2014Annual Report FERC Form.pdf

ROCKY MOUNTAIN
FIOWER
201 South Main, Suite 2300
Salt Lake City, Utah 84111
May 28,2015
VIA ELECTRONIC FILING
AND OWRNIGHT DELIWRY
Idaho Public Utilities Commission
472West Washington
Boise,ID 83702-5983
Attention: Jean D. Jewell
Commission Secretary
RE: FERC Form I
PacifiCorp (d.b.a. Rocky Mountain Power) submits for filing one copy of PacifiCorp's annual
FERC Form 1 report for the year ended December 31,2014.
PacifiCorp respectfully requests that all data requests regarding this matter be addressed to:
By email (preferred):
By regular mail:
datareq uest@pacifi corp. com
Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR97232
Please direct any informal questions to Ted Weston, Regulatory Manager, at [phone].
Sincerely,
url{yh V, . -J-,u^", l,r"-
Jeffrey K. Larien
Vice President, Regulation
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 11/30/2016)
(Expires 11/30/2016)
(Expires 11/30/2016)
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 2014/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
/ /
2014/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
/ /
2014/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
/ /
2014/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
/ /2014/Q4
Douglas K. Stuver, Senior Vice President and Chief Financial Officer
825 N.E. Multnomah Street, 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. In
March 2015, PacifiCorp reorganized its divisions to be comprised of Rocky Mountain Power, Pacific Power
and PacifiCorp Transmission.
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
2014/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
/ /2014/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)
Berkshire Hathaway Energy Company ("BHE") (100%)
PPW Holdings LLC (100% controlled by BHE)
PacifiCorp (100% of common stock held by PPW Holdings LLC)
(a) Berkshire Hathaway Inc. owns 89.9%, Walter Scott, Jr. (along with family members and related entities) owns 9.1% and Gregory E.
Abel owns 1.0% of BHE'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
/ /
2014/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 Energy West Mining Company
Mining 100 2 Fossil Rock Fuels, LLC
Mining 100 3 Glenrock Coal Company
Management Services 100 4 Interwest Mining Company
Management Services 100 5 Pacific Minerals, Inc.
Mining 66.67 6 Bridger Coal Company
Mining 21.40 7 Trapper Mining Inc.
Non-profit foundation 8 PacifiCorp Foundation
9
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
Energy West Mining Company provides coal-mining services to PacifiCorp utilizing
PacifiCorp's assets. Energy West Mining Company's costs are fully absorbed by PacifiCorp.
Schedule Page: 103 Line No.: 3 Column: a
Glenrock Coal Company ceased mining operations in October 1999.
Schedule Page: 103 Line No.: 5 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.: 6 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.: 7 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.: 8 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. As of December 31, 2014, 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
2014/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
/ /
2014/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.
Chairman of the Board of Directors 1
and Chief Executive Officer Gregory E. Abel 2
Senior Vice President and Chief Financial Officer 252,000Douglas K. Stuver 3
President and Chief Executive Officer, Pacific Power 320,000R. Patrick Reiten 4
President and Chief Executive Officer, PacifiCorp Energy 320,000Micheal G. Dunn 5
President and Chief Executive Officer, 6
Rocky Mountain Power 224,538Cindy A. Crane 7
Former President and Chief Executive Officer, 8
Rocky Mountain Power 379,034A. Richard Walje 9
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FERC FORM NO. 1 (ED. 12-96) Page 104
Schedule Page: 104 Line No.: 1 Column: c
PacifiCorp sets forth the salary information for its "named executive officers" for the
year ended December 31, 2014, 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.: 2 Column: b
Mr. Abel receives no direct compensation from PacifiCorp. PacifiCorp reimburses Berkshire
Hathaway Energy Company ("BHE")for the cost of Mr. Abel’s time spent on matters supporting
PacifiCorp, including compensation paid to him by BHE, pursuant to an intercompany
administrative services agreement among BHE and its subsidiaries. Please refer to BHE’s
Annual Report on Form 10-K for the year ended December 31, 2014 (File No. 001-14881) for
executive compensation information for Mr. Abel.
Schedule Page: 104 Line No.: 4 Column: b
R. Patrick Reiten was elected President and Chief Executive Officer of PacifiCorp
Transmission, a new division of PacifiCorp, effective March 10, 2015. Stefan A. Bird was
elected President and Chief Executive Officer of Pacific Power effective March 10, 2015.
Refer to Item 13 in Important Changes During the Quarter/Year of this Form 1.
Schedule Page: 104 Line No.: 5 Column: b
Micheal G. Dunn resigned as a director and employee of PacifiCorp effective March 2015.
Refer to Item 13 in Important Changes During the Quarter/Year of this Form 1.
Schedule Page: 104 Line No.: 7 Column: b
Cindy A. Crane was appointed President and Chief Executive Officer of Rocky Mountain
Power, a division of PacifiCorp, on November 1, 2014 and was elected to that position on
December 18, 2014. Refer to Item 13 in Important Changes During the Quarter/Year of this
Form 1.
Schedule Page: 104 Line No.: 9 Column: b
A. Richard Walje was appointed President and Chief Executive Officer of Gateway Projects,
PacifiCorp on November 1, 2014 and was elected to that position on December 18, 2014.
Refer to Item 13 in Important Changes During the Quarter/Year of this Form 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
2014/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
/ /
2014/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, 2014: 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
1407 West North Temple, Suite 270, Salt Lake City, Utah 84116(Former 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
Natalie L. Hocken 13
825 NE Multnomah, Suite 1600, Portland, Oregon 97232(SVP, Transmission and System Operations, PacifiCorp) 14
Mark C. Moench 15
201 South Main, Suite 2400, Salt Lake City, Utah 84111(SVP, General Counsel and Corporate Secretary, PacifiCorp) 16
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FERC FORM NO. 1 (ED. 12-95) Page 105
Schedule Page: 105 Line No.: 6 Column: a
A. Richard Walje resigned as a director effective November 2014. Refer to Item 13 in
Important Changes During the Quarter/Year of this Form 1.
Schedule Page: 105 Line No.: 9 Column: a
Brent E. Gale retired as a director and employee effective January 1, 2015. Refer to Item
13 in Important Changes During the Quarter/Year of this Form 1.
Schedule Page: 105 Line No.: 11 Column: a
Micheal G. Dunn resigned as a director and employee effective March 2015. Refer to Item 13
in Important Changes During the Quarter/Year of this Form 1.
Schedule Page: 105 Line No.: 15 Column: a
Mark C. Moench retired as a director and employee effective February 2014. Refer to Item
13 in Important Changes During the Quarter/Year of this Form 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
2014/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
/ /2014/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
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2014/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
04/01/201420140401-5215 ER14-1635 1
05/15/201420140515-5146 ER11-3643 2
07/23/201420140723-5137 ER11-3643 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 (Rev
Depreciation Rates 2014) to be effective 6/1/2014 under ER 14-1635
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
Supplement to May 15, 2014 Transmission Formula Rate Annual Update Informational Filing of
PacifiCorp under ER11-3643
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
2014/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
/ /2014/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 / /2014/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)
None
Oregon (3)
Creswell 01/16/2014 01/16/2024 5.0%
Rogue River 05/24/2014 05/24/2024 7.0%
Butte Falls 07/15/2014 07/15/2024 5.0%
Utah (5)
Juab County 03/07/2014 03/07/2034 -
Santaquin 05/28/2014 05/28/2029 -
Henefer 06/26/2014 06/26/2024 -
Lynndyl 06/26/2014 06/26/2029 -
Coalville 07/15/2014 07/15/2024 -
Wallsburg 10/23/2014 10/23/2034 -
Emery County 11/24/2014 11/24/2039 -
Leamington 12/02/2014 12/02/2039 -
Washington (5)
Asotin County 06/20/2014 06/20/2039 -
Walla Walla 09/18/2014 09/18/2034 -
Wyoming (4)
Shoshoni 03/25/2014 03/25/2039 2.0%
Worland 09/01/2014 09/01/2024 5.0%
(1) In California, franchise agreement fees are an expense to PacifiCorp and are embedded in rates.
(2) In Idaho, PacifiCorp collects franchise agreement fees from customers and remits them directly to the applicable municipalities.
(3) In Oregon, the first 3.5% of the franchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 3.5% is collected from
customers and remitted directly to the applicable municipalities.
(4) In Wyoming, the first 1.0% of the franchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 1.0% is collected
from customers and remitted directly to the applicable municipalities.
(5) In Utah and Washington, PacifiCorp collects associated taxes from customers and remits them directly to the applicable municipalities.
ITEM 2.
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
2014/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.1
ITEM 3.
In December 2014, PacifiCorp entered into asset purchase and sale agreements to sell certain Utah mining assets, which are
contingent upon regulatory approvals from certain state commissions. For further discussion, refer to Note 5 of Notes to Financial
Statements in this Form No. 1.
In October 2014, PacifiCorp and Idaho Power Company ("Idaho Power") executed a Joint Purchase and Sale Agreement under which
each party has agreed to transfer to the other party full or undivided joint ownership interests in specified transmission-related
equipment and facilities with an estimated net book value of approximately $43 million. The Joint Purchase and Sale Agreement also
provides for the termination and amendment of a number of legacy long-term transmission service agreements between PacifiCorp
and Idaho Power. Contemporaneously with the Joint Purchase and Sale Agreement, PacifiCorp and Idaho Power executed a Joint
Ownership and Operating Agreement applicable to the specified transmission-related equipment and facilities to be transferred. The
closing of the transfer of the transmission-related equipment and facilities, the effectiveness of the two executed agreements, and the
termination and amendment of the legacy long-term transmission service agreements are subject to approval by the Federal Energy
Regulatory Commission ("FERC"), the Oregon Public Utility Commission ("OPUC"), the Wyoming Public Service Commission
("WPSC"), the Idaho Public Utilities Commission ("IPUC"), the Washington Utilities and Transportation Commission ("WUTC") and
the California Public Utilities Commission. The required notice filing with the Utah Public Service Commission was submitted in
December 2014.
In September 2014, PacifiCorp entered into an agreement for the sale of the Fountain Green hydroelectric generating facility in
exchange for a transmission line corridor easement with the Utah Division of Wildlife Resources. The sale was approved by the
WPSC in Docket No. 20000-459-EA-14 and the OPUC in Docket No. UP 312, Order No. 15-071 in January 2015 and March 2015,
respectively. As a result of receiving the required regulatory approvals, PacifiCorp recorded the sale in account 102, Electric plant
purchased or sold, in March 2015.

ITEM 4.
In February 2005, PacifiCorp entered into a long-term firm natural gas transportation service agreement with Questar Gas Company
("Questar") to provide firm natural gas transportation service to the Lake Side generating facility ("Lake Side") and construct a natural
gas pipeline and facilities necessary to connect Lake Side to Questar's existing feeder line. PacifiCorp accounted for the agreement as
a capital lease. During 2011, PacifiCorp began construction of the 631-MW Lake Side 2 combined-cycle combustion turbine natural
gas-fueled generating facility ("Lake Side 2") adjacent to Lake Side, which was placed in service in May 2014. In February 2012,
PacifiCorp entered into a second long-term agreement with Questar to provide firm natural gas transportation service to Lake Side 2
and construct facilities to provide the additional natural gas transportation service. As a result of the construction of the additional
facilities, Questar is able to utilize the facilities to provide natural gas transportation service to customers other than PacifiCorp's Lake
Side generating facilities. In March 2014, Questar notified PacifiCorp that the construction of the additional facilities was
substantially complete and available for service. As a result of PacifiCorp entering into the second agreement with Questar and the
ability for others to benefit from Questar's facilities located near the Lake Side generating facilities, the February 2005 firm natural
gas transportation service agreement is no longer accounted for as a lease.
ITEM 5.
In April 2015, PacifiCorp and the California Independent System Operator Corporation ("California ISO") entered into a non-binding
memorandum of understanding to explore the feasibility, costs and benefits of PacifiCorp joining the California ISO as a participating
transmission owner. A comprehensive benefits study is underway and is expected to be completed this summer. Should PacifiCorp
decide to take additional steps to pursue joining the California ISO, a stakeholder input and review process would be initiated and
PacifiCorp would seek necessary regulatory approvals, including from its state regulatory commissions and the FERC.
PacifiCorp and the California ISO launched the regional energy imbalance market in November 2014, which allows PacifiCorp to
participate in the California ISO's real-time energy markets to most cost-effectively manage short-term fluctuations in energy supply
and demand. Joining the California ISO would extend that participation by PacifiCorp into the day-ahead energy market operated by
the California ISO, in addition to unified planning and operation of PacifiCorp's transmission network.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.2
ITEM 6.
Short-term Debt and Credit Facilities
Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. PacifiCorp had $20 million of short-term debt outstanding
as of December 31, 2014 at a weighted average interest rate of 0.43%.
Commission authorizations for up to $1.5 billion outstanding at any one time in commercial paper and other unsecured short-term
debt are as follows:
OPUC – Docket No. UF-4120, Order No. 98-158, dated April 16, 1998.
WUTC - Docket No. UE-980404, dated April 8, 1998.
IPUC - Case No. PAC-E-11-09, Order No. 32221, dated April 8, 2011, effective through April 30, 2016.
FERC - Docket No. ES14-5-000, dated November 26, 2013, letter order effective January 1, 2014 through December 31,
2015.
For further discussion, refer to Note 6 of Notes to Financial Statements in this Form No. 1.
Long-term Debt
In March 2014, PacifiCorp issued $425 million of its 3.60% First Mortgage Bonds due April 2024. The net proceeds were 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 in March 2014 to PPW Holdings LLC, a wholly owned subsidiary of Berkshire Hathaway
Energy Company, PacifiCorp's indirect parent company. The OPUC and the IPUC authorizations for this issuance were as follows:
OPUC – Docket No. UF-4262, Order No. 10-062, dated February 23, 2010.
IPUC – Case No. PAC-E-10-02, Order No. 31018, dated March 5, 2010.
PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $1.575 billion of long-term debt.
PacifiCorp must make a notice filing with the WUTC prior to any future issuance. State commission authorizations for future
issuances are as follows:
OPUC – Docket No. UF-4288, Order No. 14-268, dated July 22, 2014.
IPUC – Case No. PAC-E-14-05, Order No. 33083, dated July 29, 2014.
As of December 31, 2014, PacifiCorp had $451 million of letters of credit providing credit enhancement and liquidity support for
variable-rate tax-exempt bond obligations totaling $444 million plus interest. These letters of credit were fully available as of
December 31, 2014 and expire periodically through March 2017. 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,
2014, PacifiCorp estimated it would be able to issue up to $9.2 billion of new first mortgage bonds under the most restrictive issuance
test in the mortgage. Any issuances are subject to market conditions and amounts may be further limited by regulatory authorizations
or commitments or by covenants and tests contained in other financing agreements. PacifiCorp also has the ability to release property
from the lien of the mortgage on the basis of property additions, bond credits or deposits of cash.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.3
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.
ITEM 8.
For the year ended December 31, 2014, 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% 1/26/2014 $ 485,704
IBEW 57 Power Delivery (UT, ID & WY) 1.81% 1/26/2014 1,414,035
IBEW 57 Power Supply (UT, ID & WY) 1.86% 1/26/2014 731,827
IBEW 57 Combustion Turbine (UT) 2.23% 2/26/2014 68,816
IBEW 659 (OR, CA) 1.28% 4/26/2014 404,537
UWUA 197 (OR) 1.19% 5/26/2014 18,302
IBEW 57 Laramie (WY) 1.03% 6/26/2014 4,899
UWUA 127 (WY) 0.52% 9/26/2014 232,549
Total $ 3,360,669
(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, 2014 other than preferred and
common stock dividends declared and paid.
ITEM 11.
(Reserved.)
ITEM 12.
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
2014/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.4
ITEM 13.
Mark C. Moench retired as a director and employee effective February 2014.
Effective April 30, 2014, MidAmerican Energy Holdings Company was renamed Berkshire Hathaway Energy Company.
Cindy A. Crane was appointed President and Chief Executive Officer ("CEO"), Rocky Mountain Power, a division of PacifiCorp, on
November 1, 2014 and was elected to that position on December 18, 2014. A. Richard Walje, the former President and CEO of Rocky
Mountain Power, was appointed President and CEO, Gateway Projects, PacifiCorp on November 1, 2014 and was elected to that
position on December 18, 2014. Mr. Walje resigned as a director effective November 8, 2014.
Brent E. Gale retired as a director and employee effective December 31, 2014.
In March 2015, PacifiCorp reorganized its divisions to be comprised of Rocky Mountain Power, Pacific Power and PacifiCorp
Transmission. Stefan A. Bird was elected President and CEO of Pacific Power effective March 10, 2015. R. Patrick Reiten, the former
President and CEO of Pacific Power, was elected President and CEO of PacifiCorp Transmission effective March 10, 2015.
Ms. Crane, Mr. Bird and Andrea L. Kelly, Senior Vice President, Strategic Business Performance, were elected directors of
PacifiCorp effective March 10, 2015.
Michael G. Dunn resigned as a director and President and CEO of PacifiCorp Energy effective March 2015.
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
2014/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.5
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
PacifiCorp / /2014/Q4
UTILITY PLANT 1
26,026,444,483 24,810,145,362200-201Utility Plant (101-106, 114) 2
934,535,929 1,321,622,138200-201Construction Work in Progress (107) 3
26,960,980,412 26,131,767,500TOTAL Utility Plant (Enter Total of lines 2 and 3) 4
9,057,705,065 8,511,018,083200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5
17,903,275,347 17,620,749,417Net 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
17,903,275,347 17,620,749,417Net 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
13,345,624 14,388,489Nonutility Property (121) 18
2,556,976 2,937,770(Less) Accum. Prov. for Depr. and Amort. (122) 19
69,928 69,928Investments in Associated Companies (123) 20
227,471,078 210,924,059224-225Investment 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
83,174,506 82,248,215Other Investments (124) 24
0 0Sinking Funds (125) 25
0 0Depreciation Fund (126) 26
0 0Amortization Fund - Federal (127) 27
19,384,022 19,849,214Other Special Funds (128) 28
0 0Special Funds (Non Major Only) (129) 29
128,978 154,542Long-Term Portion of Derivative Assets (175) 30
0 0Long-Term Portion of Derivative Assets – Hedges (176) 31
341,017,160 324,696,677TOTAL 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
7,178,730 6,739,098Cash (131) 35
0 172,901Special Deposits (132-134) 36
0 0Working Fund (135) 37
6,297,596 44,824,535Temporary Cash Investments (136) 38
52,493 72,137Notes Receivable (141) 39
376,015,082 420,371,007Customer Accounts Receivable (142) 40
38,029,262 34,941,278Other Accounts Receivable (143) 41
7,018,317 8,008,893(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42
0 0Notes Receivable from Associated Companies (145) 43
152,259,841 6,608,556Accounts Receivable from Assoc. Companies (146) 44
198,515,639 240,980,677227Fuel Stock (151) 45
0 0227Fuel Stock Expenses Undistributed (152) 46
0 0227Residuals (Elec) and Extracted Products (153) 47
223,638,201 212,544,115227Plant 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 / /2014/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
54,470,840 48,954,180Prepayments (165) 57
0 0Advances for Gas (166-167) 58
0 14,382Interest and Dividends Receivable (171) 59
1,902,475 2,320,602Rents Receivable (172) 60
243,252,000 258,009,000Accrued Utility Revenues (173) 61
180,653 109,302Miscellaneous Current and Accrued Assets (174) 62
18,078,275 10,279,567Derivative Instrument Assets (175) 63
128,978 154,542(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
1,312,723,792 1,278,777,902Total Current and Accrued Assets (Lines 34 through 66) 67
DEFERRED DEBITS 68
34,036,382 33,721,944Unamortized Debt Expenses (181) 69
0 0230aExtraordinary Property Losses (182.1) 70
0 1,760,602230bUnrecovered Plant and Regulatory Study Costs (182.2) 71
1,589,995,081 1,373,975,244232Other Regulatory Assets (182.3) 72
3,103,498 3,615,224Prelim. 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
80,622 113,051Temporary Facilities (185) 77
110,913,409 90,972,267233Miscellaneous Deferred Debits (186) 78
0 0Def. Losses from Disposition of Utility Plt. (187) 79
0 0352-353Research, Devel. and Demonstration Expend. (188) 80
7,184,006 8,089,941Unamortized Loss on Reaquired Debt (189) 81
544,969,532 482,567,288234Accumulated Deferred Income Taxes (190) 82
0 0Unrecovered Purchased Gas Costs (191) 83
2,290,282,530 1,994,815,561Total Deferred Debits (lines 69 through 83) 84
21,847,298,829 21,219,039,557TOTAL ASSETS (lines 14-16, 32, 67, and 84) 85
FERC FORM NO. 1 (REV. 12-03) Page 111
Schedule Page: 110 Line No.: 44 Column: c
As of December 31, 2014, Account 146, Accounts receivable from associated companies,
included $139,681,803 of income taxes receivable from Berkshire Hathaway Energy 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Year/Period of ReportName of Respondent This Report is:
(1) An Original
(2) A Resubmission
x
Date of Report
(mo, da, yr)
end of
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
PacifiCorp / /2014/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
PROPRIETARY CAPITAL 1
3,417,945,8963,417,945,896Common Stock Issued (201) 2 250-251
2,397,6002,397,600Preferred 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
1,102,063,9561,102,063,956Other Paid-In Capital (208-211) 7 253
00Installments Received on Capital Stock (212) 8 252
00(Less) Discount on Capital Stock (213) 9 254
41,101,06141,101,061(Less) Capital Stock Expense (214) 10 254b
3,187,664,9833,145,875,690Retained Earnings (215, 215.1, 216) 11 118-119
127,661,628142,148,647Unappropriated Undistributed Subsidiary Earnings (216.1) 12 118-119
00(Less) Reaquired Capital Stock (217) 13 250-251
00 Noncorporate Proprietorship (Non-major only) (218) 14
-9,091,505-13,665,680Accumulated Other Comprehensive Income (219) 15 122(a)(b)
7,787,541,4977,755,665,048Total Proprietary Capital (lines 2 through 15) 16
LONG-TERM DEBT 17
6,842,300,0007,031,538,000Bonds (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
91,15280,126Unamortized Premium on Long-Term Debt (225) 22
13,958,23713,185,043(Less) Unamortized Discount on Long-Term Debt-Debit (226) 23
6,828,432,9157,018,433,083Total Long-Term Debt (lines 18 through 23) 24
OTHER NONCURRENT LIABILITIES 25
45,935,96131,882,690Obligations Under Capital Leases - Noncurrent (227) 26
00Accumulated Provision for Property Insurance (228.1) 27
59,307,72115,776,598Accumulated Provision for Injuries and Damages (228.2) 28
205,063,178324,459,642Accumulated Provision for Pensions and Benefits (228.3) 29
38,745,81037,861,624Accumulated Miscellaneous Operating Provisions (228.4) 30
01,879,732Accumulated Provision for Rate Refunds (229) 31
26,001,56935,217,373Long-Term Portion of Derivative Instrument Liabilities 32
00Long-Term Portion of Derivative Instrument Liabilities - Hedges 33
137,818,818134,721,631Asset Retirement Obligations (230) 34
512,873,057581,799,290Total Other Noncurrent Liabilities (lines 26 through 34) 35
CURRENT AND ACCRUED LIABILITIES 36
020,000,000Notes Payable (231) 37
472,746,697436,531,636Accounts Payable (232) 38
8,616,7190Notes Payable to Associated Companies (233) 39
42,517,163147,513,984Accounts Payable to Associated Companies (234) 40
36,794,11539,692,452Customer Deposits (235) 41
53,535,70239,025,536Taxes Accrued (236) 42 262-263
113,038,154113,861,896Interest Accrued (237) 43
40,47640,475Dividends 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 / /2014/Q4
(continued)COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
00Matured Interest (240) 46
19,668,64319,834,847Tax Collections Payable (241) 47
81,535,72869,093,393Miscellaneous Current and Accrued Liabilities (242) 48
2,772,4971,986,489Obligations Under Capital Leases-Current (243) 49
52,849,12875,193,965Derivative Instrument Liabilities (244) 50
26,001,56935,217,373(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
858,113,453927,557,300Total Current and Accrued Liabilities (lines 37 through 53) 54
DEFERRED CREDITS 55
24,877,48931,403,438Customer Advances for Construction (252) 56
32,306,32527,213,937Accumulated Deferred Investment Tax Credits (255) 57 266-267
00Deferred Gains from Disposition of Utility Plant (256) 58
308,485,444303,969,379Other Deferred Credits (253) 59 269
91,533,91471,012,945Other Regulatory Liabilities (254) 60 278
00Unamortized Gain on Reaquired Debt (257) 61
226,880,978252,151,842Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277
3,991,613,4124,244,780,923Accum. Deferred Income Taxes-Other Property (282) 63
556,381,073633,311,644Accum. Deferred Income Taxes-Other (283) 64
5,232,078,6355,563,844,108Total Deferred Credits (lines 56 through 64) 65
21,219,039,55721,847,298,829TOTAL 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: d
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 the interest rate on the outstanding borrowings was 0.25%.
Schedule Page: 112 Line No.: 42 Column: d
As of December 31, 2013, Account 236, Taxes accrued, included $18,691,010 of income taxes
payable to Berkshire Hathaway Energy 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
2014/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
/ /2014/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
5,267,001,125 5,153,186,543300-301Operating Revenues (400) 2
Operating Expenses 3
2,632,619,056 2,660,714,690320-323Operation Expenses (401) 4
437,565,258 423,183,559320-323Maintenance Expenses (402) 5
663,171,827 600,829,680336-337Depreciation Expense (403) 6
336-337Depreciation Expense for Asset Retirement Costs (403.1) 7
40,709,374 45,434,666336-337Amort. & Depl. of Utility Plant (404-405) 8
4,834,296 5,211,112336-337Amort. of Utility Plant Acq. Adj. (406) 9
1,760,602 2,365,947Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10
Amort. of Conversion Expenses (407) 11
415,224 294,983Regulatory Debits (407.3) 12
1,049,382(Less) Regulatory Credits (407.4) 13
171,415,396 169,647,183262-263Taxes Other Than Income Taxes (408.1) 14
-2,889,557 74,343,217262-263Income Taxes - Federal (409.1) 15
9,721,676 15,767,344262-263 - Other (409.1) 16
1,071,119,870 826,690,640234, 272-277Provision for Deferred Income Taxes (410.1) 17
760,877,449 625,812,453234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.1) 18
-5,019,198 -1,812,064266Investment 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
1,117 26,460(Less) Gains from Disposition of Allowances (411.8) 22
Losses from Disposition of Allowances (411.9) 23
Accretion Expense (411.10) 24
4,263,495,876 4,196,895,425TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25
1,003,505,249 956,291,118Net 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
/ /2014/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
5,267,001,125 5,153,186,543 2
3
2,632,619,056 2,660,714,690 4
437,565,258 423,183,559 5
663,171,827 600,829,680 6
7
40,709,374 45,434,666 8
4,834,296 5,211,112 9
1,760,602 2,365,947 10
11
415,224 294,983 12
1,049,382 13
171,415,396 169,647,183 14
-2,889,557 74,343,217 15
9,721,676 15,767,344 16
1,071,119,870 826,690,640 17
760,877,449 625,812,453 18
-5,019,198 -1,812,064 19
20
63,381 21
1,117 26,460 22
23
24
4,263,495,876 4,196,895,425 25
1,003,505,249 956,291,118 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
/ /2014/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)
1,003,505,249 956,291,118Net Utility Operating Income (Carried forward from page 114) 27
Other Income and Deductions 28
Other Income 29
Nonutilty Operating Income 30
1,742,323 1,154,351Revenues From Merchandising, Jobbing and Contract Work (415) 31
1,612,424 1,395,781(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32
389,833Revenues From Nonutility Operations (417) 33
46,644 127,665(Less) Expenses of Nonutility Operations (417.1) 34
164,280 122,658Nonoperating Rental Income (418) 35
14,581,067 13,397,403119Equity in Earnings of Subsidiary Companies (418.1) 36
7,738,789 5,541,076Interest and Dividend Income (419) 37
50,655,904 57,244,026Allowance for Other Funds Used During Construction (419.1) 38
353,146 1,000,254Miscellaneous Nonoperating Income (421) 39
224,256 306,494Gain on Disposition of Property (421.1) 40
73,800,697 77,632,649TOTAL Other Income (Enter Total of lines 31 thru 40) 41
Other Income Deductions 42
11,056 342,145Loss on Disposition of Property (421.2) 43
1,342,957 1,298,969Miscellaneous Amortization (425) 44
2,522,386 2,516,950 Donations (426.1) 45
-6,393,772 -4,817,326 Life Insurance (426.2) 46
1,814,037 2,337,066 Penalties (426.3) 47
2,583,944 1,763,417 Exp. for Certain Civic, Political & Related Activities (426.4) 48
37,428,313 3,789,575 Other Deductions (426.5) 49
39,308,921 7,230,796TOTAL Other Income Deductions (Total of lines 43 thru 49) 50
Taxes Applic. to Other Income and Deductions 51
203,109 345,622262-263Taxes Other Than Income Taxes (408.2) 52
-6,629,160 -2,396,204262-263Income Taxes-Federal (409.2) 53
-900,793 -325,603262-263Income Taxes-Other (409.2) 54
102,052,978 70,283,900234, 272-277Provision for Deferred Inc. Taxes (410.2) 55
105,466,318 67,854,963234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.2) 56
Investment Tax Credit Adj.-Net (411.5) 57
691,070 928,426(Less) Investment Tax Credits (420) 58
-11,431,254 -875,674TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59
45,923,030 71,277,527Net Other Income and Deductions (Total of lines 41, 50, 59) 60
Interest Charges 61
358,380,033 355,945,454Interest on Long-Term Debt (427) 62
4,073,420 3,888,848Amort. of Debt Disc. and Expense (428) 63
905,935 1,421,460Amortization of Loss on Reaquired Debt (428.1) 64
11,026 11,027(Less) Amort. of Premium on Debt-Credit (429) 65
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 66
2,512 24,397Interest on Debt to Assoc. Companies (430) 67
13,513,332 13,394,876Other Interest Expense (431) 68
25,295,555 29,258,693(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69
351,568,651 345,405,315Net Interest Charges (Total of lines 62 thru 69) 70
697,859,628 682,163,330Income 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
697,859,628 682,163,330Net 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, 2014 and 2013, depreciation expense associated with transportation
equipment was $13,767,456 and $15,921,062, 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, 2014 and 2013, payroll taxes were
$40,126,082 and $39,811,382, respectively.
Schedule Page: 114 Line No.: 24 Column: c
Generally, PacifiCorp records the accretion expense of asset retirement obligations as
either a regulatory asset or liability.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
/ /
2014/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)
2,974,333,637 3,180,100,349 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)
668,765,927 683,278,561 16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
( 2,762,978) -3,096,169215.1 18 Appropriation of excess earnings at certain hydroelectric generating facilities
19
20
21
( 2,762,978) -3,096,169 22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
( 1,493,811) -161,902238 24 Preferred Stock, various series and rates
25
26
27
28
( 1,493,811) -161,902 29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
( 500,000,000) -725,000,000238 31 Common Stock
32
33
34
35
( 500,000,000) -725,000,000 36 TOTAL Dividends Declared-Common Stock (Acct. 438)
43,034,828 94,048216.1 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
3,180,100,349 3,135,214,887 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
/ /
2014/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)
7,564,634 10,660,803 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
7,564,634 10,660,803 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
3,187,664,983 3,145,875,690 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
157,299,053 127,661,628 49 Balance-Beginning of Year (Debit or Credit)
13,397,403 14,581,067 50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
( 43,034,828) -94,048 52 Transfers to/from Unappropriated Retained Earnings (Account 216)
127,661,628 142,148,647 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, 2014 and dividends on preferred
stock during the year ended December 31, 2014 were as follows:

Shares Dividend
6.00% Serial Preferred 5,930 $ 35,580
7.00% Serial Preferred 18,046 126,322
23,976 $ 161,902
Schedule Page: 118 Line No.: 24 Column: d
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.: 37 Column: c
In September 2014, Trapper Mining Inc., a subsidiary of PacifiCorp, paid a dividend of
$94,048 to PacifiCorp.
Schedule Page: 118 Line No.: 37 Column: d
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.: 46 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.: 46 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
2014/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
/ /2014/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:
682,163,330 697,859,628 2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
623,158,412 678,784,159 4 Depreciation and Depletion
52,239,730 46,983,824 5 Amortization:
6
7
203,307,124 306,829,081 8 Deferred Income Taxes (Net)
-2,740,490 -5,710,268 9 Investment Tax Credit Adjustment (Net)
-10,007,750 9,327,709 10 Net (Increase) Decrease in Receivables
14,591,039 31,370,952 11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
30,795,829 10,273,904 13 Net Increase (Decrease) in Payables and Accrued Expenses
-23,882,915 -95,045,998 14 Net (Increase) Decrease in Other Regulatory Assets
-8,253,088 -10,169,717 15 Net Increase (Decrease) in Other Regulatory Liabilities
57,244,026 50,655,904 16 (Less) Allowance for Other Funds Used During Construction
-29,637,425 14,487,019 17 (Less) Undistributed Earnings from Subsidiary Companies
-33,476,313 -54,351,514 18 Amounts Due To/From Affiliates (Net)
42,900,000 -16,500,000 19 Derivative Collateral (Net)
21,056,199 21,671,928 20 Other Operating Acitivities:
21
1,564,244,506 1,556,180,765 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):
-1,119,674,872 -1,115,501,291 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
-57,244,026 -50,655,904 30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33
-1,062,430,846 -1,064,845,387 34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
277,539 1,069,188 37 Proceeds from Disposal of Noncurrent Assets (d)
38
-1,499,000 -2,060,000 39 Investments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
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
/ /2014/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
6,064,789 1,624,874 53 Other Investing Activities:
54
55
56 Net Cash Provided by (Used in) Investing Activities
-1,057,587,518 -1,064,211,325 57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
299,100,000 424,745,000 61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
19,999,528 66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68
69
299,100,000 444,744,528 70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
-277,729,000 -235,762,000 73 Long-term Debt (b)
-40,095,281 74 Preferred Stock
75 Common Stock
-6,831,840 -12,032,497 76 Other (provide details in footnote):
-6,407,670 -1,844,876 77 Repayment of Capital Lease Obligations
78 Net Decrease in Short-Term Debt (c)
79
-1,965,797 -161,902 80 Dividends on Preferred Stock
-500,000,000 -725,000,000 81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
-533,929,588 -530,056,747 83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
-27,272,600 -38,087,307 86 (Total of lines 22,57 and 83)
87
78,836,233 51,563,633 88 Cash and Cash Equivalents at Beginning of Period
89
51,563,633 13,476,326 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 $15,612,332 and $22,328,732 during the years ended December 31, 2014 and 2013,
respectively.
Schedule Page: 120 Line No.: 5 Column: a
Years Ended December 31,
2014 2013
Amortization of software development & other intangibles $ 42,052,331 $ 46,733,635
Amortization of electric plant acquisition adjustments 4,834,296 5,211,112
Amortization of regulatory assets 97,197 294,983
$ 46,983,824 $ 52,239,730
Schedule Page: 120 Line No.: 20 Column: a
Years Ended December 31,
2014 2013
Depreciation and depletion included in cost of fuel $ 24,247,414 $ 12,456,145
Net(gain)/loss on sale of property (310,850) 22,871
Write-off of assets under construction 362,850 10,483,484
Change in corporate owned life insurance cash surrender
value (6,374,744) (4,880,695)
Amortization of debt issuance expenses and bond
discount/premium 4,062,394 3,877,821
Other (315,136) (903,427)
$ 21,671,928 $ 21,056,199
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,
2014 2013
Other investments/special funds $ 1,174,723 $ 5,949,345
Temporary facilities 32,429 (66,153)
Restricted cash 417,722 181,597
$ 1,624,874 $ 6,064,789
Schedule Page: 120 Line No.: 76 Column: a
Years Ended December 31,
2014 2013 _
Net repayments of affiliate borrowing from subsidiary
company, Pacific Minerals, Inc. $( 8,615,195) $ (2,492,611)
Long-term debt issuance and other deferred financing costs__(3,417,302) (4,339,229)
$(12,032,497) $ (6,831,840)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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 / /2014/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 Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des Moines, Iowa that owns subsidiaries
principally engaged in energy businesses. BHE 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.
Interest and penalties on income taxes for GAAP are classified as income tax expense. All such amounts are classified as interest
income, interest expense and penalties under the FERC accounting and reporting standards.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.1
Reclassifications
Certain other reclassifications of balance sheet, income statement and cash flow amounts have been made in order to conform
to the FERC basis of presentation. These reclassifications had no effect on net income.
Use of Estimates in Preparation of Financial Statements
The preparation of the financial statements in conformity with the FERC and 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
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
2014/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):
2014 2013
Cash (131)$7 $7
Temporary cash investments (136)6 45
Total cash and cash equivalents $13 $52
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, 2014 and 2013, 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):
2014 2013
Beginning balance $ 8 $ 9
Charged to operating costs and expenses, net 11 13
Write-offs, net (12) (14)
Ending balance $7 $8
Derivatives
PacifiCorp employs a number of different derivative contracts, which may include 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 FERC and 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
2014/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 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 represent 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 and unbilled amounts.
As of December 31, 2014 and 2013, unbilled revenue was $243 million and $258 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
2014/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
$446 million and $461 million as of December 31, 2014 and 2013, respectively, and regulatory liabilities of $13 million and $21
million as of December 31, 2014 and 2013, respectively, and will be included in rates when the temporary differences reverse. Other
changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income
tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense 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 to be 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
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.5
New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, which
creates FASB Accounting Standards Codification ("ASC") Topic 606, "Revenue from Contracts with Customers" and supersedes ASC
Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to
identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control
of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in
exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative
information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the
significant judgments and estimates used in recognizing revenues from contracts with customers. This guidance is effective for interim
and annual reporting periods beginning after December 15, 2016. Early application is not permitted. This guidance may be adopted
retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application.
PacifiCorp is currently evaluating the impact of adopting this guidance on its financial statements and disclosures included within
Notes to Financial Statements.
In February 2013, the FASB issued ASU No. 2013-04, which amends FASB 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. 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.
Subsequent Events
PacifiCorp has evaluated the impact of events occurring after December 31, 2014 up to February 27, 2015, the date that PacifiCorp’s
GAAP financial statements were filed with the Securities and Exchange Commission and has updated such evaluation for disclosure
purposes through April 17, 2015. These financial statements include all necessary adjustments and disclosures resulting from these
evaluations.
(3) Net Utility Plant
The average depreciation and amortization rate applied to depreciable utility plant was 3.0% for the year ended December 31, 2014
and 2.8% for the year ended December 31, 2013.
Depreciation Study
As a result of PacifiCorp's depreciation study approved by its state regulatory commissions, PacifiCorp revised its depreciation rates
effective January 1, 2014. The approved depreciation rates resulted in an increase in depreciation expense of $35 million for the year
ended December 31, 2014 as compared to the year ended December 31, 2013.
(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
2014/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, 2014
(dollars in millions):
Facility Accumulated Construction
PacifiCorp in
Depreciation
and Work-in-
Share Service Amortization Progress
Jim Bridger Nos. 1 - 4 67% $ 1,134 $ 549 $ 116
Hunter No. 1 94 467 141 —
Hunter No. 2 60 290 86 1
Wyodak 80 450 178 5
Colstrip Nos. 3 and 4 10 231 127 1
Hermiston 50 175 66 1
Craig Nos. 1 and 2 19 323 206 7
Hayden No. 1 25 55 28 12
Hayden No. 2 13 33 18 3
Foote Creek 79 37 23 —
Transmission and distribution facilities Various 347 79 —
Total $3,542 $1,501 $146
(5) Regulatory Matters
Utah Mine Disposition
Due to quality issues with the coal reserves at PacifiCorp's Deer Creek mine in Utah and rising costs at PacifiCorp's wholly owned
subsidiary, Energy West Mining Company, PacifiCorp believes the Deer Creek coal reserves are no longer able to be economically
mined. As a result, in December 2014, PacifiCorp filed applications with the Utah Public Service Commission, the Oregon Public
Utility Commission ("OPUC"), the Wyoming Public Service Commission and the Idaho Public Utilities Commission ("IPUC") seeking
certain approvals, prudence determinations and accounting orders to close its Deer Creek mining operations, sell certain Utah mining
assets, enter into a replacement coal supply agreement, amend an existing coal supply agreement, withdraw from the United Mine
Workers of America ("UMWA") 1974 Pension Trust and settle PacifiCorp's other postretirement benefit obligation for UMWA
participants (collectively, the "Utah Mine Disposition"). PacifiCorp also filed an advice letter with the California Public Utilities
Commission ("CPUC"). The asset sales and coal supply agreements are contingent upon regulatory approvals for which orders are
expected to be issued in the second quarter of 2015. PacifiCorp expects to transfer funds from its other postretirement plan assets to
the UMWA in June 2015 to effectuate the settlement of the portion of the obligation related to UMWA participants.
Regulatory Assets
PacifiCorp had regulatory assets not earning a return on investment of $1.479 billion and $1.244 billion as of December 31, 2014 and
2013, 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
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.7
(6) Short-term Debt and Other Financing Agreements
The following table summarizes PacifiCorp's availability under its credit facilities as of December 31 (in millions):
2014:
Credit facilities $ 1,200
Less:
Short-term debt (20)
Letters of credit and tax-exempt bond support (398)
Net credit facilities $782
2013:
Credit facilities $ 1,200
Less:
Short-term debt —
Letters of credit and tax-exempt bond support (321)
Net credit facilities $879
PacifiCorp has a $600 million unsecured credit facility expiring in June 2017 and a $600 million unsecured credit facility expiring in
March 2018. 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. As of December 31, 2014, the weighted average interest rate on commercial paper borrowings outstanding was 0.43%.
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, 2014, PacifiCorp was in compliance with the covenants of its
credit facilities.
As of December 31, 2014 and 2013, PacifiCorp had $451 million and $559 million, respectively, of fully available letters of credit
issued under committed arrangements, of which $270 million as of December 31, 2014 and 2013 were issued under the credit
facilities. These letters of credit support PacifiCorp's variable-rate tax-exempt bond obligations and expire through March 2017.
As of December 31, 2014, 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, 2014
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 its 3.60% First Mortgage Bonds due April 2024. The net proceeds were 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 in March 2014 to PPW Holdings LLC, a wholly owned subsidiary of BHE and PacifiCorp's
direct parent company ("PPW Holdings").
PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $1.575 billion of long-term debt.
PacifiCorp must make a notice filing with the Washington Utilities and Transportation Commission prior to any future issuance.
PacifiCorp currently has an effective shelf registration statement filed with the United States Securities and Exchange Commission
expected to provide for future first mortgage bond issuances through October 2016.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.8
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's
mortgage. Approximately $25 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage
as of December 31, 2014.
PacifiCorp has entered into long-term agreements that qualify as capital leases and expire at various dates through March 2035 for
transportation services, power purchase agreements and real estate. The transportation services agreements included as capital leases
are for the right to use pipeline facilities to provide natural gas to two of PacifiCorp's generating facilities. Net capital lease assets of
$34 million and $49 million as of December 31, 2014 and 2013, respectively, were included in net utility plant in the Comparative
Balance Sheet.
As of December 31, 2014, the annual maturities of long-term debt and capital lease obligations, excluding unamortized discounts and
including interest on capital lease obligations, for 2015 and thereafter are as follows (in millions):
Long-term Capital Lease
Debt Obligations Total
2015 $ 132 $ 5 $ 137
2016 57 5 62
2017 52 10 62
2018 586 6 592
2019 350 5 355
Thereafter 5,855 31 5,886
Total 7,032 62 7,094
Unamortized discount (13)—(13)
Amounts representing interest —(28)(28)
Total $7,019 $34 $7,053
(8) Income Taxes
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2014 2013
Current:
Federal $ (10) $ 72
State 9 16
Total (1)88
Deferred:
Federal 264 177
State 43 26
Total 307 203
Investment tax credits (6) (3)
Total income tax expense $300 $288
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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:
2014 2013
Federal statutory income tax rate 35% 35%
State income taxes, net of federal income tax benefit 3 3
Federal income tax credits(1)(7)(7)
Other (1)(1)
Effective income tax rate 30%30%
(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):
2014 2013
Deferred income tax assets:
Employee benefits $ 183 $ 99
Derivative contracts and unamortized contract values 79 76
State carryforwards 68 68
Loss contingencies 51 67
Asset retirement obligations 47 48
Regulatory liabilities 29 36
Other 88 89
545 483
Deferred income tax liabilities:
Property, plant and equipment (4,497) (4,219)
Regulatory assets (611) (526)
Other (22)(30)
(5,130)(4,775)
Net deferred income tax liability $(4,585)$(4,292)
The following table provides PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31,
2014 (in millions):
State
Net operating loss carryforwards $ 1,417
Deferred income taxes on net operating loss carryforwards $ 52
Expiration dates 2015 - 2032
Tax credit carryforwards $ 16
Expiration dates 2015 - 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
2014/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, 2006, except
for the December 31, 1995 and 1997 tax years in Utah and the March 31, 2004, 2005 and 2006 tax years in Colorado and 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 and froze future accruals for active participants
as of December 31, 2014. 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.
Utah Mine Disposition and Labor Agreement
In conjunction with the Utah Mine Disposition described in Note 5, in December 2014, Energy West Mining Company reached a labor
settlement with the UMWA covering union employees at PacifiCorp's Deer Creek mining operations. As a result of the labor
settlement, the UMWA agreed to assume PacifiCorp's other postretirement benefit obligation associated with UMWA plan participants
in exchange for PacifiCorp transferring $150 million to the UMWA. Transfer of the assets to the UMWA and settlement of this
obligation is expected to occur in June 2015, which will result in a remeasurement of the other postretirement plan assets and benefit
obligation. No curtailment accounting will be triggered as a result of the settlement due to an insignificant impact to the average
remaining service lives in the plan.
As a result of the intended closure of the Deer Creek mining operations, withdrawal by Energy West Mining Company from the
UMWA 1974 Pension Trust could be triggered as early as spring 2015. Refer to "Multiemployer and Joint Trustee Pension Plans"
below for further information regarding the withdrawal.
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.11
Net periodic benefit cost for the plans included the following components for the years ended December 31 (in millions):
Pension Other Postretirement
2014 2013 2014 2013
Service cost
$ 5 $ 6 $ 6 $ 9
Interest cost 57 54 28 25
Expected return on plan assets (76) (74) (31) (30)
Net amortization 29 48 2 8
Net periodic benefit cost $15 $34 $5 $12
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
2014 2013 2014 2013
Plan assets at fair value, beginning of year $ 1,171 $ 1,012 $ 486 $ 424
Employer contributions 10 63 1 8
Participant contributions — — 7 7
Actual return on plan assets 53 213 25 86
Benefits paid (88) (117) (37) (39)
Plan assets at fair value, end of year $1,146 $1,171 $482 $486
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
Pension Other Postretirement
2014 2013 2014 2013
Benefit obligation, beginning of year $ 1,230 $ 1,391 $ 598 $ 632
Service cost 5 6 6 9
Interest cost 57 54 28 25
Participant contributions ——7 7
Actuarial loss (gain)174 (104)(63)(36)
Benefits paid (88)(117)(37)(39)
Benefit obligation, end of year $1,378 $1,230 $539 $598
Accumulated benefit obligation, end of year $1,378 $1,229
The actuarial gain associated with the other postretirement benefit obligation during the year ended December 31, 2014 includes a gain
that reduced the benefit obligation resulting from the $150 million to be transferred to the UMWA in June 2015 as a result of the
contractually binding labor settlement.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.12
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
2014 2013 2014 2013
Plan assets at fair value, end of year $ 1,146 $ 1,171 $ 482 $ 486
Less - Benefit obligation, end of year 1,378 1,230 539 598
Funded status $(232)$(59)$(57)$(112)
Amounts recognized on the Comparative Balance Sheet:
Miscellaneous current and accrued liabilities $ (4) $ (4) $ — $ —
Accumulated provision for pensions and benefits (228)(55)(57)(112)
Amounts recognized $(232)$(59)$(57)$(112)
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
$51 million and $48 million as of December 31, 2014 and 2013, respectively. These assets are not included in the plan assets in the
above table, but are reflected in other investments on the Comparative Balance Sheet.
Unrecognized Amounts
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in
millions):
Pension Other Postretirement
2014 2013 2014 2013
Net loss $ 520 $ 361 $ 41 $ 108
Prior service credit (21) (29) (26) (33)
Regulatory deferrals
(3) (4) 2 2
Total $496 $328 $17 $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
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.13
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2014
and 2013 is as follows (in millions):
Accumulated
Other
Regulatory Comprehensive
Asset Loss Total
Pension
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
Net loss arising during the year 189 8 197
Net amortization (28)(1)(29)
Total 161 7 168
Balance, December 31, 2014 $474 $22 $496
Regulatory
Asset
Other Postretirement
Balance, December 31, 2012 $177
Net gain arising during the year (92)
Net amortization (8)
Total (100)
Balance, December 31, 2013 77
Net gain arising during the year (58)
Net amortization (2)
Total (60)
Balance, December 31, 2014 $17
The net loss, prior service credit and regulatory deferrals that will be amortized in 2015 into net periodic benefit cost are estimated to
be as follows (in millions):
Net Prior Service Regulatory
Loss Credit Deferrals Total
Pension $50 $(8) $(1) $ 41
Other postretirement 2 (7)1 (4)
Total $52 $(15)$—$37
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.14
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
Pension Other Postretirement
2014 2013 2014 2013
Benefit obligations as of December 31:
Discount rate 4.00% 4.80% 3.90% 4.90%
Rate of compensation increase 2.75 3.00 N/A N/A
Net periodic benefit cost for the years ended December 31:
Discount rate 4.80% 4.05% 4.90% 4.10%
Expected return on plan assets 7.50 7.50 7.50 7.50
Rate of compensation increase 3.00 3.00 N/A N/A
In establishing its assumption as to the expected return on plan assets, PacifiCorp utilizes the asset allocation and return assumptions
for each asset class based on forward-looking views of the financial markets and historical performance.
2014 2013
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 2025 2019
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 for the year ended December 31, 2014 $3 $(2)
Other postretirement benefit obligation as of December 31, 2014 ——
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $- million, respectively,
during 2015. 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, subject to tax deductibility limitations and other considerations.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.15
The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2015 through 2019
and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Pension Other Postretirement
2015 $ 106 $ 184
2016 111 29
2017 108 28
2018 107 28
2019 109 27
2020 - 2024 465 126
Projected benefit payments for the other postretirement plan in 2015 include the $150 million to be transferred to the UMWA in
June 2015 as a result of the contractually binding labor settlement with the UMWA.
Plan Assets
Investment Policy and Asset Allocations
PacifiCorp's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified
portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets
consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments within the parameters
outlined by the PacifiCorp Pension Committee. The investment portfolio is managed in line with the investment policy with sufficient
liquidity to meet near-term benefit payments.
The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows as
of December 31, 2014:
Pension(1)Other Postretirement(1)
% %
Debt securities(2)33 - 37 33 - 37
Equity securities(2)53 - 57 61 - 65
Limited partnership interests 8 - 12 1 - 3
Other 0 - 1 0 - 1
(1) PacifiCorp's Retirement Plan trust includes a separate account that is used to fund benefits for the other postretirement benefit plan. In addition to this
separate account, the assets for the other postretirement benefit 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
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.16
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, 2014
Cash equivalents $— $8 $— $8
Debt securities:
United States government obligations 15 ——15
Corporate obligations —53 —53
Municipal obligations —8 —8
Agency, asset and mortgage-backed obligations —48 —48
Equity securities:
United States companies 488 ——488
International companies 16 ——16
Investment funds(2)217 223 —440
Limited partnership interests(3)— — 70 70
Total $736 $340 $70 $1,146
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 $1,171
(1) Refer to Note 12 for additional discussion regarding the three levels of the fair value hierarchy.
(2) Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately
50% and 50%, respectively, for 2014 and 2013, and are invested in United States and international securities of approximately 43% and 57%, respectively,
for 2014 and 42% and 58%, respectively, for 2013.
(3) Limited partnership interests include several funds that invest primarily in buyout, growth equity, venture capital and real estate.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.17
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit other postretirement plan
(in millions):
Input Levels for Fair Value Measurements
Level 1(1)Level 2(1)Level 3(1)Total
As of December 31, 2014
Cash and cash equivalents(2)$ 139 $— $— $ 139
Debt securities:
United States government obligations 8 ——8
Corporate obligations —18 —18
Municipal obligations —2 —2
Agency, asset and mortgage-backed obligations —16 —16
Equity securities:
United States companies 112 ——112
International companies 4 ——4
Investment funds(3)84 94 —178
Limited partnership interests(4)— — 5 5
Total $347 $130 $5 $482
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(3)173 120 —293
Limited partnership interests(4)— — 6 6
Total $350 $130 $6 $486
(1) Refer to Note 12 for additional discussion regarding the three levels of the fair value hierarchy.
(2) In December 2014, PacifiCorp began to migrate funds to cash and cash equivalents in anticipation of the $150 million to be transferred to the UMWA in
June 2015 as a result of the other postretirement settlement. Remaining investments were rebalanced to align to target investment allocations.
(3) Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately
63% and 37%, respectively, for 2014 and 49% and 51%, respectively, for 2013, and are invested in United States and international securities of
approximately 64% and 36%, respectively, for 2014 and 70% and 30%, respectively, for 2013.
(4) 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
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.18
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, 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
Actual return on plan assets still held at December 31, 2014 (1) —
Purchases, sales, distributions and settlements (15)(1)
Balance, December 31, 2014 $70 $5
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 its
subsidiary, Energy West Mining Company, contributes to the UMWA 1974 Pension Trust (plan number 002). Contributions to these
pension plans are based on the terms of collective bargaining agreements.
As a result of the Utah Mine Disposition and UMWA labor settlement, PacifiCorp believes withdrawal by its subsidiary, Energy West
Mining Company, from the UMWA 1974 Pension Trust is probable. As a result, the estimated withdrawal obligation was recorded in
December 2014 and a regulatory asset established for the portion of the obligation considered probable of recovery. The most recent
estimate of the withdrawal obligation provided by the UMWA 1974 Pension Trust is $97 million for a withdrawal occurring by July 1,
2015. In the event of withdrawal, Energy West Mining Company may elect to make a lump sum payment or annual installment
payments to settle the withdrawal obligation. PacifiCorp is seeking recovery of the withdrawal obligation from its customers as part of
the regulatory filings associated with the Utah Mine Disposition.
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. This is expected to occur upon Energy West Mining
Company's withdrawal from the UMWA 1974 Pension Trust. If participating employers withdraw from a multiemployer 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.19
The following table presents PacifiCorp's and Energy West Mining Company's participation in individually significant joint trustee and
multiemployer pension plans for the years ended December 31 (dollars in millions):
PPA zone status or planfunded status percentage forplan years beginning July 1,Contributions(1)
Plan name
Employer
Identification
Number 2014 2013
Funding
improvement
plan
Surcharge
imposed
under PPA 2014 2013
Year contributions to plan
exceeded more than 5% of
total contributions(2)
UMWA
Pension
Plan
52-1050282 Critical Seriously
Endangered
Implemented Yes $2 $3 None
Local 57
Trust Fund 87-0640888 At least 80% At least 80% None None $ 9 $ 9 2013, 2012
(1) PacifiCorp's and Energy West Mining Company'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 1974 Pension Trust, respectively, subject to
ERISA minimum funding requirements. As a result of the plan's critical status, Energy West Mining Company was required to begin paying a surcharge for
hours worked on and after December 1, 2014.
(2) For the UMWA 1974 Pension Trust, information is for plan year beginning July 1, 2012. Information for the plan years beginning July 1, 2014 is not yet
available. For the Local 57 Trust Fund, information is for plan years beginning July 1, 2013 and 2012. Information for the plan year beginning July 1, 2014
is not yet available.
The current collective bargaining agreements governing the Local 57 Trust Fund expire in January 2016. The current collective
bargaining agreement governing the UMWA 1974 Pension Trust expires in June 2016.
Defined Contribution Plan
PacifiCorp's 401(k) Plan covers 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 $34
million and $35 million for the years ended December 31, 2014 and 2013, 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 changes in laws and regulations,
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 $873
million and $843 million as of December 31, 2014 and 2013, 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
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.20
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31
(in millions):
2014 2013
Beginning balance $ 138 $ 127
Change in estimated costs (3) 3
Additions — 8
Retirements (6) (6)
Accretion 6 6
Ending balance $135 $138
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.
In December 2014, the Environmental Protection Agency released its final rule regulating the management and disposal of coal
combustion byproducts resulting from the operation of coal-fueled generating facilities, including requirements for the operation and
closure of surface impoundment and ash landfill facilities. The final rule will be effective 180 days after it is published in the Federal
Register. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts may need to be closed
unless they can meet the more stringent regulatory requirements. PacifiCorp is currently evaluating the requirements and costs of the
new rule and cannot determine the impact on its ARO liabilities at this time.
(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
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.21
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 FERC and 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, 2014
Not designated as hedging contracts(1):
Commodity assets $ 28 $ — $ 1 $ — $ 29
Commodity liabilities (10)— (55) (49)(114)
Total 18 —(54)(49)(85)
Total derivatives 18 — (54) (49) (85)
Cash collateral receivable — — 14 14 28
Total derivatives - net basis $18 $—$(40)$(35)$(57)
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)
(1) PacifiCorp's commodity derivatives are generally included in rates and as of December 31, 2014 and 2013, a regulatory asset of $85 million and
$55 million, respectively, was recorded related to the net derivative liability of $85 million and $55 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):
2014 2013
Beginning balance $ 55 $ 121
Changes in fair value recognized in regulatory assets 45 15
Net (losses) gains reclassified to operating revenue (4) 9
Net losses reclassified to energy costs (11) (90)
Ending balance $85 $55
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.22
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 2014 2013
Electricity sales Megawatt hours (1) (1)
Natural gas purchases Decatherms 113 120
Fuel oil purchases Gallons 3 15
Credit Risk
PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities,
energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent
PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among
the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale
counterparty, 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 further mitigate wholesale counterparty credit risk, 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. 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, 2014, 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 $113 million and $68 million as of December 31, 2014 and 2013, respectively, for which PacifiCorp had posted collateral of
$28 million and $12 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative
contracts in liability positions had been triggered as of December 31, 2014 and 2013, PacifiCorp would have been required to post
$75 million and $51 million, respectively, of additional collateral.
In addition to derivative contracts in liability positions, PacifiCorp has non-derivative wholesale agreements with specified
credit-risk-related contingent features that base certain collateral requirements on credit ratings. If all credit-risk-related contingent
features or adequate assurance provisions for wholesale agreements, including non-derivative agreements and derivative contracts in
liability positions, had been triggered as of December 31, 2014 and December 31, 2013, PacifiCorp would have been required to post
$233 million and $236 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
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.23
(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, 2014
Assets:
Commodity derivatives $ — $ 25 $ 4 $ (11) $ 18
Money market mutual funds(2)23 ———23
$23 $25 $4 $(11)$41
Liabilities - Commodity derivatives $—$(114)$—$39 $(75)
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)
(1) Represents netting under master netting arrangements and a net cash collateral receivable of $28 million and $12 million as of December 31, 2014 and
2013, 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
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.24
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.
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):
2014 2013
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $7,019 $8,358 $6,828 $7,626
(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
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.25
USA Power
In October 2005, prior to BHE'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 a May 2010 ruling on the Plaintiff's petition for reconsideration, the Utah Supreme Court reversed
summary judgment and remanded the case back to the Third District Court for further consideration. In May 2012, a 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. 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. 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. 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 is vigorously pursuing
all appellate measures. Both PacifiCorp and the Plaintiff filed appeals with the Utah Supreme Court. Briefing before the Utah Supreme
Court is complete and oral arguments will most likely be held in 2015. As of December 31, 2014, PacifiCorp had accrued $119 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 expected insurance
recovery. PacifiCorp believes it is reasonably possible it may incur additional loss beyond the amount accrued, but does not believe the
potential additional loss will have a material impact 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.26
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 May 2014, a bill was introduced in the United States Senate that, if passed by both houses of Congress, would enact the
KHSA and companion agreements that seek to resolve other water-related conflicts and restore habitat in the Klamath basin. A hearing
on the bill before a Senate Energy and Natural Resources subcommittee was held in June 2014, and the bill was voted out of
committee and referred to the full Senate for consideration in November 2014. However, the bill was not passed by Congress prior to
the end of the 2014 session. In January 2015, the bill was re-introduced into 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. Additional funding of up to $250 million for dam removal costs is to be provided by the State of California. California
voters approved a water bond measure in November 2014 from which the State of California's contribution towards dam removal costs
will be drawn. If dam removal costs exceed the combined funding that will be available from PacifiCorp's Oregon and California
customers and the State of California, 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 and California customers for their share of dam removal costs, as approved
by the OPUC and the CPUC, and is depositing the proceeds into trust accounts maintained by the OPUC and the CPUC, respectively.
PacifiCorp is authorized to collect the surcharges through 2019.
As of December 31, 2014, PacifiCorp's assets included $92 million of costs associated with the Klamath hydroelectric system's
mainstem dams and the associated relicensing and settlement costs, which are being depreciated and amortized in accordance with
state regulatory approvals through either December 31, 2019 or 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 $203 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, 2014 are as follows (in millions):
2015 2016 2017 2018 2019
2020 and
Thereafter Total
Contract type:
Purchased electricity contracts -
commercially operable $ 167 $ 90 $ 65 $ 61 $ 58 $ 292 $ 733
Purchased electricity contracts -
non-commercially operable 3 16 64 65 65 1,078 1,291
Fuel contracts 789 653 588 452 460 1,294 4,236
Construction commitments 231 53 12 8 2 8 314
Transmission 116 112 102 95 78 617 1,120
Operating leases and easements 5 5 4 4 4 46 68
Maintenance, service and
other contracts 49 29 26 14 19 81 218
Total commitments $1,360 $958 $861 $699 $686 $3,416 $7,980

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.27
Purchased Electricity Contracts - Commercially Operable
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 generating facilities that are not included in the
table above as the payments are based on the amount of energy generated and there are no minimum payments. Included in the
purchased electricity payments are any power purchase agreements that meet the definition of a lease. Rent expense related to those
power purchase agreements that meet the definition of a lease totaled $15 million for 2014 and $24 million for 2013.
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 2014
and 2013 energy sources.
Purchased Electricity Contracts - Non-commercially Operable
PacifiCorp has several contracts for purchases of electricity from facilities that have not yet achieved commercial operation. To the
extent any of these facilities do not achieve commercial operation, PacifiCorp has no obligation to the counterparty.
Fuel Contracts
PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments.
Construction Commitments
PacifiCorp's construction commitments included in the table above relate to firm commitments and include costs associated with
investments in emissions control equipment and certain transmission and distribution projects.
Transmission
PacifiCorp has contracts 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 each of the years ended December 31, 2014 and 2013.
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 outstanding shares of its redeemable preferred stock at stated redemption prices, which
in aggregate totaled $40 million, plus accrued and unpaid dividends.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.28
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.
(15) Common Shareholder's Equity
In February 2015, PacifiCorp declared a dividend of $450 million, which was paid to PPW Holdings in March 2015.
Through PPW Holdings, BHE is the sole shareholder of PacifiCorp's common stock. The state regulatory orders that authorized BHE'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, 2014, the most restrictive of these
commitments prohibits PacifiCorp from making any distribution to PPW Holdings or BHE 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 BHE as common equity. As of December 31, 2014, PacifiCorp's actual common equity
percentage, as calculated under this measure, was 53.0%, and PacifiCorp would have been permitted to dividend $2.3 billion under this
commitment.
These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings or BHE 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, 2014, 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):
2014 2013
Interest paid, net of amounts capitalized $340 $340
Income taxes paid, net(1)$154 $124
Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to utility plant additions $140 $157
(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 BHE.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
/ /2014/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)
( 12,003,821)
Balance of Account 219 at Beginning of
Preceding Year
1
498,291
Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
2
2,414,025
Preceding Quarter/Year to Date Changes in
Fair Value
3
2,912,316Total (lines 2 and 3) 4
( 9,091,505)
Balance of Account 219 at End of Preceding
Quarter/Year
5
( 9,091,505)
Balance of Account 219 at Beginning of
Current Year
6
346,579
Current Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
7
( 4,920,754)
Current Quarter/Year to Date Changes in
Fair Value
8
( 4,574,175)Total (lines 7 and 8) 9
( 13,665,680)
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
/ /2014/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)
( 12,003,821) 1
498,291 2
2,414,025 3
682,163,330 685,075,646 2,912,316 4
( 9,091,505) 5
( 9,091,505) 6
346,579 7
( 4,920,754) 8
697,859,628 693,285,453( 4,574,175) 9
( 13,665,680) 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
/ /2014/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
25,724,748,750 25,724,748,750Plant in Service (Classified) 3
33,869,179 33,869,179Property Under Capital Leases 4
Plant Purchased or Sold 5
101,339,366 101,339,366Completed Construction not Classified 6
Experimental Plant Unclassified 7
25,859,957,295 25,859,957,295Total (3 thru 7) 8
Leased to Others 9
23,319,217 23,319,217Held for Future Use 10
934,535,929 934,535,929Construction Work in Progress 11
143,167,971 143,167,971Acquisition Adjustments 12
26,960,980,412 26,960,980,412Total Utility Plant (8 thru 12) 13
9,057,705,065 9,057,705,065Accum Prov for Depr, Amort, & Depl 14
17,903,275,347 17,903,275,347Net Utility Plant (13 less 14) 15
Detail of Accum Prov for Depr, Amort & Depl 16
In Service: 17
8,395,189,232 8,395,189,232Depreciation 18
Amort & Depl of Producing Nat Gas Land/Land Right 19
Amort of Underground Storage Land/Land Rights 20
555,584,757 555,584,757Amort of Other Utility Plant 21
8,950,773,989 8,950,773,989Total 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
106,931,076 106,931,076Amort of Plant Acquisition Adj 32
9,057,705,065 9,057,705,065Total 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
/ /2014/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
/ /2014/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 207,652,388 67,385 3
(303) Miscellaneous Intangible Plant 649,633,440 32,977,923 4
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 857,285,828 33,045,308 5
2. PRODUCTION PLANT 6
A. Steam Production Plant 7
(310) Land and Land Rights 93,604,532 932 8
(311) Structures and Improvements 1,011,284,474 9,947,043 9
(312) Boiler Plant Equipment 4,116,137,262 182,742,714 10
(313) Engines and Engine-Driven Generators 11
(314) Turbogenerator Units 989,029,762 13,079,519 12
(315) Accessory Electric Equipment 480,444,603 12,097,029 13
(316) Misc. Power Plant Equipment 31,133,252 106,928 14
(317) Asset Retirement Costs for Steam Production 58,481,237 1,768,435 15
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 6,780,115,122 219,742,600 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 31,316,716 27
(331) Structures and Improvements 192,276,703 58,529,867 28
(332) Reservoirs, Dams, and Waterways 471,289,781 11,420,487 29
(333) Water Wheels, Turbines, and Generators 120,766,696 7,507,493 30
(334) Accessory Electric Equipment 76,319,914 1,730,349 31
(335) Misc. Power PLant Equipment 2,359,453 19,746 32
(336) Roads, Railroads, and Bridges 19,882,202 619,445 33
(337) Asset Retirement Costs for Hydraulic Production 34
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 914,211,465 79,827,387 35
D. Other Production Plant 36
(340) Land and Land Rights 29,095,936 13,813,089 37
(341) Structures and Improvements 165,443,499 61,501,263 38
(342) Fuel Holders, Products, and Accessories 11,117,341 4,960,268 39
(343) Prime Movers 2,565,322,968 344,113,254 40
(344) Generators 313,142,611 158,064,197 41
(345) Accessory Electric Equipment 249,675,392 76,211,255 42
(346) Misc. Power Plant Equipment 12,138,583 3,004,061 43
(347) Asset Retirement Costs for Other Production 9,072,015 402,636 44
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 3,355,008,345 662,070,023 45
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 11,049,334,932 961,640,010 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
/ /2014/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent’s plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
1
2
206,918,794 800,979 3
673,276,331 -31,619 9,303,413 4
880,195,125 -31,619 10,104,392 5
6
7
93,605,464 8
1,016,964,547 -2,184,776 2,082,194 9
4,241,159,623 2,177,184 59,897,537 10
11
996,174,043 -105,238 5,830,000 12
491,994,671 112,830 659,791 13
31,176,256 63,924 14
56,579,908 -3,669,764 15
6,927,654,512 -3,669,764 68,533,446 16
17
18
19
20
21
22
23
24
25
26
31,316,716 27
246,835,680 -716,157 3,254,733 28
481,948,519 712,008 1,473,757 29
126,979,854 1,294,335 30
77,521,376 528,887 31
2,375,380 3,819 32
20,500,603 4,149 5,193 33
34
987,478,128 6,560,724 35
36
43,017,819 108,159 -635 37
226,915,569 -1,904 27,289 38
15,869,834 1,904 209,679 39
2,899,836,969 -1,845,837 7,753,416 40
471,641,816 1,845,837 1,410,829 41
325,607,171 279,476 42
15,102,112 40,532 43
9,474,651 44
4,007,465,941 108,159 9,720,586 45
11,922,598,581 108,159 -3,669,764 84,814,756 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
/ /2014/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
3. TRANSMISSION PLANT 47
(350) Land and Land Rights 225,631,404 4,661,601 48
(352) Structures and Improvements 184,174,369 3,191,210 49
(353) Station Equipment 1,813,896,299 103,221,884 50
(354) Towers and Fixtures 1,218,917,978 2,631,301 51
(355) Poles and Fixtures 706,210,382 39,618,286 52
(356) Overhead Conductors and Devices 1,059,513,463 25,619,465 53
(357) Underground Conduit 3,340,104 -1,100 54
(358) Underground Conductors and Devices 7,499,460 55
(359) Roads and Trails 11,922,795 14,405 56
(359.1) Asset Retirement Costs for Transmission Plant 57
TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 5,231,106,254 178,957,052 58
4. DISTRIBUTION PLANT 59
(360) Land and Land Rights 62,028,583 1,318,226 60
(361) Structures and Improvements 97,377,014 2,458,813 61
(362) Station Equipment 906,249,058 30,807,276 62
(363) Storage Battery Equipment 63
(364) Poles, Towers, and Fixtures 1,052,968,133 38,012,995 64
(365) Overhead Conductors and Devices 693,804,415 16,695,558 65
(366) Underground Conduit 330,194,141 12,134,599 66
(367) Underground Conductors and Devices 776,602,508 20,568,877 67
(368) Line Transformers 1,200,818,543 41,991,053 68
(369) Services 654,161,585 26,466,667 69
(370) Meters 177,965,016 5,767,721 70
(371) Installations on Customer Premises 8,822,747 89,214 71
(372) Leased Property on Customer Premises 72
(373) Street Lighting and Signal Systems 60,769,235 1,066,268 73
(374) Asset Retirement Costs for Distribution Plant 1,651,393 74
TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 6,023,412,371 197,377,267 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 21,472,385 7,532 86
(390) Structures and Improvements 233,694,751 8,204,632 87
(391) Office Furniture and Equipment 87,147,440 12,215,804 88
(392) Transportation Equipment 105,016,260 4,986,063 89
(393) Stores Equipment 14,884,798 600,188 90
(394) Tools, Shop and Garage Equipment 63,129,288 1,714,310 91
(395) Laboratory Equipment 35,461,262 873,136 92
(396) Power Operated Equipment 158,392,929 9,677,000 93
(397) Communication Equipment 384,826,535 22,677,764 94
(398) Miscellaneous Equipment 8,030,164 394,660 95
SUBTOTAL (Enter Total of lines 86 thru 95) 1,112,055,812 61,351,089 96
(399) Other Tangible Property 305,657,640 874,375 97
(399.1) Asset Retirement Costs for General Plant 39,748 98
TOTAL General Plant (Enter Total of lines 96, 97 and 98) 1,417,753,200 62,225,464 99
TOTAL (Accounts 101 and 106) 24,578,892,585 1,433,245,101 100
(102) Electric Plant Purchased (See Instr. 8) 101
(Less) (102) Electric Plant Sold (See Instr. 8) 102
(103) Experimental Plant Unclassified 103
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 24,578,892,585 1,433,245,101 104
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
/ /2014/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
47
230,226,403 284,199 350,801 48
210,430,141 23,259,250 194,688 49
1,875,788,731 -24,935,844 16,393,608 50
1,221,298,019 209,892 461,152 51
744,102,993 1,725,675 52
1,082,532,470 -926,348 1,674,110 53
3,519,566 180,562 54
8,035,354 535,894 55
11,937,200 56
57
5,387,870,877 -1,392,395 20,800,034 58
59
63,135,433 -208,464 2,912 60
104,255,048 4,791,897 372,676 61
925,759,498 -5,298,161 5,998,675 62
63
1,085,444,520 5,536,608 64
707,873,785 2,626,188 65
341,230,913 1,097,827 66
795,524,274 1,647,111 67
1,234,715,959 8,093,637 68
679,839,675 788,577 69
180,902,129 2,830,608 70
8,831,952 80,009 71
72
61,371,460 464,043 73
1,507,080 -144,313 74
6,190,391,726 -714,728 -144,313 29,538,871 75
76
77
78
79
80
81
82
83
84
85
21,396,610 -83,307 86
239,006,029 -2,898 2,890,456 87
82,750,840 13,986 16,626,390 88
107,071,045 15,148 2,946,426 89
14,910,200 51,661 626,447 90
62,963,632 -223,632 1,656,334 91
33,940,714 170,460 2,564,144 92
163,759,938 112,577 4,422,568 93
408,492,593 2,294,721 1,306,427 94
8,038,720 386,104 95
1,142,330,321 2,348,716 33,425,296 96
302,661,738 -134,238 3,736,039 97
39,748 98
1,445,031,807 2,214,478 37,161,335 99
25,826,088,116 183,895 -3,814,077 182,419,388 100
101
102
103
25,826,088,116 183,895 -3,814,077 182,419,388 104
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 43,927,215 4,334 1,225 - - 43,930,324
39941 Surface-Plant Equipment 14,435,529 - - - - 14,435,529
39944 Surface-Electric Power Facil 3,424,575 - - - - 3,424,575
39945 Underground-Coal Mine Equip 74,986,010 - 3,601,104 - - 71,384,906
39946 Longwall Shields 24,486,688 - - - - 24,486,688
39947 Longwall Equipment 9,115,912 - - - - 9,115,91239948 Mainline Extension 20,274,157 - - - - 20,274,157
39949 Section Extension 7,412,591 (25,749) - - - 7,386,842
39951 Vehicles 1,321,430 - - - - 1,321,430
39952 Heavy Construction Equip 6,158,245 - 32 - (134,238) 6,023,975
39960 Miscellaneous General Equip 2,355,726 135,692 127,093 - - 2,364,32539961 Computers-Mainframe 470,996 3,306 6,585 - - 467,717
39970 Mine Development and Road Ext 38,657,119 - - - - 38,657,119
39915 Coal Mine ARO 3,445,884 756,792 - - - 4,202,676
$305,657,640 $ 874,375 $ 3,736,039 $ - $(134,238) $302,661,738

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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
/ /2014/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 746,2682024 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 396,0202021 10
2010Bend Service Center 3,507,8382022 11
2010Legacy Substation 562,2762025 12
2011Aeolus Substation 1,013,5772022 13
2011Anticline Substation 964,0432024 14
2011Populus Substation 254,7532024 15
2011Snyderville Substation 253,4012016 16
2012Lassen Substation 683,3182018 17
2012Old Mill Substation 1,838,2812020 18
2013Chimney Butte-Paradise 230-kV Transmission Line 598,4572025 19
Miscellaneous, each under $250,000: 912,001 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 23,319,217
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
2014/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
/ /2014/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
15,928,188EMS/SCADA Replacement / Upgrade 2
3,034,862GIS - FastGate Replacement Project 3
2,164,106Wallowa Falls Hydro Relicensing 4
1,527,036Spectrum License Buildout 5
1,157,673Customer Service Mobile Applications 6
7
Production: 8
57,730,063Jim Bridger U3 Selective Catalytic Reduction System 9
37,229,315Jim Bridger U4 Selective Catalytic Reduction System 10
11,685,541Hayden U1 Selective Catalytic Reduction System 11
6,986,266Lewis River System Relicensing Implementation 12
5,095,667Craig U2 Selective Catalytic Reduction System 13
4,353,322Wyodak Mercury Controls 14
3,973,947Jim Bridger U4 Mercury Controls 15
3,916,631Jim Bridger U1 Mercury Controls 16
3,916,257Jim Bridger U2 Mercury Controls 17
3,915,114Jim Bridger U3 Mercury Controls 18
3,879,853Yale Upper Rock Block Stabilization 19
3,343,135Jim Bridger U3 Replace Finishing Superheater 20
2,994,372Hayden U2 Selective Catalytic Reduction System 21
2,645,330Huntington U1 and U2 Submerged Drag Chain Conveyor 22
2,595,516Dave Johnston U4 Mercury Controls 23
2,544,220Dave Johnston U3 Mercury Controls 24
2,096,845Dave Johnston U2 Mercury Controls 25
2,089,082Dave Johnston U1 Mercury Controls 26
1,299,133Naughton U1 Mercury Controls 27
1,291,773Naughton U2 Mercury Controls 28
29
Transmission: 30
314,444,993Sigurd - Red Butte - Crystal 345kV Line 31
61,248,993Aeolus - Clover 500kV Line 32
61,025,629Windstar - Populus 230 - 500kV Line 33
39,399,837Populus - Hemingway 500kV Line 34
38,148,609Boardman - Hemingway 500kV Line 35
29,425,633Carbon Plant Replacement - Transmission 36
13,806,887Whetstone 230 - 115kV Substation Phase 1 37
13,334,864Vantage - Pomona Heights 230kV Line 38
10,114,858Oquirrh - Terminal 345kV Line 39
8,847,470Southwest WY - Silver Creek Build 138kV Line 40
8,028,832West Point - New 138kV Line and 40 MVA Substation 41
6,676,652Fry Substation Install 115kV Capacitor Bank 42
FERC FORM NO. 1 (ED. 12-87) Page 216
43 TOTAL 934,535,929
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
/ /2014/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.
5,478,801Cameron - Milford 138kV Transmission 138 - 46kV Transformer 1
4,880,942Standpipe Substation New 230kV Substation 2
3,876,263Union Gap Substation Add 230 - 115kV Capacity 3
3,329,780Utah Facility Rating Modifications 4
3,027,341Lake Side 2 Spare Generator Step-Up Transformer 5
2,877,584Wallula - McNary 230kV Line 6
2,092,314Snow Goose 500 - 230kV Substation 7
2,004,504Klamath Falls - Purchase Spare 230 - 69kV Auto-Transformer 8
1,947,842Terminal - Horseshoe Relocate 138 and 46kV Lines 9
1,886,886Two Elks Intercon at Tri County Switchyard 10
1,826,068Pinto Substation Add 3rd Phase Shifting Transformer 11
1,508,840Casper Outer Loop - Complete 115kV Loop 12
1,355,097Bucking Horse 7.5 MW Load 13
1,340,734Lyons Substation Increase Capacity 14
1,077,071Chehalis U3 Generator Step-Up Transformer Replacement 15
1,034,563Casper Substation Install 230 - 115kV 250 MVA Transformer 16
17
Distribution: 18
4,253,006Pomona Heights Substation Add 115 - 12.47kV Capacity 19
3,196,652Threemile Canyon Farms Irrigation Pumping 2,500 HP Increase 20
2,055,104Bar Nunn New 115 - 12.5kV Substation and Transmission Line 21
1,374,254Knott Substation Increase Capacity 22
23
General: 24
2,460,306Non-Data Center Router and Switch Technology Obsolescence Management 25
1,547,357Deer Creek - 2 Section Terminal Groups 26
1,291,324F5 Hardware Load Balancer Blade Upgrade 27
28
86,916,792Miscellaneous Projects each under $1,000,000 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 934,535,929
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
/ /2014/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 7,863,751,463 7,863,751,463
Depreciation Provisions for Year, Charged to 2
(403) Depreciation Expense 3 663,171,827 663,171,827
(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 74,687,869 74,687,869
9
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
10 737,859,696 737,859,696
Net Charges for Plant Retired: 11
Book Cost of Plant Retired 12 170,396,930 170,396,930
Cost of Removal 13 46,586,700 46,586,700
Salvage (Credit) 14 8,035,148 8,035,148
TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
15 208,948,482 208,948,482
Other Debit or Cr. Items (Describe, details in
footnote):
16 2,526,555 2,526,555
17
Book Cost or Asset Retirement Costs Retired 18
Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
19 8,395,189,232 8,395,189,232
Steam Production 20
Section B. Balances at End of Year According to Functional Classification
2,822,999,224 2,822,999,224
Nuclear Production 21
Hydraulic Production-Conventional 22 302,834,825 302,834,825
Hydraulic Production-Pumped Storage 23
Other Production 24 777,090,296 777,090,296
Transmission 25 1,432,003,537 1,432,003,537
Distribution 26 2,479,873,031 2,479,873,031
Regional Transmission and Market Operation 27
General 28 580,388,319 580,388,319
TOTAL (Enter Total of lines 20 thru 28) 29 8,395,189,232 8,395,189,232
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 $ 22,191,690
Account 143, Other accounts receivable, - depreciation
expense billed to joint owners 205,655
Asset retirement obligation asset depreciation recorded
as a regulatory asset or liability 4,284,437
Deferral of Carbon depreciation recorded as a regulatory asset 22,035,266
Deferral of increased depreciation, due to depreciation study rates,
net of amortization, recorded as a regulatory asset 10,998,313
Transportation depreciation charged to operations and maintenance
expense and construction work in progress based on usage activity 13,767,456
Account 503, Steam from other sources, - Blundell depletion 185,368
Account 503, Steam from other sources, - Blundell depreciation 1,019,684
Total Other Accounts $ 74,687,869

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 $ (1,526,419)
Other items include: 4,052,974
- 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 $ 2,526,555
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
/ /2014/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.
PACIFIC MINERALS, INC. 1
1 Common Stock 2
47,960,000 Paid-in Capital 3
121,361,852 Undistributed Subsidiary Earnings 4
169,321,853 SUBTOTAL 5
6
1990ENERGY WEST MINING COMPANY 7
1,000 Common Stock 8
1,000 SUBTOTAL 9
10
1991GLENROCK COAL COMPANY 11
1 Common Stock 12
1 SUBTOTAL 13
14
1992INTERWEST MINING COMPANY 15
1,000 Common Stock 16
1,000 SUBTOTAL 17
18
1992TRAPPER MINING INC. 19
6,038,000 Members' Equity 20
6,310,111 Undistributed Subsidiary Earnings 21
12,348,111 SUBTOTAL 22
23
2011FOSSIL ROCK FUELS, LLC 24
29,262,429 Paid-in Capital 25
-10,335 Undistributed Subsidiary Earnings 26
29,252,094 SUBTOTAL 27
28
29
30
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 210,924,059 85,322,431
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
/ /2014/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
135,509,939 14,148,087 4
183,469,940 14,148,087 5
6
7
1,000 8
1,000 9
10
11
1 12
1 13
14
15
1,000 16
1,000 17
18
19
6,038,000 20
6,652,381 436,318 21
12,690,381 436,318 22
23
24
31,322,429 25
-13,673 -3,338 26
31,308,756 -3,338 27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89) Page 225
42 14,581,067 227,471,078
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.: 21 Column: g
In September 2014, Trapper Mining Inc., a subsidiary of PacifiCorp, paid a dividend of
$94,048 to PacifiCorp.
Schedule Page: 224 Line No.: 25 Column: g
In January 2014, PacifiCorp contributed $2,060,000 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
2014/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
/ /2014/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.
240,980,677 Electric 198,515,639 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)
91,333,148 Electric 111,221,100 5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
101,171,275 Electric 94,012,733 7 Production Plant (Estimated)
678,432 Electric 490,752 8 Transmission Plant (Estimated)
12,375,512 Electric 12,319,645 9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant
(Estimated)
6,985,748 Electric 5,593,971 11 Assigned to - Other (provide details in footnote)
212,544,115 223,638,201 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
453,524,792 422,153,840 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 $ 6,914,497
General plant materials and supplies 71,251
$ 6,985,748
Schedule Page: 227 Line No.: 11 Column: c
Mining materials and supplies $ 5,512,384
General plant materials and supplies 81,587
$ 5,593,971

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
/ /2014/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.
2015
347,437.00 136,466.00Balance-Beginning of Year 1
2
Acquired During Year: 3
Issued (Less Withheld Allow) 4
Returned by EPA 5
6
7
Purchases/Transfers: 8
9
10
11
12
13
14
Total 15
16
Relinquished During Year: 17
40,554.00 Charges to Account 509 18
Other: 19
20
Cost of Sales/Transfers: 21
22
23
24
25
26
27
Total 28
306,883.00 136,466.00Balance-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
/ /2014/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.
2016 2017
1 4,067,537.00 151,733.00 149,627.00 4,852,800.00
2
3
4 156,643.00 156,643.00
5
6
7
8
9
10
11
12
13
14
15
16
17
18 40,554.00
19
20
21
22
23
24
25
26
27
28
29 4,224,180.00 151,733.00 149,627.00 4,968,889.00
30
31
32
33
34
35
36 110,921.00 2,259.00 2,259.00 119,957.00
37 4,528.00 4,528.00
38
39 2,269.00 4,528.00
40 113,180.00 2,259.00 2,259.00 119,957.00
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-95) Page 229a
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
PacifiCorp X
/ /2014/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 1,205,416 407 1,205,41622
upgrades23
Plant located near Evanston, WY24
Date of Commission Authorization25
09/19/201226
Amortization period: 10/12/201227
through 08/31/201428
29
WY-Naughton Unit #3 environmental 555,186 407 555,18630
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 1,760,602 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
/ /2014/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. In column (a) provide the name of the study.
4. In column (b) report the cost incurred to perform the study at the end of period.
5. In column (c) report the account charged with the cost of the study.
6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
7. In column (e) report the account credited with the reimbursement received for performing the study.
the Period
Transmission Studies 1
3,879Q1789 561.6 3,879 456 2
47,663Q1799 561.6 47,663 456 3
103Q1802 561.6 103 456 4
4,312Q1803 561.6 4,312 456 5
359Q1827 561.6 359 456 6
860AREF 78351080 561.6 7
215AREF 78834184 561.6 8
180AREF 78926238 561.6 9
716AREF 79272901 561.6 10
10,489AREF 79428812 561.6 11
11,477AREF 79456228 561.6 12
409AREF 79486154 561.6 13
654AREF 79611263 561.6 14
2,755AREF 79648694 561.6 15
2,216AREF 79648850 561.6 16
363AREF 79648886 561.6 17
363AREF 79648900 561.6 18
903AREF 79651319 561.6 19
2,062AREF 79656579 561.6 20
Generation Studies 21
142GIQ0252 561.7 142 456 22
1,232GIQ0255 561.7 1,232 456 23
2,799GIQ0316 561.7 2,799 456 24
155GIQ0332 561.7 155 456 25
5,575GIQ0397 561.7 5,575 456 26
1,232GIQ0403 561.7 1,232 456 27
602GIQ0409 561.7 602 456 28
1,346GIQ0420 561.7 1,346 456 29
771GIQ0425 561.7 771 456 30
4,022GIQ0426 561.7 4,022 456 31
142GIQ0427 561.7 142 456 32
719GIQ0429 561.7 719 456 33
2,384GIQ0438 561.7 2,384 456 34
744GIQ0443 561.7 744 456 35
1,480GIQ0450 561.7 1,480 456 36
248GIQ0451 561.7 248 456 37
2,081GIQ0453 561.7 2,081 456 38
213GIQ0456 561.7 213 456 39
3,601GIQ0460 561.7 3,601 456 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
/ /2014/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
1,802AREF 79656649 561.6 2
4,442AREF 79656693 561.6 3
252AREF 79656740 561.6 4
1,995AREF 79656769 561.6 5
4,943AREF 79656794 561.6 6
1,711AREF 79656841 561.6 7
1,787AREF 79656858 561.6 8
2,039AREF 79656968 561.6 9
1,715AREF 79656996 561.6 10
1,715AREF 79657047 561.6 11
2,045AREF 79657068 561.6 12
287AREF 79657086 561.6 13
287AREF 79675896 561.6 14
449AREF 79675996 561.6 15
2,058AREF 79857385 561.6 16
1,586AREF 79857389 561.6 17
725AREF 79857395 561.6 18
840AREF 79857400 561.6 19
593AREF 79887230 561.6 20
Generation Studies 21
744GIQ0463 561.7 744 456 22
2,109GIQ0464 561.7 2,109 456 23
31,187GIQ0465 561.7 31,187 456 24
567GIQ0471 561.7 567 456 25
496GIQ0472 561.7 496 456 26
496GIQ0473 561.7 496 456 27
2,472GIQ0475 561.7 2,472 456 28
1,630GIQ0488 561.7 1,630 456 29
1,564GIQ0489 561.7 1,564 456 30
1,927GIQ0491 561.7 1,927 456 31
2,265GIQ0492 561.7 2,265 456 32
1,856GIQ0493 561.7 1,856 456 33
284GIQ0495 561.7 284 456 34
3,064GIQ0496 561.7 3,064 456 35
106GIQ0500 561.7 106 456 36
35GIQ0501 561.7 35 456 37
1,760GIQ0502 561.7 1,760 456 38
2,661GIQ0503 561.7 2,661 456 39
2,991GIQ0504 561.7 2,991 456 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
/ /2014/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
410AREF 79887233 561.6 2
2,263AREF 80031241 561.6 3
1,393AREF 80039313 561.6 4
2,135AREF 80039416 561.6 5
2,221AREF 80149329 561.6 6
1,778AREF 80243374 561.6 7
( 11,756)AREF 788834184 561.6 8
11,756AREF 788834184 107 9
284AREF 78764672 107 10
981AREF 78849614 107 11
1,481AREF 78984295 107 12
2,369AREF 79341660 107 13
2,519Q0568 107 14
2,524Q0569 107 15
( 43,668)Customer Studies Accruals 561.6 16
17
18
19
20
Generation Studies 21
17,883GIQ0509 561.7 17,883 456 22
13,424GIQ0510 561.7 13,424 456 23
2,788GIQ0511 561.7 2,788 456 24
2,918GIQ0512 561.7 2,918 456 25
23,812GIQ0513 561.7 23,812 456 26
28,471GIQ0514 561.7 28,471 456 27
22,780GIQ0515 561.7 22,780 456 28
16,453GIQ0516 561.7 16,453 456 29
9,554GIQ0517 561.7 9,554 456 30
16,830GIQ0518 561.7 16,830 456 31
15,156GIQ0519 561.7 15,156 456 32
11,685GIQ0520 561.7 11,685 456 33
14,111GIQ0521 561.7 14,111 456 34
523GIQ0522 561.7 523 456 35
23,928GIQ0523 561.7 23,928 456 36
15,235GIQ0524 561.7 15,235 456 37
13,845GIQ0525 561.7 13,845 456 38
1,873GIQ0526 561.7 1,873 456 39
1,686GIQ0527 561.7 1,686 456 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
/ /2014/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
1,369GIQ0528 561.7 1,369 456 22
2,644GIQ0529 561.7 2,644 456 23
3,669GIQ0530 561.7 3,669 456 24
2,220GIQ0531 561.7 2,220 456 25
33,344GIQ0532 561.7 33,344 456 26
6,849GIQ0533 561.7 6,849 456 27
15,390GIQ0534 561.7 15,390 456 28
409GIQ0535 561.7 409 456 29
409GIQ0536 561.7 409 456 30
409GIQ0537 561.7 409 456 31
33,442GIQ0539 561.7 33,442 456 32
630GIQ0540 561.7 630 456 33
1,835GIQ0541 561.7 1,835 456 34
41,186GIQ0542 561.7 41,186 456 35
21,681GIQ0543 561.7 21,681 456 36
15,728GIQ0544 561.7 15,728 456 37
4,606GIQ0545 561.7 4,606 456 38
2,924GIQ0546 561.7 2,924 456 39
22,134GIQ0547 561.7 22,134 456 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
/ /2014/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
22,142GIQ0548 561.7 22,142 456 22
5,208GIQ0549 561.7 5,208 456 23
370GIQ0550 561.7 370 456 24
17,778GIQ0551 561.7 17,778 456 25
7,245GIQ0552 561.7 7,245 456 26
1,439GIQ0553 561.7 1,439 456 27
6,343GIQ0554 561.7 6,343 456 28
20,617GIQ0555 561.7 20,617 456 29
20,650GIQ0556 561.7 20,650 456 30
6,126GIQ0557 561.7 6,126 456 31
44,962GIQ0558 561.7 44,962 456 32
1,295GIQ0559 561.7 1,295 456 33
6,051GIQ0560 561.7 6,051 456 34
471GIQ0561 561.7 471 456 35
20,459GIQ0564 561.7 20,459 456 36
2,581GIQ0565 561.7 2,581 456 37
16,208GIQ0566 561.7 16,208 456 38
13,299GIQ0567 561.7 13,299 456 39
2,535GIQ0570 561.7 2,535 456 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
/ /2014/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
9,600GIQ0571 561.7 9,600 456 22
13,157GIQ0572 561.7 13,157 456 23
23,352GIQ0573 561.7 23,352 456 24
1,596GIQ0574 561.7 1,596 456 25
1,220GIQ0575 561.7 1,220 456 26
1,051GIQ0576 561.7 1,051 456 27
19,553GIQ0577 561.7 19,553 456 28
15,284GIQ0578 561.7 15,284 456 29
12,162GIQ0579 561.7 12,162 456 30
8,556GIQ0580 561.7 8,556 456 31
3,852GIQ0581 561.7 3,852 456 32
24,438GIQ0582 561.7 24,438 456 33
8,731GIQ0585 561.7 8,731 456 34
7,331GIQ0586 561.7 7,331 456 35
9,563GIQ0587 561.7 9,563 456 36
938GIQ0588 561.7 938 456 37
7,620GIQ0589 561.7 7,620 456 38
1,483GIQ0590 561.7 1,483 456 39
2,051GIQ0591 561.7 2,051 456 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
/ /2014/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
11,139GIQ0592 561.7 11,139 456 22
12,600GIQ0593 561.7 12,600 456 23
9,684GIQ0594 561.7 9,684 456 24
5,816GIQ0595 561.7 5,816 456 25
179GIQ0596 561.7 179 456 26
4,967GIQ0597 561.7 4,967 456 27
4,770GIQ0598 561.7 4,770 456 28
1,513GIQ0599 561.7 1,513 456 29
7,666GIQ0600 561.7 7,666 456 30
1,161GIQ0601 561.7 1,161 456 31
926GIQ0602 561.7 926 456 32
1,592GIQ0603 561.7 1,592 456 33
5,595GIQ0604 561.7 5,595 456 34
3,911GIQ0605 561.7 3,911 456 35
4,023GIQ0606 561.7 4,023 456 36
3,365GIQ0607 561.7 3,365 456 37
6,688GIQ0608 561.7 6,688 456 38
7,014GIQ0609 561.7 7,014 456 39
1,874GIQ0610 561.7 1,874 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.6
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2014/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
5,530GIQ0611 561.7 5,530 456 22
8,243GIQ0612 561.7 8,243 456 23
3,477GIQ0613 561.7 3,477 456 24
3,719GIQ0614 561.7 3,719 456 25
1,912GIQ0615 561.7 1,912 456 26
6,711GIQ0616 561.7 6,711 456 27
1,295GIQ0617 561.7 1,295 456 28
1,445GIQ0618 561.7 1,445 456 29
2,329GIQ0619 561.7 2,329 456 30
1,998GIQ0620 561.7 1,998 456 31
2,089GIQ0621 561.7 2,089 456 32
3,572GIQ0622 561.7 3,572 456 33
2,782GIQ0623 561.7 2,782 456 34
4,722GIQ0624 561.7 4,722 456 35
3,703GIQ0625 561.7 3,703 456 36
1,237GIQ0626 561.7 1,237 456 37
1,377GIQ0627 561.7 1,377 456 38
1,306GIQ0628 561.7 1,306 456 39
4,987GIQ0629 561.7 4,987 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2014/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
2,520GIQ0630 561.7 2,520 456 22
1,200GIQ0631 561.7 1,200 456 23
974GIQ0632 561.7 974 456 24
2,173Pre-Application Studies - East 561.7 2,173 456 25
3,535Pre-Application Studies - West 561.7 3,535 456 26
9,661Q0568 561.7 27
8,722Q0569 561.7 28
1,710Q0583 561.7 29
1,140 561.7 30
12,083Customer Studies Accruals 561.7 31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.8
Schedule Page: 231.8 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
2014/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
/ /
2014/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 1,166,810 2,108,072908,431 2,273,447DSM Balancing Account - CA 1
744,888 2,633,413908,431 3,378,301DSM Balancing Account - ID 2
18,414,133 59,356,900908 77,771,033DSM Balancing Account - UT 3
1,078,059 10,593,061908 11,671,120DSM Balancing Account - WA 4
4,791,326 7,094,731 1,622,261555 3,925,666Deferred Excess Net Power Costs - CA 5
24,493,966 25,605,859 13,140,236555 14,252,129Deferred Excess Net Power Costs - ID 6
71,218,625 63,084,452 33,496,987555 25,362,814Deferred Excess Net Power Costs - UT 7
38,359,894 26,163,378 23,547,981555 11,351,465Deferred Excess Net Power Costs - WY 8
16,140,769 19,001,916 3,107,779456 5,968,926Deferred Excess RECs in Rates - UT 9
5,405,889 2,207,437 3,293,278456 94,826Deferred Excess RECs/SO2 in Rates - WY 10
248,555 248,555456Deferred Excess RECs in Rates - OR 11
4,917,237 4,917,237Deferred Excess RECs in Rates - WA 12
254,760 3,865,030254 4,119,790Income Tax Reg. Asset - WA Flow Through 13
461,454,531 446,017,017 19,091,517282,283 3,654,003Deferred Income Tax Electric 14
82,313 5,307282,283 87,620Solar ITC Basis Adjustment Regulatory Asset 15
2 2410.1,283Tax Adj on Postretirement Benefits - CA (3) 16
204,997 204,997410.1Tax Adj on Postretirement Benefits - ID (4) 17
3,577,313 2,682,984 894,329410.1Tax Adj on Postretirement Benefits - OR (5) 18
1,178,250 1,178,250410.1Tax Adj on Postretirement Benefits - UT (4) 19
559,135 1 559,134410.1Tax Adj on Postretirement Benefits - WY (4) 20
39,674 22,041 17,633Tax Revenue Requirement Adjustment - WY (4) 21
312,870,952 473,546,816 28,705,712 189,381,576Pension 22
76,812,296 16,758,010 60,054,286Other Postretirement 23
7,734,798 8,361,445 1,222,297 1,848,944Postemployment Costs 24
182,578 156,362 26,216407.3Powerdale Decommissioning - ID (10) 25
70,982 70,982407.3Powerdale Decommissioning - WA (3) 26
2,106,371 2,106,371Carbon Plant Regulatory Asset - ID 27
14,599,216 14,599,216Carbon Plant Regulatory Asset - UT 28
5,329,679 5,329,679Carbon Plant Regulatory Asset - WY 29
1,589,451 1,589,451Depreciation Study Deferral - ID 30
2,112,712 88,864403 2,201,576Depreciation Study Deferral - UT (17) 31
7,296,150 236,050403 7,532,200Depreciation Study Deferral - WY (17) 32
1,461,568 1,407,280 54,288930.2Generating Plant Liquidated Damages - WY 33
700,000 665,000 35,000930.2Generating Plant Liquidated Damages - UT 34
6,000,000 3,000,000 3,000,000Chehalis Generating Facility Deferral - WA (6) 35
32,014,114 29,170,485 4,483,442404 1,639,813Klamath Hydroelectric Relicensing Costs - UT (10) 36
3,363,432 2,424,799 938,633557Cholla Plant Transaction Costs (26) 37
369,695 317,507 52,188456Washington Colstrip Unit No. 3 (22) 38
102,043 51,021 51,022407Naughton Unit No. 3 Environmental Costs - CA (2) 39
478,988 239,494 239,494407Naughton Unit No. 3 Environmental Costs - ID (2) 40
37,043,065 40,073,889 2,555,190925,253 5,586,014Environmental Costs (10) 41
51,025,640 51,344,265 318,625Asset Retirement Obligations Regulatory Difference 42
145,804,625 123,014,796 22,789,829242Unamortized Contract Values 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
/ /
2014/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)
54,369,561 85,415,690 31,046,129Unrealized Loss on Derivative Contracts 1
7,099,190 5,110,660 7,554,206555 5,565,676Greenhouse Gas Allowance Compliance Costs - CA 2
4,105,556 5,021,117 3,639,844 4,555,405Solar Feed-In Tariff Deferral - OR (1) 3
180,906 180,906555Renewable Portfolio Standards Compliance - OR (1) 4
802,926 1,069,569 266,643Deferred Intervenor Funding Grants - OR 5
40,307 40,347 40Deferred Intervenor Funding Grants - CA 6
55,462 39,031 16,431928Deferred Intervenor Funding Grants - ID (2) 7
11,572 18,919 30,491Schedule 203 - Black Cap Solar - OR (1) 8
6,945 6,945588Schedule 94 - Distribution Safety Surcharge - OR 9
184,683 254,022 1,080,904501 1,150,243Deferred Overburden Cost - ID 10
493,553 677,346 2,883,221501 3,067,014Deferred Overburden Cost - WY 11
316,957 316,957BPA Balancing Account - WA 12
1,468,531 1,468,531BPA Balancing Account - OR 13
275,610 142,389 136,985 3,764Excess Gain on Sale of Assets in Rates - OR (1) 14
418,227 418,227GRC Invest. In Emission Control Equip. - OR (1) 15
886,570 886,570925Injuries & Damages Reserve - OR 16
702,183 470,868 349,810924 118,495Property Insurance Reserve - WY 17
62,655 56,405 6,250Misc. Regulatory Assets/Liabilities - OR 18
86,357,715 86,357,715Utah Mine Disposition 19
261,901 261,901Preferred Stock Redemption Loss - WY 20
759,970 27,510407.3 787,480Preferred Stock Redemption Loss - UT (10) 21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
1,373,975,244TOTAL :44 1,589,995,081 320,356,716 536,376,553
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 approximately one year for deferred excess net power
cost mechanisms being amortized.
Schedule Page: 232 Line No.: 6 Column: a
Weighted average remaining life is approximately one year for deferred excess net power
cost mechanisms being amortized, including Monsanto and Agrium net power cost components.
Schedule Page: 232 Line No.: 7 Column: a
Weighted average remaining life is approximately one year for deferred excess net power
cost mechanisms being amortized.
Schedule Page: 232 Line No.: 8 Column: a
Weighted average remaining life is approximately one year for deferred excess net power
cost mechanisms being amortized.
Schedule Page: 232 Line No.: 9 Column: a
Weighted average remaining life is approximately two years for deferred excess renewable
energy credits in rates being amortized.
Schedule Page: 232 Line No.: 10 Column: a
Weighted average remaining life is approximately one year for deferred excess renewable
energy credits and sulfur dioxide revenues in rates being amortized.
Schedule Page: 232 Line No.: 14 Column: a
Weighted average remaining life is 26 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.: 21 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 232 Line No.: 22 Column: a
Weighted average remaining life is eight 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.: 22 Column: d
Pensions are associated with labor and generally charged to operations and maintenance
expense and construction work in progress.
Schedule Page: 232 Line No.: 23 Column: a
Weighted average remaining life is eight 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.: 23 Column: d
Other benefits are associated with labor and generally charged to operations and
maintenance expense, construction work in progress and Account 228.3, Accumulated
provision for pensions and benefits.
Schedule Page: 232 Line No.: 24 Column: a
Weighted average remaining life is six years.
Schedule Page: 232 Line No.: 24 Column: d
Other benefits are associated with labor and generally charged to operations and
maintenance expense and construction work in progress.
Schedule Page: 232 Line No.: 33 Column: a
Weighted average remaining life is 28 years.
Schedule Page: 232 Line No.: 34 Column: a
Weighted average remaining life is 19 years.
Schedule Page: 232 Line No.: 35 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 232 Line No.: 43 Column: a
Weighted average remaining life is eight years. Represents frozen values of contracts
previously accounted for as derivatives and recorded at fair value.
Schedule Page: 232.1 Line No.: 1 Column: a
Weighted average remaining life is four years.
Schedule Page: 232.1 Line No.: 3 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 232.1 Line No.: 8 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 232.1 Line No.: 14 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 232.1 Line No.: 18 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
2014/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
/ /2014/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.
560,971 423,590 137,381557Joseph Settlement (21) 1
2
369,570 323,850 45,720557Lacomb Irrigation (24) 3
4
1,076,720 1,035,440 41,280557Bogus Creek (41) 5
6
Mead Phoenix Availability and 7
12,623,480 12,245,720 377,760565Transmission Charge (50) 8
9
94,130 78,656 15,474557TGS Buyout (23) 10
11
1,603,678 1,054,377 838,404 289,103 142Point-to-Point Transmission 12
13
6,905 6,905557Jim Boyd Hydro Buyout (11) 14
15
3,877,405 3,705,711 171,694557Hermiston Swap (40) 16
17
Oregon Prepaid REC Purchases 18
188,367 98,273 98,664 8,570 555for RPS Compliance (1) 19
20
1,288,250 26,832 2,787,566 1,526,148 151Deferred Longwall Costs 21
22
Deferred Coal Costs - Wyodak 23
3,016,636 2,681,454 335,182151Settlement (22) 24
25
Deferred Coal Costs - Naughton 26
4,128,461 2,752,307 1,376,154151Settlement (7) 27
28
Deferred Coal Costs - Jim 29
2,916,673 2,916,673Bridger Plant 30
31
Deferred Colstrip Plant 32
625,000 325,000 300,000501Costs (5) 33
34
Deferred Royalty Reduction - 35
20,728 20,728151Craig Plant 36
37
LT Lease Commissions 38
432,574 333,059 99,515931Prepaids (10) 39
40
19,523,667 26,426,083 6,902,416Lake Side Maintenance Prepaid 41
42
5,281,592 5,281,592Lake Side 2 Maintenance Prepaid 43
44
13,717,203 21,838,914 8,121,711Chehalis Maintenance 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)
90,972,267 110,913,409
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
/ /2014/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.
7,272,782 13,996,108 6,723,326Currant Creek Maint. Prepaid 1
2
649,871 492,642 157,229454Lease Incentives (10) 3
4
2,885,523 2,141,252 744,271427,431Credit Agreement Costs (5) 5
6
346,216 88,026 258,190427PCRB LOC/SBBPA Costs 7
8
259,606 245,844 117,173 103,411 427PCRB Mode Conversion Costs 9
10
673,998 611,783 62,215427'94 Series Restruct. Costs (16) 11
12
LT Prepaid IBEW 57 Pension 13
6,230,810 4,787,907 1,736,591 293,688Contribution 14
15
5,658,577 4,717,195 1,104,072 162,690 565BPA LT Transmission Prepaid 16
17
306,510 306,510Emission Reduction Credits 18
19
312,267 131,614 180,653174Unamortized Contract Values 20
21
Sales of Electric Utility 22
276,000 1,845,747 1,569,747Facilities & Properties 23
24
29,689 1,250 48,487 20,048 181Other Deferred Charges 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)
90,972,267 110,913,409
Schedule Page: 233.1 Line No.: 7 Column: a
Weighted average life is three years.
Schedule Page: 233.1 Line No.: 9 Column: a
Weighted average life is seven years.
Schedule Page: 233.1 Line No.: 14 Column: d
Pensions are associated with labor and generally charged to operations and maintenance
expense and construction work in progress.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
/ /2014/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
182,825,392 98,584,009Employee benefits 2
79,219,960 76,128,093Derivative contracts and unamortized contract values 3
68,037,070 68,472,715State carryforwards 4
51,188,383 66,767,632Loss contingencies 5
47,023,073 47,989,295Asset retirement obligations 6
116,675,654 124,625,544Other 7
544,969,532 482,567,288TOTAL 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
544,969,532 482,567,288TOTAL (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 $ 36,289,678 $ 28,575,535
Other 88,335,866 88,100,119
$124,625,544 $116,675,654
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
/ /2014/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
Berkshire Hathaway Energy 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
Authorized and Unissued Capital Stock 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. 12-91) 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
/ /2014/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.: 20 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, 2014, PacifiCorp had regulatory approval from the aforementioned
commissions for the issuance of an additional 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
2014/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
/ /2014/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 ScottishPower plc stock 7
-1,275,241Qualified production activity tax deduction 8
432,552Contribution of Intermountain Geothermal 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
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 ScottishPower 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 ScottishPower 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 ScottishPower plc.
Schedule Page: 253 Line No.: 6 Column: b
Represents capital contributions to PacifiCorp (with no shares of stock issued) from its
indirect parent Berkshire Hathaway Energy Company ("BHE"). No capital contributions were
made by BHE to PacifiCorp during the year ended December 31, 2014.
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 ScottishPower 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 BHE in
March 2006, subsequent to the sale of PacifiCorp to BHE. Intermountain Geothermal Company
was merged with and into its direct parent, PacifiCorp, on August 31, 2007, with
PacifiCorp surviving.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
/ /2014/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
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
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
/ /2014/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
1,442,365 200,000,000 4.95% Series due August 15, 2014 4
728,000 5 D
28,218,000 8.734% Series due October 1, 2014 6
46,946,000 8.294% Series due October 1, 2015 7
18,750,000 8.635% Series due October 1, 2016 8
19,609,000 8.470% Series due October 1, 2017 9
3,067,221 500,000,000 5.65% Series due July 15, 2018 10
905,000 11 D
2,515,793 350,000,000 5.50% Series due January 15, 2019 12
2,292,500 13 D
3,007,139 400,000,000 3.85% Series due June 15, 2021 14
744,000 15 D
2,424,350 350,000,000 2.95% Series due February 1, 2022 16
308,000 17 D
254,129 100,000,000 2.95% Series due February 1, 2022 18
-81,000 19 P
1,859,352 300,000,000 2.95% Series due June 1, 2023 20
900,000 21 D
3,345,164 425,000,000 3.60% Series due April 1, 2024 22
255,000 23 D
2,874,150 300,000,000 7.70% Series due November 15, 2031 24
864,000 25 D
1,892,365 200,000,000 5.90% Series due August 15, 2034 26
722,000 27 D
2,912,021 300,000,000 5.25% Series due June 15, 2035 28
1,080,000 29 D
2,907,881 350,000,000 6.10% Series due August 1, 2036 30
1,141,000 31 D
589,216 600,000,000 5.75% Series due April 1, 2037 32
FERC FORM NO. 1 (ED. 12-96)Page 256
33 TOTAL 7,417,018,000 79,444,237
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
/ /2014/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
6,187,50008/15/201408/24/200408/15/201408/24/2004 4
5
171,82010/01/201404/15/199210/01/201404/15/1992 6
4,178,000 586,38610/01/201504/15/199210/01/201504/15/1992 7
3,241,000 372,53510/01/201604/15/199210/01/201604/15/1992 8
4,779,000 490,66710/01/201704/15/199210/01/201704/15/1992 9
500,000,000 28,250,00007/15/201807/17/200807/15/201807/17/2008 10
11
350,000,000 19,250,00001/15/201901/08/200901/15/201901/08/2009 12
13
400,000,000 15,400,00006/15/202105/12/201106/15/202105/12/2011 14
15
350,000,000 10,325,00002/01/202201/06/201202/01/202201/06/2012 16
17
100,000,000 2,950,00002/01/202203/06/201202/01/202203/06/2012 18
19
300,000,000 8,850,00006/01/202306/06/201306/01/202306/06/2013 20
21
425,000,000 12,240,00004/01/202403/13/201404/01/202403/13/2014 22
23
300,000,000 23,100,00011/15/203111/21/200111/15/203111/21/2001 24
25
200,000,000 11,800,00008/15/203408/24/200408/15/203408/24/2004 26
27
300,000,000 15,750,00006/15/203506/13/200506/15/203506/13/2005 28
29
350,000,000 21,350,00008/01/203608/10/200608/01/203608/10/2006 30
31
600,000,000 34,500,00004/01/203703/14/200704/01/203703/14/2007 32
FERC FORM NO. 1 (ED. 12-96)Page 257
33 7,031,538,000 358,380,033
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
/ /2014/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.
24,000 1 D
5,127,281 600,000,000 6.25% Series due October 15, 2037 2
750,000 3 D
2,290,333 300,000,000 6.35% Series due July 15, 2038 4
1,671,000 5 D
6,134,687 650,000,000 6.00% Series due January 15, 2039 6
6,175,000 7 D
2,737,911 300,000,000 4.10% Series due February 1, 2042 8
987,000 9 D
115,202 15,000,000 8.53% Series C Medium-Term Notes due Dec. 16, 2021 10
38,400 5,000,000 8.375% Series C Medium-Term Notes due Dec. 31, 2021 11
33,243 5,000,000 8.26% Series C Medium-Term Notes due Jan. 7, 2022 12
30,594 4,000,000 8.27% Series C Medium-Term Notes due Jan. 10, 2022 13
131,471 15,000,000 8.05% Series E Medium-Term Notes due Sept. 1, 2022 14
70,118 8,000,000 8.07% Series E Medium-Term Notes due Sept. 9, 2022 15
438,238 50,000,000 8.12% Series E Medium-Term Notes due Sept. 9, 2022 16
105,177 12,000,000 8.11% Series E Medium-Term Notes due Sept. 9, 2022 17
87,648 10,000,000 8.05% Series E Medium-Term Notes due Sept. 14, 2022 18
208,198 26,000,000 8.08% Series E Medium-Term Notes due Oct. 14, 2022 19
200,190 25,000,000 8.08% Series E Medium-Term Notes due Oct. 14, 2022 20
37,914 5,000,000 8.23% Series E Medium-Term Notes due Jan. 20, 2023 21
30,331 4,000,000 8.23% Series E Medium-Term Notes due Jan. 20, 2023 22
-81,560 23 P
246,981 27,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 24
100,622 11,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 25
137,211 15,000,000 7.23% Series F Medium-Term Notes due Aug. 16, 2023 26
274,423 30,000,000 7.24% Series F Medium-Term Notes due Aug. 16, 2023 27
38,250 5,000,000 6.75% Series F Medium-Term Notes due Sept. 14, 2023 28
15,300 2,000,000 6.75% Series F Medium-Term Notes due Sept. 14, 2023 29
15,300 2,000,000 6.72% Series F Medium-Term Notes due Sept. 14, 2023 30
152,326 20,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 31
121,861 16,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 32
FERC FORM NO. 1 (ED. 12-96)Page 256.1
33 TOTAL 7,417,018,000 79,444,237
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
/ /2014/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
600,000,000 37,500,00010/15/203710/03/200710/15/203710/03/2007 2
3
300,000,000 19,050,00007/15/203807/17/200807/15/203807/17/2008 4
5
650,000,000 39,000,00001/15/203901/08/200901/15/203901/08/2009 6
7
300,000,000 12,300,00002/01/204201/06/201202/01/204201/06/2012 8
9
15,000,000 1,279,50012/16/202112/16/199112/16/202112/16/1991 10
5,000,000 418,75012/31/202112/31/199112/31/202112/31/1991 11
5,000,000 413,00001/07/202201/08/199201/07/202201/08/1992 12
4,000,000 330,80001/10/202201/09/199201/10/202201/09/1992 13
15,000,000 1,207,50009/01/202209/18/199209/01/202209/18/1992 14
8,000,000 645,60009/09/202209/09/199209/09/202209/09/1992 15
50,000,000 4,060,00009/09/202209/11/199209/09/202209/11/1992 16
12,000,000 973,20009/09/202209/11/199209/09/202209/11/1992 17
10,000,000 805,00009/14/202209/14/199209/14/202209/14/1992 18
26,000,000 2,100,80010/14/202210/15/199210/14/202210/15/1992 19
25,000,000 2,020,00010/14/202210/15/199210/14/202210/15/1992 20
5,000,000 411,50001/20/202301/20/199301/20/202301/20/1993 21
4,000,000 329,20001/20/202301/29/199301/20/202301/29/1993 22
23
27,000,000 1,960,20007/21/202307/22/199307/21/202307/22/1993 24
11,000,000 798,60007/21/202307/22/199307/21/202307/22/1993 25
15,000,000 1,084,50008/16/202308/16/199308/16/202308/16/1993 26
30,000,000 2,172,00008/16/202308/16/199308/16/202308/16/1993 27
5,000,000 337,50009/14/202309/14/199309/14/202309/14/1993 28
2,000,000 135,00009/14/202309/14/199309/14/202309/14/1993 29
2,000,000 134,40009/14/202309/14/199309/14/202309/14/1993 30
20,000,000 1,350,00010/26/202310/26/199310/26/202310/26/1993 31
16,000,000 1,080,00010/26/202310/26/199310/26/202310/26/1993 32
FERC FORM NO. 1 (ED. 12-96)Page 257.1
33 7,031,538,000 358,380,033
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
/ /2014/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.
91,396 12,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 1
904,467 100,000,000 6.71% Series G Medium-Term Notes due Jan. 15, 2026 2
68,390,159 6,762,523,000Subtotal - First Mortgage Bonds 3
4
Pollution Control Obligations - Secured by Pledged First Mortgage Bonds: 5
6
874,159 40,655,000 Poll Ctrl Rev Refunding Bonds, Moffat County, CO, Series 1994 7
510,479 21,260,000 Poll Ctrl Rev Refunding Bonds, Sweetwater County, WY, Series 1994 8
209,777 8,190,000 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1994 9
3,274,246 121,940,000 Poll Ctrl Rev Refunding Bonds, Emery County, UT, Series 1994 10
206,519 9,365,000 Poll Ctrl Rev Refunding Bonds, Carbon County, UT, Series 1994 11
422,858 15,060,000 Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1994 12
155,970 17,000,000 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1988 13
771,836 45,000,000 Poll Ctrl Rev Refunding Bonds, Lincoln Cnty, WY, Series 1991 14
122,887 15,000,000 Poll Ctrl Revenue Bonds, Sweetwater County, WY, Series 1984 15
105,000 16 D
304,824 8,500,000 Poll Ctrl Revenue Bonds, City of Forsyth, MT, Series 1986 17
132,043 5,300,000 Environ. Imprvmnt Rev Bonds, Converse County, WY, Series 1995 18
404,262 22,000,000 Environ. Imprvmnt Rev Bonds, Lincoln County, WY, Series 1995 19
7,494,860 329,270,000Subtotal Pollution Control Obligations - Secured by Pledged First Mortgage Bonds 20
21
22
Pollution Control Obligations - Unsecured: 23
24
872,505 45,000,000 Poll Ctrl Rev Refndng Bonds, Emery County, UT, Series 1991 25
380,198 45,000,000 Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Series 1988 26
422,443 50,000,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Series 1988A 27
351,905 41,200,000 Poll Ctrl Rev Refndng Bonds, City of Gillette, WY, Ser. 1988 28
84,822 11,500,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988B 29
660,750 70,000,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1990A 30
167,524 9,335,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992A 31
242,163 22,485,000 Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 32
FERC FORM NO. 1 (ED. 12-96)Page 256.2
33 TOTAL 7,417,018,000 79,444,237
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
/ /2014/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.
12,000,000 810,00010/26/202310/26/199310/26/202310/26/1993 1
100,000,000 6,710,00001/15/202601/23/199601/15/202601/23/1996 2
6,461,198,000 350,990,958 3
4
5
6
-1405/01/201311/17/199405/01/201311/17/1994 7
21,260,000 354,37811/01/202411/17/199411/01/202411/17/1994 8
8,190,000 138,87311/01/202411/17/199411/01/202411/17/1994 9
121,940,000 2,022,02911/01/202411/17/199411/01/202411/17/1994 10
9,365,000 157,77211/01/202411/17/199411/01/202411/17/1994 11
15,060,000 270,71811/01/202411/17/199411/01/202411/17/1994 12
-2,22201/01/201401/01/198801/01/201401/01/1988 13
45,000,000 555,93301/01/201601/17/199101/01/201601/17/1991 14
105,52312/01/201412/01/198412/01/201412/01/1984 15
16
8,500,000 57,15712/01/201612/01/198612/01/201612/01/1986 17
5,300,000 29,79211/01/202511/17/199511/01/202511/17/1995 18
22,000,000 145,88911/01/202511/17/199511/01/202511/17/1995 19
256,615,000 3,835,828 20
21
22
23
24
45,000,000 733,37507/01/201505/23/199107/01/201505/23/1991 25
45,000,000 728,64801/01/201801/01/198801/01/201801/01/1988 26
50,000,000 430,23401/01/201701/01/198801/01/201701/01/1988 27
41,200,000 338,98701/01/201801/01/198801/01/201801/01/1988 28
-4,89601/01/201401/01/198801/01/201401/01/1988 29
70,000,000 703,61007/01/201507/25/199007/01/201507/25/1990 30
9,335,000 92,76212/01/202009/29/199212/01/202009/29/1992 31
22,485,000 220,05412/01/202009/29/199212/01/202009/29/1992 32
FERC FORM NO. 1 (ED. 12-96)Page 257.2
33 7,031,538,000 358,380,033
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
/ /2014/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.
151,908 6,305,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992B 1
225,000 24,400,000 Environ. Imprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 2
3,559,218 325,225,000Subtotal - Pollution Control Obligations - Unsecured 3
4
5
79,444,237 7,417,018,000TOTAL ACCOUNT 221 6
7
Reacquired Bonds: (Account 222) 8
9
Advances from Associated Companies: (Account 223) 10
11
Other Long-Term Debt: (Account 224) 12
13
14
Long-Term Debt Authorized but Unissued 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 256.3
33 TOTAL 7,417,018,000 79,444,237
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
/ /2014/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.
6,305,000 63,43212/01/202009/29/199212/01/202009/29/1992 1
24,400,000 247,04111/01/202512/14/199511/01/202512/14/1995 2
313,725,000 3,553,247 3
4
5
7,031,538,000 358,380,033 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
FERC FORM NO. 1 (ED. 12-96)Page 257.3
33 7,031,538,000 358,380,033
Schedule Page: 256 Line No.: 22 Column: a
In March 2014, PacifiCorp issued $425 million of its 3.60% First Mortgage Bonds due April
2024. 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.: 7 Column: i
Interest refund received.
Schedule Page: 256.2 Line No.: 13 Column: i
Interest refund received.
Schedule Page: 256.2 Line No.: 29 Column: i
Interest refund received.
Schedule Page: 256.3 Line No.: 6 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.: 6 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 all such interest was accrued on amounts included in Account 233, Notes
payable to associated companies.
Schedule Page: 256.3 Line No.: 15 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 ($1.575 billion authorized; $1.575
billion available as of December 31, 2014), 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, 2014) 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,
2014) 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
2014/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
/ /2014/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.
697,859,628Net Income for the Year (Page 117) 1
2
3
Taxable Income Not Reported on Books 4
5
6
7
92,436,304Other 8
Deductions Recorded on Books Not Deducted for Return 9
10
11
12
1,325,973,022Other 13
Income Recorded on Books Not Included in Return 14
15
16
17
57,848,632Other 18
Deductions on Return Not Charged Against Book Income 19
20
21
22
23
24
1,828,618,654Other 25
-7,579,764State Tax Deductions 26
222,221,904Federal Tax Net Income 27
Show Computation of Tax: 28
29
77,777,666Federal Income Tax at 35.00% 30
-19,317,309Provision to Return Adjustment 31
16,580Tax Reserve Changes 32
-67,845,972Renewable Energy Production Tax Credits 33
-149,682Other Federal Tax Credits 34
35
-9,518,717Federal Income Tax Accrual 36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96)Page 261
Schedule Page: 261 Line No.: 8 Column: a
Particulars (Details) Amounts
Contribution in Aid of Construction 74,536,326
Deferred Revenue - Lease Incentives 279,558
Regulatory Asset - REC Sales Deferral - OR - Current 414,385
Regulatory Asset - REC Sales Deferral - OR - Noncurrent 15,076
Regulatory Asset - REC Sales Deferral - UT - Noncurrent 1,199,664
Regulatory Asset - REC Sales Deferral - WY - Current 1,470,421
Regulatory Asset - REC Sales Deferral - WY - Noncurrent 1,728,031
Regulatory Asset - WA Colstrip #3 52,188
Reimbursements 1,879,476
Regulatory Liability - BPA Balancing Account - ID 1,392,822
Regulatory Liability - Deferred Excess NPC - OR - Noncurrent 6,025,257
Regulatory Liability - Depreciation Decrease - OR 854,995
Regulatory Liability - Depreciation Decrease - WA 668,497
Regulatory Liability - Sale of REC - OR - Current 404,974
Regulatory Liability - UT Home Energy Lifeline 1,048,013
Regulatory Liability - WA Low Energy Program 186,554
Transmission Service Deposit 200,763
Trapper Mining Stock Basis 50,479
Unearned Joint Use Pole Contact Revenue 28,825
Total $ 92,436,304
Schedule Page: 261 Line No.: 13 Column: a
Particulars (Details) Amounts
Fed/State Tax Expense 300,420,980
Fed/State Tax Expense-Interest 1,010,061
50% Meals and Entertainment 868,859
Accrued Bonus 84,982
Accrued Final Reclamation 2,440,579
Accrued Royalties 38,339
Accrued Severance 1,044,553
Avoided Costs 39,260,939
Bear River Settlement Agreement 239,318
Book Cost Depletion 1,167,298
Book Depreciation 784,239,359
Book Depreciation Allocated to Medicare and M&E 70,328
Capitalization of Test Energy 9,961,641
Deferred Coal Costs - Naughton Contract Settlement 1,376,154
Deferred Compensation - Noncurrent 516,674
FAS 112 Book Reserve - Postemployment Benefits 2,031,113
FAS 158 Post-Retirement Liability 2,560,420
Fuel Cost Adjustment 1,250,016
Hermiston Swap 171,693
Hydro Relicensing Obligation 1,342,957
Income Tax Interest 33,464
Injuries and Damages Accrual - Cash Basis 6,566,251
Joseph Settlement 137,381
Lewis River Settlement Agreement 66,619
Lobbying Expenses 1,863,970
LT Incentive Plan - Noncurrent 6,935,250
LT Prepaid IBEW 57 Pension Contribution 5,642,903
Medicare Subsidy 5,538,043
Mine Rescue Training Credit Addback 38,764
Miscellaneous Current and Accrued Liability 3,223,493
Oregon Regulatory Asset/Regulatory Liability Consolidation 6,250
Other Environmental Liabilities 10,472
Penalties 1,639,702
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Pension/Retirement Accrual 118,135
Prepaid Aircraft Maintenance 86,725
Regulatory Asset - Chehalis Generating Facility Deferral - WA 3,000,000
Regulatory Asset - Cholla Plant Transaction Costs 1,122,425
Regulatory Asset - Deferred Excess NPC - ID - Noncurrent 4,676,756
Regulatory Asset - Deferred Excess NPC - WY - Current 1,494,117
Regulatory Asset - Deferred Excess NPC - WY '09 & After - Noncurrent 10,702,399
Regulatory Asset - Deferred Intervenor Funding Grants - ID 16,431
Regulatory Asset - DSM Balance Reclass 25,255,409
Regulatory Asset - Environmental Costs - WA 351,452
Regulatory Asset - FAS 158 Pension Liability 29,529,090
Regulatory Asset - FAS 158 Post Retirement Liability 1,946,135
Regulatory Asset - GHG Allowances - CA - Current 1,988,530
Regulatory Asset - Goodnoe Hills Settlement - WY 21,250
Regulatory Asset - Klamath Hydroelectric Relicensing Costs - UT 2,843,628
Regulatory Asset - Lake Side Settlement - WY 27,331
Regulatory Asset - Liquidation Damages - N2 - WY 5,708
Regulatory Asset - Naughton Unit #3 Costs - CA 51,021
Regulatory Asset - Naughton Unit #3 Costs - ID 239,494
Regulatory Asset - Naughton Unit #3 Costs - UT 1,205,417
Regulatory Asset - Naughton Unit #3 Costs - WY 555,186
Regulatory Asset - OR Asset Sale Gain GB - Current 140,166
Regulatory Asset - OR Sch94 Distribution Safety Surcharge 375,629
Regulatory Asset - Pension MMT - UT 283,176
Regulatory Asset - Post Merger Loss - Reacquired Debt 905,935
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 26,216
Regulatory Asset - Powerdale Decommissioning - WA 70,981
Regulatory Asset - Tax Revenue Requirement Adj - WY 17,633
Regulatory Asset - UT Liquidation Damages 35,000
Regulatory Asset - Utah ECAM 27,889,661
Regulatory Liability - ARO/Reg Diff - Trojan - WA Portion 8,242
Regulatory Liability - Blue Sky - CA 45,601
Regulatory Liability - Blue Sky - ID 32,279
Regulatory Liability - Blue Sky - OR 91,771
Regulatory Liability - Blue Sky - UT 233,319
Regulatory Liability - Blue Sky - WA 16,222
Regulatory Liability - Blue Sky - WY 64,230
Regulatory Liability - Deferred Excess NPC - WA - Current 9,513
Regulatory Liability - Injuries & Damages Reserve - OR 2,971,603
Regulatory Liability - Property Insurance Reserve - ID 66,424
Regulatory Liability - Property Insurance Reserve - OR 590,939
Regulatory Liability - Property Insurance Reserve - UT 1,175,615
Regulatory Liability - Property Insurance Reserve - WY 231,315
Regulatory Liability - Solar Feed-in Tariff Deferral - CA - Current 821,873
Regulatory Liability - Solar Incentive Program - UT - Current 4,134,727
Regulatory Liability - Trojan Decommissioning 154,870
TGS Buyout 15,474
USA Power Litigation 2,480,165
Utah Mine Disposition 14,524,828
Western Coal Carrier Retiree Medical Accrual 602,000
Intercompany adjustment 432,980
Total $ 1,325,973,022
Schedule Page: 261 Line No.: 18 Column: a
Particulars (Details) Amounts
Dividend Received Deduction - Deferred Compensation (97,316)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Foote Creek Contract (137,640)
Investment Gain/Loss - Current (6,597)
MCI F.O.G. Wire Lease (77)
Officer's Life Insurance (6,143,752)
Redding Contract (549,996)
Regulatory Asset - BPA Balancing Account - OR (1,468,531)
Regulatory Asset - BPA Balancing Account - WA (316,957)
Regulatory Asset - REC Sales Deferral - UT - Current (4,060,810)
Regulatory Asset - REC Sales Deferral - WA - Current (1,843,964)
Regulatory Asset - REC Sales Deferral - WA - Noncurrent (3,073,273)
Regulatory Liability - Alt Rate for Energy Program (CARE) - CA - Current (221,063)
Regulatory Liability - BPA Balancing Account - OR (211,995)
Regulatory Liability - BPA Balancing Account - WA (149,739)
Regulatory Liability - GHG Allowance Revenues - CA - Current (6,201,433)
Regulatory Liability - OR 2012 GRC Giveback - Noncurrent (1,181,807)
Regulatory Liability - Sale of REC - UT - Current (1,521,547)
Regulatory Liability - Sale of REC - WA - Current (14,121,277)
Regulatory Liability - SMUD Revenue Imputation - UT (1,823,147)
Unrealized Gain/Loss from Trading Securities (136,644)
Equity Earnings in Subsidiaries (14,581,067)
Total $ (57,848,632)
Schedule Page: 261 Line No.: 25 Column: a
Particulars (Details) Amounts
Accrued Vacation (8,896,278)
Amortization NOPAs 99-00 RAR (50,796)
Basis Intangible Difference (164,861)
Book Fixed Asset Gain/Loss (310,850)
Capitalized Depreciation (5,051,360)
Capitalized labor and benefit costs (2,662,821)
Cholla SHL NOPA (Lease Amortization) (162,147)
Coal Pile Inventory Adjustment (7,672,640)
Cost of Removal (46,586,700)
CWIP Reserve (3,721,441)
Debt AFUDC (25,240,671)
Deferred Revenue - Citibank (154,403)
Deseret Settlement Receivable (104,502)
Environmental Liability - Non-regulated (316,833)
Environmental Liability - Regulated (2,129,561)
Equity AFUDC-Temp (50,545,926)
FAS 158 Pension Liability (17,063,795)
FAS 158 SERP Liability (1,146,920)
Federal Tax Depreciation (1,246,168,964)
Federal Tax Fixed Asset Gain/Loss (4,980,604)
Insurance Reserve - Current (50,097,374)
Inventory Reserve (618,500)
MEHC Insurance Services - Receivable (69,076)
N Umpqua Settlement Agreement (188,658)
Non-deductible Post-Retirement Costs (5,538,043)
Pre-1943 Preferred Stock Dividend - Deduction (64,760)
Prepaid IBEW 57 Pension Contribution - Current (4,200,000)
Prepaid Membership Fees (3,460,390)
Prepaid Surety Bond (158,745)
Prepaid Taxes - ID PUC (51,552)
Prepaid Taxes - OR PUC (57,637)
Prepaid Taxes - Property Taxes (404,491)
Prepaid Taxes - UT PUC (40,515)
Prepaid Water Rights (689,556)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Regulatory Asset - Carbon Unrecovered Plant - ID (2,106,371)
Regulatory Asset - Carbon Unrecovered Plant - UT (14,599,216)
Regulatory Asset - Carbon Unrecovered Plant - WY (5,329,679)
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 (1,209,396)
Regulatory Asset - Deferred Excess NPC - CA - Noncurrent (1,094,009)
Regulatory Asset - Deferred Excess NPC - ID - Current (5,788,650)
Regulatory Asset - Deferred Excess NPC - UT - Current (7,203,350)
Regulatory Asset - Deferred Excess NPC - UT - Noncurrent (12,552,136)
Regulatory Asset - Deferred Independent Evaluator Fee - UT (62,151)
Regulatory Asset - Deferred Intervenor Funding Grants - CA (40)
Regulatory Asset - Deferred Intervenor Funding Grants - OR (266,642)
Regulatory Asset - Deferred Overburden Costs - ID (69,339)
Regulatory Asset - Deferred Overburden Costs - WY (183,793)
Regulatory Asset - Demand Side Management - Current (20,402,455)
Regulatory Asset - Demand Side Management - Noncurrent (25,255,409)
Regulatory Asset - Depreciation Increase - ID (1,589,451)
Regulatory Asset - Depreciation Increase - UT (2,112,712)
Regulatory Asset - Depreciation Increase - WY (7,296,150)
Regulatory Asset - Environmental Costs (3,382,277)
Regulatory Asset - OR Asset Sale Gain GB - Noncurrent (6,945)
Regulatory Asset - OR Sch 203 Black Cap Solar (11,572)
Regulatory Asset - Post Employment Costs (626,647)
Regulatory Asset - Pref Stock Redemption - WY (261,901)
Regulatory Asset - Pref Stock Redemption Loss - UT (759,970)
Regulatory Asset - Solar Feed-In Tariff Deferral - OR - Current (823,055)
Regulatory Asset - Solar Feed-in Tariff Deferral - OR - Noncurrent (92,506)
Repairs Deduction (156,673,269)
Reserve for Bad Debts (1,338,678)
Regulatory Liability - Contra-Carbon Decommissioning - ID (966,650)
Regulatory Liability - Contra-Carbon Decommissioning - UT (6,743,936)
Regulatory Liability - Contra-Carbon Decommissioning - WY (2,460,237)
Regulatory Liability - Deferred Excess NPC - OR - Current (2,273,466)
Regulatory Liability - Demand Side Management - Current (4,852,954)
Regulatory Liability - OR Energy Conservation Charge (432,204)
Rogue River - Habitat Enhancement Liability (7,201)
Sec. 481a Adjustment - Repair Deduction (43,322,360)
Tax Depletion-SRC (174,980)
Tax Percentage Depletion - Blundell Steam Field (482,315)
Tax Percentage Depletion - Deer Creek (5,491,852)
Wasatch Workers Comp Reserve (251,014)
Total $ (1,828,618,654)

Schedule Page: 261 Line No.: 36 Column: b
Berkshire Hathaway Inc. includes PacifiCorp in its United States Federal Income Tax
Return. PacifiCorp's provision for income taxes has been computed on a stand-alone basis.
Names of group members who will file a consolidated United States Federal Income Tax
Return:
Under Berkshire Hathaway Energy ("BHE"):
PPW Holdings LLC Sub-Group:
PacifiCorp
PPW Holdings 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
PacifiCorp Sub-Group:
Energy West Mining Company
Glenrock Coal Company
Interwest Mining Company
Pacific Minerals, Inc
BHE Sub-Group:
Alaska Gas Transmission Company, LLC
American Pacific Finance Company
American Pacific Finance Company II
AVSP 1B, LLC
AVSP 2B, LLC
Berkshire Hathaway Energy Company
BG Energy Holding Company LLC
BG Energy LLC
BHE AC Holding, LLC
BHE America Transco, LLC
BHE California Utility Holdco, LLC
BHE Canada, LLC
BHE Geothermal, LLC
BHE Hydro, LLC
BHE Renewables, LLC
BHE Solar, LLC
BHE Texas Transco, LLC
BHE U.K. Electric, Inc
BHE U.K. Inc
BHE U.K. Power, Inc
BHE U.S. Transmission, LLC
BHE Wind, 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
CE Administrative Services, Inc
CE Black Rock Holdings LLC
CE Butte Energy Holdings LLC
CE Butte Energy LLC
CE Electric (NY), Inc
CE Exploration Company
CE Geothermal, Inc.
CE Indonesia Geothermal, Inc
CE International Investments, Inc
CE Obsidian Energy LLC
CE Obsidian Holding LLC
CE Red Island Energy Holdings LLC
CE Red Island Energy LLC
Cordova Energy Company, LLC
Cordova Funding Corporation
IES Holding LLC
Intelligent Energy Solutions LLC
Jumbo Road Holdings, 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
M & M Ranch Acquisition Company LLC
M & M Ranch Holding Company LLC
MEHC Insurance Services Ltd.
MEHC Investment, Inc
MEHC Merger Sub Inc
MidAmerican Central California Transco LLC
MidAmerican Energy Machining Services LLC
MidAmerican Funding, LLC
MidAmerican Geothermal Development Corp
MidAmerican Nuclear Energy Company LLC
Midwest Power Transmission Illinois LLC
Midwest Power Transmission Iowa LLC
NNGC Acquisition LLC
Northern Aurora Inc
Pinyon Pines I Holding Company, LLC
Pinyon Pines II Holding Company, LLC
Pinyon Pines Wind I, LLC
Pinyon Pines Wind II, LLC
Quad Cities Energy Company
S.W. Hydro, Inc.
Salton Sea Minerals Corporation
Solar Star 3, LLC
Solar Star California XIX, LLC
Solar Star California XX, LLC
Solar Star Funding, LLC
Solar Star Projects Holdings, LLC
SSC XIX, LLC
SSC XX, LLC
Topaz Solar Farms, LLC
TPZ Holding, LLC
TX Jumbo Road Wiind, LLC
Wailuku Holding Company LLC
Wailuku Investment LLC
Wailuku River Hydroelectric Power Co, Inc.
Kern River Funding Corporation
KR Acquisition 1, LLC
KR Acquisition 2, LLC
KR Holding, LLC
Cimmred Leasing Company
Dakota Dunes Development Company
DCCO, Inc
MEC Construction Services Company
MHC Investment Company
MHC, Inc
MidAmerican Energy Company
Midwest Capital Group, Inc
MWR Capital, Inc
Two Rivers, Inc
Northern Natural Gas Company
Commonsite, Inc.
GPSF-B
Lands of Sierra, Inc.
Nevada Electric Investment Company
Nevada Power Company d/b/a NV Energy
NV Energy, Inc. fka Sierra Pacific Resources
NVE Holdings, LLC
NVE Insurance Co, Inc.
Pinon Pine 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
Pinon Pine Investment Company
Sierra Gas Holding Company
Sierra Pacific Power Company d/b/a NV Energy
Big Spring Pipeline Company
CalEnergy Operating Corporation
California Energy Development Corporation
California Energy Management Company
California Energy Yuma Corporation
CE Gen Oil Company
CE Gen Pipeline Corporation
CE Gen Power Corporation
CE Generation LLC
CE Leathers Company
CE Salton Sea Inc
CE Texas Energy, LLC
CE Texas Fuel LLC
CE Texas Pipeline LLC
CE Texas Power LLC
CE Texas Resources LLC
CE Turbo LLC
Conejo Energy Company
Del Ranch Company
Desert Valley Company
Elmore Company
Falcon Power Operating Company
FSRI Holdings, Inc
Imperial Magma LLC
Magma Land Company I
Magma Power Company
Niguel Energy Company
Norcon Holdings, Inc
Northern Consolidated Power, Inc
Salton Sea Brine Processing Company
Salton Sea Funding Corporation
Salton Sea Power Company
Salton Sea Power Generation Company
Salton Sea Power LLC
Salton Sea Royalty Company
San Felipe Energy Company
Saranac Energy Company, Inc
SECI Holdings, Inc
VPC Geothermal LLC
Vulcan Power Company
Vulcan/BN Geothermal Power Company
Arizona HomeServices, LLC
BHH KC Real Estate, LLC
California Title Company
Capitol Title Company
CBSHome Commerical, LLC
CBSHome Real Estate Company
CBSHome Real Estate of Iowa, Inc
CBSHome Relocation Services, Inc
Champion Realty, Inc
Chancellor Title Services, Inc
Columbia Title of Florida, Inc
Connecticut Referral Group, L.L.C.
CTHM, L.L.C.
CTRE, L.L.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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
Edina Financial Services, Inc
Edina Realty Referral Network, Inc
Edina Realty Relocation, Inc
Edina Realty Title, Inc
Edina Realty, Inc
Esslinger-Wooten-Maxwell, Inc
E-W-M Referral Services, Inc.
F&R/T LLC
FFR, Inc
First Realty, Ltd
First Reserve Insurance, Inc
For Rent, Inc
FRTC, LLC
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
HomeServcies Lending, LLC
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 Illinois Holdings, LLC
HomeServices of Illinois Holdings, LLC
HomeServices of Iowa, Inc
HomeServices of Kentucky, Inc
HomeServices of MOKAN, LLC
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
Intero Franchise Services, Inc.
Intero Real Estate Holdings, Inc.
Intero Real Estate Services, Inc.
Intero Referral Services, Inc.
Iowa Realty Company, Inc
Iowa Realty Insurance Agency, Inc
Iowa Title Company
J.S. White Associates, Inc
JBRC, Inc
Jim Huff 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
JRHBW Realty, Inc d/b/a RealtySouth
Kansas City Title, Inc
Kentucky Residential Referral, LLC
Larabee School of Real Estate & Insurance, Inc
Mid-America Referral Network, Inc.
Midland Escrow Services, Inc
Midwest Realty Ventures, LLC
Nebraska Land Title & Abstract Company
Nebraska Referral, Inc.
NMA, LLC
NRS Referral Services, LLC
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
PNW Referral, LLC
PPW Staffers, LLC
Preferred Carolinas Realty, Inc
Preferred Carolinas Title Agency, LLC
Professional Referral Organization, Inc
PW Fox Holding LLC
PW Fox, LLC
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
San Diego PCRE, Inc
Semonin Realtors, Inc
Southwest Relocation, LLC
Sterling Title Services, LLC
The Escrow Firm
The Referral Company
TIAC LLC
TitleSouth, LLC
TLTC LLC
TRMC LLC
Wm Broughton, LLC
With respect to members of the BHE Sub-Group, BHE requires all subsidiaries to pay or
receive from BHE 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:
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
Berkshire Hathaway Inc.
Berkshire Hathaway Automotive Inc.
Berkshire Hathaway Credit Corporation
BH Columbia Inc.
Berkshire Hathaway Finance Corporation
Railsplitter Holdings Corporation
Acme Brick Company
Acme Brick DFW, Inc.
Acme Brick Sales Company
Acme Ochs Brick and Stone, Inc.
American Tile and Stone, Inc
Innovative Building Products, Inc
Alpha Cargo Motor Express, Inc
Acme Brick Tile & Stone, Inc. (fka Brick Acquisition Company)
Acme Building Brands, Inc
Acme Investment Company
Acme Management Company
Acme Services Company, L.P.
Denver Brick Company
Edmonds Material and Equipment Co.
Justin Industries, Inc.
AEG Processing Center No. 35, Inc.
AEG Processing Center No. 58, Inc.
Applied Processing Center No. 60, Inc.
American Employers Group, Inc.
Applied Group Insurance Holdings, Inc.
Applied Investigations Inc.
Applied Logistics, Inc.
Applied Premium Finance, Inc.
Applied Risk Services of New York, Inc.
Applied Risk Services, Inc.
AU Holding Company, Inc.
Applied Underwriters, Inc.
AU Captive Risk Assurance Co.
BH, LLC
Berkshire Indemnity Group Inc.
Combined Claims Services, Inc.
Coverage Dynamics Group, Inc.
Commercial General Indemnity, Inc.
California Insurance Company
Continental Indemnity Company
Applied Underwriters Captive Risk Assurance Company, Inc.
Illinois Insurance Company
North American Casualty Co.
Promesa Health, Inc.
Pennsylvania Insurance Company
Strategic Staff Management, Inc.
Texas Insurance Company
The Ben Bridge Corporation
Ben Bridge Jeweler, Inc.
Benjamin Moore & Co.
Complementary Coatings Corporation
Eco Color Company
The Indecor Group, Inc.
Burlington Northern Santa Fe, LLC
FreightWise, Inc.
Burlington Northern Santa Fe Insurance Company, Ltd.
BNSF Logistics International, Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
Royal Cargo Lines
Albacor Shipping (USA) Inc.
BNSF Railway Company
Bayport Systems, Inc.
Burlington Northern Santa Fe Manitoba, Inc.
Los Angeles Junction Railway Company
Star Lake Railroad Company
The BN and SF Railway de Mexico, S.A. de C.V.
The Zia Company
Santa Fe Pacific Pipeline Holdings, Inc.
Burlington Northern Santa Fe British Columbia, Ltd.
Pine Canyon Land Company
Santa Fe Pacific Insurance Company
Santa Fe Pacific Railroad Company
Western Fruit Express Company
Burlington Northern Railroad Holdings, Inc.
Winona Bridge Railroad Company
BNSF Railway International Services, Inc.
BN Leasing Corporation
Midwest Northwest Properties, Inc.
Santa Fe Pacific Pipelines, Inc.
BNSF Communications, Inc.
BNSF Spectrum, Inc.
Borsheim Jewelry Company, Inc
Brooks Sports, Inc.
Total Quality Apparel Resources
The Buffalo News, Inc.
Business Wire, Inc.
Charter Brokerage Holdings Corp.
DL Trading Holdings I, Inc.
Clayton Commercial Buildings, Inc.
CMH Hodgenville, Inc.
CMH Manufacturing, Inc.
CMH Set and Finish, Inc.
CMH Manufacturing West, Inc.
AL/TEX Homes, Inc.
BR Agency, Inc.
Giles Industries, Inc.
Southern Energy Homes, Inc.
CMH Transport, Inc.
Cavalier Homes, Inc.
Fontana Wood Products, Inc.
Fontana Wood Products of Oregon, Inc.
CMH Homes, Inc.
CMH of KY, Inc.
CMH Parks, Inc.
Chatwell, Inc.
Freedom Warehouse Corp.
Vanderbilt ABS Corp.
Vanderbilt Mortgage and Finance, Inc.
Vanderbilt SPC, Inc.
Vanderbilt Property&Casualty Insurance Co., Ltd.
Homefirst Agency, Inc.
21st Communities, Inc.
21st Mortgage Corporation
Henley Holdings, LLC
21 SPC, Inc.
Clayton Homes, 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.11
CMH Capital, Inc.
CMH Services, Inc.
Clayton Education Corp.
Cort Business Services Corporation
Central States of Omaha Companies, Inc.
Central States Indemnity Co. of Omaha
CSI Life Insurance Company
Roxell USA, Inc. (fka Agile Manufacturing Inc.)
CTB Credit Corp
CTB Inc.
CTB International Corp
Ironwood Plastics Inc
CTB IW INC
CTB Midwest
CTB MN Investments
Meyn LLC
International Dairy Queen, Inc.
American Dairy Queen Corporation
DQF, Inc.
DQGC, Inc.
Unified Supply Chain, Inc.
DQ Funding Corporation
Dairy Queen Of Georgia, Inc.
Golden Skillet International, Inc.
Karmelkorn Shoppes, Inc.
Orange Julius Of America
Dairy Queen Corporate Stores, Inc.
DQ Managed Stores, Inc.
DQ Wholly-Owned Stores, Inc.
DQ Joint Venture Stores, Inc.
PJR Management, Inc.
All Bilt Uniforms
Commonwealth Uniforms Inc.
Crowley Garment Mfg Co Inc.
Crowley Shirt Mfg Co Inc.
The Eagle Company
Farriors, Inc.
The Fechheimer Brothers Co.
Fulton Manufacturing Company
Great Plains Uniforms
Griffey Uniforms
Harris Uniforms
Martin Manufacturing Company
McCain Uniform Company Inc.
Metro Uniforms
Nick Bloom Uniforms
Nationwide Uniforms
Roberts Men's Shop
Silver State Uniforms
Simon's Incorporated
Sol Frank Uniforms Inc.
Uniforms of Texas
Universal Uniforms
Waynesburg Shirt Company Inc.
Zuckerbergs Uniforms
Fruit of the Loom, Inc.
Union Underwear Co., Inc
Cumberland Asset Management, 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.12
Fruit of the Loom Direct, Inc.
Vanity Fair, Inc.
VFI-Mexico, Inc.
The BVD Licensing Corporation
Russell Athletic Corporation
Martin Mills, Inc.
Camp Manufacturing Company
Leesburg Yarn Mills, Inc.
Rabun Apparel, Inc.
FTL Regional Sales Co., Inc.
Union Sales, Inc.
Fruit of the Loom Trading Company
Fruit of the Loom, Inc. (Sub)
Forest River Financial Services, Inc.
Forest River Housing, Inc.
Forest River, Inc.
Forest River Manufacturing LLC
Mapletree Transportation, Inc.
Priority One Financial Services, Inc.
Veritas Insurance Group, Inc.
FlightSafety Capital Corp.
FlightSafety Development Corp.
FlightSafety International Inc.
FlightSafety New York, Inc.
FlightSafety Properties, Inc.
FlightSafety Services Corporation
Garan Central America Corp.
Garan Incorporated
Garan Manufacturing Corp.
Garan Services Corp
Criterion Insurance Agency
GEICO Corporation
Government Employees Financial Corp.
GEICO Insurance Agency
GEICO Products, Inc.
International Insurance Underwriters, Inc.
Maryland Ventures, Inc..
Plaza Financial Services Co.
Plaza Resources Co.
Top Five Club, Inc.
GEICO Advantage Insurance Company
GEICO Casualty Co.
GEICO Choice Insurance Company
GEICO General Insurance Co.
Government Employees Insurance Co.
GEICO Indemnity Co.
GEICO Secure Insurance Company
General Re Corporation
Elm Street Corporation
GRD Holdings Corporation
Gen Re Intermediaries Corporation
General Re New England Asset Management
Genesis Management and Insurance Services Corporation
General Star Management Company
United States Aviation Underwriters, Incorporated
General Re Financial Products Corporation
General Reinsurance Corporation
Faraday Capital Limited
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.13
Genesis Insurance Company
General Star Indemnity Company
General Star National Insurance Company
Helzberg's Diamond Shops, Inc.
HDS Redevelopment Corporation
H. H. Brown Shoe Company, Inc.
BH Shoe Holdings, Inc.
Vision Retailing, Inc.
American All Risk Insurance Services Inc.
American Commercial Claims Administrators Inc
Brookwood Insurance Company
Berkshire Hathaway Homestate Insurance Company
Continental Divide Insurance Company
Cypress Insurance Company
Oak River Insurance Company
Redwood Fire and Casualty Insurance Company
D.I. Properties Inc.
IMC Group USA Holdings, Inc.
Ingersoll Cutting Tool Company
IMC Investment Holding Inc
Iscar Metals Inc.
Taegutec Inc.
Tool-Flo Manufacturing, Inc.
Boot Royalty Company
Chippewa Shoe Company
Footwear Investment Company
H.J. Justin & Sons, Inc.
Justin Belt Company, Inc.
Justin Brands, Inc.
Justin Boot Company
J.S Justin, Inc.
Nocona Boot Company
Tony Lama Company
Johns Manville Corporation
Johns Manville, Inc.
Seventeenth Street Realty, Inc.
Johns Manville China, Ltd.
Jordan's Furniture, Inc.
Albecca, Inc.
Active Organics, Inc.
Lubrizol Inter-Americas Corporation
Lubrizol Advanced Materials China, Inc.
The Lubrizol Corporation
Chemtool Incorporated
Lubrizol Advanced Materials FCC, Inc.
Lubrizol Specialty Products, Inc. FKA Phillips Specialty Products, Inc
Lubrizol Advanced Materials Holding Corporation
Lubrizol Advanced Materials International, Inc.
Lipotec Group Corp.
Lubrizol Enterprises, Inc.
Lubrizol International Management Corporation
Lubrizol Overseas Trading Corporation
LSP Holding, Inc.
MPP Pipeline Corporation
Noveon Hilton Davis, Inc.
Lubrizol Advanced Materials, Inc.
Lubrizol Oilfield Solutions, Inc.
P Chem, 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.14
Lubrizol Advanced Materials Gibraltar, Inc.
Syrgis Holdings, Inc.
Vesta Funding, Inc.
Vesta Intermediate Funding, Inc.
ExtruMed, Inc.
SSP-SiMatrix Inc.
Lubricant Investments, Inc.
Warwick Chemicals USA, Inc.
Marmon Water, Inc.
Marmon Crane Services, Inc.
Marmon Electrical & Plumbing Distribution Products, Inc.
Marmon Engineered Components Company
Marmon Retail Technologies Company
Marmon Wire & Cable, Inc.
Lockwood Street Urban Renewal Corporation
Ecodyne Corporation
J.L. Mining Company
Fontaine Truck Equipment Company
Marmon Retail Products, Inc.
Morgantown-National Supply, Inc.
Procrane Holdings, Inc.
RCP Investment, Inc.
Tucker Safety Products, Inc.
Artform International Inc.
DCI Marketing Inc.
Marmon Merchandising Holdings, Inc.
Marmon Beverage Technologies, Inc.
Cornelius Renew, Inc.
3Wire Group Inc.
Cornelius Inc.
HG-Power Plant. Inc.
Marmon Energy Services Company
UTLX Company
Penn Coal Land, Inc.
Penn Pocahontas Coal Co.
TRH Holding Corp.
Precision Millwork Settings LLC
Marmon Holdings, Inc.
Webb Wheel Products, Inc.
Perfection Hy-Test Company
Marathon Suspension Systems, Inc.
Fontaine Trailer Company
Fontaine Modification Company
Fontaine Fifth Wheel Company
Fontaine Commercial Trailer, Inc.
Fontaine Engineered Products, Inc.
Marmon-Herrington Company
Triangle Suspension Systems, Inc.
Fontaine Spray Suppression Company
TSE Brakes, Inc.
Union Tank Car Company
Uni-Form Components Co.
Marmon Distribution Services, Inc.
Railserve, Inc.
Tiger-Sunbelt Industries, Inc.
Worldwide Containers, Inc.
Exsif Worldwide, Inc.
Marmon Beverage Technologies Espana, S.A. (fka IMI Cornelius Expana SA)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.15
McLane Southern, Inc.
McLane Western, Inc.
McLane Beverage Distribution, Inc.
McLane Beverage Holding, Inc.
McLane Minnesota, Inc.
McLane Express, Inc.
JDS Properties, Inc.
Intrepid JSB, Inc.
International Traders, Inc.
First American Carriers, Inc.
Meadowbrook Meat Company, Inc.
McLane New Jersey, Inc.
Kahn Ventures, Inc.
Empire Distributors, Inc.
Empire Distributors of North Carolina, Inc.
Horizon Wine & Spirits - Nashville, Inc.
Horizon Wine & Spirits - Chattanooga, Inc.
Delta Wholesale Liquors, Inc.
Salado Sales, Inc.
McLane Foodservice, Inc.
McCarty-Hull Cigar Company, Inc.
Professional Datasolutions, Inc.
Claims Services, Inc.
M & C Products, Inc.
Transco, Inc.
McLane Company, Inc.
McLane Eastern, Inc.
McLane Midwest, Inc.
McLane Suneast, Inc.
McLane Mid-Atlantic, Inc.
C & R Insurance Services, Inc.
Medical Protective Finance Corporation
The Medical Protective Company
Medical Protective Insurance Services, Inc.
Princeton Advertising & Marketing Group, Inc.
Alexander Road Insurance Agency, Inc.
Princeton Insurance Company
Medical Protective Corporation
Princeton Risk Protection, Inc.
MedPro Risk Retention Services, Inc.
Somerset Services, Inc
Accurate Installations, Inc.
Benson, Ltd.
Benson Industries, Inc.
Cubic Designs, Inc.
Hohmann & Barnard, Inc.
MiTek Holdings, Inc.
HeatPipe Technology, Inc.
Kova Solutions, Inc.
MiTek Industries, Inc.
Miller-Sage, Inc.
Rush Air Inc
SidePlate Systems, Inc.
SSS Acquisition Inc.
TBS USA, Inc.
TMI Climate Solutions, Inc.
MiTek USA, Inc.
121 Acquisition Co., LLC
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.16
Floors, Inc.
NFM of Kansas, Inc.
LMG Ventures, LLC
Nebraska Furniture Mart, Inc.
NFM SERVICES, LLC
Homemakers Plaza, Inc.
TXFM, Inc.
WMC Corp.
First Berkshire Hathaway Life Insurance Company
Berkshire Hathaway Life Insurance Company of Nebraska
BHG Life Insurance Company
Ringwalt & Liesche Co.
Brilliant National Services, Inc.
Soco West, Inc.
Whittaker, Clark & Daniels, Inc.
L.A. Terminals, Inc.
Boat America Corporation
Boat/U.S, Inc.
BHG Structured Settlements, Inc.
Resolute Management Inc.
International American Group Inc.
International American Management Company
Northern States Agency, Inc.
Finial Holdings, Inc.
CLAL U.S. Holdings, Inc.
GUARD Financial Group, Inc.
GUARD Insurance Group, Inc.
GUARDco, Inc.
Affiliated Agency Operations Co.
InterGUARD, Ltd.
Hartford Life International, Ltd.
Consolidated Health Plans Inc.
Affordable Housing Partners, Inc.
Berkshire Hathaway Specialty Concierge, LLC
Boat Owners Association of the United States
VT Insurance Acquisition Sub Inc.
VT Real Estate Acquisition Sub Inc
American Centennial Insurance Company
WestGUARD Insurance Company
Berkshire Hathaway Assurance Corporation
EastGUARD Insurance Company
National Liability & Fire Insurance Company
National Indemnity Company of Mid-America
National Fire & Marine Insurance Company
National Indemnity Company
Atlanta International Insurance Company
Berkshire Hathaway Specialty Insurance Company
Columbia Insurance Company
NorGUARD Insurance Company
Commercial Casualty Insurance Company
Unione Italiana Reinsurance Company of America, Inc.
Seaworthy Insurance Company
Finial Reinsurance Company
National Indemnity Company of the South
AmGUARD Insurance Company
BNJ NetJets, Inc.
Executive Jet Management, Inc.
NetJets Aviation, 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.17
NetJets Europe Holdings, LLC
NetJets Inc.
NetJets International, Inc.
NetJets Large Aircraft, Inc.
NetJets Sales, Inc.
NetJets Services, Inc.
NetJets U.S., Inc.
NJE Holdings, LLC
NJI Sales, Inc.
Marquis Jet Partners, Inc.
Marquis Jet Holdings, Inc.
Brainy Toys, Inc.
OTC Brands, Inc.
OTC Direct, Inc.
Mindware Corporation
MW Wholesale, Inc.
Oriental Trading Company, Inc.
OTC Worldwide Holdings, Inc.
Smilemakers, Inc.
Smilemakers Canada Inc.
Ace Mailing Services, Inc.
BH Media Group, Inc.
BH Media Group Holdings, Inc.
LEE Distributing Services, Inc.
Mail Tech, LTD.
Omaha World-Herald Company
World Investments, Inc.
World Marketing, Inc.
World Publishing Enterprises, Inc.
World Technologies, Inc.
TPC European Holdings, LTD.
TPC North America, Ltd.
The Pampered Chef, Ltd.
Precision Steel Warehouse - Charlotte
Precision Steel Warehouse, Inc.
Precision Brand Products, Inc.
R.C. Willey Home Furnishings
Richline Group, Inc
Hallmark Sweet, Inc.
Stern/Leach Company
Rio Grande, Inc.
See's Candies, Inc
Sees Candy Shops, Incorporated
BHSF, Inc.
Ambucor Health Solutions, Inc.
ScottCare Corporation
The Scott Fetzer Company
Campbell Hausfeld/Scott Fetzer Company
Adalet/Scott Fetzer Company
Western/Scott Fetzer Company
Halex/Scott Fetzer Company
Stahl/Scott Fetzer Company
France/Scott Fetzer Company
Wayne/Scott Fetzer Company
Carefree/Scott Fetzer Company
Scott Fetzer Financial Group, Inc.
UCFS Europe Company
BH Finance, 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.18
United Consumer Financial Services Company
United Direct Finance, Inc.
World Book, Inc.
World Book Encyclopedia, Inc.
World Book/Scott Fetzer Company
SHX Leasing, Inc.
SHX Flooring, Inc.
Shaw International Services, Inc.
Pro Installations, Inc.
Shaw Contract Flooring Installation Services, Inc.
Shaw Contract Flooring Services, Inc.
Spectra Contract Flooring Puerto Rico, Inc.
Shaw Industries Group, Inc.
Shaw Industries, Inc.
Shaw Diversified Services, Inc.
Shaw Transport, Inc.
Queen Carpet Corporation
Shaw Floors, Inc.
Shaw Retail Properties, Inc.
Shaw Funding Company
Star Furniture Company
CJE II
Mouser Electronics, Inc.
Sager Electrical Supply Co. Inc
Astrex Holding Company
Astrex Electronics, Inc
TTI, Inc.
Gateway Underwriters Agency, Inc.
U.S. Investment Corporation
United States Liability Insurance Company
Mount Vernon Fire Insurance Company
Mount Vernon Specialty Insurance Company
U.S. Underwriters Insurance Co.
Blue Chip Stamps, Inc.
Montana Retail Properties, Inc.
MS Property Company
AJF Warehouse Distributors, Inc.
XTRA Finance Corporation
XTRA Intermodal, Inc.
RENTCO Trailer Corporation
X-L-Co., Inc.
XTRA Corporation
XTRA Companies, 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.19
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2014/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
132,869,369 -128,255,990 -9,518,717 14,281,052 Income 2
36,469,676 36,493,634 10,234 645,661 FICA 3
242,552 243,208 4,601 Unemployment 4
2,281,538 2,187,559 101,364 Excise Tax - Coal 5
171,863,135 -128,255,990 29,405,684 10,234 15,032,678Subtotal 6
7
State: 8
9
Arizona: 10
3,510,489 3,782,928 1,619,025 Property 11
538,000 -271,388 -349,018 615,630 Income 12
4,048,489 -271,388 3,433,910 2,234,655Subtotal 13
14
California: 15
2,253,386 2,253,386 Property 16
31,070 32,086 45 1,236 Unemployment 17
1,817,546 -345,139 1,823,050 -350,643 Franchise-Income 18
38,509 28,440 12,710 Use 19
1,215,654 1,229,045 1,265,469 Local Franchise 20
5,356,165 -345,139 5,366,007 45 928,772Subtotal 21
22
Colorado: 23
2,134,499 2,264,499 2,060,000 Property 24
351 -5,885 6,236 Income 25
2,134,499 351 2,258,614 2,066,236Subtotal 26
27
Idaho: 28
4,189,309 3,244,612 3,351,464 Property 29
1,896,252 -467,204 1,465,328 -36,280 Income 30
32,889 34,818 15,087 KWh 31
43,973 43,560 1,836 Unemployment 32
202,347 195,941 20,867 Use 33
6,364,770 -467,204 4,984,259 3,352,974Subtotal 34
35
Montana: 36
4,126,597 4,314,789 1,967,726 Property 37
124,797 -56,981 56,847 10,969 Corporate License-Income 38
1,056 1,056 Unemployment 39
181,996 203,996 40,000 Energy License 40
12,025,243
FERC FORM NO. 1 (ED. 12-96)Page 262
TOTAL41 234,971,158 389,765,588 -139,933,468 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 (Continued)
PacifiCorp X
/ /2014/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
-6,629,160 -2,889,557 148,956 2
36,493,634 5,000 664,385 3
243,208 5,257 4
2,187,559 7,385 5
32,295,241 -2,889,557 5,000 825,983 6
7
8
9
10
3,782,928 1,891,464 11
-14,466 -334,552 12
-14,466 3,448,376 1,891,464 13
14
15
117,724 2,135,662 16
32,086 2,207 17
-48,053 1,871,103 18
28,440 2,641 19
1,229,045 1,278,860 20
130,197 5,235,810 1,283,708 21
22
23
173,050 2,091,449 2,190,000 24
-30 -5,855 25
173,020 2,085,594 2,190,000 26
27
28
6,132 3,238,480 2,406,767 29
-60,008 1,525,336 30
34,818 17,016 31
43,560 1,423 32
195,941 14,461 33
185,625 4,798,634 2,439,667 34
35
36
4,314,789 2,155,918 37
-5,707 62,554 38
1,056 39
203,996 62,000 40
FERC FORM NO. 1 (ED. 12-96)Page 263
41 12,376,039 178,247,515 56,723,643 39,025,536
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
/ /2014/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.
129,304 143,304 30,000 Wholesale Energy 1
4,563,750 -56,981 4,719,992 2,048,695Subtotal 2
3
Nebraska: 4
359 359 Unemployment 5
359 359Subtotal 6
7
New Mexico: 8
21,695 21,695 Property 9
50 19,372 -57,603 77,025 Income 10
21,745 19,372 -35,908 77,025Subtotal 11
12
Oregon: 13
24,051,822 23,740,607 11,539,928 Property 14
1,521,854 1,525,204 110 50,661 Unemployment 15
785 9 776 Wilsonville Payroll 16
7,458,278 -6,072,662 1,439,332 -53,716 Excise-Income 17
-53,404 -12,528 -81,063 15,131 City of Portland-Income 18
1,039,793 994,823 474,926 Department of Energy 19
1,053,217 1,069,137 411,201 Tri-Met 20
1,973 1,973 Lane County 21
28,951,795 29,046,878 4,526,794 Franchise 22
64,026,113 -6,085,190 57,736,900 12,014,964 4,950,847Subtotal 23
24
Utah: 25
69,060,666 68,915,491 704,212 Property 26
9,490,718 -4,471,299 4,529,895 489,524 Income 27
320,003 321,658 5,925 Unemployment 28
1,284 1,284 Navajo Nation 29
4,619,062 4,612,972 409,248 Use 30
83,491,733 -4,471,299 78,381,300 1,608,909Subtotal 31
32
Washington: 33
10,028,150 10,228,150 10,090,000 Property 34
74,693 74,051 2,563 Unemployment 35
28,850 27,907 3,657 Business & Occupation 36
12,468,513 12,593,513 1,200,000 Public Utility 37
3,665,607 3,894,859 124,916 Natural Gas Use Tax 38
546,755 579,222 57,636 Use 39
26,812,568 27,397,702 11,478,772Subtotal 40
12,025,243
FERC FORM NO. 1 (ED. 12-96)Page 262.1
TOTAL41 234,971,158 389,765,588 -139,933,468 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 (Continued)
PacifiCorp X
/ /2014/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.
143,304 44,000 1
-4,651 4,724,643 2,261,918 2
3
4
359 5
359 6
7
8
21,695 9
-1,629 -55,974 10
-1,629 -34,279 11
12
13
444,191 23,296,416 11,851,143 14
1,525,204 53,901 15
9 16
-370,314 1,809,646 17
-1,026 -80,037 18
994,823 519,896 19
1,069,137 427,121 20
1,973 21
29,046,878 4,621,877 22
2,669,174 55,067,726 12,371,039 5,102,899 23
24
25
10,018,128 58,897,363 559,037 26
-399,560 4,929,455 27
321,658 7,580 28
1,284 29
4,612,972 403,158 30
14,553,198 63,828,102 969,775 31
32
33
329,916 9,898,234 10,290,000 34
74,051 1,921 35
27,907 2,714 36
12,593,513 1,325,000 37
3,894,859 354,168 38
579,222 90,103 39
4,878,048 22,519,654 12,063,906 40
FERC FORM NO. 1 (ED. 12-96)Page 263.1
41 12,376,039 178,247,515 56,723,643 39,025,536
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
/ /2014/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a)(b)(c)(d)(e)(f)
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
1
Wyoming: 2
14,948,136 14,978,109 7,459,081 Property 3
1,878,035 2,075,142 1,830,847 Wind Generation Tax 4
325,431 320,147 10,441 Unemployment 5
1,952,076 1,954,276 283,100 Franchise 6
1,435,020 1,450,821 132,962 Use 7
71,948 71,948 Annual Report 8
20,610,646 20,850,443 9,716,431Subtotal 9
10
20,512State Other 11
12
Miscellaneous: 13
24,288 24,288 Goshute Possessory 14
235,663 235,663 Sho-Ban Possessory 15
38,671 38,951 19,196 Navajo Possessory 16
37,776 37,776 Ute Possessory 17
69,444 69,444 Crow Possessory 18
65,774 65,774 Umatilla Possessory 19
471,616 471,896 39,708Subtotal 20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
12,025,243
FERC FORM NO. 1 (ED. 12-96)Page 262.2
TOTAL41 234,971,158 389,765,588 -139,933,468 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 (Continued)
PacifiCorp X
/ /2014/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
88,559 14,889,550 7,489,054 3
2,075,142 2,027,954 4
320,147 5,157 5
1,954,276 285,300 6
1,450,821 148,763 7
71,948 8
1,859,527 18,990,916 9,956,228 9
10
20,512 11
12
13
24,288 14
235,663 15
38,951 19,476 16
37,776 17
69,444 18
65,774 19
471,896 39,988 20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 263.2
41 12,376,039 178,247,515 56,723,643 39,025,536
Schedule Page: 262 Line No.: 2 Column: f
Represents a reclassification of a portion of the balance at end of year to Account 146,
Accounts receivable from associated companies.
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: f
Represents a reclassification of the balance at end of year to Account 143, Other accounts
receivable.
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
$111,629 Account 408.2, Taxes other than income taxes, other income and deductions
1,569 Account 589, Rents
4,526 Account 107, Construction work in progress
$117,724
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: f
Represents a reclassification of the balance at end of year to Account 146, Accounts
receivable from associated companies.
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
$ 826 Account 408.2, Taxes other than income taxes, other income and deductions
172,224 Account 107, Construction work in progress
$173,050
Schedule Page: 262 Line No.: 25 Column: f
Represents a reclassification of the balance at end of year to Account 143, Other accounts
receivable.
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
$1,183 Account 408.2, Taxes other than income taxes, other income and deductions
4,949 Account 107, Construction work in progress
$6,132
Schedule Page: 262 Line No.: 30 Column: f
Represents a reclassification of the balance at end of year to Account 146, Accounts
receivable from associated companies.
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
2014/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: f
Represents a reclassification of the balance at end of year to Account 146, Accounts
receivable from associated companies.
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: f
Represents a reclassification of the balance at end of year to Account 143, Other accounts
receivable.
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
$ 18,268 Account 408.2, Taxes other than income taxes, other income and deductions
134,418 Account 589, Rents
291,505 Account 107, Construction work in progress
$444,191
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: f
Represents a reclassification of the balance at end of year to Account 146, Accounts
receivable from associated companies.
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: f
Represents a reclassification of the balance at end of year to Account 146, Accounts
receivable from associated companies.
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.: 20 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
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.: 26 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
$ 35,798 Account 408.2, Taxes other than income taxes, other income and deductions
530 Account 589, Rents
7,955,390 Account 107, Construction work in progress
2,026,410 Account 151, Fuel stock
$10,018,128
Schedule Page: 262.1 Line No.: 27 Column: f
Represents a reclassification of the balance at end of year to Account 146, Accounts
receivable from associated companies.
Schedule Page: 262.1 Line No.: 27 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.: 28 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 30 Column: l
Charged to same account as related goods.
Schedule Page: 262.1 Line No.: 34 Column: l
$(30,415) Account 408.2, Taxes other than income taxes, other income and deductions
360,331 Account 107, Construction work in progress
$329,916
Schedule Page: 262.1 Line No.: 35 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 38 Column: l
Account 151, Fuel stock
Schedule Page: 262.1 Line No.: 39 Column: l
Charged to same account as related goods.
Schedule Page: 262.2 Line No.: 3 Column: l
$ 1,960 Account 408.2, Taxes other than income taxes, other income and deductions
15,382 Account 589, Rents
71,217 Account 107, Construction work in progress
$88,559
Schedule Page: 262.2 Line No.: 5 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.2 Line No.: 7 Column: l
Charged to same account as related goods.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
/ /2014/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% 31,144,100 411.4, 420 5,705,998 5
30% 420 168,013 110,915 420 9,770 6
Idaho 133,626 411.4, 420 9,632 7
TOTAL 31,445,739 110,915 5,725,400 8
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
9
10
Idaho 190 79,560 860,586 538,320 420 95,783 11
Total Nonutility 79,560 860,586 538,320 95,783 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
/ /2014/Q4
Line
No.ADJUSTMENT EXPLANATIONAverage Periodof Allocationto Income
1
2
3
4
25,438,102 38.82 and 30 5
269,158 24 6
123,994 38.82 and 30 7
25,831,254 8
9
10
1,382,683 30 11
1,382,683 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% $29,765,829 - - 411.4(1) $5,012,746 $ - $24,753,083 38.82

10% 1,378,271 - - 420(2) 693,252 - 685,019 30
$31,144,100 - $5,705,998 $ - $25,438,102
(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 $ 66,539 - - 411.4(1) $ 6,452 $ - $ 60,087 38.82

Idaho 67,087 - - 420(2) 3,180 - 63,907 30
$ 133,626 - $ 9,632 $ - $ 123,994
(1)Internal Revenue Code 46(f)2
(2)Internal Revenue Code 46(f)1
Schedule Page: 266 Line No.: 11 Column: g
Represents an adjustment to the balance at beginning of year debited to Account 190,
Accumulated deferred income taxes.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
/ /2014/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.
6,686,727Working Capital Deposits 6,804,201 148,474 31,000131 1
2
5,466,807Reclamation Costs - Trapper Mine 5,617,504 150,697 3
4
451,406Reclamation Costs - Deseret Mine 451,406131,182.3 5
6
Western Coal Carriers Benefits 7
11,815,000 Obligation 12,417,000 1,392,520 790,520131,232 8
9
423,276Program Incentives 268,873 154,403921 10
11
9,205,162Deferred Compensation Plans 9,721,835 1,139,146 622,473131,232,241 12
13
Long-Term Incentive Plan 6,935,250 6,935,250 14
15
1,100,092Redding Contract (20) 550,096 549,996456 16
17
154,742Foote Creek Contract (15) 17,102 137,640456 18
19
26,273,100Environmental Liabilities 23,837,178 6,238,532 8,674,454 20
21
Unearned Joint Use Pole 22
2,886,601Contact (1) 2,915,426 6,268,613 6,239,788454 23
24
2,200Misc. Security Deposits 1,900 300131 25
26
Lease Incentives (9) 279,558 292,500 12,942931 27
28
117,115Cowlitz/Lewis River O&M (1) 118,811 285,146 283,450539 29
30
18,275Employee Housing Security Deposits 17,806 1,000 1,469131 31
32
413,417Cogeneration Bonds-Sunnyside 413,417 33
34
681,500Transmission Security Deposits 1,104,607 450,000 26,893131 35
36
153,225Transmission Service Deposits 353,987 210,208 9,446131 37
38
557,890MCI F.O.G. Wire Lease (1) 557,813 3,346,878 3,346,955454 39
40
123,327,063Unamortized Contract Values 110,203,561 13,123,502242 41
42
116,623,436Loss Contingency - USA Power 119,103,601 2,480,165 43
44
1,648,357Accrued Right-of-Way Obligations 2,249,800 601,443 45
46
FERC FORM NO. 1 (ED. 12-94) Page 269
47 TOTAL 29,940,572 34,456,637 303,969,379 308,485,444
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
/ /2014/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.
Navajo Tribal Utility Authority 1
480,053 Escrow 480,053 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 (ED. 12-94) Page 269.1
47 TOTAL 29,940,572 34,456,637 303,969,379 308,485,444
Schedule Page: 269 Line No.: 10 Column: a
The weighted average life is four 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
2014/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
/ /2014/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
2,526,993 27,797,857 226,880,978 4 Pollution Control Facilities
5 Other (provide details in footnote):
6
7
2,526,993 27,797,857 226,880,978 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
2,526,993 27,797,857 226,880,978 17 TOTAL (Acct 281) (Total of 8, 15 and 16)
18 Classification of TOTAL
1,084,136 23,331,892 199,739,675 19 Federal Income Tax
1,442,857 4,465,965 27,141,303 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
/ /2014/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
252,151,842 4
5
6
7
252,151,842 8
9
10
11
12
13
14
15
16
252,151,842 17
18
221,987,431 19
30,164,411 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
/ /2014/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 3,991,613,412 757,539,035 501,658,642 2
Gas 3
4
TOTAL (Enter Total of lines 2 thru 4) 3,991,613,412 757,539,035 501,658,642 5
Nonutility 6
7
8
TOTAL Account 282 (Enter Total of lines 5 thru 8) 3,991,613,412 757,539,035 501,658,642 9
Classification of TOTAL 10
Federal Income Tax 3,546,947,138 617,557,067 394,790,406 11
State Income Tax 444,666,274 139,981,968 106,868,236 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
/ /2014/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
4,244,780,923 14,265,314 11,552,432 2
3
4
4,244,780,923 14,265,314 11,552,432 5
6
7
8
4,244,780,923 14,265,314 11,552,432 9
10
3,767,325,446 11,106,181 8,717,828 11
477,455,477 3,159,133 2,834,604 12
13
FERC FORM NO. 1 (ED. 12-96)Page 275
NOTES (Continued)
Schedule Page: 274 Line No.: 2 Column: g
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Account 283, Accumulated deferred income taxes-other
Schedule Page: 274 Line No.: 2 Column: i
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Account 283, Accumulated deferred income taxes-other
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
/ /2014/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
119,064,278 156,269,401 526,062,074Regulatory Assets 3
23,796,286 25,060,716 30,318,999Other 4
5
6
7
8
142,860,564 181,330,117 556,381,073TOTAL 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
142,860,564 181,330,117 556,381,073TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19
Classification of TOTAL 20
125,916,651 159,784,161 489,857,428Federal Income Tax 21
16,943,913 21,545,956 66,523,645State 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
/ /2014/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
610,798,415 84,377,673 42,801,732 45,935,084 39,979,807 3
22,513,229 3,075,609190, 282190, 282 10,150,102 7,601,957 9,597,664 4
5
6
7
8
633,311,644 87,453,282 52,951,834 53,537,041 49,577,471 9
10
11
12
13
14
15
16
17
18
633,311,644 87,453,282 52,951,834 53,537,041 49,577,471 19
20
557,584,936 76,351,810 46,177,693 46,692,890 43,007,009 21
75,726,708 11,101,472 6,774,141 6,844,151 6,570,462 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
Schedule Page: 276 Line No.: 3 Column: i
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
/ /2014/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)
2,053 2,053DSM Balancing Account - ID 1
6,191,038 6,191,038DSM Balancing Account - UT 2
367,062 367,062DSM Balancing Account - WA 3
183,406 4,852,032 1,890,606 6,559,232DSM Balancing Account - WY 4
3,062,696 26,652,465 2,630,492 26,220,261Oregon Energy Conservation Charge 131,232 5
112,448 121,961 9,513Deferred Excess Net Power Costs - WA Hydro 6
1,521,547 1,521,547Deferred Excess RECs in Rates - UT 456 7
300,002 300,002Deferred Excess RECs in Rates - OR 8
14,121,277 14,121,277Deferred Excess RECs in Rates - WA 456 9
4,787,240 4,787,240Income Tax Reg. Liab. - WA Flow Through 182.3,411.1 10
16,068,451 2,703,477 13,365,333 359Investment Tax Credit Regulatory Liability 190 11
123,782 135,623 945,656 957,497Solar Feed-In Tariff Deferral - CA 12
5,982,150 2,677,911 10,116,877 6,812,638Solar Incentive Program - UT 13
91,428 104,972 196,400Renewable Portfolio Standards Compliance - OR (1) 555,431 14
124,303 62,152 62,151Deferred Independent Evaluator Fee - UT (1) 923 15
896,054 221,815 674,990 751Alternative Rate for Energy (CARE) - CA 16
1,448,684 20,891 2,496,697 1,068,904Utah Home Energy Lifeline 142 17
1,116,234 300,688 1,302,789 487,243Washington Low Income Program 142 18
610,415 368,684 979,099Schedule 94-Distribution Safety Surcharge - OR 923 19
2,273,466 6,025,257 3,751,7912013 FERC Rate True-up - OR 20
9,106,055 14,726,605 2,904,622 8,525,172Greenhouse Gas Allowance Revenues - CA 456,909 21
10,657,389 713,401 9,943,988Asset Retirement Obligations Reg. Difference 230 22
149,742 149,742BPA Balancing Account - WA 440,442 23
211,990 211,990BPA Balancing Account - OR 440,442 24
922,145 2,314,967 1,392,822BPA Balancing Account - ID 25
1,823,145 1,823,556 411SMUD Revenue Imputation (11) 440,442 26
763,580 763,580GRC Invest. In Emission Control Equip. - OR (1) 27
2,732,953 1,674,572 2,824,724 1,766,343Blue Sky - OR 440,442 28
330,282 161,685 346,504 177,907Blue Sky - WA 440,442 29
87,852 23,573 133,454 69,175Blue Sky - CA 440,442 30
2,929,746 2,612,963 3,163,064 2,846,281Blue Sky - UT 440,442 31
91,282 20,316 123,561 52,595Blue Sky - ID 440,442 32
287,012 150,710 351,243 214,941Blue Sky - WY 440,442 33
397,575 2,085,033 2,482,608Injuries & Damages Reserve - OR 925 34
445,516 6,483,405 1,036,454 7,074,343Property Insurance Reserve - OR 924 35
315,300 47,120 381,724 113,544Property Insurance Reserve - ID 924 36
2,298,034 976,622 3,473,648 2,152,236Property Insurance Reserve - UT 924 37
854,995 854,995Depreciation Deferral - OR 38
668,497 668,497Depreciation Deferral - WA 39
40
FERC FORM NO. 1/3-Q (REV 02-04) Page 278
41 TOTAL 75,735,560 96,256,529 71,012,945 91,533,914
Schedule Page: 278 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 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
Schedule Page: 278 Line No.: 3 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 278 Line No.: 4 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 278 Line No.: 11 Column: a
Weighted average remaining life is 39 years.
Schedule Page: 278 Line No.: 12 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 278 Line No.: 13 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.: 16 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 278 Line No.: 27 Column: c
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
2014/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
/ /2014/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
1,773,896,154(440) Residential Sales 1,732,822,429 2
(442) Commercial and Industrial Sales 3
1,467,851,627Small (or Comm.) (See Instr. 4) 1,517,907,746 4
1,365,175,755Large (or Ind.) (See Instr. 4) 1,430,453,424 5
20,047,674(444) Public Street and Highway Lighting 20,446,444 6
17,101,922(445) Other Sales to Public Authorities 17,499,523 7
(446) Sales to Railroads and Railways 8
(448) Interdepartmental Sales 9
4,644,073,132TOTAL Sales to Ultimate Consumers 4,719,129,566 10
325,520,827(447) Sales for Resale 360,600,595 11
4,969,593,959TOTAL Sales of Electricity 5,079,730,161 12
(Less) (449.1) Provision for Rate Refunds 13
4,969,593,959TOTAL Revenues Net of Prov. for Refunds 5,079,730,161 14
Other Operating Revenues 15
9,906,509(450) Forfeited Discounts 9,670,249 16
6,310,584(451) Miscellaneous Service Revenues 5,956,286 17
1,577(453) Sales of Water and Water Power 18
17,887,016(454) Rent from Electric Property 17,827,613 19
(455) Interdepartmental Rents 20
63,993,962(456) Other Electric Revenues 65,097,066 21
85,492,936(456.1) Revenues from Transmission of Electricity of Others 88,719,750 22
(457.1) Regional Control Service Revenues 23
(457.2) Miscellaneous Revenues 24
25
183,592,584TOTAL Other Operating Revenues 187,270,964 26
5,153,186,543TOTAL Electric Operating Revenues 5,267,001,125 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
/ /2014/Q4
Line
No.
MEGAWATT HOURS SOLD
Previous Year (no Quarterly)Current Year (no Quarterly)
AVG.NO. CUSTOMERS PER MONTH
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)
(d) (e) (f) (g)
6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by
the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of
classification in a footnote.)
7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
9. Include unmetered sales. Provide details of such Sales in a footnote.
1
16,339,122 1,522,173 1,545,529 15,567,753 2
3
17,057,194 207,690 200,454 17,073,151 4
21,831,865 33,561 33,373 21,933,602 5
142,585 3,557 3,534 143,147 6
292,107 3 3 281,624 7
8
9
55,662,873 1,766,984 1,782,893 54,999,277 10
10,206,135 10,270,247 11
65,869,008 1,766,984 1,782,893 65,269,524 12
13
65,869,008 1,766,984 1,782,893 65,269,524 14
Page 301
Line 12, column (b) includes $ of unbilled revenues.
Line 12, column (d) includes MWH relating to unbilled revenues
243,252,000
3,131,082
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:
2014 2013
Account service charges -
disconnects/reconnects/returned check charges $ 4,450,910 $ 4,737,594
Customer contract flat rate billings 1,464,397 1,525,594

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:
2014 2013
Renewable energy credit sales, including
amortization and deferrals $ 23,779,972 $ 32,904,131
Amortization of California greenhouse gas
allowance revenue 14,673,226 -
Wind-based ancillary services 10,678,814 12,114,934
Energy exchange credits 9,010,784 10,700,944
Flyash/by-product sales 4,998,296 3,264,830
Revenue from generation interconnection and
transmission service request studies 1,162,487 905,164
Steam sales 988,645 2,029,668
Power sale and exchange agreements 685,320 1,091,292
Phase shifting equipment fee from
Western Electricity Coordinating Council 656,040 1,062,518
Maintenance charges for work on transmission facilities 606,542 727,226
Timber sales 426,135 -
Net profit on sales of materials and supplies inventory 381,251 356,039
Service territory fixed cost recovery fee 302,725 276,016
Indemnity revenues (a) 346,845
Deferral of Oregon retail customers' allocated share of
the incremental Open Access Transmission Tariff
revenues associated with FERC Docket No. ER11-3643-000 (3,442,129) (2,220,863)
(a) The 2014 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
2014/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
/ /2014/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
789 141 5,596 0.0815 64,299 5 06NETMT135 - RES NET MTR
308 327 942 0.2698 83,085 6 06OALT015R-OUTD AR LGT SR
164,540 17,379 9,468 0.1089 17,925,280 7 06RESD000D-RES SRVC
114,930 10,791 10,651 0.1098 12,622,348 8 06RESDDL06-CA LOW INCOME
1,082 427 2,534 0.2077 224,722 9 06RGNSV025-CA SMALL GEN
186 7 26,571 0.0815 15,159 10 06RESD0DM9 - MULTI FAMILY
1,117 16 69,813 0.0464 51,839 11 06RESD0DS8-MULT FAM SBMET
2 12 06UPPL000R-BASE SCH FALL
3,000 13 UNBILLED REV - UNCOLLECTIBLE
-1,320,292 14 REVENUE_ACCT ADJ
29,027 15 SMUD REVENUE IMPUTATIONS
77,562 7,135 10,871 0.1124 8,721,123 16 06RESD00DN - RES SVC DEL NO
1,025,229 17 DSM REVENUE-RESIDENTIAL
20,458 18 BLUE SKY REV RESIDENTIAL
64,434 19 SOLAR FEED-IN REVENUE
-8,694 0.0926 -805,000 20 UNBILLED REVENUE
21
22 IDAHO
1,460 23 07LNX00010-MNTHLY 80%GUAR
1,869 24 07LNX00035-ADV 80%MO GUAR
1,545 104 14,856 0.1026 158,461 25 07NETMT135 - ID RES NET MTR
10 1 10,000 0.3825 3,825 26 07OALCO007-CUST OWN LIGHT
87 123 707 0.4241 36,897 27 07OALT07AR-SECURITY AR LG
436,720 46,174 9,458 0.1135 49,550,473 28 07RESD0001-RES SRVC
231,669 13,354 17,348 0.0972 22,512,773 29 07RESD0036-RES SRVC-OPTIO
6,767 869 7,787 0.1143 773,802 30 07RGNSV23A-SM GEN SVC-R
5 31 07ZZMERGCR-MERGER CREDITS
7,000 32 UNBILLED REV - UNCOLLECTIBLE
45,392 33 SMUD REVENUE IMPUTATIONS
-11,454 0.1026 -1,175,000 34 UNBILLED REVENUE
1,392,294 35 DSM REVENUE-RESIDENTIAL
18,150 36 BLUE SKY REV RESIDENTIAL
37
38 OREGON
1 39 01CHCK000R-RES CHECK MTR
4,950,084 0.0579 286,737,427 40 01COST0004 - 01RESD0004
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
68,401 0.0596 4,076,112 1 01COSTR023 RES GEN SRV CST
19,524 0.0593 1,158,185 2 01COSTR028, OR RES GEN SVC
-2 3 01FXRENEWR - FIXED
38,255 0.0568 2,171,891 4 01HABIT004 - 01RESD0004
102 0.0614 6,266 5 01HABTR023-RES GEN SVC HAB
8,803 6 01LNX00102-LINE EXT 80% G
5,484 7 01LNX00109-REF/NREF ADV +
26 8 01LNX00300 - LINE EXT 80% GTY
2,710 1,226,621 9 01NETMT135-NET METERING
18 9,533 10 01NMTOU135-TOU NET METERING
2,317 2,640 878 0.1601 371,065 11 01OALTB15R-OUTD AR LGT RE
16,887 0.0597 1,007,762 12 01PTOU0004 - 01RESD0004
276,939 0.0561 15,529,866 13 01RENEW004 - 01RESD0004
305 0.0609 18,588 14 01RENWR023-RENEW USAGE
477,485 283,129,141 15 01RESD0004-RES SRVC
1,169 862,946 16 01RESD004T - RES TIME OPT
13,808 5,478,529 17 01RGNSB023-SMALL GENERAL
164 601,571 18 01RGNSB028 -GEN SVC > 30 KW
15 34,803 19 01RNETM023-NET METER RES
2 20 01UPPL000R-BASE SCH FALL
361 284,648 21 01VIR04136-OR RES VOL INC
-15,286 22 OR GAIN ON SALE OF ASSET
-243,749 23 REVENUE ADJ - DEF NPC
-1,716,610 24 REVENUE_ACCT ADJ
359,986 25 SMUD REVENUE IMPUTATIONS
1,293,279 26 SOLAR FEED-IN REVENUE
26,000 27 UNBILLED REV - UNCOLLECTIBLE
-63,519 0.0951 -6,038,000 28 UNBILLED REVENUE
15,198,990 29 DSM REVENUE-RESIDENTIAL
482,286 30 BLUE SKY REV-RESIDENTIAL
31
32 UTAH
1 33 08ACTSETUP-NEW SRVC SETUP
-3 34 08BLSKY01R-BLUESKY ENERGY
838 35 08CFR00001-MTH FACILITY S
1 36 08CHCK000R-UT RES CHECK M
91,379 37 08COOLKPRR -COOL KEEPER
4,411 38 08LNX00001-MTHLY 80% GUAR
396 39 08LNX00005-MTHLY MIN GUAR
23,379 40 08LNX00013-80% MNTHLY MIN
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
2,574 1 08LNX00108-ANN COST MTHLY
11,215 8 1,401,875 0.0754 845,910 2 08MHTP0006-MOBILE HOME &
282 2 141,000 0.0937 26,416 3 08MHTP0023-MOBILE HOME &
15,117 2,495 6,059 0.1122 1,696,352 4 08NETMT135 - NET MTR
2,686 2,894 928 0.2856 767,153 5 08OALT007R-SECURITY AR LG
2 3 667 0.0655 131 6 08PTLD000R-POST TOP LIGHT
6,241,612 707,396 8,823 0.1086 677,726,573 7 08RESD0001-RES SRVC
3,090 371 8,329 0.1065 329,135 8 08RESD0002-RES SRVC-OPTIO
201,030 26,798 7,502 0.1065 21,403,238 9 08RESD0003-LIFELINE PRGRM
84,775 225 376,778 0.0772 6,545,358 10 08RGNSV006-GEN SRVC-RES
91,740 12,324 7,444 0.1114 10,219,952 11 08RGNSV023-GEN SRVC-RES
15,085 23 655,870 0.0824 1,242,804 12 08RGNSV06A-UT SM GEN SVC
22 1 22,000 0.0905 1,992 13 08RGNSV06B-UT SM GEN SVC
287 4 71,750 0.1060 30,422 14 08RNM06135 - UT NET MTR, GEN
234 29 8,069 0.1103 25,819 15 08RNM23135 - UT NET MTR, GEN
4 16 08UPPL000R-BASE SCH FALL
-2,406,676 17 REVENUE_ACCOUNTING
13,190,462 18 REVENUE ADJ - DEF NPC
1,017,606 19 SOLAR FEED-IN REVENUE
48,000 20 UNBILLED REV - UNCOLLECTIBLE
-62,038 0.0815 -5,058,000 21 UNBILLED REVENUE
25,798,568 22 DSM REVENUE-RESIDENTIAL
1,995,804 23 BLUE SKY REV-RESIDENTIAL
24
25 WASHINGTON
904 26 02LNX00109-REF/NREF ADV +
2,411 161 14,975 0.0909 219,080 27 02NETMT135 - WA RES NET MTR
1,033 1,118 924 0.1438 148,519 28 02OALTB15R-WA OUTD AR LGT
1,500,324 99,277 15,113 0.0879 131,844,971 29 02RESD0016-WA RES SRVC
80,814 5,400 14,966 0.0872 7,043,752 30 02RESD0017-BILL ASSISTANCE
2,259 83 27,217 0.0960 216,923 31 02RESD0018-WA 3 PHASE RES
428 18 23,778 0.0934 39,959 32 02RESD018X-WA 3 PHASE RES
19,359 3,044 6,360 0.1095 2,120,558 33 02RGNSB024-WA SM GEN SVC
1 34 02UPPL000R-BASE SCH FALL
-311,259 35 REVENUE ADJ- DEF NPC
-4,547,120 36 REVENUE_ACCT ADJUSTMENTS
105,830 37 SMUD REVENUE IMPUTATIONS
-1,320,000 38 WASHINGTON - CHEHALIS DEF
3,000 39 UNBILLED REV - UNCOLLECTIBLE
-11,884 0.0632 -751,000 40 UNBILLED REVENUE
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
4,676,006 1 DSM REVENUE-RESIDENTIAL
126,825 2 BLUE SKY REV-RESIDENTIAL
3
4 WYOMING
753 5 05LNX00102-LINE EXT 80% G
1,421 127 11,189 0.1150 163,454 6 05NETMT135 - EXP PARTIALREQ
890 1,041 855 0.1611 143,381 7 05OALT015R-OUTD AR LGT SR
919,330 100,120 9,182 0.1066 97,988,436 8 05RESD0002-WY RES SRVC
8,294 1,220 6,798 0.1197 992,423 9 05RGNSV025-WY SM GEN SVC
243,423 10 REVENUE ADJUSTMENT -
-2,962 11 REVENUE_ACCT ADJUSTMENTS
56,842 12 SMUD REVENUE IMPUTATIONS
12,000 13 UNBILLED REV - UNCOLLECTIBLE
-7,487 0.0915 -685,000 14 UNBILLED REVENUE
1,442,805 15 DSM REVENUE-RESIDENTIAL
14,494 16 DSM REVENUE-RESIDENTIAL GEN
116,728 17 BLUE SKY REV-RESIDENTIAL
825 18 05LNX00109-REF/NREF ADV +
118,783 12,508 9,497 0.1082 12,852,318 19 05RESD0002-WY RES SRVC
398 121 3,289 0.1649 65,612 20 05RGNSV025- SM GEN SVC-R
75 89 843 0.2911 21,834 21 09OALT207R-SECURITY AR LG
241 14 17,214 0.1136 27,382 22 05NETMT135 - EXP PARTIAL REQ
2 23 09RES00002
4 24 09RESD0002
-534 0.1030 -55,000 25 UNBILLED REVENUE
185,079 26 DSM REVENUE-RESIDENTIAL
1,925 27 DSM REVENUE-RES GEN SVC
19,893 28 BLUE SKY REV-RESIDENTIAL
29
-118,001 30 LESS MULTIPLE BILLINGS
31
15,567,753 1,545,529 10,073 0.1113 1,732,822,429 32 TOTAL RESIDENTIAL SALES
33
34 COMMERCIAL SALES
35 CALIFORNIA
1 36 06CHCK000N-CA NRES CHECK
53,397 6,457 8,270 0.1663 8,878,328 37 06GNSV0025-CA GEN SRVC
873 85 10,271 0.1833 160,013 38 06GNSV025F-GEN SRVC-< 20
81,380 1,022 79,628 0.1469 11,951,341 39 06GNSV0A32-GEN SRVC-20 KW
28,466 5 5,693,200 0.0959 2,730,670 40 06LGSV048T-LRG GEN SERV
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
2,691 1 2,691,000 0.0973 261,910 1 06NMT48135-CA GEN SVC NET
68,270 162 421,420 0.1245 8,499,700 2 06LGSV0A36-LRG GEN SRVC-O
7,998 3 06LNX00102-LINE EXT 80% GTY
4,953 4 06LNX00105-CNTRCT $ MIN G
76,943 5 06LNX00109-REF/NREF ADV +
4,759 6 06LNX00300 - 80% MTHLY MIN
11,120 7 06LNX00311 - LINE EXT 80% GTY
2,315 4 578,750 0.1257 290,998 8 06NMT36135-G SVC NT ->100
695 491 1,415 0.2730 189,765 9 06OALT015N-OUTD AR LGT SR
176 36 4,889 0.2151 37,857 10 06RCFL0042-AIRWAY & ATHLE
81 8 10,125 0.1614 13,073 11 06NMT25135-CA GEN SVC NET
475 10 47,500 0.1729 82,111 12 06NMT32135-CA GEN SVC NET
-974,465 13 REVENUE_ACCT ADJUSTMENTS
19,485 14 SMUD REVENUE IMPUTATIONS
6,602 15 06LNX00110-REF/NREF ADV +
54,047 16 SOLAR FEED-IN REVENUE
-1,608 0.0479 -77,000 17 UNBILLED REVENUE
632,637 18 DSM REVENUE-COMMERCIAL
3,017 19 BLUE SKY REV-COMMERCIAL
20
21 IDAHO
5,094 101 50,436 0.0866 441,181 22 07CISH0019-COMM & IND SPA
213,973 932 229,585 0.0819 17,526,970 23 07GNSV0006-GEN SRVC-LRG P
43,654 2 21,827,000 0.0612 2,673,086 24 07GNSV0009-GEN SRVC-HI VO
139,863 6,260 22,342 0.0983 13,749,621 25 07GNSV0023-GEN SRVC-SML P
875 2 437,500 0.0640 55,969 26 07GNSV0035-GEN SRVCOPTION
26,883 189 142,238 0.0869 2,335,614 27 07GNSV006A-GEN SRVC-LRG P
24,780 1,278 19,390 0.0985 2,440,529 28 07GNSV023A-GEN SRVC-SML P
7 5 1,400 0.2787 1,951 29 07GNSV023F-GEN SRVC SML P
8,987 30 07LNX00010-MNTHLY 80%GUAR
207,261 31 07LNX00035-ADV 80%MO GUAR
47,913 32 07LNX00040-ADV+REFCHG+80%
243 176 1,381 0.3840 93,311 33 07OALT007N-SECURITY AR LG
11 12 917 0.4026 4,429 34 07OALT07AN-SECURITY AR LG
11,134 35 07LNX00312 - ID LINE EXT
1,681 4 420,250 0.0862 144,948 36 07NMT06135 - NET MTR - LG GEN
717 17 42,176 0.0850 60,967 37 07NMT23135 - NET MTR - SM GEN
211 38 07LNX00015-ANNUAL 80%GUAR
23,473 39 07LNX00311 - LINE EXT 80% GTY
10,072 40 07LNX00300 - 80% MTHLY MIN
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
28,043 1 SMUD REVENUE IMPUTATIONS
-2,942 0.0948 -279,000 2 UNBILLED REVENUE
720,858 3 DSM REVENUE-COMMERCIAL
1 2,136 4 BLUE SKY REV-COMMERCIAL
5
6 OREGON
977,448 0.0572 55,943,107 7 01COST0023, OR GEN SRV, COST
862,794 0.0487 42,047,669 8 01COST0048 - 01LGSV0048
3,034 0.0610 185,180 9 01COST023F - GEN SRV COST
38,730 0.0585 2,266,327 10 01COSTB023 - OR GEN SRV,
1,108,862 0.0509 56,434,545 11 01COSTL030 - OR LRG GEN SRV,
1,918,139 0.0593 113,675,844 12 01COSTS028, OR GEN SERV
55,095 51,888,496 13 01GNSV0023, GEN SRV < 30 KW
8,893 55,678,970 14 01GNSV0028, GEN SRV > 30 KW
10,219 781 13,085 0.1584 1,618,934 15 01GNSV023F - GEN SRV - FLAT RA
78 1 78,000 0.1040 8,112 16 01GNSV023M - GEN SRV, MANUAL
204 169,370 17 01GNSV023T, OR GEN SRV, TOU
2,500 0.0588 146,925 18 01HABT0023, OR HABITAT BLEND
69 0.0607 4,191 19 01HABTB023 - OR HABITAT BLEND
22 1,061,780 20 01LGSB0030, GEN DEL SRV, > 200
617 27,838,472 21 01LGSV0030 - LG GEN SRV > 1000
92 15,185,516 22 01LGSV0048-1000KW AND OVR
63,518 1 63,518,000 0.0643 4,084,862 23 01LGSV048M-LRG GEN SRVC 1
3,406 24 01LNX00100-LINE EXT 60% G
320,010 25 01LNX00102-LINE EXT 80% G
5,383 26 01LNX00103-LINE EXT 80% G
14,004 27 01LNX00105-CNTRCT $ MIN G
1,123,757 28 01LNX00109-REF/NREF ADV +
8,342 29 01LNX00110-REF/NREF ADV +
133,264 30 01LNX00311 - LINE EXT 80% GTY
294 31 01LNX00120 - LINE EXT 60% GTY
192,390 32 01LNX00300 - LINE EXT 80% GTY
636 33 01LNX00310-LINE EXTENSION
48,149 5 9,629,800 0.0933 4,494,139 34 01LPRS047M-PART REQ SRVC
204 174,593 35 01NMT23135 - NET MTR GEN < 30
115 834,349 36 01NMT28135 - NET MTR GEN > 30
23 1,024,606 37 01NMT30135 -NET MTR GEN > 200
4 393,768 38 01NMT48135-NET MTR GEN SVC =
5,620 2,906 1,934 0.1458 819,409 39 01OALT015N-OUTD AR LGT NR
1,497 1,091 1,372 0.1652 247,369 40 01OALTB15N-OUTD AR LGT NR
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
3,050 0.0581 177,076 1 01PTOU0023, OR GEN SRV, TOU
470 0.0598 28,102 2 01PTOUB023, OR GEN SRV, TOU
1,405 107 13,131 0.0977 137,250 3 01RCFL0054-REC FIELD LGT
8,171 0.0585 478,253 4 01RENW0023, OR RENW USAGE
198 0.0600 11,873 5 01RENWB023 - OR RENEWABLE
2,833 0.0682 193,073 6 01STDAY023 - DAY STD OFR SCH
13,756 0.0691 950,975 7 01STDAY028 - DAY STD OFF SCH
4,829 0.0623 301,016 8 01STDAY030 - STD DAY OFF SCH
80 121,061 9 01VIR23136-VOL INC <=30KW
84 547,135 10 01VIR28136-VOL INC >30KW
5 219,403 11 01VIR30136-VOL INC >200KW
1 127,100 12 01VIR48136-VOL INC >1000KW
1 84,743 13 01LGSB0048 - LG GSVC > 1000
466 1 466,000 0.0914 42,586 14 01LGSV028M - LGSV, <1000 kW, M
145 1 145,000 0.1605 23,270 15 01GNSV030M - GEN SRV, 200 KW
15 250,417 16 01GNSV0728 - GEN SVC DIR ACC
16 2,174,244 17 01GNSV0730 -GEN SVC DIR ACC
4 2,099,603 18 01GNSV0748 LG GEN SVC DIR
-2 19 01ZZ MERGCR-MERGER CREDITS
-13,728 20 OR GAIN ON SALE OF ASSET
-183,213 21 REVENUE ADJ - DEF NPC
-1,290,514 22 REVENUE_ACCT ADJUSTMENTS
331,311 23 SMUD REVENUE IMPUTATIONS
1,089,606 24 SOLAR FEED-IN REVENUE
10,260 0.2115 2,170,000 25 UNBILLED REVENUE
9,857,491 26 DSM REVENUE-COMMERCIAL
109 727,145 27 BLUE SKY REV-COMMERCIAL
4,812 2,657,473 28 01GNSB0023, OR GEN SRV, BPA
411 2,873,018 29 01GNSB0028, OR GEN SRV, BPA
55 30,295 30 01GNSB023T - OR GEN SRV - TOU
31
32 UTAH
7,654 33 08ABL-NRES - APPLICANT BUILT
-1 34 08BLSKY01N-BLUESKY ENERGY
38,907 35 08CFR00051-MTH FAC SRVCHG
2 36 08CFR00052-ANN FAC SVCCHG
2,881 37 08COOLKPRN - A/C DIRECT LOAD
4,938,734 10,904 452,929 0.0832 411,142,588 38 08GNSV0006-GEN SRVC-DISTR
676,042 26 26,001,615 0.0599 40,462,935 39 08GNSV0009-GEN SRVC-HI VO
1,197,924 65,953 18,163 0.0990 118,608,752 40 08GNSV0023-GEN SRVC-DISTR
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
237,223 2,050 115,719 0.1181 28,023,955 1 08GNSV006A-GEN SRVC-ENERG
2,271 29 78,310 0.1146 260,319 2 08GNSV006B-GEN SRVC-DEM&
1,538 6 256,333 0.0760 116,926 3 08GNSV006M-MNL DIST VOLTG
23,096 2 11,548,000 0.0662 1,528,199 4 08GNSV009A-GEN SRVC HI VO
4,033 1 4,033,000 0.0721 290,743 5 08GNSV009M-MANL HIGH VOLT
1,307 127 10,291 0.1435 187,525 6 08GNSV023F-GEN SRVC FIXED
101 4 25,250 0.0959 9,689 7 08GNSV023M-GNSV DIST VOLT
582 1 582,000 0.1014 59,022 8 08GNSV06AM-MNL ENERGY TOD
35,335 524 67,433 0.0768 2,714,908 9 08GNSV06MN-GNSV DIST VOLT
229,822 10 08LNX00002-MTHLY 80% GUAR
17,166 11 08LNX00004-ANNUAL 80%GUAR
4,476 12 08LNX00006-FIXD MTHLY MIN
10,757 13 08LNX00008-ANNUALMIN GUAR
1,456,844 14 08LNX00014-80% MIN MNTHLY
153,901 15 08LNX00017-ADV/REF&80%ANN
32,125 16 08LNX00158-ANNUALCOST MTH
100,545 17 08LNX00300 - LINE EXT 80% PLUS
50,649 18 08LNX00310 - IRR 80% ANN MIN
4,924 19 08LNX00312 UT IRG LINE EXT
60,904 126 483,365 0.0867 5,282,497 20 08NMT06135-NET MTR GEN SV
60,584 5 12,116,800 0.0670 4,061,468 21 08NMT08135 -NET MTR GEN SVC
3,302 190 17,379 0.1040 343,308 22 08NMT23135 - UT NET MTR, GEN
1,936 13 148,923 0.1221 236,429 23 08NMT6A135-NET MTR GEN SVC T
8,143 4,259 1,912 0.2327 1,894,612 24 08OALT007N-SECURITY AR LG
2 230 25 08POLE0075-POLES W/LIGHT
24,290 3 8,096,667 0.0726 1,762,247 26 08PRSV031M-BKUP MNT&SUPPL
6 2 3,000 0.0753 452 27 08PTLD000N-POST TOP LIGHT
167 20 8,350 0.0934 15,592 28 08TOSS015F-TRAFFIC SIG NM
2,193 855 2,565 0.1101 241,435 29 08TOSS0015-TRAF & OTHER S
17,789 461 38,588 0.0702 1,248,743 30 08MONL0015-MTR OUTDONIGHT
-1,672,573 31 REVENUE_ACCT ADJUSTMENTS
13,699,555 32 REVENUE ADJ - DEF NPC
707,504 33 SOLAR FEED-IN REVENUE
267,510 34 08LNX00311 - LINE EXT 80% GTY
970,917 149 6,516,221 0.0738 71,667,899 35 08GNSV0008 -GEN SVC TOU
29,441 5 5,888,200 0.0795 2,340,606 36 08GNSV008M -GEN SVC TOU
-30,279 0.0682 -2,064,000 37 UNBILLED REVENUE
24,842,117 38 DSM REVENUE-COMMERCIAL
434,725 39 BLUE SKY REV-COMMERCIAL
40
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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 WASHINGTON
33,078 1,773 18,657 0.0916 3,030,551 2 02GNSB0024-WA GEN SRVC DO
154 6 25,667 0.1216 18,731 3 02GNSB024F-GEN SRVC DOM/F
185 84 2,202 0.4485 82,969 4 02GNSB24FP-WA GEN SVC
479,723 13,549 35,407 0.0870 41,734,253 5 02GNSV0024-WA GEN SRVC
1,116 111 10,054 0.1295 144,572 6 02GNSV024F-WA GEN SRVC-FL
71,510 113 632,832 0.0756 5,403,808 7 02LGSB0036-LRG GEN SVC IRG
744,523 845 881,092 0.0735 54,743,597 8 02LGSV0036-WA LRG GEN SRV
183,063 34 5,384,206 0.0674 12,335,935 9 02LGSV048T-LRG GEN SRVC 1
29,002 10 02LNX00102-LINE EXT 80% G
7,237 11 02LNX00103-LINE EXT 80% G
1,754 12 02LNX00105-CNTRCT $ MIN G
255,524 13 02LNX00109-REF/NREF ADV +
13,532 14 02LNX00110-REF/NREF ADV +
669 15 02LNX00112-YR INCURRED CH
11,101 16 02LNX00300-LINE EXT 80% G
1,741 17 02LNX00310 - IRG, 80% ANNUAL
72,584 18 02LNX00311 - LINE EXT 80% GTY
2,922 19 02LNX00312 - WA IRG LINE EXT
1,532 802 1,910 0.1363 208,736 20 02OALT015N-WA OUTD AR LGT
557 491 1,134 0.1454 80,992 21 02OALTB15N-WA OUTD AR LGT
267 30 8,900 0.0874 23,346 22 02RCFL0054-WA REC FIELD L
1,125 24 46,875 0.0833 93,684 23 02NMT24135, NET MTR, WA
3,111 4 777,750 0.0745 231,906 24 02NMT36135-NET METER LG SVC
5,138 1 5,138,000 0.0637 327,238 25 02NMT48135-WA LG SVC NET
-244,702 26 REVENUE ADJ - DEF NPC
-3,884,429 27 REVENUE_ACCT ADJUSTMENTS
97,430 28 SMUD REVENUE IMPUTATIONS
-1,020,000 29 WASHINGTON - CHEHALIS DEF
11,391 0.1000 1,139,000 30 UNBILLED REVENUE
4,004,906 31 DSM REVENUE-COMMERCIAL
5 34,752 32 BLUE SKY REV-COMMERCIAL
33
34 WYOMING
1 35 05CHCK000N-WY NRES CHECK
228,493 17,509 13,050 0.0994 22,715,976 36 05GNSV0025-WY GEN SRVC
912,076 3,384 269,526 0.0844 76,976,356 37 05GNSV0028-GEN SVC > 15 KW
1,013 180 5,628 0.1613 163,412 38 05GNSV025F-GEN SRVC-FL RA
214,848 19 11,307,789 0.0697 14,973,247 39 05LGSV0046-WY LRG GEN SRV
11,578 1 11,578,000 0.0767 888,516 40 05LGSV048T-LRG GENSRV TIM
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
451 1 05LNX00100-LINE EXT 60% G
561,536 2 05LNX00102-LINE EXT 80% G
7,799 3 05LNX00103-LINE EXT 80% G
6,005 4 05LNX00105-CNTRCT $ MIN G
615,241 5 05LNX00109-REF/NREF ADV +
5,915 6 05LNX00110-REF/NREF ADV +
787 7 05LNX00114-TEMP SVC 12MO>
255 19 13,421 0.0979 24,955 8 05NMT25135 - NET MTR, GEN
6,747 18 374,833 0.0963 649,697 9 05NMT28135-NET MTR SM GEN
2,764 1,681 1,644 0.1622 448,371 10 05OALT015N-OUTD AR LGT SR
765 51 15,000 0.0830 63,511 11 05RCFL0054-WY REC FIELD L
1 12 05RFNDCENT-CENTRALIA RFND
1 152 13 09OALT207N-SECURITY AR LG
50,285 14 05LNX00300 - LINE EXT 80% GTY
84,149 15 05LNX00311 - LINE EXT 80% GTY
2,225 16 05LNX00312 - WY IRG LINE EXT
348,447 17 REVENUE ADJ - DEF NPC
-3,509 18 REVENUE_ACCT ADJUSTMENTS
80,756 19 SMUD REVENUE IMPUTATIONS
-15,923 0.0673 -1,071,000 20 UNBILLED REVENUE
1,207,456 21 DSM REVENUE-SMALL
53,176 22 DSM REVENUE-LARGE
5,624 23 BLUE SKY
31,186 2,311 13,495 0.0987 3,077,215 24 05GNSV0025-WY GEN SRVC
96,539 415 232,624 0.0848 8,187,915 25 05GNSV0028-GEN SVC > 15 KW
209 33 6,333 0.1280 26,747 26 05GNSV025F-GEN SRVC-FL RA
8,640 27 05LNX00102-LINE EXT 80% G
186,285 28 05LNX00109-REF/NREF ADV +
1,691 29 05LNX00110-REF/NREF ADV +
488 30 05LNX00114-TEMP SVC 12MO>
5 2 2,500 0.1828 914 31 05NMT25135 - WY NET MTR, GEN
521 4 130,250 0.0933 48,620 32 05NMT28135-NET MTR SM GEN
275 138 1,993 0.2539 69,829 33 09OALT207N-SECURITY AR LG
409 11 37,182 0.0502 20,551 34 09MONL0213-WY MTR OUTDOOR
711 35 05LNX00300 - LINE EXT 80%
3,063 36 05LNX00311 - LINE EXT 80%
-951 0.0673 -64,000 37 UNBILLED REVENUE
251,935 38 DSM REVENUE-SMALL
969 39 BLUE SKY REV-COMMERCIAL
40
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
-24,811 1 LESS MULTIPLE BILLINGS
2
17,073,151 200,454 85,172 0.0889 1,517,907,746 3 TOTAL COMMERCIAL SALES
4
5 INDUSTRIAL SALES
6 CALIFORNIA
704 92 7,652 0.1698 119,533 7 06GNSV0025-CA GEN SRVC
1,778 23 77,304 0.1740 309,329 8 06GNSV0A32-GEN SRVC-20 KW
46,895 10 4,689,500 0.1010 4,737,861 9 06LGSV048T-LRG GEN SERV
4,778 12 398,167 0.1345 642,554 10 06LGSV0A36-LRG GEN SRVC-O
-164,914 11 REVENUE_ACCT ADJUSTMENTS
2,905 12 SMUD REVENUE IMPUTATIONS
7,303 13 SOLAR FEED-IN REVENUE
500 0.1820 91,000 14 UNBILLED REVENUE
107,433 15 DSM REVENUE-INDUSTRIAL
75 16 BLUE SKY REVENUE-INDUSTRIAL
17
18 IDAHO
2,217 19 07CFR00001-MTH FACILITY S
47 2 23,500 0.0963 4,524 20 07CISH0019-COMM & IND SPA
88,944 106 839,094 0.0716 6,369,347 21 07GNSV0006-GEN SRVC-LRG P
78,074 15 5,204,933 0.0643 5,024,006 22 07GNSV0009-GEN SRVC-HI VO
13,335 328 40,655 0.0948 1,264,065 23 07GNSV0023-GEN SRVC-SML P
1,029 1 1,029,000 0.0670 68,920 24 07GNSV0035-GEN SRVCOPTION
3,846 24 160,250 0.0850 326,745 25 07GNSV006A-GEN SRVC LG P
2,170 166 13,072 0.1042 226,142 26 07GNSV023A-GEN SRVC-SML P
5 1 5,000 0.1218 609 27 07GNSV023S-IDAHO TRAFFIC
1,996 28 07LNX00108-ANN COST MTHLY
12 16 750 0.3973 4,767 29 07OALT007N-SECURITY AR LG
1 238 30 07OALT07AN-SECURITY AR LG
1,441,000 1 1,441,000,000 0.0619 89,205,252 31 07SPCL0001
107,327 1 107,327,000 0.0591 6,345,346 32 07SPCL0002
112,240 33 SMUD REVENUE IMPUTATIONS
-301 -0.7973 240,000 34 UNBILLED REVENUE
234,190 35 DSM REVENUE-INDUSTRIAL
36
37 OREGON
20,169 0.0574 1,157,777 38 01COST0023, GEN SRV CST BSD
1,730,907 0.0484 83,849,862 39 01COST0048 - 01LGSV0048
1 0.0630 63 40 01COST023F - GEN SRV CST-BSD
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
234 0.0558 13,060 1 01COSTB023 - GEN SRV, CST-BSD
220,008 0.0511 11,231,660 2 01COSTL030 - LRG GEN SRV, CST
93,365 0.0591 5,515,819 3 01COSTS028, OR GEN SERV
1,081 1,121,615 4 01GNSV0023, OR GEN SRV, < 30
461 3,522,412 5 01GNSV0028, OR GEN SRV > 30
2 2 1,000 0.3440 688 6 01GNSV023F - GEN SRV - FLT
1 7 01GNSV023M - OR GEN SRV
3 2,346 8 01GNSV023T, GEN SRV, TOU OPT
1 7,469 9 01GNSV0728 -GEN SVC DIR
3 39,989 10 01GNSV0730 -GEN SVC DIR
2 1,723,866 11 01GNSV0748 LG GEN SVC DIR
150 7,779,630 12 01LGSV0030 - LG G SRV > 1000
88 28,485,668 13 01LGSV0048-1000KW AND OVR
87,763 3 29,254,333 0.0755 6,623,196 14 01LGSV048M-LRG GEN SRVC 1
45,792 15 01LNX00102-LINE EXT 80% G
2,256 16 01LNX00109-REF/NREF ADV +
22,656 17 01LNX00300 - LINE EXT 80% GTY
18,604 2 9,302,000 0.0836 1,554,677 18 01LPRS047M-PART REQ SRVC
2 1,454 19 01NMT23135 - NET MTR GEN < 30
4 27,928 20 01NMT28135 - NET MTR GEN > 30
1 39,491 21 01NMT30135 - NET MTR GEN > 200
285 128 2,227 0.1425 40,624 22 01OALT015N-OUTD AR LGT NR
1 4 250 0.1270 127 23 01OALTB15N-OR OUTD AR LGT
31 0.0625 1,936 24 01PTOU0023, GEN SRV, TOU ENG
96 0.0554 5,314 25 01RENW0023, RENW USAGE SPLY
2 26 01RENWB023 - OR RENEWABLE
16 0.0698 1,116 27 01STDAY023 - DAY STD OFR SCH
537 0.0696 37,355 28 01STDAY028 - DAY STD OFF SCH
728 0.0634 46,138 29 01STDAY030 - STD DAY OFF SCH
1 1,047 30 01VIR23136-VOL INC <=30KW
1 36,487 31 01VIR30136-VOL INC >200KW
-9,488 32 OR GAIN ON SALE OF ASSET
-60,536 33 REVENUE ADJ - DEF NPC
-780,844 34 REVENUE_ACCT ADJUSTMENTS
141,188 35 SMUD REVENUE IMPUTATIONS
723,370 36 SOLAR FEED-IN REVENUE
-956 -0.1998 191,000 37 UNBILLED REVENUE
873,524 38 DSM REVENUE-INDUSTRIAL
34 464,643 39 BLUE SKY REVENUE-INDUSTRIAL
22 15,302 40 01GNSB0023, OR GEN SRV, BPA
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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 9,200 1 01GNSB0028, OR GEN SRV, BPA
2
3 UTAH
18,725 4 08CFR00051-MTH FAC SRVCHG
1,960 2 980,000 0.1062 208,099 5 08EFOP0021-ELEC FURNACE O
1,229 3 409,667 0.1341 164,840 6 08EFOP021M-ELEC FURNACE O
667,128 1,097 608,139 0.0869 57,986,225 7 08GNSV0006-GEN SRVC-DISTR
3,587,791 116 30,929,233 0.0540 193,621,203 8 08GNSV0009-GEN SRVC-HI VO
54,959 3,347 16,420 0.1009 5,543,230 9 08GNSV0023-GEN SRVC-DISTR
60,045 255 235,471 0.1189 7,139,984 10 08GNSV006A-GEN SRVC-ENERG
1,951 2 975,500 0.0709 138,237 11 08GNSV006B-GEN SRVC-DEM&
17,076 6 2,846,000 0.0859 1,466,883 12 08GNSV009A-GEN SRVC HI VO
488,858 9 54,317,556 0.0539 26,344,251 13 08GNSV009M-MANL HIGH VOLT
4 1 4,000 0.6423 2,569 14 08GNSV023F-GEN SRVC FIXED
1,194 25 47,760 0.0890 106,255 15 08GNSV06MN-GNSV DIST VOLT
1,087 1 1,087,000 0.1084 117,879 16 08GNSV09AM-MAN TOD HIVOLT
482,057 17 08LNX00002-MTHLY 80% GUAR
7,582 18 08LNX00014-80% MIN MNTHLY
1,708 19 08LNX00311 - LINE EXT 80% GTY
30,640 20 08LNX00300 - LINE EXT 80% PLUS
3,493 21 08LNX00310 - IRR 80% ANN MIN
1,210 453 2,671 0.2145 259,489 22 08OALT007N-SECURITY AR LG
10 9 1,111 0.1398 1,398 23 08TOSS0015-TRAF & OTHER S
14 7 2,000 0.1969 2,757 24 08MONL0015-MTR OUTDONIGHT
2,492 8 311,500 0.1171 291,762 25 08NMT06135-NET MTR GEN SV
173 6 28,833 0.0909 15,723 26 08NMT23135 -NET MTR G <25
2,939 3 979,667 0.1184 347,946 27 08NMT6A135-NET MTR GEN SVC T
6,541 1 6,541,000 0.1064 695,654 28 08PRSV031M-BKUP MNT&SUPPL
605,019 1 605,019,000 0.0495 29,957,097 29 08SPCL0001
911,562 1 911,562,000 0.0441 40,226,507 30 08SPCL0002
1,176,612 1 1,176,612,000 0.0455 53,533,831 31 08SPCL0003
-2,087,301 32 REVENUE_ACCT ADJUSTMENTS
8,463,673 33 REVENUE ADJ - DEF NPC
325 2 162,500 0.1272 41,337 34 08GNSV06AM-MNL ENERGY TOD
1,021,842 105 9,731,829 0.0750 76,659,982 35 08GNSV0008 - GEN SVC TOU
60,639 7 8,662,714 0.0759 4,600,454 36 08GNSV008M - GEN SVC TOU
882,372 37 SOLAR FEED-IN REVENUE
-47,474 0.0244 -1,160,000 38 UNBILLED REVENUE
13,361,539 39 DSM REVENUE-INDUSTRIAL
7 105,703 40 BLUE SKY REVENUE-INDUSTRIAL
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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 WASHINGTON
1,312 49 26,776 0.0965 126,570 2 02GNSB0024-WA GEN SRVC DO
6 1 6,000 0.3690 2,214 3 02GNSB24FP-WA GEN SVC
16,746 345 48,539 0.0866 1,450,848 4 02GNSV0024-WA GEN SRVC
33 4 8,250 0.2403 7,930 5 02GNSV024F-WA GEN SRVC-FL
102,051 104 981,260 0.0763 7,784,835 6 02LGSV0036-WA LRG GEN SRV
679,498 31 21,919,290 0.0585 39,753,291 7 02LGSV048T-LRG GEN SRVC 1
121 41 2,951 0.1270 15,363 8 02OALT015N-WA OUTD AR LGT
29 15 1,933 0.1389 4,028 9 02OALTB15N-WA OUTD AR LGT
1,996 1 1,996,000 0.1472 293,874 10 02PRSV47TM-LRG PART REQMT
1,880 14 134,286 0.1259 236,627 11 02LGSB0036-LRG GEN SVC IRG
-113,560 12 REVENUE ADJ - DEF NPC
-1,648,227 13 REVENUE_ACCT ADJUSTMENTS
52,367 14 SMUD REVENUE IMPUTATIONS
-510,000 15 WASHINGTON - CHEHALIS
-3,800 0.0116 -44,000 16 UNBILLED REVENUE
1,700,460 17 DSM REVENUE-INDUSTRIAL
18
19 WYOMING
28,048 1,141 24,582 0.0894 2,506,415 20 05GNSV0025-WY GEN SRVC
258,078 481 536,545 0.0740 19,105,345 21 05GNSV0028-GEN SVC > 15 KW
26 8 3,250 0.1655 4,302 22 05GNSV025F-GEN SRVC-FL RA
1,702,965 57 29,876,579 0.0657 111,811,653 23 05LGSV0046-WY LRG GEN SRV
19,709 1 19,709,000 0.0707 1,392,451 24 05LGSV046M-WY LRG GEN SRV
287,448 1 287,448,000 0.0566 16,256,612 25 05LGSV048M-TOU>1000KW MAN
1,574,638 10 157,463,800 0.0588 92,566,416 26 05LGSV048T-LRG GENSRV TIM
36,161 27 05LNX00100-LINE EXT 60% G
406,293 28 05LNX00102-LINE EXT 80% G
36,851 29 05LNX00105-CNTRCT $ MIN G
238,170 30 05LNX00109-REF/NREF ADV +
83 41 2,024 0.1459 12,113 31 05OALT015N-OUTD AR LGT SR
1,371,276 8 171,409,500 0.0648 88,855,668 32 05PRSV033M-PART SERV REQ
1,633,205 33 REVENUE ADJ - DEF NPC
-11,109 34 REVENUE_ACCT ADJUSTMENTS
360,754 35 SMUD REVENUE IMPUTATIONS
30,798 36 05LNX00300 - LINE EXT 80%
22,578 37 05LNX00311 - LINE EXT 80%
6,762 0.1507 1,019,000 38 UNBILLED REVENUE
228,545 39 DSM REVENUE-SMALL
966,948 40 DSM REVENUE-LARGE
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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 7,474 1 BLUE SKY REVENUE-INDUSTRIAL
3,660 288 12,708 0.1003 367,246 2 05GNSV0025-WY GEN SRVC
56,472 77 733,403 0.0754 4,260,213 3 05GNSV0028-GEN SVC > 15 KW
3,407 3 1,135,667 0.0611 208,024 4 05GNSV028M-GEN SVC > 15 KW
45,999 4 11,499,750 0.0694 3,192,808 5 05LGSV0046-WY LRG GEN SRV
235,847 4 58,961,750 0.0586 13,816,600 6 05LGSV048M-TOU>1000KW MAN
1,310,835 12 109,236,250 0.0623 81,609,106 7 05LGSV048T-LRG GENSRV TIM
46,001 8 05LNX00102-LINE EXT 80% G
1,640,760 9 05LNX00109-REF/NREF ADV +
1,668 10 05LNX00300 - LINE EXT 80%
97,095 2 48,547,500 0.0647 6,284,861 11 05PRSV033M-PART SERV REQ
4 2 2,000 0.2350 940 12 09OALT207N-SECURITY AR LG
-817 0.1016 -83,000 13 UNBILLED REVENUE
106,661 14 DSM REVENUE-SMALL
421,189 15 DSM REVENUE-LARGE
23 16 BLUE SKY REVENUE-INDUSTRIAL
17
-962 18 LESS MULTIPLE BILLINGS
19
20,388,527 10,054 2,027,902 0.0632 1,287,846,708 20 TOTAL INDUSTRIAL SALES
21
22 IRRIGATION SALES
23 CALIFORNIA
13,728 879 15,618 0.1304 1,790,015 24 06APSV0020-AG PMP SRVC
61,142 579 105,599 0.1384 8,461,322 25 06APSV020L-AG PMP SRVC-NO
934 1 934,000 0.1352 126,297 26 06LGSV048T-LRG GEN SERV
3,934 27 06LNX00103-LINE EXT 80% G
104 28 06LNX00109-REF/NREF ADV +
21,790 29 06LNX00110-REF/NREF ADV +
3,345 30 06LNX00312 - CA IRG LINE EXT
641 7 91,571 0.1677 107,517 31 06NML20135-AGRI PUMP-NET MTR
5 4 1,250 0.1604 802 32 06NMT20135-AGRI PUMP-NET
4,570 348 13,132 0.1429 652,962 33 06USBR0020-KLAM IRG ONPRJ
27,160 370 73,405 0.1494 4,057,061 34 06USBR020L-KLAM IRG PRJ-NO
9,124 35 SOLAR FEED-IN REVENUE
-22 0.9545 -21,000 36 IRRIGATION UNBILLED
333,182 37 DSM REVENUE-IRRIGATION
23 38 BLUE SKY REVENUE-IRRIGATION
-591,320 39 REVENUE_ACCT ADJUSTMENTS
40
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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 IDAHO
392,904 2,676 146,825 0.0903 35,466,958 2 07APSA010L - IRG & PUMP LG
4,476 346 12,936 0.1122 502,010 3 07APSA010S - IRG & PUMP SM
205,238 1,456 140,960 0.0885 18,170,839 4 07APSAL10X - IRG & PUMP - LG
3,701 359 10,309 0.1165 431,317 5 07APSAS10X - IRG & PUMP - SM
2 148 6 07APSV006A-LRG POWER OPT
5 3 1,667 0.1078 539 7 07APSV023A-SM POWER OPT S
27,526 64 430,094 0.0810 2,229,602 8 07APSVCNLL-LG LOAD CANAL
366 16 22,875 0.0953 34,870 9 07APSVCNLS-SM LOAD CANAL
730 10 07LNX00015-ANNUAL 80%GUAR
242 11 07LNX00035-ADV 80%MO GUAR
126,037 12 07LNX00040-ADV+REFCHG+80%
432 13 07LNX00310 80% ANNUAL GTY
1,755 14 07LNX00311 - LINE EXT 80% GTY
35,574 15 07LNX00312 - ID LINE EXT
2,273 26 87,423 0.0969 220,301 16 07APSN010L - ID LG IRR & PUMP
59 5 11,800 0.1240 7,316 17 07APSN010S - IRRIGATION SM
261 12 21,750 0.1075 28,055 18 07APSNS10X - IRRIGATION SM
23 0.3043 7,000 19 UNBILLED REV - IRRIGATION
675,443 20 DSM REVENUE-IRRIGATION
1 30 21 BLUE SKY REV-IRRIGATION
22
23 OREGON
3,833 2,118,801 24 01APSV0041-AG PMP SRVC
3 1,471 25 01APSV0215-OR IRR TOU PILO
841 2,795,795 26 01APSV041L-PUMP SERV >30KW
55 29,902 27 01APSV041T - AGR PUMP SRV
1,195 773,982 28 01APSV041X-AG PMP SRVC
137,787 0.0573 7,897,519 29 01COST0041 -01APSV0041
118,510 0.0495 5,860,447 30 01COST0048 - 01LGSV0048
409 0.0412 16,856 31 01COST0215-OR TOU PILOT COST
583 0.0594 34,620 32 01COSTS028 G SERV CST > 30
94,869 0.0572 5,424,571 33 01CSTUSB41-USBR IRR CONTRA
2 9,754 34 01GNSB0028-OR GENL SVC > 30
2 16,112 35 01GNSV0028, OR GEN SRV > 30
8 0.0556 445 36 01HABIT041 - 01APSV0041 AG
2 614,870 37 01LGSB0048 - LG GEN SVC > 1000
4 1,661,291 38 01LGSV0048-1000KW AND OVR
36,255 39 01LNX00103-LINE EXT 80% G
210,904 40 01LNX00110-REF/NREF ADV +
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
11,273 1 01LNX00310-LINE EXTENSION
583 0.0557 32,487 2 01PTOU0041 - 01APSV0041 AG
149 0.0581 8,651 3 01RENEW041 - 01APSV0041 AG
148 0.0658 9,737 4 01STDAY041 - DAILY STD OFFER
3 17,377 5 01USBR0215-OR IRG TOU PILOT
9 41,213 6 01USBRGV41-IRG TOU W/O BPA
565 1,986,068 7 01USBROF41-KLAMATH BASIN
1,221 2,221,687 8 01USBRON41-KLAMATH BASIN
15 39,733 9 01VIR41136-OR VOLUME INC
81 313,444 10 01VRU41136-VOL INC USB
25,734 11 SOLAR FEED-IN REVENUE
-160 0.2625 -42,000 12 IRRIGATION UNBILLED
585,964 13 DSM REVENUE-IRRIGATION
498 14 BLUE SKY REVENUE-IRRIGATION
23,678 15 01LNX00312 - OR IRG LINE EXT
5 4,087 16 01NMT41135 - NETMTR AG PMP
3 3,580 17 01NMU41135 -NET MTR <PRJ
-716 18 OR GAIN ON SALE OF ASSET
8,115 19 REVENUE ADJ - DEF NPC
-54,820 20 REVENUE_ACCT ADJUSTMENTS
221 1,194,471 21 01APSV41XL-OR Pumping Serv
22
23 UTAH
214,373 2,866 74,799 0.0739 15,849,826 24 08APSV0010-IRR & SOIL DRA
35,312 192 183,917 0.0675 2,382,786 25 08APSV10NS- LG SOIL DRAIN
4,127 26 08LNX00004-ANNUAL 80%GUAR
14,195 27 08LNX00014-80% MIN MNTHLY
189,517 28 08LNX00017-ADV/REF&80%ANN
9,439 29 08LNX00310 - IRR, 80% ANN MIN
173 30 08LNX00311 - LINE EXT 80% GTY
28,370 31 08LNX00312 UT IRG LINE EXT
103 4 25,750 0.0944 9,720 32 08NMT10135-UT IRR_SOIL DRNG
-48,758 33 REVENUE_ACCT ADJUSTMENTS
20,620 34 SOLAR FEED-IN REVENUE
160 0.0313 5,000 35 UNBILLED REV - IRRIGATION
597,897 36 DSM REVENUE-IRRIGATION
30 37 BLUE SKY REVENUE-IRRIGATION
38
39 WASHINGTON
134,082 4,010 33,437 0.0823 11,033,682 40 02APSV0040-WA AG PMP SRVC
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
40,863 1,214 33,660 0.0848 3,463,324 1 02APSV040X-WA AG PMP SRVC
6,067 2 02LNX00103-LINE EXT 80% G
79 3 02LNX00105-CNTRCT $ MIN G
5,923 4 02LNX00109-REF/NREF ADV +
172,588 5 02LNX00110-REF/NREF ADV +
10,695 6 02LNX00310 - IRG 80% ANN MIN
180 7 02LNX00311 - LINE EXT 80%
37,516 8 02LNX00312 - WA IRG LINE EXT
70 3 23,333 0.0861 6,030 9 02NMT40135-WA NET MTR -IRG
-485,911 10 REVENUE_ACCT ADJUSTMENTS
-120,000 11 WASHINGTON - CHEHALIS DEF
-38 -0.2895 11,000 12 IRRIGATION UNBILLED
492,680 13 DSM REVENUE-IRRIGATION
5 107 14 BLUE SKY REVENUE-IRRIGATION
15
16 WYOMING
18,040 689 26,183 0.0878 1,583,791 17 05APS00040-AG PUMPING SVC
7,130 18 05LNX00103-LINE EXT 80% G
714 19 05LNX00109-REF/NREF ADV +
67,817 20 05LNX00110-REF/NREF ADV +
96 21 05LNX00310-LINE EXTCONTRAC
8,278 22 05LNX00312 - WY IRG LINE EXT
-10 -0.1000 1,000 23 IRRIGATION UNBILLED
26,098 24 DSM REVENUE-IRRIGATION
1,220 25 05LNX00103-LINE EXT 80% G
10,299 26 05LNX00110-REF/NREF ADV +
1,023 27 05LNX00312 - WY IRG LINE EXT
4,244 88 48,227 0.0862 366,043 28 09APSV0210-IRR & SOIL DRA
8,093 29 DSM REVENUE-IRRIGATION
30
-966 31 LESS MULTIPLE BILLINGS
32
1,545,075 23,319 66,258 0.0923 142,606,716 33 TOTAL IRRIGATION SALES
34
35 PUBLIC STREET & HWY LIGHTING
36 CALIFORNIA
1,415 108 13,102 0.1680 237,749 37 06CUSL053E-SPECIAL CUST O
237 22 10,773 0.1871 44,331 38 06CUSL058F-CUST OWND STR
669 79 8,468 0.3059 204,661 39 06HPSV0051-HI PRESSURE SO
9,366 40 DSM REVENUE-PUB ST & HWY LT
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
-14,352 1 REVENUE_ACCT ADJUSTMENTS
715 2 SOLAR FEED-IN REVENUE
-17 0.1176 -2,000 3 UNBILLED REVENUE
4
5 IDAHO
141 24 5,875 0.1222 17,226 6 07GNSV023S-IDAHO TRAFFIC
88 37 2,378 0.4587 40,365 7 07SLCO0011-STR LGT CO-OWN
364 28 13,000 0.1110 40,418 8 07SLCU012E-ENGY STR LGT
1,891 191 9,901 0.1980 374,337 9 07SLCU012F-FULL MNT STR
195 16 12,188 0.1449 28,262 10 07SLCU012P-PART MNT STR LGT
8,882 11 DSM REVENUE-PUB ST & HWY LT
-7 0.1429 -1,000 12 UNBILLED REVENUE
13
14 OREGON
411 35 11,743 0.1488 61,152 15 01COSL0052-STR LGT SRVC C
762 72 10,583 0.0734 55,908 16 01CUSL0053-CUS-OWNED MTRD
8,927 167 53,455 0.0738 658,889 17 01CUSL053E-STR LGT SVC
123 9 13,667 0.0946 11,637 18 01CUSL053F-STR LGT SRVC C
19,716 725 27,194 0.2097 4,134,931 19 01HPSV0051-HI PRESSURE SO
45 20 2,250 0.3542 15,940 20 01LEDSL051-OR LED PILOT
7,969 238 33,483 0.1316 1,048,894 21 01MVSL0050-MERC VAPSTR LG
2 2 1,000 0.1560 312 22 01OALT015N-OUTD AR LGT NR
2 1 2,000 0.1325 265 23 01OALTB15N-OR OUTD AR LGT
136,498 24 DSM REVENUE-PUB ST & HWY LT
-118 25 OR GAIN ON SALE OF ASSET
1,695 26 REVENUE ADJ - DEF NPC
-12,092 27 REVENUE_ACCT ADJUSTMENTS
6,277 28 SOLAR FEED-IN REVENUE
565 0.1770 100,000 29 UNBILLED REVENUE
30
31 UTAH
54 32 08CFR00012-STR LGTS (CONV
4,529 33 08CFR00051-MTH FAC SRVCHG
79 34 08CFR00062-STREET LIGHTS
3 3 1,000 0.3447 1,034 35 08OALT007N-SECURITY AR LG
1,141 123 9,276 0.0918 104,793 36 08TOSS015F-TRAFFIC SIG NM
15,377 792 19,415 0.3058 4,702,714 37 08SLCO0011-STR LGT CO-OWN
3,072 1,533 2,004 0.1174 360,580 38 08TOSS0015-TRAF & OTHER S
714 65 10,985 0.0823 58,762 39 08MONL0015-MTR OUTDONIGHT
4,927 204 24,152 0.1281 630,951 40 08SLCU012P-STR LGT CUST-O
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
1,070 86 12,442 0.1390 148,685 1 08SLCU012F-STR LGT CUST-O
50,742 614 82,642 0.0657 3,333,456 2 08SLCU012E-DECOR CUST-OWN
335,335 3 DSM REVENUE-PSHL
-48,163 4 REVENUE_ACCT ADJUSTMENTS
20,352 5 SOLAR FEED-IN REVENUE
-1,221 0.1204 -147,000 6 UNBILLED REVENUE
7
8 WASHINGTON
91 9 02CFR00012-STR LGTS (CONV
207 15 13,800 0.1675 34,676 10 02COSL0052-WA STR LGT SRV
3,672 111 33,081 0.0687 252,176 11 02CUSL053F-WA STR LGT SRV
1,149 105 10,943 0.0709 81,429 12 02CUSL053M-WA STR LGT SRV
3,871 159 24,346 0.1930 747,076 13 02SLCO0051-WA COMPANY
1,742 40 43,550 0.1231 214,458 14 02MVSL0057-WA MERC VAPSTR
-30,000 15 WASHINGTON - CHEHALIS
27,982 16 DSM REVENUE-PSHL
-27,376 17 REVENUE_ACCT ADJUSTMENTS
942 0.1285 121,000 18 UNBILLED REVENUE
19
20 WYOMING
273 18 15,167 0.2201 60,081 21 05COSL0057-CO-OWND STR LG
84 11 7,636 0.0689 5,790 22 05CUSL058M-CUST OWND STR
1,098 30 36,600 0.0691 75,883 23 05CUSL0E58-CUST OWNED STR
44 3 14,667 0.0817 3,595 24 05CUSL0M58-CUST OWNED STR
5,453 174 31,339 0.2245 1,224,114 25 05HPSV0051-HI PRESSURE SO
3,854 254 15,173 0.1379 531,376 26 05MVS00053-MERCURY VAPOR
24 1 24,000 0.1217 2,921 27 05OALT015N-OUTD AR LGT SR
15,367 28 DSM REVENUE-PSHL
-53 29 REVENUE_ACCT ADJUSTMENTS
-200 0.1650 -33,000 30 UNBILLED REVENUE
26 1 26,000 0.0945 2,457 31 09MONL0213-WY MTR OUTDOOR
1,490 51 29,216 0.2701 402,387 32 09SLCO0211-STR LGT CO-OWN
34 5 6,800 0.1753 5,959 33 09SLCUP212-CUST OWNED
56 14 4,000 0.0476 2,663 34 09TOSS0213-TRAFFIC & OTHER
9,083 35 DSM REVENUE-PSHL
5 0.2000 1,000 36 UNBILLED REVENUE
37
-2,652 38 LESS MULTIPLE BILLINGS
39
143,147 3,534 40,506 0.1428 20,446,444 40 TOTAL PUBLIC SREET & HWY
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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 OTHER SALES TO PUBLIC AUTH
3 UTAH
35,786 1 35,786,000 0.0797 2,853,146 4 08PRSV031M-BKUP MNT&SUPPL
612,481 5 DSM REVENUE-OSPA
-69,636 6 REVENUE_ACCT ADJUSTMENTS
29,457 7 SOLAR FEED-IN REVENUE
-5,272 0.0563 -297,000 8 UNBILLED REVENUE
251,110 2 125,555,000 0.0572 14,371,075 9 08GNSV009M-MANL HIGH VOLT
10
281,624 3 93,874,667 0.0621 17,499,523 11 TOTAL OTHER SALES TO PUBLIC
12
13 FORFEITED DISCOUNTS
14 CALIFORNIA
283,123 15 06LPAY0300-LATEFEE
16
17 IDAHO
452,358 18 07LPAY0300-LATEFEE
19
20 OREGON
3,979,745 21 01LPAY0300-LATEFEE
22
23 UTAH
3,550,834 24 08LPAY0300-LATEFEE
1,964 25 OTHER
26
27 WASHINGTON
676,553 28 02LPAY0300-LATEFEE
29
30 WYOMING
459,852 31 05LPAY0300-RES-LATEFEE
145,733 32 05LPAY0300-COM-LATEFEE
120,062 33 05LPAY0300-IND-LATEFEE
25 34 05LPAY0300-OTHER-LATEFEE
35
9,670,249 36 TOTAL FORFEITED DISCOUNTS
37
38 MISCELLANEOUS SERVICE REV
39 CALIFORNIA
1,454 40 06CFR00003-MTH MAINTENANC
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
26,835 1 06CONN0300-CA RECONNECTIO
50,273 2 06FCBUYOUT
10,464 3 06RCHK0300-CA RET CHK CHR
1,200 4 06TAMP0300-CA TAMP & UNAU
1,105 5 06TEMP0300-CA TEMP SRVC C
298 6 06XMTRTAMP-TMPRING - UNAU
225 7 HOME COMFORT
8
9 IDAHO
1,682 10 07CFR00001-MTH FAC SRVCHG
44,155 11 07CONN0300-ID RECONNECTIO
14,438 12 07FCBUYOUT - FAC CHG BUYOUT
29,640 13 07RCHK0300-ID RET CHK CHR
225 14 07TAMP0300
18,505 15 07TEMP0014-TEMP SRVC CONN
-5 16 OTHER
17
18 OREGON
137,462 19 01CFR00001-MTH FACILITY S
25,984 20 01CFR00003-MTH MAINTENANC
25,753 21 01CFR00004-MTH MAINTENANC
37,401 22 01CFR00005-INTERMTNT SRVC
2,284 23 01CFR00013-MTH MISC CHRG
5 24 01CFR00014-YR MISC CHRG
374,310 25 01CONN0300-RECONNECTION C
8,677 26 01CONTSERV-OR 3RD PARTY
6,774 27 01ESSC0600 - ESS CHARGES
317,420 28 01FCBUYOUT-FAC CHG BUYOUT
295,700 29 01RCHK0300-RETURNED CHECK
14,700 30 01TAMP0300-TAMP & UNAUTH
143,500 31 01TEMP0300-TEMP SRVC CHRG
3,425 32 01XMTRTAMP-TAMPRING - UNAU
-47,410 33 OTHER
34
35 UTAH
147,885 36 08CFR00013-MTH MISC CHRG
87,747 37 08CFR00051-MTH FAC SRVCHG
424 38 08CFR00052-ANN FAC SVCCHG
11,633 39 08CFR00053-MTHLY MAINTFEE
4,976 40 08CFR00054-NRES EMERGENCY
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
2,343 1 08CFR00063-MTH MISC CHARG
6,660 2 08CFR00064-ANN MISC CHARG
457,930 3 08CONN0300-RECONN&DISCONN
82,012 4 08CONTSERV-3RD PARTY O/S
289,656 5 08FCBUYOUT-FAC CHG BUYOUT
8,050 6 08NCON0300-UT FEE NRES RE
1,415 7 08NSMTR300-NON STAN MTR
366 8 08PRINT300-SCREEN PRINT FOR
470,000 9 08RCHK0300-UT RET CHK CHR
1,641,530 10 08RCON0001-CONNECT FEE
2,311 11 08RESD0001-RES SRVC
8,175 12 08TAMP0300-TAMPERING&UNAU
462,950 13 08TEMP0014-TEMP SRVC CONN
1,904 14 08XMTRTAMP-TMPRING - UNAU
5,592 15 ENERGY FINANSWER NEW COM
48,655 16 08VISIT300 - UT VISIT, SERVICE
-4,765 17 OTHER
18
19 WASHINGTON
1,320 20 02CFR00003-MTH MAINTENANC
5,892 21 02CFR00004-EMRGNCY ST&BY
4,302 22 02CFR00005-INTERMTNT SRVC
93,380 23 02CONN0300-WA RECONNECTIO
13,610 24 02FCBUYOUT - FAC CHG BUYOUT
58,160 25 02RCHK0300-WA RET CHK CHR
3,150 26 02TAMP0300-WA TAMP & UNAU
21,005 27 02TEMP0300-WA TEMP SRVC C
344 28 02XMTRTAMP-TMPRING - UNAU
11 29 ENERGY FINANSWER NEW COM
611 30 HOME COMFORT
-38,445 31 OTHER
32
33 WYOMING
1,768 34 05CFR00003-MTH MAINTENANC
18,416 35 05CFR00004-EMRGNCY ST&BY
10,133 36 05CFR00005-INTERMTNT SRVC
3,186 37 05CFR00013-MTH MISC CHRG
94,593 38 05CONN0300-WY RECONNECTIO
205,684 39 05FCBUYOUT - FAC CHG BUYOUT
74,970 40 05RCHK0300-WY RET CHK CHR
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
825 1 05TAMP0300
39,630 2 05TEMP0300-WY TEMP SRVC C
52 3 05XMTRTAMP-TMPRING - UNAU
339 4 09CFR00005-INTERMTNT SRVC
4,799 5 OTHER
16,898 6 05CONN0300-WY RECONNECTIO
26,427 7 05FCBUYOUT - FAC CHG BUYOUT
8,160 8 05RCHK0300-WY RET CHK CHR
150 9 05TAMP0300
285 10 05TEMP0300-WY TEMP SRVC C
88 11 05XMTRTAMP-TAMP - UNAUTH
5,025 12 09CFR00001-MTH FAC SRVCHG
3 13 09CFR00014-YR MISC CHRG
4 14 ENERGY FINANSWER 12,000
-2,417 15 OTHER
16
5,956,286 17 TOTAL MISC SERVICE REV
18
19 RENT FROM ELEC PROPERTIES
20 CALIFORNIA
1,710 21 06CFR00006-MTH RNTAL CHRG
1,200 22 RENT REVENUE-HYDRO
19,200 23 RENT REVENUE - SUBLEASES
520,750 24 JOINT USE
25
26 IDAHO
788 27 07CFR00009-YR LSE CHRG-EQ
150 28 07INVCHG00-INVEST MNT CHG
276 29 07POLE0075-STEEL POLES US
66,535 30 RENT REVENUE-HYDRO
250 31 RENT REV-TRANSMISS
300 32 RENT REV-DISTRIBUT
2,216 33 RENT REVENUE - SUBLEASES
147,819 34 JOINT USE
35
36 OREGON
811,575 37 01CFR00006-MTH RNTAL CHRG
670,588 38 RENTS - COMMON
25 39 RENTS - NON COMMON
3,346,955 40 MCI FOGWIRE REVENUE
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
36,292 1 RENT REV - SUBLEASES
23,721 2 RENT REVENUE-HYDRO
262,156 3 RENT REV-TRANSMISS
64,141 4 RENT REV-DISTRIBUT
56,559 5 RENT REV-GEN(COMM)
2,725,516 6 JOINT USE
7
8 UTAH
33 9 08CFR00056-MTH EQUIP RENT
534,384 10 08CFR00058-MTH EQUIP LEAS
4,403 11 08INVCHG0N-INVEST MNT CHG
242 12 08INVCHG0R-INVEST MNT CHG
54,832 13 08POLE0075-STEEL POLES US
11,100 14 RENTS - NON COMMON
124,465 15 RENT REVENUE-STEAM
71,196 16 RENT REVENUE-HYDRO
1,014,098 17 RENT REV-TRANSMISS
543,048 18 RENT REV-DISTRIBUT
13,384 19 RENT REV-GEN(COMM)
2,793,143 20 RENT REVENUE - SUBLEASES
2,116,411 21 JOINT USE
22
23 WASHINGTON
2,086 24 02CFR00001-MTH FACILITY S
9,073 25 02CFR00006-MTH RNTAL CHRG
342,580 26 RENT REVENUE-HYDRO
20,558 27 RENT REV-DISTRIBUT
39,942 28 RENT REV-GEN(COMM)
17,974 29 RENT REV-TRANSMISS
874,037 30 JOINT USE
31
32 WYOMING
11,524 33 05CFR00001-MTH FACILITY S
2,482 34 05CFR00006-MTH RNTAL CHRG
34,241 35 RENT REVENUE-STEAM
20,982 36 RENT REVENUE-HYDRO
14,230 37 RENT REV-TRANSMISS
150 38 RENT REV-DISTRIBUT
27,838 39 RENT REV-GEN(COMM)
1,467 40 RENT REVENUE - SUBLEASES
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
346,652 1 JOINT USE
18,313 2 09POLE0075-STEEL POLES US
3,880 3 RENT REVENUE-STEAM
143 4 JOINT USE
5
17,827,613 6 TOTAL RENT FROM ELEC PROP
7
8 OTHER ELECTRIC REVENUE
11,521,257 9 WIND BASED ANCILLARY SVC
-3,442,129 10 FERC TRANSMISSION REFUND
-127,236 11 OTH ELEC ESTIMATE
10,144,970 12 RENEW ENERGY CRDT SALES
5,572,977 13 GREEN CREDIT SALES
14,673,226 14 CA GHG ALLOW REV AMORT
9,065,100 15 NON-WHEELING SYSTEM
16,000 16 OTHER ELEC (EXCLUDE WHEEL)
8,174 17 REC SALES-WIND WAKE LOSS
8,053,851 18 RENEWABLE ENERGY CR AMORT
19
20 CALIFORNIA
9,581 21 3RD PARTY TRANS
7,679 22 FISH, WILDLIFE, RECR
-11 23 OTHER ELEC (EXCLUDE WHEELl)
24
25 IDAHO
133,191 26 3RD PARTY TRANS O&M
27
28 OREGON
141,624 29 3RD PARTY TRANS O&M
-10,244 30 I/C TRANS O&M REV - SIERRA
1,199 31 M&S INV REVENUE
1,845,579 32 OTHER ELEC (EXCLUDE WHEELl)
33
34 UTAH
931 35 08XTRN0011-SALES ORDERS
97,060 36 ELEC INC-OTHR
2,105,993 37 FLYASH SALES
196,351 38 3RD PARTY TRANS O&M
2,240 39 FISH, WILDLIFE, RECR
19,244 40 I/C TRANS O&M REV - SIERRA
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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
/ /2014/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.
-30 1 OTHER ELEC (EXCLUDE WHEEL)
939,493 2 M&S INVENTORY REVENUE
3 WASHINGTON
426,135 4 TIMBER SALES - UTILITY PROP
6,975 5 FISH, WILDLIFE, RECR
-33 6 OTHER ELEC (EXCLUDE WHEELl)
-52,188 7 WASH COLSTRIP 3
8
9 WYOMING
11,854 10 05XTRN0011-SALES ORDERS
15 11 ELEC INC-OTHR
2,892,303 12 FLYASH SALES
302,725 13 WY REG RECOVERY FEE
116,795 14 3RD PARTY TRANS
-4 15 OTHER ELEC (EX WHEEL)
16
64,680,647 17 TOTAL OTHER ELEC REV
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
54,999,277 4,817,264,361 1,782,893 30,848 0.0876
-247,000 -14,757,000 0 0 0.0597
55,246,277 4,832,021,361 1,782,893 30,987 0.0875
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 / /2014/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 19.020.021.0T-12RQ 2
Deaver, Town of 0.10.10.2T-4RQ 3
Helper City 0.91.01.0T-6RQ 4
Helper City Annex 0.60.60.6T-6RQ 5
Navajo Tribal Util. Auth. (Mexican Hat)0.10.20.2T-6RQ 6
Navajo Tribal Util. Auth. (Red Mesa)1.01.01.0T-6RQ 7
Portland General Electric Company NANANA147RQ 8
Price City Corporation 11.012.024.0T-12RQ 9
Accrual NANANANARQ 10
11
Nonrequirement Sales 12
Arizona Public Service Company NANANAT-12SF 13
Avista Corporation NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90)Page 310
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2014/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
3,586,164 2,868,386 6,454,550 123,953 2
12,209 10,987 23,196 681 3
106,275 111,213 217,488 6,010 4
64,319 69,461 133,780 3,637 5
16,037 17,762 33,799 920 6
150,710 132,339 283,049 8,651 7
1,155,439 1,155,439 11,440 8
2,003,819 1,658,233 3,662,052 69,473 9
13,523 13,523 732 10
11
12
3,518,994 3,518,994 93,364 13
3,330,072 3,330,072 110,082 14
FERC FORM NO. 1 (ED. 12-90)Page 311
7,094,972
490,410,575
497,505,547
225,497
10,044,750
10,270,247
13,523 11,976,876
-153,554,753
-153,541,230
348,623,719
360,600,595
4,868,381
11,767,897
16,636,278
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 / /2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Avista Corporation NANANAT-13SF 1
Avista Corporation NANANAWSPP - QSF 2
BP Energy Company NANANAT-12AD 3
BP Energy Company NANANAT-12SF 4
Basin Electric Power Cooperative NANANAT-11SF 5
Basin Electric Power Cooperative NANANAT-12SF 6
Black Hills Power, Inc.515650441LF 7
Black Hills Power, Inc.NANANAT-12SF 8
Black Hills Wyoming, Inc.NANANAT-11SF 9
Bonneville Power Administration NANANAT-12AD 10
Bonneville Power Administration NANANA368LF 11
Bonneville Power Administration NANANAT-11LF 12
Bonneville Power Administration NANANA519LU 13
Bonneville Power Administration NANANAT-11SF 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 / /2014/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.
716 716 22 1
17,400 17,400 400 2
371 371 14 3
7,151,715 7,151,715 229,200 4
6,436 6,436 173 5
4,660,591 4,660,591 139,965 6
6,561,184 7,371,697 13,932,881 343,081 7
6,871,319 6,871,319 204,744 8
794 794 39 9
226,265 226,265 10
88,475 88,475 2,748 11
553,546 553,546 16,022 12
2,921,593 2,921,593 38,882 13
471 471 13 14
FERC FORM NO. 1 (ED. 12-90)Page 311.1
7,094,972
490,410,575
497,505,547
225,497
10,044,750
10,270,247
13,523 11,976,876
-153,554,753
-153,541,230
348,623,719
360,600,595
4,868,381
11,767,897
16,636,278
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 / /2014/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-12SF 1
Bonneville Power Administration NANANAT-13SF 2
British Columbia Hydro and Power NANANAT-13SF 3
Brookfield Energy Marketing L.P.NANANAT-12SF 4
California Independent System Operator NANANAT-12SF 5
Calpine Energy Services, L.P.NANANAT-12SF 6
Cargill Power Markets, LLC NANANAT-12AD 7
Cargill Power Markets, LLC NANANAT-11SF 8
Cargill Power Markets, LLC NANANAT-12SF 9
Cargill Power Markets, LLC NANANAWSPP - QSF 10
City of Anaheim NANANAT-12SF 11
City of Burbank NANANAT-12SF 12
City of Glendale NANANAT-12SF 13
City of Redding 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 / /2014/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.
4,973,781 4,973,781 151,803 1
1,823 1,823 61 2
2,352 2,352 63 3
1,488,481 1,488,481 39,088 4
1,787,553 1,787,553 47,538 5
2,302,519 2,302,519 71,587 6
7 7 7
64,176 64,176 1,706 8
33,135,641 33,135,641 921,868 9
6,468 6,468 196 10
96,347 96,347 2,309 11
5,058,817 5,058,817 152,420 12
2,261,618 2,261,618 65,613 13
436,909 436,909 15,368 14
FERC FORM NO. 1 (ED. 12-90)Page 311.2
7,094,972
490,410,575
497,505,547
225,497
10,044,750
10,270,247
13,523 11,976,876
-153,554,753
-153,541,230
348,623,719
360,600,595
4,868,381
11,767,897
16,636,278
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 / /2014/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.
Clatskanie People's Utility District NANANAT-12SF 1
ConocoPhillips Company NANANAT-12SF 2
Constellation Energy Commodities Group NANANAT-11SF 3
Constellation Energy Commodities Group NANANAT-11SF 4
Coral Power, LLC NANANAT-11SF 5
Deseret Generation & Transmission NANANAT-11SF 6
EDF Trading North America, LLC NANANAT-12SF 7
EDF Trading North America, LLC NANANAWSPP - QSF 8
El Paso Electric Company NANANAT-12SF 9
Eugene Water & Electric Board NANANAT-12SF 10
Exelon Generation Company, LLC NANANAT-12SF 11
Gila River Power LLC NANANAT-12AD 12
Gila River Power LLC NANANAT-12SF 13
Gridforce Energy Management, LLC NANANAT-13AD 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 / /2014/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.
129,469 129,469 2,867 1
36,400 36,400 800 2
5,240 5,240 122 3
1,031 1,031 26 4
227,620 227,620 7,367 5
9,257 9,257 273 6
22,120,148 22,120,148 584,339 7
820,060 820,060 20,761 8
1,596,994 1,596,994 42,627 9
1,048,315 1,048,315 34,344 10
55,586,831 55,586,831 1,535,176 11
7,475 7,475 250 12
3,574,736 3,574,736 98,400 13
1,320 1,320 37 14
FERC FORM NO. 1 (ED. 12-90)Page 311.3
7,094,972
490,410,575
497,505,547
225,497
10,044,750
10,270,247
13,523 11,976,876
-153,554,753
-153,541,230
348,623,719
360,600,595
4,868,381
11,767,897
16,636,278
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 / /2014/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.
Gridforce Energy Management, LLC NANANAT-13SF 1
Iberdrola Renewables, LLC NANANAT-11LF 2
Iberdrola Renewables, LLC NANANAT-11SF 3
Iberdrola Renewables, LLC NANANAT-11SF 4
Iberdrola Renewables, LLC NANANAT-12SF 5
Iberdrola Renewables, LLC NANANAWSPP - QSF 6
Idaho Power Company NANANAT-11LF 7
Idaho Power Company NANANAT-11SF 8
Idaho Power Company NANANAT-12SF 9
Idaho Power Company NANANAT-13SF 10
J. Aron & Company NANANAT-12SF 11
J.P. Morgan Ventures Energy Corporation NANANAT-11SF 12
J.P. Morgan Ventures Energy Corporation NANANAT-11SF 13
Los Angeles Dept. of Water and Power NANANA301LU 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 / /2014/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.
6,517 6,517 219 1
130,569 130,569 3,787 2
480,087 480,087 14,435 3
2,265 2,265 34 4
35,035,427 35,035,427 1,021,064 5
434,500 434,500 10,000 6
94,158 94,158 2,737 7
86,513 86,513 2,468 8
175,684 175,684 5,593 9
1,744 1,744 73 10
10,879,278 10,879,278 317,414 11
33,113 33,113 997 12
7,088 7,088 224 13
26,706,775 26,706,775 542,628 14
FERC FORM NO. 1 (ED. 12-90)Page 311.4
7,094,972
490,410,575
497,505,547
225,497
10,044,750
10,270,247
13,523 11,976,876
-153,554,753
-153,541,230
348,623,719
360,600,595
4,868,381
11,767,897
16,636,278
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 / /2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Los Angeles Dept. of Water and Power NANANAT-11SF 1
Los Angeles Dept. of Water and Power NANANAT-12SF 2
Macquarie Energy LLC NANANAT-11SF 3
Macquarie Energy LLC NANANAT-12SF 4
Metro Water Dist. of S. California NANANAT-12SF 5
Modesto Irrigation District NANANAT-12SF 6
Morgan Stanley Capital Group Inc.NANANAT-11SF 7
Morgan Stanley Capital Group Inc.NANANAT-12SF 8
Municipal Energy Agency of Nebraska NANANAT-12SF 9
NaturEner Power Watch, LLC NANANAT-13SF 10
Nevada Power Company NANANAT-11SF 11
Nevada Power Company NANANAWSPP - QSF 12
NextEra Energy Power Marketing, LLC NANANAT-11OS 13
NextEra Energy Power Marketing, LLC NANANAT-11SF 14
FERC FORM NO. 1 (ED. 12-90)Page 310.5
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2014/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.
6,340 6,340 186 1
1,727,435 1,727,435 49,084 2
3,058 3,058 525 3
4,301,341 4,301,341 120,000 4
1,004,447 1,004,447 31,167 5
1,587,904 1,587,904 44,759 6
217,440 217,440 6,959 7
12,492,902 12,492,902 408,833 8
2,691,785 2,691,785 96,950 9
304 304 10 10
9,408 9,408 234 11
4,542,803 4,542,803 166,872 12
289,188 289,188 9,697 13
1,149 1,149 47 14
FERC FORM NO. 1 (ED. 12-90)Page 311.5
7,094,972
490,410,575
497,505,547
225,497
10,044,750
10,270,247
13,523 11,976,876
-153,554,753
-153,541,230
348,623,719
360,600,595
4,868,381
11,767,897
16,636,278
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 / /2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
NextEra Energy Power Marketing, LLC NANANAT-11SF 1
NextEra Energy Power Marketing, LLC NANANAT-12SF 2
Noble Americas Energy Solutions LLC NANANAT-11LF 3
NorthWestern Corporation NANANAT-12SF 4
NorthWestern Corporation NANANAT-13SF 5
Northern California Power Agency NANANAT-12SF 6
Northpoint Energy Solutions Inc.NANANAT-12AD 7
PPL EnergyPlus, LLC NANANAT-11SF 8
PPL EnergyPlus, LLC NANANAT-12SF 9
Pacific Gas & Electric Company NANANAT-11SF 10
Portland General Electric Company NANANAT-11SF 11
Portland General Electric Company NANANAT-12SF 12
Portland General Electric Company NANANAT-13SF 13
Powerex Corporation NANANAT-11LF 14
FERC FORM NO. 1 (ED. 12-90)Page 310.6
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2014/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.
193 193 7 1
25,200 25,200 800 2
27,836 27,836 923 3
387,027 387,027 12,915 4
11,919 11,919 370 5
114,229 114,229 6,397 6
-2 -2 7
16,131 16,131 427 8
945,269 945,269 25,672 9
1,131 1,131 22 10
11,955 11,955 475 11
7,314,693 9,250 7,323,943 253,763 12
5,364 5,364 131 13
876,125 876,125 28,390 14
FERC FORM NO. 1 (ED. 12-90)Page 311.6
7,094,972
490,410,575
497,505,547
225,497
10,044,750
10,270,247
13,523 11,976,876
-153,554,753
-153,541,230
348,623,719
360,600,595
4,868,381
11,767,897
16,636,278
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 / /2014/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-12SF 7
PUD #1 of Chelan County NANANAT-13SF 8
PUD #1 of Clark County NANANAT-12SF 9
PUD #1 of Douglas County NANANAT-12SF 10
PUD #1 of Douglas County NANANAT-13SF 11
PUD #1 of Snohomish County NANANAT-12SF 12
PUD #2 of Grant County NANANAT-12SF 13
PUD #2 of Grant County NANANAT-13SF 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 / /2014/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.
654,319 654,319 22,426 1
11,234,614 8,900 11,243,514 443,363 2
530 530 34 3
1,004 1,004 27 4
3,878,580 3,878,580 119,166 5
9,053,039 9,053,039 244,997 6
214,050 214,050 7,150 7
166 166 5 8
662,327 662,327 17,818 9
5,900 5,900 120 10
168 168 7 11
887,732 887,732 21,821 12
1,033,728 1,033,728 25,079 13
120 120 3 14
FERC FORM NO. 1 (ED. 12-90)Page 311.7
7,094,972
490,410,575
497,505,547
225,497
10,044,750
10,270,247
13,523 11,976,876
-153,554,753
-153,541,230
348,623,719
360,600,595
4,868,381
11,767,897
16,636,278
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 / /2014/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.
Puget Sound Energy, Inc.NANANAT-11SF 1
Puget Sound Energy, Inc.NANANAT-12SF 2
Puget Sound Energy, Inc.NANANAT-13SF 3
Rainbow Energy Marketing Corporation NANANAT-11SF 4
Rainbow Energy Marketing Corporation NANANAT-12SF 5
Sacramento Municipal Utility District NANANA250AD 6
Sacramento Municipal Utility District NANANA250LF 7
Sacramento Municipal Utility District NANANAT-11LF 8
Sacramento Municipal Utility District NANANAT-12SF 9
Salt River Project NANANAT-11LF 10
Salt River Project NANANAT-11SF 11
Salt River Project NANANAT-12SF 12
Seattle City Light NANANAT-12SF 13
Seattle City Light NANANAT-13SF 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 / /2014/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.
4,234 4,234 84 1
2,423,344 2,423,344 71,286 2
1,810 1,810 71 3
29,100 29,100 759 4
5,673,880 5,673,880 190,280 5
762,981 762,981 6
15,800,795 15,800,795 569,398 7
161,698 161,698 5,027 8
3,542,317 3,542,317 116,001 9
190,444 190,444 5,655 10
5,859 5,859 188 11
7,962,328 7,962,328 240,870 12
1,424,148 1,424,148 46,725 13
711 711 23 14
FERC FORM NO. 1 (ED. 12-90)Page 311.8
7,094,972
490,410,575
497,505,547
225,497
10,044,750
10,270,247
13,523 11,976,876
-153,554,753
-153,541,230
348,623,719
360,600,595
4,868,381
11,767,897
16,636,278
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 / /2014/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.
Sempra Generation, LLC NANANAT-12SF 1
Shell Energy North America (US), L.P.NANANAT-12IF 2
Shell Energy North America (US), L.P.NANANAT-12SF 3
Shell Energy North America (US), L.P.NANANAWSPP - QSF 4
Sierra Pacific Power Company NANANAT-11SF 5
Sierra Pacific Power Company NANANAT-13SF 6
Sierra Pacific Power Company NANANAWSPP - QSF 7
Southern California Edison Company NANANAT-11SF 8
Southern California Edison Company NANANAT-11SF 9
Southern California Edison Company NANANAT-12SF 10
Southern California Public Power Auth.NANANAT-11SF 11
Southwestern Public Service Company NANANAT-12SF 12
Tacoma Power NANANAT-12SF 13
Tacoma Power NANANAT-13SF 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 / /2014/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.
35,557,196 35,557,196 1,067,740 1
8,646,268 8,646,268 213,171 2
7,215,625 7,215,625 203,816 3
66,107 66,107 1,895 4
189 189 12 5
8,516 8,516 232 6
20,125 20,125 875 7
462,275 462,275 13,694 8
174 174 9 9
7,256,460 7,256,460 217,159 10
1,465 1,465 49 11
104,375 104,375 3,075 12
891,310 891,310 32,025 13
411 411 16 14
FERC FORM NO. 1 (ED. 12-90)Page 311.9
7,094,972
490,410,575
497,505,547
225,497
10,044,750
10,270,247
13,523 11,976,876
-153,554,753
-153,541,230
348,623,719
360,600,595
4,868,381
11,767,897
16,636,278
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 / /2014/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.
Tenaska Power Services Co.NANANAT-11SF 1
Tenaska Power Services Co.NANANAT-12SF 2
Tenaska Power Services Co.NANANAWSPP - QSF 3
The Energy Authority, Inc.NANANAT-12AD 4
The Energy Authority, Inc.NANANAT-11SF 5
The Energy Authority, Inc.NANANAT-12SF 6
Thermo No. 1 BE-01, LLC NANANAT-11LF 7
TransAlta Energy Marketing (U.S.) Inc.NANANAT-11SF 8
TransAlta Energy Marketing (U.S.) Inc.NANANAT-12SF 9
TransCanada Energy Sales Ltd.NANANAT-12SF 10
Tri-State Gen. and Trans.NANANAT-11LF 11
Tri-State Gen. and Trans.NANANAT-11SF 12
Tri-State Gen. and Trans.NANANAT-12SF 13
Tucson Electric Power Company NANANAT-12SF 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 / /2014/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.
124,761 124,761 3,857 1
9,659,251 9,659,251 325,715 2
34,000 34,000 1,200 3
-2,090 -2,090 -55 4
3,504 3,504 146 5
2,111,757 2,111,757 58,232 6
83,555 83,555 2,510 7
80,515 80,515 2,624 8
13,543,810 13,543,810 445,425 9
45,700 45,700 850 10
34,113 34,113 1,257 11
17,939 17,939 631 12
10,057,019 10,057,019 339,115 13
19,619,702 19,619,702 590,689 14
FERC FORM NO. 1 (ED. 12-90)Page 311.10
7,094,972
490,410,575
497,505,547
225,497
10,044,750
10,270,247
13,523 11,976,876
-153,554,753
-153,541,230
348,623,719
360,600,595
4,868,381
11,767,897
16,636,278
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 / /2014/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.
Turlock Irrigation District NANANAT-12SF 1
Turlock Irrigation District NANANAT-13SF 2
UNS Electric, Inc.NANANAT-12SF 3
Utah Associated Municipal Power Systems NANANAT-11SF 4
Utah Associated Municipal Power Systems NANANAT-12SF 5
Utah Municipal Power Agency 343434433LF 6
Utah Municipal Power Agency NANANA637LF 7
Utah Municipal Power Agency NANANAT-11SF 8
Utah Municipal Power Agency NANANAT-12SF 9
Vitol Inc.NANANAT-12SF 10
Western Area Power Administration NANANAT-11SF 11
Western Area Power Administration NANANAT-12SF 12
Western Area Power Administration NANANAT-13SF 13
Test generation NANANANA 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 / /2014/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.
137,450 137,450 4,430 1
39 39 1 2
6,628,546 6,628,546 196,913 3
10,178 10,178 288 4
120,525 120,525 4,173 5
5,202,320 4,396,200 9,598,520 223,852 6
107,315 107,315 3,876 7
64 64 2 8
233,453 233,453 8,042 9
404,800 404,800 11,800 10
1,188 1,188 40 11
17,197,340 17,197,340 461,770 12
42 42 1 13
-9,961,642 -9,961,642 -426,743 14
FERC FORM NO. 1 (ED. 12-90)Page 311.11
7,094,972
490,410,575
497,505,547
225,497
10,044,750
10,270,247
13,523 11,976,876
-153,554,753
-153,541,230
348,623,719
360,600,595
4,868,381
11,767,897
16,636,278
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 / /2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Netting - Bookouts NANANANA 1
Netting - Trading NANANANA 2
Line Loss Accrual NANANANA 3
Accrual NANANANA 4
5
6
7
8
9
10
11
12
13
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 / /2014/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.
-151,199,671 -151,199,671 -4,273,034 1
-243,458 -243,458 2
148,624 148,624 3
1,418,979 1,418,979 -8,054 4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 311.12
7,094,972
490,410,575
497,505,547
225,497
10,044,750
10,270,247
13,523 11,976,876
-153,554,753
-153,541,230
348,623,719
360,600,595
4,868,381
11,767,897
16,636,278
Schedule Page: 310 Line No.: 6 Column: a
This footnote applies to all occurrences of "Navajo Tribal Util. Auth. (Mexican Hat)" on
pages 310-311. Complete name is Navajo Tribal Utility Authority (Mexican Hat).
Schedule Page: 310 Line No.: 7 Column: a
This footnote applies to all occurrences of "Navajo Tribal Util. Auth. (Red Mesa)" on
pages 310-311. Complete name is Navajo Tribal Utility Authority (Red Mesa).
Schedule Page: 310 Line No.: 10 Column: j
Represents the difference between actual requirement sales revenues for the period as
reflected on the individual line items within this schedule, and the accruals charged to
Account 447, Sales for resale, during the period.
Schedule Page: 310.1 Line No.: 1 Column: j
Reserve share.
Schedule Page: 310.1 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 3 Column: j
Settlement adjustment.
Schedule Page: 310.1 Line No.: 5 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 7 Column: b
Black Hills Power, Inc. - FERC 441 - Contract termination date: December 31, 2023.
Schedule Page: 310.1 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 10 Column: j
Settlement adjustment.
Schedule Page: 310.1 Line No.: 11 Column: b
Bonneville Power Administration - FERC, 5th revised R.S. 368 [Use of Facilities Agreement
for the Malin Transformer under the AC Intertie Agreement with BPA] - Contract termination
date: Upon mutual agreement.
Schedule Page: 310.1 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 12 Column: b
Bonneville Power Administration - FERC T-11 [Network and Point-to-Point Services under the
Open Access Transmission Tariff] - Contracts terminate September 30, 2025 through August
31, 2030.
Schedule Page: 310.1 Line No.: 12 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.2 Line No.: 2 Column: j
Reserve share.
Schedule Page: 310.2 Line No.: 3 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.
Schedule Page: 310.2 Line No.: 3 Column: j
Reserve share.
Schedule Page: 310.2 Line No.: 5 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.: 7 Column: b
Settlement adjustment.
Schedule Page: 310.2 Line No.: 7 Column: j
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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 310.2 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 3 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.: 3 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 4 Column: j
Unauthorized use charges.
Schedule Page: 310.3 Line No.: 5 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 6 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.: 6 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 310.3 Line No.: 12 Column: j
Settlement adjustment.
Schedule Page: 310.3 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 310.3 Line No.: 14 Column: j
Settlement adjustment.
Schedule Page: 310.4 Line No.: 1 Column: j
Reserve share.
Schedule Page: 310.4 Line No.: 2 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.: 2 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 3 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 4 Column: j
Unauthorized use charges.
Schedule Page: 310.4 Line No.: 7 Column: b
Idaho Power Company - FERC T-11 [Point-to-Point Transmission Service under the Open Access
Transmission Tariff (8th revised S.A. 212)] - Contract termination date: May 31, 2019.
Schedule Page: 310.4 Line No.: 7 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 10 Column: j
Reserve share.
Schedule Page: 310.4 Line No.: 12 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 13 Column: j
Unauthorized use charges.
Schedule Page: 310.4 Line No.: 14 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.: 1 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 310.5 Line No.: 3 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 5 Column: a
This footnote applies to all occurrences of "Metro Water Dist. of S. California" on pages
310-311. Complete name is Metropolitan Water District of Southern California.
Schedule Page: 310.5 Line No.: 7 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 10 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 11 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 Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
company.
Schedule Page: 310.5 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 13 Column: b
NextEra Energy Power Marketing, LLC - FERC T-11 [Point-to-Point Transmission Service under
the Open Access Transmission Tariff (2nd revised S.A. 733)] - Contract termination date:
November 17, 2017.
Schedule Page: 310.5 Line No.: 13 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 1 Column: j
Unauthorized use charges.
Schedule Page: 310.6 Line No.: 3 Column: b
Noble Americas Energy Solutions LLC - FERC T-11 [Network Transmission Service under the
Open Access Transmission Tariff (6th Revised Service Agreement 299)]- Contract termination
upon notification pursuant to Oregon Direct Access and Open Access Transmission Tariff.
Schedule Page: 310.6 Line No.: 3 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 5 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 310.6 Line No.: 7 Column: j
Settlement adjustment.
Schedule Page: 310.6 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 10 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 12 Column: j
Pond sales.
Schedule Page: 310.6 Line No.: 13 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 14 Column: b
Powerex Corporation - FERC T-11 [Point-to-Point Transmission Service under the Open Access
Transmission Tariff (8th revised S.A. 169)] - Contract termination date: October 31, 2020.
Schedule Page: 310.6 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.7 Line No.: 1 Column: j
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Transmission losses.
Schedule Page: 310.7 Line No.: 2 Column: j
Pond sales.
Schedule Page: 310.7 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 310.7 Line No.: 3 Column: j
Settlement adjustment.
Schedule Page: 310.7 Line No.: 4 Column: j
Transmission losses.
Schedule Page: 310.7 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: 310.7 Line No.: 8 Column: j
Reserve share.
Schedule Page: 310.7 Line No.: 9 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: 310.7 Line No.: 10 Column: a
This footnote applies to all occurrences of "PUD #1 of Douglas County" on pages 310-311.
Complete name is Public Utility District No. 1 of Douglas County.
Schedule Page: 310.7 Line No.: 11 Column: j
Reserve share.
Schedule Page: 310.7 Line No.: 12 Column: a
This footnote applies to all occurrences of "PUD #1 of Snohomish County" on pages 310-311.
Complete name is Public Utility District No. 1 of Snohomish County.
Schedule Page: 310.7 Line No.: 13 Column: a
This footnote applies to all occurrences of "PUD #2 of Grant County" on pages 310-311.
Complete name is Public Utility District No. 2 of Grant County.
Schedule Page: 310.7 Line No.: 14 Column: j
Reserve share.
Schedule Page: 310.8 Line No.: 1 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 3 Column: j
Reserve share.
Schedule Page: 310.8 Line No.: 4 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 310.8 Line No.: 6 Column: j
Settlement adjustment.
Schedule Page: 310.8 Line No.: 7 Column: b
Sacramento Municipal Utility District - FERC 250 - Contract termination date: December 31,
2014.
Schedule Page: 310.8 Line No.: 8 Column: b
Sacramento Municipal Utility District - FERC T-11 [Point-to-Point Transmission Service
under the Open Access Transmission Tariff (Service Agreement 751)] - Contract termination
date: September 30, 2018.
Schedule Page: 310.8 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 10 Column: b
Salt River Project - FERC T-11 [Point-to-Point Transmission Service under the Open Access
Transmission Tariff (Service Agreement 765)] - Contract termination date: November 30,
2018.
Schedule Page: 310.8 Line No.: 10 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 310.8 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 14 Column: j
Reserve share.
Schedule Page: 310.9 Line No.: 5 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 Berkshire Hathaway Energy Company, PacifiCorp's
indirect parent company.
Schedule Page: 310.9 Line No.: 5 Column: j
Transmission losses.
Schedule Page: 310.9 Line No.: 6 Column: j
Reserve share.
Schedule Page: 310.9 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.9 Line No.: 9 Column: j
Unauthorized use charges.
Schedule Page: 310.9 Line No.: 11 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: 310.9 Line No.: 11 Column: j
Unauthorized use charges.
Schedule Page: 310.9 Line No.: 14 Column: j
Reserve share.
Schedule Page: 310.10 Line No.: 1 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 310.10 Line No.: 4 Column: j
Settlement adjustment.
Schedule Page: 310.10 Line No.: 5 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 7 Column: b
Thermo No. 1 BE-01, LLC - FERC T-11 [Point-to-Point Transmission Service under the Open
Access Transmission Tariff (3rd Revised Service Agreement 568)] - Contract termination
date: April 30, 2029.
Schedule Page: 310.10 Line No.: 7 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 8 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 11 Column: a
This footnote applies to all occurrences of "Tri-State Gen. and Trans." on pages 310-311.
Complete name is Tri-State Generation and Transmission Association, Inc.
Schedule Page: 310.10 Line No.: 11 Column: b
Tri-State Generation and Transmission Association, Inc. - FERC T-11 [Network Transmission
Service under the Open Access Transmission Tariff (3rd Revised Service Agreement 628)] -
Contract termination date: June 30, 2021.
Schedule Page: 310.10 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 12 Column: j
Transmission losses.
Schedule Page: 310.11 Line No.: 2 Column: j
Reserve share.
Schedule Page: 310.11 Line No.: 4 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Transmission losses.
Schedule Page: 310.11 Line No.: 6 Column: b
Utah Municipal Power Agency - FERC 433 - Contract termination date: June 30, 2017.
Schedule Page: 310.11 Line No.: 7 Column: b
Utah Municipal Power Agency - Legacy contract [Transmission Service over agreed upon
facilities (5th Revised Rate Schedule 637)] - Subject to termination upon mutual agreement
and replacement agreements are in effect.
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.: 11 Column: j
Transmission losses.
Schedule Page: 310.11 Line No.: 13 Column: j
Reserve share.
Schedule Page: 310.11 Line No.: 14 Column: j
The negative revenue reported on this line reflects test energy generated at the Lake Side
II power plant that was transferred to construction. Energy generated during testing was
delivered to PacifiCorp’s electric system for sale, as required by the guidance in 18 CFR
Electric Plant Instructions 18(a), is a component of construction and is the fair value of
the energy delivered.
Schedule Page: 310.12 Line No.: 1 Column: j
Reflects transactions that did not physically settle.
Schedule Page: 310.12 Line No.: 2 Column: j
Reflects transactions that did not physically settle.
Schedule Page: 310.12 Line No.: 3 Column: j
Transmission losses.
Schedule Page: 310.12 Line No.: 4 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
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
/ /2014/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 18,091,723 18,509,642
(501) Fuel 5 836,194,561 860,709,193
(502) Steam Expenses 6 43,916,579 43,153,691
(503) Steam from Other Sources 7 4,312,439 4,303,809
(Less) (504) Steam Transferred-Cr. 8
(505) Electric Expenses 9 3,949,096 3,921,304
(506) Miscellaneous Steam Power Expenses 10 55,018,295 41,560,988
(507) Rents 11 496,045 379,252
(509) Allowances 12
TOTAL Operation (Enter Total of Lines 4 thru 12) 13 961,978,738 972,537,879
Maintenance 14
(510) Maintenance Supervision and Engineering 15 7,331,481 6,742,774
(511) Maintenance of Structures 16 29,996,120 28,711,998
(512) Maintenance of Boiler Plant 17 103,206,206 114,942,694
(513) Maintenance of Electric Plant 18 31,091,746 44,711,216
(514) Maintenance of Miscellaneous Steam Plant 19 14,777,438 11,939,661
TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 186,402,991 207,048,343
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 1,148,381,729 1,179,586,222
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 7,551,949 7,346,206
(536) Water for Power 45 197,600 200,374
(537) Hydraulic Expenses 46 4,009,780 4,387,105
(538) Electric Expenses 47
(539) Miscellaneous Hydraulic Power Generation Expenses 48 15,446,587 16,721,432
(540) Rents 49 1,075,124 921,405
TOTAL Operation (Enter Total of Lines 44 thru 49) 50 28,281,040 29,576,522
C. Hydraulic Power Generation (Continued) 51
Maintenance 52
(541) Mainentance Supervision and Engineering 53 506 388
(542) Maintenance of Structures 54 1,156,074 797,907
(543) Maintenance of Reservoirs, Dams, and Waterways 55 2,292,070 1,890,427
(544) Maintenance of Electric Plant 56 2,907,970 1,991,634
(545) Maintenance of Miscellaneous Hydraulic Plant 57 4,284,443 3,739,521
TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 10,641,063 8,419,877
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 38,922,103 37,996,399
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
/ /2014/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 62 448,713 353,767
(547) Fuel 63 321,290,415 396,700,941
(548) Generation Expenses 64 14,406,401 17,772,523
(549) Miscellaneous Other Power Generation Expenses 65 10,582,172 9,084,850
(550) Rents 66 4,649,553 4,187,040
TOTAL Operation (Enter Total of lines 62 thru 66) 67 351,377,254 428,099,121
Maintenance 68
(551) Maintenance Supervision and Engineering 69
(552) Maintenance of Structures 70 3,029,122 2,279,301
(553) Maintenance of Generating and Electric Plant 71 17,613,519 17,425,171
(554) Maintenance of Miscellaneous Other Power Generation Plant 72 3,121,555 2,986,641
TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 23,764,196 22,691,113
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 375,141,450 450,790,234
E. Other Power Supply Expenses 75
(555) Purchased Power 76 666,554,057 603,201,899
(556) System Control and Load Dispatching 77 1,439,706 1,262,603
(557) Other Expenses 78 66,410,600 53,534,340
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 734,404,363 657,998,842
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 2,296,849,645 2,326,371,697
2. TRANSMISSION EXPENSES 81
Operation 82
(560) Operation Supervision and Engineering 83 6,231,709 5,651,643
84
(561.1) Load Dispatch-Reliability 85
(561.2) Load Dispatch-Monitor and Operate Transmission System 86 7,218,959 8,490,351
(561.3) Load Dispatch-Transmission Service and Scheduling 87
(561.4) Scheduling, System Control and Dispatch Services 88 292,567 824,276
(561.5) Reliability, Planning and Standards Development 89 1,114,579 1,111,085
(561.6) Transmission Service Studies 90 89,710 76,025
(561.7) Generation Interconnection Studies 91 861,392 1,139,487
(561.8) Reliability, Planning and Standards Development Services 92 5,545,389
(562) Station Expenses 93 3,029,593 3,333,301
(563) Overhead Lines Expenses 94 353,289 488,475
(564) Underground Lines Expenses 95
(565) Transmission of Electricity by Others 96 137,182,304 151,335,724
(566) Miscellaneous Transmission Expenses 97 4,162,643 4,350,698
(567) Rents 98 2,755,216 1,917,195
TOTAL Operation (Enter Total of lines 83 thru 98) 99 163,291,961 184,263,649
Maintenance 100
(568) Maintenance Supervision and Engineering 101 1,608,159 1,369,666
(569) Maintenance of Structures 102 181,944 -46,352
(569.1) Maintenance of Computer Hardware 103 247,522 111,446
(569.2) Maintenance of Computer Software 104 318,385 448,520
(569.3) Maintenance of Communication Equipment 105 3,584,282 3,573,267
(569.4) Maintenance of Miscellaneous Regional Transmission Plant 106
(570) Maintenance of Station Equipment 107 10,141,753 7,895,835
(571) Maintenance of Overhead Lines 108 18,707,537 15,744,941
(572) Maintenance of Underground Lines 109 72,498 100,695
(573) Maintenance of Miscellaneous Transmission Plant 110 516,090 -1,477,863
TOTAL Maintenance (Total of lines 101 thru 110) 111 35,378,170 27,720,155
TOTAL Transmission Expenses (Total of lines 99 and 111) 112 198,670,131 211,983,804
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
/ /2014/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 13,049,994 9,856,256
(581) Load Dispatching 135 12,422,223 11,105,285
(582) Station Expenses 136 4,264,228 4,646,431
(583) Overhead Line Expenses 137 6,083,986 5,735,189
(584) Underground Line Expenses 138 496 128
(585) Street Lighting and Signal System Expenses 139 202,145 231,729
(586) Meter Expenses 140 7,072,984 7,226,408
(587) Customer Installations Expenses 141 11,097,401 10,081,874
(588) Miscellaneous Expenses 142 4,751,998 5,691,371
(589) Rents 143 3,698,889 2,539,539
TOTAL Operation (Enter Total of lines 134 thru 143) 144 62,644,344 57,114,210
Maintenance 145
(590) Maintenance Supervision and Engineering 146 6,186,943 5,882,500
(591) Maintenance of Structures 147 1,710,762 2,239,835
(592) Maintenance of Station Equipment 148 11,897,335 12,488,442
(593) Maintenance of Overhead Lines 149 89,950,166 95,268,142
(594) Maintenance of Underground Lines 150 21,363,704 21,417,732
(595) Maintenance of Line Transformers 151 1,024,257 872,964
(596) Maintenance of Street Lighting and Signal Systems 152 3,591,531 3,389,842
(597) Maintenance of Meters 153 6,666,726 5,985,723
(598) Maintenance of Miscellaneous Distribution Plant 154 3,403,630 1,977,891
TOTAL Maintenance (Total of lines 146 thru 154) 155 145,795,054 149,523,071
TOTAL Distribution Expenses (Total of lines 144 and 155) 156 208,439,398 206,637,281
5. CUSTOMER ACCOUNTS EXPENSES 157
Operation 158
(901) Supervision 159 2,441,991 2,621,299
(902) Meter Reading Expenses 160 19,662,071 17,785,403
(903) Customer Records and Collection Expenses 161 52,388,395 53,283,660
(904) Uncollectible Accounts 162 12,924,355 11,444,958
(905) Miscellaneous Customer Accounts Expenses 163 117,514 156,938
TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 87,534,326 85,292,258
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
/ /2014/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 167 331,132 150,177
(908) Customer Assistance Expenses 168 112,671,756 132,017,498
(909) Informational and Instructional Expenses 169 3,484,752 3,745,519
(910) Miscellaneous Customer Service and Informational Expenses 170 117,029 99,133
TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 116,604,669 136,012,327
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 76,754,883 75,687,733
(921) Office Supplies and Expenses 182 8,363,743 8,332,848
(Less) (922) Administrative Expenses Transferred-Credit 183 29,238,955 33,980,836
(923) Outside Services Employed 184 16,481,262 14,156,752
(924) Property Insurance 185 13,818,764 15,633,179
(925) Injuries and Damages 186 36,151,606 -23,490,203
(926) Employee Pensions and Benefits 187
(927) Franchise Requirements 188
(928) Regulatory Commission Expenses 189 22,768,237 24,280,590
(929) (Less) Duplicate Charges-Cr. 190 4,347,767 7,469,667
(930.1) General Advertising Expenses 191 1,546 6,832
(930.2) Miscellaneous General Expenses 192 7,526,075 2,426,050
(931) Rents 193 6,318,601 6,140,970
TOTAL Operation (Enter Total of lines 181 thru 193) 194 154,597,995 81,724,248
Maintenance 195
(935) Maintenance of General Plant 196 21,202,085 22,162,699
TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 175,800,080 103,886,947
TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 3,083,898,249 3,070,184,314
FERC FORM NO. 1 (ED. 12-93) Page 323
Schedule Page: 320 Line No.: 102 Column: b
Represents the difference between actual expense for the period and the accruals charged
to Account 569, Maintenance of Structures, during the period.
Schedule Page: 320 Line No.: 110 Column: b
Amount includes reinstatement of a construction work in progress balance for which the
construction was previously expected to be canceled.
Schedule Page: 320 Line No.: 186 Column: b
Amount includes expected insurance recovery related to the Sanpete County, Utah rangeland
fire. Refer to footnote 13, Commitments and Contingencies, in Notes to Financial
Statements of this Form 1.
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, 2014 and 2013, pensions and benefits expense was $126,017,454 and $145,750,552,
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
2014/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 / /2014/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
0.020.020.02Ballard Hog Farms Inc. LU 7
NANANABarclays Bank PLC SF 8
NANANABasin Electric Power Cooperative SF 9
NANANABeaver City Corporation LF 10
NANANABell Mountain Hydro, LLC LU 11
NANANABig Top, LLC LU 12
NANANABiomass One, L.P. LU 13
NANANABirch Power Company, Inc. 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 / /2014/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
6,600 6,600 2 200
3,616,329 3,616,329 3 104,264
6,551,536 354,565 6,906,101 4 161,453
4,134,979 10,088 4,145,067 5 101,514
4,440,340 -180,239 4,260,101 6 102,090
1,637 5,869 7,506 7 150
-610,073 -610,073 8
87,965 87,965 9 2,480
6,157 6,157 10 75
49,807 49,807 11 637
272,136 272,136 12 3,886
13,811,713 1,290,790 15,102,503 13 195,149
794,736 794,736 14 13,210
FERC FORM NO. 1 (ED. 12-90) Page 327
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANABlack Cap Solar, LLC LU 1
NANANABlack Hills Power, Inc. SF 2
NANANABonneville Power Administration AD 3
NANANABonneville Power Administration LF 4
NANANABonneville Power Administration OS 5
NANANABonneville Power Administration SF 6
0.721.1Box Canyon Limited Partnership LU 7
NANANABrookfield Energy Marketing L.P. SF 8
NANANAButter Creek Power, LLC LU 9
NANANAC Drop Hydro, LLC LU 10
NANANACDM Hydroelectric Company LU 11
NANANACalifornia Independent System Operator AD 12
NANANACalifornia Independent System Operator SF 13
NANANACalpine Energy Services, L.P. SF 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 / /2014/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.
20,797 20,797 1 597
85,604 85,604 2 1,550
1 1 3
35,240 35,240 4
25,331 25,331 5
8,930,656 77,970 9,008,626 6 265,415
103,609 1,033,288 1,136,897 7 8,188
382,200 382,200 8 4,800
919,315 919,315 9 13,236
153,658 153,658 10 2,152
1,925,673 1,925,673 11 32,046
22,623 22,623 12 -776
6,327,022 6,327,022 13 195,865
4,647,519 4,647,519 14 94,919
FERC FORM NO. 1 (ED. 12-90) Page 327.1
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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.
NANANACameron A. Curtiss LU 1
NANANACargill Power Markets, LLC AD 2
NANANACargill Power Markets, LLC SF 3
NANANACargill, Incorporated LU 4
2.94.33.5Central Oregon Irrigation District LU 5
NANANAChevron U.S.A. Inc. LU 6
NANANACity of Albany LU 7
NANANACity of Burbank SF 8
NANANACity of Glendale SF 9
NANANACity of Hurricane LF 10
NANANACity of Lehi AD 11
NANANACity of Lehi IF 12
NANANACity of Pasadena SF 13
NANANACity of Portland, Water Bureau LU 14
FERC FORM NO. 1 (ED. 12-90)Page 326.2
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
3,157 3,157 1 44
-43 -43 2
14,243,799 738,032 14,981,831 3 378,414
539,531 539,531 4 7,688
577,297 3,754,003 4,331,300 5 39,535
2,655,660 2,655,660 6 42,376
75,641 75,641 7 1,063
855,096 855,096 8 11,472
4,125 4,125 9 165
125,307 125,307 10 1,928
2,056 2,056 11 21
761 761 12 7
4,770 4,770 13 188
9,086 9,086 14 127
FERC FORM NO. 1 (ED. 12-90) Page 327.2
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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 Preston Idaho LU 1
NANANAClatskanie People's Utility District SF 2
NANANACommercial Energy Management Inc. LU 3
NANANAConocoPhillips Company OS 4
NANANAConocoPhillips Company SF 5
NANANACottonwood Hydro, LLC IU 6
NANANACrook County Solar 1, LLC RQ 7
3.24.24.7Deschutes Valley Water District LU 8
95100100Deseret Generation & Transmission Coop LF 9
NANANADorena Hydro, LLC LU 10
0.30.50.4Douglas County LU 11
NANANADouglas County, Inc. AD 12
NANANADouglas County, Inc. LU 13
NANANADraper Irrigation Company IU 14
FERC FORM NO. 1 (ED. 12-90)Page 326.3
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2014/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.
152,140 152,140 1 2,741
15,666 15,666 2 547
71,775 71,775 3 1,303
13,948 13,948 4
124,400 124,400 5 2,400
236,172 236,172 6 3,596
37,928 37,928 7 1,096
460,721 3,214,281 3,675,002 8 26,920
15,870,020 14,119,817 4,136,234 34,126,071 9 697,852
38,407 38,407 10 538
39,727 362,649 402,376 11 2,708
10,562 10,562 12 267
100,949 100,949 13 3,053
426 426 14 9
FERC FORM NO. 1 (ED. 12-90) Page 327.3
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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.
NANANADry Creek LLC LU 1
NANANAEDF Trading North America, LLC SF 2
NANANAeBay Inc. LU 3
NANANAEl Paso Electric Company SF 4
NANANAEugene Water & Electric Board OS 5
NANANAEugene Water & Electric Board SF 6
NANANAEurus Combine Hills I, LLC LU 7
NANANAEvergreen BioPower, LLC LU 8
NANANAExelon Generation Company, LLC IF 9
NANANAExelon Generation Company, LLC SF 10
1.43.53.5Falls Creek H.P. Limited Partnership LU 11
NANANAFarm Power Misty Meadow, LLC LU 12
NANANAFarmers Irrigation District LU 13
NANANAFillmore City Corporation LF 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 / /2014/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.
425,150 425,150 1 7,719
15,752,755 15,752,755 2 407,936
42,614 42,614 3 795
250,955 17,027 267,982 4 6,963
-819,190 -819,190 5
283,693 283,693 6 8,432
4,554,379 4,554,379 7 107,568
3,616,903 3,616,903 8 54,926
5,791,248 5,791,248 9 122,811
19,225,879 19,225,879 10 497,720
223,600 2,023,021 2,246,621 11 16,830
264,317 264,317 12 3,674
1,601,266 1,601,266 13 22,998
19,680 19,680 14 182
FERC FORM NO. 1 (ED. 12-90) Page 327.4
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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.
NANANAFinley BioEnergy, LLC LU 1
NANANAFlathead Electric Cooperative, Inc. LF 2
NANANAFoote Creek II, LLC LU 3
NANANAFoote Creek III, LLC LU 4
NANANAFour Corners Windfarm, LLC LU 5
NANANAFour Mile Canyon Windfarm, LLC LU 6
0.60.80.6George DeRuyter & Sons Dairy LU 7
NANANAGeorgetown Irrigation Company LU 8
NANANAGila River Power LLC SF 9
NANANAGrand Valley Power LF 10
NANANAGridforce Energy Management SF 11
NANANAHarold Foster & Robert Walker LU 12
NANANAHermiston Generating Company, L.P. AD 13
169211211Hermiston Generating Company, L.P. 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 / /2014/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.
2,410,770 2,410,770 1 33,886
14,013 14,013 2 447
52,009 52,009 3 2,991
652,259 652,259 4 32,679
2,015,952 2,015,952 5 29,057
1,774,767 1,774,767 6 25,406
19,467 170,680 190,147 7 5,010
111,933 111,933 8 1,899
3,879,043 3,879,043 9 71,931
12,453 12,453 10 62
2,038 2,038 11 41
33,852 33,852 12 877
206 206 13
36,916,842 49,889,760 329,240 87,135,842 14 1,162,637
FERC FORM NO. 1 (ED. 12-90) Page 327.5
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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.
NANANAIberdrola Renewables, LLC SF 1
NANANAIdaho Falls, City of AD 2
NANANAIdaho Falls, City of LU 3
NANANAIdaho Power Company SF 4
NANANAIntermountain Power Agency LU 5
NANANAJ Bar 9 Ranch, Inc. LU 6
NANANAJake Amy LU 7
NANANAJoseph Community Solar LLC LU 8
NANANAKennecott Utah Copper LLC LU 9
NANANALacomb Irrigation District LU 10
NANANALos Angeles Dept. of Water & Power SF 11
NANANALower Valley Energy, Inc. IU 12
NANANALower Valley Energy, Inc. LU 13
NANANALoyd Fery 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 / /2014/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.
43,908,209 1,171,916 45,080,125 1 1,315,878
-62,539 -62,539 2
3,030,682 3,030,682 3 52,354
866,793 2,217 869,010 4 23,492
26,706,775 26,706,775 5 542,628
3,888 3,888 6 66
66,956 66,956 7 1,200
25,106 25,106 8 740
2,537,238 2,537,238 9 78,586
160,444 37,919 198,363 10 4,496
1,025,020 12,749 1,037,769 11 18,470
351,411 351,411 12 5,939
94,261 94,261 13 1,529
11,615 11,615 14 330
FERC FORM NO. 1 (ED. 12-90) Page 327.6
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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.
NANANAMacquarie Energy LLC SF 1
NANANAMarsh Valley Hydro Electric Company AD 2
NANANAMarsh Valley Hydro Electric Company LU 3
NANANAMeadow Creek Project Company LLC LU 4
NANANAMetropolitan Water District of S. CA SF 5
NANANAMiddle Fork Irrigation District LU 6
NANANAMink Creek Hydro LLC LU 7
NANANAMonsanto Company IU 8
NANANAMorgan City Corporation LF 9
NANANAMorgan Stanley Capital Group Inc. AD 10
NANANAMorgan Stanley Capital Group Inc. SF 11
NANANAMountain Energy, Inc. LU 12
NANANAMountain Wind Power II, LLC LU 13
NANANAMountain Wind Power, LLC LU 14
FERC FORM NO. 1 (ED. 12-90)Page 326.7
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2014/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
3,843,146 3,843,146 1 86,096
7,254 7,254 2 122
219,983 219,983 3 3,661
23,774,146 23,774,146 4 375,128
7,400 7,400 5 200
1,728,532 1,728,532 6 26,290
449,887 449,887 7 7,758
20,003,760 20,003,760 8
1,236 1,236 9 15
1,853 1,853 10 -33
13,120,000 13,120,000 11 283,273
4,339 4,339 12 61
16,309,431 16,309,431 13 255,545
10,583,909 10,583,909 14 191,634
FERC FORM NO. 1 (ED. 12-90) Page 327.7
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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.
NANANAMunicipal Energy Agency of Nebraska SF 1
NANANANaturEner Power Watch, LLC SF 2
NANANANevada Power Company AD 3
NANANANevada Power Company SF 4
NANANANextEra Energy Power Marketing, LLC SF 5
0.40.50.8Nichols Gap Limited Partnership LU 6
NANANANicholson's Sunny Bar Ranch IF 7
NANANANorthWestern Corporation SF 8
NANANANucor Corporation IF 9
NANANAO.J. Power Company LU 10
NANANAObsidian Renewables, LLC LU 11
NANANAOneEnergy, Inc. OS 12
NANANAOregon Environmental Industries, LLC LU 13
NANANAOregon Institute of Technology LU 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 / /2014/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.
33,655 33,655 1 655
100 100 2 4
-152,075 -152,075 3
2,114,476 39,395 2,153,871 4 41,753
18,433 18,433 5 560
42,062 384,325 426,387 6 3,049
77,036 77,036 7 1,300
18,815 9,219 28,034 8 990
6,055,400 6,055,400 9
13,765 13,765 10 289
30,084 30,084 11 865
40,515 40,515 12
1,463,702 1,463,702 13 22,322
2,126 2,126 14 95
FERC FORM NO. 1 (ED. 12-90) Page 327.8
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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.
NANANAOregon State University LU 1
NANANAOregon Trail Windfarm, LLC LU 2
NANANAPPL EnergyPlus, LLC SF 3
NANANAPacific Canyon Windfarm, LLC LU 4
NANANAPaul Luckey LU 5
NANANAPlatte River Power Authority SF 6
NANANAPortland General Electric Company AD 7
NANANAPortland General Electric Company LF 8
NANANAPortland General Electric Company SF 9
NANANAPower County Wind Park North, LLC LU 10
NANANAPower County Wind Park South, LLC LU 11
NANANAPowerex Corporation OS 12
NANANAPowerex Corporation SF 13
NANANAProvo City Corporation LF 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 / /2014/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.
53 53 1 1
1,805,149 1,805,149 2 25,949
1,611,829 1,611,829 3 41,780
1,337,876 1,337,876 4 19,108
8,700 8,700 5 245
108,809 108,809 6 2,843
-84,958 -84,958 7
307,000 307,000 8 12,024
2,213,795 12,083 2,225,878 9 58,015
4,329,172 4,329,172 10 72,267
4,046,252 4,046,252 11 65,970
3,250 3,250 12 50
33,061,386 33,061,386 13 638,320
3,357 3,357 14 35
FERC FORM NO. 1 (ED. 12-90) Page 327.9
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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 SF 1
NANANAPublic Service Company of New Mexico SF 2
NANANAPUD No. 1 of Chelan County SF 3
NANANAPUD No. 1 of Clark County SF 4
NANANAPUD No. 1 of Cowlitz County OS 5
NANANAPUD No. 1 of Douglas County AD 6
NANANAPUD No. 1 of Douglas County AD 7
NANANAPUD No. 1 of Douglas County LF 8
NANANAPUD No. 1 of Douglas County LU 9
NANANAPUD No. 1 of Douglas County OS 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 326.10
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 / /2014/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.
70,576 70,576 1 1,932
2,183,324 12,695 2,196,019 2 61,760
201,100 4,595 205,695 3 5,334
266,982 266,982 4 8,334
479,694 479,694 5
528 528 6
-92,951 -92,951 7
2,144,732 2,144,732 8 73,291
3,401,377 3,401,377 9 239,142
34,723 34,723 10
309,430 1,086 310,516 11 7,943
741,030 741,030 12 22,750
-24,689 -24,689 13
-8,143,703 -8,143,703 14 84,664
FERC FORM NO. 1 (ED. 12-90) Page 327.10
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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 SF 4
NANANARiverside, City of SF 5
NANANARock River 1, LLC LU 6
NANANARoseburg Forest Products Company LU 7
NANANARoseburg LFG Energy, LLC LU 8
NANANARoush Hydro Inc. LU 9
NANANASacramento Municipal Utility District AD 10
NANANASacramento Municipal Utility District LF 11
NANANASacramento Municipal Utility District SF 12
NANANASalt River Project SF 13
NANANASand Ranch Windfarm, LLC LU 14
FERC FORM NO. 1 (ED. 12-90)Page 326.11
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2014/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.
993,848 4,962 998,810 1 30,707
4,199,324 14,482 4,213,806 2 109,668
35,452 35,452 3 475
1,018,021 1,018,021 4 29,020
5,920 5,920 5 680
5,528,938 5,528,938 6 155,833
4,229,402 4,229,402 7 80,306
756,057 756,057 8 10,604
7,263 7,263 9 205
182,445 182,445 10
4,454,236 4,454,236 11 218,989
102,600 102,600 12 2,400
4,598,172 93,178 4,691,350 13 99,049
1,737,748 1,737,748 14 24,872
FERC FORM NO. 1 (ED. 12-90) Page 327.11
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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.
0.20.20.2Santiam Water Control District LU 1
NANANASeattle City Light SF 2
NANANASempra Generation, LLC SF 3
NANANAShell Energy North America (US), L.P. SF 4
NANANAShiloh Warm Springs Ranch, LLC LU 5
1.21.32.4Shoshone Irrigation District LU 6
NANANASierra Pacific Power Company AD 7
NANANASierra Pacific Power Company SF 8
NANANASierra Pacific Power Company SF 9
0.51.32.1Slate Creek Hydro Company, Inc. LU 10
NANANASolwatt LLC LU 11
NANANASouth Utah Valley Electric LF 12
NANANASouthern California Edison Company AD 13
NANANASouthern California Edison Company SF 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 / /2014/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.
13,632 166,240 179,872 1 1,561
2,406,922 6,198 2,413,120 2 63,484
15,716,619 15,716,619 3 464,282
7,137,007 64,256 7,201,263 4 197,975
52,859 52,859 5 879
187,507 419,875 607,382 6 9,285
-45,156 -45,156 7
8,789 8,789 8 305
11,426 4,285 15,711 9 392
69,023 503,199 572,222 10 4,427
23,202 23,202 11 665
3,102 3,102 12 44
350 350 13 14
158,030 158,030 14 6,212
FERC FORM NO. 1 (ED. 12-90) Page 327.12
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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.
NANANASpanish Fork Wind Park 2, LLC LU 1
0.20.60.6Sprague Hydro LLC LU 2
NANANASt. Anthony Hydro, LLC LU 3
NANANAStahlbush Island Farms, Inc. IU 4
NANANASunnyside Cogeneration Associates AD 5
475352Sunnyside Cogeneration Associates LU 6
NANANASwalley Irrigation District LU 7
NANANATMF Biofuels, LLC LU 8
NANANATacoma Power SF 9
NANANATata Chemicals (Soda Ash) Partners AD 10
NANANATata Chemicals (Soda Ash) Partners LU 11
NANANATenaska Power Services Co. SF 12
NANANATesoro Refining & Marketing Co, LLC LU 13
NANANAThayn Hydro LLC AD 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 / /2014/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.
2,542,259 2,542,259 1 47,368
50,567 351,448 402,015 2 2,812
37,577 37,577 3 932
171,209 171,209 4 2,870
20,385 20,385 5
10,803,672 17,043,240 27,846,912 6 419,649
167,423 167,423 7 2,351
2,286,547 2,286,547 8 34,040
2,063,969 2,991 2,066,960 9 65,541
44,461 44,461 10 2,984
89,418 89,418 11 3,246
281,573 281,573 12 6,490
1,262,102 1,262,102 13 36,819
-25,875 -25,875 14
FERC FORM NO. 1 (ED. 12-90)Page 327.13
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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.
0.40.40.4Thayn Hydro LLC LU 1
NANANAThe Confederated Tribe of Warm Springs LU 2
NANANAThe Energy Authority, Inc. SF 3
0.20.20.2The Town of the City of Buffalo LU 4
NANANAThree Buttes Windpower, LLC LU 5
NANANAThree Sisters Irrigation District LU 6
NANANAThreemile Canyon Wind I, LLC AD 7
NANANAThreemile Canyon Wind I, LLC LU 8
NANANATop of The World Wind Energy LLC LU 9
NANANATransAlta Energy Marketing (U.S.) Inc. SF 10
NANANATransCanada Energy Sales Ltd. SF 11
182425Tri-State Generation and Transmission LF 12
NANANATri-State Generation and Transmission SF 13
NANANATuana Springs Energy, LLC 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 / /2014/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.
100,394 264,962 365,356 1 3,103
7,680 7,680 2 218
2,425,630 2,425,630 3 70,606
37,020 204,399 241,419 4 1,882
21,141,685 21,141,685 5 331,586
32,703 32,703 6 902
-24,298 -24,298 7 -363
1,639,809 1,639,809 8 23,075
42,305,091 42,305,091 9 640,986
20,401,577 20,401,577 10 486,651
13,200 13,200 11 400
6,117,000 3,409,198 9,526,198 12 112,850
141,159 62,072 203,231 13 5,560
-77,340 -77,340 14
FERC FORM NO. 1 (ED. 12-90)Page 327.14
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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
NANANATurlock Irrigation District SF 3
NANANAU.S. Dept of the Interior LU 4
NANANAUNS Electric, Inc. SF 5
NANANAUS Magnesium LLC LF 6
NANANAUnited States Air Force at Hill Base LU 7
NANANAVitol Inc. SF 8
NANANAWagon Trail, LLC LU 9
NANANAWard Butte Windfarm, LLC LU 10
NANANAWasatch Integrated Waste Mgmt District 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 326.15
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 / /2014/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.
327,969 327,969 1
611,013 183,656 794,669 2 19,077
1,600 1,600 3 50
966 966 4 16
166,791 166,791 5 3,371
6,367,389 6,367,389 6
673,718 673,718 7 13,945
1,099,800 1,099,800 8 21,600
525,515 525,515 9 7,518
1,228,590 1,228,590 10 17,696
20,758 20,758 11 361
195,608 195,608 12 3,963
1,528,501 1,528,501 13 35,277
49,098 197 49,295 14 2,360
FERC FORM NO. 1 (ED. 12-90) Page 327.15
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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
11.41.5Yakima-Tieton Irrigation District LU 3
NANANAOregon Solar Incentive LU 4
NANANASettlements/Reserves 5
NANANANetting-Trading 6
NANANANetting-Bookouts 7
NANANACA Greenhouse Gas Allowance Purchases 8
NANANANet Power Cost Deferrals 9
NANANAAccrual 10
11
Power Exchanges: 12
NANANAArizona Public Service Company 307EX 13
NANANAAvista Corporation T-13EX 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 / /2014/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.
722,035 722,035 1 16,971
10,544,211 10,544,211 2 183,793
23,970 274,566 298,536 3 7,881
290,386 290,386 4 8,531
2,273,073 2,273,073 5
-243,458 -243,458 6
-151,199,670 -151,199,670 7 -4,272,938
884,031 884,031 8
20,321,005 20,321,005 9
7,266,834 7,266,834 10
11
12
571,431 566,750 -203,000 -203,000 13
2,005 14
FERC FORM NO. 1 (ED. 12-90)Page 327.16
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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 237AD 2
NANANABonneville Power Administration T-12AD 3
NANANABonneville Power Administration 237EX 4
NANANABonneville Power Administration 368EX 5
NANANABonneville Power Administration 519EX 6
NANANABonneville Power Administration T-13EX 7
NANANABonneville Power Administration T-11EX 8
NANANABonneville Power Administration T-12EX 9
NANANACalifornia Independent System Operator T-11EX 10
NANANACalifornia Independent System Operator T-12EX 11
NANANACargill Power Markets, LLC T-11EX 12
NANANACity of Redding 364EX 13
NANANAConstellation Energy Commodities Group T-11EX 14
FERC FORM NO. 1 (ED. 12-90)Page 326.17
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2014/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.
61 8,533 290,845 290,845 1
61,870 154,676 154,676 2
-253 4,297 4,297 3
82,666 -206,666 -206,666 4
50,000 53,125 76,938 76,938 5
111,622 108,456 -37,304 -37,304 6
9,788 235,092 7
6,704 9,141 78,690 78,690 8
15,157 500,537 500,537 9
-4,526,444 -4,526,444 10
180,898 28,078 -1,359,495 -1,359,495 11
857 356 -3,058 -3,058 12
109,431 114,230 235,898 235,898 13
3,512 3,329 -7,769 -7,769 14
FERC FORM NO. 1 (ED. 12-90)Page 327.17
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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.
NANANADeseret Generation & Transmission Coop 280AD 1
NANANADeseret Generation & Transmission Coop 280EX 2
NANANAEmerald People's Utility District 351EX 3
NANANAEugene Water & Electric Board T-12EX 4
NANANAIberdrola Renewables, LLC T-11EX 5
NANANAIdaho Power Company 380EX 6
NANANAIdaho Power Company T-11EX 7
NANANAJ.P. Morgan Ventures Energy Corp T-11EX 8
NANANALos Angeles Dept. of Water & Power OV-1EX 9
NANANAMacquarie Energy LLC T-11EX 10
NANANAMilford Wind Corridor Phase I, LLC OV-1EX 11
NANANAMilford Wind Corridor Phase II, LLC OV-1EX 12
NANANAMorgan Stanley Capital Group Inc. T-11EX 13
NANANANevada Power Company T-11EX 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 / /2014/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.
-898 4,227 238,835 238,835 1
51,984 61,610 8,538 8,538 2
674 -16,854 -16,854 3
19,752 19,384 -14,308 -14,308 4
18,744 12,069 -217,427 -217,427 5
220,923 365,057 6
2,552 2,354 45 45 7
22,206 63,027 1,048,764 1,048,764 8
4,311 282,127 282,127 9
-16 10
2,698 -203,249 -203,249 11
1,613 -120,398 -120,398 12
34,635 35,578 -12,601 -12,601 13
1,015 1,015 -189 -189 14
FERC FORM NO. 1 (ED. 12-90)Page 327.18
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANANextEra Energy Power Marketing, LLC T-11EX 1
NANANANoble Americas Energy Solutions LLC T-11EX 2
NANANANorthWestern Corporation 160EX 3
NANANAPPL EnergyPlus, LLC T-11EX 4
NANANAPortland General Electric Company T-13EX 5
NANANAPortland General Electric Company T-11EX 6
NANANAPowerex Corporation T-11EX 7
NANANAPublic Service Company of Colorado T-12AD 8
NANANAPublic Service Company of Colorado 319EX 9
NANANAPublic Service Company of Colorado 334EX 10
NANANAPublic Service Company of Colorado T-12EX 11
NANANAPUD No. 1 of Cowlitz County 554EX 12
NANANASacramento Municipal Utility District T-11EX 13
NANANASeattle City Light 554EX 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 / /2014/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.
62,948 89,266 801,344 801,344 1
3,619 8,142 132,689 132,689 2
2,075 3
11,004 11,004 24 24 4
156,494 157,676 5
470 468 302 302 6
25,840 23,073 27,720 27,720 7
-1 -55 -55 8
3,100 9
1,310,382 1,313,875 5,400,000 5,400,000 10
68,821 48,845 -649,641 -649,641 11
253,349 236,756 12
90 367 13
357,724 357,430 -478,383 -478,383 14
FERC FORM NO. 1 (ED. 12-90)Page 327.19
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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.
NANANAShell Energy North America (US), L.P. T-11EX 1
NANANASouthern California Edison Company T-11AD 2
NANANASouthern California Edison Company T-11EX 3
NANANASouthern CA Public Power Authority T-11EX 4
NANANAThe Energy Authority, Inc. T-11EX 5
NANANAThermo No. 1 BE-01, LLC T-11EX 6
NANANATransAlta Energy Marketing (U.S.) Inc. T-11EX 7
NANANATri-State Generation and Transmission 319AD 8
NANANATri-State Generation and Transmission 319EX 9
NANANATri-State Generation and Transmission T-11EX 10
NANANAUtah Associated Municipal Power T-11AD 11
NANANAUtah Associated Municipal Power T-11EX 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 / /2014/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.
513 334 -3,995 -3,995 1
107 -68 -7,007 -7,007 2
77,320 86,504 262,366 262,366 3
2,594 1,427 -39,522 -39,522 4
477 522 1,727 1,727 5
2,024 1,860 -13,509 -13,509 6
7,644 6,282 7,922 7,922 7
34,882 34,882 8
3,100 31,220 31,220 9
4,288 5,034 14,429 14,429 10
-2,355 3,224 180,013 180,013 11
86,471 152,033 2,190,683 2,190,683 12
9,007 33,758 747,327 747,327 13
1,367 10,057 296,682 296,682 14
FERC FORM NO. 1 (ED. 12-90)Page 327.20
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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 / /2014/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
NANANAWestern Area Power Administration OATTEX 3
NANANAImbalance Energy Accrual T-11EX 4
NANANASystem Deviation NA 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 / /2014/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.
2,783 84 -87,525 -87,525 1
22,284 94 -713,650 -713,650 2
55 3
632,983 632,983 4
5 18,257
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 327.21
9,846,352 4,330,806 3,968,188 71,657,767 605,511,668 -73,967,536 603,201,899
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: l
Financial swap.
Schedule Page: 326 Line No.: 10 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326 Line No.: 13 Column: l
Non-generation agreement.
Schedule Page: 326.1 Line No.: 1 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.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.1 Line No.: 3 Column: l
Reserve share.
Schedule Page: 326.1 Line No.: 4 Column: b
Bonneville Power Administration - contract termination date: 30 days written notice.
Schedule Page: 326.1 Line No.: 4 Column: l
Ancillary services.
Schedule Page: 326.1 Line No.: 5 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.1 Line No.: 5 Column: l
Imbalance energy.
Schedule Page: 326.1 Line No.: 6 Column: l
Reserve share.
Schedule Page: 326.1 Line No.: 12 Column: a
This footnote applies to all occurrences of "California Independent System Operator" on
pages 326-327. Complete name is California Independent System Operator Corporation.
Schedule Page: 326.1 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.1 Line No.: 12 Column: l
Settlement adjustment.
Schedule Page: 326.2 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 326.2 Line No.: 2 Column: l
Settlement adjustment.
Schedule Page: 326.2 Line No.: 3 Column: l
Financial swap.
Schedule Page: 326.2 Line No.: 10 Column: b
City of Hurricane - contract termination date: August 31, 2017.
Schedule Page: 326.2 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 326.2 Line No.: 11 Column: l
Settlement adjustment.
Schedule Page: 326.2 Line No.: 14 Column: a
This footnote applies to all occurrences of "City of Portland, Water Bureau" 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
326-327. Complete name is City of Portland, Portland Water Bureau.
Schedule Page: 326.3 Line No.: 4 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.3 Line No.: 4 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio standard
requirements.
Schedule Page: 326.3 Line No.: 9 Column: a
This footnote applies to all occurrences of "Deseret Generation & Transmission Coop" on
pages 326-327. Complete name is Deseret Generation and Transmission Co-operative.
Schedule Page: 326.3 Line No.: 9 Column: b
Deseret Generation and Transmission Co-operative - contract termination date: September
30, 2024.
Schedule Page: 326.3 Line No.: 9 Column: l
Reimbursement to counterparty for operation and maintenance costs at coal fired generating
facility located in Vernal, Utah.
Schedule Page: 326.3 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.3 Line No.: 12 Column: l
Settlement adjustment.
Schedule Page: 326.4 Line No.: 4 Column: l
Line loss.
Schedule Page: 326.4 Line No.: 5 Column: b
Settlement for costs of replacement power resulting from wind turbine failure.
Schedule Page: 326.4 Line No.: 14 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.5 Line No.: 2 Column: b
Flathead Electric Cooperative, Inc. - contract termination date: September 30, 2016.
Schedule Page: 326.5 Line No.: 2 Column: l
Line loss.
Schedule Page: 326.5 Line No.: 10 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.5 Line No.: 11 Column: l
Reserve share.
Schedule Page: 326.5 Line No.: 13 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: 326.5 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.5 Line No.: 13 Column: l
Settlement adjustment.
Schedule Page: 326.5 Line No.: 14 Column: l
On peak incentive, supplemental dispatch efficiency expense, start-up charges and
committee settlements.
Schedule Page: 326.6 Line No.: 1 Column: l
Financial swap.
Schedule Page: 326.6 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 326.6 Line No.: 2 Column: l
Labor, equipment and administration fees associated with hydro project in Idaho Falls,
Idaho.
Schedule Page: 326.6 Line No.: 3 Column: l
Labor, equipment and administration fees associated with hydro project in Idaho Falls,
Idaho.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 326.6 Line No.: 4 Column: l
Reserve share.
Schedule Page: 326.6 Line No.: 10 Column: l
Fixed annual payment.
Schedule Page: 326.6 Line No.: 11 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: 326.6 Line No.: 11 Column: l
Line loss.
Schedule Page: 326.7 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 326.7 Line No.: 2 Column: l
Settlement adjustment.
Schedule Page: 326.7 Line No.: 5 Column: a
This footnote applies to all occurrences of "Metropolitan Water District of S. CA" on
pages 326-327. Complete name is Metropolitan Water District of Southern California.
Schedule Page: 326.7 Line No.: 8 Column: l
Compensation for interruptible service and operating reserves.
Schedule Page: 326.7 Line No.: 9 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.7 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.7 Line No.: 10 Column: l
Settlement adjustment.
Schedule Page: 326.8 Line No.: 2 Column: l
Reserve share.
Schedule Page: 326.8 Line No.: 3 Column: a
This footnote applies to all occurrences of "Nevada Power Company" on pages 326-327.
Nevada Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect
wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
company.
Schedule Page: 326.8 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.8 Line No.: 3 Column: l
Line loss.
Schedule Page: 326.8 Line No.: 4 Column: l
Line loss.
Schedule Page: 326.8 Line No.: 8 Column: l
Reserve share.
Schedule Page: 326.8 Line No.: 9 Column: l
Ancillary services.
Schedule Page: 326.8 Line No.: 12 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.8 Line No.: 12 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio standard
requirements.
Schedule Page: 326.9 Line No.: 6 Column: l
Line loss.
Schedule Page: 326.9 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.9 Line No.: 7 Column: l
Operation expense plus amortization of unrecovered costs of Cove Project.
Schedule Page: 326.9 Line No.: 8 Column: b
Portland General Electric Company - contract termination date: terminates when the Round
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Butte project is no longer operating for power production purposes.
Schedule Page: 326.9 Line No.: 8 Column: l
Operation expense plus amortization of unrecovered costs of Cove Project.
Schedule Page: 326.9 Line No.: 9 Column: l
Reserve share.
Schedule Page: 326.9 Line No.: 12 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.9 Line No.: 14 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.10 Line No.: 2 Column: l
Line loss.
Schedule Page: 326.10 Line No.: 3 Column: a
This footnote applies to all occurrences of "PUD No. 1 of Chelan County" on pages 326-327.
Complete name is Public Utility District No. 1 of Chelan County.
Schedule Page: 326.10 Line No.: 3 Column: l
Reserve share.
Schedule Page: 326.10 Line No.: 4 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: 326.10 Line No.: 5 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: 326.10 Line No.: 5 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.10 Line No.: 5 Column: l
Liability associated with paper pond at hydro facility located on the Lewis River in the
state of Washington.
Schedule Page: 326.10 Line No.: 6 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: 326.10 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.10 Line No.: 6 Column: l
Settlement adjustment.
Schedule Page: 326.10 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.10 Line No.: 7 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.10 Line No.: 8 Column: b
Public Utility District No. 1 of Douglas County - contract termination date: August 31,
2018.
Schedule Page: 326.10 Line No.: 9 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.10 Line No.: 10 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.10 Line No.: 10 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio standard
requirements.
Schedule Page: 326.10 Line No.: 11 Column: l
Reserve share.
Schedule Page: 326.10 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: 326.10 Line No.: 13 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
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: 326.10 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.10 Line No.: 13 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.10 Line No.: 14 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.11 Line No.: 1 Column: l
Reserve share.
Schedule Page: 326.11 Line No.: 2 Column: l
Reserve share.
Schedule Page: 326.11 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.11 Line No.: 10 Column: l
Settlement adjustment.
Schedule Page: 326.11 Line No.: 11 Column: b
Sacramento Municipal Utility District - contract termination date: December 31, 2014.
Schedule Page: 326.11 Line No.: 13 Column: l
Line loss.
Schedule Page: 326.12 Line No.: 2 Column: l
Reserve share.
Schedule Page: 326.12 Line No.: 4 Column: l
Financial swap.
Schedule Page: 326.12 Line No.: 7 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 Berkshire Hathaway Energy Company, PacifiCorp's
indirect parent company.
Schedule Page: 326.12 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.12 Line No.: 7 Column: l
Line loss.
Schedule Page: 326.12 Line No.: 8 Column: l
Line loss.
Schedule Page: 326.12 Line No.: 9 Column: l
Reserve share.
Schedule Page: 326.12 Line No.: 12 Column: a
This footnote applies to all occurrences of "South Utah Valley Electric" on pages 326-327.
Complete company name is South Utah Valley Electric Service District.
Schedule Page: 326.12 Line No.: 12 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.12 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.12 Line No.: 13 Column: l
Settlement adjustment.
Schedule Page: 326.13 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 326.13 Line No.: 5 Column: l
Settlement adjustment.
Schedule Page: 326.13 Line No.: 9 Column: l
Reserve share.
Schedule Page: 326.13 Line No.: 10 Column: b
Settlement adjustment.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Schedule Page: 326.13 Line No.: 10 Column: l
Settlement adjustment.
Schedule Page: 326.13 Line No.: 13 Column: a
This footnote applies to all occurrences of "Tesoro Refining & Marketing Co, LLC" on pages
326-327. Complete name is Tesoro Refining & Marketing Company, LLC.
Schedule Page: 326.13 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.13 Line No.: 14 Column: l
Settlement adjustment.
Schedule Page: 326.14 Line No.: 2 Column: a
This footnote applies to all occurrences of "The Confederated Tribe of Warm Springs" on
pages 326-327. Complete name is The Confederated Tribe of Warm Springs Utilities.
Schedule Page: 326.14 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.14 Line No.: 7 Column: l
Settlement adjustment.
Schedule Page: 326.14 Line No.: 12 Column: a
This footnote applies to all occurrences of "Tri-State Generation and Transmission" on
pages 326-327. Complete name is Tri-State Generation and Transmission Association, Inc.
Schedule Page: 326.14 Line No.: 12 Column: b
Tri-State Generation and Transmission Association, Inc. - contract termination date:
December 31, 2020.
Schedule Page: 326.14 Line No.: 13 Column: l
Line loss.
Schedule Page: 326.14 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.14 Line No.: 14 Column: l
Purchase of renewable energy credit certificates for Washington renewable portfolio
standard requirements.
Schedule Page: 326.15 Line No.: 1 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.15 Line No.: 1 Column: l
Purchase of renewable energy credit certificates for Washington renewable portfolio
standard requirements.
Schedule Page: 326.15 Line No.: 2 Column: l
Line loss.
Schedule Page: 326.15 Line No.: 4 Column: a
This footnote applies to all occurrences of "U.S. Dept of the Interior" on pages 326-327.
Complete name is U.S. Department of the Interior - Bureau of Land Management.
Schedule Page: 326.15 Line No.: 6 Column: b
US Magnesium LLC - contract termination date: December 31, 2014.
Schedule Page: 326.15 Line No.: 6 Column: l
Ancillary services.
Schedule Page: 326.15 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: 326.15 Line No.: 11 Column: a
This footnote applies to all occurrences of "Wasatch Integrated Waste Mgmt District" on
pages 326-327. Complete name is Wasatch Integrated Waste Management District.
Schedule Page: 326.15 Line No.: 13 Column: b
Western Area Power Administration - contract termination date: May 31, 2022.
Schedule Page: 326.15 Line No.: 13 Column: l
Line loss.
Schedule Page: 326.15 Line No.: 14 Column: l
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
Reserve share.
Schedule Page: 326.16 Line No.: 1 Column: l
Line loss.
Schedule Page: 326.16 Line No.: 5 Column: l
Settlement associated with insufficient line loss compensation in past.
Schedule Page: 326.16 Line No.: 6 Column: l
Reflects transactions that did not physically settle.
Schedule Page: 326.16 Line No.: 7 Column: l
Reflects transactions that did not physically settle.
Schedule Page: 326.16 Line No.: 8 Column: l
Purchases of greenhouse gas allowances for compliance with the California Air Resources
Board greenhouse gas cap-and-trade program.
Schedule Page: 326.16 Line No.: 9 Column: l
Deferrals and associated amortization under various energy cost adjustment mechanisms.
Schedule Page: 326.16 Line No.: 10 Column: l
Represents the difference between actual purchase expenses for the period as reflected on
the individual line items within this schedule and the accruals charged to Account 555,
Purchased Power, during this period.
Schedule Page: 326.16 Line No.: 13 Column: l
Exchange energy expense.
Schedule Page: 326.17 Line No.: 1 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.17 Line No.: 2 Column: l
Storage and exchange charges.
Schedule Page: 326.17 Line No.: 3 Column: l
Imbalance energy.
Schedule Page: 326.17 Line No.: 4 Column: l
Storage and exchange charges.
Schedule Page: 326.17 Line No.: 5 Column: l
Storage and exchange charges.
Schedule Page: 326.17 Line No.: 6 Column: l
Exchange energy expense.
Schedule Page: 326.17 Line No.: 8 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.17 Line No.: 9 Column: l
Imbalance energy.
Schedule Page: 326.17 Line No.: 10 Column: l
EIM entity settlements in Energy Imbalance Market.
Schedule Page: 326.17 Line No.: 11 Column: l
EIM participating resource settlements in Energy Imbalance Market.
Schedule Page: 326.17 Line No.: 12 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.17 Line No.: 13 Column: l
Exchange energy expense.
Schedule Page: 326.17 Line No.: 14 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: 326.17 Line No.: 14 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.18 Line No.: 1 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.18 Line No.: 2 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.18 Line No.: 3 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
Storage and exchange charges.
Schedule Page: 326.18 Line No.: 4 Column: l
Exchange energy expense.
Schedule Page: 326.18 Line No.: 5 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.18 Line No.: 7 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.18 Line No.: 8 Column: a
This footnote applies to all occurrences of "J.P. Morgan Ventures Energy Corp" on pages
326-327. Complete name is J.P. Morgan Ventures Energy Corporation.
Schedule Page: 326.18 Line No.: 8 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.18 Line No.: 9 Column: l
Station service for third-party wind project.
Schedule Page: 326.18 Line No.: 11 Column: l
Reimbursement for providing station service to third-party wind project.
Schedule Page: 326.18 Line No.: 12 Column: l
Reimbursement for providing station service to third-party wind project.
Schedule Page: 326.18 Line No.: 13 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.18 Line No.: 14 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.19 Line No.: 1 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.19 Line No.: 2 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.19 Line No.: 4 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.19 Line No.: 6 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.19 Line No.: 7 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.19 Line No.: 8 Column: l
Exchange energy expense.
Schedule Page: 326.19 Line No.: 10 Column: l
Storage and exchange charges.
Schedule Page: 326.19 Line No.: 11 Column: l
Exchange energy expense.
Schedule Page: 326.19 Line No.: 14 Column: l
Exchange energy expense.
Schedule Page: 326.20 Line No.: 1 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 2 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 3 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 4 Column: a
This footnote applies to all occurrences of "Southern CA Public Power Authority" on pages
326-327. Complete name is Southern California Public Power Authority.
Schedule Page: 326.20 Line No.: 4 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 5 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 7 Column: l
PacifiCorp imbalance energy service for others.
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: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 11 Column: a
This footnote applies to all occurrences of "Utah Associated Municipal Power" on pages
326-327. Complete name is Utah Associated Municipal Power Systems.
Schedule Page: 326.20 Line No.: 11 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 12 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 13 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 14 Column: l
PacifiCorp imbalance energy service for others.
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.: 4 Column: l
Reimbursement for third-party services provided.
Schedule Page: 326.21 Line No.: 5 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
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 / /2014/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 NF 4
Black Hills/Colorado Electric Utility Company NF 5
Black Hills/Colorado Electric Utility Company SFP 6
Black Hills Corporation PacifiCorp Energy Montana-Dakota Utilities FNO 7
Black Hills Corporation PacifiCorp Energy Montana-Dakota Utilities AD 8
Black Hills Corporation NF 9
Black Hills Corporation AD 10
Black Hills Corporation SFP 11
Black Hills Corporation PacifiCorp Energy Black Hills Corporation LFP 12
Black Hills Corporation PacifiCorp Energy Black Hills Corporation AD 13
Black Hills Wyoming SFP 14
Black Hills Wyoming NF 15
Bonneville Power Administration OS 16
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 17
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 18
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration LFP 19
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 20
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative FNO 21
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative AD 22
Bonneville Power Administration Bonneville Power Administration Benton REA FNO 23
Bonneville Power Administration Bonneville Power Administration Benton REA AD 24
Bonneville Power Administration Bonneville Power Administration Umatilla Electric & Columbia FNO 25
Bonneville Power Administration Bonneville Power Administration Umatilla Electric & Columbia AD 26
Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration LFP 27
Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration AD 28
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 29
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 30
Bonneville Power Administration Bonneville Power Administration Yakama Power FNO 31
Bonneville Power Administration Bonneville Power Administration Yakama Power AD 32
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 33
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 34
FERC FORM NO. 1 (ED. 12-90)Page 328
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2014/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 3,464 3,464 2
Yellowtail SubV11-1,2,3 Sheridan Substation 1 408 408 3
VariousV11-1,2,8 Various 2,688 2,688 4
VariousV11-1,2,8 Various 1,398 1,398 5
VariousV11-1,2,7 Various 1,829 1,829 6
VariousV11-1,2 Sheridan Substation 45 7
VariousV11-1,2 Sheridan Substation 56 8
VariousV11-1,2,8 Various 13,155 13,155 9
VariousV11-1,2,8 Various 397 397 10
VariousV11-1,2,7 Various 4,035 4,035 11
VariousV11-1,2,7 Wyodak Substation 52 182,880 182,880 12
VariousV11-1,2,7 Wyodak Substation 52 6,481 6,481 13
VariousV11-1,2,7 Various 215 215 14
VariousV11-1,2,8 Various 427 427 15
Midpoint SubstationR.S. 369 Summer Lake Sub 16
VariousR.S. 237 Various 336 1,010,505 1,010,505 17
VariousR.S. 237 Various 349 105,694 105,694 18
Lost Creek Hydro PltV11-2,7 Alvey Substation 58 241,995 241,995 19
Lost Creek Hydro PltV11-2,7 Alvey Substation 58 13,872 13,872 20
Bonneville Power AdmV11-1,2,3 Gazley Substation 3 23,435 23,435 21
Bonneville Power AdmV11-1,2,3 Gazley Substation 3 2,323 2,323 22
Bonneville Power AdmV11-1,2,3 Tieton Substation 1 5,401 5,401 23
Bonneville Power AdmV11-1,2,3 Tieton Substation 1 862 862 24
McNary SubstationV11-1,2,3 Hinkle Substation 1 908 908 25
McNary SubstationV11-1,2,3 Hinkle Substation 1 114 114 26
USBR Green SpringsV11-2,7 Bonneville Power Adm 19 68,312 68,312 27
USBR Green SpringsV11-2,7 Bonneville Power Adm 19 28
Malin SubstationR.S. 368 Malin Substation 675,121 675,121 29
Malin SubstationR.S. 368 Malin Substation 62,042 62,042 30
Bonneville Power AdmV11-1,2,3,4 6 34,941 34,941 31
Bonneville Power AdmV11-1,2,3,4 6 3,760 3,760 32
VariousR.S. 299 Various 168 989,870 989,870 33
VariousR.S. 299 Various 193 108,136 108,136 34
FERC FORM NO. 1 (ED. 12-90)Page 329
4,781 13,674,599 13,563,767
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 / /2014/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
8,971 21,843 12,872 2
-1,815 -1,815 3
17,414 704 16,710 4
14,931 606 14,325 5
2,431 182 2,249 6
1,124,973 1,172,384 47,411 7
84,511 84,511 8
29,865 1,212 28,653 9
460 460 10
27,199 1,077 26,122 11
1,279,338 1,333,252 53,914 12
77,260 77,260 13
14
15
16
3,892,268 3,960,215 67,947 17
261,846 261,846 18
1,432,868 1,448,050 15,182 19
81,433 81,433 20
69,611 200,192 130,581 21
1,482 1,482 22
15,220 17,655 2,435 23
2,517 2,517 24
3,462 4,049 587 25
763 763 26
460,567 464,713 4,146 27
42,504 42,504 28
224,496 224,496 29
22,450 22,450 30
129,455 225,873 96,418 31
16,830 16,830 32
871,166 1,895,739 1,024,573 33
175,634 175,634 34
FERC FORM NO. 1 (ED. 12-90)Page 330
45,500,570 88,719,750 31,682,875 11,536,305
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 / /2014/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying
facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Bonneville Power Administration NF 1
Bonneville Power Administration Bonneville Power Administration Clark Public Utilities FNO 2
Bonneville Power Administration Bonneville Power Administration Clark Public Utilities AD 3
Cargill Power Markets, LLC NF 4
Cargill Power Markets, LLC AD 5
Cargill Power Markets, LLC SFP 6
Cargill Power Markets, LLC AD 7
Constellation Energy Commodities Group NF 8
Constellation Energy Commodities Group SFP 9
Coral Power, LLC NF 10
Coral Power, LLC AD 11
Coral Power, LLC SFP 12
Coral Power, LLC AD 13
Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration OS 14
Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration AD 15
Deseret Generation & Trans.Deseret Generation & Trans.Deseret Generation & Trans.OS 16
Deseret Generation & Trans.Deseret Generation & Trans.Deseret Generation & Trans.AD 17
Deseret Generation & Trans.NF 18
EDF Trading North America, LLC AD 19
Enel Cove Fort, LLC Enel Cove Fort, LLC LFP 20
Enel Cove Fort, LLC Enel Cove Fort, LLC AD 21
Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company OS 22
Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company AD 23
Foote Creek III, LLC Foote Creek III, LLC PacifiCorp Energy OS 24
Foote Creek III, LLC Foote Creek III, LLC PacifiCorp Energy AD 25
Iberdrola Renewables, LLC NF 26
Iberdrola Renewables, LLC AD 27
Iberdrola Renewables, LLC SFP 28
Iberdrola Renewables, LLC AD 29
Iberdrola Renewables, LLC Iberdrola Renewables, LLC OS 30
Iberdrola Renewables, LLC Iberdrola Renewables, LLC AD 31
Iberdrola Renewables, LLC Exxon Mobil Nevada Power Company LFP 32
Iberdrola Renewables, LLC Exxon Mobil Nevada Power Company AD 33
Iberdrola Renewables, LLC Bonneville Power Administration Oregon Direct Access FNO 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 / /2014/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 298 298 1
Cardwell-MerwinV11-1,2,3,4 18 107,488 107,488 2
Cardwell-MerwinV11-1,2,3,4 33 17,073 17,073 3
VariousV11-1,2,8 Various 39,210 39,210 4
VariousV11-1,2,8 Various 13,699 13,699 5
VariousV11-1,2,7 Various 6
VariousV11-1,2,7 Various 1,263 1,263 7
VariousV11-5,6,11 Various 1,789 1,789 8
VariousV11-1-3,7 Various 1,650 1,650 9
VariousV11-1,2,8 Various 50,003 50,003 10
VariousV11-1,2,8 Various 1,208 1,208 11
VariousV11-1,2,7 Various 115,557 115,557 12
VariousV11-1,2,7 Various 10,375 10,375 13
Swift Unit No. 2R.S. 234 Woodland Substation 14
Swift Unit No. 2R.S. 234 Woodland Substation 15
VariousR.S. 280 Various 82 612,946 612,946 16
VariousR.S. 280 Various 109 65,185 65,185 17
VariousV11-1,2 Various 6,386 6,386 18
VariousV11-1,2 Various 19
Enel Cove FortV11 Red Butte Substation 20
Enel Cove FortV11 Mona Substation 26 13,969 13,969 21
Targhee SubstationR.S. 322 Goshen Substation 22
Targhee SubstationR.S. 322 Goshen Substation 23
Foote Creek SubS.A 761 Various 24
Foote Creek SubS.A 761 Various 25
VariousV11-1-3,8,9,11 Various 248,249 248,249 26
VariousV11-1-3,8,9 Various 30,155 30,155 27
VariousV11-1,2,3,7 Various 67,933 67,933 28
VariousV11-1,2,3,7 Various 13,621 13,621 29
V11-5,6 30
V11-5,6 31
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 31 81,958 81,958 32
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 31 11,604 11,604 33
Ponderosa SubstationV11-1,2,3 Various 4 28,735 28,735 34
FERC FORM NO. 1 (ED. 12-90)Page 329.1
4,781 13,674,599 13,563,767
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 / /2014/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.
1,789 73 1,716 1
380,860 446,295 65,435 2
65,695 65,695 3
220,017 8,903 211,114 4
56,052 56,052 5
1,512 1,512 6
17,719 17,719 7
126,533 115,600 10,933 8
23,719 971 22,748 9
268,482 10,870 257,612 10
8,041 8,041 11
539,946 23,501 516,445 12
44,858 44,858 13
135,586 135,586 14
11,985 11,985 15
2,017,848 4,050,698 2,032,850 16
481,342 481,342 17
33,372 1,351 32,021 18
72 3 69 19
86,188 86,188 20
55,617 55,617 21
138,699 138,699 22
12,609 12,609 23
56,769 56,769 24
3,015 3,015 25
1,849,902 256,848 1,593,054 26
173,672 173,672 27
571,953 39,299 532,654 28
93,125 93,125 29
219,643 219,643 30
39,679 39,679 31
767,602 799,950 32,348 32
45,449 45,449 33
51,312 60,967 9,655 34
FERC FORM NO. 1 (ED. 12-90)Page 330.1
45,500,570 88,719,750 31,682,875 11,536,305
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 / /2014/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying
facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Iberdrola Renewables, LLC Iberdrola Renewables, LLC AD 1
Idaho Power Company Idaho Power Company Idaho Power Company OS 2
Idaho Power Company Exxon Mobil Nevada Power Company LFP 3
Idaho Power Company Exxon Mobil Nevada Power Company AD 4
Idaho Power Company OS 5
Idaho Power Company AD 6
Idaho Power Company OS 7
Idaho Power Company AD 8
Idaho Power Company NF 9
Idaho Power Company AD 10
Idaho Power Company SFP 11
Idaho Power Company AD 12
Idaho Power Marketing Operations NF 13
JP Morgan Ventures Energy Corp.NF 14
JP Morgan Ventures Energy Corp.AD 15
Los Angeles Department of Water & Power NF 16
Macquarie Energy, LLC NF 17
Macquarie Energy, LLC AD 18
Macquarie Energy, LLC SFP 19
Macquarie Energy, LLC AD 20
Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association OS 21
Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association AD 22
Morgan Stanley Capital Group, Inc.NF 23
Morgan Stanley Capital Group, Inc.AD 24
Morgan Stanley Capital Group, Inc.SFP 25
Morgan Stanley Capital Group, Inc.AD 26
Nevada Power Company NF 27
Nevada Power Company AD 28
Nevada Power Company SFP 29
NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD LFP 30
NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD AD 31
NextEra Energy Resources, LLC NF 32
NextEra Energy Resources, LLC AD 33
Noble Americas Energy Solutions LLC Bonneville Power Administration Oregon Direct Access FNO 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 / /2014/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.
Malin 500 SubstationV11-1,2,3 Round Mountain Sub 4 2,417 2,417 1
Goshen SubstationR.S. 427 Goshen Substation 2
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 59,643 59,643 3
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 4
Antelope SubstationR.S. 257 Antelope Substation 183,420 183,420 5
Antelope SubstationR.S. 257 Antelope Substation 23,925 23,925 6
Jim Bridger SubR.S. 203 Bridger Pump Sub 44,027 44,027 7
Jim Bridger SubR.S. 203 Bridger Pump Sub 2,491 2,491 8
VariousV11-1,2,8 Various 54,046 54,046 9
VariousV11-1,2,8 Various 81 81 10
VariousV11-1,2,7 Various 3,080 3,080 11
VariousV11-1,2 Various 12
VariousV11-1,2,8 Various 811 811 13
VariousV11-1-3,8,9,11 Various 28,479 28,479 14
VariousV11-1,2,3 Various 6,172 6,172 15
VariousV11-1,2,8 Various 4,356 4,356 16
VariousV11-1,2,8 Various 5,642 5,642 17
VariousV11-1,2,8 Various 9,248 9,248 18
VariousV11-1,2,7 Various 6,687 6,687 19
VariousV11-1,2,7 Various 8,050 8,050 20
DuchesneR.S. 302 Duchesne 22,002 22,002 21
DuchesneR.S. 302 Duchesne 2,208 2,208 22
VariousV11-1-3,8 Various 149,158 149,158 23
VariousV11-1-3,8 Various 10,975 10,975 24
VariousV11-1,2,7 Various 10,892 10,892 25
VariousV11-1,2,7 Various 1,582 1,582 26
VariousV11-1,2,8 Various 4,001 4,001 27
VariousV11-1,2,8 Various 466 466 28
VariousV11-1,2,7 Various 1,500 1,500 29
Wallula Substation Wala-MIDC path 103 211,794 211,794 30
Wallula SubstationV11-5,6,7,9 Wala-MIDC path 103 25,327 25,327 31
VariousV11-1,2,3,8,11 Various 1,048 1,048 32
VariousV11-1,2,8 Various 42 42 33
Bonneville Power AdmV11-1,2,3,4 Various 21 144,786 144,786 34
FERC FORM NO. 1 (ED. 12-90)Page 329.2
4,781 13,674,599 13,563,767
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 / /2014/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.
3,517 3,517 1
2
897,147 934,940 37,793 3
-41,599 -41,599 4
67,672 67,672 5
6,152 6,152 6
14,927 14,927 7
1,357 1,357 8
295,337 11,959 283,378 9
338 338 10
25,892 1,047 24,845 11
-36 -36 12
3,051 124 2,927 13
1,512,517 935,693 576,824 14
100,636 100,636 15
44,304 1,793 42,511 16
18,818 759 18,059 17
4,637 4,637 18
11,028 449 10,579 19
58,530 58,530 20
16,050 16,050 21
1,605 1,605 22
909,381 37,090 872,291 23
52,933 52,933 24
64,328 2,611 61,717 25
6,933 6,933 26
26,850 3,191 23,659 27
1,501 1,501 28
16,209 656 15,553 29
2,305,807 3,113,196 807,389 30
259,608 259,608 31
37,625 10,290 27,335 32
248 248 33
285,840 334,020 48,180 34
FERC FORM NO. 1 (ED. 12-90)Page 330.2
45,500,570 88,719,750 31,682,875 11,536,305
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 / /2014/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.
Noble Americas Energy Solutions LLC Bonneville Power Administration Oregon Direct Access AD 1
Pacific Gas & Electric Company OS 2
Pacific Gas & Electric Company AD 3
Pacific Gas & Electric Company OS 4
Pacific Gas & Electric Company NF 5
Portland General Electric Company NF 6
Portland General Electric Company AD 7
Portland General Electric Company SFP 8
Portland General Electric Company AD 9
Portland General Electric Company OS 10
Powder River Energy Corporation Western Area Power Administration Sheridan-Johnson Rural Elect.OS 11
Powder River Energy Corporation Western Area Power Administration Sheridan-Johnson Rural Elect.AD 12
Powerex Corporation Bonneville Power Administration CAISO LFP 13
Powerex Corporation Bonneville Power Administration CAISO AD 14
Powerex Corporation Powerex Corporation CAISO LFP 15
Powerex Corporation Powerex Corporation CAISO AD 16
Powerex Corporation Powerex Corporation CAISO LFP 17
Powerex Corporation Powerex Corporation CAISO AD 18
Powerex Corporation Powerex Corporation CAISO LFP 19
Powerex Corporation Powerex Corporation CAISO AD 20
Powerex Corporation Powerex Corporation CAISO LFP 21
Powerex Corporation Powerex Corporation CAISO LFP 22
Powerex Corporation NF 23
Powerex Corporation AD 24
Powerex Corporation SFP 25
Powerex Corporation AD 26
PPL Energy Plus, LLC NF 27
PPL Energy Plus, LLC AD 28
PPL Energy Plus, LLC SFP 29
Public Svc. Co. of CO NF 30
Puget Sound Power & Light Company SFP 31
Puget Sound Power & Light Company NF 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 / /2014/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.
Bonneville Power AdmV11-1,2,3,4 Various 26 17,414 17,414 1
R.S. 607 2
VariousV11-1,2 Various 3
Sigurd-Glen CanyonR.S. 298 Pinto-Four Corners 4
VariousV11-1,2,8 Various 260 260 5
VariousV11-1,2,8 Various 9,388 9,388 6
VariousV11-1,2,8 Various 1,149 1,149 7
VariousV11-1,2,7 Various 1,768 1,768 8
VariousV11-1,2,7 Various 1,210 1,210 9
VariousR.S. 137 Various 10
VariousR.S. 123 Buffalo Substation 11
VariousR.S. 123 Buffalo Substation 12
Bonneville Power AdmV11-1,2,7 CRAG View Substation 83 620,286 620,286 13
Bonneville Power AdmV11-1,2,7 CRAG View Substation 83 13,947 13,947 14
Malin 500 SubstationV11-1,7 Round Mountain Sub 67 15
Malin 500 SubstationV11-1,7 Round Mountain Sub 67 16
Malin 500 SubstationV11-1,7 Round Mountain Sub 67 17
Malin 500 SubstationV11-1,7 Round Mountain Sub 67 18
Malin 500 SubstationV11-1,7 Round Mountain Sub 66 19
Malin 500 SubstationV11-1,7 Round Mountain Sub 66 20
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 21
Malin 500 SubstationV11-1,7 Round Mountain Sub 150 22
VariousV11-1,2,3,8 Various 488,152 488,152 23
VariousV11-1,2,8 Various 4,162 4,162 24
VariousV11-1,2,3,7 Various 33,375 33,375 25
VariousV11-1,2,7 Various 611 611 26
VariousV11-1,2,8 Various 4,136 4,136 27
VariousV11-1,2,8 Various 641 641 28
VariousV11-1,2,7 Various 4,626 4,626 29
VariousV11-1,2,8 Various 30
VariousV11-1,2,7 Various 31
VariousV11-1,2,8 Various 1,976 1,976 32
VariousV11-1,2,8 Various 492 492 33
VariousV11-1,2 Various 1,200 1,200 34
FERC FORM NO. 1 (ED. 12-90)Page 329.3
4,781 13,674,599 13,563,767
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 / /2014/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.
33,610 33,610 1
13,291,667 13,291,667 2
1,208,333 1,208,333 3
220,508 220,508 4
1,871 76 1,795 5
69,901 2,833 67,068 6
6,906 6,906 7
9,574 387 9,187 8
7,433 7,433 9
3,314 3,314 10
350 350 11
34 34 12
2,046,940 2,133,204 86,264 13
121,197 121,197 14
1,644,267 1,679,783 35,516 15
94,339 94,339 16
1,644,267 1,679,783 35,516 17
94,339 94,339 18
1,619,726 1,654,711 34,985 19
92,967 92,967 20
1,227,065 1,253,570 26,505 21
3,681,194 3,770,394 89,200 22
2,724,240 143,831 2,580,409 23
21,456 21,456 24
198,469 18,370 180,099 25
3,525 3,525 26
40,122 1,623 38,499 27
3,637 3,637 28
30,369 1,232 29,137 29
180 7 173 30
20 1 19 31
14,118 571 13,547 32
4,113 166 3,947 33
5,403 5,403 34
FERC FORM NO. 1 (ED. 12-90)Page 330.3
45,500,570 88,719,750 31,682,875 11,536,305
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 / /2014/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
Sacramento Municipal Utility District Sacramento Municipal Utility Dist Sacramento Municipal Utility Dist LFP 2
Sacramento Municipal Utility District Sacramento Municipal Utility Dist Sacramento Municipal Utility Dist AD 3
Sacramento Municipal Utility District Sacramento Municipal Utility Dist Sacramento Municipal Utility Dist LFP 4
Salt River Project Salt River Project Salt River Project LFP 5
Salt River Project NF 6
Salt River Project AD 7
Seattle City Light FPL Energy Vansycle, LLC Grant County PUD AD 8
Sierra Pacific Power Company OS 9
Sierra Pacific Power Company AD 10
Sierra Pacific Power Company NF 11
Southern California Edison Company NF 12
Southern California Edison Company AD 13
Southern California Edison Company SFP 14
Southern California Edison Company AD 15
Southern California Edison Company OS 16
Southern California Public Power Authority Powerex Corporation Southern California Public Power 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
State of South Dakota Western Area Power Administration Black Hills Corporation SFP 20
Tenaska Power Services Company NF 21
Tenaska Power Services Company AD 22
Tenaska Power Services Company SFP 23
Tenaska Power Services Company AD 24
The Energy Authority, Inc.NF 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
Tri-State Generation & Trans.Tri-State Generation & Trans.OS 30
Tri-State Generation & Trans.Tri-State Generation & Trans AD 31
Tri-State Generation & Trans.Tri-State Generation & Trans.FNO 32
Tri-State Generation & Trans.Tri-State Generation & Trans AD 33
Tri-State Generation & Trans.NF 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 / /2014/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 17,328 17,328 1
Malin SubstationV11-1,2,7 Malin Substation 31 105,118 105,118 2
Malin SubstationV11-1,2,7 Malin Substation 1,632 1,632 3
Malin SubstationV11 Malin Substation 4
Enel Cove FortV11-1,2,7 Red Butte Substation 26 121,700 121,700 5
VariousV11-1,2,3,8 Various 3,577 3,577 6
VariousV11-1,2,3,7 Various 1,586 1,586 7
Wallula SubstationV11-1,2 Wala-MIDC path 8
Sigurd SubstationR.S. 674 Utah-Nevada Border 9
Sigurd SubstationR.S. 674 Utah-Nevada Border 10
VariousV11-1,2,8 Various 280 280 11
VariousV11-1-3,8,9,11 Various 315,360 315,360 12
VariousV11-1-3,8,9,11 Various 17,895 17,895 13
VariousV11-1-3,7 Various 1,000 1,000 14
VariousV11-1-3,7 Various 270 270 15
Sigurd-Glen CanyonR.S. 298 Pinto-Four Corners 16
Tieton SubstationV11-9,11 Various 1,144 1,144 17
Yellowtail SubV11-1,2,7 Wyodak Substation 4 12,235 12,235 18
Yellowtail SubV11-1,2,7 Wyodak Substation 4 1,496 1,496 19
VariousV11-1,2,7 Various 3,481 3,481 20
VariousV11-1,2,8 Various 43,092 43,092 21
VariousV11-1,2,8 Various 8,321 8,321 22
VariousV11-1,2,7 Various 40,590 40,590 23
VariousV11-1,2,7 Various 11,080 11,080 24
VariousV11-1,2,8 Various 2,661 2,661 25
South Milford Sub Mona Substation 11 53,417 53,417 26
South Milford Sub Mona Substation 11 5,984 5,984 27
VariousV11-1,2,8 Various 54,023 54,023 28
VariousV11-1,2,8 Various 1,813 1,813 29
VariousR.S. 123 Various 37 133,369 133,369 30
VariousR.S. 123 Various 36 19,900 19,900 31
Dave Johnston SubV11-1,2,3,4 Thermopolis Sub 6 47,158 47,158 32
Dave Johnston SubV11-1,2,3,4 Thermopolis Sub 1 263 263 33
VariousV11-1,2,8 Various 14,522 14,522 34
FERC FORM NO. 1 (ED. 12-90)Page 329.4
4,781 13,674,599 13,563,767
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 / /2014/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.
80,643 3,257 77,386 1
767,602 799,950 32,348 2
59,749 59,749 3
67,394 67,394 4
639,668 666,626 26,958 5
19,991 809 19,182 6
13,063 13,063 7
-3,524 -3,524 8
62,654 62,654 9
6,265 6,265 10
1,929 77 1,852 11
3,450,166 1,027,319 2,422,847 12
231,470 231,470 13
9,204 1,224 7,980 14
2,695 2,695 15
220,508 220,508 16
18,980 18,980 17
73,631 76,735 3,104 18
6,057 6,057 19
22,110 894 21,216 20
230,032 12,171 217,861 21
13,516 13,516 22
178,556 7,478 171,078 23
81,527 81,527 24
17,559 711 16,848 25
281,464 367,196 85,732 26
24,410 24,410 27
337,752 13,710 324,042 28
8,987 8,987 29
107,496 107,496 30
11,179 11,179 31
98,186 118,623 20,437 32
-1,974 -1,974 33
74,288 3,010 71,278 34
FERC FORM NO. 1 (ED. 12-90)Page 330.4
45,500,570 88,719,750 31,682,875 11,536,305
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 / /2014/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.AD 1
Tri-State Generation & Trans.SFP 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
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency NF 15
Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric Co OS 16
Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric Co AD 17
Western Area Power Administration Western Area Power Administration OS 18
Western Area Power Administration Western Area Power Administration AD 19
Western Area Power Administration Western Area Power Administration OS 20
Western Area Power Administration Western Area Power Administration AD 21
Western Area Power Administration Western Area Power Administration OS 22
Western Area Power Administration Western Area Power Administration Western Area Power Administration FNO 23
Western Area Power Administration Western Area Power Administration Western Area Power Administration AD 24
Western Area Power Adm. CO River Western Area Power Adm. CO River NF 25
Western Area Power Adm. CO River Western Area Power Adm. CO River SFP 26
Western Area Power Adm. CO MO Western Area Power Adm. CO MO NF 27
Accrual 28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90)Page 328.5
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2014/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 246 246 1
VariousV11-1,2,7 Various 244 244 2
VariousV11-1,2,7 Various 9 9 3
Walla Walla SubV11-1,2,3 Burbank Pumps 1 2,372 2,372 4
Walla Walla SubV11-1,2,3 Burbank Pumps 1 3 3 5
VariousR.S. 286 Various 21,481 21,481 6
VariousR.S. 286 Various 1,568 1,568 7
Redmond SubstationR.S. 67 Crooked River Pumps 13,028 13,028 8
VariousR.S. 297 Various 422 2,476,308 2,476,308 9
VariousR.S. 297 Various 521 229,844 229,844 10
VariousV11-1,2,3,8 Various 4,241 4,241 11
VariousV11-1,2,8 Various 105 105 12
VariousR.S. 637 Various 115 652,710 652,710 13
VariousR.S. 637 Various 106 59,234 59,234 14
VariousV11-1,2,8 Various 40 40 15
Pelton ReregulatingR.S. 591 Round Butte Sub 80,305 80,305 16
Pelton ReregulatingR.S. 591 Round Butte Sub 7,298 7,298 17
VariousR.S. 262 Various 330 1,583,864 1,489,212 18
VariousR.S. 262 Various 330 187,719 176,455 19
VariousR.S. 263 Various 84,635 79,280 20
VariousR.S. 263 Various 8,557 8,075 21
Dave Johnston SubR.S. 664 Various 22
Wyoming DistributionV11-1,2 Wyoming Distribution 1 10,097 10,097 23
Wyoming DistributionV11-1,2 Wyoming Distribution 1 2 2 24
VariousV11-1,2,8 Various 25
VariousV11-1,2,7 Various 63 63 26
VariousV11-1,2,8 Various 636 636 27
-128,476 -127,555 28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90)Page 329.5
4,781 13,674,599 13,563,767
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 / /2014/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.
1,287 1,287 1
1,220 50 1,170 2
57 57 3
8,690 21,475 12,785 4
-240 -240 5
21,481 21,481 6
1,569 1,569 7
12,532 12,532 8
10,464,185 13,030,097 2,565,912 9
1,691,156 1,691,156 10
24,559 3,232 21,327 11
605 605 12
2,850,553 3,415,195 564,642 13
222,675 222,675 14
270 11 259 15
109,725 109,725 16
9,975 9,975 17
2,305,111 2,855,111 550,000 18
233,426 233,426 19
52,071 52,071 20
5,825 5,825 21
22
33,678 76,219 42,541 23
-1,285 -1,285 24
10,721 434 10,287 25
499 64 435 26
1,328 54 1,274 27
-1,402,686 -1,402,686 28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90)Page 330.5
45,500,570 88,719,750 31,682,875 11,536,305
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. 2013 transmission and
ancillary services. Refunds for transmission services pursuant to FERC Docket No.
ER11-3646. 2013 annual transmission services true-up refund.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service.
Schedule Page: 328 Line No.: 5 Column: a
This footnote applies to all occurrences of "Black Hills/Colorado Electric Utility
Company" on pages 328-300. 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
Transmission resales, purchase of point-to-point transmission. 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 328 Line No.: 7 Column: b
PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and
commodity trading activities.
Schedule Page: 328 Line No.: 7 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.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 8 Column: b
PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and
commodity trading activities.
Schedule Page: 328 Line No.: 8 Column: d
Network transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 347) terminating on December 31, 2017.
Schedule Page: 328 Line No.: 8 Column: m
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
Schedule Page: 328 Line No.: 9 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 9 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 9 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
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
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 10 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 10 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 10 Column: m
2013 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER11-3646.
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
Transmission resales, amount paid by seller. Scheduling, system control and dispatch
service. Reactive supply and voltage control service.
Schedule Page: 328 Line No.: 12 Column: b
PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and
commodity trading activities.
Schedule Page: 328 Line No.: 12 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.: 12 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 13 Column: b
PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and
commodity trading activities.
Schedule Page: 328 Line No.: 13 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.: 13 Column: m
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
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.: 15 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 15 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 16 Column: b
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.
Schedule Page: 328 Line No.: 16 Column: c
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.
Schedule Page: 328 Line No.: 16 Column: d
Legacy contract executed between PacifiCorp and Bonneville Power Administration 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.: 17 Column: d
Legacy contract (3rd Revised Rate Schedule 237) executed between PacifiCorp and Bonneville
Power Administration ("BPA") for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Contract subject to termination upon the
earlier of the termination of the "Exchange Agreement" between PacifiCorp and BPA or the
time of the termination of all deliveries as defined in the agreement.
Schedule Page: 328 Line No.: 17 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Schedule Page: 328 Line No.: 18 Column: d
Legacy contract (3rd Revised Rate Schedule 237) executed between PacifiCorp and Bonneville
Power Administration ("BPA") for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Contract subject to termination upon the
earlier of the termination of the "Exchange Agreement" between PacifiCorp and BPA or the
time of the termination of all deliveries as defined in the agreement.
Schedule Page: 328 Line No.: 18 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
or facilities charge. 2013 transmission and ancillary services.
Schedule Page: 328 Line No.: 19 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.: 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. Reactive supply and voltage control service.
Schedule Page: 328 Line No.: 20 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 656) terminating on August 31, 2030.
Schedule Page: 328 Line No.: 20 Column: m
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
Schedule Page: 328 Line No.: 21 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (8th Revised Service Agreement 229) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 21 Column: f
This footnote applies to all occurrences of "Bonneville Power Adm" on pages 328-330.
Complete name is Bonneville Power Administration.
Schedule Page: 328 Line No.: 21 Column: m
Distribution voltage service charge. Primary delivery service. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Regulation and
frequency response service.
Schedule Page: 328 Line No.: 22 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (8th Revised Service Agreement 229) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 22 Column: m
2012 annual transmission services true-up charge. 2013 annual transmission services
true-up refund.
Schedule Page: 328 Line No.: 23 Column: c
This footnote applies to all occurrences of "Benton REA" on pages 328-330. Complete name
is Benton Rural Electric Association.
Schedule Page: 328 Line No.: 23 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (3rd Revised Service Agreement 539) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 23 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service.
Schedule Page: 328 Line No.: 24 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (3rd Revised Service Agreement 539) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 24 Column: m
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
Schedule Page: 328 Line No.: 25 Column: c
This footnote applies to all occurrences of "Umatilla Electric & Columbia" on pages
328-330. Complete name is Umatilla Electric Cooperative Association and Columbia Basin
Electric Cooperative, Inc.
Schedule Page: 328 Line No.: 25 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 538) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 25 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 328 Line No.: 26 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 538) terminating on September 30, 2028.
Schedule Page: 328 Line No.: 26 Column: m
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
Schedule Page: 328 Line No.: 27 Column: b
This footnote applies to all occurrences of "U.S. Bureau of Reclamation" on pages 328-330.
Complete name is United States Department of Interior Bureau of Reclamation.
Schedule Page: 328 Line No.: 27 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (5th Revised
Service Agreement 179) terminating on September 30, 2025.
Schedule Page: 328 Line No.: 27 Column: m
Reactive supply and voltage control service.
Schedule Page: 328 Line No.: 28 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (5th Revised
Service Agreement 179) terminating on September 30, 2025.
Schedule Page: 328 Line No.: 28 Column: m
2013 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER11-3646.
Schedule Page: 328 Line No.: 29 Column: d
Legacy contract (5th Revised Rate Schedule 368) executed between PacifiCorp and Bonneville
Power Administration ("BPA") for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Subject to termination upon mutual agreement.
Schedule Page: 328 Line No.: 29 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
Schedule Page: 328 Line No.: 30 Column: d
Legacy contract (5th Revised Rate Schedule 368) executed between PacifiCorp and Bonneville
Power Administration ("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. 2013 transmission and ancillary services.
Schedule Page: 328 Line No.: 31 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (6th Revised Service Agreement 328) terminating on July 31, 2028.
Schedule Page: 328 Line No.: 31 Column: g
White Swan/Toppenish Substations
Schedule Page: 328 Line No.: 31 Column: m
Distribution voltage service charge. Primary delivery service. Penalty revenues covering
imbalance charges per Schedules 4 and 9. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Regulation and frequency response service.
Schedule Page: 328 Line No.: 32 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (6th 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
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
Schedule Page: 328 Line No.: 33 Column: d
Legacy contract (2nd Revised Rate Schedule 299) executed between PacifiCorp and Bonneville
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Power Administration ("BPA") for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Contract terminates with three years notice by
BPA or five years notice by PacifiCorp. PacifiCorp provided notice of termination in June
2011.
Schedule Page: 328 Line No.: 33 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. Charges for scheduling and operating reserves.
Schedule Page: 328 Line No.: 34 Column: d
Legacy contract (2nd Revised Rate Schedule 299) executed between PacifiCorp and Bonneville
Power Administration ("BPA") for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Contract terminates with three years notice by
BPA or five years notice by PacifiCorp. PacifiCorp provided notice of termination in June
2011.
Schedule Page: 328 Line No.: 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. 2013 transmission and
ancillary services.
Schedule Page: 328.1 Line No.: 1 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 1 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 1 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 1 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 2 Column: d
Network Transmission Service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 735) terminating on September 30, 2028.
Schedule Page: 328.1 Line No.: 2 Column: g
Chelatchie/View 115kV
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. Regulation and
frequency response service.
Schedule Page: 328.1 Line No.: 3 Column: d
Network Transmission Service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 735) terminating on September 30, 2028.
Schedule Page: 328.1 Line No.: 3 Column: g
Chelatchie/View 115kV
Schedule Page: 328.1 Line No.: 3 Column: m
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
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.
Schedule Page: 328.1 Line No.: 4 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 5 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
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
2013 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 6 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 6 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 6 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 6 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 7 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 7 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 7 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 7 Column: m
2013 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 8 Column: a
This footnote applies to all occurrences of "Constellation Energy Commodities Group" on
pages 328-330. Complete name is Constellation Energy Commodities Group, Inc.
Schedule Page: 328.1 Line No.: 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
Unauthorized use of transmission service. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Operating reserve - spinning reserve service.
Operating reserve - supplemental reserve 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
Transmission resales, purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Generation regulation
and frequency response service.
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 10 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 10 Column: m
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
2013 transmission and ancillary services.
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
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.: 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
2013 transmission and ancillary services. Transmission resales, purchase of point-to-point
transmission.
Schedule Page: 328.1 Line No.: 14 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.: 14 Column: d
Legacy contract (Rate Schedule 234) providing for transmission and operation of Swift
Hydroelectric Plant No. 2, and for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Agreement may be terminated subsequent to the
termination of the Power Contract as defined in the agreement by the customer providing at
least six months written notice and specifying the date on which the customer will assume
responsibility of operations and maintenance of Swift Hydroelectric Plant No. 2.
Schedule Page: 328.1 Line No.: 14 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and or proportional use as defined in the
contract.
Schedule Page: 328.1 Line No.: 15 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
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.: 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. 2013 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 16 Column: a
This footnote applies to all occurrences of "Deseret Generation & Trans." on pages
328-330. Complete name is Deseret Generation and Transmission Co-operative.
Schedule Page: 328.1 Line No.: 16 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.: 16 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. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.
Schedule Page: 328.1 Line No.: 17 Column: d
Legacy contract executed between PacifiCorp and Deseret Generation and Transmission
Cooperative 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.: 17 Column: m
Distribution voltage service charge. Meter interrogation services. 2013 transmission and
ancillary services. 2013 annual transmission services true-up refund.
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: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 19 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 19 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 20 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 20 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff, (2nd
Revised Service Agreement 711) terminating November 30, 2018.
Schedule Page: 328.1 Line No.: 20 Column: m
2013 transmission and ancillary services. 2013 annual transmission services true-up
refund.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
Schedule Page: 328.1 Line No.: 21 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 21 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff, (2nd
Revised Service Agreement 711) terminating November 30, 2018.
Schedule Page: 328.1 Line No.: 21 Column: m
2013 transmission and ancillary services. 2013 annual transmission services true-up
refund.
Schedule Page: 328.1 Line No.: 22 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.: 22 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
Schedule Page: 328.1 Line No.: 23 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.: 23 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. 2013 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 24 Column: c
PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and
commodity trading activities.
Schedule Page: 328.1 Line No.: 24 Column: d
Service Agreement 761 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 March 1, 2024.
Schedule Page: 328.1 Line No.: 24 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. Distribution voltage service charge.
Schedule Page: 328.1 Line No.: 25 Column: c
PacifiCorp Energy, a business unit of PacifiCorp responsible for electric generation and
commodity trading activities.
Schedule Page: 328.1 Line No.: 25 Column: d
Service Agreement 761 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 March 1, 2024.
Schedule Page: 328.1 Line No.: 25 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. 2013 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 26 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
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
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 26 Column: m
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
reserve - spinning reserve service. Operating reserve - supplemental reserve service.
Schedule Page: 328.1 Line No.: 27 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
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
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.: 27 Column: m
2013 transmission and ancillary services.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.1 Line No.: 29 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 29 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 29 Column: m
2013 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 30 Column: c
Iberdrola Renewables, LLC and Utah Associated Municipal Power Systems
Schedule Page: 328.1 Line No.: 30 Column: d
Ancillary services under the Open Access Transmission Tariff (1st Revised Service
Agreement 476) in effect until superseded.
Schedule Page: 328.1 Line No.: 30 Column: f
Long Hollow, WY Switching Station
Schedule Page: 328.1 Line No.: 30 Column: g
Long Hollow, WY Switching Station
Schedule Page: 328.1 Line No.: 30 Column: m
Operating reserve - spinning reserve service. Operating reserve - supplemental reserve
service.
Schedule Page: 328.1 Line No.: 31 Column: c
Iberdrola Renewables, LLC and Utah Associated Municipal Power Systems
Schedule Page: 328.1 Line No.: 31 Column: d
Ancillary services under the Open Access Transmission Tariff (1st Revised Service
Agreement 476) in effect until superseded.
Schedule Page: 328.1 Line No.: 31 Column: f
Long Hollow, WY Switching Station
Schedule Page: 328.1 Line No.: 31 Column: g
Long Hollow, WY Switching Station
Schedule Page: 328.1 Line No.: 31 Column: m
2013 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 32 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.11
Service Agreement 279). Agreement terminating April 30, 2019.
Schedule Page: 328.1 Line No.: 32 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 33 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 279). Agreement terminating April 30, 2019.
Schedule Page: 328.1 Line No.: 33 Column: m
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
Schedule Page: 328.1 Line No.: 34 Column: d
Network transmission service under the Open Access Transmission Tariff (Service Agreement
742) terminating on April 30, 2018.
Schedule Page: 328.1 Line No.: 34 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.: 1 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 1 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreements 697, 698, 699). Agreements terminated in 2013.
Schedule Page: 328.2 Line No.: 1 Column: m
2013 transmission and ancillary services. 2013 annual transmission services true-up
refund.
Schedule Page: 328.2 Line No.: 2 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 1.
Schedule Page: 328.2 Line No.: 3 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 212) terminating May 31, 2019.
Schedule Page: 328.2 Line No.: 3 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 4 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff(8th Revised
Service Agreement 212) terminating May 31, 2019.
Schedule Page: 328.2 Line No.: 4 Column: m
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
Schedule Page: 328.2 Line No.: 5 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 5 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 5 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.: 5 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.12
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Schedule Page: 328.2 Line No.: 6 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 6 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 6 Column: d
Legacy contract (Rate Schedule 257) executed between PacifiCorp and Idaho Power Company
for transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge for the Antelope Substation terminating coterminous with the
Idaho/United States Department of Energy Supply Agreement.
Schedule Page: 328.2 Line No.: 6 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. 2013 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 7 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 7 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 7 Column: d
Legacy contract (Rate Schedule 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.: 7 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.: 8 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 8 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 8 Column: d
Legacy contract (Rate Schedule 203) executed between PacifiCorp and Idaho Power Company
for transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge (Service Agreement 203) for the Bridger Pump Substation. Agreement
terminates upon 12-months written notice.
Schedule Page: 328.2 Line No.: 8 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. 2013 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 9 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 9 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 9 Column: d
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.: 9 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 10 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 10 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 10 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.13
Schedule Page: 328.2 Line No.: 10 Column: m
2013 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 11 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 11 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 11 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 12 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 12 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 12 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 12 Column: m
2013 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
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 13 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 14 Column: a
This footnote applies to all occurrences of "JP Morgan Ventures Energy Corp." on pages
328-330. Complete name is JP Morgan Ventures Energy Corporation.
Schedule Page: 328.2 Line No.: 14 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 14 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 14 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 14 Column: m
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Schedules 4 and 9. Scheduling, system control and dispatch service. Reactive supply and
voltage control service. Generation regulation and frequency response service. Operating
reserve - spinning reserve service. Operating reserve - supplemental reserve service.
Schedule Page: 328.2 Line No.: 15 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 15 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 15 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 15 Column: m
2013 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.14
Schedule Page: 328.2 Line No.: 16 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 16 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 16 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 16 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 17 Column: 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
Transmission resales, amount paid by seller. 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
2013 transmission and ancillary services.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
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
2013 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 21 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 after October 14, 2016, by providing two years written notice.
Schedule Page: 328.2 Line No.: 21 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.15
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.: 22 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 after October 14, 2016, by providing two years written notice.
Schedule Page: 328.2 Line No.: 22 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract. 2013 transmission and ancillary services.
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. Generation regulation and frequency response 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.: 24 Column: m
2013 transmission and ancillary services.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 26 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 26 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 26 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 26 Column: m
2013 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 27 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 Berkshire Hathaway Energy 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.16
Schedule Page: 328.2 Line No.: 27 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 27 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 27 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 27 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 28 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 28 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 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: 328.2 Line No.: 28 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 29 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 29 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 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: 328.2 Line No.: 29 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 30 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.: 30 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.: 30 Column: e
V11-1-3,5-6,7,9
Schedule Page: 328.2 Line No.: 30 Column: m
Penalty revenues covering imbalance charges per Schedules 4 and 9. Scheduling, system
control and dispatch service. Reactive supply and voltage control service. Generation
regulation and frequency response service. Operating reserve - spinning reserve service.
Operating reserve - supplemental reserve service.
Schedule Page: 328.2 Line No.: 31 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.: 31 Column: m
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.17
between various parties and points.
Schedule Page: 328.2 Line No.: 32 Column: m
Unauthorized use of transmission service. 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.
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
2013 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 34 Column: d
Transmission service under the Open Access Transmission Tariff (6th Revised Service
Agreement 299). Service provided pursuant to rules and regulations of Oregon Direct
Access. Agreement termination upon notification pursuant to Oregon Direct Access and Open
Access Transmission Tariff.
Schedule Page: 328.2 Line No.: 34 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.: 1 Column: d
Transmission service under the Open Access Transmission Tariff (6th 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.: 1 Column: m
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
Schedule Page: 328.3 Line No.: 2 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 2 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 2 Column: d
Legacy contract (Rate Schedule 607) executed between PacifiCorp and Pacific Gas & Electric
Company for transmission service over agreed-upon facilities (Malin to Round Mountain)
and/or subject to a sole-use or facilities charge. Terminating December 31, 2017. See
PacifiCorp, Docket No. ER07-882, et al, Settlement Agreement, Appendix 2 (filed November
20, 2007).
Schedule Page: 328.3 Line No.: 2 Column: f
Malin to Indian Springs line segment
Schedule Page: 328.3 Line No.: 2 Column: g
Malin to Indian Springs line segment
Schedule Page: 328.3 Line No.: 2 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
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
Legacy contract (Rate Schedule 607) executed between PacifiCorp and Pacific Gas & Electric
Company for transmission service over agreed-upon facilities (Malin to Round Mountain)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.18
and/or subject to a sole-use or facilities charge. Terminating December 31, 2017. See
PacifiCorp, Docket No. ER07-882, et al, Settlement Agreement, Appendix 2 (filed November
20, 2007).
Schedule Page: 328.3 Line No.: 3 Column: m
2013 transmission and ancillary services. 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.: 4 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 4 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 4 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 February 12, 2020.
Schedule Page: 328.3 Line No.: 4 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.: 5 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 5 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 5 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 5 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 6 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 6 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 6 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 6 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 7 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 7 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 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: 328.3 Line No.: 7 Column: m
2013 transmission and ancillary services.
Schedule Page: 328.3 Line No.: 8 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 8 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 8 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.19
between various parties and points.
Schedule Page: 328.3 Line No.: 8 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 9 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 9 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 9 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 9 Column: m
2013 transmission and ancillary services.
Schedule Page: 328.3 Line No.: 10 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 10 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 10 Column: d
Legacy contract (1st Revised Rate Schedule 137) executed between PacifiCorp and Portland
General Electric for transmission service over agreed-upon facilities and/or subject to a
sole-use or facilities charge for the Dalreed Substation, which terminated December 2013.
Schedule Page: 328.3 Line No.: 10 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Schedule Page: 328.3 Line No.: 11 Column: c
This footnote applies to all occurrences of "Sheridan-Johnson Rural Elect." on pages
328-330. Complete name is Sheridan-Johnson Rural Electric Association.
Schedule Page: 328.3 Line No.: 11 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.: 11 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.: 12 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.: 12 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. 2013 transmission and ancillary services.
Schedule Page: 328.3 Line No.: 13 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.: 13 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.: 13 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 14 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.: 14 Column: m
2013 transmission and ancillary services. 2012 annual transmission services true-up
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.20
charge. 2013 annual transmission services true-up refund.
Schedule Page: 328.3 Line No.: 15 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.: 15 Column: m
Scheduling, system control and dispatch service.
Schedule Page: 328.3 Line No.: 16 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.: 16 Column: m
2013 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER11-3646. 2012 annual transmission services true-up charge. Scheduling,
system control and dispatch service.
Schedule Page: 328.3 Line No.: 17 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.: 17 Column: m
Scheduling, system control and dispatch service.
Schedule Page: 328.3 Line No.: 18 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.: 18 Column: m
2013 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER11-3646. 2012 annual transmission services true-up charge. 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 702) terminating on March 31, 2017.
Schedule Page: 328.3 Line No.: 19 Column: m
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 702) terminating on March 31, 2017.
Schedule Page: 328.3 Line No.: 20 Column: m
2012 annual transmission services true-up charge. 2013 annual transmission services
true-up refund. 2013 annual transmission services true-up refund.
Schedule Page: 328.3 Line No.: 21 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 748) terminating on December 31, 2018.
Schedule Page: 328.3 Line No.: 21 Column: m
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 (Service
Agreement 749) terminating on December 31, 2018.
Schedule Page: 328.3 Line No.: 22 Column: m
Scheduling, system control and dispatch service.
Schedule Page: 328.3 Line No.: 23 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 23 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 23 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 23 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.21
service. Generation regulation and frequency response 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
2013 transmission and ancillary services.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.3 Line No.: 26 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 26 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 26 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 26 Column: m
2013 transmission and ancillary services.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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.
Schedule Page: 328.3 Line No.: 28 Column: m
2013 transmission and ancillary services.
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.22
between various parties and points.
Schedule Page: 328.3 Line No.: 29 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 30 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.: 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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 32 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 32 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 32 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 32 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 33 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 33 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 33 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 33 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.23
2013 transmission and ancillary services.
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
This footnote applies to all occurrences of "Sacramento Municipal Utility Dist" on pages
328-330. Complete name is Sacramento Municipal Utility District.
Schedule Page: 328.4 Line No.: 2 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 751) terminating September 30, 2018.
Schedule Page: 328.4 Line No.: 2 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 3 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 751) terminating September 30, 2018.
Schedule Page: 328.4 Line No.: 3 Column: m
2013 transmission and ancillary services. 2013 annual transmission services true-up
refund.
Schedule Page: 328.4 Line No.: 4 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (Service
Agreement 752) terminating March 31, 2019.
Schedule Page: 328.4 Line No.: 4 Column: m
Extension of commencement date fee.
Schedule Page: 328.4 Line No.: 5 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 765) terminating November 30, 2018.
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. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve 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
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.
Schedule Page: 328.4 Line No.: 7 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 7 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 7 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.24
Schedule Page: 328.4 Line No.: 7 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.: 8 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised
Service Agreement 289) which terminated October 11, 2014.
Schedule Page: 328.4 Line No.: 8 Column: m
2012 annual transmission services true-up charge. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.
Schedule Page: 328.4 Line No.: 9 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 Berkshire Hathaway Energy Company, PacifiCorp's
indirect parent company.
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 d/b/a NV Energy 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.
Schedule Page: 328.4 Line No.: 10 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 10 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 10 Column: d
Legacy contract (Rate Schedule 674) executed between PacifiCorp and Sierra Pacific Power
Company d/b/a NV Energy for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Terminating in September 2022.
Schedule Page: 328.4 Line No.: 10 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. 2013 transmission and ancillary services.
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.
Schedule Page: 328.4 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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
Unauthorized use of transmission service. Penalty revenues covering imbalance charges per
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.25
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.: 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
2013 transmission and ancillary services.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response 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
2013 transmission and ancillary services.
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 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.
Schedule Page: 328.4 Line No.: 17 Column: c
This footnote applies to all occurrences of "Southern California Public Power" on pages
328-330. Complete name is Southern California Public Power Authority.
Schedule Page: 328.4 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.26
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 779) terminating on August 31, 2019.
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 (Service
Agreement 779) terminating on August 31, 2019.
Schedule Page: 328.4 Line No.: 19 Column: m
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
Schedule Page: 328.4 Line No.: 20 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 779) terminating on August 31, 2019.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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
2013 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 23 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
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
Transmission resales, amount paid by seller. Scheduling, system control and dispatch
service. Reactive supply and voltage control service.
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
2013 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.27
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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 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 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
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
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
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
2013 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 30 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.: 30 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.28
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 30 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. Terminated October 1, 2014.
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. Terminated October 1, 2014.
Schedule Page: 328.4 Line No.: 31 Column: m
2013 transmission and ancillary services.
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
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.: 32 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.: 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
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
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: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 34 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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
2013 transmission and ancillary services.
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.29
between various parties and points.
Schedule Page: 328.5 Line No.: 2 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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
2013 transmission and ancillary services.
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. 2013 transmission and
ancillary services. Refunds for transmission services pursuant to FERC Docket No.
ER11-3646. 2013 annual transmission services true-up refund.
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
or facilities charge for energy deliveries at and below 138kV. Agreement terminates any
time after April 1, 2040 with 4 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 4 years written notification.
Schedule Page: 328.5 Line No.: 7 Column: m
2013 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.30
Legacy contract executed between PacifiCorp and Utah Associated Municipal Power Systems
for transmission service over agreed-upon facilities (Third Amended and Restated
Transmission Service and Operating Agreement, Third 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. 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: 328.5 Line No.: 10 Column: d
Legacy contract executed between PacifiCorp and Utah Associated Municipal Power Systems
for transmission service over agreed-upon facilities (Third Amended and Restated
Transmission Service and Operating Agreement, Third 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
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
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. Generation regulation and frequency response 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.
Schedule Page: 328.5 Line No.: 12 Column: m
2013 transmission and ancillary services.
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. Operating reserve - spinning reserve service. Operating
reserve - supplemental reserve 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
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
Schedule Page: 328.5 Line No.: 15 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.31
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.: 15 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.5 Line No.: 16 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.: 16 Column: d
Legacy contract (Rate Schedule 591) executed between PacifiCorp and Warm Springs Power
Enterprises for transmission service over agreed-upon facilities and/or subject to
sole-use or facilities charge. Agreement terminating January 31, 2032.
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.
Schedule Page: 328.5 Line No.: 17 Column: d
Legacy contract (Rate Schedule 591) executed between PacifiCorp and Warm Springs Power
Enterprises for transmission service over agreed-upon facilities and/or subject to
sole-use or facilities charge. Agreement terminating January 31, 2032.
Schedule Page: 328.5 Line No.: 17 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
Schedule Page: 328.5 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
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.: 18 Column: m
Fixed termination fee associated with a contract cancellation applied for the duration of
this agreement.
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 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.: 19 Column: m
Fixed termination fee associated with a contract cancellation applied for the duration of
this agreement. 2013 transmission and ancillary services.
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
138 kV. Agreement termination upon three years after written notice and mutual consent.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.32
Schedule Page: 328.5 Line No.: 20 Column: m
Charges for low-voltage transmission of power and energy.
Schedule Page: 328.5 Line No.: 21 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.5 Line No.: 21 Column: d
Legacy contract (Rate Schedule 263) executed between PacifiCorp and Western Area Power
Administration for transmission and interconnection service over agreed-upon facilities
and/or subject to a sole-use or facilities charge for load service to low voltage
customers for deliveries of power and energy from Salt Lake City Area Integrated Projects,
including the Colorado River Storage Projects, to certain municipalities at service below
138 kV. Agreement termination upon three years after written notice and mutual consent.
Schedule Page: 328.5 Line No.: 21 Column: m
Charges for low-voltage transmission of power and energy. 2013 transmission and ancillary
services.
Schedule Page: 328.5 Line No.: 22 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 22 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.: 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
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.: 24 Column: d
Evergreen network transmission service under the Open Access Transmission Tariff (3rd
Revised Service Agreement 175).
Schedule Page: 328.5 Line No.: 24 Column: m
2013 transmission and ancillary services. 2012 annual transmission services true-up
charge. 2013 annual transmission services true-up refund.
Schedule Page: 328.5 Line No.: 25 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.: 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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.5 Line No.: 27 Column: a
This footnote applies to all occurrences of "Western Area Power Adm. CO MO" 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.33
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.5 Line No.: 28 Column: m
Represents the difference between actual wheeling revenues for the period as reflected on
the individual line items within this schedule, and the accruals credited to Account
456.1, Revenues from transmission of electricity for others, during the period.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
/ /2014/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 1,690,366 1,690,366 548,589 548,589Arizona Public Service 1
NF 317,582 317,582 57,950 57,950Arizona Public Service 2
OS 24,488 15,000 9,488 1 1Arizona Public Service 3
OSArizona Public Service 4
SFP 295,818 295,818 44,735 44,735Arizona Public Service 5
FNS 21,346 21,346 2,227 2,227Ashland, City of 6
FNS 231,694 231,694 66,615 64,411Avista Corporation 7
NF 124,569 124,569 21,589 21,589Avista Corporation 8
NF 20,501 20,501 13,759 13,759Basin Elect. Power Coop 9
OLF 203,014 203,014Big Horn Rural Electric 10
AD -40 -40Black Hills Power, Inc. 11
NF 1,187 1,187 1,187 1,187Black Hills Power, Inc. 12
OS 1,988 1,988Black Hills Power, Inc. 13
SFP 3,968 3,968 625 625Black Hills Power, Inc. 14
AD 292,700 93,509 199,191Bonneville Power Admin 15
FNS 6,781,444 6,781,444Bonneville Power Admin 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332
17,778,500 18,261,782 123,849,237 10,001,730 17,484,757 151,335,724TOTAL
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
/ /2014/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 58,311,815 58,311,815 5,557,956 5,557,956Bonneville Power Admin 1
NF 82,252 82,252 16,597 16,597Bonneville Power Admin 2
OLF 31,631,101 107,740 31,523,361 4,755,610 4,528,946Bonneville Power Admin 3
OS 1,399,869 1,043,744 346,225 9,900 22,289 22,289Bonneville Power Admin 4
OSBonneville Power Admin 5
SFP 7,795,071 7,795,071 1,550,757 1,550,757Bonneville Power Admin 6
AD -192,480 -179,668 -12,812CA Ind. Sys. Operator 7
OS 828,758 828,758CA Ind. Sys. Operator 8
SFP 1,738,060 1,738,060 212,694 212,694CA Ind. Sys. Operator 9
AD 300 300Deseret Gen & Trans 10
LFP 4,693,645 4,693,645 187,792 187,792Deseret Gen & Trans 11
NF 1,134,223 1,134,223 171,099 171,099Deseret Gen & Trans 12
NF 35,184 35,184 39,757 39,757El Paso Electric Co. 13
OS 18,027 18,027El Paso Electric Co. 14
SFP 71,722 71,722 31,582 31,582El Paso Electric Co. 15
OS 76,849 76,849Flathead Elect Coop Inc 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1
17,778,500 18,261,782 123,849,237 10,001,730 17,484,757 151,335,724TOTAL
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
/ /2014/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification(b)
OS 191,074 191,074Hermiston Gen Co L.P. 1
AD -164,930 -58,221 -106,709Idaho Power Company 2
FNS 9,331 9,331Idaho Power Company 3
LFP 5,741,100 5,741,100 2,236,072 1,991,048Idaho Power Company 4
NF 1,162,265 1,162,265 265,309 265,309Idaho Power Company 5
OS 13,417,668 13,428,563 -10,895Idaho Power Company 6
OSIdaho Power Company 7
SFP 436,850 436,850 169,872 169,872Idaho Power Company 8
NF 36,217 36,217 3,357 3,357LA Dept of Water & Pwr 9
OS 5,156 5,156LA Dept of Water & Pwr 10
AD -1,863 -1,863Moon Lake Elect. Assoc. 11
FNS 292,764 292,764Moon Lake Elect. Assoc. 12
LFP 1,599 1,599 13 13Morgan City Corporation 13
AD -254,833 -64,251 -190,582Nevada Power Company 14
NF 267,471 267,471 37,199 37,199Nevada Power Company 15
OS 63,292 63,292Nevada Power Company 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.2
17,778,500 18,261,782 123,849,237 10,001,730 17,484,757 151,335,724TOTAL
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
/ /2014/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification(b)
SFP 198,000 198,000 40,200 40,200Nevada Power Company 1
NF 508,074 508,074 117,304 114,091NorthWestern Corp. 2
OS 35,326 35,326NorthWestern Corp. 3
SFP 217,255 217,255 50,090 50,090NorthWestern Corp. 4
LFP 849,700 849,700 162,547 162,547Platte River Pwr Auth 5
OS 9,299 9,299Platte River Pwr Auth 6
OLF 941 941Portland Gen. Electric 7
LFP 990,630 990,630 87,441 84,355Public Service Co of CO 8
NF 2,732 2,732 490 490Public Service Co of NM 9
OS 1,704 1,704Public Service Co of NM 10
SFP 48,507 48,507 6,770 6,770Public Service Co of NM 11
NF 334,073 334,073 138,112 138,112Salt River Project 12
OS 54,292 54,292Salt River Project 13
NF 72,525 72,525 9,855 9,855Sierra Pacific Power Co 14
OS 14,288 14,288Sierra Pacific Power Co 15
SFP 33,600 33,600 4,177 4,177Sierra Pacific Power Co 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.3
17,778,500 18,261,782 123,849,237 10,001,730 17,484,757 151,335,724TOTAL
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
/ /2014/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)
OLF 8,886 8,886Surprise Valley Electr. 1
LFP 990,630 990,630 42,406 39,315Tri-State Gen & Transm 2
NF 131,348 131,348 32,729 32,729Tri-State Gen & Transm 3
OS 35,071 35,071Tri-State Gen & Transm 4
LFP 596,442 596,442 187,696 187,696Tucson Electric Power 5
NF 27,930 27,930 6,631 6,631Tucson Electric Power 6
OS 62,620 62,620Tucson Electric Power 7
SFP 60,175 60,175 9,306 9,306Tucson Electric Power 8
LFP -3,705,509 -3,705,509Westport Field Svc LLC 9
AD 10,896 3,444 7,452Western Area Power Admn 10
FNS 6,500,251 6,500,251Western Area Power Admn 11
LFP 1,693,333 1,693,333 652,572 652,572Western Area Power Admn 12
NF 641,035 641,035 327,759 327,759Western Area Power Admn 13
OS 1,360,066 1,360,066Western Area Power Admn 14
OSWestern Area Power Admn 15
SFP 880,077 880,077 370,465 370,465Western Area Power Admn 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.4
17,778,500 18,261,782 123,849,237 10,001,730 17,484,757 151,335,724TOTAL
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
/ /2014/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)
-166,655 -166,655Accrual 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.5
17,778,500 18,261,782 123,849,237 10,001,730 17,484,757 151,335,724TOTAL
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, of this Form No. 1.
Schedule Page: 332 Line No.: 10 Column: b
Big Horn Rural Electric Company - contract termination date: March 10, 2015.
Schedule Page: 332 Line No.: 10 Column: g
Use of facilities.
Schedule Page: 332 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 11 Column: e
Settlement adjustment.
Schedule Page: 332 Line No.: 13 Column: g
Ancillary services.
Schedule Page: 332 Line No.: 15 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 15 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.1 Line No.: 1 Column: b
Bonneville Power Administration - contract termination dates: January 1, 2016; July 1,
2016; September 1, 2016; November 1, 2016; December 1, 2016; April 1, 2017; July 1, 2017;
November 1, 2017; September 1, 2018; October 1, 2018; December 1, 2018; January 1, 2019;
July 1, 2019; September 1, 2019; October 1, 2019; November 1, 2019; December 1, 2019;
November 1, 2020; October 1, 2027; November 1, 2033; and evergreen.
Schedule Page: 332.1 Line No.: 3 Column: b
Bonneville Power Administration - contract termination dates: December 31, 2018; September
30, 2027; and evergreen.
Schedule Page: 332.1 Line No.: 3 Column: g
Use of facilities.
Schedule Page: 332.1 Line No.: 4 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.1 Line No.: 5 Column: b
Bonneville Power Administration - Legacy contract executed between PacifiCorp and
Bonneville Power Administration concerning the exchange of transmission services over
agreed-upon facilities ("Midpoint-Meridian Transmission Agreement", Rate Schedule 369).
This agreement runs concurrently with the AC Intertie Agreement (Rate Schedule 368), which
terminates when the facilities subject to that agreement are taken out of service. See
also page 328, Transmission of electricity for others, of this Form No. 1.
Schedule Page: 332.1 Line No.: 7 Column: a
This footnote applies to all occurrences of "CA Ind. Sys. Operator" on page 332. Complete
name is California Independent System Operator Corporation.
Schedule Page: 332.1 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 332.1 Line No.: 7 Column: f
Settlement adjustment.
Schedule Page: 332.1 Line No.: 7 Column: g
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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 332.1 Line No.: 8 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 332.1 Line No.: 11 Column: b
Deseret Generation & Transmission Cooperative - contract termination dates: January 1,
2018 and September 1, 2018.
Schedule Page: 332.1 Line No.: 14 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 16 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 1 Column: a
Hermiston Generating Company, L.P. operates the Hermiston Generating Plant, which is
jointly owned. PacifiCorp owns 50% of the plant.
Schedule Page: 332.2 Line No.: 1 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 332.2 Line No.: 2 Column: e
Settlement adjustment.
Schedule Page: 332.2 Line No.: 2 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 4 Column: b
Idaho Power Company - contract termination dates: April 1, 2025 and July 1, 2025.
Schedule Page: 332.2 Line No.: 6 Column: e
Credit for unreserved use.
Schedule Page: 332.2 Line No.: 6 Column: g
Ancillary services. Use of facilities. PacifiCorp's portion of specified costs of certain
facilities.
Schedule Page: 332.2 Line No.: 7 Column: b
Idaho Power Company - Legacy contract (Rate Schedule 427) executed between PacifiCorp and
Idaho Power Company concerning the exchange of transmission services over agreed-upon
facilities (Draft Transmission Services Agreement between PacifiCorp and Idaho Power
Company, Draft 1 – 5/19/95 (“Goshen Agreement”)). Termination of this agreement occurs at
the end of the calendar month following the earlier of the effectiveness of a replacement
contract, or upon three years written notice of termination as long as PacifiCorp has
facilities in place to serve PacifiCorp's Big Grassy load. See also page 328, Transmission
of electricity for others, of this Form No. 1.
Schedule Page: 332.2 Line No.: 9 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.: 10 Column: g
Ancillary services.
Schedule Page: 332.2 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 332.2 Line No.: 11 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 12 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 13 Column: b
Morgan City Corporation - contract termination date: Evergreen.
Schedule Page: 332.2 Line No.: 14 Column: a
This footnote applies to all occurrences of "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 Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
company.
Schedule Page: 332.2 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 332.2 Line No.: 14 Column: e
Settlement adjustment.
Schedule Page: 332.2 Line No.: 14 Column: g
Imbalance energy.
Schedule Page: 332.2 Line No.: 16 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 3 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 5 Column: b
Platte River Power Authority - contract termination date: October 31, 2017.
Schedule Page: 332.3 Line No.: 6 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 7 Column: b
Portland General Electric Company - contract termination date: Upon two years written
notice.
Schedule Page: 332.3 Line No.: 7 Column: g
Use of facilities.
Schedule Page: 332.3 Line No.: 8 Column: b
Public Service Company of Colorado - contract termination date: The date that all
generating plants comprising PacifiCorp resources associated with this agreement have been
retired from service or interests transferred.
Schedule Page: 332.3 Line No.: 10 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 13 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 14 Column: a
This footnote applies to all occurrences of "Sierra Pacific Power Co" on page 332. Sierra
Pacific Power Company is a principal subsidiary of NV Energy, Inc., which is an indirect
wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
company.
Schedule Page: 332.3 Line No.: 15 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 1 Column: b
Surprise Valley Electrification Corp. - contract termination date: Evergreen.
Schedule Page: 332.4 Line No.: 1 Column: g
Use of facilities.
Schedule Page: 332.4 Line No.: 2 Column: b
Tri-State Generation and Transmission Association, Inc. - contract termination date: The
date that all generating plants comprising PacifiCorp resources associated with this
agreement have been retired from service or interests transferred.
Schedule Page: 332.4 Line No.: 4 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 5 Column: b
Tucson Electric Power Company - contract termination date: December 1, 2015.
Schedule Page: 332.4 Line No.: 7 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 9 Column: b
Westport Field Services, LLC - contract termination date: Evergreen.
Schedule Page: 332.4 Line No.: 9 Column: e
Reimbursement for third-party services provided.
Schedule Page: 332.4 Line No.: 10 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Settlement adjustment.
Schedule Page: 332.4 Line No.: 10 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 12 Column: b
Western Area Power Administration - contract termination date: May 31, 2022.
Schedule Page: 332.4 Line No.: 14 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.4 Line No.: 15 Column: b
Western Area Power Administration - Legacy contract (Rate Schedule 664) executed between
PacifiCorp and Western Area Power Administration concerning the exchange of transmission
services over agreed-upon facilities. The contract terminates 50 years from execution. See
also page 328, Transmission of electricity for others, of this Form No. 1.
Schedule Page: 332.5 Line No.: 1 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
PacifiCorp X / /2014/Q4
Line Description Amount
(b)(a)No.
1,114,980Industry Association Dues 1
Nuclear Power Research Expenses 2
Other Experimental and General Research Expenses 3
Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 4
Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 5
6
Community & Economic Development and 7
Corporate Memberships & Subscriptions: 8
5,000Albina Opportunities Corporation 9
5,000American Leadership Forum of Oregon 10
13,782American Wind Energy Association 11
28,000Associated Oregon Industries 12
7,000Carbon County Economic Development Corporation 13
5,000Clatsop Economic Development Resources 14
5,000Eastern Idaho Economic Development Partners 15
19,000Economic Development Corporation of Utah 16
8,000Economic Development for Central Oregon 17
6,061Equal Employment Advisory Council 18
10,000Four County Economic Development Corporation 19
9,000Intermountain Electrical Association 20
5,000Klamath County Economic Development Association 21
13,900Oregon Business Association 22
31,378Oregon Business Council 23
7,500Oregon Economic Development Association 24
5,000Oregon Sports Authority 25
15,000Oregon State University Utility Pole Research Coop 26
5,000Oregon Tourism Commission 27
37,300Portland Business Alliance 28
7,000Redmond Economic Development, Inc. 29
18,000Rocky Mountain Electrical League 30
27,230Salt Lake Area Chamber of Commerce 31
5,000Siskiyou County Economic Development Council, Inc. 32
5,000South Coast Development Council, Inc. 33
5,000Southern Oregon Regional Economic Development, Inc. 34
6,400Strategic Economic Development Corporation 35
5,000Utah Alliance for Economic Development 36
6,600Utah Manufacturers Association 37
18,700Utah Taxpayers Association 38
5,000Webster Global Site Selectors 39
44,901Western Energy Institute 40
25,660Western Energy Supply and Transmission Associates 41
7,000Wyoming Business Alliance 42
5,000Wyoming Business Council 43
11,199Wyoming Taxpayers Association 44
7,500Yakima County Development Association 45
2,426,050
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 / /2014/Q4
Line Description Amount
(b)(a)No.
196,494Other (Individually < $5,000) 6
7
15,754Directors' Fees - Regional Advisory Board 8
9
Rating Agency and Trustee Fees: 10
133,054The Bank of New York Mellon 11
-17,059Computershare Shareowner Services, LLC 12
41,347Fitch, Inc. 13
157,296Moody's Investors Service, Inc. 14
222,903Standard and Poor's Financial Services, LLC 15
10,303U.S. Bank National Association 16
8,540United States Securities and Exchange Commission 17
1,200Financial Industry Regulatory Authority, Inc. 18
19
Regulatory Asset Amortization: 20
35,000Generating Plant Liquidated Damages - UT 21
54,288Generating Plant Liquidated Damages - WY 22
23
General: 24
839Other 25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
2,426,050
FERC FORM NO. 1 (ED. 12-94) Page 335.1
46 TOTAL
Schedule Page: 335.1 Line No.: 12 Column: b
Represents the difference between actual expense for the period and the accruals charged
to Account 930.2, Miscellaneous general expenses, during the period for Computershare
Shareowner Services, 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
2014/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
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
PacifiCorp X
/ /2014/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)
39,290,397 39,290,397 1 Intangible Plant
248,248,020 248,248,020 2 Steam Production Plant
3 Nuclear Production Plant
32,297,592 32,023,230 274,362 4 Hydraulic Production Plant-Conventional
5 Hydraulic Production Plant-Pumped Storage
117,620,076 117,620,076 6 Other Production Plant
92,085,625 92,085,625 7 Transmission Plant
133,686,007 133,686,007 8 Distribution Plant
9 Regional Transmission and Market Operation
40,653,484 39,508,869 1,144,615 10 General Plant
11 Common Plant-Electric
703,881,201 663,171,827 40,709,374 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
/ /2014/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)
STEAM PRODUCTION 12
Blundell Plant 13
46.97 2.09 24.00310.20 UT 35,883 14
42.30 -4.00 2.51 23.30311.00 UT 8,248 15
34.11 -3.00 2.98 22.20312.00 UT 57,994 16
32.76 -5.00 3.30 21.50314.00 UT 33,932 17
39.15 -3.00 2.70 23.10315.00 UT 7,526 18
29.19 -5.00 3.76 19.30316.00 UT 1,261 19
20
Carbon Plant 21
14.49 -17.00 40.37 1.30311.00 UT 15,579 22
9.82 -17.00 44.69 1.30312.00 UT 68,203 23
10.45 -17.00 45.16 1.30314.00 UT 28,155 24
10.50 -17.00 45.76 1.30315.00 UT 6,302 25
6.67 -17.00 56.80 1.30316.00 UT 809 26
27
Cholla Plant 28
34.48 2.89 29.00310.20 AZ 1,368 29
45.93 -6.00 2.34 28.00311.00 AZ 64,092 30
37.41 -5.00 2.89 26.20312.00 AZ 333,544 31
38.37 -7.00 2.85 24.80314.00 AZ 67,730 32
46.05 -5.00 2.32 27.30315.00 AZ 67,923 33
33.53 -7.00 3.31 21.40316.00 AZ 4,094 34
35
Colstrip Plant 36
55.79 -6.00 1.88 31.50311.00 MT 60,705 37
47.52 -6.00 2.24 28.10312.00 MT 118,087 38
41.60 -8.00 2.61 27.30314.00 MT 37,925 39
56.37 -5.00 1.83 30.00315.00 MT 9,051 40
36.94 -7.00 2.90 22.90316.00 MT 321 41
42
Craig Plant 43
48.45 -6.00 2.11 20.40311.00 CO 37,497 44
34.51 -5.00 3.00 19.40312.00 CO 95,910 45
31.03 -7.00 3.50 19.10314.00 CO 28,475 46
49.53 -5.00 2.04 19.80315.00 CO 16,995 47
34.18 -7.00 3.11 16.50316.00 CO 1,226 48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337
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
/ /2014/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)
Dave Johnston Plant 12
53.86 2.30 14.00310.20 WY 100 13
20.39 -4.00 5.56 13.80311.00 WY 155,554 14
19.99 -4.00 5.69 13.60312.00 WY 670,321 15
24.19 -5.00 4.82 13.20314.00 WY 94,804 16
20.04 -3.00 5.67 13.80315.00 WY 62,233 17
18.11 -4.00 6.03 12.60316.00 WY 8,418 18
19
Gadsby Plant 20
43.40 -15.00 2.02 18.60311.00 UT 15,103 21
39.12 -13.00 2.22 17.50312.00 UT 38,758 22
37.19 -15.00 2.43 16.80314.00 UT 19,657 23
34.93 -14.00 2.87 18.30315.00 UT 8,341 24
29.04 -13.00 3.17 15.80316.00 UT 458 25
26
Hayden Plant 27
23.54 -5.00 4.62 16.70311.00 CO 17,684 28
30.98 -5.00 3.14 16.00312.00 CO 54,659 29
27.79 -6.00 3.69 15.80314.00 CO 9,301 30
48.38 -5.00 1.74 16.10315.00 CO 2,546 31
30.28 -6.00 3.22 14.20316.00 CO 637 32
33
Hunter Plant 34
60.93 1.61 29.00310.20 UT 246 35
55.00 -7.00 1.93 27.80311.00 UT 206,744 36
38.55 -6.00 2.79 26.10312.00 UT 750,440 37
34.57 -8.00 3.17 25.60314.00 UT 191,922 38
53.28 -6.00 1.97 26.70315.00 UT 106,650 39
35.58 -8.00 3.08 20.80316.00 UT 3,691 40
41
Huntington Plant 42
45.56 -7.00 2.39 22.30311.00 UT 119,464 43
29.78 -6.00 3.64 21.60312.00 UT 547,010 44
31.75 -7.00 3.43 20.80314.00 UT 121,652 45
39.00 -6.00 2.78 22.00315.00 UT 47,353 46
27.99 -7.00 3.96 18.70316.00 UT 2,866 47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
Camas Co-Gen Plant 12
19.19 6.42 2.00311.00 WA 5,734 13
18.98 6.51 2.00312.00 WA 5,798 14
18.76 6.64 2.00314.00 WA 18,616 15
19.01 6.48 2.00315.00 WA 4,304 16
17
Jim Bridger Plant 18
61.28 1.36 24.00310.20 WY 281 19
51.14 -8.00 1.87 23.20311.00 WY 139,956 20
35.97 -7.00 2.86 22.00312.00 WY 699,179 21
31.25 -8.00 3.36 21.70314.00 WY 201,832 22
49.15 -7.00 1.93 22.40315.00 WY 60,807 23
33.02 -8.00 3.12 18.50316.00 WY 4,115 24
25
Naughton Plant 26
66.74 1.45 16.00310.20 WY 15 27
24.81 -5.00 4.34 15.80311.00 WY 118,149 28
22.44 -4.00 4.81 15.40312.00 WY 496,398 29
25.92 -6.00 4.17 15.00314.00 WY 77,837 30
21.19 -4.00 5.13 15.80315.00 WY 62,960 31
21.86 -6.00 5.15 13.90316.00 WY 2,011 32
33
Wyodak Plant 34
57.58 1.65 26.00310.20 WY 165 35
51.08 -5.00 2.01 25.10311.00 WY 51,286 36
34.28 -4.00 3.09 23.90312.00 WY 300,425 37
34.60 -6.00 3.12 22.90314.00 WY 63,689 38
42.62 -4.00 2.44 24.60315.00 WY 28,510 39
26.65 -6.00 4.07 21.10316.00 WY 1,211 40
41
HYDRAULIC 42
Ashton/St. Anthony 43
40.48 2.79 14.00330.20 ID 29 44
34.65 -2.00 3.33 13.80331.00 ID 2,009 45
17.43 -1.00 6.19 13.90332.00 ID 28,077 46
35.43 -2.00 3.21 13.60333.00 ID 1,958 47
30.80 -3.00 3.77 13.00334.00 ID 1,241 48
41.77 -1.00 2.82 13.20335.00 ID 8 49
96.08 -5.00 1.64 13.50336.00 ID 6 50
FERC FORM NO. 1 (REV. 12-03) Page 337.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
Bear River 12
115.28 1.38 19.80330.20 ID 6 13
38.54 -3.00 3.09 19.30331.00 ID 4,807 14
34.60 -2.00 3.31 19.60332.00 ID 26,197 15
33.28 -4.00 3.50 19.20333.00 ID 11,045 16
30.59 -4.00 3.79 18.20334.00 ID 4,422 17
42.57 -1.00 2.73 18.50335.00 ID 82 18
40.28 -3.00 2.94 19.40336.00 ID 844 19
20
Bend 21
32.00 2.09 3.00331.00 OR 57 22
8.74 17.64 3.00332.00 OR 767 23
18.04 -1.00 6.79 3.00333.00 OR 97 24
25.63 3.53 3.00334.00 OR 628 25
15.79 3.38 3.00335.00 OR 15 26
86.23336.00 OR 27
28
Big Fork 29
52.37 -5.00 1.41 38.30331.00 MT 606 30
53.78 -4.00 1.29 38.70332.00 MT 4,686 31
50.44 -8.00 1.46 37.20333.00 MT 1,496 32
46.04 -8.00 1.52 33.00334.00 MT 404 33
45.15 -4.00 2.13 38.40336.00 MT 232 34
35
Cutler 36
8.34330.20 UT 1 37
96.37 3.11 11.00330.30 UT 5 38
74.44 3.33 11.00330.40 UT 91 39
28.62 -1.00 5.06 10.80331.00 UT 3,970 40
30.30 -1.00 5.01 10.80332.00 UT 9,130 41
17.15 -1.00 7.18 10.90333.00 UT 12,001 42
17.22 -2.00 7.29 10.60334.00 UT 2,598 43
36.34 -1.00 4.52 10.60335.00 UT 11 44
35.14 -1.00 4.54 10.80336.00 UT 572 45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
Eagle Point 12
68.49330.20 OR 12 13
33.98 -1.00 1.31 11.90331.00 OR 138 14
33.88 -1.00 1.25 11.90332.00 OR 1,235 15
42.71 -4.00 0.31 11.80333.00 OR 252 16
25.76 -2.00 2.68 11.50334.00 OR 126 17
24.29 -1.00 2.96 11.90336.00 OR 136 18
19
Granite 20
25.43 -2.00 4.42 16.70331.00 UT 535 21
30.19 -1.00 3.60 16.80332.00 UT 3,768 22
38.99 -4.00 3.06 16.30333.00 UT 721 23
31.63 -3.00 3.63 15.60334.00 UT 210 24
48.73 -2.00 2.45 16.00335.00 UT 1 25
26
Klamath River 27
24.88 7.02 7.00330.20 CA/OR 639 28
48.84 5.27 7.00330.40 CA/OR 253 29
21.42 -1.00 7.87 6.90331.00 CA/OR 913 30
40.24 -1.00 5.79 6.90332.00 CA/OR 11,773 31
43.09 -3.00 5.84 6.70333.00 CA/OR 315 32
19.24 -1.00 8.32 6.80334.00 CA/OR 874 33
29.11 -1.00 6.92 6.80335.00 CA/OR 62 34
23.60 -1.00 7.41 6.90336.00 CA/OR 241 35
36
Klamath River Accel 37
3.60 5.00330.20 CA/OR 41 38
3.61 5.00330.40 CA/OR 1 39
7.78 5.00331.00 CA/OR 14,420 40
7.26 5.00332.00 CA/OR 35,252 41
7.65 5.00333.00 CA/OR 17,824 42
8.82 5.00334.00 CA/OR 15,801 43
6.38 5.00335.00 CA/OR 183 44
7.35 5.00336.00 CA/OR 2,567 45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
Last Chance 12
35.19 -1.00 3.45 11.80331.00 ID 448 13
29.40 -1.00 4.03 11.90332.00 ID 959 14
36.38 -2.00 3.35 11.70333.00 ID 1,068 15
22.78 -2.00 5.03 11.40334.00 ID 266 16
40.81 -1.00 3.07 11.80336.00 ID 65 17
18
Lifton 19
99.80 1.87 20.00330.20 ID 21 20
92.81 1.93 20.00330.30 ID 24 21
51.97 -4.00 2.80 19.10331.00 ID 1,224 22
40.45 -3.00 3.17 19.50332.00 ID 8,270 23
26.40 -2.00 4.13 19.70333.00 ID 7,875 24
36.10 -4.00 3.53 18.00334.00 ID 302 25
46.32 -2.00 2.97 18.30335.00 ID 3 26
29.39 -2.00 3.83 19.60336.00 ID 187 27
28
Merwin 29
121.57 0.50 45.00330.20 WA 301 30
125.02 0.48 45.00330.50 WA 212 31
48.18 -4.00 2.11 42.90331.00 WA 87,942 32
54.60 -6.00 1.83 43.10332.00 WA 28,047 33
65.82 -16.00 1.44 37.20333.00 WA 7,963 34
44.36 -8.00 2.34 36.30334.00 WA 10,481 35
48.09 -3.00 2.07 38.40335.00 WA 169 36
59.30 -5.00 1.62 42.40336.00 WA 2,978 37
38
North Umpqua 39
27.53 -2.00 3.82 24.40331.00 OR 30,289 40
38.59 -2.00 2.90 24.40332.00 OR 197,618 41
34.44 -4.00 3.27 24.00333.00 OR 24,650 42
29.42 -4.00 3.75 22.60334.00 OR 16,743 43
36.23 -2.00 3.05 22.90335.00 OR 722 44
41.97 -3.00 2.73 24.20336.00 OR 8,666 45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
Olmsted 12
31.23 -1.00 5.97 3.00331.00 UT 188 13
13.70 9.28 3.00334.00 UT 29 14
33.94 4.47 3.00335.00 UT 3 15
11.31 12.71 3.00336.00 UT 13 16
17
Paris 18
10.31 10.16 4.00331.00 ID 110 19
46.25 -1.00332.00 ID 96 20
31.74 -1.00333.00 ID 73 21
14.62 -1.00 4.90 4.00334.00 ID 151 22
34.25335.00 ID 23
24
Pioneer 25
134.02 1.09 17.00330.20 UT 9 26
133.34 1.09 17.00330.30 UT 111 27
32.02 -2.00 3.54 16.60331.00 UT 508 28
37.80 -2.00 2.97 16.70332.00 UT 8,128 29
25.26 -2.00 4.31 16.70333.00 UT 1,616 30
30.51 -3.00 3.67 15.60334.00 UT 544 31
39.03 -1.00 2.85 16.00335.00 UT 10 32
21.11 -1.00 5.17 16.70336.00 UT 54 33
34
Prospect #1, 2 & 4 35
56.24 2.02 25.30330.20 OR 4 36
102.16 1.36 24.90330.40 OR 3 37
40.66 -3.00 2.77 24.20331.00 OR 3,873 38
32.55 -2.00 3.27 24.60332.00 OR 31,103 39
35.11 -4.00 3.18 24.00333.00 OR 3,898 40
33.85 -5.00 3.34 22.20334.00 OR 6,786 41
35.19 -2.00 3.05 23.10335.00 OR 19 42
39.57 -3.00 2.84 24.20336.00 OR 339 43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.6
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
Prospect #3 12
21.27 5.46 5.00331.00 OR 636 13
25.67 4.15 5.00332.00 OR 4,228 14
21.89 4.76 5.00333.00 OR 1,809 15
21.02 -1.00 5.25 4.90334.00 OR 1,887 16
25.01 4.22 4.90335.00 OR 63 17
36.09 -1.00 3.29 5.00336.00 OR 117 18
19
Santa Clara 20
23.79 -1.00 5.05 6.90331.00 UT 180 21
24.52 -1.00 4.92 7.00332.00 UT 1,139 22
26.11 -1.00 4.44 6.90333.00 UT 464 23
20.82 -1.00 5.46 6.80334.00 UT 692 24
32.24 -1.00 3.62 6.80335.00 UT 8 25
80.51 -2.00 1.79 6.80336.00 UT 22 26
27
Stairs 28
39.40 -3.00 2.38 16.60331.00 UT 181 29
28.73 -2.00 3.56 16.80332.00 UT 811 30
36.73 -3.00 2.52 16.50333.00 UT 518 31
33.10 -3.00 2.83 15.60334.00 UT 176 32
19.20 -1.00 5.08 16.80336.00 UT 33 33
34
Swift 35
99.73 0.86 45.00330.20 WA 6,277 36
98.01 0.88 45.00330.50 WA 97 37
46.22 -4.00 2.26 43.00331.00 WA 69,952 38
70.57 -7.00 1.40 42.00332.00 WA 46,648 39
65.49 -16.00 1.63 37.00333.00 WA 16,298 40
45.90 -8.00 2.29 35.90334.00 WA 7,786 41
64.91 -5.00 1.46 34.20335.00 WA 411 42
52.23 -5.00 1.98 42.70336.00 WA 1,133 43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
Viva Naughton 12
49.70 -3.00 2.15 26.10331.00 WY 403 13
51.79 -2.00 2.04 26.30332.00 WY 104 14
49.03 -7.00 2.26 25.10333.00 WY 497 15
42.11 -6.00 2.63 23.20334.00 WY 170 16
46.04 -2.00 2.29 24.30335.00 WY 21 17
18
Wallowa Falls 19
23.24 4.41 3.00331.00 OR 168 20
23.14 4.39 3.00332.00 OR 909 21
15.16 9.10 3.00333.00 OR 743 22
18.38 4.99 3.00334.00 OR 731 23
20.11 4.76 3.00336.00 OR 649 24
25
Weber 26
34.24 -1.00 3.55 6.90331.00 UT 368 27
32.11 -1.00 3.90 6.90332.00 UT 1,865 28
28.58 -1.00 4.14 6.90333.00 UT 943 29
12.47 -1.00 9.75 6.80334.00 UT 258 30
28.45 3.97 6.80335.00 UT 22 31
25.64 -1.00 4.36 6.90336.00 UT 40 32
33
Yale 34
103.77 0.82 45.00330.20 WA 762 35
62.83 -6.00 1.60 42.10331.00 WA 9,215 36
70.68 -8.00 1.40 41.80332.00 WA 29,588 37
63.81 -15.00 1.68 37.70333.00 WA 12,493 38
48.93 -9.00 2.14 35.00334.00 WA 3,398 39
66.44 -5.00 1.40 33.00335.00 WA 547 40
57.33 -5.00 1.76 42.50336.00 WA 1,471 41
42
OTHER PRODUCTION 43
Chehalis 44
39.75 -3.00 2.65 29.50341.00 WA 23,908 45
36.50 -2.00 2.87 26.90342.00 WA 1,597 46
35.70 -4.00 3.04 26.80343.00 WA 200,171 47
36.45 -4.00 2.94 26.90344.00 WA 69,031 48
39.21 -3.00 2.69 29.20345.00 WA 39,287 49
38.83 -1.00 2.66 28.80346.00 WA 3,269 50
FERC FORM NO. 1 (REV. 12-03) Page 337.8
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
Currant Creek 12
39.83 -3.00 2.59 31.50341.00 UT 44,165 13
36.50 -2.00 2.80 28.70342.00 UT 3,300 14
35.19 -4.00 3.01 28.80343.00 UT 212,744 15
36.06 -4.00 2.91 28.80344.00 UT 62,977 16
39.03 -3.00 2.64 31.20345.00 UT 42,568 17
39.06 -1.00 2.59 30.70346.00 UT 2,983 18
19
Hermiston 20
38.73 -3.00 2.90 22.60341.00 OR 12,845 21
36.50 -2.00 3.08 20.70342.00 OR 25 22
33.48 -4.00 3.42 20.80343.00 OR 108,844 23
35.85 -3.00 3.16 20.80344.00 OR 42,463 24
39.23 -3.00 2.88 22.40345.00 OR 9,293 25
39.06 -1.00 2.84 22.00346.00 OR 169 26
27
Lake Side/Lake Side 2 28
39.96 -4.00 2.77 33.50341.00 UT 88,355 29
36.50 -3.00 3.01 30.60342.00 UT 8,501 30
36.11 -4.00 3.11 30.40343.00 UT 534,347 31
36.40 -4.00 3.05 30.60344.00 UT 221,933 32
39.46 -3.00 2.77 33.10345.00 UT 119,178 33
39.06 -1.00 2.75 32.70346.00 UT 6,150 34
35
Gadsby Gas Peakers 36
29.80 -1.00 3.43 18.90341.00 UT 4,273 37
28.45 -1.00 3.61 18.00342.00 UT 2,447 38
26.97 -2.00 3.91 18.10343.00 UT 54,922 39
28.61 -2.00 3.64 18.00344.00 UT 16,886 40
28.31 -1.00 3.62 18.80345.00 UT 2,877 41
42
WIND GENERATION 43
Dunlap Ranch I 44
28.47 -1.00 3.49 25.30341.00 WY 7,742 45
29.58 -1.00 3.34 26.20343.00 WY 207,519 46
29.59 -1.00 3.34 26.20344.00 WY 6,565 47
29.93 3.26 26.50345.00 WY 12,293 48
29.94 3.25 26.50346.00 WY 149 49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.9
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
Foote Creek 12
29.33 -1.00 3.49 15.30341.00 WY 110 13
30.37 -1.00 2.84 15.50343.00 WY 31,950 14
30.49 -1.00 2.83 15.50344.00 WY 1,612 15
30.96 -1.00 2.78 15.70345.00 WY 2,926 16
17
Glenrock/Glenrock III 18
27.88 -1.00 3.53 23.50341.00 WY 10,198 19
29.01 -1.00 3.37 24.30343.00 WY 438,311 20
29.01 -1.00 3.37 24.30344.00 WY 13,560 21
29.33 3.30 24.60345.00 WY 29,513 22
29.44 3.28 24.60346.00 WY 1,157 23
24
Goodnoe Hills 25
28.49 -1.00 3.44 23.50341.00 WA 5,484 26
29.53 -1.00 3.30 24.30343.00 WA 162,588 27
29.46 -1.00 3.31 24.30344.00 WA 4,407 28
29.73 3.24 24.50345.00 WA 10,170 29
29.94 3.21 24.50346.00 WA 172 30
31
High Plains / McFadden 32
28.46 -1.00 3.47 24.40341.00 WY 7,815 33
29.57 -1.00 3.32 25.20343.00 WY 245,688 34
29.59 -1.00 3.32 25.20344.00 WY 6,963 35
29.92 3.23 25.50345.00 WY 14,750 36
29.94 3.23 25.50346.00 WY 114 37
38
Leaning Juniper 1 39
28.49 -1.00 3.39 21.70341.00 OR 4,955 40
29.47 -1.00 3.25 22.30343.00 OR 157,209 41
29.36 -1.00 3.28 22.30344.00 OR 5,493 42
29.70 -1.00 3.23 22.60345.00 OR 9,162 43
29.94 3.16 22.60346.00 OR 81 44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.10
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
Marengo/Marengo II 12
28.15 -1.00 3.47 22.60341.00 WA 10,220 13
29.23 -1.00 3.32 23.30343.00 WA 327,182 14
29.22 -1.00 3.32 23.30344.00 WA 10,398 15
29.57 -1.00 3.27 23.60345.00 WA 19,742 16
29.48 3.25 23.60346.00 WA 337 17
18
Seven Mile Hill 19
28.38 -1.00 3.45 23.50341.00 WY 6,392 20
29.56 -1.00 3.29 24.30343.00 WY 215,374 21
29.59 -1.00 3.29 24.30344.00 WY 6,600 22
29.86 3.22 24.50345.00 WY 13,260 23
29.78 3.23 24.50346.00 WY 520 24
25
SOLAR GENERATING 26
Wyoming Solar 27
20.46 4.11 14.00344.00 WY 6 28
20.42344.00 WY 55 29
30
Utah Solar 31
20.49344.00 UT 36 32
33
Oregon Solar 34
19.88344.00 OR 56 35
36
MOBILE GENERATOR 37
East Side 38
50.00 -5.00 1.60 42.50R2344.00 UT 840 39
40
West Side 41
50.00 -5.00 1.80 46.00R2344.00 OR 849 42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.11
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
TRANSMISSION PLANT 12
75.00 1.27 63.50R4350.20 177,590 13
75.00 -10.00 1.42 66.40R2.5352.00 210,411 14
58.00 -5.00 1.74 48.90S0353.00 1,853,585 15
68.00 -10.00 1.53 55.70R4354.00 1,217,800 16
60.00 -40.00 2.18 46.10R2355.00 733,629 17
63.00 -30.00 1.88 46.00R3356.00 1,073,715 18
60.00 1.60 48.50R2357.00 3,520 19
60.00 -5.00 1.66 48.20R2358.00 8,035 20
70.00 1.32 49.40R5359.00 11,937 21
22
DISTRIBUTION PLANT 23
55.00 1.21 36.80S3360.20 OR 4,644 24
60.00 -10.00 1.79 49.80R1.5361.00 OR 25,770 25
55.00 -15.00 1.94 43.50R1362.00 OR 230,331 26
55.00 -100.00 3.29 42.00R1.5364.00 OR 353,395 27
60.00 -70.00 2.63 47.40R0.5365.00 OR 246,995 28
70.00 -50.00 1.97 54.60R2.5366.00 OR 89,813 29
58.00 -35.00 2.11 43.70R2.5367.00 OR 168,094 30
42.00 -20.00 2.44 29.00R1.5368.00 OR 415,551 31
55.00 -35.00 2.28 42.50R1369.10 OR 82,671 32
55.00 -40.00 2.34 41.30R4369.20 OR 165,785 33
27.00 -4.00 3.60 17.90R1370.00 OR 60,387 34
25.00 -50.00 4.79 14.30L0371.00 OR 2,573 35
44.00 -40.00 2.91 33.80R0.5373.00 OR 22,931 36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.12
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
DISTRIBUTION PLANT 12
50.00 1.63 24.50R3360.20 WA 409 13
60.00 -5.00 1.64 42.10R2361.00 WA 2,816 14
53.00 -20.00 2.14 38.90R1362.00 WA 56,847 15
52.00 -100.00 3.64 39.40R1.5364.00 WA 97,325 16
60.00 -60.00 2.51 45.10R1365.00 WA 62,120 17
50.00 -50.00 2.84 35.40R3366.00 WA 17,190 18
50.00 -35.00 2.56 36.80R3367.00 WA 24,164 19
43.00 -25.00 2.64 28.90R2368.00 WA 104,828 20
55.00 -30.00 2.27 41.90R1369.10 WA 20,611 21
55.00 -50.00 2.63 41.30R4369.20 WA 36,049 22
25.00 -1.00 3.93 21.20S5370.00 WA 11,708 23
30.00 -25.00 3.48 15.50L0371.00 WA 512 24
45.00 -30.00 2.64 31.70R1373.00 WA 4,218 25
26
DISTRIBUTION PLANT 27
50.00 1.99 33.50R4360.20 WY 5,200 28
60.00 -10.00 1.83 49.90R2.5361.00 WY 14,949 29
55.00 -10.00 1.99 42.20R1362.00 WY 126,365 30
50.00 -100.00 3.99 39.10R1364.00 WY 140,570 31
57.00 -40.00 2.45 44.20R0.5365.00 WY 104,291 32
42.00 -40.00 3.32 30.60R3366.00 WY 23,881 33
40.00 -35.00 3.35 26.20R4367.00 WY 56,808 34
39.00 -25.00 3.19 28.90R1368.00 WY 110,125 35
60.00 -25.00 2.08 47.20R1.5369.10 WY 17,925 36
55.00 -50.00 2.72 44.10R4369.20 WY 39,409 37
25.00 -2.00 4.04 20.60S5370.00 WY 14,526 38
25.00 -60.00 6.10 12.20O1371.00 WY 962 39
50.00 -45.00 2.89 38.90R0.5373.00 WY 10,478 40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.13
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
DISTRIBUTION PLANT 12
60.00 1.66 49.60R4360.20 UT 12,826 13
60.00 1.66 50.90S0.5361.00 UT 53,857 14
47.00 -10.00 2.34 39.70R0.5362.00 UT 448,775 15
50.00 -80.00 3.59 39.60R0.5364.00 UT 346,939 16
52.00 -45.00 2.78 40.20R0.5365.00 UT 221,142 17
60.00 -50.00 2.49 49.00R2366.00 UT 182,797 18
50.00 -25.00 2.49 38.80R2367.00 UT 498,612 19
45.00 -5.00 2.33 36.30R0.5368.00 UT 471,178 20
55.00 -25.00 2.27 44.60S5369.00 UT 257,823 21
25.00 -2.00 3.90 16.90S5370.00 UT 76,325 22
25.00 -60.00 6.37 16.80L0371.00 UT 4,345 23
25.00 -20.00 4.78 16.90R0.5373.00 UT 22,378 24
25
DISTRIBUTION PLANT 26
50.00 1.99 34.20R4360.20 ID 1,227 27
60.00 1.66 48.90R2361.00 ID 2,296 28
55.00 -10.00 1.99 41.20R1.5362.00 ID 29,136 29
50.00 -80.00 3.59 39.50R0.5364.00 ID 78,677 30
52.00 -30.00 2.49 36.30R0.5365.00 ID 35,857 31
60.00 -40.00 2.33 48.90R2366.00 ID 8,871 32
50.00 -15.00 2.29 37.80R2367.00 ID 26,159 33
45.00 -5.00 2.33 34.20R0.5368.00 ID 75,656 34
55.00 -25.00 2.27 44.00S5369.00 ID 34,980 35
25.00 -3.00 3.95 13.10S5370.00 ID 13,904 36
25.00 -45.00 5.77 16.80L0371.00 ID 169 37
25.00 -20.00 4.78 16.90R0.5373.00 ID 666 38
39
GENERAL PLANT 40
58.00 -10.00 1.86 47.20R1390.00 OR 79,565 41
12.00 10.00 7.04 6.90L2.5392.01 OR 10,154 42
16.00 10.00 5.48 8.70L3392.05 OR 12,797 43
34.00 15.00 2.44 23.70L2392.09 OR 3,327 44
9.00 15.00 9.23 5.50L3396.03 OR 7,624 45
15.00 20.00 5.14 9.80L1396.07 OR 28,535 46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.14
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
GENERAL PLANT 12
40.00 -10.00 2.52 24.70R3390.00 WA 12,923 13
13.00 10.00 5.60 8.10L2.5392.01 WA 2,077 14
16.00 10.00 5.07 9.60L2.5392.05 WA 4,965 15
33.00 15.00 2.38 24.10S0.5392.09 WA 761 16
10.00 10.00 5.66 7.30R4396.03 WA 1,676 17
13.00 15.00 6.03 8.00L1.5396.07 WA 6,193 18
19
GENERAL PLANT 20
50.00 1.98 43.40SQ389.20 WY 74 21
58.00 -15.00 1.95 47.70R1390.00 WY 10,747 22
13.00 10.00 5.85 6.10S1.5392.01 WY 4,499 23
15.00 10.00 5.66 9.20L1.5392.05 WY 6,189 24
34.00 5.00 2.68 23.20L2392.09 WY 3,063 25
9.00 15.00 8.47 5.30L3396.03 WY 3,893 26
15.00 25.00 4.86 11.60L0396.07 WY 35,877 27
28
GENERAL PLANT 29
60.00 -20.00 1.71 46.30R3390.00 CA 3,305 30
10.00 20.00 3.48 6.60S3392.01 CA 838 31
15.00 15.00 4.49 9.10L2392.05 CA 1,214 32
35.00 5.00 2.32 26.20R2392.09 CA 488 33
8.00 15.00 7.20 4.30R4396.03 CA 1,220 34
14.00 15.00 4.98 9.20L1.5396.07 CA 3,038 35
36
GENERAL PLANT 37
45.00 2.03 36.20S0389.20 UT 85 38
58.00 5.00 1.53 44.60R1390.00 UT 91,532 39
12.00 10.00 5.04 5.50L3392.01 UT 16,111 40
16.00 10.00 4.56 9.20L2392.05 UT 22,246 41
34.00 25.00 1.91 22.40L2392.09 UT 7,499 42
10.00 64.00 2.51 5.30SQ392.30 UT 3,076 43
9.00 10.00 8.10 5.70L3396.03 UT 6,891 44
14.00 15.00 5.36 9.90L0.5396.07 UT 55,636 45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.15
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
GENERAL PLANT 12
55.00 1.17 25.10R3389.20 ID 5 13
58.00 -5.00 1.65 43.40R1390.00 ID 12,568 14
12.00 10.00 4.28 7.00S2392.01 ID 2,475 15
15.00 15.00 4.34 8.80L2392.05 ID 3,061 16
34.00 10.00 2.28 24.40L2392.09 ID 983 17
9.00 10.00 7.67 5.90L3396.03 ID 2,533 18
18.00 25.00 3.73 13.10L0.5396.07 ID 7,458 19
20
GENERAL PLANT 21
AZ, CO, MT, Etc. 22
45.00 1.51 25.10R2390.00 385 23
16.00 2.53 10.70R2392.01 602 24
19.00 15.00 2.10 13.70R2.5392.05 299 25
25.00 2.18 12.80R1.5392.09 9 26
25.00 5.00 1.86 17.80R2396.07 2,413 27
28
GENERAL PLANT 29
ALL STATES 30
20.00 5.00391.00 28,177 31
5.00 20.00391.20 53,280 32
8.00 12.50391.30 728 33
25.00 4.00393.00 14,660 34
24.00 4.17394.00 62,494 35
20.00 5.00395.00 33,842 36
24.00 4.30397.00 392,330 37
11.00 9.09397.20 12,080 38
20.00 5.00398.00 7,957 39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.16
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2014/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)
MINING 12
22.06 -1.00 3.81 5.70399.30 UT 15,747 13
46.27 -7.00 2.06 25.80399.31 UT 27,996 14
46.20 -6.00 2.05 25.80399.41 UT 8,694 15
13.40 6.29 6.00399.44 UT 3,425 16
8.60 5.00 11.91 4.70399.45 UT 104,787 17
8.53 7.00 12.85 5.50399.46 UT 33,603 18
12.23 5.00 6.96 4.40399.51 UT 1,275 19
12.21 5.00 8.14 5.50399.52 UT 5,854 20
10.59 1.00 9.23 4.50399.60 UT 2,364 21
8.68 11.35 2.90399.61 UT 468 22
19.73 4.23 6.00399.70 UT 38,657 23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.17
Schedule Page: 336 Line No.: 12 Column: b
Depreciation expense associated with transportation equipment is generally charged to
operations and maintenance expense and contruction work in progress. During the year ended
December 31, 2014, depreciation expense associated with transportation equipment was
$13,767,456.
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.: 12 Column: a
The Oregon Public Utility Commission required modifications related to the depreciable
lives of coal-fired generating facilities. Below are the affected facilities and the lives
and rates required by Oregon.
Account
No.
(a)
Depreciable
Plant Base
(In Thousands)
(b)
Estimated
Avg.
Service
Life
(c)
Net
Salvage
(Percent)
(d)
Applied
Depr.
rates
(Percent)
(e)
Mortality
Curve
Type
(f)
Average
Remaining
Life
(g)
STEAM PRODUCTION PLANT
CARBON PLANT
311.00 UT 15,579 -48.00 34.29 1.30
312.00 UT 68,203 -47.00 37.03 1.30
314.00 UT 28,155 -47.00 36.37 1.30
315.00 UT 6,302 -47.00 36.50 1.30
316.00 UT 809 -47.00 43.59 1.30
CHOLLA PLANT
310.20 AZ 1,368 5.72 15.00
311.00 AZ 64,092 -5.00 4.04 14.70
312.00 AZ 333,544 -4.00 4.94 14.20
314.00 AZ 67,730 -5.00 4.67 13.80
315.00 AZ 67,923 -4.00 3.98 14.60
316.00 AZ 4,094 -5.00 4.92 13.00
COLSTRIP PLANT
311.00 MT 60,705 -5.00 2.31 18.40
312.00 MT 118,087 -5.00 2.81 16.80
314.00 MT 37,925 -6.00 3.34 17.00
315.00 MT 9,051 -4.00 2.16 18.20
316.00 MT 321 -6.00 3.24 15.70
CRAIG PLANT
311.00 CO 37,497 -5.00 2.92 12.70
312.00 CO 95,910 -5.00 4.37 12.20
314.00 CO 28,475 -6.00 5.06 12.20
315.00 CO 16,995 -4.00 2.80 12.60
316.00 CO 1,226 -6.00 3.98 11.30
DAVE JOHNSTON PLANT
310.20 WY 100 3.18 10.00
311.00 WY 155,554 -4.00 7.50 9.90
312.00 WY 670,321 -4.00 7.66 9.80
314.00 WY 94,804 -4.00 6.32 9.60
315.00 WY 62,233 -3.00 7.70 9.90
316.00 WY 8,418 -4.00 7.69 9.30
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
HAYDEN PLANT
311.00 CO 17,684 -5.00 7.49 9.90
312.00 CO 54,659 -5.00 4.62 9.60
314.00 CO 9,301 -5.00 5.65 9.60
315.00 CO 2,546 -4.00 2.59 9.70
316.00 CO 637 -5.00 4.36 9.00
HUNTER PLANT
310.20 UT 246 2.43 16.00
311.00 UT 206,744 -6.00 2.84 15.50
312.00 UT 750,440 -5.00 4.36 15.00
314.00 UT 191,922 -6.00 4.84 15.00
315.00 UT 106,650 -5.00 2.88 15.40
316.00 UT 3,691 -6.00 4.00 13.50
HUNTINGTON PLANT
311.00 UT 119,464 -7.00 3.06 16.50
312.00 UT 547,010 -6.00 4.70 16.10
314.00 UT 121,652 -7.00 4.37 15.70
315.00 UT 47,353 -5.00 3.51 16.50
316.00 UT 2,866 -6.00 4.77 14.70
JIM BRIDGER PLANT
310.20 WY 281 2.43 12.00
311.00 WY 139,956 -7.00 3.19 11.70
312.00 WY 699,179 -6.00 4.85 11.40
314.00 WY 201,832 -7.00 5.78 11.50
315.00 WY 60,807 -6.00 3.36 11.70
316.00 WY 4,115 -7.00 4.71 10.60
NAUGHTON PLANT
310.20 WY 15 1.60 15.00
311.00 WY 118,149 -5.00 4.63 14.80
312.00 WY 496,398 -5.00 5.21 14.40
314.00 WY 77,837 -6.00 4.44 14.00
315.00 WY 62,960 -4.00 5.46 14.80
316.00 WY 2,011 -5.00 5.38 13.10
WYODAK PLANT
310.20 WY 165 2.84 13.00
311.00 WY 51,286 -4.00 3.41 12.70
312.00 WY 300,425 -3.00 5.43 12.40
314.00 WY 63,689 -4.00 5.27 12.20
315.00 WY 28,510 -3.00 4.34 12.70
316.00 WY 1,211 -4.00 6.52 11.80
Schedule Page: 336.4 Line No.: 37 Column: a
The depreciation rate changes 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.
Schedule Page: 336.10 Line No.: 32 Column: a
High Plains and McFadden Ridge I wind plants
Schedule Page: 336.11 Line No.: 19 Column: a
Seven Mile Hill and Seven Mile Hill II wind plants
Schedule Page: 336.17 Line No.: 25 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
FERC Sub Acct Description
310.20 Land Rights
330.20 Land Rights
330.30 Water Rights
330.40 Flood Rights
330.50 Fish/Wildlife
350.20 Land Rights
360.20 Land Rights
369.10 Overhead Services
369.20 Underground Services
389.20 Land Rights
391.20 Personal Computers and Printers
391.30 Office Equipment
392.01 Transportation Equipment - Light Trucks and Vans
392.05 Transportation Equipment - Medium Trucks
392.09 Transportation Equipment - Trailers
392.30 Aircraft
396.03 Light Power Operated Equipment
396.07 Heavy Power Operated Equipment
397.20 Mobile Radio Equipment
399.30 Structures and Improvements
399.31 Structures and Improvements - Prep Plant
399.41 Surface Processing Equipment - Prep Plant
399.44 Surface Electric Power Facilities
399.45 Underground Equipment
399.46 Longwall Equipment
399.51 Vehicles
399.52 Heavy Construction Equipment
399.60 Miscellaneous Equipment
399.61 Computer Equipment
399.70 Mine Development
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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
REGULATORY COMMISSION EXPENSES
PacifiCorp X
/ /2014/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 5,301,974 5,301,974 2
Rate Cases and Proceedings 1,540,055 1,540,055 3
4
Oregon Public Utility Commission: 5
Annual Fee 3,390,231 3,390,231 6
Rate Cases and Proceedings 644,161 644,161 7
802,926Deferred Intervenor Funding Grants 8
9
Wyoming Public Service Commission: 10
Annual Fee 1,552,185 1,552,185 11
Rate Cases and Proceedings 1,352,270 1,352,270 12
13
Washington Utilities and Transportation 14
Commission: 15
Annual Fee 643,084 643,084 16
Rate Cases and Proceedings 1,414,014 1,414,014 17
18
Idaho Public Utilities Commission: 19
Annual Fee 639,630 639,630 20
Rate Cases and Proceedings 115,423 115,423 21
55,462Deferred Intervenor Funding Grants (2) 16,431 16,431 22
23
California Public Utilities Commission: 24
Annual Fee 1,145 1,145 25
Rate Cases and Proceedings 174,600 174,600 26
40,307Deferred Intervenor Funding Grants 27
28
California Environmental Protection Agency: 29
Industry Compliance Fee 29,081 14,250 43,331 30
31
Multi-State: 32
Rate Cases and Proceedings 876,832 876,832 33
Other Regulatory 399,685 399,685 34
35
Federal Energy Regulatory Commission: 36
Annual Fee 1,782,520 1,782,520 37
Anuual Fee - Hydroelectric Plants 1,940,450 1,940,450 38
Transmission Rate Cases 108,012 108,012 39
Other Regulatory 2,344,209 2,344,209 40
41
Charges for services from Berkshire Hathaway 42
Energy Company and its affiliates: 43
FERC - Transmission Rate Case 348 348 44
45
FERC FORM NO. 1 (ED. 12-96) Page 350
46 TOTAL 15,280,300 9,000,290 24,280,590 898,695
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES (Continued)
PacifiCorp X
/ /2014/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 5,301,974 928
Electric 3 1,540,055 928
4
5
Electric 6 3,390,231 928
Electric 7 644,161 928
1,069,569 266,643 8
9
10
Electric 11 1,552,185 928
Electric 12 1,352,270 928
13
14
15
Electric 16 643,084 928
Electric 17 1,414,014 928
18
19
Electric 20 639,630 928
Electric 21 115,423 928
39,031 16,431928Electric 22 16,431 928
23
24
Electric 25 1,145 928
Electric 26 174,600 928
40,347 40 27
28
29
Electric 30 43,331 928
31
32
Electric 33 876,832 928
Electric 34 399,685 928
35
36
Electric 37 1,782,520 928
Electric 38 1,940,450 928
Electric 39 108,012 928
Electric 40 2,344,209 928
41
42
43
Electric 44 348 928
45
FERC FORM NO. 1 (ED. 12-96) Page 351
46 24,280,590 266,683 16,431 1,148,947
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
/ /2014/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
/ /2014/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 1,250 930.2 1,250
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
/ /2014/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
105,003,774Production 3
15,492,573Transmission 4
Regional Market 5
35,675,236Distribution 6
39,175,124Customer Accounts 7
6,429,131Customer Service and Informational 8
Sales 9
39,822,468Administrative and General 10
241,598,306TOTAL Operation (Enter Total of lines 3 thru 10) 11
Maintenance 12
42,910,933Production 13
10,037,416Transmission 14
Regional Market 15
66,449,152Distribution 16
1,797,933Administrative and General 17
121,195,434TOTAL Maintenance (Total of lines 13 thru 17) 18
Total Operation and Maintenance 19
147,914,707Production (Enter Total of lines 3 and 13) 20
25,529,989Transmission (Enter Total of lines 4 and 14) 21
Regional Market (Enter Total of Lines 5 and 15) 22
102,124,388Distribution (Enter Total of lines 6 and 16) 23
39,175,124Customer Accounts (Transcribe from line 7) 24
6,429,131Customer Service and Informational (Transcribe from line 8) 25
Sales (Transcribe from line 9) 26
41,620,401Administrative and General (Enter Total of lines 10 and 17) 27
362,793,740 362,793,740TOTAL 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
/ /2014/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
362,793,740 362,793,740TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65
Utility Plant 66
Construction (By Utility Departments) 67
141,856,645 141,856,645Electric Plant 68
Gas Plant 69
Other (provide details in footnote): 70
141,856,645 141,856,645TOTAL Construction (Total of lines 68 thru 70) 71
Plant Removal (By Utility Departments) 72
7,307,095 7,307,095Electric Plant 73
Gas Plant 74
Other (provide details in footnote): 75
7,307,095 7,307,095TOTAL Plant Removal (Total of lines 73 thru 75) 76
Other Accounts (Specify, provide details in footnote): 77
2,562,661 2,562,661Fuel Stock 78
797,876 797,876Miscellaneous Other Income Deductions 79
604,655 604,655Charges to Affiliates 80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
3,965,192 3,965,192TOTAL Other Accounts 95
515,922,672 515,922,672TOTAL 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
/ /2014/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) 2 463,706 3,242,368 6,030,615 6,341,843
Net Sales (Account 447) 3 ( 1,787,553)( 1,949) ( 1,100) ( 266,834)
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
( 1,323,847) 3,240,419 6,029,515 6,075,009
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
/ /2014/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
10,356,630MWh146,378,455Scheduling, System Control and Dispatch 1
9,309,361MWh139,807,710 8,600,455MWh129,068,844Reactive Supply and Voltage 2
34,221,632MWh 99,738,252 31,037,826MWh 92,384,862Regulation and Frequency Response 3
-137,927MWh -38,394Energy Imbalance 4
28,332,570MWh 72,561,623 25,970,806MWh 66,591,811Operating Reserve - Spinning 5
24,075,231MWh 70,710,010 22,641,216MWh 66,591,811Operating Reserve - Supplement 6
Other 7
106,157,497529,157,656 88,250,303354,637,328Total (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 / /2014/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
792 1,637 3,715 111 8,694 800 6 14,949January 1
512 1,658 3,715 148 8,935 800 6 14,968February 2
484 1,485 3,715 110 7,936 80018 13,730March 3
1,788 4,780 11,145 369 25,565 43,647Total for Quarter 1 4
241 1,389 3,715 93 7,663 800 1 13,101April 5
483 1,686 3,715 91 8,452150028 14,427May 6
1,069 1,825 3,869 86 9,266170024 16,115June 7
1,793 4,900 11,299 270 25,381 43,643Total for Quarter 2 8
1,436 2,028 3,842 100 10,645160014 18,051July 9
937 1,940 3,529 111 9,940160011 16,457August 10
788 1,823 3,533 88 9,024160017 15,256September 11
3,161 5,791 10,904 299 29,609 49,764Total for Quarter 3 12
605 1,519 3,533 91 7,4831600 6 13,231October 13
1,759 1,642 3,376 130 8,505 80017 15,412November 14
1,123 1,689 3,376 151 9,061190030 15,400December 15
3,487 4,850 10,285 372 25,049 44,043Total for Quarter 4 16
10,229 20,321 43,633 1,310 105,604 181,097
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 Daylight Time
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.: 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.: 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.: 17 Column: e
Year-to-date 2014 Net System Load information was compiled using metering and/or
scheduling data. Reflects actual peak net system load for self at time of Transmission
System Peak. Peak load includes behind-the-meter generation.
Schedule Page: 400 Line No.: 17 Column: f
Year-to-date 2014 Net System Load information was compiled using metering and/or
scheduling data. Reflects actual peak of customers' load at time of Transmission System
Peak.
Schedule Page: 400 Line No.: 17 Column: g
Year-to-date 2014 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.: 17 Column: i
Year-to-date 2014 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak.
Schedule Page: 400 Line No.: 17 Column: j
Year-to-date 2014 Net System Load information was compiled using metering, scheduling
and/or contractual data. Reflects actual peak and/or contractual demands of customers'
load at time of Transmission System Peak.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/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 ENERGY ACCOUNT
PacifiCorp X
/ /2014/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
46,275,199Steam3
Nuclear4
3,784,143Hydro-Conventional5
Hydro-Pumped Storage6
10,147,955Other7
1,973Less Energy for Pumping8
60,205,324Net Generation (Enter Total of lines 3
through 8)
9
9,846,352Purchases10
Power Exchanges:11
4,330,806Received12
3,968,188Delivered13
362,618Net Exchanges (Line 12 minus line 13)14
Transmission For Other (Wheeling)15
13,674,599Received16
13,563,767Delivered17
110,832Net Transmission for Other (Line 16 minus
line 17)
18
-483,282Transmission By Others Losses19
70,041,844TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
20
DISPOSITION OF ENERGY21
54,999,277Sales to Ultimate Consumers (Including
Interdepartmental Sales)
22
225,497Requirements Sales for Resale (See
instruction 4, page 311.)
23
10,044,750Non-Requirements Sales for Resale (See
instruction 4, page 311.)
24
Energy Furnished Without Charge25
134,392Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
26
4,637,928Total Energy Losses27
70,041,844TOTAL (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 / /2014/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 6 8,455 988,995 0800 PST 6,363,644
February 30 6 8,712 917,443 0800 PST 5,646,244
March 31 18 7,640 1,006,675 0800 PDT 5,817,887
April 32 1 7,381 680,421 0800 PDT 5,168,847
May 33 28 8,198 502,920 1500 PDT 5,323,912
June 34 24 8,909 705,883 1700 PDT 5,675,200
July 35 14 10,314 649,756 1600 PDT 6,592,264
August 36 18 9,696 733,102 1700 PDT 6,074,127
September 37 17 8,718 801,195 1600 PDT 5,642,499
October 38 6 7,245 974,002 1600 PDT 5,616,344
November 39 17 8,301 1,231,483 0800 PST 6,017,740
December 40 30 8,870 852,875 1900 PST 6,103,136
FERC FORM NO. 1 (ED. 12-90) Page 401b
41 TOTAL 70,041,844 10,044,750
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
2014/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
/ /2014/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
414.00188.64 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
381175 6 Net Peak Demand on Plant - MW (60 minutes)
79898760 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
048 11 Average Number of Employees
26338740001283645000 12 Net Generation, Exclusive of Plant Use - KWh
2635317956546 13 Cost of Plant: Land and Land Rights
6409151815578830 14 Structures and Improvements
473257301103469556 15 Equipment Costs
390007036834 16 Asset Retirement Costs
540023136127041766 17 Total Cost
1304.4037673.4614 18 Cost per KW of Installed Capacity (line 17/5) Including
1464607191851 19 Production Expenses: Oper, Supv, & Engr
6471619429430662 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
78549321454315 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
7902112272687 25 Electric Expenses
19813902831179 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
20708390 29 Maintenance Supervision and Engineering
1262532266798 30 Maintenance of Structures
56684582407648 31 Maintenance of Boiler (or reactor) Plant
1152865694610 32 Maintenance of Electric Plant
2871419264010 33 Maintenance of Misc Steam (or Nuclear) Plant
8983344739813760 34 Total Production Expenses
0.03410.0310 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)
592394 1566 0 1511810 3726 0 38 Quantity (Units) of Fuel Burned
12279 138000 0 9248 126976 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
49.118 136.683 0.000 40.465 166.712 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
49.320 136.683 0.000 42.396 166.712 0.000 41 Average Cost of Fuel per Unit Burned
2.008 23.582 2.022 2.292 31.260 2.313 42 Average Cost of Fuel Burned per Million BTU
0.023 0.000 0.023 0.024 0.000 0.024 43 Average Cost of Fuel Burned per KWh Net Gen
11332.910 7.070 11339.980 10616.114 7.544 10623.658 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
/ /2014/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
816.77155.61 172.13 5
725157 166 6
87608581 8694 7
00 0 8
760148 165 9
00 0 10
1880 0 11
51833470001021984000 1205340000 12
104497931788644 137086 13
15555427460703874 37497228 14
835463641165246003 142606455 15
1293697539236 35149 16
1014404683227777757 180275918 17
1241.97101463.7733 1047.3242 18
12228427586 301885 19
6210584115871182 23394925 20
00 0 21
449005980771 1280120 22
00 0 23
00 0 24
069242 600289 25
18599956741345 921567 26
11630924937 0 27
00 0 28
0266039 612610 29
2012438449798 413469 30
127741672947925 3941026 31
76363821040373 1952786 32
1702890411744 914686 33
10551927222830942 34333363 34
0.02040.0223 0.0285 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
644853 1607 0 3520539 13748 0602222 23 0 38
8369 140000 0 8221 138000 09990 133693 0 39
21.257 134.238 0.000 17.200 134.243 0.00036.949 126.581 0.000 40
24.278 134.238 0.000 17.117 134.243 0.00038.679 126.581 0.000 41
1.450 22.831 1.469 1.041 23.161 1.0711.936 22.462 1.944 42
0.015 0.000 0.015 0.012 0.000 0.0120.019 0.000 0.019 43
10561.875 9.243 10571.118 11167.357 15.373 11182.7309982.397 0.107 9982.504 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
/ /2014/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
457.7381.37 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
42778 6 Net Peak Demand on Plant - MW (60 minutes)
68608672 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
2436169000579722000 12 Net Generation, Exclusive of Plant Use - KWh
9688975683069 13 Cost of Plant: Land and Land Rights
6322523017681882 14 Structures and Improvements
37788249467093265 15 Equipment Costs
1976952532363 16 Asset Retirement Costs
45277365185990579 17 Total Cost
989.17191056.7848 18 Cost per KW of Installed Capacity (line 17/5) Including
0188049 19 Production Expenses: Oper, Supv, & Engr
5095134114512093 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
3245727888884 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
-16633168580 25 Electric Expenses
1350426557759 26 Misc Steam (or Nuclear) Power Expenses
430 27 Rents
00 28 Allowances
0284003 29 Maintenance Supervision and Engineering
3299598559927 30 Maintenance of Structures
122581931084289 31 Maintenance of Boiler (or reactor) Plant
4325252348027 32 Maintenance of Electric Plant
211565351466 33 Maintenance of Misc Steam (or Nuclear) Plant
7562551218943077 34 Total Production Expenses
0.03100.0327 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)
275147 322 0 1146361 3798 0 38 Quantity (Units) of Fuel Burned
11309 137269 0 11332 138000 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
49.815 143.958 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
52.483 143.958 0.000 43.988 0.000 0.000 41 Average Cost of Fuel per Unit Burned
2.320 24.969 2.331 1.941 23.876 1.959 42 Average Cost of Fuel Burned per Million BTU
0.025 0.000 0.025 0.021 0.000 0.021 43 Average Cost of Fuel Burned per KWh Net Gen
10734.804 3.200 10738.004 10664.799 9.036 10673.835 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
/ /2014/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
1247.79294.47 495.59 5
1369274 473 6
87608556 8141 7
00 0 8
1158269 471 9
00 0 10
2150 0 11
76248850001955381000 3233335000 12
296533519688975 10275401 13
20671766652461173 91031263 14
1052530874243071566 431576814 15
59308561976952 1976952 16
1294832747307198666 534860430 17
1037.70091043.2257 1079.2398 18
00 0 19
15592180239456154 65514307 20
00 0 21
92595662456393 3557446 22
00 0 23
00 0 24
1548481237 -49120 25
483364-3287342 2420280 26
11928 48 27
00 0 28
00 0 29
78640031912689 2651716 30
288172297348943 9210093 31
92094101468956 3415202 32
745051244500 288986 33
21231602849681558 87008958 34
0.02780.0254 0.0269 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
894168 998 0 3507174 12120 01466646 7324 0 38
11561 138000 0 11388 138000 011326 138000 0 39
0.000 0.000 0.000 44.230 136.622 0.0000.000 0.000 0.000 40
43.975 0.000 0.000 43.986 136.622 0.00043.991 0.000 0.000 41
1.902 23.412 1.908 1.931 23.572 1.9501.942 23.436 1.969 42
0.020 0.000 0.020 0.020 0.000 0.0200.020 0.000 0.020 43
10573.394 2.957 10576.351 10476.030 9.212 10485.24210274.919 13.128 10288.047 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
/ /2014/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)
1422898 6 Net Peak Demand on Plant - MW (60 minutes)
87608760 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
1415909 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
342161 11 Average Number of Employees
93645490006300558000 12 Net Generation, Exclusive of Plant Use - KWh
11619252386782 13 Cost of Plant: Land and Land Rights
139947094119455994 14 Structures and Improvements
965565367718833576 15 Equipment Costs
52805284288219 16 Asset Retirement Costs
1111954914844964571 17 Total Cost
717.0896848.3580 18 Cost per KW of Installed Capacity (line 17/5) Including
155065947222 19 Production Expenses: Oper, Supv, & Engr
232993037117536334 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
41457969114860 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
00 25 Electric Expenses
-143979149431134 26 Misc Steam (or Nuclear) Power Expenses
2035082183 27 Rents
00 28 Allowances
6384111366194 29 Maintenance Supervision and Engineering
106345453144883 30 Maintenance of Structures
2654502515965023 31 Maintenance of Boiler (or reactor) Plant
119938604249840 32 Maintenance of Electric Plant
23317481278324 33 Maintenance of Misc Steam (or Nuclear) Plant
290594610162095997 34 Total Production Expenses
0.03100.0257 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)
2680629 5565 0 5194359 7920 0 38 Quantity (Units) of Fuel Burned
11975 138000 0 9185 138000 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
43.433 137.778 0.000 40.792 136.202 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
43.561 137.778 0.000 44.647 136.202 0.000 41 Average Cost of Fuel per Unit Burned
1.819 23.771 1.830 2.431 23.499 2.441 42 Average Cost of Fuel Burned per Million BTU
0.019 0.000 0.019 0.025 0.000 0.025 43 Average Cost of Fuel Burned per KWh Net Gen
10190.056 5.119 10195.175 10188.966 4.902 10193.868 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
/ /2014/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
251.64707.20 289.66 5
158701 284 6
58318757 8511 7
00 0 8
238687 266 9
00 0 10
34130 64 11
1907580004958589000 2064501000 12
12520901094739 210526 13
15102344118115225 51280955 14
67141700639040252 393772884 15
73791217656470 322234 16
84234046775906686 445586599 17
334.74031097.1531 1538.3090 18
131419388644 136912 19
13875780105259424 25091919 20
00 0 21
12696449955 332452 22
00 0 23
00 0 24
03230 1581 25
418300711305157 4411909 26
0100 25850 27
00 0 28
01504678 0 29
1263901397146 286015 30
14096857141993 5872320 31
30970401783604 1357736 32
33936837379 123854 33
22858526136071310 37640548 34
0.11980.0274 0.0182 35
Coal Gas Composite GasCoal Oil Composite 36
Tons MCF MCFTons Barrels 37
2673244 76127 0 2702332 0 01543509 2409 0 38
9835 1046 0 1049 0 07980 138000 0 39
38.944 7.776 0.000 5.135 0.000 0.00015.999 134.675 0.000 40
39.154 7.776 0.000 5.135 0.000 0.00016.046 134.675 0.000 41
1.990 7.432 1.999 4.895 0.000 0.0001.005 23.236 1.018 42
0.021 0.000 0.021 0.073 0.000 0.0000.012 0.000 0.012 43
10604.770 16.062 10620.832 14859.550 0.000 0.00011931.840 6.762 11938.602 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
/ /2014/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
38.10279.59 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
36250 6 Net Peak Demand on Plant - MW (60 minutes)
85788321 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
32231 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
210 11 Average Number of Employees
2749960001164903000 12 Net Generation, Exclusive of Plant Use - KWh
41195596842245 13 Cost of Plant: Land and Land Rights
824806912844996 14 Structures and Improvements
100699306160780575 15 Equipment Costs
1744133214373 16 Asset Retirement Costs
151887104174682189 17 Total Cost
3986.5382624.7798 18 Cost per KW of Installed Capacity (line 17/5) Including
425890 19 Production Expenses: Oper, Supv, & Engr
049011065 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
9417660 22 Steam Expenses
43038090 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
09519723 25 Electric Expenses
5111350 26 Misc Steam (or Nuclear) Power Expenses
62470 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
2940540 30 Maintenance of Structures
3679070 31 Maintenance of Boiler (or reactor) Plant
1946830 32 Maintenance of Electric Plant
731540 33 Maintenance of Misc Steam (or Nuclear) Plant
673534458530788 34 Total Production Expenses
0.02450.0502 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)
8653384 0 0 0 0 0 38 Quantity (Units) of Fuel Burned
1026 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
5.664 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
5.664 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
5.521 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.042 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
7620.062 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
/ /2014/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
8220 482 6
51626112 8419 7
00 0 8
11910 477 9
00 0 10
00 18 11
13491900066234000 2543785000 12
00 1973791 13
42730005733734 23907900 14
7712890228718343 313342108 15
00 689117 16
8140190234452077 339912916 17
449.4859560.1964 572.9191 18
00 131343 19
102013540 103755001 20
00 0 21
00 0 22
00 0 23
00 0 24
6246720 2327072 25
0-10235 686775 26
00 0 27
00 0 28
00 0 29
1463210 29716 30
00 0 31
6312160 2302129 32
1268630 0 33
11730426-10235 109232036 34
0.0869-0.0002 0.0429 35
GasGas 36
MCFMCF 37
0 0 0 1938971 0 019454730 0 0 38
0 0 0 1049 0 01016 0 0 39
0.000 0.000 0.000 5.261 0.000 0.0005.333 0.000 0.000 40
0.000 0.000 0.000 5.261 0.000 0.0005.333 0.000 0.000 41
0.000 0.000 0.000 5.015 0.000 0.0005.251 0.000 0.000 42
0.000 0.000 0.000 0.076 0.000 0.0000.041 0.000 0.000 43
0.000 0.000 0.000 15077.862 0.000 0.0007766.875 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
/ /2014/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)
550550 6 Net Peak Demand on Plant - MW (60 minutes)
77108558 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
546524 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
3420 11 Average Number of Employees
26306430002498058000 12 Net Generation, Exclusive of Plant Use - KWh
145306823403277 13 Cost of Plant: Land and Land Rights
3528590744164698 14 Structures and Improvements
321281043324572642 15 Equipment Costs
0134848 16 Asset Retirement Costs
371097632372275465 17 Total Cost
627.5962656.6863 18 Cost per KW of Installed Capacity (line 17/5) Including
7380063335 19 Production Expenses: Oper, Supv, & Engr
9189750687949444 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)
18912591735241 25 Electric Expenses
534208709776 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
1136151486763 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
2952041126843 32 Maintenance of Electric Plant
6441646108 33 Maintenance of Misc Steam (or Nuclear) Plant
9589254492117510 34 Total Production Expenses
0.03650.0369 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)
18034666 0 0 18553782 0 0 38 Quantity (Units) of Fuel Burned
1032 0 0 1037 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
4.877 0.000 0.000 4.953 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
4.877 0.000 0.000 4.953 0.000 0.000 41 Average Cost of Fuel per Unit Burned
4.726 0.000 0.000 4.778 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.035 0.000 0.000 0.035 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
7450.079 0.000 0.000 7311.722 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.
Lake Side 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
/ /2014/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
Combined Cycle 1
Outdoor 2
2014 3
2014 4
0.00655.20 0.00 5
0628 0 6
04813 0 7
00 0 8
0631 0 9
00 0 10
00 0 11
01720539000 0 12
016796219 0 13
053065674 0 14
0568819804 0 15
00 0 16
0638681697 0 17
0974.7889 0 18
085289 0 19
053886571 0 20
00 0 21
00 0 22
00 0 23
00 0 24
01675929 0 25
0990826 0 26
00 0 27
00 0 28
00 0 29
0480350 0 30
00 0 31
00 0 32
00 0 33
057118965 0 34
0.00000.0332 0.0000 35
Gas 36
MCF 37
11522252 0 0 0 0 00 0 0 38
1036 0 0 0 0 00 0 0 39
4.677 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 40
4.677 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 41
4.512 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 42
0.031 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 43
6940.966 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
2014 were $1.9 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 2014 were $7.9
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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
2014 were $28.0 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 2014 were $3.6
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 the Camas
Co-Generation unit 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: 403.4 Line No.: 11 Column: d
Refer to the Lake Side Plant on page 402.4 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Hayden - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: c2
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
2014/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
/ /2014/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 22 27
Plant Hours Connect to Load 7 6,158 6,204
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 65,390,000 86,439,000
Cost of Plant 13
Land and Land Rights 14 107,019 20,914
Structures and Improvements 15 1,621,652 2,345,799
Reservoirs, Dams, and Waterways 16 2,936,826 2,954,724
Equipment Costs 17 5,354,740 10,366,514
Roads, Railroads, and Bridges 18 105,442 479,588
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 10,125,679 16,167,539
Cost per KW of Installed Capacity (line 20 / 5) 21 506.2840 598.7977
Production Expenses 22
Operation Supervision and Engineering 23 9,390 12,677
Water for Power 24 0 0
Hydraulic Expenses 25 544 734
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 1,037,203 1,283,380
Rents 28 29,076 39,252
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 3,035 3,423
Maintenance of Reservoirs, Dams, and Waterways 31 7,621 10,581
Maintenance of Electric Plant 32 59,407 117,852
Maintenance of Misc Hydraulic Plant 33 15,072 20,347
Total Production Expenses (total 23 thru 33) 34 1,161,348 1,488,246
Expenses per net KWh 35 0.0178 0.0172
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
/ /2014/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
17 2210 6
7,681 6,1028,729 7
8
31 2918 9
31 2918 10
1 31 11
44,892,000 40,610,00041,246,000 12
13
0 3,511,1050 14
2,343,700 3,969,9081,331,943 15
14,744,099 9,126,0035,130,510 16
1,974,558 14,610,1691,327,380 17
250,151 572,05950,817 18
0 00 19
19,312,508 31,789,2447,840,650 20
742.7888 1,059.6415522.7100 21
22
19,096 96,4849,442 23
2,078 -6,3251,199 24
64,335 90,22037,117 25
0 00 26
426,582 736,397250,659 27
71,216 12,92241,086 28
0 00 29
53,475 -33519,318 30
19,531 12,97623,718 31
54,134 25,2708,946 32
96,170 350,98155,483 33
806,617 1,318,590446,968 34
0.0180 0.03250.0108 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
/ /2014/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 11 29
Plant Hours Connect to Load 7 3,209 8,276
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 24,132,000 56,069,000
Cost of Plant 13
Land and Land Rights 14 0 62,169
Structures and Improvements 15 986,633 2,037,704
Reservoirs, Dams, and Waterways 16 12,375,292 11,146,387
Equipment Costs 17 1,865,557 4,395,351
Roads, Railroads, and Bridges 18 533,015 341,093
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 15,760,497 17,982,704
Cost per KW of Installed Capacity (line 20 / 5) 21 1,432.7725 544.9304
Production Expenses 22
Operation Supervision and Engineering 23 13,725 108,716
Water for Power 24 879 -6,958
Hydraulic Expenses 25 27,219 30,619
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 254,640 1,339,772
Rents 28 30,130 12,051
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 28,412 17,014
Maintenance of Reservoirs, Dams, and Waterways 31 41,238 155,869
Maintenance of Electric Plant 32 65,146 92,815
Maintenance of Misc Hydraulic Plant 33 40,686 104,967
Total Production Expenses (total 23 thru 33) 34 502,075 1,854,865
Expenses per net KWh 35 0.0208 0.0331
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
/ /2014/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
81 3219 6
5,266 8,2148,426 7
8
83 3219 9
83 3219 10
2 11 11
172,588,000 140,861,00085,550,000 12
13
25,845 0341,706 14
3,458,985 2,474,3606,991,560 15
15,664,267 15,759,70913,695,754 16
15,363,498 6,717,5882,722,639 17
886,710 488,8771,095,742 18
0 00 19
35,399,305 25,440,53424,847,401 20
361.2911 795.26521,380.4112 21
22
130,104 37,2401,490,363 23
0 2,5560 24
5,296 79,1576,319 25
0 00 26
883,402 711,432979,956 27
-111,960 87,62326,168 28
0 00 29
7,872 51,6993,273 30
8,513 136,62618,678 31
23,058 103,36695,487 32
45,343 163,80716,040 33
991,628 1,373,5062,636,284 34
0.0057 0.00980.0308 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
/ /2014/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 36 146
Plant Hours Connect to Load 7 8,731 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 1
Net Generation, Exclusive of Plant Use - Kwh 12 173,729,000 579,582,000
Cost of Plant 13
Land and Land Rights 14 0 1,086,564
Structures and Improvements 15 4,783,250 101,021,680
Reservoirs, Dams, and Waterways 16 31,442,142 28,046,815
Equipment Costs 17 11,739,603 18,612,476
Roads, Railroads, and Bridges 18 1,952,391 2,978,489
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 49,917,386 151,746,024
Cost per KW of Installed Capacity (line 20 / 5) 21 1,296.5555 1,115.7796
Production Expenses 22
Operation Supervision and Engineering 23 20,903 1,190,463
Water for Power 24 3,077 45,183
Hydraulic Expenses 25 95,266 762,185
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 603,752 611,936
Rents 28 105,454 89,565
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 47,752 52,769
Maintenance of Reservoirs, Dams, and Waterways 31 38,304 36,154
Maintenance of Electric Plant 32 25,171 147,545
Maintenance of Misc Hydraulic Plant 33 142,406 479,056
Total Production Expenses (total 23 thru 33) 34 1,082,085 3,414,856
Expenses per net KWh 35 0.0062 0.0059
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
/ /2014/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
15 3643 6
8,755 8,4918,717 7
8
28 3645 9
28 3645 10
2 12 11
21,691,000 206,474,000226,366,000 12
13
36,698 105,1680 14
1,888,351 3,515,9474,062,128 15
6,321,486 30,120,17412,755,268 16
5,765,653 7,056,0473,809,818 17
503,332 324,221264,441 18
0 00 19
14,515,520 41,121,55720,891,655 20
483.8507 1,285.0487491.5684 21
22
98,833 157,46178,241 23
-6,325 28,5663,397 24
27,835 3,278105,163 25
0 00 26
552,799 835,511654,504 27
10,703 9,621116,410 28
0 2650 29
32,766 31,71595,552 30
2,471 179,3572,189 31
91,160 74,767172,566 32
75,406 188,722157,202 33
885,648 1,509,2631,385,224 34
0.0408 0.00730.0061 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
/ /2014/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 18 9
Plant Hours Connect to Load 7 8,719 6,147
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 70,420,000 14,510,000
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 14,880,391 8,729,478
Equipment Costs 17 8,966,147 5,386,467
Roads, Railroads, and Bridges 18 463,083 0
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 26,495,808 15,359,424
Cost per KW of Installed Capacity (line 20 / 5) 21 1,471.9893 1,097.1017
Production Expenses 22
Operation Supervision and Engineering 23 9,773 46,122
Water for Power 24 1,438 -2,952
Hydraulic Expenses 25 44,540 12,990
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 287,277 372,328
Rents 28 49,303 4,995
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 30,671 34,099
Maintenance of Reservoirs, Dams, and Waterways 31 24,075 0
Maintenance of Electric Plant 32 11,049 38,820
Maintenance of Misc Hydraulic Plant 33 66,580 35,190
Total Production Expenses (total 23 thru 33) 34 524,706 541,592
Expenses per net KWh 35 0.0075 0.0373
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
/ /2014/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
260 17012 6
6,159 7,4918,676 7
8
264 16412 9
264 16412 10
1 12 11
811,753,000 671,963,00054,071,000 12
13
14,163,614 8,363,0130 14
69,951,939 9,214,4833,960,783 15
46,645,795 29,588,46089,238,752 16
24,495,462 16,437,1932,350,076 17
1,133,091 1,471,2302,068,792 18
0 00 19
156,389,901 65,074,37997,618,403 20
651.6246 485.62978,874.4003 21
22
1,988,188 1,124,8155,972 23
79,735 44,519879 24
1,543,605 750,977110,738 25
0 00 26
509,081 434,419308,772 27
158,055 88,24830,130 28
0 00 29
45,425 27,87715,270 30
363,289 53,676242,318 31
187,130 91,02122,079 32
771,959 444,65240,688 33
5,646,467 3,060,204776,846 34
0.0070 0.00460.0144 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
/ /2014/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 8 0
Plant Hours Connect to Load 7 6,655 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 7,064,000 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 33,126 0
Water for Power 24 -2,172 0
Hydraulic Expenses 25 30,976 0
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 178,113 0
Rents 28 3,698 0
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 -9,761 0
Maintenance of Reservoirs, Dams, and Waterways 31 -18,880 0
Maintenance of Electric Plant 32 1,189 0
Maintenance of Misc Hydraulic Plant 33 114,605 0
Total Production Expenses (total 23 thru 33) 34 330,894 0
Expenses per net KWh 35 0.0468 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
/ /2014/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
2014/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 / /2014/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 32,826,000 33,392,1681917Ashton 2381 2
1.11 1.0 2,498,000 1,568,7991913Bend 3
4.15 4.6 31,240,000 7,430,0761910Big Fork 2652 4
2.81 3.0 16,187,000 1,898,2901957Eagle Point 5
3.20 1,991,6951924East Side 2082 6
2.20 2.0 7,396,000 1,433,4911903Fall Creek 2082 7
0.16 594,2821922Fountain Green 8
2.00 1.3 6,050,000 5,234,5691896Granite 9
0.75 0.2 532,000 683,0451917Gunlock 10
1.73 1.0 3,094,000 2,806,5761983Last Chance 11
0.72 0.1 1,879,000 432,4941910Paris 12
5.00 2.6 9,008,000 10,982,4441897Pioneer 2722 13
3.76 4.6 23,728,000 2,590,0261912Prospect No. 1 2630 14
7.20 8.0 35,937,000 8,779,9141932Prospect No. 3 2337 15
1.00 0.9 4,567,000 2,409,7921944Prospect No. 4 2630 16
0.80 0.3 415,000 933,7221926Sand Cove 17
1.00 1.2 4,648,000 1,721,1281895Stairs 597 18
0.50 0.2 286,000 893,4111920Veyo 19
0.74 0.5 1,012,000 1,194,4861986Viva Naughton 20
1.10 1.0 2,354,000 3,203,0191921Wallowa Falls 308 21
3.85 2.0 5,031,000 3,504,9401911Weber 1744 22
0.60 0.6 55,000 468,5741908West Side 2082 23
7,527,975Keno Regulating Dam 2082 24
3,845,151Upper Klamath Lake 2082 25
15,403,557North Umpqua 1927 26
27
Pumping Plant: 28
-2.80 -3.0 -1,973,000 19,406,7481917Lifton 29
30
Wind: 31
111.00 112.0 382,995,000 240,704,5482010Dunlap Ranch 1 32
32.15 30.6 101,592,000 36,597,9491999Foote Creek 33
99.00 100.0 299,004,000 201,773,1482008Glenrock 34
39.00 40.0 112,823,000 87,723,5422009Glenrock III 35
99.00 100.0 271,147,000 203,222,9742009Rolling Hills 36
94.00 94.0 216,762,000 183,711,7872008Goodnoe Hills 37
100.00 100.0 215,245,000 178,214,6602006Leaning Juniper 1 38
140.40 136.0 367,390,000 240,396,4612007Marengo 39
70.20 70.0 174,766,000 129,587,0102008Marengo II 40
99.00 99.0 335,038,000 201,107,6422008Seven Mile Hill 41
19.50 21.0 73,601,000 42,240,5872008Seven Mile Hill II 42
99.00 100.0 324,244,000 220,037,4112009High Plains 43
28.50 29.0 98,411,000 56,983,5262009McFadden Ridge I 44
45
Solar: 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 / /2014/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
173,100 4,983,906 2Water 587,439
20,225 1,413,332 3Water 72,273
153,315 1,790,380 4Water 311,465
150,514 675,548 5Water 268,850
43,148 622,405 6Water 11,346
55,639 651,587 7Water 167,083
432 3,714,263 8Water 5,032
39,279 2,617,285 9Water 157,554
8,503 910,727 10Water 61,963
15,474 1,622,298 11Water 109,858
44,304 600,686 12Water 74,370
118,271 2,196,489 13Water 444,306
38,095 688,837 14Water 166,494
269,678 1,219,433 15Water 413,412
11,261 2,409,792 16Water 60,298
57,384 1,167,153 17Water 69,677
18,595 1,721,128 18Water 158,456
108,944 1,786,822 19Water 59,390
28,950 1,614,170 20Water 92,467
53,780 2,911,835 21Water 73,989
62,242 910,374 22Water 245,686
7,656 780,957 23Water 30,979
1,713 24 12,836
13,047 25 758,188
26
27
28
43,097 -6,930,981 29Water 308,429
30
31
1,499,213 2,168,509 32Wind 357,133
1,098,311 1,138,350 33Wind 823,987
1,681,532 2,038,113 34Wind 611,457
629,658 2,249,322 35Wind 247,113
1,598,361 2,052,757 36Wind 574,141
1,511,541 1,954,381 37Wind 472,331
1,178,211 1,782,147 38Wind 1,830,660
1,421,542 1,712,226 39Wind 1,685,427
1,010,454 1,845,969 40Wind 746,617
1,773,314 2,031,390 41Wind 858,582
357,810 2,166,184 42Wind 222,299
1,565,175 2,222,600 43Wind 1,098,093
490,003 1,999,422 44Wind 308,247
45
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 / /2014/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.
2.00 2.0 4,307,000 74,9862012Black Cap 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03) 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 / /2014/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
37,493 1Solar 524,453
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 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.: 24 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.: 25 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.: 26 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.: 29 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.: 31 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.: 33 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.: 1 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
2014/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
/ /2014/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 #3, 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 16,211.00 694.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2014/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
279,703,832 266,364,133 13,339,699 911,099 242,202 665,808 3,089 13
14
279,703,832 266,364,133 13,339,699 911,099 242,202 665,808 3,089 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
36 211,652,349 3,045,766,779 3,257,419,128 488,475 15,845,636 1,917,195 18,251,306
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
/ /2014/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 #1, WY
Wood - H 230.00 230.00 88.00 1 27 BEN LOMOND, UT NAUGHTON #2, 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 16,211.00 694.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2014/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
1,472,044,219 1,334,182,160 137,862,059 2,310,229 525,051 1,697,983 87,195 18
19
1,472,044,219 1,334,182,160 137,862,059 2,310,229 525,051 1,697,983 87,195 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
36 211,652,349 3,045,766,779 3,257,419,128 488,475 15,845,636 1,917,195 18,251,306
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
/ /2014/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 40.00 1 13 BUFFALO, WY SHERIDAN (MDU), WY
Wood - H 230.00 230.00 62.00 1 14 DIXONVILLE, OR GRANTS PASS, OR
Wood - H 230.00 230.00 78.00 1 15 HURRICANE, OR WALLA WALLA, WA
Wood - H 230.00 230.00 177.00 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 35.00 1 18 KLAMATH FALLS, OR MALIN, OR
Wood - H 230.00 230.00 2.00 1 19 LIMA, WY ROBERSON, WY
Wood - H 230.00 230.00 76.00 1 20 LONE PINE, OR KLAMATH FALLS, OR
Steel SP 230.00 230.00 5.00 1 21 LONE PINE, OR MERIDIAN #1, OR
Steel SP 230.00 230.00 5.00 1 22 LONE PINE, OR MERIDIAN #2, OR
Wood - H 230.00 230.00 56.00 1 23 MCNARY (BPA), WA WALLA WALLA, WA
Wood - H 230.00 230.00 35.00 1 24 MERIDIAN, OR GRANTS PASS, OR
Wood - H 230.00 230.00 70.00 1 25 HIGH PLAINS, WY PLATTE, WY
Wood - H 230.00 230.00 13.00 1 26 MONUMENT, WY EXXON, WY
Wood - H 230.00 230.00 20.00 1 27 MONUMENT, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 80.00 1 28 NAUGHTON, WY TREASURETON, ID
Wood - H 230.00 230.00 30.00 1 29 NAUGHTON, WY MONUMENT, WY
Wood - H 230.00 230.00 16.00 1 30 NAUGHTON, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 4.00 1 31 PALISADES SS, WY BLUE RIM, WY
Wood - H 230.00 230.00 94.00 1 32 PAROWAN VALLEY, UT SIGURD, UT
Wood - H 230.00 230.00 26.00 1 33 PAROWAN VALLEY, UT WEST CEDAR, UT
Wood - H 230.00 230.00 43.00 1 34 PAVANT, UT SIGURD, UT
Wood - H 230.00 230.00 35.00 1 35 JIM BRIDGER, WY ROCK SPRINGS, WY
FERC FORM NO. 1 (ED. 12-87)Page 422.2
36 TOTAL 16,211.00 694.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2014/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 36/1 18
1272 ACSR 45/7 19
795 ACSR 26/7 20
1272 ACSR 54/19 21
1272 ACSR 36/1 22
1272 ACSR 36/1 23
1272 ACSR 36/1 24
1272 ACSR 45/7 25
1272 ACSR 36/1 26
1272 ACSR 45/7 27
1272 ACSR 45/7 28
1272 ACSR 36/1 29
954 ACSR 54/7 30
1272 ACSR 36/1 31
795 ACSR 45/7 32
795 ACSR 45/7 33
795 ACSR 45/7 34
1272 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.2
36 211,652,349 3,045,766,779 3,257,419,128 488,475 15,845,636 1,917,195 18,251,306
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
/ /2014/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Wood - H 230.00 230.00 8.00 1 1 POMONA, WA UNION GAP, WA
Wood - H 230.00 230.00 118.00 1 2 RIVERTON, WY ROCK SPRINGS, WY
Wood - H 230.00 230.00 51.00 1 3 RIVERTON, WY THERMOPOLIS, WY
Wood - H 230.00 230.00 55.00 1 4 ROCK SPRINGS, WY FLAMING GORGE, UT
Wood - H 230.00 230.00 35.00 1 5 ROCK SPRINGS, WY JIM BRIDGER, WY
Wood - H 230.00 230.00 41.00 1 6 ROCK SPRINGS, WY MONUMENT, WY
Wood - H 230.00 230.00 12.00 1 7 SHIRLEY BASIN, WY DUNLAP RANCH, WY
Wood - H 230.00 230.00 2.00 1 8 SWIFT No. 1, WA SWIFT No. 2, WA
Wood - H 230.00 230.00 23.00 1 9 SWIFT No. 2, WA WOODLAND (BPA) SS, WA
Wood - H 230.00 230.00 7.00 1 10 TALBOT, WA MARENGO II, WA
Wood - H 230.00 230.00 9.00 1 11 TAP TO HANNA, OR NICKEL MOUNTAIN, OR
Wood - H 230.00 230.00 176.00 1 12 THERMOPOLIS, WY YELLOWTAIL, MT
Wood - H 230.00 230.00 66.00 1 13 TREASURETON, ID BRADY, ID
Steel Tower 230.00 230.00 6.00 1 14 TROUTDALE (BPA), OR GRESHAM (PGE), OR
230.00 230.00 7.00 1 15 TROUTDALE (BPA), OR LINNEMAN (PGE), OR
Wood - H 230.00 230.00 39.00 1 16 UNION GAP, WA MIDWAY (BPA), WA
Wood - H 230.00 230.00 45.00 1 17 WALLA WALLA, WA LEWISTON (AVISTA), ID
Wood - H 230.00 230.00 33.00 1 18 WALLA WALLA, WA WANAPUM (GPUD), WA
Wood - H 230.00 230.00 37.00 1 19 WANAPUM (GPUD), WA POMONA, WA
Wood - H 230.00 230.00 13.00 1 20 WINDSTAR, WY GLENROCK, WY
Wood - H 230.00 230.00 69.00 1 21 WYODAK, WY BUFFALO, WY
Wood - H 230.00 230.00 63.00 1 22 YAMSAY (BPA), OR KLAMATH FALLS, OR
Wood - H 230.00 230.00 62.00 1 23 SHERIDAN (MDU), WY YELLOWTAIL, MT
24 230 kV costs and expenses
25
13.00 3,329.00 72 26 Subtotal 230 kV
27
Wood - H 161.00 161.00 61.00 1 28 ANACONDA, ID JEFFERSON, ID
Wood - H 161.00 161.00 45.00 1 29 ANTELOPE, ID GOSHEN, ID
Wood SP 161.00 161.00 9.00 1 30 BONNEVILLE, ID EAGLEROCK, ID
Wood SP 161.00 161.00 3.00 1 31 EAGLEROCK, ID SUGARMILL, ID
Wood - H 161.00 161.00 57.00 1 32 GOSHEN, ID GRACE, ID
Wood - H 161.00 161.00 31.00 1 33 GOSHEN, ID RIGBY, ID
Wood SP 161.00 161.00 17.00 1 34 RIGBY, ID SUGARMILL, ID
Wood SP 161.00 161.00 17.00 1 35 SUGARMILL, ID RIGBY, ID
FERC FORM NO. 1 (ED. 12-87) Page 422.3
36 TOTAL 16,211.00 694.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2014/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i)(j)(k)(l)(m)(n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
1272 ACSR 36/1 1
1272 ACSR 36/1 2
1272 ACSR 36/1 3
1272 ACSR 36/1 4
1272 ACSR 36/1 5
1272 ACSR 36/1 6
795 ACSR 26/7 7
954 ACSR 45/7 8
954 ACSR 45/7 9
795 ACSR 26/7 10
795 ACSR 26/7 11
1272 ACSR 36/1 12
795 ACSR 26/7 13
954 ACSR 45/7 14
900 ACSR 54/7 15
954 ACSR 45/7 16
1272 ACSR 36/1 17
1272 ACSR 36/1 18
1272 ACSR 36/1 19
1272 ACSR 45/7 20
1272 ACSR 36/1 21
795 ACSR 26/7 22
795 ACSR 26/7 23
397,032,281 378,604,964 18,427,317 4,275,654 570,918 3,636,619 68,117 24
25
397,032,281 378,604,964 18,427,317 4,275,654 570,918 3,636,619 68,117 26
27
250HH CU /7 28
397.5 ACSR 26/7 29
954 ACSR 45/7 30
954 ACSR 45/7 31
250HH CU /7 32
397.5 ACSR 26/7 33
795 AAC /37 34
397.5 ACSR 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.3
36 211,652,349 3,045,766,779 3,257,419,128 488,475 15,845,636 1,917,195 18,251,306
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
/ /2014/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 12.00 1 1 EAGLEROCK, ID GOSHEN, ID
Wood - H 161.00 161.00 46.00 1 2 YELLOWTAIL, MT RIMROCK, MT
Wood SP 161.00 161.00 18.00 1 3 RIGBY, ID JEFFERSON, ID
Wood - H 161.00 161.00 30.00 1 4 GOSHEN, ID JEFFERSON, ID
5 161 kV costs and expenses
6
91.00 255.00 12 7 Subtotal 161 kV
8
Steel - SP 138.00 138.00 1.00 1 9 90TH SOUTH, UT SANDY, UT
Wood - H 138.00 138.00 12.00 1 10 90TH SOUTH, UT DUMAS #1, UT
Wood - H 138.00 138.00 6.00 1 11 90TH SOUTH, UT DUMAS #2, UT
Wood SP 138.00 138.00 10.00 1 12 90TH SOUTH, UT OQUIRRH, UT
Wood - H 138.00 138.00 44.00 1 13 ABAJO, UT PINTO, UT
Wood - H 138.00 138.00 4.00 1 14 AGRIUM, UT THREEMILE KNOLL, ID
Wood - H 138.00 138.00 22.00 1 15 ANSCHTZ CO-GEN, WY EVANSTON, WY
Wood - H 138.00 138.00 1.00 1 16 ANTELOPE, ID SCOVILLE #1, WY
Wood - H 138.00 138.00 1.00 1 17 ANTELOPE, ID SCOVILLE #2, WY
Wood - H 138.00 138.00 26.00 1 18 ASHGROVE, UT CLOVER, UT
Wood - H 138.00 138.00 102.00 1 19 ASHLEY, UT CARBON, UT
Wood - H 138.00 138.00 12.00 1 20 ASHLEY, UT VERNAL, UT
Wood - H 138.00 138.00 6.00 1 21 BANGERTER, UT OQUIRRH, UT
Wood - SP 138.00 138.00 1.00 1 22 BDO, UT BDO TAP, UT
Wood - H 138.00 138.00 14.00 1 23 BEN LOMOND, UT BRIGHAM CITY, UT
Steel - SP 138.00 138.00 14.00 1 24 BEN LOMOND #1, UT EL MONTE, UT
138.00 138.00 13.00 1 25 BEN LOMOND #2, UT EL MONTE, UT
Steel Tower 138.00 138.00 22.00 1 26 BEN LOMOND, UT HONEYVILLE, UT
Steel Tower 230.00 138.00 13.00 7.00 1 27 BEN LOMOND, UT SYRACUSE #1, UT
Steel - SP 138.00 138.00 28.00 1 28 BEN LOMOND, UT ANGEL, UT
Wood -SP 138.00 138.00 14.00 1 29 BEN LOMOND, UT W ZIRCONIUM, UT
Steel Tower 138.00 138.00 42.00 1 30 BEN LOMOND, UT WHEELON, UT
Steel Tower 138.00 138.00 25.00 1 31 BEN LOMOND, UT SYRACUSE, UT
Wood - H 138.00 138.00 9.00 1 32 BONANZA, UT CHAPITA, UT
Wood -SP 138.00 138.00 16.00 1 33 BRIDGERLAND, UT GREEN CANYON, UT
Wood - H 138.00 138.00 24.00 1 34 BRIGHAM CITY, UT WHEELON, UT
Steel - SP 138.00 138.00 9.00 1 35 BUTLERVILLE, UT 90TH SOUTH, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.4
36 TOTAL 16,211.00 694.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2014/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
556.5 ACSR 26/7 2
397.5 ACSR 26/7 3
250HH CU /7 4
23,486,043 22,862,553 623,490 324,044 1,712 322,044 288 5
6
23,486,043 22,862,553 623,490 324,044 1,712 322,044 288 7
8
795 AAC /37 9
795 AAC /37 10
795 AAC /37 11
795 ACSR 26/7 12
397.5 ACSR 26/7 13
397.5 ACSR 26/7 14
795 ACSR 26/7 15
397.5 ACSR 26/7 16
397.5 ACSR 26/7 17
397.5 ACSR 26/7 18
397.5 ACSR 26/7 19
397.5 ACSR 26/7 20
21
397.5 ACSR 26/7 22
1272 ACSR 45/7 23
795 ACSR 45/7 24
795 ACSR 45/7 25
250 CUHD /12 26
795 AAC /37 27
397.5 ACSR 26/7 28
795 AAC /37 29
250 CUHD /12 30
1272 ACSR 45/7 31
795 ACSR 26/7 32
1272 ACSR 45/7 33
795 ACSR 26/7 34
795 AAC /37 35
FERC FORM NO. 1 (ED. 12-87) Page 423.4
36 211,652,349 3,045,766,779 3,257,419,128 488,475 15,845,636 1,917,195 18,251,306
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
/ /2014/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 35.00 1 1 CAMERON, UT PAROWAN, UT
Wood - H 138.00 138.00 64.00 1 2 CAMERON, UT SIGURD, UT
Wood - H 138.00 138.00 12.00 1 3 CANYON COMP, WY STR 204, WY
Wood - H 138.00 138.00 2.00 1 4 CARBON, UT HELPER #2, UT
Steel Tower 138.00 138.00 54.00 1 5 CARBON, UT SPANISH FORK #1, UT
Steel Tower 138.00 138.00 52.00 1 6 CARBON, UT SPANISH FORK #2, UT
Wood - H 138.00 138.00 120.00 1 7 CARBON, UT MOAB, UT
Wood -SP 138.00 138.00 5.00 1 8 CLEAR CREEK, WY PAINTER, UT
Wood -SP 138.00 138.00 8.00 1 9 CLOVER, UT NEBO, UT
Wood - H 138.00 138.00 2.00 1 10 COLUMBIA, UT SUNNYSIDE, UT
Steel - SP 138.00 138.00 6.00 1 11 COTTONWOOD, UT MCCLELLAND, UT
Wood -SP 138.00 138.00 5.00 1 12 COTTONWOOD, UT HAMMER, UT
Wood -SP 138.00 138.00 29.00 1 13 COTTONWOOD, UT SILVER CREEK, UT
Wood -SP 138.00 138.00 1.00 1 14 CUTLER, UT WHEELON, UT
Steel - SP 138.00 138.00 5.00 1 15 DRY CREEK, UT SPANISH FORK, UT
Wood -SP 138.00 138.00 18.00 1 16 DUMAS, UT WESTFIELD, UT
Steel - SP 138.00 138.00 2.00 1 17 DYNAMO, UT TRI-CITY #1, UT
138.00 138.00 3.00 1 18 DYNAMO, UT TRI-CITY #2, UT
Steel - SP 138.00 138.00 15.00 1 19 EAST LAYTON, UT 105 TAP, UT
Wood -SP 138.00 138.00 1.00 1 20 EBAY TAP, UT OQUIRRH, UT
Steel - SP 138.00 138.00 4.00 1 21 EL MONTE, UT STR 30B, UT
Steel - SP 138.00 138.00 1.00 1 22 EL MONTE, UT PIONEER, UT
Wood -SP 138.00 138.00 3.00 1 23 EVANSTON, WY RAILROAD, UT
Wood -SP 138.00 138.00 10.00 1 24 FRANKLIN, ID TREASURETON, ID
Wood -SP 138.00 138.00 25.00 1 25 FRANKLIN, ID GREEN CANYON, UT
Wood -SP 138.00 138.00 1.00 1 26 GADSBY, UT THIRD WEST, UT
Wood -SP 138.00 138.00 6.00 1 27 GADSBY, UT TERMINAL, UT
Wood -SP 138.00 138.00 1.00 1 28 GADSBY, UT JORDAN, UT
Wood -SP 138.00 138.00 7.00 1 29 GREEN CANYON, UT NIBLEY, UT
Wood -SP 138.00 138.00 19.00 1 30 GREEN CANYON, UT WHEELON, UT
Wood - H 138.00 138.00 19.00 1 31 HALE, UT MIDWAY, UT
Wood - H 138.00 138.00 7.00 1 32 HALE, UT TANNER, UT
Wood - H 138.00 138.00 18.00 1 33 HALE, UT SPANISH FORK, UT
138.00 138.00 2.00 1 34 HAMMER, UT BUTLERVILLE, UT
Wood - H 138.00 138.00 25.00 1 35 HONEYVILLE, UT LAMPO, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.5
36 TOTAL 16,211.00 694.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2014/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.
397.5 ACSR 26/7 1
397.5 ACSR 26/7 2
795 ACSR 26/7 3
556.5 ACSR 26/7 4
795 ACSR 26/7 5
1272 ACSR 45/7 6
954 ACSR 54/7 7
795 ACSR 26/7 8
1272 ACSR 45/7 9
397.5 ACSR 26/7 10
795 AAC /37 11
795 AAC /37 12
397.5 ACSR 26/7 13
250 CUHD /12 14
1272 ACSR 45/7 15
795 ACSR 26/7 16
795 ACSR 26/7 17
795 ACSR 26/7 18
795 ACSR 26/7 19
795 ACSR 26/7 20
1272 ACSR 45/7 21
1272 ACSR 45/7 22
795 ACSR 26/7 23
795 ACSR 26/7 24
397.5 ACSR 26/7 25
1272 AAC /61 26
1272 ACSR 45/7 27
1272 ACSR 45/7 28
1272 ACSR 45/7 29
397.5 ACSR 26/7 30
397.5 ACSR 26/7 31
1272 ACSR 45/7 32
1272 ACSR 45/7 33
795 ACSR 26/7 34
397.5 ACSR 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.5
36 211,652,349 3,045,766,779 3,257,419,128 488,475 15,845,636 1,917,195 18,251,306
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
/ /2014/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.
138.00 138.00 14.00 1 1 HONEYVILLE, UT WHEELON, UT
Wood - H 138.00 138.00 7.00 1 2 HUNTINGTON, UT MCFADDEN, UT
Wood - H 138.00 138.00 26.00 1 3 JERUSALEM, UT NEBO, UT
Wood -SP 138.00 138.00 1.00 1 4 JORDAN, UT THIRDWEST, UT
Wood -SP 138.00 138.00 5.00 1 5 JORDAN, UT MCCLELLAND, UT
Wood -SP 138.00 138.00 6.00 1 6 JORDAN, UT TERMINAL, UT
Wood -SP 138.00 138.00 1.00 1 7 BARNEYS, UT GRINDING, UT
Wood -SP 138.00 138.00 3.00 1 8 KEARNS, UT TAYLORSVILLE, UT
Wood -SP 138.00 138.00 2.00 1 9 KEARNS, UT WEST VALLEY, UT
138.00 138.00 8.00 1 10 LONE PEAK, UT CAMP WILLIAMS, UT
Wood -SP 138.00 138.00 6.00 1 11 MCCLELLAND, UT MID VALLEY, UT
Wood - H 138.00 138.00 11.00 1 12 MCFADDEN, UT BLACKHAWK, UT
Wood -SP 138.00 138.00 2.00 4.00 1 13 MID VALLEY, UT TAYLORSVILLE, UT
Wood -SP 138.00 138.00 5.00 1 14 MID VALLEY #2, UT COTTONWOOD, UT
Wood -SP 138.00 138.00 3.00 1 15 MID VALLEY #1, UT COTTONWOOD, UT
Wood - H 138.00 138.00 9.00 1 16 MID VALLEY, UT 90TH SOUTH, UT
Wood - H 138.00 138.00 1.00 1 17 MIDDLETON, UT SAINT GEORGE, UT
Wood - H 138.00 138.00 68.00 1 18 MOAB, UT PINTO, UT
Wood - H 138.00 138.00 36.00 1 19 NAUGHTON, WY CANYON COMP, WY
Wood - H 138.00 138.00 48.00 1 20 NAUGHTON, WY PAINTER, WY
Wood - H 138.00 138.00 33.00 1 21 NEBO, UT DRY CREEK, UT
Wood - H 138.00 138.00 10.00 1 22 NUCOR STEEL, UT WHEELON, UT
Wood - H 138.00 138.00 23.00 1 23 ONEIDA, ID OVID, UT
Wood - H 138.00 138.00 19.00 1 24 ONEIDA, ID GRACE, ID
Wood -SP 138.00 138.00 14.00 1 25 GRINDING, UT OQUIRRH, UT
Wood-SP 138.00 138.00 7.00 1 26 GRINDING, UT TOOELE, UT
Steel - SP 138.00 138.00 23.00 1 27 OQUIRRH, UT TOOELE, UT
Wood - H 138.00 138.00 5.00 1 28 OQUIRRH, UT BARNEY, UT
Wood - H 138.00 138.00 8.00 1 29 OQUIRRH, UT BINGHAM CANYON, UT
Wood - H 138.00 138.00 7.00 1 30 PAINTER, UT RAILROAD, UT
Wood - H 138.00 138.00 21.00 1 31 PAROWAN, UT WEST CEDAR, UT
Steel - SP 138.00 138.00 16.00 1 32 PARRISH, UT TERMINAL #1, UT
138.00 138.00 14.00 1 33 PARRISH, UT TERMINAL #2, UT
Steel - SP 138.00 138.00 14.00 1 34 PARRISH #105, UT TERMINAL, UT
Steel - SP 138.00 138.00 8.00 1 35 PARRISH, UT TAP TO N SALT LAKE, UT
FERC FORM NO. 1 (ED. 12-87)Page 422.6
36 TOTAL 16,211.00 694.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2014/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.
250 CUHD /12 1
397.5 ACSR 26/7 2
397.5 ACSR 26/7 3
1272 AAC /61 4
795 AAC /37 5
1272 AAC /91 6
1272 AAC /61 7
500 AAC /19 8
9
1272 ACSR 45/7 10
795 AAC 26/7 11
795 AAC 26/7 12
1272 ACSR /61 13
14
15
1272 ACSR 45/7 16
397.5 ACSR 26/7 17
397.5 ACSR 26/7 18
795 AAC 26/7 19
795 AAC 26/7 20
795 AAC 26/7 21
397.5 ACSR 26/7 22
336.4 ACSR 26/7 23
250 CUHD /12 24
795 AAC 45/7 25
796 AAC 45/7 26
1272 ACSR 45/7 27
795 AAC 26/7 28
1557.4 ACSR/TW 29
1272 ACSR 45/7 30
397.5 ACSR 26/7 31
795 AAC 45/7 32
795 AAC 26/7 33
795 AAC 45/7 34
795 AAC 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.6
36 211,652,349 3,045,766,779 3,257,419,128 488,475 15,845,636 1,917,195 18,251,306
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
/ /2014/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 17.00 1 1 RAILROAD, UT CANYON COMP, WY
Steel - SP 138.00 138.00 20.00 1 2 CENTRAL (UAMPS) #2, UT SAINT GEORGE, UT
Steel - SP 138.00 138.00 20.00 1 3 CENTRAL (UAMPS) #3, UT SAINT GEORGE, UT
Steel - SP 138.00 138.00 1.00 1 4 RED BUTTE, UT SAINT GEORGE, UT
Wood - H 138.00 138.00 49.00 1 5 RED BUTTE, UT WEST CEDAR, UT
Steel - SP 138.00 138.00 7.00 1 6 RIVERDALE, UT EAST LAYTON, UT
Wood - H 138.00 138.00 10.00 1 7 SHICK, UT PARRISH, UT
Wood - SP 138.00 138.00 10.00 1 8 SILVER CREEK, UT JORDANELLE, UT
Wood - H 138.00 138.00 10.00 1 9 SPANISH FORK, UT TANNER, UT
Wood - SP 138.00 138.00 2.00 1 10 SUNRISE, UT OQUIRRH, UT
Steel - SP 138.00 138.00 1.00 1 11 SYRACUSE, UT CLEARFIELD SOUTH, UT
Steel Tower 138.00 138.00 15.00 1 12 SYRACUSE, UT PARRISH, UT
138.00 138.00 9.00 1 13 SYRACUSE, UT ANGEL #1, UT
Wood - H 138.00 138.00 13.00 1 14 TAP TO ANGEL NORTH, UT TAP TO PARRISH, UT
Wood - SP 138.00 138.00 2.00 6.00 1 15 TAYLORSVILLE, UT 90TH SOUTH, UT
Steel - SP 138.00 138.00 9.00 1 16 TERMINAL, UT KENNECOTT, UT
Wood - H 138.00 138.00 53.00 1 17 TERMINAL, UT ROWLEY, UT
Wood - H 138.00 138.00 7.00 1 18 TERMINAL, UT MID VALLEY #1, UT
Wood - H 138.00 138.00 7.00 1 19 TERMINAL, UT MID VALLEY #2, UT
Wood - H 138.00 138.00 6.00 24.00 1 20 TERMINAL, UT TOOELE, UT
Wood - SP 138.00 138.00 7.00 1 21 TERMINAL, UT WEST VALLEY, UT
Wood - H 138.00 138.00 17.00 1 22 THREEMILE KNOLL, ID GRACE #1, ID
Wood - H 138.00 138.00 17.00 1 23 THREEMILE KNOLL, ID GRACE #2, ID
Wood - H 138.00 138.00 2.00 1 24 THREEMILE KNOLL, ID MONSANTO #1, ID
Steel - SP 138.00 138.00 2.00 1 25 THREEMILE KNOLL, ID MONSANTO #2, ID
Steel - SP 138.00 138.00 2.00 1 26 TIMP #1, UT DYNAMO, UT
138.00 138.00 2.00 1 27 TIMP #2, UT DYNAMO, UT
Steel - SP 138.00 138.00 4.00 1 28 TIMP, UT HALE, UT
Wood - H 138.00 138.00 23.00 1 29 TIMP, UT SPANISH FORK, UT
Steel Tower 138.00 138.00 25.00 1 30 TREASURETON, ID GRACE, ID
138.00 138.00 25.00 1 31 TREASURETON, ID GRACE #2, ID
Wood - H 138.00 138.00 6.00 1 32 TREASURETON, ID ONEIDA, ID
Wood - SP 138.00 138.00 22.00 1 33 TRI-CITY, UT SUNRISE, ID
Wood - SP 138.00 138.00 12.00 6.00 1 34 TRI-CITY, UT BANGERTER, UT
Wood - H 138.00 138.00 15.00 1 35 TRI-CITY, UT WESTFIELD, UT
FERC FORM NO. 1 (ED. 12-87)Page 422.7
36 TOTAL 16,211.00 694.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2014/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i)(j)(k)(l)(m)(n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
795 ACSR 26/7 1
1272 ACSR 45/7 2
1272 ACSR 45/7 3
1272 ACSR 45/7 4
397.5 ACSR 26/7 5
795 AAC 26/7 6
250 CUHD /12 7
795 AAC 26/7 8
1272 ACSR 45/7 9
10
1272 ACSR 45/7 11
1272 ACSR 45/7 12
250 CUHD /12 13
795 AAC /37 14
795 AAC /37 15
795 AAC 26/7 16
795 AAC /37 17
1272 ACSR 45/7 18
1272 AAC /61 19
397.5 ACSR 26/7 20
21
250 CUHD /12 22
1272 ACSR 45/7 23
1272 AAC /61 24
1272 ACSR 45/7 25
26
27
28
29
250 CUHD /12 30
250 CUHD /12 31
250 CUHD /12 32
33
34
1272 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.7
36 211,652,349 3,045,766,779 3,257,419,128 488,475 15,845,636 1,917,195 18,251,306
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
/ /2014/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 20.00 1 1 WEST CEDAR, UT THREE PEAKS, UT
Wood - H 138.00 138.00 9.00 1 2 WEST VALLEY, UT OQUIRRH, UT
Wood - H 138.00 138.00 14.00 1 3 WESTFIELD, UT HALE, UT
Wood - H 138.00 138.00 86.00 1 4 WHEELON, UT AMERICAN FALLS, ID
Steel Tower 138.00 138.00 29.00 1 5 WHEELON #1, UT TREASURETON, ID
138.00 138.00 29.00 1 6 WHEELON #2, UT TREASURETON, ID
Wood - H 138.00 138.00 29.00 1 7 WHEELON #3, UT TREASURETON, ID
Wood - SP 138.00 138.00 3.00 1 8 FORT DOUGLAS, UT MCCLELLAND, UT
9 138 kV costs and expenses
10
207.00 2,070.00 140 11 Subtotal 138 kV
12
1,636.00 13 All 115 kV Lines
14
2,966.00 15 All 69 kV Lines
16
113.00 17 All 57 kV Lines
18
2,544.00 19 All 46 kV Lines
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 422.8
36 TOTAL 16,211.00 694.00 272
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2014/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
2
795 AAC 26/7 3
250 CUHD /12 4
250 CUHD /12 5
250 CUHD /12 6
250 CUHD /12 7
8
365,201,981 346,043,380 19,158,601 2,198,843 109,823 1,965,663 123,357 9
10
365,201,981 346,043,380 19,158,601 2,198,843 109,823 1,965,663 123,357 11
12
184,851,867 179,774,507 5,077,360 2,290,524 229,146 2,057,338 4,040 13
14
272,128,425 264,967,484 7,160,941 3,332,562 207,831 3,059,220 65,511 15
16
10,441,227 10,394,900 46,327 46,660 3,791 41,472 1,397 17
18
252,529,253 242,572,698 9,956,555 2,561,691 26,721 2,399,489 135,481 19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 423.8
36 211,652,349 3,045,766,779 3,257,419,128 488,475 15,845,636 1,917,195 18,251,306
Schedule Page: 422 Line No.: 1 Column: a
Certain transmission lines reported on pages 422-423 are part of exchange agreements with
various third parties. Refer to the footnotes on pages 328-330 of this FERC Form No. 1
for further discussion.
Schedule Page: 422 Line No.: 2 Column: a
The Dixonville - Meridian 500-kV line is jointly owned by PacifiCorp and the Bonneville
Power Administration ("the BPA"). Ownership of the line is as follows: PacifiCorp 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, Avista Corporation 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, Avista Corporation 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, Avista Corporation 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
Broadview - Townsend A 500-kV line is jointly owned by PacifiCorp, NorthWestern
Corporation, Puget Sound Energy, Avista Corporation 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
Broadview - Townsend B 500-kV line is jointly owned by PacifiCorp, NorthWestern
Corporation, Puget Sound Energy, Avista Corporation 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.: 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
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: 422.2 Line No.: 12 Column: a
Complete name is GONDER (NV ENERGY), UT - NV STATE.
Schedule Page: 422.4 Line No.: 21 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 9 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 14 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 15 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 29 Column: b
Complete name is BINGHAM CANYON (KCC), UT.
Schedule Page: 422.7 Line No.: 2 Column: a
The Central - Saint 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.: 3 Column: a
See Footnote on page 422.7 for line 2 column (a).
Schedule Page: 422.7 Line No.: 10 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 21 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 26 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.: 33 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: 422.8 Line No.: 2 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 8 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
2014/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
/ /2014/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
1 None
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
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
/ /2014/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
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
FERC FORM NO. 1 (REV. 12-03) Page 425
44
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 / /2014/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 12.47 115.00DISTRIBUTION-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 / /2014/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 / /2014/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 3082.00 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 / /2014/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 / /2014/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 SUB 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 / /2014/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 / /2014/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 46.00 2.40TRANSMISSION-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 46.00 138.00 6.60TRANSMISSION-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 1254.47 2921.00 217.94 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 / /2014/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
30 1 10
71 4 1 11
14 1 12
189 4 13
40 2 14
344 12 1 15
16
17
75 1 1 18
445 3 19
15 1 20
67 1 21
67 1 22
67 1 23
25 3 24
75 1 25
908 4 26
217 2 27
233 3 28
30 1 29
76 2 30
168 3 31
700 1 32
533 2 33
3701 30 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 / /2014/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
CANYONVILLE SUB 12.47 116.00DISTRIBUTION-UNATTEN 29
CARNES SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
CASEBEER SUB 20.80 69.00DISTRIBUTION-UNATTEN 31
CAVEMAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 32
CHERRY LANE SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
CHILOQUIN MARKET SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
CHINA HAT SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
CIRCLE BLVD SUB 20.80 115.00DISTRIBUTION-UNATTEN 36
CLEVELAND AVE SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
CLOAKE SUB 20.80 69.00DISTRIBUTION-UNATTEN 38
COBURG SUB 20.80 69.00DISTRIBUTION-UNATTEN 39
COLISEUM SUB 4.16 20.80DISTRIBUTION-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 / /2014/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
25 1 29
9 3 30
20 1 31
45 2 32
25 1 33
6 3 34
25 1 35
80 2 36
45 2 37
20 1 38
10 3 39
9 2 40
FERC FORM NO. 1 (ED. 12-96)Page 427.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2014/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).
COLUMBIA SUB 12.47 115.00 57.00DISTRIBUTION-UNATTEN 1
COOS RIVER SUB 20.80 115.00DISTRIBUTION-UNATTEN 2
COQUILLE SUB 20.80 115.00DISTRIBUTION-UNATTEN 3
CREEK SUB 34.50 69.00DISTRIBUTION-UNATTEN 4
CROOKED RIVER RANCH SUB 20.80 69.00DISTRIBUTION-UNATTEN 5
CROWFOOT SUB 12.47 115.00DISTRIBUTION-UNATTEN 6
CULLY SUB 12.47 115.00DISTRIBUTION-UNATTEN 7
CULVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
DAIRY SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
DALLAS SUB 20.80 115.00DISTRIBUTION-UNATTEN 10
DALREED SUB 34.50 230.00DISTRIBUTION-UNATTEN 11
DESCHUTES SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
DEVILS LAKE SUB 20.80 115.00DISTRIBUTION-UNATTEN 13
DIXON SUB 4.16 115.00DISTRIBUTION-UNATTEN 14
DODGE BRIDGE SUB 20.80 69.00DISTRIBUTION-UNATTEN 15
DOWELL SUB 12.47 115.00DISTRIBUTION-UNATTEN 16
EASY VALLEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
EMPIRE SUB 20.80 115.00DISTRIBUTION-UNATTEN 18
ENTERPRISE SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
FERN HILL SUB 12.47 115.00DISTRIBUTION-UNATTEN 20
FIELDER CREEK SUB 20.80 115.00DISTRIBUTION-UNATTEN 21
FOOTHILLS SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
FRALEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
GARDEN VALLEY SUB 20.80 69.00DISTRIBUTION-UNATTEN 24
GAZLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
GLENDALE SUB 12.47 230.00DISTRIBUTION-UNATTEN 26
GLENEDEN SUB 4.16 20.80DISTRIBUTION-UNATTEN 27
GLIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 28
GOLD HILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
GORDON HOLLOW SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
GOSHEN SUB 20.80 115.00DISTRIBUTION-UNATTEN 31
GRANT STREET SUB 20.80 115.00DISTRIBUTION-UNATTEN 32
GRASS VALLEY SUB 4.16 20.80DISTRIBUTION-UNATTEN 33
GREEN SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
GRIFFIN CREEK SUB 12.47 115.00DISTRIBUTION-UNATTEN 35
HAMAKER SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
HARRISBURG SUB 20.80 69.00DISTRIBUTION-UNATTEN 37
HENLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
HERMISTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
HILLVIEW SUB 20.80 115.00DISTRIBUTION-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 / /2014/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.
55 2 1 1
20 1 2
40 2 3
5 1 4
25 2 5
20 1 6
25 1 7
13 1 8
25 1 9
50 2 10
75 3 11
25 1 12
50 2 13
7 1 14
13 1 15
20 1 16
45 2 17
20 1 18
19 2 19
12 1 20
25 1 21
21 4 22
5 3 23
20 1 24
8 4 25
25 2 26
5 1 27
12 1 28
11 3 29
6 1 30
20 1 31
45 2 32
1 4 33
25 1 34
20 1 35
8 3 36
13 1 37
6 3 38
40 1 39
45 2 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 / /2014/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).
HINKLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
HOLLADAY SUB 12.47 115.00DISTRIBUTION-UNATTEN 2
HOLLYWOOD SUB 12.47 115.00DISTRIBUTION-UNATTEN 3
HOOD RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
HORNET SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
HUMBUG CREEK SUB 12.50 67.00DISTRIBUTION-UNATTEN 6
HUNTERS CIRCLE TEMP SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
ILLAHEE FLATS SUB 12.47 115.00DISTRIBUTION-UNATTEN 8
INDEPENDENCE SUB 20.80 69.00DISTRIBUTION-UNATTEN 9
JACKSONVILLE SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 10
JEFFERSON SUB 20.80 69.00DISTRIBUTION-UNATTEN 11
JEROME PRAIRIE SUB 12.47 115.00DISTRIBUTION-UNATTEN 12
JORDAN POINT SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
JOSEPH SUB 12.47 20.80DISTRIBUTION-UNATTEN 14
JUNCTION CITY SUB 20.80 69.00DISTRIBUTION-UNATTEN 15
KENWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
KILLINGWORTH SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
KNAPPA SVENSEN SUB 12.47 115.00DISTRIBUTION-UNATTEN 18
LAKEPORT SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
LANCASTER SUB 20.80 69.00DISTRIBUTION-UNATTEN 20
LEBANON SUB 20.80 115.00DISTRIBUTION-UNATTEN 21
LINCOLN SUB 12.47 115.00DISTRIBUTION-UNATTEN 22
LOCKHART SUB 20.80 115.00DISTRIBUTION-UNATTEN 23
LYONS SUB 20.80 69.00DISTRIBUTION-UNATTEN 24
MADRAS SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
MALLORY SUB 12.47 115.00DISTRIBUTION-UNATTEN 26
MARYS RIVER SUB 20.80 115.00DISTRIBUTION-UNATTEN 27
MEDCO SUB 12.47 115.00DISTRIBUTION-UNATTEN 28
MEDFORD 12.47 115.00DISTRIBUTION-UNATTEN 29
MERLIN SUB 12.47 115.00DISTRIBUTION-UNATTEN 30
MERRILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
MINAM SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
MODOC SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
MORO SUB 2.40 20.80DISTRIBUTION-UNATTEN 34
MURDER CREEK SUB 20.80 115.00DISTRIBUTION-UNATTEN 35
MYRTLE CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
MYRTLE POINT SUB 20.80 115.00DISTRIBUTION-UNATTEN 37
NELSCOTT SUB 4.16 20.80DISTRIBUTION-UNATTEN 38
NEW O'BRIEN SUB 12.47 115.00DISTRIBUTION-UNATTEN 39
OAK KNOLL 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 / /2014/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
75 3 2
50 2 3
40 2 4
20 1 5
9 1 6
12 1 7
2 1 8
20 1 9
75 2 10
12 1 11
20 1 12
20 1 13
6 1 1 14
25 2 15
3 3 16
40 2 17
6 1 18
50 2 19
12 3 20
40 2 21
105 3 22
40 2 23
9 2 24
25 2 25
25 1 26
20 1 27
20 1 28
67 8 29
45 2 30
17 6 31
1 32
6 3 33
2 3 34
100 4 35
14 1 36
9 1 37
4 1 38
9 1 39
45 2 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 / /2014/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).
OAKLAND SUB 12.47 115.00DISTRIBUTION-UNATTEN 1
OREMET SUB 12.47 115.00DISTRIBUTION-UNATTEN 2
OVERPASS SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
PALLETTE SUB 20.80 69.00DISTRIBUTION-UNATTEN 4
PARK STREET SUB 12.47 115.00DISTRIBUTION-UNATTEN 5
PARKROSE SUB 12.47 57.00DISTRIBUTION-UNATTEN 6
PENDLETON SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
PILOT ROCK SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
POWELL BUTTE SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
PRINEVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 10
PROVOLT SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
QUEEN AVE SUB 20.80 69.00DISTRIBUTION-UNATTEN 12
RED BLANKET SUB 4.16 69.00DISTRIBUTION-UNATTEN 13
REDMOND SUB 12.47 115.00DISTRIBUTION-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 20.80 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 12.47 115.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2014/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.
8 1 1
75 2 2
45 2 3
1 1 1 4
40 2 5
39 2 6
46 7 1 7
22 2 8
6 1 9
50 2 10
11 3 11
50 2 12
2 3 13
50 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 / /2014/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 2511.60 15569.27 195.00 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 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
RIDDLE SUB 69.00 115.00T/D-UNATTENDED 37
SAGE ROAD SUB 12.47 115.00T/D-UNATTENDED 38
WINCHESTER SUB 12.47 115.00 69.00T/D-UNATTENDED 39
TOTAL 489.44 1449.00 338.82 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 / /2014/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
2 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
4569 345 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
75 2 37
40 2 38
75 5 39
1337 44 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 / /2014/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).
Number of Substations-12 1
2
LEMOLO #1 HYDRO 12.50 11.50TRANSMISSION-ATTENDE 3
CALAPOOYA SUB 69.00 230.00TRANSMISSION-UNATTEN 4
CHILOQUIN SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 5
COLD SPRINGS SUB 69.00 230.00 2.40TRANSMISSION-UNATTEN 6
COVE SUB 69.00 230.00TRANSMISSION-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 2691.50 5950.50 431.27 30
Number of Substations-27 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 / /2014/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
2 3 1 3
75 1 4
119 4 5
66 2 6
67 3 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
500 2 25
30 3 26
50 1 27
500 3 28
100 2 29
7261 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 / /2014/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 67.00DISTRIBUTION-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 / /2014/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 / /2014/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
DEWEYVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
DIMPLE DELL SUB 12.47 138.00DISTRIBUTION-UNATTEN 11
DRAPER SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
EAST BENCH SUB 12.47 138.00DISTRIBUTION-UNATTEN 13
EAST HYRUM SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
EAST LAYTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 15
EAST MILLCREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
EDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
ELBERTA SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
ELK MEADOWS SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
ELSINORE SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
EMERY CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
EMIGRATION SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
ENOCH SUB 12.47 138.00DISTRIBUTION-UNATTEN 23
ENTERPRISE VALLEY SUB 12.47 138.00DISTRIBUTION-UNATTEN 24
EUREKA SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
FARMINGTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 26
FAYETTE SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
FERRON SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
FIELDING SUB 12.00 46.00DISTRIBUTION-UNATTEN 29
FIFTH WEST SUB 12.47 138.00DISTRIBUTION-UNATTEN 30
FLUX SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
FOOL CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
FORT DOUGLAS 13.20 138.00DISTRIBUTION-UNATTEN 33
FOUNTAIN GREEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
FREEDOM SUB 7.20 46.00DISTRIBUTION-UNATTEN 35
FRUIT HEIGHTS SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
GARDEN CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
GATEWAY SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
GOLD RUSH SUB 12.50 138.00DISTRIBUTION-UNATTEN 39
GORDON AVENUE SUB 12.50 138.00DISTRIBUTION-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 / /2014/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
4 1 10
60 2 11
23 2 12
30 1 13
6 1 14
60 2 15
20 1 16
19 2 17
5 1 18
3 1 19
2 1 20
3 3 21
25 1 22
14 1 23
10 1 24
3 1 25
30 1 26
1 2 27
5 1 28
6 1 29
50 2 30
4 1 31
2 1 32
40 1 33
7 1 34
1 35
22 1 36
12 1 37
28 1 1 38
30 1 39
30 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 / /2014/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).
GOSHEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
GRANGER SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
GRANTSVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
GUNNISON SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
HAMMER SUB 12.47 138.00DISTRIBUTION-UNATTEN 5
HAVASU SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
HELPER CITY SUB 4.16 46.00DISTRIBUTION-UNATTEN 7
HENEFER SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
HERRIMAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 9
HIGHLAND DIST SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
HOGGARD SUB 12.47 138.00DISTRIBUTION-UNATTEN 11
HOLDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
HOLLADAY SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
HUNTER SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
HUNTINGTON CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
IRON MOUNTAIN SUB 7.20 34.50DISTRIBUTION-UNATTEN 16
IRONTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
IVINS SUB 12.47 34.50DISTRIBUTION-UNATTEN 18
JORDAN NARROWS SUB 2.40 46.00DISTRIBUTION-UNATTEN 19
JORDAN PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 20
JORDANELLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 21
JUAB SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
JUNCTION SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
KAIBAB SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
KAMAS SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
KEARNS SUB 12.47 138.00DISTRIBUTION-UNATTEN 26
KENSINGTON SUB 4.16 46.00DISTRIBUTION-UNATTEN 27
KYUNE SUB 7.20 46.00DISTRIBUTION-UNATTEN 28
LAKE PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 29
LARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
LAYTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
LEGRANDE SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
LEWISTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
LINCOLN SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
LINDON SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
LISBON SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
LOAFER SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
LOGAN CANYON SUB 7.20 46.00DISTRIBUTION-UNATTEN 38
LONE TREE SUB 12.47 34.50DISTRIBUTION-UNATTEN 39
LOWER BEAVER SUB 6.60 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.12
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2014/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i)(j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
2 1 1
50 2 2
23 1 3
11 2 4
60 2 5
3 1 6
3 3 7
4 1 8
30 1 9
25 1 10
50 2 11
4 1 12
32 2 13
22 1 14
12 2 15
1 1 16
2 1 17
22 1 18
13 2 19
30 1 20
30 1 21
2 3 22
3 1 23
5 1 24
7 1 25
60 2 26
7 1 27
1 28
53 2 29
6 1 30
40 2 31
2 1 32
14 1 33
20 1 34
20 1 35
4 1 36
1 37
1 1 38
20 1 39
1 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 / /2014/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).
LYNNDYL SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
MAESER SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
MAGNA SUB 12.47 138.00DISTRIBUTION-UNATTEN 3
MANILA SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
MANTUA SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
MAPLETON SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
MARRIOTT SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
MARYSVALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
MATHIS SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
MCCORNICK SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
MCKAY SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
MEADOWBROOK SUB 12.47 138.00 46.00DISTRIBUTION-UNATTEN 12
MEDICAL SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
MIDLAND SUB 12.47 138.00DISTRIBUTION-UNATTEN 14
MIDVALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
MILFORD SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
MILFORD TV SUB 13.20 46.00DISTRIBUTION-UNATTEN 17
MINERSVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
MOAB CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
MONTEZUMA SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
MOORE SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
MORGAN SUB 4.16 46.00DISTRIBUTION-UNATTEN 22
MORONI SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
MOSS JUNCTION SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
MOUNTAIN DELL SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
MOUNTAIN GREEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
MYTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
NEW HARMONY SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
NEWGATE SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
NEWTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
NIBLEY SUB 24.90 138.00DISTRIBUTION-UNATTEN 31
NORTH BENCH SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
NORTH FIELDS SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
NORTH LOGAN SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
NORTH OGDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
NORTH SALT LAKE SUB 13.20 46.00DISTRIBUTION-UNATTEN 36
NORTHEAST SUB 12.50 46.00DISTRIBUTION-UNATTEN 37
NORTHRIDGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
OAKLAND AVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
OAKLEY 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 / /2014/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.
4 1 1
12 1 2
30 1 3
22 1 4
2 1 5
14 1 6
20 1 7
3 1 8
9 1 9
6 1 10
20 1 11
42 2 12
57 4 13
30 1 14
25 1 15
14 1 16
1 17
2 1 18
19 2 19
12 1 20
3 1 21
7 2 22
6 1 23
6 3 24
5 1 25
6 1 26
6 1 27
7 1 28
20 1 29
5 1 30
14 1 31
25 1 32
2 1 33
25 1 34
22 1 35
25 1 36
45 2 37
14 1 38
24 2 39
6 1 40
FERC FORM NO. 1 (ED. 12-96)Page 427.13
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2014/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).
OLYMPUS SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
OPHIR SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
ORANGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
ORANGEVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
OREM SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
PACK CREEK RESERVOIR 12.47 46.00DISTRIBUTION-UNATTEN 6
PANGUITCH SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
PARIETTE SUB 24.94 67.00DISTRIBUTION-UNATTEN 8
PARK CITY SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
PARKWAY SUB 12.47 138.00DISTRIBUTION-UNATTEN 10
PARLEYS SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
PELICAN POINT SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
PINE CANYON SUB 12.47 138.00DISTRIBUTION-UNATTEN 13
PINE CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
PINNACLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
PLAIN CITY SUB 12.47 138.00DISTRIBUTION-UNATTEN 16
PLEASANT GROVE SUB 12.47 138.00DISTRIBUTION-UNATTEN 17
PLEASANT VIEW SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
PORTER ROCKWELL SUB 12.47 138.00DISTRIBUTION-UNATTEN 19
PROMONTORY SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
QUAIL CREEK SUB 12.47 34.50DISTRIBUTION-UNATTEN 21
QUARRY SUB 12.47 138.00DISTRIBUTION-UNATTEN 22
QUICHAPA SUB 12.47 34.50DISTRIBUTION-UNATTEN 23
RAINS SUB 7.20 46.00DISTRIBUTION-UNATTEN 24
RANDOLPH SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
RASMUSON SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
RATTLESNAKE SUB 24.90 69.00DISTRIBUTION-UNATTEN 27
RED MOUNTAIN SUB 34.50 69.00DISTRIBUTION-UNATTEN 28
RED ROCK SUB 4.16 69.00DISTRIBUTION-UNATTEN 29
REDWOOD SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
RESEARCH PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
RICH SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
RICHFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
RICHMOND SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
RIDGELAND SUB 12.47 138.00DISTRIBUTION-UNATTEN 35
RITER SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
ROCK CANYON SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
ROCKVILLE SUB 12.47 34.50DISTRIBUTION-UNATTEN 38
ROCKY POINT 13.20 138.00DISTRIBUTION-UNATTEN 39
ROSE PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.14
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2014/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
3 1 2
20 1 3
14 1 4
48 2 5
4 1 6
5 1 7
14 1 8
35 2 9
50 2 10
16 2 11
6 1 12
55 2 13
2 1 14
14 1 15
22 1 16
25 1 17
14 1 18
30 1 19
2 1 20
4 1 21
60 2 22
4 1 23
15 1 24
2 1 25
1 3 26
14 1 27
12 1 28
3 1 29
45 2 30
45 2 31
5 1 32
22 2 33
11 1 34
40 2 35
20 1 36
5 1 37
4 1 38
30 1 39
24 3 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 / /2014/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).
ROYAL SUB 4.16 46.00DISTRIBUTION-UNATTEN 1
SALINA SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
SANDY SUB 12.47 138.00DISTRIBUTION-UNATTEN 3
SARATOGA SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
SCIPIO SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
SCOFIELD RESERVOIR SUB 7.20 46.00DISTRIBUTION-UNATTEN 6
SCOFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
SECOND STREET SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
SEGO CANYON SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
SEVEN MILE SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
SHARON SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
SHIVWITS SUB 4.16 34.50DISTRIBUTION-UNATTEN 12
SHORELINE SUB 13.20 138.00DISTRIBUTION-UNATTEN 13
SIXTH SOUTH SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
SKULL VALLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
SKYPARK SUB 12.50 138.00 12.50DISTRIBUTION-UNATTEN 16
SNARR SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
SNOWVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
SNYDERVILLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 19
SOLDIER SUMMIT SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
SOUTH JORDAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 21
SOUTH MILFORD SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
SOUTH MOUNTAIN SUB 12.47 138.00DISTRIBUTION-UNATTEN 23
SOUTH OGDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
SOUTH PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 25
SOUTH WEBER SUB 12.47 138.00DISTRIBUTION-UNATTEN 26
SOUTHWEST SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
SPANISH VALLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
SPRINGDALE SUB 12.47 34.50DISTRIBUTION-UNATTEN 29
ST. JOHNS SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
STANSBURY SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
SUMMIT CREEK SUB 12.47 138.00DISTRIBUTION-UNATTEN 32
SUMMIT PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
SUNRISE SUB 12.47 138.00DISTRIBUTION-UNATTEN 34
SUPERIOR SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
SUTHERLAND SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
TAMARISK SUB 12.47 138.00DISTRIBUTION-UNATTEN 37
TAYLOR SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
THIEF CREEK SUB 24.90 138.00DISTRIBUTION-UNATTEN 39
THIRD WEST SUB 13.20 138.00DISTRIBUTION-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 / /2014/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
11 1 2
60 2 3
60 2 4
1 3 5
1 1 6
1 3 7
13 2 8
14 1 9
1 10
20 1 11
6 1 12
60 2 13
20 1 14
2 1 15
40 1 16
40 2 17
5 1 18
60 2 19
12 1 20
60 2 21
20 2 22
60 2 23
25 1 24
30 1 25
22 1 26
22 2 27
6 1 28
4 1 29
4 1 30
20 1 31
14 1 32
7 1 33
60 2 34
8 1 35
6 1 36
20 1 37
14 1 38
14 1 39
100 2 40
FERC FORM NO. 1 (ED. 12-96)Page 427.15
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2014/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).
THIRTEENTH SOUTH SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
TOOELE DEPOT SUB 12.50 46.00DISTRIBUTION-UNATTEN 2
TOQUERVILLE SUB 12.47 69.00 34.50DISTRIBUTION-UNATTEN 3
UINTAH SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
UNION SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
VALLEY CENTER SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
VERMILLION SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
VERNAL SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
VICKERS SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
VINEYARD SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
WALLSBURG SUB 12.47 138.00DISTRIBUTION-UNATTEN 11
WALNUT GROVE SUB 12.50 138.00DISTRIBUTION-UNATTEN 12
WARREN SUB 12.47 138.00DISTRIBUTION-UNATTEN 13
WASATCH STATE PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
WASHAKIE SUB 4.16 138.00DISTRIBUTION-UNATTEN 15
WELBY SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
WELFARE SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
WEST COMMERCIAL SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
WEST JORDAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 19
WEST OGDEN SUB 12.47 138.00DISTRIBUTION-UNATTEN 20
WEST ROY SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
WEST TEMPLE SUB 4.16 46.00DISTRIBUTION-UNATTEN 22
WESTWATER SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
WHITE MESA SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
WHITE ROCK SUB 12.47 138.00DISTRIBUTION-UNATTEN 25
WILLOWCREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
WILLOWRIDGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
WINCHESTER HILLS SUB 12.47 34.50DISTRIBUTION-UNATTEN 28
WINKLEMAN SUB 7.20 46.00DISTRIBUTION-UNATTEN 29
WOLF CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
WOOD CROSS SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
WOODRUFF SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
TOTAL 3535.85 19877.30 105.47 33
Number of Substations-279 34
35
90TH SOUTH SUB 138.00 345.00 12.47T/D-UNATTENDED 36
ANGEL SUB 12.47 138.00 46.00T/D-UNATTENDED 37
BDO SUBSTATION 12.47 138.00T/D-UNATTENDED 38
BUTLERVILLE SUB 46.00 138.00 12.47T/D-UNATTENDED 39
CENTENNIAL SUB 12.47 138.00T/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 / /2014/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
25 1 2
34 2 3
39 2 4
50 2 5
22 1 6
3 1 7
33 2 8
2 1 9
25 1 10
13 1 11
30 1 12
30 1 13
2 3 14
14 1 15
42 2 16
10 1 17
22 1 18
28 1 19
60 2 20
25 1 21
60 3 22
5 1 23
14 1 24
30 1 25
1 1 26
14 1 27
4 1 28
1 29
6 1 30
20 1 31
2 1 32
5470 380 1 33
34
35
1572 5 1 36
135 3 37
30 1 38
205 4 39
40 2 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 / /2014/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).
COTTONWOOD SUB 12.47 138.00 46.00T/D-UNATTENDED 1
DECADE SUB 12.50 138.00T/D-UNATTENDED 2
DUMAS SUB 12.47 138.00T/D-UNATTENDED 3
EMMA PARK SUBSTATION 12.47 138.00T/D-UNATTENDED 4
GROW SUB 12.47 138.00 46.00T/D-UNATTENDED 5
HALE SUB 46.00 138.00 12.47T/D-UNATTENDED 6
HIGHLAND SUB 12.47 138.00 46.00T/D-UNATTENDED 7
JORDAN SUB 46.00 138.00 12.47T/D-UNATTENDED 8
JUDGE SUB 12.47 46.00T/D-UNATTENDED 9
MCCLELLAND SUB 46.00 138.00 12.47T/D-UNATTENDED 10
MORTON COURT SUB 12.47 138.00T/D-UNATTENDED 11
OQUIRRH SUB 46.00 345.00 138.00T/D-UNATTENDED 12
PARRISH SUB 12.47 138.00 46.00T/D-UNATTENDED 13
PIONEER PLANT 12.47 138.00T/D-UNATTENDED 14
RIVERDALE SUB 46.00 138.00 12.47T/D-UNATTENDED 15
SEVIER SUB 46.00 138.00 12.47T/D-UNATTENDED 16
SILVER CREEK SUB 12.47 138.00 46.00T/D-UNATTENDED 17
SOUTHEAST SUB 12.47 138.00 46.00T/D-UNATTENDED 18
SYRACUSE SUB 46.00 345.00 138.00T/D-UNATTENDED 19
TAYLORSVILLE SUB 46.00 138.00 12.47T/D-UNATTENDED 20
TERMINAL SUB 46.00 345.00 138.00T/D-UNATTENDED 21
TIMP SUB 46.00 138.00 12.47T/D-UNATTENDED 22
TOOELE SUB 46.00 138.00 12.47T/D-UNATTENDED 23
TRI CITY SUB 12.47 138.00T/D-UNATTENDED 24
WEST VALLEY SUB 12.47 138.00T/D-UNATTENDED 25
WESTFIELD SUB 12.47 138.00T/D-UNATTENDED 26
TOTAL 914.49 5014.00 860.70 27
Number of Substations-31 28
29
EMERY SUB 138.00 345.00 69.00TRANSMISSION-ATTENDE 30
GADSBY SUB 46.00 138.00TRANSMISSION-ATTENDE 31
ABAJO SUB 69.00 138.00TRANSMISSION-UNATTEN 32
ASHLEY SUB 46.00 138.00TRANSMISSION-UNATTEN 33
BARNEY SUB 46.00 138.00TRANSMISSION-UNATTEN 34
BEN LOMOND SUB 230.00 345.00 138.00TRANSMISSION-UNATTEN 35
BLACK ROCK SUB 69.00 230.00TRANSMISSION-UNATTEN 36
BLACKHAWK SUB 69.00 138.00 46.00TRANSMISSION-UNATTEN 37
CAMERON SUB 46.00 138.00TRANSMISSION-UNATTEN 38
CAMP WILLIAMS SUB 138.00 345.00 12.47TRANSMISSION-UNATTEN 39
CLOVER SUB 138.00 345.00 14.40TRANSMISSION-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 / /2014/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.
289 7 1
60 2 2
60 2 3
8 1 4
72 3 5
114 2 6
97 2 7
164 2 8
22 1 9
340 3 10
65 2 11
835 4 1 12
97 2 13
30 1 14
180 3 15
34 4 16
100 2 17
50 2 18
600 5 19
358 4 20
1108 6 2 21
130 2 22
249 3 23
30 1 24
30 1 25
20 1 26
7124 83 4 27
28
29
783 13 1 30
318 2 31
67 1 32
133 2 33
100 1 34
1813 5 35
75 1 36
100 2 37
25 4 38
169 2 39
448 1 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 / /2014/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).
COLUMBIA SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 1
CRANER FLAT SUB 12.47 138.00TRANSMISSION-UNATTEN 2
CUTLER SUB 46.00 138.00TRANSMISSION-UNATTEN 3
EL MONTE SUB 46.00 138.00TRANSMISSION-UNATTEN 4
GARKANE SUB 46.00 69.00TRANSMISSION-UNATTEN 5
GREEN CANYON SUB 46.00 138.00TRANSMISSION-UNATTEN 6
GRINDING SUB 13.80 138.00TRANSMISSION-UNATTEN 7
HELPER SUB 46.00 138.00TRANSMISSION-UNATTEN 8
HONEYVILLE SUB 46.00 138.00TRANSMISSION-UNATTEN 9
HORSESHOE SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 10
HUNTINGTON SUB 138.00 345.00 24.90TRANSMISSION-UNATTEN 11
JERUSALEM SUB 46.00 138.00TRANSMISSION-UNATTEN 12
LAMPO SUB 46.00 138.00TRANSMISSION-UNATTEN 13
MATHINGTON SUB 46.00 138.00 13.20TRANSMISSION-UNATTEN 14
MCFADDEN SUB 46.00 138.00TRANSMISSION-UNATTEN 15
MIDDLETON SUB 69.00 138.00 34.50TRANSMISSION-UNATTEN 16
MIDVALLEY SUB 138.00 345.00TRANSMISSION-UNATTEN 17
MIDWAY CITY SUB 46.00 138.00TRANSMISSION-UNATTEN 18
MINERAL PRODUCTS SUB 46.00 69.00TRANSMISSION-UNATTEN 19
MOAB SUB 69.00 138.00TRANSMISSION-UNATTEN 20
NEBO SUB 46.00 138.00TRANSMISSION-UNATTEN 21
PAROWAN VALLEY SUB 138.00 230.00 34.50TRANSMISSION-UNATTEN 22
PAVANT SUB 46.00 230.00TRANSMISSION-UNATTEN 23
PINTO SUB 138.00 345.00 69.00TRANSMISSION-UNATTEN 24
RED BUTTE SUB 138.00 230.00TRANSMISSION-UNATTEN 25
SIGURD SUB 230.00 345.00 138.00TRANSMISSION-UNATTEN 26
SMITHFIELD SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 27
SPANISH FORK SUB 138.00 345.00 46.00TRANSMISSION-UNATTEN 28
ST GEORGE SUB 16.50 138.00TRANSMISSION-UNATTEN 29
THREE PEAKS SUB 138.00 345.00TRANSMISSION-UNATTEN 30
WEST CEDAR SUB 138.00 230.00 34.50TRANSMISSION-UNATTEN 31
TOTAL 3331.77 8188.00 711.88 32
Number of Substations-42 33
34
WASHINGTON 35
ATTALIA SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
BOWMAN SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
CASCADE KRAFT SUB 12.47 69.00 4.16DISTRIBUTION-UNATTEN 38
CLINTON SUB 12.47 115.00DISTRIBUTION-UNATTEN 39
DAYTON SUB 12.47 69.00DISTRIBUTION-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 / /2014/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.
71 2 1
40 2 2
50 1 3
312 3 4
33 1 5
67 2 6
225 3 7
142 2 8
35 1 9
80 2 10
270 4 11
67 1 12
75 1 13
75 1 14
45 1 15
141 4 16
900 2 17
67 1 18
12 1 19
67 1 20
67 1 21
138 2 22
133 2 23
258 3 24
414 2 25
1124 6 26
63 2 27
1017 5 28
100 3 1 29
450 1 30
262 3 31
10831 100 2 32
33
34
35
25 1 36
45 2 37
118 6 38
25 1 39
23 2 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 / /2014/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).
DODD ROAD SUB 20.80 69.00DISTRIBUTION-UNATTEN 1
GRANDVIEW SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 2
HOPLAND SUB 12.47 115.00DISTRIBUTION-UNATTEN 3
NACHES 12.00 116.00DISTRIBUTION-UNATTEN 4
NOB HILL SUB 12.47 115.00DISTRIBUTION-UNATTEN 5
NORTH PARK SUB 12.47 115.00DISTRIBUTION-UNATTEN 6
ORCHARD SUB 12.47 115.00DISTRIBUTION-UNATTEN 7
PACIFIC SUB 12.47 115.00DISTRIBUTION-UNATTEN 8
POMEROY SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
PROSPECT POINT SUB 12.47 69.00DISTRIBUTION-UNATTEN 10
PUNKIN CENTER SUB 12.47 115.00DISTRIBUTION-UNATTEN 11
RIVER ROAD SUB 12.47 115.00DISTRIBUTION-UNATTEN 12
SELAH SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
SULPHUR CREEK SUB 12.47 115.00DISTRIBUTION-UNATTEN 14
SUNNYSIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 15
TIETON SUB 12.47 115.00 34.50DISTRIBUTION-UNATTEN 16
TOPPENISH SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
TOUCHET SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
VOELKER SUB 12.47 115.00DISTRIBUTION-UNATTEN 19
WAITSBURG SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
WAPATO SUB 12.47 115.00DISTRIBUTION-UNATTEN 21
WENAS SUB 12.47 115.00DISTRIBUTION-UNATTEN 22
WHITE SWAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 23
WILEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 24
TOTAL 369.49 2922.00 107.66 25
Number of Substations-29 26
27
CENTRAL SUB 12.47 69.00T/D-UNATTENDED 28
MILL CREEK SUB 12.47 69.00T/D-UNATTENDED 29
UNION GAP SUB 115.00 230.00 12.47T/D-UNATTENDED 30
TOTAL 139.94 368.00 12.47 31
Number of Substations-3 32
33
OUTLOOK SUB 115.00 230.00TRANSMISSION-UNATTEN 34
PASCO SUB 69.00 115.00 7.20TRANSMISSION-UNATTEN 35
POMONA HEIGHTS SUB 115.00 230.00TRANSMISSION-UNATTEN 36
WALLA WALLA 230KV SUB 69.00 230.00TRANSMISSION-UNATTEN 37
WALLULA SUB 69.00 230.00TRANSMISSION-UNATTEN 38
WINE COUNTRY SUB 115.00 230.00TRANSMISSION-UNATTEN 39
TOTAL 552.00 1265.00 7.20 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 / /2014/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 4 1
42 2 2
50 2 3
25 1 4
42 2 5
45 2 6
50 2 7
28 3 8
9 1 9
40 2 10
20 2 11
51 4 12
45 2 13
25 1 14
45 2 15
29 2 16
50 2 17
6 1 18
25 1 19
9 1 20
45 2 21
25 2 22
22 2 23
45 2 24
1034 59 25
26
27
14 1 28
45 2 29
333 4 30
392 7 31
32
33
125 1 34
39 9 35
300 2 36
300 2 37
120 2 38
250 1 39
1134 17 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 / /2014/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).
Number of Substations-6 1
2
WYOMING 3
ANTELOPE MINE SUB 34.50 230.00DISTRIBUTION-UNATTEN 4
ASTLE STREET 13.20 34.50DISTRIBUTION-UNATTEN 5
BAILEY DOME SUB 12.47 57.00DISTRIBUTION-UNATTEN 6
BAR X SUB 34.50 230.00DISTRIBUTION-UNATTEN 7
BIG MUDDY SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
BIG PINEY SUB 24.90 69.00DISTRIBUTION-UNATTEN 9
BLACKS FORK SUB 34.50 230.00DISTRIBUTION-UNATTEN 10
BRIDGER PUMP SUB 34.50 230.00 13.20DISTRIBUTION-UNATTEN 11
BRYAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 12
BUFFALO TOWN SUB 4.16 20.80DISTRIBUTION-UNATTEN 13
BYRON SUB 4.16 34.50DISTRIBUTION-UNATTEN 14
CASSA SUB 20.80 57.00 12.47DISTRIBUTION-UNATTEN 15
CENTER STREET SUB 4.16 115.00DISTRIBUTION-UNATTEN 16
CHAPMAN SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
CHUKAR SUB 4.16 12.47DISTRIBUTION-UNATTEN 18
CHURCH AND DWIGHT SUB 0.48 34.50DISTRIBUTION-UNATTEN 19
COKEVILLE SUB 24.90 46.00DISTRIBUTION-UNATTEN 20
COLUMBIA-GENEVA SUB 13.80 230.00DISTRIBUTION-UNATTEN 21
COMMUNITY PARK SUB 13.20 116.00DISTRIBUTION-UNATTEN 22
CROOKS GAP SUB 12.47 34.50DISTRIBUTION-UNATTEN 23
DEER CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
DJ COAL MINE SUB 34.50 69.00DISTRIBUTION-UNATTEN 25
DOUGLAS SUB 2.30 57.00DISTRIBUTION-UNATTEN 26
DRY FORK SUB 4.16 69.00DISTRIBUTION-UNATTEN 27
ELK BASIN SUB 7.20 34.50DISTRIBUTION-UNATTEN 28
EMIGRANT SUB 12.47 115.00DISTRIBUTION-UNATTEN 29
EVANS SUB 12.47 115.00DISTRIBUTION-UNATTEN 30
EVANSTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 31
FORT CASPER SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
FORT SANDERS SUB 13.20 115.00DISTRIBUTION-UNATTEN 33
FRANNIE SUB 34.50 230.00DISTRIBUTION-UNATTEN 34
FRONTIER SUB 4.16 69.00DISTRIBUTION-UNATTEN 35
GARLAND SUB 34.50 230.00DISTRIBUTION-UNATTEN 36
GLENDO SUB 4.16 57.00DISTRIBUTION-UNATTEN 37
GRASS CREEK SUB 34.50 230.00DISTRIBUTION-UNATTEN 38
GREAT DIVIDE SUB 34.50 115.00DISTRIBUTION-UNATTEN 39
GREYBULL SUB 4.16 34.50DISTRIBUTION-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 / /2014/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
25 1 4
12 1 5
2 1 6
25 1 7
7 1 8
14 1 9
150 2 10
73 4 11
25 1 12
2 3 13
2 3 14
2 6 1 15
12 1 16
4 1 17
1 3 18
3 2 19
4 1 20
45 2 21
45 2 22
5 3 23
9 1 24
12 1 25
6 3 26
9 1 27
5 1 28
12 1 29
9 1 30
40 2 31
28 1 32
20 1 33
50 2 34
6 1 35
45 2 36
3 4 37
25 1 38
20 1 39
3 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 / /2014/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).
HANNA SUB 12.47 34.50DISTRIBUTION-UNATTEN 1
JACKALOPE SUB 12.47 115.00DISTRIBUTION-UNATTEN 2
KEMMERER SUB 24.90 69.00DISTRIBUTION-UNATTEN 3
KIRBY CREEK PUMPING STATION 2.40 34.50DISTRIBUTION-UNATTEN 4
KIRBY CREEK SUB 4.16 34.50DISTRIBUTION-UNATTEN 5
LANDER SUB 12.47 34.50DISTRIBUTION-UNATTEN 6
LARAMIE SUB 13.20 115.00DISTRIBUTION-UNATTEN 7
LATHAM SUB 34.50 230.00DISTRIBUTION-UNATTEN 8
LINCH SUB 13.80 69.00DISTRIBUTION-UNATTEN 9
LITTLE MOUNTAIN SUB 34.50 230.00DISTRIBUTION-UNATTEN 10
LOVELL SUB 4.16 34.50DISTRIBUTION-UNATTEN 11
MILL IRON SUB 13.80 34.50DISTRIBUTION-UNATTEN 12
MILLS SUB 4.16 12.47DISTRIBUTION-UNATTEN 13
MURPHY DOME SUB 13.20 34.50DISTRIBUTION-UNATTEN 14
NUGGETT SUB 7.20 69.00DISTRIBUTION-UNATTEN 15
OPAL SUB 24.90 69.00DISTRIBUTION-UNATTEN 16
ORIN SUB 7.20 32.90DISTRIBUTION-UNATTEN 17
ORPHA SUB 7.20 57.00DISTRIBUTION-UNATTEN 18
PARADISE SUB 25.00 69.00DISTRIBUTION-UNATTEN 19
PARCO SUB 12.47 34.50DISTRIBUTION-UNATTEN 20
PINEDALE SUB 24.90 69.00DISTRIBUTION-UNATTEN 21
PITCHFORK SUB 24.90 69.00DISTRIBUTION-UNATTEN 22
POISON SPIDER SUB 2.40 69.00DISTRIBUTION-UNATTEN 23
POLECAT SUB 12.47 34.50DISTRIBUTION-UNATTEN 24
RAINBOW SUB 13.20 34.50DISTRIBUTION-UNATTEN 25
RAVEN SUB 34.50 230.00DISTRIBUTION-UNATTEN 26
RED BUTTE SUB 13.20 116.00DISTRIBUTION-UNATTEN 27
REFINERY SUB 12.47 115.00DISTRIBUTION-UNATTEN 28
SAGE HILL SUB 13.20 34.50DISTRIBUTION-UNATTEN 29
SHOSHONI SUB 2.40 34.50DISTRIBUTION-UNATTEN 30
SLATE CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
SOUTH CODY SUB 24.90 69.00DISTRIBUTION-UNATTEN 32
SOUTH ELK BASIN SUB 4.16 34.50DISTRIBUTION-UNATTEN 33
SOUTH TRONA SUB 34.50 230.00DISTRIBUTION-UNATTEN 34
SPRING CREEK SUB 13.20 115.00DISTRIBUTION-UNATTEN 35
SVILAR SUB 4.16 34.50DISTRIBUTION-UNATTEN 36
TEN MILE STEP DOWN SUB 12.50 34.50DISTRIBUTION-UNATTEN 37
TEN MILE SUB 34.50 69.00DISTRIBUTION-UNATTEN 38
THERMOPOLIS TOWN SUB 4.16 34.50DISTRIBUTION-UNATTEN 39
THUNDER CREEK SUB 12.47 57.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.21
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2014/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
25 1 2
10 1 3
3 3 4
2 3 5
25 2 6
50 2 7
25 1 8
12 1 9
20 1 10
4 1 11
12 1 1 12
1 3 13
5 1 14
1 15
8 1 16
1 1 17
3 3 18
30 1 19
5 1 20
20 1 21
17 9 2 22
3 1 23
1 3 24
12 1 25
200 2 26
50 2 27
45 2 28
6 1 29
2 3 30
1 1 31
14 3 1 32
2 6 33
150 2 34
25 1 35
2 3 36
5 1 37
12 1 38
5 1 39
9 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 / /2014/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).
VETERANS SUB 13.20 34.50DISTRIBUTION-UNATTEN 1
WELCH SUB 2.40 57.00DISTRIBUTION-UNATTEN 2
WERTZ-SINCLAIR SUB 4.16 57.00 12.50DISTRIBUTION-UNATTEN 3
WEST ADAMS SUB 4.16 34.50DISTRIBUTION-UNATTEN 4
WESTVACO SUB 34.50 230.00DISTRIBUTION-UNATTEN 5
WORLAND TOWN SUB 4.16 34.50DISTRIBUTION-UNATTEN 6
WYOPO SUB 34.50 230.00DISTRIBUTION-UNATTEN 7
WYUTA SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
TOTAL 1306.83 7517.14 38.17 9
Number of Substations-85 10
11
BUFFALO SUB 20.80 230.00T/D-UNATTENDED 12
ELK HORN SUB 12.50 115.00T/D-UNATTENDED 13
FIREHOLE SUB 34.50 230.00T/D-UNATTENDED 14
HILLTOP SUB 34.50 115.00 20.80T/D-UNATTENDED 15
LABARGE SUB 24.90 69.00T/D-UNATTENDED 16
POINT OF ROCKS SUB 34.50 230.00T/D-UNATTENDED 17
RIVERTON 230 SUB 12.47 230.00 34.50T/D-UNATTENDED 18
YELLOWCAKE SUB 34.50 230.00T/D-UNATTENDED 19
TOTAL 208.67 1449.00 55.30 20
Number of Substations-8 21
22
DAVE JOHNSTON PLANT/SUB 115.00 230.00 69.00TRANSMISSION-ATTENDE 23
JIM BRIDGER 345KV SUB 230.00 345.00 34.50TRANSMISSION-ATTENDE 24
NAUGHTON SUB 138.00 230.00 69.00TRANSMISSION-ATTENDE 25
BAIROIL SUB 34.50 115.00 57.00TRANSMISSION-UNATTEN 26
CASPER SUB 115.00 230.00 13.20TRANSMISSION-UNATTEN 27
CHAPPELL CREEK SUB 69.00 230.00TRANSMISSION-UNATTEN 28
CHIMNEY BUTTE SUB 69.00 230.00TRANSMISSION-UNATTEN 29
FOOTE CREEK WIND FARM 34.50 230.00TRANSMISSION-UNATTEN 30
GLENDO AUTO SUB 57.00 69.00TRANSMISSION-UNATTEN 31
MANSFACE SUB 34.50 230.00TRANSMISSION-UNATTEN 32
MIDWEST SUB 69.00 230.00 34.50TRANSMISSION-UNATTEN 33
MINERS SUB 34.50 230.00 9.70TRANSMISSION-UNATTEN 34
MUSTANG SUB 115.00 230.00TRANSMISSION-UNATTEN 35
OREGON BASIN SUB 34.50 230.00 69.00TRANSMISSION-UNATTEN 36
PLATTE SUB 115.00 230.00 34.50TRANSMISSION-UNATTEN 37
RAILROAD SUB 138.00 230.00TRANSMISSION-UNATTEN 38
ROCK SPRINGS 230 SUB 34.50 230.00TRANSMISSION-UNATTEN 39
SAGE SUB 46.00 69.00TRANSMISSION-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 / /2014/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 2 1
3 3 2
2 6 3
3 1 4
25 1 5
5 1 6
20 1 1 7
1 8
1671 156 6 9
10
11
20 1 12
25 1 13
50 2 14
45 2 1 15
8 6 16
25 1 17
74 4 18
25 1 19
272 18 1 20
21
22
336 4 23
703 7 24
633 4 25
53 3 26
517 5 27
67 1 28
75 1 29
196 2 30
15 2 31
20 1 32
157 3 33
20 1 34
100 1 35
65 2 36
140 3 37
400 1 38
50 2 39
22 1 40
FERC FORM NO. 1 (ED. 12-96)Page 427.22
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2014/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).
THERMOPOLIS SUB 115.00 230.00TRANSMISSION-UNATTEN 1
TOTAL 1598.00 4048.00 390.40 2
Number of Substations-19 3
4
CALIFORNIA 5
Distribution - 42 6
T/D - 2 7
Transmission - 6 8
9
IDAHO 10
Distribution - 65 11
T/D - 5 12
Transmission - 16 13
14
MONTANA 15
Transmission - 3 16
17
OREGON 18
Distribution - 180 19
T/D - 12 20
Transmission - 27 21
22
UTAH 23
Distribution - 279 24
T/D - 31 25
Transmission - 42 26
27
WASHINGTON 28
Distribution - 29 29
T/D - 3 30
Transmission - 6 31
32
WYOMING 33
Distribution - 85 34
T/D - 8 35
Transmission - 19 36
37
ALL STATES 38
Distribution - 680 39
T/D - 61 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 / /2014/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.
175 2 1
3744 46 2
3
4
5
323 6
126 7
762 8
9
10
721 11
344 12
3701 13
14
15
200 16
17
18
4569 19
1337 20
7261 21
22
23
5470 24
7124 25
10831 26
27
28
1034 29
392 30
1134 31
32
33
1671 34
272 35
3744 36
37
38
13788 39
9596 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 / /2014/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).
Transmission - 119 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
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 / /2014/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.
27633 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
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.: 23 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.: 24 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
2014/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
/ /2014/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 Coal purchases and support services 158,300,630Bridger Coal Company
3
4 Coal mining services and information technology
5 support services 47,664,734Energy West Mining Company 151, 920
6
7 Coal purchases 9,889,757Trapper Mining Inc. 151
8
9 Administrative and financial support services 777,745Interwest Mining Company
10
11 Administrative services under the IASA 3,738,954BHE
12 Administrative services under the IASA 5,659,614MEC
13 Administrative services under the IASA 148,029Kern River Gas Transmission Company 107, 923
14
15 Gas transportation services and equipment
16 installation 3,187,452Kern River Gas Transmission Company 501, 547, 571
17
18 Relocation services 1,300,079HomeServices of America, Inc.
19
20 Non-power Goods or Services Provided for Affiliate
21 Information technology and administrative
22 support services 857,074Bridger Coal Company
23
24 Financial support services and employee benefits 729,835Interwest Mining Company 557,580,588,921
25
26 Administrative services under the IASA 257,866BHE
27 Administrative services under the IASA 2,318,734MEC
28 Administrative services under the IASA 322,965HomeServices of America, Inc. 557,560,920,921
29 Administrative services under the IASA 563,688Kern River Gas Transmission Company
30 Administrative services under the IASA 426,990Northern Natural Gas Company
31 Administrative services under the IASA 1,225,925NV Energy, Inc.
32 Administrative services under the IASA 3,047,749MEHC Canada Transmission
33 Administrative services under the IASA 933,555BHE U.S. Transmission, LLC
34 Administrative services under the IASA 331,413Central California Transco, LLC 560, 920, 921
35 Administrative services under the IASA 146,951CE Casecnan 557
36
37 Equipment transfer 161,914CE Casecnan 101, 557
38
39
40
41
42
1 Non-power Goods or Services Provided by Affiliated
2 Equipment transfer 335,467MEC 513
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
/ /2014/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
4 Rail services / right-of-way fees 39,212,561BNSF Railway Company 151,507,567,589
5
6 Banking services and financial transactions
7 related to energy hedging activity 1,912,391Wells Fargo & Company
8
9 Banking services 815,272U.S. Bancorp
10
11 Computer hardware and software and computer
12 systems consulting and maintenance services 2,112,921International Business Machines Corp 107,165,921,935
13
14 Rating agency fees 418,171Moody's Investors Service 181, 186, 930.2
15
16 Surety bond premium 427,920National Indemnity Company 165
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.: 2 Column: c
Accounts charged for Bridger Coal Company: 151, 501, 513 and 935.
Schedule Page: 429 Line No.: 2 Column: d
Non-power goods or services provided by Bridger Coal Company are as follows:
Coal purchases $158,295,850
Support services 4,780
$158,300,630
Schedule Page: 429 Line No.: 5 Column: d
Non-power goods or services provided by Energy West Mining Company are as follows:
Coal mining services $47,447,164
Information technology support services 217,570
$47,664,734
Under the terms of the coal mining agreement between PacifiCorp and Energy West Mining
Company, Energy West Mining Company provides coal mining services to PacifiCorp that are
absorbed directly by PacifiCorp.
Schedule Page: 429 Line No.: 9 Column: c
Accounts charged for Interwest Mining Company: 421, 426.1, 426.5, 557, 923 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 and financial 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 Berkshire
Hathaway Energy Company ("BHE") 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 BHE organization.
Legislative and Regulatory: The Legislative and Regulatory allocation is used to allocate
costs incurred by BHE'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 BHE 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 429 Line No.: 11 Column: c
Accounts charged for BHE: 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
of, and charged to, other entities within the BHE group. Such affiliate charges reflect
the ability to obtain price discounts as a result of larger purchasing power.
Excluded from this page are reimbursements by BHE for payments made by PacifiCorp to its
employees under the long-term incentive plan ("LTIP") that was maintained by BHE 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 BHE 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.: 16 Column: d
Non-power goods or services provided by Kern River Gas Transmission Company are as
follows:
Gas transportation services $3,173,351
Equipment installation 14,101
$3,187,452
Schedule Page: 429 Line No.: 18 Column: c
Accounts charged for HomeServices of America, Inc.: 184, 501, 502, 506, 539, 548, 549,
557, 560, 561.2, 580, 581, 590, 592, 593, 597, 901, 902, 903, 908 and 921.
Schedule Page: 429 Line No.: 22 Column: c
Accounts charged for Bridger Coal Company: 232, 426.5, 501, 909 and 929.
Schedule Page: 429 Line No.: 24 Column: d
PacifiCorp provides Interwest Mining Company with financial support 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.: 26 Column: c
Accounts charged for BHE: 426.5, 557, 560, 580, 588, 908, 909, 920 and 921.
Schedule Page: 429 Line No.: 26 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 BHE 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.: 27 Column: c
Accounts charged for MEC: 426.5, 500, 506, 535, 557, 580, 588, 909, 920 and 921.
Schedule Page: 429 Line No.: 27 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 BHE 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.: 29 Column: c
Accounts charged for Kern River Gas Transmission Company: 426.5, 535, 557, 560, 580, 590,
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
920, 921 and 930.2.
Schedule Page: 429 Line No.: 30 Column: c
Accounts charged for Northern Natural Gas Company: 426.5, 557, 580, 920 and 921.
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 BHE 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: c
Accounts charged for NV Energy, Inc.: 557, 560, 561.5, 580, 588, 593, 597, 903, 908, 909,
920 and 921.
Schedule Page: 429 Line No.: 32 Column: b
This footnote applies to all occurrences of "MEHC Canada Transmission" on page 429.
Complete name is MEHC Canada Transmission GP Corporation.
Schedule Page: 429 Line No.: 32 Column: c
Accounts charged for MEHC Canada Transmission: 426.5, 557, 560, 580, 920 and 921.
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 BHE 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.: 33 Column: b
BHE U.S. Transmission, LLC was formerly known as MidAmerican Transmission, LLC.
Schedule Page: 429 Line No.: 33 Column: c
Accounts charged for BHE U.S. Transmission, LLC: 426.5, 557, 560, 580, 588, 920 and 921.
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 BHE 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.: 34 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 BHE 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.: 35 Column: b
This footnote applies to all occurrences of “CE Casecnan” on page 429. Complete name is CE
Casecnan Water and Energy Company, Inc.
Schedule Page: 429 Line No.: 35 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 BHE 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.: 4 Column: d
Non-power goods or services provided by BNSF Railway Company are as follows:
Rail services $39,180,671
Right-of-way fees 31,890
$39,212,561
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.: 7 Column: c
Accounts charged for Wells Fargo & Company: 181, 228.3, 419, 427, 431, 501, 547, 560, 588,
903, 921 and 928.
Schedule Page: 429.1 Line No.: 7 Column: d
Non-power goods or services provided by Wells Fargo & Company are as follows:
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Banking services $1,782,491
Financial transactions related to energy hedging activity 129,900
$1,912,391
Schedule Page: 429.1 Line No.: 9 Column: c
Accounts charged for U.S. Bancorp: 181, 419, 427, 431, 537, 557, 903, 920, 928 and 930.2.
Schedule Page: 429.1 Line No.: 12 Column: b
Complete name is International Business Machines 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
2014/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
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)