2013Annual Report FERC Form.pdf

BSIYE#*,
May 28,2014
ROCKY MOUNTAIN
VA OYERNIGHT DELIWRY
Idaho Public Utilities Commission
472West Washington
Boise,ID 83702-5983
Attention: Jean D. Jewell
Commission Secretary
RE: FERC Form I
REGE IVI S
201 South Main, Suite 2300
tfilt l{AY 28 Al'l l0: 33 salt Lake citv' Utah 84111
TDAHO Fi"lIL'l;
UT ILIT|ES COM}'1I$SICi']
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 31,2013.
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].
K. n*-/",
Vice President, Regulation & Government Affairs
Enclosure
THIS FILING IS
Item 1: An Initial (Original)
Submission
OR Resubmission No. ____X
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
OMB No.1902-0021
OMB No.1902-0029
OMB No.1902-0205
(Expires 12/31/2014)
(Expires 12/31/2014)
(Expires 05/31/2014)
Form 1 Approved
Form 1-F Approved
Form 3-Q Approved
FERC FORM No.1/3-Q (REV. 02-04)
Exact Legal Name of Respondent (Company) Year/Period of Report
End of 2013/Q4PacifiCorp
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
/ /
2013/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
/ /
2013/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
/ /
2013/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
/ /2013/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
2013/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
/ /2013/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 9.2% and Gregory E.
Abel owns 1.0% 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
/ /
2013/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
Mining 21.40 8 Trapper Mining Inc.
Non-profit foundation 9 PacifiCorp Foundation
10
11
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, an inactive wholly owned subsidiary
of PacifiCorp, were sold to TransAlta. In December 2013, Centralia Mining Company was
dissolved.
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
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.: 9 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
2013/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
/ /
2013/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, 2013: 1
Chairman of the Board of Directors 2
and Chief Executive Officer Gregory E. Abel 3
Senior Vice President and Chief Financial Officer 246,495Douglas K. Stuver 4
President and Chief Executive Officer, 5
Rocky Mountain Power 372,000A. Richard Walje 6
President and Chief Executive Officer, Pacific Power 310,000R. Patrick Reiten 7
President and Chief Executive Officer, PacifiCorp Energy 310,000Micheal 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, 2013, 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, 2013 (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
2013/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
/ /
2013/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, 2013: 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
1111 South 103rd Street, Omaha, Nebraska 68124Douglas 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
Schedule Page: 105 Line No.: 13 Column: a
Mark C. Moench retired as a director and employee of PacifiCorp effective February 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
2013/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
INFORMATION ON FORMULA RATES
PacifiCorp X
/ /2013/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. The settlement agreement includes modifications to the formula
used to determine transmission rates. The FERC approved interim rates for real power loss
factors and certain ancillary services to be effective March 1, 2013 and for a new
reactive power service rate to be effective May 1, 2013. In May 2013, the FERC approved
PacifiCorp's settlement agreement resolving all issues for the transmission rate case. 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
2013/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
/ /2013/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
04/01/201320130401-5001 ER13-1207 1
05/15/201320130515-5178 ER11-3643 2
12/31/201320131231-5176 ER14-918 3
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FERC FORM NO. 1 (NEW. 12-08) Page 106a
Schedule Page: 1061 Line No.: 1 Column: d
PacifiCorp submits tariff filing per 35.13(a)(2)(iii: OATT Revised Attachment H-1
(Depreciation Rates) to be effective 6/1/2013 under ER13-1207
Schedule Page: 1061 Line No.: 1 Column: e
PacifiCorp's Volume No. 11 Open Access Transmission Tariff
Schedule Page: 1061 Line No.: 2 Column: d
Transmission Formula Rate Annual Update Informational Filing of PacifiCorp under ER11-3643
Schedule Page: 1061 Line No.: 2 Column: e
PacifiCorp's Volume No. 11 Open Access Transmission Tariff
Schedule Page: 1061 Line No.: 3 Column: d
PacifiCorp submits tariff filing per 35.13(a)(2)(iii: OATT Revised Attachment H-1 (Revised
Depreciation Rates) to be effective 1/1/2014 under ER14-918
Schedule Page: 1061 Line No.: 3 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
2013/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
/ /2013/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 / /2013/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)
Iona 07/25/2013 07/25/2028 3.0%
Oregon (3)
Astoria 01/17/2013 01/17/2023 3.5%
Hermiston 02/21/2013 02/21/2043 $2,500 annual
Waterloo 04/03/2013 04/03/2033 7.0%
Jacksonville 04/23/2013 04/23/2033 6.0%
Coburg 07/26/2013 07/26/2023 7.5%
Klamath Falls 12/10/2013 12/10/2014 7.0%
Pilot Rock 12/19/2013 12/19/2033 8.0%
Utah (2)
Garland 01/09/2013 01/09/2023 4.0%
Joseph 01/09/2013 01/09/2038 -
Kane County 03/27/2013 03/27/2038 -
Sigurd 03/27/2013 03/27/2038 -
Elmo 04/05/2013 04/05/2038 6.0%
American Fork 04/24/2013 04/24/2023 6.0%
Syracuse 07/25/2013 07/25/2023 6.0%
Mapleton 08/12/2013 08/12/2023 6.0%
Annabella 08/14/2013 08/14/2038 -
Cedar City 08/19/2013 08/19/2023 6.0%
Lehi 08/28/2013 08/28/2018 6.0%
Provo 09/03/2013 09/03/2018 6.0%
Salina 11/15/2013 11/15/2038 -
Washington (2)
Pomeroy 07/11/2013 07/11/2033 6.0%
Garfield County 12/12/2013 12/12/2038 -
Selah 12/24/2013 12/24/2038 6.0%
Wyoming (4)
Sublette County 07/09/2013 07/09/2038 -
Cokeville 10/22/2013 10/22/2033 1.0%
Rawlins 11/01/2013 11/01/2038 5.0%
Manderson 12/20/2013 12/20/2038 2.0%
(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. The 3.5% franchise agreement fee does not apply to Hermiston and is not embedded in rates.
This $2,500 annual fee is an expense to PacifiCorp.
(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
2013/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.1
ITEM 2.
None.
ITEM 3.
In March 2013, the Federal Energy Regulatory Commission ("FERC") in Docket No. AC-13-18-000 approved the journal entries
required by the Uniform System of Accounts ("USofA") for the acquisition from Brigham City Corporation of certain electric
transmission facilities as approved in Docket No. EC12-136-000. Accordingly, PacifiCorp cleared account 102, Electric plant
purchased or sold, and recorded the purchase to the appropriate accounts. For further discussion, refer to Important Changes During
the Quarter/Year, Item 3, in PacifiCorp’s Form No. 1 for the year ended December 31, 2012.
In September 2013, PacifiCorp sold the St. Anthony hydroelectric generating facility to St. Anthony Hydro LLC and recorded the sale
in account 102, Electric plant purchased or sold. The sale was approved by the FERC in Docket No. P-2381-063, the Idaho Public
Utilities Commission ("IPUC") in Case No. PAC-E-13-06 and Order No. 32864 and the Wyoming Public Service Commission
("WPSC") in Docket No. 20000-433-EA-13. In October and November 2013, PacifiCorp filed for approval with the FERC the
journal entries required by the USofA. In December 2013, the FERC in Docket No. AC14-1-000 approved the journal entries for the
sale. Accordingly, PacifiCorp cleared account 102, Electric plant purchased or sold, and recorded the sale to the appropriate accounts.
PacifiCorp also received approval from the IPUC in Case No. PAC-E-13-07 and Order No. 32865 and from the WPSC in Docket No.
20000-434-EK-13 to enter into a power purchase agreement with St. Anthony Hydro LLC for all of the net output of the St. Anthony
hydroelectric generating facility, which became effective after the closing of the sale. For further discussion, refer to Important
Changes During the Quarter/Year, Item 3, in PacifiCorp’s Form No. 1 for the year ended December 31, 2012.
In December 2013, PacifiCorp entered into an agreement for the sale of certain facilities to the Navajo Tribal Utility Authority
("NTUA"). These facilities, substantially consisting of distribution facilities, provide service to approximately 1,500 customers on the
Navajo Nation Reservation. The sale is subject to approval by the Public Service Commission of Utah, the WPSC, the Oregon Public
Utility Commission ("OPUC"), the California Public Utilities Commission and the Navajo Nation Council and President of the
Navajo Nation. Incorporated as part of the agreement for the sale of facilities is a power supply agreement with the NTUA for
PacifiCorp to sell power to the NTUA, which is to become effective after the closing of the sale of the facilities.
ITEM 4.
None.
ITEM 5.
In May 2013, PacifiCorp placed into service the 100-mile high-voltage Mona-Oquirrh transmission line. Refer to pages 424-425 in
this Form No. 1 for additional information regarding transmission lines added or removed during the year ended December 31, 2013.
For the year ended December 31, 2013, PacifiCorp did not significantly increase or decrease its distribution territory.
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, 2013. 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
2013/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.2
Long-term Debt
In March 2014, PacifiCorp issued $425 million of 3.60% First Mortgage Bonds due April 2024. The net proceeds are being used to
fund capital expenditures and for general corporate purposes, including retirement of short-term debt that was partially incurred to pay
a $500 million common stock dividend to PPW Holdings LLC, a wholly owned subsidiary of MidAmerican Energy Holdings
Company and PacifiCorp’s direct parent company ("PPW Holdings"), in March 2014.
In June 2013, PacifiCorp issued $300 million of 2.95% First Mortgage Bonds due June 2023. The net proceeds were used to fund
capital expenditures and for general corporate purposes, including a portion of the common stock dividend paid to PPW Holdings in
June 2013.
After the March 2014 issuance, PacifiCorp has regulatory authority from the OPUC and the IPUC to issue an additional $125 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.
As of December 31, 2013, PacifiCorp had $559 million of letters of credit providing credit enhancement and liquidity support for
variable-rate tax-exempt bond obligations totaling $546 million plus interest. These letters of credit were fully available as of
December 31, 2013 and expire periodically through March 2015. 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,
2013, PacifiCorp estimated it would be able to issue up to $8.8 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.
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
2013/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.3
ITEM 8.
For the year ended December 31, 2013, PacifiCorp’s bargaining unit wage scale changes were as follows:
Estimated Annual
Unions Represented % Increase (1)Effective Date(s)Financial Impact (2)
IBEW 125 (OR, WA) 1.86% 1/26/2013 $ 479,528
IBEW 57 Combustion Turbine (UT) 1.18% 1/26/2013 29,427
IBEW 659 (OR, CA) 1.29% 4/26/2013 419,724
UWUA 197 (OR) 1.20% 5/26/2013 18,146
IBEW 57 Laramie (WY) 1.03% 6/26/2013 4,803
IBEW 57 Power Delivery (UT, ID & WY) 0.83% 6/26/2013 691,751
IBEW 57 Power Supply (UT, ID & WY) 0.85%6/26/2013 335,000
UWUA 127 (WY) 0.53% 9/26/2013 233,143
Total $ 2,211,522
(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.
Refer to Note 13 of Notes to Financial Statements in this Form No. 1 for information regarding certain legal proceedings affecting
PacifiCorp.
ITEM 10.
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, 2013 other than the
redemption of preferred stock shares as discussed in Note 14 of Notes to Financial Statements in this Form No. 1 and common and
preferred stock dividends declared and paid.
ITEM 11.
(Reserved)
ITEM 12.
None.
ITEM 13.
Mark C. Moench retired as a director and employee of PacifiCorp effective February 2014.
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
2013/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.4
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 / /2013/Q4
UTILITY PLANT 1
24,810,145,362 23,971,186,312200-201Utility Plant (101-106, 114) 2
1,321,622,138 1,250,513,185200-201Construction Work in Progress (107) 3
26,131,767,500 25,221,699,497TOTAL Utility Plant (Enter Total of lines 2 and 3) 4
8,511,018,083 8,018,360,420200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5
17,620,749,417 17,203,339,077Net 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
17,620,749,417 17,203,339,077Net 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
14,388,489 16,067,385Nonutility Property (121) 18
2,937,770 3,461,732(Less) Accum. Prov. for Depr. and Amort. (122) 19
69,928 69,928Investments in Associated Companies (123) 20
210,924,059 239,062,484224-225Investment 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
82,248,215 84,847,739Other Investments (124) 24
0 0Sinking Funds (125) 25
0 0Depreciation Fund (126) 26
0 0Amortization Fund - Federal (127) 27
19,849,214 19,796,604Other Special Funds (128) 28
0 0Special Funds (Non Major Only) (129) 29
154,542 1,367,457Long-Term Portion of Derivative Assets (175) 30
0 0Long-Term Portion of Derivative Assets – Hedges (176) 31
324,696,677 357,749,865TOTAL 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
6,739,098 23,522,354Cash (131) 35
172,901 139,866Special Deposits (132-134) 36
0 0Working Fund (135) 37
44,824,535 55,313,879Temporary Cash Investments (136) 38
72,137 102,892Notes Receivable (141) 39
420,371,007 388,339,929Customer Accounts Receivable (142) 40
34,941,278 49,311,318Other Accounts Receivable (143) 41
8,008,893 8,884,148(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42
0 0Notes Receivable from Associated Companies (145) 43
6,608,556 4,537,480Accounts Receivable from Assoc. Companies (146) 44
240,980,677 265,591,187227Fuel Stock (151) 45
0 0227Fuel Stock Expenses Undistributed (152) 46
0 0227Residuals (Elec) and Extracted Products (153) 47
212,544,115 202,524,644227Plant 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 / /2013/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
48,954,180 45,371,059Prepayments (165) 57
0 0Advances for Gas (166-167) 58
14,382 16,988Interest and Dividends Receivable (171) 59
2,320,602 1,773,869Rents Receivable (172) 60
258,009,000 250,650,000Accrued Utility Revenues (173) 61
109,302 481,065Miscellaneous Current and Accrued Assets (174) 62
10,279,567 9,253,434Derivative Instrument Assets (175) 63
154,542 1,367,457(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
1,278,777,902 1,286,678,359Total Current and Accrued Assets (Lines 34 through 66) 67
DEFERRED DEBITS 68
33,721,944 34,752,802Unamortized Debt Expenses (181) 69
0 0230aExtraordinary Property Losses (182.1) 70
1,760,602 4,126,549230bUnrecovered Plant and Regulatory Study Costs (182.2) 71
1,373,975,244 1,821,244,610232Other Regulatory Assets (182.3) 72
3,615,224 4,377,278Prelim. 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
113,051 46,898Temporary Facilities (185) 77
90,972,267 86,782,863233Miscellaneous Deferred Debits (186) 78
0 0Def. Losses from Disposition of Utility Plt. (187) 79
0 0352-353Research, Devel. and Demonstration Expend. (188) 80
8,089,941 9,502,793Unamortized Loss on Reaquired Debt (189) 81
482,567,288 648,219,005234Accumulated Deferred Income Taxes (190) 82
0 0Unrecovered Purchased Gas Costs (191) 83
1,994,815,561 2,609,052,798Total Deferred Debits (lines 69 through 83) 84
21,219,039,557 21,456,820,099TOTAL ASSETS (lines 14-16, 32, 67, and 84) 85
FERC FORM NO. 1 (REV. 12-03) Page 111
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 / /2013/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
PROPRIETARY CAPITAL 1
3,417,945,8963,417,945,896Common Stock Issued (201) 2 250-251
40,733,1002,397,600Preferred 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
1,102,229,9811,102,063,956Other Paid-In Capital (208-211) 7 253
00Installments Received on Capital Stock (212) 8 252
00(Less) Discount on Capital Stock (213) 9 254
41,284,56041,101,061(Less) Capital Stock Expense (214) 10 254b
2,979,135,2933,187,664,983Retained Earnings (215, 215.1, 216) 11 118-119
157,299,053127,661,628Unappropriated 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
-12,003,821-9,091,505Accumulated Other Comprehensive Income (219) 15 122(a)(b)
7,644,054,9427,787,541,497Total Proprietary Capital (lines 2 through 15) 16
LONG-TERM DEBT 17
6,820,029,0006,842,300,000Bonds (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
102,17991,152Unamortized Premium on Long-Term Debt (225) 22
14,074,07613,958,237(Less) Unamortized Discount on Long-Term Debt-Debit (226) 23
6,806,057,1036,828,432,915Total Long-Term Debt (lines 18 through 23) 24
OTHER NONCURRENT LIABILITIES 25
48,633,50245,935,961Obligations Under Capital Leases - Noncurrent (227) 26
00Accumulated Provision for Property Insurance (228.1) 27
41,118,85059,307,721Accumulated Provision for Injuries and Damages (228.2) 28
621,638,182205,063,178Accumulated Provision for Pensions and Benefits (228.3) 29
38,367,73038,745,810Accumulated Miscellaneous Operating Provisions (228.4) 30
6,578,7970Accumulated Provision for Rate Refunds (229) 31
26,416,84126,001,569Long-Term Portion of Derivative Instrument Liabilities 32
00Long-Term Portion of Derivative Instrument Liabilities - Hedges 33
127,418,688137,818,818Asset Retirement Obligations (230) 34
910,172,590512,873,057Total Other Noncurrent Liabilities (lines 26 through 34) 35
CURRENT AND ACCRUED LIABILITIES 36
00Notes Payable (231) 37
440,465,394472,746,697Accounts Payable (232) 38
11,109,9788,616,719Notes Payable to Associated Companies (233) 39
37,303,25542,517,163Accounts Payable to Associated Companies (234) 40
34,640,41036,794,115Customer Deposits (235) 41
87,443,80853,535,702Taxes Accrued (236) 42 262-263
114,528,244113,038,154Interest Accrued (237) 43
512,46240,476Dividends 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 / /2013/Q4
(continued)COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
00Matured Interest (240) 46
17,617,88219,668,643Tax Collections Payable (241) 47
74,650,81081,535,728Miscellaneous Current and Accrued Liabilities (242) 48
6,482,6262,772,497Obligations Under Capital Leases-Current (243) 49
74,922,88452,849,128Derivative Instrument Liabilities (244) 50
26,416,84126,001,569(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
873,260,912858,113,453Total Current and Accrued Liabilities (lines 37 through 53) 54
DEFERRED CREDITS 55
19,569,96924,877,489Customer Advances for Construction (252) 56
34,331,01732,306,325Accumulated Deferred Investment Tax Credits (255) 57 266-267
00Deferred Gains from Disposition of Utility Plant (256) 58
333,027,535308,485,444Other Deferred Credits (253) 59 269
102,737,54291,533,914Other Regulatory Liabilities (254) 60 278
00Unamortized Gain on Reaquired Debt (257) 61
208,722,047226,880,978Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277
3,796,825,2803,991,613,412Accum. Deferred Income Taxes-Other Property (282) 63
728,061,162556,381,073Accum. Deferred Income Taxes-Other (283) 64
5,223,274,5525,232,078,635Total Deferred Credits (lines 56 through 64) 65
21,456,820,09921,219,039,557TOTAL 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.: 39 Column: c
Represents amounts due to Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp,
pursuant to an umbrella loan agreement for which interest is determined daily and is equal
to the lowest cost of borrowings PacifiCorp could otherwise incur externally. At December
31, 2013 and 2012, the interest rate on the outstanding borrowings was 0.25% and 0.35%,
respectively.
Schedule Page: 112 Line No.: 42 Column: c
As of December 31, 2013, Account 236, Taxes accrued, included $18,691,010 of income taxes
payable to MidAmerican Energy Holdings Company, PacifiCorp's indirect parent company.
Schedule Page: 112 Line No.: 42 Column: d
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
2013/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
/ /2013/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
5,153,186,543 4,849,485,873300-301Operating Revenues (400) 2
Operating Expenses 3
2,660,714,690 2,512,486,745320-323Operation Expenses (401) 4
423,183,559 427,348,788320-323Maintenance Expenses (402) 5
600,829,680 571,953,425336-337Depreciation Expense (403) 6
336-337Depreciation Expense for Asset Retirement Costs (403.1) 7
45,434,666 44,350,044336-337Amort. & Depl. of Utility Plant (404-405) 8
5,211,112 5,523,970336-337Amort. of Utility Plant Acq. Adj. (406) 9
2,365,947 507,060Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10
Amort. of Conversion Expenses (407) 11
294,983 337,452Regulatory Debits (407.3) 12
(Less) Regulatory Credits (407.4) 13
169,647,183 160,882,952262-263Taxes Other Than Income Taxes (408.1) 14
74,343,217 -106,857,967262-263Income Taxes - Federal (409.1) 15
15,767,344 -785,331262-263 - Other (409.1) 16
826,690,640 770,193,169234, 272-277Provision for Deferred Income Taxes (410.1) 17
625,812,453 419,882,524234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.1) 18
-1,812,064 -1,851,300266Investment Tax Credit Adj. - Net (411.4) 19
(Less) Gains from Disp. of Utility Plant (411.6) 20
63,381Losses from Disp. of Utility Plant (411.7) 21
26,460 49,887(Less) Gains from Disposition of Allowances (411.8) 22
Losses from Disposition of Allowances (411.9) 23
7,758Accretion Expense (411.10) 24
4,196,895,425 3,964,164,354TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25
956,291,118 885,321,519Net 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
/ /2013/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
5,153,186,543 4,849,485,873 2
3
2,660,714,690 2,512,486,745 4
423,183,559 427,348,788 5
600,829,680 571,953,425 6
7
45,434,666 44,350,044 8
5,211,112 5,523,970 9
2,365,947 507,060 10
11
294,983 337,452 12
13
169,647,183 160,882,952 14
74,343,217 -106,857,967 15
15,767,344 -785,331 16
826,690,640 770,193,169 17
625,812,453 419,882,524 18
-1,812,064 -1,851,300 19
20
63,381 21
26,460 49,887 22
23
7,758 24
4,196,895,425 3,964,164,354 25
956,291,118 885,321,519 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
/ /2013/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)
956,291,118 885,321,519Net Utility Operating Income (Carried forward from page 114) 27
Other Income and Deductions 28
Other Income 29
Nonutilty Operating Income 30
1,154,351 3,143,641Revenues From Merchandising, Jobbing and Contract Work (415) 31
1,395,781 3,064,403(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32
389,833 651,778Revenues From Nonutility Operations (417) 33
127,665 130,325(Less) Expenses of Nonutility Operations (417.1) 34
122,658 -9,703Nonoperating Rental Income (418) 35
13,397,403 11,211,230119Equity in Earnings of Subsidiary Companies (418.1) 36
5,541,076 6,422,547Interest and Dividend Income (419) 37
57,244,026 58,494,261Allowance for Other Funds Used During Construction (419.1) 38
1,000,254 602,865Miscellaneous Nonoperating Income (421) 39
306,494 896,553Gain on Disposition of Property (421.1) 40
77,632,649 78,218,444TOTAL Other Income (Enter Total of lines 31 thru 40) 41
Other Income Deductions 42
342,145 71,235Loss on Disposition of Property (421.2) 43
1,298,969 1,292,207Miscellaneous Amortization (425) 44
2,516,950 2,491,665 Donations (426.1) 45
-4,817,326 -5,124,160 Life Insurance (426.2) 46
2,337,066 719,036 Penalties (426.3) 47
1,763,417 1,497,850 Exp. for Certain Civic, Political & Related Activities (426.4) 48
3,789,575 129,377,724 Other Deductions (426.5) 49
7,230,796 130,325,557TOTAL Other Income Deductions (Total of lines 43 thru 49) 50
Taxes Applic. to Other Income and Deductions 51
345,622 315,476262-263Taxes Other Than Income Taxes (408.2) 52
-2,396,204 -1,654,653262-263Income Taxes-Federal (409.2) 53
-325,603 -224,840262-263Income Taxes-Other (409.2) 54
70,283,900 84,103,300234, 272-277Provision for Deferred Inc. Taxes (410.2) 55
67,854,963 129,629,658234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.2) 56
Investment Tax Credit Adj.-Net (411.5) 57
928,426 1,827,951(Less) Investment Tax Credits (420) 58
-875,674 -48,918,326TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59
71,277,527 -3,188,787Net Other Income and Deductions (Total of lines 41, 50, 59) 60
Interest Charges 61
355,945,454 355,713,688Interest on Long-Term Debt (427) 62
3,888,848 3,835,726Amort. of Debt Disc. and Expense (428) 63
1,421,460 1,797,595Amortization of Loss on Reaquired Debt (428.1) 64
11,027 8,949(Less) Amort. of Premium on Debt-Credit (429) 65
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 66
24,397 -12,665Interest on Debt to Assoc. Companies (430) 67
13,394,876 12,226,166Other Interest Expense (431) 68
29,258,693 28,756,114(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69
345,405,315 344,795,447Net Interest Charges (Total of lines 62 thru 69) 70
682,163,330 537,337,285Income 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
682,163,330 537,337,285Net 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, 2013 and 2012, depreciation expense associated with transportation
equipment was $15,921,062 and $15,898,715, 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, 2013 and 2012, payroll taxes were
$39,811,382 and $40,291,150, respectively.
Schedule Page: 114 Line No.: 24 Column: d
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
2013/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
/ /
2013/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)
2,645,655,455 2,974,333,637 1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4
5
166,025211 6 Write-off of 2010 gain on repurchase of preferred stock
7
8
166,025 9 TOTAL Credits to Retained Earnings (Acct. 439)
10
-1,943,279 11 Call premiums and fees on preferred stock redemption
12
13
14
-1,943,279 15 TOTAL Debits to Retained Earnings (Acct. 439)
526,126,055 668,765,927 16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
( 1,225,845) -2,762,978215.1 18 Appropriation of excess earnings at certain hydroelectric generating facilities
19
20
21
( 1,225,845) -2,762,978 22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
( 2,049,846) -1,493,811238 24 Preferred Stock, various series and rates
25
26
27
28
( 2,049,846) -1,493,811 29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
( 200,000,000) -500,000,000238 31 Common Stock
32
33
34
35
( 200,000,000) -500,000,000 36 TOTAL Dividends Declared-Common Stock (Acct. 438)
5,827,818 43,034,828216.1 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
2,974,333,637 3,180,100,349 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
/ /
2013/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)
4,801,656 7,564,634 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
4,801,656 7,564,634 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
2,979,135,293 3,187,664,983 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
151,915,641 157,299,053 49 Balance-Beginning of Year (Debit or Credit)
11,211,230 13,397,403 50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
( 5,827,818) -43,034,828 52 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
157,299,053 127,661,628 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.: 11 Column: b
Account 131, Cash
Account 214, Capital stock expense
Account 930.2, Miscellaneous general expenses
Schedule Page: 118 Line No.: 24 Column: c
Outstanding shares of preferred stock as of December 31, 2013 and dividends on preferred
stock during the year ended December 31, 2013 were as follows:
Shares Dividend
4.52% Serial Preferred - $ 7,062
4.56% Serial Preferred - 280,575
4.72% Serial Preferred - 235,099
5.00% Serial Preferred - 62,862
5.40% Serial Preferred - 269,113
6.00% Serial Preferred 5,930 35,580
7.00% Serial Preferred 18,046 126,322
5% Preferred - 477,198
23,976 $ 1,493,811
Schedule Page: 118 Line No.: 24 Column: d
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% Preferred 126,243 631,215
407,331 $2,049,846
Schedule Page: 118 Line No.: 37 Column: c
In May 2013, Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp, declared and
paid a dividend of $43 million to PacifiCorp. Also, in September 2013, Trapper Mining
Inc., a subsidiary of PacifiCorp, paid a dividend of $34,828 to PacifiCorp.
Schedule Page: 118 Line No.: 37 Column: d
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.
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
The balance in Account 215.1, Appropriated retained earnings - Amortization reserve,
Federal, is due to requirements of certain hydroelectric relicensing projects.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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
/ /2013/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:
537,337,285 682,163,330 2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
589,168,608 623,158,412 4 Depreciation and Depletion
51,502,307 52,239,730 5 Amortization:
6
7
304,784,287 203,307,124 8 Deferred Income Taxes (Net)
-3,679,251 -2,740,490 9 Investment Tax Credit Adjustment (Net)
-14,624,273 -10,007,750 10 Net (Increase) Decrease in Receivables
-34,659,850 14,591,039 11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
57,856,504 30,795,829 13 Net Increase (Decrease) in Payables and Accrued Expenses
17,169,240 -23,882,915 14 Net (Increase) Decrease in Other Regulatory Assets
-15,997,931 -8,253,088 15 Net Increase (Decrease) in Other Regulatory Liabilities
58,494,261 57,244,026 16 (Less) Allowance for Other Funds Used During Construction
5,383,412 -29,637,425 17 (Less) Undistributed Earnings from Subsidiary Companies
110,233,418 -33,476,313 18 Amounts Due To/From Affiliates (Net)
68,250,000 42,900,000 19 Derivative Collateral (Net)
25,993,723 21,056,199 20 Other Operating Activities:
21
1,629,456,394 1,564,244,506 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):
-1,398,801,462 -1,119,674,872 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
-58,494,261 -57,244,026 30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33
-1,340,307,201 -1,062,430,846 34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
739,512 277,539 37 Proceeds from Disposal of Noncurrent Assets (d)
38
-1,499,000 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
/ /2013/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
-13,553,729 6,064,789 53 Other Investing Activities:
54
55
56 Net Cash Provided by (Used in) Investing Activities
-1,331,952,019 -1,057,587,518 57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
748,786,000 299,100,000 61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
66 Net Increase in Short-Term Debt (c)
11,107,806 67 Other (provide details in footnote):
68
69
759,893,806 299,100,000 70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
-101,026,000 -277,729,000 73 Long-term Debt (b)
-40,095,281 74 Preferred Stock
75 Common Stock
-7,826,267 -6,831,840 76 Other (provide details in footnote):
-1,316,468 -6,407,670 77 Repayment of Capital Lease Obligations
-688,436,607 78 Net Decrease in Short-Term Debt (c)
79
-2,049,846 -1,965,797 80 Dividends on Preferred Stock
-200,000,000 -500,000,000 81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
-240,761,382 -533,929,588 83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
56,742,993 -27,272,600 86 (Total of lines 22,57 and 83)
87
22,093,240 78,836,233 88 Cash and Cash Equivalents at Beginning of Period
89
78,836,233 51,563,633 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 $22,328,732 and $17,215,183 during the years ended December 31, 2013 and 2012,
respectively.
Schedule Page: 120 Line No.: 5 Column: a
Years Ended December 31,
2013 2012
Amortization of software development & other intangibles $ 46,733,635 $ 45,642,251
Amortization of electric plant acquisition adjustments 5,211,112 5,523,970
Amortization of regulatory assets 294,983 336,086
$ 52,239,730 $ 51,502,307
Schedule Page: 120 Line No.: 20 Column: a
Years Ended December 31,
2013 2012
Depreciation and depletion included in cost of fuel $12,456,145 $12,461,354
Net (gain)/loss on sale of property 22,871 (1,063,591)
Write-off of assets under construction 10,483,484 10,606,163
Change in corporate owned life insurance cash surrender
value (4,880,695) -
Amortization of debt issuance expenses and bond
discount/premium 3,877,821 3,826,777
Other (903,427) 163,020
$21,056,199 $25,993,723
Schedule Page: 120 Line No.: 37 Column: b
Represents proceeds from the disposal of fixed assets.
Schedule Page: 120 Line No.: 37 Column: c
Represents proceeds from the disposal of fixed assets.
Schedule Page: 120 Line No.: 53 Column: a
Years Ended December 31,
2013 2012
Other investments/special funds $ 5,949,345 $ (369,775)
Temporary facilities (66,153) 20,007
Restricted cash 181,597 (13,203,961)
$ 6,064,789 $(13,553,729)
Schedule Page: 120 Line No.: 67 Column: c
Affiliate borrowing from subsidiary company, Pacific Minerals, Inc.
Schedule Page: 120 Line No.: 76 Column: a
Years Ended December 31,
2013 2012
Net repayments of affiliate borrowing from subsidiary
company, Pacific Minerals, Inc. $ (2,492,611) $ -
Long-term debt issuance and other deferred financing costs (4,339,229) (7,826,267)
$ (6,831,840) $(7,826,267)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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 / /2013/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 utility 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 other utilities, energy
marketing companies, financial institutions and other market participants. 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." For GAAP, unrecognized tax
benefits associated with temporary differences are reflected as other liabilities while for FERC the income tax impact of
uncertain tax positions associated with temporary differences are reflected in 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
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.1
Interest and penalties on income taxes for GAAP are classified as income tax expense. All such amounts are classified as
interest income, interest expense and penalties under the FERC accounting and reporting standards.
Reclassifications
Certain other reclassifications of balance sheet, income statement and cash flow amounts have been made in order to
conform to the FERC basis of presentation. These reclassifications had no effect on net income.
Use 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 will be 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 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
2013/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):
2013 2012
Cash (131)$7 $24
Working funds (135)——
Temporary cash investments (136)45 55
Total cash and cash equivalents $52 $79
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, 2013 and 2012,
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):

2013 2012
Beginning balance $9 $9
Charged to operating costs and expenses, net 13 14
Write-offs, net (14)(14)
Ending balance $8 $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
2013/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.
Debt and equity AFUDC, which represents the estimated costs of debt and equity funds necessary to finance the construction of utility
plant, 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 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, 2013 and 2012, unbilled revenue was $258 million and $251 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
2013/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 include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses,
economic impacts and composition of sales among 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
and expense for certain property-related basis differences and other various differences that PacifiCorp is required to pass on to its
customers are charged or credited directly to a regulatory asset or liability. These amounts were recognized as regulatory assets of
$461 million and $456 million as of December 31, 2013 and 2012, respectively, and regulatory liabilities of $21 million as of
December 31, 2013 and 2012, 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 or a regulatory asset or liability in
the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that
is more likely than not to be realized.
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 income 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 on examination by the taxing authorities, based on the technical
merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest
benefit that 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 impact on PacifiCorp's financial results.
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
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.5
New Accounting Pronouncements
In February 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2013-04,
which amends FASB Accounting Standards Codification ("ASC") Topic 405, "Liabilities." The amendments in this guidance require
an entity to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is
fixed at the reporting date as the amount the reporting entity agreed to pay plus any additional amounts the reporting entity expects to
pay on behalf of its co-obligor. Additionally, the guidance requires the entity to disclose the nature and amount of the obligation, as
well as other information about those obligations. This guidance is effective for interim and annual reporting periods beginning after
December 15, 2013. PacifiCorp adopted this guidance on January 1, 2014. The adoption of this guidance did not have a material
impact on PacifiCorp's disclosures included within Notes to Financial Statements.
In December 2011, the FASB issued ASU No. 2011-11, which amends FASB 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. 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. PacifiCorp adopted the guidance on January 1, 2013.
The adoption of the 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, 2013 and 2012.
In January 2013, PacifiCorp filed applications for depreciation rate changes with the Utah Public Service Commission ("UPSC"), the
Oregon Public Utility Commission ("OPUC"), the Wyoming Public Service Commission ("WPSC"), the Washington Utilities and
Transportation Commission ("WUTC") and the Idaho Public Utilities Commission ("IPUC") based on PacifiCorp's most recent
depreciation study. PacifiCorp received approval from the state commissions to change the depreciation rates effective January 1,
2014. The approved depreciation rates will result in an estimated annual increase in depreciation expense of $40 million on a total
company basis based on the depreciable plant balances as of December 31, 2013 included in the study.
(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
2013/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, 2013
(dollars in millions):
Facility Accumulated Construction
PacifiCorp in Depreciation and Work-in-
Share Service Amortization Progress
Jim Bridger Nos. 1 - 4 67%$1,121 $523 $19
Hunter No. 1 94 394 152 54
Hunter No. 2 60 293 85 —
Wyodak 80 450 163 1
Colstrip Nos. 3 and 4 10 227 126 4
Hermiston 50 173 62 1
Craig Nos. 1 and 2(1)19 323 197 2
Hayden No. 1 25 55 26 6
Hayden No. 2 13 32 17 2
Foote Creek 79 37 21 —
Transmission and distribution facilities Various 341 75 3
Total $3,446 $1,447 $92
(1) Includes unallocated acquisition adjustments of $141 million related to Facility in Service and $102 million related to Accumulated Depreciation and
Amortization.
(5) Regulatory Matters
PacifiCorp had regulatory assets not earning a return on investment of $1.244 billion and $1.618 billion as of December 31, 2013 and
2012, 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):
2013:
Revolving credit facilities $1,200
Less:
Short-term debt —
Letters of credit and tax-exempt bond support (321)
Net revolving credit facilities $879
2012:
Revolving credit facilities $1,230
Less:
Short-term debt —
Letters of credit (602)
Net revolving credit facilities $628
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.7
In March 2013, PacifiCorp replaced its $630 million unsecured revolving credit facility, which had been set to expire in July 2013,
with a $600 million unsecured revolving credit facility expiring in March 2018. Additionally, PacifiCorp has a $600 million
unsecured revolving credit facility expiring in June 2017. These credit facilities, which support PacifiCorp's commercial paper
program, certain series of its tax-exempt bond obligations and provide for the issuance of letters of credit, 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. These 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. As of December 31,
2013, PacifiCorp was in compliance with the covenants of its credit facilities.
As of December 31, 2013 and 2012, PacifiCorp had $559 million and $602 million, respectively, of fully available letters of credit
issued under committed arrangements, of which $270 million and $602 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 expire through March 2015.
As of December 31, 2013, PacifiCorp had approximately $16 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, 2013
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 generally includes provisions that allow PacifiCorp to redeem the first mortgage bonds 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 March 2014, PacifiCorp issued $425 million of 3.60% First Mortgage Bonds due April 2024. The net proceeds are being used to
fund capital expenditures and for general corporate purposes, including retirement of short-term debt that was partially incurred to pay
a $500 million common stock dividend to PPW Holdings LLC, a wholly owned subsidiary of MEHC and PacifiCorp’s direct parent
company ("PPW Holdings"), in March 2014.
In June 2013, PacifiCorp issued $300 million of 2.95% First Mortgage Bonds due June 2023. The net proceeds were used to fund
capital expenditures and for general corporate purposes, including a portion of the common stock dividend paid to PPW Holdings in
June 2013.
After the March 2014 issuance, PacifiCorp has regulatory authority from the OPUC and the IPUC to issue an additional $125 million
of long-term debt. PacifiCorp must make a notice filing with the WUTC 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 October 2016.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's
mortgage. Approximately $24 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage
as of December 31, 2013.
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 $49 million and $55 million as of December 31, 2013 and 2012, 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
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.8
As of December 31, 2013, the annual maturities of long-term debt and capital lease obligations, excluding unamortized discounts and
including interest on capital lease obligations, for 2014 and thereafter are as follows (in millions):
Long-term Capital Lease
Debt Obligations Total
2014 $236 $8 $244
2015 122 7 129
2016 57 7 64
2017 52 11 63
2018 586 7 593
Thereafter 5,789 61 5,850
Total 6,842 101 6,943
Unamortized discount (14)— (14)
Amounts representing interest — (52)(52)
Total $6,828 $49 $6,877
(8) Income Taxes
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2013 2012
Current:
Federal $72 $(108)
State 16 (1)
Total 88 (109)
Deferred:
Federal 177 273
State 26 32
Total 203 305
Investment tax credits (3)(4)
Total income tax expense $288 $192
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.9
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:
2013 2012
Federal statutory income tax rate 35 % 35 %
State income taxes, net of federal income tax benefit 3 3
Federal income tax credits(1)(7)(9)
Other (1)(3)
Effective income tax rate 30 %26 %
(1) Primarily attributable to the impact of federal renewable electricity production tax credits for qualifying wind-powered generating facilities that extend 10 years
from the date the facilities were placed in service.
The net deferred income tax liability consists of the following as of December 31 (in millions):
2013 2012
Deferred income tax assets:
Employee benefits $99 $217
Derivative contracts and unamortized contract values 76 109
State carryforwards 68 69
Loss contingencies 67 61
Asset retirement obligations 48 46
Regulatory liabilities 36 40
Other 89 106
483 648
Deferred income tax liabilities:
Property, plant and equipment (4,219)(4,005)
Regulatory assets (526)(696)
Other (30)(32)
(4,775)(4,733)
Net deferred income tax liability $(4,292)$(4,085)
The following table provides PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31,
2013 (in millions):
State
Net operating loss carryforwards $1,451
Deferred income taxes on net operating loss carryforwards $52
Expiration dates 2014 - 2032
Tax credit carryforwards $16
Expiration dates 2014 - indefinite
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.10
The United States Internal Revenue Service has effectively settled its examination of PacifiCorp's income tax returns through
December 31, 2009. State agencies have closed their examinations of PacifiCorp's income tax returns through March 31, 2003, except
for the 1995 and 1997 tax years in Utah.
(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
continue to 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.
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
2013 2012 2013 2012
Service cost
$6 $7 $9 $7
Interest cost 54 61 25 28
Expected return on plan assets (74)(74)(30)(30)
Net amortization 48 34 8 4
Net periodic benefit cost $34 $28 $12 $9
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.11
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
2013 2012 2013 2012
Plan assets at fair value, beginning of year $1,012 $931 $424 $384
Employer contributions 63 49 8 9
Participant contributions — — 7 7
Actual return on plan assets 213 120 86 52
Benefits paid (117)(88)(39)(28)
Plan assets at fair value, end of year $1,171 $1,012 $486 $424
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
Pension Other Postretirement
2013 2012 2013 2012
Benefit obligation, beginning of year $1,391 $1,291 $632 $575
Service cost 6 7 9 7
Interest cost 54 61 25 28
Participant contributions — — 7 7
Actuarial (gain) loss (104)120 (36)43
Benefits paid (117)(88)(39)(28)
Benefit obligation, end of year $1,230 $1,391 $598 $632
Accumulated benefit obligation, end of year $1,229 $1,390
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
2013 2012 2013 2012
Plan assets at fair value, end of year $1,171 $1,012 $486 $424
Less - Benefit obligation, end of year 1,230 1,391 598 632
Funded status $(59)$(379)$(112)$(208)
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
$48 million and $44 million as of December 31, 2013 and 2012, 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.12
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
2013 2012 2013 2012
Net loss $361 $660 $108 $214
Prior service credit (29)(37)(33)(40)
Regulatory deferrals (4)(5)2 3
Total $328 $618 $77 $177
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2013
and 2012 is as follows (in millions):
Accumulated
Other
Regulatory Comprehensive
Asset Loss Total
Pension
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
Net gain arising during the year (239)(3)(242)
Net amortization (47)(1)(48)
Total (286)(4)(290)
Balance, December 31, 2013 $313 $15 $328
Regulatory
Asset
Other Postretirement
Balance, December 31, 2011 $163
Net loss arising during the year 18
Net amortization (4)
Total 14
Balance, December 31, 2012 177
Net gain arising during the year (92)
Net amortization (8)
Total (100)
Balance, December 31, 2013 $77
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.13
The net loss, prior service credit and regulatory deferrals that will be amortized in 2014 into net periodic benefit cost are estimated to
be as follows (in millions):

Net Prior Service Regulatory
Loss Credit Deferrals Total
Pension $38 $(8)$(1)$29
Other postretirement 9 (7)— 2
Total $47 $(15)$(1)$31
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
Pension Other Postretirement
2013 2012 2013 2012
Benefit obligations as of December 31:
Discount rate 4.80 % 4.05 % 4.90% 4.10 %
Rate of compensation increase 3.00 3.00 N/A N/A
Net periodic benefit cost for the years ended December 31:
Discount rate 4.05 % 4.90 % 4.10% 4.95 %
Expected return on plan assets 7.50 7.50 7.50 7.50
Rate of compensation increase 3.00 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 forward-looking views of the financial markets and historical performance.
2013 2012
Assumed healthcare cost trend rates as of December 31:
Healthcare cost trend rate assumed for next year 8.00%8.00%
Rate that the cost trend rate gradually declines to 5.00%5.00%
Year that the rate reaches the rate it is assumed to remain at 2019 2018
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 $4 $(3)
Other postretirement benefit obligation 41 (33)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.14
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $10 million and $4 million,
respectively, during 2014. 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
generally contribute an amount equal to the net periodic benefit cost.
The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2014 through 2018
and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Other Postretirement
Pension Gross Medicare Subsidy
2014 $102 $38 $—
2015 108 39 —
2016 109 39 —
2017 104 40 —
2018 104 42 —
2019 - 2023 470 210 (3)
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 target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows
as of December 31, 2013:

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 are 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
2013/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, 2013
Cash equivalents $—$18 $—$18
Debt securities:
United States government obligations 13 — — 13
International government obligations — 1 — 1
Corporate obligations — 48 — 48
Municipal obligations — 8 — 8
Agency, asset and mortgage-backed obligations — 50 — 50
Equity securities:
United States companies 489 — — 489
International companies 16 — — 16
Investment funds(2)215 227 —442
Limited partnership interests(3)— — 86 86
Total $733 $352 $86 $1,171
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
(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
50% and 50%, respectively, for 2013 and 60% and 40%, respectively, for 2012, and are invested in United States and international securities of
approximately 42% and 58%, respectively, for 2013 and 2012.
(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
2013/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, 2013
Cash and cash equivalents $3 $1 $—$4
Debt securities:
United States government obligations 1 — — 1
Corporate obligations — 4 — 4
Municipal obligations — 1 — 1
Agency, asset and mortgage-backed obligations — 4 — 4
Equity securities:
United States companies 167 — — 167
International companies 6 — — 6
Investment funds(2)173 120 —293
Limited partnership interests(3)— — 6 6
Total $350 $130 $6 $486
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
(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
49% and 51%, respectively, for 2013 and 48% and 52%, respectively, for 2012, and are invested in United States and international securities of
approximately 70% and 30%, respectively, for 2013 and 66% and 34%, respectively, for 2012.
(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
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.17
For level 1 investments, 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. For level 2 investments, the fair value is determined using pricing models or unquoted net asset values based
on observable market inputs. For level 3 investments, 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 pension and other postretirement benefit plans' proportionate
shares 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, 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
Actual return on plan assets still held at December 31, 2013 16 1
Purchases, sales, distributions and settlements (26)(2)
Balance, December 31, 2013 $86 $6
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 although
formed with the ability for other employers to participate in the plan, there are no other employers that participate in this 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
2013/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 plan funded
status percentage for plan years
beginning July 1,(1)Contributions(2)
Plan name
Employer
Identification
Number 2013 2012
Funding
improvement
plan
Surcharge
imposed
under PPA 2013 2012
Year contributions to plan
exceeded more than 5% of
total contributions(3)
UMWA
Pension Plan
52-1050282 Seriously
Endangered(4)
Seriously
Endangered
Implemented None $3 $3 None
Local 57
Trust Fund 87-0640888 At least 80% At least 80% None None $ 9 $ 12 2012, 2011
(1) Among other factors, multiemployer plans in seriously endangered status are at least 65% but less than 80% funded and 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.
(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 agreements 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, 2011. Information for the plan years beginning July 1, 2013 and 2012 is not available. For the Local
57 Trust Fund, information is for plan years beginning July 1, 2012 and 2011. Information for the plan year beginning July 1, 2013 is not yet available.
(4) If PacifiCorp's subsidiary was to withdraw from the UMWA Pension Plan, a liability of up to an estimated $125 million could be triggered.
The current collective bargaining agreements governing the Local 57 Trust Fund expire in January 2016. Although the collective
bargaining agreement governing the UMWA Pension Plan expired in January 2013 and a new agreement has not yet been reached,
operations continue under the provisions of the expired agreement.
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 $35 million and $36 million for the years ended December 31, 2013 and 2012, 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 $843
million and $810 million as of December 31, 2013 and 2012, 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
2013/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):
2013 2012
Beginning balance $127 $123
Change in estimated costs 3 17
Additions 8 4
Retirements (6)(22)
Accretion 6 5
Ending balance $138 $127
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 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
2013/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, 2013
Not designated as hedging contracts(1):
Commodity assets $11 $—$2 $1 $14
Commodity liabilities (1)— (29)(39) (69)
Total 10 —(27)(38)(55)
Total derivatives 10 — (27)(38)(55)
Cash collateral receivable — — — 12 12
Total derivatives - net basis $10 $—$(27)$(26)$(43)
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)
(1) PacifiCorp's commodity derivatives are generally included in rates and as of December 31, 2013 and 2012, a regulatory asset of $55 million and
$121 million, respectively, was recorded related to the net derivative liability of $55 million and $121 million, respectively.
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):
2013 2012
Beginning balance $121 $264
Changes in fair value recognized in regulatory assets 15 45
Net gains reclassified to operating revenue 9 38
Net losses reclassified to energy costs (90)(226)
Ending balance $55 $121
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.21
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 2013 2012
Electricity sales Megawatt hours (1) (1)
Natural gas purchases Decatherms 120 74
Fuel oil purchases Gallons 15 16
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 credit support provisions that in part base certain
collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating
agencies. 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, 2013, PacifiCorp's credit ratings from the three recognized
credit rating agencies were investment grade.
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features
totaled $68 million and $153 million as of December 31, 2013 and 2012, respectively, for which PacifiCorp had posted collateral of
$12 million and $56 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, 2013 and 2012, PacifiCorp would have
been required to post $51 million and $73 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.22
(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.
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, 2013
Assets:
Commodity derivatives $—$12 $2 $(4)$10
Money market mutual funds(2) 61 ———61
$61 $12 $2 $(4)$71
Liabilities - Commodity derivatives $—$(69)$—$16 $(53)
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)
(1) Represents netting under master netting arrangements and a net cash collateral receivable of $12 million and $55 million as of December 31, 2013 and 2012,
respectively.
(2) Amounts are included in other special funds and temporary cash investments on the Comparative Balance Sheet. The fair value of these money market
mutual funds approximates cost.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.23
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. 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 to record the fair value.
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):
2013 2012
Beginning balance $—$1
Changes in fair value recognized in regulatory assets 1 1
Purchases 4 —
Settlements (3)(2)
Ending balance $2 $—
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):
2013 2012
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $6,828 $7,626 $6,806 $8,350
(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
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.24
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 the first quarter of 2013, PacifiCorp filed its responses to the Plaintiff's
post-trial motions for exemplary damages, attorneys' fees and prejudgment interest. An initial judgment was entered in April 2013 in
which 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. In May 2013, a final judgment was entered against PacifiCorp in the amount of $115
million, which includes the $113 million of aggregate damages previously awarded and amounts awarded for the Plaintiff's attorneys'
fees. The final judgment also ordered that postjudgment interest accrue beginning as of the date of the April 2013 initial judgment. In
May 2013, PacifiCorp posted a surety bond issued by a subsidiary of Berkshire Hathaway to secure its estimated obligation.
PacifiCorp strongly disagrees with the jury's verdict and plans to vigorously pursue all appellate measures. Both PacifiCorp and the
Plaintiff filed appeals with the Utah Supreme Court. The parties are briefing their positions before the Utah Supreme Court with
briefing expected to be completed and oral arguments held by late 2014. As of December 31, 2013, PacifiCorp had accrued
$117 million for the final judgment and postjudgment interest, 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 appeals process, which could take as long as several years.
Sanpete County, Utah Rangeland Fire
In June 2012, a major rangeland fire occurred in Sanpete County, Utah. Certain parties allege that contact between two of
PacifiCorp’s transmission lines may have triggered a ground fault that led to the fire. PacifiCorp has engaged experts to review the
cause and origin of the fire, as well as to assess the damages. PacifiCorp has accrued its best estimate of the potential loss and believes
it is reasonably possible it may incur additional loss beyond the amount accrued. PacifiCorp does not believe the potential additional
loss will have a material impact to its financial results, particularly with PacifiCorp's ability to seek insurance recovery if considered
necessary.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.25
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 among all parties. The plaintiff parties to the proceeding filed claims against
multiple parties, including PacifiCorp. PacifiCorp entered into settlements with the plaintiff parties, and the resulting settlements were
approved by the FERC. The outcome of such settlements did not have a material impact on PacifiCorp's financial results. The FERC,
however, declined to dismiss PacifiCorp from the case entirely, noting that additional parties may, in the future, assert sequential
claims against parties to the case, including PacifiCorp. PacifiCorp believes it is unlikely that the FERC will address sequential claims
until after the primary cases have proceeded through the trial-type hearing. Due to the uncertainties associated with the sequential
claims, PacifiCorp is unable to predict the outcome and the impact of any claims on its 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.
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.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.26
As of December 31, 2013, PacifiCorp's assets included $103 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 and the CPUC
to depreciate and amortize the Klamath hydroelectric system's mainstem dams and the associated relicensing and settlement costs
through the December 2019 expected dam removal date. PacifiCorp also filed for consistent ratemaking treatment in the 2011 and
2013 Washington general rate cases and the treatment was uncontested in both cases. PacifiCorp has received approvals from the
UPSC, the WPSC and the IPUC to depreciate and amortize 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 $189 million
over the next 10 years related to these licenses.
Commitments
PacifiCorp has the following firm commitments that are not reflected on the Comparative Balance Sheet. Minimum payments as of
December 31, 2013 are as follows (in millions):
2014 2015 2016 2017 2018
2019 and
Thereafter Total
Contract type:
Purchased electricity contracts $119 $116 $100 $76 $72 $503 $986
Fuel contracts 765 570 514 516 451 1,776 4,592
Construction commitments 404 121 37 9 9 37 617
Transmission 115 105 98 87 79 656 1,140
Operating leases and easements 6 5 4 4 4 49 72
Maintenance, service and
other contracts 52 28 16 16 12 79 203
Total commitments $1,461 $945 $769 $708 $627 $3,100 $7,610
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 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 a lease. Rent expense related to those power
purchase agreements that meet the definition of a lease totaled $24 million for 2013 and $19 million for 2012.
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 2013
and 2012 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
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.27
Construction Commitments
PacifiCorp's construction commitments included in the table above relate to firm commitments and include costs associated with
investments in emissions control equipment and certain transmission projects.
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 $16 million for 2013 and $14 million for 2012.
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
In 2013, PacifiCorp redeemed and canceled all remaining outstanding shares of its redeemable preferred stock at stated redemption
prices, which in aggregate totaled $40 million, plus accrued and unpaid dividends.
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 $- million and $1 million as of December 31, 2013 and 2012,
respectively.
(15) Common Shareholder's Equity
In February 2014, PacifiCorp declared a dividend of $500 million, which was paid to PPW Holdings in March 2014.
Through PPW Holdings, 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, 2013, the most restrictive of
these commitments prohibits PacifiCorp from making any distribution to PPW Holdings 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, 2013, PacifiCorp's actual
common equity percentage, as calculated under this measure, was 54.1%, and PacifiCorp would have been permitted to dividend
$2.6 billion under this commitment.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.28
These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings or MEHC if PacifiCorp's senior
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, 2013, PacifiCorp met the minimum required senior
unsecured debt ratings for making distributions.
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):
2013 2012
Interest paid, net of amounts capitalized $ 340 $ 330
Income taxes paid (received), net(1)$124 $(209)
Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to utility plant additions $157 $167
(1) PacifiCorp is party to a tax-sharing agreement and is part of the Berkshire Hathaway United States federal income tax return. Amounts substantially
represent income taxes paid to (received from) MEHC.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.29
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
PacifiCorp X
/ /2013/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)
( 9,055,432)
Balance of Account 219 at Beginning of
Preceding Year
1
317,072
Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
2
( 3,265,461)
Preceding Quarter/Year to Date Changes in
Fair Value
3
( 2,948,389)Total (lines 2 and 3) 4
( 12,003,821)
Balance of Account 219 at End of Preceding
Quarter/Year
5
( 12,003,821)
Balance of Account 219 at Beginning of
Current Year
6
498,291
Current Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
7
2,414,025
Current Quarter/Year to Date Changes in
Fair Value
8
2,912,316Total (lines 7 and 8) 9
( 9,091,505)
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
/ /2013/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)
( 9,055,432) 1
317,072 2
( 3,265,461) 3
537,337,285 534,388,896( 2,948,389) 4
( 12,003,821) 5
( 12,003,821) 6
498,291 7
2,414,025 8
682,163,330 685,075,646 2,912,316 9
( 9,091,505) 10
FERC FORM NO. 1 (NEW 06-02)Page 122b
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
/ /2013/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
24,483,414,682 24,483,414,682Plant in Service (Classified) 3
48,708,458 48,708,458Property Under Capital Leases 4
Plant Purchased or Sold 5
95,477,903 95,477,903Completed Construction not Classified 6
Experimental Plant Unclassified 7
24,627,601,043 24,627,601,043Total (3 thru 7) 8
Leased to Others 9
23,368,811 23,368,811Held for Future Use 10
1,321,622,138 1,321,622,138Construction Work in Progress 11
159,175,508 159,175,508Acquisition Adjustments 12
26,131,767,500 26,131,767,500Total Utility Plant (8 thru 12) 13
8,511,018,083 8,511,018,083Accum Prov for Depr, Amort, & Depl 14
17,620,749,417 17,620,749,417Net Utility Plant (13 less 14) 15
Detail of Accum Prov for Depr, Amort & Depl 16
In Service: 17
7,863,751,463 7,863,751,463Depreciation 18
Amort & Depl of Producing Nat Gas Land/Land Right 19
Amort of Underground Storage Land/Land Rights 20
529,162,303 529,162,303Amort of Other Utility Plant 21
8,392,913,766 8,392,913,766Total 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
118,104,317 118,104,317Amort of Plant Acquisition Adj 32
8,511,018,083 8,511,018,083Total 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
/ /2013/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
/ /2013/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 206,314,615 1,937,773 3
(303) Miscellaneous Intangible Plant 648,104,811 8,094,410 4
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 854,419,426 10,032,183 5
2. PRODUCTION PLANT 6
A. Steam Production Plant 7
(310) Land and Land Rights 93,164,157 441,938 8
(311) Structures and Improvements 1,004,588,118 9,774,932 9
(312) Boiler Plant Equipment 4,091,983,619 42,030,125 10
(313) Engines and Engine-Driven Generators 11
(314) Turbogenerator Units 966,966,274 39,953,518 12
(315) Accessory Electric Equipment 475,506,492 4,268,263 13
(316) Misc. Power Plant Equipment 34,367,481 138,263 14
(317) Asset Retirement Costs for Steam Production 53,698,542 10,962,817 15
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 6,720,274,683 107,569,856 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 31,389,764 27
(331) Structures and Improvements 181,647,007 7,701,030 28
(332) Reservoirs, Dams, and Waterways 453,238,675 24,745,664 29
(333) Water Wheels, Turbines, and Generators 120,151,371 1,431,836 30
(334) Accessory Electric Equipment 74,757,801 2,201,133 31
(335) Misc. Power PLant Equipment 2,358,351 1,702 32
(336) Roads, Railroads, and Bridges 17,635,627 514,113 33
(337) Asset Retirement Costs for Hydraulic Production 34
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 881,178,596 36,595,478 35
D. Other Production Plant 36
(340) Land and Land Rights 29,096,571 37
(341) Structures and Improvements 164,387,266 1,394,065 38
(342) Fuel Holders, Products, and Accessories 10,801,123 347,115 39
(343) Prime Movers 2,512,410,690 26,242,867 40
(344) Generators 353,390,092 2,150,465 41
(345) Accessory Electric Equipment 249,559,251 608,767 42
(346) Misc. Power Plant Equipment 12,476,182 8,309 43
(347) Asset Retirement Costs for Other Production 9,072,015 44
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 3,341,193,190 30,751,588 45
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 10,942,646,469 174,916,922 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
/ /2013/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
207,652,388 600,000 3
649,633,440 69,660 6,635,441 4
857,285,828 69,660 7,235,441 5
6
7
93,604,532 1,563 8
1,011,284,474 -643,167 2,435,409 9
4,116,137,262 -459,302 17,417,180 10
11
989,029,762 -47,213 17,842,817 12
480,444,603 1,209,122 539,274 13
31,133,252 -1,044,592 2,327,900 14
58,481,237 -6,180,122 15
6,780,115,122 -985,152 -6,180,122 40,564,143 16
17
18
19
20
21
22
23
24
25
26
31,316,716 -69,719 3,329 27
192,276,703 3,399,612 470,946 28
471,289,781 -5,413,120 1,281,438 29
120,766,696 816,511 30
76,319,914 639,020 31
2,359,453 600 32
19,882,202 2,012,668 280,206 33
34
914,211,465 -70,559 3,492,050 35
36
29,095,936 635 37
165,443,499 862 338,694 38
11,117,341 30,897 39
2,565,322,968 41,311,300 14,641,889 40
313,142,611 -41,314,067 1,083,879 41
249,675,392 -5,291 487,335 42
12,138,583 -328,178 17,730 43
9,072,015 44
3,355,008,345 -335,374 16,601,059 45
11,049,334,932 -1,391,085 -6,180,122 60,657,252 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
/ /2013/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
3. TRANSMISSION PLANT 47
(350) Land and Land Rights 198,218,069 26,830,476 48
(352) Structures and Improvements 170,949,185 2,454,073 49
(353) Station Equipment 1,735,328,437 102,719,775 50
(354) Towers and Fixtures 992,008,798 226,035,308 51
(355) Poles and Fixtures 686,214,770 22,197,850 52
(356) Overhead Conductors and Devices 919,805,558 140,800,705 53
(357) Underground Conduit 3,312,843 27,261 54
(358) Underground Conductors and Devices 7,489,179 10,281 55
(359) Roads and Trails 11,586,681 336,114 56
(359.1) Asset Retirement Costs for Transmission Plant 57
TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 4,724,913,520 521,411,843 58
4. DISTRIBUTION PLANT 59
(360) Land and Land Rights 59,625,027 1,953,555 60
(361) Structures and Improvements 89,144,237 2,823,009 61
(362) Station Equipment 884,422,143 34,439,329 62
(363) Storage Battery Equipment 63
(364) Poles, Towers, and Fixtures 1,015,605,530 41,474,798 64
(365) Overhead Conductors and Devices 679,910,311 16,227,790 65
(366) Underground Conduit 322,706,767 8,701,790 66
(367) Underground Conductors and Devices 759,050,565 18,756,758 67
(368) Line Transformers 1,165,115,776 42,891,258 68
(369) Services 628,986,472 25,907,953 69
(370) Meters 176,687,115 5,148,695 70
(371) Installations on Customer Premises 8,827,913 76,676 71
(372) Leased Property on Customer Premises 72
(373) Street Lighting and Signal Systems 60,443,784 1,289,956 73
(374) Asset Retirement Costs for Distribution Plant 2,459,448 74
TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 5,852,985,088 199,691,567 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 19,478,606 1,995,376 86
(390) Structures and Improvements 227,482,706 8,525,002 87
(391) Office Furniture and Equipment 89,904,683 12,843,359 88
(392) Transportation Equipment 103,227,297 3,808,692 89
(393) Stores Equipment 14,568,536 323,811 90
(394) Tools, Shop and Garage Equipment 62,887,623 1,897,471 91
(395) Laboratory Equipment 37,053,335 889,654 92
(396) Power Operated Equipment 155,194,085 6,930,033 93
(397) Communication Equipment 344,747,037 40,183,598 94
(398) Miscellaneous Equipment 7,929,038 274,366 95
SUBTOTAL (Enter Total of lines 86 thru 95) 1,062,472,946 77,671,362 96
(399) Other Tangible Property 296,636,099 14,112,209 97
(399.1) Asset Retirement Costs for General Plant 39,748 98
TOTAL General Plant (Enter Total of lines 96, 97 and 98) 1,359,148,793 91,783,571 99
TOTAL (Accounts 101 and 106) 23,734,113,296 997,836,086 100
(102) Electric Plant Purchased (See Instr. 8) 124,000 101
(Less) (102) Electric Plant Sold (See Instr. 8) 4,235 102
(103) Experimental Plant Unclassified 103
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 23,734,237,296 997,831,851 104
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
/ /2013/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
47
225,631,404 540,691 -42,168 48
184,174,369 11,108,939 337,828 49
1,813,896,299 -13,781,678 10,370,235 50
1,218,917,978 1,157,121 283,249 51
706,210,382 2,209 2,204,447 52
1,059,513,463 101,667 1,194,467 53
3,340,104 54
7,499,460 55
11,922,795 56
57
5,231,106,254 -871,051 14,348,058 58
59
62,028,583 450,001 60
97,377,014 5,573,747 163,979 61
906,249,058 -6,314,001 6,298,413 62
63
1,052,968,133 -29,476 4,082,719 64
693,804,415 -490 2,333,196 65
330,194,141 1,214,416 66
776,602,508 29,966 1,234,781 67
1,200,818,543 68,471 7,256,962 68
654,161,585 732,840 69
177,965,016 3,870,794 70
8,822,747 81,842 71
72
60,769,235 964,505 73
1,651,393 -808,055 74
6,023,412,371 -221,782 -808,055 28,234,447 75
76
77
78
79
80
81
82
83
84
85
21,472,385 -1,570 27 86
233,694,751 381,097 2,694,054 87
87,147,440 251,723 15,852,325 88
105,016,260 -6,743 2,012,986 89
14,884,798 101,319 108,868 90
63,129,288 509,735 2,165,541 91
35,461,262 178,018 2,659,745 92
158,392,929 3,731,189 93
384,826,535 1,922,418 2,026,518 94
8,030,164 107,673 280,913 95
1,112,055,812 3,443,670 31,532,166 96
305,657,640 -64,568 -104,703 4,921,397 97
39,748 98
1,417,753,200 3,379,102 -104,703 36,453,563 99
24,578,892,585 964,844 -7,092,880 146,928,761 100
-124,000 101
-4,235 102
103
24,578,892,585 845,079 -7,092,880 146,928,761 104
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 40,344,676 3,929,050 49,700 - (296,811) 43,927,215
39941 Surface-Plant Equipment 13,554,030 734,400 85,144 - 232,243 14,435,529
39944 Surface-Electric Power Facil 3,424,575 - - - - 3,424,575
39945 Underground-Coal Mine Equip 73,363,902 4,977,654 3,355,546 - - 74,986,010
39946 Longwall Shields 24,486,688 - - - - 24,486,688
39947 Longwall Equipment 9,115,912 - - - - 9,115,91239948 Mainline Extension 19,968,210 305,947 - - - 20,274,157
39949 Section Extension 7,293,886 906,150 787,445 - - 7,412,591
39951 Vehicles 1,235,651 136,486 50,707 - - 1,321,430
39952 Heavy Construction Equip 6,158,245 - - - - 6,158,245
39960 Miscellaneous General Equip 2,519,978 171,624 335,876 - - 2,355,72639961 Computers-Mainframe 398,573 128,483 56,060 - - 470,996
39970 Mine Development and Road Ext 38,858,038 - 200,919 - - 38,657,119
39915 Coal Mine ARO 728,172 2,822,415 - (104,703) - 3,445,884
$296,636,099 $14,112,209 $ 4,921,397 $(104,703) $(64,568) $305,657,640
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: f
Refer to Important Changes During the Quarter/Year, Item 3, in this Form No. 1.
Schedule Page: 204 Line No.: 102 Column: c
Refer to Important Changes During the Quarter/Year, Item 3, 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
2013/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
/ /2013/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 6,763,0942028 5
2007Twelve Mile Wind Plant 2,160,2072028 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 396,0202017 10
2010Bend Service Center 3,507,8382021 11
2010Legacy Substation 562,2762025 12
2011Aeolus Substation 1,014,0532019 13
2011Anticline Substation 964,5052019 14
2011Populus Substation 254,7532021 15
2011Snyderville Substation 253,4012016 16
2012Lassen Substation 683,3182019 17
2012Old Mill Substation 1,838,2812020 18
2013Chimney Butte-Paradise 230-kV Transmission Line 598,4572017 19
Miscellaneous, each under $250,000: 960,657 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 23,368,811
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 2028, 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 2028, 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
2013/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
/ /2013/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
6,379,651EMS/SCADA Replacement / Upgrade 2
3,945,054IT-Mobility Upgrade / Click Replacement 3
3,172,645Call Center Automated Call Distribution Replacement Project 4
1,669,508Wallowa Falls Hydro Relicensing 5
1,640,548FastGate Replacement Project 6
7
Production: 8
614,209,928Lake Side 2 Development 9
52,671,773Lewis River System Relicensing Implementation 10
46,150,540Hunter U1 Clean Air - Particulate Matter Emissions 11
20,557,817Blundell Proofing Well Integration 12
7,127,067Jim Bridger U3 Selective Catalytic Reduction System 13
5,733,463Hayden U1 Selective Catalytic Reduction System 14
4,317,914Jim Bridger U4 Selective Catalytic Reduction System 15
3,541,368Soda Springs Hydro Fish Screen Upgrade 16
2,911,278Hunter U1 Reheater Pendant Replacement 17
2,147,715Huntington U1 and U2 Submerged Drag Chain Conveyor 18
2,105,610Hunter U1 Finishing Superheat Replacement 19
1,818,427Hayden U2 Selective Catalytic Reduction System 20
1,393,943Colstrip 4 Generator Repair 21
1,193,369Hunter U1 NOX LNB Clean Air (low NOx burners ) 22
1,150,546Dave Johnston U2 Secondary Superheater Pendant Replacement 23
1,102,463Jim Bridger New Sewage Treatment Facility 24
1,057,878Naughton Fire Pump Backup 25
26
Transmission: 27
174,960,526Sigurd - Red Butte - Crystal 345kV Line 28
54,190,714Energy Gateway Preliminary Engineering and Permitting 29
49,711,487Aeolus Clover 500kV Line 30
34,443,886Populus - Hemingway 500kV Line 31
18,345,344Boardman - Hemingway 500kV Line 32
15,350,782Standpipe Substation New 230kV Sub 33
9,194,279Oquirrh - Terminal 345kV Line 34
7,543,974Southwest WY Silver Creek Build 138kV Line 35
6,765,795Carbon Plant Replacement - Transmission 36
6,393,911Whetstone 230-115kV Substation Phase 1 37
5,956,560Vantage - Pomona Heights 230kV Line 38
5,492,868West Point - New 138kV Line & 40 MVA Substation 39
5,402,073Lake Side 2 Transmission Interconnection 40
4,496,676Cameron Milford 138kV Transmission 138-46 Transformer 41
4,462,667Line 37 Convert to 115kV Build Nickel Mt Substation 42
FERC FORM NO. 1 (ED. 12-87) Page 216
43 TOTAL 1,321,622,138
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
/ /2013/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.
3,879,167Goshen Substation Bus Rebuild - Kinsport Line Relocation 1
2,994,234Union Gap Substation Add 230 - 115kV Capacity 2
2,592,977Jim Bridger U2 GSU Transformer Replacement 3
2,398,388Red Butte WY Increase Substation Capacity 4
2,110,627Middleton - Toquerville Rebuild 69kV to 138kV 5
1,816,880Huntington U2 Main GSU Transformer 6
1,751,357Two Elks Intercon at Tri County Switchyard 7
1,452,170Tooele Sub Connect to Oquirrh - Limber 345kV 8
1,195,558Utah-NERC Line Rating Project - Low Priority Lines 9
1,159,498Terminal - Tooele 138kV Reconductor 10
1,155,493Fry Substation Install 115 kV Capacitor Bank 11
12
Distribution: 13
1,259,146ODOT Highway Relocation OR 99 & Fern Valley Road 14
1,118,415Wyoming Avian Protection 15
16
General: 17
8,195,396Mobile Radio Replacement Project 18
3,732,249EIM Energy Imbalance Market Project (CAISO) 19
2,586,739Lloyd Center Tower EMC VMAX Storage 20
1,547,357Deer Creek - 2 Section Terminal Groups 21
22
91,966,440Miscellaneous Projects each under $1,000,000 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. 12-87) Page 216.1
43 TOTAL 1,321,622,138
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
/ /2013/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 7,404,667,421 7,404,667,421
Depreciation Provisions for Year, Charged to 2
(403) Depreciation Expense 3 600,829,680 600,829,680
(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 34,064,727 34,064,727
9
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
10 634,894,407 634,894,407
Net Charges for Plant Retired: 11
Book Cost of Plant Retired 12 138,724,384 138,724,384
Cost of Removal 13 42,756,350 42,756,350
Salvage (Credit) 14 7,019,825 7,019,825
TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
15 174,460,909 174,460,909
Other Debit or Cr. Items (Describe, details in
footnote):
16 -1,349,456 -1,349,456
17
Book Cost or Asset Retirement Costs Retired 18
Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
19 7,863,751,463 7,863,751,463
Steam Production 20
Section B. Balances at End of Year According to Functional Classification
2,621,710,730 2,621,710,730
Nuclear Production 21
Hydraulic Production-Conventional 22 281,113,356 281,113,356
Hydraulic Production-Pumped Storage 23
Other Production 24 672,417,401 672,417,401
Transmission 25 1,361,684,760 1,361,684,760
Distribution 26 2,387,803,953 2,387,803,953
Regional Transmission and Market Operation 27
General 28 539,021,263 539,021,263
TOTAL (Enter Total of lines 20 thru 28) 29 7,863,751,463 7,863,751,463
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 $10,502,660
Account 143, Other accounts receivable, - depreciation
expense billed to joint owners 236,958
Asset retirement obligation asset depreciation recorded
as a regulatory asset or liability 6,120,540
Transportation depreciation charged to operations and maintenance
expense and construction work in progress based on usage activity 15,921,062
Account 503, Steam from other sources, - Blundell depletion 185,368
Account 503, Steam from other sources, - Blundell depreciation 1,098,139
Total Other Accounts $34,064,727
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. $(12,902,183)
Other items include: 11,552,727
- 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 $ (1,349,456)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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
/ /2013/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
151,388,983 Undistributed Subsidiary Earnings 4
199,348,984 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
5,916,977 Undistributed Subsidiary Earnings 25
11,954,977 SUBTOTAL 26
27
2011FOSSIL ROCK FUELS, LLC 28
27,762,429 Paid-in Capital 29
-6,907 Undistributed Subsidiary Earnings 30
27,755,522 SUBTOTAL 31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89) Page 224
42 Total Cost of Account 123.1 $TOTAL 239,062,484 83,262,431
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
/ /2013/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
121,361,852 12,972,869 4
169,321,853 12,972,869 5
6
7
1,000 8
1,000 9
10
11
12
13
14
15
1 16
1 17
18
19
1,000 20
1,000 21
22
23
6,038,000 24
6,310,111 427,962 25
12,348,111 427,962 26
27
28
29,262,429 29
-10,335 -3,428 30
29,252,094 -3,428 31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89) Page 225
42 13,397,403 210,924,059
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.: 4 Column: g
In May 2013, Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp, declared and
paid a dividend of $43 million to PacifiCorp.
Schedule Page: 224 Line No.: 11 Column: a
In December 2013, Centralia Mining Company, an inactive wholly owned subsidiary of
PacifiCorp, was dissolved.
Schedule Page: 224 Line No.: 25 Column: g
In September 2013, Trapper Mining Inc., a subsidiary of PacifiCorp, paid a dividend of
$34,828 to PacifiCorp.
Schedule Page: 224 Line No.: 29 Column: g
In August 2013, PacifiCorp contributed $1.5 million to its wholly owned subsidiary Fossil
Rock Fuels, 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
2013/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
/ /2013/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.
265,591,187 Electric 240,980,677 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)
83,816,884 Electric 91,333,148 5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
98,097,803 Electric 101,171,275 7 Production Plant (Estimated)
750,972 Electric 678,432 8 Transmission Plant (Estimated)
13,817,380 Electric 12,375,512 9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant
(Estimated)
6,041,605 Electric 6,985,748 11 Assigned to - Other (provide details in footnote)
202,524,644 212,544,115 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
468,115,831 453,524,792 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 $ 5,910,897
General plant materials and supplies 130,708
$ 6,041,605

Schedule Page: 227 Line No.: 11 Column: c
Mining materials and supplies $ 6,914,497
General plant materials and supplies 71,251
$ 6,985,748
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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
/ /2013/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.
2014
270,494.00 156,645.00Balance-Beginning of Year 1
2
Acquired During Year: 3
Issued (Less Withheld Allow) 4
Returned by EPA 5
6
7
Purchases/Transfers: 8
25.00Hermiston Generating Co. 9
10
11
12
13
14
25.00Total 15
16
Relinquished During Year: 17
42,227.00 Charges to Account 509 18
Other: 19
20
Cost of Sales/Transfers: 21
2,500.00AES Warrior Run LP 22
6,000.00AES Beaver Valley, LLC 23
29,000.00Duke Energy Kentucky, Inc 24
25
26
27
37,500.00Total 28
190,792.00 156,645.00Balance-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
/ /2013/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.
2015 2016
1 4,062,626.00 149,627.00 136,466.00 4,775,858.00
2
3
4 156,644.00 156,644.00
5
6
7
8
9 25.00
10
11
12
13
14
15 25.00
16
17
18 42,227.00
19
20
21
22 2,500.00
23 6,000.00
24 29,000.00
25
26
27
28 37,500.00
29 4,219,270.00 149,627.00 136,466.00 4,852,800.00
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
Schedule Page: 228 Line No.: 9 Column: a
Hermiston Generating Company, L.P. operates the Hermiston Generating Plant, which is
jointly owned. PacifiCorp owns 50% of the plant. Purchases represent PacifiCorp's share of
allowances purchased by Hermiston Generating Company, L.P. for the Hermiston Generating
Plant.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
PacifiCorp X
/ /2013/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 environmental 3,013,540 407 1,808,124 1,205,41622
upgrades23
Plant located near Evanston, WY24
Date of Commission Authorization:25
09/19/201226
Amortization Period: 10/12/201227
through 08/31/201428
29
WY-Naughton Unit #3 environmental 1,113,009 407 557,823 555,18630
upgrades31
Plant located near Evanston, WY32
Date of Commission Authorization:33
10/8/201234
Amortization Period: 10/22/201235
through 12/31/201436
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-88)Page 230b
49 TOTAL 4,126,549 2,365,947 1,760,602
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
/ /2013/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 0 0 1
3,219AREF 78003595 561.6 3,219 456 2
11,829AREF 77762035 561.6 3
11,316AREF 77762000 561.6 4
1,179System Impact Study Agreement 561.6 5
19,271AREF 78351080 561.6 6
335AREF 788834184 561.6 7
42,403Integrated Resource Planning Agrmt 561.6 8
3,827AREF 77755718 107 9
34AREF 78764672 107 10
34AREF 78849614 107 11
158Customer Studies Accrual 561.6 12
13
14
15
16
17
18
19
20
Generation Studies 21
442GIQ0252 561.7 442 456 22
5,051GIQ0255 561.7 5,051 456 23
101GIQ0311 561.7 101 456 24
1,031GIQ0316 561.7 1,031 456 25
74GIQ0332 561.7 74 456 26
1,179GIQ0335 561.7 1,179 456 27
396GIQ0367 561.7 396 456 28
147GIQ0377 561.7 147 456 29
3,162GIQ0384 561.7 3,162 456 30
2,795GIQ0393 561.7 2,795 456 31
4,904GIQ0397 561.7 4,904 456 32
6,445GIQ0403 561.7 6,445 456 33
86,820GIQ0409 561.7 86,820 456 34
1,620GIQ0411 561.7 1,620 456 35
6,158GIQ0414 561.7 6,158 456 36
20,827GIQ0420 561.7 20,827 456 37
1,651GIQ0422 561.7 1,651 456 38
9,778GIQ0425 561.7 9,778 456 39
23,908GIQ0426 561.7 23,908 456 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
/ /2013/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
9,362GIQ0427 561.7 9,362 456 22
24,141GIQ0429 561.7 24,141 456 23
3,133GIQ0430 561.7 3,133 456 24
3,444GIQ0431 561.7 3,444 456 25
4,497GIQ0432 561.7 4,497 456 26
1,446GIQ0436 561.7 1,446 456 27
7,903GIQ0437 561.7 7,903 456 28
20,622GIQ0438 561.7 20,622 456 29
706GIQ0439 561.7 706 456 30
2,145GIQ0440 561.7 2,145 456 31
9,444GIQ0441 561.7 9,444 456 32
11,365GIQ0442 561.7 11,365 456 33
34,673GIQ0443 561.7 34,673 456 34
15,848GIQ0445 561.7 15,848 456 35
161GIQ0446 561.7 161 456 36
1,516GIQ0447 561.7 1,516 456 37
825GIQ0448 561.7 825 456 38
3,632GIQ0449 561.7 3,632 456 39
25,465GIQ0450 561.7 25,465 456 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
/ /2013/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
13,558GIQ0451 561.7 13,558 456 22
18,808GIQ0453 561.7 18,808 456 23
12,348GIQ0454 561.7 12,348 456 24
7,905GIQ0455 561.7 7,905 456 25
12,458GIQ0456 561.7 12,458 456 26
9,206GIQ0457 561.7 9,206 456 27
10,076GIQ0458 561.7 10,076 456 28
7,530GIQ0459 561.7 7,530 456 29
33,332GIQ0460 561.7 33,332 456 30
1,891GIQ0461 561.7 1,891 456 31
8,512GIQ0462 561.7 8,512 456 32
10,283GIQ0463 561.7 10,283 456 33
16,256GIQ0464 561.7 16,256 456 34
4,229GIQ0465 561.7 4,229 456 35
3,584GIQ0466 561.7 3,584 456 36
886GIQ0467 561.7 886 456 37
3,526GIQ0468 561.7 3,526 456 38
7,122GIQ0469 561.7 7,122 456 39
22,149GIQ0470 561.7 22,149 456 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
/ /2013/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
7,937GIQ0471 561.7 7,937 456 22
6,543GIQ0472 561.7 6,543 456 23
5,871GIQ0473 561.7 5,871 456 24
4,566GIQ0474 561.7 4,566 456 25
13,417GIQ0475 561.7 13,417 456 26
2,022GIQ0476 561.7 2,022 456 27
1,410GIQ0477 561.7 1,410 456 28
731GIQ0478 561.7 731 456 29
584GIQ0479 561.7 584 456 30
530GIQ0480 561.7 530 456 31
530GIQ0481 561.7 530 456 32
530GIQ0482 561.7 530 456 33
614GIQ0483 561.7 614 456 34
772GIQ0484 561.7 772 456 35
530GIQ0485 561.7 530 456 36
530GIQ0486 561.7 530 456 37
732GIQ0487 561.7 732 456 38
12,769GIQ0488 561.7 12,769 456 39
11,531GIQ0489 561.7 11,531 456 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
/ /2013/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
5,973GIQ0490 561.7 5,973 456 22
7,992GIQ0491 561.7 7,992 456 23
11,626GIQ0492 561.7 11,626 456 24
9,437GIQ0493 561.7 9,437 456 25
825GIQ0494 561.7 825 456 26
3,672GIQ0495 561.7 3,672 456 27
11,932GIQ0496 561.7 11,932 456 28
2,796GIQ0497 561.7 2,796 456 29
8,233GIQ0498 561.7 8,233 456 30
6,456GIQ0499 561.7 6,456 456 31
1,903GIQ0500 561.7 1,903 456 32
10,027GIQ0501 561.7 10,027 456 33
9,380GIQ0502 561.7 9,380 456 34
7,835GIQ0503 561.7 7,835 456 35
5,914GIQ0504 561.7 5,914 456 36
3,380GIQ0505 561.7 3,380 456 37
7,195GIQ0507 561.7 7,195 456 38
47,491GIQ0509 561.7 47,491 456 39
21,762GIQ0510 561.7 21,762 456 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
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2013/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
7,063GIQ0511 561.7 7,063 456 22
9,586GIQ0512 561.7 9,586 456 23
7,433GIQ0513 561.7 7,433 456 24
2,017GIQ0514 561.7 2,017 456 25
4,763GIQ0515 561.7 4,763 456 26
3,897GIQ0516 561.7 3,897 456 27
3,959GIQ0517 561.7 3,959 456 28
1,514GIQ0522 561.7 1,514 456 29
5,958GIQ0523 561.7 5,958 456 30
6,599GIQ0524 561.7 6,599 456 31
3,848GIQ0525 561.7 3,848 456 32
6,493GIQ0526 561.7 6,493 456 33
5,452GIQ0527 561.7 5,452 456 34
4,578GIQ0528 561.7 4,578 456 35
2,356GIQ0529 561.7 2,356 456 36
1,965GIQ0530 561.7 1,965 456 37
1,895GIQ0531 561.7 1,895 456 38
1,909GIQ0532 561.7 1,909 456 39
1,273GIQ0533 561.7 1,273 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2013/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
686GIQ0534 561.7 686 456 22
872GIQ0535 561.7 872 456 23
462GIQ0536 561.7 462 456 24
462GIQ0537 561.7 462 456 25
451GIQ0539 561.7 451 456 26
( 20,254)GIQ1605 561.7 27
( 16,038)GIQ1604 561.7 28
( 4,261)Customer Studies Accrual 561.7 29
4,427 107 30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.6
Schedule Page: 231.6 Line No.: 30 Column: a
Large Generation Interconnect Agreement Modification
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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 ASSETS (Account 182.3)
PacifiCorp X
/ /
2013/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)
1,001,435 1,001,435DSM Regulatory Asset - CA 1
511,241 4,328,960908,431 3,817,719DSM Regulatory Asset - ID 2
1,428,381 11,313,928908 9,885,547DSM Regulatory Asset - WA 3
591,995 5,269,290908,431 4,677,295DSM Regulatory Asset - WY 4
455,760,491 461,454,531 5,694,040Deferred Income Taxes Electric 5
70,531 39,674 30,857Tax Revenue Requirement Adjustment - WY (4) 6
2,690,515 4,791,326 876,977555 2,977,788Deferred Excess Net Power Costs - CA (1) 7
35,999,609 38,359,894 11,106,414 13,466,699Deferred Excess Net Power Costs - WY 8
23,109,560 24,493,966 12,551,661555 13,936,067Deferred Excess Net Power Costs - ID 9
73,121,161 71,218,625 27,003,375 25,100,839Deferred Excess Net Power Costs - UT 10
16,140,769 16,140,769Deferred Excess RECs in Rates - UT 11
1,415,596 5,405,889 1,328,559456 5,318,852Deferred Excess RECs/SO2 in Rates - WY (1) 12
33,421,538 38,110,147 5,531,702925,253 10,220,311Environmental Costs (10) 13
( 905,335) -1,067,082 336,552925 174,805Environmental Costs - WA (10) 14
4,302,064 3,363,432 1,122,424557 183,792Cholla Plant Transaction Costs (26) 15
421,883 369,695 52,188456Washington Colstrip Unit No. 3 (22) 16
166,028,027 145,804,625 20,223,402242Unamortized Contract Values 17
120,369,451 54,369,561 65,999,890175,244Derivative Net Regulatory Asset 18
55,451,404 51,025,640 4,425,764230Asset Retirement Obligations Regulatory Difference 19
599,085,779 312,870,952 286,214,827Pension 20
176,879,947 76,812,296 100,067,651Other Postretirement 21
8,226,541 7,734,798 1,564,795 1,073,052Postemployment Costs 22
97,200 97,873254 673Deferred Independent Evaluator Fee - OR (1) 23
32,952 40,307 7,355Deferred Intervenor Funding Grants - CA 24
69,206 55,462 19,500928 5,756Deferred Intervenor Funding Grants - ID (2) 25
585,536 802,926 217,390Deferred Intervenor Funding Grants - OR 26
257,230 257,230BPA Balancing Account - ID 27
1,395,997 1,461,568 48,581930.2 114,152Generating Plant Liquidated Damages - WY 28
700,000 700,000Generating Plant Liquidated Damages - UT 29
9,000,000 6,000,000 3,000,000Chehalis Generating Facility Deferral - WA (6) 30
193,631 182,578 24,838407.3 13,785Powerdale Decommissioning - ID (10) 31
354,912 70,982 283,930407.3Powerdale Decommissioning - WA (3) 32
2,751,487 4,105,556 2,179,249 3,533,318Solar Feed-In Tariff Deferral - OR (1) 33
127,813 2 127,811410.1,283Tax Adj on Postretirement Benefits - CA (3) 34
409,994 204,997 204,997410.1,283Tax Adj on Postretirement Benefits - ID (4) 35
4,471,643 3,577,313 894,330410.1,283Tax Adj on Postretirement Benefits - OR (5) 36
2,749,250 1,178,250 1,571,000410.1,283Tax Adj on Postretirement Benefits - UT (4) 37
1,118,269 559,135 559,134410.1,283Tax Adj on Postretirement Benefits - WY (4) 38
169,233 184,683 436,551501 452,001Deferred Overburden Cost - ID 39
466,888 493,553 1,178,554501 1,205,219Deferred Overburden Cost - WY 40
102,043 102,043Naughton Unit No. 3 Environmental Costs - CA 41
478,988 478,988Naughton Unit No. 3 Environmental Costs - ID 42
34,709,389 32,014,114 4,483,442404 1,788,167Klamath Hydroelectric Relicensing Costs - UT (10) 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
/ /
2013/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)
7,099,190 7,099,190Greenhouse Gas Allowance Compliance Costs - CA 1
180,906 180,906Renewable Portfolio Standards Compliance - OR 2
6,945 111,185588 118,130Schedule 94-Distribution Safety Surcharge - OR 3
275,610 275,610Excess Gain on Sale of Assets in Rates - OR 4
614,814 886,570 248,471925 520,227Injuries & Damage Reserve - OR 5
3,107,756 5,277,349924 2,169,593Property Insurance Reserve - OR 6
702,183 702,183Property Insurance Reserve - WY 7
62,655 62,655Misc. Regulatory Assets/Liabilities - OR 8
248,555 248,555Renewable Energy Credit Sales Deferral - OR 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
1,821,244,610TOTAL :44 1,373,975,244 580,353,241 133,083,875
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232.1
Schedule Page: 232 Line No.: 5 Column: a
Weighted average remaining life is 33 years. Amounts primarily represent income tax
benefits related to certain property-related basis differences and other various items
that PacifiCorp is required to pass on to its customers.
Schedule Page: 232 Line No.: 6 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 232 Line No.: 8 Column: a
Weighted average remaining life is 2 years for deferred excess net power cost mechanisms
being amortized.
Schedule Page: 232 Line No.: 8 Column: d
Account 555, Purchased power
Account 431, Other interest expense
Account 182.3, Other regulatory assets
Schedule Page: 232 Line No.: 9 Column: a
Weighted average remaining life is 2 years for deferred excess net power cost mechanisms
being amortized, including Monsanto and Agrium net power cost components.
Schedule Page: 232 Line No.: 10 Column: a
Weighted average remaining life is 2 years for deferred excess net power cost mechanisms
being amortized.
Schedule Page: 232 Line No.: 10 Column: d
Account 555, Purchased power
Account 431, Other interest expense
Account 182.3, Other regulatory assets
Schedule Page: 232 Line No.: 17 Column: a
Weighted average remaining life is 8 years. Represents frozen values of contracts
previously accounted for as derivatives and recorded at fair value.
Schedule Page: 232 Line No.: 18 Column: a
Weighted average remaining life is 4 years.
Schedule Page: 232 Line No.: 20 Column: a
Weighted average remaining life is 9 years. Substantially represents amounts not yet
recognized as a component of net periodic benefit cost that are expected to be included in
rates when recognized.
Schedule Page: 232 Line No.: 20 Column: d
Pensions are associated with labor and generally charge to operations and maintenance
expense, construction work in progress and Account 228.3, Accumulated provision for
pensions and benefits.
Schedule Page: 232 Line No.: 21 Column: a
Weighted average remaining life is 9 years. Substantially represents amounts not yet
recognized as a component of net periodic benefit cost that are expected to be included in
rates when recognized.
Schedule Page: 232 Line No.: 21 Column: d
Other benefits are associated with labor and generally charge to operations and
maintenance expense, construction work in progress and Account 228.3, Accumulated
provision for pensions and benefits.
Schedule Page: 232 Line No.: 22 Column: a
Weighted average remaining life is 6 years.
Schedule Page: 232 Line No.: 22 Column: d
Other benefits are associated with labor and generally charge to operations and
maintenance expense and construction work in progress.
Schedule Page: 232 Line No.: 27 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Account 254, Other regulatory liabilities
Schedule Page: 232 Line No.: 28 Column: a
Weighted average remaining life is 30 years.
Schedule Page: 232 Line No.: 30 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 232 Line No.: 33 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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
/ /2013/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.
698,352 560,971 137,381557Joseph Settlement (21) 1
2
415,290 369,570 45,720557Lacomb Irrigation (24) 3
4
1,118,000 1,076,720 41,280557Bogus Creek (41) 5
6
Mead Phoenix Availability and 7
13,001,240 12,623,480 377,760565Transmission Charge (50) 8
9
109,604 94,130 15,474557TGS Buyout (23) 10
11
2,779,963 1,603,678 1,602,250 425,965 142Point to Point Transmission 12
13
89,765 6,905 82,860557Jim Boyd Hydro Buyout (11) 14
15
4,049,098 3,877,405 171,693557Hermiston Swap (40) 16
17
Oregon Prepaid REC Purchases 18
188,367 158,405 346,772 555for RPS Compliance 19
20
1,135,424 1,288,250 2,796,364 2,949,190 151Deferred Longwall Costs 21
22
Deferred Coal Costs - Wyodak 23
3,351,818 3,016,636 335,182151Settlement (22) 24
25
Deferred Coal Costs - Naughton 26
5,504,615 4,128,461 1,376,154151Settlement (7) 27
28
Deferred Coal Costs - Jim 29
2,916,673 2,916,673Bridger Plant 30
31
Deferred Colstrip Plant 32
925,000 625,000 300,000501Costs (5) 33
34
Deferred Royalty Reduction - 35
742,039 20,728 721,994 683 151Craig Plant 36
37
LT Lease Commissions 38
464,020 432,574 98,399 66,953 931Prepaids (10) 39
40
18,058,649 19,523,667 4,908,546 6,373,564 107Lake Side Maintenance Prepaid 41
42
9,718,670 13,717,203 3,998,533Chehalis Maintenance Prepaid 43
44
812,932 7,272,782 6,459,850Currant Creek Maint. Prepaid 45
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)
86,782,863 90,972,267
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
/ /2013/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.
804,990 649,871 155,119454Lease Incentives (10) 1
2
1,917,712 2,885,523 764,366 1,732,177 427,431Credit Agreement Costs (5) 3
4
203,282 346,216 349,156 492,090 427PCRB LOC/SBBPA Costs 5
6
145,615 259,606 98,183 212,174 427PCRB Mode Conversion Costs 7
8
754,468 673,998 80,470427'94 Series Restruct. Costs (16) 9
10
LT Prepaid IBEW 57 Pension 11
5,934,114 6,230,810 296,696Contribution 12
13
8,017,011 5,658,577 2,635,125 276,691 565,131BPA LT Transmission Prepaid 14
15
2,631,396 306,510 2,324,886557,131Emission Reduction Credits 16
17
421,569 312,267 109,302174Unamortized contract values 18
19
Sales of Electric Utility 20
61,554 276,000 90,961 305,407 102Facilities & Properties 21
22
29,689 17,336 47,025 561Other Deferred Charges 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)
86,782,863 90,972,267
Schedule Page: 233.1 Line No.: 5 Column: a
Weighted average life is 3 years.
Schedule Page: 233.1 Line No.: 7 Column: a
Weighted average life is 8 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
2013/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
/ /2013/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
98,584,009 216,807,008Employee benefits 2
76,128,093 109,033,262Derivative contracts and unamortized contract values 3
68,472,715 69,029,182State carryforwards 4
66,767,632 61,244,886Loss contingencies 5
47,989,295 45,589,770Asset retirement obligations 6
124,625,544 146,514,897Other 7
482,567,288 648,219,005TOTAL 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
482,567,288 648,219,005TOTAL (Acct 190) (Total of lines 8, 16 and 17) 18
Notes
FERC FORM NO. 1 (ED. 12-88) Page 234
Schedule Page: 234 Line No.: 7 Column: a
Description and Location Bal. at Beg. of Year Bal. at End of Year
(a) (b) (c)
Regulatory Liabilities $ 39,958,098 $ 36,289,678
Other 106,556,799 88,335,866
$146,514,897 $124,625,544
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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 STOCKS (Account 201 and 204)
PacifiCorp X
/ /2013/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
100.00 126,5335% Cumulative Preferred 12
13
3,500,000Serial Preferred, Cumulative: 14
100.007.00% Series 15
100.006.00% Series 16
16,000,000No Par Serial Preferred 17
19,626,533TOTAL PREFERRED STOCK 18
19
20
21
22
23
24
25
26
27
Authorized and Unissued Capital Stock 28
29
30
31
32
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
/ /2013/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
13
14
1,804,600 18,046 15
593,000 5,930 16
17
2,397,600 23,976 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
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.: 15 Column: d
This series of preferred stock is not redeemable.
Schedule Page: 250 Line No.: 16 Column: d
This series of preferred stock is not redeemable.
Schedule Page: 250 Line No.: 28 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, 2013, 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
2013/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
/ /2013/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
Gain 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 1,102,063,956
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, 2013.
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: a
In 2013, PacifiCorp redeemed and canceled all remaining outstanding shares of its
redeemable preferred stock at a loss. As a result, the $166,025 previously reported gain
on repurchase of certain shares of PacifiCorp’s preferred stock in 2010 was reversed in
2013 by debiting account 211, Miscellaneous paid-in capital, and crediting account 439,
Adjustments to retained 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
2013/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
/ /2013/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.
41,101,061Common Stock 1
2
Preferred Stock 3
4
5
6
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 41,101,061
Schedule Page: 254 Line No.: 3 Column: a
In 2013, PacifiCorp redeemed and canceled all remaining outstanding shares of its
redeemable preferred stock. The charge-off of the related capital stock expense was
charged to account 439, Adjustments to retained 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
2013/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
LONG-TERM DEBT (Account 221, 222, 223 and 224)
PacifiCorp X
/ /2013/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
16,203,000 8.797% Series due October 1, 2013 4
1,422,659 200,000,000 5.45% Series due September 15, 2013 5
232,000 6 D
1,442,365 200,000,000 4.95% Series due August 15, 2014 7
728,000 8 D
28,218,000 8.734% Series due October 1, 2014 9
46,946,000 8.294% Series due October 1, 2015 10
18,750,000 8.635% Series due October 1, 2016 11
19,609,000 8.470% Series due October 1, 2017 12
3,067,221 500,000,000 5.65% Series due July 15, 2018 13
905,000 14 D
2,515,793 350,000,000 5.50% Series due January 15, 2019 15
2,292,500 16 D
3,007,139 400,000,000 3.85% Series due June 15, 2021 17
744,000 18 D
2,424,350 350,000,000 2.95% Series due February 1, 2022 19
308,000 20 D
254,129 100,000,000 2.95% Series due February 1, 2022 21
-81,000 22 P
1,844,850 300,000,000 2.95% Series due June 1, 2023 23
900,000 24 D
2,874,150 300,000,000 7.70% Series due November 15, 2031 25
864,000 26 D
1,892,365 200,000,000 5.90% Series due August 15, 2034 27
722,000 28 D
2,912,021 300,000,000 5.25% Series due June 15, 2035 29
1,080,000 30 D
2,907,881 350,000,000 6.10% Series due August 1, 2036 31
1,141,000 32 D
FERC FORM NO. 1 (ED. 12-96)Page 256
33 TOTAL 7,218,221,000 77,560,057
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
/ /2013/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
101,34110/01/201304/15/199210/1/201304/15/1992 4
7,720,83309/15/201309/08/200309/15/201309/08/2003 5
6
200,000,000 9,900,00008/15/201408/24/200408/15/201408/24/2004 7
8
2,623,000 387,28710/01/201404/15/199210/01/201404/15/1992 9
8,034,000 887,79010/01/201504/15/199210/01/201504/15/1992 10
4,672,000 488,71910/01/201604/15/199210/01/201604/15/1992 11
6,131,000 598,44810/01/201704/15/199210/01/201704/15/1992 12
500,000,000 28,250,00007/15/201807/17/200807/15/201807/17/2008 13
14
350,000,000 19,250,00001/15/201901/08/200901/15/201901/08/2009 15
16
400,000,000 15,400,00006/15/202105/12/201106/15/202105/12/2011 17
18
350,000,000 10,325,00002/01/202201/06/201202/01/202201/06/2012 19
20
100,000,000 2,950,00002/01/202203/06/201202/01/202203/06/2012 21
22
300,000,000 5,039,58306/01/202306/01/201306/01/202306/03/2013 23
24
300,000,000 23,100,00011/15/203111/21/200111/15/203111/21/2001 25
26
200,000,000 11,800,00008/15/203408/24/200408/15/203408/24/2004 27
28
300,000,000 15,750,00006/15/203506/13/200506/15/203506/13/2005 29
30
350,000,000 21,350,00008/01/203608/10/200608/01/203608/10/2006 31
32
FERC FORM NO. 1 (ED. 12-96)Page 257
33 6,842,300,000 355,945,454
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
/ /2013/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
2,737,911 300,000,000 4.10% Series due February 1, 2042 9
987,000 10 D
75,827 10,000,000 8.13% Series E Medium-Term Notes due Jan. 22, 2013 11
115,202 15,000,000 8.53% Series C Medium-Term Notes due Dec. 16, 2021 12
38,400 5,000,000 8.375% Series C Medium-Term Notes due Dec. 31, 2021 13
33,243 5,000,000 8.26% Series C Medium-Term Notes due Jan. 7, 2022 14
30,594 4,000,000 8.27% Series C Medium-Term Notes due Jan. 10, 2022 15
131,471 15,000,000 8.05% Series E Medium-Term Notes due Sept. 1, 2022 16
70,118 8,000,000 8.07% Series E Medium-Term Notes due Sept. 9, 2022 17
438,238 50,000,000 8.12% Series E Medium-Term Notes due Sept. 9, 2022 18
105,177 12,000,000 8.11% Series E Medium-Term Notes due Sept. 9, 2022 19
87,648 10,000,000 8.05% Series E Medium-Term Notes due Sept. 14, 2022 20
208,198 26,000,000 8.08% Series E Medium-Term Notes due Oct. 14, 2022 21
200,190 25,000,000 8.08% Series E Medium-Term Notes due Oct. 14, 2022 22
37,914 5,000,000 8.23% Series E Medium-Term Notes due Jan. 20, 2023 23
30,331 4,000,000 8.23% Series E Medium-Term Notes due Jan. 20, 2023 24
-81,560 25 P
246,981 27,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 26
100,622 11,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 27
137,211 15,000,000 7.23% Series F Medium-Term Notes due Aug. 16, 2023 28
274,423 30,000,000 7.24% Series F Medium-Term Notes due Aug. 16, 2023 29
38,250 5,000,000 6.75% Series F Medium-Term Notes due Sept. 14, 2023 30
15,300 2,000,000 6.75% Series F Medium-Term Notes due Sept. 14, 2023 31
15,300 2,000,000 6.72% Series F Medium-Term Notes due Sept. 14, 2023 32
FERC FORM NO. 1 (ED. 12-96)Page 256.1
33 TOTAL 7,218,221,000 77,560,057
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
/ /2013/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 12,300,00002/01/204201/06/201202/01/204201/06/2012 9
10
47,42501/22/201301/20/199301/22/201301/20/1993 11
15,000,000 1,279,50012/16/202112/16/199112/16/202112/16/1991 12
5,000,000 418,75012/31/202112/31/199112/31/202112/31/1991 13
5,000,000 413,00001/07/202201/08/199201/07/202201/08/1992 14
4,000,000 330,80001/10/202201/09/199201/10/202201/09/1992 15
15,000,000 1,207,50009/01/202209/18/199209/01/202209/18/1992 16
8,000,000 645,60009/09/202209/09/199209/09/202209/09/1992 17
50,000,000 4,060,00009/09/202209/11/199209/09/202209/11/1992 18
12,000,000 973,20009/09/202209/11/199209/09/202209/11/1992 19
10,000,000 805,00009/14/202209/14/199209/14/202209/14/1992 20
26,000,000 2,100,80010/14/202210/15/199210/14/202210/15/1992 21
25,000,000 2,020,00010/14/202210/15/199210/14/202210/15/1992 22
5,000,000 411,50001/20/202301/20/199301/20/202301/20/1993 23
4,000,000 329,20001/20/202301/29/199301/20/202301/29/1993 24
25
27,000,000 1,960,20007/21/202307/22/199307/21/202307/22/1993 26
11,000,000 798,60007/21/202307/22/199307/21/202307/22/1993 27
15,000,000 1,084,50008/16/202308/16/199308/16/202308/16/1993 28
30,000,000 2,172,00008/16/202308/16/199308/16/202308/16/1993 29
5,000,000 337,50009/14/202309/14/199309/14/202309/14/1993 30
2,000,000 135,00009/14/202309/14/199309/14/202309/14/1993 31
2,000,000 134,40009/14/202309/14/199309/14/202309/14/1993 32
FERC FORM NO. 1 (ED. 12-96)Page 257.1
33 6,842,300,000 355,945,454
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
/ /2013/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.
152,326 20,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 1
121,861 16,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 2
91,396 12,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 3
904,467 100,000,000 6.71% Series G Medium-Term Notes due Jan. 15, 2026 4
66,505,979 6,563,726,000Subtotal - First Mortgage Bonds 5
6
Pollution Control Obligations - Secured by Pledged First Mortgage Bonds: 7
8
874,159 40,655,000 Poll Ctrl Rev Refunding Bonds, Moffat County, CO, Series 1994 9
510,479 21,260,000 Poll Ctrl Rev Refunding Bonds, Sweetwater County, WY, Series 1994 10
209,777 8,190,000 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1994 11
3,274,246 121,940,000 Poll Ctrl Rev Refunding Bonds, Emery County, UT, Series 1994 12
206,519 9,365,000 Poll Ctrl Rev Refunding Bonds, Carbon County, UT, Series 1994 13
422,858 15,060,000 Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1994 14
155,970 17,000,000 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1988 15
771,836 45,000,000 Poll Ctrl Rev Refunding Bonds, Lincoln Cnty, WY, Series 1991 16
122,887 15,000,000 Poll Ctrl Revenue Bonds, Sweetwater County, WY, Series 1984 17
105,000 18 D
304,824 8,500,000 Poll Ctrl Revenue Bonds, City of Forsyth, MT, Series 1986 19
132,043 5,300,000 Environ. Imprvmnt Rev Bonds, Converse County, WY, Series 1995 20
404,262 22,000,000 Environ. Imprvmnt Rev Bonds, Lincoln County, WY, Series 1995 21
7,494,860 329,270,000Subtotal Pollution Control Obligations - Secured by Pledged First Mortgage Bonds 22
23
24
Pollution Control Obligations - Unsecured 25
26
872,505 45,000,000 Poll Ctrl Rev Refndng Bonds, Emery County, UT, Series 1991 27
380,198 45,000,000 Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Series 1988 28
422,443 50,000,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Series 1988A 29
351,905 41,200,000 Poll Ctrl Rev Refndng Bonds, City of Gillette, WY, Ser. 1988 30
84,822 11,500,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988B 31
660,750 70,000,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1990A 32
FERC FORM NO. 1 (ED. 12-96)Page 256.2
33 TOTAL 7,218,221,000 77,560,057
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
/ /2013/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.
20,000,000 1,350,00010/26/202310/26/199310/26/202310/26/1993 1
16,000,000 1,080,00010/26/202310/26/199310/26/202310/26/1993 2
12,000,000 810,00010/26/202310/26/199310/26/202310/26/1993 3
100,000,000 6,710,00001/15/202601/23/199601/15/202601/23/1996 4
6,245,460,000 347,263,476 5
6
7
8
161,58105/01/201311/17/199405/01/201311/17/1994 9
21,260,000 329,54111/01/202411/17/199411/01/202411/17/1994 10
8,190,000 127,02011/01/202411/17/199411/01/202411/17/1994 11
121,940,000 1,860,95611/01/202411/17/199411/01/202411/17/1994 12
9,365,000 143,92711/01/202411/17/199411/01/202411/17/1994 13
15,060,000 248,73311/01/202411/17/199411/01/202411/17/1994 14
287,16301/01/201401/01/198801/01/201401/01/1988 15
45,000,000 617,55201/01/201601/17/199101/01/201601/17/1991 16
15,000,000 311,52312/01/201412/01/198412/01/201412/01/1984 17
18
8,500,000 180,48212/01/201612/01/198612/01/201612/01/1986 19
5,300,000 109,69711/01/202511/17/199511/01/202511/17/1995 20
22,000,000 478,21811/01/202511/17/199511/01/202511/17/1995 21
271,615,000 4,856,393 22
23
24
25
26
45,000,000 657,84907/01/201505/23/199107/01/201505/23/1991 27
45,000,000 656,53301/01/201801/01/198801/01/201801/01/1988 28
50,000,000 582,07901/01/201701/01/198801/01/201701/01/1988 29
41,200,000 430,39101/01/201801/01/198801/01/201801/01/1988 30
11,500,000 119,43901/01/201401/01/198801/01/201401/01/1988 31
70,000,000 732,27507/01/201507/25/199007/01/201507/25/1990 32
FERC FORM NO. 1 (ED. 12-96)Page 257.2
33 6,842,300,000 355,945,454
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
/ /2013/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.
167,524 9,335,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992A 1
242,163 22,485,000 Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 2
151,908 6,305,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992B 3
225,000 24,400,000 Environ. Imprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 4
5
3,559,218 325,225,000Subtotal - Pollution Control Obligations - Unsecured 6
7
8
77,560,057 7,218,221,000TOTAL ACCOUNT 221 9
10
Reacquired Bonds: (Account 222) 11
12
Advances from Associated Companies: (Account 223) 13
14
Other Long-Term Debt: (Account 224) 15
16
17
Long-Term Debt Authorized but Unissued 18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 256.3
33 TOTAL 7,218,221,000 77,560,057
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
/ /2013/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.
9,335,000 95,11212/01/202009/29/199212/01/202009/29/1992 1
22,485,000 223,99712/01/202009/29/199212/01/202009/29/1992 2
6,305,000 65,41512/01/202009/29/199212/01/202009/29/1992 3
24,400,000 262,49511/01/202512/14/199511/01/202512/14/1995 4
5
325,225,000 3,825,585 6
7
8
6,842,300,000 355,945,454 9
10
11
12
13
14
15
16
17
18
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 6,842,300,000 355,945,454
Schedule Page: 256 Line No.: 23 Column: a
In June 2013, PacifiCorp issued $300 million of 2.95% First Mortgage Bonds due June 2023.
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: 256.2 Line No.: 15 Column: a
In June 2013, PacifiCorp redeemed the Pollution Control Revenue Refunding Bonds, Converse
County, WY, Series 1988, and transferred the associated unamortized debt expense to
Account 189, Unamortized loss on reacquired debt.
Schedule Page: 256.3 Line No.: 9 Column: h
Refer to Important Changes During the Quarter/Year, Item 6, and Notes to Financial
Statements, Note 7, in this Form No. 1 for a discussion of PacifiCorp's long-term debt.
Schedule Page: 256.3 Line No.: 9 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.: 18 Column: a
In November 2013, 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 October 2016.
For authorization for the issuance of long-term debt ($2.0 billion authorized; $550
million available as of December 31, 2013), refer to Important Changes During the
Quarter/Year, Item 6, in 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, 2013) 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,
2013) 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
2013/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
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
PacifiCorp X
/ /2013/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.
682,163,330Net Income for the Year (Page 117) 1
2
3
Taxable Income Not Reported on Books 4
5
6
7
79,300,662Other 8
Deductions Recorded on Books Not Deducted for Return 9
10
11
12
1,221,784,029Other 13
Income Recorded on Books Not Included in Return 14
15
16
17
85,304,455Other 18
Deductions on Return Not Charged Against Book Income 19
20
21
22
23
24
1,485,136,624Other 25
-15,444,967State Tax Deductions 26
397,361,975Federal Tax Net Income 27
Show Computation of Tax: 28
29
139,076,690Federal Income Tax at 35.00% 30
2,627,525Provision to Return Adjustment 31
29,841Tax Reserve Changes 32
-69,527,495Renewable Energy Production Tax Credits 33
-220,516Other Federal Tax Credits 34
-39,032Other Miscellaneous Adjustments 35
36
71,947,013Federal Income Tax Accrual 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
Contribution in Aid of Construction 48,806,340
Regulatory Asset - BPA Balancing Account - ID 257,229
Reimbursements 1,902,055
Regulatory Liability - Alt Rate for Energy Program (CARE) - CA - Current 896,054
Regulatory Liability - BPA Balancing Account - ID 922,145
Regulatory Liability - GHG Allowance Revenues - CA - Current 9,106,055
Regulatory Liability - Sale of REC - UT - Current 1,521,547
Regulatory Liability - Sale of REC - WA - Current 14,121,277
Regulatory Liability - UT Home Energy Lifeline 998,055
Regulatory Liability - WA Low Energy Program 315,383
Trapper Mining Stock Basis 266,976
Unearned Joint Use Pole Contact Revenue 187,546
Total $ 79,300,662
Schedule Page: 261 Line No.: 13 Column: a
Particulars (Details) Amounts
Fed/State Tax Expense 287,955,389
Fed/State Tax Expense-Interest 1,187,488
50% Meals and Entertainment 864,737
Accrued Final Reclamation 247,461
Accrued Royalties 1,119
Avoided Costs 51,869,123
Bear River Settlement Agreement 274,325
Book Cost Depletion 1,581,526
Book Depreciation 674,122,571
Book Depreciation Allocated to Medicare and M&E 56,215
Book Fixed Asset Gain/Loss 10,743
Coal Pile Inventory Adjustment 1,215,354
Deferred Coal Costs - Naughton Contract Settlement 1,376,154
Deferred Compensation - Non Current 1,004,858
Deferred Revenue - Citibank 88,577
Deseret Settlement Receivable 652,544
Environmental Liability - Regulated 2,281,625
ERC Impairment Reserve 2,040,000
FAS 112 Book Reserve - Postemployment Benefits 341,049
Fuel Cost Adjustment 1,250,360
Hermiston Swap 171,693
Hydro Relicensing Obligation 1,298,969
Income Tax Interest 113,960
Injuries and Damages Accrual - Cash Basis 18,188,871
Joseph Settlement 137,381
Lewis River Settlement Agreement 93,452
Lobbying Expenses 2,045,817
Medicare Subsidy 3,927,059
MEHC Insurance Services - Receivable 129,380
Mine Rescue Training Credit Addback 50,735
Penalties 2,279,737
Prepaid Membership Fees 1,890,373
Prepaid Taxes - OR PUC 4,126
Regulatory Asset - Chehalis Generating Facility Deferral - WA 3,000,000
Regulatory Asset - Cholla Plant Transaction Costs 1,122,425
Regulatory Asset - Deferred Excess NPC - CA - Noncurrent 94,422
Regulatory Asset - Deferred Excess NPC - ID - Noncurrent 12,628,376
Regulatory Asset - Deferred Excess NPC - UT - Noncurrent 16,542,262
Regulatory Asset - Deferred Excess NPC - WY '09 & After - Noncurrent 20,806,366
Regulatory Asset - Deferred Independent Evaluator Fee - UT 9,363
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Regulatory Asset - Deferred Independent Evaluator Fees - OR 97,202
Regulatory Asset - Deferred Intervenor Funding Grants - ID 13,744
Regulatory Asset - Demand Side Management - Current 1,530,180
Regulatory Asset - DSM Balance Reclass 697,970
Regulatory Asset - Environmental Costs - WA 161,748
Regulatory Asset - FAS 158 Pension Liability 48,029,981
Regulatory Asset - FAS 158 Post Retirement Liability 7,923,283
Regulatory Asset - Goodnoe Hills Settlement - WY 21,250
Regulatory Asset - Klamath Hydroelectric Relicensing Costs - UT 2,695,276
Regulatory Asset - Lake Side Settlement - WY 27,331
Regulatory Asset - Naughton Unit #3 Costs 2,776,067
Regulatory Asset - Naughton Unit #3 Costs - UT 1,808,124
Regulatory Asset - Naughton Unit #3 Costs - WY 557,823
Regulatory Asset - OR Asset Sale Gain GB - Noncurrent 6,945
Regulatory Asset - Pension MMT - UT 283,176
Regulatory Asset - Post Employment Costs 491,743
Regulatory Asset - Post Merger Loss - Reacquired Debt 1,412,851
Regulatory Asset - Post-Ret MMT - CA 17,488
Regulatory Asset - Post-Ret MMT - OR 193,035
Regulatory Asset - Post-Ret MMT - UT 278,648
Regulatory Asset - Powerdale Decommissioning - ID 11,053
Regulatory Asset - Powerdale Decommissioning - WA 283,929
Regulatory Asset - Solar Feed-In Tariff Deferral - OR - Noncurrent 1,945,266
Regulatory Asset - Tax Revenue Requirement Adj - WY 30,857
Regulatory Asset - Utah ECAM 20,649,532
Regulatory Asset - WA Colstrip #3 52,188
Regulatory Liability - Blue Sky - ID 35,703
Regulatory Liability - Blue Sky - OR 93,856
Regulatory Liability - Blue Sky - UT 204,757
Regulatory Liability - Blue Sky - WA 116,538
Regulatory Liability - Blue Sky - WY 57,608
Regulatory Liability - Deferred Excess NPC - OR - Current 2,273,466
Regulatory Liability - Deferred Excess NPC - WA - Current 112,448
Regulatory Liability - OR Energy Conservation Charge 743,447
Regulatory Liability - Property Insurance Reserve - ID 113,544
Regulatory Liability - Property Insurance Reserve - OR 3,553,271
Regulatory Liability - Property Insurance Reserve - UT 1,750,403
Regulatory Liability - Solar Feed-in Tariff Deferral - CA - Current 123,782
Regulatory Liability - Solar Incentive Program - UT - Current 5,982,150
Regulatory Liability - Trojan Decommissioning 492,373
TGS Buyout 15,474
Western Coal Carrier Retiree Medical Accrual 738,000
Intercompany adjustment 424,534
Total $ 1,221,784,029
Schedule Page: 261 Line No.: 18 Column: a
Particulars (Details) Amounts
Deferred Revenue - Lease Incentives (28,089)
Dividend Received Deduction - Deferred Compensation (107,511)
Foote Creek Contract (137,640)
MCI F.O.G. Wire Lease (324)
Officer's Life Insurance (4,204,253)
Regulatory Asset - Alt Rate for Energy Program (CARE) - CA - Current (621,982)
Regulatory Asset - REC Sales Deferral - OR - Current (414,385)
Regulatory Asset - REC Sales Deferral - OR - Noncurrent (15,076)
Regulatory Asset - REC Sales Deferral - UT - Current (3,138,483)
Regulatory Asset - REC Sales Deferral - UT - Noncurrent (15,755,935)
Regulatory Asset - REC Sales Deferral - WY - Current (3,668,887)
Regulatory Asset - REC Sales Deferral - WY - Noncurrent (321,406)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Redding Contract (549,996)
Regulatory Liability - 2010 Protocol Deferral - OR (222,076)
Regulatory Liability - BPA Balancing Account - OR (1,580,712)
Regulatory Liability - BPA Balancing Account - WA (916,135)
Regulatory Liability - Gain on Sale of Assets - OR - Current (35,161)
Regulatory Liability - GHG Allowance Revenues - CA - Noncurrent (2,434,344)
Regulatory Liability - OR 2012 GRC Giveback - Noncurrent (16,236,420)
Regulatory Liability - Powerdale Decommissioning Costs Giveback - UT (180,277)
Regulatory Liability - Sale of REC - OR - Noncurrent (606,954)
Regulatory Liability - Sale of REC - UT - Noncurrent (2,474,146)
Regulatory Liability - Sale of REC - WA - Noncurrent (14,509,138)
Regulatory Liability - SMUD Revenue Imputation - UT (2,291,714)
Regulatory Liability - Tax Revenue Requirement Adj - UT (61,695)
Transmission Service Deposit (700,211)
Unrealized Gain/Loss from Trading Securities (694,102)
Equity Earnings in Subsidiaries (13,397,403)
Total $ (85,304,455)
Schedule Page: 261 Line No.: 25 Column: a
Particulars (Details) Amounts
Accrued Bonus (91,402)
Accrued Severance (86,701)
Accrued Vacation (1,422,118)
Amortization NOPAs 99-00 RAR (52,712)
Basis Intangible Difference (92,988)
Capitalized Depreciation (5,833,974)
Capitalized labor and benefit costs (9,133,607)
Cholla SHL NOPA (Lease Amortization) (136,961)
Coal Mine Extension Costs (1,252,369)
Cost of Removal (42,756,350)
CWIP Reserve (9,160)
Debt AFUDC (29,227,220)
Environmental Liability - Non-regulated (2,777,126)
Equity AFUDC-Temp (57,182,510)
FAS 158 Pension Liability (22,082,107)
FAS 158 Post-Retirement Liability (963,166)
FAS 158 SERP Liability (973,735)
Federal Tax Depreciation (1,090,720,929)
Federal Tax Fixed Asset Gain/Loss (2,578,728)
Inventory Reserve (306,204)
LT Prepaid IBEW 57 Pension Contribution (296,696)
Mine Safety Sec. 179E Election (110,218)
Miscellaneous Current and Accrued Liability (537,384)
N Umpqua Settlement Agreement (9,336)
Non-deductible Post-Retirement Costs (3,927,059)
Oregon RA/RL Consolidation (345,410)
Other Environmental Liabilities (484)
Pension/Retirement Accrual (196,213)
Pre-1943 Preferred Stock Dividend - Deduction (353,861)
Prepaid Aircraft Maintenance (97,347)
Prepaid Taxes - ID PUC (24,695)
Prepaid Taxes - Property Taxes (1,693,070)
Prepaid Taxes - UT PUC (402,884)
Regulatory Asset - Cholla Plant Transaction Costs - ID (32,973)
Regulatory Asset - Cholla Plant Transaction Costs - OR (53,813)
Regulatory Asset - Cholla Plant Transaction Costs - WA (97,006)
Regulatory Asset - Contra Pension MMT & CTG - CA (91,920)
Regulatory Asset - Contra Pension MMT & CTG - OR (1,014,634)
Regulatory Asset - Deferred Excess NPC - CA - Current (2,195,233)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Regulatory Asset - Deferred Excess NPC - ID - Current (14,012,780)
Regulatory Asset - Deferred Excess NPC - UT - Current (35,289,259)
Regulatory Asset - Deferred Excess NPC - WA Hydro - Noncurrent (103,750)
Regulatory Asset - Deferred Excess NPC - WY - Current (23,166,651)
Regulatory Asset - Deferred Intervenor Funding Grants - CA (7,355)
Regulatory Asset - Deferred Intervenor Funding Grants - OR (217,391)
Regulatory Asset - Deferred Overburden Costs - ID (15,450)
Regulatory Asset - Deferred Overburden Costs - WY (26,665)
Regulatory Asset - Demand Side Management - Noncurrent (697,970)
Regulatory Asset - Environmental Costs (4,688,608)
Regulatory Asset - GHG Allowances - CA - Current (7,099,190)
Regulatory Asset - GHG Allowances - CA - Noncurrent (3)
Regulatory Asset - Liquidation Damages - N2 - WY (114,152)
Regulatory Asset - Naughton Unit #3 Costs - CA (102,043)
Regulatory Asset - Naughton Unit #3 Costs - OR - Contra (2,044,913)
Regulatory Asset - Naughton Unit #3 Costs - WA - Contra (629,111)
Regulatory Asset - OR Asset Sale Gain GB - Current (282,555)
Regulatory Asset - OR Sch94 Distribution Safety Surcharge (6,945)
Regulatory Asset - Powerdale Decommissioning (164,704)
Regulatory Asset - SB 408 - OR (11,834)
Regulatory Asset - Solar Feed-In Tariff Deferral - CA - Noncurrent (354,070)
Regulatory Asset - Solar Feed-in Tariff Deferral - OR - Current (3,299,335)
Regulatory Asset - Solar Incentive Program - UT - Noncurrent (867,044)
Regulatory Asset - UT Liquidation Damages (700,000)
Repairs Deduction (100,764,600)
Reserve for Bad Debts (1,865,600)
Regulatory Liability - ARO/Reg Diff - Trojan - WA Portion (285,034)
Regulatory Liability - Blue Sky - CA (9,224)
Regulatory Liability - Demand Side Management - Current (2,228,150)
Regulatory Liability - Injuries & Damages Reserve - OR (271,755)
Regulatory Liability - Property Insurance Reserve - WY (1,323,754)
Rogue River - Habitat Enhancement Liability (8,303)
RTO Grid West N/R - OR (6,035)
Tax Depletion-SRC (172,440)
Tax Percentage Depletion - Blundell Steam Field (475,313)
Tax Percentage Depletion - Deer Creek (837,121)
USA Power Litigation (3,636,564)
Wasatch Workers Comp Reserve (190,650)
Total $ (1,485,136,624)
Schedule Page: 261 Line No.: 37 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
MEHC Sub-Group:
Alaska Gas Transmission Company, LLC
American Pacific Finance Company
American Pacific Finance Company II
Arizona HomeServices, LLC
AVSP 1B, LLC
AVSP 2B, 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
CalEnergy International, Inc
CalEnergy Minerals Development, LLC
CalEnergy Minerals LLC
CalEnergy Pacific Holdings Corp
CalEnergy UK Inc
Capitol Title Company
CBSHome Commerical, 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
Champion Realty, Inc
Chancellor Title Services, Inc
Cimmred Leasing Company
Columbia Title of Florida, Inc
Commonsite, 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Employee Transfer Corporation
Esslinger-Wooten-Maxwell, Inc
E-W-M Referral Services, Inc.
F&R/T LLC
FFR, Inc
First Realty, Ltd
First Reserve Insurance, Inc
For Rent, Inc
FRTC, LLC
GPSF-B
Guarantee Appraisal Corporation
Guarantee Real Estate
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 Northeast, LLC
HomeServices of Alabama, Inc.
HomeServices of America, Inc
HomeServices of California, Inc
HomeServices of Connecticut, LLC
HomeServices of Florida, Inc
HomeServices of Georgia, 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 Referral Network, LLC
HomeServices Relocation, LLC
HomeSvc of IL LLC d/b/a Koenig & Strey GMAC RE
HS Franchise Holding, LLC
HSGA Real Estate Group, L.L.C.
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
KR Acquisition 1, LLC
KR Acquisition 2, LLC
KR Holding, LLC
Lands of Sierra, Inc.
Larabee School of Real Estate & Insurance, Inc
M & M Ranch Acquisition Company LLC
M & M Ranch Holding Company 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
MEC Construction Services Company
MEHC American 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
MidAmerican Wind, LLC
Midland Escrow Services, Inc
Midwest Capital Group, Inc
Midwest Power Transmission Illinois LLC
Midwest Power Transmission Iowa LLC
Midwest Realty Ventures, LLC
MWR Capital, Inc
Nebraska Land Title & Abstract Company
Nebraska Referral, Inc.
Nevada Electric Investment Company
Nevada Power Company dba NV Energy
NMA, LLC
NNGC Acquisition LLC
Northern Aurora Inc
Northern Natural Gas Company
NRS Referral Services, LLC
NV Energy, Inc. fka Sierra Pacific Resources
NVE Holdings, LLC
NVE Insurance Co, Inc.
NW Referral Services, LLC
PCRE, L.L.C.
PFR Staffers, LLC
Pickford Escrow Company, Inc
Pickford Holdings, LLC
Pickford Real Estate, Inc
Pickford Services Company, Inc
Pilot Butte, LLC
Pinon Pine Corporation
Pinon Pine Investment Company
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
PPW Staffers, LLC
Preferred Carolinas Realty, Inc
Preferred Carolinas Title Agency, 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
Professional Referral Organization, Inc
PW Fox Holding LLC
PW Fox, LLC
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 Associates of Georgia, LLC
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
Rubloff Insurance Agency LLC
Salton Sea Minerals Corporation
San Diego PCRE, Inc
Semonin Realtors, Inc
Sierra Gas Holding Company
Sierra Pacific Power Company dba NV Energy
Solar Star 3, LLC
Solar Star California XIX, LLC
Solar Star California XX, LLC
Solar Star Funding, LLC
Solar Star Projects Holdings, LLC
Southwest Relocation, LLC
SSC XIX, LLC
SSC XX, LLC
Sterling Title Services, LLC
The Escrow Firm
The Referral Company
TIAC LLC
TitleSouth, LLC
TLTC LLC
Topaz Solar Farms, LLC
TPZ Holding, LLC
TRMC 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
21 SPC, Inc.
21st Communities, Inc.
21st Mortgage Corporation
Accurate Installations, Inc.
Ace Mailing Services, Inc.
Acme Brick Company
Acme Brick DFW, 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
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.
AJF Warehouse Distributors, Inc.
AL/TEX Homes, Inc.
Albacor Shipping (USA) Inc.
Albecca, Inc.
Alexander Road Insurance Agency, Inc.
Alexander-Otto Company, LLC
All Bilt Uniforms
Alpha Cargo Motor Express, Inc
Amarillo Gear, 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.
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.
Bayport Systems, Inc.
Ben Bridge Jeweler, Inc.
Benjamin Moore & Co.
Benson Industries, Inc.
Benson, Ltd.
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 Nebraska
Berkshire Indemnity Group Inc.
BH Columbia Inc.
BH Finance, Inc.
BH Media Group Holdings, Inc.
BH Media Group, 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
BH Shoe Holdings, Inc.
BH, LLC
BHG Life Insurance Company
BHG Structured Settlements, Inc.
BHSF, Inc.
Blue Chip Stamps, Inc.
BN Leasing Corporation
BNJ NetJets, Inc.
BNSF Communications, Inc.
BNSF Logistics International, Inc.
BNSF Railway Company
BNSF Railway International Services, Inc.
BNSF Spectrum, Inc.
Boat America Corporation
Boat Owners Association of the United States
Boat/U.S, Inc.
Boot Royalty Company
Borsheim Jewelry Company, Inc
BR Agency, Inc.
Brainy Toys, Inc.
Brick Acquisition Company
Brilliant National Services, Inc.
Brooks Sports, Inc.
Brookwood Insurance Company
Burlington Northern Railroad Holdings, Inc.
Burlington Northern Santa Fe British Columbia, Ltd.
Burlington Northern Santa Fe Insurance Company, Ltd.
Burlington Northern Santa Fe Manitoba, Inc.
Burlington Northern Santa Fe, LLC
Business Wire, Inc.
C & R Insurance Services, Inc.
C & R Legal Insurance Agency, LLC
California Insurance Company
Camp Manufacturing Company
Campbell Hausfeld/Scott Fetzer Company
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.
Chatwell, Inc.
Chemtool Incorporated
Chippewa Shoe Company
CJE II
Claims Services, Inc.
CLAL U.S. Holdings, Inc.
Clayton Commercial Buildings, Inc.
Clayton Education Corp.
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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
CMH Set and Finish, Inc.
CMH Transport, Inc.
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
Cort Business Services Corporation
Coverage Dynamics Group, 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 Midwest
CTB MN Investments
Cubic Designs, Inc.
Cumberland Asset Management, Inc.
Cypress Insurance Company
Dairy Queen Corporate Stores, Inc.
Dairy Queen Of Georgia, Inc.
Delta Wholesale Liquors, Inc.
Denver Brick Company
Diversified Mailing, Inc.
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.
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.
FlightSafety New York, 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.11
FlightSafety Properties, Inc.
FlightSafety Services Corporation
Floors, Inc.
Fontaine Commercial Trailer, Inc.
Fontaine Engineered Products, Inc.
Fontaine Fifth Wheel Company
Fontaine Modification Company
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 Manufacturing LLC
Forest River, Inc.
France/Scott Fetzer Company
Freedom Warehouse Corp.
FreightWise, 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
Fun Express LLC
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.12
GRD Holdings Corporation
Great Plains Uniforms
Griffey Uniforms
GUARD Financial Group, Inc.
GUARD Insurance Group, Inc.
GUARDco, Inc.
H. H. Brown Shoe Company, Inc.
H.J. Justin & Sons, Inc.
Halex/Scott Fetzer Company
Hallmark Sweet, Inc.
Hardy Frames, Inc.
Harris Uniforms
Hawthorn Life International Limited
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
J.L. Mining Company
J.S Justin, Inc.
JDS Properties, Inc.
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.
Kansas Bankers Surety Company
Karmelkorn Shoppes, Inc.
Kova Solutions, Inc.
L.A. Terminals, Inc.
LEE Distributing Services, 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.
Lubrizol Advanced Materials FCC, 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.13
Lubrizol Advanced Materials Gibraltar, Inc.
Lubrizol Advanced Materials Holding Corporation
Lubrizol Advanced Materials International, Inc.
Lubrizol Advanced Materials, Inc.
Lubrizol Enterprises, Inc.
Lubrizol Inter-Americas Corporation
Lubrizol International Management Corporation
Lubrizol Overseas Trading Corporation
LZ Holding Corporation
M W Wholesale, Inc.
Mail Tech, LTD.
Mapletree Transportation, Inc.
Marathon Suspension Systems, Inc.
Marmon Crane Services, Inc.
Marmon Distribution Services, Inc.
Marmon Electrical & Plumbing Products Distribution, Inc.
Marmon Engineered Industrial & Metal Components, Inc.
Marmon Holdings, Inc.
Marmon Natural Resource & Transportation Service
Marmon Retail & End User Technologies, Inc.
Marmon Retail Home Improvement Products, 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
Meyn LLC
Midlands Newspapers, Inc.
Midwest Northwest Properties, Inc.
Miller-Sage, Inc.
Mindware Corporation
MiTek Holdings, Inc.
MiTek Industries, Inc.
MiTek USA, 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.14
Mobile Disaster Structures, Inc
Montana Retail Properties, Inc.
Morgantown-National Supply, Inc.
Mount Vernon Fire Insurance Company
Mount Vernon Specialty 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 Sales, Inc.
NetJets Services, Inc.
NetJets U.S., Inc.
NFM of Kansas, Inc.
NFM SERVICES, LLC
Nick Bloom Uniforms
NJE Holdings, LLC
NJI Sales, 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
Oriental Trading Company, Inc.
OTC Brands, Inc.
OTC Direct, Inc.
OTC Worldwide Holdings, Inc.
Penn Coal Land, Inc.
Penn Pocahontas Coal Co.
Pennsylvania Insurance Company
Perfection Hy-Test Company
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.
Procrane Holdings, 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.15
Professional Datasolutions, Inc.
Promesa Health, Inc.
Queen Carpet Corporation
R.C. Willey Home Furnishings
Rabun Apparel, Inc.
Railserve, Inc.
Railsplitter Holdings Corporation
Ray-Q, Inc
RCP Investment, Inc.
Redwood Fire and Casualty Insurance Company
RENTCO Trailer Corporation
Resolute Management Inc.
Richline Group, Inc
Ringwalt & Liesche Co.
Rio Grande, Inc.
Roberts Men's Shop
Roxell USA, Inc. (fka Agile Manufacturing Inc.)
Royal Cargo Lines
Running with Heels, Inc.
Rush Air Inc
Russell Athletic Corporation
Sager Electrical Supply Co. Inc
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
Soco West, Inc.
Sol Frank Uniforms Inc.
Somerset Services, Inc
Southern Energy Homes, Inc.
Spectra Contract Flooring Puerto Rico, Inc.
SSS Acquisition Inc.
Stahl/Scott Fetzer Company
Star Furniture Company
Star Lake Railroad Company
Stern/Leach 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.16
Stonewall Insurance Company
Strategic Staff Management, Inc.
The Ben Bridge Corporation
The BN and SF Railway de Mexico, S.A. de C.V.
The Buffalo News, Inc.
The BVD Licensing Corporation
The Eagle Company
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 Climate Solutions, 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.
UCFS Europe Company
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
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.17
Wells Lamont Retail, Inc.
Wesco-Financial Insurance Company
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
World Investments, Inc.
World Marketing, Inc.
World Publishing Enterprises, Inc.
World Technologies, Inc.
Worldwide Containers, Inc.
X-L-Co., Inc.
XTRA Companies, Inc.
XTRA Corporation
XTRA Finance Corporation
XTRA Intermodal, Inc.
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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.18
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2013/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
108,946,084 -39,032 71,947,013 51,241,091 Income 2
35,747,579 35,953,995 2,832 431,843 FICA 3
245,288 245,558 4,331 Unemployment 4
2,934,284 2,956,843 78,805 Excise Tax - Coal 5
147,873,235 -39,032 111,103,409 2,832 51,756,070Subtotal 6
7
State: 8
9
Arizona: 10
3,046,495 3,238,051 1,427,469 Property 11
10,883 421,083 205,430 Income 12
3,057,378 3,659,134 1,632,899Subtotal 13
14
California: 15
2,196,241 2,196,241 Property 16
32,321 33,392 45 165 Unemployment 17
1,503,354 1,290,834 -138,123 Franchise-Income 18
112,206 111,578 13,338 Use 19
1,192,363 1,202,546 1,255,286 Local Franchise 20
5,036,485 4,834,591 45 1,130,666Subtotal 21
22
Colorado: 23
1,912,995 2,062,995 1,910,000 Property 24
2,127 6,236 2,127 Income 25
1,915,122 2,069,231 1,912,127Subtotal 26
27
Idaho: 28
4,824,971 5,036,393 3,140,042 Property 29
1,534,354 111,495 1,538,365 71,204 Income 30
23,193 35,280 3,000 KWh 31
75,035 75,415 1,456 Unemployment 32
163,681 169,280 15,268 Use 33
6,621,234 111,495 6,854,733 3,230,970Subtotal 34
35
Montana: 36
3,762,893 3,954,501 1,776,118 Property 37
110,634 119,019 2,584 Corporate License-Income 38
1,239 1,239 Unemployment 39
205,637 185,637 60,000 Energy License 40
12,036,297
FERC FORM NO. 1 (ED. 12-96)Page 262
TOTAL41 319,034,603 352,859,192 72,463 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 (Continued)
PacifiCorp X
/ /2013/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
-2,396,204 74,343,217 14,281,052 2
35,953,995 10,234 645,661 3
245,558 4,601 4
2,956,843 101,364 5
36,760,192 74,343,217 10,234 15,032,678 6
7
8
9
10
3,238,051 1,619,025 11
-8,712 429,795 615,630 12
-8,712 3,667,846 2,234,655 13
14
15
118,697 2,077,544 16
33,392 45 1,236 17
-16,408 1,307,242 -350,643 18
111,578 12,710 19
1,202,546 1,265,469 20
247,259 4,587,332 45 928,772 21
22
23
93,579 1,969,416 2,060,000 24
-102 6,338 6,236 25
93,477 1,975,754 2,066,236 26
27
28
85,222 4,951,171 3,351,464 29
-21,193 1,559,558 -36,280 30
35,280 15,087 31
75,415 1,836 32
169,280 20,867 33
308,724 6,546,009 3,352,974 34
35
36
3,954,501 1,967,726 37
-1,951 120,970 10,969 38
1,239 39
185,637 40,000 40
FERC FORM NO. 1 (ED. 12-96)Page 263
41 12,025,243 259,757,744 59,276,859 53,535,702
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
/ /2013/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.
146,521 133,899 42,622 Wholesale Energy 1
4,226,924 4,394,295 1,881,324Subtotal 2
3
Nebraska: 4
357 357 Unemployment 5
357 357Subtotal 6
7
New Mexico: 8
6,628 6,628 Property 9
2,003 77,075 1,953 Income 10
8,631 83,703 1,953Subtotal 11
12
Oregon: 13
23,027,833 23,103,236 11,615,331 Property 14
1,601,673 1,619,781 4,418 36,861 Unemployment 15
2,162 2,263 675 Wilsonville Payroll 16
4,055,153 3,917,378 84,059 Excise-Income 17
-50,960 -42,767 6,938 City of Portland-Income 18
-92,193 -93,691 1,498 Multnomah County 19
949,852 888,597 413,671 Department of Energy 20
962,461 992,323 381,339 Tri-Met 21
2,169 2,169 Lane County 22
27,366,391 27,490,971 4,402,214 Franchise 23
57,824,541 57,880,260 12,033,420 4,913,584Subtotal 24
25
Utah: 26
67,939,917 68,725,315 -81,186 Property 27
7,918,672 8,234,382 173,814 Income 28
387,215 388,511 4,629 Unemployment 29
934 934 Navajo Nation 30
3,168,614 3,291,390 286,472 Use 31
79,415,352 80,640,532 383,729Subtotal 32
33
Washington: 34
9,730,861 10,420,861 9,400,000 Property 35
72,596 73,134 2,025 Unemployment 36
32,540 32,684 3,513 Business & Occupation 37
13,164,318 13,264,318 1,100,000 Public Utility 38
2,157,675 2,237,933 44,658 Natural Gas Use Tax 39
1,137,421 584,382 610,675 Use 40
12,036,297
FERC FORM NO. 1 (ED. 12-96)Page 262.1
TOTAL41 319,034,603 352,859,192 72,463 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 (Continued)
PacifiCorp X
/ /2013/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.
133,899 30,000 1
-712 4,395,007 2,048,695 2
3
4
357 5
357 6
7
8
6,628 9
-1,262 78,337 77,025 10
-1,262 84,965 77,025 11
12
13
284,446 22,818,790 11,539,928 14
1,619,781 110 50,661 15
2,263 776 16
-138,358 4,055,736 -53,716 17
-2,557 -40,210 15,131 18
-93,691 19
888,597 474,926 20
992,323 411,201 21
2,169 22
27,490,971 4,526,794 23
2,760,067 55,120,193 12,014,964 4,950,847 24
25
26
10,018,513 58,706,802 704,212 27
-135,060 8,369,442 489,524 28
388,511 5,925 29
934 30
3,291,390 409,248 31
13,563,354 67,077,178 1,608,909 32
33
34
377,238 10,043,623 10,090,000 35
73,134 2,563 36
32,684 3,657 37
13,264,318 1,200,000 38
2,237,933 124,916 39
584,382 57,636 40
FERC FORM NO. 1 (ED. 12-96)Page 263.1
41 12,025,243 259,757,744 59,276,859 53,535,702
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
/ /2013/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.
26,295,411 26,613,312 11,160,871Subtotal 1
2
Wyoming: 3
14,971,702 14,918,164 7,512,619 Property 4
1,373,012 1,813,575 1,390,284 Wind generation tax 5
421,401 423,245 8,597 Unemployment 6
1,910,374 1,886,074 307,400 Franchise 7
1,430,850 1,408,591 155,221 Use 8
70,239 70,239 Annual Report 9
20,177,578 20,519,888 9,374,121Subtotal 10
11
-26,173 46,685State Other 12
13
Miscellaneous: 14
23,082 23,082 Goshute Possessory 15
183,560 183,560 Sho-Ban Possessory 16
38,004 38,391 18,809 Navajo Possessory 17
29,220 29,220 Ute Possessory 18
67,500 67,500 Crow Possessory 19
65,578 65,578 Umatilla Possessory 20
406,944 381,158 65,494Subtotal 21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
12,036,297
FERC FORM NO. 1 (ED. 12-96)Page 262.2
TOTAL41 319,034,603 352,859,192 72,463 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 (Continued)
PacifiCorp X
/ /2013/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.
3,272,687 23,340,625 11,478,772 1
2
3
449,592 14,468,572 7,459,081 4
1,813,575 1,830,847 5
423,245 10,441 6
1,886,074 283,100 7
1,408,591 132,962 8
70,239 9
2,281,428 18,238,460 9,716,431 10
11
-26,173 20,512 12
13
14
23,082 15
183,560 16
38,391 19,196 17
29,220 18
67,500 19
65,578 20
381,158 39,708 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 12,025,243 259,757,744 59,276,859 53,535,702
Schedule Page: 262 Line No.: 2 Column: f
$ (39,024) Account 255, Accumulated Deferred Investment Tax Credits (1)
(8) Other
$ (39,032)

(1) Represents the federal impact of the adjustment discussed in footnote (4) of the
footnote to line 7 column b of page 266, Accumulated deferred investment tax credits, in
this Form No. 1.
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
Account 151, Fuel stock
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
$110,925 Account 408.2, Taxes other than income taxes, other income and deductions
1,569 Account 589, Rents
6,203 Account 107, Construction work in progress
$118,697
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
$ 677 Account 408.2, Taxes other than income taxes, other income and deductions
92,902 Account 107, Construction work in progress
$93,579
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
83,921 Account 107, Construction work in progress
$85,222
Schedule Page: 262 Line No.: 30 Column: f
$111,496 Account 255, Accumulated Deferred Investment Tax Credits (1)
(1) Other
$111,495
(1) Represents the state impact of the adjustment discussed in footnote (4) of the
footnote to line 7 column b of page 266, Accumulated deferred investment tax credits, in
this Form No. 1.
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
2013/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.: 5 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 10 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: l
$ 14,741 Account 408.2, Taxes other than income taxes, other income and deductions
144,319 Account 589, Rents
125,386 Account 107, Construction work in progress
$284,446
Schedule Page: 262.1 Line No.: 15 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 16 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 17 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.: 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: 262.1 Line No.: 21 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 22 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
$ 30,763 Account 408.2, Taxes other than income taxes, other income and deductions
551 Account 589, Rents
7,898,009 Account 107, Construction work in progress
2,089,190 Account 151, Fuel stock
$10,018,513
Schedule Page: 262.1 Line No.: 28 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.: 29 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 31 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Charged to same account as related goods.
Schedule Page: 262.1 Line No.: 35 Column: l
$ 82,806 Account 408.2, Taxes other than income taxes, other income and deductions
294,432 Account 107, Construction work in progress
$377,238
Schedule Page: 262.1 Line No.: 36 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 39 Column: l
Account 151, Fuel stock
Schedule Page: 262.1 Line No.: 40 Column: l
Charged to same account as related goods.
Schedule Page: 262.2 Line No.: 4 Column: l
$ 957 Account 408.2, Taxes other than income taxes, other income and deductions
12,187 Account 589, Rents
436,448 Account 107, Construction work in progress
$449,592
Schedule Page: 262.2 Line No.: 6 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.2 Line No.: 8 Column: l
Charged to same account as related goods.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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
/ /2013/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% 33,995,519 411.4,420 2,851,419 5
30% 420 169,781 420 1,768 6
Idaho -193,191 335,498 411.4,420 8,681 7
TOTAL -193,191 34,331,017 169,781 2,861,868 8
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
9
10
Idaho 190 424,071 468,027 420 31,512 11
Total Nonutility 424,071 468,027 31,512 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 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
/ /2013/Q4
Line
No.ADJUSTMENT EXPLANATIONAverage Periodof Allocationto Income
1
2
3
4
31,144,100 48.37 and 30 5
168,013 24 6
133,626 30 7
31,445,739 8
9
10
860,586 30 11
860,586 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: b
The electric utility subdivision of 10% accumulated deferred investment tax credits are as
follows:
Acct. Beginning Deferred for Yr. Allocat. to CY Adj. Ending Avg.
Sub. Balance Acct. Amount Acct. Amount Balance Per.
(a) (b) (c) (d) (e) (f) (g) (h) (i)
10% $31,574,597 - - 411.4(1) $1,808,768 $ - $29,765,829 48.37

10% 2,420,922 - - 420(2) 1,042,651 - 1,378,271 30
$33,995,519 - $2,851,419 $ - $31,144,100
(1) Internal Revenue Code 46(f)2
(2) Internal Revenue Code 46(f)1
Schedule Page: 266 Line No.: 7 Column: b
The electric utility subdivision of Idaho accumulated deferred investment tax credits are
as follows:
Acct. Beginning Deferred for Yr. Allocat. to CY Adj. Ending Avg.
Sub. Balance Acct. Amount Acct. Amount Balance Per.
(a) (b) (c) (d) (e) (f) (g) (h) (i)

Idaho $ 335,498 - $ - 411.4(1) $ 3,296 $(265,663)(2) $ 66,539 30

Idaho - - - 420(3) 5,385 72,472 (4) 67,087 30
$ 335,498 $ - $ 8,681 $(193,191) $ 133,626
(1)Internal Revenue Code 46(f)2
(2)Represents an adjustment to the balance at beginning of year:
$ 143,049 Account 410.1, Provision for deferred income taxes
(408,712) Account 411.1, Provision for deferred income taxes-credit
$(265,663)
(3)Internal Revenue Code 46(f)1
(4)Represents an adjustment to the balance at beginning of year:
$ 111,496 Account 409.1, Income taxes-other
(39,024) Account 409.1, Income taxes-federal
$ 72,472
Schedule Page: 266 Line No.: 7 Column: g
For further information, refer to this page Line 7, Column (b).
Schedule Page: 266 Line No.: 11 Column: g
Represents an adjustment to the balance at beginning of year:
$(237,441) Account 411.1, Provision for deferred income taxes-credit
(16,891) Account 420, Investment tax credits
678,403 Account 410.1, Provision for deferred income taxes
$ 424,071
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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
/ /2013/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.
5,997,934Working Capital Deposits 6,686,727 688,793 1
2
5,258,748Reclamation Costs - Trapper Mine 5,466,807 208,059 3
4
476,006Reclamation Costs - Deseret Mine 451,406 24,600232 5
6
Western Coal Carriers Benefits 7
11,077,000 Obligation 11,815,000 1,661,770 923,770131 8
9
334,699Bank Card Incentives 423,276 179,700 91,123921 10
11
25,000Deferred Revenue - Other (5) 25,000421 12
13
8,200,305Deferred Compensation Plan 9,205,162 1,728,942 724,085131,232,241 14
15
1,650,088Redding Contract (20) 1,100,092 549,996456 16
17
292,382Foote Creek Contract (15) 154,742 137,640456 18
19
26,769,085Environmental Liabilities 26,273,100 8,659,860 9,155,845 20
21
Unearned Joint Use Pole 22
2,699,055Contact (1) 2,886,601 6,363,842 6,176,296454 23
24
2,875Misc. Security Deposits 2,200 675454,456,557 25
26
28,090Lease Incentives (10) 28,090931 27
28
115,085Cowlitz/Lewis River O&M (1) 117,115 281,076 279,046539 29
30
15,775Employee Housing Security Deposits 18,275 2,500 31
32
Oregon DSM Loans NPV Unearned 33
15,734 Income (10) 15,734456 34
35
413,417Cogeneration Bonds-Sunnyside 413,417 36
37
667,243Transmission Security Deposits 681,500 170,000 155,743131,107 38
39
853,435Transmission Service Deposits 153,225 901,259 1,601,469131 40
41
558,214MCI F.O.G. wire lease (1) 557,890 3,347,342 3,347,666454 42
43
146,226,194Unamortized contract values 123,327,063 22,899,131242 44
45
120,260,000Loss contingency - USA Power 116,623,436 1,800,968 5,437,532426.5 46
FERC FORM NO. 1 (ED. 12-94) Page 269
47 TOTAL 27,031,350 51,573,441 308,485,444 333,027,535
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
/ /2013/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.
1
1,091,171Accrued Right-of-Way Obligations 1,648,357 557,186 2
3
Navajo Tribal Utility Authority 4
Escrow 480,053 480,053 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 27,031,350 51,573,441 308,485,444 333,027,535
Schedule Page: 269 Line No.: 10 Column: a
The weighted average life is 4 years.
Schedule Page: 269 Line No.: 20 Column: c
Account 131, Cash
Account 182.3, Other regulatory assets
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
2013/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
/ /2013/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
3,578,386 21,737,317 208,722,047 4 Pollution Control Facilities
5 Other (provide details in footnote):
6
7
3,578,386 21,737,317 208,722,047 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
3,578,386 21,737,317 208,722,047 17 TOTAL (Acct 281) (Total of 8, 15 and 16)
18 Classification of TOTAL
2,147,401 18,134,016 183,753,060 19 Federal Income Tax
1,430,985 3,603,301 24,968,987 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
/ /2013/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
226,880,978 4
5
6
7
226,880,978 8
9
10
11
12
13
14
15
16
226,880,978 17
18
199,739,675 19
27,141,303 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
/ /2013/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 3,796,825,280 627,266,829 436,011,788 2
Gas 3
4
TOTAL (Enter Total of lines 2 thru 4) 3,796,825,280 627,266,829 436,011,788 5
Nonutility 6
7
8
TOTAL Account 282 (Enter Total of lines 5 thru 8) 3,796,825,280 627,266,829 436,011,788 9
Classification of TOTAL 10
Federal Income Tax 3,339,798,865 507,155,316 337,290,386 11
State Income Tax 457,026,415 120,111,513 98,721,402 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
/ /2013/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
182.3 3,991,613,412 4,258,141182.3 7,791,232 2
3
4
3,991,613,412 4,258,141 7,791,232 5
6
7
8
3,991,613,412 4,258,141 7,791,232 9
10
3,546,947,138 -31,782,947 5,500,396 11
444,666,274 36,041,088 2,290,836 12
13
FERC FORM NO. 1 (ED. 12-96)Page 275
NOTES (Continued)
Schedule Page: 274 Line No.: 11 Column: h
Includes adjustment to the balance at beginning of year to reflect direct allocation of
the federal deferred tax balances.
Schedule Page: 274 Line No.: 12 Column: h
Includes adjustment to the balance at beginning of year to reflect direct allocation of
the state deferred tax balances.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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 DEFFERED INCOME TAXES - OTHER (Account 283)
PacifiCorp X
/ /2013/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
91,527,025 76,645,227 695,709,590Regulatory Assets 3
6,849,053 5,284,329 32,351,572Other 4
5
6
7
8
98,376,078 81,929,556 728,061,162TOTAL 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
98,376,078 81,929,556 728,061,162TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19
Classification of TOTAL 20
84,259,562 69,778,623 640,964,707Federal Income Tax 21
14,116,516 12,150,933 87,096,455State 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
/ /2013/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
526,062,074 19,620,390 47,196,345 14,473,744 141,663,507 3
30,318,999 17,697,822190,283190,283 4,608,277 4,425,708 17,983,102 4
5
6
7
8
556,381,073 37,318,212 51,804,622 18,899,452 159,646,609 9
10
11
12
13
14
15
16
17
18
556,381,073 37,318,212 51,804,622 18,899,452 159,646,609 19
20
489,857,428 31,992,735 45,070,291 16,101,498 139,650,282 21
66,523,645 5,325,477 6,734,331 2,797,954 19,996,327 22
23
FERC FORM NO. 1 (ED. 12-96)Page 277
NOTES (Continued)
Schedule Page: 276 Line No.: 3 Column: g
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Account 283, Accumulated deferred income taxes-other
Schedule Page: 276 Line No.: 3 Column: i
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Account 283, Accumulated deferred income taxes-other
Schedule Page: 276 Line No.: 21 Column: h
Includes adjustment to the balance at beginning of year to reflect direct allocation of
the federal deferred tax balances.
Schedule Page: 276 Line No.: 22 Column: h
Includes adjustment to the balance at beginning of year to reflect direct allocation of
the state deferred tax balances.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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
/ /2013/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)
17,206,905 1,138,454 16,068,451Investment Tax Credit Regulatory Liability 190 1
3,785,659 4,787,240 1,001,581Income Tax Reg. Liab. - WA Flow Through 2
35,161 335,679 300,518Excess Gain on Sale of Assets in Rates - OR (1) 3
445,516 445,516Property Insurance Reserve - OR 4
201,756 315,300 113,544Property Insurance Reserve - ID 5
547,631 401,833 2,298,034 2,152,236Property Insurance Reserve - UT 924 6
621,571 1,673,564 1,051,993Property Insurance Reserve - WY 924 7
4,114,860 2,295,647 1,823,145 3,932SMUD Revenue Imputation (11) 440,442 8
450,629 20,724 1,448,684 1,018,779Utah Home Energy Lifeline 142 9
1,065,877 916,135 149,742BPA Balancing Account - WA 440,442 10
1,792,701 1,580,711 211,990BPA Balancing Account - OR 440,442 11
922,145 922,145BPA Balancing Account - ID 12
12,259,337 1,601,948 10,657,389Asset Retirement Obligations Reg. Difference 230 13
800,851 272,951 1,116,234 588,334Washington Low Income Program 142 14
282,755 368,046 85,291Misc. Regulatory Assets/Liabilities - OR 182.3 15
2,639,097 1,631,385 2,732,953 1,725,241Blue Sky - OR 440,442 16
213,744 54,425 330,282 170,963Blue Sky - WA 440,442 17
97,076 77,893 87,852 68,669Blue Sky - CA 440,442 18
2,724,989 2,561,593 2,929,746 2,766,350Blue Sky - UT 440,442 19
55,579 18,092 91,282 53,795Blue Sky - ID 440,442 20
229,404 155,520 287,012 213,128Blue Sky - WY 440,442 21
2,319,249 26,447,000 3,062,696 27,190,447OR Energy Conservation Charge 131,232 22
17,590,233 4,722,664 14,121,277 1,253,708Renewable Energy Credit Sales Deferral 23
61,696 61,696Tax Revenue Requirement Adj. - UT (1) 24
222,077 491,346 269,2692010 Protocol Deferral - OR (1) 25
180,278 180,278Powerdale Decommissioning Costs Giveback - UT (2) 26
2,434,345 9,106,055 6,671,710Green House Gas Allowance Revenues - CA 27
17,000,000 16,236,420 763,580GRC Invest. in Emission Control Equip. - OR (1) 28
2,273,466 2,273,4662013 FERC Rate True-up - OR 29
765,482 2,173,566 1,408,084DSM Regulatory Asset - CA 30
2,053 2,053DSM Regulatory Asset - ID 31
8,206,230 51,076,864 6,191,038 49,061,672DSM Regulatory Asset - UT 32
367,062 367,062DSM Regulatory Asset - WA 33
183,406 183,406DSM Regulatory Asset - WY 34
621,982 70,976 896,054 345,048Alternative Rate for Energy (CARE) - CA 35
103,748 3 112,448 8,703Deferred Excess Net Power Costs - WA Hydro 555 36
114,940 18,210 124,303 27,573Deferred Independent Evaluator Fee - UT 923 37
2,753,648 1,379,266 1,521,547 147,165Deferred Excess RECs in Rates - UT 2012 456 38
6,035 7,342 1,307RTO Grid West N/R - OR 904 39
10,904 15,303 4,399SB 408 and MCBIT Regulatory Asset - OR 40
FERC FORM NO. 1/3-Q (REV 02-04) Page 278
41 TOTAL 109,373,077 120,576,705 91,533,914 102,737,542
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
/ /2013/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)
354,070 1,220,826 123,782 990,538Solar Feed-In Tariff Deferral - CA 1
867,043 1,370,345 5,982,150 6,485,452Solar Incentive Program - UT 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
FERC FORM NO. 1/3-Q (REV 02-04) Page 278.1
41 TOTAL 109,373,077 120,576,705 91,533,914 102,737,542
Schedule Page: 278 Line No.: 1 Column: a
Weighted average life is 48 years.
Schedule Page: 278 Line No.: 3 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Account 419, Interest and dividend income
Schedule Page: 278 Line No.: 23 Column: c
Account 456, Other electric revenues
Account 419, Interest and dividend income
Account 182.3, Other regulatory assets
Schedule Page: 278 Line No.: 24 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
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
Account 419, Interest and dividend income
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: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 278 Line No.: 30 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 278 Line No.: 32 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.: 35 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 278 Line No.: 40 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 278.1 Line No.: 1 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 278.1 Line No.: 2 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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
/ /2013/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
1,611,369,814(440) Residential Sales 1,773,896,154 2
(442) Commercial and Industrial Sales 3
1,376,215,099Small (or Comm.) (See Instr. 4) 1,467,851,627 4
1,247,618,388Large (or Ind.) (See Instr. 4) 1,365,175,755 5
19,998,454(444) Public Street and Highway Lighting 20,047,674 6
16,263,330(445) Other Sales to Public Authorities 17,101,922 7
(446) Sales to Railroads and Railways 8
(448) Interdepartmental Sales 9
4,271,465,085TOTAL Sales to Ultimate Consumers 4,644,073,132 10
330,569,624(447) Sales for Resale 325,520,827 11
4,602,034,709TOTAL Sales of Electricity 4,969,593,959 12
(Less) (449.1) Provision for Rate Refunds 13
4,602,034,709TOTAL Revenues Net of Prov. for Refunds 4,969,593,959 14
Other Operating Revenues 15
9,445,744(450) Forfeited Discounts 9,906,509 16
6,413,143(451) Miscellaneous Service Revenues 6,310,584 17
860(453) Sales of Water and Water Power 1,577 18
18,875,927(454) Rent from Electric Property 17,887,016 19
(455) Interdepartmental Rents 20
136,299,293(456) Other Electric Revenues 63,993,962 21
76,416,197(456.1) Revenues from Transmission of Electricity of Others 85,492,936 22
(457.1) Regional Control Service Revenues 23
(457.2) Miscellaneous Revenues 24
25
247,451,164TOTAL Other Operating Revenues 183,592,584 26
4,849,485,873TOTAL Electric Operating Revenues 5,153,186,543 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
/ /2013/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
15,968,423 1,504,514 1,522,173 16,339,122 2
3
16,828,774 211,986 207,690 17,057,194 4
21,316,760 33,553 33,561 21,831,865 5
142,675 3,636 3,557 142,585 6
292,709 3 3 292,107 7
8
9
54,549,341 1,753,692 1,766,984 55,662,873 10
11,869,789 10,206,135 11
66,419,130 1,753,692 1,766,984 65,869,008 12
13
66,419,130 1,753,692 1,766,984 65,869,008 14
Page 301
Line 12, column (b) includes $ of unbilled revenues.
Line 12, column (d) includes MWH relating to unbilled revenues
258,009,000
3,378,082
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:
2013 2012
Account service charges -
disconnects/reconnects/returned check charges $ 4,737,594 $ 4,448,063
Customer contract flat rate billings 1,525,594 1,907,528
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:
2013 2012
Renewable energy credit sales, including
amortization and deferrals $ 32,904,131 $ 106,970,144
Wind-based ancillary services 12,114,934 12,186,449
Energy exchange credits 10,700,944 7,178,646
Flyash/by-product sales 3,264,830 3,234,313
Steam sales 2,029,668 3,708,368
Power sale and exchange agreements 1,091,292 1,091,292
Phase shifting equipment fee from
Western Electricity Coordinating Council 1,062,518 338,147
Revenue from generation interconnection and
transmission service request studies 905,164 715,380
Maintenance charges for work on transmission facilities 727,226 783,876
Net profit on sales of materials and supplies inventory 356,039 (a)
Indemnity revenues 346,845 -
Service territory fixed cost recovery fee 276,016 262,676
Deferral of Oregon retail customers' allocated share of
the incremental Open Access Transmission Tariff
revenues associated with FERC Docket No. ER11-3643-000 (2,220,863) -
(a) The 2012 amount is less than $250,000.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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
/ /2013/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 3 06CHCK000R-CA RES CHECK M
1,949 4 06LNX00311-LINE EXT 80% GTY
745 112 6,652 0.1385 103,180 5 06NETMT135-CA RES NET MTR
314 337 932 0.2414 75,804 6 06OALT015R-OUTD AR LGT SR
181,182 18,049 10,038 0.1351 24,471,231 7 06RESD000D-RES SRVC
113,839 10,040 11,339 0.1324 15,077,666 8 06RESDDL06-CA LOW INCOME
853 360 2,369 0.2025 172,754 9 06RGNSV025-CA SMALL GEN
224 8 28,000 0.1308 29,304 10 06RESD0DM9 - MULTI FAMILY
1,247 16 77,938 0.1084 135,133 11 06RESD0DS8-MULT FAM SBMET
88,767 7,290 12,177 0.1336 11,857,936 12 06RESD00DN-RES SVC-DEL NORT
2 13 06UPPL000R-BASE SCH FALL
39,478 14 SMUD REVENUE IMPUTATIONS
3,175 0.1669 530,000 15 UNBILLED REVENUE
-3,000 16 UNBILLED REV - UNCOLLECTIBLE
417,325 17 DSM - RESIDENTIAL
71,689 18 BLUE SKY - RESIDENTIAL
614,423 19 SOLAR FEED-IN REVENUE
-596,584 20 REVENUE - ACCOUNTING ADJ
21
22 IDAHO
1,277 23 07LNX00010-MNTHLY 80%GUAR
1,741 24 07LNX00035-ADV 80%MO GUAR
1,519 90 16,878 0.0992 150,626 25 07NETMT135-ID RES NET MTR
10 1 10,000 0.3811 3,811 26 07OALCO007-CUST OWN LIGHT
97 120 808 0.4087 39,647 27 07OALT07AR-SECURITY AR LG
447,863 44,771 10,003 0.1144 51,227,760 28 07RESD0001-RES SRVC
256,413 13,768 18,624 0.0969 24,844,435 29 07RESD0036-RES SRVC-OPTIO
4,172 539 7,740 0.1146 478,247 30 07RGNSV23A-ID SM GEN SVC
53,413 31 SMUD REVENUE IMPUTATIONS
8,016 0.1266 1,015,000 32 UNBILLED REVENUE
-5,000 33 UNBILLED REV - UNCOLLECTIBLE
1,413,723 34 DSM - RESIDENTIAL
16,227 35 BLUE SKY - RESIDENTIAL
36
37 OREGON
1 38 01CHCK000R-RES CHECK MTR
5,201,789 0.0569 296,221,924 39 01COST0004 - 01RESD0004
25,896 0.0569 1,474,019 40 01COSTR023-RES GEN SRV CST
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
-3 1 01FXRENEWR-Fixed Renewable
39,492 0.0557 2,200,021 2 01HABIT004 - 01RESD0004
34 0.0577 1,962 3 01HABTR023-RES GEN SVC HAB
13,272 4 01LNX00102-LINE EXT 80% G
6,052 5 01LNX00109-REF/NREF ADV +
1,195 6 01LNX00110-REF/NREF ADV +
2,353 1,080,461 7 01NETMT135-NET METERING
17 8,808 8 01NMTOU135-TOU NET MTR
2,379 2,688 885 0.1552 369,102 9 01OALTB15R-OUTD AR LGT RE
18,103 0.0585 1,059,603 10 01PTOU0004 - 01RESD0004
252,267 0.0549 13,859,073 11 01RENEW004 - 01RESD0004
125 0.0585 7,307 12 01RENWR023-RENEW USAGE
474,545 283,961,543 13 01RESD0004-RES SRVC
1,190 892,476 14 01RESD004T-RES Time Option
5,689 2,152,108 15 01RGNSB023-SM GEN SVC-RES
1 38 16 01RNETM023-NET MTR RES GEN
2 17 01UPPL000R-BASE SCH FALL
253 196,370 18 01VIR04136-OR RES VOL INCTV
164,015 19 OR GAIN ON SALE OF ASSET
455,825 20 SMUD REVENUE IMPUTATIONS
738,490 21 SOLAR FEED-IN REVENUE
-5,231 -0.2602 1,361,000 22 UNBILLED REVENUE
-8,000 23 UNBILLED REV - UNCOLLECTIBLE
14,724,948 24 DSM - RESIDENTIAL
465,004 25 BLUE SKY - RESIDENTIAL
-495,823 26 REVENUE - ACCOUNTING ADJ
27
28 UTAH
-5 29 08BLSKY01R-BLUESKY ENERGY
1,014 30 08CFR00001-MTH FACILITY S
1 31 08CHCK000R-UT RES CHECK M
97,347 32 08COOLKPRR - Utah Cool Keeper
4,631 33 08LNX00001-MTHLY 80% GUAR
396 34 08LNX00005-MTHLY MIN GUAR
22,348 35 08LNX00013-80% MNTHLY MIN
2,604 36 08LNX00108-ANN COST MTHLY
11,702 8 1,462,750 0.0733 858,289 37 08MHTP0006-MOBILE HOME &
333 3 111,000 0.0925 30,805 38 08MHTP0023-MOBILE HOME &
11,518 1,614 7,136 0.1070 1,232,865 39 08NETMT135-Net Metering
2,707 2,946 919 0.2862 774,671 40 08OALT007R-SECURITY AR LG
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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 3 667 0.0655 131 1 08PTLD000R-POST TOP LIGHT
6,549,249 696,264 9,406 0.1058 692,990,791 2 08RESD0001-RES SRVC
2,971 350 8,489 0.1033 307,037 3 08RESD0002-RES SRVC-OPTIO
221,906 27,556 8,053 0.1035 22,974,695 4 08RESD0003-LIFELINE PRGRM
80,880 215 376,186 0.0755 6,105,375 5 08RGNSV006-GEN SRVC-RES
91,081 11,997 7,592 0.1091 9,937,681 6 08RGNSV023-GEN SRVC-RES
5,389 19 283,632 0.0828 446,426 7 08RGNSV06A-UT SM GEN SVC
4 1 4,000 0.1170 468 8 08RGNSV06B-UT SM GEN SVC
139 16 8,688 0.1015 14,111 9 08RNM23135-UT NET MTR, GEN
4 10 08UPPL000R-BASE SCH FALL
520,731 11 SOLAR FEED-IN REVENUE
-1,244 -0.7717 960,000 12 UNBILLED REVENUE
-33,000 13 UNBILLED REV - UNCOLLECTIBLE
20,716,225 14 DSM - RESIDENTIAL
1,988,616 15 BLUE SKY - RESIDENTIAL
-2,288,587 16 REVENUE - ACCOUNTING ADJ
7,950,175 17 REVENUE ADJ - DEFERRED NPC
18
19 WASHINGTON
-2 20 02BLSKY01R-BLUESKY ENERGY
783 21 02LNX00109-REF/NREF ADV +
1,372 96 14,292 0.0883 121,143 22 02NETMT135-WA RES NET MTR
1,051 1,133 928 0.1489 156,487 23 02OALTB15R-WA OUTD AR LGT
1,553,802 100,211 15,505 0.0871 135,331,410 24 02RESD0016-WA RES SRVC
66,140 4,195 15,766 0.0868 5,742,704 25 02RESD0017-BILL ASSISTANCE
2,277 84 27,107 0.0955 217,410 26 02RESD0018-WA 3 PHASE RES
435 18 24,167 0.0938 40,818 27 02RESD018X-WA 3 PHASE RES
7,081 1,453 4,873 0.1143 809,006 28 02RGNSB024-WA SM GEN SVC
1 29 02UPPL000R-BASE SCH FALL
-1,320,000 30 WASHINGTON-CHEHALIS
128,745 31 SMUD REVENUE IMPUTATIONS
-5,896 0.0485 -286,000 32 UNBILLED REVENUE
5,000 33 UNBILLED REV - UNCOLLECTIBLE
4,639,763 34 DSM - RESIDENTIAL
-4,765,913 35 REVENUE - ACCOUNTING ADJ
42,672 36 BLUE SKY - RESIDENTIAL
-416,095 37 REVENUE ADJ - DEFERRED NPC
38
39 WYOMING
924 40 05LNX00102-LINE EXT 80% G
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
830 1 05LNX00109-REF/NREF ADV +
1,487 121 12,289 0.1105 164,348 2 05NETMT135-EXPERIMENTAL
248 14 17,714 0.1094 27,140 3 05NETMT135-EXPERIMENTAL
909 1,060 858 0.1592 144,678 4 05OALT015R-OUTD AR LGT SR
1 43 5 05OALT015R-OUTD AR LGT SR
959,922 99,417 9,656 0.1036 99,423,224 6 05RESD0002-WY RES SRVC
125,997 12,468 10,106 0.1052 13,253,358 7 05RESD0002-WY RES SRVC
7,550 1,102 6,851 0.1154 870,968 8 05RGNSV025-WY SM GEN SVC
344 110 3,127 0.1638 56,352 9 05RGNSV025-WY SM GEN SVC
76 89 854 0.2910 22,116 10 09OALT207R-SECURITY AR LG
2 11 09RES00002
4 12 09RESD0002
71,453 13 SMUD REVENUE IMPUTATIONS
1,063 0.3612 384,000 14 UNBILLED REVENUE
-4,663 0.1032 -481,000 15 UNBILLED REVENUE
8,000 16 UNBILLED REV - UNCOLLECTIBLE
1,201,049 17 DSM - RESIDENTIAL
187,337 18 DSM - RESIDENTIAL
16,213 19 DSM - RESIDENTIAL GEN SVC
1,260 20 DSM - RESIDENTIAL GEN SVC
121,262 21 BLUE SKY - RESIDENTIAL
19,723 22 BLUE SKY - RESIDENTIAL
-708,349 23 REVENUE ADJ - DEFERRED NPC
-5,184 24 REVENUE - ACCOUNTING ADJ
25
-119,993 26 LESS MULTIPLE BILLINGS
27
16,339,122 1,522,173 10,734 0.1086 1,773,896,154 28 TOTAL RESIDENTIAL SALES
29
30 COMMERCIAL SALES
31 CALIFORNIA
1 32 06CHCK000N-CA NRES CHECK
55,446 6,538 8,481 0.1591 8,820,224 33 06GNSV0025-CA GEN SRVC
911 85 10,718 0.1756 159,928 34 06GNSV025F-GEN SRVC-<20
82,550 998 82,715 0.1313 10,842,772 35 06GNSV0A32-GEN SRVC-20 KW
38,613 8 4,826,625 0.0875 3,378,064 36 06LGSV048T-LRG GEN SERV
1,362 1 1,362,000 0.0875 119,185 37 06NMT48135-CA GEN SVC NET
72,422 165 438,921 0.1113 8,063,921 38 06LGSV0A36-LRG GEN SRVC-O
11,207 39 06LNX00102-LINE EXT 80% G
4,196 40 06LNX00105-CNTRCT $ MIN G
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
80,943 1 06LNX00109-REF/NREF ADV +
9,891 2 06LNX00300-80% MTHLY MIN GU
10,372 3 06LNX00311-LINE EXT 80% GUAR
2,251 4 562,750 0.1174 264,277 4 06NMT36135-CA GEN SVC NET
708 505 1,402 0.2449 173,411 5 06OALT015N-OUTD AR LGT SR
175 37 4,730 0.1918 33,562 6 06RCFL0042-AIRWAY & ATHLE
95 7 13,571 0.1530 14,532 7 06NMT25135-GN SVC NET<20K
502 9 55,778 0.1555 78,071 8 06NMT32135-GN SVC NET>20K
7,797 9 06LNX00110-REF/NREF ADV +
27,921 10 SMUD REVENUE IMPUTATIONS
498,016 11 SOLAR FEED-IN REVENUE
2,749 0.1564 430,000 12 UNBILLED REVENUE
276,607 13 DSM - COMMERCIAL
5,999 14 BLUE SKY - COMMERCIAL
-492,257 15 REVENUE - ACCOUNTING ADJ
16
17 IDAHO
5,996 108 55,519 0.0861 516,035 18 07CISH0019-COMM & IND SPA
206,249 928 222,251 0.0833 17,176,129 19 07GNSV0006-GEN SRVC-LRG P
43,730 2 21,865,000 0.0622 2,718,415 20 07GNSV0009-GEN SRVC-HI VO
138,144 6,314 21,879 0.0992 13,700,560 21 07GNSV0023-GEN SRVC-SML P
627 3 209,000 0.0701 43,941 22 07GNSV0035-GEN SRVCOPTION
31,676 193 164,124 0.0871 2,758,666 23 07GNSV006A-GEN SRVC-LRG P
23,821 1,328 17,938 0.1001 2,384,682 24 07GNSV023A-GEN SRVC-SML P
7 5 1,400 0.2891 2,024 25 07GNSV023F-GEN SRVC SML P
830 26 07LNX00010-MNTHLY 80%GUAR
214,065 27 07LNX00035-ADV 80%MO GUAR
72,205 28 07LNX00040-ADV+REFCHG+80%
243 175 1,389 0.3815 92,714 29 07OALT007N-SECURITY AR LG
11 12 917 0.4021 4,423 30 07OALT07AN-SECURITY AR LG
3,888 31 07LNX00312-ID LINE EXT
1,667 4 416,750 0.0899 149,785 32 07NMT06135-ID NET MTR-LG GEN
636 15 42,400 0.0885 56,317 33 07NMT23135-ID NET MTR-SM GEN
2,070 34 07LNX00015-ANNUAL 80%GUAR
35,108 35 07LNX00311-LINE EXT 80% GUAR
11,325 36 07LNX00300-80% MTHLY MIN GU
34,231 37 SMUD REVENUE IMPUTATIONS
-15,175 0.0706 -1,071,000 38 UNBILLED REVENUE
755,454 39 DSM - COMMERCIAL
1 1,841 40 BLUE SKY - COMMERCIAL
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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 OREGON
988,536 0.0548 54,145,651 3 01COST0023-OR GEN SRV-COST
914,242 0.0490 44,791,217 4 01COST0048 - 01LGSV0048
3,193 0.0583 186,144 5 01COST023F-OR GEN SRV-COST
72,409 0.0567 4,107,057 6 01COSTB023-OR GEN SRV-COST
1,058,078 0.0511 54,036,206 7 01COSTL030-OR LG GEN SRV
1,911,364 0.0570 109,010,029 8 01COSTS028-OR GEN SERV-COST
11,488 5,228,633 9 01GNSB0023-BPA GEN SRV<30kW
547 3,647,485 10 01GNSB0028-BPA GEN SRV>30kW
52 27,466 11 01GNSB023T-BPA-OR GEN SRV
55,970 50,696,910 12 01GNSV0023-OR GEN SRV<30kW
8,742 52,491,987 13 01GNSV0028-OR GEN SRV>30kW
10,811 783 13,807 0.1539 1,663,280 14 01GNSV023F-OR GEN SRV-FLAT
129 2 64,500 0.1289 16,628 15 01GNSV023M-OR GEN SRV-MANU
214 182,978 16 01GNSV023T-OR GEN SRV-TOU
2,595 0.0559 144,969 17 01HABT0023-OR HABITAT BLEND
181 0.0580 10,490 18 01HABTB023-OR HABITAT BLEND
25 1,142,871 19 01LGSB0030-GEN DEL SRV >200
612 24,136,983 20 01LGSV0030-LG GEN SRV >1000
95 14,167,603 21 01LGSV0048-1000kW AND OVR
60,568 1 60,568,000 0.0590 3,572,046 22 01LGSV048M-LRG GEN SRVC 1
4,983 23 01LNX00100-LINE EXT 60% G
320,377 24 01LNX00102-LINE EXT 80% G
3,897 25 01LNX00103-LINE EXT 80% G
14,384 26 01LNX00105-CNTRCT $ MIN G
1,318,215 27 01LNX00109-REF/NREF ADV +
363 28 01LNX00110-REF/NREF ADV +
416 29 01LNX00120-LINE EXT 60% G
191,967 30 01LNX00300-LINE EXT 80% GUAR
758 31 01LNX00310-LINE EXT CONTRACT
138,752 32 01LNX00311-LINE EXT 80% G
2,197 33 01LNX00312-OR IRG LINE EXT
40,491 5 8,098,200 0.0971 3,931,654 34 01LPRS047M-PART REQ SRVC
178 159,571 35 01NMT23135-NET MTR GEN <30
5,665 2,928 1,935 0.1419 804,111 36 01OALT015N-OUTD AR LGT NR
1,549 1,113 1,392 0.1596 247,263 37 01OALTB15N-OUTD AR LGT NR
3,437 0.0549 188,609 38 01PTOU0023-OR GEN SRV-TOU
437 0.0568 24,815 39 01PTOUB023-OR GEN SRV-TOU
1,419 105 13,514 0.0949 134,613 40 01RCFL0054-REC FIELD LGT
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
8,213 0.0560 459,807 1 01RENW0023-OR RENW USAGE
395 0.0581 22,931 2 01RENWB023-OR RENEWABLE
2,665 0.0627 167,228 3 01STDAY023-DAY STD OFR SCH
14,988 0.0626 938,328 4 01STDAY028-DAY STD OFF SCH
4,682 0.0585 273,665 5 01STDAY030-STD DAY OFF SCH
5,725 0.0539 308,809 6 01STDAY048 - 01LGNSV048
63 98,546 7 01VIR23136-VOL INCTV <=30 kW
70 442,555 8 01VIR28136-VOL INCTV >30 kW
5 169,725 9 01VIR30136-VOL INCTV >200 kW
1 110,516 10 01VIR48136-VOL INCTV >1000 kW
1 79,764 11 01LGSB0048-LG GEN SVC >1000
98 704,429 12 01NMT28135-NET MTR GEN >30
20 879,947 13 01NMT30135-NET MTR GEN >200
3 226,272 14 01NMT48135-NET MTR GEN
532 1 532,000 0.0824 43,854 15 01LGSV028M-LGSV <1000 kW
500 1 500,000 0.0719 35,962 16 01GNSV030M-GEN SRV 200 kW
23 458,163 17 01GNSV0728-GEN SVC DIR ACC
42 4,312,377 18 01GNSV0730-GEN SVC DIR ACC
3 876,131 19 01GNSV0748-LG GEN SVC DIR
119,767 20 OR GAIN ON SALE OF ASSET
417,009 21 SMUD REVENUE IMPUTATIONS
622,188 22 SOLAR FEED-IN REVENUE
-19,290 0.0600 -1,157,000 23 UNBILLED REVENUE
-2 24 01ZZMERGCR-MERGER CREDITS
10,058,629 25 DSM - COMMERCIAL
150 751,719 26 BLUE SKY - COMMERCIAL
-412,096 27 REVENUE - ACCOUNTING ADJ
28
29 UTAH
7,825 30 08ABL-NRES - APPLICANT BUILT
38,746 31 08CFR00051-MTH FAC SRVCHG
2 32 08CFR00052-ANN FAC SVCCHG
3,508 33 08COOLKPRN-A/C DIR LOAD
5,017,120 10,931 458,981 0.0817 409,832,112 34 08GNSV0006-GEN SRVC-DISTR
493,005 27 18,259,444 0.0565 27,879,043 35 08GNSV0009-GEN SRVC-HI VO
1,214,456 65,292 18,600 0.0967 117,414,215 36 08GNSV0023-GEN SRVC-DISTR
230,662 1,950 118,288 0.1123 25,894,312 37 08GNSV006A-GEN SRVC-ENERG
2,690 27 99,630 0.1062 285,750 38 08GNSV006B-GEN SRVC-DEM&
1,501 5 300,200 0.0736 110,404 39 08GNSV006M-MNL DIST VOLTG
24,013 2 12,006,500 0.0630 1,513,634 40 08GNSV009A-GEN SRVC HI VO
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
110,232 1 110,232,000 0.0528 5,819,994 1 08GNSV009M-MANL HIGH VOLT
1,304 127 10,268 0.1411 183,955 2 08GNSV023F-GEN SRVC FIXED
201 5 40,200 0.0850 17,084 3 08GNSV023M-GNSV DIST VOLT
565 1 565,000 0.1088 61,451 4 08GNSV06AM-MNL ENERGY TOD
34,115 462 73,842 0.0751 2,561,156 5 08GNSV06MN-GNSV DIST VOLT
292,355 6 08LNX00002-MTHLY 80% GUAR
19,804 7 08LNX00004-ANNUAL 80%GUAR
4,668 8 08LNX00006-FIXD MTHLY MIN
10,757 9 08LNX00008-ANNUALMIN GUAR
1,548,574 10 08LNX00014-80% MIN MNTHLY
183,666 11 08LNX00017-ADV/REF&80%ANN
32,125 12 08LNX00158-ANNUALCOST MTH
97,404 13 08LNX00300-LINE EXT 80% PLUS
54,414 14 08LNX00310-IRR 80% ANNUAL MIN
7,816 15 08LNX00312-UT IRG LINE EXT
46,015 90 511,278 0.0829 3,815,846 16 08NMT06135-UT NET MTR GEN
20,720 3 6,906,667 0.0725 1,502,334 17 08NMT08135-NET MTR GEN SVC
2,622 126 20,810 0.0996 261,267 18 08NMT23135-NET MTR GEN <25
1,064 7 152,000 0.1228 130,704 19 08NMT6A135-NET MTR GEN SVC
8,268 4,312 1,917 0.2328 1,925,139 20 08OALT007N-SECURITY AR LG
2 226 21 08POLE0075-POLES W/LIGHT
10,648 2 5,324,000 0.0845 899,672 22 08PRSV031M-BKUP MNT&SUPPL
6 2 3,000 0.0753 452 23 08PTLD000N-POST TOP LIGHT
172 20 8,600 0.0909 15,631 24 08TOSS015F-TRAFFIC SIG NM
2,081 804 2,588 0.1077 224,067 25 08TOSS0015-TRAF &amp; OTHER
18,009 447 40,289 0.0697 1,255,580 26 08MONL0015-MTR OUTDONIGHT
318,312 27 08LNX00311-LINE EXT 80% GUAR
1,014,684 152 6,675,553 0.0717 72,780,864 28 08GNSV0008-GEN SVC TOU >1000
30,452 5 6,090,400 0.0780 2,374,021 29 08GNSV008M-GEN SVC TOU
362,045 30 SOLAR FEED-IN REVENUE
-46,789 0.0691 -3,231,000 31 UNBILLED REVENUE
17,986,623 32 DSM - COMMERCIAL
6 460,881 33 BLUE SKY - COMMERCIAL
-1,565,804 34 REVENUE - ACCOUNTING ADJ
8,257,016 35 REVENUE ADJ - DEFERRED NPC
36
37 WASHINGTON
40,697 2,792 14,576 0.0927 3,772,957 38 02GNSB0024-GEN SRVC DO
167 6 27,833 0.1193 19,924 39 02GNSB024F-GEN SRVC DOM/F
456 85 5,365 0.2516 114,724 40 02GNSB24FP-GEN SVC SEASON
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
483,688 13,902 34,793 0.0860 41,590,704 1 02GNSV0024-WA GEN SRVC
1,115 111 10,045 0.1277 142,335 2 02GNSV024F-WA GEN SRVC-FL
89,972 113 796,212 0.0720 6,477,033 3 02LGSB0036-LRG GEN SVC IRG
714,509 809 883,200 0.0726 51,909,016 4 02LGSV0036-WA LRG GEN SRV
172,308 31 5,558,323 0.0659 11,358,741 5 02LGSV048T-LRG GEN SRVC 1
34,589 6 02LNX00102-LINE EXT 80% G
9,450 7 02LNX00103-LINE EXT 80% G
1,783 8 02LNX00105-CNTRCT $ MIN G
291,327 9 02LNX00109-REF/NREF ADV +
4,142 10 02LNX00110-REF/NREF ADV +
669 11 02LNX00112-YR INCURRED CH
10,694 12 02LNX00300-LINE EXT 80% G
1,112 13 02LNX00310-IRG 80% ANNUAL
57,278 14 02LNX00311-LINE EXT 80% GUAR
4,398 15 02LNX00312-WA IRG LINE EXT
1,570 826 1,901 0.1386 217,534 16 02OALT015N-WA OUTD AR LGT
560 502 1,116 0.1496 83,769 17 02OALTB15N-WA OUTD AR LGT
296 30 9,867 0.0908 26,870 18 02RCFL0054-WA REC FIELD L
761 13 58,538 0.0815 62,012 19 02NMT24135-Net metering WA
1,142 2 571,000 0.0729 83,301 20 02NMT36135-NET MTR LG SVC
718 1 718,000 0.0639 45,862 21 02NMT48135-LG SVC NET
115,878 22 SMUD REVENUE IMPUTATIONS
-1,020,000 23 WASHINGTON - CHEHALIS
-4,263 0.0650 -277,000 24 UNBILLED REVENUE
3,876,602 25 DSM - COMMERCIAL
5 11,667 26 BLUE SKY - COMMERCIAL
-321,503 27 REVENUE ADJ - DEFERRED NPC
-3,994,653 28 REVENUE - ACCOUNTING ADJ
29
30 WYOMING
1 31 05CHCK000N-WY NRES CHECK
-41 0.0667 -2,735 32 05GNS28025-GEN SVC
233,269 17,422 13,389 0.0951 22,187,313 33 05GNSV0025-WY GEN SRVC
32,559 2,302 14,144 0.0939 3,057,586 34 05GNSV0025-WY GEN SRVC
918,980 3,369 272,775 0.0815 74,932,139 35 05GNSV0028-GEN SVC >15 kW
99,377 412 241,206 0.0813 8,075,279 36 05GNSV0028-GEN SVC >15 kW
1,009 182 5,544 0.1309 132,102 37 05GNSV025F-GEN SRVC-FL RA
198 33 6,000 0.1238 24,507 38 05GNSV025F-GEN SRVC-FL RA
245,789 18 13,654,944 0.0655 16,092,551 39 05LGSV0046-WY LRG GEN SRV
13,104 1 13,104,000 0.0682 894,206 40 05LGSV048T-LRG GENSRV TIM
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
12,881 1 05LNX00100-LINE EXT 60% G
577,798 2 05LNX00102-LINE EXT 80% G
8,819 3 05LNX00102-LINE EXT 80% G
18,938 4 05LNX00103-LINE EXT 80% G
5,343 5 05LNX00105-CNTRCT $ MIN G
640,629 6 05LNX00109-REF/NREF ADV +
187,096 7 05LNX00109-REF/NREF ADV +
5,750 8 05LNX00110-REF/NREF ADV +
1,624 9 05LNX00110-REF/NREF ADV +
274 10 05LNX00114-TEMP SVC 12MO>
109 11 05LNX00114-TEMP SVC 12MO>
273 17 16,059 0.0907 24,759 12 05NMT25135-NET MTR GEN <25
6 2 3,000 0.1558 935 13 05NMT25135-NET MTR GEN <25
6,238 17 366,941 0.0917 571,753 14 05NMT28135-NET MTR SM GEN
517 3 172,333 0.0891 46,069 15 05NMT28135-NET MTR SM GEN
2,818 1,703 1,655 0.1605 452,237 16 05OALT015N-OUTD AR LGT SR
711 50 14,220 0.0781 55,528 17 05RCFL0054-WY REC FIELD L
71,152 18 05LNX00300-LINE EXT 80% GUAR
97 19 05LNX00310-LINE EXT CONTRACT
87,597 20 05LNX00311-LINE EXT 80% GUAR
2,225 21 05LNX00312 - WY IRG LINE EXT
276 138 2,000 0.2548 70,318 22 09OALT207N-SECURITY AR LG
274 11 24,909 0.0490 13,413 23 09MONL0213-WY MTR OUTDOOR
843 24 05LNX00300-LINE EXT 80% GUAR
2,079 25 05LNX00311-LINE EXT 80% GUAR
106,855 26 SMUD REVENUE IMPUTATIONS
-22,805 0.0692 -1,577,000 27 UNBILLED REVENUE
-5,800 0.0816 -473,000 28 UNBILLED REVENUE
1,565,828 29 DSM - SMALL COMMERCIAL
176,236 30 301271-DSM REVENUE-SM COMM
73,395 31 DSM - LARGE COMMERCIAL
1 5,806 32 BLUE SKY - COMMERCIAL
892 33 301280-BLUE SKY
-1,013,963 34 REVENUE ADJ - DEFERRED NPC
-6,141 35 REVENUE - ACCOUNTING ADJ
36
-26,323 37 LESS MULTIPLE BILLINGS
38
17,057,194 207,690 82,128 0.0861 1,467,851,627 39 TOTAL COMMERCIAL SALES
40
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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
676 92 7,348 0.1639 110,780 3 06GNSV0025-CA GEN SRVC
1,765 23 76,739 0.1557 274,841 4 06GNSV0A32-GEN SRVC-20 kW
35,540 9 3,948,889 0.0926 3,290,381 5 06LGSV048T-LRG GEN SERV
4,881 12 406,750 0.1208 589,517 6 06LGSV0A36-LRG GEN SRVC-O
2,632 7 SMUD REVENUE IMPUTATIONS
39,695 8 SOLAR FEED-IN REVENUE
967 0.0579 56,000 9 UNBILLED REVENUE
52,049 10 DSM - INDUSTRIAL
182 11 BLUE SKY - INDUSTRIAL
-65,243 12 REVENUE - ACCOUNTING ADJ
13
14 IDAHO
2,217 15 07CFR00001-MTH FACILITY S
100 3 33,333 0.0897 8,973 16 07CISH0019-COMM & IND SPA
90,586 104 871,019 0.0722 6,537,560 17 07GNSV0006-GEN SRVC-LRG P
76,683 15 5,112,200 0.0660 5,059,890 18 07GNSV0009-GEN SRVC-HI VO
12,563 340 36,950 0.0962 1,209,071 19 07GNSV0023-GEN SRVC-SML P
778 1 778,000 0.0705 54,876 20 07GNSV0035-GEN SRVCOPTION
4,499 27 166,630 0.0849 381,924 21 07GNSV006A-GEN SRVC-LRG P
2,507 225 11,142 0.1078 270,162 22 07GNSV023A-GEN SRVC-SML P
5 1 5,000 0.1550 775 23 07GNSV023S-ID TRAFFIC SIGNALS
2,204 24 07LNX00035-ADV 80%MO GUAR
1,996 25 07LNX00108-ANN COST MTHLY
13 17 765 0.3940 5,122 26 07OALT007N-SECURITY AR LG
1 237 27 07OALT07AN-SECURITY AR LG
1,461,600 1 1,461,600,000 0.0592 86,483,195 28 07SPCL0001
112,098 1 112,098,000 0.0569 6,378,879 29 07SPCL0002
131,992 30 SMUD REVENUE IMPUTATIONS
10,472 0.1266 1,326,000 31 UNBILLED REVENUE
268,620 32 DSM - INDUSTRIAL
33
34 OREGON
20,641 0.0549 1,133,328 35 01COST0023-GEN SRV CST BSD
1,723,539 0.0486 83,823,263 36 01COST0048 - 01LGSV0048
1 0.0600 60 37 01COST023F-GEN SRV CST BSD
354 0.0561 19,856 38 01COSTB023-GEN SRV CST BSD
216,047 0.0512 11,063,839 39 01COSTL030-LG GEN SRV CST
92,568 0.0569 5,266,459 40 01COSTS028-GEN SRV COST >30
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
54 27,454 1 01GNSB0023-GEN SRV BPA <30
6 24,727 2 01GNSB0028-GEN SRV BPA >30
1,121 1,113,987 3 01GNSV0023-OR GEN SRV <30 kW
464 3,397,556 4 01GNSV0028-OR GEN SRV >30 kW
3 2 1,500 0.2407 722 5 01GNSV023F-GEN SRV - FLAT
46 1 46,000 0.0991 4,557 6 01GNSV023M-GEN SRV MANUAL
4 2,651 7 01GNSV023T-GEN SRV TOU Option
3 50,549 8 01GNSV0728-GEN SVC DIR
2 54,733 9 01GNSV0730-GEN SVC DIR
2 1,641,588 10 01GNSV0748-LG GEN SVC DIR
148 7,049,268 11 01LGSV0030-LG GEN SRV >1000
91 24,034,371 12 01LGSV0048-1000kW AND OVR
85,343 4 21,335,750 0.0724 6,175,625 13 01LGSV048M-LRG GEN SRVC 1
47,042 14 01LNX00102-LINE EXT 80% G
17,818 15 01LNX00300-LINE EXT 80% GUAR
15,576 2 7,788,000 0.0893 1,390,891 16 01LPRS047M-PART REQ SRVC
1 929 17 01NMT23135-NET MTR GEN <30
3 22,576 18 01NMT28135-NET MTR GEN >30
1 17,718 19 01NMT30135-NET MTR GEN >200
299 132 2,265 0.1385 41,409 20 01OALT015N-OUTD AR LGT NR
5 5 1,000 0.1316 658 21 01OALTB15N-OR OUTD AR LGT
34 0.0590 2,005 22 01PTOU0023-GEN SRV TOU ENG
105 0.0530 5,569 23 01RENW0023-RNW USAGE SPLY
9 24 01RENWB023-OR RENEWABLE
20 0.0621 1,241 25 01STDAY023-DAY STD OFR SCH
155 0.0636 9,862 26 01STDAY028-DAY STD OFF SCH
1 1,309 27 01VIR23136-VOL INCTV <=30 kW
1 30,846 28 01VIR30136-VOL INCTV >200 kW
42,584 29 OR GAIN ON SALE OF ASSET
179,663 30 SMUD REVENUE IMPUTATIONS
413,060 31 SOLAR FEED-IN REVENUE
15,300 0.0927 1,419,000 32 UNBILLED REVENUE
800,016 33 DSM - INDUSTRIAL
32 414,340 34 BLUE SKY - INDUSTRIAL
-350,288 35 REVENUE - ACCOUNTING ADJ
36
37 UTAH
18,725 38 08CFR00051-MTH FAC SRVCHG
2,019 2 1,009,500 0.1017 205,415 39 08EFOP0021-ELEC FURNACE O
1,137 3 379,000 0.1385 157,457 40 08EFOP021M-ELEC FURNACE O
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
655,131 1,108 591,273 0.0862 56,482,005 1 08GNSV0006-GEN SRVC-DISTR
3,365,911 113 29,786,823 0.0528 177,632,112 2 08GNSV0009-GEN SRVC-HI VO
57,268 3,379 16,948 0.0985 5,638,575 3 08GNSV0023-GEN SRVC-DISTR
62,137 263 236,262 0.1170 7,272,430 4 08GNSV006A-GEN SRVC-ENERG
703 2 351,500 0.0075 5,272 5 08GNSV006B-GEN SRVC-DEM&
15,745 6 2,624,167 0.0836 1,315,808 6 08GNSV009A-GEN SRVC HI VO
603,245 9 67,027,222 0.0508 30,655,621 7 08GNSV009M-MANL HIGH VOLT
4 1 4,000 0.6403 2,561 8 08GNSV023F-GEN SRVC FIXED
1,340 26 51,538 0.0857 114,889 9 08GNSV06MN-GNSV DIST VOLT
1,197 1 1,197,000 0.0936 112,092 10 08GNSV09AM-MAN TOD HIVOLT
120,053 11 08LNX00002-MTHLY 80% GUAR
7,123 12 08LNX00014-80% MIN MNTHLY
243 13 08LNX00017-ADV/REF&80%ANN
1,638 14 08LNX00311-LINE EXT 80% GUAR
9,193 15 08LNX00300-LINE EXT 80% PLUS
6,356 16 08LNX00310-IRR 80% ANNUAL MIN
1,214 465 2,611 0.2153 261,409 17 08OALT007N-SECURITY AR LG
17 10 1,700 0.1200 2,040 18 08TOSS0015-TRAF & OTHER S
16 7 2,286 0.1974 3,158 19 08MONL0015-MTR OUTDONIGHT
3,846 5 769,200 0.1020 392,122 20 08NMT06135-NET MTR GEN SVC
83 4 20,750 0.0900 7,471 21 08NMT23135-NET MTR GEN <25
21 1 21,000 0.2264 4,754 22 08NMT6A135-NET MTR GEN SVC
4,621 1 4,621,000 0.1580 730,315 23 08PRSV031M-BKUP MNT&SUPPL
588,186 1 588,186,000 0.0485 28,520,035 24 08SPCL0001
990,973 1 990,973,000 0.0416 41,197,541 25 08SPCL0002
1,086,466 1 1,086,466,000 0.0454 49,361,366 26 08SPCL0003
310 2 155,000 0.1228 38,074 27 08GNSV06AM-MNL ENERGY TOD
979,466 104 9,417,942 0.0732 71,667,765 28 08GNSV0008-GEN SVC TOU >1000
60,877 7 8,696,714 0.0748 4,554,170 29 08GNSV008M-GEN SVC TOU
451,529 30 SOLAR FEED-IN REVENUE
198,366 0.0531 10,528,000 31 UNBILLED REVENUE
8,108,380 32 DSM - INDUSTRIAL
7 112,058 33 BLUE SKY - INDUSTRIAL
-2,001,079 34 REVENUE - ACCOUNTING ADJ
5,101,238 35 REVENUE ADJ - DEFERRED NPC
36
37 WASHINGTON
2,044 90 22,711 0.0941 192,406 38 02GNSB0024-WA GEN SRVC DO
10 1 10,000 0.2842 2,842 39 02GNSB24FP-GEN SVC SEASON
17,253 350 49,294 0.0859 1,482,310 40 02GNSV0024-WA GEN SRVC
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
33 4 8,250 0.2380 7,854 1 02GNSV024F-WA GEN SRVC-FL
102,694 106 968,811 0.0758 7,783,071 2 02LGSV0036-WA LRG GEN SRV
677,586 32 21,174,563 0.0585 39,610,319 3 02LGSV048T-LRG GEN SRVC 1
114 41 2,780 0.1295 14,761 4 02OALT015N-WA OUTD AR LGT
29 15 1,933 0.1459 4,231 5 02OALTB15N-WA OUTD AR LGT
2,049 1 2,049,000 0.1429 292,763 6 02PRSV47TM-LRG PART REQMT
3,532 26 135,846 0.1189 419,914 7 02LGSB0036-LRG GEN SVC IRG
-510,000 8 WASHINGTON - CHEHALIS
66,246 9 SMUD REVENUE IMPUTATIONS
-12,861 0.0813 -1,046,000 10 UNBILLED REVENUE
1,683,434 11 DSM - INDUSTRIAL
-160,707 12 REVENUE ADJ - DEFERRED NPC
-1,734,474 13 REVENUE - ACCOUNTING ADJ
14
15 WYOMING
21,114 1,111 19,005 0.0898 1,895,712 16 05GNSV0025-WY GEN SRVC
4,444 290 15,324 0.0931 413,838 17 05GNSV0025-WY GEN SRVC
260,664 493 528,730 0.0721 18,806,813 18 05GNSV0028-GEN SVC >15 kW
57,049 79 722,139 0.0725 4,135,763 19 05GNSV0028-GEN SVC >15 kW
26 8 3,250 0.1620 4,211 20 05GNSV025F-GEN SRVC-FL RA
4,143 3 1,381,000 0.0588 243,678 21 05GNSV028M-GEN SVC >15 KW
1,711,512 55 31,118,400 0.0630 107,741,565 22 05LGSV0046-WY LRG GEN SRV
50,907 4 12,726,750 0.0658 3,349,174 23 05LGSV0046-WY LRG GEN SRV
120,859 2 60,429,500 0.0608 7,353,047 24 05LGSV046M-WY LRG GEN SRV
286,176 1 286,176,000 0.0544 15,563,127 25 05LGSV048M-TOU>1000KW MAN
237,638 4 59,409,500 0.0574 13,645,898 26 05LGSV048M-TOU>1000KW MAN
1,511,165 10 151,116,500 0.0560 84,632,513 27 05LGSV048T-LRG GENSRV TIM
1,238,989 11 112,635,364 0.0588 72,847,079 28 05LGSV048T-LRG GENSRV TIM
38,807 29 05LNX00100-LINE EXT 60% G
192,843 30 05LNX00102-LINE EXT 80% G
44,915 31 05LNX00102-LINE EXT 80% G
35,212 32 05LNX00105-CNTRCT $ MIN G
218,808 33 05LNX00109-REF/NREF ADV +
2,446,708 34 05LNX00109-REF/NREF ADV +
84 41 2,049 0.1438 12,081 35 05OALT015N-OUTD AR LGT SR
1,312,862 6 218,810,333 0.0633 83,046,997 36 05PRSV033M-PART SERV REQ
18,724 37 05LNX00300-LINE EXT 80% GUAR
1,566 38 05LNX00300-LINE EXT 80% GUAR
15,706 39 05LNX00311-LINE EXT 80% GUAR
101,943 2 50,971,500 0.0609 6,209,586 40 05PRSV033M-PART SERV REQ
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
5 3 1,667 0.2126 1,063 1 09OALT207N-SECURITY AR LG
464,306 2 SMUD REVENUE IMPUTATIONS
-5,652 -0.0205 116,000 3 UNBILLED REVENUE
-17,680 0.0623 -1,102,000 4 UNBILLED REVENUE
329,417 5 DSM - SMALL INDUSTRIAL
77,298 6 DSM - SMALL INDUSTRIAL
1,187,412 7 DSM - LARGE INDUSTRIAL
378,471 8 DSM - LARGE INDUSTRIAL
1 7,819 9 BLUE SKY - INDUSTRIAL
17 10 BLUE SKY - INDUSTRIAL
-4,752,545 11 REVENUE ADJ - DEFERRED NPC
-19,440 12 REVENUE - ACCOUNTING ADJ
13
-977 14 LESS MULTIPLE BILLINGS
15
20,354,799 10,294 1,977,346 0.0603 1,228,376,450 16 TOTAL INDUSTRIAL SALES
17
18 IRRIGATION SALES
19 CALIFORNIA
70,142 1,352 51,880 0.1217 8,537,342 20 06APSV0020-AG PMP SRVC
1,658 1 1,658,000 0.1064 176,388 21 06LGSV048T-LRG GEN SERV
380 4 95,000 0.1666 63,305 22 06NMT20135-AGRICULTURAL
2,805 23 06LNX00103-LINE EXT 80% G
35,940 24 06LNX00110-REF/NREF ADV +
932 25 06LNX00310-IRG 80% ANNUAL MIN
6,098 26 06LNX00312-CA IRG LINE EXT
28,280 656 43,110 0.1343 3,799,085 27 06USBR0020-KLAM IRG ONPRJ
62,480 28 SOLAR FEED-IN REVENUE
22 1.1364 25,000 29 UNBILLED REVENUE
162,030 30 DSM - IRRIGATION
23 31 BLUE SKY - IRRIGATION
-235,569 32 REVENUE - ACCOUNTING ADJ
33
34 IDAHO
437,214 2,720 160,740 0.0910 39,795,807 35 07APSA010L-IRG & Pump Large
4,835 356 13,581 0.1100 531,656 36 07APSA010S-IRG & Pump Small
197,934 1,418 139,587 0.0902 17,862,542 37 07APSAL10X-IRG & PUMP-Large l
3,477 323 10,765 0.1142 397,083 38 07APSAS10X-IRG & PUMP-Small l
45,729 48 952,688 0.0806 3,683,729 39 07APSVCNLL-LRG LOAD CANAL
120 11 10,909 0.1401 16,806 40 07APSVCNLS-SML LOAD CANAL
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
39 1 07LNX00015-ANNUAL 80%GUAR
157,591 2 07LNX00040-ADV+REFCHG+80%
77 3 07LNX00310 80% ANNUAL GUAR
1,845 4 07LNX00311-LINE EXT 80% GUAR
27,411 5 07LNX00312-ID LINE EXT
1,962 26 75,462 0.1010 198,165 6 07APSN010L-ID LG IRR & PUMP
33 4 8,250 0.1324 4,370 7 07APSN010S-IRR SM 3 PH
188 12 15,667 0.1123 21,108 8 07APSNS10X-IRR SM 3 PHASE
-6 9 UNBILLED REVENUE
1,322,553 10 DSM - IRRIGATION
1 23 11 BLUE SKY - IRRIGATION
12
13 OREGON
4,761 2,515,761 14 01APSV0041-AG PMP SRVC
1,101 3,845,061 15 01APSV041L-Pumping Serv >30 kW
54 26,208 16 01APSV041T-AGR PUMP SRV-TOU
190 83,151 17 01APSV041X-AG PMP SRVC
35 190,391 18 01APSV41XL-Pumping Serv no BPA
136,233 0.0551 7,505,737 19 01COST0041- 01APSV0041
22,885 0.0491 1,123,364 20 01COST0048 - 01LGSV0048
335 0.0573 19,187 21 01COSTS028-GEN SRV CST >30
91,970 0.0548 5,044,276 22 01CSTUSB41-USBR IRR CONTRAC
3 16,258 23 01GNSV0028-GEN SRV >30 kW
6 0.0543 326 24 01HABIT041-01APSV0041 AG PMP
1 112,801 25 01LGSB0048-LG GEN SVC >1000
1 26 01LGSV0030-3P,DEMAND VAR
4 355,360 27 01LGSV0048-1000KW AND OVR
40,634 28 01LNX00103-LINE EXT 80% G
189,705 29 01LNX00110-REF/NREF ADV +
14,374 30 01LNX00310-LINE EXTENSION
516 0.0533 27,526 31 01PTOU0041 - 01APSV0041 AG
150 0.0556 8,346 32 01RENEW041 - 01APSV0041 AG
-2,405 33 01SLX00005-KLAMATH FALLS
92 0.0644 5,927 34 01STDAY041-Daily Standard Offer
38 10 3,800 1.8600 70,680 35 01USBGV041-IRG TOU W/O BPA
110 572 192 0.0718 7,898 36 01USBOF033-KLAMATH BASIN
283 581 487 6.2567 1,770,653 37 01USBOF041-KLAMATH BASIN IRG
212 1,282 165 0.0691 14,639 38 01USBON033-KLAMATH BASIN
651 1,279 509 3.6550 2,379,411 39 01USBON041-KLAMATH BASIN
99 53 1,868 0.0680 6,730 40 01VIR33136-VOL INCTV USB
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
8 18,939 1 01VIR41136-VOL INCTV-AGRI
76 69 1,101 3.1081 236,216 2 01VRU41136-VOL INCTV USB
1,080 10 108,000 0.0554 59,876 3 01USBGV033-IRG TOU W/O BPA
13,635 4 01LNX00312-OR IRG LINE EXT
2 5 01NMT33135-NET MTR - PROJECT
4 2,544 6 01NMT41135-NETMTR AG PMP
2 3,091 7 01NMU41135-NET MTR PROJECT
4,325 8 OR GAIN ON SALE OF ASSET
14,695 9 SOLAR FEED-IN REVENUE
82 0.3659 30,000 10 UNBILLED REVENUE
721,518 11 DSM - IRRIGATION
322 12 BLUE SKY - IRRIGATION
-8,321 13 REVENUE - ACCOUNTING ADJ
14
15 UTAH
210,552 2,819 74,690 0.0728 15,335,770 16 08APSV0010-IRR & SOIL DRA
32,848 179 183,508 0.0651 2,138,545 17 08APSV10NS-Irg Soil Drain Pump N
8,281 18 08LNX00004-ANNUAL 80%GUAR
12,680 19 08LNX00014-80% MIN MNTHLY
212,459 20 08LNX00017-ADV/REF&80%ANN
10,178 21 08LNX00310-IRR 80% ANNUAL MIN
26,455 22 08LNX00312-UT IRG LINE EXT
13 2 6,500 0.0934 1,214 23 08NMT10135-UT IRR SOIL DRNG
10,552 24 SOLAR FEED-IN REVENUE
-343 0.0496 -17,000 25 UNBILLED REVENUE
447,106 26 DSM - IRRIGATION
37 27 BLUE SKY - IRRIGATION
-46,726 28 REVENUE - ACCOUNTING ADJ
29
30 WASHINGTON
155,908 5,071 30,745 0.0822 12,822,363 31 02APSV0040-WA AG PMP SRVC
5,474 187 29,273 0.0828 453,169 32 02APSV040X-WA AG PMP SRVC
6,771 33 02LNX00103-LINE EXT 80% G
81 34 02LNX00105-CNTRCT $ MIN G
5,226 35 02LNX00109-REF/NREF ADV +
177,557 36 02LNX00110-REF/NREF ADV +
7,271 37 02LNX00310-IRG 80% ANNUAL MIN
205 38 02LNX00311-LINE EXT 80% GUAR
38,092 39 02LNX00312-WA IRG LINE EXT
13 2 6,500 0.0802 1,043 40 02NMT40135-WA NET MTR IRG
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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
-212 0.1557 -33,000 2 UNBILLED REVENUE
450,938 3 DSM - IRRIGATION
-457,544 4 REVENUE - ACCOUNTING ADJ
4 85 5 BLUE SKY - IRRIGATION
6
7 WYOMING
20,895 664 31,468 0.0797 1,665,841 8 05APS00040-AG PUMPING SVC
2 -332 9 05APS00040-AG PUMPING SVC
57,319 10 05LNX00110-REF/NREF ADV +
14,373 11 05LNX00110-REF/NREF ADV +
8,848 12 05LNX00103-LINE EXT 80% G
1,232 13 05LNX00103-LINE EXT 80% G
5,237 14 05LNX00312-WY IRG LINE EXT
997 15 05LNX00312-WY IRG LINE EXT
5,142 85 60,494 0.0756 388,829 16 09APSV0210-IRR & SOIL DRA
-10 0.1000 -1,000 17 UNBILLED REVENUE
32,810 18 DSM - IRRIGATION
7,838 19 DSM - IRRIGATION
2 20 BLUE SKY - IRRIGATION
21
-2,702 22 LESS MULTIPLE BILLINGS
23
1,477,066 23,267 63,483 0.0926 136,799,305 24 TOTAL IRRIGATION SALES
25
26 PUBLIC STREET & HWY LIGHTING
27 CALIFORNIA
1,430 109 13,119 0.1502 214,769 28 06CUSL053F-SPECIAL CUST O
237 22 10,773 0.1674 39,681 29 06CUSL058F-CUST OWND STR
708 80 8,850 0.2728 193,117 30 06HPSV0051-HI PRESSURE SO
6,212 31 SOLAR FEED-IN REVENUE
17 0.2353 4,000 32 UNBILLED REVENUE
3,457 33 DSM REVENUE - PSHL
-7,063 34 REVENUE - ACCOUNTING ADJ
35
36 IDAHO
148 24 6,167 0.1205 17,827 37 07GNSV023S-IDAHO TRAFFIC
74 33 2,242 0.4534 33,553 38 07SLCO0011-STR LGT CO-OWN
323 23 14,043 0.1120 36,169 39 07SLCU012E-ENGY STR LGT
1,884 198 9,515 0.1985 373,942 40 07SLCU012F-FULL MNT STR
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
192 16 12,000 0.1454 27,909 1 07SLCU012P-PART MNT STR LGT
-91 0.1648 -15,000 2 UNBILLED REVENUE
9,595 3 DSM REVENUE - PSHL
4
5 OREGON
427 39 10,949 0.1449 61,886 6 01COSL0052-STR LGT SRVC C
770 73 10,548 0.0715 55,035 7 01CUSL0053-CUS-OWNED MTRD
8,388 159 52,755 0.0714 599,097 8 01CUSL053E-STR LGT SVC
154 11 14,000 0.1186 18,264 9 01CUSL053F-STR LGT SRVC C
19,453 718 27,093 0.2035 3,958,682 10 01HPSV0051-HI PRESSURE SO
33 15 2,200 0.3036 10,018 11 01LEDSL051-LED PILOT ST LIGHT
8,562 246 34,805 0.1280 1,095,908 12 01MVSL0050-MERC VAPSTR LG
1 129 13 01OALT015N-OUTD AR LGT NR
1,996 14 OR GAIN ON SALE OF ASSET
3,584 15 SOLAR FEED-IN REVENUE
-1,041 0.1816 -189,000 16 UNBILLED REVENUE
141,889 17 DSM REVENUE - PSHL
-633 18 REVENUE - ACCOUNTING ADJ
19
20 UTAH
54 21 08CFR00012-STR LGTS (CONV
4,529 22 08CFR00051-MTH FAC SRVCHG
79 23 08CFR00062-STREET LIGHTS
2 84 24 08OALT007N-SECURITY AR LG
1,159 123 9,423 0.0895 103,770 25 08TOSS015F-TRAFFIC SIG NM
16,040 808 19,851 0.3046 4,885,747 26 08SLCO0011-STR LGT CO-OWN
3,064 1,532 2,000 0.1151 352,684 27 08TOSS0015-TRAF & OTHER S
798 59 13,525 0.0793 63,260 28 08MONL0015-MTR OUTDONIGHT
5,188 216 24,019 0.1231 638,617 29 08SLCU012P-STR LGT CUST-O
1,588 96 16,542 0.1407 223,392 30 08SLCU012F-STR LGT CUST-O
50,685 556 91,160 0.0658 3,336,954 31 08SLCU012E-DECOR CUST-OWN
10,415 32 SOLAR FEED-IN REVENUE
1,583 0.1181 187,000 33 UNBILLED REVENUE
279,072 34 DSM REVENUE - PSHL
-46,396 35 REVENUE - ACCOUNTING ADJ
36
37 WASHINGTON
91 38 02CFR00012-STR LGTS (CONV
220 15 14,667 0.1717 37,773 39 02COSL0052-WA STR LGT SRV
3,235 112 28,884 0.0718 232,145 40 02CUSL053F-WA STR LGT SRV
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
1,153 105 10,981 0.0711 81,927 1 02CUSL053M-WA STR LGT SRV
3,527 160 22,044 0.1977 697,460 2 02HPSV0051-WA HI PRESSURE
1,939 42 46,167 0.1245 241,434 3 02MVSL0057-WA MERC VAPSTR
-30,000 4 WASHINGTON - CHEHALIS
-1,008 0.1250 -126,000 5 UNBILLED REVENUE
26,851 6 DSM REVENUE - PSHL
-27,450 7 REVENUE - ACCOUNTING ADJ
8
9 WYOMING
269 18 14,944 0.2206 59,333 10 05COSL0057-CO-OWND STR LG
81 11 7,364 0.0681 5,519 11 05CUSL058M-CUST OWND STR
1,067 30 35,567 0.0678 72,317 12 05CUSL0E58-CUST OWND ST LT
44 3 14,667 0.0804 3,539 13 05CUSL0M58-CUST OWND ST LT
5,147 171 30,099 0.2228 1,146,660 14 05HPSV0051-HI PRESSURE SO
3,774 256 14,742 0.1358 512,457 15 05MVS00053-MERCURY VAPOR
27 1 27,000 0.1219 3,292 16 05OALT015N-OUTD AR LGT SR
25 1 25,000 0.0893 2,232 17 09MONL0213-WY MTR OUTDOOR
1,464 51 28,706 0.2737 400,731 18 09SLCO0211-STR LGT CO-OWN
45 6 7,500 0.1619 7,285 19 09SLCUP212-CUST OWND ST LT
62 14 4,429 0.0435 2,700 20 09TOSS0213-TRAFFIC & OTHER
60 0.1667 10,000 21 UNBILLED REVENUE
-319 0.2571 -82,000 22 UNBILLED REVENUE
28,473 23 DSM REVENUE - PSHL
6,714 24 DSM REVENUE - PSHL
-93 25 REVENUE - ACCOUNTING ADJ
26
-2,598 27 LESS MULTIPLE BILLINGS
28
142,585 3,557 40,086 0.1406 20,047,674 29 TOTAL PUBLIC STREET & HWY
30
31 OTHER SALES TO PUBLIC AUTH
32 UTAH
253,786 2 126,893,000 0.0547 13,876,269 33 08GNSV009M-MANL HIGH VOLT
36,496 1 36,496,000 0.0734 2,679,992 34 08PRSV031M-BKUP MNT&SUPPL
15,074 35 SOLAR FEED-IN REVENUE
1,825 0.0975 178,000 36 UNBILLED REVENUE
419,207 37 DSM REVENUE - OSPA
-66,620 38 REVENUE - ACCOUNTING ADJ
39
292,107 3 97,369,000 0.0585 17,101,922 40 TOTAL OTHER SALES TO PUBLIC
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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 FORFEITED DISCOUNTS
3 CALIFORNIA
347,643 4 06LPAY0300-LATEFEE
5
6 IDAHO
559,231 7 07LPAY0300-LATEFEE
8
9 OREGON
3,761,604 10 01LPAY0300-LATEFEE
11
12 UTAH
3,744,504 13 08LPAY0300-LATEFEE
-3,512 14 OTHER
15
16 WASHINGTON
675,829 17 02LPAY0300-LATEFEE
18
19 WYOMING
466,367 20 05LPAY0300-RES-LATEFEE
156,332 21 05LPAY0300-COM-LATEFEE
199,799 22 05LPAY0300-IND-LATEFEE
-1,288 23 05LPAY0300-Other-LATEFEE
24
9,906,509 25 TOTAL FORFEITED DISCOUNTS
26
27 MISCELLANEOUS SERVICE REV
28 CALIFORNIA
1,454 29 06CFR00003-MTH MAINTENANC
39,340 30 06CONN0300-CA RECONNECTIO
57,816 31 06FCBUYOUT
12,780 32 06RCHK0300-CA RET CHK CHR
1,575 33 06TAMP0300-CA TAMP & UNAU
765 34 06TEMP0300-CA TEMP SRVC C
30 35 06TRBL0300-CA TROUBLE CAL
133 36 06XMTRTAMP-TAMPERING-UNAU
544 37 HOME COMFORT
38
39 IDAHO
1,682 40 07CFR00001-MTH FAC SRVCHG
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
59,775 1 07CONN0300-ID RECONNECTIO
27,907 2 07FCBUYOUT-FAC CHG BUYOUT
32,320 3 07RCHK0300-ID RET CHK CHR
375 4 07TAMP0300
15,990 5 07TEMP0014-TEMP SRVC CONN
17 6 07XMTRTAMP-TAMPERING-UNAU
811 7 OTHER
8
9 OREGON
135,233 10 01CFR00001-MTH FACILITY S
25,966 11 01CFR00003-MTH MAINTENANC
25,716 12 01CFR00004-EMRGNCY ST&BY
35,398 13 01CFR00005-INTERMTNT SRVC
2,284 14 01CFR00013-MTH MISC CHRG
5 15 01CFR00014-YR MISC CHRG
417,055 16 01CONN0300-RECONNECTION C
13,022 17 01CONTSERV-3RD PRTY OUTSIDE
490 18 01ESSC0600-ESS charges
243,474 19 01FCBUYOUT-FAC CHG BUYOUT
299,380 20 01RCHK0300-RETURNED CHECK
15,000 21 01TAMP0300-TAMP & UNAUTH
144,340 22 01TEMP0300-TEMP SRVC CHRG
3,461 23 01XMTRTAMP-TAMPERING-UNAU
-62,108 24 OTHER
25
26 UTAH
147,885 27 08CFR00013-MTH MISC CHRG
87,026 28 08CFR00051-MTH FAC SRVCHG
424 29 08CFR00052-ANN FAC SVCCHG
11,265 30 08CFR00053-MTHLY MAINTFEE
2,073 31 08CFR00054-NRES EMERG
2,361 32 08CFR00063-MTH MISC CHARG
6,660 33 08CFR00064-ANN MISC CHARG
640,110 34 08CONN0300-RECONN&DISCONN
79,336 35 08CONTSERV-3RD PARTY O/S
284,192 36 08FCBUYOUT-FAC CHG BUYOUT
7,350 37 08NCON0300-UT FEE NRES RE
1,981 38 08NSMTR300-NON STNDRD MTR
536 39 08PRINT300-SCREEN PRINT FOR
480,360 40 08RCHK0300-UT RET CHK CHR
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
1,644,800 1 08RCON0001-CONNECT FEE
693 2 08RESD0001-RES SRVC
11,625 3 08TAMP0300-TAMPERING&UNAU
485,580 4 08TEMP0014-TEMP SRVC CONN
1,307 5 08XMTRTAMP-TAMPERING-UNAU
29,120 6 08VISIT300-UT Visit Service Call
7,255 7 ENERGY FINANSWER NEW COM
43,329 8 OTHER
9
10 WASHINGTON
1,320 11 02CFR00003-MTH MAINTENANC
5,931 12 02CFR00004-EMRGNCY ST&BY
4,264 13 02CFR00005-INTERMTNT SRVC
126,410 14 02CONN0300-WA RECONNECTIO
9,222 15 02FCBUYOUT - FAC CHG BUYOUT
59,840 16 02RCHK0300-WA RET CHK CHR
3,075 17 02TAMP0300-WA TAMP & UNAU
20,690 18 02TEMP0300-WA TEMP SRVC C
949 19 02XMTRTAMP-TAMPERING-UNAU
891 20 HOME COMFORT
46 21 ENERGY FINANSWER NEW COM
-8,575 22 OTHER
23
24 WYOMING
1,768 25 05CFR00003-MTH MAINTENANC
18,817 26 05CFR00004-EMRGNCY ST&BY
10,217 27 05CFR00005-INTERMTNT SRVC
3,186 28 05CFR00013-MTH MISC CHRG
81,150 29 05CONN0300-WY RECONNECTIO
15,650 30 05CONN0300-WY RECONNECTIO
118,855 31 05FCBUYOUT-FAC CHG BUYOUT
185,551 32 05FCBUYOUT-FAC CHG BUYOUT
73,350 33 05RCHK0300-WY RET CHK CHR
9,390 34 05RCHK0300-WY RET CHK CHR
825 35 05TAMP0300
150 36 05TAMP0300
37,495 37 05TEMP0300-WY TEMP SRVC C
1,360 38 05TEMP0300-WY TEMP SRVC C
86 39 05XMTRTAMP-TAMPERING-UNAU
339 40 09CFR00005-INTERMTNT SRVC
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
5,065 1 09CFR00001-MTH FAC SRVCHG
3 2 09CFR00014-YR MISC CHRG
83 3 ENERGY FINANSWER 12,000
-3,924 4 OTHER
-193 5 OTHER
6
6,310,584 7 TOTAL MISC SERVICE REV
8
9 SALES OF WATER AND WTR PWR
1,577 10 UTAH
11
1,577 12 TOTAL WATER AND WATER PWR
13
14 RENT FROM ELEC PROPERTIES
15 CALIFORNIA
1,710 16 06CFR00006-MTH RNTAL CHRG
1,200 17 RENT REVENUE - HYDRO
19,200 18 RENT REVENUE - SUBLEASES
471,217 19 JOINT USE
20
21 IDAHO
788 22 07CFR00009-YR LSE CHRG-EQ
161 23 07INVCHG00-INVEST MNT CHG
277 24 07POLE0075-STEEL POLES US
66,960 25 RENT REVENUE - HYDRO
2,216 26 RENT REVENUE - SUBLEASES
152,113 27 JOINT USE
28
29 OREGON
740,865 30 01CFR00006-MTH RNTAL CHRG
568,165 31 RENTS - COMMON
50 32 RENTS - NON COMMON
3,347,666 33 MCI FOGWIRE REVENUE
177,744 34 RENT REVENUE - SUBLEASES
256,294 35 RENT REV - TRANSMISSION
58,721 36 RENT REV - DISTRIBUTION
22,831 37 RENT REVENUE - HYDRO
48,027 38 RENT REV - GEN(COMM)
2,707,379 39 JOINT USE
40
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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
33 2 08CFR00056-MTH EQUIP RENT
676,099 3 08CFR00058-MTH EQUIP LEAS
4,406 4 08INVCHG0N-INVEST MNT CHG
255 5 08INVCHG0R-INVEST MNT CHG
55,048 6 08POLE0075-STEEL POLES US
3,600 7 RENTS - NON COMMON
116,271 8 RENT REVENUE - STEAM
1,015,041 9 RENT REV - TRANSMISSION
535,499 10 RENT REV - DISTRIBUTION
78,737 11 RENT REVENUE - HYDRO
13,634 12 RENT REV - GEN(COMM)
2,648,443 13 RENT REVENUE - SUBLEASES
91,739 14 INTERCOMPANY RENT REVENUE
2,103,705 15 JOINT USE
16
17 WASHINGTON
2,104 18 02CFR00001-MTH FACILITY S
9,073 19 02CFR00006-MTH RNTAL CHRG
17,371 20 RENT REV - TRANSMISSION
17,616 21 RENT REV - DISTRIBUTION
337,375 22 RENT REVENUE - HYDRO
40,250 23 RENT REV - GEN(COMM)
8,059 24 RENT REVENUE - SUBLEASES
974,514 25 JOINT USE
26
27 WYOMING
11,524 28 05CFR00001-MTH FACILITY S
2,482 29 05CFR00006-MTH RNTAL CHRG
18,317 30 09POLE0075-STEEL POLES US
54,019 31 RENT REVENUE - STEAM
4,675 32 RENT REVENUE - STEAM
2,606 33 RENT REV - TRANSMISSION
150 34 RENT REV - DISTRIBUTION
33,038 35 RENT REVENUE - HYDRO
31,736 36 RENT REV - GEN(COMM)
7,055 37 RENT REVENUE - SUBLEASES
328,917 38 JOINT USE
41 39 JOINT USE
40
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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.
17,887,016 1 TOTAL RENT FROM ELEC PROP
2
3 OTHER ELECTRIC REVENUE
12,114,934 4 WIND BASED ANCILLARY SVC
12,967,601 5 RENEWABLE ENERGY CREDIT
15,535,015 6 GREEN CREDIT SALES
4,383,115 7 RENEWABLE ENERGY CR AMORT
12,177,493 8 NON-WHEELING SYSTEM
246,823 9 OTHER ELECTRIC ESTIMATE
21,210 10 OTHER ELECTRIC (EXCL
2,000 11 ELECTRIC INCOME - OTHER
-2,220,863 12 FERC TRANSMISSION REFUND
18,400 13 REC SALES WIND WAKE LOSS
14
15 CALIFORNIA
20,227 16 3RD PARTY TRANS O&M
6,376 17 FISH, WILDLIFE, RECR
18
19 IDAHO
133,191 20 3RD PARTY TRANS O&M
-542 21 OTHER ELECTRIC (EXCL
22
23 OREGON
174,417 24 3RD PARTY TRANS O&M
17,090 25 OTHER ELECTRIC DSR CARRY
2,034,112 26 OTHER ELECTRIC (EXCL WHL
10,244 27 I/C TRANS O&M REVENUE -
28
29 UTAH
329,960 30 3RD PARTY TRANS O&M
2,300 31 FISH, WILDLIFE, RECR
1,823,965 32 FLYASH SALES
1,113,002 33 M&S INVENTORY REVENUE
81,141 34 ELECTRIC INCOME - OTHER
35
36 WASHINGTON
479 37 3RD PARTY TRANS O&M
6,634 38 FISH, WILDLIFE, RECR
-52,188 39 WA - COLSTRIP 3
-458 40 OTHER ELECTRIC (EXCL WHL
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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
/ /2013/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 WYOMING
58,708 3 3RD PARTY TRANS O&M
1,439,192 4 FLYASH SALES
1,673 5 FLYASH SALES
276,016 6 WY-REGULATORY RECOVERY
15 7 ELECTRIC INCOME - OTHER
-25 8 DSM REVENUE - WY SBC - CAT 2
9
62,721,257 10 TOTAL OTHER ELEC REVENUE
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
55,662,873 4,740,900,075 1,766,984 31,502 0.0852
73,318 7,359,000 0 0 0.1004
55,589,555 4,733,541,075 1,766,984 31,460 0.0852
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 FOR RESALE (Account 447)
PacifiCorp X / /2013/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 202121T-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
3 Phases Renewables, LLC NANANAT-12SF 13
Arizona Public Service Company 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 / /2013/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
3,506,889 2,797,856 6,304,745 125,517 2
14,368 11,454 25,822 802 3
117,297 120,700 237,997 6,633 4
66,399 72,477 138,876 3,754 5
17,181 18,182 35,363 986 6
159,774 139,402 19,791 318,967 9,388 7
1,059,831 1,059,831 11,447 8
2,014,956 1,663,276 3,678,232 72,332 9
-64,480 -64,480 -577 10
11
12
582,754 582,754 12,956 13
3,429,634 3,429,634 103,946 14
FERC FORM NO. 1 (ED. 12-90) Page 311
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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 / /2013/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-12SF 1
Avista Corporation NANANAT-13SF 2
BP Energy Company NANANAT-12SF 3
Barclays Bank PLC NANANAT-12SF 4
Basin Electric Power Cooperative NANANAT-11AD 5
Basin Electric Power Cooperative NANANAT-12SF 6
Black Hills Power, Inc.NANANA441AD 7
Black Hills Power, Inc.475250441LF 8
Black Hills Power, Inc.NANANAT-12SF 9
Bonneville Power Administration NANANAT-11AD 10
Bonneville Power Administration NANANAT-12AD 11
Bonneville Power Administration NANANA368LF 12
Bonneville Power Administration NANANAT-11LF 13
Bonneville Power Administration NANANA519LU 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 / /2013/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.
2,100,087 2,100,087 73,399 1
3,098 3,098 96 2
2,839,433 2,839,433 90,097 3
800,371 800,371 23,575 4
-8 -8 5
799,061 799,061 23,722 6
-36,701 -36,701 -1,824 7
6,309,504 7,341,126 -384,413 13,266,217 338,283 8
5,439,959 5,439,959 203,244 9
-48,263 -48,263 -2,059 10
180,917 180,917 11
71,328 71,328 2,305 12
343,501 343,501 11,149 13
2,451,087 2,451,087 34,076 14
FERC FORM NO. 1 (ED. 12-90) Page 311.1
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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 / /2013/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.
Bonneville Power Administration NANANAT-11SF 1
Bonneville Power Administration NANANAT-12SF 2
Bonneville Power Administration NANANAT-13SF 3
British Columbia Hydro and Power NANANAT-13SF 4
Brookfield Energy Marketing L.P.NANANAT-12SF 5
California Independent System Operator NANANAT-12AD 6
California Independent System Operator NANANAT-12SF 7
Calpine Energy Services, L.P.NANANAT-12AD 8
Calpine Energy Services, L.P.NANANAT-12SF 9
Cargill Power Markets, LLC NANANAT-11AD 10
Cargill Power Markets, LLC NANANAT-12AD 11
Cargill Power Markets, LLC NANANAT-12IF 12
Cargill Power Markets, LLC NANANAT-11SF 13
Cargill Power Markets, LLC 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 / /2013/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.
14,827 14,827 496 1
4,827,193 4,827,193 180,298 2
3,553 3,553 110 3
3,196 3,196 79 4
1,182,151 1,182,151 41,231 5
22,490 22,490 1,504 6
157 157 7
4,924 4,924 182 8
7,921,043 7,921,043 267,780 9
-31,240 -31,240 -1,578 10
11,051 11,051 290 11
16,601,200 16,601,200 246,400 12
183,680 183,680 5,012 13
22,880,176 22,880,176 706,344 14
FERC FORM NO. 1 (ED. 12-90) Page 311.2
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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 / /2013/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 Anaheim NANANAT-12SF 1
City of Burbank NANANAT-12SF 2
City of Glendale NANANAT-12SF 3
City of Hurricane NANANAT-12LF 4
City of Redding NANANAT-12SF 5
City of Santa Clara NANANAT-12SF 6
Clatskanie People's Utility District NANANAT-12SF 7
Constellation Energy Commodities Group NANANAT-11AD 8
Constellation Energy Commodities Group NANANAT-11SF 9
Constellation Energy Commodities Group NANANAT-12SF 10
Deseret Generation & Transmission NANANAT-11SF 11
EDF Trading North America, LLC NANANAT-11AD 12
EDF Trading North America, LLC NANANAT-12AD 13
EDF Trading North America, LLC NANANAT-12SF 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 / /2013/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.
2,004,775 2,004,775 48,755 1
6,814,166 6,814,166 236,236 2
170,064 170,064 4,976 3
13,325 13,325 205 4
2,165,437 2,165,437 71,360 5
1,884,612 1,884,612 60,000 6
31,880 31,880 1,056 7
-15,496 -15,496 -1,410 8
1,805 1,805 50 9
1,145,180 1,145,180 37,033 10
178 178 7 11
-257 -257 -17 12
24,177 24,177 1,334 13
28,670,956 28,670,956 876,001 14
FERC FORM NO. 1 (ED. 12-90) Page 311.3
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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 / /2013/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.
El Paso Electric Company NANANAT-12SF 1
Enel Cove Fort, LLC NANANA711LF 2
Eugene Water & Electric Board NANANAT-11AD 3
Eugene Water & Electric Board NANANAT-12SF 4
Exelon Generation Company, LLC NANANAT-12SF 5
Gila River Power LLC NANANAT-12SF 6
Iberdrola Renewables, LLC NANANAT-11AD 7
Iberdrola Renewables, LLC NANANAT-11LF 8
Iberdrola Renewables, LLC NANANAT-11SF 9
Iberdrola Renewables, LLC NANANAT-11SF 10
Iberdrola Renewables, LLC NANANAT-12SF 11
Idaho Power Company NANANAT-11AD 12
Idaho Power Company NANANAT-11LF 13
Idaho Power Company NANANAT-11SF 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 / /2013/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.
1,090,900 1,090,900 33,832 1
25,884 25,884 595 2
-1 -1 3
463,444 463,444 14,738 4
26,613,451 26,613,451 777,210 5
3,466,800 3,466,800 121,280 6
-57,952 -57,952 -2,499 7
104,253 104,253 3,329 8
348,891 348,891 10,779 9
1,785 1,785 58 10
24,800,670 24,800,670 792,705 11
-15,465 -15,465 -638 12
102,112 102,112 2,814 13
24,105 24,105 669 14
FERC FORM NO. 1 (ED. 12-90) Page 311.4
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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 / /2013/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.
Idaho Power Company NANANAT-12SF 1
Idaho Power Company NANANAT-13SF 2
J. Aron & Company NANANAT-12SF 3
J.P. Morgan Ventures Energy Corporation NANANAT-11AD 4
J.P. Morgan Ventures Energy Corporation NANANAT-11SF 5
J.P. Morgan Ventures Energy Corporation NANANAT-11SF 6
J.P. Morgan Ventures Energy Corporation NANANAT-12SF 7
Los Angeles Dept. of Water and Power NANANAT-11AD 8
Los Angeles Dept. of Water and Power NANANA301LU 9
Los Angeles Dept. of Water and Power NANANAT-11SF 10
Los Angeles Dept. of Water and Power NANANAT-12SF 11
Macquarie Energy LLC NANANAT-11SF 12
Macquarie Energy LLC NANANAT-12SF 13
Modesto Irrigation District NANANAT-12SF 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 / /2013/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.
354,752 354,752 12,573 1
8,799 8,799 251 2
27,129,794 27,129,794 822,456 3
-12,752 -12,752 -595 4
840 840 27 5
90,381 90,381 3,130 6
1,030,904 1,030,904 36,550 7
-944 -944 -40 8
28,954,728 28,954,728 568,255 9
5,184 5,184 188 10
540,654 540,654 18,772 11
57,347 57,347 1,557 12
3,152,302 3,152,302 105,108 13
3,138,191 3,138,191 89,435 14
FERC FORM NO. 1 (ED. 12-90) Page 311.5
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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 / /2013/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.
Morgan Stanley Capital Group, Inc.NANANAT-11AD 1
Morgan Stanley Capital Group, Inc.NANANAT-11SF 2
Morgan Stanley Capital Group, Inc.NANANAT-12SF 3
Municipal Energy Agency of Nebraska NANANAT-12SF 4
NaturEner Power Watch, LLC NANANAT-13SF 5
Nevada Power Company NANANAT-11SF 6
Nevada Power Company NANANAT-12SF 7
NextEra Energy Power Marketing, LLC NANANAT-11AD 8
NextEra Energy Power Marketing, LLC NANANAT-11LF 9
NextEra Energy Power Marketing, LLC NANANAT-11SF 10
NextEra Energy Power Marketing, LLC NANANAT-11SF 11
NextEra Energy Power Marketing, LLC NANANAT-12SF 12
Noble Americas Gas & Power Corp.NANANAT-12SF 13
NorthWestern Corporation NANANAT-12SF 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 / /2013/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.
-36,766 -36,766 -1,504 1
352,848 352,848 11,446 2
3,129,581 3,129,581 94,300 3
3,193,665 3,193,665 123,450 4
422 422 17 5
3,083 3,083 86 6
1,832,661 1,832,661 70,821 7
-33,108 -33,108 -1,457 8
299,238 299,238 10,122 9
224 224 8 10
64 64 2 11
5,016 5,016 132 12
123,800 123,800 3,600 13
55,285 55,285 1,910 14
FERC FORM NO. 1 (ED. 12-90) Page 311.6
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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 / /2013/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.
NorthWestern Corporation NANANAT-13SF 1
Northern California Power Agency NANANAT-12SF 2
Northpoint Energy Solutions Inc.NANANAT-12SF 3
PPL EnergyPlus, LLC NANANAT-12SF 4
PPL Montana, LLC NANANAT-11AD 5
PPL Montana, LLC NANANAT-11SF 6
Pacific Gas & Electric Company NANANAT-12AD 7
Pacific Summit Energy LLC NANANAT-12SF 8
Portland General Electric Company NANANAT-11AD 9
Portland General Electric Company NANANAT-11SF 10
Portland General Electric Company NANANAT-12SF 11
Portland General Electric Company NANANAT-13SF 12
Powerex Corporation NANANAT-11AD 13
Powerex Corporation NANANAT-11LF 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 / /2013/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.
6,124 6,124 186 1
21,400 21,400 1,000 2
85,543 85,543 2,974 3
606,032 606,032 20,472 4
-1,166 -1,166 -44 5
6,641 6,641 185 6
14,302 14,302 588 7
4,966,566 4,966,566 61,597 8
-54 -54 -2 9
17,176 17,176 487 10
8,352,129 8,352,129 281,529 11
5,595 5,595 149 12
-280,542 -280,542 -12,650 13
517,681 517,681 16,819 14
FERC FORM NO. 1 (ED. 12-90) Page 311.7
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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 / /2013/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 NANANAT-12AD 3
Public Service Company of Colorado NANANAT-11SF 4
Public Service Company of Colorado NANANAT-12SF 5
Public Service Company of New Mexico NANANAT-12SF 6
PUD #1 of Chelan County NANANAT-13SF 7
PUD #1 of Clark County NANANAT-12SF 8
PUD #1 of Snohomish County NANANAT-12SF 9
PUD #2 of Grant County NANANAT-12SF 10
PUD #2 of Grant County NANANAT-13SF 11
Puget Sound Energy, Inc.NANANAT-12SF 12
Puget Sound Energy, Inc.NANANAT-13SF 13
Rainbow Energy Marketing Corporation NANANAT-11AD 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 / /2013/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.
820,913 820,913 28,003 1
8,368,991 52,550 8,421,541 371,021 2
-3,801 -3,801 -108 3
757 757 34 4
2,877,327 2,877,327 105,984 5
6,855,497 6,855,497 217,341 6
123 123 3 7
119,378 119,378 2,463 8
262,546 262,546 8,218 9
450,874 450,874 16,065 10
414 414 14 11
2,272,746 2,272,746 82,820 12
1,664 1,664 44 13
-5,867 -5,867 -339 14
FERC FORM NO. 1 (ED. 12-90) Page 311.8
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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 / /2013/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.
Rainbow Energy Marketing Corporation NANANAT-11SF 1
Rainbow Energy Marketing Corporation NANANAT-12SF 2
Riverside, City of NANANAT-12SF 3
Sacramento Municipal Utility District NANANA250AD 4
Sacramento Municipal Utility District NANANA250LF 5
Sacramento Municipal Utility District NANANA751LF 6
Sacramento Municipal Utility District NANANAT-12SF 7
Sacramento Municipal Utility District NANANAT-13SF 8
Salt River Project NANANAT-11SF 9
Salt River Project NANANAT-12SF 10
Seattle City Light NANANAT-12SF 11
Seattle City Light NANANAT-13SF 12
Sempra Generation, LLC NANANAT-12SF 13
Shell Energy North America (US), L.P.NANANAT-11AD 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 / /2013/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.
8,312 8,312 328 1
6,222,589 6,222,589 208,745 2
2,161,500 2,161,500 51,525 3
698,634 698,634 4
15,151,441 15,151,441 569,389 5
2,546 2,546 69 6
4,143,071 4,143,071 136,217 7
180 180 6 8
3,491 3,491 97 9
6,447,782 6,447,782 231,506 10
1,294,345 1,294,345 45,035 11
840 840 36 12
6,715,522 6,715,522 213,030 13
-1,239 -1,239 -46 14
FERC FORM NO. 1 (ED. 12-90) Page 311.9
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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 / /2013/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.
Shell Energy North America (US), L.P.NANANAT-12IF 1
Shell Energy North America (US), L.P.NANANAT-11SF 2
Shell Energy North America (US), L.P.NANANAT-12SF 3
Sierra Pacific Power Company NANANAT-11AD 4
Sierra Pacific Power Company NANANAT-3SF 5
Sierra Pacific Power Company NANANAT-11SF 6
Sierra Pacific Power Company NANANAT-12SF 7
Sierra Pacific Power Company NANANAT-13SF 8
Southern California Edison Company NANANAT-11AD 9
Southern California Edison Company NANANAT-11AD 10
Southern California Edison Company NANANAT-11SF 11
Southern California Edison Company NANANAT-11SF 12
Southern California Edison Company NANANAT-12SF 13
Southern California Public Power Auth.NANANAT-11SF 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 / /2013/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.
5,858,032 5,858,032 153,595 1
59,889 59,889 1,901 2
8,253,783 8,253,783 246,000 3
-3,419 -3,419 -144 4
3,254 3,254 140 5
30,310 30,310 615 6
685,389 685,389 25,957 7
11,581 11,581 363 8
-58,750 -58,750 -2,545 9
-922 -922 -37 10
388,219 388,219 9,440 11
1,086 1,086 35 12
10,443,683 10,443,683 356,251 13
246 246 9 14
FERC FORM NO. 1 (ED. 12-90) Page 311.10
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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 / /2013/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.
Southwestern Public Service Company NANANAT-12SF 1
Tacoma Power NANANAT-12SF 2
Tacoma Power NANANAT-13SF 3
Tenaska Power Services Co.NANANAT-11AD 4
Tenaska Power Services Co.NANANAT-11SF 5
Tenaska Power Services Co.NANANAT-12SF 6
The Energy Authority, Inc.NANANAT-11AD 7
The Energy Authority, Inc.NANANAT-11SF 8
The Energy Authority, Inc.NANANAT-12SF 9
Thermo No. 1 BE-01, LLC NANANAT-11AD 10
Thermo No. 1 BE-01, LLC NANANAT-11LF 11
TransAlta Energy Marketing (U.S.) Inc.NANANAT-11AD 12
TransAlta Energy Marketing (U.S.) Inc.NANANAT-12AD 13
TransAlta Energy Marketing (U.S.) Inc.NANANAT-11SF 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 / /2013/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.
717,200 717,200 22,850 1
1,054,461 1,054,461 41,635 2
127 127 2 3
-5,299 -5,299 -205 4
104,522 104,522 3,010 5
12,525,903 12,525,903 426,419 6
-176 -176 -12 7
977 977 41 8
1,383,973 1,383,973 42,675 9
-7,967 -7,967 -346 10
91,040 91,040 2,881 11
-3,684 -3,684 -199 12
8,349 8,349 225 13
40,795 40,795 1,395 14
FERC FORM NO. 1 (ED. 12-90) Page 311.11
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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 / /2013/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.
TransAlta Energy Marketing (U.S.) Inc.NANANAT-12SF 1
TransCanada Energy Sales Ltd.NANANAT-12SF 2
Tri-State Gen. & Trans.NANANAT-11AD 3
Tri-State Gen. & Trans.NANANAT-11SF 4
Tri-State Gen. & Trans.NANANAT-12SF 5
Tucson Electric Power Company NANANAT-12SF 6
Turlock Irrigation District NANANAT-12SF 7
Twin Eagle Resource Management, LLC NANANAT-12SF 8
UNS Electric, Inc.NANANAT-12SF 9
Utah Associated Municipal Power Systems NANANAT-11AD 10
Utah Associated Municipal Power Systems NANANAT-11SF 11
Utah Associated Municipal Power Systems NANANAT-12SF 12
Utah Municipal Power Agency 343434433LF 13
Utah Municipal Power Agency NANANAT-3SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.12
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 / /2013/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.
11,440,499 11,440,499 393,129 1
18,800 18,800 600 2
-8,608 -8,608 -339 3
24,257 24,257 751 4
5,814,391 5,814,391 213,650 5
11,067,994 11,067,994 382,774 6
39,568 39,568 1,002 7
175,587 175,587 6,488 8
9,169,276 9,169,276 308,825 9
-1,722 -1,722 -65 10
4,182 4,182 134 11
1,266,781 1,266,781 44,657 12
5,187,029 4,396,200 9,583,229 223,194 13
666,437 666,437 25,832 14
FERC FORM NO. 1 (ED. 12-90) Page 311.12
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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 / /2013/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.
Western Area Power Administration NANANAT-11AD 1
Western Area Power Administration NANANAT-11SF 2
Western Area Power Administration NANANAT-12SF 3
Reserve for potential refunds NANANANA 4
Netting - Bookouts NANANANA 5
Netting - Trading NANANANA 6
Accrual NANANANA 7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 310.13
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 / /2013/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.
-6,068 -6,068 -310 1
838 838 23 2
16,259,998 16,259,998 516,945 3
634,716 634,716 4
-129,340,690 -129,340,690 -3,558,566 5
-1,479,332 -1,479,332 6
-1,470,562 -1,470,562 2,217 7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 311.13
6,956,695
429,548,120
436,504,815
230,282
9,975,853
10,206,135
-44,689 11,735,353
-127,499,972
-127,544,661
313,785,474
325,520,827
4,823,347
11,737,326
16,560,673
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.: 7 Column: j
Settlement adjustment.
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.: 2 Column: j
Reserve share.
Schedule Page: 310.1 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 5 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 7 Column: j
Settlement adjustment.
Schedule Page: 310.1 Line No.: 8 Column: b
Black Hills Power Inc. - FERC 441 - Contract termination date: December 31, 2023.
Schedule Page: 310.1 Line No.: 8 Column: j
Liquidated damages.
Schedule Page: 310.1 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 10 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 11 Column: j
Settlement adjustment.
Schedule Page: 310.1 Line No.: 12 Column: b
Bonneville Power Administration - FERC, 5th revised R.S. 368 [Use of Facilities Agreement
for Malin Transformer under the AC Intertie Agreement with BPA] - Contract termination
date: Upon Mutual agreement.
Schedule Page: 310.1 Line No.: 12 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 13 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.: 13 Column: j
Transmission losses.
Schedule Page: 310.2 Line No.: 1 Column: j
Transmission losses.
Schedule Page: 310.2 Line No.: 3 Column: j
Reserve share.
Schedule Page: 310.2 Line No.: 4 Column: a
This footnote applies to all occurrences of "British Columbia Hydro and Power" on pages
310-311. Complete name is British Columbia Hydro and Power Authority.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 310.2 Line No.: 4 Column: j
Reserve share.
Schedule Page: 310.2 Line No.: 6 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.: 6 Column: b
Settlement adjustment.
Schedule Page: 310.2 Line No.: 6 Column: j
Settlement adjustment.
Schedule Page: 310.2 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 310.2 Line No.: 8 Column: j
Settlement adjustment.
Schedule Page: 310.2 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 310.2 Line No.: 10 Column: j
Transmission losses.
Schedule Page: 310.2 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 310.2 Line No.: 11 Column: j
Settlement adjustment.
Schedule Page: 310.2 Line No.: 13 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 4 Column: b
City of Hurricane - FERC T-12 - Contract termination date: August 31, 2017.
Schedule Page: 310.3 Line No.: 8 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.: 8 Column: b
Settlement adjustment.
Schedule Page: 310.3 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 11 Column: a
This footnote applies to all occurrences of "Deseret Generation & Transmission" on pages
310-311. Complete name is Deseret Generation and Transmission Co-operative.
Schedule Page: 310.3 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 310.3 Line No.: 12 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 310.3 Line No.: 13 Column: j
Settlement adjustment.
Schedule Page: 310.4 Line No.: 2 Column: b
Enel Cove Fort, LLC - FERC 711 - (4th revised S.A. 706) - Contract termination date: April
30, 2045.
Schedule Page: 310.4 Line No.: 2 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 3 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 310.4 Line No.: 3 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 310.4 Line No.: 7 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 8 Column: b
Iberdrola Renewables, LLC - FERC T-11 [Point-to-Point Transmission Service under the Open
Access Transmission Tariff (8th revised S.A. 279)] - Contract termination date: April 30,
2019.
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.: 10 Column: j
Unauthorized use charges.
Schedule Page: 310.4 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 310.4 Line No.: 12 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 13 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, 2019.
Schedule Page: 310.4 Line No.: 13 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 2 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 310.5 Line No.: 4 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 5 Column: j
Unauthorized use charges.
Schedule Page: 310.5 Line No.: 6 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 8 Column: a
This footnote applies to all occurrences of "Los Angeles Dept. of Water and Power" on
pages 310-311. Complete name is Los Angeles Department of Water and Power.
Schedule Page: 310.5 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 310.5 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 10 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 12 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 310.6 Line No.: 1 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 2 Column: j
Transmission losses.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 310.6 Line No.: 5 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 6 Column: a
This footnote applies to all occurrences of "Nevada Power Company" on pages 310-311.
Nevada Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect
wholly owned subsidiary of MidAmerican Energy Holdings Company.
Schedule Page: 310.6 Line No.: 6 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 310.6 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 9 Column: b
NextEra Energy Power Marketing, LLC - FERC T-11 [Point-to-Point Transmission Service under
the Open Access Transmission Tariff (2nd revised S.A. 733)] - Contract termination date:
November 17, 2017.
Schedule Page: 310.6 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 10 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 11 Column: j
Unauthorized use charges.
Schedule Page: 310.7 Line No.: 1 Column: j
Reserve share.
Schedule Page: 310.7 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 310.7 Line No.: 5 Column: j
Transmission losses.
Schedule Page: 310.7 Line No.: 6 Column: j
Transmission losses.
Schedule Page: 310.7 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 310.7 Line No.: 7 Column: j
Settlement adjustment.
Schedule Page: 310.7 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 310.7 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.7 Line No.: 10 Column: j
Transmission losses.
Schedule Page: 310.7 Line No.: 12 Column: j
Reserve share.
Schedule Page: 310.7 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 310.7 Line No.: 13 Column: j
Transmission losses.
Schedule Page: 310.7 Line No.: 14 Column: b
Powerex Corporation - FERC T-11 [Point-to-Point Transmission Service under the Open Access
Transmission Tariff (8th revised S.A. 169)] - Contract termination date: October 31, 2020.
Schedule Page: 310.7 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 1 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 2 Column: j
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Pond sales.
Schedule Page: 310.8 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 310.8 Line No.: 3 Column: j
Settlement adjustment.
Schedule Page: 310.8 Line No.: 4 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 7 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: 310.8 Line No.: 7 Column: j
Reserve share.
Schedule Page: 310.8 Line No.: 8 Column: a
This footnote applies to all occurrences of "PUD #1 of Clark County" on pages 310-311.
Complete name is Public Utility District No. 1 of Clark County.
Schedule Page: 310.8 Line No.: 9 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: 310.8 Line No.: 10 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: 310.8 Line No.: 11 Column: j
Reserve share.
Schedule Page: 310.8 Line No.: 13 Column: j
Reserve share.
Schedule Page: 310.8 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 310.8 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.9 Line No.: 1 Column: j
Transmission losses.
Schedule Page: 310.9 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 310.9 Line No.: 4 Column: j
Settlement adjustment.
Schedule Page: 310.9 Line No.: 5 Column: b
Sacramento Municipal Utility District - FERC 250 - Contract termination date: December 31,
2014.
Schedule Page: 310.9 Line No.: 6 Column: b
Sacramento Municipal Utility District - FERC 751 [Point-to-Point Transmission Service
under the Open Access Transmission Tariff] - Contract termination date: September 30,
2018.
Schedule Page: 310.9 Line No.: 6 Column: j
Transmission losses.
Schedule Page: 310.9 Line No.: 8 Column: j
Reserve share.
Schedule Page: 310.9 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.9 Line No.: 12 Column: j
Reserve share.
Schedule Page: 310.9 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 310.9 Line No.: 14 Column: j
Transmission losses.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Schedule Page: 310.10 Line No.: 2 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 4 Column: a
This footnote applies to all occurrences of "Sierra Pacific Power Company" on pages
310-311. Sierra Pacific Power Company is a principal subsidiary of NV Energy, Inc., which
is an indirect wholly owned subsidiary of MidAmerican Energy Holdings Company.
Schedule Page: 310.10 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 310.10 Line No.: 4 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 6 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 8 Column: j
Reserve share.
Schedule Page: 310.10 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 310.10 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 310.10 Line No.: 10 Column: j
Unauthorized use charges.
Schedule Page: 310.10 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 12 Column: j
Unauthorized use charges.
Schedule Page: 310.10 Line No.: 14 Column: a
This footnote applies to all occurrences of "Southern California Public Power Auth." on
pages 310-311. Complete name is Southern California Public Power Authority.
Schedule Page: 310.10 Line No.: 14 Column: j
Unauthorized use charges.
Schedule Page: 310.11 Line No.: 3 Column: j
Reserve share.
Schedule Page: 310.11 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 310.11 Line No.: 4 Column: j
Transmission losses.
Schedule Page: 310.11 Line No.: 5 Column: j
Transmission losses.
Schedule Page: 310.11 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 310.11 Line No.: 7 Column: j
Transmission losses.
Schedule Page: 310.11 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.11 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 310.11 Line No.: 10 Column: j
Transmission losses.
Schedule Page: 310.11 Line No.: 11 Column: b
Thermo No. 1 BE-01, LLC - FERC T-11 [Point-to-Point Transmission Service under the Open
Access Transmission Tariff (3rd revised S.A. 568)] - Contract termination date: April 30,
2029.
Schedule Page: 310.11 Line No.: 11 Column: j
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
Transmission losses.
Schedule Page: 310.11 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 310.11 Line No.: 12 Column: j
Transmission losses.
Schedule Page: 310.11 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 310.11 Line No.: 13 Column: j
Settlement adjustment.
Schedule Page: 310.11 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.12 Line No.: 3 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: 310.12 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 310.12 Line No.: 3 Column: j
Transmission losses.
Schedule Page: 310.12 Line No.: 4 Column: j
Transmission losses.
Schedule Page: 310.12 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 310.12 Line No.: 10 Column: j
Transmission losses.
Schedule Page: 310.12 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.12 Line No.: 13 Column: b
Utah Municipal Power Agency - FERC 433 - Contract termination date: June 30, 2017.
Schedule Page: 310.13 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 310.13 Line No.: 1 Column: j
Transmission losses.
Schedule Page: 310.13 Line No.: 2 Column: j
Transmission losses.
Schedule Page: 310.13 Line No.: 4 Column: j
Transmission losses.
Schedule Page: 310.13 Line No.: 5 Column: j
Reflects transactions that did not physically settle.
Schedule Page: 310.13 Line No.: 6 Column: j
Reflects transactions that did not physically settle.
Schedule Page: 310.13 Line No.: 7 Column: j
Represents the difference between actual non-requirement sales revenues for the period as
reflected on the individual line items within this schedule, and the accruals charged to
Account 447, 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
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
/ /2013/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 19,142,283 18,091,723
(501) Fuel 5 768,997,788 836,194,561
(502) Steam Expenses 6 41,809,206 43,916,579
(503) Steam from Other Sources 7 3,937,027 4,312,439
(Less) (504) Steam Transferred-Cr. 8
(505) Electric Expenses 9 3,896,688 3,949,096
(506) Miscellaneous Steam Power Expenses 10 56,759,531 55,018,295
(507) Rents 11 396,587 496,045
(509) Allowances 12
TOTAL Operation (Enter Total of Lines 4 thru 12) 13 894,939,110 961,978,738
Maintenance 14
(510) Maintenance Supervision and Engineering 15 6,378,884 7,331,481
(511) Maintenance of Structures 16 25,384,395 29,996,120
(512) Maintenance of Boiler Plant 17 107,992,173 103,206,206
(513) Maintenance of Electric Plant 18 35,012,328 31,091,746
(514) Maintenance of Miscellaneous Steam Plant 19 12,158,343 14,777,438
TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 186,926,123 186,402,991
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 1,081,865,233 1,148,381,729
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 4,711,673 7,551,949
(536) Water for Power 45 134,519 197,600
(537) Hydraulic Expenses 46 4,265,329 4,009,780
(538) Electric Expenses 47
(539) Miscellaneous Hydraulic Power Generation Expenses 48 18,412,058 15,446,587
(540) Rents 49 661,711 1,075,124
TOTAL Operation (Enter Total of Lines 44 thru 49) 50 28,185,290 28,281,040
C. Hydraulic Power Generation (Continued) 51
Maintenance 52
(541) Mainentance Supervision and Engineering 53 388 506
(542) Maintenance of Structures 54 825,279 1,156,074
(543) Maintenance of Reservoirs, Dams, and Waterways 55 2,088,303 2,292,070
(544) Maintenance of Electric Plant 56 1,974,573 2,907,970
(545) Maintenance of Miscellaneous Hydraulic Plant 57 2,936,126 4,284,443
TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 7,824,669 10,641,063
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 36,009,959 38,922,103
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
/ /2013/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 62 369,904 448,713
(547) Fuel 63 364,507,540 321,290,415
(548) Generation Expenses 64 17,430,953 14,406,401
(549) Miscellaneous Other Power Generation Expenses 65 9,147,157 10,582,172
(550) Rents 66 3,662,580 4,649,553
TOTAL Operation (Enter Total of lines 62 thru 66) 67 395,118,134 351,377,254
Maintenance 68
(551) Maintenance Supervision and Engineering 69
(552) Maintenance of Structures 70 2,291,254 3,029,122
(553) Maintenance of Generating and Electric Plant 71 25,781,191 17,613,519
(554) Maintenance of Miscellaneous Other Power Generation Plant 72 1,966,376 3,121,555
TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 30,038,821 23,764,196
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 425,156,955 375,141,450
E. Other Power Supply Expenses 75
(555) Purchased Power 76 535,586,277 666,554,057
(556) System Control and Load Dispatching 77 1,546,050 1,439,706
(557) Other Expenses 78 62,779,248 66,410,600
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 599,911,575 734,404,363
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 2,142,943,722 2,296,849,645
2. TRANSMISSION EXPENSES 81
Operation 82
(560) Operation Supervision and Engineering 83 5,532,584 6,231,709
84
(561.1) Load Dispatch-Reliability 85
(561.2) Load Dispatch-Monitor and Operate Transmission System 86 6,733,470 7,218,959
(561.3) Load Dispatch-Transmission Service and Scheduling 87
(561.4) Scheduling, System Control and Dispatch Services 88 239,500 292,567
(561.5) Reliability, Planning and Standards Development 89 850,396 1,114,579
(561.6) Transmission Service Studies 90 127,861 89,710
(561.7) Generation Interconnection Studies 91 617,977 861,392
(561.8) Reliability, Planning and Standards Development Services 92
(562) Station Expenses 93 2,984,932 3,029,593
(563) Overhead Lines Expenses 94 285,237 353,289
(564) Underground Lines Expenses 95
(565) Transmission of Electricity by Others 96 142,125,115 137,182,304
(566) Miscellaneous Transmission Expenses 97 3,696,068 4,162,643
(567) Rents 98 1,497,301 2,755,216
TOTAL Operation (Enter Total of lines 83 thru 98) 99 164,690,441 163,291,961
Maintenance 100
(568) Maintenance Supervision and Engineering 101 2,486,358 1,608,159
(569) Maintenance of Structures 102 1,145 181,944
(569.1) Maintenance of Computer Hardware 103 203,102 247,522
(569.2) Maintenance of Computer Software 104 1,001,012 318,385
(569.3) Maintenance of Communication Equipment 105 3,270,838 3,584,282
(569.4) Maintenance of Miscellaneous Regional Transmission Plant 106
(570) Maintenance of Station Equipment 107 11,423,719 10,141,753
(571) Maintenance of Overhead Lines 108 20,575,947 18,707,537
(572) Maintenance of Underground Lines 109 82,622 72,498
(573) Maintenance of Miscellaneous Transmission Plant 110 2,748,898 516,090
TOTAL Maintenance (Total of lines 101 thru 110) 111 41,793,641 35,378,170
TOTAL Transmission Expenses (Total of lines 99 and 111) 112 206,484,082 198,670,131
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
/ /2013/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 14,093,118 13,049,994
(581) Load Dispatching 135 13,036,839 12,422,223
(582) Station Expenses 136 4,078,201 4,264,228
(583) Overhead Line Expenses 137 5,526,165 6,083,986
(584) Underground Line Expenses 138 249 496
(585) Street Lighting and Signal System Expenses 139 222,740 202,145
(586) Meter Expenses 140 7,071,031 7,072,984
(587) Customer Installations Expenses 141 12,473,499 11,097,401
(588) Miscellaneous Expenses 142 4,562,147 4,751,998
(589) Rents 143 3,366,940 3,698,889
TOTAL Operation (Enter Total of lines 134 thru 143) 144 64,430,929 62,644,344
Maintenance 145
(590) Maintenance Supervision and Engineering 146 4,472,548 6,186,943
(591) Maintenance of Structures 147 1,310,306 1,710,762
(592) Maintenance of Station Equipment 148 10,993,806 11,897,335
(593) Maintenance of Overhead Lines 149 88,718,266 89,950,166
(594) Maintenance of Underground Lines 150 20,313,015 21,363,704
(595) Maintenance of Line Transformers 151 957,612 1,024,257
(596) Maintenance of Street Lighting and Signal Systems 152 3,704,762 3,591,531
(597) Maintenance of Meters 153 6,749,398 6,666,726
(598) Maintenance of Miscellaneous Distribution Plant 154 2,027,649 3,403,630
TOTAL Maintenance (Total of lines 146 thru 154) 155 139,247,362 145,795,054
TOTAL Distribution Expenses (Total of lines 144 and 155) 156 203,678,291 208,439,398
5. CUSTOMER ACCOUNTS EXPENSES 157
Operation 158
(901) Supervision 159 2,603,420 2,441,991
(902) Meter Reading Expenses 160 20,679,578 19,662,071
(903) Customer Records and Collection Expenses 161 53,770,351 52,388,395
(904) Uncollectible Accounts 162 14,337,468 12,924,355
(905) Miscellaneous Customer Accounts Expenses 163 142,188 117,514
TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 91,533,005 87,534,326
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
/ /2013/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 167 301,706 331,132
(908) Customer Assistance Expenses 168 103,156,102 112,671,756
(909) Informational and Instructional Expenses 169 3,294,390 3,484,752
(910) Miscellaneous Customer Service and Informational Expenses 170 204,557 117,029
TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 106,956,755 116,604,669
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 74,368,102 76,754,883
(921) Office Supplies and Expenses 182 8,706,781 8,363,743
(Less) (922) Administrative Expenses Transferred-Credit 183 27,128,855 29,238,955
(923) Outside Services Employed 184 13,277,918 16,481,262
(924) Property Insurance 185 16,404,849 13,818,764
(925) Injuries and Damages 186 48,931,701 36,151,606
(926) Employee Pensions and Benefits 187
(927) Franchise Requirements 188
(928) Regulatory Commission Expenses 189 22,965,972 22,768,237
(929) (Less) Duplicate Charges-Cr. 190 4,869,262 4,347,767
(930.1) General Advertising Expenses 191 4,948 1,546
(930.2) Miscellaneous General Expenses 192 7,338,998 7,526,075
(931) Rents 193 6,720,354 6,318,601
TOTAL Operation (Enter Total of lines 181 thru 193) 194 166,721,506 154,597,995
Maintenance 195
(935) Maintenance of General Plant 196 21,518,172 21,202,085
TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 188,239,678 175,800,080
TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 2,939,835,533 3,083,898,249
FERC FORM NO. 1 (ED. 12-93) Page 323
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, 2013 and 2012, pensions and benefits expense was $145,750,552 and $144,687,083,
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
2013/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 / /2013/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 LF 3
NANANAArizona Public Service Company SF 4
NANANAAvista Corporation SF 5
NANANABP Energy Company SF 6
0.010.010.01Ballard Hog Farms Inc. LU 7
NANANABarclays Bank PLC AD 8
NANANABarclays Bank PLC SF 9
NANANABasin Electric Power Cooperative SF 10
NANANABeaver City Corporation LF 11
NANANABell Mountain Hydro, LLC LU 12
NANANABig Top, LLC LU 13
NANANABiomass One, L.P. 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 / /2013/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
73,570 73,570 2 1,640
3,153,294 3,153,294 3 93,837
3,832,474 177,358 4,009,832 4 101,786
4,435,355 7,668 4,443,023 5 135,605
10,302,589 2,083,345 12,385,934 6 336,844
680 2,387 3,067 7 63
8 231
4,113,800 471,315 4,585,115 9 122,800
29,648 29,648 10 1,162
5,979 5,979 11 71
48,729 48,729 12 631
254,612 254,612 13 3,763
11,983,883 2,087,168 14,071,051 14 171,997
FERC FORM NO. 1 (ED. 12-90) Page 327
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANABirch Power Company, Inc. LU 1
NANANABlack Cap Solar, LLC LU 2
NANANABlack Hills Power, Inc. SF 3
NANANABlanding City Corporation LF 4
NANANABonneville Power Administration LF 5
NANANABonneville Power Administration OS 6
NANANABonneville Power Administration OS 7
NANANABonneville Power Administration SF 8
1.32.22.3Box Canyon Limited Partnership LU 9
NANANABrookfield Energy Marketing L.P. SF 10
NANANAButter Creek Power, LLC LU 11
NANANAC Drop Hydro, LLC LU 12
NANANACDM Hydroelectric Company LU 13
NANANACE2 Environmental Markets L.P. OS 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 / /2013/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.
723,842 723,842 1 12,243
7,499 7,499 2 248
682,382 682,382 3 13,566
22,274 22,274 4 297
1,132,440 1,132,440 5
61,938 61,938 6 1,617
32,500 32,500 7
12,833,312 67,267 12,900,579 8 382,957
219,208 1,323,252 1,542,460 9 10,837
455,100 455,100 10 4,600
908,634 908,634 11 13,494
103,477 103,477 12 1,904
1,451,550 1,451,550 13 24,615
44,010 44,010 14
FERC FORM NO. 1 (ED. 12-90) Page 327.1
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANACE2 Environmental Opportunities I L.P. OS 1
NANA200CER Generation II, LLC IU 2
NANANACalifornia Independent System Operator AD 3
NANANACalifornia Independent System Operator SF 4
NANANACalpine Energy Services, L.P. AD 5
NANANACalpine Energy Services, L.P. SF 6
NANANACameron A. Curtiss LU 7
NANANACargill Power Markets, LLC AD 8
NANANACargill Power Markets, LLC IF 9
NANANACargill Power Markets, LLC SF 10
NANANACargill, Incorporated LU 11
2.53.75.6Central Oregon Irrigation District LU 12
NANANAChevron U.S.A. Inc. LU 13
NANANACity of Albany AD 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 / /2013/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.
27,990 27,990 1
7,368,000 21,673,353 29,041,353 2 346,843
15,169 15,169 3 -1,109
8,669,593 8,669,593 4 190,320
1,995 1,995 5 92
18,343,619 18,343,619 6 513,424
3,289 3,289 7 60
-8,907 -8,907 8 -76
17,945,382 17,945,382 9 245,428
6,619,013 -271,096 6,347,917 10 144,816
473,257 473,257 11 7,192
577,297 3,629,166 4,206,463 12 39,232
2,939,829 2,939,829 13 43,971
-1 -1 14
FERC FORM NO. 1 (ED. 12-90) Page 327.2
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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 Albany LU 1
NANANACity of Burbank SF 2
NANANACity of Glendale SF 3
NANANACity of Hurricane LF 4
NANANACity of Pasadena SF 5
NANANACity of Portland, Water Bureau LU 6
NANANACity of Preston Idaho LU 7
NANANAClatskanie People's Utility District SF 8
NANANACommercial Energy Management Inc. LU 9
NANANAConstellation Energy Commodities Group SF 10
NANANACottonwood Hydro, LLC IU 11
NANANACrook County Solar 1, LLC LU 12
3.13.75.7Deschutes Valley Water District LU 13
87100100Deseret Generation & Transmission Coop LF 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 / /2013/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.
141,108 141,108 1 2,044
560,456 560,456 2 10,162
15,000 15,000 3 400
127,553 127,553 4 1,962
79,600 79,600 5 1,520
7,406 7,406 6 137
161,534 161,534 7 2,962
109,714 109,714 8 8,230
62,369 62,369 9 1,142
757,886 77,436 835,322 10 26,000
210,763 210,763 11 3,345
5,830 5,830 12 145
561,548 3,088,962 3,650,510 13 26,675
15,445,275 13,363,006 4,035,350 32,843,631 14 678,610
FERC FORM NO. 1 (ED. 12-90) Page 327.3
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANADeutsche Bank AG SF 1
0.70.90.8Douglas County LU 2
NANANADouglas County, Inc. AD 3
NANANADouglas County, Inc. LU 4
NANANADraper Irrigation Company IU 5
NANANADry Creek LLC LU 6
NANANADuane Wiggins Hydro, Inc. IU 7
NANANAEDF Trading North America, LLC AD 8
NANANAEDF Trading North America, LLC SF 9
NANANAeBay Inc. LU 10
0.30.50.7Eagle Point Irrigation District LU 11
NANANAEl Paso Electric Company SF 12
NANANAEugene Water & Electric Board SF 13
NANANAEurus Combine Hills I, LLC LU 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 / /2013/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.
-2,804,354 -2,804,354 1
91,027 746,774 837,801 2 5,749
20,863 20,863 3 532
387,336 387,336 4 12,342
1,214 1,214 5 26
266,511 266,511 6 5,158
56 56 7 1
11,420 11,420 8 209
6,509,757 367,388 6,877,145 9 214,992
25,664 25,664 10 740
39,326 369,030 408,356 11 3,021
14,430 352 14,782 12 510
656,151 656,151 13 18,117
3,947,242 3,947,242 14 102,419
FERC FORM NO. 1 (ED. 12-90) Page 327.4
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANAEvergreen BioPower, LLC LU 1
NANANAExelon Generation Company, LLC IF 2
NANANAExelon Generation Company, LLC SF 3
NANANAExxonMobil Production Company LU 4
1.63.82.9Falls Creek H.P. Limited Partnership LU 5
NANANAFarm Power Misty Meadow, LLC LU 6
NANANAFarmers Irrigation District LU 7
NANANAFillmore City Corporation LF 8
NANANAFinley BioEnergy, LLC LU 9
NANANAFlathead Electric Cooperative, Inc. LF 10
NANANAFour Corners Windfarm, LLC LU 11
NANANAFour Mile Canyon Windfarm, LLC LU 12
0.70.90.7George DeRuyter & Sons Dairy LU 13
NANANAGeorgetown Irrigation Company LU 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 / /2013/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.
2,218,076 2,218,076 1 34,190
5,619,679 5,619,679 2 123,054
2,523,971 147,508 2,671,479 3 100,608
4,564 4,564 4 151
203,884 1,835,257 2,039,141 5 15,794
139,332 139,332 6 2,810
1,477,026 1,477,026 7 22,759
19,680 19,680 8 182
2,362,039 2,362,039 9 34,266
13,919 13,919 10 432
1,978,574 1,978,574 11 29,364
1,816,914 1,816,914 12 26,947
19,672 194,627 214,299 13 6,124
102,947 102,947 14 1,776
FERC FORM NO. 1 (ED. 12-90) Page 327.5
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANAGila River Power LLC SF 1
NANANAGrand Valley Power LF 2
NANANAGrowPro, Inc. IU 3
NANANAHarold Foster & Robert Walker LU 4
NANANAHermiston Generating Company, L.P. AD 5
184231231Hermiston Generating Company, L.P. LU 6
NANANAIberdrola Renewables, LLC AD 7
NANANAIberdrola Renewables, LLC SF 8
NANANAIdaho Falls, City of AD 9
NANANAIdaho Falls, City of LU 10
NANANAIdaho Power Company OS 11
NANANAIdaho Power Company SF 12
NANANAIngram Warm Springs Ranch Partnership LU 13
NANANAIntermountain Power Agency LU 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 / /2013/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.
1,607,409 1,607,409 1 39,248
17,161 17,161 2 89
1 1 3
35,907 35,907 4 954
-876,467 -876,467 5
36,496,342 62,918,909 454,679 99,869,930 6 1,291,921
7 400
39,944,984 -697,223 39,247,761 8 1,109,345
-84,913 -84,913 9
2,921,763 2,921,763 10 42,705
4,750 4,750 11
1,062,479 2,509 1,064,988 12 34,791
60,519 60,519 13 1,023
28,954,728 28,954,728 14 568,255
FERC FORM NO. 1 (ED. 12-90) Page 327.6
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANAJ Bar 9 Ranch, Inc. AD 1
NANANAJ Bar 9 Ranch, Inc. LU 2
NANANAJ. Aron & Company SF 3
NANANAJP Morgan Ventures Energy Corporation SF 4
NANANAJake Amy LU 5
NANANAJoseph Community Solar LLC LU 6
NANANALacomb Irrigation District LU 7
NANANALos Angeles Dept. of Water & Power AD 8
NANANALos Angeles Dept. of Water & Power SF 9
NANANALower Valley Energy, Inc. IU 10
NANANALower Valley Energy, Inc. LU 11
NANANALoyd Fery LU 12
NANANAMacquarie Energy LLC AD 13
NANANAMacquarie Energy LLC SF 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 / /2013/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.
-198 -198 1
1,525 1,525 2 68
16,084,423 163,858 16,248,281 3 359,981
2,025,127 -1,700,247 324,880 4 80,900
66,910 66,910 5 1,219
23,662 23,662 6 735
127,884 36,850 164,734 7 3,659
-750 -750 8
2,317,004 2,317,004 9 40,795
315,597 315,597 10 5,067
70,768 70,768 11 1,279
22,501 22,501 12 340
13 415
6,738,922 6,738,922 14 169,957
FERC FORM NO. 1 (ED. 12-90) Page 327.7
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANAMarsh Valley Hydro Electric Company LU 1
NANANAMeadow Creek Project Company LLC LU 2
NANANAMiddle Fork Irrigation District LU 3
NANANAMink Creek Hydro LLC LU 4
NANANAModesto Irrigation District SF 5
NANANAMonsanto Company IU 6
NANANAMorgan City Corporation LF 7
NANANAMorgan Stanley Capital Group, Inc. SF 8
NANANAMountain Energy, Inc. LU 9
NANANAMountain Wind Power II, LLC LU 10
NANANAMountain Wind Power, LLC LU 11
NANANAMunicipal Energy Agency of Nebraska SF 12
NANANANaturEner Power Watch, LLC SF 13
NANANANephi City Corporation LF 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 / /2013/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.
191,278 191,278 1 3,230
18,289,862 18,289,862 2 307,676
1,702,598 1,702,598 3 26,144
335,321 335,321 4 5,953
12,150 12,150 5 450
20,000,910 20,000,910 6
2,417 2,417 7 24
16,747,543 275,101 17,022,644 8 390,959
2,026 2,026 9 29
14,497,482 14,497,482 10 227,852
9,227,299 9,227,299 11 166,926
134,320 134,320 12 2,530
103 103 13 4
882 882 14 7
FERC FORM NO. 1 (ED. 12-90) Page 327.8
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANANevada Power Company SF 1
NANANANextEra Energy Power Marketing, LLC SF 2
NANANANicholson's Sunny Bar Ranch LU 3
NANANANoble Americas Gas & Power Corp. SF 4
NANANANorthWestern Corporation SF 5
NANANANorthpoint Energy Solutions Inc. SF 6
NANANANucor Corporation IF 7
NANANAO.J. Power Company LU 8
NANANAOneEnergy, Inc. OS 9
NANANAOregon Environmental Industries, LLC LU 10
NANANAOregon Environmental Industries, LLC OS 11
NANANAOregon State University LU 12
NANANAOregon Trail Windfarm, LLC LU 13
NANANAPPL EnergyPlus, LLC SF 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 / /2013/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.
1,350,007 273,127 1,623,134 1 35,699
790,095 790,095 2 24,824
92,388 92,388 3 1,580
281,600 281,600 4 9,000
7,225 7,225 5 243
3,470 3,470 6 187
5,763,000 5,763,000 7
24,881 24,881 8 481
35,985 35,985 9
1,407,382 1,407,382 10 21,616
5,990 5,990 11
5,061 5,061 12 181
1,804,918 1,804,918 13 26,822
3,860,396 3,860,396 14 112,666
FERC FORM NO. 1 (ED. 12-90) Page 327.9
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANAPacific Canyon Windfarm, LLC LU 1
NANANAPacific Summit Energy LLC SF 2
NANANAPaul Luckey LU 3
NANANAPayson City Corporation LF 4
NANANAPlatte River Power Authority SF 5
NANANAPortland General Electric Company AD 6
NANANAPortland General Electric Company LF 7
NANANAPortland General Electric Company SF 8
NANANAPower County Wind Park North, LLC LU 9
NANANAPower County Wind Park South, LLC LU 10
NANANAPowerex Corporation AD 11
NANANAPowerex Corporation SF 12
NANANAProvo City Corporation LF 13
NANANAPublic Service Company of Colorado SF 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 / /2013/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.
1,357,755 1,357,755 1 20,098
5,367,969 5,367,969 2 61,524
39,641 39,641 3 288
458 458 4 4
75,272 75,272 5 2,275
-103,559 -103,559 6
320,000 320,000 7 12,000
2,613,839 9,131 2,622,970 8 77,057
3,788,855 3,788,855 9 63,984
3,416,416 3,416,416 10 57,523
11 3
32,727,689 559,823 33,287,512 12 605,523
4,394 4,394 13 50
103,530 103,530 14 2,300
FERC FORM NO. 1 (ED. 12-90) Page 327.10
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANAPublic Service Company of New Mexico AD 1
NANANAPublic Service Company of New Mexico SF 2
NANANAPUD No. 1 of Clark County SF 3
NANANAPUD No. 1 of Chelan County OS 4
NANANAPUD No. 1 of Chelan County SF 5
NANANAPUD No. 1 of Cowlitz County OS 6
NANANAPUD No. 1 of Douglas County AD 7
NANANAPUD No. 1 of Douglas County AD 8
NANANAPUD No. 1 of Douglas County LF 9
NANANAPUD No. 1 of Douglas County LU 10
NANANAPUD No. 1 of Douglas County SF 11
NANANAPUD No. 1 of Snohomish County SF 12
NANANAPUD No. 2 of Grant County AD 13
NANANAPUD No. 2 of Grant County 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 / /2013/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.
-23,159 -23,159 1
490,427 490,427 2 14,654
84,270 84,270 3 2,230
24,156 24,156 4
1,066,066 3,780 1,069,846 5 31,327
-355,482 -355,482 6
-55,912 -55,912 7
-128,105 -128,105 8
1,955,593 1,955,593 9 73,057
3,321,835 3,321,835 10 250,922
2,099,606 593 2,100,199 11 61,093
1,415,128 1,415,128 12 43,396
-519,157 -519,157 13 550
-7,211,199 -7,211,199 14 128,302
FERC FORM NO. 1 (ED. 12-90) Page 327.11
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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. 2 of Grant County SF 1
NANANAPuget Sound Energy, Inc. SF 2
NANANARES Ag - Oak Lea LLC LU 3
NANANARainbow Energy Marketing Corporation AD 4
NANANARainbow Energy Marketing Corporation SF 5
NANANARalphs Ranch, Inc. AD 6
NANANARiverside, City of SF 7
NANANARock River 1, LLC LU 8
NANANARoseburg Forest Products Company LU 9
NANANARoseburg LFG Energy, LLC LU 10
NANANARough & Ready Lumber Company LU 11
NANANARoush Hydro Inc. LU 12
NANANASacramento Municipal Utility District AD 13
NANANASacramento Municipal Utility District LF 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 / /2013/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.
1,520,026 3,934 1,523,960 1 44,714
10,541,549 12,231 10,553,780 2 277,053
45,459 45,459 3 832
4 400
976,694 976,694 5 30,436
817 817 6 6
7,080 7,080 7 640
5,023,060 5,023,060 8 141,574
4,072,004 4,072,004 9 92,739
651,928 651,928 10 12,071
78,045 78,045 11 1,363
19,202 19,202 12 278
107,302 107,302 13
3,504,024 3,504,024 14 178,868
FERC FORM NO. 1 (ED. 12-90) Page 327.12
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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 SF 1
NANANASalt River Project SF 2
NANANASan Diego Gas & Electric Company SF 3
NANANASand Ranch Windfarm, LLC LU 4
0.20.20.2Santiam Water Control District LU 5
NANANASeattle City Light SF 6
NANANASempra Generation, LLC AD 7
NANANASempra Generation, LLC SF 8
NANANAShell Energy North America (US), L.P. AD 9
NANANAShell Energy North America (US), L.P. IF 10
NANANAShell Energy North America (US), L.P. SF 11
1.01.42.5Shoshone Irrigation District LU 12
NANANASierra Pacific Power Company SF 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 / /2013/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.
335,400 335,400 1 8,950
2,357,447 70,672 2,428,119 2 57,035
323,950 323,950 3 4,800
1,681,447 1,681,447 4 24,926
13,632 154,860 168,492 5 1,494
3,549,121 3,524 3,552,645 6 110,624
-36 -36 7 -1
623,700 623,700 8 16,800
9 925
2,905,585 2,905,585 10 61,407
12,484,454 -3,605,397 8,879,057 11 382,600
186,682 425,452 612,134 12 9,683
71,800 71,800 13 853
94,865 1,683 96,548 14 2,755
FERC FORM NO. 1 (ED. 12-90) Page 327.13
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
91310Simplot Phosphates LLC LU 1
0.61.13.1Slate Creek Hydro Company, Inc. LU 2
NANANASolwatt LLC LU 3
NANANASouthern California Edison Company SF 4
NANANASpanish Fork Wind Park 2, LLC LU 5
0.20.50.4Sprague Hydro, LLC LU 6
NANANASpringville City Corporation LF 7
NANANAStahlbush Island Farms, Inc. IU 8
NANANAStrawberry Electric Service District LF 9
475352Sunnyside Cogeneration Associates LU 10
NANANASwalley Irrigation District LU 11
NANANATMF Biofuels, LLC AD 12
NANANATMF Biofuels, LLC LU 13
NANANATacoma Power AD 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 / /2013/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.
494,000 4,114,911 4,608,911 1 79,212
90,853 601,424 692,277 2 5,483
16,084 16,084 3 511
65,583 65,583 4 2,310
2,446,795 2,446,795 5 46,031
43,494 315,772 359,266 6 2,601
3,378 3,378 7 28
325,720 325,720 8 5,980
4,398 4,398 9 55
10,726,151 16,193,977 26,920,128 10 414,217
156,483 156,483 11 2,266
1,387 1,387 12 56
1,072,082 1,072,082 13 21,457
50,000 50,000 14 2
FERC FORM NO. 1 (ED. 12-90) Page 327.14
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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
NANANATenaska Power Services Co. SF 2
NANANATesoro Refining & Marketing Company LU 3
0.30.40.3Thayn Hydro LLC LU 4
NANANAThe Energy Authority, Inc. SF 5
0.20.20.2The Town of the City of Buffalo LU 6
NANANAThree Buttes Windpower, LLC LU 7
NANANAThreemile Canyon Wind I, LLC LU 8
NANANATop of The World Wind Energy LLC LU 9
NANANATransAlta Energy Marketing (U.S.) Inc. AD 10
NANANATransAlta Energy Marketing (U.S.) Inc. SF 11
NANANATri-State Gen. & Trans. AD 12
182425Tri-State Gen. & Trans. LF 13
NANANATri-State Gen. & Trans. SF 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 / /2013/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.
1,645,531 1,228 1,646,759 1 61,753
928,093 928,093 2 19,135
894,129 894,129 3 30,148
90,623 253,448 344,071 4 2,861
4,504,388 4,504,388 5 117,850
35,218 190,534 225,752 6 1,846
21,529,508 21,529,508 7 337,785
1,573,813 1,573,813 8 22,982
42,382,819 42,382,819 9 642,164
10 50
27,099,375 27,099,375 11 757,406
229 229 12 9
6,378,000 3,511,610 9,889,610 13 121,509
181,018 214,412 395,430 14 10,574
FERC FORM NO. 1 (ED. 12-90) Page 327.15
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANATuana Springs Energy, LLC OS 1
NANANATucson Electric Power Company SF 2
NANANATwin Eagle Resource Management, LLC SF 3
NANANAU.S. Department of the Interior LU 4
NANANAUNS Electric, Inc. SF 5
NANANAUS Magnesium LLC LF 6
NANANAUnited States Air Force at Hill Base LU 7
NANANAUtah Associated Municipal Power OS 8
NANANAWagon Trail, LLC LU 9
NANANAWard Butte Windfarm, LLC LU 10
NANANAWasatch Integrated Waste Management LU 11
NANANAWeber County LU 12
NANANAWestern Area Power Administration LF 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 / /2013/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.
254,073 254,073 1
439,250 150,909 590,159 2 14,781
414,616 414,616 3 9,200
466 466 4 20
1,934,071 1,934,071 5 53,879
6,441,608 6,441,608 6
649,254 649,254 7 13,703
1,567,390 553,400 2,120,790 8 54,840
527,834 527,834 9 7,823
1,205,942 1,205,942 10 17,935
20,297 20,297 11 368
212,749 212,749 12 4,387
1,145,825 1,145,825 13 30,486
520,709 520,709 14 14,235
FERC FORM NO. 1 (ED. 12-90) Page 327.16
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANAWestern Area Power Administration SF 1
NANANAWolverine Creek Energy, LLC LU 2
0.91.51.7Yakima-Tieton Irrigation District LU 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-11AD 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 / /2013/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.
46,435 29 46,464 1 1,738
8,744,766 8,744,766 2 154,015
19,909 205,106 225,015 3 6,454
214,140 214,140 4 6,615
-50,000 -50,000 5
-1,479,332 -1,479,332 6
-129,340,690 -129,340,690 7 -3,558,121
-4,237,655 -4,237,655 8
1,103,395 1,103,395 9
10
11
571,377 569,772 -1,666,947 -1,666,947 12
1,823 13
-6 22 371 371 14
FERC FORM NO. 1 (ED. 12-90) Page 327.17
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANABasin Electric Power Cooperative T-11EX 1
NANANABonneville Power Administration T-11AD 2
NANANABonneville Power Administration 237AD 3
NANANABonneville Power Administration 237EX 4
NANANABonneville Power Administration 368EX 5
NANANABonneville Power Administration 519EX 6
NANANABonneville Power Administration 554EX 7
NANANABonneville Power Administration T-11EX 8
NANANABonneville Power Administration T-12EX 9
NANANACity of Redding 364EX 10
NANANACyrg Energy T-11EX 11
NANANADeseret Generation & Transmission Coop 280AD 12
NANANADeseret Generation & Transmission Coop 280EX 13
NANANAEmerald People's Utility District 351EX 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 / /2013/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.
160 9,659 297,772 297,772 1
-604 439 3,804 3,804 2
9,634 24,082 24,082 3
26,393 -65,981 -65,981 4
155,901 155,901 5
94,200 102,898 276,984 276,984 6
10,937 222,511 7
8,785 13,259 137,621 137,621 8
27,203 1,075,578 1,075,578 9
109,287 110,006 -130,201 -130,201 10
2,090 2,168 3,942 3,942 11
-85 2,359 -50,703 -50,703 12
47,951 54,246 -95,436 -95,436 13
706 -17,664 -17,664 14
FERC FORM NO. 1 (ED. 12-90) Page 327.18
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANAEugene Water & Electric Board T-12EX 1
NANANAIberdrola Renewables, LLC T-11EX 2
NANANAIdaho Power Company 380EX 3
NANANAJP Morgan Ventures Energy Corporation T-11EX 4
NANANALos Angeles Dept. of Water & Power OV-1EX 5
NANANAMilford Wind Corridor Phase I, LLC OV-1EX 6
NANANAMilford Wind Corridor Phase II, LLC OV-1EX 7
NANANANextEra Energy Power Marketing, LLC T-11EX 8
NANANANoble Americas Energy Solutions LLC T-11AD 9
NANANANoble Americas Energy Solutions LLC T-11EX 10
NANANAPortland General Electric Company 554EX 11
NANANAPublic Service Company of Colorado 334AD 12
NANANAPublic Service Company of Colorado 319EX 13
NANANAPublic Service Company of Colorado 334EX 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 / /2013/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.
16,549 16,966 11,139 11,139 1
3,593 1,481 -79,247 -79,247 2
267,826 431,225 3
1,086 1,937 24,275 24,275 4
6,581 357,807 357,807 5
3,723 -234,217 -234,217 6
2,858 -165,110 -165,110 7
60,467 93,973 980,924 980,924 8
-657 751 6,089 6,089 9
3,683 10,677 179,030 179,030 10
157,094 158,278 11
3 12
3,035 13
1,303,377 1,313,932 5,400,000 5,400,000 14
FERC FORM NO. 1 (ED. 12-90) Page 327.19
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANAPublic Service Company of Colorado T-12EX 1
NANANAPUD No. 1 of Cowlitz County 554EX 2
NANANASeattle City Light 554EX 3
NANANASouthern California Edison Company T-11EX 4
NANANASouthern California Public Power Auth. T-11EX 5
NANANATri-State Gen. and Trans. 319AD 6
NANANATri-State Gen. and Trans. T-11AD 7
NANANATri-State Gen. and Trans. 319EX 8
NANANATri-State Gen. and Trans. T-11EX 9
NANANAUtah Associated Municipal Power T-11AD 10
NANANAUtah Associated Municipal Power T-11EX 11
NANANAUtah Municipal Power Agency T-11AD 12
NANANAUtah Municipal Power Agency T-11EX 13
NANANAWarm Springs Power Enterprises 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 / /2013/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.
78,992 80,919 115,552 115,552 1
209,840 164,497 2
363,404 354,485 534,412 534,412 3
64,293 77,491 387,600 387,600 4
1,772 349 -46,020 -46,020 5
-515 -515 6
-391 74 565 565 7
3,035 51,084 51,084 8
6,115 3,700 -71,627 -71,627 9
-4,241 5,494 38,456 38,456 10
55,739 133,209 2,382,054 2,382,054 11
-1,577 1,991 9,986 9,986 12
11,024 30,206 568,632 568,632 13
1,932 9,571 222,306 222,306 14
FERC FORM NO. 1 (ED. 12-90) Page 327.20
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
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 / /2013/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.
NANANAWestern Area Power Administration LAS-4AD 1
NANANAWestern Area Power Administration LAS-4EX 2
NANANASystem Deviation NA 3
4
5
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 / /2013/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.
11,472 77 -300,043 -300,043 1
49,802 701 -1,225,439 -1,225,439 2
3 -25,182
4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 327.21
12,096,279 4,186,538 3,694,867 79,100,821 654,538,801 -67,085,565 666,554,057
Schedule Page: 326 Line No.: 3 Column: b
Arizona Public Service Company - contract termination date: October 31, 2020.
Schedule Page: 326 Line No.: 4 Column: l
Line loss.
Schedule Page: 326 Line No.: 5 Column: l
Reserve share.
Schedule Page: 326 Line No.: 6 Column: l
Financial swap.
Schedule Page: 326 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 326 Line No.: 9 Column: l
Financial swap.
Schedule Page: 326 Line No.: 11 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326 Line No.: 14 Column: l
Non-generation agreement.
Schedule Page: 326.1 Line No.: 2 Column: a
PacifiCorp has 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.
Schedule Page: 326.1 Line No.: 4 Column: b
Blanding City Corporation - contract termination date: September 26, 2013.
Schedule Page: 326.1 Line No.: 5 Column: b
Bonneville Power Administration - contract termination date: 30 days written notice.
Schedule Page: 326.1 Line No.: 5 Column: l
Ancillary services.
Schedule Page: 326.1 Line No.: 6 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.1 Line No.: 6 Column: l
Ancillary services.
Schedule Page: 326.1 Line No.: 7 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.1 Line No.: 7 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio
standard requirements.
Schedule Page: 326.1 Line No.: 8 Column: l
Reserve share.
Schedule Page: 326.1 Line No.: 14 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.1 Line No.: 14 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio
standard requirements.
Schedule Page: 326.2 Line No.: 1 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.2 Line No.: 1 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio
standard requirements.
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
pages 326-327. Complete name is California Independent System Operator 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
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.: 5 Column: b
Settlement adjustment.
Schedule Page: 326.2 Line No.: 5 Column: l
Settlement adjustment.
Schedule Page: 326.2 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 326.2 Line No.: 8 Column: l
Settlement adjustment.
Schedule Page: 326.2 Line No.: 10 Column: l
Financial swap.
Schedule Page: 326.2 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.2 Line No.: 14 Column: l
Settlement adjustment.
Schedule Page: 326.3 Line No.: 4 Column: b
City of Hurricane - contract termination date: August 31, 2017.
Schedule Page: 326.3 Line No.: 6 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.: 10 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.: 10 Column: l
Financial swap.
Schedule Page: 326.3 Line No.: 14 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: 326.3 Line No.: 14 Column: b
Deseret Generation and Transmission Cooperative - contract termination date: September 30,
2024.
Schedule Page: 326.3 Line No.: 14 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.: 1 Column: l
Financial swap.
Schedule Page: 326.4 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.4 Line No.: 3 Column: l
Settlement adjustment.
Schedule Page: 326.4 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 326.4 Line No.: 8 Column: l
Settlement adjustment.
Schedule Page: 326.4 Line No.: 9 Column: l
Financial swap.
Schedule Page: 326.4 Line No.: 12 Column: l
Line loss.
Schedule Page: 326.5 Line No.: 3 Column: l
Financial swap.
Schedule Page: 326.5 Line No.: 8 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.5 Line No.: 10 Column: b
Flathead Electric Cooperative, Inc. - contract termination date: September 30, 2016.
Schedule Page: 326.5 Line No.: 10 Column: l
Line loss.
Schedule Page: 326.6 Line No.: 2 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.6 Line No.: 5 Column: a
This footnote applies to all occurrences of "Hermiston Generating Company, L.P." on pages
326-327. 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) in this Form
No. 1 for further information on the Hermiston Generating Plant.
Schedule Page: 326.6 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 326.6 Line No.: 5 Column: l
Settlement adjustment.
Schedule Page: 326.6 Line No.: 6 Column: l
On peak incentive, supplemental dispatch efficiency expense, start-up charges and
committee settlements.
Schedule Page: 326.6 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.6 Line No.: 8 Column: l
Financial swap.
Schedule Page: 326.6 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.6 Line No.: 9 Column: l
Labor, equipment and administration fees associated with hydro project in Idaho Falls,
Idaho.
Schedule Page: 326.6 Line No.: 10 Column: l
Labor, equipment and administration fees associated with hydro project in Idaho Falls,
Idaho.
Schedule Page: 326.6 Line No.: 11 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.6 Line No.: 11 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio
standard requirements.
Schedule Page: 326.6 Line No.: 12 Column: l
Reserve share.
Schedule Page: 326.7 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 326.7 Line No.: 1 Column: l
Settlement adjustment.
Schedule Page: 326.7 Line No.: 3 Column: l
Financial swap.
Schedule Page: 326.7 Line No.: 4 Column: l
Financial swap.
Schedule Page: 326.7 Line No.: 7 Column: l
Fixed annual payment.
Schedule Page: 326.7 Line No.: 8 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.: 8 Column: b
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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Settlement adjustment.
Schedule Page: 326.7 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.8 Line No.: 6 Column: l
Compensation for interruptible service and operating reserves.
Schedule Page: 326.8 Line No.: 7 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.8 Line No.: 8 Column: l
Financial swap.
Schedule Page: 326.8 Line No.: 13 Column: l
Reserve share.
Schedule Page: 326.8 Line No.: 14 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.9 Line No.: 1 Column: a
Nevada Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect
wholly owned subsidiary of MidAmerican Energy Holdings Company.
Schedule Page: 326.9 Line No.: 1 Column: l
Line loss.
Schedule Page: 326.9 Line No.: 5 Column: l
Reserve share.
Schedule Page: 326.9 Line No.: 7 Column: l
Ancillary services.
Schedule Page: 326.9 Line No.: 9 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.9 Line No.: 9 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio
standard requirements.
Schedule Page: 326.9 Line No.: 11 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.9 Line No.: 11 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio
standard requirements.
Schedule Page: 326.10 Line No.: 4 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.10 Line No.: 5 Column: l
Line loss.
Schedule Page: 326.10 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.10 Line No.: 6 Column: l
Operation expense plus amortization of unrecovered costs of Cove Project.
Schedule Page: 326.10 Line No.: 7 Column: b
Portland General Electric Company - contract termination date: terminates when the Round
Butte project is no longer operating for power production purposes.
Schedule Page: 326.10 Line No.: 7 Column: l
Operation expense plus amortization of unrecovered costs of Cove Project.
Schedule Page: 326.10 Line No.: 8 Column: l
Reserve share.
Schedule Page: 326.10 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 326.10 Line No.: 12 Column: l
Financial swap.
Schedule Page: 326.10 Line No.: 13 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.11 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Settlement adjustment.
Schedule Page: 326.11 Line No.: 1 Column: l
Line loss.
Schedule Page: 326.11 Line No.: 3 Column: a
This footnote applies to all occurrences of "PUD No. 1 of Clark County" on pages 326-327.
Complete name is Public Utility District No. 1 of Clark County.
Schedule Page: 326.11 Line No.: 4 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: 326.11 Line No.: 4 Column: b
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: 326.11 Line No.: 4 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio
standard requirements.
Schedule Page: 326.11 Line No.: 5 Column: l
Reserve share.
Schedule Page: 326.11 Line No.: 6 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.: 6 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.11 Line No.: 6 Column: l
Liability associated with paper pond at hydro facility located on the Lewis River in
Washington.
Schedule Page: 326.11 Line No.: 7 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.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.11 Line No.: 7 Column: l
Settlement adjustment.
Schedule Page: 326.11 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 326.11 Line No.: 8 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.11 Line No.: 9 Column: b
Public Utility District No. 1 of Douglas County - contract termination date: August 31,
2018.
Schedule Page: 326.11 Line No.: 10 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.11 Line No.: 11 Column: l
Reserve share.
Schedule Page: 326.11 Line No.: 12 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.: 13 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.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.11 Line No.: 13 Column: l
Operating expense, bond interest, amortization and 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Schedule Page: 326.11 Line No.: 14 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.12 Line No.: 1 Column: l
Reserve share.
Schedule Page: 326.12 Line No.: 2 Column: l
Reserve share.
Schedule Page: 326.12 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 326.12 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.12 Line No.: 6 Column: l
Settlement adjustment.
Schedule Page: 326.12 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.12 Line No.: 13 Column: l
Settlement adjustment.
Schedule Page: 326.12 Line No.: 14 Column: b
Sacramento Municipal Utility District - contract termination date: December 31, 2014.
Schedule Page: 326.13 Line No.: 2 Column: l
Line loss.
Schedule Page: 326.13 Line No.: 6 Column: l
Reserve share.
Schedule Page: 326.13 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.13 Line No.: 7 Column: l
Settlement adjustment.
Schedule Page: 326.13 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.13 Line No.: 11 Column: l
Financial swap.
Schedule Page: 326.13 Line No.: 13 Column: a
This footnote applies to all occurrences of "Sierra Pacific Power Company" on pages
326-327. Sierra Pacific Power Company is a principal subsidiary of NV Energy, Inc., which
is an indirect wholly owned subsidiary of MidAmerican Energy Holdings Company.
Schedule Page: 326.13 Line No.: 13 Column: l
Line loss.
Schedule Page: 326.13 Line No.: 14 Column: l
Reserve share.
Schedule Page: 326.14 Line No.: 7 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.14 Line No.: 9 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.14 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.14 Line No.: 12 Column: l
Settlement adjustment.
Schedule Page: 326.14 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.14 Line No.: 14 Column: l
Settlement of Pacific Northwest Refund case.
Schedule Page: 326.15 Line No.: 1 Column: l
Reserve share.
Schedule Page: 326.15 Line No.: 3 Column: a
This footnote applies to all occurrences of "Tesoro Refining & Marketing Company" on pages
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
326-327. Complete name is Tesoro Refining & Marketing Company, LLC.
Schedule Page: 326.15 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.15 Line No.: 12 Column: a
This footnote applies to all occurrences of "Tri-State Gen. & Trans." on pages 326-327.
Complete name is Tri-State Generation and Transmission Association, Inc.
Schedule Page: 326.15 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.15 Line No.: 12 Column: l
Settlement adjustment.
Schedule Page: 326.15 Line No.: 13 Column: b
Tri-State Generation and Transmission Association, Inc. - contract termination date:
December 31, 2020.
Schedule Page: 326.15 Line No.: 14 Column: l
Line loss.
Schedule Page: 326.16 Line No.: 1 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.16 Line No.: 1 Column: l
Purchase of renewable energy credit certificates for Washington renewable portfolio
standard requirements.
Schedule Page: 326.16 Line No.: 2 Column: l
Line loss.
Schedule Page: 326.16 Line No.: 4 Column: a
This footnote applies to all occurrences of "U.S. Department of the Interior" on pages
326-327. Complete name is U.S. Department of the Interior - Bureau of Land Management.
Schedule Page: 326.16 Line No.: 6 Column: b
US Magnesium LLC - contract termination date: December 31, 2014.
Schedule Page: 326.16 Line No.: 6 Column: l
Ancillary services.
Schedule Page: 326.16 Line No.: 7 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.: 8 Column: a
This footnote applies to all occurrences of "Utah Associated Municipal Power" on
pages 326-327. Complete name is Utah Associated Municipal Power Systems.
Schedule Page: 326.16 Line No.: 8 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.16 Line No.: 8 Column: l
Start-up and variable operation and maintenance charges.
Schedule Page: 326.16 Line No.: 11 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.: 13 Column: b
Western Area Power Administration - contract termination date: May 31, 2022.
Schedule Page: 326.16 Line No.: 13 Column: l
Line loss.
Schedule Page: 326.16 Line No.: 14 Column: l
Line loss.
Schedule Page: 326.17 Line No.: 1 Column: l
Reserve share.
Schedule Page: 326.17 Line No.: 5 Column: l
Reversal of reserve for potential liabilities associated with the Pacific Northwest Refund
case.
Schedule Page: 326.17 Line No.: 6 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
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
during this period.
Schedule Page: 326.17 Line No.: 12 Column: l
Exchange energy expense.
Schedule Page: 326.17 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.17 Line No.: 14 Column: l
Imbalance energy.
Schedule Page: 326.18 Line No.: 1 Column: l
Imbalance energy.
Schedule Page: 326.18 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 326.18 Line No.: 2 Column: l
Imbalance energy.
Schedule Page: 326.18 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.18 Line No.: 3 Column: l
Storage and exchange charges.
Schedule Page: 326.18 Line No.: 4 Column: l
Storage and exchange charges.
Schedule Page: 326.18 Line No.: 6 Column: l
Exchange energy expense.
Schedule Page: 326.18 Line No.: 8 Column: l
Imbalance energy.
Schedule Page: 326.18 Line No.: 9 Column: l
Imbalance energy.
Schedule Page: 326.18 Line No.: 10 Column: l
Exchange energy expense.
Schedule Page: 326.18 Line No.: 11 Column: l
Imbalance energy.
Schedule Page: 326.18 Line No.: 12 Column: b
Settlement adjustment.
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
Storage and exchange charges.
Schedule Page: 326.19 Line No.: 1 Column: l
Exchange energy expense.
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
Station service for third party wind project.
Schedule Page: 326.19 Line No.: 6 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
Reimbursement for providing station service to third party wind project.
Schedule Page: 326.19 Line No.: 7 Column: l
Reimbursement for providing station service to third party wind project.
Schedule Page: 326.19 Line No.: 8 Column: l
Imbalance energy.
Schedule Page: 326.19 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.19 Line No.: 9 Column: l
Imbalance energy.
Schedule Page: 326.19 Line No.: 10 Column: l
Imbalance energy.
Schedule Page: 326.19 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.19 Line No.: 14 Column: l
Storage and exchange charges.
Schedule Page: 326.20 Line No.: 1 Column: l
Exchange energy expense.
Schedule Page: 326.20 Line No.: 3 Column: l
Exchange energy expense.
Schedule Page: 326.20 Line No.: 4 Column: l
Imbalance energy.
Schedule Page: 326.20 Line No.: 5 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.: 5 Column: l
Imbalance energy.
Schedule Page: 326.20 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.20 Line No.: 6 Column: l
Imbalance energy.
Schedule Page: 326.20 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.20 Line No.: 7 Column: l
Imbalance energy.
Schedule Page: 326.20 Line No.: 8 Column: l
Imbalance energy.
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: b
Settlement adjustment.
Schedule Page: 326.20 Line No.: 12 Column: l
Imbalance energy.
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
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: 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
2013/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 / /2013/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.
Arizona Public Service Company Arizona Public Service Company OS 1
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation FNO 2
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation AD 3
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation AD 4
Black Hills/Colorado Electric Utility Company NF 5
Black Hills/Colorado Electric Utility Company AD 6
Black Hills/Colorado Electric Utility Company SFP 7
Black Hills/Colorado Electric Utility Company AD 8
Black Hills Corporation Montana-Dakota Utilities FNO 9
Black Hills Corporation Montana-Dakota Utilities AD 10
Black Hills Corporation NF 11
Black Hills Corporation AD 12
Black Hills Corporation SFP 13
Black Hills Corporation AD 14
Black Hills Corporation Black Hills Corporation LFP 15
Black Hills Corporation Black Hills Corporation AD 16
Bonneville Power Administration OS 17
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 18
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 19
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration LFP 20
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 21
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative FNO 22
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative AD 23
Bonneville Power Administration Bonneville Power Administration Benton REA FNO 24
Bonneville Power Administration Bonneville Power Administration Benton REA AD 25
Bonneville Power Administration Bonneville Power Administration Umatilla Electric & Columbia FNO 26
Bonneville Power Administration Bonneville Power Administration Umatilla Electric & Columbia AD 27
Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration LFP 28
Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration AD 29
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 30
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 31
Bonneville Power Administration Bonneville Power Administration Yakama Power FNO 32
Bonneville Power Administration Bonneville Power Administration Yakama Power AD 33
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 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 / /2013/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.
R.S. 436 Borah/Brady Sub 1
Yellowtail SubV11-1,2,3 Sheridan Substation 1 3,960 3,960 2
Yellowtail SubV11-1,2,3 Sheridan Substation 1 877 877 3
VariousV11-1,2 Various 4
VariousV11-1,2,8 Various 137 137 5
VariousV11-1,2 Various 6
VariousV11-1,2,7 Various 1,278 1,278 7
VariousV11-1,2 Various 120 120 8
VariousV11-1,2 Sheridan Substation 48 7,655 7,655 9
VariousV11-1,2 Sheridan Substation 48 2,637 2,637 10
VariousV11-1,2,8 Various 16,569 16,569 11
VariousV11-1,2,8 Various 4,189 4,189 12
VariousV11-1,2,7 Various 3,608 3,608 13
VariousV11-1,2,7 Various 689 689 14
VariousV11-1,2,7 Wyodak Substation 52 159,922 159,922 15
VariousV11-1,2,7 Wyodak Substation 53 13,126 13,126 16
Midpoint SubstationR.S. 369 Summer Lake Sub 17
VariousR.S. 237 Various 316 1,089,709 1,089,709 18
VariousR.S. 237 Various 292 107,030 107,030 19
Lost Creek Hydro PltV11-2,7 Alvey Substation 58 190,684 190,684 20
Lost Creek Hydro PltV11-2,7 Alvey Substation 59 -8,836 -8,836 21
Bonneville Power AdmV11-1,2,3,4 Gazley Substation 3 23,751 23,751 22
Bonneville Power AdmV11-1,2,3 Gazley Substation 4 2,505 2,505 23
Bonneville Power AdmV11-1,2,3 Tieton Substation 1 5,332 5,332 24
Bonneville Power AdmV11-1,2,3 Tieton Substation 1 908 908 25
McNary SubstationV11-1,2,3 Hinkle Substation 1 894 894 26
McNary SubstationV11-1,2,3 Hinkle Substation 1 94 94 27
USBR Green SpringsV11-2,7 Bonneville Power Adm 19 57,151 57,151 28
USBR Green SpringsV11-2,7 Bonneville Power Adm 19 -6,524 -6,524 29
Malin SubstationR.S. 368 Malin Substation 691,534 691,534 30
Malin SubstationR.S. 368 Malin Substation 60,638 60,638 31
Bonneville Power AdmV11-1,2,3,4 6 33,631 33,631 32
Bonneville Power AdmV11-1,2,3,4 5 3,187 3,187 33
VariousR.S. 299 Various 198 1,030,985 1,030,985 34
FERC FORM NO. 1 (ED. 12-90) Page 329
4,438 12,830,379 12,712,106
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 / /2013/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.
1
13,925 38,950 25,025 2
-86 -86 3
-4 -4 4
432 57 375 5
-26 -26 6
10,250 734 9,516 7
-11 -11 8
1,117,870 1,167,289 49,419 9
-54,126 -54,126 10
30,973 1,882 29,091 11
1,566 1,566 12
19,044 1,024 18,020 13
927 927 14
1,210,316 1,263,711 53,395 15
-83,042 -83,042 16
17
4,529,672 4,585,265 55,593 18
346,660 346,660 19
1,355,561 1,370,101 14,540 20
-110,855 -110,855 21
77,588 230,177 152,589 22
6,797 6,797 23
15,423 17,564 2,141 24
-670 -670 25
1,541 1,753 212 26
-701 -701 27
435,718 440,312 4,594 28
-38,242 -38,242 29
246,946 246,946 30
22,450 22,450 31
129,682 236,953 107,271 32
-6,729 -6,729 33
896,621 1,921,194 1,024,573 34
FERC FORM NO. 1 (ED. 12-90) Page 330
38,697,973 85,492,936 34,015,065 12,779,898
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 / /2013/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 Bonneville Power Administration Bonneville Power Administration AD 1
Bonneville Power Administration NF 2
Bonneville Power Administration AD 3
Bonneville Power Administration SFP 4
Bonneville Power Administration AD 5
Bonneville Power Administration Bonneville Power Administration Clark Public Utilities FNO 6
Bonneville Power Administration Bonneville Power Administration Clark Public Utilities AD 7
Cargill Power Markets, LLC NF 8
Cargill Power Markets, LLC AD 9
Cargill Power Markets, LLC SFP 10
Cargill Power Markets, LLC AD 11
Constellation Energy Commodities Group NF 12
Constellation Energy Commodities Group AD 13
Constellation Energy Commodities Group SFP 14
Constellation Energy Commodities Group AD 15
Coral Power NF 16
Coral Power AD 17
Coral Power SFP 18
Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration OS 19
Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration AD 20
Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans.OS 21
Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans.AD 22
Deseret Generation & Trans.NF 23
EDF Trading North America, LLC AD 24
EDF Trading North America, LLC AD 25
Enel Cove Fort, LLC Enel Cove Fort, LLC LFP 26
Enel Cove Fort, LLC Enel Cove Fort, LLC LFP 27
Eugene Water & Electric Board AD 28
Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company OS 29
Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company AD 30
Foote Creek III, LLC Foote Creek III, LLC OS 31
Foote Creek III, LLC Foote Creek III, LLC AD 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 / /2013/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. 299 Various 207 104,202 104,202 1
VariousV11-1,2,3,8 Various 3,076 3,076 2
VariousV11-1,2,3,8 Various 2,422 2,422 3
VariousV11-1,2,3,7 Various 7,602 7,602 4
VariousV11-1,2,3,7 Various 8,322 8,322 5
Cardwell-MerwinV11-1,2,3,4 19 108,186 108,186 6
Cardwell-MerwinV11-1,2,3,4,11 2,939 2,939 7
VariousV11-1,2,8 Various 100,801 100,801 8
VariousV11-1,2,8 Various -34,564 -34,564 9
VariousV11-1,2,7 Various 1,899 1,899 10
VariousV11-1,2 Various -863 -863 11
VariousV11-1,2,8 Various 375 375 12
VariousV11-1,2 Various -33,104 -33,104 13
VariousV11-1-3,7 Various 400 400 14
VariousV11-1,2 Various 15
VariousV11-1,2,8 Various 7,837 7,837 16
VariousV11-1,2,8 Various -970 -970 17
VariousV11-1,2,7 Various 25,210 25,210 18
Swift Unit No. 2R.S. 234 Woodland Substation 19
Swift Unit No. 2R.S. 234 Woodland Substation 20
VariousR.S. 280 Various 104 632,463 632,463 21
VariousR.S. 280 Various 91 61,799 61,799 22
VariousV11-1,2 Various 154 154 23
VariousV11-1,2 Various -256 -256 24
VariousV11-1,2 Various -145 -145 25
Enel Cove FortV11 Red Butte Substation 26
Enel Cove FortV11 Mona Substation 27
VariousV11-1,2 Various -1 -1 28
Targhee SubstationR.S. 322 Goshen Substation 29
Targhee SubstationR.S. 322 Goshen Substation 30
Foote Creek SubS.A 130 Various 31
Foote Creek SubS.A 130 Various 32
VariousV11-1-3,8,9,11 Various 197,421 197,421 33
VariousV11-1-3,8,9,11 Various -16,770 -16,770 34
FERC FORM NO. 1 (ED. 12-90) Page 329.1
4,438 12,830,379 12,712,106
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 / /2013/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.
175,086 175,086 1
17,717 725 16,992 2
12,704 12,704 3
36,724 1,631 35,093 4
41,658 41,658 5
430,388 495,766 65,378 6
-69,223 -69,223 7
884,173 36,725 847,448 8
-14,878 -14,878 9
27,850 10,906 16,944 10
-573 -573 11
1,821 76 1,745 12
-84 -84 13
-43,812 -43,812 14
-33,550 -33,550 15
52,772 2,810 49,962 16
-619 -619 17
103,061 4,245 98,816 18
117,403 117,403 19
10,181 10,181 20
1,977,392 4,350,257 2,372,865 21
1,075,146 1,075,146 22
474 21 453 23
-413 -413 24
-201 -201 25
50,625 50,625 26
81,000 81,000 27
-1 -1 28
138,699 138,699 29
12,609 12,609 30
33,168 33,168 31
3,015 3,015 32
1,656,559 252,460 1,404,099 33
258,158 258,158 34
FERC FORM NO. 1 (ED. 12-90) Page 330.1
38,697,973 85,492,936 34,015,065 12,779,898
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 / /2013/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 SFP 1
Iberdrola Renewables, LLC Iberdrola Renewables, LLC OS 2
Iberdrola Renewables, LLC Iberdrola Renewables, LLC AD 3
Iberdrola Renewables, LLC Exxon Mobil Nevada Power Company LFP 4
Iberdrola Renewables, LLC Exxon Mobil Nevada Power Company AD 5
Iberdrola Renewables, LLC Bonneville Power Administration Oregon Direct Access FNO 6
Iberdrola Renewables, LLC Iberdrola Renewables, LLC LFP 7
Idaho Power Company Idaho Power Company Idaho Power Company OS 8
Idaho Power Company Exxon Mobil Nevada Power Company LFP 9
Idaho Power Company Exxon Mobil Nevada Power Company AD 10
Idaho Power Company OS 11
Idaho Power Company AD 12
Idaho Power Company OS 13
Idaho Power Company AD 14
Idaho Power Company NF 15
Idaho Power Company AD 16
Idaho Power Company SFP 17
Idaho Power Company AD 18
JP Morgan Ventures Energy Corp.NF 19
JP Morgan Ventures Energy Corp.AD 20
JP Morgan Ventures Energy Corp.SFP 21
JP Morgan Ventures Energy Corp.AD 22
Los Angeles Department of Water & Power SFP 23
Los Angeles Department of Water & Power NF 24
Los Angeles Department of Water & Power AD 25
Macquarie Energy, LLC NF 26
Macquarie Energy, LLC SFP 27
Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association OS 28
Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association AD 29
Morgan Stanley Capital Group, Inc.NF 30
Morgan Stanley Capital Group, Inc.AD 31
Morgan Stanley Capital Group, Inc.SFP 32
Morgan Stanley Capital Group, Inc.AD 33
NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD LFP 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 / /2013/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.
VariousV11-1,2,7 Various 12,988 12,988 1
V11-5,6 2
V11-5,6 3
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 31 66,531 66,531 4
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 32 -4,788 -4,788 5
Ponderosa SubstationV11-1,2,3 Various 1 11,114 11,114 6
Malin 500 SubstationV11 Round Mountain Sub 7
Goshen SubstationR.S. 427 Goshen Substation 8
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 78 66,060 66,060 9
Trona SubstationV11-1,2,7 Red Butte/Mona Sub -4,421 -4,421 10
Antelope SubstationR.S. 257 Antelope Substation 188,742 188,742 11
Antelope SubstationR.S. 257 Antelope Substation 22,528 22,528 12
Jim Bridger SubR.S. 203 Bridger Pump Sub 42,883 42,883 13
Jim Bridger SubR.S. 203 Bridger Pump Sub 3,801 3,801 14
VariousV11-1,2,8 Various 12,900 12,900 15
VariousV11-1,2,8 Various -6,841 -6,841 16
VariousV11-1,2,7 Various 2,610 2,610 17
VariousV11-1,2,7 Various -2,209 -2,209 18
VariousV11-1-3,8,11 Various 68,205 68,205 19
VariousV11-1,2,3 Various -4,816 -4,816 20
VariousV11-1,2,7 Various 21
VariousV11-1,2,7 Various -2 -2 22
VariousV11-1,2,7 Various 4,415 4,415 23
VariousV11-1,2,8 Various 24
VariousV11-1,2,9 Various -937 -937 25
VariousV11-1,2,8 Various 19,253 19,253 26
VariousV11-1,2,7 Various 27
DuchesneR.S. 302 Duchesne 24,489 24,489 28
DuchesneR.S. 302 Duchesne 1,862 1,862 29
VariousV11-1-3,8 Various 240,605 240,605 30
VariousV11-1-3,8 Various 8,088 8,088 31
VariousV11-1,2,7 Various 15,520 15,520 32
VariousV11-1,2,7 Various -12,536 -12,536 33
Wallula Substation Wala-MIDC path 94 212,356 212,356 34
FERC FORM NO. 1 (ED. 12-90) Page 329.2
4,438 12,830,379 12,712,106
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 / /2013/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.
203,488 26,755 176,733 1
217,287 217,287 2
23,220 23,220 3
726,189 758,226 32,037 4
-49,825 -49,825 5
24,279 28,266 3,987 6
303,750 303,750 7
8
842,430 877,952 35,522 9
-122,000 -122,000 10
67,672 67,672 11
6,152 6,152 12
14,927 14,927 13
1,357 1,357 14
75,735 3,177 72,558 15
3,411 3,411 16
14,835 710 14,125 17
17,895 17,895 18
1,081,691 178,215 903,476 19
-10,866 -10,866 20
31,416 -4,874 36,290 21
47,661 47,661 22
29,563 1,256 28,307 23
3 3 24
-966 -966 25
73,669 2,963 70,706 26
13,693 10,064 3,629 27
17,655 17,655 28
1,605 1,605 29
1,297,138 65,368 1,231,770 30
137,713 137,713 31
88,531 3,733 84,798 32
-1,612 -1,612 33
2,487,695 3,507,099 1,019,404 34
FERC FORM NO. 1 (ED. 12-90) Page 330.2
38,697,973 85,492,936 34,015,065 12,779,898
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 / /2013/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.
NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD AD 1
NextEra Energy Resources, LLC NF 2
NextEra Energy Resources, LLC AD 3
Nevada Power Company NF 4
Noble Americas Energy Solutions LLC Bonneville Power Administration Oregon Direct Access FNO 5
Noble Americas Energy Solutions LLC Bonneville Power Administration Oregon Direct Access AD 6
Pacific Gas & Electric Company OS 7
Pacific Gas & Electric Company AD 8
Pacific Gas & Electric Company OS 9
Portland General Electric Company NF 10
Portland General Electric Company AD 11
Portland General Electric Company SFP 12
Portland General Electric Company OS 13
Powder River Energy Corporation Western Area Power Administration Sheridan-Johnson Rural Elect.OS 14
Powder River Energy Corporation Western Area Power Administration Sheridan-Johnson Rural Elect.AD 15
Powerex Corporation Bonneville Power Administration CAISO LFP 16
Powerex Corporation Bonneville Power Administration CAISO AD 17
Powerex Corporation Powerex Corporation CAISO LFP 18
Powerex Corporation Powerex Corporation CAISO AD 19
Powerex Corporation Powerex Corporation CAISO LFP 20
Powerex Corporation Powerex Corporation CAISO AD 21
Powerex Corporation Powerex Corporation CAISO LFP 22
Powerex Corporation Powerex Corporation CAISO AD 23
Powerex Corporation NF 24
Powerex Corporation AD 25
Powerex Corporation SFP 26
Powerex Corporation AD 27
PPL Energy Plus, LLC NF 28
PPL Energy Plus, LLC AD 29
PPL Energy Plus, LLC SFP 30
PPL Energy Plus, LLC AD 31
Public Svc. Co. of CO SFP 32
Rainbow Energy Marketing Corporation NF 33
Rainbow Energy Marketing Corporation AD 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 / /2013/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.
Wallula SubstationV11-5,6,7,9 Wala-MIDC path 104 1,891 1,891 1
VariousV11-1,2,8 Various 99 99 2
VariousV11-1,2,8 Various 76 76 3
VariousV11-1,2,8 Various 1,560 1,560 4
Bonneville Power AdmV11-1,2,3,4 Various 26 191,994 191,994 5
Bonneville Power AdmV11-1,2,3,4 Various 25 17,047 17,047 6
R.S. 607 7
VariousV11-1,2 Various 8
Sigurd-Glen CanyonR.S. 298 Pinto-Four Corners 9
VariousV11-1,2,8 Various 8,767 8,767 10
VariousV11-1,2,8 Various 207 207 11
VariousV11-1,2,7 Various 295 295 12
VariousR.S. 137 Various 13
VariousR.S. 123 Buffalo Substation 14
VariousR.S. 123 Buffalo Substation 15
Bonneville Power AdmV11-1,2,7 CRAG View Substation 83 380,866 380,866 16
Bonneville Power AdmV11-1,2,7 CRAG View Substation 84 -58,690 -58,690 17
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 18
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 19
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 20
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 21
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 22
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 23
VariousV11-1,2,8 Various 575,984 575,984 24
VariousV11-1,2,8 Various -153,684 -153,684 25
VariousV11-1,2,7 Various 76,587 76,587 26
VariousV11-1,2,7 Various -54,264 -54,264 27
VariousV11-1,2,8 Various 807 807 28
VariousV11-1,2,8 Various -791 -791 29
VariousV11-1,2,7 Various 2,891 2,891 30
VariousV11-1,2 Various -149 -149 31
VariousV11-1,2,7 Various 800 800 32
VariousV11-1,2,8 Various 929 929 33
VariousV11-1,2 Various -6,662 -6,662 34
FERC FORM NO. 1 (ED. 12-90) Page 329.3
4,438 12,830,379 12,712,106
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 / /2013/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.
-665,697 -665,697 1
23,723 3,241 20,482 2
-1,058 -1,058 3
10,338 460 9,878 4
356,153 422,260 66,107 5
-34,255 -34,255 6
14,500,000 14,500,000 7
-5 -5 8
271,951 271,951 9
54,541 2,308 52,233 10
2,290 2,290 11
3,196 129 3,067 12
3,314 3,314 13
337 337 14
28 28 15
1,936,508 2,021,942 85,434 16
-77,044 -77,044 17
1,553,607 1,588,455 34,848 18
-7,399 -7,399 19
1,553,607 1,588,455 34,848 20
-7,399 -7,399 21
1,530,413 1,564,741 34,328 22
-7,399 -7,399 23
3,865,484 165,274 3,700,210 24
-65,297 -65,297 25
1,031,524 73,068 958,456 26
-13,041 -13,041 27
4,578 187 4,391 28
-317 -317 29
18,270 752 17,518 30
-115 -115 31
2,572 103 2,469 32
4,080 170 3,910 33
-3,436 -3,436 34
FERC FORM NO. 1 (ED. 12-90) Page 330.3
38,697,973 85,492,936 34,015,065 12,779,898
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 / /2013/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.
Rainbow Energy Marketing Corporation SFP 1
Rainbow Energy Marketing Corporation AD 2
Sacramento Municipal Utility District Sacramento Municipal Util. Dist. Sacramento Municipal Util. Dist.LFP 3
Sacramento Municipal Utility District Sacramento Municipal Util. Dist. Sacramento Municipal Util. Dist.LFP 4
Salt River Project NF 5
Salt River Project SFP 6
Seattle City Light FPL Energy Vansycle, LLC Grant County PUD AD 7
Sierra Pacific Power Company OS 8
Sierra Pacific Power Company AD 9
Sierra Pacific Power Company NF 10
Sierra Pacific Power Company AD 11
Sierra Pacific Power Company SFP 12
Sierra Pacific Power Company AD 13
Southern California Edison Company NF 14
Southern California Edison Company AD 15
Southern California Edison Company OS 16
Southern California Public Power Authority Powerex Corporation OS 17
State of South Dakota Western Area Power Administration Black Hills Corporation LFP 18
State of South Dakota Western Area Power Administration Black Hills Corporation AD 19
Tenaska Power Services Company NF 20
Tenaska Power Services Company AD 21
Tenaska Power Services Company SFP 22
Tenaska Power Services Company AD 23
The Energy Authority, Inc.NF 24
The Energy Authority, Inc.AD 25
Thermo No. 1 BE-01, LLC Thermo Geothermal Project LFP 26
Thermo No. 1 BE-01, LLC Thermo Geothermal Project AD 27
TransAlta Energy Marketing NF 28
TransAlta Energy Marketing AD 29
TransAlta Energy Marketing SFP 30
Tri-State Generation & Trans. Tri-State Generation & Trans.OS 31
Tri-State Generation & Trans. Tri-State Generation & Trans.AD 32
Tri-State Generation & Trans. Tri-State Generation & Trans.FNO 33
Tri-State Generation & Trans. Tri-State Generation & Trans.AD 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 / /2013/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.
VariousV11-1,2,7 Various 5,566 5,566 1
VariousV11-1,2 Various -1,300 -1,300 2
Malin SubstationV11-1,2,7 Malin Substation 31 3
Malin SubstationV11 Malin Substation 4
VariousV11-1,2,3,8 Various 195 195 5
VariousV11-1,2,3,7 Various 491 491 6
Wallula SubstationV11-1,2 Wala-MIDC path 7
Sigurd SubstationR.S. 674 Utah-Nevada Border 8
Sigurd SubstationR.S. 674 Utah-Nevada Border 9
VariousV11-1,2,8 Various 14,229 14,229 10
VariousV11-1,2 Various -1,637 -1,637 11
VariousV11-1,2,7 Various 200 200 12
VariousV11-1,2 Various -1,742 -1,742 13
VariousV11-1-3,8,9,11 Various 292,921 292,921 14
VariousV11-1-3,8,9,11 Various -19,718 -19,718 15
Sigurd-Glen CanyonR.S. 298 Pinto-Four Corners 16
Tieton SubstationV11-9,11 Various 205 205 17
Yellowtail SubV11-1,2,7 Wyodak Substation 4 17,821 17,821 18
Yellowtail SubV11-1,2,7 Wyodak Substation 4 1,845 1,845 19
VariousV11-1,2,8 Various 4,705 4,705 20
VariousV11-1,2 Various -2,430 -2,430 21
VariousV11-1,2,3,7 Various 46,567 46,567 22
VariousV11-1,2 Various -2,390 -2,390 23
VariousV11-1,2,8 Various 967 967 24
VariousV11-1,2,8 Various 144 144 25
South Milford Sub Mona Substation 11 61,635 61,635 26
South Milford Sub Mona Substation 12 4,385 4,385 27
VariousV11-1,2,8 Various 30,798 30,798 28
VariousV11-1,2,8 Various -3,844 -3,844 29
VariousV11-1,2,7 Various 146 146 30
VariousR.S. 123 Various 36 177,352 177,352 31
VariousR.S. 123 Various 34 17,895 17,895 32
Dave Johnston SubV11-1,2,3,4 Thermopolis Sub 3 40,378 40,378 33
Dave Johnston SubV11-1,2,3,4 Thermopolis Sub 1 249 249 34
FERC FORM NO. 1 (ED. 12-90) Page 329.4
4,438 12,830,379 12,712,106
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 / /2013/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.
22,419 954 21,465 1
-639 -639 2
134,789 140,472 5,683 3
130,043 130,043 4
1,004 134 870 5
7,050 942 6,108 6
-5,252 -5,252 7
68,919 68,919 8
6,265 6,265 9
91,105 3,690 87,415 10
-1,069 -1,069 11
5,403 219 5,184 12
-1,042 -1,042 13
3,097,866 917,821 2,180,045 14
333,001 333,001 15
271,951 271,951 16
9,034 9,034 17
96,818 101,091 4,273 18
-6,650 -6,650 19
12,405 521 11,884 20
-1,480 -1,480 21
267,356 16,167 251,189 22
-1,259 -1,259 23
4,372 192 4,180 24
1,229 1,229 25
266,276 358,169 91,893 26
-36,213 -36,213 27
169,867 7,174 162,693 28
174 174 29
1,028 42 986 30
101,745 101,745 31
9,867 9,867 32
61,641 89,651 28,010 33
-67,731 -67,731 34
FERC FORM NO. 1 (ED. 12-90) Page 330.4
38,697,973 85,492,936 34,015,065 12,779,898
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 / /2013/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.
Tri-State Generation & Trans.NF 1
Tri-State Generation & Trans.AD 2
Tri-State Generation & Trans.AD 3
U. S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation FNO 4
U. S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation AD 5
U. S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.OS 6
U. S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.AD 7
U. S. Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District OS 8
Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power OS 9
Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power AD 10
Utah Associated Municipal Power Systems NF 11
Utah Associated Municipal Power Systems AD 12
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency OS 13
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency AD 14
Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric Co OS 15
Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric Co AD 16
Western Area Power Administration Western Area Power Administration OS 17
Western Area Power Administration Western Area Power Administration AD 18
Western Area Power Administration Western Area Power Administration OS 19
Western Area Power Administration Western Area Power Administration AD 20
Western Area Power Administration Western Area Power Administration OS 21
Western Area Power Administration Western Area Power Administration Western Area Power Administration FNO 22
Western Area Power Administration Western Area Power Administration Western Area Power Administration AD 23
Western Area Power Adm. CO River Western Area Power Adm. CO River NF 24
Western Area Power Adm. CO River Western Area Power Adm. CO River AD 25
Western Area Power Adm. CO River Western Area Power Adm. CO River AD 26
Western Area Power Adm. CO MO Western Area Power Adm. CO MO AD 27
Western Area Power Adm. CO MO Western Area Power Adm. CO MO AD 28
Accrual 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 / /2013/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 17,364 17,364 1
VariousV11-1,2 Various -7,330 -7,330 2
VariousV11-1,2 Various -633 -633 3
Walla Walla SubV11-1,2,3 Burbank Pumps 1 2,361 2,361 4
Walla Walla SubV11-1,2,3 Burbank Pumps 1 3 3 5
VariousR.S. 286 Various 28,798 28,798 6
VariousR.S. 286 Various 986 986 7
Redmond SubstationR.S. 67 Crooked River Pumps 11,219 11,219 8
VariousR.S. 297 Various 444 2,431,316 2,431,316 9
VariousR.S. 297 Various 521 217,249 217,249 10
VariousV11-1,2,8 Various 3,051 3,051 11
VariousV11-1,2 Various -1,514 -1,514 12
VariousR.S. 637 Various 113 644,731 644,731 13
VariousR.S. 637 Various 97 48,262 48,262 14
Pelton ReregulatingR.S. 591 Round Butte Sub 76,161 76,161 15
Pelton ReregulatingR.S. 591 Round Butte Sub 8,974 8,974 16
VariousR.S. 262 Various 330 1,685,843 1,584,694 17
VariousR.S. 262 Various 330 171,661 161,362 18
VariousR.S. 263 Various 84,691 79,313 19
VariousR.S. 263 Various 8,557 8,073 20
Dave Johnston SubR.S. 664 Various 21
Wyoming DistributionV11-1,2 Wyoming Distribution 11,051 11,051 22
Wyoming DistributionV11-1,2 Wyoming Distribution 23
VariousV11-1,2,8 Various 654 654 24
VariousV11-1,2,8 Various -85 -85 25
VariousV11-1,2 Various -615 -615 26
VariousV11-1,2 Various -1,665 -1,665 27
VariousV11-1,2 Various -4,893 -4,893 28
57,714 56,751 29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.5
4,438 12,830,379 12,712,106
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 / /2013/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.
98,527 4,239 94,288 1
-4,450 -4,450 2
-428 -428 3
6,956 17,698 10,742 4
-1,160 -1,160 5
28,798 28,798 6
793 793 7
12,543 12,543 8
10,027,476 12,371,669 2,344,193 9
125,698 125,698 10
19,249 2,640 16,609 11
-3,021 -3,021 12
2,676,688 3,302,489 625,801 13
-176,837 -176,837 14
109,725 109,725 15
9,975 9,975 16
2,076,355 2,626,355 550,000 17
227,294 227,294 18
-11,156 -11,156 19
5,825 5,825 20
21
34,108 78,642 44,534 22
-4,679 -4,679 23
14,026 607 13,419 24
114 114 25
-186 -186 26
-2,327 -2,327 27
-899 -899 28
5,474,456 5,474,456 29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.5
38,697,973 85,492,936 34,015,065 12,779,898
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
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, in this Form No. 1.
Schedule Page: 328 Line No.: 1 Column: f
Glenn Canyon/Four Corners Substation
Schedule Page: 328 Line No.: 2 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.: 2 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.: 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. December 2012 transmission
and ancillary services. Refunds for transmission and ancillary services pursuant to FERC
Docket No. ER11-3643.
Schedule Page: 328 Line No.: 4 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 4 Column: m
Refunds for transmission and ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328 Line No.: 5 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.: 5 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 5 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 5 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
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: 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
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328 Line No.: 7 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 328 Line No.: 7 Column: c
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
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 8 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 8 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328 Line No.: 9 Column: b
PacifiCorp Energy, a business unit of PacifiCorp responsible for generation and commercial
and 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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 10 Column: b
PacifiCorp Energy, a business unit of PacifiCorp responsible for generation and commercial
and trading activities.
Schedule Page: 328 Line No.: 10 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.: 10 Column: m
December 2012 transmission and ancillary services. Refunds for transmission and ancillary
services pursuant to FERC Docket No. ER11-3643.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
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
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 328 Line No.: 13 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 14 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 14 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 14 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 14 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Schedule Page: 328 Line No.: 15 Column: b
PacifiCorp Energy, a business unit of PacifiCorp responsible for generation and commercial
and trading activities.
Schedule Page: 328 Line No.: 15 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 67) terminating on December 31, 2023.
Schedule Page: 328 Line No.: 15 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 16 Column: b
PacifiCorp Energy, a business unit of PacifiCorp responsible for generation and commercial
and trading activities.
Schedule Page: 328 Line No.: 16 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 67) terminating on December 31, 2023.
Schedule Page: 328 Line No.: 16 Column: m
December 2012 transmission and ancillary services. Refunds for transmission and ancillary
services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328 Line No.: 17 Column: b
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.
Schedule Page: 328 Line No.: 17 Column: c
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.
Schedule Page: 328 Line No.: 17 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, in this Form No. 1.
Schedule Page: 328 Line No.: 18 Column: d
Legacy contract (3rd 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
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.
Schedule Page: 328 Line No.: 19 Column: d
Legacy contract (3rd 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.: 19 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2012 transmission and ancillary services.
Schedule Page: 328 Line No.: 20 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 656) terminating on August 31, 2030.
Schedule Page: 328 Line No.: 20 Column: m
Reactive supply and voltage control service.
Schedule Page: 328 Line No.: 21 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 656) terminating on August 31, 2030.
Schedule Page: 328 Line No.: 21 Column: m
December 2012 transmission and ancillary services.
Schedule Page: 328 Line No.: 22 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (7th Revised Service Agreement 229) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 22 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.: 22 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.: 23 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (7th Revised Service Agreement 229) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 23 Column: m
Distribution voltage service charge. Primary delivery service. December 2012 transmission
and ancillary services. Refunds for transmission and ancillary services pursuant to FERC
Docket No. ER11-3643.
Schedule Page: 328 Line No.: 24 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.: 24 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (2nd Revised Service Agreement 539) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 24 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service.
Schedule Page: 328 Line No.: 25 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (2nd Revised Service Agreement 539) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 25 Column: m
December 2012 transmission and ancillary services. Refunds for transmission and ancillary
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328 Line No.: 26 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.: 26 Column: d
Network transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 538) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 26 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service.
Schedule Page: 328 Line No.: 27 Column: d
Network transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 538) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 27 Column: m
December 2012 transmission and ancillary services. Refunds for transmission and ancillary
services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328 Line No.: 28 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.: 28 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised
Service Agreement 179) terminating on September 30, 2025.
Schedule Page: 328 Line No.: 28 Column: m
Reactive supply and voltage control service.
Schedule Page: 328 Line No.: 29 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised
Service Agreement 179) terminating on September 30, 2025.
Schedule Page: 328 Line No.: 29 Column: m
December 2012 transmission and ancillary services. Refunds for transmission and ancillary
services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328 Line No.: 30 Column: d
Legacy contract (5th Revised Rate Schedule 368) executed between PacifiCorp and BPA 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.
Schedule Page: 328 Line No.: 31 Column: d
Legacy contract (5th Revised Rate Schedule 368) executed between PacifiCorp and BPA 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.: 31 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract. December 2012 transmission and ancillary services.
Schedule Page: 328 Line No.: 32 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (5th Revised Service Agreement 328) terminating on July 31, 2028.
Schedule Page: 328 Line No.: 32 Column: g
White Swan/Toppenish Substations
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. Scheduling, system control and dispatch 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Reactive supply and voltage control service. Regulation and frequency response service.
Schedule Page: 328 Line No.: 33 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (5th Revised Service Agreement 328) terminating on July 31, 2028.
Schedule Page: 328 Line No.: 33 Column: g
White Swan/Toppenish Substations
Schedule Page: 328 Line No.: 33 Column: m
Distribution voltage service charge. Primary delivery service. December 2012 transmission
and ancillary services. Penalty revenues covering imbalance charges per Schedules 4 and 9.
Refunds for transmission and ancillary services pursuant to FERC Docket No. ER11-3643.
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
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.
Schedule Page: 328.1 Line No.: 1 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: 328.1 Line No.: 1 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. December 2012
transmission and ancillary services.
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
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.: 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
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Schedule Page: 328.1 Line No.: 4 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 4 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 4 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
Schedule Page: 328.1 Line No.: 4 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.: 5 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 5 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 5 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 5 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Schedule Page: 328.1 Line No.: 6 Column: d
Network transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 735) terminating on September 30, 2028.
Schedule Page: 328.1 Line No.: 6 Column: g
Chelatchie/View 115kV
Schedule Page: 328.1 Line No.: 6 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.: 7 Column: d
Network transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 735) terminating on September 30, 2028.
Schedule Page: 328.1 Line No.: 7 Column: g
Chelatchie/View 115kV
Schedule Page: 328.1 Line No.: 7 Column: m
Unauthorized use of transmission service. December 2012 transmission and ancillary
services. Penalty revenues covering imbalance charges per Schedules 4 and 9. Refunds for
transmission and ancillary services pursuant to FERC Docket No. ER11-3643.
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: 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
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
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. Scheduling, system control
and dispatch service. Reactive supply and voltage control 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
between various parties and points.
Schedule Page: 328.1 Line No.: 11 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
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.
Schedule Page: 328.1 Line No.: 13 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 13 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 13 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.1 Line No.: 14 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 14 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 14 Column: m
Transmission resales, purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control 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
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.: 15 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.1 Line No.: 16 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
2013/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: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 16 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 17 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 17 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 17 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Schedule Page: 328.1 Line No.: 18 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 18 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 18 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.: 18 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 19 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.: 19 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.: 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.
Schedule Page: 328.1 Line No.: 20 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.: 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. December 2012 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 21 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
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.: 21 Column: d
Legacy contract executed between PacifiCorp and Deseret Generation and Transmission
Co-operative for transmission service over agreed-upon facilities (6th Amended and
Restated Transmission Service and Operating Agreement, Rate Schedule 280). Agreement
subject to termination upon mutual agreement.
Schedule Page: 328.1 Line No.: 21 Column: m
Distribution voltage service charge. 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. Regulation and frequency response
service. Operating reserve - spinning reserve service. Operating reserve - supplemental
reserve service.
Schedule Page: 328.1 Line No.: 22 Column: d
Legacy contract executed between PacifiCorp and Deseret Generation and Transmission
Co-operative for transmission service over agreed-upon facilities (6th Amended and
Restated Transmission Service and Operating Agreement, Rate Schedule 280). Agreement
subject to termination upon mutual agreement.
Schedule Page: 328.1 Line No.: 22 Column: m
Distribution voltage service charge. Meter interrogation services. December 2012
transmission and ancillary services. Penalty revenues covering imbalance charges per
Schedules 4 and 9. Refunds for transmission and ancillary services pursuant to FERC Docket
No. ER11-3643. Refunds of transmission service covering prior years.
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: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 24 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 24 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.1 Line No.: 25 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 25 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 25 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 25 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.1 Line No.: 26 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 26 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
Service Agreement 711) terminating on November 30, 2018.
Schedule Page: 328.1 Line No.: 26 Column: m
Extension of commencement date fee.
Schedule Page: 328.1 Line No.: 27 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 27 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (10th
Revised Service Agreement 426) terminating on April 30, 2044.
Schedule Page: 328.1 Line No.: 27 Column: m
Extension of commencement date fee.
Schedule Page: 328.1 Line No.: 28 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 28 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 28 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.1 Line No.: 29 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.: 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: 328.1 Line No.: 30 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.: 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 2012 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 31 Column: c
PacifiCorp Energy, a business unit of PacifiCorp responsible for generation and commercial
and trading activities.
Schedule Page: 328.1 Line No.: 31 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.: 31 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.: 32 Column: c
PacifiCorp Energy, a business unit of PacifiCorp responsible for generation and commercial
and trading activities.
Schedule Page: 328.1 Line No.: 32 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.: 32 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2012 transmission and ancillary services.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.11
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 2012 transmission and ancillary services. Refunds for
ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.2 Line No.: 1 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 1 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 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: 328.2 Line No.: 1 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
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.
Schedule Page: 328.2 Line No.: 3 Column: c
Iberdrola Renewables, LLC and Utah Associated Municipal Power Systems
Schedule Page: 328.2 Line No.: 3 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.: 3 Column: f
Long Hollow, Wyoming Switching Station
Schedule Page: 328.2 Line No.: 3 Column: g
Long Hollow, Wyoming Switching Station
Schedule Page: 328.2 Line No.: 3 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.12
to FERC Docket No. ER11-3643.
Schedule Page: 328.2 Line No.: 4 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 279). Terminating on April 30, 2019.
Schedule Page: 328.2 Line No.: 4 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 5 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 279). Terminating on April 30, 2019.
Schedule Page: 328.2 Line No.: 5 Column: m
December 2012 transmission and ancillary services. Refunds for transmission and ancillary
services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.2 Line No.: 6 Column: d
Network transmission service under the Open Access Transmission Tariff (Service Agreement
742) terminating on April 30, 2018.
Schedule Page: 328.2 Line No.: 6 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service.
Schedule Page: 328.2 Line No.: 7 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 7 Column: d
Point-to-point transmission service agreements under the Open Access Transmission Tariff
(Service Agreements 697, 698, 699) terminated in 2013.
Schedule Page: 328.2 Line No.: 7 Column: m
Extension of commencement date fee.
Schedule Page: 328.2 Line No.: 8 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, in this Form No. 1.
Schedule Page: 328.2 Line No.: 9 Column: d
Point-to-point transmission Service under the Open Access Transmission Tariff (8th Revised
Service Agreement 212) terminating on May 31, 2019.
Schedule Page: 328.2 Line No.: 9 Column: m
Refunds for transmission and ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.2 Line No.: 10 Column: d
Point-to-point transmission Service under the Open Access Transmission Tariff (8th Revised
Service Agreement 212) terminating on May 31, 2019.
Schedule Page: 328.2 Line No.: 10 Column: m
Refunds for transmission and ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.2 Line No.: 11 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 11 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 11 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.: 11 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.13
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Schedule Page: 328.2 Line No.: 12 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 12 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 12 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.: 12 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2012 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 13 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 13 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 13 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.: 13 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.: 14 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 14 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 14 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.: 14 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2012 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 15 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 15 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.14
Schedule Page: 328.2 Line No.: 16 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
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.
Schedule Page: 328.2 Line No.: 18 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 18 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 18 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.: 18 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Schedule Page: 328.2 Line No.: 19 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.: 19 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 19 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 19 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.: 19 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: 328.2 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
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
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
Penalty revenues covering imbalance charges per Schedules 4 and 9. Scheduling, system
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.15
control and dispatch service. Reactive supply and voltage control 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
December 2012 transmission and ancillary services. Penalty revenues covering imbalance
charges per Schedules 4 and 9. Refunds for ancillary services pursuant to FERC Docket No.
ER11-3643.
Schedule Page: 328.2 Line No.: 23 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 23 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 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: 328.2 Line No.: 23 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 24 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 24 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 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: 328.2 Line No.: 25 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 25 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
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
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.16
Schedule Page: 328.2 Line No.: 27 Column: m
Transmission resales, purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service.
Schedule Page: 328.2 Line No.: 28 Column: d
Legacy contract (3rd 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.: 28 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
Schedule Page: 328.2 Line No.: 29 Column: d
Legacy contract (3rd 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.: 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. December 2012 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 30 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 30 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 30 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 30 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.: 31 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 31 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 31 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 31 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Schedule Page: 328.2 Line No.: 32 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 32 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
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
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 33 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.17
Schedule Page: 328.2 Line No.: 33 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 33 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Schedule Page: 328.2 Line No.: 34 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.: 34 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 733) terminating on November 30, 2017.
Schedule Page: 328.2 Line No.: 34 Column: e
V11-1-3,5-6,7,9,11
Schedule Page: 328.2 Line No.: 34 Column: m
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Schedules 4 and 9. Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
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.: 1 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 733) terminating on November 30, 2017.
Schedule Page: 328.3 Line No.: 1 Column: m
December 2012 transmission and ancillary services. Penalty revenues covering imbalance
charges per Schedules 4 and 9. Refunds for transmission and ancillary services pursuant to
FERC Docket No. ER11-3643.
Schedule Page: 328.3 Line No.: 2 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 2 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 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: 328.3 Line No.: 2 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.: 3 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 3 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 3 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 3 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Schedule Page: 328.3 Line No.: 4 Column: a
This footnote applies to all occurrences of "Nevada Power Company" on pages 328-330.
Nevada Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect
wholly owned subsidiary of MidAmerican Energy Holdings Company.
Schedule Page: 328.3 Line No.: 4 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 4 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.18
Schedule Page: 328.3 Line No.: 4 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 4 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 5 Column: d
Transmission service under the Open Access Transmission Tariff (5th 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: 328.3 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: 328.3 Line No.: 6 Column: d
Transmission service under the Open Access Transmission Tariff (5th 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: 328.3 Line No.: 6 Column: m
December 2012 transmission and ancillary services. Penalty revenues covering imbalance
charges per Schedules 4 and 9. Refunds for transmission and ancillary services pursuant to
FERC Docket No. ER11-3643.
Schedule Page: 328.3 Line No.: 7 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 7 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 7 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: 328.3 Line No.: 7 Column: f
Malin to Indian Springs line segment
Schedule Page: 328.3 Line No.: 7 Column: g
Malin to Indian Springs line segment
Schedule Page: 328.3 Line No.: 7 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
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
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: 328.3 Line No.: 8 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.3 Line No.: 9 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.19
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 9 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 9 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 230kV transmission
line and Pinto-Four Corners 345kV transmission line). Terminating on February 12, 2020.
Schedule Page: 328.3 Line No.: 9 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.: 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.
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
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 13 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 13 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 13 Column: d
Legacy contract (1st Revised Rate Schedule 137) executed between PacifiCorp and Portland
General Electric Company for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge for the Dalreed Substation, which terminated
December 2013.
Schedule Page: 328.3 Line No.: 13 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.: 14 Column: c
This footnote applies to all occurrences of "Sheridan-Johnson Rural Elect." on pages 328 -
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.20
330. Complete name is Sheridan-Johnson Rural Electric Association.
Schedule Page: 328.3 Line No.: 14 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.: 14 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.: 15 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.: 15 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2012 transmission and ancillary services.
Schedule Page: 328.3 Line No.: 16 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.: 16 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 169) terminating on October 31, 2020.
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: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 169) terminating on October 31, 2020.
Schedule Page: 328.3 Line No.: 17 Column: m
December 2012 transmission and ancillary services. Refunds for transmission and ancillary
services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.3 Line No.: 18 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 700) terminating on March 31, 2017.
Schedule Page: 328.3 Line No.: 18 Column: m
Scheduling, system control and dispatch service.
Schedule Page: 328.3 Line No.: 19 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 700) terminating on March 31, 2017.
Schedule Page: 328.3 Line No.: 19 Column: m
December 2012 transmission and ancillary services. Scheduling, system control and dispatch
service.
Schedule Page: 328.3 Line No.: 20 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 701) terminating on March 31, 2017.
Schedule Page: 328.3 Line No.: 20 Column: m
Scheduling, system control and dispatch service.
Schedule Page: 328.3 Line No.: 21 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 701) terminating on March 31, 2017.
Schedule Page: 328.3 Line No.: 21 Column: m
December 2012 transmission and ancillary services. Scheduling, system control and dispatch
service.
Schedule Page: 328.3 Line No.: 22 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 702) terminating on March 31, 2017.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.21
Schedule Page: 328.3 Line No.: 22 Column: m
Scheduling, system control and dispatch service.
Schedule Page: 328.3 Line No.: 23 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 702) terminating on March 31, 2017.
Schedule Page: 328.3 Line No.: 23 Column: m
December 2012 transmission and ancillary services. Scheduling, system control and dispatch
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response 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
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
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
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
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Schedule Page: 328.3 Line No.: 28 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 28 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 28 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.22
Schedule Page: 328.3 Line No.: 28 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 29 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 29 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 29 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 29 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Schedule Page: 328.3 Line No.: 30 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 30 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 30 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 31 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 31 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 31 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 31 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.3 Line No.: 32 Column: a
This footnote applies to all occurrences of "Public Svc. Co. of CO" on pages 328 - 330.
Complete name is Public Service Company of Colorado.
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.23
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
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
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
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.4 Line No.: 3 Column: b
This footnote applies to all occurrences of "Sacramento Municipal Util. Dist." on pages
328 - 330. Complete name is Sacramento Municipal Utility District.
Schedule Page: 328.4 Line No.: 3 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 751) terminating on September 30, 2018.
Schedule Page: 328.4 Line No.: 3 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.4 Line No.: 4 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 552) terminating on September 30, 2018.
Schedule Page: 328.4 Line No.: 4 Column: m
Extension of commencement date fee.
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: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 5 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.: 6 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 6 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.24
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 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: 328.4 Line No.: 7 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 289) terminating on February 28, 2018.
Schedule Page: 328.4 Line No.: 7 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.4 Line No.: 8 Column: a
This footnote applies to all occurrences of "Sierra Pacific Power Company" on pages
328-330. Sierra Pacific Power Company is a principal subsidiary of NV Energy, Inc., which
is an indirect wholly owned subsidiary of MidAmerican Energy Holdings Company.
Schedule Page: 328.4 Line No.: 8 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 8 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 8 Column: d
Legacy contract (Rate Schedule 674) executed between PacifiCorp and Sierra Pacific Power
Company for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Terminating in September 2022.
Schedule Page: 328.4 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: 328.4 Line No.: 9 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 9 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 9 Column: d
Legacy contract (Rate Schedule 674) executed between PacifiCorp and Sierra Pacific Power
Company for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Terminating in September 2022.
Schedule Page: 328.4 Line No.: 9 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. December 2012 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 10 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 10 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 10 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 11 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 11 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 11 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.25
Schedule Page: 328.4 Line No.: 11 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.4 Line No.: 12 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 12 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 12 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 13 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 13 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 13 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.4 Line No.: 14 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 14 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 14 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: 328.4 Line No.: 15 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 15 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 15 Column: m
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Schedules 4 and 9. December 2012 transmission and ancillary services. Refunds for ancillary services
pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.4 Line No.: 16 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 16 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 16 Column: d
Use of Facilities Agreement - Phase shifting transformers at Sigurd-Glen Canyon 230kV
transmission line and Pinto-Four Corners 345kV transmission line (Rate Schedule 298)
terminating on February 12, 2020.
Schedule Page: 328.4 Line No.: 16 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.26
Schedule Page: 328.4 Line No.: 17 Column: c
Southern California Public Power Authority
Schedule Page: 328.4 Line No.: 17 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: 328.4 Line No.: 17 Column: m
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Schedules 4 and 9.
Schedule Page: 328.4 Line No.: 18 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (11th
Revised Service Agreement 170) terminating on May 31, 2014.
Schedule Page: 328.4 Line No.: 18 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 19 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (11th
Revised Service Agreement 170) terminating on May 31, 2014.
Schedule Page: 328.4 Line No.: 19 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Schedule Page: 328.4 Line No.: 20 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 20 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 20 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 21 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 21 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 21 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 21 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.4 Line No.: 22 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 22 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 22 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 22 Column: m
Transmission resales, amount paid by seller. Scheduling, system control and dispatch
service. Reactive supply and voltage control service. Generation regulation and frequency
response service.
Schedule Page: 328.4 Line No.: 23 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.27
Schedule Page: 328.4 Line No.: 23 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 23 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.4 Line No.: 24 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 24 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 24 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 25 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 25 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 25 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
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
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 568) terminating on April 30, 2029.
Schedule Page: 328.4 Line No.: 26 Column: e
V11-1-3,5-6,7,9
Schedule Page: 328.4 Line No.: 26 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: 328.4 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
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 568) terminating on April 30, 2029.
Schedule Page: 328.4 Line No.: 27 Column: e
V11-1-3,5-6,7,9
Schedule Page: 328.4 Line No.: 27 Column: m
December 2012 transmission and ancillary services. Penalty revenues covering imbalance
charges per Schedules 4 and 9. Refunds for transmission and ancillary services pursuant to
FERC Docket No. ER11-3643.
Schedule Page: 328.4 Line No.: 28 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.28
between various parties and points.
Schedule Page: 328.4 Line No.: 28 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 29 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
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
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.: 29 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Schedule Page: 328.4 Line No.: 30 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 30 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 30 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 31 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.: 31 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 31 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.: 32 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 32 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.: 32 Column: m
December 2012 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 33 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 33 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.: 33 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.: 34 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 34 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.29
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.: 34 Column: m
December 2012 transmission and ancillary services. Penalty revenues covering imbalance
charges per Schedules 4 and 9. Refunds for transmission and ancillary services pursuant to
FERC Docket No. ER11-3643.
Schedule Page: 328.5 Line No.: 1 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 1 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 Line No.: 1 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.5 Line No.: 2 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 2 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 Line No.: 2 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.5 Line No.: 3 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 3 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 Line No.: 3 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.5 Line No.: 4 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (Service Agreement 506) terminating upon written notification.
Schedule Page: 328.5 Line No.: 4 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: 328.5 Line No.: 5 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (Service Agreement 506) terminating upon written notification.
Schedule Page: 328.5 Line No.: 5 Column: m
Distribution voltage service charge. Primary delivery service. December 2012 transmission
and ancillary services. Refunds for transmission and ancillary services pursuant to FERC
Docket No. ER11-3643.
Schedule Page: 328.5 Line No.: 6 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: 328.5 Line No.: 6 Column: d
Legacy contract (3rd 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.30
or facilities charge for energy deliveries at and below 138kV. Agreement terminates any
time after April 1, 2040 with four years written notification.
Schedule Page: 328.5 Line No.: 6 Column: m
Energy consumption charge for deliveries at and below 138kV.
Schedule Page: 328.5 Line No.: 7 Column: d
Legacy contract (3rd 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 138kV. Agreement terminates any
time after April 1, 2040 with four years written notification.
Schedule Page: 328.5 Line No.: 7 Column: m
Distribution voltage service charge. Primary delivery service. December 2012 transmission
and ancillary services.
Schedule Page: 328.5 Line No.: 8 Column: d
Legacy contract (3rd Amended Rate Schedule 67) executed between PacifiCorp and United
States Department of the Interior, Bureau of Reclamation Crooked River Irrigation District
for transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge. Agreement termination with one year written notice.
Schedule Page: 328.5 Line No.: 9 Column: b
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: 328.5 Line No.: 9 Column: d
Legacy contract executed between PacifiCorp and Utah Associated Municipal Power Systems
for transmission service over agreed-upon facilities (3rd Amended and Restated
Transmission Service and Operating Agreement, 3rd Revised Rate Schedule 297). Agreement
subject to termination upon mutual agreement and replacement agreements are in effect.
Schedule Page: 328.5 Line No.: 9 Column: m
Distribution voltage service charge. 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: 328.5 Line No.: 10 Column: d
Legacy contract executed between PacifiCorp and Utah Associated Municipal Power Systems
for transmission service over agreed-upon facilities (3rd Amended and Restated
Transmission Service and Operating Agreement, 3rd Revised Rate Schedule 297). Agreement
subject to termination upon mutual agreement and replacement agreements are in effect.
Schedule Page: 328.5 Line No.: 10 Column: m
Distribution voltage service charge. December 2012 transmission and ancillary services.
Refunds for transmission and ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.5 Line No.: 11 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 11 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.5 Line No.: 12 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 12 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.31
Schedule Page: 328.5 Line No.: 12 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.5 Line No.: 13 Column: d
Legacy contract (5th 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: 328.5 Line No.: 13 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: 328.5 Line No.: 14 Column: d
Legacy contract (5th 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: 328.5 Line No.: 14 Column: m
December 2012 transmission and ancillary services. Penalty revenues covering imbalance
charges per Schedules 4 and 9. Refunds for transmission and ancillary services pursuant to
FERC Docket No. ER11-3643.
Schedule Page: 328.5 Line No.: 15 Column: c
This footnote applies to all occurrences of "Portland General Electric Co" on pages 328 -
330. Complete name is Portland General Electric Company.
Schedule Page: 328.5 Line No.: 15 Column: d
Legacy contract (Rate Schedule 591) executed between PacifiCorp and Warm Springs Power
Enterprises for transmission service over agreed-upon facilities and/or subject to a
sole-use or facilities charge. Terminating on January 31, 2032.
Schedule Page: 328.5 Line No.: 15 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: 328.5 Line No.: 16 Column: d
Legacy contract (Rate Schedule 591) executed between PacifiCorp and Warm Springs Power
Enterprises for transmission service over agreed-upon facilities and/or subject to a
sole-use or facilities charge. Terminating on January 31, 2032.
Schedule Page: 328.5 Line No.: 16 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 2012 transmission and ancillary services.
Schedule Page: 328.5 Line No.: 17 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.5 Line No.: 17 Column: d
Legacy contract (Rate Schedule 262) executed between PacifiCorp and Western Area Power
Administration for transmission and interconnection service over agreed-upon facilities
and/or subject to a sole-use or facilities charge for load service to preferential
customers for deliveries of Colorado River Storage Project power and energy. Agreement
termination upon three years after written notice and mutual consent.
Schedule Page: 328.5 Line No.: 17 Column: m
Fixed termination fee associated with a contract cancellation applied for the duration of
this agreement.
Schedule Page: 328.5 Line No.: 18 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.5 Line No.: 18 Column: d
Legacy contract (Rate Schedule 262) executed between PacifiCorp and Western Area Power
Administration for transmission and interconnection service over agreed-upon facilities
and/or subject to a sole-use or facilities charge for load service to preferential
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.32
customers for deliveries of Colorado River Storage Project power and energy. Agreement
termination upon three years written notice and mutual consent.
Schedule Page: 328.5 Line No.: 18 Column: m
Fixed termination fee associated with a contract cancellation applied for the duration of
this agreement. December 2012 transmission and ancillary services.
Schedule Page: 328.5 Line No.: 19 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.5 Line No.: 19 Column: d
Legacy contract (Rate Schedule 263) executed between PacifiCorp and Western Area Power
Administration for transmission and interconnection service over agreed-upon facilities
and/or subject to a sole-use or facilities charge for load service to low-voltage
customers for deliveries of power and energy from Salt Lake City Area Integrated Projects,
including the Colorado River Storage Projects, to certain municipalities at service below
138kV. Agreement termination upon three years written notice and mutual consent.
Schedule Page: 328.5 Line No.: 19 Column: m
Charges for low-voltage transmission of power and energy.
Schedule Page: 328.5 Line No.: 20 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.5 Line No.: 20 Column: d
Legacy contract (Rate Schedule 263) executed between PacifiCorp and Western Area Power
Administration for transmission and interconnection service over agreed-upon facilities
and/or subject to a sole-use or facilities charge for load service to low-voltage
customers for deliveries of power and energy from Salt Lake City Area Integrated Projects,
including the Colorado River Storage Projects, to certain municipalities at service below
138kV. Agreement termination upon three years written notice and mutual consent.
Schedule Page: 328.5 Line No.: 20 Column: m
Charges for low-voltage transmission of power and energy. December 2012 transmission and
ancillary services.
Schedule Page: 328.5 Line No.: 21 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 21 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, in this Form No. 1.
Schedule Page: 328.5 Line No.: 22 Column: d
Evergreen network transmission service under the Open Access Transmission Tariff (3rd
Revised Service Agreement 175).
Schedule Page: 328.5 Line No.: 22 Column: m
Distribution voltage service charge. Primary delivery service. Scheduling, system control
and dispatch service. Reactive supply and voltage control service.
Schedule Page: 328.5 Line No.: 23 Column: d
Evergreen network transmission service under the Open Access Transmission Tariff (3rd
Revised Service Agreement 175).
Schedule Page: 328.5 Line No.: 23 Column: m
Refunds for transmission and ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.5 Line No.: 24 Column: a
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: 328.5 Line No.: 24 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 24 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.33
Schedule Page: 328.5 Line No.: 24 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.5 Line No.: 25 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 Line No.: 25 Column: m
December 2012 transmission and ancillary services. Refunds for ancillary services pursuant
to FERC Docket No. ER11-3643.
Schedule Page: 328.5 Line No.: 26 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 Line No.: 26 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.5 Line No.: 27 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: 328.5 Line No.: 27 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 Line No.: 27 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.5 Line No.: 28 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 Line No.: 28 Column: m
Refunds for ancillary services pursuant to FERC Docket No. ER11-3643.
Schedule Page: 328.5 Line No.: 29 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 of 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 of 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.34
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
/ /2013/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 1,289,153 1,289,153 324,224 324,224Arizona Public Service 1
NF 440,288 440,288 90,107 90,107Arizona Public Service 2
OS 17,979 8,473 9,506 46 46Arizona Public Service 3
OSArizona Public Service 4
SFP 69,235 69,235 13,940 13,940Arizona Public Service 5
FNS 23,471 23,471 2,453 2,453Ashland, City of 6
FNS 213,342 213,342 60,577 58,144Avista Corporation 7
NF 218,702 218,702 43,970 43,970Avista Corporation 8
SFP 38,766 38,766 10,080 10,080Avista Corporation 9
NF 148,595 148,595 91,732 91,732Basin Elect. Power Coop 10
OLF 197,474 197,474Big Horn Rural Electric 11
AD -79,056 -79,056Black Hills Power, Inc. 12
NF 7,617 7,617 3,358 3,358Black Hills Power, Inc. 13
AD -246,684 -312,299 44,805 20,810Bonneville Power Admin 14
FNS 6,323,965 6,323,965Bonneville Power Admin 15
LFP 49,722,211 49,722,211 4,001,799 4,001,799Bonneville Power Admin 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332
14,366,419 14,832,184 116,749,567 3,806,761 16,625,976 137,182,304TOTAL
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
/ /2013/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)
NF 592,328 592,328 133,795 133,795Bonneville Power Admin 1
OLF 31,810,534 91,505 27,270 31,691,759 3,519,332 3,306,781Bonneville Power Admin 2
OS 2,166,733 2,161,341 5,392 30,174 30,174Bonneville Power Admin 3
OSBonneville Power Admin 4
SFP 1,195,629 1,195,629 253,705 253,705Bonneville Power Admin 5
AD -45,745 -105,154 59,409CA Ind Sys Oper Corp 6
OS 443,390 443,390CA Ind Sys Oper Corp 7
SFP 1,665,643 1,665,643 190,423 190,423CA Ind Sys Oper Corp 8
LFP 4,603,580 4,603,580 130,341 130,341Deseret Gen & Trans 9
NF 1,729,784 1,729,784 285,318 285,318Deseret Gen & Trans 10
NF 5,205 5,205 7,506 7,506El Paso Electric Co. 11
OS 724 724El Paso Electric Co. 12
OS 76,508 76,508Flathead Elect Coop Inc 13
OS 188,315 188,315Hermiston Gen Co L.P. 14
AD 801,575 734,544 67,031Idaho Power Company 15
FNS 8,463 8,463Idaho Power Company 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1
14,366,419 14,832,184 116,749,567 3,806,761 16,625,976 137,182,304TOTAL
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
/ /2013/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 6,593,851 6,593,851 2,663,040 2,418,342Idaho Power Company 1
NF 474,856 32,901 441,955 117,813 117,813Idaho Power Company 2
OS 12,503,647 12,527,593 -23,946Idaho Power Company 3
OSIdaho Power Company 4
SFP 680,901 680,901 273,264 273,264Idaho Power Company 5
NF 3,600 3,600 400 400LA Dept of Water & Pwr 6
FNS 294,174 294,174Moon Lake Elect. Assoc. 7
LFP 1,812 1,812 13 13Morgan City Corporation 8
NF 186,911 186,911 32,429 32,429Nevada Power Company 9
OS 246,447 246,447Nevada Power Company 10
SFP 985,280 985,280 239,518 239,518Nevada Power Company 11
NF 1,549,329 1,549,329 356,978 356,978NorthWestern Corp. 12
OS 112,754 112,754NorthWestern Corp. 13
SFP 785,276 785,276 130,013 130,013NorthWestern Corp. 14
LFP 849,700 849,700 126,414 126,414Platte River Pwr Auth 15
OS 6,501 6,501Platte River Pwr Auth 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.2
14,366,419 14,832,184 116,749,567 3,806,761 16,625,976 137,182,304TOTAL
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
/ /2013/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)
NF 1 1 1 1Portland Gen. Electric 1
OLF 848 848Portland Gen. Electric 2
LFP 966,469 966,469 71,793 68,753Public Service Co of CO 3
AD -271,290 -271,290Public Service Co of NM 4
NF 221,730 221,730 83,419 83,419Salt River Project 5
OS 36,232 36,232Salt River Project 6
NF 245,389 245,389 35,400 35,400Sierra Pacific Pwr Co 7
OS 26,362 26,362Sierra Pacific Pwr Co 8
SFP 13,338 13,338 1,540 1,540Sierra Pacific Pwr Co 9
OLF 8,062 8,062Surprise Valley Electr. 10
LFP 966,469 966,469 64,355 61,312Tri-State Gen & Transm 11
NF 545,211 545,211 145,781 145,781Tri-State Gen & Transm 12
OS 134,008 134,008Tri-State Gen & Transm 13
LFP 596,442 596,442 192,720 192,720Tucson Electric Power 14
NF 17,198 17,198 3,950 3,950Tucson Electric Power 15
OS 54,882 54,882Tucson Electric Power 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.3
14,366,419 14,832,184 116,749,567 3,806,761 16,625,976 137,182,304TOTAL
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
/ /2013/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 -3,615,444 -3,615,444Westport Field Svc LLC 1
AD 157,462 160,660 -3,198Western Area Power Admn 2
FNS 6,112,866 6,112,866Western Area Power Admn 3
LFP 1,780,000 1,780,000 733,826 733,826Western Area Power Admn 4
NF 696,529 696,529 340,471 340,471Western Area Power Admn 5
OS 1,207,646 1,207,646Western Area Power Admn 6
OSWestern Area Power Admn 7
SFP 54,145 54,145 26,166 26,166Western Area Power Admn 8
-611,558 -611,558Accrual 9
AD -1,063,456 -1,063,456Reserve 10
11
12
13
14
15
16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.4
14,366,419 14,832,184 116,749,567 3,806,761 16,625,976 137,182,304TOTAL
Schedule Page: 332 Line No.: 1 Column: b
Arizona Public Service Company - contract termination dates: 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, in this Form No. 1.
Schedule Page: 332 Line No.: 11 Column: b
Big Horn Rural Electric Company - contract termination date: March 10, 2015
Schedule Page: 332 Line No.: 11 Column: g
Use of facilities.
Schedule Page: 332 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 12 Column: e
Settlement adjustment.
Schedule Page: 332 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 14 Column: g
Ancillary services.
Schedule Page: 332 Line No.: 16 Column: b
Bonneville Power Administration - contract termination dates: 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.: 2 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.: 2 Column: g
Use of facilities.
Schedule Page: 332.1 Line No.: 3 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.1 Line No.: 4 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, in this Form No. 1.
Schedule Page: 332.1 Line No.: 6 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.: 6 Column: b
Settlement adjustment.
Schedule Page: 332.1 Line No.: 6 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 7 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 9 Column: b
Deseret Generation and Transmission Cooperative - contract termination dates: January 1,
2018 and September 1, 2018
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 332.1 Line No.: 12 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 13 Column: g
Use of facilities.
Schedule Page: 332.1 Line No.: 14 Column: a
Hermiston Generating Company, L.P. operates the Hermiston Generating Plant, which is
jointly owned. PacifiCorp owns 50% of the plant.
Schedule Page: 332.1 Line No.: 14 Column: g
Use of facilities.
Schedule Page: 332.1 Line No.: 15 Column: b
Settlement adjustment.
Schedule Page: 332.1 Line No.: 15 Column: g
PacifiCorp's portion of specified costs of certain facilities.
Schedule Page: 332.2 Line No.: 1 Column: b
Idaho Power Company - contract termination dates: April 1, 2025 and July 1, 2025
Schedule Page: 332.2 Line No.: 3 Column: e
Credit for unreserved use.
Schedule Page: 332.2 Line No.: 3 Column: g
Ancillary services. Use of facilities. PacifiCorp's portion of specified costs of certain
facilities.
Schedule Page: 332.2 Line No.: 4 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, in this Form No. 1.
Schedule Page: 332.2 Line No.: 6 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.: 7 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 8 Column: b
Morgan City Corporation - contract termination date: Evergreen
Schedule Page: 332.2 Line No.: 9 Column: a
This footnote applies to all occurrences of "Nevada Power Company" on page 332. Nevada
Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect wholly
owned subsidiary of MidAmerican Energy Holdings Company.
Schedule Page: 332.2 Line No.: 10 Column: g
Ancillary services.
Schedule Page: 332.2 Line No.: 13 Column: g
Ancillary services.
Schedule Page: 332.2 Line No.: 15 Column: b
Platte River Power Authority - contract termination date: October 31, 2017
Schedule Page: 332.2 Line No.: 16 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 2 Column: b
Portland General Electric Company - contract termination date: Upon two years written
notice
Schedule Page: 332.3 Line No.: 2 Column: g
Use of facilities.
Schedule Page: 332.3 Line No.: 3 Column: b
Public Service Company of Colorado - contract termination date: The date that all
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
generating plants comprising PacifiCorp resources associated with this agreement have been
retired from service or interests transferred.
Schedule Page: 332.3 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 332.3 Line No.: 4 Column: e
Settlement adjustment.
Schedule Page: 332.3 Line No.: 6 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 7 Column: a
This footnote applies to all occurrences of "Sierra Pacific Pwr Co" on page 332. Sierra
Pacific Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect
wholly owned subsidiary of MidAmerican Energy Holdings Company.
Schedule Page: 332.3 Line No.: 8 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 10 Column: b
Surprise Valley Electrification Corp. - contract termination date: Evergreen
Schedule Page: 332.3 Line No.: 10 Column: g
Use of facilities.
Schedule Page: 332.3 Line No.: 11 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: 332.3 Line No.: 13 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 14 Column: b
Tucson Electric Power Company - contract termination date: December 1, 2015
Schedule Page: 332.3 Line No.: 16 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 1 Column: b
Westport Field Services, LLC - contract termination date: Evergreen
Schedule Page: 332.4 Line No.: 1 Column: e
Reimbursement for third-party service provided.
Schedule Page: 332.4 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 332.4 Line No.: 2 Column: e
Settlement adjustment.
Schedule Page: 332.4 Line No.: 2 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 4 Column: b
Western Area Power Administration - contract termination date: May 31, 2022
Schedule Page: 332.4 Line No.: 6 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.4 Line No.: 7 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, in this Form No. 1.
Schedule Page: 332.4 Line No.: 9 Column: g
Represents the difference between actual wheeling expenses for the period as reflected on
the individual line items within this schedule, and the accruals charged to Account 565,
Transmission of electricity by others, during this period.
Schedule Page: 332.4 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 332.4 Line No.: 10 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
2013/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
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
PacifiCorp X / /2013/Q4
Line Description Amount
(b)(a)No.
1,673,683Industry 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
5,000Alberta Main Street 9
5,000Albina Opportunities Corporation 10
5,000American Leadership Forum 11
5,000Casper Area Economic Development Alliance 12
6,000Clatsop Economic Development 13
19,100Economic Development Corporation of Utah 14
9,000Economic Development for Central Oregon 15
7,446Equal Employment Advisory Council 16
10,000Four County Economic Development Corporation 17
5,000Gorge Oregon Entrepreneurs Network 18
15,000Grow Oregon 19
7,000Idaho Economic Development Association 20
9,000Intermountain Electrical Assoication 21
5,735Klamath County Chamber of Commerce 22
7,390North Davis Chamber of Commerce 23
595,784Northern Tier Transmission Group 24
13,250Oregon Business Association 25
25,938Oregon Business Council 26
12,000Oregon Economic Development Association 27
5,000Oregon Sports Authority Foundation 28
15,000Oregon State University 29
74,153Pacific Northwest Utilities Conference 30
38,950Portland Business Alliance 31
7,000Redmond Economic Development 32
16,000Rocky Mountain Electrical League 33
30,742Salt Lake Area Chamber of Commerce 34
5,000Siskiyou County Economic Development 35
6,000South Coast Development Council, Inc. 36
10,000Tree Research and Education Endowment Fund 37
15,000Utah Governor's Economic Summit 38
6,600Utah Manufacturers Association 39
18,700Utah Taxpayers Association 40
52,450Watson & Renner 41
3,725,747Western Electricity Coordinating Council 42
44,690Western Energy Institute 43
15,694Western Energy Supply and Transmission Associates 44
6,000Wyoming Business Alliance 45
7,526,075
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 / /2013/Q4
Line Description Amount
(b)(a)No.
5,000Wyoming Business Council 6
11,223Wyoming Taxpayers Association 7
7,500Yakima County Development 8
161,745Other (Individually < $5,000) 9
10
22,945Directors' Fees - Regional Advisory Boards 11
12
Rating Agency and Trustee Fees: 13
169,602The Bank of New York Mellon 14
58,205Computershare Shareowner Services, LLC 15
6,400Financial Industry Regulatory Authority, Inc. 16
54,575Fitch, Inc. 17
175,015Moody's Investors Service, Inc. 18
258,000Standard and Poor's Financial Services, LLC 19
9,682U.S. Bank National Association 20
3,094Other (Individually < $5,000) 21
22
General: 23
456Other 24
25
Regulatory Asset Amortization: 26
48,581Generating Plant Liquidated Damages - WY 27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
7,526,075
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
/ /2013/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)
43,538,777 43,538,777 1 Intangible Plant
166,446,520 166,446,520 2 Steam Production Plant
3 Nuclear Production Plant
25,288,855 25,014,943 273,912 4 Hydraulic Production Plant-Conventional
5 Hydraulic Production Plant-Pumped Storage
115,859,652 115,859,652 6 Other Production Plant
94,564,623 94,564,623 7 Transmission Plant
159,821,396 159,821,396 8 Distribution Plant
9 Regional Transmission and Market Operation
40,744,523 39,122,546 1,621,977 10 General Plant
11 Common Plant-Electric
646,264,346 600,829,680 45,434,666 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
/ /2013/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
-3.59 6.00330.20 OR/CA 41 14
-3.76 6.00330.40 OR/CA 1 15
8.66 6.00331.00 OR/CA 14,044 16
5.67 6.00332.00 OR/CA 34,145 17
7.88 6.00333.00 OR/CA 17,883 18
10.66 6.00334.00 OR/CA 15,622 19
4.28 6.00335.00 OR/CA 183 20
6.78 6.00336.00 OR/CA 2,567 21
22
Cutler 23
8.34 11.00332.20 1 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, 2013, depreciation expense associated with transportation equipment was
$15,921,062.
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
2013/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
/ /2013/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 4,858,574 4,858,574 2
Rate Case 1,282,915 1,282,915 3
4
Oregon Public Utility Commission: 5
Annual Fee 3,273,471 3,273,471 6
Rate Case 1,219,564 1,219,564 7
585,536Deferred Intervenor Funding Grants 8
9
Wyoming Public Service Commission: 10
Annual Fee 1,525,742 1,525,742 11
Rate Case 228,179 228,179 12
13
Washington Utilities and Transportation 14
Commission: 15
Annual Fee 553,548 553,548 16
Rate Case 1,882,949 1,882,949 17
18
Idaho Public Utilities Commission: 19
Annual Fee 563,383 563,383 20
Rate Case 243,493 243,493 21
69,206Deferred Intervenor Funding Grants (2) 19,500 19,500 22
23
California Public Utilities Commission: 24
Annual Fee 1,099 1,099 25
Rate Case 538,867 538,867 26
32,952Deferred Intervenor Funding Grants 27
28
California Environmental Protection Agency: 29
Industry Compliance Fee 43,433 17,244 60,677 30
31
Rate Cases - All States 713,472 713,472 32
33
Federal Energy Regulatory Commission: 34
Annual Fee 1,883,087 1,883,087 35
Annual Fee - Hydro 2,350,790 2,350,790 36
Transmission Rate Case 254,925 254,925 37
Other Regulatory 1,243,762 1,243,762 38
39
Other Regulatory 68,285 68,285 40
41
Charges for services from MidAmerican Energy 42
Holdings Company and its affiliates: 43
Washington - Rate Case 1,421 1,421 44
FERC - Transmission Rate Case 534 534 45
FERC FORM NO. 1 (ED. 12-96) Page 350
46 TOTAL 15,053,127 7,715,110 22,768,237 687,694
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES (Continued)
PacifiCorp X
/ /2013/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 4,858,574928
Electric 3 1,282,915928
4
5
Electric 6 3,273,471928
Electric 7 1,219,564928
802,926 217,390 8
9
10
Electric 11 1,525,742928
Electric 12 228,179928
13
14
15
Electric 16 553,548928
Electric 17 1,882,949928
18
19
Electric 20 563,383928
Electric 21 243,493928
55,462 19,500928 5,756Electric 22 19,500928
23
24
Electric 25 1,099928
Electric 26 538,867928
40,307 7,355 27
28
29
Electric 30 60,677928
31
Electric 32 713,472928
33
34
Electric 35 1,883,087928
Electric 36 2,350,790928
Electric 37 254,925928
Electric 38 1,243,762928
39
Electric 40 68,285928
41
42
43
Electric 44 1,421928
Electric 45 534928
FERC FORM NO. 1 (ED. 12-96) Page 351
46 22,768,237 230,501 19,500 898,695
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
/ /2013/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
Edison Electric Institute (2) Research Support 4
- Avian Power Line Interaction Committee - membership dues 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
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
/ /2013/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 15,000 557 15,000
4
5 2,500 930.2 2,500
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
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
/ /2013/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
95,938,433Production 3
12,303,303Transmission 4
Regional Market 5
36,478,819Distribution 6
39,530,024Customer Accounts 7
6,206,300Customer Service and Informational 8
Sales 9
40,980,627Administrative and General 10
231,437,506TOTAL Operation (Enter Total of lines 3 thru 10) 11
Maintenance 12
48,511,570Production 13
10,595,957Transmission 14
Regional Market 15
69,062,051Distribution 16
1,837,373Administrative and General 17
130,006,951TOTAL Maintenance (Total of lines 13 thru 17) 18
Total Operation and Maintenance 19
144,450,003Production (Enter Total of lines 3 and 13) 20
22,899,260Transmission (Enter Total of lines 4 and 14) 21
Regional Market (Enter Total of Lines 5 and 15) 22
105,540,870Distribution (Enter Total of lines 6 and 16) 23
39,530,024Customer Accounts (Transcribe from line 7) 24
6,206,300Customer Service and Informational (Transcribe from line 8) 25
Sales (Transcribe from line 9) 26
42,818,000Administrative and General (Enter Total of lines 10 and 17) 27
361,444,457 361,444,457TOTAL 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
/ /2013/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
361,444,457 361,444,457TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65
Utility Plant 66
Construction (By Utility Departments) 67
137,795,183 137,795,183Electric Plant 68
Gas Plant 69
Other (provide details in footnote): 70
137,795,183 137,795,183TOTAL Construction (Total of lines 68 thru 70) 71
Plant Removal (By Utility Departments) 72
8,060,331 8,060,331Electric Plant 73
Gas Plant 74
Other (provide details in footnote): 75
8,060,331 8,060,331TOTAL Plant Removal (Total of lines 73 thru 75) 76
Other Accounts (Specify, provide details in footnote): 77
2,125,458 2,125,458Fuel Stock 78
677,250 677,250Miscellaneous Other Income Deductions 79
558,584 558,584Charges to Affiliates 80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
3,361,292 3,361,292TOTAL Other Accounts 95
510,661,263 510,661,263TOTAL 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
/ /2013/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 8,684,762 599,396 2,731,410 4,571,210
Net Sales (Account 447) 3 ( 22,647)( 16,815) ( 11,343) ( 22,647)
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
8,662,115 582,581 2,720,067 4,548,563
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
/ /2013/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
10,147,822MWh148,574,179Scheduling, System Control and Dispatch 1
-210,228MWh120,147,582 -26,122MWh109,647,672Reactive Supply and Voltage 2
29,568,048MWh 92,553,762 26,889,201MWh 82,131,450Regulation and Frequency Response 3
-7,556,884MWh -255,953Energy Imbalance 4
23,768,254MWh 73,290,551 20,974,879MWh 65,546,498Operating Reserve - Spinning 5
22,090,479MWh 68,694,640 20,950,006MWh 65,546,498Operating Reserve - Supplement 6
Other 7
77,807,491503,004,761 68,787,964322,872,118Total (Lines 1 thru 7) 8
FERC FORM NO. 1 (New 2-04) Page 398
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 / /2013/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
498 1,792 4,237 115 9,028180014 15,670January 1
208 1,627 4,237 107 8,252 80011 14,431February 2
514 1,547 3,951 108 8,066 800 4 14,186March 3
1,220 4,966 12,425 330 25,346 44,287Total for Quarter 1 4
327 1,461 3,951 108 7,604 800 9 13,451April 5
368 1,678 3,951 103 8,350160014 14,450May 6
197 2,042 4,109 110 10,148160028 16,606June 7
892 5,181 12,011 321 26,102 44,507Total for Quarter 2 8
566 2,132 4,109 115 10,8231600 1 17,745July 9
163 1,940 4,109 113 9,857150019 16,182August 10
350 1,879 4,369 108 9,1411600 5 15,847September 11
1,079 5,951 12,587 336 29,821 49,774Total for Quarter 3 12
424 1,415 4,401 97 7,771 80030 14,108October 13
252 1,618 4,243 115 8,389180021 14,617November 14
515 1,808 4,269 131 9,6561800 9 16,379December 15
1,191 4,841 12,913 343 25,816 45,104Total for Quarter 4 16
4,382 20,939 49,936 1,330 107,085 183,672
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 2013 Net System Load information was estimated using metering and/or
scheduling data. Reflects actual peak net system load for self at time of Transmission
System Peak. Peak load includes 690 megawatts of behind-the-meter generation for the
quarter.
Schedule Page: 400 Line No.: 4 Column: f
1st Quarter 2013 Net System Load information was estimated 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 2013 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 2013 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 2013 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 2013 Net System Load information was estimated using metering and/or
scheduling data. Reflects actual peak net system load for self at time of Transmission
System Peak. Peak load includes 825 megawatts of behind-the-meter generation for the
quarter.
Schedule Page: 400 Line No.: 8 Column: f
2nd Quarter 2013 Net System Load information was estimated 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 2013 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. 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
2nd Quarter 2013 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 2013 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.: 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 2013 Net System Load information was estimated using metering and/or
scheduling data. Reflects actual peak net system load for self at time of Transmission
System Peak. Peak load includes 927 megawatts of behind-the-meter generation for the
quarter.
Schedule Page: 400 Line No.: 12 Column: f
3rd Quarter 2013 Net System Load information was estimated 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 2013 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. 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 2013 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 2013 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 2013 Net System Load information was estimated using metering and/or
scheduling data. Reflects actual peak net system load for self at time of Transmission
System Peak. Peak load includes 663 megawatts of behind-the-meter generation for the
quarter.
Schedule Page: 400 Line No.: 16 Column: f
4th Quarter 2013 Net System Load information was estimated 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 2013 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. This adjustment has been made to ensure
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
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 2013 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak.
Schedule Page: 400 Line No.: 16 Column: j
4th Quarter 2013 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
2013/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
/ /2013/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
46,010,930Steam3
Nuclear4
3,167,941Hydro-Conventional5
Hydro-Pumped Storage6
9,202,064Other7
4,363Less Energy for Pumping8
58,376,572Net Generation (Enter Total of lines 3
through 8)
9
12,096,279Purchases10
Power Exchanges:11
4,186,538Received12
3,694,867Delivered13
491,671Net Exchanges (Line 12 minus line 13)14
Transmission For Other (Wheeling)15
12,830,379Received16
12,712,106Delivered17
118,273Net Transmission for Other (Line 16 minus
line 17)
18
-465,765Transmission By Others Losses19
70,617,030TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
20
DISPOSITION OF ENERGY21
55,662,873Sales to Ultimate Consumers (Including
Interdepartmental Sales)
22
230,282Requirements Sales for Resale (See
instruction 4, page 311.)
23
9,975,853Non-Requirements Sales for Resale (See
instruction 4, page 311.)
24
Energy Furnished Without Charge25
146,698Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
26
4,601,324Total Energy Losses27
70,617,030TOTAL (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 / /2013/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 14 8,825 882,817 1800 PST 6,434,963
February 30 11 8,052 832,058 0800 PST 5,529,546
March 31 4 7,780 823,326 0800 PST 5,615,389
April 32 9 7,338 917,507 0800 PDT 5,377,407
May 33 14 8,106 683,636 1600 PDT 5,422,233
June 34 28 9,833 557,062 1600 PDT 5,718,492
July 35 1 10,507 615,054 1600 PDT 6,429,745
August 36 19 9,571 706,835 1500 PDT 6,221,862
September 37 5 8,822 1,081,292 1500 PDT 5,780,942
October 38 30 7,512 989,707 0800 PDT 5,727,662
November 39 22 8,213 1,070,176 0800 PST 5,897,169
December 40 9 9,451 816,383 1800 PST 6,461,620
FERC FORM NO. 1 (ED. 12-90) Page 401b
41 TOTAL 70,617,030 9,975,853
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
2013/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
/ /2013/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)
385177 6 Net Peak Demand on Plant - MW (60 minutes)
73518714 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
058 11 Average Number of Employees
23936810001197765000 12 Net Generation, Exclusive of Plant Use - KWh
2634927956546 13 Cost of Plant: Land and Land Rights
6258905115572243 14 Structures and Improvements
470480250104471837 15 Equipment Costs
390007036834 16 Asset Retirement Costs
535743228128037460 17 Total Cost
1294.0658678.8837 18 Cost per KW of Installed Capacity (line 17/5) Including
159176798985 19 Production Expenses: Oper, Supv, & Engr
5622734626055932 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
80080511532464 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
9335451974477 25 Electric Expenses
21551584086786 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
26356680 29 Maintenance Supervision and Engineering
928885422120 30 Maintenance of Structures
55882453885492 31 Maintenance of Boiler (or reactor) Plant
6939071427205 32 Maintenance of Electric Plant
4089307390544 33 Maintenance of Misc Steam (or Nuclear) Plant
8285187939874005 34 Total Production Expenses
0.03460.0333 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)
565299 2475 0 1360563 2967 0 38 Quantity (Units) of Fuel Burned
12127 138000 0 9326 128637 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
45.045 140.214 0.000 39.291 147.143 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
45.478 140.214 0.000 41.006 147.143 0.000 41 Average Cost of Fuel per Unit Burned
1.875 24.192 1.898 2.199 27.235 2.214 42 Average Cost of Fuel Burned per Million BTU
0.021 0.000 0.021 0.023 0.000 0.023 43 Average Cost of Fuel Burned per KWh Net Gen
11447.018 11.977 11458.995 10601.257 6.697 10607.954 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
/ /2013/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
739153 168 6
87608587 8557 7
00 0 8
762148 166 9
00 0 10
1880 0 11
5308783000837293000 1017613000 12
104497931788103 137086 13
15477355060600305 37619781 14
823783706161516721 142410204 15
1239503639236 35149 16
1001402085223944365 180202220 17
1226.00651439.2311 1047.0786 18
27024242881 390267 19
6421851413373215 19463157 20
00 0 21
500025868394 1876621 22
00 0 23
00 0 24
046461 818263 25
184103951171565 1104254 26
8971620596 940 27
00 0 28
0247232 847093 29
2798820370814 612875 30
110026342694697 5201028 31
5472546538267 2274296 32
2023789347860 1171426 33
10478668119721982 33760220 34
0.01970.0236 0.0332 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
523604 1131 0 3686523 12788 0505363 22 0 38
8464 140000 0 8077 138000 09983 133693 0 39
23.602 132.611 0.000 17.395 133.120 0.00037.265 126.158 0.000 40
25.254 132.611 0.000 16.958 133.120 0.00038.318 126.158 0.000 41
1.492 22.551 1.508 1.050 22.968 1.0771.919 22.542 1.929 42
0.016 0.000 0.016 0.012 0.000 0.0120.019 0.000 0.019 43
10585.699 7.943 10593.642 11217.306 13.962 11231.2689915.736 0.119 9915.855 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
/ /2013/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)
42275 6 Net Peak Demand on Plant - MW (60 minutes)
82238760 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
2858108000646108000 12 Net Generation, Exclusive of Plant Use - KWh
9688975683069 13 Cost of Plant: Land and Land Rights
6345766917674475 14 Structures and Improvements
31415149166895845 15 Equipment Costs
1976952532363 16 Asset Retirement Costs
38927508785785752 17 Total Cost
850.50271053.8790 18 Cost per KW of Installed Capacity (line 17/5) Including
0201094 19 Production Expenses: Oper, Supv, & Engr
5621708816238571 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
3089428907330 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
-55967223553 25 Electric Expenses
2190948471736 26 Misc Steam (or Nuclear) Power Expenses
-5590 27 Rents
00 28 Allowances
0337693 29 Maintenance Supervision and Engineering
3280523749591 30 Maintenance of Structures
7406991994074 31 Maintenance of Boiler (or reactor) Plant
2310964265846 32 Maintenance of Electric Plant
252079480996 33 Maintenance of Misc Steam (or Nuclear) Plant
7469149520870484 34 Total Production Expenses
0.02610.0323 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)
309815 283 0 1313405 6539 0 38 Quantity (Units) of Fuel Burned
11202 137191 0 11312 138000 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
50.229 144.576 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
52.252 144.576 0.000 42.109 0.000 0.000 41 Average Cost of Fuel per Unit Burned
2.332 25.090 2.339 1.861 24.018 1.889 42 Average Cost of Fuel Burned per Million BTU
0.025 0.000 0.025 0.019 0.000 0.019 43 Average Cost of Fuel Burned per KWh Net Gen
10743.313 2.527 10745.840 10396.815 13.261 10410.076 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
/ /2013/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
1160275 478 6
87608626 8369 7
00 0 8
1158269 471 9
00 0 10
2190 0 11
80678890001987634000 3222147000 12
296533519688975 10275401 13
20668915452330697 90900788 14
988010140242846489 431012160 15
59308561976952 1976952 16
1230283501306843113 534165301 17
985.96211041.9121 1077.8154 18
00 0 19
15483653936679012 61940439 20
00 0 21
87736372319226 3364983 22
00 0 23
00 0 24
-5134657894 -53273 25
3537513-1052422 2398987 26
-1549-360 -630 27
00 0 28
00 0 29
84012732097254 3023496 30
238882575777677 10703589 31
49791991013320 1654915 32
1014787283864 478844 33
20537831047175465 83511350 34
0.02550.0237 0.0259 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
868601 585 0 3621335 16800 01439329 9676 0 38
11524 138000 0 11368 138000 011325 138000 0 39
0.000 0.000 0.000 42.708 138.309 0.0000.000 0.000 0.000 40
42.137 0.000 0.000 42.115 138.309 0.00042.107 0.000 0.000 41
1.828 23.203 1.832 1.852 23.863 1.8781.859 23.798 1.897 42
0.018 0.000 0.018 0.019 0.000 0.0190.019 0.000 0.019 43
10071.695 1.706 10073.401 10205.411 12.070 10217.48110118.118 17.406 10135.524 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
/ /2013/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
1550.65996.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
1423912 6 Net Peak Demand on Plant - MW (60 minutes)
87608760 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
345164 11 Average Number of Employees
99363880006768625000 12 Net Generation, Exclusive of Plant Use - KWh
11619252386782 13 Cost of Plant: Land and Land Rights
138651627118613800 14 Structures and Improvements
957423038703371377 15 Equipment Costs
47503444179560 16 Asset Retirement Costs
1101986934828551519 17 Total Cost
710.6613831.8790 18 Cost per KW of Installed Capacity (line 17/5) Including
1462661712135 19 Production Expenses: Oper, Supv, & Engr
220562489111058721 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
41950889245363 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
29410 25 Electric Expenses
-1085608612978016 26 Misc Steam (or Nuclear) Power Expenses
3622521522 27 Rents
00 28 Allowances
6227631407281 29 Maintenance Supervision and Engineering
110449052731649 30 Maintenance of Structures
266525818277705 31 Maintenance of Boiler (or reactor) Plant
79177511587328 32 Maintenance of Electric Plant
25661691240962 33 Maintenance of Misc Steam (or Nuclear) Plant
277697470148540682 34 Total Production Expenses
0.02790.0219 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)
2891832 4368 0 5434450 12125 0 38 Quantity (Units) of Fuel Burned
12003 138000 0 9339 138000 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
40.364 140.939 0.000 37.815 133.981 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
38.191 140.939 0.000 40.287 133.981 0.000 41 Average Cost of Fuel per Unit Burned
1.591 24.317 1.599 2.157 23.116 2.171 42 Average Cost of Fuel Burned per Million BTU
0.016 0.000 0.016 0.022 0.000 0.022 43 Average Cost of Fuel Burned per KWh Net Gen
10256.196 3.741 10259.937 10215.569 7.073 10222.642 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
/ /2013/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
161712 283 6
53128760 8223 7
00 0 8
238687 268 9
00 0 10
34134 65 11
2223960005533895000 1975401000 12
12520901094739 210526 13
15102770116741815 51295214 14
65900473635993498 393360506 15
58700820721266 490453 16
82842341774551318 445356699 17
329.26211095.2366 1537.3031 18
259921362513 217876 19
16789712116935308 20435057 20
00 0 21
06827303 321768 22
00 0 23
00 0 24
01202 0 25
424245812253566 4475333 26
01282 15039 27
00 0 28
01233751 0 29
877961158048 308539 30
13397617350601 6123857 31
10213571960476 1239636 32
420123822674 130614 33
24161128148906724 33267719 34
0.10860.0269 0.0168 35
Coal Gas Composite GasCoal Oil Composite 36
Tons MCF MCFTons Barrels 37
2951673 67897 0 3240573 0 01504512 4169 0 38
10012 1050 0 1021 0 07939 138000 0 39
39.363 8.628 0.000 5.181 0.000 0.00013.127 135.319 0.000 40
39.418 8.628 0.000 5.181 0.000 0.00013.208 135.319 0.000 41
1.968 8.216 1.976 5.073 0.000 0.0000.832 23.347 0.855 42
0.021 0.000 0.021 0.075 0.000 0.0000.010 0.000 0.010 43
10680.842 12.885 10693.727 14882.624 0.000 0.00012092.393 12.232 12104.625 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
/ /2013/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)
38245 6 Net Peak Demand on Plant - MW (60 minutes)
83148014 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
240 11 Average Number of Employees
2507220001293909000 12 Net Generation, Exclusive of Plant Use - KWh
41195596842245 13 Cost of Plant: Land and Land Rights
824563812844996 14 Structures and Improvements
71389327158857742 15 Equipment Costs
1744133214373 16 Asset Retirement Costs
122574694172759356 17 Total Cost
3217.1836617.8804 18 Cost per KW of Installed Capacity (line 17/5) Including
174250 19 Production Expenses: Oper, Supv, & Engr
061105462 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
8605350 22 Steam Expenses
43124390 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
07066609 25 Electric Expenses
9876010 26 Misc Steam (or Nuclear) Power Expenses
62470 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
3808050 30 Maintenance of Structures
2072740 31 Maintenance of Boiler (or reactor) Plant
17139320 32 Maintenance of Electric Plant
781870 33 Maintenance of Misc Steam (or Nuclear) Plant
856444568172071 34 Total Production Expenses
0.03420.0527 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)
9845424 0 0 0 0 0 38 Quantity (Units) of Fuel Burned
1023 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
6.206 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
6.206 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
6.069 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.047 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
7781.617 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
/ /2013/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
12122 494 6
36145941 4403 7
00 0 8
12014 518 9
00 0 10
00 18 11
11746400062089000 1674194000 12
00 1973790 13
42730005733734 23907901 14
7694699528718343 313293868 15
00 689117 16
8121999534452077 339864676 17
448.4815560.1964 572.8378 18
00 192329 19
88302330 68274999 20
00 0 21
00 0 22
00 0 23
00 0 24
5250610 2048664 25
0421378 694005 26
00 49584 27
00 0 28
00 0 29
1659980 49830 30
00 0 31
10123980 2332424 32
1146280 0 33
10648318421378 73641835 34
0.09070.0068 0.0440 35
GasGas 36
MCFMCF 37
0 0 0 1504686 0 011912103 0 0 38
0 0 0 1120 0 01042 0 0 39
0.000 0.000 0.000 5.868 0.000 0.0005.732 0.000 0.000 40
0.000 0.000 0.000 5.868 0.000 0.0005.732 0.000 0.000 41
0.000 0.000 0.000 5.238 0.000 0.0005.501 0.000 0.000 42
0.000 0.000 0.000 0.075 0.000 0.0000.041 0.000 0.000 43
0.000 0.000 0.000 14352.457 0.000 0.0007412.944 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
/ /2013/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)
553550 6 Net Peak Demand on Plant - MW (60 minutes)
78768625 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
2920 11 Average Number of Employees
25089600002359924000 12 Net Generation, Exclusive of Plant Use - KWh
172786833403277 13 Cost of Plant: Land and Land Rights
2822108144185107 14 Structures and Improvements
323085508324569362 15 Equipment Costs
0134848 16 Asset Retirement Costs
368585272372292594 17 Total Cost
623.3473656.7165 18 Cost per KW of Installed Capacity (line 17/5) Including
18170374681 19 Production Expenses: Oper, Supv, & Engr
9317484589904876 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)
25867911815653 25 Electric Expenses
1006461788639 26 Misc Steam (or Nuclear) Power Expenses
058 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
2590159221060 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
7505761242948 32 Maintenance of Electric Plant
7872077060 33 Maintenance of Misc Steam (or Nuclear) Plant
10036925594124975 34 Total Production Expenses
0.04000.0399 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)
17147926 0 0 17434244 0 0 38 Quantity (Units) of Fuel Burned
1041 0 0 1038 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
5.243 0.000 0.000 5.344 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
5.243 0.000 0.000 5.344 0.000 0.000 41 Average Cost of Fuel per Unit Burned
5.036 0.000 0.000 5.149 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.038 0.000 0.000 0.037 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
7565.569 0.000 0.000 7213.003 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
/ /2013/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: 403 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: 403 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: 403 Line No.: 11 Column: d
PacifiCorp does not have employees at the Colstrip Plant.
Schedule Page: 403 Line No.: 11 Column: e
PacifiCorp does not have employees at the Craig Plant.
Schedule Page: 403 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
2013 were $1.5 million and were primarily credited to Account 506, Miscellaneous steam
power expenses.
Schedule Page: 403.1 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 2013 were $7.2
million and were primarily credited to Account 506, Miscellaneous steam power expenses.
Schedule Page: 403.1 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: 403.1 Line No.: 11 Column: d
Refer to Hunter - Total Plant on page 403.1 for the average number of employees.
Schedule Page: 403.1 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
2013 were $27.2 million and were primarily credited to Account 506, Miscellaneous steam
power expenses.
Schedule Page: 403.2 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 2013 were $3.7
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, in 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: 403.3 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: 403.3 Line No.: 11 Column: d
PacifiCorp does not have employees at the Camas Co-Generation unit at Georgia-Pacific
Corporation's Camas, Washington paper mill.
Schedule Page: 403.3 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
2013/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
2013/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
/ /2013/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 25 29
Plant Hours Connect to Load 7 6,251 6,080
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 67,577,000 83,609,000
Cost of Plant 13
Land and Land Rights 14 107,019 20,914
Structures and Improvements 15 1,615,906 2,342,432
Reservoirs, Dams, and Waterways 16 2,933,710 2,954,724
Equipment Costs 17 5,278,956 10,396,954
Roads, Railroads, and Bridges 18 105,442 479,588
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 10,041,033 16,194,612
Cost per KW of Installed Capacity (line 20 / 5) 21 502.0517 599.8004
Production Expenses 22
Operation Supervision and Engineering 23 40,381 29,190
Water for Power 24 -1,734 -2,341
Hydraulic Expenses 25 1,846 2,492
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 921,504 1,225,104
Rents 28 34,453 46,512
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 3,699 5,506
Maintenance of Reservoirs, Dams, and Waterways 31 95,732 88,429
Maintenance of Electric Plant 32 107,103 249,711
Maintenance of Misc Hydraulic Plant 33 12,405 16,745
Total Production Expenses (total 23 thru 33) 34 1,215,389 1,661,348
Expenses per net KWh 35 0.0180 0.0199
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
/ /2013/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
23 1712 6
8,118 5,3148,190 7
8
31 2918 9
31 2918 10
1 31 11
39,381,000 31,877,00037,778,000 12
13
0 3,511,1050 14
1,738,004 3,969,9861,228,415 15
14,743,489 7,580,9665,130,185 16
1,976,274 14,609,3621,326,944 17
250,151 572,05950,817 18
0 00 19
18,707,918 30,243,4787,736,361 20
719.5353 1,008.1159515.7574 21
22
30,786 106,30830,048 23
2,101 3,7491,212 24
99,254 54,21257,262 25
0 00 26
391,227 443,247258,655 27
57,609 -50033,236 28
68 039 29
57,674 37,03950,539 30
67,658 9,71110,723 31
56,770 21,270109,899 32
123,431 231,34691,376 33
886,578 906,382642,989 34
0.0225 0.02840.0170 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
/ /2013/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 17
Plant Hours Connect to Load 7 2,327 6,688
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 15,766,000 70,991,000
Cost of Plant 13
Land and Land Rights 14 0 62,169
Structures and Improvements 15 989,738 1,964,387
Reservoirs, Dams, and Waterways 16 12,379,990 10,964,143
Equipment Costs 17 1,865,730 4,338,635
Roads, Railroads, and Bridges 18 533,015 341,093
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 15,768,473 17,670,427
Cost per KW of Installed Capacity (line 20 / 5) 21 1,433.4975 535.4675
Production Expenses 22
Operation Supervision and Engineering 23 12,997 87,844
Water for Power 24 889 4,123
Hydraulic Expenses 25 41,992 59,634
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 261,197 1,345,200
Rents 28 24,373 4,330
Maintenance Supervision and Engineering 29 29 0
Maintenance of Structures 30 21,200 77,198
Maintenance of Reservoirs, Dams, and Waterways 31 87,902 56,422
Maintenance of Electric Plant 32 28,442 71,240
Maintenance of Misc Hydraulic Plant 33 43,664 163,256
Total Production Expenses (total 23 thru 33) 34 522,685 1,869,247
Expenses per net KWh 35 0.0332 0.0263
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
/ /2013/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
78 2719 6
5,270 8,0148,292 7
8
83 3219 9
83 3219 10
2 11 11
166,834,000 123,888,00085,349,000 12
13
25,845 0341,706 14
3,445,932 2,471,8746,639,458 15
14,559,725 15,366,40913,695,754 16
15,295,677 6,844,2082,716,356 17
886,710 484,7281,095,742 18
0 00 19
34,213,889 25,167,21924,489,016 20
349.1926 786.72141,360.5009 21
22
308,557 38,1271,365,809 23
-8,496 2,585-1,561 24
10,206 122,12141,822 25
0 00 26
800,712 519,841836,885 27
122,680 70,88131,074 28
0 830 29
6,417 105,80140,040 30
9,330 108,31024,499 31
79,168 107,282192,132 32
59,869 125,64311,165 33
1,388,443 1,200,6742,541,865 34
0.0083 0.00970.0298 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
/ /2013/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 35 144
Plant Hours Connect to Load 7 8,317 8,760
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 12 150,001,000 460,852,000
Cost of Plant 13
Land and Land Rights 14 0 1,086,564
Structures and Improvements 15 4,371,431 51,335,863
Reservoirs, Dams, and Waterways 16 31,376,412 25,767,703
Equipment Costs 17 11,748,386 18,512,487
Roads, Railroads, and Bridges 18 1,955,909 2,978,357
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 49,452,138 99,680,974
Cost per KW of Installed Capacity (line 20 / 5) 21 1,284.4711 732.9483
Production Expenses 22
Operation Supervision and Engineering 23 46,312 1,231,090
Water for Power 24 3,112 6,787
Hydraulic Expenses 25 146,972 714,351
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 552,618 385,275
Rents 28 85,306 99,592
Maintenance Supervision and Engineering 29 100 0
Maintenance of Structures 30 94,035 19,811
Maintenance of Reservoirs, Dams, and Waterways 31 225,784 36,174
Maintenance of Electric Plant 32 79,238 71,305
Maintenance of Misc Hydraulic Plant 33 151,211 374,946
Total Production Expenses (total 23 thru 33) 34 1,384,688 2,939,331
Expenses per net KWh 35 0.0092 0.0064
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
/ /2013/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
21 3643 6
8,319 8,6268,043 7
8
28 3645 9
28 3645 10
2 11 11
28,182,000 215,139,000195,898,000 12
13
36,698 105,1680 14
1,888,351 3,525,8964,057,415 15
6,083,220 30,122,38212,783,603 16
5,626,866 6,778,9603,786,254 17
503,332 305,160264,441 18
0 00 19
14,138,467 40,837,56620,891,713 20
471.2822 1,276.1739491.5697 21
22
79,380 103,06058,347 23
3,749 102,2183,435 24
54,212 8,481162,242 25
0 00 26
654,229 1,053,083546,867 27
2,182 4,05294,169 28
0 0111 29
33,227 73,16492,229 30
-3,679 338,925138,116 31
272,057 354,888236,812 32
162,086 716,683166,921 33
1,257,443 2,754,5541,499,249 34
0.0446 0.01280.0077 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
/ /2013/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 16 8
Plant Hours Connect to Load 7 8,318 7,319
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 53,119,000 15,674,000
Cost of Plant 13
Land and Land Rights 14 0 511,083
Structures and Improvements 15 2,186,187 732,396
Reservoirs, Dams, and Waterways 16 14,872,403 8,721,281
Equipment Costs 17 8,966,627 5,361,205
Roads, Railroads, and Bridges 18 463,083 0
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 26,488,300 15,325,965
Cost per KW of Installed Capacity (line 20 / 5) 21 1,471.5722 1,094.7118
Production Expenses 22
Operation Supervision and Engineering 23 22,287 37,044
Water for Power 24 3,053 1,749
Hydraulic Expenses 25 68,714 25,299
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 297,879 444,011
Rents 28 39,883 1,018
Maintenance Supervision and Engineering 29 47 0
Maintenance of Structures 30 65,113 30,043
Maintenance of Reservoirs, Dams, and Waterways 31 19,862 -9,892
Maintenance of Electric Plant 32 76,458 58,036
Maintenance of Misc Hydraulic Plant 33 79,514 51,033
Total Production Expenses (total 23 thru 33) 34 672,810 638,341
Expenses per net KWh 35 0.0127 0.0407
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
/ /2013/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
258 16412 6
6,115 7,2688,411 7
8
264 16412 9
263 16412 10
2 21 11
574,493,000 506,285,00045,782,000 12
13
14,163,614 8,363,0130 14
68,071,694 8,316,8653,964,411 15
46,650,810 29,579,03986,742,403 16
20,162,067 15,035,5742,345,095 17
1,009,965 1,471,2302,068,792 18
0 00 19
150,058,150 62,765,72195,120,701 20
625.2423 468.40098,647.3365 21
22
2,067,645 1,190,92012,997 23
11,977 6,687889 24
1,474,531 703,84669,783 25
0 00 26
403,561 378,285397,059 27
177,614 98,12724,373 28
0 029 29
32,138 29,52529,378 30
7,962 23,93175,966 31
70,052 16,47848,554 32
620,619 356,41143,203 33
4,866,099 2,804,210702,231 34
0.0085 0.00550.0153 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
/ /2013/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 6,351 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 8,225,000 0
Cost of Plant 13
Land and Land Rights 14 0 0
Structures and Improvements 15 188,467 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) 20 233,022 0
Cost per KW of Installed Capacity (line 20 / 5) 21 22.6235 0.0000
Production Expenses 22
Operation Supervision and Engineering 23 36,499 0
Water for Power 24 1,287 0
Hydraulic Expenses 25 18,613 0
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 150,175 0
Rents 28 -172 0
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 20,270 0
Maintenance of Reservoirs, Dams, and Waterways 31 38,316 0
Maintenance of Electric Plant 32 7,980 0
Maintenance of Misc Hydraulic Plant 33 180,672 0
Total Production Expenses (total 23 thru 33) 34 453,640 0
Expenses per net KWh 35 0.0552 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
/ /2013/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
2013/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 / /2013/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 7.2 34,536,000 32,977,1041917Ashton 2381 2
1.11 1.0 1,925,000 1,335,0931913Bend 3
4.15 4.6 30,165,000 7,372,6381910Big Fork 2652 4
2.81 3.0 16,334,000 1,891,0131957Eagle Point 5
3.20 1,991,6951924East Side 2082 6
2.20 2.0 9,864,000 1,403,0141903Fall Creek 2082 7
0.16 594,2821922Fountain Green 8
2.00 1.3 5,671,000 5,234,5691896Granite 9
0.75 0.5 1,053,000 683,0451917Gunlock 10
1.73 1.2 3,257,000 2,806,7151983Last Chance 11
0.72 0.7 1,400,000 432,4941910Paris 12
5.00 2.7 7,718,000 10,963,2621897Pioneer 2722 13
3.76 2.0 20,789,000 2,589,6971912Prospect No. 1 2630 14
7.20 6.0 33,745,000 8,783,2191932Prospect No. 3 2337 15
1.00 0.9 4,178,000 2,410,0231944Prospect No. 4 2630 16
0.80 0.4 855,000 933,7221926Sand Cove 17
1.00 1.2 3,909,000 1,721,3941895Stairs 597 18
0.50 2,0981915St. Anthony 2381 19
0.50 0.2 787,000 893,4111920Veyo 20
0.74 -119,000 1,194,4861986Viva Naughton 21
1.10 1.0 5,340,000 2,865,2441921Wallowa Falls 308 22
3.85 2.0 8,908,000 2,962,1091911Weber 1744 23
0.60 0.6 926,000 468,5741908West Side 2082 24
7,527,975Keno Regulating Dam 2082 25
3,847,587Upper Klamath Lake 2082 26
15,448,123North Umpqua 1927 27
28
Pumping Plant: 29
-4.50 -3.0 -4,363,000 19,383,2481917Lifton 30
31
Wind: 32
111.00 112.0 409,613,000 239,703,0122010Dunlap Ranch 1 33
32.15 30.6 89,042,000 36,515,9081999Foote Creek 34
99.00 100.0 322,390,000 201,863,7672008Glenrock 35
39.00 40.0 121,920,000 87,422,5702009Glenrock III 36
99.00 100.0 294,834,000 202,658,1562009Rolling Hills 37
94.00 91.0 227,258,000 183,564,5372008Goodnoe Hills 38
100.50 96.0 206,164,000 176,493,7222006Leaning Juniper 1 39
140.40 136.0 331,240,000 240,176,3002007Marengo 40
70.20 69.0 154,612,000 129,350,6252008Marengo II 41
99.00 100.0 356,097,000 200,853,5502008Seven Mile Hill 42
19.50 20.0 77,049,000 42,253,6262008Seven Mile Hill II 43
99.00 101.0 341,250,000 219,781,6322009High Plains 44
28.50 29.0 103,727,000 56,962,9232009McFadden 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 / /2013/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
91,561 4,921,956 2Water 474,309
46,484 1,202,786 3Water 125,821
121,517 1,776,539 4Water 249,507
133,733 672,958 5Water 266,588
8,857 622,405 6Water 122,786
138,103 637,734 7Water 159,176
1,171 3,714,263 8Water 5,271
36,998 2,617,285 9Water 142,274
10,151 910,727 10Water 41,386
15,522 1,622,379 11Water 107,064
65,809 600,686 12Water 70,477
133,160 2,192,652 13Water 221,161
150,329 688,749 14Water 194,814
596,435 1,219,892 15Water 415,438
44,133 2,410,023 16Water 69,086
37,806 1,167,153 17Water 40,103
40,258 1,721,394 18Water 158,398
2,717 4,196 19Water 35,346
185,131 1,786,822 20Water 48,279
13,643 1,614,170 21Water 63,074
67,643 2,604,767 22Water 56,230
104,185 769,379 23Water 192,361
12,311 780,957 24Water 31,118
5,369 25 10,737
14,964 26 320,020
27
28
29
92,494 -4,307,388 30Water 322,146
31
32
2,329,809 2,159,487 33Wind 352,624
741,698 1,135,798 34Wind 1,957,740
1,085,043 2,039,028 35Wind 635,932
417,112 2,241,604 36Wind 235,747
1,058,824 2,047,052 37Wind 491,385
1,120,969 1,952,814 38Wind 1,277,218
1,589,215 1,756,156 39Wind 1,673,711
2,162,549 1,710,657 40Wind 1,306,188
883,674 1,842,601 41Wind 740,521
1,232,534 2,028,824 42Wind 889,139
241,749 2,166,853 43Wind 198,362
2,494,427 2,220,016 44Wind 1,313,683
737,080 1,998,699 45Wind 368,796
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 / /2013/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 2.0 4,699,000 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 / /2013/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 453,533
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
The St. Anthony hydroelectric generating facility was sold in September 2013 to St.
Anthony Hydro LLC. For more information, refer to Important Changes During the
Quarter/Year, Item 3, in this 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.: 30 Column: a
Lifton
Used in regulating the release of water from Bear Lake and in maintaining proper water
surface level in the Bear River near St. Charles, Idaho.
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 line 34 represents PacifiCorp's share.
Schedule Page: 410.1 Line No.: 2 Column: a
Black Cap
PacifiCorp has 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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
/ /2013/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 , 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, 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 #3, UT
345.00 345.00 11.00 1 18 90TH SOUTH, UT CAMP WILLIAMS #4, UT
Steel SP 345.00 345.00 11.00 1 19 90TH SOUTH, UT CAMP WILLIAMS #1, UT
345.00 345.00 16.00 1 20 90TH SOUTH, UT TERMINAL, UT
Steel SP 345.00 345.00 11.00 15.00 1 21 TERMINAL, UT CAMP WILLIAMS #2, UT
Wood - H 345.00 345.00 138.00 1 22 TERMINAL, UT BORAH, ID
Steel SP 345.00 345.00 47.00 1 23 TERMINAL, UT BORAH, ID
345.00 345.00 82.00 1 24 BEN LOMOND, UT POPULUS #1, ID
Steel SP 345.00 345.00 86.00 1 25 BEN LOMOND, UT POPULUS #2, ID
Steel SP 345.00 345.00 69.00 1 26 BEN LOMOND, UT CAMP WILLIAMS, UT
345.00 345.00 47.00 1 27 BEN LOMOND, UT TERMINAL, UT
Steel SP 345.00 345.00 47.00 1 28 BEN LOMOND, UT TERMINAL, UT
Wood - H 345.00 345.00 47.00 1 29 CAMP WILLIAMS, UT MONA, UT
Wood - H 345.00 345.00 47.00 1 30 CAMP WILLIAMS, UT MONA #1, UT
Steel Tower 345.00 345.00 47.00 1 31 CAMP WILLIAMS, UT MONA #2, UT
345.00 345.00 42.00 5.00 1 32 CAMP WILLIAMS, UT MONA #4 UT
Steel SP 345.00 345.00 1.00 1 33 CURRANT CREEK, UT MONA, UT
Steel Tower 345.00 345.00 121.00 1 34 EMERY, UT CAMP WILLIAMS, UT
Wood - H 345.00 345.00 20.00 1 35 EMERY, UT HUNTINGTON, UT
FERC FORM NO. 1 (ED. 12-87) Page 422
36 TOTAL 16,219.00 693.00 273
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
/ /2013/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
795 KCM ACSR 8
795 KCM ACSR 9
795 KCM ACSR 10
795 KCM ACSR 11
795 KCM ACSR 12
279,394,946 266,055,247 13,339,699 1,172,376 523,691 642,185 6,500 13
14
279,394,946 266,055,247 13,339,699 1,172,376 523,691 642,185 6,500 15
16
17
18
1272 ACSR 45/7 19
1272 ACSR 45/7 20
1272 ACSR 45/7 21
954 ACSR 45/7 22
1272 ACSR 45/7 23
1272 ACSR 45/7 24
1272 ACSR 45/7 25
1272 ACSR 45/7 26
1272 ACSR 45/7 27
1272 ACSR 45/7 28
954 ACSR 45/7 29
1272 ACSR 45/7 30
954 ACSR 45/7 31
954 ACSR 45/7 32
954 ACSR 54/7 33
1272 ACSR 45/7 34
954 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423
36 206,909,237 2,968,482,206 3,175,391,443 353,289 18,780,035 2,755,216 21,888,540
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
/ /2013/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 - H 345.00 345.00 74.00 1 1 EMERY, UT SIGURD #1, UT
Steel - H 345.00 345.00 75.00 1 2 EMERY, UT SIGURD, #2 UT
Wood - H 345.00 345.00 100.00 1 3 FOUR CORNERS, NM PINTO, UT
Wood - H 345.00 345.00 41.00 1 4 GOSHEN, ID KINPORT, ID
Steel Tower 345.00 345.00 1.00 1 5 HUNTINGTON, UT HUNT PLANT 1, UT
Steel Tower 345.00 345.00 1.00 1 6 HUNTINGTON, UT HUNT PLANT 2, UT
Steel SP 345.00 345.00 158.00 1 7 HUNTINGTON, UT PINTO, UT
Steel Tower 345.00 345.00 78.00 1 8 HUNTINGTON, UT SPANISH FORK, UT
Steel Tower 345.00 345.00 240.00 1 9 JIM BRIDGER, WY BORAH, ID
Steel SP 345.00 345.00 234.00 1 10 JIM BRIDGER, WY KINPORT, ID
Wood - H 345.00 345.00 69.00 1 11 MONA, UT SIGURD #1, UT
Steel SP 345.00 345.00 69.00 1 12 MONA, UT SIGURD #2, UT
Steel SP 345.00 345.00 60.00 1 13 MONA, UT HUNTINGTON, UT
Steel Tower 345.00 345.00 190.00 1 14 SIGURD, UT UT/NV STATE LINE
345.00 345.00 35.00 1 15 SPANISH FORK, UT CAMP WILLIAMS, UT
345.00 345.00 23.00 1 16 TERMINAL, UT CAMP WILLIAMS, UT
Steel Tower 345.00 345.00 100.00 1 17 CLOVER, UT OQUIRRH, UT
18 345 kV costs and expenses
19
383.00 2,086.00 36 20 Subtotal 345 kV
21
Wood - H 230.00 230.00 59.00 1 22 ALVEY, OR DIXONVILLE, OR
Wood - H 230.00 230.00 76.00 1 23 ANTELOPE, ID ANACONDA, MT
Wood - H 230.00 230.00 20.00 1 24 ANTELOPE, ID LOST RIVER, ID
Wood - H 230.00 230.00 1.00 1 25 ATLANTIC CITY, WY COLUMBIA GENEVA, WY
Wood - H 230.00 230.00 88.00 1 26 BEN LOMOND, UT NAUGHTON, WY
Wood - H 230.00 230.00 88.00 1 27 BEN LOMOND, UT NAUGHTON, WY
Wood - H 230.00 230.00 19.00 1 28 BIRCH CREEK, UT RAILROAD, WY
Wood - H 230.00 230.00 3.00 1 29 BITTER CREEK, WY MONELL, WY
Wood - H 230.00 230.00 1.00 1 30 BRIDGER PUMP, WY MANS FACE, WY
Wood - H 230.00 230.00 107.00 1 31 BUFFALO, WY CASPER, WY
Wood - H 230.00 230.00 36.00 1 32 CASPER, WY DAVE JOHNSTON, WY
Wood - H 230.00 230.00 110.00 1 33 CASPER, WY RIVERTON, WY
Steel-SP 230.00 230.00 30.00 1 34 CHAPPEL CREEK, WY CRAVEN CREEK, 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 16,219.00 693.00 273
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
/ /2013/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.
954 ACSR 45/7 1
954 ACSR 54/7 2
795 ACSR 45/7 3
795 ACSR 26/7 4
2156 ACSR 8419 5
2156 ACSR 8419 6
795 ACSR 45/7 7
1272 ACSR 45/7 8
1272 ACSR 36/1 9
1272 ACSR 36/1 10
795 ACSR 45/7 11
954 ACSR 45/7 12
954 ACSR 54/7 13
954 ACSR 54/7 14
1272 ACSR 45/7 15
1272 ACSR 45/7 16
1949 ACSR 45/7 17
1,455,406,407 1,321,625,567 133,780,840 2,370,840 640,985 1,729,855 18
19
1,455,406,407 1,321,625,567 133,780,840 2,370,840 640,985 1,729,855 20
21
1272 ACSR 36/1 22
1272 ACSR 45/7 23
795 ACSR 45/7 24
1272 ACSR 36/1 25
795 ACSR 26/7 26
795 ACSR 26/7 27
954 ACSR 54/7 28
795 ACSR 26/7 29
1272 ACSR 36/1 30
1272 ACSR 36/1 31
32
1272 ACSR 36/1 33
954 ACSR 54/7 34
1272 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.1
36 206,909,237 2,968,482,206 3,175,391,443 353,289 18,780,035 2,755,216 21,888,540
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
/ /2013/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 6.00 29.00 1 1 CHAPPEL CREEK, WY RILEY RIDGE, WY
Wood - H 230.00 230.00 2.00 1 2 CRAVEN CREEK, WY PIONEER, WY
Wood - H 230.00 230.00 31.00 1 3 DAVE JOHNSTON, WY SPENCE, WY
Wood - H 230.00 230.00 69.00 1 4 DAVE JOHNSTON, WY WYODAK, WY
Wood - H 230.00 230.00 1.00 1 5 DIXONVILLE 500kV, OR DIXONVILLE 230kV, OR
Wood - H 230.00 230.00 17.00 1 6 DIXONVILLE, OR RESTON BPA, OR
Wood - H 230.00 230.00 12.00 1 7 FAIRVIEW BPA, OR ISTHMUS, OR
Wood - H 230.00 230.00 49.00 1 8 FIREHOLE, WY MONUMENT, WY
Wood - H 230.00 230.00 26.00 1 9 FRY, OR BETHEL, OR
Wood - H 230.00 230.00 45.00 1 10 FRY, OR ALVEY, OR
Wood - H 230.00 230.00 159.00 1 11 GLEN CANYON, AZ SIGURD, UT
Wood - H 230.00 230.00 98.00 1 12 GONDER, UT - NV STATE PAVANT, UT
Wood - H 230.00 230.00 43.00 1 13 SHERIDAN, WY BUFFALO, WY
Wood - H 230.00 230.00 62.00 1 14 GRANTS PASS, OR DIXONVILLE, OR
Wood - H 230.00 230.00 78.00 1 15 HURRICANE, OR WALLA WALLA, WA
Wood - H 230.00 230.00 209.00 1 16 POINT OF ROCKS, WY DAVE JOHNSTON, WY
Wood - H 230.00 230.00 149.00 1 17 JIM BRIDGER, WY SPENCE, WY
Wood - H 230.00 230.00 1.00 1 18 JONES CANYON (BPA), OR LEANING JUNIPER, OR
Wood - H 230.00 230.00 35.00 1 19 KLAMATH FALLS, OR MALIN, OR
Wood - H 230.00 230.00 2.00 1 20 LIMA, WY ROBERSON, WY
Wood - H 230.00 230.00 76.00 1 21 LONE PINE, OR KLAMATH FALLS, OR
Steel SP 230.00 230.00 5.00 1 22 LONE PINE, OR MERIDIAN #1, OR
Steel SP 230.00 230.00 5.00 1 23 LONE PINE, OR MERIDIAN #2, OR
Wood - H 230.00 230.00 56.00 1 24 MCNARY (BPA), WA WALLA WALLA, WA
Wood - H 230.00 230.00 35.00 1 25 MERIDIAN, OR GRANTS PASS, OR
Wood - H 230.00 230.00 39.00 1 26 MINERS, WY HIGH PLAINS, WY
Wood - H 230.00 230.00 13.00 1 27 MONUMENT, WY EXXON, WY
Wood - H 230.00 230.00 20.00 1 28 MONUMENT, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 80.00 1 29 NAUGHTON, WY TREASURETON, ID
Wood - H 230.00 230.00 30.00 1 30 NAUGHTON, WY MONUMENT , WY
Wood - H 230.00 230.00 16.00 1 31 NAUGHTON, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 1.00 1 32 OREGON BASIN (PAC), WY OR BASIN (MART OIL), WY
Wood - H 230.00 230.00 4.00 1 33 PALISADES SS, WY BLUE RIM, WY
Wood - H 230.00 230.00 94.00 1 34 PAROWAN VALLEY, UT SIGURD, UT
Wood - H 230.00 230.00 26.00 1 35 PAROWAN VALLEY, UT WEST CEDAR, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.2
36 TOTAL 16,219.00 693.00 273
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
/ /2013/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 45/7 2
1272 ACSR 45/7 3
1272 ACSR 36/1 4
1272 ACSR 36/1 5
795 ACSR 26/7 6
1272 ACSR 36/1 7
1272 ACSR 45/7 8
1272 ACSR 36/1 9
1272 ACSR 36/1 10
954 ACSR 45/7 11
795 ACSR 45/7 12
795 ACSR 26/7 13
1272 ACSR 36/1 14
1272 ACSR 36/1 15
1272 ACSR 36/1 16
1272 ACSR 36/1 17
1272 ACSR 45/7 18
1272 ACSR 36/1 19
1272 ACSR 45/7 20
795 ACSR 26/7 21
1272 ACSR 54/19 22
1272 ACSR 36/1 23
1272 ACSR 36/1 24
1272 ACSR 36/1 25
1272 ACSR 45/7 26
1272 ACSR 36/1 27
1272 ACSR 45/7 28
1272 ACSR 45/7 29
1272 ACSR 36/1 30
954 ACSR 54/7 31
1272 ACSR 45/7 32
1272 ACSR 36/1 33
795 ACSR 45/7 34
795 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.2
36 206,909,237 2,968,482,206 3,175,391,443 353,289 18,780,035 2,755,216 21,888,540
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
/ /2013/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 43.00 1 1 PAVANT, UT SIGURD, UT
Wood - H 230.00 230.00 35.00 1 2 JIM BRIDGER, WY ROCK SPRINGS, WY
Wood - H 230.00 230.00 8.00 1 3 POMONA, WA UNION GAP, WA
Wood - H 230.00 230.00 118.00 1 4 RIVERTON, WY ROCK SPRINGS, WY
Wood - H 230.00 230.00 51.00 1 5 RIVERTON, WY THERMOPOLIS, WY
Wood - H 230.00 230.00 1.00 1 6 ROCK CREEK (BPA), WA GOODNOE HILLS, WA
Wood - H 230.00 230.00 55.00 1 7 ROCK SPRINGS, WY FLAMING GORGE, UT
Wood - H 230.00 230.00 35.00 1 8 ROCK SPRINGS, WY JIM BRIDGER, WY
Wood - H 230.00 230.00 41.00 1 9 ROCK SPRINGS, WY MONUMENT, WY
Wood - H 230.00 230.00 12.00 1 10 SHIRLEY BASIN, WY DUNLAP RANCH, WY
Wood - H 230.00 230.00 2.00 1 11 SWIFT No. 1, WA SWIFT No. 2, WA
Wood - H 230.00 230.00 23.00 1 12 SWIFT No. 2, WA WOODLAND BPA SS, WA
Wood - H 230.00 230.00 7.00 1 13 TALBOT, WA MARENGO II, WA
Wood - H 230.00 230.00 9.00 1 14 TAP TO HANNA, OR NICKEL MOUNTAIN, OR
Wood - H 230.00 230.00 176.00 1 15 THERMOPOLIS, WY YELLOWTAIL, MT
Wood - H 230.00 230.00 66.00 1 16 TREASURETON, ID BRADY, ID
Steel Tower 230.00 230.00 6.00 1 17 TROUTDALE (BPA), OR GRESHAM (PGE), OR
230.00 230.00 6.00 1 18 TROUTDALE (BPA), OR LINNEMAN (PGE), OR
Wood - H 230.00 230.00 1.00 1 19 TROUTDLE-LINNEMN, OR TROUTDALE PP&L, OR
Wood - H 230.00 230.00 39.00 1 20 UNION GAP, WA MIDWAY BPA, WA
Wood - H 230.00 230.00 45.00 1 21 WALLA WALLA, WA AVISTA LEWISTON, ID
Wood - H 230.00 230.00 33.00 1 22 WALLA WALLA, WA WANAPUM (GPUD), WA
Wood - H 230.00 230.00 37.00 1 23 WANAPUM, WA POMONA, WA
Wood - H 230.00 230.00 13.00 1 24 WINDSTAR, WY GLENROCK, WY
Wood - H 230.00 230.00 69.00 1 25 WYODAK, WY BUFFALO, WY
Wood - H 230.00 230.00 63.00 1 26 YAMSAY, OR KLAMATH FALLS, OR
Wood - H 230.00 230.00 59.00 1 27 YELLOWTAIL, WY SHERIDAN, WY
28 230 kV costs and expenses
29
12.00 3,334.00 76 30 Subtotal 230 kV
31
Wood - H 161.00 161.00 61.00 1 32 ANACONDA, ID JEFFERSON, ID
Wood - H 161.00 161.00 45.00 1 33 ANTELOPE, ID GOSHEN, ID
Wood SP 161.00 161.00 9.00 1 34 BONNEVILLE, ID EAGLEROCK, ID
Wood SP 161.00 161.00 3.00 1 35 EAGLEROCK, ID SUGARMILL, ID
FERC FORM NO. 1 (ED. 12-87) Page 422.3
36 TOTAL 16,219.00 693.00 273
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
/ /2013/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 45/7 1
1272 ACSR 45/7 2
1272 ACSR 36/1 3
1272 ACSR 36/1 4
1272 ACSR 36/1 5
1272 ACSR 45/7 6
1272 ACSR 36/1 7
1272 ACSR 36/1 8
1272 ACSR 36/1 9
795 ACSR 26/7 10
954 ACSR 45/7 11
954 ACSR 45/7 12
795 ACSR 26/7 13
795 ACSR 26/7 14
1272 ACSR 36/1 15
795 ACSR 26/7 16
954 ACSR 45/7 17
900 ACSR 54/7 18
1272 ACSR 36/1 19
954 ACSR 45/7 20
1272 ACSR 36/1 21
1272 ACSR 36/1 22
1272 ACSR 36/1 23
1272 ACSR 45/7 24
1272 ACSR 36/1 25
795 ACSR 26/7 26
795 ACSR 26/7 27
383,565,594 365,472,752 18,092,842 5,617,012 539,922 5,025,192 51,898 28
29
383,565,594 365,472,752 18,092,842 5,617,012 539,922 5,025,192 51,898 30
31
250HH CU /7 32
397.5 ACSR 26/7 33
954 ACSR 45/7 34
954 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.3
36 206,909,237 2,968,482,206 3,175,391,443 353,289 18,780,035 2,755,216 21,888,540
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
/ /2013/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 31.00 1 2 GOSHEN, ID RIGBY, ID
Wood SP 161.00 161.00 17.00 1 3 GOSHEN, ID SUGAR MILL, ID
Wood SP 161.00 161.00 17.00 1 4 SUGARMILL, ID RIGBY, ID
Wood - H 161.00 161.00 12.00 1 5 EAGLEROCK, ID GOSHEN, ID
Wood - H 161.00 161.00 46.00 1 6 YELLOWTAIL, MT RIMROCK, MT
Wood SP 161.00 161.00 18.00 1 7 RIGBY, ID JEFFERSON, ID
Wood - H 161.00 161.00 30.00 1 8 GOSHEN, ID JEFFERSON, ID
9 161 kV costs and expenses
10
91.00 255.00 12 11 Subtotal 161 kV
12
Steel - SP 138.00 138.00 1.00 1 13 90TH SOUTH , UT SANDY , UT
Wood - H 138.00 138.00 12.00 1 14 90TH SOUTH , UT DUMAS #1, UT
Wood - H 138.00 138.00 6.00 1 15 90TH SOUTH , UT DUMAS #2, UT
Wood SP 138.00 138.00 10.00 1 16 90TH SOUTH , UT OQUIRRH , UT
Wood - H 138.00 138.00 44.00 1 17 ABAJO , UT PINTO , UT
Wood - H 138.00 138.00 4.00 1 18 AGRIUM , UT THREEMILE KNOLL , ID
Wood - H 138.00 138.00 22.00 1 19 ANSCHTZ CO-GEN, WY EVANSTON , WY
Wood - H 138.00 138.00 1.00 1 20 ANTELOPE , ID SCOVILLE #1 , WY
Wood - H 138.00 138.00 1.00 1 21 ANTELOPE , ID SCOVILLE #2 , WY
Wood - H 138.00 138.00 26.00 1 22 ASHGROVE , UT CLOVER , UT
Wood - H 138.00 138.00 92.00 1 23 ASHLEY , UT CARBON , UT
Wood - H 138.00 138.00 12.00 1 24 ASHLEY , UT VERNAL , UT
Wood - H 138.00 138.00 6.00 1 25 BANGERTER , UT OQUIRRH , UT
Wood - H 138.00 138.00 14.00 1 26 BEN LOMOND , UT BRIGHAM CITY , UT
Steel - SP 138.00 138.00 14.00 1 27 BEN LOMOND #1 , UT EL MONTE , UT
138.00 138.00 13.00 1 28 BEN LOMOND #2 , UT EL MONTE , UT
Steel Tower 138.00 138.00 22.00 1 29 BEN LOMOND , UT HONEYVILLE , UT
Steel Tower 230.00 138.00 13.00 7.00 1 30 BEN LOMOND , UT SYRACUSE , UT
Steel - SP 138.00 138.00 28.00 1 31 BEN LOMOND , UT ANGEL #2 , UT
Wood -SP 138.00 138.00 14.00 1 32 BEN LOMOND , UT W ZIRCONIUM , UT
Steel Tower 138.00 138.00 42.00 1 33 BEN LOMOND , UT WHEELON , UT
Steel Tower 138.00 138.00 25.00 1 34 BEN LOMOND , UT SYRACUSE , UT
Wood - H 138.00 138.00 9.00 1 35 BONANZA , UT CHAPITA , UT
FERC FORM NO. 1 (ED. 12-87) Page 422.4
36 TOTAL 16,219.00 693.00 273
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
/ /2013/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
397.5 ACSR 26/7 2
795 AAC /37 3
397.5 ACSR 26/7 4
1272 ACSR 45/7 5
556.5 ACSR 26/7 6
397.5 ACSR 26/7 7
250HH CU /7 8
21,965,733 21,342,243 623,490 206,588 610 205,978 9
10
21,965,733 21,342,243 623,490 206,588 610 205,978 11
12
795 AAC /37 13
795 AAC /37 14
795 AAC /37 15
795 ACSR 26/7 16
397.5 ACSR 26/7 17
397.5 ACSR 26/7 18
795 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
397.5 ACSR 26/7 24
25
1272 ACSR 45/7 26
795 ACSR 45/7 27
795 ACSR 45/7 28
250 CUHD /12 29
795 AAC /37 30
397.5 ACSR 26/7 31
795 AAC /37 32
250 CUHD /12 33
1272 ACSR 45/7 34
795 ACSR 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.4
36 206,909,237 2,968,482,206 3,175,391,443 353,289 18,780,035 2,755,216 21,888,540
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
/ /2013/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 -SP 138.00 138.00 16.00 1 1 BRIDGERLAND , UT GREEN CANYON , UT
Wood - H 138.00 138.00 24.00 1 2 BRIGHAM CITY , UT WHEELON , UT
Steel - SP 138.00 138.00 9.00 1 3 BUTLERVILLE , UT 90TH SOUTH , UT
Wood - H 138.00 138.00 35.00 1 4 CAMERON , UT PAROWAN , UT
Wood - H 138.00 138.00 64.00 1 5 CAMERON , UT SIGURD , UT
Wood - H 138.00 138.00 12.00 1 6 CANYON COMP, WY STR 204 , WY
Wood - H 138.00 138.00 2.00 1 7 CARBON , UT HELPER #2 , UT
Steel Tower 138.00 138.00 54.00 1 8 CARBON, UT SPANISH FORK #1, UT
138.00 138.00 52.00 1 9 CARBON, UT SPANISH FORK #2, UT
Wood - H 138.00 138.00 120.00 1 10 CARBON , UT MOAB , UT
Wood -SP 138.00 138.00 5.00 1 11 CLEAR CREEK , WY PAINTER , UT
Wood -SP 138.00 138.00 8.00 1 12 CLOVER , UT NEBO , UT
Wood - H 138.00 138.00 2.00 1 13 COLUMBIA , UT SUNNYSIDE , UT
Steel - SP 138.00 138.00 6.00 1 14 COTTONWOOD , UT MCCLELLAND , UT
Wood -SP 138.00 138.00 5.00 1 15 COTTONWOOD , UT HAMMER , UT
Wood -SP 138.00 138.00 29.00 1 16 COTTONWOOD , UT SILVER CREEK , UT
Wood -SP 138.00 138.00 1.00 1 17 CUTLER , UT WHEELON , UT
Steel - SP 138.00 138.00 5.00 1 18 DRY CREEK , UT SPANISH FORK , UT
Wood -SP 138.00 138.00 18.00 1 19 DUMAS , UT WESTFIELD , UT
Steel - SP 138.00 138.00 2.00 1 20 DYNAMO , UT TRI-CITY #1 , UT
138.00 138.00 3.00 1 21 DYNAMO , UT TRI-CITY #2 , UT
Steel - SP 138.00 138.00 15.00 1 22 EAST LAYTON , UT 105 TAP , UT
Wood -SP 138.00 138.00 1.00 1 23 EBAY TAP , UT OQUIRRH , UT
Steel - SP 138.00 138.00 4.00 1 24 EL MONTE , UT STR 30B , UT
Steel - SP 138.00 138.00 1.00 1 25 EL MONTE , UT PIONEER , UT
Wood -SP 138.00 138.00 3.00 1 26 EVANSTON , WY RAILROAD , UT
Wood -SP 138.00 138.00 10.00 1 27 FRANKLIN , ID TREASURETON , ID
Wood -SP 138.00 138.00 25.00 1 28 FRANKLIN , ID GREEN CANYON , UT
Wood -SP 138.00 138.00 1.00 1 29 GADSBY , UT JORDAN , UT
Wood -SP 138.00 138.00 1.00 1 30 GADSBY , UT THIRD WEST , UT
Wood -SP 138.00 138.00 6.00 1 31 GADSBY , UT TERMINAL , 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 16,219.00 693.00 273
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
/ /2013/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
795 AAC /37 3
397.5 ACSR 26/7 4
397.5 ACSR 26/7 5
795 ACSR 26/7 6
556.5 ACSR 26/7 7
795 ACSR 26/7 8
1272 ACSR 45/7 9
954 ACSR 54/7 10
795 ACSR 26/7 11
1272 ACSR 45/7 12
397.5 ACSR 26/7 13
795 AAC /37 14
795 AAC /37 15
397.5 ACSR 26/7 16
250 CUHD /12 17
1272 ACSR 45/7 18
795 ACSR 26/7 19
795 ACSR 26/7 20
795 ACSR 26/7 21
795 ACSR 26/7 22
795 ACSR 26/7 23
1272 ACSR 45/7 24
1272 ACSR 45/7 25
795 ACSR 26/7 26
795 ACSR 26/7 27
397.5 ACSR 26/7 28
1272 ACSR 45/7 29
1272 AAC /61 30
1272 ACSR 45/7 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
36 206,909,237 2,968,482,206 3,175,391,443 353,289 18,780,035 2,755,216 21,888,540
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
/ /2013/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 BARNEYS, UT GRINDING, 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 #2, UT COTTONWOOD , UT
Wood -SP 138.00 138.00 3.00 1 18 MID VALLEY #1, 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 , UT
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 BINGHAM CANYON (KCC),
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, UT TERMINAL #1, UT
138.00 138.00 14.00 1 34 PARRISH, UT TERMINAL #2, UT
Steel - SP 138.00 138.00 14.00 1 35 PARRISH #105 , UT TERMINAL , UT
FERC FORM NO. 1 (ED. 12-87) Page 422.6
36 TOTAL 16,219.00 693.00 273
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
/ /2013/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 26/7 34
795 AAC 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.6
36 206,909,237 2,968,482,206 3,175,391,443 353,289 18,780,035 2,755,216 21,888,540
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
/ /2013/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) #2 , UT SAINT GEORGE , UT
Steel - SP 138.00 138.00 20.00 1 4 CENTRAL (UAMPS) #3 , 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 7.00 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
138.00 138.00 9.00 1 14 SYRACUSE , UT ANGEL #1 , UT
Wood - H 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 16,219.00 693.00 273
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
/ /2013/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
36 206,909,237 2,968,482,206 3,175,391,443 353,289 18,780,035 2,755,216 21,888,540
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
/ /2013/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 #1, UT TREASURETON , ID
138.00 138.00 29.00 1 7 WHEELON #2, UT TREASURETON , ID
Wood - H 138.00 138.00 29.00 1 8 WHEELON #3, UT TREASURETON , ID
Wood - SP 138.00 138.00 3.00 1 9 FORT DOUGLAS, UT MCCLELLAND, UT
10 138 kV costs and expenses
11
207.00 2,038.00 137 12 Subtotal 138 kV
13
1,620.00 14 All 115 kV Lines
15
2,992.00 16 All 69 kV Lines
17
113.00 18 All 57 kV Lines
19
2,569.00 20 All 46 kV Lines
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 16,219.00 693.00 273
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
/ /2013/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
9
345,380,995 326,244,179 19,136,816 1,837,992 131,331 1,580,578 126,083 10
11
345,380,995 326,244,179 19,136,816 1,837,992 131,331 1,580,578 126,083 12
13
175,748,640 170,671,280 5,077,360 3,992,767 619,803 3,372,964 14
15
262,159,962 255,019,466 7,140,496 3,657,252 233,094 3,370,620 53,538 16
17
10,300,507 10,254,180 46,327 63,882 4,169 59,713 18
19
241,468,659 231,797,292 9,671,367 2,969,831 61,611 2,792,950 115,270 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
36 206,909,237 2,968,482,206 3,175,391,443 353,289 18,780,035 2,755,216 21,888,540
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 in 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 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 line 3 column (a).
Schedule Page: 422 Line No.: 5 Column: a
See footnote on page 422 for line 3 column (a).
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 line 3 column (a).
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 reflect
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 reflect
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 reflect
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 reflect
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 reflect
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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 422 Line No.: 17 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422 Line No.: 18 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.1 Line No.: 32 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 reflect PacifiCorp's share.
Schedule Page: 422.1 Line No.: 32 Column: i
1557 ACSS/TW 45/7
Schedule Page: 422.4 Line No.: 25 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
reflect PacifiCorp's share.
Schedule Page: 422.7 Line No.: 4 Column: a
See footnote on page 422.7 for line 3 column (a).
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
Schedule Page: 422.8 Line No.: 9 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
2013/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
/ /2013/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
8.00Steel Tower 1 1 1 Clover, UT Oquirrh, UT 100.00
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
100.00 8.00 1 1
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
/ /2013/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 27'ACSR3-1949 115,868,548 334,633,915199,062,352 19,703,015 345 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
115,868,548 199,062,352
FERC FORM NO. 1 (REV. 12-03) Page 425
44 19,703,015 334,633,915
Schedule Page: 424 Line No.: 1 Column: a
This line is also known as the Mona-Oquirrh transmission line.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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 / /2013/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
CASTELLA SUB 2.40 69.00DISTRIBUTION-UNATTEN 4
CLEAR LAKE SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
DOG CREEK SUB 2.40 69.00DISTRIBUTION-UNATTEN 6
DORRIS SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
FORT JONES SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
GASQUET SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
GREENHORN SUB 12.47 69.00DISTRIBUTION-UNATTEN 10
HAMBURG SUB 2.40 69.00DISTRIBUTION-UNATTEN 11
HAPPY CAMP SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
HORNBROOK SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
INTERNATIONAL PAPER SUB 2.40 69.00DISTRIBUTION-UNATTEN 14
LAKE EARL SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
LITTLE SHASTA SUB 7.20 69.00DISTRIBUTION-UNATTEN 16
LUCERNE SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
MACDOEL SUB 20.80 69.00DISTRIBUTION-UNATTEN 18
MCCLOUD SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
MILLER REDWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
MONTAGUE SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
MORRISON CREEK SUB 12.50 69.00DISTRIBUTION-UNATTEN 22
MOUNT SHASTA SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
NEWELL SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
NORTH DUNSMUIR SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
NORTHCREST SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
NUTGLADE SUB 2.40 69.00DISTRIBUTION-UNATTEN 27
PATRICKS CREEK SUB 7.20 115.00DISTRIBUTION-UNATTEN 28
PEREZ SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
REDWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
SCOTT BAR SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
SEIAD SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
SHASTINA SUB 20.80 69.00DISTRIBUTION-UNATTEN 33
SHOTGUN CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
SMITH RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
SNOW BRUSH SUB 7.20 69.00DISTRIBUTION-UNATTEN 36
SOUTH DUNSMUIR SUB 4.16 69.00DISTRIBUTION-UNATTEN 37
TULELAKE SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
TUNNEL SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
WALKER BRYAN 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 / /2013/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
4 3 5
1 6
7 3 7
6 1 8
9 1 9
12 1 10
1 1 11
7 3 12
4 3 13
9 3 14
12 1 15
2 3 16
4 1 17
30 2 18
6 1 19
4 3 20
6 1 21
14 1 22
16 4 23
12 1 24
6 6 25
20 4 26
1 3 27
1 1 28
1 3 29
9 3 30
2 3 31
2 3 32
6 3 33
1 1 34
6 3 35
1 3 36
2 3 37
20 1 38
6 6 39
9 3 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 / /2013/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).
WEED SUB 12.47 115.00DISTRIBUTION-UNATTEN 1
YUBA SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
YUROK SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
Total 465.96 3036.00 4
Number of Substations-42 5
6
ALTURAS SUB 12.47 115.00 69.00T/D-UNATTENDED 7
YREKA SUB 12.47 115.00 69.00T/D-UNATTENDED 8
Total 24.94 230.00 138.00 9
Number of Substations-2 10
11
COPCO #2 230 SUB 115.00 230.00TRANSMISSION-ATTENDE 12
COPCO #2 SUB 69.00 115.00 12.47TRANSMISSION-ATTENDE 13
AGER SUB 69.00 115.00TRANSMISSION-UNATTEN 14
CRAG VIEW SUB 69.00 115.00TRANSMISSION-UNATTEN 15
DEL NORTE SUB 69.00 115.00TRANSMISSION-UNATTEN 16
WEED JUNCTION SUB 69.00 115.00TRANSMISSION-UNATTEN 17
Total 460.00 805.00 12.47 18
Number of Substations-6 19
20
IDAHO 21
ALEXANDER 12.47 46.00DISTRIBUTION-UNATTEN 22
AMMON 12.47 69.00DISTRIBUTION-UNATTEN 23
ANDERSON 12.47 69.00DISTRIBUTION-UNATTEN 24
ARCO 12.47 69.00DISTRIBUTION-UNATTEN 25
ARIMO 12.47 46.00DISTRIBUTION-UNATTEN 26
BANCROFT SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
BELSON SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
BERENICE SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
CAMAS SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
CANYON CREEK SUB 24.90 69.00DISTRIBUTION-UNATTEN 31
CHESTERFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
CLEMENTS SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
CLIFTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
COVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
DOWNEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
DUBOIS SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
EASTMONT SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
EGIN SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
EIGHT MILE 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 / /2013/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
4 3 2
4 3 3
323 99 4
5
6
31 4 7
95 2 8
126 6 9
10
11
500 2 12
51 4 13
5 3 14
19 3 15
150 2 16
37 3 17
762 17 18
19
20
21
4 1 22
14 1 23
20 1 24
6 1 25
7 1 26
4 1 27
12 1 28
10 1 29
14 1 30
20 1 31
5 1 32
5 1 33
4 1 34
6 1 35
5 1 36
12 1 37
14 1 38
14 1 39
3 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 / /2013/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).
GEORGETOWN SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
GRACE CITY SUBSTATION 12.47 46.00DISTRIBUTION-UNATTEN 2
HAMER SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
HAYES SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
HENRY SUB 7.20 46.00DISTRIBUTION-UNATTEN 5
HOLBROOK SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
HOOPES SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
HORSLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
IDAHO FALLS SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
INDIAN CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 10
JEFFCO SUB 24.90 69.00DISTRIBUTION-UNATTEN 11
KETTLE SUB 24.90 69.00DISTRIBUTION-UNATTEN 12
LAVA SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
LUND SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
MCCAMMON SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
MENAN SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
MERRILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
MILLER SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
MONTPELIER SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
MOODY SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
NEWDALE SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
OSGOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
PRESTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
RAYMOND SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
RENO SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
REXBURG SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
RIRIE SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
ROBERTS SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
RUBY SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
SAND CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
SANDUNE SUB 24.90 69.00DISTRIBUTION-UNATTEN 31
SHELLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
SMITH SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
SOUTH FORK SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
SPUD SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
ST. CHARLES SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
SUGAR CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
SUNNYDELL SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
TANNER SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
TARGHEE 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 / /2013/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
5 1 2
14 1 3
9 1 4
1 1 5
6 1 6
9 1 7
4 1 8
20 1 9
3 1 10
22 1 11
14 1 12
3 1 13
5 1 14
3 1 15
10 1 16
20 1 17
5 1 18
8 1 19
14 1 20
20 1 21
20 1 22
12 1 23
2 1 24
20 1 25
32 2 26
9 1 27
8 1 28
7 1 29
40 2 30
20 1 31
20 1 32
20 1 33
14 1 34
8 1 35
5 1 36
12 1 37
12 1 38
4 1 39
4 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 / /2013/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).
THORNTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
UCON SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
WATKINS SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
WEBSTER SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
WESTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
WINDSPER SUB 24.90 69.00DISTRIBUTION-UNATTEN 6
Total 867.43 4002.00 7
Number of Substations-65 8
9
CINDER BUTTE SUB 12.47 161.00T/D-UNATTENDED 10
MALAD SUB 46.00 138.00 12.47T/D-UNATTENDED 11
MUD LAKE SUB 12.47 69.00T/D-UNATTENDED 12
RIGBY SUB 12.47 161.00 69.00T/D-UNATTENDED 13
SAINT ANTHONY SUB 46.00 69.00 12.47T/D-UNATTENDED 14
Total 129.41 598.00 93.94 15
Number of Substations-5 16
17
AMPS SUB 69.00 230.00 12.47TRANSMISSION-UNATTEN 18
ANTELOPE SUB 161.00 230.00 12.47TRANSMISSION-UNATTEN 19
ASHTON PLANT 12.47 46.00TRANSMISSION-UNATTEN 20
BIG GRASSY SUB 69.00 161.00TRANSMISSION-UNATTEN 21
BONNEVILLE SUB 69.00 161.00TRANSMISSION-UNATTEN 22
CONDA SUB 46.00 138.00TRANSMISSION-UNATTEN 23
FISH CREEK SUB 46.00 161.00TRANSMISSION-UNATTEN 24
FRANKLIN SUB 46.00 138.00TRANSMISSION-UNATTEN 25
GOSHEN SUB 161.00 345.00 69.00TRANSMISSION-UNATTEN 26
GRACE SUB 138.00 161.00 46.00TRANSMISSION-UNATTEN 27
JEFFERSON SUB 69.00 161.00TRANSMISSION-UNATTEN 28
OVID SUB 69.00 138.00TRANSMISSION-UNATTEN 29
SCOVILLE SUB 69.00 138.00TRANSMISSION-UNATTEN 30
SUGARMILL SUB 46.00 161.00 69.00TRANSMISSION-UNATTEN 31
THREEMILE KNOLL SUB 138.00 345.00 46.00TRANSMISSION-UNATTEN 32
TREASURETON SUB 138.00 230.00TRANSMISSION-UNATTEN 33
Total 1346.47 2944.00 254.94 34
Number of Substations-16 35
36
MONTANA 37
BROADVIEW SUB 230.00 500.00TRANSMISSION-UNATTEN 38
COLSTRIP SUB 230.00 500.00TRANSMISSION-UNATTEN 39
YELLOWTAIL SUB 161.00 230.00TRANSMISSION-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 / /2013/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
7 1 2
14 1 3
20 1 4
4 1 5
20 1 6
721 67 7
8
9
60 2 1 10
71 4 1 11
14 1 12
189 4 13
40 2 14
374 13 2 15
16
17
75 1 1 18
445 3 19
13 1 20
67 1 21
67 1 22
67 1 23
25 3 24
75 1 25
938 5 26
217 2 27
233 3 28
30 1 29
76 2 30
168 3 31
775 2 32
533 2 33
3804 32 1 34
35
36
37
32 2 38
68 2 39
100 1 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 / /2013/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 621.00 1230.00 1
Number of Substations-3 2
3
OREGON 4
26TH STREET 4.16 20.80DISTRIBUTION-UNATTEN 5
35TH STREET 2.40 20.80DISTRIBUTION-UNATTEN 6
AGNESS AVE 12.47 115.00DISTRIBUTION-UNATTEN 7
ALDERWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
ARLINGTON 12.47 69.00DISTRIBUTION-UNATTEN 9
ATHENA 12.47 69.00DISTRIBUTION-UNATTEN 10
BANDON TIE SUB 12.47 20.80DISTRIBUTION-UNATTEN 11
BEACON SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
BEALL LANE SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
BEATTY SUB 12.47 69.00DISTRIBUTION-UNATTEN 14
BELKNAP SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
BLALOCK SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
BLOSS SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
BLY SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
BOISE CASCADE SUB 11.00 69.00DISTRIBUTION-UNATTEN 19
BONANZA SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
BOND STREET SUB 12.50 69.00DISTRIBUTION-UNATTEN 21
BROOKHURST SUB 12.47 115.00DISTRIBUTION-UNATTEN 22
BROWNSVILLE SUB 20.80 69.00DISTRIBUTION-UNATTEN 23
BRYANT SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
BUCHANAN SUB 20.80 115.00DISTRIBUTION-UNATTEN 25
BUCKAROO SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
CAMPBELL SUB 12.47 115.00DISTRIBUTION-UNATTEN 27
CANNON BEACH SUB 12.47 115.00DISTRIBUTION-UNATTEN 28
CARNES SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
CASEBEER SUB 20.80 69.00DISTRIBUTION-UNATTEN 30
CAVEMAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 31
CHERRY LANE SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
CHILOQUIN MARKET SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
CHINA HAT SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
CIRCLE BLVD SUB 20.80 115.00DISTRIBUTION-UNATTEN 35
CLEVELAND AVE SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
CLOAKE SUB 20.80 69.00DISTRIBUTION-UNATTEN 37
COBURG SUB 20.80 69.00DISTRIBUTION-UNATTEN 38
COLISEUM SUB 4.16 20.80DISTRIBUTION-UNATTEN 39
COLUMBIA SUB 12.47 115.00 57.00DISTRIBUTION-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 / /2013/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.
200 5 1
2
3
4
5 1 5
30 6 6
25 1 7
45 2 8
5 1 9
9 1 10
8 3 1 11
11 3 12
25 1 13
6 1 14
40 2 15
2 3 16
32 2 17
8 3 18
3 1 19
8 3 20
25 1 21
50 2 22
13 1 23
34 2 24
45 2 25
34 2 26
20 2 27
13 1 28
9 3 29
20 1 30
45 2 31
25 1 32
6 3 33
25 1 34
80 2 35
45 2 36
20 1 37
10 3 38
9 2 39
55 2 1 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 / /2013/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).
COOS RIVER SUB 20.80 115.00DISTRIBUTION-UNATTEN 1
COQUILLE SUB 20.80 115.00DISTRIBUTION-UNATTEN 2
CREEK SUB 34.50 69.00DISTRIBUTION-UNATTEN 3
CROOKED RIVER RANCH SUB 20.80 69.00DISTRIBUTION-UNATTEN 4
CROWFOOT SUB 12.47 115.00DISTRIBUTION-UNATTEN 5
CULLY SUB 12.47 115.00DISTRIBUTION-UNATTEN 6
CULVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
DAIRY SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
DALLAS SUB 20.80 115.00DISTRIBUTION-UNATTEN 9
DALREED SUB 34.50 230.00DISTRIBUTION-UNATTEN 10
DESCHUTES SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
DEVILS LAKE SUB 20.80 115.00DISTRIBUTION-UNATTEN 12
DIXON SUB 4.16 115.00DISTRIBUTION-UNATTEN 13
DODGE BRIDGE SUB 20.80 69.00DISTRIBUTION-UNATTEN 14
DOWELL SUB 12.47 115.00DISTRIBUTION-UNATTEN 15
EASY VALLEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 16
EMPIRE SUB 20.80 115.00DISTRIBUTION-UNATTEN 17
ENTERPRISE SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
FERN HILL SUB 12.47 115.00DISTRIBUTION-UNATTEN 19
FIELDER CREEK SUB 20.80 115.00DISTRIBUTION-UNATTEN 20
FOOTHILLS SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
FRALEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
GARDEN VALLEY SUB 20.80 69.00DISTRIBUTION-UNATTEN 23
GAZLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
GLENDALE SUB 12.47 230.00DISTRIBUTION-UNATTEN 25
GLENEDEN SUB 4.16 20.80DISTRIBUTION-UNATTEN 26
GLIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 27
GOLD HILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
GORDON HOLLOW SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
GOSHEN SUB 20.80 115.00DISTRIBUTION-UNATTEN 30
GRANT STREET SUB 20.80 115.00DISTRIBUTION-UNATTEN 31
GRASS VALLEY SUB 4.16 20.80DISTRIBUTION-UNATTEN 32
GREEN SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
GRIFFIN CREEK SUB 12.47 115.00DISTRIBUTION-UNATTEN 34
HAMAKER SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
HARRISBURG SUB 20.80 69.00DISTRIBUTION-UNATTEN 36
HENLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
HERMISTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
HILLVIEW SUB 20.80 115.00DISTRIBUTION-UNATTEN 39
HINKLE 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 / /2013/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.
20 1 1
40 2 2
5 1 3
25 2 4
20 1 5
25 1 6
13 1 7
25 1 8
50 2 9
75 3 10
25 1 11
50 2 12
7 1 13
12 1 14
20 1 15
45 2 16
20 1 17
19 2 18
12 1 19
25 1 20
21 4 21
5 3 22
20 1 23
8 4 24
25 2 25
5 1 26
12 1 27
11 3 28
6 1 29
20 1 30
45 2 31
1 4 32
25 1 33
20 1 34
8 3 35
13 1 36
6 3 37
40 1 38
45 2 39
20 1 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 / /2013/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).
HOLLADAY SUB 12.47 115.00DISTRIBUTION-UNATTEN 1
HOLLYWOOD SUB 12.47 115.00DISTRIBUTION-UNATTEN 2
HOOD RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
HORNET SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
HUMBUG CREEK SUB 12.50 67.00DISTRIBUTION-UNATTEN 5
HUNTERS CIRCLE TEMP SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
ILLAHEE FLATS SUB 12.47 115.00DISTRIBUTION-UNATTEN 7
INDEPENDENCE SUB 20.80 69.00DISTRIBUTION-UNATTEN 8
JACKSONVILLE SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 9
JEFFERSON SUB 20.80 69.00DISTRIBUTION-UNATTEN 10
JEROME PRAIRIE SUB 12.47 115.00DISTRIBUTION-UNATTEN 11
JORDAN POINT SUB 12.47 115.00DISTRIBUTION-UNATTEN 12
JOSEPH SUB 12.47 20.80DISTRIBUTION-UNATTEN 13
JUNCTION CITY SUB 20.80 69.00DISTRIBUTION-UNATTEN 14
KENWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
KILLINGWORTH SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
KNAPPA SVENSEN SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
LAKEPORT SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
LANCASTER SUB 20.80 69.00DISTRIBUTION-UNATTEN 19
LEBANON SUB 20.80 115.00DISTRIBUTION-UNATTEN 20
LINCOLN SUB 12.47 115.00DISTRIBUTION-UNATTEN 21
LOCKHART SUB 20.80 115.00DISTRIBUTION-UNATTEN 22
LYONS SUB 20.80 69.00DISTRIBUTION-UNATTEN 23
MADRAS SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
MALLORY SUB 12.47 115.00DISTRIBUTION-UNATTEN 25
MARYS RIVER SUB 20.80 115.00DISTRIBUTION-UNATTEN 26
MEDCO SUB 12.47 115.00DISTRIBUTION-UNATTEN 27
MEDFORD 12.47 69.00DISTRIBUTION-UNATTEN 28
MERLIN SUB 12.47 115.00DISTRIBUTION-UNATTEN 29
MERRILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
MINAM SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
MODOC SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
MORO SUB 2.40 20.80DISTRIBUTION-UNATTEN 33
MURDER CREEK SUB 20.80 115.00DISTRIBUTION-UNATTEN 34
MYRTLE CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
MYRTLE POINT SUB 20.80 115.00DISTRIBUTION-UNATTEN 36
NELSCOTT SUB 4.16 20.80DISTRIBUTION-UNATTEN 37
NEW O'BRIEN SUB 12.47 115.00DISTRIBUTION-UNATTEN 38
OAK KNOLL SUB 12.47 115.00DISTRIBUTION-UNATTEN 39
OAKLAND SUB 12.47 115.00DISTRIBUTION-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 / /2013/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.
75 3 1
50 2 2
40 2 3
20 1 4
9 1 5
12 1 6
2 1 7
20 1 8
75 2 9
12 1 10
20 1 11
20 1 12
6 1 1 13
25 2 14
3 3 15
40 2 16
6 1 17
50 2 18
12 3 19
40 2 20
105 3 21
40 2 22
9 2 23
25 2 24
25 1 25
20 1 26
20 1 27
67 8 28
45 2 29
17 6 30
1 31
6 3 32
2 3 33
100 4 34
14 1 35
9 1 36
4 1 37
9 1 38
45 2 39
8 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 / /2013/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).
OREMET SUB 12.47 115.00DISTRIBUTION-UNATTEN 1
OVERPASS SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
PALLETTE SUB 20.80 69.00DISTRIBUTION-UNATTEN 3
PARK STREET SUB 12.47 115.00DISTRIBUTION-UNATTEN 4
PARKROSE SUB 12.47 57.00DISTRIBUTION-UNATTEN 5
PENDLETON SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
PILOT ROCK SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
POWELL BUTTE SUB 12.47 115.00DISTRIBUTION-UNATTEN 8
PRINEVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
PROVOLT SUB 12.47 69.00DISTRIBUTION-UNATTEN 10
QUEEN AVE SUB 20.80 69.00DISTRIBUTION-UNATTEN 11
RED BLANKET SUB 4.16 69.00DISTRIBUTION-UNATTEN 12
REDMOND SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
RIDDLE SUB 69.00 116.00DISTRIBUTION-UNATTEN 14
RIDDLE VENEER SUB 12.47 115.00DISTRIBUTION-UNATTEN 15
ROGUE RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
ROSEBURG SUB 20.80 115.00DISTRIBUTION-UNATTEN 17
ROSS AVE SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
ROXY ANN SUB 12.50 115.00DISTRIBUTION-UNATTEN 19
RUCH SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
RUNNING Y SUB 20.80 69.00DISTRIBUTION-UNATTEN 21
RUSSELLVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 22
SCENIC SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 23
SCIO SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
SEASIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 25
SELMA SUB 12.47 115.00DISTRIBUTION-UNATTEN 26
SHASTA WAY SUB 4.16 12.47DISTRIBUTION-UNATTEN 27
SHEVLIN PARK SUB 12.50 69.00DISTRIBUTION-UNATTEN 28
SIMTAG BOOSTER PUMP 4.16 34.50DISTRIBUTION-UNATTEN 29
SOUTH DUNES SUB 12.47 115.00DISTRIBUTION-UNATTEN 30
SOUTHGATE SUB 20.80 69.00DISTRIBUTION-UNATTEN 31
SPRAGUE RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
STATE STREET SUB 20.80 115.00DISTRIBUTION-UNATTEN 33
STAYTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
STEAMBOAT SUB 7.20 115.00DISTRIBUTION-UNATTEN 35
STEVENS ROAD SUB 20.80 115.00DISTRIBUTION-UNATTEN 36
SUTHERLIN SUB 12.00 115.00DISTRIBUTION-UNATTEN 37
SWEET HOME SUB 20.80 115.00DISTRIBUTION-UNATTEN 38
TAKELMA SUB 20.80 115.00DISTRIBUTION-UNATTEN 39
TALENT SUB 12.47 116.00DISTRIBUTION-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 / /2013/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.
75 2 1
45 2 2
1 1 1 3
40 2 4
39 2 5
46 7 1 6
22 2 7
6 1 8
50 2 9
11 3 10
50 2 11
2 3 12
50 2 13
75 2 14
25 1 1 15
25 2 16
50 2 17
9 3 18
25 1 19
9 1 20
9 1 21
45 2 22
70 3 23
8 1 24
40 2 25
9 1 26
2 3 27
25 1 28
19 2 29
9 1 30
20 1 31
7 3 32
40 2 33
55 2 34
1 35
50 2 36
25 1 37
42 2 38
12 1 39
50 2 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 / /2013/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).
TEXUM SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
TILLER SUB 12.47 115.00DISTRIBUTION-UNATTEN 2
TOLO SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
TURKEY HILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
UMAPINE SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
UMATILLA SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
VERNON SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
VILAS SUB 12.47 115.00DISTRIBUTION-UNATTEN 8
VILLAGE GREEN SUB 20.80 115.00DISTRIBUTION-UNATTEN 9
VINE STREET SUB 20.80 69.00DISTRIBUTION-UNATTEN 10
WALLOWA SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
WARM SPRINGS SUB 20.80 69.00DISTRIBUTION-UNATTEN 12
WARRENTON SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
WASCO SUB 4.16 20.80DISTRIBUTION-UNATTEN 14
WECOMA BEACH SUB 4.16 20.80DISTRIBUTION-UNATTEN 15
WESTERN KRAFT SUB 12.47 115.00DISTRIBUTION-UNATTEN 16
WESTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
WESTSIDE HYDRO/SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
WEYERHAUSER SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
WHITE CITY SUB 12.47 115.00DISTRIBUTION-UNATTEN 20
WILLOW COVE SUB 4.16 34.50DISTRIBUTION-UNATTEN 21
WINSTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
YEW AVENUE SUB 12.50 115.00DISTRIBUTION-UNATTEN 23
YOUNGS BAY SUB 12.47 115.00DISTRIBUTION-UNATTEN 24
Total 2559.80 15524.27 195.00 25
Number of Substations-180 26
27
ALBINA SUB 12.47 115.00 69.00T/D-UNATTENDED 28
APPLEGATE SUB 69.00 115.00 12.47T/D-UNATTENDED 29
ASHLAND MTN AVE SUB 69.00 115.00 12.47T/D-UNATTENDED 30
BEND PLANT SUB 13.09 69.00 12.47T/D-UNATTENDED 31
CAVE JUNCTION SUB 12.47 115.00 69.00T/D-UNATTENDED 32
HAZELWOOD SUB 69.00 115.00 12.47T/D-UNATTENDED 33
KNOTT SUB 12.47 115.00 57.00T/D-UNATTENDED 34
MILE HI SUB 69.00 115.00 12.47T/D-UNATTENDED 35
PILOT BUTTE SUB 69.00 230.00 12.47T/D-UNATTENDED 36
SAGE ROAD SUB 12.47 115.00T/D-UNATTENDED 37
WINCHESTER SUB 12.47 115.00 69.00T/D-UNATTENDED 38
Total 420.44 1334.00 338.82 39
Number of Substations-11 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 / /2013/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
1 1 2
11 1 3
13 3 4
20 1 5
25 2 6
50 2 7
25 1 8
40 2 9
20 1 10
7 1 11
12 3 12
25 2 13
3 3 14
3 1 15
50 2 16
22 2 17
22 9 18
40 2 19
60 3 20
28 3 21
22 3 22
25 1 23
37 2 24
4619 346 6 25
26
27
177 9 28
65 2 29
70 2 30
31 3 31
70 2 32
132 4 33
163 5 34
39 4 35
400 4 36
40 2 37
75 5 38
1262 42 39
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 / /2013/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
LEMOLO #1 HYDRO 12.50 11.30TRANSMISSION-ATTENDE 2
CALAPOOYA SUB 69.00 230.00TRANSMISSION-UNATTEN 3
CHILOQUIN SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 4
COLD SPRINGS SUB 69.00 230.00 2.40TRANSMISSION-UNATTEN 5
COVE SUB 69.00 230.00TRANSMISSION-UNATTEN 6
DAYS CREEK SUB 69.00 115.00TRANSMISSION-UNATTEN 7
DIAMOND HILL SUB 69.00 230.00TRANSMISSION-UNATTEN 8
DIXONVILLE 115/230 SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 9
DIXONVILLE 500 SUB 230.00 500.00TRANSMISSION-UNATTEN 10
FISH HOLE SUB 69.00 115.00TRANSMISSION-UNATTEN 11
FRY SUB 115.00 230.00TRANSMISSION-UNATTEN 12
GRANTS PASS SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 13
GREEN SPRINGS PLANT/SUB 69.00 115.00TRANSMISSION-UNATTEN 14
HURRICANE SUB 69.00 230.00 2.40TRANSMISSION-UNATTEN 15
ISTHMUS SUB 115.00 230.00TRANSMISSION-UNATTEN 16
KENNEDY SUB 57.00 69.00TRANSMISSION-UNATTEN 17
KLAMATH FALLS SUB 69.00 230.00TRANSMISSION-UNATTEN 18
LONE PINE SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 19
MALIN SUB 230.00 500.00 69.00TRANSMISSION-UNATTEN 20
MERIDIAN SUB 230.00 500.00TRANSMISSION-UNATTEN 21
MONPAC SUB 69.00 115.00TRANSMISSION-UNATTEN 22
NICKEL MOUNTAIN SUB 115.00 230.00TRANSMISSION-UNATTEN 23
PARRISH GAP SUB 69.00 230.00 12.47TRANSMISSION-UNATTEN 24
PONDEROSA SUB 115.00 230.00TRANSMISSION-UNATTEN 25
PROSPECT CENTRAL SUB 69.00 115.00TRANSMISSION-UNATTEN 26
ROBERTS CREEK SUB 69.00 115.00TRANSMISSION-UNATTEN 27
TROUTDALE SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 28
TUCKER SUB 69.00 115.00TRANSMISSION-UNATTEN 29
Total 2760.50 6065.30 431.27 30
Number of Substations-28 31
32
UTAH 33
106TH SOUTH SUB 12.50 138.00DISTRIBUTION-UNATTEN 34
118TH SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 35
23RD ST SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
70TH SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 37
ALTAVIEW SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
AMALGA SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
AMERICAN FORK SUB 12.47 138.00DISTRIBUTION-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 / /2013/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 3 1 2
75 1 3
119 4 4
66 2 5
67 3 6
50 1 7
75 1 8
343 6 9
650 3 1 10
7 3 11
500 2 12
473 5 13
19 3 14
29 2 15
250 1 16
33 1 17
251 6 1 18
733 10 19
775 4 1 20
1300 6 1 21
50 1 22
114 1 23
150 1 24
250 1 25
30 3 26
50 1 27
500 3 28
100 2 29
7061 80 5 30
31
32
33
30 1 34
30 1 35
12 1 36
30 1 37
45 2 38
11 1 39
30 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 / /2013/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).
ARAGONITE 7.20 46.00DISTRIBUTION-UNATTEN 1
AURORA SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
BANGERTER SUB 12.47 138.00DISTRIBUTION-UNATTEN 3
BEAR RIVER SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
BENJAMIN SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
BINGHAM SUB 7.62 46.00DISTRIBUTION-UNATTEN 6
BLUE CREEK 12.47 46.00DISTRIBUTION-UNATTEN 7
BLUFF SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
BLUFFDALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
BOTHWELL SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
BRIAN HEAD SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
BRICKYARD SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
BRIGHTON SUB 24.90 46.00DISTRIBUTION-UNATTEN 13
BROOKLAWN SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
BRUNSWICK SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
BURTON SUB 12.47 34.50DISTRIBUTION-UNATTEN 16
BUSH SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
CANNON SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
CANYONLANDS SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
CAPITOL SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
CARBIDE SUB 7.20 46.00DISTRIBUTION-UNATTEN 21
CARBONVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
CARLISLE SUB 12.50 138.00DISTRIBUTION-UNATTEN 23
CASTO SUBSTATION 12.47 46.00DISTRIBUTION-UNATTEN 24
CENTERVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
CENTRAL SUB 12.47 43.80DISTRIBUTION-UNATTEN 26
CHAPEL HILL SUB 12.47 138.00DISTRIBUTION-UNATTEN 27
CHERRYWOOD SUB 12.47 138.00DISTRIBUTION-UNATTEN 28
CIRCLEVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
CLEAR CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
CLEAR LAKE SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
CLEARFIELD SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 32
CLINTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 33
CLIVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
COALVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
COLD WATER CANYON SUB 12.47 138.00DISTRIBUTION-UNATTEN 36
COLEMAN SUB 69.00 138.00 12.47DISTRIBUTION-UNATTEN 37
COLTON WELL SUB 2.40 46.00DISTRIBUTION-UNATTEN 38
COMMERCE SUB 12.50 138.00DISTRIBUTION-UNATTEN 39
COPPER HILLS SUB 12.47 138.00DISTRIBUTION-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 / /2013/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 1
3 1 2
50 2 3
17 2 4
2 1 5
25 1 6
2 3 7
1 3 8
9 1 9
4 1 10
14 1 11
9 1 12
29 2 13
6 1 14
60 3 15
11 3 16
9 1 17
12 1 18
1 1 19
20 1 20
3 1 21
6 1 22
30 1 23
25 1 24
22 1 25
9 1 26
30 1 27
50 2 28
3 1 29
4 1 30
3 31
60 2 32
50 2 33
4 1 34
6 1 35
30 1 36
106 4 37
1 3 38
30 1 39
30 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 / /2013/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).
CORINNE SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
COVE FORT SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
COZYDALE SUB 12.50 138.00DISTRIBUTION-UNATTEN 3
CROSS HOLLOW SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
CUDAHY SUB 12.47 138.00DISTRIBUTION-UNATTEN 5
DAMMERON VALLEY SUB 12.47 34.50DISTRIBUTION-UNATTEN 6
DECKER LAKE SUB 12.47 138.00DISTRIBUTION-UNATTEN 7
DELLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
DELTA SUB 69.00 46.00DISTRIBUTION-UNATTEN 9
DESERET SUB 4.16 46.00DISTRIBUTION-UNATTEN 10
DEWEYVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
DIMPLE DELL SUB 12.47 138.00DISTRIBUTION-UNATTEN 12
DIXIE DEER SUB 12.47 34.50DISTRIBUTION-UNATTEN 13
DRAPER SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
EAST BENCH SUB 12.47 138.00DISTRIBUTION-UNATTEN 15
EAST HYRUM SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
EAST LAYTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 17
EAST MILLCREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
EDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
ELBERTA SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
ELK MEADOWS SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
ELSINORE SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
EMERY CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
EMIGRATION SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
ENOCH SUB 12.47 138.00DISTRIBUTION-UNATTEN 25
ENTERPRISE VALLEY SUB 12.47 138.00DISTRIBUTION-UNATTEN 26
EUREKA SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
FARMINGTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 28
FAYETTE SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
FERRON SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
FIELDING SUB 12.00 46.00DISTRIBUTION-UNATTEN 31
FIFTH WEST SUB 12.47 138.00DISTRIBUTION-UNATTEN 32
FLUX SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
FOOL CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
FORT DOUGLAS 13.20 138.00DISTRIBUTION-UNATTEN 35
FOUNTAIN GREEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
FREEDOM SUBSTATION 7.20 46.00DISTRIBUTION-UNATTEN 37
FRUIT HEIGHTS SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
GARDEN CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
GATEWAY SUB 12.47 69.00DISTRIBUTION-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 / /2013/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.
3 1 1
2 3 2
30 1 3
22 1 4
30 1 5
42 1 6
55 2 7
6 1 8
48 3 9
2 1 10
4 1 11
60 2 12
2 1 13
23 2 14
30 1 15
6 1 16
60 2 17
20 1 18
19 2 19
5 1 20
3 1 21
2 1 22
3 3 23
25 1 24
14 1 25
10 1 26
3 1 27
30 1 28
1 2 29
5 1 30
6 1 31
50 2 32
4 1 33
2 1 34
40 1 35
7 1 36
1 37
22 1 38
12 1 39
28 1 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 / /2013/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).
GOLD RUSH SUB 12.50 138.00DISTRIBUTION-UNATTEN 1
GORDON AVENUE SUB 12.50 138.00DISTRIBUTION-UNATTEN 2
GOSHEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
GRANGER SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
GRANTSVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
GUNNISON SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
HAMMER SUB 12.47 138.00DISTRIBUTION-UNATTEN 7
HAVASU SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
HELPER CITY SUB 4.16 46.00DISTRIBUTION-UNATTEN 9
HENEFER SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
HERRIMAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 11
HIGHLAND DIST SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
HOGGARD SUB 12.47 138.00DISTRIBUTION-UNATTEN 13
HOLDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
HOLLADAY SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
HUNTER SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
HUNTINGTON CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
IRON MOUNTAIN SUB 7.20 34.50DISTRIBUTION-UNATTEN 18
IRONTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
IVINS SUB 12.47 34.50DISTRIBUTION-UNATTEN 20
JORDAN NARROWS SUB 2.40 46.00DISTRIBUTION-UNATTEN 21
JORDAN PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 22
JORDANELLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 23
JUAB SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
JUNCTION SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
KAIBAB SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
KAMAS SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
KEARNS SUB 12.47 138.00DISTRIBUTION-UNATTEN 28
KENSINGTON SUB 4.16 46.00DISTRIBUTION-UNATTEN 29
LAKE PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 30
LARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
LAYTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
LEGRANDE SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
LEWISTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
LINCOLN SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
LINDON SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
LISBON SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
LOAFER SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
LOGAN CANYON SUB 7.20 46.00DISTRIBUTION-UNATTEN 39
LONE TREE SUB 12.47 34.50DISTRIBUTION-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 / /2013/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
30 1 2
2 1 3
50 2 4
23 1 5
11 2 6
60 2 7
3 1 8
3 3 9
4 1 10
30 1 11
25 1 12
50 2 13
4 1 14
32 2 15
22 1 16
12 2 17
1 1 18
2 1 19
22 1 20
13 2 21
30 1 22
30 1 23
2 3 24
2 1 25
5 1 26
7 1 27
60 2 28
7 1 29
53 2 30
6 1 31
40 2 32
2 1 33
14 1 34
20 1 35
20 1 36
4 1 37
1 38
1 1 39
20 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 / /2013/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).
LOWER BEAVER SUB 6.60 46.00DISTRIBUTION-UNATTEN 1
LYNNDYL SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
MAESER SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
MAGNA SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
MANILA SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
MANTUA SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
MAPLETON SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
MARRIOTT SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
MARYSVALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
MATHIS SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
MCCORNICK SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
MCKAY SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
MEADOWBROOK SUB 12.47 138.00 46.00DISTRIBUTION-UNATTEN 13
MEDICAL SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
MIDLAND SUB 12.47 138.00DISTRIBUTION-UNATTEN 15
MIDVALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
MILFORD SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
MILFORD TV SUB 13.20 46.00DISTRIBUTION-UNATTEN 18
MINERSVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
MOAB CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
MONTEZUMA SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
MOORE SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
MORGAN SUB 4.16 46.00DISTRIBUTION-UNATTEN 23
MORONI SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
MOSS JUNCTION SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
MOUNTAIN DELL SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
MOUNTAIN GREEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
MYTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
NEW HARMONY SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
NEWGATE SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
NEWTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
NIBLEY SUB 24.90 46.00DISTRIBUTION-UNATTEN 32
NORTH BENCH SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
NORTH FIELDS SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
NORTH LOGAN SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
NORTH OGDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
NORTH SALT LAKE SUB 13.20 46.00DISTRIBUTION-UNATTEN 37
NORTHEAST SUB 12.50 46.00DISTRIBUTION-UNATTEN 38
NORTHRIDGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
OAKLAND AVE 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 / /2013/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 1
4 1 2
12 1 3
30 1 4
22 1 5
2 1 6
14 1 7
20 1 8
3 1 9
9 1 10
6 1 11
20 1 12
42 2 13
57 4 14
30 1 15
25 1 16
14 1 17
1 18
2 1 19
19 2 20
12 1 21
3 1 22
7 2 23
6 1 24
6 3 25
5 1 26
6 1 27
6 1 28
7 1 29
20 1 30
5 1 31
14 1 32
25 1 33
2 1 34
25 1 35
22 1 36
25 1 37
45 2 38
14 1 39
24 2 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 / /2013/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).
OAKLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
OLYMPUS SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
OPHIR SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
ORANGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
ORANGEVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
OREM SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
PACK CREEK RESERVOIR 12.47 46.00DISTRIBUTION-UNATTEN 7
PANGUITCH SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
PARIETTE SUBSTATION 24.90 69.00DISTRIBUTION-UNATTEN 9
PARK CITY SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
PARKWAY SUB 12.47 138.00DISTRIBUTION-UNATTEN 11
PARLEYS SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
PELICAN POINT SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
PINE CANYON SUB 12.47 138.00DISTRIBUTION-UNATTEN 14
PINE CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
PINNACLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
PLAIN CITY SUB 12.47 138.00DISTRIBUTION-UNATTEN 17
PLEASANT GROVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
PLEASANT VIEW SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
PORTER ROCKWELL SUB 12.47 138.00DISTRIBUTION-UNATTEN 20
PROMONTORY SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
QUAIL CREEK SUB 12.47 34.50DISTRIBUTION-UNATTEN 22
QUARRY SUB 12.47 138.00DISTRIBUTION-UNATTEN 23
QUICHAPA SUB 12.47 34.50DISTRIBUTION-UNATTEN 24
RAINS SUB 7.20 46.00DISTRIBUTION-UNATTEN 25
RANDOLPH SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
RASMUSON SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
RATTLESNAKE SUB 24.90 69.00DISTRIBUTION-UNATTEN 28
RED MOUNTAIN SUB 34.50 69.00DISTRIBUTION-UNATTEN 29
RED ROCK SUB 4.16 69.00DISTRIBUTION-UNATTEN 30
REDWOOD SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
RESEARCH PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
RICH SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
RICHFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
RICHMOND SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
RIDGELAND SUB 12.47 138.00DISTRIBUTION-UNATTEN 36
RITER SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
ROCK CANYON SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
ROCKVILLE SUB 12.47 34.50DISTRIBUTION-UNATTEN 39
ROCKY POINT 13.20 138.00DISTRIBUTION-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 / /2013/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
22 1 2
3 1 3
20 1 4
14 1 5
48 2 6
4 1 7
5 1 8
4 3 9
35 2 10
50 2 11
16 2 12
6 1 13
55 2 14
2 1 15
14 1 16
22 1 17
25 1 18
14 1 19
30 1 20
2 1 21
4 1 22
60 2 23
4 1 24
15 1 25
2 1 26
1 3 27
14 1 28
12 1 29
3 1 30
45 2 31
45 2 32
5 1 33
22 2 34
11 1 35
40 2 36
20 1 37
5 1 38
4 1 39
30 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 / /2013/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).
ROSE PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
ROYAL SUB 4.16 46.00DISTRIBUTION-UNATTEN 2
SALINA SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
SANDY SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
SARATOGA SUB 12.47 138.00DISTRIBUTION-UNATTEN 5
SCIPIO SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
SCOFIELD RESERVOIR SUB 7.20 46.00DISTRIBUTION-UNATTEN 7
SCOFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
SECOND STREET SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
SEGO CANYON SUB 12.47 69.00DISTRIBUTION-UNATTEN 10
SEVEN MILE SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
SHARON SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
SHIVWITS SUB 4.16 34.50DISTRIBUTION-UNATTEN 13
SHORELINE SUB 13.20 138.00DISTRIBUTION-UNATTEN 14
SIXTH SOUTH SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
SKULL VALLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
SKYPARK SUB 12.50 138.00 12.50DISTRIBUTION-UNATTEN 17
SNARR SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
SNOWVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
SNYDERVILLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 20
SOLDIER SUMMIT SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
SOUTH JORDAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 22
SOUTH MILFORD SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
SOUTH MOUNTAIN SUB 12.47 138.00DISTRIBUTION-UNATTEN 24
SOUTH OGDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
SOUTH PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 26
SOUTH WEBER SUB 12.47 138.00DISTRIBUTION-UNATTEN 27
SOUTHWEST SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
SPANISH VALLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
SPRINGDALE SUB 12.47 34.50DISTRIBUTION-UNATTEN 30
ST. JOHNS SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
STANSBURY SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
SUMMIT CREEK SUB 12.47 138.00DISTRIBUTION-UNATTEN 33
SUMMIT PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
SUNRISE SUB 12.47 138.00DISTRIBUTION-UNATTEN 35
SUPERIOR SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
SUTHERLAND SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
TAMARISK SUB 12.47 138.00DISTRIBUTION-UNATTEN 38
TAYLOR SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
THIEF CREEK SUB 24.90 138.00DISTRIBUTION-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 / /2013/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.
24 3 1
3 2
11 1 3
60 2 4
60 2 5
1 3 6
1 1 7
1 3 8
13 2 9
14 1 10
1 11
20 1 12
6 1 13
60 2 14
20 1 15
2 1 16
40 1 17
40 2 18
5 1 19
60 2 20
12 1 21
60 2 22
20 2 23
60 2 24
25 1 25
30 1 26
22 1 27
22 2 28
6 1 29
4 1 30
4 1 31
20 1 32
14 1 33
7 1 34
60 2 35
8 1 36
6 1 37
20 1 38
14 1 39
14 1 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 / /2013/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).
THIRD WEST SUB 13.20 138.00DISTRIBUTION-UNATTEN 1
THIRTEENTH SOUTH SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
TOOELE DEPOT SUB 12.50 46.00DISTRIBUTION-UNATTEN 3
TOQUERVILLE SUB 12.47 69.00 34.50DISTRIBUTION-UNATTEN 4
UINTAH SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
UNION SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
VALLEY CENTER SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
VERMILLION SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
VERNAL SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
VICKERS SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
VINEYARD SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
WALLSBURG SUB 12.47 138.00DISTRIBUTION-UNATTEN 12
WALNUT GROVE SUB 12.50 138.00DISTRIBUTION-UNATTEN 13
WARREN SUB 12.47 138.00DISTRIBUTION-UNATTEN 14
WASATCH STATE PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
WASHAKIE SUB 4.16 138.00DISTRIBUTION-UNATTEN 16
WELBY SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
WELFARE SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
WEST COMMERCIAL SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
WEST JORDAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 20
WEST OGDEN SUB 12.47 138.00DISTRIBUTION-UNATTEN 21
WEST ROY SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
WEST TEMPLE SUB 4.16 46.00DISTRIBUTION-UNATTEN 23
WESTWATER SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
WHITE MESA SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
WHITE ROCK SUB 12.47 138.00DISTRIBUTION-UNATTEN 26
WILLOWCREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
WILLOWRIDGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
WINCHESTER HILLS SUB 12.47 34.50DISTRIBUTION-UNATTEN 29
WINKLEMAN SUB 7.20 46.00DISTRIBUTION-UNATTEN 30
WOLF CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
WOOD CROSS SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
WOODRUFF SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
Total 3545.24 19616.80 105.47 34
Number of Substations-280 35
36
90TH SOUTH SUB 138.00 345.00 12.47T/D-UNATTENDED 37
ANGEL SUB 12.47 138.00 46.00T/D-UNATTENDED 38
BDO SUBSTATION 12.47 138.00T/D-UNATTENDED 39
BUTLERVILLE SUB 46.00 138.00 12.47T/D-UNATTENDED 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 / /2013/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.
100 2 1
22 1 2
25 1 3
34 2 4
39 2 5
50 2 6
22 1 7
3 1 8
33 2 9
2 1 10
25 1 11
13 1 12
30 1 13
30 1 14
2 3 15
14 1 16
42 2 17
5 1 18
22 1 19
28 1 20
60 2 21
25 1 22
60 3 23
5 1 24
14 1 25
30 1 26
1 1 27
14 1 28
4 1 29
1 30
6 1 31
20 1 32
2 1 33
5458 383 1 34
35
36
1572 5 1 37
135 3 38
30 1 39
205 4 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 / /2013/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).
CENTENNIAL SUB 12.47 138.00T/D-UNATTENDED 1
COTTONWOOD SUB 12.47 138.00 46.00T/D-UNATTENDED 2
DECADE SUB 12.50 138.00T/D-UNATTENDED 3
DUMAS SUB 12.47 138.00T/D-UNATTENDED 4
EMMA PARK SUBSTATION 12.47 138.00T/D-UNATTENDED 5
GROW SUB 12.47 138.00 46.00T/D-UNATTENDED 6
HALE SUB 46.00 138.00 12.47T/D-UNATTENDED 7
HIGHLAND SUB 12.47 138.00 46.00T/D-UNATTENDED 8
JORDAN SUB 46.00 138.00 12.47T/D-UNATTENDED 9
JUDGE SUB 12.47 46.00T/D-UNATTENDED 10
MCCLELLAND SUB 46.00 138.00 12.47T/D-UNATTENDED 11
MORTON COURT SUB 12.47 138.00T/D-UNATTENDED 12
OQUIRRH SUB 46.00 345.00 138.00T/D-UNATTENDED 13
PARRISH SUB 12.47 138.00 46.00T/D-UNATTENDED 14
PIONEER PLANT 12.47 138.00T/D-UNATTENDED 15
RIVERDALE SUB 46.00 138.00 12.47T/D-UNATTENDED 16
SEVIER SUB 46.00 138.00 12.47T/D-UNATTENDED 17
SILVER CREEK SUB 12.47 138.00 46.00T/D-UNATTENDED 18
SOUTHEAST SUB 12.47 138.00 46.00T/D-UNATTENDED 19
SPHINX SUB 12.47 46.00T/D-UNATTENDED 20
SYRACUSE SUB 46.00 345.00 138.00T/D-UNATTENDED 21
TAYLORSVILLE SUB 46.00 138.00 12.47T/D-UNATTENDED 22
TERMINAL SUB 46.00 345.00 138.00T/D-UNATTENDED 23
TIMP SUB 46.00 138.00 12.47T/D-UNATTENDED 24
TOOELE SUB 46.00 138.00 12.47T/D-UNATTENDED 25
TRI CITY SUB 12.47 138.00T/D-UNATTENDED 26
WEST VALLEY SUB 12.47 138.00T/D-UNATTENDED 27
WESTFIELD SUB 12.47 138.00T/D-UNATTENDED 28
Total 926.96 5060.00 860.70 29
Number of Substations-32 30
31
EMERY SUB 138.00 345.00 69.00TRANSMISSION-ATTENDE 32
GADSBY SUB 46.00 138.00TRANSMISSION-ATTENDE 33
ABAJO SUB 69.00 138.00TRANSMISSION-UNATTEN 34
ASHLEY SUB 46.00 138.00TRANSMISSION-UNATTEN 35
BARNEY SUB 46.00 138.00TRANSMISSION-UNATTEN 36
BEN LOMOND SUB 230.00 345.00 138.00TRANSMISSION-UNATTEN 37
BLACK ROCK SUB 69.00 230.00TRANSMISSION-UNATTEN 38
BLACKHAWK SUB 69.00 138.00 46.00TRANSMISSION-UNATTEN 39
CAMERON SUB 46.00 138.00TRANSMISSION-UNATTEN 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 / /2013/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
289 7 2
60 2 3
60 2 4
8 1 5
72 3 6
114 2 7
97 2 8
164 2 9
22 1 10
340 3 11
65 2 12
835 4 1 13
97 2 14
30 1 15
180 3 16
34 4 17
100 2 18
50 2 19
3 1 3 20
600 5 21
358 4 22
1108 6 2 23
130 2 24
158 3 25
30 1 26
30 1 27
20 1 28
7036 84 7 29
30
31
783 13 1 32
318 2 33
67 1 34
133 2 35
100 1 36
1813 5 37
75 1 38
100 2 39
25 4 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 / /2013/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).
CAMP WILLIAMS SUB 138.00 345.00 12.47TRANSMISSION-UNATTEN 1
CLOVER SUB 138.00 345.00 14.40TRANSMISSION-UNATTEN 2
COLUMBIA SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 3
CRANER FLAT SUB 12.47 138.00TRANSMISSION-UNATTEN 4
CUTLER SUB 46.00 138.00TRANSMISSION-UNATTEN 5
EL MONTE SUB 46.00 138.00TRANSMISSION-UNATTEN 6
GARKANE SUB 46.00 69.00TRANSMISSION-UNATTEN 7
GREEN CANYON SUB 46.00 138.00TRANSMISSION-UNATTEN 8
GRINDING SUB 13.80 138.00TRANSMISSION-UNATTEN 9
HELPER SUB 46.00 138.00TRANSMISSION-UNATTEN 10
HONEYVILLE SUB 46.00 138.00TRANSMISSION-UNATTEN 11
HORSESHOE SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 12
HUNTINGTON SUB 138.00 345.00TRANSMISSION-UNATTEN 13
JERUSALEM SUB 46.00 138.00TRANSMISSION-UNATTEN 14
LAMPO SUB 46.00 138.00TRANSMISSION-UNATTEN 15
MATHINGTON SUB 46.00 138.00 13.20TRANSMISSION-UNATTEN 16
MCFADDEN SUB 46.00 138.00TRANSMISSION-UNATTEN 17
MIDDLETON SUB 69.00 138.00 34.50TRANSMISSION-UNATTEN 18
MIDVALLEY SUB 138.00 345.00TRANSMISSION-UNATTEN 19
MIDWAY CITY SUB 46.00 138.00TRANSMISSION-UNATTEN 20
MINERAL PRODUCTS SUB 46.00 69.00TRANSMISSION-UNATTEN 21
MOAB SUB 69.00 138.00TRANSMISSION-UNATTEN 22
NEBO SUB 46.00 138.00TRANSMISSION-UNATTEN 23
PAROWAN VALLEY SUB 138.00 230.00 34.50TRANSMISSION-UNATTEN 24
PAVANT SUB 46.00 230.00TRANSMISSION-UNATTEN 25
PINTO SUB 138.00 345.00 69.00TRANSMISSION-UNATTEN 26
RED BUTTE SUB 138.00 230.00TRANSMISSION-UNATTEN 27
SIGURD SUB 230.00 345.00 138.00TRANSMISSION-UNATTEN 28
SMITHFIELD SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 29
SPANISH FORK SUB 138.00 345.00 46.00TRANSMISSION-UNATTEN 30
ST GEORGE SUB 16.50 138.00TRANSMISSION-UNATTEN 31
THREE PEAKS SUB 138.00 345.00TRANSMISSION-UNATTEN 32
WEST CEDAR SUB 138.00 230.00 34.50TRANSMISSION-UNATTEN 33
Total 3331.77 8188.00 686.98 34
Number of Substations-42 35
36
WASHINGTON 37
ATTALIA SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
BOWMAN SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
CASCADE KRAFT SUB 12.47 69.00 4.16DISTRIBUTION-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 / /2013/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.
169 2 1
448 1 2
71 2 3
40 2 4
50 1 5
312 3 6
33 1 7
67 2 8
225 3 9
142 2 10
35 1 11
80 2 12
270 4 13
67 1 14
75 1 15
75 1 16
45 1 17
141 4 18
900 2 19
67 1 20
12 1 21
67 1 22
67 1 23
138 2 24
133 2 25
258 3 26
400 1 27
1124 6 28
63 2 29
1017 5 30
100 3 1 31
450 1 32
262 3 33
10817 99 2 34
35
36
37
25 1 38
45 2 39
118 6 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 / /2013/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).
CLINTON SUB 12.47 115.00DISTRIBUTION-UNATTEN 1
DAYTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
DODD ROAD SUB 20.80 69.00DISTRIBUTION-UNATTEN 3
GRANDVIEW SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 4
HOPLAND SUB 12.47 115.00DISTRIBUTION-UNATTEN 5
NACHES 12.47 115.00DISTRIBUTION-UNATTEN 6
NOB HILL SUB 12.47 115.00DISTRIBUTION-UNATTEN 7
NORTH PARK SUB 12.47 115.00DISTRIBUTION-UNATTEN 8
ORCHARD SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
PACIFIC SUB 12.47 115.00DISTRIBUTION-UNATTEN 10
POMEROY SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
PROSPECT POINT SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
PUNKIN CENTER SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
RIVER ROAD SUB 12.47 115.00DISTRIBUTION-UNATTEN 14
SELAH SUB 12.47 115.00DISTRIBUTION-UNATTEN 15
SULPHUR CREEK SUB 12.47 115.00DISTRIBUTION-UNATTEN 16
SUNNYSIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
TIETON SUB 12.47 115.00 34.50DISTRIBUTION-UNATTEN 18
TOPPENISH SUB 12.47 115.00DISTRIBUTION-UNATTEN 19
TOUCHET SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
VOELKER SUB 12.47 115.00DISTRIBUTION-UNATTEN 21
WAITSBURG SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
WAPATO SUB 12.47 115.00DISTRIBUTION-UNATTEN 23
WENAS SUB 12.47 115.00DISTRIBUTION-UNATTEN 24
WHITE SWAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 25
WILEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 26
Total 369.96 2921.00 107.66 27
Number of Substations-29 28
29
CENTRAL SUB 12.47 69.00T/D-UNATTENDED 30
MILL CREEK SUB 12.47 69.00T/D-UNATTENDED 31
UNION GAP SUB 115.00 230.00 12.47T/D-UNATTENDED 32
Total 139.94 368.00 12.47 33
Number of Substations-3 34
35
OUTLOOK SUB 115.00 230.00TRANSMISSION-UNATTEN 36
PASCO SUB 69.00 115.00 7.20TRANSMISSION-UNATTEN 37
POMONA HEIGHTS SUB 115.00 230.00TRANSMISSION-UNATTEN 38
WALLA WALLA 230KV SUB 69.00 230.00TRANSMISSION-UNATTEN 39
WALLULA SUB 69.00 230.00TRANSMISSION-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 / /2013/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
23 2 2
25 4 3
42 2 4
50 2 5
20 1 6
42 2 7
45 2 8
50 2 9
28 3 10
9 1 11
40 2 12
20 2 13
51 4 14
45 2 15
25 1 16
45 2 17
29 2 18
50 2 19
6 1 20
25 1 21
9 1 22
45 2 23
25 2 24
22 2 25
45 2 26
1029 59 27
28
29
14 1 30
45 2 31
348 5 32
407 8 33
34
35
125 1 36
39 9 37
300 2 38
300 2 39
120 2 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 / /2013/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).
WINE COUNTRY SUB 115.00 230.00TRANSMISSION-UNATTEN 1
Total 552.00 1265.00 7.20 2
Number of Substations-6 3
WYOMING 4
ANTELOPE MINE SUB 34.50 230.00DISTRIBUTION-UNATTEN 5
ASTLE STREET 13.20 34.50DISTRIBUTION-UNATTEN 6
BAILEY DOME SUB 12.47 57.00DISTRIBUTION-UNATTEN 7
BAR X SUB 34.50 230.00DISTRIBUTION-UNATTEN 8
BIG MUDDY SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
BIG PINEY SUB 24.90 69.00DISTRIBUTION-UNATTEN 10
BLACKS FORK SUB 34.50 230.00DISTRIBUTION-UNATTEN 11
BRIDGER PUMP SUB 34.50 230.00 13.20DISTRIBUTION-UNATTEN 12
BRYAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
BUFFALO TOWN SUB 4.16 20.80DISTRIBUTION-UNATTEN 14
BYRON SUB 4.16 34.50DISTRIBUTION-UNATTEN 15
CASSA SUB 20.80 57.00 12.47DISTRIBUTION-UNATTEN 16
CENTER STREET SUB 4.16 115.00DISTRIBUTION-UNATTEN 17
CHAPMAN SUBSTATION 12.47 46.00DISTRIBUTION-UNATTEN 18
CHUKAR SUB 4.16 12.47DISTRIBUTION-UNATTEN 19
CHURCH AND DWIGHT SUB 0.48 34.50DISTRIBUTION-UNATTEN 20
COKEVILLE SUB 24.90 46.00DISTRIBUTION-UNATTEN 21
COLUMBIA-GENEVA SUB 13.80 230.00DISTRIBUTION-UNATTEN 22
COMMUNITY PARK SUB 13.20 116.00DISTRIBUTION-UNATTEN 23
CROOKS GAP SUB 12.47 34.50DISTRIBUTION-UNATTEN 24
DEER CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
DJ COAL MINE SUB 34.50 69.00DISTRIBUTION-UNATTEN 26
DOUGLAS SUB 2.30 57.00DISTRIBUTION-UNATTEN 27
DRY FORK SUB 4.16 69.00DISTRIBUTION-UNATTEN 28
ELK BASIN SUB 7.20 34.50DISTRIBUTION-UNATTEN 29
EMIGRANT SUB 12.47 115.00DISTRIBUTION-UNATTEN 30
EVANS SUB 12.47 115.00DISTRIBUTION-UNATTEN 31
EVANSTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 32
FORT CASPER SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
FORT SANDERS SUB 13.20 115.00DISTRIBUTION-UNATTEN 34
FRANNIE SUB 34.50 230.00DISTRIBUTION-UNATTEN 35
FRONTIER SUB 4.16 69.00DISTRIBUTION-UNATTEN 36
GARLAND SUB 34.50 230.00DISTRIBUTION-UNATTEN 37
GLENDO SUB 4.16 57.00DISTRIBUTION-UNATTEN 38
GRASS CREEK SUB 34.50 230.00DISTRIBUTION-UNATTEN 39
GREAT DIVIDE SUB 34.50 115.00DISTRIBUTION-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 / /2013/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
1134 17 2
3
4
25 1 5
12 1 6
2 1 7
25 1 8
7 1 9
14 1 10
150 2 11
72 4 12
25 1 13
2 3 14
2 3 15
2 6 1 16
12 1 17
4 1 18
1 3 19
3 2 20
4 1 21
45 2 22
45 2 23
5 3 24
9 1 25
12 1 26
6 3 27
9 1 28
5 1 29
12 1 30
9 1 31
40 2 32
28 1 33
20 1 34
50 2 35
6 1 36
45 2 37
3 4 38
25 1 39
20 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 / /2013/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).
GREYBULL SUB 4.16 34.50DISTRIBUTION-UNATTEN 1
HANNA SUB 12.47 34.50DISTRIBUTION-UNATTEN 2
JACKALOPE SUB 12.47 115.00DISTRIBUTION-UNATTEN 3
KEMMERER SUB 24.90 69.00DISTRIBUTION-UNATTEN 4
KIRBY CREEK PUMPING STATION 2.40 34.50DISTRIBUTION-UNATTEN 5
KIRBY CREEK SUB 4.16 34.50DISTRIBUTION-UNATTEN 6
LANDER SUB 12.47 34.50DISTRIBUTION-UNATTEN 7
LARAMIE SUB 13.20 115.00DISTRIBUTION-UNATTEN 8
LATHAM SUB 34.50 230.00DISTRIBUTION-UNATTEN 9
LINCH SUB 13.80 69.00DISTRIBUTION-UNATTEN 10
LITTLE MOUNTAIN SUB 34.50 230.00DISTRIBUTION-UNATTEN 11
LOVELL SUB 4.16 34.50DISTRIBUTION-UNATTEN 12
MILL IRON SUB 13.80 34.50DISTRIBUTION-UNATTEN 13
MILLS SUB 4.16 12.47DISTRIBUTION-UNATTEN 14
MURPHY DOME SUB 13.20 34.50DISTRIBUTION-UNATTEN 15
NUGGETT SUB 7.20 69.00DISTRIBUTION-UNATTEN 16
OPAL SUB 24.90 69.00DISTRIBUTION-UNATTEN 17
ORIN SUB 12.47 57.00DISTRIBUTION-UNATTEN 18
ORPHA SUB 7.20 57.00DISTRIBUTION-UNATTEN 19
PARADISE SUB 25.00 69.00DISTRIBUTION-UNATTEN 20
PARCO SUB 12.47 34.50DISTRIBUTION-UNATTEN 21
PINEDALE SUB 24.90 69.00DISTRIBUTION-UNATTEN 22
PITCHFORK SUB 24.90 69.00DISTRIBUTION-UNATTEN 23
POISON SPIDER SUB 2.40 69.00DISTRIBUTION-UNATTEN 24
POLECAT SUB 12.47 34.50DISTRIBUTION-UNATTEN 25
RAINBOW SUB 13.20 34.50DISTRIBUTION-UNATTEN 26
RAVEN SUB 34.50 230.00DISTRIBUTION-UNATTEN 27
RED BUTTE SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
REFINERY SUB 12.47 115.00DISTRIBUTION-UNATTEN 29
SAGE HILL SUB 13.20 34.50DISTRIBUTION-UNATTEN 30
SHOSHONI SUB 2.40 34.50DISTRIBUTION-UNATTEN 31
SLATE CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
SOUTH CODY SUB 24.90 69.00DISTRIBUTION-UNATTEN 33
SOUTH ELK BASIN SUB 4.16 34.50DISTRIBUTION-UNATTEN 34
SOUTH TRONA SUB 34.50 230.00DISTRIBUTION-UNATTEN 35
SPRING CREEK SUB 13.20 115.00DISTRIBUTION-UNATTEN 36
SVILAR SUB 4.16 34.50DISTRIBUTION-UNATTEN 37
TEN MILE STEP DOWN SUB 12.50 34.50DISTRIBUTION-UNATTEN 38
TEN MILE SUB 34.50 69.00DISTRIBUTION-UNATTEN 39
THERMOPOLIS TOWN SUB 4.16 34.50DISTRIBUTION-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 / /2013/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.
3 1 1
6 1 2
25 1 3
10 1 4
3 3 5
2 3 6
25 2 7
50 2 8
25 1 9
12 1 10
20 1 11
4 1 12
12 1 1 13
1 3 14
5 1 15
1 16
8 1 17
2 3 18
3 3 19
30 1 20
5 1 21
8 1 22
17 9 2 23
3 1 24
1 3 25
12 1 26
200 2 27
20 1 28
45 2 29
6 1 30
2 3 31
1 1 32
14 3 1 33
2 6 34
150 2 35
25 1 36
2 3 37
5 1 38
12 1 39
5 1 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 / /2013/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).
THUNDER CREEK SUB 12.47 57.00DISTRIBUTION-UNATTEN 1
VETERANS SUB 13.20 34.50DISTRIBUTION-UNATTEN 2
WELCH SUB 2.40 57.00DISTRIBUTION-UNATTEN 3
WERTZ-SINCLAIR SUB 4.16 57.00 12.50DISTRIBUTION-UNATTEN 4
WEST ADAMS SUB 4.16 34.50DISTRIBUTION-UNATTEN 5
WESTVACO SUB 34.50 230.00DISTRIBUTION-UNATTEN 6
WORLAND TOWN SUB 4.16 34.50DISTRIBUTION-UNATTEN 7
WYOPO SUB 34.50 230.00DISTRIBUTION-UNATTEN 8
WYUTA SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
Total 1311.37 7494.24 38.17 10
Number of Substations-85 11
12
BUFFALO SUB 20.80 230.00T/D-UNATTENDED 13
ELK HORN SUB 12.50 115.00T/D-UNATTENDED 14
FIREHOLE SUB 34.50 230.00T/D-UNATTENDED 15
HILLTOP SUB 34.50 115.00 20.80T/D-UNATTENDED 16
LABARGE SUB 24.90 69.00T/D-UNATTENDED 17
POINT OF ROCKS SUB 34.50 230.00T/D-UNATTENDED 18
RIVERTON 230 SUB 12.47 230.00 34.50T/D-UNATTENDED 19
YELLOWCAKE SUB 34.50 230.00T/D-UNATTENDED 20
Total 208.67 1449.00 55.30 21
Number of Substations-8 22
23
DAVE JOHNSTON PLANT/SUB 115.00 230.00 69.00TRANSMISSION-ATTENDE 24
JIM BRIDGER 345KV SUB 230.00 345.00 34.50TRANSMISSION-ATTENDE 25
NAUGHTON SUB 138.00 230.00 69.00TRANSMISSION-ATTENDE 26
BAIROIL SUB 34.50 115.00 57.00TRANSMISSION-UNATTEN 27
CASPER SUB 115.00 230.00 13.20TRANSMISSION-UNATTEN 28
CHAPPELL CREEK SUB 69.00 230.00TRANSMISSION-UNATTEN 29
CHIMNEY BUTTE SUB 69.00 230.00TRANSMISSION-UNATTEN 30
FOOTE CREEK WIND FARM 34.50 230.00TRANSMISSION-UNATTEN 31
GLENDO AUTO SUB 57.00 69.00TRANSMISSION-UNATTEN 32
MANSFACE SUB 34.50 230.00TRANSMISSION-UNATTEN 33
MIDWEST SUB 69.00 230.00 34.50TRANSMISSION-UNATTEN 34
MINERS SUB 34.50 230.00 9.70TRANSMISSION-UNATTEN 35
MUSTANG SUB 115.00 230.00TRANSMISSION-UNATTEN 36
OREGON BASIN SUB 34.50 230.00 69.00TRANSMISSION-UNATTEN 37
PLATTE SUB 115.00 230.00 34.50TRANSMISSION-UNATTEN 38
RAILROAD SUB 138.00 230.00TRANSMISSION-UNATTEN 39
ROCK SPRINGS 230 SUB 34.50 230.00TRANSMISSION-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 / /2013/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
25 2 2
3 3 3
2 6 4
3 1 5
25 1 6
5 1 7
20 1 1 8
1 9
1629 157 6 10
11
12
20 1 13
25 1 14
50 2 15
45 2 1 16
8 6 17
25 1 18
74 4 19
25 1 20
272 18 1 21
22
23
336 4 24
703 7 25
599 4 26
53 3 27
517 5 28
67 1 29
75 1 30
196 2 31
15 2 32
20 1 33
91 4 34
20 1 35
100 1 36
65 2 37
140 3 38
400 1 39
50 2 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 / /2013/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).
SAGE SUB 46.00 69.00TRANSMISSION-UNATTEN 1
THERMOPOLIS SUB 115.00 230.00TRANSMISSION-UNATTEN 2
Total 1598.00 4048.00 390.40 3
Number of Substations-19 4
5
CALIFORNIA 6
Distribution - 42 7
T/D - 2 8
Transmission - 6 9
10
IDAHO 11
Distribution - 65 12
T/D - 5 13
Transmission - 16 14
15
MONTANA 16
Transmission - 3 17
18
OREGON 19
Distribution - 180 20
T/D - 11 21
Transmission - 28 22
23
UTAH 24
Distribution - 280 25
T/D - 32 26
Transmission - 42 27
28
WASHINGTON 29
Distribution - 29 30
T/D - 3 31
Transmission - 6 32
33
WYOMING 34
Distribution - 85 35
T/D - 8 36
Transmission - 19 37
38
ALL STATES 39
Distribution - 681 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 / /2013/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
175 2 2
3644 47 3
4
5
6
323 7
126 8
762 9
10
11
721 12
374 13
3804 14
15
16
200 17
18
19
4619 20
1262 21
7061 22
23
24
5458 25
7036 26
10817 27
28
29
1029 30
407 31
1134 32
33
34
1629 35
272 36
3644 37
38
39
13779 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 / /2013/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).
T/D - 61 1
Transmission - 120 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
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 / /2013/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.
9477 1
27422 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
FERC FORM NO. 1 (ED. 12-96) Page 427.24
Schedule Page: 426.3 Line No.: 38 Column: a
The Broadview 500kV Substation is jointly owned by PacifiCorp, NorthWestern Energy, Puget
Sound Energy, Inc., Portland General Electric Company and Avista Corporation. Ownership
and operations and maintenance costs vary by type of asset as defined in the Transmission
Agreement.
Schedule Page: 426.3 Line No.: 39 Column: a
The Colstrip 500kV Substation is jointly owned by PacifiCorp, NorthWestern Energy, Puget
Sound Energy, Inc., Portland General Electric Company and Avista Corporation. Ownership
and operations and maintenance costs vary by type of asset as defined in the Transmission
Agreement.
Schedule Page: 426.9 Line No.: 10 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.: 20 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.: 21 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: 426.22 Line No.: 24 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: 426.22 Line No.: 25 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%.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/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
/ /2013/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 158,550,835Bridger Coal Company
4
5 Coal mining services 70,633,989Energy West Mining Company 151
6
7 Coal purchases 14,232,252Trapper Mining Inc. 151
8
9 Administrative support services 1,168,072Interwest Mining Company
10
11 Administrative services under the IASA 11,193,188MEHC
12 Administrative services under the IASA 4,723,795MEC
13 Administrative services under the IASA 421,420MHC, Inc. 426.5, 923
14 Administrative services under the IASA 217,785Kern River Gas Transmission Company 107, 923
15
16 Gas transportation services 3,261,037Kern River Gas Transmission Company 501, 547
17
18 Relocation services 1,647,548HomeServices of America, Inc.
19
20 Non-power Goods or Services Provided for Affiliate
21 Information technology and administrative
22 support services 960,187Bridger Coal Company 146
23
24 Financial support services and employee benefits 629,055Interwest Mining Company 146
25
26 Information technology and administrative
27 support services 502,281Energy West Mining Company 146
28
29 Administrative services under the IASA 3,415,067MEHC 146
30 Administrative services under the IASA 1,750,416MEC 146
31 Administrative services under the IASA 1,520,264MidAmerican Transmission, LLC 146
32 Administrative services under the IASA 562,243MEHC Canada Transmission 146
33 Administrative services under the IASA 357,164Northern Natural Gas Company 146
34 Administrative services under the IASA 260,300HomeServices of America, Inc. 146
35 Administrative services under the IASA 176,273Kern River Gas Transmission Company 146
36
37 Easement and relocation of utility facilities 99,344Kern River Gas Transmission Company 107, 454
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
/ /2013/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 31,801,205BNSF Railway Company 151,507,567,589
4
5 Banking services 2,262,901Wells Fargo & Company
6
7 Computer hardware and software and computer
8 systems consulting and maintenance services 4,592,665International Business Machines Corp
9
10 Rating agency fees 416,415Moody's Investors Service 181, 186, 930.2
11
12 Surety bond premium 427,920National Indemnity Company 165
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, 501, 502, 513 and 935.
Schedule Page: 429 Line No.: 3 Column: d
Non-power goods or services provided by Bridger Coal Company are as follows:
Coal purchases $ 158,490,560
Support services 60,275
$ 158,550,835
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, 512, 557, 923, 928 and
929.
Schedule Page: 429 Line No.: 9 Column: d
Interwest Mining Company manages PacifiCorp's mining operations and charges management
services to Bridger Coal Company and Energy West Mining Company. Interwest Mining Company
also charges PacifiCorp for administrative support services. All costs incurred by
Interwest Mining Company are absorbed by PacifiCorp, Bridger Coal Company and Energy West
Mining Company.
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: 107, 143, 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
2013/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 payments related to wages and benefits associated with transferred employees.
The convenience payments, the LTIP reimbursements and the reimbursements 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 and 923.
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.: 14 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.: 184, 501, 506, 535, 548, 549, 553,
557, 560, 561.2, 569.3, 580, 581, 590, 593, 597, 902, 903, 908 and 921.
Schedule Page: 429 Line No.: 24 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 Bridger Coal Company and Energy West
Mining Company.
Schedule Page: 429 Line No.: 29 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.: 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 Line No.: 31 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.: 32 Column: b
Complete name is MEHC Canada Transmission GP Corporation.
Schedule Page: 429 Line No.: 32 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
constitute “services” as required by this page.
Schedule Page: 429 Line No.: 33 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 $ 31,747,908
Right-of-way fees 53,297
$ 31,801,205
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.: 5 Column: c
Accounts charged for Wells Fargo & Company: 181, 186, 228.3, 419, 427, 431, 501, 557, 560,
588, 903, 921 and 928.
Schedule Page: 429.1 Line No.: 8 Column: b
This footnote applies to all occurrences of “International Business Machines Corp” on page
429. Complete name is International Business Machines Corporation.
Schedule Page: 429.1 Line No.: 8 Column: c
Accounts charged for International Business Machines Corp: 107, 165, 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
2013/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
INDEX
Schedule Page No.
Accrued and prepaid taxes ........................................................................ 262-263
Accumulated Deferred Income Taxes .................................................................... 234
272-277
Accumulated provisions for depreciation of
common utility plant ............................................................................. 356
utility plant .................................................................................... 219
utility plant (summary) ...................................................................... 200-201
Advances
from associated companies .................................................................... 256-257
Allowances ....................................................................................... 228-229
Amortization
miscellaneous .................................................................................... 340
of nuclear fuel .............................................................................. 202-203
Appropriations of Retained Earnings .............................................................. 118-119
Associated Companies
advances from ................................................................................ 256-257
corporations controlled by respondent ............................................................ 103
control over respondent .......................................................................... 102
interest on debt to .......................................................................... 256-257
Attestation ............................................................................................ i
Balance sheet
comparative .................................................................................. 110-113
notes to ..................................................................................... 122-123
Bonds ............................................................................................ 256-257
Capital Stock ........................................................................................ 251
expense .......................................................................................... 254
premiums ......................................................................................... 252
reacquired ....................................................................................... 251
subscribed ....................................................................................... 252
Cash flows, statement of ......................................................................... 120-121
Changes
important during year ........................................................................ 108-109
Construction
work in progress - common utility plant .......................................................... 356
work in progress - electric ...................................................................... 216
work in progress - other utility departments ................................................. 200-201
Control
corporations controlled by respondent ............................................................ 103
over respondent .................................................................................. 102
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)