long Hollow, Wyoming Switching Station.
Schedule Page: 328.2 Line No.: 2 Column: g
Long Hollow, Wyoming Switching Station.
Schedule Page: 328.2 Line No.: 2 Column: m
Operating reserve - spinning reserve service. Operating reserve - supplemental reserve
service. December 2011 service.
Schedule Page: 328.2 Line No.: 3 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (6th Revised
Service Agreement 279) terminating on April 30, 2014.
Schedule Page: 328.2 Line No.: 3 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 4 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (6th Revised
Service Agreement 279) terminating on April 30, 2014.
Schedule Page: 328.2 Line No.: 4 Column: m
December 2011 service.
Schedule Page: 328.2 Line No.: 5 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 PacifiCorp's Big Grassy load. See also page 332, Transmission of
electricity by others, of this Form No. 1.
Schedule Page: 328.2 Line No.: 6 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 6 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 6 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/United States Department of Energy Supply Agreement.
Schedule Page: 328.2 Line No.: 6 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.: 7 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 7 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 7 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.12
facilities charge for the Antelope Substation terminating coterminous with the
Idaho/United States Department of Energy Supply Agreement.
Schedule Page: 328.2 Line No.: 7 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2011 service.
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 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 Bridger Pump Substation. Agreement
terminates upon 12 months written notice.
Schedule Page: 328.2 Line No.: 8 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Schedule Page: 328.2 Line No.: 9 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 9 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 9 Column: d
Legacy contract (Rate Schedule 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 Bridger Pump Substation. Agreement
terminates upon 12 months written notice.
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 2011 service.
Schedule Page: 328.2 Line No.: 10 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 10 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 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: 328.2 Line No.: 10 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 11 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 11 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 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: 328.2 Line No.: 11 Column: m
December 2011 service.
Schedule Page: 328.2 Line No.: 12 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 12 Column: c
Various signatories to the 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.13
Schedule Page: 328.2 Line No.: 12 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 13 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (6th Revised
Service Agreement 212) terminating on May 31, 2014.
Schedule Page: 328.2 Line No.: 13 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 14 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.: 14 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 14 Column: c
Various signatories to the 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.: 14 Column: m
Penalty revenues covering imbalance charges per Schedules 4 and 9. Scheduling, system
control and dispatch service. Reactive supply and voltage control service. Generation
regulation and frequency response service.
Schedule Page: 328.2 Line No.: 15 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 15 Column: c
Various signatories to the 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
Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2011 service.
Schedule Page: 328.2 Line No.: 16 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 16 Column: c
Various signatories to the 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.
Schedule Page: 328.2 Line No.: 16 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 17 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.: 17 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 17 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 17 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.: 17 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.14
Schedule Page: 328.2 Line No.: 18 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, by providing two years' written notice.
Schedule Page: 328.2 Line No.: 18 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
Schedule Page: 328.2 Line No.: 19 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, by providing two years' written notice.
Schedule Page: 328.2 Line No.: 19 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 2011 service.
Schedule Page: 328.2 Line No.: 20 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 20 Column: c
Various signatories to the 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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.2 Line No.: 21 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 21 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 21 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 21 Column: m
December 2011 service.
Schedule Page: 328.2 Line No.: 22 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 22 Column: c
Various signatories to the 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.: 22 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 23 Column: c
This footnote applies to all occurrences of "Grant County PUD" on pages 328 - 330.
Complete name is Grant County Public Utility District.
Schedule Page: 328.2 Line No.: 23 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 626) assignment from Seattle City Light, terminated December 31, 2011.
Customer executed extension of service through assignment from Seattle City Light (Service
Agreement 708) through October 31, 2014.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.15
Schedule Page: 328.2 Line No.: 23 Column: e
V11-1-3,5-7,9,11
Schedule Page: 328.2 Line No.: 23 Column: m
Transmission resales, amount paid by seller. Unauthorized use of transmission service.
Penalty revenues covering imbalance charges per Schedules 4 and 9. Scheduling, system
control and dispatch service. Reactive supply and voltage control service. Generation
regulation and frequency response service. Operating reserve - spinning reserve service.
Operating reserve - supplemental reserve service.
Schedule Page: 328.2 Line No.: 24 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 626) assignment from Seattle City Light, terminated 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
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Schedules 4 and 9. Transmission resales, amount paid by seller for December 2011 service.
Operating reserve - spinning reserve service. Operating reserve - supplemental reserve
service.
Schedule Page: 328.2 Line No.: 25 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.: 25 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.2 Line No.: 26 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 26 Column: c
Various signatories to the 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.: 26 Column: m
December 2011 service.
Schedule Page: 328.2 Line No.: 27 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 27 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule 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.
Schedule Page: 328.2 Line No.: 27 Column: m
December 2011 service.
Schedule Page: 328.2 Line No.: 28 Column: d
Transmission service under the Open Access Transmission Tariff (4th Revised Service
Agreement 299). Service provided pursuant to rules and 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
Penalty revenues covering imbalance charges per Schedules 4 and 9. Scheduling, system
control and dispatch service. Reactive supply and voltage control service. Regulation and
frequency response service.
Schedule Page: 328.2 Line No.: 29 Column: d
Transmission service under the Open Access Transmission Tariff (4th Revised Service
Agreement 299). Service provided pursuant to rules and regulations of Oregon Direct
Access. Agreement termination upon notification pursuant to Oregon Direct Access and Open
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.16
Access Transmission Tariff.
Schedule Page: 328.2 Line No.: 29 Column: m
December 2011 service.
Schedule 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 on 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
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 on 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 2011 service.
Schedule Page: 328.2 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: 328.2 Line No.: 32 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 33 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 33 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 33 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 kilovolt
("kV")transmission line and Pinto-Four Corners 345-kV transmission line). Terminating on
February 12, 2020.
Schedule Page: 328.2 Line No.: 33 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.17
or facilities charge.
Schedule Page: 328.2 Line No.: 34 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 34 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 34 Column: d
Legacy contract (Rate Schedule 137) executed between PacifiCorp and Portland General
Electric for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge for the Dalreed Substation terminating on December 12, 2012.
Schedule Page: 328.2 Line No.: 34 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.: 1 Column: c
This footnote applies to all occurrences of "Sheridan-Johnson Rural Elect." on pages 328 -
330. Complete name is Sheridan-Johnson Rural Electric Association.
Schedule Page: 328.3 Line No.: 1 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.: 1 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.: 2 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.: 2 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2011 service.
Schedule Page: 328.3 Line No.: 3 Column: c
This footnote applies to all occurrences of "CAISO" on pages 328 - 330. Complete name is
California Independent System Operator Corporation.
Schedule Page: 328.3 Line No.: 3 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (7th Revised
Service Agreement 169) terminating on October 31, 2020.
Schedule Page: 328.3 Line No.: 3 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 4 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (7th Revised
Service Agreement 169) terminating on October 31, 2020.
Schedule Page: 328.3 Line No.: 4 Column: m
December 2011 service.
Schedule Page: 328.3 Line No.: 5 Column: d
Point-to-point transmission service the Open Access Transmission Tariff (1st Revised
Service Agreement 701) terminating on March 31, 2017.
Schedule Page: 328.3 Line No.: 5 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 6 Column: d
Point-to-point transmission service the Open Access Transmission Tariff (1st Revised
Service Agreement 702) terminating on March 31, 2017.
Schedule Page: 328.3 Line No.: 6 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.18
Schedule Page: 328.3 Line No.: 7 Column: d
Point-to-point transmission service the Open Access Transmission Tariff (1st Revised
Service Agreement 703) terminating on March 31, 2017.
Schedule Page: 328.3 Line No.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 8 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 8 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 8 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 8 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.3 Line No.: 9 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 9 Column: c
Various signatories to the 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.: 9 Column: m
December 2011 service.
Schedule Page: 328.3 Line No.: 10 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 10 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule 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.
Schedule Page: 328.3 Line No.: 10 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.
Schedule Page: 328.3 Line No.: 11 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 11 Column: c
Various signatories to the 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.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 12 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 12 Column: c
Various signatories to the 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.: 12 Column: m
December 2011 service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.19
Schedule Page: 328.3 Line No.: 13 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 13 Column: c
Various signatories to the 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
between various parties and points.
Schedule Page: 328.3 Line No.: 13 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.3 Line No.: 14 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.: 14 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 14 Column: c
Various signatories to the 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.
Schedule Page: 328.3 Line No.: 14 Column: m
December 2011 service.
Schedule Page: 328.3 Line No.: 15 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 15 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule 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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 16 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 16 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 16 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.: 16 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 17 Column: b
Sacramento Municipal Utility District.
Schedule Page: 328.3 Line No.: 17 Column: c
Sacramento Municipal Utility District.
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 on October 31, 2014.
Schedule Page: 328.3 Line No.: 17 Column: f
Malin 230 transformer.
Schedule Page: 328.3 Line No.: 17 Column: g
Malin 500 transformer.
Schedule Page: 328.3 Line No.: 17 Column: m
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.20
Extension of commencement date fee.
Schedule Page: 328.3 Line No.: 18 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 552) terminating on February 28, 2018.
Schedule Page: 328.3 Line No.: 18 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.
Schedule Page: 328.3 Line No.: 19 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 552) terminating on February 28, 2018.
Schedule Page: 328.3 Line No.: 19 Column: m
Charges for spinning and/or supplemental reserves. Penalty revenues covering imbalance
charges per Schedules 4 and 9. December 2011 service.
Schedule Page: 328.3 Line No.: 20 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.: 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.
Schedule Page: 328.3 Line No.: 20 Column: d
Legacy contract (Rate Schedule 674) executed between 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 April 2017.
Schedule Page: 328.3 Line No.: 20 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Schedule Page: 328.3 Line No.: 21 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 21 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 21 Column: d
Legacy contract (Rate Schedule 674) executed between 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 April 2017.
Schedule Page: 328.3 Line No.: 21 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2011 service.
Schedule Page: 328.3 Line No.: 22 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 22 Column: c
Various signatories to the 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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 23 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 23 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 23 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.21
between various parties and points.
Schedule Page: 328.3 Line No.: 23 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 24 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 24 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 24 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.: 24 Column: m
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Schedules 4 and 9. Scheduling, system control and dispatch service. Reactive supply and
voltage control service. Generation regulation and frequency response service. Operating
reserve - spinning reserve service. Operating reserve - supplemental reserve service.
Schedule Page: 328.3 Line No.: 25 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 25 Column: c
Various signatories to the 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.
Schedule Page: 328.3 Line No.: 25 Column: m
Charges for spinning and/or supplemental reserves. December 2011 service.
Schedule Page: 328.3 Line No.: 26 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 26 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 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: 328.3 Line No.: 26 Column: m
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Schedules 4 and 9. Scheduling, system control and dispatch service. Reactive supply and
voltage control service. Generation regulation and frequency response service.
Schedule Page: 328.3 Line No.: 27 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 27 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 27 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.: 27 Column: m
Penalty revenues covering imbalance charges per Schedules 4 and 9. December 2011 service.
Schedule Page: 328.3 Line No.: 28 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 28 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 28 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 on February 12, 2020.
Schedule Page: 328.3 Line No.: 28 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.22
or facilities charge.
Schedule Page: 328.3 Line No.: 29 Column: a
This footnote applies to all occurrences of "Southern California Public Power" on pages
328 - 330. Complete name is Southern California Public Power Authority.
Schedule Page: 328.3 Line No.: 29 Column: d
Small Generator Interconnection Agreement (Service Agreement 629) executed between
PacifiCorp and Southern California Public Power Authority terminating on November 30, 2019
or such other longer period as the Interconnection Customer may request and shall be
automatically renewed for each successive one-year period thereafter, unless terminated
earlier based on terms listed in the contract.
Schedule Page: 328.3 Line No.: 29 Column: m
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Schedules 4 and 9.
Schedule Page: 328.3 Line No.: 30 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (10th
Revised Service Agreement 170) terminating on May 31, 2014.
Schedule Page: 328.3 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 31 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (10th
Revised Service Agreement 170) terminating on May 31, 2014.
Schedule Page: 328.3 Line No.: 31 Column: m
December 2011 service.
Schedule Page: 328.3 Line No.: 32 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 32 Column: c
Various signatories to the 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.
Schedule Page: 328.3 Line No.: 32 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 33 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 33 Column: c
Various signatories to the 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.
Schedule Page: 328.3 Line No.: 33 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.
Schedule Page: 328.3 Line No.: 34 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 34 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 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: 328.3 Line No.: 34 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.23
Schedule Page: 328.4 Line No.: 1 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 1 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 1 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.: 1 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 2 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 2 Column: c
Various signatories to the 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.: 2 Column: m
December 2011 service.
Schedule Page: 328.4 Line No.: 3 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.
Schedule Page: 328.4 Line No.: 3 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 3 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 on October 1,
2014.
Schedule Page: 328.4 Line No.: 4 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 4 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 on October 1,
2014.
Schedule Page: 328.4 Line No.: 4 Column: m
Adjustment for 2011 transmission service.
Schedule Page: 328.4 Line No.: 5 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 5 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.: 5 Column: m
Penalty revenues covering imbalance charges per Schedules 4 and 9. Scheduling, system
control and dispatch service. Reactive supply and voltage control service. Regulation and
frequency response service.
Schedule Page: 328.4 Line No.: 6 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 6 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.: 6 Column: m
Penalty revenues covering imbalance charges per Schedules 4 and 9. Regulation and
frequency response service. December 2011 service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.24
Schedule Page: 328.4 Line No.: 7 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 7 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 8 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 8 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 8 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.: 8 Column: m
December 2011 service.
Schedule Page: 328.4 Line No.: 9 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 9 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 9 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 10 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.: 10 Column: m
Distribution voltage service charge. Primary delivery service. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Regulation and
frequency response service.
Schedule Page: 328.4 Line No.: 11 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.: 11 Column: m
Distribution voltage service charge. Primary delivery service. Regulation and frequency
response service. December 2011 service.
Schedule Page: 328.4 Line No.: 12 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.: 13 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.: 13 Column: d
Legacy contract (2nd Revised Rate Schedule 286) executed between PacifiCorp and United
States Department of the Interior, 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.25
time after April 1, 2040 with four years written notification.
Schedule Page: 328.4 Line No.: 13 Column: m
Energy consumption charge for deliveries at and below 138-kV.
Schedule Page: 328.4 Line No.: 14 Column: d
Legacy contract (2nd Revised Rate Schedule 286) executed between PacifiCorp and United
States Department of the Interior, 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.: 14 Column: m
Energy consumption charge for deliveries at and below 138-kV. December 2011 service.
Schedule Page: 328.4 Line No.: 15 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.
Schedule Page: 328.4 Line No.: 15 Column: d
Legacy contract executed between PacifiCorp and Utah Associated Municipal Power Systems
for transmission service over agreed-upon facilities (2nd Amended and Restated
Transmission Service and Operating Agreement, 2nd Revised Rate Schedule 297). Agreement
subject to termination upon mutual agreement and replacement agreements are in effect.
Schedule Page: 328.4 Line No.: 15 Column: m
Scheduling and load following charges. Distribution voltage service charge. Charges for
spinning and/or supplemental reserves. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Regulation and frequency response service.
Schedule Page: 328.4 Line No.: 16 Column: d
Legacy contract executed between PacifiCorp and Utah Associated Municipal Power Systems
for transmission service over agreed-upon facilities (2nd Amended and Restated
Transmission Service and Operating Agreement, 2nd Revised Rate Schedule 297). Agreement
subject to termination upon mutual agreement and replacement agreements are in effect.
Schedule Page: 328.4 Line No.: 16 Column: m
Charges for scheduling and load following. Distribution voltage service charge. December
2011 service.
Schedule Page: 328.4 Line No.: 17 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 17 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 17 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.: 17 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.4 Line No.: 18 Column: d
Legacy contract (4th 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.: 18 Column: m
Scheduling and load following charges. Charges for spinning and/or supplemental reserves.
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service.
Schedule Page: 328.4 Line No.: 19 Column: d
Legacy contract (4th 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.26
Schedule Page: 328.4 Line No.: 19 Column: m
Scheduling and load following charges. December 2011 service.
Schedule Page: 328.4 Line No.: 20 Column: c
This footnote applies to all occurrences of "Portland General Electric" on pages
328 - 330. Complete name is Portland General Electric Company.
Schedule Page: 328.4 Line No.: 20 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 on January 31, 2032.
Schedule Page: 328.4 Line No.: 20 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: 328.4 Line No.: 21 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 on January 31, 2032.
Schedule Page: 328.4 Line No.: 21 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract. December 2011 service.
Schedule Page: 328.4 Line No.: 22 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.4 Line No.: 22 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.: 22 Column: m
Fixed termination fee associated with a contract cancellation applied for the duration of
this agreement.
Schedule Page: 328.4 Line No.: 23 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.4 Line No.: 23 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.: 23 Column: m
Fixed termination fee associated with a contract cancellation applied for the duration of
this agreement. December 2011 service.
Schedule Page: 328.4 Line No.: 24 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.4 Line No.: 24 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
138-kV. Agreement termination upon three years after written notice and mutual consent.
Schedule Page: 328.4 Line No.: 24 Column: m
Charges for low-voltage transmission of power and energy.
Schedule Page: 328.4 Line No.: 25 Column: c
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.27
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.4 Line No.: 25 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
138-kV. Agreement termination upon three years after written notice and mutual consent.
Schedule Page: 328.4 Line No.: 25 Column: m
Charges for low-voltage transmission of power and energy. December 2011 service.
Schedule Page: 328.4 Line No.: 26 Column: a
This footnote applies to all occurrences of "Western Area Power Adm. CO MO" on pages
328 - 330. Complete name is Western Area Power Administration Colorado Missouri.
Schedule Page: 328.4 Line No.: 26 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 26 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 27 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 27 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.: 27 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 28 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 28 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.: 28 Column: m
December 2011 service.
Schedule Page: 328.4 Line No.: 29 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 29 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 page 332,
Transmission of electricity by others, of this Form No 1.
Schedule Page: 328.4 Line No.: 30 Column: d
Evergreen network transmission service under the Open Access Transmission Tariff (3rd
Revised Service Agreement 175).
Schedule Page: 328.4 Line No.: 30 Column: m
Distribution voltage service charge. Primary delivery service. Scheduling, system control
and dispatch service. Reactive supply and voltage control service.
Schedule Page: 328.4 Line No.: 31 Column: d
Evergreen network transmission service under the Open Access Transmission Tariff (3rd
Revised Service Agreement 175).
Schedule Page: 328.4 Line No.: 31 Column: m
Distribution voltage service charge. Primary delivery service. December 2011 service.
Schedule Page: 328.4 Line No.: 32 Column: a
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.28
This footnote applies to all occurrences of "Western Area Power Adm. CO River" on pages
328 - 330. Complete name is Western Area Power Administration Colorado River Storage
Project.
Schedule Page: 328.4 Line No.: 32 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 32 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 33 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 33 Column: m
December 2011 service.
Schedule Page: 328.4 Line No.: 34 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 709) terminating on March 31, 2018.
Schedule Page: 328.4 Line No.: 34 Column: m
Extension of commencement date fee.
Schedule Page: 328.5 Line No.: 1 Column: m
Represents the difference between actual wheeling revenues for the period as reflected on
the individual line items within this schedule, and the accruals credited to Account
456.1, Revenues from transmission of electricity for others, during the period and
estimates for amounts subject to refund per FERC Docket No. ER11-3643 charged to Account
456.1, Revenues from transmission of electricity for others, during the period.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.29
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
PacifiCorp X
/ /2012/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(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.
Statistical
Classification(b)
LFP 1,140,058 1,140,058 301,061 301,061Arizona Public Service 1
NF 362,454 362,454 75,567 75,567Arizona Public Service 2
OS 8,601 5,711 2,890 15 15Arizona Public Service 3
OSArizona Public Service 4
SFP 57,043 57,043 8,877 8,877Arizona Public Service 5
AD 46,802 46,802 4,680 4,680Ashland, City of 6
FNS 22,044 22,044 2,377 2,377Ashland, City of 7
FNS 214,489 214,489 56,261 53,305Avista Corporation 8
NF 287,853 287,853 54,690 54,690Avista Corporation 9
SFP 18,460 18,460 4,800 4,800Avista Corporation 10
NF 144,782 144,782 97,169 97,169Basin Elect. Power Coop 11
OLF 199,860 199,860Big Horn Rural Electric 12
AD 79,056 79,056 11,760 11,760Black Hills Power, Inc. 13
NF 885 885 416 416Black Hills Power, Inc. 14
SFP 89,069 89,069 18,432 18,432Black Hills Power, Inc. 15
AD -530,918 -579,443 -20,982 69,507 -21 -21Bonneville Power Admin 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332
15,224,309 15,633,061 116,058,925 5,457,822 20,608,368 142,125,115TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
PacifiCorp X
/ /2012/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(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.
Statistical
Classification(b)
FNS 6,140,993 6,140,993Bonneville Power Admin 1
LFP 51,824,309 51,824,309 5,598,921 5,598,921Bonneville Power Admin 2
NF 1,049,643 1,049,643 242,533 242,533Bonneville Power Admin 3
OLF 30,964,402 98,317 30,866,085 2,836,843 2,639,814Bonneville Power Admin 4
OS 4,811,467 4,716,140 83,427 11,900 27,680 27,680Bonneville Power Admin 5
OSBonneville Power Admin 6
SFP 2,161,891 2,161,891 418,209 418,209Bonneville Power Admin 7
AD -131,809 -143,654 11,845CA Ind Sys Oper Corp 8
OS 746,138 746,138CA Ind Sys Oper Corp 9
SFP 1,954,627 1,954,627 288,908 288,908CA Ind Sys Oper Corp 10
AD -10,841 -10,841 955 955Deseret Gen & Trans 11
LFP 4,554,688 4,554,688 241,736 241,736Deseret Gen & Trans 12
NF 1,908,383 1,908,383 270,268 270,268Deseret Gen & Trans 13
NF 250 250 330 330El Paso Electric Co. 14
OS 32 32El Paso Electric Co. 15
AD 7,511 7,511Flathead Elect Coop Inc 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1
15,224,309 15,633,061 116,058,925 5,457,822 20,608,368 142,125,115TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
PacifiCorp X
/ /2012/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(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.
Statistical
Classification(b)
OS 81,375 81,375Flathead Elect Coop Inc 1
OS 184,498 184,498Hermiston Gen Co L.P. 2
AD 7,419 7,419Idaho Power Company 3
FNS 8,230 8,230Idaho Power Company 4
LFP 6,132,562 6,132,562 2,455,284 2,253,091Idaho Power Company 5
NF 178,461 178,461 34,392 34,392Idaho Power Company 6
OS 11,996,454 12,019,872 -23,418Idaho Power Company 7
OSIdaho Power Company 8
SFP 54,594 54,594 20,760 20,760Idaho Power Company 9
NF 90 90 10 10LA Dept of Water & Pwr 10
OS 138 138LA Dept of Water & Pwr 11
FNS 251,428 251,428Moon Lake Elect. Assoc. 12
LFP 853 853 165 165Morgan City Corporation 13
SFP -293,838 -293,838Morgan Stanley Capital 14
NF 122,442 122,442 44,404 44,404Nevada Power Company 15
OS 175,257 175,257Nevada Power Company 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.2
15,224,309 15,633,061 116,058,925 5,457,822 20,608,368 142,125,115TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
PacifiCorp X
/ /2012/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(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.
Statistical
Classification(b)
SFP 843,368 843,368 374,062 374,062Nevada Power Company 1
NF 461,704 461,704 106,441 106,441NorthWestern Corp. 2
OS 22,315 22,315NorthWestern Corp. 3
SFP 312 312 72 72NorthWestern Corp. 4
LFP 946,617 946,617 205,145 205,145Platte River Pwr Auth 5
OS 8,508 8,508Platte River Pwr Auth 6
OLF 890 890Portland Gen. Electric 7
SFP -633,289 -633,289Powerex Corporation 8
LFP 942,896 942,896 71,101 67,818Public Service Co of CO 9
LFP 690,347 690,347 109,494 109,494Public Service Co of NM 10
NF 1,501 1,501 235 235Public Service Co of NM 11
OS 19,387 19,387Public Service Co of NM 12
NF 41,439 41,439 20,500 20,500Salt River Project 13
OS 958 958Salt River Project 14
NF 598,728 598,728 93,082 93,082Sierra Pacific Pwr Co 15
OS 207,514 207,514Sierra Pacific Pwr Co 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.3
15,224,309 15,633,061 116,058,925 5,457,822 20,608,368 142,125,115TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
PacifiCorp X
/ /2012/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(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.
Statistical
Classification(b)
SFP 878,308 878,308 159,691 159,691Sierra Pacific Pwr Co 1
OLF 10,836 10,836Surprise Valley Electr. 2
AD -869 -869Tri-State Gen & Transm 3
LFP 942,896 942,896 94,621 91,330Tri-State Gen & Transm 4
NF 726,368 726,368 209,398 209,398Tri-State Gen & Transm 5
OS 186,408 186,408Tri-State Gen & Transm 6
LFP 49,704 49,704 16,368 16,368Tucson Electric Power 7
NF 13,516 13,516 3,000 3,000Tucson Electric Power 8
OS 6,753 6,753Tucson Electric Power 9
SFP 9,360 9,360 2,160 2,160Tucson Electric Power 10
LFP -3,489,354 -3,489,354Westport Field Svc LLC 11
AD 62,969 65,554 -2,585Western Area Power Admn 12
FNS 5,908,753 5,908,753Western Area Power Admn 13
LFP 2,016,426 2,016,426 585,110 585,110Western Area Power Admn 14
NF 814,572 814,572 336,679 336,679Western Area Power Admn 15
OS 663,700 663,700Western Area Power Admn 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.4
15,224,309 15,633,061 116,058,925 5,457,822 20,608,368 142,125,115TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
PacifiCorp X
/ /2012/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(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.
Statistical
Classification(b)
OSWestern Area Power Admn 1
SFP 503,574 503,574 128,420 128,420Western Area Power Admn 2
582,359 582,359Accrual 3
1,063,456 1,063,456Reserve 4
5
6
7
8
9
10
11
12
13
14
15
16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.5
15,224,309 15,633,061 116,058,925 5,457,822 20,608,368 142,125,115TOTAL
Schedule Page: 332 Line No.: 1 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.: 3 Column: g
Ancillary services.
Schedule Page: 332 Line No.: 4 Column: b
Arizona Public Service Company - Legacy contract executed between PacifiCorp and Arizona
Public Service Company concerning the exchange of transmission services over agreed-upon
facilities (Restated Transmission Service Agreement between PacifiCorp and Arizona Public
Service Company, Rate Schedule 436). The contract terminates October 31, 2020. See also
page 328, Transmission of electricity for others, of this Form 1.
Schedule Page: 332 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 12 Column: b
Big Horn Rural Electric Company - contract termination date: March 10, 2015
Schedule Page: 332 Line No.: 12 Column: g
Use of facilities.
Schedule Page: 332 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 16 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 16 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.1 Line No.: 2 Column: b
Bonneville Power Administration - contract termination dates: July 1, 2012; October 1,
2013; December 1, 2013; January 1, 2014; November 1, 2014; November 1, 2015; July 1, 2016;
December 1, 2016; April 1, 2017; July 1, 2017; November 1, 2017; October 1, 2018; December
1, 2018; October 1, 2027; November 1, 2033; and evergreen
Schedule Page: 332.1 Line No.: 4 Column: b
Bonneville Power Administration - contract termination dates: October 3, 2014; December
31, 2018; September 30, 2027; and evergreen
Schedule Page: 332.1 Line No.: 4 Column: g
Use of facilities.
Schedule Page: 332.1 Line No.: 5 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.1 Line No.: 6 Column: b
Bonneville Power Administration - 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 page 328, Transmission of electricity for others, of this Form 1.
Schedule Page: 332.1 Line No.: 8 Column: a
This footnote applies to all occurrences of "CA Ind Sys Oper Corp" on page 332. Complete
name is California Independent System Operator Corporation.
Schedule Page: 332.1 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 332.1 Line No.: 8 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 9 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 332.1 Line No.: 12 Column: b
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Deseret Generation and Transmission Cooperative - contract termination dates: October 31,
2012 and September 1, 2018
Schedule Page: 332.1 Line No.: 15 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 16 Column: b
Settlement adjustment.
Schedule Page: 332.1 Line No.: 16 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 1 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 2 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 332.2 Line No.: 3 Column: g
PacifiCorp's portion of specified costs of certain facilities.
Schedule Page: 332.2 Line No.: 5 Column: b
Idaho Power Company - contract termination dates: April 1, 2025 and July 1, 2025
Schedule Page: 332.2 Line No.: 7 Column: e
Credit for unreserved use.
Schedule Page: 332.2 Line No.: 7 Column: g
Ancillary services. Use of facilities. PacifiCorp's portion of specified costs of certain
facilities.
Schedule Page: 332.2 Line No.: 8 Column: b
Idaho Power Company - 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 page 328, Transmission
of electricity for others, of this Form 1.
Schedule Page: 332.2 Line No.: 10 Column: a
This footnote applies to all occurrences of "LA Dept of Water & Pwr" on page 332. Complete
name is Los Angeles Department of Water and Power.
Schedule Page: 332.2 Line No.: 11 Column: g
Ancillary services.
Schedule Page: 332.2 Line No.: 12 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 13 Column: b
Morgan City Corporation - contract termination date: Evergreen
Schedule Page: 332.2 Line No.: 14 Column: a
This footnote applies to all occurrences of "Morgan Stanley Capital" on page 332. Complete
name is Morgan Stanley Capital Group, Inc.
Schedule Page: 332.2 Line No.: 14 Column: e
Reassignment of Bonneville Power Administration transmission.
Schedule Page: 332.2 Line No.: 16 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 3 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 5 Column: b
Platte River Power Authority - contract termination date: October 31, 2017
Schedule Page: 332.3 Line No.: 6 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 7 Column: b
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Portland General Electric Company - contract termination date: Upon two years written
notice
Schedule Page: 332.3 Line No.: 7 Column: g
Use of facilities.
Schedule Page: 332.3 Line No.: 8 Column: e
Reassignment of Bonneville Power Administration transmission.
Schedule Page: 332.3 Line No.: 9 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.
Schedule Page: 332.3 Line No.: 10 Column: b
Public Service Company of New Mexico - contract termination date: November 30, 2015
Schedule Page: 332.3 Line No.: 12 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 14 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 16 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 2 Column: b
Surprise Valley Electrification Corp. - contract termination date: Evergreen
Schedule Page: 332.4 Line No.: 2 Column: g
Use of facilities.
Schedule Page: 332.4 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 332.4 Line No.: 3 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 4 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.
Schedule Page: 332.4 Line No.: 6 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 7 Column: b
Tucson Electric Power Company - contract termination date: December 1, 2015
Schedule Page: 332.4 Line No.: 9 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 11 Column: b
Westport Field Services, LLC - contract termination date: Evergreen
Schedule Page: 332.4 Line No.: 11 Column: e
Reimbursement for providing third party service.
Schedule Page: 332.4 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 332.4 Line No.: 12 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.4 Line No.: 14 Column: b
Western Area Power Administration - contract termination date: May 31, 2022
Schedule Page: 332.4 Line No.: 16 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.5 Line No.: 1 Column: b
Western Area Power Administration - 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 page 328, Transmission of electricity for others, of this Form 1.
Schedule Page: 332.5 Line No.: 3 Column: g
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Represents the difference between actual wheeling expenses for the period as reflected on
the individual line items within this schedule, and the accruals charged to Account 565,
Transmission of electricity by others, during the period.
Schedule Page: 332.5 Line No.: 4 Column: g
Reserve for potential liability associated with unreserved use penalty.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
PacifiCorp X / /2012/Q4
Line Description Amount
(b)(a)No.
1,715,222Industry Association Dues 1
Nuclear Power Research Expenses 2
Other Experimental and General Research Expenses 3
Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 4
Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 5
6
Community & Economic Development and 7
Corporate Memberships & Subscriptions: 8
5,000Albina Opportunities Corporation 9
56,000Associated Oregon Industries 10
5,000Clatsop Economic Development 11
9,100Economic Development Corporation of Utah 12
8,400Economic Development for Central Oregon 13
Electric Power Research Institute, Inc. - Prism 2.0 14
350,000 Regional Energy and Economic Model Development Fees 15
7,073Equal Employment Advisory Council 16
37,500Four County Economic Development Corporation 17
5,000Gorge Oregon Entrepreneurs Network 18
5,000Idaho Economic Development Association 19
9,000Intermountain Electrical Association 20
446,097Northern Tier Transmission Group 21
12,250Oregon Business Association 22
25,808Oregon Business Council 23
15,000Oregon Economic Development Association 24
5,000Oregon Sports Authority Foundation 25
15,000Oregon State University 26
70,981Pacific Northwest Utilities Conference 27
52,500Portland Business Alliance 28
7,000Redmond Economic Development 29
5,750Rock Springs Chamber of Commerce 30
15,500Rocky Mountain Electrical League 31
30,542Salt Lake Area Chamber of Commerce 32
15,000Siskiyou County Economic Development 33
7,500South Coast Development Council, Inc. 34
8,750Southern Oregon Regional Economic Development Inc. 35
8,000Utah Governor's Economic Summit 36
6,000Utah Manufacturers Association 37
34,000Utah Taxpayers Association 38
5,500Utah Technology Council 39
28,511WEST Associates 40
3,162,479Western Electricity Coordinating Council 41
36,260Western Energy Institute 42
6,000Wyoming Business Alliance 43
20,455Wyoming Taxpayers Association 44
7,500Yakima County Development 45
7,338,998
FERC FORM NO. 1 (ED. 12-94) Page 335
46 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
PacifiCorp X / /2012/Q4
Line Description Amount
(b)(a)No.
152,957Other (individually < $5,000) 6
7
21,612Directors' Fees - Regional Advisory Boards 8
9
Rating Agency and Trustee Fees: 10
141,947The Bank of New York Mellon 11
38,160Computershare Shareowner Services, LLC 12
560CUSIP Global Services 13
5,800Financial Industry Regulatory Authority, Inc. 14
20,833Fitch, Inc. 15
222,017Moody's Investors Service, Inc. 16
82,500NYSE Market, Inc. 17
320,000Standard & Poor's Financial Services, LLC 18
12,776U.S. Bank National Association 19
20
General: 21
5,000Citizens Utility Board 22
6,425Settlement Fees 23
54Other 24
25
Regulatory Asset Amortization: 26
21,250Goodnoe Hills Settlement - WY 27
27,429Lake Side Settlement - WY 28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
7,338,998
FERC FORM NO. 1 (ED. 12-94) Page 335.1
46 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
PacifiCorp X
/ /2012/Q4
Line
No.Functional Classification Depreciation
(d)(b)(a)
Amortization of
Total
(Except amortization of aquisition adjustments)
A. Summary of Depreciation and Amortization Charges
Expense(Account 403)
Limited TermElectric Plant Amortization ofOther ElectricPlant (Acc 405)(e) (f)
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.
(Account 404)(c)
DepreciationExpense for AssetRetirement Costs(Account 403.1)
41,692,182 41,692,182 1 Intangible Plant
154,203,420 154,203,420 2 Steam Production Plant
3 Nuclear Production Plant
22,132,361 21,831,861 300,500 4 Hydraulic Production Plant-Conventional
5 Hydraulic Production Plant-Pumped Storage
115,343,392 115,343,392 6 Other Production Plant
86,537,884 86,537,884 7 Transmission Plant
155,833,318 155,833,318 8 Distribution Plant
9 Regional Transmission and Market Operation
40,560,912 38,203,550 2,357,362 10 General Plant
11 Common Plant-Electric
616,303,469 571,953,425 44,350,044 12 TOTAL
The Amortization of Limited Term Electric Plant is based on straight-line amortization over the life of the asset.
FERC FORM NO. 1 (REV. 12-03) Page 336
B. Basis for Amortization Charges
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.Account No.
(c)(b)(a)(d) (e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f) (g)(Percent)
HYDRAULIC PROD. 12
Klamath River 13
-1.90 7.00330.20 OR/CA 41 14
-2.07 7.00330.40 OR/CA 1 15
8.41 7.00331.00 OR/CA 13,856 16
5.94 7.00332.00 OR/CA 34,067 17
7.79 7.00333.00 OR/CA 17,823 18
10.22 7.00334.00 OR/CA 15,503 19
4.65 7.00335.00 OR/CA 181 20
6.85 7.00336.00 OR/CA 2,548 21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337
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, 2012, depreciation expense associated with transportation equipment was
$15,898,715.
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.
Schedule Page: 336 Line No.: 13 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES
PacifiCorp X
/ /2012/Q4
Line
No.
Description Assessed by
(c)(b)(a)
Total Expense forExpenses
of
(d)
(Furnish name of regulatory commission or body the Regulatory
docket or case number and a description of the case)Commission Utility Current Year(b) + (c)
Deferredin Account182.3 at Beginning of Year(e)
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being
amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Utah Public Service Commission: 1
Annual Fee 4,535,884 4,535,884 2
Rate Case 1,707,929 1,707,929 3
4
Oregon Public Utility Commission: 5
Annual Fee 3,147,620 3,147,620 6
Rate Case 1,554,980 1,554,980 7
345,643Deferred Intervenor Funding Grants 8
9
Wyoming Public Service Commission: 10
Annual Fee 1,415,560 1,415,560 11
Rate Case 1,083,926 1,083,926 12
13
Washington Utilities and Transportation 14
Commission: 15
Annual Fee 574,750 574,750 16
Rate Case 1,124,102 1,124,102 17
18
Idaho Public Utilities Commission: 19
Annual Fee 506,579 506,579 20
Rate Case 247,596 247,596 21
58,702Deferred Intervenor Funding Grants (2) 39,201 39,201 22
23
California Public Utilities Commission: 24
Annual Fee 948 948 25
Rate Case 343,959 343,959 26
32,885Deferred Intervenor Funding Grants 27
28
Rate Cases - All States 261,357 261,357 29
30
Federal Energy Regulatory Commission: 31
Annual Fee 2,043,517 2,043,517 32
Annual Fee - Hydro 2,983,740 2,983,740 33
Transmission Rate Case 757,804 757,804 34
Other Regulatory 365,986 365,986 35
36
Other Regulatory 259,773 259,773 37
38
Charges for services from MidAmerican Energy 39
Holdings Company and its affiliates: 40
Utah - Rate Case 1,816 1,816 41
Wyoming - Rate Case 1,614 1,614 42
Washington - Rate Case 1,227 1,227 43
FERC - Transmission Rate Case 4,271 4,271 44
FERC - Other Regulatory 1,833 1,833 45
FERC FORM NO. 1 (ED. 12-96) Page 350
46 TOTAL 15,208,598 7,757,374 22,965,972 437,230
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
(j)(i)(f)(k) (l)
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO
Department AccountNo.(g)
Amount
(h)
Deferred to
Account 182.3
Contra
Account Amount Deferred in Account 182.3End of Year
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.
1
Electric 2 4,535,884928
Electric 3 1,707,929928
4
5
Electric 6 3,147,620928
Electric 7 1,554,980928
585,536 239,893Electric 8928
9
10
Electric 11 1,415,560928
Electric 12 1,083,926928
13
14
15
Electric 16 574,750928
Electric 17 1,124,102928
18
19
Electric 20 506,579928
Electric 21 247,596928
69,206 39,201928 49,705Electric 22 39,201928
23
24
Electric 25 948928
Electric 26 343,959928
32,952 67Electric 27928
28
Electric 29 261,357928
30
31
Electric 32 2,043,517928
Electric 33 2,983,740928
Electric 34 757,804928
Electric 35 365,986928
36
Electric 37 259,773928
38
39
40
Electric 41 1,816928
Electric 42 1,614928
Electric 43 1,227928
Electric 44 4,271928
Electric 45 1,833928
FERC FORM NO. 1 (ED. 12-96) Page 351
46 22,965,972 289,665 39,201 687,694
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
PacifiCorp X
/ /2012/Q4
Line
No.
Description
(b)(a)
Classification
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.(Identify
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
B. Electric R, D & D Performed Externally: 1
Electric Power Research Institute (1) Research Support 2
- Toxic Release Inventory reporting for power plants program 3
- Prism 2.0 Regional Energy and Economic Model Development 4
Edison Electric Institute (2) Research Support 5
- Utility Solid Waste Activities Group - membership dues 6
- Avian Power Line Interaction Committee - membership dues 7
National Electric Energy Testing, Research & Applications Center (4) Research Support 8
- Membership dues 9
- Participation 10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87) Page 352
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
AMOUNTS CHARGED IN CURRENT YEAR
(e)(c)
Costs Incurred Internally
Current Year Costs Incurred Externally
Current Year
(d)Account Amount(f)
Unamortized
Accumulation
(g)
(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.
1
2
3 12,000 557 12,000
4 350,000 930.2 350,000
5
6 77,589 930.2 77,589
7 1,250 923 1,250
8
9 95,000 930.2 95,000
3,231 10580 3,231
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87) Page 353
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DISTRIBUTION OF SALARIES AND WAGES
PacifiCorp X
/ /2012/Q4
Line
No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)
Distribution Payroll charged forClearing Accounts
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.
Electric 1
Operation 2
93,582,637Production 3
10,163,006Transmission 4
Regional Market 5
39,607,326Distribution 6
40,371,041Customer Accounts 7
6,388,736Customer Service and Informational 8
Sales 9
41,294,116Administrative and General 10
231,406,862TOTAL Operation (Enter Total of lines 3 thru 10) 11
Maintenance 12
47,411,932Production 13
13,336,909Transmission 14
Regional Market 15
69,305,897Distribution 16
1,803,880Administrative and General 17
131,858,618TOTAL Maintenance (Total of lines 13 thru 17) 18
Total Operation and Maintenance 19
140,994,569Production (Enter Total of lines 3 and 13) 20
23,499,915Transmission (Enter Total of lines 4 and 14) 21
Regional Market (Enter Total of Lines 5 and 15) 22
108,913,223Distribution (Enter Total of lines 6 and 16) 23
40,371,041Customer Accounts (Transcribe from line 7) 24
6,388,736Customer Service and Informational (Transcribe from line 8) 25
Sales (Transcribe from line 9) 26
43,097,996Administrative and General (Enter Total of lines 10 and 17) 27
363,265,480 363,265,480TOTAL Oper. and Maint. (Total of lines 20 thru 27) 28
Gas 29
Operation 30
Production-Manufactured Gas 31
Production-Nat. Gas (Including Expl. and Dev.) 32
Other Gas Supply 33
Storage, LNG Terminaling and Processing 34
Transmission 35
Distribution 36
Customer Accounts 37
Customer Service and Informational 38
Sales 39
Administrative and General 40
TOTAL Operation (Enter Total of lines 31 thru 40) 41
Maintenance 42
Production-Manufactured Gas 43
Production-Natural Gas (Including Exploration and Development) 44
Other Gas Supply 45
Storage, LNG Terminaling and Processing 46
Transmission 47
FERC FORM NO. 1 (ED. 12-88) Page 354
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)
Distribution Payroll charged forClearing Accounts
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Distribution 48
Administrative and General 49
TOTAL Maint. (Enter Total of lines 43 thru 49) 50
Total Operation and Maintenance 51
Production-Manufactured Gas (Enter Total of lines 31 and 43) 52
Production-Natural Gas (Including Expl. and Dev.) (Total lines 32, 53
Other Gas Supply (Enter Total of lines 33 and 45) 54
Storage, LNG Terminaling and Processing (Total of lines 31 thru 47) 55
Transmission (Lines 35 and 47) 56
Distribution (Lines 36 and 48) 57
Customer Accounts (Line 37) 58
Customer Service and Informational (Line 38) 59
Sales (Line 39) 60
Administrative and General (Lines 40 and 49) 61
TOTAL Operation and Maint. (Total of lines 52 thru 61) 62
Other Utility Departments 63
Operation and Maintenance 64
363,265,480 363,265,480TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65
Utility Plant 66
Construction (By Utility Departments) 67
144,657,545 144,657,545Electric Plant 68
Gas Plant 69
Other (provide details in footnote): 70
144,657,545 144,657,545TOTAL Construction (Total of lines 68 thru 70) 71
Plant Removal (By Utility Departments) 72
9,090,299 9,090,299Electric Plant 73
Gas Plant 74
Other (provide details in footnote): 75
9,090,299 9,090,299TOTAL Plant Removal (Total of lines 73 thru 75) 76
Other Accounts (Specify, provide details in footnote): 77
2,225,996 2,225,996Fuel Stock 78
643,947 643,947Miscellaneous Other Income Deductions 79
1,309,283 1,309,283Charges to Affiliates 80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
4,179,226 4,179,226TOTAL Other Accounts 95
521,192,550 521,192,550TOTAL SALARIES AND WAGES 96
FERC FORM NO. 1 (ED. 12-88) Page 355
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.
Description of Item(s) Balance at End of
(c)(b)(a)
Balance at End of
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
Quarter 1 Quarter 2
Balance at End of
Quarter 3
(d) (e)
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.
Balance at End of
Year
Energy 1
Net Purchases (Account 555) 2 6,535,622 384,849 3,125,896 4,895,208
Net Sales (Account 447) 3 ( 12,268,026)( 4,168,463) ( 5,738,731) ( 8,675,216)
Transmission Rights 4
Ancillary Services 5
Other Items (list separately) 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
( 5,732,404)( 3,783,614) ( 2,612,835) ( 3,780,008)
FERC FORM NO. 1/3-Q (NEW. 12-05) Page 397
46 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASES AND SALES OF ANCILLARY SERVICES
PacifiCorp X
/ /2012/Q4
Line
No.
Type of Ancillary Service
(a)
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.
Number of Units
Unit of
Measure Dollars
(b) (c) (d)
Number of Units
Unit of
Measure Dollars
(e) (f) (g)
Usage - Related Billing Determinant Usage - Related Billing Determinant
Amount Purchased for the Year Amount Sold for the Year
11,109,603MWh152,206,512Scheduling, System Control and Dispatch 1
20,469,053MWh150,646,535 18,792,632MWh137,653,555Reactive Supply and Voltage 2
49,328,910MWh106,811,215 45,766,634MWh 99,681,323Regulation and Frequency Response 3
-1,633,644MWh -78,884Energy Imbalance 4
20,845,908MWh 97,820,872 20,320,136MWh 96,321,836Operating Reserve - Spinning 5
17,731,244MWh 97,820,872 17,283,747MWh 96,321,836Operating Reserve - Supplement 6
7,421MWh 566Other 7
117,858,495605,227,688102,163,149429,978,550Total (Lines 1 thru 7) 8
FERC FORM NO. 1 (New 2-04) Page 398
Schedule Page: 398 Line No.: 7 Column: g
Emergency reserve energy provided.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
PacifiCorp X / /2012/Q4
Line
No.
Monthly Peak
MW - Total
(c)(b)(a)
Month
NAME OF SYSTEM:
Day of
Monthly
Peak
(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 (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the
definition of each statistical classification.
(d)
Hour of
Monthly
Peak
(e)
Firm Network
Service for Self
(f)
Firm Network
Service for
Others
(g)
Long-Term Firm
Point-to-point
Reservations
(h)
Other Long-
Term Firm
Service
(i)
Short-Term Firm
Point-to-point
Reservation
(j)
Other
Service
222 1,586 4,936 115 8,445180016 15,304January 1
226 1,535 4,936 102 8,118 800 6 14,917February 2
272 1,513 4,930 103 7,799 800 7 14,617March 3
720 4,634 14,802 320 24,362 44,838Total for Quarter 1 4
398 1,515 5,080 100 7,337150023 14,430April 5
1,046 1,530 5,080 103 8,006160015 15,765May 6
701 1,821 5,429 107 9,020160029 17,078June 7
2,145 4,866 15,589 310 24,363 47,273Total for Quarter 2 8
658 1,903 5,429 124 9,831150012 17,945July 9
382 1,900 5,429 119 9,6071600 6 17,437August 10
302 1,780 5,429 104 8,6671700 5 16,282September 11
1,342 5,583 16,287 347 28,105 51,664Total for Quarter 3 12
219 1,586 5,429 93 7,7491700 2 14,847October 13
92 1,561 4,317 104 8,212180027 14,111November 14
759 1,672 4,317 110 8,803180018 15,442December 15
1,070 4,819 14,063 307 24,764 44,400Total for Quarter 4 16
5,277 19,902 60,741 1,284 101,594 188,175
Total Year to
Date/Year
17
FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400
Schedule Page: 400 Line No.: 1 Column: d
Pacific Standard Time.
Schedule Page: 400 Line No.: 2 Column: d
Pacific Standard Time.
Schedule Page: 400 Line No.: 3 Column: d
Pacific Standard Time.
Schedule Page: 400 Line No.: 4 Column: e
1st Quarter 2012 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 2012 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 2012 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
1st Quarter 2012 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak.
Schedule Page: 400 Line No.: 4 Column: j
1st Quarter 2012 Net System Load information was estimated using metering, scheduling
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.: 5 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 6 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 7 Column: d
Pacific Daylight Time.
Schedule Page: 400 Line No.: 8 Column: e
2nd Quarter 2012 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 2012 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
2nd Quarter 2012 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.: 8 Column: i
2nd Quarter 2012 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak.
Schedule Page: 400 Line No.: 8 Column: j
2nd Quarter 2012 Net System Load information was estimated using metering, scheduling
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
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 2012 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.: 12 Column: f
3rd Quarter 2012 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 2012 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 2012 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 2012 Net System Load information was estimated using metering, scheduling
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.: 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 2012 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.
Peak load includes 207 megawatts of behind-the-meter generation including losses.
Schedule Page: 400 Line No.: 16 Column: f
4th Quarter 2012 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 2012 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.: 16 Column: i
4th Quarter 2012 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 400 Line No.: 16 Column: j
4th Quarter 2012 Net System Load information was estimated using metering, scheduling
and/or contractual data. Reflects actual peak and/or contractual demands of customers'
load at time of Transmission System Peak.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC ENERGY ACCOUNT
PacifiCorp X
/ /2012/Q4
Line
No.
Item
(a)(b)(a)(b)
Line
No.MegaWatt Hours Item MegaWatt Hours
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
SOURCES OF ENERGY1
Generation (Excluding Station Use):2
44,760,136Steam3
Nuclear4
4,268,481Hydro-Conventional5
-4,193Hydro-Pumped Storage6
8,244,632Other7
Less Energy for Pumping8
57,269,056Net Generation (Enter Total of lines 3
through 8)
9
13,716,836Purchases10
Power Exchanges:11
13,296,962Received12
12,824,651Delivered13
472,311Net Exchanges (Line 12 minus line 13)14
Transmission For Other (Wheeling)15
13,731,215Received16
13,615,562Delivered17
115,653Net Transmission for Other (Line 16 minus
line 17)
18
-408,752Transmission By Others Losses19
71,165,104TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
20
DISPOSITION OF ENERGY21
54,549,341Sales to Ultimate Consumers (Including
Interdepartmental Sales)
22
223,987Requirements Sales for Resale (See
instruction 4, page 311.)
23
11,645,802Non-Requirements Sales for Resale (See
instruction 4, page 311.)
24
Energy Furnished Without Charge25
152,155Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
26
4,593,819Total Energy Losses27
71,165,104TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
28
FERC FORM NO. 1 (ED. 12-90)Page 401a
(d)
Day of Month
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MONTHLY PEAKS AND OUTPUT
PacifiCorp X / /2012/Q4
Line
No.Total Monthly Energy Megawatts
(c)(b)(a)
Hour
(e)
MONTHLY PEAK
Month
NAME OF SYSTEM:
Monthly Non-RequirmentsSales for Resale &Associated Losses (See Instr. 4)
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).
(f)
January 29 16 8,445 1,200,879 1800 PST 6,458,846
February 30 6 8,118 1,059,757 0800 PST 5,872,954
March 31 7 7,799 1,013,117 0800 PST 5,797,684
April 32 23 7,337 849,119 1500 PDT 5,218,740
May 33 15 8,006 911,832 1600 PDT 5,589,785
June 34 29 9,020 759,959 1600 PDT 5,782,404
July 35 12 9,831 752,665 1500 PDT 6,257,061
August 36 6 9,607 696,862 1600 PDT 6,250,962
September 37 5 8,667 954,704 1700 PDT 5,649,447
October 38 2 7,520 1,022,840 1700 PDT 5,728,568
November 39 26 8,059 1,210,069 1800 PST 5,972,132
December 40 18 8,584 1,213,999 1800 PST 6,586,521
FERC FORM NO. 1 (ED. 12-90) Page 401b
41 TOTAL 71,165,104 11,645,802
Schedule Page: 401 Line No.: 26 Column: b
For metered locations only.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
ChollaCarbon
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
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.
SteamSteam 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
Full OutdoorOutdoor Boiler 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
19811954 3 Year Originally Constructed
19811957 4 Year Last Unit was Installed
414.00188.60 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
401175 6 Net Peak Demand on Plant - MW (60 minutes)
84298784 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
395172 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
066 11 Average Number of Employees
27039370001287240000 12 Net Generation, Exclusive of Plant Use - KWh
2625238956546 13 Cost of Plant: Land and Land Rights
6101773515564033 14 Structures and Improvements
464180495103943645 15 Equipment Costs
3900012106545 16 Asset Retirement Costs
527862468132570769 17 Total Cost
1275.0301702.9203 18 Cost per KW of Installed Capacity (line 17/5) Including
165001955626 19 Production Expenses: Oper, Supv, & Engr
5914103125897410 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
84123431649863 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
8286561936416 25 Electric Expenses
20030224187262 26 Misc Steam (or Nuclear) Power Expenses
0701 27 Rents
00 28 Allowances
23317010 29 Maintenance Supervision and Engineering
629121363620 30 Maintenance of Structures
60493183581425 31 Maintenance of Boiler (or reactor) Plant
418957576018 32 Maintenance of Electric Plant
2615209291690 33 Maintenance of Misc Steam (or Nuclear) Plant
8407937738540031 34 Total Production Expenses
0.03110.0299 35 Expenses per Net KWh
Coal Oil Composite Coal Oil Composite 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
Tons Barrels Tons Barrels 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
605690 1886 0 1553844 2889 0 38 Quantity (Units) of Fuel Burned
11976 138000 0 9214 130889 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
43.050 136.494 0.000 36.069 112.775 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
42.332 136.494 0.000 37.851 112.775 0.000 41 Average Cost of Fuel per Unit Burned
1.767 23.551 1.784 2.054 20.514 2.064 42 Average Cost of Fuel Burned per Million BTU
0.020 0.000 0.020 0.022 0.000 0.022 43 Average Cost of Fuel Burned per KWh Net Gen
11270.192 8.491 11278.683 10590.382 5.874 10596.256 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03) Page 402
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.
Dave JohnstonCraigColstrip
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2012/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
SteamSteam Steam 1
Semi-OutdoorConventional Outdoor Boiler 2
19591984 1979 3
19721986 1980 4
816.80155.60 172.10 5
715157 167 6
87848782 8784 7
00 0 8
762148 166 9
00 0 10
1880 0 11
49064220001099064000 1344729000 12
104497931355853 137086 13
15323275859477328 36938999 14
820487776161050779 138302748 15
1176371439236 35149 16
995934041221923196 175413982 17
1219.31201426.2416 1019.2561 18
45393833138 334312 19
5809261715728446 22290729 20
00 0 21
309276951802 1634156 22
00 0 23
00 0 24
069426 672401 25
186538281250075 1064091 26
7928216661 0 27
00 0 28
0226201 722759 29
1885033346458 401205 30
120430202338341 3276490 31
8101967264357 774331 32
1901122296707 761195 33
10152008321521612 31931669 34
0.02070.0196 0.0237 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
702119 1005 0 3383247 18331 0680084 4 0 38
8492 140000 0 8148 138000 09932 133693 0 39
19.957 131.343 0.000 16.622 139.683 0.00031.508 126.088 0.000 40
22.213 131.343 0.000 16.414 139.683 0.00032.729 126.088 0.000 41
1.308 22.337 1.318 1.007 24.100 1.0521.648 22.484 1.650 42
0.014 0.000 0.014 0.011 0.001 0.0120.017 0.000 0.017 43
10850.370 5.379 10855.749 11236.529 21.654 11258.18310045.986 0.016 10046.002 44
FERC FORM NO. 1 (REV. 12-03) Page 403
Hunter Unit No. 1Hayden
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
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.
SteamSteam 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
Outdoor BoilerOutdoor Boiler 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
19781965 3 Year Originally Constructed
19781976 4 Year Last Unit was Installed
457.7081.40 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
42578 6 Net Peak Demand on Plant - MW (60 minutes)
82728663 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
41878 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
00 11 Average Number of Employees
2904129000488619000 12 Net Generation, Exclusive of Plant Use - KWh
9688975684632 13 Cost of Plant: Land and Land Rights
6327820517623650 14 Structures and Improvements
31364288467147409 15 Equipment Costs
431476532363 16 Asset Retirement Costs
38704154085988054 17 Total Cost
845.62281056.3643 18 Cost per KW of Installed Capacity (line 17/5) Including
0179935 19 Production Expenses: Oper, Supv, & Engr
5331479911686571 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
3283594952473 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
0329863 25 Electric Expenses
2495461430372 26 Misc Steam (or Nuclear) Power Expenses
142430 27 Rents
00 28 Allowances
0315156 29 Maintenance Supervision and Engineering
2355738409933 30 Maintenance of Structures
69813651416973 31 Maintenance of Boiler (or reactor) Plant
1383908534236 32 Maintenance of Electric Plant
202364457559 33 Maintenance of Misc Steam (or Nuclear) Plant
7003147216713071 34 Total Production Expenses
0.02410.0342 35 Expenses per Net KWh
Coal Oil Composite Coal Oil Composite 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
Tons Barrels Tons Barrels 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
234905 313 0 1323968 3226 0 38 Quantity (Units) of Fuel Burned
11411 137010 0 11226 138000 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
49.795 137.545 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
49.426 137.545 0.000 39.926 0.000 0.000 41 Average Cost of Fuel per Unit Burned
2.166 23.902 2.179 1.778 24.309 1.792 42 Average Cost of Fuel Burned per Million BTU
0.024 0.000 0.024 0.018 0.000 0.018 43 Average Cost of Fuel Burned per KWh Net Gen
10972.076 3.682 10975.758 10235.932 6.439 10242.371 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03) Page 402.1
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.
Hunter - Total PlantHunter Unit No. 3Hunter Unit No. 2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2012/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
SteamSteam Steam 1
Outdoor BoilerOutdoor Boiler Outdoor Boiler 2
19781980 1983 3
19831980 1983 4
1247.80294.50 495.60 5
1163276 484 6
87848366 7479 7
00 0 8
1147269 460 9
00 0 10
2160 0 11
75745930001820865000 2849599000 12
296533519688975 10275401 13
20702500052143586 91603209 14
995130447250825062 430662501 15
1294428431476 431476 16
1233103226313089099 532972587 17
988.22191063.1209 1075.4088 18
-550 -55 19
13784034931803729 52721821 20
00 0 21
90606562179725 3597337 22
00 0 23
00 0 24
00 0 25
62203901138435 2586494 26
390839166 15674 27
00 0 28
00 0 29
68804811553613 2971130 30
289910146121020 15888629 31
64305581488115 3558535 32
53247688546 241566 33
19599495244382349 81581131 34
0.02590.0244 0.0286 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
790593 1595 0 3389124 19729 01274563 14908 0 38
11469 138000 0 11331 138000 011354 138000 0 39
0.000 0.000 0.000 41.089 142.029 0.0000.000 0.000 0.000 40
39.942 0.000 0.000 39.845 142.029 0.00039.700 0.000 0.000 41
1.741 24.421 1.753 1.758 24.505 1.7921.748 24.556 1.816 42
0.017 0.000 0.017 0.018 0.000 0.0180.018 0.001 0.019 43
9959.099 5.077 9964.176 10139.602 15.096 10154.69810156.768 30.322 10187.090 44
FERC FORM NO. 1 (REV. 12-03) Page 403.1
Jim BridgerHuntington
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
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.
SteamSteam 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
Semi-OutdoorOutdoor Boiler 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
19741974 3 Year Originally Constructed
19791977 4 Year Last Unit was Installed
1545.10996.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
1421925 6 Net Peak Demand on Plant - MW (60 minutes)
87848784 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
1407909 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
341161 11 Average Number of Employees
92506680006744160000 12 Net Generation, Exclusive of Plant Use - KWh
11619252386782 13 Cost of Plant: Land and Land Rights
140849737118257607 14 Structures and Improvements
921917205702927608 15 Equipment Costs
50496121207009 16 Asset Retirement Costs
1068978479824779006 17 Total Cost
691.8507828.0914 18 Cost per KW of Installed Capacity (line 17/5) Including
1599736414408 19 Production Expenses: Oper, Supv, & Engr
20315181295307621 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
38122138262629 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
3070 25 Electric Expenses
-1206177612905679 26 Misc Steam (or Nuclear) Power Expenses
2375001000 27 Rents
00 28 Allowances
4826991216824 29 Maintenance Supervision and Engineering
100933112152196 30 Maintenance of Structures
246203266825169 31 Maintenance of Boiler (or reactor) Plant
87067521195547 32 Maintenance of Electric Plant
26902111162346 33 Maintenance of Misc Steam (or Nuclear) Plant
257730719129043419 34 Total Production Expenses
0.02790.0191 35 Expenses per Net KWh
Coal Oil Composite Coal Oil Composite 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
Tons Barrels Tons Barrels 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
2748248 5982 0 5078683 8259 0 38 Quantity (Units) of Fuel Burned
11774 138000 0 9331 138000 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
34.998 139.360 0.000 35.566 134.041 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
34.376 139.360 0.000 39.783 134.041 0.000 41 Average Cost of Fuel per Unit Burned
1.460 24.044 1.472 2.132 23.126 2.142 42 Average Cost of Fuel Burned per Million BTU
0.014 0.000 0.014 0.022 0.000 0.022 43 Average Cost of Fuel Burned per KWh Net Gen
9595.574 5.141 9600.715 10245.890 5.175 10251.065 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03) Page 402.2
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.
Gadsby SteamWyodakNaughton
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2012/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
SteamSteam Steam 1
OutdoorOutdoor Boiler Conventional 2
19511963 1978 3
19551971 1978 4
251.60707.20 289.70 5
166712 276 6
22408784 8305 7
00 0 8
231687 268 9
00 0 10
35139 67 11
1203480005056959000 1990902000 12
12520901094739 210526 13
15104432113655782 51193186 14
65835385634446600 393394231 15
58700818809893 490453 16
82778915768007014 445288396 17
329.01001085.9828 1537.0673 18
50041153055 195245 19
14231285105801044 19828875 20
00 0 21
05562053 41419 22
00 0 23
00 0 24
059619 0 25
405379013061246 4422350 26
01259 15119 27
00 0 28
01083545 0 29
1524801320614 330423 30
101490511294077 6347538 31
27663473763244 850363 32
316861910489 175264 33
22585709143010245 32206596 34
0.18770.0283 0.0162 35
Coal Gas Composite GasCoal Oil Composite 36
Tons MCF MCFTons Barrels 37
2745732 89796 0 1818972 0 01503568 4499 0 38
9803 1041 0 1045 0 07942 138000 0 39
38.332 10.129 0.000 7.824 0.000 0.00012.835 136.918 0.000 40
38.202 10.129 0.000 7.824 0.000 0.00012.778 136.918 0.000 41
1.948 9.728 1.962 7.489 0.000 0.0000.804 23.623 0.829 42
0.021 0.000 0.021 0.118 0.000 0.0000.010 0.000 0.010 43
10645.435 18.490 10663.925 15790.026 0.000 0.00011996.030 13.098 12009.128 44
FERC FORM NO. 1 (REV. 12-03) Page 403.2
BlundellHermiston
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
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.
Steam - GeothermalCombined Cycle 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
IndoorOutdoor 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
19841996 3 Year Originally Constructed
20071996 4 Year Last Unit was Installed
38.10279.60 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
36245 6 Net Peak Demand on Plant - MW (60 minutes)
86187424 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
34237 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
230 11 Average Number of Employees
2685420001149724000 12 Net Generation, Exclusive of Plant Use - KWh
41195596842245 13 Cost of Plant: Land and Land Rights
823408212844996 14 Structures and Improvements
69321581158510917 15 Equipment Costs
1744133214373 16 Asset Retirement Costs
120495392172412531 17 Total Cost
3162.6087616.6400 18 Cost per KW of Installed Capacity (line 17/5) Including
252570 19 Production Expenses: Oper, Supv, & Engr
047631026 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
11603230 22 Steam Expenses
39370270 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
09287696 25 Electric Expenses
5692020 26 Misc Steam (or Nuclear) Power Expenses
59820 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
4195190 30 Maintenance of Structures
1935770 31 Maintenance of Boiler (or reactor) Plant
6296500 32 Maintenance of Electric Plant
472140 33 Maintenance of Misc Steam (or Nuclear) Plant
698775156918722 34 Total Production Expenses
0.02600.0495 35 Expenses per Net KWh
Gas 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
MCF 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
8714895 0 0 0 0 0 38 Quantity (Units) of Fuel Burned
1020 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
5.465 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
5.465 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
5.360 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.041 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
7728.566 0.000 0.000 0.000 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03) Page 402.3
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.
Gadsby PeakersChehalisCamas Co-Gen
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2012/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
Gas TurbineSteam Combined Cycle 1
OutdoorOutdoor Boiler Outdoor 2
20021996 2003 3
20021996 2003 4
181.1061.50 593.30 5
12026 514 6
24456568 2617 7
00 0 8
12014 520 9
00 0 10
00 18 11
9439100078036000 849938000 12
00 1973791 13
42730005733734 23264896 14
7638412128716806 314522888 15
00 689117 16
8065712134450540 340450692 17
445.3734560.1714 573.8255 18
00 176623 19
94150920 47149887 20
00 0 21
00 0 22
00 0 23
00 0 24
59659621507 2533731 25
00 0 26
00 34668 27
00 0 28
00 0 29
2328910 110048 30
00 0 31
6389090 2786575 32
00 0 33
1088348821507 52791532 34
0.11530.0003 0.0621 35
GasGas 36
MCFMCF 37
0 0 0 1210063 0 06431911 0 0 38
0 0 0 1041 0 01033 0 0 39
0.000 0.000 0.000 7.781 0.000 0.0007.331 0.000 0.000 40
0.000 0.000 0.000 7.781 0.000 0.0007.331 0.000 0.000 41
0.000 0.000 0.000 7.475 0.000 0.0007.096 0.000 0.000 42
0.000 0.000 0.000 0.100 0.000 0.0000.055 0.000 0.000 43
0.000 0.000 0.000 13344.726 0.000 0.0007817.313 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403.3
Lake SideCurrant Creek
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2012/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
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.
Combined CycleCombined Cycle 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
OutdoorOutdoor 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
20072005 3 Year Originally Constructed
20072006 4 Year Last Unit was Installed
591.30566.90 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
552567 6 Net Peak Demand on Plant - MW (60 minutes)
85007659 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
558550 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
2519 11 Average Number of Employees
28909380002132523000 12 Net Generation, Exclusive of Plant Use - KWh
172786833403277 13 Cost of Plant: Land and Land Rights
2784039244108711 14 Structures and Improvements
311614489325722454 15 Equipment Costs
0134848 16 Asset Retirement Costs
356733564373369290 17 Total Cost
603.3038658.6158 18 Cost per KW of Installed Capacity (line 17/5) Including
12548167800 19 Production Expenses: Oper, Supv, & Engr
149162596111149193 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
00 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
37416362769637 25 Electric Expenses
00 26 Misc Steam (or Nuclear) Power Expenses
22456 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
1148289800026 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
8033296404209 32 Maintenance of Electric Plant
00 33 Maintenance of Misc Steam (or Nuclear) Plant
154981555121190921 34 Total Production Expenses
0.05360.0568 35 Expenses per Net KWh
Gas Gas 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
MCF MCF 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
15426336 0 0 20470520 0 0 38 Quantity (Units) of Fuel Burned
1055 0 0 1024 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
7.205 0.000 0.000 7.287 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
7.205 0.000 0.000 7.287 0.000 0.000 41 Average Cost of Fuel per Unit Burned
6.832 0.000 0.000 7.119 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.052 0.000 0.000 0.052 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
7628.814 0.000 0.000 7247.963 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03) Page 402.4
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.
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2012/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
0 1
0 2
0 3
0 4
0.000.00 0.00 5
00 0 6
00 0 7
00 0 8
00 0 9
00 0 10
00 0 11
00 0 12
00 0 13
00 0 14
00 0 15
00 0 16
00 0 17
00 0 18
00 0 19
00 0 20
00 0 21
00 0 22
00 0 23
00 0 24
00 0 25
00 0 26
00 0 27
00 0 28
00 0 29
00 0 30
00 0 31
00 0 32
00 0 33
00 0 34
0.00000.0000 0.0000 35
36
37
0 0 0 0 0 00 0 0 38
0 0 0 0 0 00 0 0 39
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403.4
Schedule Page: 402 Line No.: -1 Column: c
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
The Colstrip Plant is operated by PPL Montana, LLC and is jointly owned. PacifiCorp owns a
10.0% share of Colstrip Plant Unit Nos. 3 and 4. Data reported in column (d) represents
PacifiCorp's share.
Schedule Page: 402 Line No.: -1 Column: e
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 Unit Nos. 1 and 2 and 12.86%
of common facilities. Data in column (e) represents PacifiCorp's share.
Schedule Page: 402 Line No.: 11 Column: c
PacifiCorp does not have employees at the Cholla Plant.
Schedule Page: 402 Line No.: 11 Column: d
PacifiCorp does not have employees at the Colstrip Plant.
Schedule Page: 402 Line No.: 11 Column: e
PacifiCorp does not have employees at the Craig Plant.
Schedule Page: 402 Line No.: 20 Column: e
Amount includes intercompany profits.
Schedule Page: 402.1 Line No.: -1 Column: b
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, a 12.6% (33 MW) share of
Hayden Unit No. 2 and 17.5% of common facilities. Data reported in column (b) represents
PacifiCorp's share.
Schedule Page: 402.1 Line No.: -1 Column: c
Hunter Unit No. 1 is operated by PacifiCorp and is jointly 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
2012 were $1.3 million and were primarily credited to Account 506, Miscellaneous steam
power expenses.
Schedule Page: 402.1 Line No.: -1 Column: d
Hunter Unit No. 2 is operated by PacifiCorp and is jointly owned by PacifiCorp, Deseret
Power Electric Cooperative and Utah Associated Municipal Power Systems, each with an
undivided interest of 60.31%, 25.108% and 14.582%, 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 2012 were $7.2
million and were primarily credited to Account 506, Miscellaneous steam power expenses.
Schedule Page: 402.1 Line No.: -1 Column: f
Refer to plant statistics for each Hunter Unit Nos. 1, 2 and 3 on pages 402.1 and 403.1.
Schedule Page: 402.1 Line No.: 11 Column: b
PacifiCorp does not have employees at the Hayden Plant.
Schedule Page: 402.1 Line No.: 11 Column: c
Refer to Hunter - Total Plant on page 403.1 for the average number of employees.
Schedule Page: 402.1 Line No.: 11 Column: d
Refer to Hunter - Total Plant on page 403.1 for the average number of employees.
Schedule Page: 402.1 Line No.: 11 Column: e
Refer to Hunter - Total Plant on page 403.1 for the average number of employees.
Schedule Page: 402.2 Line No.: -1 Column: c
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
2012 were $26.2 million and were primarily credited to Account 506, Miscellaneous steam
power expenses.
Schedule Page: 402.2 Line No.: -1 Column: e
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 2012 were $3.5
million and were primarily credited to Account 506, Miscellaneous steam power expenses.
Schedule Page: 402.2 Line No.: 20 Column: c
Amount includes intercompany profits.
Schedule Page: 402.3 Line No.: -1 Column: b
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 (b)
represents PacifiCorp's share. See page 326, Purchased Power, of this Form No. 1 for
further information on Hermiston Generating Company, L.P.
Schedule Page: 402.3 Line No.: -1 Column: c
All or some of the renewable energy attributes associated with generation from the
Blundell generating facility may be: (a) used in future years to comply with renewable
portfolio standards 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: d
PacifiCorp owns the steam turbine generator and associated systems directly related to the
operation of the Camas Co-Generation 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 Corporation retained ownership of these
modifications. Georgia-Pacific Corporation 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 renewable portfolio
standards 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: b
PacifiCorp does not have employees at the Hermiston Plant.
Schedule Page: 402.3 Line No.: 11 Column: d
PacifiCorp does not have employees at the Camas paper mill.
Schedule Page: 402.3 Line No.: 11 Column: f
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-up purposes.
Schedule Page: 402 Line No.: 36 Column: d2
Colstrip - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 36 Column: e2
Craig - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 36 Column: f2
Dave Johnston - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: b2
Hayden - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: c2
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Hunter Unit No. 1 - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: d2
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
Hunter - Total Plant - Fuel oil is used for start-up purposes.
Schedule Page: 402.2 Line No.: 36 Column: b2
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
2082
Copco No. 2
2082
Copco No. 1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2012/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
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.
Kind of Plant (Run-of-River or Storage) 1 Storage Run-of-River
Plant Construction type (Conventional or Outdoor) 2 Conventional Conventional
Year Originally Constructed 3 1918 1925
Year Last Unit was Installed 4 1922 1925
Total installed cap (Gen name plate Rating in MW) 5 20.00 27.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 27 33
Plant Hours Connect to Load 7 8,715 8,727
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 28 34
(b) Under the Most Adverse Oper Conditions 10 28 34
Average Number of Employees 11 1 2
Net Generation, Exclusive of Plant Use - Kwh 12 85,352,000 109,416,000
Cost of Plant 13
Land and Land Rights 14 107,019 20,914
Structures and Improvements 15 1,615,906 2,265,689
Reservoirs, Dams, and Waterways 16 2,851,569 2,954,724
Equipment Costs 17 5,261,118 10,342,093
Roads, Railroads, and Bridges 18 105,442 479,588
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 9,941,054 16,063,008
Cost per KW of Installed Capacity (line 20 / 5) 21 497.0527 594.9262
Production Expenses 22
Operation Supervision and Engineering 23 -76,303 -101,905
Water for Power 24 0 0
Hydraulic Expenses 25 2,156 2,911
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 1,018,689 1,315,918
Rents 28 15,721 19,233
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 13,430 12,347
Maintenance of Reservoirs, Dams, and Waterways 31 18,156 -5,962
Maintenance of Electric Plant 32 65,490 44,013
Maintenance of Misc Hydraulic Plant 33 14,347 19,369
Total Production Expenses (total 23 thru 33) 34 1,071,686 1,305,924
Expenses per net KWh 35 0.0126 0.0119
FERC FORM NO. 1 (REV. 12-03) Page 406
1927
Clearwater No. 1 Cutler
2420
Clearwater No. 2
1927
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
PacifiCorp X
/ /2012/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Run-of-River StorageRun-of-River 1
Outdoor ConventionalOutdoor 2
1953 19271953 3
1953 19271953 4
26.00 30.0015.00 5
22 2910 6
8,069 5,6878,739 7
8
31 2918 9
31 2918 10
1 31 11
54,153,000 50,408,00050,701,000 12
13
0 3,511,1850 14
1,737,299 3,968,8921,226,050 15
14,745,199 7,582,6084,526,756 16
1,771,075 14,601,4891,193,576 17
250,151 572,05950,817 18
0 00 19
18,503,724 30,236,2336,997,199 20
711.6817 1,007.8744466.4799 21
22
-29,194 -11,077-26,615 23
3,668 02,116 24
128,192 54,75273,957 25
0 00 26
486,386 839,868372,291 27
42,692 16324,630 28
52 030 29
50,123 8,31016,999 30
48,739 24,27016,254 31
130,464 6,13814,156 32
128,490 205,51244,908 33
989,612 1,127,936538,726 34
0.0183 0.02240.0106 35
FERC FORM NO. 1 (REV. 12-03) Page 407
20
Grace
1927
Fish Creek
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2012/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
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.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River Storage
Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional
Year Originally Constructed 3 1952 1908
Year Last Unit was Installed 4 1952 1923
Total installed cap (Gen name plate Rating in MW) 5 11.00 33.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 10 30
Plant Hours Connect to Load 7 5,882 8,071
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 10 33
(b) Under the Most Adverse Oper Conditions 10 10 33
Average Number of Employees 11 1 3
Net Generation, Exclusive of Plant Use - Kwh 12 42,829,000 82,593,000
Cost of Plant 13
Land and Land Rights 14 0 62,169
Structures and Improvements 15 918,915 1,962,958
Reservoirs, Dams, and Waterways 16 12,444,216 10,964,143
Equipment Costs 17 1,863,628 4,338,888
Roads, Railroads, and Bridges 18 533,015 105,373
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 15,759,774 17,433,531
Cost per KW of Installed Capacity (line 20 / 5) 21 1,432.7067 528.2888
Production Expenses 22
Operation Supervision and Engineering 23 -14,124 -290,114
Water for Power 24 1,552 0
Hydraulic Expenses 25 54,235 68,200
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 353,115 1,651,269
Rents 28 18,062 9,350
Maintenance Supervision and Engineering 29 22 0
Maintenance of Structures 30 14,745 63,294
Maintenance of Reservoirs, Dams, and Waterways 31 27,143 214,758
Maintenance of Electric Plant 32 67,686 85,695
Maintenance of Misc Hydraulic Plant 33 32,932 99,606
Total Production Expenses (total 23 thru 33) 34 555,368 1,902,058
Expenses per net KWh 35 0.0130 0.0230
FERC FORM NO. 1 (REV. 12-03) Page 406.1
2082
Iron Gate Lemolo No. 1
1927
JC Boyle
2082
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
PacifiCorp X
/ /2012/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Storage StorageStorage 1
Outdoor OutdoorOutdoor 2
1958 19551962 3
1958 19551962 4
97.98 31.9918.00 5
89 3119 6
5,822 8,2458,479 7
8
83 3219 9
83 3219 10
1 11 11
240,436,000 166,546,000100,757,000 12
13
25,845 0341,706 14
3,360,801 2,300,8916,613,508 15
14,555,422 15,267,69113,705,126 16
15,240,195 6,048,6822,663,338 17
886,710 484,7281,076,116 18
0 00 19
34,068,973 24,101,99224,399,794 20
347.7135 753.42271,355.5441 21
22
175,210 -34,8081,281,336 23
0 4,5130 24
10,564 157,7264,310 25
0 00 26
752,476 615,183925,564 27
2,980 52,52712,945 28
0 640 29
40,707 53,6936,536 30
26,908 137,24117,231 31
53,572 96,296163,127 32
126,698 95,77412,912 33
1,189,115 1,178,2092,423,961 34
0.0049 0.00710.0241 35
FERC FORM NO. 1 (REV. 12-03) Page 407.1
935
Merwin
1927
Lemolo No. 2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2012/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
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.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River Storage (Re-Reg)
Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional
Year Originally Constructed 3 1956 1931
Year Last Unit was Installed 4 1956 1958
Total installed cap (Gen name plate Rating in MW) 5 38.50 136.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 35 149
Plant Hours Connect to Load 7 8,774 8,782
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 39 151
(b) Under the Most Adverse Oper Conditions 10 39 151
Average Number of Employees 11 1 2
Net Generation, Exclusive of Plant Use - Kwh 12 207,037,000 657,225,000
Cost of Plant 13
Land and Land Rights 14 0 1,086,417
Structures and Improvements 15 4,128,326 49,329,570
Reservoirs, Dams, and Waterways 16 31,090,995 11,855,653
Equipment Costs 17 11,737,456 18,375,213
Roads, Railroads, and Bridges 18 1,940,746 2,892,565
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 48,897,523 83,539,418
Cost per KW of Installed Capacity (line 20 / 5) 21 1,270.0655 614.2604
Production Expenses 22
Operation Supervision and Engineering 23 -66,443 956,087
Water for Power 24 5,431 12,574
Hydraulic Expenses 25 189,823 697,204
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 692,173 749,343
Rents 28 63,216 57,016
Maintenance Supervision and Engineering 29 77 0
Maintenance of Structures 30 50,106 19,676
Maintenance of Reservoirs, Dams, and Waterways 31 51,703 135,168
Maintenance of Electric Plant 32 24,482 103,362
Maintenance of Misc Hydraulic Plant 33 115,264 373,448
Total Production Expenses (total 23 thru 33) 34 1,125,832 3,103,878
Expenses per net KWh 35 0.0054 0.0047
FERC FORM NO. 1 (REV. 12-03) Page 406.2
1927
Toketee Prospect No. 2
2630
Oneida
20
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
PacifiCorp X
/ /2012/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Storage Run-of-RiverStorage 1
Conventional ConventionalConventional 2
1915 19281949 3
1920 19281950 4
30.00 32.0042.50 5
14 3643 6
8,731 7,8818,716 7
8
28 3645 9
28 3645 10
2 11 11
32,971,000 238,047,000263,788,000 12
13
36,698 105,1680 14
1,861,886 3,107,2153,626,010 15
6,083,220 29,875,84310,730,500 16
5,432,798 6,609,1613,286,759 17
503,332 305,160264,441 18
0 00 19
13,917,934 40,002,54717,907,710 20
463.9311 1,250.0796421.3579 21
22
-264,820 245,401-37,979 23
0 10,4015,995 24
62,000 6,342209,545 25
0 00 26
978,624 494,501698,997 27
8,500 3,86269,784 28
0 085 29
11,606 43,03256,934 30
3,149 316,82069,647 31
97,184 19,768206,614 32
73,438 42,847127,239 33
969,681 1,182,9741,406,861 34
0.0294 0.00500.0053 35
FERC FORM NO. 1 (REV. 12-03) Page 407.2
20
Soda
1927
Slide Creek
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2012/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
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.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River Storage
Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional
Year Originally Constructed 3 1951 1924
Year Last Unit was Installed 4 1951 1924
Total installed cap (Gen name plate Rating in MW) 5 18.00 14.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 17 9
Plant Hours Connect to Load 7 8,524 8,088
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 18 14
(b) Under the Most Adverse Oper Conditions 10 18 14
Average Number of Employees 11 1 2
Net Generation, Exclusive of Plant Use - Kwh 12 96,627,000 20,023,000
Cost of Plant 13
Land and Land Rights 14 0 511,083
Structures and Improvements 15 2,173,443 713,731
Reservoirs, Dams, and Waterways 16 14,331,075 8,381,621
Equipment Costs 17 8,962,026 5,364,557
Roads, Railroads, and Bridges 18 463,083 0
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 25,929,627 14,970,992
Cost per KW of Installed Capacity (line 20 / 5) 21 1,440.5348 1,069.3566
Production Expenses 22
Operation Supervision and Engineering 23 -28,680 -112,440
Water for Power 24 45,039 0
Hydraulic Expenses 25 88,749 28,934
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 409,034 552,784
Rents 28 29,556 3,967
Maintenance Supervision and Engineering 29 36 0
Maintenance of Structures 30 36,130 9,684
Maintenance of Reservoirs, Dams, and Waterways 31 22,467 32,817
Maintenance of Electric Plant 32 63,882 51,174
Maintenance of Misc Hydraulic Plant 33 53,890 33,791
Total Production Expenses (total 23 thru 33) 34 720,103 600,711
Expenses per net KWh 35 0.0075 0.0300
FERC FORM NO. 1 (REV. 12-03) Page 406.3
1927
Soda Springs Yale
2071
Swift No. 1
2111
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
PacifiCorp X
/ /2012/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Storage StorageStorage (Re-Reg) 1
Conventional ConventionalOutdoor 2
1958 19531952 3
1958 19531952 4
240.00 134.0011.00 5
255 16311 6
6,551 7,4097,313 7
8
264 16412 9
263 16412 10
2 22 11
809,468,000 702,744,00050,541,000 12
13
14,163,614 8,363,0130 14
65,660,841 7,712,7151,219,251 15
45,249,478 28,410,90988,716,620 16
20,120,170 15,037,2332,180,534 17
1,009,965 1,471,23056,124 18
0 00 19
146,204,068 60,995,10092,172,529 20
609.1836 455.18738,379.3208 21
22
1,744,707 887,53418,567 23
22,189 12,3891,552 24
1,587,676 686,95154,235 25
0 00 26
1,014,429 642,433266,444 27
100,617 56,17818,062 28
0 022 29
29,896 21,13934,019 30
144,257 139,19644,859 31
226,702 -42,059120,853 32
614,959 354,64732,932 33
5,485,432 2,758,408591,545 34
0.0068 0.00390.0117 35
FERC FORM NO. 1 (REV. 12-03) Page 407.3
0 0
Olmsted
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2012/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
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.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River
Plant Construction type (Conventional or Outdoor) 2 Conventional
Year Originally Constructed 3 1904
Year Last Unit was Installed 4 1922
Total installed cap (Gen name plate Rating in MW) 5 10.30 0.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 7 0
Plant Hours Connect to Load 7 7,856 0
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 10 0
(b) Under the Most Adverse Oper Conditions 10 10 0
Average Number of Employees 11 3 0
Net Generation, Exclusive of Plant Use - Kwh 12 19,185,000 0
Cost of Plant 13
Land and Land Rights 14 0 0
Structures and Improvements 15 188,165 0
Reservoirs, Dams, and Waterways 16 0 0
Equipment Costs 17 31,914 0
Roads, Railroads, and Bridges 18 12,641 0
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 232,720 0
Cost per KW of Installed Capacity (line 20 / 5) 21 22.5942 0.0000
Production Expenses 22
Operation Supervision and Engineering 23 -3,803 0
Water for Power 24 0 0
Hydraulic Expenses 25 18,798 0
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 357,499 0
Rents 28 56 0
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 -1,270 0
Maintenance of Reservoirs, Dams, and Waterways 31 9,879 0
Maintenance of Electric Plant 32 7,736 0
Maintenance of Misc Hydraulic Plant 33 171,161 0
Total Production Expenses (total 23 thru 33) 34 560,056 0
Expenses per net KWh 35 0.0292 0.0000
FERC FORM NO. 1 (REV. 12-03) Page 406.4
0 0 0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
PacifiCorp X
/ /2012/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
1
2
3
4
0.00 0.000.00 5
0 00 6
0 00 7
8
0 00 9
0 00 10
0 00 11
0 00 12
13
0 00 14
0 00 15
0 00 16
0 00 17
0 00 18
0 00 19
0 00 20
0.0000 0.00000.0000 21
22
0 00 23
0 00 24
0 00 25
0 00 26
0 00 27
0 00 28
0 00 29
0 00 30
0 00 31
0 00 32
0 00 33
0 00 34
0.0000 0.00000.0000 35
FERC FORM NO. 1 (REV. 12-03) Page 407.4
Schedule 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 renewable portfolio
standards 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
Schedule Page: 406 Line No.: 1 Column: d
Clearwater No. 1
Forebay for peaking
Schedule Page: 406 Line No.: 1 Column: e
Clearwater No. 2
Forebay for peaking
Schedule Page: 406.1 Line No.: 1 Column: b
Fish Creek
Forebay for peaking
Schedule Page: 406.1 Line No.: 1 Column: d
Iron Gate
Storage for regulation
Schedule Page: 406.1 Line No.: 1 Column: e
JC Boyle
Pondage for peaking - storage, Upper Klamath Lake
Schedule Page: 406.1 Line No.: 1 Column: f
Lemolo No. 1
Storage, Lemolo Lake
Schedule Page: 406.2 Line No.: 1 Column: b
Lemolo No. 2
Storage, Lemolo Lake
Schedule Page: 406.2 Line No.: 1 Column: d
Toketee
Pondage for peaking - storage, Lemolo Lake
Schedule Page: 406.2 Line No.: 1 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants)
PacifiCorp X / /2012/Q4
Line
No.Name of Plant
Installed Capacity
(c)(b)(a)
Cost of PlantNet PeakDemand
(d)
YearOrig.Const.Name Plate Rating
(In MW)MW(60 min.)
Net GenerationExcludingPlant Use
(e) (f)
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.
Hydroelectric : Licensed Proj. No. 1
6.70 3.9 1,903,000 35,512,6861917Ashton 2381 2
1.11 1.0 3,344,000 1,335,0931913Bend 3
4.15 4.6 33,426,000 7,373,5471910Big Fork 2652 4
2.81 3.0 17,897,000 1,861,0571957Eagle Point 5
3.20 2.0 1,991,6951924East Side 2082 6
2.20 2.0 10,432,000 1,395,0111903Fall Creek 2082 7
0.16 597,6301922Fountain Green 8
2.00 1.2 6,406,000 5,234,5691896Granite 9
0.75 0.5 1,489,000 683,0451917Gunlock 10
1.73 1.4 3,833,000 2,809,6251983Last Chance 11
0.72 0.7 2,434,000 432,4941910Paris 12
5.00 4.0 15,091,000 11,000,9321897Pioneer 2722 13
3.76 4.6 20,393,000 2,531,5261912Prospect No. 1 2630 14
7.20 8.0 37,518,000 8,343,8681932Prospect No. 3 2337 15
1.00 1.0 3,833,000 2,365,5241944Prospect No. 4 2630 16
0.80 0.4 1,326,000 933,7221926Sand Cove 17
1.00 1.2 4,803,000 1,626,6261895Stairs 597 18
0.50 1,337,2791915St. Anthony 2381 19
0.50 0.3 1,030,000 893,1251920Veyo 20
0.74 0.3 -45,000 1,194,4861986Viva Naughton 21
1.10 1.0 5,611,000 2,887,1271921Wallowa Falls 308 22
3.85 2.0 15,100,000 2,962,1091911Weber 1744 23
0.60 0.6 1,810,000 468,5741908West Side 2082 24
7,527,975Keno Regulating Dam 2082 25
3,847,587Upper Klamath Lake 2082 26
15,458,169North Umpqua 1927 27
28
Pumping Plant: 29
-4.50 -3.0 -4,193,000 19,248,1451917Lifton 30
31
Wind: 32
111.00 112.0 387,973,000 239,618,2182010Dunlap Ranch 1 33
32.15 33.0 85,137,000 36,515,9081999Foote Creek 34
99.00 100.0 314,476,000 201,049,7492008Glenrock 35
39.00 38.0 119,142,000 87,388,6842009Glenrock III 36
99.00 100.0 292,022,000 201,829,1002009Rolling Hills 37
94.00 95.0 221,156,000 183,027,1322008Goodnoe Hills 38
100.50 102.0 190,905,000 175,690,2432006Leaning Juniper 1 39
140.40 139.0 358,669,000 239,478,5352007Marengo 40
70.20 69.0 177,552,000 129,148,7932008Marengo II 41
99.00 100.0 342,192,000 200,758,0392008Seven Mile Hill 42
19.50 20.0 72,558,000 42,010,2092008Seven Mile Hill II 43
99.00 98.0 315,879,000 219,515,4802009High Plains 44
28.50 29.0 94,789,000 56,961,3912009McFadden Ridge I 45
46
FERC FORM NO. 1 (REV. 12-03) Page 410
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants) (Continued)
PacifiCorp X / /2012/Q4
Line
No.(i)(h)(g)(j) (k) (l)
Operation
Exc'l. Fuel
Production Expenses
Fuel Maintenance Kind of Fuel Fuel Costs (in cents
(per Million Btu)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl AssetRetire. Costs) Per MW
1
76,526 5,300,401 2Water 367,409
29,047 1,202,786 3Water 57,264
50,310 1,776,758 4Water 313,976
44,632 662,298 5Water 225,627
6,920 622,405 6Water 37,406
144,095 634,096 7Water 153,733
1,088 3,735,188 8Water 5,679
20,985 2,617,285 9Water 173,630
58,452 910,727 10Water 65,737
16,368 1,624,061 11Water 103,716
47,888 600,686 12Water 63,914
113,529 2,200,186 13Water 367,005
23,354 673,278 14Water 169,165
345,078 1,158,871 15Water 291,122
25,067 2,365,524 16Water 50,335
13,987 1,167,153 17Water 63,586
13,834 1,626,626 18Water 133,818
2,141 2,674,558 19Water 55,684
91,170 1,786,250 20Water 67,832
31,859 1,614,170 21Water 79,107
68,798 2,624,661 22Water 77,992
39,872 769,379 23Water 249,197
14,359 780,957 24Water 56,414
23,399 25 8,093
10,632 26 315,040
27
28
29
43,441 -4,277,366 30Water 307,728
31
32
2,017,563 2,158,723 33Wind 489,426
2,500 1,135,798 34Wind 1,660,970
2,057,419 2,030,806 35Wind 400,851
601,039 2,240,735 36Wind 46,584
1,097,841 2,038,678 37Wind 421,491
1,407,823 1,947,097 38Wind 656,635
1,134,225 1,748,162 39Wind 1,568,930
2,137,651 1,705,688 40Wind 1,598,918
1,058,379 1,839,726 41Wind 716,078
1,849,355 2,027,859 42Wind 591,417
360,024 2,154,370 43Wind 99,170
2,565,222 2,217,328 44Wind 868,449
746,044 1,998,645 45Wind 238,105
46
FERC FORM NO. 1 (REV. 12-03) Page 411
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants)
PacifiCorp X / /2012/Q4
Line
No.Name of Plant
Installed Capacity
(c)(b)(a)
Cost of PlantNet PeakDemand
(d)
YearOrig.Const.Name Plate Rating
(In MW)MW(60 min.)
Net GenerationExcludingPlant Use
(e) (f)
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.
Solar: 1
2.00 1.9 585,000 74,9862012Black Cap 2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03) Page 410.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants) (Continued)
PacifiCorp X / /2012/Q4
Line
No.(i)(h)(g)(j) (k) (l)
Operation
Exc'l. Fuel
Production Expenses
Fuel Maintenance Kind of Fuel Fuel Costs (in cents
(per Million Btu)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl AssetRetire. Costs) Per MW
1
37,493 2Solar 149,884
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03) Page 411.1
Schedule Page: 410 Line No.: 1 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 renewable portfolio
standards 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.: 19 Column: a
St. Anthony
PacifiCorp has entered into an agreement for the sale of the St. Anthony hydroelectric
generating facility with St. Anthony Hydro LLC, which is subject to certain regulatory
approvals. For more information, refer to Important Changes During the Year, Item 3, in
this FERC Form No. 1.
Schedule Page: 410 Line No.: 25 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.: 26 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.: 27 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.: 32 Column: a
Common 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 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 renewable portfolio
standards 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.: 34 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 34 represents PacifiCorp's share.
Schedule Page: 410.1 Line No.: 2 Column: a
PacifiCorp has entered into an agreement with RBS Asset Finance, Inc. to lease the Black
Cap Solar generating facility. The lease has a 16-year term from October 2012 to October
2028 and is accounted for as an operating lease. For more information, refer to Important
Changes During the Year, Item 4, in this FERC Form No. 1.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2012/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
Steel Tower 500.00 500.00 47.00 1 1 MALIN , OR PG&E ROUND MTN ,CA
Steel Tower 500.00 500.00 74.00 1 2 DIXONVILLE 500KV , OR MERIDIAN , OR
Steel Tower 500.00 500.00 7.00 1 3 CAPTAIN JACK , OR MALIN , OR
Steel Tower 500.00 500.00 26.00 1 4 KLAMATH CO-GEN , OR CAPTAIN JACK , OR
Steel Tower 500.00 500.00 58.00 1 5 MERIDIAN , OR KLAMATH CO-GEN , OR
Steel Tower 500.00 500.00 58.00 1 6 ALVEY , OR DIXONVILLE 500KV , OR
Steel Tower 500.00 500.00 447.00 1 7 MIDPOINT , OR MALIN , OR
Steel Tower 500.00 500.00 1.00 1 8 COLSTRIP 4, MT SWITCHYARD, MT
Steel Tower 500.00 500.00 112.00 1 9 COLSTRIP, MT BROADVIEW A, MT
Steel Tower 500.00 500.00 116.00 1 10 COLSTRIP, MT BROADVIEW B, MT
Steel Tower 500.00 500.00 133.00 1 11 BROADVIEW, MT TOWNSEND A, MT
Steel Tower 500.00 500.00 133.00 1 12 BROADVIEW, MT TOWNSEND B, MT
13 500 kV costs and expenses
14
1,212.00 12 15 Subtotal 500 kV
16
Steel SP 345.00 345.00 11.00 1 17 90TH SOUTH , UT CAMP WILLIAMS #4 , UT
345.00 345.00 11.00 1 18 90th SOUTH , UT CAMP WILLIAMS #3 , UT
Steel SP 345.00 345.00 11.00 1 19 90TH SOUTH , UT CAMP WILLIAMS #1 , UT
345.00 345.00 69.00 1 20 BEN LOMOND , UT CAMP WILLIAMS , UT
Steel SP 345.00 345.00 47.00 1 21 BEN LOMOND , UT TERMINAL , UT
Steel SP 345.00 345.00 47.00 1 22 BEN LOMOND , UT TERMINAL , UT
Steel SP 345.00 345.00 82.00 1 23 BEN LOMOND , UT POPULUS #1 , UT
345.00 345.00 86.00 1 24 BEN LOMOND , UT POPULUS #2 , UT
Wood - H 345.00 345.00 47.00 1 25 CAMP WILLIAMS , UT MONA , UT
Wood - H 345.00 345.00 47.00 1 26 CAMP WILLIAMS , UT MONA #1 , UT
Steel Tower 345.00 345.00 47.00 1 27 CAMP WILLIAMS , UT MONA #2 , UT
345.00 345.00 42.00 5.00 1 28 CAMP WILLIAMS , UT MONA #4 , UT
Steel SP 345.00 345.00 1.00 1 29 CURRENT CREEK , UT MONA , UT
Wood - H 345.00 345.00 20.00 1 30 EMERY , UT HUNTINGTON , UT
Steel - H 345.00 345.00 74.00 1 31 EMERY , UT SIGURD #1 , UT
Steel - H 345.00 345.00 75.00 1 32 EMERY , UT SIGURD #2 , UT
Steel Tower 345.00 345.00 121.00 1 33 EMERY , UT CAMP WILLIAMS , UT
Wood - H 345.00 345.00 101.00 1 34 FOUR CORNERS , NM PINTO , UT
Wood - H 345.00 345.00 41.00 1 35 GOSHEN , ID KINPORT , ID
FERC FORM NO. 1 (ED. 12-87) Page 422
36 TOTAL 16,076.00 741.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
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 (l) on the book cost at end of year.
3-1852 ACSR 51/27 1
3-1272 ACSR 36/1 2
3-1272 ACSR 36/1 3
3-1272 ACSR 54/19 4
3-1272 ACSR 54/19 5
3-2250 AAC /91 6
3-1272 ACSR 36/1 7
8
9
10
11
12
284,333,156 270,049,800 14,283,356 949,500 309,160 640,340 13
14
284,333,156 270,049,800 14,283,356 949,500 309,160 640,340 15
16
17
18
1272 ACSR 45/7 19
1272 ACSR 45/7 20
1272 ACSR 45/7 21
1272 ACSR 45/7 22
1272 ACSR 45/7 23
1272 ACSR 45/7 24
954 ACSR 45/7 25
1272 ACSR 45/7 26
954 ACSR 45/7 27
954 ACSR 45/7 28
954 ACSR 54/7 29
954 ACSR 54/7 30
954 ACSR 45/7 31
954 ACSR 54/7 32
1272 ACSR 45/7 33
795 ACSR 45/7 34
795 ACSR 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423
36 180,557,171 2,596,399,120 2,776,956,291 285,237 20,575,947 1,497,301 22,358,485
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2012/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
Steel Tower 345.00 345.00 1.00 1 1 HUNTINGTON , UT HUNT PLANT 1 , ID
Steel Tower 345.00 345.00 1.00 1 2 HUNTINGTON , UT HUNT PLANT 2 , ID
Steel SP 345.00 345.00 159.00 1 3 HUNTINGTON , UT PINTO , ID
Steel Tower 345.00 345.00 78.00 1 4 HUNTINGTON , UT SPANISH FORK , ID
Steel Tower 345.00 345.00 240.00 1 5 JIM BRIDGER , WY BORAH , ID
Steel SP 345.00 345.00 234.00 1 6 JIM BRIDGER , WY KINPORT , ID
Wood - H 345.00 345.00 69.00 1 7 MONA , UT SIGURD #1 , UT
Steel Tower 345.00 345.00 69.00 1 8 MONA , UT SIGURD #2 , UT
Wood - H 345.00 345.00 60.00 1 9 MONA , UT HUNTINGTON , UT
Steel Tower 345.00 345.00 190.00 1 10 SIGURD , UT HARRY ALLEN, UT
345.00 345.00 35.00 1 11 SPANISH FORK , WY CAMP WILLIAMS , UT
Steel Tower 345.00 345.00 138.00 1 12 TERMINAL , WY BORAH , ID
345.00 345.00 47.00 1 13 TERMINAL , WY BORAH , ID
Steel SP 345.00 345.00 26.00 1 14 TERMINAL , WY CAMP WILLIAMS #2 , UT
345.00 345.00 23.00 1 15 TERMINAL , WY CAMP WILLIAMS , UT
345.00 345.00 16.00 1 16 TERMINAL , WY 90th SOUTH , UT
17 345 kV costs and expenses
18
383.00 1,988.00 35 19 Subtotal 345 kV
20
Wood - H 230.00 230.00 59.00 1 21 ALVEY , OR DIXONVILLE , OR
Wood - H 230.00 230.00 76.00 1 22 ANTELOPE , ID ANACONDA, MT
Wood - H 230.00 230.00 20.00 1 23 ANTELOPE , ID LOST RIVER , ID
Wood - H 230.00 230.00 1.00 1 24 ATLANTIC CITY , WY COLUMBIA GENEVA , WY
Wood - H 230.00 230.00 88.00 1 25 BEN LOMOND , UT NAUGHTON , WY
Wood - H 230.00 230.00 88.00 1 26 BEN LOMOND , UT NAUGHTON , WY
Wood - H 230.00 230.00 19.00 1 27 BIRCH CREEK , UT RAILROAD , WY
Wood - H 230.00 230.00 3.00 1 28 BITTER CREEK , WY MONELL , WY
Wood - H 230.00 230.00 1.00 1 29 BRIDGER PUMP , WY MANSFACE , WY
Wood - H 230.00 230.00 107.00 1 30 BUFFALO , WY CASPER , WY
Wood - H 230.00 230.00 36.00 1 31 CASPER , WY DAVE JOHNSTON , WY
Wood - H 230.00 230.00 110.00 1 32 CASPER , WY RIVERTON , WY
Steel SP 230.00 230.00 30.00 1 33 CHAPPEL CREEK , WY CRAVEN CREEK , WY
Wood - H 230.00 230.00 6.00 29.00 1 34 CHAPPEL CREEK , WY RILEY RIDGE , WY
Wood - H 230.00 230.00 32.00 1 35 CHAPPEL CREEK , WY JONAH GAS , WY
FERC FORM NO. 1 (ED. 12-87) Page 422.1
36 TOTAL 16,076.00 741.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
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 (l) on the book cost at end of year.
2156 ACSR 8419 1
2156 ACSR 8419 2
795 ACSR 45/7 3
1272 ACSR 45/7 4
1272 ACSR 36/1 5
1272 ACSR 36/1 6
795 ACSR 45/7 7
954 ACSR 45/7 8
954 ACSR 54/7 9
954 ACSR 54/7 10
1272 ACSR 45/7 11
954 ACSR 45/7 12
1272 ACSR 45/7 13
1272 ACSR 45/7 14
1272 ACSR 45/7 15
1272 ACSR 45/7 16
1,098,926,048 989,411,424 109,514,624 1,939,932 144,796 1,786,539 8,597 17
18
1,098,926,048 989,411,424 109,514,624 1,939,932 144,796 1,786,539 8,597 19
20
1272 ACSR 36/1 21
795 ACSR 45/7 22
1272 ACSR 45/7 23
1272 ACSR 36/1 24
795 ACSR 26/7 25
795 ACSR 26/7 26
954 ACSR 54/7 27
795 ACSR 26/7 28
1272 ACSR 36/1 29
1272 ACSR 36/1 30
31
1272 ACSR 36/1 32
954 ACSR 54/7 33
1272 ACSR 45/7 34
1272 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.1
36 180,557,171 2,596,399,120 2,776,956,291 285,237 20,575,947 1,497,301 22,358,485
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2012/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
Wood - H 230.00 230.00 31.00 1 1 DAVE JOHNSTON , WY SPENCE , WY
Wood - H 230.00 230.00 69.00 1 2 DAVE JOHNSTON , WY WYODAK , WY
Wood - H 230.00 230.00 1.00 1 3 DIXONVILLE 500 KV , OR DIXONVILLE , OR
Wood - H 230.00 230.00 17.00 1 4 DIXONVILLE , OR RESTON BPA , OR
Wood - H 230.00 230.00 12.00 1 5 FAIRVIEW BPA , OR ISTHMUS , OR
Wood - H 230.00 230.00 49.00 1 6 FIREHOLE , WY MONUMENT , WY
Wood - H 230.00 230.00 26.00 1 7 FRY , OR BETHEL , OR
Wood - H 230.00 230.00 45.00 1 8 FRY , OR ALVEY , OR
Wood - H 230.00 230.00 159.00 1 9 GLEN CANYON , AZ SIGURD , UT
Wood - H 230.00 230.00 98.00 1 10 GONDER (ELY) , AZ PAVANT , UT
Wood - H 230.00 230.00 43.00 1 11 GOOSE CREEK , WY BUFFALO , WY
Wood - H 230.00 230.00 62.00 1 12 GRANTS PASS , OR DIXONVILLE , OR
Wood - H 230.00 230.00 78.00 1 13 HURRICANE , WA WALLA WALLA , OR
Wood - H 230.00 230.00 149.00 1 14 JIM BRIDGER , WY SPENCE , WY
Wood - H 230.00 230.00 35.00 1 15 JIM BRIDGER , WY ROCK SPRINGS , WY
Wood - H 230.00 230.00 1.00 1 16 JONES CANYON (BPA) , OR LEANING JUNIPER , OR
Wood - H 230.00 230.00 35.00 1 17 KLAMATH FALLS , OR MALIN , OR
Wood - H 230.00 230.00 2.00 1 18 LIMA , WY ROBERSON CREEK , WY
Wood - H 230.00 230.00 76.00 1 19 LONE PINE , OR KLAMATH FALLS , OR
Steel SP 230.00 230.00 5.00 1 20 LONE PINE , OR MERIDIAN , OR
Wood - H 230.00 230.00 56.00 1 21 MCNARY BPA , WA WALLA WALLA , OR
Wood - H 230.00 230.00 35.00 1 22 MERIDIAN , OR GRANTS PASS , OR
Wood - H 230.00 230.00 5.00 1 23 MERIDIAN , OR LONE PINE , OR
Wood - H 230.00 230.00 39.00 1 24 MINERS , WY HIGH PLAINS , WY
Wood - H 230.00 230.00 13.00 1 25 MONUMENT , WY EXXON , WY
Wood - H 230.00 230.00 20.00 1 26 MONUMENT , WY CRAVEN CREEK , WY
Wood - H 230.00 230.00 80.00 1 27 NAUGHTON , WY TREASURETON , WY
Wood - H 230.00 230.00 30.00 1 28 NAUGHTON , WY MONUMENT , WY
Wood - H 230.00 230.00 16.00 1 29 NAUGHTON , WY WILLIAMS OPAL , WY
Wood - H 230.00 230.00 1.00 1 30 OREGON BASIN (PAC), WY OR BASIN (MART OIL), WY
Wood - H 230.00 230.00 4.00 1 31 PALISADES SS , OR BLUE RIM , WY
Wood - H 230.00 230.00 94.00 1 32 PAROWAN VALLEY , UT SIGURD , UT
Wood - H 230.00 230.00 26.00 1 33 PAROWAN VALLEY , UT WEST CEDAR , UT
Wood - H 230.00 230.00 43.00 1 34 PAVANT , UT SIGURD , UT
Wood - H 230.00 230.00 209.00 1 35 POINT OF ROCKS , OR DAVE JOHNSTON , WY
FERC FORM NO. 1 (ED. 12-87) Page 422.2
36 TOTAL 16,076.00 741.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
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 (l) on the book cost at end of year.
1272 ACSR 45/7 1
1272 ACSR 36/1 2
1272 ACSR 36/1 3
795 ACSR 26/7 4
1272 ACSR 36/1 5
1272 ACSR 45/7 6
1272 ACSR 36/1 7
1272 ACSR 36/1 8
954 ACSR 45/7 9
795 ACSR 45/7 10
795 ACSR 26/7 11
1272 ACSR 36/1 12
1272 ACSR 36/1 13
1272 ACSR 36/1 14
1272 ACSR 36/1 15
1272 ACSR 45/7 16
1272 ACSR 36/1 17
1272 ACSR 45/1 18
795 ACSR 26/7 19
1272 ACSR 36/1 20
1272 ACSR 36/1 21
1272 ACSR 36/1 22
1272 ACSR 54/19 23
1272 ACSR 45/7 24
1272 ACSR 36/1 25
1272 ACSR 45/7 26
1272 ACSR 45/7 27
1272 ACSR 36/1 28
954 ACSR 54/7 29
1272 ACSR 45/7 30
1272 ACSR 36/1 31
795 ACSR 45/7 32
795 ACSR 45/7 33
795 ACSR 45/7 34
1272 ACSR 36/1 35
FERC FORM NO. 1 (ED. 12-87) Page 423.2
36 180,557,171 2,596,399,120 2,776,956,291 285,237 20,575,947 1,497,301 22,358,485
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2012/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
Wood - H 230.00 230.00 8.00 1 1 POMONA , WA UNION GAP , WA
Wood - H 230.00 230.00 118.00 1 2 RIVERTON , WY ROCK SPRINGS , WY
Wood - H 230.00 230.00 51.00 1 3 RIVERTON , WY THERMOPOLIS , WY
Wood - H 230.00 230.00 1.00 1 4 ROCK CREEK (BPA) , WA GOODNOE HILLS , WA
Wood - H 230.00 230.00 55.00 1 5 ROCK SPRINGS , WY FLAMING GORGE , UT
Wood - H 230.00 230.00 35.00 1 6 ROCK SPRINGS , WY JIM BRIDGER , WY
Wood - H 230.00 230.00 41.00 1 7 ROCK SPRINGS , WY MONUMENT , WY
Wood - H 230.00 230.00 12.00 1 8 SHIRLEY BASIN , OR DUNLAP , WY
Wood - H 230.00 230.00 2.00 1 9 SWIFT No. 1 , WA SWIFT No. 2 , WA
Wood - H 230.00 230.00 23.00 1 10 SWIFT No. 2 , WA WOODLAND BPA SS , WA
Wood - H 230.00 230.00 7.00 1 11 TALBOT , WA MARENGO II , WA
Wood - H 230.00 230.00 1.00 1 12 TAP TO DALREED , OR TAP TO DALREED No.2, OR
Wood - H 230.00 230.00 9.00 1 13 TAP TO HANNA , OR NICKEL MOUNTAIN , OR
Wood - H 230.00 230.00 176.00 1 14 THERMOPOLIS , WY YELLOWTAIL , MT
Wood - H 230.00 230.00 66.00 1 15 TREASURETON , ID BRADY , ID
Steel Tower 230.00 230.00 6.00 1 16 TROUTDALE BPA , OR GRESHAM PGE , OR
230.00 230.00 6.00 1 17 TROUTDALE BPA , OR LINNEMAN PGE , OR
Wood - H 230.00 230.00 1.00 1 18 TROUTDLE-LINNEMN, OR TROUTDALE PP&L , OR
Wood - H 230.00 230.00 39.00 1 19 UNION GAP , OR MIDWAY (BPA) , OR
Wood - H 230.00 230.00 45.00 1 20 WALLA WALLA , OR AVISTA LEWISTON , WA
Wood - H 230.00 230.00 33.00 1 21 WALLA WALLA , OR WANAPUM (GPUD) , WA
Wood - H 230.00 230.00 37.00 1 22 WANAPUM , OR POMONA , WA
Wood - H 230.00 230.00 13.00 1 23 WINDSTAR , OR GLENROCK/ROLLING, WA
Wood - H 230.00 230.00 69.00 1 24 WYODAK , WY BUFFALO , WY
Wood - H 230.00 230.00 63.00 1 25 YAMSAY , OR KLAMATH FALLS , OR
Wood - H 230.00 230.00 59.00 1 26 YELLOWTAIL , OR GOOSE CREEK , WY
27 230 kV costs and expenses
28
12.00 3,333.00 76 29 Subtotal 230 kV
30
Wood - H 161.00 161.00 61.00 1 31 ANACONDA, ID JEFFERSON, ID
Wood - H 161.00 161.00 45.00 1 32 ANTELOPE , ID GOSHEN , ID
Wood SP 161.00 161.00 9.00 1 33 BONNEVILLE , ID EAGLEROCK , ID
Wood SP 161.00 161.00 3.00 1 34 EAGLEROCK , ID SUGARMILL , ID
Wood - H 161.00 161.00 12.00 1 35 EAGLEROCK , ID GOSHEN , ID
FERC FORM NO. 1 (ED. 12-87) Page 422.3
36 TOTAL 16,076.00 741.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
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 (l) on the book cost at end of year.
1272 ACSR 36/1 1
1272 ACSR 36/1 2
1272 ACSR 36/1 3
1272 ACSR 45/7 4
1272 ACSR 36/1 5
1272 ACSR 36/1 6
1272 ACSR 36/1 7
795 ACSR 26/7 8
954 ACSR 45/7 9
954 ACSR 45/7 10
795 ACSR 26/7 11
795 ACSR 26/7 12
795 ACSR 26/7 13
1272 ACSR 36/1 14
795 ACSR 26/7 15
954 ACSR 45/7 16
900 ACSR 54/7 17
1272 ACSR 36/1 18
954 ACSR 45/7 19
1272 ACSR 36/1 20
1272 ACSR 36/1 21
1272 ACSR 36/1 22
1272 ACSR 45/7 23
1272 ACSR 36/1 24
795 ACSR 26/7 25
795 ACSR 26/7 26
373,524,696 357,004,905 16,519,791 5,219,643 351,027 4,818,539 50,077 27
28
373,524,696 357,004,905 16,519,791 5,219,643 351,027 4,818,539 50,077 29
30
250HH CU/7 31
397.5 ACSR 26/7 32
954 ACSR 45/7 33
954 ACSR 45/7 34
1272 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.3
36 180,557,171 2,596,399,120 2,776,956,291 285,237 20,575,947 1,497,301 22,358,485
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2012/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
Wood - H 161.00 161.00 57.00 1 1 GOSHEN , ID GRACE , ID
Wood - H 161.00 161.00 29.00 1 2 GOSHEN , ID JEFFERSON , ID
Wood - H 161.00 161.00 31.00 1 3 GOSHEN , ID RIGBY , ID
Wood SP 161.00 161.00 17.00 1 4 GOSHEN , ID SUGAR MILL , ID
Wood SP 161.00 161.00 18.00 1 5 RIGBY , ID JEFFERSON , ID
Wood SP 161.00 161.00 17.00 1 6 SUGARMILL , ID RIGBY , ID
Wood - H 161.00 161.00 46.00 1 7 YELLOWTAIL , MT RIMROCK , ID
8 161 kV costs and expenses
9
90.00 255.00 12 10 Subtotal 161 kV
11
Steel - SP 138.00 138.00 1.00 1 12 90TH SOUTH , UT SANDY , UT
Wood - H 138.00 138.00 12.00 1 13 90TH SOUTH , UT QUARRY , UT
Wood - H 138.00 138.00 6.00 1 14 90TH SOUTH , UT DUMAS , UT
Wood SP 138.00 138.00 10.00 1 15 90TH SOUTH , UT OQUIRRH , UT
Wood - H 138.00 138.00 44.00 1 16 ABAJO , UT PINTO , UT
Wood - H 138.00 138.00 4.00 1 17 AGRIUM , UT THREEMILE KNOLL , ID
Wood - H 138.00 138.00 22.00 1 18 ANSCHTZ CO-GEN, WY EVANSTON , WY
Wood - H 138.00 138.00 1.00 1 19 ANTELOPE , ID SCOVILLE #1 , WY
Wood - H 138.00 138.00 1.00 1 20 ANTELOPE , ID SCOVILLE #2 , WY
Wood - H 138.00 138.00 26.00 1 21 ASHGROVE , ID CLOVER , WY
Wood - H 138.00 138.00 92.00 1 22 ASHLEY , UT CARBON , UT
Wood - H 138.00 138.00 12.00 1 23 ASHLEY , UT VERNAL , UT
Wood - H 138.00 138.00 6.00 1 24 BANGERTER , UT OQUIRRH , UT
Wood - H 138.00 138.00 14.00 1 25 BEN LOMOND , UT BRIGHAM CITY , UT
Steel - SP 138.00 138.00 14.00 1 26 BEN LOMOND #1 , UT EL MONTE , UT
138.00 138.00 13.00 1 27 BEN LOMOND #2 , UT EL MONTE , UT
138.00 138.00 22.00 1 28 BEN LOMOND , UT HONEYVILLE , UT
Steel Tower 138.00 138.00 13.00 7.00 1 29 BEN LOMOND , UT SYRACUSE , UT
Steel - SP 138.00 138.00 28.00 1 30 BEN LOMOND , UT ANGEL #2 , UT
Wood -SP 138.00 138.00 14.00 1 31 BEN LOMOND , UT W ZIRCONIUM , UT
Steel Tower 138.00 138.00 42.00 1 32 BEN LOMOND , UT WHEELON , UT
Steel Tower 230.00 138.00 25.00 1 33 BEN LOMOND , UT SYRACUSE , UT
Wood - H 138.00 138.00 9.00 1 34 BONANZA , UT CHAPITA , UT
Wood -SP 138.00 138.00 16.00 1 35 BRIDGERLAND , UT GREEN CANYON , UT
FERC FORM NO. 1 (ED. 12-87) Page 422.4
36 TOTAL 16,076.00 741.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
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 (l) on the book cost at end of year.
250HH CU/7 1
250HH CU/7 2
397.5 ACSR 26/7 3
795 AAC /37 4
397.5 ACSR 26/7 5
397.5 ACSR 26/7 6
556.5 ACSR 26/7 7
21,504,616 20,881,126 623,490 264,016 14,301 249,715 8
9
21,504,616 20,881,126 623,490 264,016 14,301 249,715 10
11
795 AAC /37 12
795 AAC /37 13
795 AAC /37 14
795 ACSR 26/7 15
397.5 ACSR 26/7 16
397.5 ACSR 26/7 17
795 ACSR 26/7 18
397.5 ACSR 26/7 19
397.5 ACSR 26/7 20
397.5 ACSR 26/7 21
397.5 ACSR 26/7 22
397.5 ACSR 26/7 23
24
1272 ACSR 45/7 25
795 ACSR 45/7 26
795 ACSR 45/7 27
250 CUHD /12 28
795 AAC /37 29
397.5 ACSR 26/7 30
795 AAC /37 31
250 CUHD /12 32
1272 ACSR 45/7 33
795 ACSR 26/7 34
1272 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.4
36 180,557,171 2,596,399,120 2,776,956,291 285,237 20,575,947 1,497,301 22,358,485
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2012/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
Wood - H 138.00 138.00 24.00 1 1 BRIGHAM CITY , UT WHEELON , UT
Steel - SP 138.00 138.00 9.00 1 2 BUTLERVILLE , UT 90TH SOUTH , UT
Wood - H 138.00 138.00 35.00 1 3 CAMERON , UT PAROWAN , UT
Wood - H 138.00 138.00 64.00 1 4 CAMERON , UT SIGURD , UT
Wood - H 138.00 138.00 12.00 1 5 CANYON COMP, WY STR 204 , UT
Wood - H 138.00 138.00 2.00 1 6 CARBON , UT HELPER #2 , UT
Steel Tower 138.00 138.00 54.00 1 7 CARBON #1 , UT SPANISH FORK , UT
138.00 138.00 52.00 1 8 CARBON #2 , UT SPANISH FORK , UT
Wood - H 138.00 138.00 120.00 1 9 CARBON , UT MOAB , UT
Wood -SP 138.00 138.00 5.00 1 10 CLEAR CREEK , WY PAINTER , UT
Wood -SP 138.00 138.00 8.00 1 11 CLOVER , WY NEBO , UT
Wood - H 138.00 138.00 2.00 1 12 COLUMBIA , UT SUNNYSIDE , UT
Steel - SP 138.00 138.00 6.00 1 13 COTTONWOOD , UT MCCLELLAND , UT
Wood -SP 138.00 138.00 5.00 1 14 COTTONWOOD , UT HAMMER , UT
Wood -SP 138.00 138.00 29.00 1 15 COTTONWOOD , UT SILVER CREEK , UT
Wood -SP 138.00 138.00 1.00 1 16 CUTLER , UT WHEELON , UT
Steel - SP 138.00 138.00 5.00 1 17 DRY CREEK , UT SPANISH FORK , UT
Wood -SP 138.00 138.00 18.00 1 18 DUMAS , UT WESTFIELD , UT
Steel - SP 138.00 138.00 2.00 1 19 DYNAMO , UT TRI-CITY #1 , UT
138.00 138.00 3.00 1 20 DYNAMO , UT TRI-CITY #2 , UT
Steel - SP 138.00 138.00 15.00 1 21 EAST LAYTON , UT 105 TAP , UT
Wood -SP 138.00 138.00 1.00 1 22 EBAY TAP , UT OQUIRRH , UT
Steel - SP 138.00 138.00 4.00 1 23 EL MONTE , UT STR 30B , UT
Steel - SP 138.00 138.00 1.00 1 24 EL MONTE , UT PIONEER , UT
Wood -SP 138.00 138.00 3.00 1 25 EVANSTON , WY RAILROAD , UT
Wood -SP 138.00 138.00 10.00 1 26 FRANKLIN , ID TREASURETON , ID
Wood -SP 138.00 138.00 25.00 1 27 FRANKLIN , ID GREEN CANYON , UT
Wood -SP 138.00 138.00 1.00 1 28 GADSBY , UT JORDAN , UT
Wood -SP 138.00 138.00 1.00 1 29 GADSBY , UT THIRD WEST , UT
Wood -SP 138.00 138.00 6.00 1 30 GADSBY , UT TERMINAL , UT
Wood -SP 138.00 138.00 1.00 1 31 GENEVA , UT TIMP , UT
Wood -SP 138.00 138.00 7.00 1 32 GREEN CANYON , UT NIBLEY , UT
Wood -SP 138.00 138.00 19.00 1 33 GREEN CANYON , UT WHEELON , UT
Wood - H 138.00 138.00 19.00 1 34 HALE , UT MIDWAY , UT
Wood - H 138.00 138.00 7.00 1 35 HALE , UT TANNER , UT
FERC FORM NO. 1 (ED. 12-87) Page 422.5
36 TOTAL 16,076.00 741.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
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 (l) on the book cost at end of year.
795 ACSR 26/7 1
795 AAC /37 2
397.5 ACSR 26/7 3
397.5 ACSR 26/7 4
795 ACSR 26/7 5
556.5 ACSR 26/7 6
795 ACSR 26/7 7
1272 ACSR 45/7 8
954 ACSR 54/7 9
795 ACSR 26/7 10
1272 ACSR 45/7 11
397.5 ACSR 26/7 12
795 AAC /37 13
795 AAC /37 14
397.5 ACSR 26/7 15
250 CUHD /12 16
1272 ACSR 45/7 17
795 ACSR 26/7 18
795 ACSR 26/7 19
795 ACSR 26/7 20
795 ACSR 26/7 21
795 ACSR 26/7 22
1272 ACSR 45/7 23
1272 ACSR 45/7 24
795 ACSR 26/7 25
795 ACSR 26/7 26
397.5 ACSR 26/7 27
1272 ACSR 45/7 28
1272 AAC /61 29
1272 ACSR 45/7 30
1272 AAC /61 31
1272 ACSR 45/7 32
397.5 ACSR 26/7 33
397.5 ACSR 26/7 34
1272 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.5
36 180,557,171 2,596,399,120 2,776,956,291 285,237 20,575,947 1,497,301 22,358,485
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2012/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
Wood - H 138.00 138.00 18.00 1 1 HALE , UT SPANISH FORK , UT
138.00 138.00 2.00 1 2 HAMMER , UT BUTLERVILLE , UT
Wood - H 138.00 138.00 25.00 1 3 HONEYVILLE , UT LAMPO , UT
138.00 138.00 14.00 1 4 HONEYVILLE , UT WHEELON , UT
Wood - H 138.00 138.00 7.00 1 5 HUNTINGTON , UT MCFADDEN , UT
Wood - H 138.00 138.00 26.00 1 6 JERUSALEM , UT NEBO , UT
Wood -SP 138.00 138.00 1.00 1 7 JORDAN , UT THIRD WEST , UT
Wood -SP 138.00 138.00 5.00 1 8 JORDAN , UT MCCLELLAND , UT
Wood -SP 138.00 138.00 6.00 1 9 JORDAN , UT TERMINAL , UT
Wood -SP 138.00 138.00 1.00 1 10 KCC BARNEY , UT KCCGRIND , UT
Wood -SP 138.00 138.00 3.00 1 11 KEARNS , UT TAYLORSVILLE , UT
Wood -SP 138.00 138.00 2.00 1 12 KEARNS , UT WEST VALLEY , UT
138.00 138.00 8.00 1 13 LONE PEAK , UT CAMP WILLIAMS , UT
Wood -SP 138.00 138.00 6.00 1 14 MCCLELLAND , UT MIDVALLEY , UT
Wood - H 138.00 138.00 11.00 1 15 MCFADDEN , UT BLACKHAWK , UT
Wood -SP 138.00 138.00 2.00 4.00 1 16 MID VALLEY , UT TAYLORSVILLE , UT
Wood -SP 138.00 138.00 5.00 1 17 MID VALLEY , UT COTTONWOOD , UT
Wood -SP 138.00 138.00 3.00 1 18 MID VALLEY , UT COTTONWOOD , UT
Wood - H 138.00 138.00 9.00 1 19 MID VALLEY , UT 90TH SOUTH , UT
Wood - H 138.00 138.00 1.00 1 20 MIDDLETON , UT ST. GEORGE , UT
Wood - H 138.00 138.00 68.00 1 21 MOAB , UT PINTO , UT
Wood - H 138.00 138.00 36.00 1 22 NAUGHTON , WY CANYON COMP, WY
Wood - H 138.00 138.00 48.00 1 23 NAUGHTON , WY PAINTER , WY
Wood - H 138.00 138.00 33.00 1 24 NEBO , UT DRY CREEK , UT
Wood - H 138.00 138.00 10.00 1 25 NUCOR STEEL , UT WHEELON , UT
Wood - H 138.00 138.00 23.00 1 26 ONEIDA , ID OVID , UT
Wood - H 138.00 138.00 19.00 1 27 ONIEDA , ID GRACE , ID
Wood -SP 138.00 138.00 21.00 1 28 OQUIRRH , UT TOOELE , ID
Wood - H 138.00 138.00 5.00 1 29 OQUIRRH , UT BARNEY , UT
Wood - H 138.00 138.00 8.00 1 30 OQUIRRH , UT KCC BINGHAM , UT
Wood - H 138.00 138.00 7.00 1 31 PAINTER , UT RAILROAD , UT
Wood - H 138.00 138.00 21.00 1 32 PAROWAN , UT WEST CEDAR , UT
Steel - SP 138.00 138.00 16.00 1 33 PARRISH #1 , UT TERMINAL , UT
Steel - SP 138.00 138.00 14.00 1 34 PARRISH #105 , UT TERMINAL , UT
138.00 138.00 14.00 1 35 PARISH #2 , UT TERMINAL , UT
FERC FORM NO. 1 (ED. 12-87) Page 422.6
36 TOTAL 16,076.00 741.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
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 (l) on the book cost at end of year.
1272 ACSR 45/7 1
795 ACSR 26/7 2
397.5 ACSR 26/7 3
250 CUHD /12 4
397.5 ACSR 26/7 5
397.5 ACSR 26/7 6
1272 AAC /61 7
795 AAC /37 8
1272 AAC/91 9
1272 AAC /61 10
500 AAC/19 11
12
1272 ACSR 45/7 13
795 AAC 26/7 14
795 AAC 26/7 15
1272 ACSR /61 16
17
18
1272 ACSR 45/7 19
397.5 ACSR 26/7 20
397.5 ACSR 26/7 21
795 AAC 26/7 22
795 AAC 26/7 23
795 AAC 26/7 24
397.5 ACSR 26/7 25
336.4 ACSR 26/7 26
250 CUHD /12 27
795 AAC 45/7 28
795 AAC 26/7 29
1557.4 ACSR/TW 30
1272 ACSR 45/7 31
397.5 ACSR 26/7 32
795 AAC 45/7 33
795 AAC 45/7 34
795 AAC 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.6
36 180,557,171 2,596,399,120 2,776,956,291 285,237 20,575,947 1,497,301 22,358,485
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2012/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
Steel - SP 138.00 138.00 8.00 1 1 PARRISH , UT TAP TO N SALT LAKE , UT
Wood - H 138.00 138.00 17.00 1 2 RAILROAD , UT CANYON COMP , WY
Steel - SP 138.00 138.00 20.00 1 3 CENTRAL (UAMPS) #1 , UT SAINT GEORGE , UT
Steel - SP 138.00 138.00 20.00 1 4 CENTRAL (UAMPS) #2 , UT SAINT GEORGE , UT
138.00 138.00 1.00 1 5 RED BUTTE , UT SAINT GEORGE , UT
Wood - H 138.00 138.00 50.00 1 6 RED BUTTE , UT WEST CEDAR , UT
Steel - SP 138.00 138.00 6.00 1 7 RIVERDALE , UT EAST LAYTON , UT
Wood - H 138.00 138.00 10.00 1 8 SHICK , UT PARRISH , UT
Wood - SP 138.00 138.00 10.00 1 9 SILVER CREEK , UT JORDANELLE , UT
Wood - H 138.00 138.00 10.00 1 10 SPANISH FORK , UT TANNER , UT
Wood - SP 138.00 138.00 2.00 1 11 SUNRISE , UT OQUIRRH , UT
Steel - SP 138.00 138.00 1.00 1 12 SYRACUSE , UT CLEARFIELD SOUTH , UT
Steel Tower 138.00 138.00 15.00 1 13 SYRACUSE , UT PARRISH , UT
Steel Tower 138.00 138.00 9.00 1 14 SYRACUSE , UT ANGEL #1 , UT
138.00 138.00 13.00 1 15 TAP TO ANGEL NORTH , UT TAP TO PARRISH , UT
Wood - SP 138.00 138.00 2.00 6.00 1 16 TAYLORSVILLE , UT 90TH SOUTH , UT
Steel - SP 138.00 138.00 9.00 1 17 TERMINAL , UT KENNECOTT , UT
Wood - H 138.00 138.00 56.00 1 18 TERMINAL , UT ROWLEY , UT
Wood - H 138.00 138.00 7.00 1 19 TERMINAL , UT MIDVALLEY , UT
Wood - H 138.00 138.00 7.00 1 20 TERMINAL , UT MIDVALLEY , UT
Wood - H 138.00 138.00 6.00 24.00 1 21 TERMINAL , UT TOOELE , UT
Wood - SP 138.00 138.00 7.00 1 22 TERMINAL , UT WEST VALLEY , UT
Wood - H 138.00 138.00 17.00 1 23 THREEMILE KNOLL , ID GRACE #1 , ID
Wood - H 138.00 138.00 17.00 1 24 THREEMILE KNOLL , ID GRACE #2 , ID
Wood - H 138.00 138.00 2.00 1 25 THREEMILE KNOLL , ID MONSANTO #1 , ID
Steel - SP 138.00 138.00 2.00 1 26 THREEMILE KNOLL , ID MONSANTO #2 , ID
Steel - SP 138.00 138.00 2.00 1 27 TIMP #1 , UT DYNAMO , UT
138.00 138.00 2.00 1 28 TIMP #2 , UT DYNAMO , UT
Steel - SP 138.00 138.00 4.00 1 29 TIMP , UT HALE , UT
Wood - H 138.00 138.00 23.00 1 30 TIMP , UT SPANISH FORK , UT
Steel Tower 138.00 138.00 25.00 1 31 TREASURETON , ID GRACE , ID
138.00 138.00 25.00 1 32 TREASURETON , ID GRACE #2 , ID
Wood - H 138.00 138.00 6.00 1 33 TREASURETON , ID ONEIDA , ID
Wood - SP 138.00 138.00 22.00 1 34 TRI-CITY , UT SUNRISE , ID
Wood - SP 138.00 138.00 12.00 6.00 1 35 TRI-CITY , UT BANGERTER , UT
FERC FORM NO. 1 (ED. 12-87) Page 422.7
36 TOTAL 16,076.00 741.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
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 (l) on the book cost at end of year.
795 AAC 26/7 1
795 ACSR 26/7 2
1272 ACSR 45/7 3
1272 ACSR 45/7 4
1272 ACSR 45/7 5
397.5 ACSR 26/7 6
795 AAC 26/7 7
250 CUHD /12 8
795 AAC 26/7 9
1272 ACSR 45/7 10
11
1272 ACSR 45/7 12
1272 ACSR 45/7 13
250 CUHD /12 14
795 AAC /37 15
795 AAC /37 16
795 AAC 26/7 17
795 AAC /37 18
1272 ACSR 45/7 19
1272 AAC /61 20
397.5 ACSR 26/7 21
22
250 CUHD /12 23
1272 ACSR 45/7 24
1272 AAC /61 25
1272 ACSR 45/7 26
27
28
29
30
250 CUHD /12 31
250 CUHD /12 32
250 CUHD /12 33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 423.7
36 180,557,171 2,596,399,120 2,776,956,291 285,237 20,575,947 1,497,301 22,358,485
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2012/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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.
Wood - H 138.00 138.00 15.00 1 1 TRI-CITY , UT AMERICAN FORK , UT
Wood - SP 138.00 138.00 20.00 1 2 WEST CEDAR , UT THREE PEAKS , UT
Wood - H 138.00 138.00 7.00 1 3 WEST VALLEY , UT OQUIRRH , UT
Wood - H 138.00 138.00 14.00 1 4 WESTFIELD , UT HALE , UT
Wood - H 138.00 138.00 86.00 1 5 WHEELON , UT AMERICAN FALLS , ID
Steel Tower 138.00 138.00 29.00 1 6 WHEELON #103 , UT TREASURETON , ID
138.00 138.00 29.00 1 7 WHEELON #104 , UT TREASURETON , ID
Wood - H 138.00 138.00 29.00 1 8 WHEELON #105 , UT TREASURETON , ID
9 138 kV costs and expenses
10
256.00 1,986.00 137 11 138 Kv Subtotal
12
1,613.00 13 All 115 kV Lines
14
3,003.00 15 All 69 kV Lines
16
113.00 17 All 57 kV Lines
18
2,573.00 19 All 46 kV Lines
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 422.8
36 TOTAL 16,076.00 741.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
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 (l) on the book cost at end of year.
1272 ACSR 45/7 1
795 AAC 26/7 2
3
795 AAC 26/7 4
250 CUHD /12 5
250 CUHD /12 6
250 CUHD /12 7
250 CUHD /12 8
336,138,228 317,386,565 18,751,663 2,358,133 61,455 2,203,969 92,709 9
10
336,138,228 317,386,565 18,751,663 2,358,133 61,455 2,203,969 92,709 11
12
165,100,267 160,168,165 4,932,102 4,532,933 430,779 4,099,797 2,357 13
14
251,749,741 245,155,552 6,594,189 3,729,453 153,281 3,537,690 38,482 15
16
10,146,529 10,100,248 46,281 56,300 3,652 52,648 17
18
235,533,010 226,241,335 9,291,675 3,308,575 28,850 3,186,710 93,015 19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 423.8
36 180,557,171 2,596,399,120 2,776,956,291 285,237 20,575,947 1,497,301 22,358,485
Schedule Page: 422 Line No.: 1 Column: a
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.
Schedule Page: 422 Line No.: 2 Column: a
The Dixonville - Meridian 500-kV line is jointly owned by PacifiCorp and the
Bonneville Power Administration ("the BPA"). Ownership of the line is as follows:
PacifiCorp's 50.0%, the BPA 50.0%. Plant cost reported for this line reflects PacifiCorp'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.: 3 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.: 4 Column: a
See footnote on page 422 for column (a) line 3.
Schedule Page: 422 Line No.: 5 Column: a
See footnote on page 422 for column (a) line 3.
Schedule Page: 422 Line No.: 6 Column: a
The Alvey - Dixonville 500-kV line is jointly owned by PacifiCorp and the BPA. Ownership
of the line is as follows: PacifiCorp 50.0%, the BPA 50.0%. Plant cost reported for this
line reflects PacifiCorp'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.: 7 Column: a
See footnote on page 422 for column (a) line 3.
Schedule Page: 422 Line No.: 8 Column: a
The Colstrip 4 - Switchyard 500-kV line is jointly owned by PacifiCorp, NorthWestern
Corporation, Puget Sound Energy, 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
PacifiCorp's share.
Schedule Page: 422 Line No.: 9 Column: a
The Colstrip - Broadview A 500-kV line is jointly owned by PacifiCorp, NorthWestern
Corporation, Puget Sound Energy, 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
PacifiCorp's share.
Schedule Page: 422 Line No.: 10 Column: a
The Colstrip - Broadview B 500-kV line is jointly owned by PacifiCorp, NorthWestern
Corporation, Puget Sound Energy, 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
PacifiCorp's share.
Schedule Page: 422 Line No.: 11 Column: a
The Broadview - Townsend A 500-kV line is jointly owned by PacifiCorp, NorthWestern
Corporation, Puget Sound Energy, 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
PacifiCorp's share.
Schedule Page: 422 Line No.: 12 Column: a
The Broadview - Townsend B 500-kV line is jointly owned by PacifiCorp, NorthWestern
Corporation, Puget Sound Energy, 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
PacifiCorp's share.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 422 Line No.: 17 Column: i
1157.4 ACSR/TW 36/7
Schedule Page: 422 Line No.: 18 Column: i
1157.4 ACSR/TW 36/7

Schedule Page: 422.1 Line No.: 31 Column: a
A 1.5 mile segment of the Casper - Dave Johnston 230-kV line is jointly owned by
PacifiCorp 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 PacifiCorp's share.
Schedule Page: 422.1 Line No.: 31 Column: i
1557 ACSS/TW 45/7
Schedule Page: 422.4 Line No.: 24 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 12 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 17 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 18 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 3 Column: a
The Central – St. George 138-kV line is jointly owned by PacifiCorp 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 PacifiCorp's share.
Schedule Page: 422.7 Line No.: 4 Column: a
See footnote on page 422.7 for column (a) line 3.
Schedule Page: 422.7 Line No.: 11 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 22 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 27 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 28 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 29 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 30 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 34 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 35 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 3 Column: i
1557.4 ACSR/TW 36/7
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINES ADDED DURING YEAR
PacifiCorp X
/ /2012/Q4
Line
No.
(c)(b)(a) (d) (e)
LINE DESIGNATION
From To
LineLengthinMiles
SUPPORTING STRUCTURE
Type AverageNumber perMiles
CIRCUITS PER STRUCTURE
Present Ultimate
(f) (g)
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 (l) to (o), it is permissible to report in these columns the
12.00Wood - SP 2 2 1 Ashgrove, UT Clover, UT 2.00
12.00Wood - SP 2 2 2 Clover, UT Nebo, UT 2.00
12.00Wood - SP 1 1 3 Green Canyon Sub, UT Nibley Sub, UT 6.00
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
10.00 36.00 5 5
FERC FORM NO. 1 (REV. 12-03) Page 424
44 TOTAL
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINES ADDED DURING YEAR (Continued)
PacifiCorp X
/ /2012/Q4
Line
No.
(k)(j)(h) (l) (m)
CONDUCTORS
Size Configuration
Voltage
KV
LINE COST
Land and Poles, Towers
and Fixtures Conductors
(n) (p)
Specification and Spacing (Operating)Land Rights and Devices(i)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (l) 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.
Asset
(o)Retire. Costs
Vertical 10'ACSR1272 416,155 2,080,774 1,664,619 138 1
Vertical 10'ACSR1272 138 2
Vertical 12'ACSR1272 1,792,104 4,236,652 2,444,548 138 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
2,208,259 4,109,167
FERC FORM NO. 1 (REV. 12-03) Page 425
44 6,317,426
Schedule Page: 424 Line No.: 1 Column: m
Includes costs for the 138-kV Clover, UT to Nebo, UT line designation.
Schedule Page: 424 Line No.: 1 Column: n
Includes costs for the 138-kV Clover, UT to Nebo, UT line designation.
Schedule Page: 424 Line No.: 2 Column: m
See footnote on page 424 for column (m) line 1.
Schedule Page: 424 Line No.: 2 Column: n
See footnote on page 424 for column (n) line 1.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
CALIFORNIA 1
BELMONT SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
BIG SPRINGS SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
CANBY #2 2.40 69.00DISTRIBUTION-UNATTEN 4
CASTELLA SUB 2.40 69.00DISTRIBUTION-UNATTEN 5
CLEAR LAKE SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
DOG CREEK SUB 2.40 69.00DISTRIBUTION-UNATTEN 7
DORRIS SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
FORT JONES SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
GASQUET SUB 12.47 115.00DISTRIBUTION-UNATTEN 10
GREENHORN SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
HAMBURG SUB 2.40 69.00DISTRIBUTION-UNATTEN 12
HAPPY CAMP SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
HORNBROOK SUB 12.47 69.00DISTRIBUTION-UNATTEN 14
INTERNATIONAL PAPER SUB 2.40 69.00DISTRIBUTION-UNATTEN 15
LAKE EARL SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
LITTLE SHASTA SUB 7.20 69.00DISTRIBUTION-UNATTEN 17
LUCERNE SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
MACDOEL SUB 20.80 69.00DISTRIBUTION-UNATTEN 19
MCCLOUD SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
MILLER REDWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
MONTAGUE SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
MORRISON CREEK SUB 12.50 69.00DISTRIBUTION-UNATTEN 23
MOUNT SHASTA SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
NEWELL SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
NORTH DUNSMUIR SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
NORTHCREST SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
NUTGLADE SUB 2.40 69.00DISTRIBUTION-UNATTEN 28
PATRICKS CREEK SUB 7.20 115.00DISTRIBUTION-UNATTEN 29
PEREZ SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
REDWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
SCOTT BAR SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
SEIAD SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
SHASTINA SUB 20.80 69.00DISTRIBUTION-UNATTEN 34
SHOTGUN CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
SMITH RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
SNOW BRUSH SUB 7.20 69.00DISTRIBUTION-UNATTEN 37
SOUTH DUNSMUIR SUB 4.16 69.00DISTRIBUTION-UNATTEN 38
TULELAKE SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
TUNNEL SUB 12.47 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
1
25 1 2
6 1 3
1 3 4
1 3 5
4 3 6
1 7
7 3 8
6 1 9
9 1 10
12 1 11
1 1 12
7 3 13
4 3 14
9 3 15
12 1 16
2 3 17
4 1 18
30 2 19
6 1 20
4 3 21
6 1 22
14 1 23
16 4 24
12 1 25
6 6 26
20 4 27
1 3 28
1 1 29
1 3 30
9 3 31
2 3 32
2 3 33
6 3 34
1 1 35
6 3 36
1 3 37
2 3 38
20 1 39
6 6 40
FERC FORM NO. 1 (ED. 12-96) Page 427
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
WALKER BRYAN SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
WEED SUB 12.47 115.00DISTRIBUTION-UNATTEN 2
YUBA SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
YUROK SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
Total 468.36 3105.00 5
Number of Substations-43 6
7
ALTURAS SUB 12.47 115.00 69.00T/D-UNATTENDED 8
FALL CREEK HYDRO/SUB 2.30 69.00T/D-UNATTENDED 9
YREKA SUB 12.47 115.00 69.00T/D-UNATTENDED 10
Total 27.24 299.00 138.00 11
Number of Substations-3 12
13
COPCO #1 HYDRO PLANT 2.30 69.00TRANSMISSION-ATTENDE 14
COPCO #2 230 SUB 115.00 230.00TRANSMISSION-ATTENDE 15
COPCO #2 HYDRO PLANT 69.00 115.00 12.47TRANSMISSION-ATTENDE 16
COPCO #2 SUB 69.00 115.00 12.47TRANSMISSION-ATTENDE 17
AGER SUB 69.00 115.00TRANSMISSION-UNATTEN 18
CRAG VIEW SUB 69.00 115.00TRANSMISSION-UNATTEN 19
DEL NORTE SUB 69.00 115.00TRANSMISSION-UNATTEN 20
IRON GATE HYDRO PLANT 6.60 69.00TRANSMISSION-UNATTEN 21
WEED JUNCTION SUB 69.00 115.00TRANSMISSION-UNATTEN 22
Total 537.90 1058.00 24.94 23
Number of Substations-9 24
25
IDAHO 26
ALEXANDER 12.47 46.00DISTRIBUTION-UNATTEN 27
AMMON 12.47 69.00DISTRIBUTION-UNATTEN 28
ANDERSON 12.47 69.00DISTRIBUTION-UNATTEN 29
ARCO 12.47 69.00DISTRIBUTION-UNATTEN 30
ARIMO 12.47 46.00DISTRIBUTION-UNATTEN 31
BANCROFT SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
BELSON SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
BERENICE SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
CAMAS SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
CANYON CREEK SUB 24.90 69.00DISTRIBUTION-UNATTEN 36
CHESTERFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
CLEMENTS SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
CLIFTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
COVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
9 3 1
25 1 2
4 3 3
4 3 4
324 102 5
6
7
32 4 8
3 3 9
95 2 10
130 9 11
12
13
27 6 2 14
375 2 15
122 5 1 16
51 4 17
5 3 18
19 3 19
150 2 20
19 1 21
37 3 22
805 29 3 23
24
25
26
4 1 27
14 1 28
20 1 29
6 1 30
7 1 31
4 1 32
12 1 33
10 1 34
14 1 35
20 1 36
5 1 37
5 1 38
4 1 39
6 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
DOWNEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
DUBOIS SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
EASTMONT SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
EGIN SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
EIGHT MILE SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
GEORGETOWN SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
GRACE CITY SUBSTATION 12.47 46.00DISTRIBUTION-UNATTEN 7
HAMER SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
HAYES SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
HENRY SUB 7.20 46.00DISTRIBUTION-UNATTEN 10
HOLBROOK SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
HOOPES SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
HORSLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
IDAHO FALLS SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
INDIAN CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
JEFFCO SUB 24.90 69.00DISTRIBUTION-UNATTEN 16
KETTLE SUB 24.90 69.00DISTRIBUTION-UNATTEN 17
LAVA SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
LUND SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
MCCAMMON SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
MENAN SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
MERRILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
MILLER SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
MONTPELIER SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
MOODY SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
NEWDALE SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
OSGOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
PRESTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
RAYMOND SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
RENO SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
REXBURG SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
RIRIE SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
ROBERTS SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
RUBY SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
SAND CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
SANDUNE SUB 24.90 69.00DISTRIBUTION-UNATTEN 36
SHELLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
SMITH SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
SOUTH FORK SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
SPUD SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
5 1 1
12 1 2
14 1 3
14 1 4
3 1 5
6 1 6
5 1 7
14 1 8
9 1 9
1 1 10
6 1 11
9 1 12
4 1 13
20 1 14
3 1 15
22 1 16
14 1 17
3 1 18
5 1 19
3 1 20
10 1 21
20 1 22
5 1 23
8 1 24
14 1 25
20 1 26
20 1 27
12 1 28
2 1 29
20 1 30
32 2 31
9 1 32
8 1 33
7 1 34
40 2 35
20 1 36
20 1 37
20 1 38
14 1 39
8 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
ST. CHARLES SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
SUGAR CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
SUNNYDELL SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
TANNER SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
TARGHEE SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
THORNTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
UCON SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
WATKINS SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
WEBSTER SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
WESTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
WINDSPER SUB 24.90 69.00DISTRIBUTION-UNATTEN 11
Total 867.43 4002.00 12
Number of Substations-65 13
14
CINDER BUTTE SUB 12.47 161.00T/D-UNATTENDED 15
MALAD SUB 46.00 138.00 12.47T/D-UNATTENDED 16
MUD LAKE SUB 12.47 69.00T/D-UNATTENDED 17
RIGBY SUB 12.47 161.00 69.00T/D-UNATTENDED 18
SAINT ANTHONY SUB 46.00 69.00 12.47T/D-UNATTENDED 19
Total 129.41 598.00 93.94 20
Number of Substations-5 21
22
AMPS SUB 69.00 230.00 12.47TRANSMISSION-UNATTEN 23
ANTELOPE SUB 161.00 230.00 12.47TRANSMISSION-UNATTEN 24
ASHTON PLANT 2.40 46.00 12.47TRANSMISSION-UNATTEN 25
BIG GRASSY SUB 69.00 161.00TRANSMISSION-UNATTEN 26
BONNEVILLE SUB 69.00 161.00TRANSMISSION-UNATTEN 27
CONDA SUB 46.00 138.00TRANSMISSION-UNATTEN 28
FISH CREEK SUB 46.00 161.00TRANSMISSION-UNATTEN 29
FRANKLIN SUB 46.00 138.00TRANSMISSION-UNATTEN 30
GOSHEN SUB 161.00 345.00 46.00TRANSMISSION-UNATTEN 31
GRACE SUB 46.00 138.00 6.60TRANSMISSION-UNATTEN 32
JEFFERSON SUB 69.00 161.00TRANSMISSION-UNATTEN 33
LIFTON HYDRO 2.30 69.00TRANSMISSION-UNATTEN 34
ONEIDA SUB 25.00 138.00TRANSMISSION-UNATTEN 35
OVID SUB 69.00 138.00TRANSMISSION-UNATTEN 36
SCOVILLE SUB 69.00 138.00TRANSMISSION-UNATTEN 37
SUGARMILL SUB 46.00 161.00 69.00TRANSMISSION-UNATTEN 38
THREEMILE KNOLL SUB 138.00 345.00 46.00TRANSMISSION-UNATTEN 39
TREASURETON SUB 138.00 230.00TRANSMISSION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
5 1 1
12 1 2
12 1 3
4 1 4
4 1 5
7 1 6
7 1 7
14 1 8
20 1 9
4 1 10
20 1 11
721 67 12
13
14
60 2 1 15
71 4 1 16
14 1 17
189 4 18
40 2 19
374 13 2 20
21
22
75 1 1 23
445 3 24
18 3 25
67 1 26
67 1 27
67 1 28
25 3 29
75 1 30
763 8 1 31
217 2 32
233 3 33
6 2 34
40 2 35
30 1 36
76 2 37
168 3 38
700 1 39
534 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
Total 1271.70 3128.00 205.01 1
Number of Substations-18 2
3
MONTANA 4
YELLOWTAIL SUB 161.00 230.00TRANSMISSION-UNATTEN 5
Total 161.00 230.00 6
Number of Substations-1 7
8
OREGON 9
26TH STREET 4.16 20.80DISTRIBUTION-UNATTEN 10
35TH STREET 2.40 20.80DISTRIBUTION-UNATTEN 11
AGNESS AVE 12.47 115.00DISTRIBUTION-UNATTEN 12
ALDERWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
ARLINGTON 12.47 69.00DISTRIBUTION-UNATTEN 14
ATHENA 12.47 69.00DISTRIBUTION-UNATTEN 15
BANDON TIE SUB 12.47 20.80DISTRIBUTION-UNATTEN 16
BEACON SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
BEALL LANE SUB 12.47 115.00DISTRIBUTION-UNATTEN 18
BEATTY SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
BELKNAP SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
BLALOCK SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
BLOSS SUB 12.47 115.00DISTRIBUTION-UNATTEN 22
BLY SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
BOISE CASCADE SUB 11.00 69.00DISTRIBUTION-UNATTEN 24
BONANZA SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
BOND STREET SUB 12.50 69.00DISTRIBUTION-UNATTEN 26
BROOKHURST SUB 12.47 115.00DISTRIBUTION-UNATTEN 27
BROWNSVILLE SUB 20.80 69.00DISTRIBUTION-UNATTEN 28
BRYANT SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
BUCHANAN SUB 20.80 115.00DISTRIBUTION-UNATTEN 30
BUCKAROO SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
CAMPBELL SUB 12.47 115.00DISTRIBUTION-UNATTEN 32
CANNON BEACH SUB 12.47 115.00DISTRIBUTION-UNATTEN 33
CARNES SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
CASEBEER SUB 20.80 69.00DISTRIBUTION-UNATTEN 35
CAVEMAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 36
CHERRY LANE SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
CHILOQUIN MARKET SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
CHINA HAT SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
CIRCLE BLVD SUB 20.80 115.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
3606 40 2 1
2
3
4
100 1 5
100 1 6
7
8
9
5 1 10
30 6 11
25 1 12
45 2 13
5 1 14
9 1 15
8 3 1 16
11 3 17
25 1 18
6 1 19
40 2 20
2 3 21
32 2 22
8 3 23
3 1 24
8 3 25
25 1 26
50 2 27
13 1 28
34 2 29
40 2 30
34 2 31
20 2 32
13 1 33
9 3 34
20 1 35
45 2 36
25 1 37
5 3 38
25 1 39
80 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
CLEVELAND AVE SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
CLOAKE SUB 20.80 69.00DISTRIBUTION-UNATTEN 2
COBURG SUB 20.80 69.00DISTRIBUTION-UNATTEN 3
COLISEUM SUB 4.16 20.80DISTRIBUTION-UNATTEN 4
COLUMBIA SUB 12.47 115.00 57.00DISTRIBUTION-UNATTEN 5
COOS RIVER SUB 20.80 115.00DISTRIBUTION-UNATTEN 6
COQUILLE SUB 20.80 115.00DISTRIBUTION-UNATTEN 7
CREEK SUB 34.50 69.00DISTRIBUTION-UNATTEN 8
CROOKED RIVER RANCH SUB 20.80 69.00DISTRIBUTION-UNATTEN 9
CROWFOOT SUB 12.47 115.00DISTRIBUTION-UNATTEN 10
CULLY SUB 12.47 115.00DISTRIBUTION-UNATTEN 11
CULVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
DAIRY SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
DALLAS SUB 20.80 115.00DISTRIBUTION-UNATTEN 14
DALREED SUB 34.50 230.00DISTRIBUTION-UNATTEN 15
DESCHUTES SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
DEVILS LAKE SUB 20.80 115.00DISTRIBUTION-UNATTEN 17
DIXON SUB 4.16 115.00DISTRIBUTION-UNATTEN 18
DODGE BRIDGE SUB 20.80 69.00DISTRIBUTION-UNATTEN 19
DOWELL SUB 12.47 115.00DISTRIBUTION-UNATTEN 20
EASY VALLEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 21
EMPIRE SUB 20.80 115.00DISTRIBUTION-UNATTEN 22
ENTERPRISE SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
FERN HILL SUB 12.47 115.00DISTRIBUTION-UNATTEN 24
FIELDER CREEK SUB 20.80 115.00DISTRIBUTION-UNATTEN 25
FOOTHILLS SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
FRALEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
GARDEN VALLEY SUB 20.80 69.00DISTRIBUTION-UNATTEN 28
GAZLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
GLENDALE SUB 12.47 230.00DISTRIBUTION-UNATTEN 30
GLENEDEN SUB 4.16 20.80DISTRIBUTION-UNATTEN 31
GLIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 32
GOLD HILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
GORDON HOLLOW SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
GOSHEN SUB 20.80 115.00DISTRIBUTION-UNATTEN 35
GRANT STREET SUB 20.80 115.00DISTRIBUTION-UNATTEN 36
GRASS VALLEY SUB 4.16 20.80DISTRIBUTION-UNATTEN 37
GREEN SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
GRIFFIN CREEK SUB 12.47 115.00DISTRIBUTION-UNATTEN 39
HAMAKER SUB 12.47 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
45 2 1
20 1 2
10 3 3
9 2 4
55 2 1 5
20 1 6
40 2 7
5 1 8
25 2 9
20 1 10
25 1 11
13 1 12
25 1 13
50 2 14
75 3 15
12 1 16
50 2 17
7 1 18
12 1 19
20 1 20
45 2 21
20 1 22
19 2 23
12 1 24
25 1 25
21 4 26
5 3 27
20 1 28
8 4 29
25 2 30
5 1 31
12 1 32
11 3 33
6 1 34
20 1 35
45 2 36
1 4 37
25 1 38
20 1 39
8 3 40
FERC FORM NO. 1 (ED. 12-96) Page 427.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
HARRISBURG SUB 20.80 69.00DISTRIBUTION-UNATTEN 1
HENLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
HERMISTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
HILLVIEW SUB 20.80 115.00DISTRIBUTION-UNATTEN 4
HINKLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
HOLLADAY SUB 12.47 115.00DISTRIBUTION-UNATTEN 6
HOLLYWOOD SUB 12.47 115.00DISTRIBUTION-UNATTEN 7
HOOD RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
HORNET SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
HUMBUG CREEK SUB 12.50 67.00DISTRIBUTION-UNATTEN 10
HUNTERS CIRCLE TEMP SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
ILLAHEE FLATS SUB 12.47 115.00DISTRIBUTION-UNATTEN 12
INDEPENDENCE SUB 20.80 69.00DISTRIBUTION-UNATTEN 13
JACKSONVILLE SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 14
JEFFERSON SUB 20.80 69.00DISTRIBUTION-UNATTEN 15
JEROME PRAIRIE SUB 12.47 115.00DISTRIBUTION-UNATTEN 16
JORDAN POINT SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
JOSEPH SUB 12.47 20.80DISTRIBUTION-UNATTEN 18
JUNCTION CITY SUB 20.80 69.00DISTRIBUTION-UNATTEN 19
KENWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
KILLINGWORTH SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
KNAPPA SVENSEN SUB 12.47 115.00DISTRIBUTION-UNATTEN 22
LAKEPORT SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
LANCASTER SUB 20.80 69.00DISTRIBUTION-UNATTEN 24
LEBANON SUB 20.80 115.00DISTRIBUTION-UNATTEN 25
LINCOLN SUB 12.47 115.00DISTRIBUTION-UNATTEN 26
LOCKHART SUB 20.80 115.00DISTRIBUTION-UNATTEN 27
LYONS SUB 20.80 69.00DISTRIBUTION-UNATTEN 28
MADRAS SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
MALLORY SUB 12.47 115.00DISTRIBUTION-UNATTEN 30
MARYS RIVER SUB 20.80 115.00DISTRIBUTION-UNATTEN 31
MEDCO SUB 12.47 115.00DISTRIBUTION-UNATTEN 32
MEDFORD 12.47 69.00DISTRIBUTION-UNATTEN 33
MERLIN SUB 12.47 115.00DISTRIBUTION-UNATTEN 34
MERRILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
MINAM SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
MODOC SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
MORO SUB 2.40 20.80DISTRIBUTION-UNATTEN 38
MURDER CREEK SUB 20.80 115.00DISTRIBUTION-UNATTEN 39
MYRTLE CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.6
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
13 1 1
6 3 2
40 1 3
45 2 4
20 1 5
75 3 6
50 2 7
40 2 8
20 1 9
9 1 10
12 1 11
2 1 12
20 1 13
75 2 14
12 1 15
20 1 16
20 1 17
6 1 1 18
25 2 19
3 3 20
40 2 21
6 1 22
50 2 23
12 3 24
40 2 25
105 3 26
40 2 27
9 2 28
25 2 29
25 1 30
20 1 31
20 1 32
67 8 33
45 2 34
17 6 35
1 36
6 3 37
2 3 38
100 4 39
14 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.6
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
MYRTLE POINT SUB 20.80 115.00DISTRIBUTION-UNATTEN 1
NELSCOTT SUB 4.16 20.80DISTRIBUTION-UNATTEN 2
NEW O'BRIEN SUB 12.47 115.00DISTRIBUTION-UNATTEN 3
OAK KNOLL SUB 12.47 115.00DISTRIBUTION-UNATTEN 4
OAKLAND SUB 12.47 115.00DISTRIBUTION-UNATTEN 5
OREMET SUB 12.47 115.00DISTRIBUTION-UNATTEN 6
OVERPASS SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
PALLETTE SUB 20.80 69.00DISTRIBUTION-UNATTEN 8
PARK STREET SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
PARKROSE SUB 12.47 57.00DISTRIBUTION-UNATTEN 10
PENDLETON SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
PILOT ROCK SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
POWELL BUTTE SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
PRINEVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 14
PROVOLT SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
QUEEN AVE SUB 20.80 69.00DISTRIBUTION-UNATTEN 16
RED BLANKET SUB 4.16 69.00DISTRIBUTION-UNATTEN 17
REDMOND SUB 12.47 115.00DISTRIBUTION-UNATTEN 18
RIDDLE SUB 69.00 116.00DISTRIBUTION-UNATTEN 19
RIDDLE VENEER SUB 12.47 115.00DISTRIBUTION-UNATTEN 20
ROGUE RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
ROSEBURG SUB 20.80 115.00DISTRIBUTION-UNATTEN 22
ROSS AVE SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
ROXY ANN SUB 12.50 115.00DISTRIBUTION-UNATTEN 24
RUCH SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
RUNNING Y SUB 20.80 69.00DISTRIBUTION-UNATTEN 26
RUSSELLVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 27
SCENIC SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 28
SCIO SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
SEASIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 30
SELMA SUB 12.47 115.00DISTRIBUTION-UNATTEN 31
SHASTA WAY SUB 4.16 12.47DISTRIBUTION-UNATTEN 32
SHEVLIN PARK SUB 12.50 69.00DISTRIBUTION-UNATTEN 33
SIMTAG BOOSTER PUMP 4.16 34.50DISTRIBUTION-UNATTEN 34
SOUTH DUNES SUB 12.47 115.00DISTRIBUTION-UNATTEN 35
SOUTHGATE SUB 20.80 69.00DISTRIBUTION-UNATTEN 36
SPRAGUE RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
STATE STREET SUB 20.80 115.00DISTRIBUTION-UNATTEN 38
STAYTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
STEAMBOAT SUB 7.20 115.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
9 1 1
4 1 2
9 1 3
45 2 4
8 1 5
75 2 6
45 2 7
1 1 1 8
40 2 9
39 2 10
46 7 1 11
22 2 12
6 1 13
50 2 14
11 3 15
50 2 16
2 3 17
50 2 18
50 2 19
25 1 1 20
25 2 21
50 2 22
9 3 23
25 1 24
9 1 25
9 1 26
45 2 27
70 3 28
8 1 29
40 2 30
9 1 31
2 3 32
25 1 33
19 2 34
9 1 35
20 1 36
7 3 37
40 2 38
55 2 39
1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
STEVENS ROAD SUB 20.80 115.00DISTRIBUTION-UNATTEN 1
SUTHERLIN SUB 12.00 115.00DISTRIBUTION-UNATTEN 2
SWEET HOME SUB 20.80 115.00DISTRIBUTION-UNATTEN 3
TAKELMA SUB 20.80 115.00DISTRIBUTION-UNATTEN 4
TALENT SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
TEXUM SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
TILLER SUB 12.47 115.00DISTRIBUTION-UNATTEN 7
TOLO SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
TURKEY HILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
UMAPINE SUB 12.47 69.00DISTRIBUTION-UNATTEN 10
UMATILLA SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
VERNON SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
VILAS SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
VILLAGE GREEN SUB 20.80 115.00DISTRIBUTION-UNATTEN 14
VINE STREET SUB 20.80 69.00DISTRIBUTION-UNATTEN 15
WALLOWA SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
WARM SPRINGS SUB 20.80 69.00DISTRIBUTION-UNATTEN 17
WARRENTON SUB 12.47 115.00DISTRIBUTION-UNATTEN 18
WASCO SUB 4.16 20.80DISTRIBUTION-UNATTEN 19
WECOMA BEACH SUB 4.16 20.80DISTRIBUTION-UNATTEN 20
WESTERN KRAFT SUB 12.47 115.00DISTRIBUTION-UNATTEN 21
WESTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
WESTSIDE HYDRO/SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
WEYERHAUSER SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
WHITE CITY SUB 12.47 115.00DISTRIBUTION-UNATTEN 25
WILLOW COVE SUB 4.16 34.50DISTRIBUTION-UNATTEN 26
WINSTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
YEW AVENUE SUB 12.50 115.00DISTRIBUTION-UNATTEN 28
YOUNGS BAY SUB 12.47 115.00DISTRIBUTION-UNATTEN 29
Total 2559.80 15477.27 195.00 30
Number of Substations-180 31
32
ALBINA SUB 12.47 115.00 69.00T/D-UNATTENDED 33
APPLEGATE SUB 69.00 115.00 12.47T/D-UNATTENDED 34
ASHLAND MTN AVE SUB 69.00 115.00 12.47T/D-UNATTENDED 35
BEND PLANT SUB 13.09 69.00 12.47T/D-UNATTENDED 36
CAVE JUNCTION SUB 12.47 115.00 69.00T/D-UNATTENDED 37
HAZELWOOD SUB 69.00 115.00 12.47T/D-UNATTENDED 38
KNOTT SUB 12.47 115.00 57.00T/D-UNATTENDED 39
MILE HI SUB 69.00 115.00 12.47T/D-UNATTENDED 40
FERC FORM NO. 1 (ED. 12-96) Page 426.8
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
50 2 1
25 1 2
42 2 3
12 1 4
50 2 5
25 1 6
1 1 7
11 1 8
13 3 9
20 1 10
25 2 11
50 2 12
25 1 13
40 2 14
20 1 15
7 1 16
12 3 17
25 2 18
3 3 19
3 1 20
50 2 21
22 2 22
22 9 23
40 2 24
60 3 25
28 3 26
22 3 27
25 1 28
37 2 29
4575 346 6 30
31
32
177 9 33
65 2 34
70 2 35
31 3 36
70 2 37
132 4 38
163 5 39
39 4 40
FERC FORM NO. 1 (ED. 12-96) Page 427.8
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
PILOT BUTTE SUB 69.00 230.00 12.47T/D-UNATTENDED 1
SAGE ROAD SUB 12.47 115.00T/D-UNATTENDED 2
WINCHESTER SUB 12.47 115.00 69.00T/D-UNATTENDED 3
Total 420.44 1334.00 338.82 4
Number of Substations-11 5
6
CLEARWATER #1 HYDRO PLANT 6.90 138.00TRANSMISSION-ATTENDE 7
FISH CREEK HYDRO 6.90 115.00TRANSMISSION-ATTENDE 8
JC BOYLE HYDRO 11.00 230.00TRANSMISSION-ATTENDE 9
LEMOLO #1 HYDRO 12.50 11.30TRANSMISSION-ATTENDE 10
LEMOLO #2 HYDRO 12.00 115.00TRANSMISSION-ATTENDE 11
PROSPECT 1 HYDRO 2.30 69.00TRANSMISSION-ATTENDE 12
PROSPECT 2 HYDRO 6.60 69.00TRANSMISSION-ATTENDE 13
PROSPECT 3 HYDRO 12.47 69.00TRANSMISSION-ATTENDE 14
TOKETEE HYDRO 6.90 115.00TRANSMISSION-ATTENDE 15
BEND HYDRO PLANT 2.40 4.16TRANSMISSION-UNATTEN 16
CALAPOOYA SUB 69.00 230.00TRANSMISSION-UNATTEN 17
CHILOQUIN SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 18
COLD SPRINGS SUB 69.00 230.00 2.40TRANSMISSION-UNATTEN 19
COVE SUB 69.00 230.00TRANSMISSION-UNATTEN 20
DAYS CREEK SUB 69.00 115.00TRANSMISSION-UNATTEN 21
DIAMOND HILL SUB 69.00 230.00TRANSMISSION-UNATTEN 22
DIXONVILLE 115/230 SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 23
DIXONVILLE 500 SUB 230.00 500.00TRANSMISSION-UNATTEN 24
EAGLE POINT HYDRO 2.40 115.00TRANSMISSION-UNATTEN 25
EAST SIDE HYDRO 12.47 46.00TRANSMISSION-UNATTEN 26
FISH HOLE SUB 69.00 115.00TRANSMISSION-UNATTEN 27
FRY SUB 115.00 230.00TRANSMISSION-UNATTEN 28
GRANTS PASS SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 29
GREEN SPRINGS PLANT/SUB 69.00 115.00TRANSMISSION-UNATTEN 30
HURRICANE SUB 69.00 230.00 2.40TRANSMISSION-UNATTEN 31
ISTHMUS SUB 115.00 230.00TRANSMISSION-UNATTEN 32
KENNEDY SUB 57.00 69.00TRANSMISSION-UNATTEN 33
KLAMATH FALLS SUB 69.00 230.00TRANSMISSION-UNATTEN 34
LONE PINE SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 35
MALIN SUB 230.00 500.00 69.00TRANSMISSION-UNATTEN 36
MERIDIAN SUB 230.00 500.00TRANSMISSION-UNATTEN 37
MONPAC SUB 69.00 115.00TRANSMISSION-UNATTEN 38
NICKEL MOUNTAIN SUB 115.00 230.00TRANSMISSION-UNATTEN 39
PARRISH GAP SUB 69.00 230.00 12.47TRANSMISSION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.9
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
400 4 1
40 2 2
75 5 3
1262 42 4
5
6
17 3 7
13 3 8
89 2 1 9
2 3 1 10
40 4 11
5 3 12
40 6 1 13
10 6 14
50 9 15
30 3 16
75 1 17
119 4 18
66 2 19
67 3 20
50 1 21
75 1 22
343 6 23
650 3 24
3 1 25
3 3 26
7 3 27
500 2 28
473 5 29
19 3 30
29 2 31
250 1 32
33 1 33
251 6 1 34
733 10 35
775 4 1 36
1300 6 1 37
50 1 38
114 1 39
150 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.9
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
PONDEROSA SUB 115.00 230.00TRANSMISSION-UNATTEN 1
PROSPECT CENTRAL SUB 69.00 115.00TRANSMISSION-UNATTEN 2
ROBERTS CREEK SUB 69.00 115.00TRANSMISSION-UNATTEN 3
SLIDE CREEK HYDRO 7.00 115.00TRANSMISSION-UNATTEN 4
SODA SPRINGS HYDRO 7.00 115.00TRANSMISSION-UNATTEN 5
TROUTDALE SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 6
TUCKER SUB 69.00 115.00TRANSMISSION-UNATTEN 7
WALLOWA FALLS HYDRO 20.80TRANSMISSION-UNATTEN 8
Total 2856.84 7401.26 431.27 9
Number of Substations-42 10
11
UTAH 12
106TH SOUTH SUB 12.50 138.00DISTRIBUTION-UNATTEN 13
118TH SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 14
23RD ST SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
70TH SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 16
ALTAVIEW SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
AMALGA SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
AMERICAN FORK SUB 12.47 138.00DISTRIBUTION-UNATTEN 19
ARAGONITE 7.20 46.00DISTRIBUTION-UNATTEN 20
AURORA SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
BANGERTER SUB 12.47 138.00DISTRIBUTION-UNATTEN 22
BEAR RIVER SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
BENJAMIN SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
BINGHAM SUB 7.62 46.00DISTRIBUTION-UNATTEN 25
BLUE CREEK 12.47 46.00DISTRIBUTION-UNATTEN 26
BLUFF SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
BLUFFDALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
BOTHWELL SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
BRIAN HEAD SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
BRICKYARD SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
BRIGHTON SUB 24.90 46.00DISTRIBUTION-UNATTEN 32
BROOKLAWN SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
BRUNSWICK SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
BURTON SUB 12.47 34.50DISTRIBUTION-UNATTEN 35
BUSH SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
CANNON SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
CANYONLANDS SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
CAPITOL SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
CARBIDE SUB 7.20 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.10
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
250 1 1
46 4 2
50 1 3
21 3 4
13 3 5
500 3 6
100 2 7
2 3 8
7413 133 6 9
10
11
12
30 1 13
30 1 14
12 1 15
30 1 16
45 2 17
11 1 18
30 1 19
1 1 20
3 1 21
50 2 22
17 2 23
2 1 24
25 1 25
2 3 26
1 3 27
9 1 28
4 1 29
14 1 30
9 1 31
26 2 32
6 1 33
60 3 34
11 3 35
9 1 36
12 1 37
1 1 38
20 1 39
3 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.10
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
CARBONVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
CARLISLE SUB 12.50 138.00DISTRIBUTION-UNATTEN 2
CASTO SUBSTATION 12.47 46.00DISTRIBUTION-UNATTEN 3
CENTERVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
CENTRAL SUB 12.47 43.80DISTRIBUTION-UNATTEN 5
CHAPEL HILL SUB 12.47 138.00DISTRIBUTION-UNATTEN 6
CHERRYWOOD SUB 12.47 138.00DISTRIBUTION-UNATTEN 7
CIRCLEVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
CLEAR CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
CLEAR LAKE SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
CLEARFIELD SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 11
CLINTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 12
CLIVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
COALVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
COLD WATER CANYON SUB 12.47 138.00DISTRIBUTION-UNATTEN 15
COLEMAN SUB 69.00 138.00 12.47DISTRIBUTION-UNATTEN 16
COLTON WELL SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
COMMERCE SUB 12.50 138.00DISTRIBUTION-UNATTEN 18
COPPER HILLS SUB 12.47 138.00DISTRIBUTION-UNATTEN 19
CORINNE SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
COVE FORT SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
COZYDALE SUB 12.50 138.00DISTRIBUTION-UNATTEN 22
CROSS HOLLOW SUB 12.47 138.00DISTRIBUTION-UNATTEN 23
CUDAHY SUB 12.47 138.00DISTRIBUTION-UNATTEN 24
DAMMERON VALLEY SUB 12.47 34.50DISTRIBUTION-UNATTEN 25
DECKER LAKE SUB 12.47 138.00DISTRIBUTION-UNATTEN 26
DELLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
DELTA SUB 69.00 46.00DISTRIBUTION-UNATTEN 28
DESERET SUB 4.16 46.00DISTRIBUTION-UNATTEN 29
DEWEYVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
DIMPLE DELL SUB 12.47 138.00DISTRIBUTION-UNATTEN 31
DIXIE DEER SUB 12.47 34.50DISTRIBUTION-UNATTEN 32
DRAPER SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
EAST BENCH SUB 12.47 138.00DISTRIBUTION-UNATTEN 34
EAST HYRUM SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
EAST LAYTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 36
EAST MILLCREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
EDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
ELBERTA SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
ELK MEADOWS SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.11
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
6 1 1
30 1 2
25 1 3
22 1 4
9 1 5
30 1 6
50 2 7
3 1 8
4 1 9
3 10
60 2 11
50 2 12
4 1 13
6 1 14
30 1 15
106 4 16
1 3 17
30 1 18
30 1 19
3 1 20
2 3 21
30 1 22
22 1 23
30 1 24
42 1 25
55 2 26
6 1 27
48 3 28
2 1 29
4 1 30
60 2 31
2 1 32
23 2 33
30 1 34
6 1 35
60 2 36
20 1 37
19 2 38
5 1 39
3 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.11
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
ELSINORE SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
EMERY CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
EMIGRATION SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
ENOCH SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
ENTERPRISE VALLEY SUB 12.47 138.00DISTRIBUTION-UNATTEN 5
EUREKA SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
FARMINGTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 7
FAYETTE SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
FERRON SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
FIELDING SUB 12.00 46.00DISTRIBUTION-UNATTEN 10
FIFTH WEST SUB 12.47 138.00DISTRIBUTION-UNATTEN 11
FLUX SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
FOOL CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
FOUNTAIN GREEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
FREEDOM SUBSTATION 7.20 46.00DISTRIBUTION-UNATTEN 15
FRUIT HEIGHTS SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
GARDEN CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
GATEWAY SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
GOLD RUSH SUB 12.50 138.00DISTRIBUTION-UNATTEN 19
GORDON AVENUE SUB 12.50 138.00DISTRIBUTION-UNATTEN 20
GOSHEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
GRANGER SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
GRANTSVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
GUNLOCK HYDRO 2.30 34.50DISTRIBUTION-UNATTEN 24
GUNNISON SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
HAMMER SUB 12.47 138.00DISTRIBUTION-UNATTEN 26
HAVASU SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
HELPER CITY SUB 4.16 46.00DISTRIBUTION-UNATTEN 28
HENEFER SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
HERRIMAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 30
HIAWATHA SUB 4.16 46.00DISTRIBUTION-UNATTEN 31
HIGHLAND DIST SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
HOGGARD SUB 12.47 138.00DISTRIBUTION-UNATTEN 33
HOGLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
HOLDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
HOLLADAY SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
HUNTER SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
HUNTINGTON CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
IRON MOUNTAIN SUB 7.20 34.50DISTRIBUTION-UNATTEN 39
IRONTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.12
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
2 1 1
3 3 2
25 1 3
14 1 4
10 1 5
3 1 6
30 1 7
1 2 8
5 1 9
6 1 10
50 2 11
4 1 12
2 1 13
7 1 14
1 15
22 1 16
12 1 17
28 1 1 18
30 1 19
30 1 20
2 1 21
50 2 22
23 1 23
1 1 24
11 2 25
60 2 26
3 1 27
3 3 28
4 1 29
30 1 30
4 3 31
25 1 32
50 2 33
22 1 34
4 1 35
32 2 36
22 1 37
12 2 38
1 1 39
2 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.12
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
IVINS SUB 12.47 34.50DISTRIBUTION-UNATTEN 1
JORDAN NARROWS SUB 2.40 46.00DISTRIBUTION-UNATTEN 2
JORDAN PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 3
JORDANELLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
JUAB SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
JUNCTION SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
KAIBAB SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
KAMAS SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
KEARNS SUB 12.47 138.00DISTRIBUTION-UNATTEN 9
KENSINGTON SUB 4.16 46.00DISTRIBUTION-UNATTEN 10
LAKE PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 11
LARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
LAYTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
LEGRANDE SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
LEWISTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
LINCOLN SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
LINDON SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
LISBON SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
LOAFER SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
LOGAN CANYON SUB 7.20 46.00DISTRIBUTION-UNATTEN 20
LONE TREE SUB 12.47 34.50DISTRIBUTION-UNATTEN 21
LOWER BEAVER SUB 6.60 46.00DISTRIBUTION-UNATTEN 22
LYNNDYL SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
MAESER SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
MAGNA SUB 12.47 138.00DISTRIBUTION-UNATTEN 25
MANILA SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
MANTUA SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
MAPLETON SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
MARRIOTT SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
MARYSVALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
MATHIS SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
MCCORNICK SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
MCKAY SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
MEADOWBROOK SUB 12.47 138.00 46.00DISTRIBUTION-UNATTEN 34
MEDICAL SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
MIDLAND SUB 12.47 138.00DISTRIBUTION-UNATTEN 36
MIDVALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
MILFORD SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
MILFORD TV SUB 13.20 46.00DISTRIBUTION-UNATTEN 39
MINERSVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.13
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
22 1 1
13 2 2
30 1 3
30 1 4
2 3 5
3 1 6
5 1 7
7 1 8
60 2 9
7 1 10
53 2 11
6 1 12
40 2 13
2 1 14
14 1 15
20 1 16
20 1 17
4 1 18
1 19
1 1 20
20 1 21
1 1 22
4 1 23
12 1 24
30 1 25
22 1 26
2 1 27
14 1 28
20 1 29
3 1 30
9 1 31
6 1 32
20 1 33
42 2 34
57 4 35
30 1 36
25 1 37
14 1 38
1 39
2 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.13
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
MOAB CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
MONTEZUMA SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
MOORE SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
MORGAN SUB 4.16 46.00DISTRIBUTION-UNATTEN 4
MORONI SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
MOSS JUNCTION SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
MOUNTAIN DELL SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
MOUNTAIN GREEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
MYTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
NEW HARMONY SUB 12.47 69.00DISTRIBUTION-UNATTEN 10
NEWGATE SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
NEWTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
NIBLEY SUB 24.90 46.00DISTRIBUTION-UNATTEN 13
NORTH BENCH SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
NORTH FIELDS SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
NORTH LOGAN SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
NORTH OGDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
NORTH SALT LAKE SUB 13.20 46.00DISTRIBUTION-UNATTEN 18
NORTHEAST SUB 12.50 46.00DISTRIBUTION-UNATTEN 19
NORTHRIDGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
OAKLAND AVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
OAKLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
OLYMPUS SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
OPHIR SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
ORANGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
ORANGEVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
OREM SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
PACK CREEK RESERVOIR 12.47 46.00DISTRIBUTION-UNATTEN 28
PANGUITCH SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
PARIETTE SUBSTATION 24.90 69.00DISTRIBUTION-UNATTEN 30
PARK CITY SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
PARKWAY SUB 12.47 138.00DISTRIBUTION-UNATTEN 32
PARLEYS SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
PELICAN POINT SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
PINE CANYON SUB 12.47 138.00DISTRIBUTION-UNATTEN 35
PINE CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
PINNACLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
PLAIN CITY SUB 12.47 138.00DISTRIBUTION-UNATTEN 38
PLEASANT GROVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
PLEASANT VIEW SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.14
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
19 2 1
12 1 2
3 1 3
7 2 4
6 1 5
6 3 6
5 1 7
6 1 8
6 1 9
7 1 10
20 1 11
5 1 12
14 1 13
25 1 14
2 1 15
25 1 16
22 1 17
25 1 18
45 2 19
14 1 20
24 2 21
6 1 22
22 1 23
3 1 24
20 1 25
14 1 26
48 2 27
4 1 28
5 1 29
4 3 30
35 2 31
50 2 32
16 2 33
6 1 34
55 2 35
2 1 36
14 1 37
22 1 38
25 1 39
14 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.14
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
PORTER ROCKWELL SUB 12.47 138.00DISTRIBUTION-UNATTEN 1
PROMONTORY SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
QUAIL CREEK SUB 12.47 34.50DISTRIBUTION-UNATTEN 3
QUARRY SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
QUICHAPA SUB 12.47 34.50DISTRIBUTION-UNATTEN 5
RAINS SUB 7.20 46.00DISTRIBUTION-UNATTEN 6
RANDOLPH SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
RASMUSON SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
RATTLESNAKE SUB 24.90 69.00DISTRIBUTION-UNATTEN 9
RED MOUNTAIN SUB 34.50 69.00DISTRIBUTION-UNATTEN 10
RED ROCK SUB 4.16 69.00DISTRIBUTION-UNATTEN 11
REDWOOD SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
RESEARCH PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
RICH SUB 12.47 69.00DISTRIBUTION-UNATTEN 14
RICHFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
RICHMOND SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
RIDGELAND SUB 12.47 138.00DISTRIBUTION-UNATTEN 17
RITER SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
ROCK CANYON SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
ROCKVILLE SUB 12.47 34.50DISTRIBUTION-UNATTEN 20
ROCKY POINT 13.20 138.00DISTRIBUTION-UNATTEN 21
ROSE PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
ROYAL SUB 4.16 46.00DISTRIBUTION-UNATTEN 23
SALINA SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
SANDY SUB 12.47 138.00DISTRIBUTION-UNATTEN 25
SARATOGA SUB 12.47 138.00DISTRIBUTION-UNATTEN 26
SCIPIO SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
SCOFIELD RESERVOIR SUB 7.20 46.00DISTRIBUTION-UNATTEN 28
SCOFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
SECOND STREET SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
SEVEN MILE SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
SHARON SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
SHIVWITS SUB 4.16 34.50DISTRIBUTION-UNATTEN 33
SHORELINE SUB 13.20 138.00DISTRIBUTION-UNATTEN 34
SIXTH SOUTH SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
SKULL VALLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
SKYPARK SUB 12.50 138.00 12.50DISTRIBUTION-UNATTEN 37
SNARR SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
SNOWVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
SNYDERVILLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.15
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
30 1 1
2 1 2
4 1 3
60 2 4
4 1 5
15 1 6
2 1 7
1 3 8
14 1 9
12 1 10
3 1 11
45 2 12
45 2 13
5 1 14
22 2 15
11 1 16
40 2 17
20 1 18
5 1 19
4 1 20
30 1 21
24 3 22
3 23
11 1 24
60 2 25
60 2 26
1 3 27
1 1 28
1 3 29
13 2 30
1 31
20 1 32
6 1 33
60 2 34
20 1 35
2 1 36
40 1 37
40 2 38
5 1 39
60 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.15
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
SOLDIER SUMMIT SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
SOUTH JORDAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 2
SOUTH MILFORD SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
SOUTH MOUNTAIN SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
SOUTH OGDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
SOUTH PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 6
SOUTH WEBER SUB 12.47 138.00DISTRIBUTION-UNATTEN 7
SOUTHWEST SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
SPANISH VALLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
SPRINGDALE SUB 12.47 34.50DISTRIBUTION-UNATTEN 10
ST. JOHNS SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
STAIRS SUB 2.40 12.47DISTRIBUTION-UNATTEN 12
STANSBURY SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
SUMMIT CREEK SUB 12.47 138.00DISTRIBUTION-UNATTEN 14
SUMMIT PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
SUNRISE SUB 12.47 138.00DISTRIBUTION-UNATTEN 16
SUPERIOR SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
SUTHERLAND SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
TAMARISK SUB 12.47 138.00DISTRIBUTION-UNATTEN 19
TAYLOR SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
THIEF CREEK SUB 24.90 138.00DISTRIBUTION-UNATTEN 21
THIRD WEST SUB 13.20 138.00DISTRIBUTION-UNATTEN 22
THIRTEENTH SOUTH SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
THOMPSON SUB 4.16 46.00DISTRIBUTION-UNATTEN 24
TOOELE DEPOT SUB 12.50 46.00DISTRIBUTION-UNATTEN 25
TOQUERVILLE SUB 12.47 69.00 34.50DISTRIBUTION-UNATTEN 26
UINTAH SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
UNION SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
UNIVERSITY SUB 7.20 46.00 12.50DISTRIBUTION-UNATTEN 29
VALLEY CENTER SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
VERMILLION SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
VERNAL SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
VEYO HYDRO 2.40 34.50DISTRIBUTION-UNATTEN 33
VICKERS SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
VINEYARD SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
WALLSBURG SUB 12.47 138.00DISTRIBUTION-UNATTEN 36
WALNUT GROVE SUB 12.50 138.00DISTRIBUTION-UNATTEN 37
WARREN SUB 12.47 138.00DISTRIBUTION-UNATTEN 38
WASATCH STATE PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
WASHAKIE SUB 4.16 138.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.16
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
12 1 1
60 2 2
20 2 3
60 2 4
25 1 5
30 1 6
22 1 7
22 2 8
6 1 9
4 1 10
4 1 11
2 1 12
20 1 13
14 1 14
7 1 15
60 2 16
8 1 17
6 1 18
20 1 19
14 1 20
14 1 21
100 2 22
22 1 23
2 1 24
25 1 25
34 2 26
39 2 27
50 2 28
29 2 29
22 1 30
3 1 31
32 2 32
2 3 33
2 1 34
25 1 35
13 1 36
30 1 37
30 1 38
2 3 39
14 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.16
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
WELBY SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
WELFARE SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
WEST COMMERCIAL SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
WEST JORDAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
WEST OGDEN SUB 12.47 138.00DISTRIBUTION-UNATTEN 5
WEST ROY SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
WEST TEMPLE SUB 4.16 46.00DISTRIBUTION-UNATTEN 7
WESTWATER SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
WHITE MESA SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
WHITE ROCK SUB 12.47 138.00DISTRIBUTION-UNATTEN 10
WILLOWCREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
WILLOWRIDGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
WINCHESTER HILLS SUB 12.47 34.50DISTRIBUTION-UNATTEN 13
WINKLEMAN SUB 7.20 46.00DISTRIBUTION-UNATTEN 14
WOLF CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
WOOD CROSS SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
WOODRUFF SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
Total 3564.73 19675.27 117.97 18
Number of Substations-285 19
20
90TH SOUTH SUB 138.00 345.00 12.47T/D-UNATTENDED 21
ANGEL SUB 12.47 138.00 46.00T/D-UNATTENDED 22
BDO SUBSTATION 12.47 138.00T/D-UNATTENDED 23
BUTLERVILLE SUB 46.00 138.00 12.47T/D-UNATTENDED 24
CENTENNIAL SUB 12.47 138.00T/D-UNATTENDED 25
COTTONWOOD SUB 12.47 138.00 46.00T/D-UNATTENDED 26
DECADE SUB 12.50 138.00T/D-UNATTENDED 27
DUMAS SUB 12.47 138.00T/D-UNATTENDED 28
EMMA PARK SUBSTATION 12.47 138.00T/D-UNATTENDED 29
GROW SUB 12.47 138.00 46.00T/D-UNATTENDED 30
HALE SUB 46.00 138.00 12.47T/D-UNATTENDED 31
HIGHLAND SUB 12.47 138.00 46.00T/D-UNATTENDED 32
JORDAN SUB 46.00 138.00 12.47T/D-UNATTENDED 33
JUDGE SUB 12.47 46.00T/D-UNATTENDED 34
MCCLELLAND SUB 46.00 138.00 12.47T/D-UNATTENDED 35
MORTON COURT SUB 12.47 138.00T/D-UNATTENDED 36
OQUIRRH SUB 46.00 345.00 138.00T/D-UNATTENDED 37
PARRISH SUB 12.47 138.00 46.00T/D-UNATTENDED 38
PIONEER PLANT 2.30 138.00 46.00T/D-UNATTENDED 39
RIVERDALE SUB 46.00 138.00 12.47T/D-UNATTENDED 40
FERC FORM NO. 1 (ED. 12-96) Page 426.17
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
42 2 1
5 1 2
22 1 3
28 1 4
60 2 5
25 1 6
60 3 7
5 1 8
14 1 9
30 1 10
1 1 11
14 1 12
4 1 13
1 14
6 1 15
20 1 16
2 1 17
5463 393 1 18
19
20
1572 5 1 21
135 3 22
30 1 23
205 4 24
40 2 25
289 7 26
60 2 27
60 2 28
8 1 29
72 3 30
114 2 31
97 2 32
164 2 33
22 1 34
340 3 35
65 2 36
835 4 1 37
97 2 38
51 7 39
180 3 40
FERC FORM NO. 1 (ED. 12-96) Page 427.17
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
SEVIER SUB 46.00 138.00 12.47T/D-UNATTENDED 1
SILVER CREEK SUB 12.47 138.00 46.00T/D-UNATTENDED 2
SOUTHEAST SUB 12.47 138.00 46.00T/D-UNATTENDED 3
SPHINX SUB 12.47 46.00T/D-UNATTENDED 4
SYRACUSE SUB 46.00 345.00 138.00T/D-UNATTENDED 5
TAYLORSVILLE SUB 46.00 138.00 12.47T/D-UNATTENDED 6
TERMINAL SUB 46.00 345.00 138.00T/D-UNATTENDED 7
TIMP SUB 46.00 138.00 12.47T/D-UNATTENDED 8
TOOELE SUB 46.00 138.00 12.47T/D-UNATTENDED 9
TRI CITY SUB 12.47 138.00T/D-UNATTENDED 10
WEST VALLEY SUB 12.47 138.00T/D-UNATTENDED 11
WESTFIELD SUB 12.47 138.00T/D-UNATTENDED 12
Total 916.79 5060.00 906.70 13
Number of Substations-32 14
15
EMERY SUB 138.00 345.00 69.00TRANSMISSION-ATTENDE 16
GADSBY SUB 46.00 138.00TRANSMISSION-ATTENDE 17
HUNTER PLANT 23.00 345.00TRANSMISSION-ATTENDE 18
HUNTINGTON PLANT 23.00 345.00TRANSMISSION-ATTENDE 19
ABAJO SUB 69.00 138.00TRANSMISSION-UNATTEN 20
ASHLEY SUB 46.00 138.00TRANSMISSION-UNATTEN 21
BARNEY SUB 46.00 138.00TRANSMISSION-UNATTEN 22
BEN LOMOND SUB 230.00 345.00 138.00TRANSMISSION-UNATTEN 23
BLACKHAWK SUB 69.00 138.00 46.00TRANSMISSION-UNATTEN 24
BOOKCLIFFS SUB 46.00 69.00TRANSMISSION-UNATTEN 25
CAMERON SUB 46.00 138.00TRANSMISSION-UNATTEN 26
CAMP WILLIAMS SUB 138.00 345.00 12.47TRANSMISSION-UNATTEN 27
CARBON SUB 138.00TRANSMISSION-UNATTEN 28
CLOVER SUB 138.00 345.00 14.40TRANSMISSION-UNATTEN 29
COLUMBIA SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 30
CRANER FLAT SUB 12.47 138.00TRANSMISSION-UNATTEN 31
CUTLER SUB 46.00 138.00TRANSMISSION-UNATTEN 32
EL MONTE SUB 46.00 138.00TRANSMISSION-UNATTEN 33
GARKANE SUB 46.00 69.00TRANSMISSION-UNATTEN 34
GREEN CANYON SUB 46.00 138.00TRANSMISSION-UNATTEN 35
GRINDING SUB 13.80 138.00TRANSMISSION-UNATTEN 36
HELPER SUB 46.00 138.00TRANSMISSION-UNATTEN 37
HONEYVILLE SUB 46.00 138.00TRANSMISSION-UNATTEN 38
HORSESHOE SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 39
HUNTINGTON SUB 138.00 345.00TRANSMISSION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.18
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
34 4 1
100 2 2
50 2 3
3 1 3 4
600 5 5
358 4 6
1108 6 2 7
130 2 8
158 3 9
30 1 10
30 1 11
20 1 12
7057 90 7 13
14
15
783 13 1 16
318 2 17
1513 5 1 18
981 4 19
67 1 20
133 2 21
100 1 22
1813 5 23
100 2 24
6 3 1 25
25 4 26
169 2 27
8 1 28
448 1 29
71 2 30
40 2 31
70 2 32
312 3 33
33 1 34
67 2 35
225 3 36
142 2 37
35 1 38
80 2 39
270 4 40
FERC FORM NO. 1 (ED. 12-96) Page 427.18
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
JERUSALEM SUB 46.00 138.00TRANSMISSION-UNATTEN 1
LAMPO SUB 46.00 138.00TRANSMISSION-UNATTEN 2
MCFADDEN SUB 46.00 138.00TRANSMISSION-UNATTEN 3
MIDDLETON SUB 69.00 138.00 34.50TRANSMISSION-UNATTEN 4
MIDVALLEY SUB 138.00 345.00TRANSMISSION-UNATTEN 5
MIDWAY CITY SUB 46.00 138.00TRANSMISSION-UNATTEN 6
MINERAL PRODUCTS SUB 46.00 69.00TRANSMISSION-UNATTEN 7
MOAB SUB 69.00 138.00TRANSMISSION-UNATTEN 8
NEBO SUB 46.00 138.00TRANSMISSION-UNATTEN 9
OLMSTED SUB 2.40 46.00TRANSMISSION-UNATTEN 10
PAROWAN VALLEY SUB 138.00 230.00 34.50TRANSMISSION-UNATTEN 11
PAVANT SUB 46.00 230.00TRANSMISSION-UNATTEN 12
PINTO SUB 138.00 345.00 69.00TRANSMISSION-UNATTEN 13
RED BUTTE SUB 138.00 230.00TRANSMISSION-UNATTEN 14
SAND COVE HYDRO 2.40 34.50TRANSMISSION-UNATTEN 15
SIGURD SUB 230.00 345.00 138.00TRANSMISSION-UNATTEN 16
SMITHFIELD SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 17
SPANISH FORK SUB 138.00 345.00 46.00TRANSMISSION-UNATTEN 18
ST GEORGE SUB 16.50 138.00TRANSMISSION-UNATTEN 19
THREE PEAKS SUB 138.00 345.00TRANSMISSION-UNATTEN 20
WEBER PLANT/SUB 2.30 46.00TRANSMISSION-UNATTEN 21
WEST CEDAR SUB 138.00 230.00 34.50TRANSMISSION-UNATTEN 22
Total 3315.87 8843.50 673.78 23
Number of Substations-47 24
25
WASHINGTON 26
ATTALIA SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
BOWMAN SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
CASCADE KRAFT SUB 12.47 69.00 4.16DISTRIBUTION-UNATTEN 29
CLINTON SUB 12.47 115.00DISTRIBUTION-UNATTEN 30
DAYTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
DODD ROAD SUB 20.80 69.00DISTRIBUTION-UNATTEN 32
GRANDVIEW SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 33
HOPLAND SUB 12.47 115.00DISTRIBUTION-UNATTEN 34
NACHES HYDRO 12.47 115.00DISTRIBUTION-UNATTEN 35
NOB HILL SUB 12.47 115.00DISTRIBUTION-UNATTEN 36
NORTH PARK SUB 12.47 115.00DISTRIBUTION-UNATTEN 37
ORCHARD SUB 12.47 115.00DISTRIBUTION-UNATTEN 38
PACIFIC SUB 12.47 115.00DISTRIBUTION-UNATTEN 39
POMEROY SUB 12.47 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.19
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
67 1 1
75 1 2
45 1 3
141 4 4
900 2 5
67 1 6
12 1 7
67 1 8
67 1 9
15 1 10
138 2 11
133 2 12
258 3 13
400 1 14
1 15
1124 6 16
63 2 17
1017 5 18
100 3 1 19
450 1 20
7 1 21
262 3 22
13217 114 4 23
24
25
26
25 1 27
45 2 28
118 6 29
25 1 30
23 2 31
25 4 32
42 2 33
50 2 34
20 1 35
42 2 36
45 2 37
50 2 38
28 3 39
9 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.19
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
PROSPECT POINT SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
PUNKIN CENTER SUB 12.47 115.00DISTRIBUTION-UNATTEN 2
RIVER ROAD SUB 12.47 115.00DISTRIBUTION-UNATTEN 3
SELAH SUB 12.47 115.00DISTRIBUTION-UNATTEN 4
SULPHUR CREEK SUB 12.47 115.00DISTRIBUTION-UNATTEN 5
SUNNYSIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 6
TIETON SUB 12.47 115.00 34.50DISTRIBUTION-UNATTEN 7
TOPPENISH SUB 12.47 115.00DISTRIBUTION-UNATTEN 8
TOUCHET SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
VOELKER SUB 12.47 115.00DISTRIBUTION-UNATTEN 10
WAITSBURG SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
WAPATO SUB 12.47 115.00DISTRIBUTION-UNATTEN 12
WENAS SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
WHITE SWAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 14
WILEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 15
Total 369.96 2921.00 107.66 16
Number of Substations-29 17
18
CENTRAL SUB 12.47 69.00T/D-UNATTENDED 19
MILL CREEK SUB 12.47 69.00T/D-UNATTENDED 20
UNION GAP SUB 115.00 230.00 12.47T/D-UNATTENDED 21
Total 139.94 368.00 12.47 22
Number of Substations-3 23
24
MERWIN HYDRO PLANT 13.20 115.00TRANSMISSION-ATTENDE 25
YALE PLANT 13.80 115.00TRANSMISSION-ATTENDE 26
OUTLOOK SUB 115.00 230.00TRANSMISSION-UNATTEN 27
PASCO SUB 69.00 115.00 7.20TRANSMISSION-UNATTEN 28
POMONA HEIGHTS SUB 115.00 230.00TRANSMISSION-UNATTEN 29
WALLA WALLA 230KV SUB 69.00 230.00TRANSMISSION-UNATTEN 30
WALLULA SUB 69.00 230.00TRANSMISSION-UNATTEN 31
WINE COUNTRY SUB 115.00 230.00TRANSMISSION-UNATTEN 32
Total 579.00 1495.00 7.20 33
Number of Substations-8 34
35
WYOMING 36
ANTELOPE MINE SUB 34.50 230.00DISTRIBUTION-UNATTEN 37
ASTLE STREET 13.20 34.50DISTRIBUTION-UNATTEN 38
BAILEY DOME SUB 12.47 57.00DISTRIBUTION-UNATTEN 39
BAR X SUB 34.50 230.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.20
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
40 2 1
20 2 2
51 4 3
45 2 4
25 1 5
45 2 6
29 2 7
50 2 8
6 1 9
25 1 10
9 1 11
45 2 12
25 2 13
22 2 14
45 2 15
1029 59 16
17
18
14 1 19
45 2 20
348 5 21
407 8 22
23
24
183 9 1 25
143 3 1 26
125 1 27
39 9 28
300 2 29
300 2 30
120 2 31
250 1 32
1460 29 2 33
34
35
36
25 1 37
12 1 38
2 1 39
25 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.20
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
BIG MUDDY SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
BIG PINEY SUB 24.90 69.00DISTRIBUTION-UNATTEN 2
BLACKS FORK SUB 34.50 230.00DISTRIBUTION-UNATTEN 3
BRIDGER PUMP SUB 34.50 230.00 13.20DISTRIBUTION-UNATTEN 4
BRYAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 5
BUFFALO TOWN SUB 4.16 20.80DISTRIBUTION-UNATTEN 6
BYRON SUB 4.16 34.50DISTRIBUTION-UNATTEN 7
CASSA SUB 20.80 57.00 12.47DISTRIBUTION-UNATTEN 8
CENTER STREET SUB 4.16 115.00DISTRIBUTION-UNATTEN 9
CHAPMAN SUBSTATION 12.47 46.00DISTRIBUTION-UNATTEN 10
CHUKAR SUB 4.16 12.47DISTRIBUTION-UNATTEN 11
CHURCH AND DWIGHT SUB 0.48 34.50DISTRIBUTION-UNATTEN 12
COKEVILLE SUB 24.90 46.00DISTRIBUTION-UNATTEN 13
COLUMBIA-GENEVA SUB 13.80 230.00DISTRIBUTION-UNATTEN 14
COMMUNITY PARK SUB 13.20 115.00DISTRIBUTION-UNATTEN 15
CROOKS GAP SUB 12.47 34.50DISTRIBUTION-UNATTEN 16
DEER CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
DJ COAL MINE SUB 34.50 69.00DISTRIBUTION-UNATTEN 18
DOUGLAS SUB 2.30 57.00DISTRIBUTION-UNATTEN 19
DRY FORK SUB 4.16 69.00DISTRIBUTION-UNATTEN 20
ELK BASIN SUB 7.20 34.50DISTRIBUTION-UNATTEN 21
EMIGRANT SUB 12.47 115.00DISTRIBUTION-UNATTEN 22
EVANS SUB 12.47 115.00DISTRIBUTION-UNATTEN 23
EVANSTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 24
FORT CASPER SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
FORT SANDERS SUB 13.20 115.00DISTRIBUTION-UNATTEN 26
FRANNIE SUB 34.50 230.00DISTRIBUTION-UNATTEN 27
FRONTIER SUB 4.16 69.00DISTRIBUTION-UNATTEN 28
GARLAND SUB 34.50 230.00DISTRIBUTION-UNATTEN 29
GLENDO SUB 4.16 57.00DISTRIBUTION-UNATTEN 30
GRASS CREEK SUB 34.50 230.00DISTRIBUTION-UNATTEN 31
GREAT DIVIDE SUB 34.50 115.00DISTRIBUTION-UNATTEN 32
GREYBULL SUB 4.16 34.50DISTRIBUTION-UNATTEN 33
HANNA SUB 12.47 34.50DISTRIBUTION-UNATTEN 34
JACKALOPE SUB 12.47 115.00DISTRIBUTION-UNATTEN 35
KEMMERER SUB 24.90 69.00DISTRIBUTION-UNATTEN 36
KIRBY CREEK PUMPING STATION 2.40 34.50DISTRIBUTION-UNATTEN 37
KIRBY CREEK SUB 4.16 34.50DISTRIBUTION-UNATTEN 38
LANDER SUB 12.47 34.50DISTRIBUTION-UNATTEN 39
LARAMIE SUB 13.20 115.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.21
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
7 1 1
14 1 2
150 2 3
72 4 4
25 1 5
2 3 6
2 3 7
2 6 1 8
12 1 9
4 1 10
1 3 11
3 2 12
4 1 13
45 2 14
50 2 15
5 3 16
9 1 17
12 1 18
6 3 19
9 1 20
5 1 21
12 1 22
9 1 23
40 2 24
25 1 25
20 1 26
50 2 27
6 1 28
45 2 29
3 4 30
25 1 31
20 1 32
3 1 33
6 1 34
25 1 35
10 1 36
3 3 37
2 3 38
25 2 39
50 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.21
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
LATHAM SUB 34.50 230.00DISTRIBUTION-UNATTEN 1
LINCH SUB 13.80 69.00DISTRIBUTION-UNATTEN 2
LITTLE MOUNTAIN SUB 34.50 230.00DISTRIBUTION-UNATTEN 3
LOVELL SUB 4.16 34.50DISTRIBUTION-UNATTEN 4
MILL IRON SUB 13.80 34.50DISTRIBUTION-UNATTEN 5
MILLS SUB 4.16 12.47DISTRIBUTION-UNATTEN 6
MURPHY DOME SUB 13.20 34.50DISTRIBUTION-UNATTEN 7
NUGGETT SUB 7.20 69.00DISTRIBUTION-UNATTEN 8
OPAL SUB 24.90 69.00DISTRIBUTION-UNATTEN 9
ORIN SUB 12.47 57.00DISTRIBUTION-UNATTEN 10
ORPHA SUB 7.20 57.00DISTRIBUTION-UNATTEN 11
PARADISE SUB 25.00 69.00DISTRIBUTION-UNATTEN 12
PARCO SUB 12.47 34.50DISTRIBUTION-UNATTEN 13
PINEDALE SUB 24.90 69.00DISTRIBUTION-UNATTEN 14
PITCHFORK SUB 24.90 69.00DISTRIBUTION-UNATTEN 15
POISON SPIDER SUB 2.40 69.00DISTRIBUTION-UNATTEN 16
POLECAT SUB 12.47 34.50DISTRIBUTION-UNATTEN 17
RAINBOW SUB 13.20 34.50DISTRIBUTION-UNATTEN 18
RAVEN SUB 34.50 230.00DISTRIBUTION-UNATTEN 19
RED BUTTE SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
REFINERY SUB 12.47 115.00DISTRIBUTION-UNATTEN 21
SAGE HILL SUB 13.20 34.50DISTRIBUTION-UNATTEN 22
SHOSHONI SUB 2.40 34.50DISTRIBUTION-UNATTEN 23
SLATE CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
SOUTH CODY SUB 24.90 69.00DISTRIBUTION-UNATTEN 25
SOUTH ELK BASIN SUB 4.16 34.50DISTRIBUTION-UNATTEN 26
SOUTH TRONA SUB 34.50 230.00DISTRIBUTION-UNATTEN 27
SPRING CREEK SUB 13.20 115.00DISTRIBUTION-UNATTEN 28
SVILAR SUB 4.16 34.50DISTRIBUTION-UNATTEN 29
TEN MILE STEP DOWN SUB 12.50 34.50DISTRIBUTION-UNATTEN 30
TEN MILE SUB 34.50 69.00DISTRIBUTION-UNATTEN 31
THERMOPOLIS TOWN SUB 4.16 34.50DISTRIBUTION-UNATTEN 32
THUNDER CREEK SUB 12.47 57.00DISTRIBUTION-UNATTEN 33
VETERANS SUB 13.20 34.50DISTRIBUTION-UNATTEN 34
WELCH SUB 2.40 57.00DISTRIBUTION-UNATTEN 35
WERTZ-SINCLAIR SUB 4.16 57.00 12.50DISTRIBUTION-UNATTEN 36
WEST ADAMS SUB 4.16 34.50DISTRIBUTION-UNATTEN 37
WESTVACO SUB 34.50 230.00DISTRIBUTION-UNATTEN 38
WORLAND TOWN SUB 4.16 34.50DISTRIBUTION-UNATTEN 39
WYOPO SUB 34.50 230.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.22
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
25 1 1
12 1 2
20 1 3
4 1 4
12 1 1 5
1 3 6
5 1 7
1 8
7 1 9
2 3 10
3 3 11
30 1 12
5 1 13
8 1 14
17 9 2 15
3 1 16
2 3 17
12 1 18
200 2 19
20 1 20
45 2 21
6 1 22
2 3 23
1 1 24
14 3 1 25
2 6 26
150 2 27
25 1 28
2 3 29
5 1 30
12 1 31
5 1 32
9 1 33
25 2 34
3 3 35
2 6 36
3 1 37
25 1 38
5 1 39
20 1 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.22
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
WYUTA SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
Total 1311.37 7493.24 38.17 2
Number of Substations-85 3
4
BUFFALO SUB 20.80 230.00T/D-UNATTENDED 5
ELK HORN SUB 12.50 115.00T/D-UNATTENDED 6
FIREHOLE SUB 34.50 230.00T/D-UNATTENDED 7
HILLTOP SUB 34.50 115.00 20.80T/D-UNATTENDED 8
LABARGE SUB 24.90 69.00T/D-UNATTENDED 9
POINT OF ROCKS SUB 34.50 230.00T/D-UNATTENDED 10
RIVERTON 230 SUB 12.47 230.00 34.50T/D-UNATTENDED 11
YELLOWCAKE SUB 34.50 230.00T/D-UNATTENDED 12
Total 208.67 1449.00 55.30 13
Number of Substations-8 14
15
DAVE JOHNSTON PLANT/SUB 115.00 230.00 69.00TRANSMISSION-ATTENDE 16
JIM BRIDGER 345KV SUB 230.00 345.00 34.50TRANSMISSION-ATTENDE 17
JIM BRIDGER UNITS 1-4 22.00 345.00TRANSMISSION-ATTENDE 18
NAUGHTON SUB 69.00 230.00 138.00TRANSMISSION-ATTENDE 19
WYODAK 230KV SUB 69.00 230.00TRANSMISSION-ATTENDE 20
WYODAK PLANT 22.00 230.00TRANSMISSION-ATTENDE 21
BAIROIL SUB 34.50 115.00 57.00TRANSMISSION-UNATTEN 22
CASPER SUB 115.00 230.00 13.20TRANSMISSION-UNATTEN 23
CHAPPELL CREEK SUB 69.00 230.00TRANSMISSION-UNATTEN 24
CHIMNEY BUTTE SUB 69.00 230.00TRANSMISSION-UNATTEN 25
FOOTE CREEK WIND FARM 34.50 230.00TRANSMISSION-UNATTEN 26
GLENDO AUTO SUB 57.00 69.00TRANSMISSION-UNATTEN 27
MANSFACE SUB 34.50 230.00TRANSMISSION-UNATTEN 28
MIDWEST SUB 69.00 230.00 34.50TRANSMISSION-UNATTEN 29
MINERS SUB 115.00 230.00 34.50TRANSMISSION-UNATTEN 30
MUSTANG SUB 115.00 230.00TRANSMISSION-UNATTEN 31
OREGON BASIN SUB 34.50 230.00 69.00TRANSMISSION-UNATTEN 32
PLATTE SUB 115.00 230.00 34.50TRANSMISSION-UNATTEN 33
RAILROAD SUB 138.00 230.00TRANSMISSION-UNATTEN 34
ROCK SPRINGS 230 SUB 34.50 230.00TRANSMISSION-UNATTEN 35
SAGE SUB 46.00 69.00TRANSMISSION-UNATTEN 36
THERMOPOLIS SUB 115.00 230.00TRANSMISSION-UNATTEN 37
Total 1722.50 4853.00 484.20 38
Number of Substations-22 39
40
FERC FORM NO. 1 (ED. 12-96) Page 426.23
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
1 1
1631 157 6 2
3
4
20 1 5
25 1 6
50 2 7
45 2 1 8
8 6 9
25 1 10
74 4 11
25 1 12
272 18 1 13
14
15
1358 16 16
1084 22 17
1122 2 18
1232 15 1 19
230 3 20
503 3 1 21
53 3 22
517 5 23
67 1 24
75 1 25
196 2 26
15 2 27
20 1 28
90 4 29
58 4 1 30
200 2 31
65 2 32
140 3 33
400 1 34
50 2 35
22 1 36
175 2 37
7672 97 3 38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.23
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
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).
1
CALIFORNIA 2
Distribution - 43 3
T/D - 3 4
Transmission - 9 5
6
IDAHO 7
Distribution - 65 8
T/D - 5 9
Transmission - 18 10
11
MONTANA 12
Transmission - 1 13
14
OREGON 15
Distribution - 180 16
T/D - 11 17
Transmission - 42 18
19
UTAH 20
Distribution - 285 21
T/D - 32 22
Transmission - 47 23
24
WASHINGTON 25
Distribution - 29 26
T/D - 3 27
Transmission - 8 28
29
WYOMING 30
Distribution - 85 31
T/D - 8 32
Transmission - 22 33
34
ALL STATES 35
Distribution - 687 36
T/D - 62 37
Transmission - 147 38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 426.24
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2012/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
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.
1
2
324 3
130 4
805 5
6
7
721 8
374 9
3606 10
11
12
100 13
14
15
4575 16
1262 17
7413 18
19
20
5463 21
7057 22
13217 23
24
25
1029 26
407 27
1460 28
29
30
1631 31
272 32
7672 33
34
35
13743 36
9502 37
34273 38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.24
Schedule Page: 426.9 Line No.: 24 Column: a
The Dixonville 500kV Substation is jointly owned by PacifiCorp 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 BPA 42.0%.
Schedule Page: 426.9 Line No.: 36 Column: a
The Malin 500kV Substation is jointly owned by PacifiCorp, Portland General Electric
("PGE"), BPA and Western Area Power Administration ("WAPA"). Ownership of the substation
is as follows: PacifiCorp 25.0%, PGE 25.0%, BPA 25.0% and WAPA 25.0%. Operation and
maintenance costs are shared among the four parties and responsibility is as follows:
PacifiCorp 25.0%, PGE 25.0%, BPA 25.0% and WAPA 25.0%.
Schedule Page: 426.9 Line No.: 37 Column: a
The Meridian 500kV Substation is jointly owned by PacifiCorp 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%.
Schedule Page: 426.23 Line No.: 16 Column: a
The Dave Johnston 230kV Substation is jointly owned by PacifiCorp 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.
Schedule Page: 426.23 Line No.: 17 Column: a
The Jim Bridger 345kV Substation is jointly owned by PacifiCorp 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.: 20 Column: a
The Wyodak 230kV Substation is jointly owned by PacifiCorp 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%.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
PacifiCorp X
/ /2012/Q4
Line
No. Description of the Non-Power Good or Service
Name of
(c)(b)(a)(d)
Associated/AffiliatedCompany
AccountCharged orCredited
Amount
Credited
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 toan associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should notattempt 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.
Charged or
1 Non-power Goods or Services Provided by Affiliated
2
3 Coal purchases and support services 149,861,924Bridger Coal Company
4
5 Coal mining services 65,093,351Energy West Mining Company 151
6
7 Coal purchases 13,669,844Trapper Mining Inc. 151
8
9 Administrative support services 822,352Interwest Mining Company
10
11 Administrative services under the IASA 10,423,677MEHC
12 Administrative services under the IASA 3,881,498MEC
13 Administrative services under the IASA 756,131MHC, Inc. 426.5, 923
14 Administrative services under the IASA 169,609Kern River Gas Transmission Company 107, 923
15
16 Gas transportation services 3,175,157Kern River Gas Transmission Company 501, 547
17
18 Relocation services 1,870,846HomeServices of America, Inc.
19
20 Non-power Goods or Services Provided for Affiliate
21 Financial support services and employee benefits 508,808Interwest Mining Company 146
22
23 Information technology and royalties 493,674Bridger Coal Company 146
24
25 Information technology support services 269,154Energy West Mining Company 146
26
27
28 Administrative services under the IASA 1,209,082MEC 146
29
30 Administrative services under the IASA 535,508MidAmerican Transmission LLC 146
31
32 Administrative services under the IASA 309,919Northern Natural Gas Company 146
33
34
35
36
37
38
39
40
41
42
1 Non-power Goods or Services Provided by Affiliated
2
FERC FORM NO. 1 (New) Page 429
FERC FORM NO. 1-F (New)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
PacifiCorp X
/ /2012/Q4
Line
No. Description of the Non-Power Good or Service
Name of
(c)(b)(a)(d)
Associated/AffiliatedCompany
AccountCharged orCredited
Amount
Credited
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 toan associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should notattempt 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.
Charged or
3 Rail services / right-of-way fees 34,192,694BNSF Railway Company 151,507,567,589
4
5 Financial transactions related to energy hedging
6 activity and banking services 20,050,677Wells Fargo & Company
7
8 Computer hardware and software and computer
9 systems consulting and maintenance services 2,167,361International Business Machines
10
11 Rating agency fees 517,067Moody's Investors Service 181, 186, 930.2
12
13
14
15
16
17
18
19
20 Non-power Goods or Services Provided for Affiliate
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
1 Non-power Goods or Services Provided by Affiliated
2
3
4
FERC FORM NO. 1 (New) Page 429.1
FERC FORM NO. 1-F (New)
Schedule Page: 429 Line No.: 3 Column: c
Accounts charged for Bridger Coal Company: 151, 232, 501, 513 and 921.
Schedule Page: 429 Line No.: 3 Column: d
Non-power goods or services provided by Bridger Coal Company are as follows:
Coal purchases $ 149,696,962
Support services 164,962
$ 149,861,924
Schedule 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: c
Accounts charged for Interwest Mining Company: 421, 426.1, 426.5, 557 and 929.
Schedule Page: 429 Line No.: 9 Column: d
Interwest Mining Company manages PacifiCorp's mining operations and charges management
services to Pacific Minerals, Inc., Bridger Coal Company, Energy West Mining Company and
Fossil Rock Fuels, LLC. Interwest 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
This footnote applies to all occurrences of "Administrative services under the IASA" on
page 429. "IASA" is the Intercompany Administrative Services Agreement between MidAmerican
Energy Holdings Company ("MEHC") and its subsidiaries. Amounts which are chargeable to or
from another affiliate are assigned first by coding to the specific affiliate. These
charges are based on actual labor, benefits and operational costs incurred. Amounts not
directly assignable to an individual affiliate, such as work performed where multiple
affiliates benefit, are assigned on the basis of allocations, as described below:
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. Eight combinations of this allocator are used for
allocating services that benefit different companies within the MEHC organization.
Legislative and Regulatory: The Legislative and Regulatory allocation is used to allocate
costs incurred by MEHC'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 MEHC 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.
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
utilized, number of servers utilized, server processing times, etc.
Processes: This allocator distributes costs of electronic data interchange software and
services based on the process count within each affiliate using such software or services.
Plant: This allocator distributes costs of managing the corporate insurance function based
on assets for each affiliate.
Schedule Page: 429 Line No.: 11 Column: c
Accounts charged for MEHC: 426.4, 426.5, 923 and 928.
Schedule Page: 429 Line No.: 11 Column: d
Excluded from this line are “convenience” payments made to vendors by one entity on behalf
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
of, and charged to, other entities within the MEHC group. Such affiliate charges reflect
the ability to obtain price discounts as a result of larger purchasing power.
Included in this line are amounts charged to PacifiCorp for awards granted to PacifiCorp
employees under the long-term incentive plan (“LTIP”) maintained by MEHC. Excluded from
this page are reimbursements by MEHC for payments made by PacifiCorp to its employees
under the LTIP upon vesting of the awards. Also excluded from this page are reimbursements
of deferred compensation and annual incentive payments associated with transferred
employees.
The convenience payments, the LTIP reimbursements and the deferred compensation and 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, 426.4, 426.5, 923 and 928.
Schedule Page: 429 Line No.: 12 Column: d
Excluded from this line are “convenience” payments made to vendors by one entity on behalf
of, and charged to, other entities within the MEHC group. Such affiliate charges reflect
the ability to obtain price discounts as a result of larger purchasing power and do not
constitute “services” as required by this page.
Schedule Page: 429 Line No.: 18 Column: c
Accounts charged for HomeServices of America, Inc.: 501, 506, 535, 548, 549, 556, 557,
560, 561.2, 568, 580, 581, 590, 593, 595, 597, 902, 903, 908, 921 and clearing accounts.
Schedule Page: 429 Line No.: 21 Column: d
PacifiCorp provides Interwest Mining Company with financial and administrative support and
technical services as well as employee benefits for Interwest Mining Company's employees.
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.: 23 Column: d
Non-power goods or services provided to Bridger Coal Company are as follows:
Information technology $ 465,184
Royalties 28,490
$ 493,674
Schedule Page: 429 Line No.: 30 Column: d
Excluded from this line are “convenience” payments made to vendors by one entity on behalf
of, and charged to, other entities within the MEHC group. Such affiliate charges reflect
the ability to obtain price discounts as a result of larger purchasing power and do not
constitute “services” as required by this page.
Schedule Page: 429.1 Line No.: 3 Column: d
Non-power goods or services provided by BNSF Railway Company are as follows:
Rail services $ 34,155,587
Right-of-way fees 37,107
$ 34,192,694
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.: 6 Column: c
Accounts charged for Wells Fargo & Company: 181, 186, 228.3, 419, 427, 501, 547, 560, 588,
903 and 921.
Schedule Page: 429.1 Line No.: 9 Column: c
Accounts charged for International Business Machines: 165, 232, 903, 909, 921 and 935.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2012/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
INDEX
Schedule Page No.
Accrued and prepaid taxes ........................................................................ 262-263
Accumulated Deferred Income Taxes .................................................................... 234
272-277
Accumulated provisions for depreciation of
common utility plant ............................................................................. 356
utility plant .................................................................................... 219
utility plant (summary) ...................................................................... 200-201
Advances
from associated companies .................................................................... 256-257
Allowances ....................................................................................... 228-229
Amortization
miscellaneous .................................................................................... 340
of nuclear fuel .............................................................................. 202-203
Appropriations of Retained Earnings .............................................................. 118-119
Associated Companies
advances from ................................................................................ 256-257
corporations controlled by respondent ............................................................ 103
control over respondent .......................................................................... 102
interest on debt to .......................................................................... 256-257
Attestation ............................................................................................ i
Balance sheet
comparative .................................................................................. 110-113
notes to ..................................................................................... 122-123
Bonds ............................................................................................ 256-257
Capital Stock ........................................................................................ 251
expense .......................................................................................... 254
premiums ......................................................................................... 252
reacquired ....................................................................................... 251
subscribed ....................................................................................... 252
Cash flows, statement of ......................................................................... 120-121
Changes
important during year ........................................................................ 108-109
Construction
work in progress - common utility plant .......................................................... 356
work in progress - electric ...................................................................... 216
work in progress - other utility departments ................................................. 200-201
Control
corporations controlled by respondent ............................................................ 103
over respondent .................................................................................. 102
Corporation
controlled by .................................................................................... 103
incorporated ..................................................................................... 101
CPA, background information on ....................................................................... 101
CPA Certification, this report form ................................................................. i-ii
FERC FORM NO. 1 (ED. 12-93)Index 1
INDEX (continued)
Schedule Page No.
Deferred
credits, other ................................................................................... 269
debits, miscellaneous ............................................................................ 233
income taxes accumulated - accelerated
amortization property ........................................................................ 272-273
income taxes accumulated - other property .................................................... 274-275
income taxes accumulated - other ............................................................. 276-277
income taxes accumulated - pollution control facilities .......................................... 234
Definitions, this report form ........................................................................ iii
Depreciation and amortization
of common utility plant .......................................................................... 356
of electric plant ................................................................................ 219
336-337
Directors ............................................................................................ 105
Discount - premium on long-term debt ............................................................. 256-257
Distribution of salaries and wages ............................................................... 354-355
Dividend appropriations .......................................................................... 118-119
Earnings, Retained ............................................................................... 118-119
Electric energy account .............................................................................. 401
Expenses
electric operation and maintenance ........................................................... 320-323
electric operation and maintenance, summary ...................................................... 323
unamortized debt ................................................................................. 256
Extraordinary property losses ........................................................................ 230
Filing requirements, this report form
General information .................................................................................. 101
Instructions for filing the FERC Form 1 ............................................................. i-iv
Generating plant statistics
hydroelectric (large) ........................................................................ 406-407
pumped storage (large) ....................................................................... 408-409
small plants ................................................................................. 410-411
steam-electric (large) ....................................................................... 402-403
Hydro-electric generating plant statistics ....................................................... 406-407
Identification ....................................................................................... 101
Important changes during year .................................................................... 108-109
Income
statement of, by departments ................................................................. 114-117
statement of, for the year (see also revenues) ............................................... 114-117
deductions, miscellaneous amortization ........................................................... 340
deductions, other income deduction ............................................................... 340
deductions, other interest charges ............................................................... 340
Incorporation information ............................................................................ 101
Index 2FERC FORM NO. 1 (ED. 12-95)
INDEX (continued)
Schedule Page No.

Interest
charges, paid on long-term debt, advances, etc ............................................... 256-257
Investments
nonutility property .............................................................................. 221
subsidiary companies ......................................................................... 224-225
Investment tax credits, accumulated deferred ..................................................... 266-267
Law, excerpts applicable to this report form .......................................................... iv
List of schedules, this report form .................................................................. 2-4
Long-term debt ................................................................................... 256-257
Losses-Extraordinary property ........................................................................ 230
Materials and supplies ............................................................................... 227
Miscellaneous general expenses ....................................................................... 335
Notes
to balance sheet ............................................................................. 122-123
to statement of changes in financial position ................................................ 122-123
to statement of income ....................................................................... 122-123
to statement of retained earnings ............................................................ 122-123
Nonutility property .................................................................................. 221
Nuclear fuel materials ........................................................................... 202-203
Nuclear generating plant, statistics ............................................................. 402-403
Officers and officers' salaries ...................................................................... 104
Operating
expenses-electric ............................................................................ 320-323
expenses-electric (summary) ...................................................................... 323
Other
paid-in capital .................................................................................. 253
donations received from stockholders ............................................................. 253
gains on resale or cancellation of reacquired
capital stock .................................................................................... 253
miscellaneous paid-in capital .................................................................... 253
reduction in par or stated value of capital stock ................................................ 253
regulatory assets ................................................................................ 232
regulatory liabilities ........................................................................... 278
Peaks, monthly, and output ........................................................................... 401
Plant, Common utility
accumulated provision for depreciation ........................................................... 356
acquisition adjustments .......................................................................... 356
allocated to utility departments ................................................................. 356
completed construction not classified ............................................................ 356
construction work in progress .................................................................... 356
expenses ......................................................................................... 356
held for future use .............................................................................. 356
in service ....................................................................................... 356
leased to others ................................................................................. 356
Plant data ...................................................................................336-337
401-429
Index 3FERC FORM NO. 1 (ED. 12-95)
INDEX (continued)
Schedule Page No.
Plant - electric
accumulated provision for depreciation ........................................................... 219
construction work in progress .................................................................... 216
held for future use .............................................................................. 214
in service ................................................................................... 204-207
leased to others ................................................................................. 213
Plant - utility and accumulated provisions for depreciation
amortization and depletion (summary) ............................................................. 201
Pollution control facilities, accumulated deferred
income taxes ..................................................................................... 234
Power Exchanges .................................................................................. 326-327
Premium and discount on long-term debt ............................................................... 256
Premium on capital stock ............................................................................. 251
Prepaid taxes .................................................................................... 262-263
Property - losses, extraordinary ..................................................................... 230
Pumped storage generating plant statistics ....................................................... 408-409
Purchased power (including power exchanges) ...................................................... 326-327
Reacquired capital stock ............................................................................. 250
Reacquired long-term debt ........................................................................ 256-257
Receivers' certificates .......................................................................... 256-257
Reconciliation of reported net income with taxable income
from Federal income taxes ...................................................................... 261
Regulatory commission expenses deferred .............................................................. 233
Regulatory commission expenses for year .......................................................... 350-351
Research, development and demonstration activities ............................................... 352-353
Retained Earnings
amortization reserve Federal ..................................................................... 119
appropriated ................................................................................. 118-119
statement of, for the year ................................................................... 118-119
unappropriated ............................................................................... 118-119
Revenues - electric operating .................................................................... 300-301
Salaries and wages
directors fees ................................................................................... 105
distribution of .............................................................................. 354-355
officers' ........................................................................................ 104
Sales of electricity by rate schedules ............................................................... 304
Sales - for resale ............................................................................... 310-311
Salvage - nuclear fuel ........................................................................... 202-203
Schedules, this report form .......................................................................... 2-4
Securities
exchange registration ........................................................................ 250-251
Statement of Cash Flows .......................................................................... 120-121
Statement of income for the year ................................................................. 114-117
Statement of retained earnings for the year ...................................................... 118-119
Steam-electric generating plant statistics ....................................................... 402-403
Substations .......................................................................................... 426
Supplies - materials and ............................................................................. 227
Index 4FERC FORM NO. 1 (ED. 12-90)
INDEX (continued)
Schedule Page No.
Taxes
accrued and prepaid ......................................................................... 262-263
charged during year ......................................................................... 262-263
on income, deferred and accumulated ............................................................. 234
272-277
reconciliation of net income with taxable income for ............................................ 261
Transformers, line - electric ....................................................................... 429
Transmission
lines added during year ..................................................................... 424-425
lines statistics ............................................................................ 422-423
of electricity for others ................................................................... 328-330
of electricity by others ........................................................................ 332
Unamortized
debt discount ............................................................................... 256-257
debt expense ................................................................................ 256-257
premium on debt ............................................................................. 256-257
Unrecovered Plant and Regulatory Study Costs ........................................................ 230
Index 5FERC FORM NO. 1 (ED. 12-90)