2015Annual Report FERC Form.pdf

ROCKY MOUNTAIN
POWER
May 27,2016
VA OVERNIGHT 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 I report for the year ended December 31,2015.
PacifiCorp respectfully requests that all data requests regarding this matter be addressed to:
By email (preferred): [e-mail]
By regular mail: Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR97232
Please direct any informal questions to Ted Weston, Regulatory Manager, at [phone].
Sincerely,
l't'#,taP - u,a,t,.-/1,-*,
Jeffiey K. Larsen
Vice President, Regulation
Enclosure
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Ril.CEIVED
1407 West North Temple, Suite 310
?ili6 I,IAY 3l AH l0: I tr salt Lake citv' Utah 84116
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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 2015/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
/ /
2015/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
N/A230Unrecovered 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
/ /
2015/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
/ /
2015/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
/ /2015/Q4
Nikki L. Kobliha, 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 electric utility company headquartered in Oregon that serves 1.8
million retail electric customers, including residential, commercial, industrial, irrigation and other
customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp is
principally engaged in the business of generating, transmitting, distributing and buying and selling
electricity on the wholesale market with other utilities, energy marketing companies, financial
institutions and other market participants. 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. Transmission related functions and Energy Imbalance Market activities
are operated under the trade name 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
2015/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
/ /2015/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
/ /
2015/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 provided coal-mining services to PacifiCorp utilizing
PacifiCorp's assets until mining operations ceased in 2015. 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 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, 2015, all of PacifiCorp Foundation's three
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
2015/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
/ /
2015/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
President and Chief Executive Officer, Pacific Power 313,275Stefan A. Bird 3
President and Chief Executive Officer, 4
Rocky Mountain Power 324,028Cindy A. Crane 5
President and Chief Executive Officer, 6
PacifiCorp Transmission 330,000R. Patrick Reiten 7
Vice President and Chief Financial Officer 177,384Nikki L. Kobliha 8
Former President and Chief Executive Officer, 9
PacifiCorp Energy 68,750Micheal G. Dunn 10
Former Senior Vice President and CFO, 11
PacifiCorp 163,394Douglas K. Stuver 12
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FERC FORM NO. 1 (ED. 12-96) Page 104
Schedule Page: 104 Line No.: 1 Column: a
PacifiCorp sets forth the salary information for its "named executive officers" for the
year ended December 31, 2015, consistent with Item 402 of Regulation S-K promulgated by
the Securities and Exchange Commission, in PacifiCorp's 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
Gregory E. 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, 2015 for
executive compensation information for Mr. Abel.
Schedule Page: 104 Line No.: 3 Column: b
Stefan A. Bird was elected President and Chief Executive Officer ("CEO") of Pacific Power
effective March 10, 2015. Refer to Item 13 in Important Changes During the Year in this
Form No. 1.
Schedule Page: 104 Line No.: 7 Column: b
R. Patrick Reiten, the former President and CEO of Pacific Power, was elected President
and CEO of PacifiCorp Transmission effective March 10, 2015. Refer to Item 13 in Important
Changes During the Year in this Form No. 1.
Schedule Page: 104 Line No.: 8 Column: b
Nikki L. Kobliha was appointed Vice President and Chief Financial Officer ("CFO") of
PacifiCorp effective August 13, 2015 and was elected to that position on October 26, 2015.
Refer to Item 13 in Important Changes During the Year in this Form No. 1.
Schedule Page: 104 Line No.: 10 Column: b
Micheal G. Dunn, former President and CEO of PacifiCorp Energy, resigned as a director and
employee effective March 2015. Refer to Item 13 in Important Changes During the Year in
this Form No. 1.
Schedule Page: 104 Line No.: 12 Column: b
Douglas K. Stuver resigned as an employee and Senior Vice President and CFO of PacifiCorp
effective August 13, 2015. Refer to Item 13 in Important Changes During the Year in this
Form No. 1.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
/ /
2015/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, 2015: 1
Gregory E. Abel 2
666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309(Chairman of the Board of Directors and CEO, PacifiCorp) 3
Stefan A. Bird 4
825 NE Multnomah, Suite 2000, Portland, Oregon 97232(President and CEO, Pacific Power) 5
Cindy A. Crane 6
1407 West North Temple, Suite 310, Salt Lake City, Utah 84116(President and CEO, Rocky Mountain Power) 7
R. Patrick Reiten 8
825 NE Multnomah, Suite 2000, Portland, Oregon 97232(President and CEO, PacifiCorp Transmission) 9
1111 South 103rd Street, Omaha, Nebraska 68124Douglas L. Anderson 10
666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309Patrick J. Goodman 11
825 NE Multnomah, Suite 2000, Portland, Oregon 97232Natalie L. Hocken 12
1800 M Street NW, Suite 300, Washington, DC 20036Andrea L. Kelly 13
1407 West North Temple, Suite 320, Salt Lake City, Utah 84116Micheal G. Dunn 14
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FERC FORM NO. 1 (ED. 12-95) Page 105
Schedule Page: 105 Line No.: 4 Column: a
Stefan A. Bird was elected President and Chief Executive Officer ("CEO") of Pacific Power
and director of PacifiCorp effective March 10, 2015. Refer to Item 13 in Important Changes
During the Year in this Form No. 1.
Schedule Page: 105 Line No.: 6 Column: a
Cindy A. Crane, President and CEO of Rocky Mountain Power, was elected director of
PacifiCorp effective March 10, 2015. Refer to Item 13 in Important Changes During the Year
in this Form No. 1.
Schedule Page: 105 Line No.: 8 Column: a
R. Patrick Reiten, the former President and CEO of Pacific Power, was elected President
and CEO of PacifiCorp Transmission effective March 10, 2015. Refer to Item 13 in Important
Changes During the Year in this Form No. 1.
Schedule Page: 105 Line No.: 13 Column: a
Andrea L. Kelly, Senior Vice President, Legislative and Regulatory Strategy of Berkshire
Hathaway Energy Company, was elected director of PacifiCorp effective March 10, 2015.
Refer to Item 13 in Important Changes During the Year in this Form No. 1.
Schedule Page: 105 Line No.: 14 Column: a
Micheal G. Dunn, former President and CEO of PacifiCorp Energy, resigned as a director and
employee effective March 2015. Refer to Item 13 in Important Changes During the Year in
this Form No. 1.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
/ /2015/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
/ /2015/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
03/06/201520150306-5249 ER15-1187 1
04/17/201520150417-5193 ER15-1524 2
05/15/201520150515-5231 ER11-3643 3
07/17/201520150717-5126 ER11-3643 4
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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 2015) to be effective 6/1/2015 under ER15-1187
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
PacifiCorp submits tariff filing per 35.13(a)(2)(iii: OATT Formula Rate - Schedule 10 Loss
Factor) to be effective 6/1/2015 under ER15-1524 The Commission approved the new Schedule
10 Loss Factor rate with an effective date 12/1/2015
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
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
Schedule Page: 1061 Line No.: 4 Column: d
Supplement to May 15, 2015 Transmission Formula Rate Annual Update Informational Filing of
PacifiCorp under ER11-3643
Schedule Page: 1061 Line No.: 4 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
2015/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
/ /2015/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 / /2015/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 the fee attached to the franchise agreement.
State Effective Date Expiration Date Fee
California (1)
None
Idaho (2)
Grace
Menan
Ucon
Parker
Sugar City
Roberts
01/07/2015
06/30/2015
07/20/2015
09/25/2015
09/25/2015
09/25/2015
01/07/2035
06/30/2065
07/20/2040
09/25/2065
09/25/2035
09/25/2065
-
-
3.0%
-
3.0%
-
Oregon (3)
Klamath Falls
North Bend
Gold Hill
Wasco
Sublimity
Coos Bay
Cannon Beach
Albany
Prineville
03/16/2015
04/08/2015
05/14/2015
06/05/2015
06/11/2015
07/17/2015
07/17/2015
07/22/2015
08/07/2015
03/16/2025
04/08/2025
05/14/2025
06/05/2020
06/11/2035
07/17/2025
07/17/2020
07/22/2025
06/30/2020
7.0%
9.0%
7.0%
3.5%
3.5%
9.0%
3.5%
7.0%
5.0%
Sweet Home 10/13/2015 10/13/2025 5.0%
Lincoln City 11/09/2015 11/09/2025 5.0%
Coquille 11/17/2015 11/17/2025 8.5%
Utah (4)
Carbon County 01/01/2015 01/01/2035 -
Richfield 02/06/2015 02/06/2025 -
Delta 03/25/2015 03/25/2035 -
Eagle Mountain
Apple Valley
Millard County
Wellsville
North Ogden
Ivins
Pleasant Grove
Layton
Corinne
03/25/2015
04/17/2015
05/15/2015
05/15/2015
06/03/2015
06/30/2015
07/10/2015
07/20/2015
08/07/2015
03/25/2020
04/17/2025
05/15/2030
05/15/2035
06/03/2025
06/30/2025
07/10/2025
08/18/2020
08/07/2025
-
-
-
-
-
-
-
-
-
Vineyard 11/17/2015 11/17/2035 -
Huntington 11/25/2015 11/25/2035 -
Harrisville 11/25/2015 11/25/2025 -
Washington (4)
None
Wyoming (5)
Buffalo
Douglas
03/25/2015
09/08/2015
03/25/2040
09/08/2030
4.0%
4.0%
Green River 11/20/2015 11/20/2025 3.0%
(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 Utah and Washington, PacifiCorp collects associated taxes from customers and remits them directly to the applicable municipalities.
(5) In Wyoming, the first 1.0% of the franchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 1.0% is collected
from customers and remitted directly to the applicable municipalities.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.1
ITEM 2.
None.
ITEM 3.
In March 2015, PacifiCorp acquired certain distribution and transmission systems and facilities from Eagle Mountain City, a Utah
municipal corporation ("the City"), assumed certain liabilities and began providing retail electric service to the City's approximately
6,700 customers. PacifiCorp recorded the transaction in Account 102, Electric plant purchased or sold, in March 2015. The
acquisition of the transmission facilities component of this transaction was authorized by the Federal Energy Regulatory Commission
("FERC") in Docket No. EC15-41-000 in January 2015. In September 2015, the FERC in Docket No. AC15-182-000 approved the
journal entries required by the Uniform System of Accounts as filed by PacifiCorp in September 2015. Accordingly, PacifiCorp
cleared Account 102, Electric purchased or sold and recorded the purchase to the appropriate accounts.
In March 2015, PacifiCorp sold the Fountain Green hydroelectric generating plant in Sanpete County, Utah to the Utah Division of
Wildlife Resources in exchange for a transmission line corridor easement in Salt Lake County, Utah and recorded the transaction in
Account 102, Electric plant purchased or sold. In July 2015, PacifiCorp filed with the FERC to approve the journal entries required by
the Uniform System of Accounts in Docket No. AC15-163-000 and filed with the FERC additional information related to the sale in
early April 2016. A notice of the transaction was submitted to the Idaho Public Utilities Commission ("IPUC") and commission
authorizations are as follows:
Wyoming Public Service Commission ("WPSC") – Docket No. 20000-459-EA-14, January 2015.
Oregon Public Utility Commission ("OPUC") – Docket No. UP 312, Order No. 15-071, March 2015.
In May 2015, the Navajo Nation Council and President of the Navajo Nation approved the agreement with PacifiCorp for the sale of
certain facilities located in San Juan County, Utah to the Navajo Tribal Utility Authority ("NTUA"). These facilities, substantially
consisting of distribution facilities, provide service to approximately 1,000 customers on the Navajo Nation Reservation. PacifiCorp
filed for approval of the sale with the Utah Public Service Commission ("UPSC") and the WPSC in December 2015 and with the
OPUC in January 2016. A notice of the transaction was submitted to the IPUC in January 2016. Incorporated as part of the agreement
for the sale of facilities is a power supply agreement with the NTUA for PacifiCorp to sell power to the NTUA, which is to become
effective after the closing of the sale and commission approval.
In June 2015, PacifiCorp sold certain mining assets located in Utah attributable to the closure of mining operations at the Energy West
Mining Company. For further discussion, refer to Note 5 of Notes to Financial Statements in this Form No. 1. Commission
authorizations for the sale of certain mining assets are as follows:
UPSC – Docket No. 14-035-147, April 2015.
IPUC – Order No. 33304, Case No. PAC-E-14-10, May 2015.
OPUC – Docket No. UM 1712, Order No. 15-161, May 2015.
WPSC – Docket No. 20000-464-EA-14, May 2015.
In October 2015, PacifiCorp executed the exchange of certain transmission-related equipment and facilities with Idaho Power
Company ("Idaho Power") and terminated and amended certain legacy long-term transmission agreements with Idaho Power. For
further discussion of addition of transmission-related equipment and facilities, refer to Item 5 in Important Changes During the Year
in this Form No. 1. Commission authorizations are as follows:
FERC – Docket No. EC15-54-000, ER15-680-000 and ER15-681-000, June 2015.
IPUC – Order No. 33313, Case No. PAC-E-14-11, June 2015.
OPUC – Docket No. UP 315, Order No. 15-184, June 2015.
WPSC – Docket No. 20000-465-EA-14, August 2015.
California Public Utilities Commission – Decision 15-08-037, Application 14-12-022, August 2015.
Washington Utilities and Transportation Commission ("WUTC") – Docket No. UE-144136, September 2015.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.2
In December 2015, PacifiCorp sold the assets at Camas Cogeneration facilities located in Camas, Washington and associated systems
directly related to its operation to Georgia-Pacific Consumer Products LLC and recorded the sale in Account 102, Electric plant
purchased or sold. In February 2016, PacifiCorp filed with the FERC to approve the journal entries required by the Uniform System
of Accounts in Docket No. AC16-46-000. Commission authorizations are as follows:
OPUC – Docket No. UP 325, Order No. 15-151, May 2015.
WPSC – Docket No. 20000-475-EA-15, September 2015.
ITEM 4.
None.
ITEM 5.
In March 2015, PacifiCorp acquired from Eagle Mountain City, a Utah municipal corporation, certain distribution and transmission
systems and facilities, assumed certain liabilities and began providing retail electric service to Eagle Mountain City's approximately
6,500 residential and 200 commercial customers. For the year ended December 31, 2015, PacifiCorp provided service to
approximately 7,100 residential and 300 commercial customers in Eagle Mountain City and reported $8.6 million in revenues. Refer
to Item 3 in Important Changes During the Year in this Form No. 1 for Commission authorizations.
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 a regional ISO as a participating
transmission owner if the California ISO becomes a regional ISO by modifying its governance structure and expanding its balancing
authority area. A comprehensive benefits study was completed and results were publicly announced in October 2015, along with an
extension of the non-binding memorandum of understanding. The benefits study demonstrated gross benefits for customers exist,
warranting further exploration and analysis of integration. PacifiCorp and the California ISO have initiated a stakeholder input and
review process. If PacifiCorp decides to become a participating transmission owner in the regional ISO, it will seek necessary
regulatory approvals, including from its state regulatory commissions and the FERC. Joining the regional ISO would extend
PacifiCorp's current participation in the real-time market through the Energy Imbalance Market to participation in the day-ahead
energy market operated by the California ISO, in addition to unified planning and operation of PacifiCorp's transmission network.
In May 2015, PacifiCorp's Energy Gateway Transmission Expansion Program placed into service a 170-mile single-circuit 345kV
transmission line between the Sigurd Substation in central Utah and the Red Butte Substation in southwest Utah. The Energy Gateway
Transmission line segments are intended to: (a) address customer load growth; (b) improve system reliability; (c) reduce transmission
system constraints; (d) provide access to diverse generation resources, including renewable resources; and (e) improve the flow of
electricity throughout PacifiCorp's service territories in Utah, Oregon, Wyoming, Washington, Idaho and California. Proposed
transmission line segments are evaluated to ensure optimal benefits and timing before committing to move forward with permitting
and construction.
In October 2015, PacifiCorp and Idaho Power each transferred to the other party full or undivided interests in specified
transmission-related equipment and facilities under a Joint Purchase and Sale Agreement executed in October 2014.
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 in the states of Idaho, Oregon,
Washington and Wyoming. There were no significant changes to customers and/or revenue associated with this exchange. Refer to
Item 3 in Important Changes During the Year in this Form No. 1 for Commission authorizations.
Refer to pages 424-425, Transmission lines added during the year, in this Form No. 1 for additional information regarding
transmission lines added or removed during the year ended December 31, 2015.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.3
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, 2015 at a weighted average interest rate of 0.65%.
Commission authorizations currently 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-16-03, Order No. 33476, dated March 4, 2016, effective through April 30, 2021.
FERC – Docket No. ES16-3-000, dated December 4, 2015, letter order effective January 1, 2016 through December 31,
2017.
For further discussion, refer to Note 6 of Notes to Financial Statements in this Form No. 1.
Long-term Debt
In June 2015, PacifiCorp issued $250 million of its 3.35% First Mortgage Bonds due July 2025. The net proceeds were used to fund
capital expenditures and for general corporate purposes, including retirement of short-term debt.
PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $1.325 billion of long-term debt.
PacifiCorp must make a notice filing with the WUTC prior to any future issuance. State commission authorizations for the above
issuance and 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, 2015, PacifiCorp had $310 million of letters of credit providing credit enhancement and liquidity support for
variable-rate tax-exempt bond obligations totaling $305 million plus interest. These letters of credit were fully available as of
December 31, 2015 and expire periodically through March 2017.
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,
2015, PacifiCorp estimated it would be able to issue up to $9.3 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.
ITEM 7.
None.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.4
ITEM 8.
For the year ended December 31, 2015, PacifiCorp's bargaining unit wage scale changes were as follows:
Estimated Annual
Unions Represented % Increase (1)Effective Date(s)Financial Impact (2)
IBEW 57 Power Delivery (UT, ID & WY) 1.82% 01/26/2015 $ 1,423,222
IBEW 57 Power Supply (UT, ID & WY) 1.87% 01/26/2015 707,635
IBEW 57 Combustion Turbine (UT) 1.87% 01/26/2015 59,253
IBEW 659 (OR, CA) 1.29% 04/26/2015 414,954
UWUA 197 (OR) 1.20% 05/26/2015 18,827
IBEW 57 Laramie (WY) 1.03% 06/26/2015 4,985
UWUA 127 (WY) 0.52% 09/26/2015 237,146
IBEW 125 (OR, WA) 0.12% 12/14/2015 29,969
Total $ 2,895,991
(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.
In March 2016, Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp, declared and paid a dividend of $25 million to
PacifiCorp.
Refer to page 429, Transactions with Associated (Affiliated) Companies, in this Form No. 1 for information regarding related-party
transactions.
There have been no officer, director or security holder transactions during the year ended December 31, 2015 other than preferred and
common stock dividends declared and paid.
ITEM 11.
(Reserved.)
ITEM 12.
Utah Senate Bill 115 ("SB 115"), Sustainable Transportation and Energy Plan, was signed into law in March 2016. The legislation
establishes a five year pilot program to provide mandated funding for electric vehicle infrastructure and clean coal research, and
authorizes funding at the commission’s discretion for solar development, utility-scale battery storage, and other innovative
technology, economic development and air quality initiatives. SB 115 also authorizes the development of a renewable energy tariff for
large customer loads. The legislation also allows PacifiCorp to change its accounting for energy efficiency services and programs
from expense to capital and to create a regulatory liability that may be used for depreciation of its coal-fired plants. The legislation
also mandates full recovery of Utah's share of incremental fuel, purchased power and other variable supply costs through the energy
balancing account that are not fully in base rates rather than the prior recovery of 70%.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.5
In March 2016, Oregon Senate Bill 1547-B ("SB 1547-B"), the Clean Electricity and Coal Transition Plan, was signed into law.
SB 1547-B requires that coal-fired resources are eliminated from Oregon's allocation of electricity by January 1, 2030, and increases
the current Renewable Portfolio Standards ("RPS") target from 25% in 2025 to 50% by 2040. SB 1547-B also implements new
renewable energy credit banking provisions, as well as the following interim RPS targets: 27% in 2025 through 2029, 35% in 2030
through 2034, 45% in 2035 through 2039, and 50% by 2040 and subsequent years.
ITEM 13.
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 Chief Executive Officer ("CEO") of Pacific Power effective March 10, 2015.
R. Patrick Reiten, former President and CEO of Pacific Power, was elected President and CEO of PacifiCorp Transmission effective
March 10, 2015.
Mr. Bird, Cindy A. Crane, President and CEO of Rocky Mountain Power, and Andrea L. Kelly, Senior Vice President, Legislative
and Regulatory Strategy of Berkshire Hathaway Energy Company, were elected directors of PacifiCorp effective March 10, 2015.

Micheal G. Dunn, former President and CEO of PacifiCorp Energy resigned as a director and employee effective March 2015.
Douglas K. Stuver resigned as an employee and Senior Vice President and Chief Financial Officer ("CFO") of PacifiCorp effective
August 13, 2015. Nikki L. Kobliha was appointed Vice President and CFO of PacifiCorp effective August 13, 2015 and was elected
to that position on October 26, 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
2015/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.6
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 / /2015/Q4
UTILITY PLANT 1
26,729,137,536 26,026,444,483200-201Utility Plant (101-106, 114) 2
628,213,113 934,535,929200-201Construction Work in Progress (107) 3
27,357,350,649 26,960,980,412TOTAL Utility Plant (Enter Total of lines 2 and 3) 4
9,237,522,532 9,057,705,065200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5
18,119,828,117 17,903,275,347Net 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
18,119,828,117 17,903,275,347Net 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
13,824,869 13,345,624Nonutility Property (121) 18
3,032,392 2,556,976(Less) Accum. Prov. for Depr. and Amort. (122) 19
69,928 69,928Investments in Associated Companies (123) 20
241,143,969 227,471,078224-225Investment 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
89,802,688 83,174,506Other Investments (124) 24
0 0Sinking Funds (125) 25
0 0Depreciation Fund (126) 26
0 0Amortization Fund - Federal (127) 27
15,562,725 19,384,022Other Special Funds (128) 28
0 0Special Funds (Non Major Only) (129) 29
0 128,978Long-Term Portion of Derivative Assets (175) 30
0 0Long-Term Portion of Derivative Assets – Hedges (176) 31
357,371,787 341,017,160TOTAL 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
5,873,910 7,178,730Cash (131) 35
0 0Special Deposits (132-134) 36
0 0Working Fund (135) 37
33,910 6,297,596Temporary Cash Investments (136) 38
10,055,988 52,493Notes Receivable (141) 39
400,806,409 376,015,082Customer Accounts Receivable (142) 40
42,519,736 38,029,262Other Accounts Receivable (143) 41
7,006,495 7,018,317(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42
0 0Notes Receivable from Associated Companies (145) 43
23,759,933 152,259,841Accounts Receivable from Assoc. Companies (146) 44
192,305,988 198,515,639227Fuel Stock (151) 45
0 0227Fuel Stock Expenses Undistributed (152) 46
0 0227Residuals (Elec) and Extracted Products (153) 47
233,132,093 223,638,201227Plant 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 / /2015/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
57,531,155 54,470,840Prepayments (165) 57
0 0Advances for Gas (166-167) 58
0 0Interest and Dividends Receivable (171) 59
1,485,898 1,902,475Rents Receivable (172) 60
244,424,000 243,252,000Accrued Utility Revenues (173) 61
131,614 180,653Miscellaneous Current and Accrued Assets (174) 62
8,433,083 18,078,275Derivative Instrument Assets (175) 63
0 128,978(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
1,213,487,222 1,312,723,792Total Current and Accrued Assets (Lines 34 through 66) 67
DEFERRED DEBITS 68
33,071,963 34,036,382Unamortized Debt Expenses (181) 69
0 0230aExtraordinary Property Losses (182.1) 70
0 0230bUnrecovered Plant and Regulatory Study Costs (182.2) 71
1,679,069,828 1,589,995,081232Other Regulatory Assets (182.3) 72
973,951 3,103,498Prelim. 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
23,727 80,622Temporary Facilities (185) 77
70,244,403 110,913,409233Miscellaneous Deferred Debits (186) 78
0 0Def. Losses from Disposition of Utility Plt. (187) 79
0 0352-353Research, Devel. and Demonstration Expend. (188) 80
6,351,794 7,184,006Unamortized Loss on Reaquired Debt (189) 81
606,211,204 544,969,532234Accumulated Deferred Income Taxes (190) 82
0 0Unrecovered Purchased Gas Costs (191) 83
2,395,946,870 2,290,282,530Total Deferred Debits (lines 69 through 83) 84
22,086,633,996 21,847,298,829TOTAL 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, 2015, Account 146, Accounts receivable from associated companies,
included $20,772,337 of income taxes receivable from Berkshire Hathaway Energy Company,
PacifiCorp’s indirect parent company.
Schedule Page: 110 Line No.: 44 Column: d
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
2015/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 / /2015/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
3,145,875,6902,877,592,434Retained Earnings (215, 215.1, 216) 11 118-119
142,148,647155,605,539Unappropriated 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
-13,665,680-12,014,638Accumulated Other Comprehensive Income (219) 15 122(a)(b)
7,755,665,0487,502,489,726Total Proprietary Capital (lines 2 through 15) 16
LONG-TERM DEBT 17
7,031,538,0007,159,339,000Bonds (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
80,12669,100Unamortized Premium on Long-Term Debt (225) 22
13,185,04312,502,206(Less) Unamortized Discount on Long-Term Debt-Debit (226) 23
7,018,433,0837,146,905,894Total Long-Term Debt (lines 18 through 23) 24
OTHER NONCURRENT LIABILITIES 25
31,882,69030,062,429Obligations Under Capital Leases - Noncurrent (227) 26
00Accumulated Provision for Property Insurance (228.1) 27
15,776,59826,550,966Accumulated Provision for Injuries and Damages (228.2) 28
324,459,642336,117,800Accumulated Provision for Pensions and Benefits (228.3) 29
37,861,62437,102,444Accumulated Miscellaneous Operating Provisions (228.4) 30
1,879,73258,173Accumulated Provision for Rate Refunds (229) 31
35,217,37332,083,864Long-Term Portion of Derivative Instrument Liabilities 32
00Long-Term Portion of Derivative Instrument Liabilities - Hedges 33
134,721,631224,250,680Asset Retirement Obligations (230) 34
581,799,290686,226,356Total Other Noncurrent Liabilities (lines 26 through 34) 35
CURRENT AND ACCRUED LIABILITIES 36
20,000,00020,000,000Notes Payable (231) 37
436,531,636445,603,914Accounts Payable (232) 38
015,242,674Notes Payable to Associated Companies (233) 39
147,513,984140,098,106Accounts Payable to Associated Companies (234) 40
39,692,45245,700,120Customer Deposits (235) 41
39,025,53641,847,694Taxes Accrued (236) 42 262-263
113,861,896119,224,245Interest Accrued (237) 43
40,47540,475Dividends 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 / /2015/Q4
(continued)COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
00Matured Interest (240) 46
19,834,84720,333,462Tax Collections Payable (241) 47
69,093,39369,280,619Miscellaneous Current and Accrued Liabilities (242) 48
1,986,4892,207,436Obligations Under Capital Leases-Current (243) 49
75,193,96569,761,281Derivative Instrument Liabilities (244) 50
35,217,37332,083,864(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
927,557,300957,256,162Total Current and Accrued Liabilities (lines 37 through 53) 54
DEFERRED CREDITS 55
31,403,43833,717,019Customer Advances for Construction (252) 56
27,213,93722,505,122Accumulated Deferred Investment Tax Credits (255) 57 266-267
00Deferred Gains from Disposition of Utility Plant (256) 58
303,969,379301,476,278Other Deferred Credits (253) 59 269
71,012,94577,876,318Other Regulatory Liabilities (254) 60 278
00Unamortized Gain on Reaquired Debt (257) 61
252,151,842285,986,998Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277
4,244,780,9234,414,667,387Accum. Deferred Income Taxes-Other Property (282) 63
633,311,644657,526,736Accum. Deferred Income Taxes-Other (283) 64
5,563,844,1085,793,755,858Total Deferred Credits (lines 56 through 64) 65
21,847,298,82922,086,633,996TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 66
FERC FORM NO. 1 (rev. 12-03) Page 113
Schedule Page: 112 Line No.: 39 Column: c
Represents amounts due to Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp,
pursuant to an umbrella loan agreement for which interest is determined daily and is equal
to the lowest cost of borrowings PacifiCorp could otherwise incur externally. At December
31, 2015 the interest rate on the outstanding borrowings was 0.65%.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
/ /2015/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
5,235,309,367 5,267,001,125300-301Operating Revenues (400) 2
Operating Expenses 3
2,565,045,913 2,632,619,056320-323Operation Expenses (401) 4
422,197,831 437,565,258320-323Maintenance Expenses (402) 5
697,031,280 663,171,827336-337Depreciation Expense (403) 6
336-337Depreciation Expense for Asset Retirement Costs (403.1) 7
37,690,560 40,709,374336-337Amort. & Depl. of Utility Plant (404-405) 8
4,989,371 4,834,296336-337Amort. of Utility Plant Acq. Adj. (406) 9
1,760,602Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10
Amort. of Conversion Expenses (407) 11
437,693 415,224Regulatory Debits (407.3) 12
118,750 1,049,382(Less) Regulatory Credits (407.4) 13
185,302,308 171,415,396262-263Taxes Other Than Income Taxes (408.1) 14
121,054,868 -2,889,557262-263Income Taxes - Federal (409.1) 15
25,050,102 9,721,676262-263 - Other (409.1) 16
1,039,923,787 1,071,119,870234, 272-277Provision for Deferred Income Taxes (410.1) 17
861,868,065 760,877,449234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.1) 18
-4,756,408 -5,019,198266Investment Tax Credit Adj. - Net (411.4) 19
(Less) Gains from Disp. of Utility Plant (411.6) 20
Losses from Disp. of Utility Plant (411.7) 21
320 1,117(Less) Gains from Disposition of Allowances (411.8) 22
Losses from Disposition of Allowances (411.9) 23
Accretion Expense (411.10) 24
4,231,980,170 4,263,495,876TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25
1,003,329,197 1,003,505,249Net 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
/ /2015/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
5,235,309,367 5,267,001,125 2
3
2,565,045,913 2,632,619,056 4
422,197,831 437,565,258 5
697,031,280 663,171,827 6
7
37,690,560 40,709,374 8
4,989,371 4,834,296 9
1,760,602 10
11
437,693 415,224 12
118,750 1,049,382 13
185,302,308 171,415,396 14
121,054,868 -2,889,557 15
25,050,102 9,721,676 16
1,039,923,787 1,071,119,870 17
861,868,065 760,877,449 18
-4,756,408 -5,019,198 19
20
21
320 1,117 22
23
24
4,231,980,170 4,263,495,876 25
1,003,329,197 1,003,505,249 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
/ /2015/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)
1,003,329,197 1,003,505,249Net Utility Operating Income (Carried forward from page 114) 27
Other Income and Deductions 28
Other Income 29
Nonutilty Operating Income 30
1,722,065 1,742,323Revenues From Merchandising, Jobbing and Contract Work (415) 31
1,740,032 1,612,424(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32
Revenues From Nonutility Operations (417) 33
124,007 46,644(Less) Expenses of Nonutility Operations (417.1) 34
187,080 164,280Nonoperating Rental Income (418) 35
13,544,949 14,581,067119Equity in Earnings of Subsidiary Companies (418.1) 36
9,749,146 7,738,789Interest and Dividend Income (419) 37
32,841,065 50,655,904Allowance for Other Funds Used During Construction (419.1) 38
478,158 353,146Miscellaneous Nonoperating Income (421) 39
1,427,360 224,256Gain on Disposition of Property (421.1) 40
58,085,784 73,800,697TOTAL Other Income (Enter Total of lines 31 thru 40) 41
Other Income Deductions 42
555,201 11,056Loss on Disposition of Property (421.2) 43
1,343,975 1,342,957Miscellaneous Amortization (425) 44
2,364,473 2,522,386 Donations (426.1) 45
-4,497,390 -6,393,772 Life Insurance (426.2) 46
1,526,588 1,814,037 Penalties (426.3) 47
2,593,244 2,583,944 Exp. for Certain Civic, Political & Related Activities (426.4) 48
2,407,771 37,428,313 Other Deductions (426.5) 49
6,293,862 39,308,921TOTAL Other Income Deductions (Total of lines 43 thru 49) 50
Taxes Applic. to Other Income and Deductions 51
299,513 203,109262-263Taxes Other Than Income Taxes (408.2) 52
4,267,107 -6,629,160262-263Income Taxes-Federal (409.2) 53
579,829 -900,793262-263Income Taxes-Other (409.2) 54
128,771,334 102,052,978234, 272-277Provision for Deferred Inc. Taxes (410.2) 55
131,834,874 105,466,318234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.2) 56
Investment Tax Credit Adj.-Net (411.5) 57
553,152 691,070(Less) Investment Tax Credits (420) 58
1,529,757 -11,431,254TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59
50,262,165 45,923,030Net Other Income and Deductions (Total of lines 41, 50, 59) 60
Interest Charges 61
356,471,778 358,380,033Interest on Long-Term Debt (427) 62
4,088,677 4,073,420Amort. of Debt Disc. and Expense (428) 63
832,212 905,935Amortization of Loss on Reaquired Debt (428.1) 64
11,026 11,026(Less) Amort. of Premium on Debt-Credit (429) 65
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 66
19,377 2,512Interest on Debt to Assoc. Companies (430) 67
14,445,893 13,513,332Other Interest Expense (431) 68
17,591,087 25,295,555(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69
358,255,824 351,568,651Net Interest Charges (Total of lines 62 thru 69) 70
695,335,538 697,859,628Income 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
695,335,538 697,859,628Net 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, 2015 and 2014, depreciation expense associated with transportation
equipment was $14,214,593 and $13,767,456, 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, 2015 and 2014, payroll taxes were
$39,835,178 and $40,126,082, 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
2015/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
/ /
2015/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)
3,180,100,349 3,135,214,887 1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acct. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct. 439)
683,278,561 681,790,589 16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
( 3,096,169) -5,674,637215.1 18 Appropriation of excess earnings at certain hydroelectric generating facilities
19
20
21
( 3,096,169) -5,674,637 22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
( 161,902) -161,902238 24 Preferred Stock, various series and rates
25
26
27
28
( 161,902) -161,902 29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
( 725,000,000) -950,000,000238 31 Common Stock
32
33
34
35
( 725,000,000) -950,000,000 36 TOTAL Dividends Declared-Common Stock (Acct. 438)
94,048 88,057216.1 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
3,135,214,887 2,861,256,994 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
/ /
2015/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)
10,660,803 16,335,440 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
10,660,803 16,335,440 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
3,145,875,690 2,877,592,434 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
127,661,628 142,148,647 49 Balance-Beginning of Year (Debit or Credit)
14,581,067 13,544,949 50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
( 94,048) -88,057 52 Transfers to/from Unappropriated Retained Earnings (Account 216)
142,148,647 155,605,539 53 Balance-End of Year (Total lines 49 thru 52)
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
Schedule Page: 118 Line No.: 24 Column: c
Outstanding shares of preferred stock as of December 31, 2015 and dividends on preferred
stock during the year ended December 31, 2015 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, 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.: 37 Column: c
In September 2015, Trapper Mining Inc., a subsidiary of PacifiCorp, paid a dividend of
$88,057 to PacifiCorp.
Schedule Page: 118 Line No.: 37 Column: d
In September 2014, Trapper Mining Inc., a subsidiary of PacifiCorp, paid a dividend of
$94,048 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
2015/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
/ /2015/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:
697,859,628 695,335,538 2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
678,784,159 712,627,877 4 Depreciation and Depletion
46,983,824 44,050,122 5 Amortization:
6
7
306,829,081 174,992,182 8 Deferred Income Taxes (Net)
-5,710,268 -5,309,560 9 Investment Tax Credit Adjustment (Net)
9,327,709 -4,106,411 10 Net (Increase) Decrease in Receivables
31,370,952 -7,282,585 11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
10,273,904 20,473,475 13 Net Increase (Decrease) in Payables and Accrued Expenses
-95,045,998 48,439,923 14 Net (Increase) Decrease in Other Regulatory Assets
-10,169,717 14,305,404 15 Net Increase (Decrease) in Other Regulatory Liabilities
50,655,904 32,841,065 16 (Less) Allowance for Other Funds Used During Construction
14,487,019 13,456,892 17 (Less) Undistributed Earnings from Subsidiary Companies
-54,351,514 117,602,515 18 Amounts Due To/From Affiliates (Net)
-16,500,000 -46,700,000 19 Derivative Collateral (Net)
21,671,928 5,756,910 20 Other Operating Activities:
21
1,556,180,765 1,723,887,433 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):
-1,115,501,291 -948,488,007 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
-50,655,904 -32,841,065 30 (Less) Allowance for Other Funds Used During Construction
-22,770,214 31 Other (provide details in footnote):
32
33
-1,064,845,387 -938,417,156 34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
1,069,188 19,089,066 37 Proceeds from Disposal of Noncurrent Assets (d)
38
-2,060,000 -216,000 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
/ /2015/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
1,624,874 -484,494 53 Other Investing Activities:
54
55
56 Net Cash Provided by (Used in) Investing Activities
-1,064,211,325 -920,028,584 57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
424,745,000 249,680,000 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)
15,237,000 67 Other (provide details in footnote):
68
69
444,744,528 264,917,000 70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
-235,762,000 -122,199,000 73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
-12,032,497 -2,600,477 76 Other (provide details in footnote):
-1,844,876 -1,382,004 77 Repayment of Capital Lease Obligations
-972 78 Net Decrease in Short-Term Debt (c)
79
-161,902 -161,902 80 Dividends on Preferred Stock
-725,000,000 -950,000,000 81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
-530,056,747 -811,427,355 83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
-38,087,307 -7,568,506 86 (Total of lines 22,57 and 83)
87
51,563,633 13,476,326 88 Cash and Cash Equivalents at Beginning of Period
89
13,476,326 5,907,820 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 $15,596,597 and $15,612,332 during the years ended December 31, 2015 and 2014,
respectively.
Schedule Page: 120 Line No.: 5 Column: a
Years Ended December 31,
2015 2014
Amortization of software development & other intangibles $ 39,034,535 $ 42,052,331
Amortization of electric plant acquisition adjustments 4,989,371 4,834,296
Amortization of a regulatory asset 26,216 97,197
$ 44,050,122 $ 46,983,824
Schedule Page: 120 Line No.: 20 Column: a
Years Ended December 31,
2015 2014
Depreciation and depletion included in cost of fuel $ 1,876,649 $ 24,247,414
Net loss/(gain) on sale of property 390,138 (310,850)
Write-off of assets under construction 3,748,844 362,850
Change in corporate owned life insurance cash surrender
value (4,474,180) (6,374,744)
Amortization of debt issuance expenses and bond
discount/premium 4,077,651 4,062,394
Other 137,808 (315,136)
$ 5,756,910 $ 21,671,928
Schedule Page: 120 Line No.: 31 Column: a
Acquisition of Eagle Mountain City distribution and transmission assets and liabilities:

Account 101, Electric plant in service $(32,055,360)
Account 143, Other accounts receivable (25,638)
Account 154, Plant materials and operating supplies (493,848)
Account 242, Miscellaneous current and accrued liabilities 10,678
Account 244, Derivative instrument liabilities 3,785,889
Account 253, Other deferred credits 6,008,065
$(22,770,214)
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,
2015 2014
Other investments/special funds $ 1,377,796 $ 1,174,723
Temporary facilities 56,895 32,429
Restricted cash 3,826,237 417,722
Investment in long-term incentive plan securities (5,745,422) -
$ (484,494) $ 1,624,874
Schedule Page: 120 Line No.: 67 Column: b
Net proceeds of affiliate borrowing from subsidiary company, Pacific Minerals, Inc.
Schedule Page: 120 Line No.: 76 Column: a
Years Ended December 31,
2015 2014
Net repayments of affiliate borrowing from subsidiary
company, Pacific Minerals, Inc. $ - $ (8,615,195)
Long-term debt issuance and other deferred financing costs (2,600,477) (3,417,302)
$ (2,600,477) $(12,032,497)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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 / /2015/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 net non-current assets or liabilities 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
2015/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
2015/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):
2015 2014
Cash (131) $ 6 $ 7
Temporary cash investments (136) — 6
Total cash and cash equivalents $6 $13
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, 2015 and 2014,
PacifiCorp had no unrealized gains and losses on available-for-sale securities. Trading securities are carried at fair value with realized
and unrealized gains and losses recognized in earnings.
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):
2015 2014
Beginning balance $ 7 $ 8
Charged to operating costs and expenses, net 10 11
Write-offs, net (10) (12)
Ending balance $7 $7
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
2015/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 net
realizable value.
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 regulated 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, 2015 and 2014, unbilled revenue was $245 million and $243 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
2015/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
$437 million and $446 million as of December 31, 2015 and 2014, respectively, and regulatory liabilities of $12 million and
$13 million as of December 31, 2015 and 2014, 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
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.5
New Accounting Pronouncements
In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02,
which creates FASB Accounting Standards Codification ("ASC") Subtopic 842, "Leases" and supersedes Subtopic 840 "Leases." This
guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet
and disclosing key information about leasing arrangements. A lessee should recognize in the statement of financial position a liability
to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term.
The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly
changed from previous guidance. This guidance is effective for interim and annual reporting periods beginning after December 15,
2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. PacifiCorp is currently
evaluating the impact of adopting this guidance on its financial statements and disclosures included within Notes to Financial
Statements.
In January 2016, the FASB issued ASU No. 2016-01, which amends FASB ASC Subtopic 825-10, "Financial Instruments - Overall."
The amendments in this guidance address certain aspects of recognition, measurement, presentation and disclosure of financial
instruments including a requirement that all investments in equity securities that do not qualify for equity method accounting or result
in consolidation of the investee be measured at fair value with changes in fair value recognized in net income. This guidance is
effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption not permitted, and is
required to be adopted prospectively by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal
year of adoption. PacifiCorp is currently evaluating the impact of adopting this guidance on its financial statements and disclosures
included within Notes to Financial Statements.
In May 2014, the FASB issued ASU No. 2014-09, which creates FASB 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. In
August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and
annual reporting periods beginning after December 15, 2017. 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.
Subsequent Events
PacifiCorp has evaluated the impact of events occurring after December 31, 2015 up to February 26, 2016, the date that PacifiCorp's
GAAP financial statements were filed with the United States Securities and Exchange Commission and has updated such evaluation
for disclosure purposes through April 12, 2016. 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 2.9% and 3.0% for the years ended
December 31, 2015 and 2014, 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
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.6
(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.
The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility as of December 31, 2015
(dollars in millions):
Facility Accumulated Construction
PacifiCorp in Depreciation and Work-in-
Share Service Amortization Progress
Jim Bridger Nos. 1 - 4 67% $ 1,289 $ 565 $ 83
Hunter No. 1 94 469 151 —
Hunter No. 2 60 293 93 —
Wyodak 80 457 193 3
Colstrip Nos. 3 and 4 10 239 130 2
Hermiston 50 177 71 1
Craig Nos. 1 and 2 19 325 216 18
Hayden No. 1 25 76 31 —
Hayden No. 2 13 30 18 7
Foote Creek 79 39 24 —
Transmission and distribution facilities Various 577 191 46
Total $3,971 $1,683 $160
In October 2015, PacifiCorp and Idaho Power Company ("Idaho Power") each transferred to the other party full or undivided
interests in specified transmission-related equipment and facilities under a Joint Purchase and Sale Agreement executed in
October 2014. 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.7
(5) Regulatory Matters
Regulatory Assets
PacifiCorp had regulatory assets not earning a return on investment of 1.096 billion and $1.479 billion as of December 31, 2015 and
2014, respectively.
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 ("UPSC"), the Oregon
Public Utility Commission ("OPUC"), the Wyoming Public Service Commission ("WPSC") 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 Plan and settle PacifiCorp's other postretirement
benefit obligation for UMWA participants (collectively, the "Utah Mine Disposition").
In April 2015, PacifiCorp filed all-party settlement stipulations with the UPSC and the WPSC finding that the decision to enter into
the Utah Mine Disposition transaction was prudent and in the public interest. The UPSC approved the stipulation in April 2015 and
the WPSC approved the stipulation in May 2015. In May 2015, the OPUC issued its final order concluding that the Utah Mine
Disposition transaction produces net benefits for customers and was in the public interest. The IPUC also issued an order in
May 2015, approving the Utah Mine Disposition and ruling that the decision to enter into the transaction was prudent and in the
public interest. Accordingly, in June 2015, PacifiCorp sold the specified Utah mining assets and the replacement and amended coal
supply agreements became effective. Refer to Note 9 for discussion of the UMWA 1974 Pension Plan withdrawal and the settlement
of the other postretirement benefit obligation for UMWA participants. The Deer Creek mine is currently idled and closure activities
have begun.
In December 2014, PacifiCorp also filed an advice letter with the California Public Utilities Commission ("CPUC"). In July 2015, the
CPUC Energy Division issued a letter requiring PacifiCorp to file a formal application for approval of the sale of certain Utah mining
assets. Accordingly, in September 2015, PacifiCorp filed an application with the CPUC.
(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):
2015:
Credit facilities $ 1,200
Less:
Short-term debt (20)
Tax-exempt bond support and letters of credit (160)
Net credit facilities $1,020
2014:
Credit facilities $ 1,200
Less:
Short-term debt (20)
Letters of credit and tax-exempt bond support (398)
Net credit facilities $782
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.8
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, 2015 and 2014, the weighted average interest rate on commercial paper borrowings outstanding
was 0.65% and 0.43%, respectively. 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, 2015, PacifiCorp was in
compliance with the covenants of its credit facilities.
As of December 31, 2015 and 2014, PacifiCorp had $310 million and $451 million, respectively, of fully available letters of credit
issued under committed arrangements, of which $10 million and $270 million as of December 31, 2015 and 2014 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, 2015, PacifiCorp had approximately $15 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, 2015
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 June 2015, PacifiCorp issued $250 million of its 3.35% First Mortgage Bonds due July 2025. The net proceeds were used to fund
capital expenditures and for general corporate purposes, including retirement of short-term debt.
PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $1.325 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 to
issue up to $1.325 billion additional first mortgage bonds through January 2019.
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, 2015.
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
$32 million and $34 million as of December 31, 2015 and 2014, respectively, were included in net utility plant in the Comparative
Balance Sheet.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.9
As of December 31, 2015, the annual principal maturities of long-term debt and total capital lease obligations for 2016 and thereafter
are as follows (in millions):
Long-term Capital Lease
Debt Obligations Total
2016 $ 66 $ 5 $ 71
2017 52 10 62
2018 586 5 591
2019 350 5 355
2020 38 4 42
Thereafter 6,067 27 6,094
Total 7,159 56 7,215
Unamortized discount (12) — (12)
Amounts representing interest — (24)(24)
Total $7,147 $32 $7,179
(8) Income Taxes
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2015 2014
Current:
Federal $ 125 $ (10)
State 26 9
Total 151 (1)
Deferred:
Federal 146 264
State 29 43
Total 175 307
Investment tax credits (5) (6)
Total income tax expense $321 $300
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.10
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:
2015 2014
Federal statutory income tax rate 35% 35%
State income taxes, net of federal income tax benefit 3 3
Federal income tax credits (6) (7)
Other — (1)
Effective income tax rate 32%30%
Income tax credits relate primarily to production tax credits earned by PacifiCorp's wind-powered generating facilities. Federal
renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and
sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities
are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.
The net deferred income tax liability consists of the following as of December 31 (in millions):
2015 2014
Deferred income tax assets:
Employee benefits $ 190 $ 183
Derivative contracts and unamortized contract values 94 79
State carryforwards 69 68
Loss contingencies 56 51
Asset retirement obligations 81 47
Regulatory liabilities 30 29
Other 86 88
606 545
Deferred income tax liabilities:
Property, plant and equipment (4,701) (4,497)
Regulatory assets (639) (611)
Other (18)(22)
(5,358)(5,130)
Net deferred income tax liability $(4,752)$(4,585)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.11
The following table provides PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31,
2015 (in millions):
State
Net operating loss carryforwards $ 1,416
Deferred income taxes on net operating loss carryforwards $ 52
Expiration dates 2016 - 2032
Tax credit carryforwards $ 16
Expiration dates 2016 - indefinite
The United States Internal Revenue Service has closed 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.
(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 previously contributed 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, PacifiCorp's subsidiary, 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 a fund managed by the UMWA. Transfer of the
assets and settlement of this obligation occurred in May 2015 and resulted in a remeasurement of the other postretirement plan assets
and benefit obligation. As a result of the remeasurement, PacifiCorp recognized a $9 million settlement loss, with the portion that is
probable of recovery deferred as a regulatory asset. No curtailment accounting was 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 closure of the Deer Creek mining operations, withdrawal by Energy West Mining Company from the UMWA 1974
Pension Plan was involuntarily triggered in June 2015 when UMWA employees ceased performing work for the subsidiary. Refer to
"Multiemployer and Joint Trustee Pension Plans" below for further information regarding the withdrawal.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.12
Net Periodic Benefit Cost
For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets
is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the
first year in which they occur.
Net periodic benefit cost for the plans included the following components for the years ended December 31 (in millions):
Pension Other Postretirement
2015 2014 2015 2014
Service cost $ 4 $ 5 $ 3 $ 6
Interest cost 53 57 16 28
Expected return on plan assets (77) (76) (23) (31)
Net amortization 42 29 (4) 2
Net period benefit cost $22 $15 $(8)$5
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
2015 2014 2015 2014
Plan assets at fair value, beginning of year $ 1,146 $ 1,171 $ 482 $ 486
Employer contributions 4 10 1 1
Participant contributions — — 6 7
Actual return on plan assets — 53 1 25
Settlement — — (150) —
Benefits paid (107) (88) (35) (37)
Plan assets at fair value, end of year $1,043 $1,146 $305 $482
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.13
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
Pension Other Postretirement
2015 2014 2015 2014
Benefit obligation, beginning of year $ 1,378 $ 1,230 $ 539 $ 598
Service cost 4 5 3 6
Interest cost 53 57 16 28
Participant contributions — — 6 7
Actuarial (gain) loss (39) 174 (17) (63)
Settlement — — (150) —
Benefits paid (107) (88) (35) (37)
Benefit obligation, end of year $1,289 $1,378 $362 $539
Accumulated benefit obligation, end of year $1,289 $1,378
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 associated with the UMWA plan participants to $150 million. Refer to "Utah Mine
Disposition and Labor Agreement" above.
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
2015 2014 2015 2014
Plan assets at fair value, end of year $ 1,043 $ 1,146 $ 305 $ 482
Less - Benefit obligation, end of year 1,289 1,378 362 539
Funded status $(246)$(232)$(57)$(57)
Amounts recognized on the Comparative Balance Sheet:
Miscellaneous current and accrued liabilities $ (4) $ (4) $ — $ —
Accumulated provision for pension and benefits (242) (228) (57) (57)
Amounts recognized $(246)$(232)$(57)$(57)
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
$52 million and $51 million as of December 31, 2015 and 2014, respectively. These assets are not included in the plan assets in the
above table, but are reflected in other investments on the Comparative Balance Sheet.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.14
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
2015 2014 2015 2014
Net loss $ 508 $ 520 $ 36 $ 41
Prior service credit (13) (21) (19) (26)
Regulatory deferrals (3) (3) 9 2
Total $492 $496 $26 $17
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2015
and 2014 is as follows (in millions):
Accumulated
Other
Regulatory Comprehensive
Asset Loss Total
Pension
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
Net loss (gain) arising during the year 40 (2) 38
Net amortization (41)(1)(42)
Total (1)(3)(4)
Balance, December 31, 2015 $473 $19 $492
Regulatory
Asset
Other Postretirement
Balance, December 31, 2013 $77
Net gain arising during the year (58)
Net amortization (2)
Total (60)
Balance, December 31, 2014 17
Net loss arising during the year 5
Net amortization 4
Total 9
Balance, December 31, 2015 $26
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.15
The net loss, prior service credit and regulatory deferrals that will be amortized in 2016 into net periodic benefit cost are estimated to
be as follows (in millions):
Net Prior Service Regulatory
Loss Credit Deferrals Total
Pension $ 42 $ (8) $ (1) $ 33
Other postretirement 1 (7) 1 (5)
Total $43 $(15)$—$28
Plan Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
Pension Other Postretirement
2015 2014 2015 2014
Benefit obligations as of December 31:
Discount rate 4.40% 4.00% 4.35% 3.90%
Rate of compensation increase 2.75 2.75 N/A N/A
Net periodic benefit cost for the years ended December 31:
Discount rate 4.00% 4.80% 3.99% 4.90%
Expected return on plan assets 7.50 7.50 7.08 7.50
Rate of compensation increase 2.75 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 historical performance and forward-looking views of the financial markets. As discussed above in "Utah
Mine Disposition and Labor Agreement," PacifiCorp remeasured the other postretirement plan assets and benefit obligation as of
May 31, 2015. The other postretirement assumptions for the year ended December 31, 2015 presented above reflect a weighted
average calculation that considered the assumptions used in the periods preceding and subsequent to the remeasurement.
As a result of the labor settlement discussed above in "Utah Mine Disposition and Labor Agreement," the benefit obligation for the
other postretirement plan is no longer affected by healthcare cost trends. The assumed healthcare cost trend rates used to determine
the benefit obligation as of December 31, 2014 were as follows:
Healthcare cost trend rate assumed for next year 8.00%
Rate that the cost trend rate gradually declines to 5.00%
Year that the rate reaches the rate it is assumed to remain at 2025
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.16
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $- million,
respectively, during 2016. 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.
The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2016 through 2020
and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Pension Other Postretirement
2016 $ 108 $ 28
2017 110 28
2018 108 28
2019 109 27
2020 107 30
2021-2025 448 122
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, 2015:
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
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.17
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, 2015
Cash equivalents $ — $ 10 $ — $ 10
Debt securities:
United States government obligations 19 — — 19
Corporate obligations — 42 — 42
Municipal obligations — 5 — 5
Agency, asset and mortgage-backed obligations — 43 — 43
Equity securities:
United States companies 408 — — 408
International companies 17 — — 17
Investment funds(2)83 351 — 434
Limited partnership interests(3)— — 65 65
Total $527 $451 $65 $1,043
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
(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
53% and 47%, respectively, for 2015 and 50% and 50%, respectively, for 2014, and are invested in United States and international securities of
approximately 40% and 60%, respectively, for 2015 and 43% and 57%, respectively, for 2014.
(3) Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.18
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, 2015
Cash and cash equivalents $ 4 $ 1 $ — $ 5
Debt securities:
United States government obligations 9 — — 9
Corporate obligations — 15 — 15
Municipal obligations — 1 — 1
Agency, asset and mortgage-backed obligations — 14 — 14
Equity securities:
United States companies 95 — — 95
International companies 4 — — 4
Investment funds(2)32 126 — 158
Limited partnership interests(3)— — 4 4
Total $144 $157 $4 $305
As of December 31, 2014
Cash and cash equivalents(4)$ 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(2)84 94 — 178
Limited partnership interests(3)— — 5 5
Total $347 $130 $5 $482
(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
61% and 39%, respectively, for 2015 and 63% and 37%, respectively, for 2014, and are invested in United States and international securities of
approximately 67% and 33%, respectively, for 2015 and 64% and 36%, respectively, for 2014.
(3) Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
(4) In December 2014, PacifiCorp began to migrate funds to cash and cash equivalents in anticipation of the $150 million to be transferred to a fund managed by
the UMWA in May 2015 as a result of the other postretirement settlement. Remaining investments were rebalanced to align to target investment allocations.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.19
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, 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
Actual return on plan assets still held at December 31, 2015 5 —
Purchases, sales, distributions and settlements (10) (1)
Balance, December 31, 2015 $65 $4
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, previously contributed to the UMWA 1974 Pension Plan (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's subsidiary, Energy West Mining Company,
triggered involuntary withdrawal from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased performing
work for the subsidiary. The estimated withdrawal obligation was recorded in December 2014 when withdrawal was considered
probable, and a regulatory asset was established for the portion of the obligation considered probable of recovery. The estimate of the
withdrawal obligation provided by the UMWA 1974 Pension Plan is $97 million for a withdrawal occurring by July 1, 2015. Energy
West Mining Company may elect to make a lump sum payment or annual installment payments to settle the withdrawal obligation.
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 occurred as a result of Energy West Mining Company's
withdrawal from the UMWA 1974 Pension Plan. 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 withdrew during the
three years prior to a mass withdrawal.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.20
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 plan funded
status percentage for plan years
beginning July 1,Contributions(1)
Plan name
Employer
Identification
Number 2015 2014
Funding
improvement
plan
Surcharge
imposed
under PPA 2015 2014
Year contributions to plan
exceeded more than 5% of
total contributions(2)
UMWA
Pension Plan
52-1050282 Critical and
Declining
Critical Implemented Yes $1 $2 None
Local 57
Trust Fund 87-0640888 At least 80% At least 80% None None $ 8 $ 9 2014, 2013
(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 Plan, 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 Plan, information is for plan year beginning July 1, 2013. Information for the plan years beginning July 1, 2015 and 2014 is
not yet available. For the Local 57 Trust Fund, information is for plan years beginning July 1, 2014 and 2013. Information for the plan year beginning July 1,
2015 is not yet available.
The current collective bargaining agreements governing the Local 57 Trust Fund expire in January 2020.
Defined Contribution Plan
PacifiCorp's 401(k) Plan covers substantially all employees. PacifiCorp's matching contributions are based on each participant's level
of contribution, and certain participants receive contributions based on eligible pre-tax annual compensation. Contributions cannot
exceed the maximum allowable for tax purposes. PacifiCorp's contributions to the 401(k) Plan were $35 million and $34 million for
the years ended December 31, 2015 and 2014, 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
$894 million and $873 million as of December 31, 2015 and 2014, 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
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.21
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31
(in millions):
2015 2014
Beginning balance $ 135 $ 138
Change in estimated costs 62 (3)
Additions 30 —
Retirements (10) (6)
Accretion 7 6
Ending balance $224 $135
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 United States 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 was published in the Federal Register in
April 2015 and was effective in October 2015. The final rule substantially impacted existing AROs reflected in the December 31,
2015 change in estimated costs above and also resulted in the recognition of additional AROs.
(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
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.22
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, 2015
Not designated as hedging contracts(1):
Commodity assets $ 10 $ — $ 2 $ — $ 12
Commodity liabilities (1)— (58) (89)(148)
Total 9 —(56)(89)(136)
Total derivatives 9 — (56) (89) (136)
Cash collateral receivable — — 18 57 75
Total derivatives - net basis $9 $—$(38)$(32)$(61)
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)
(1) PacifiCorp's commodity derivatives are generally included in rates and as of December 31, 2015 and 2014, a regulatory asset of $133 million and
$85 million, respectively, was recorded related to the net derivative liability of $136 million and $85 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):
2015 2014
Beginning balance $ 85 $ 55
Changes in fair value recognized in regulatory assets 82 45
Net gains (losses) reclassified to operating revenue 40 (4)
Net losses reclassified to energy costs (74) (11)
Ending balance $133 $85
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.23
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 2015 2014
Electricity purchases (sales) Megawatt hours 1 (1)
Natural gas purchases Decatherms 111 113
Fuel oil purchases Gallons 11 3
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, 2015, 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 $142 million and $113 million as of December 31, 2015 and 2014, respectively, for which PacifiCorp had posted collateral of
$75 million and $28 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, 2015 and 2014, PacifiCorp would have been required to post
$64 million and $75 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, 2015 and December 31, 2014, PacifiCorp would have been required to post
$261 million and $233 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
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.24
(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, 2015
Assets:
Commodity derivatives $ — $ 9 $ 3 $ (3) $ 9
Money market mutual funds(2)13 — — — 13
Investment funds 15 ———15
$28 $9 $3 $(3)$37
Liabilities - Commodity derivatives $—$(148)$—$78 $(70)
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)
(1) Represents netting under master netting arrangements and a net cash collateral receivable of $75 million and $28 million as of December 31, 2015 and 2014,
respectively.
(2) Amounts are included in other special funds and temporary cash investments on the Comparative Balance Sheet. Money market mutual funds are accounted
for as available-for-sale securities and the fair value 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
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.25
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. 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 and investment funds are stated at fair value. PacifiCorp uses a readily
observable quoted market price or net asset value of an identical security in an active market to record the fair value.
PacifiCorp's long-term debt is carried at cost on the Comparative Balance Sheet. 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):
2015 2014
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $7,147 $8,210 $7,019 $8,358
(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
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.26
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. After considering various motions filed by the parties to
expand or limit damages, interest and attorney's fees, in May 2013, the court entered a final judgment 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
were heard in September 2015. As of December 31, 2015, PacifiCorp had accrued $122 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.
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 provided that the United States Department of the Interior would conduct scientific and
engineering studies to assess whether removal of the Klamath hydroelectric system's mainstem dams was in the public interest and
would advance restoration of the Klamath Basin's salmonid fisheries. If it was determined that dam removal should proceed, dam
removal would have begun no earlier than 2020.
Under the KHSA, PacifiCorp and its customers were protected from uncapped dam removal costs and liabilities. For dam removal to
occur, federal legislation consistent with the KHSA was required to provide, among other things, protection for PacifiCorp from all
liabilities associated with dam removal activities. As of December 31, 2015, no federal legislation had been enacted and several
parties to the KHSA initiated a dispute resolution process.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.27
In February 2016, the principal parties to the KHSA (PacifiCorp, the states of California and Oregon, and the United States
Departments of the Interior and Commerce) executed an agreement in principle committing to explore potential amendment of the
KHSA to facilitate removal of the Klamath dams through a FERC process without the need for federal legislation. Since that time,
PacifiCorp, the states of California and Oregon, and the United States Department of Interior and Commerce negotiated an
amendment to the KHSA that was signed on April 6, 2016. Under the amended KSHA, PacifiCorp will file an application with the
FERC to transfer the license for the four mainstem Klamath River hydroelectric generating facilities to a newly formed private entity,
the Klamath River Renewal Corporation ("KRRC"). The KRRC will file an application to surrender the license and decommission the
facilities with the FERC.
The amended KHSA provides PacifiCorp with liability protections comparable to the KHSA. The amended KHSA also limits
PacifiCorp's contribution to facilities 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 facilities 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 toward facilities removal costs will be drawn. If facilities
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 the KRRC or an entity other than PacifiCorp in order for facilities removal
to proceed.
If certain conditions in the amended KSHA are not satisfied and the license does not transfer to the KRRC, PacifiCorp will resume
relicensing with the FERC.
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 $252 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, 2015 are as follows (in millions):
2016 2017 2018 2019 2020
2021 and
Thereafter Total
Contract type:
Purchased electricity contracts -
commercially operable $ 168 $ 71 $ 70 $ 67 $ 68 $ 401 $ 845
Purchased electricity contracts -
non-commercially operable 16 102 104 104 104 1,687 2,117
Fuel contracts 862 689 558 542 496 1,720 4,867
Construction commitments 144 12 10 2 2 5 175
Transmission 105 97 91 76 55 508 932
Operating leases and easements 5 4 4 4 4 42 63
Maintenance, service and
other contracts 36 30 19 24 11 74 194
Total commitments $1,336 $1,005 $856 $819 $740 $4,437 $9,193
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.28
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 $13 million for 2015 and $15 million for 2014.
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 2015
and 2014 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 $15 million for the year ended December 31, 2015 and $16 million for the year
ended December 31, 2014.
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.29
(14) Preferred Stock
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 2016, PacifiCorp declared a dividend of $100 million which was paid to PPW Holdings LLC, a wholly owned subsidiary
of BHE and PacifiCorp's direct parent company ("PPW Holdings") in March 2016.
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, 2015, 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, 2015, PacifiCorp's actual
common equity percentage, as calculated under this measure, was 52%, and PacifiCorp would have been permitted to dividend
$2.0 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, 2015, 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):
2015 2014
Interest paid, net of amounts capitalized $342 $340
Income taxes paid, net(1)$32 $154
Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to utility plant additions $ 147 $ 140
Accounts receivable related to utility plant sales $10 $—
(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 received from or 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
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.30
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
PacifiCorp X
/ /2015/Q4
Line
No.
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Other
Adjustments
(e)
Foreign Currency
Hedges
(d)
Minimum Pension
Liability adjustment
(net amount)
(c)
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Item
(a)
( 9,091,505)
Balance of Account 219 at Beginning of
Preceding Year
1
346,579
Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
2
( 4,920,754)
Preceding Quarter/Year to Date Changes in
Fair Value
3
( 4,574,175)Total (lines 2 and 3) 4
( 13,665,680)
Balance of Account 219 at End of Preceding
Quarter/Year
5
( 13,665,680)
Balance of Account 219 at Beginning of
Current Year
6
549,221
Current Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
7
1,101,821
Current Quarter/Year to Date Changes in
Fair Value
8
1,651,042Total (lines 7 and 8) 9
( 12,014,638)
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
/ /2015/Q4
Line
No.
Total
Comprehensive
Income
(j)
Net Income (Carried
Forward from
Page 117, Line 78)
(i)
Totals for each
category of items
recorded in
Account 219
(h)
( 9,091,505) 1
346,579 2
( 4,920,754) 3
697,859,628 693,285,453( 4,574,175) 4
( 13,665,680) 5
( 13,665,680) 6
549,221 7
1,101,821 8
695,335,538 696,986,580 1,651,042 9
( 12,014,638) 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
/ /2015/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
26,338,511,410 26,338,511,410Plant in Service (Classified) 3
32,269,865 32,269,865Property Under Capital Leases 4
2,021,782 2,021,782Plant Purchased or Sold 5
178,083,508 178,083,508Completed Construction not Classified 6
Experimental Plant Unclassified 7
26,550,886,565 26,550,886,565Total (3 thru 7) 8
Leased to Others 9
23,319,217 23,319,217Held for Future Use 10
628,213,113 628,213,113Construction Work in Progress 11
154,931,754 154,931,754Acquisition Adjustments 12
27,357,350,649 27,357,350,649Total Utility Plant (8 thru 12) 13
9,237,522,532 9,237,522,532Accum Prov for Depr, Amort, & Depl 14
18,119,828,117 18,119,828,117Net Utility Plant (13 less 14) 15
Detail of Accum Prov for Depr, Amort & Depl 16
In Service: 17
8,565,801,806 8,565,801,806Depreciation 18
Amort & Depl of Producing Nat Gas Land/Land Right 19
Amort of Underground Storage Land/Land Rights 20
559,800,280 559,800,280Amort of Other Utility Plant 21
9,125,602,086 9,125,602,086Total 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
111,920,446 111,920,446Amort of Plant Acquisition Adj 32
9,237,522,532 9,237,522,532Total 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
/ /2015/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
/ /2015/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account
103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of
plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)
1. INTANGIBLE PLANT 1
(301) Organization 2
(302) Franchises and Consents 206,918,794 55,991 3
(303) Miscellaneous Intangible Plant 673,276,331 24,205,162 4
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 880,195,125 24,261,153 5
2. PRODUCTION PLANT 6
A. Steam Production Plant 7
(310) Land and Land Rights 93,605,464 47,987 8
(311) Structures and Improvements 1,016,964,547 18,702,737 9
(312) Boiler Plant Equipment 4,241,159,623 238,183,284 10
(313) Engines and Engine-Driven Generators 11
(314) Turbogenerator Units 996,174,043 17,716,957 12
(315) Accessory Electric Equipment 491,994,671 2,559,657 13
(316) Misc. Power Plant Equipment 31,176,256 176,739 14
(317) Asset Retirement Costs for Steam Production 56,579,908 89,146,747 15
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 6,927,654,512 366,534,108 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 246,835,680 16,242,098 28
(332) Reservoirs, Dams, and Waterways 481,948,519 8,166,920 29
(333) Water Wheels, Turbines, and Generators 126,979,854 2,130,269 30
(334) Accessory Electric Equipment 77,521,376 4,853,291 31
(335) Misc. Power PLant Equipment 2,375,380 8,928 32
(336) Roads, Railroads, and Bridges 20,500,603 1,720,983 33
(337) Asset Retirement Costs for Hydraulic Production 34
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 987,478,128 33,122,489 35
D. Other Production Plant 36
(340) Land and Land Rights 43,017,819 1,756,736 37
(341) Structures and Improvements 226,915,569 607,659 38
(342) Fuel Holders, Products, and Accessories 15,869,834 194,191 39
(343) Prime Movers 2,899,836,969 87,055,026 40
(344) Generators 471,641,816 5,065,733 41
(345) Accessory Electric Equipment 325,607,171 982,837 42
(346) Misc. Power Plant Equipment 15,102,112 819,853 43
(347) Asset Retirement Costs for Other Production 9,474,651 4,502,488 44
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 4,007,465,941 100,984,523 45
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 11,922,598,581 500,641,120 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
/ /2015/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
206,974,785 3
669,757,688 -296,242 27,427,563 4
876,732,473 -296,242 27,427,563 5
6
7
93,556,326 -87,288 9,837 8
1,011,697,865 -45,298 23,924,121 9
4,374,914,312 -1,260,711 103,167,884 10
11
954,177,895 77,526 59,790,631 12
484,708,784 1,000,767 10,846,311 13
31,275,408 124,182 201,769 14
141,661,372 -3,897,507 167,776 15
7,091,991,962 -190,822 -3,897,507 198,108,329 16
17
18
19
20
21
22
23
24
25
26
31,312,931 3,785 27
262,514,284 -164,236 399,258 28
488,402,461 -43,767 1,669,211 29
128,919,258 190,865 30
79,819,536 2,555,131 31
2,380,783 -3,274 251 32
22,170,609 6,895 57,872 33
34
1,015,519,862 -204,382 4,876,373 35
36
44,773,920 635 37
227,589,347 149,751 83,632 38
15,904,296 159,729 39
2,930,023,773 948,488 57,816,710 40
473,476,623 -916,710 2,314,216 41
326,256,540 -19,457 314,011 42
15,921,587 -378 43
13,031,355 -945,784 44
4,046,977,441 161,694 -945,784 60,688,933 45
12,154,489,265 -233,510 -4,843,291 263,673,635 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
/ /2015/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
3. TRANSMISSION PLANT 47
(350) Land and Land Rights 230,226,403 17,839,900 48
(352) Structures and Improvements 210,430,141 20,077,892 49
(353) Station Equipment 1,875,788,731 155,302,132 50
(354) Towers and Fixtures 1,221,298,019 67,458,271 51
(355) Poles and Fixtures 744,102,993 158,276,662 52
(356) Overhead Conductors and Devices 1,082,532,470 109,294,243 53
(357) Underground Conduit 3,519,566 54
(358) Underground Conductors and Devices 8,035,354 55
(359) Roads and Trails 11,937,200 56
(359.1) Asset Retirement Costs for Transmission Plant 57
TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 5,387,870,877 528,249,100 58
4. DISTRIBUTION PLANT 59
(360) Land and Land Rights 63,135,433 1,379,309 60
(361) Structures and Improvements 104,255,048 3,093,921 61
(362) Station Equipment 925,759,498 38,711,222 62
(363) Storage Battery Equipment 63
(364) Poles, Towers, and Fixtures 1,085,444,520 39,717,972 64
(365) Overhead Conductors and Devices 707,873,785 17,703,989 65
(366) Underground Conduit 341,230,913 10,139,125 66
(367) Underground Conductors and Devices 795,524,274 24,731,953 67
(368) Line Transformers 1,234,715,959 47,383,609 68
(369) Services 679,839,675 30,420,165 69
(370) Meters 180,902,129 8,823,758 70
(371) Installations on Customer Premises 8,831,952 103,069 71
(372) Leased Property on Customer Premises 72
(373) Street Lighting and Signal Systems 61,371,460 1,174,632 73
(374) Asset Retirement Costs for Distribution Plant 1,507,080 74
TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 6,190,391,726 223,382,724 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 21,396,610 86
(390) Structures and Improvements 239,006,029 5,133,404 87
(391) Office Furniture and Equipment 82,750,840 8,903,086 88
(392) Transportation Equipment 107,071,045 6,751,977 89
(393) Stores Equipment 14,910,200 396,647 90
(394) Tools, Shop and Garage Equipment 62,963,632 2,288,604 91
(395) Laboratory Equipment 33,940,714 2,027,929 92
(396) Power Operated Equipment 163,759,938 12,043,147 93
(397) Communication Equipment 408,492,593 18,293,981 94
(398) Miscellaneous Equipment 8,038,720 623,306 95
SUBTOTAL (Enter Total of lines 86 thru 95) 1,142,330,321 56,462,081 96
(399) Other Tangible Property 302,661,738 103,342 97
(399.1) Asset Retirement Costs for General Plant 39,748 98
TOTAL General Plant (Enter Total of lines 96, 97 and 98) 1,445,031,807 56,565,423 99
TOTAL (Accounts 101 and 106) 25,826,088,116 1,333,099,520 100
(102) Electric Plant Purchased (See Instr. 8) 33,944,495 101
(Less) (102) Electric Plant Sold (See Instr. 8) -1,114,497 102
(103) Experimental Plant Unclassified 103
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 25,826,088,116 1,368,158,512 104
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
/ /2015/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
47
251,625,967 3,580,225 20,561 48
239,305,233 9,778,458 981,258 49
2,012,791,077 -7,489,910 10,809,876 50
1,288,991,817 677,369 441,842 51
901,299,535 1,125,206 2,205,326 52
1,193,250,695 3,226,200 1,802,218 53
3,519,566 54
8,035,354 55
11,937,200 56
57
5,910,756,444 10,897,548 16,261,081 58
59
62,461,151 -2,052,930 661 60
110,250,312 3,534,798 633,455 61
971,676,422 12,351,300 5,145,598 62
63
1,120,755,209 595,956 5,003,239 64
724,069,029 212,303 1,721,048 65
349,690,089 1,679,949 66
820,180,898 2,683,874 2,759,203 67
1,274,134,081 1,265,192 9,230,679 68
709,528,257 731,583 69
186,936,755 2,789,132 70
8,863,050 71,971 71
72
61,222,785 1,323,307 73
1,507,080 74
6,401,275,118 18,590,493 31,089,825 75
76
77
78
79
80
81
82
83
84
85
21,481,450 100,073 15,233 86
240,205,455 1,161,730 5,095,708 87
80,556,278 385,964 11,483,612 88
110,652,440 887,811 4,058,393 89
15,178,816 90,651 218,682 90
64,061,851 228,074 1,418,459 91
33,961,776 793,553 2,800,420 92
168,265,144 389,583 7,927,524 93
428,243,947 1,985,549 528,176 94
8,135,600 13,960 540,386 95
1,170,742,757 6,036,948 34,086,593 96
2,559,113 -2,975,841 297,230,126 97
39,748 98
1,173,341,618 3,061,107 331,316,719 99
26,516,594,918 32,019,396 -4,843,291 669,768,823 100
1,460,458 -32,504,781 20,744 101
-561,324 553,173 102
103
26,518,616,700 -1,038,558 -4,822,547 669,768,823 104
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 $ - $ 75,803 $ - $ - $2,559,113
39922 Land Rights 52,550,647 - 52,550,647 - - -
39930 Structures 43,930,324 34,802 42,812,678 - (1,152,448) -
39941 Surface-Plant Equipment 14,435,529 - 14,435,529 - - -
39944 Surface-Electric Pwr Facil 3,424,575 - 3,424,575 - - -
39945 Underground-Coal Mine Equip 71,384,906 - 71,384,906 - - -
39946 Longwall Shields 24,486,688 - 24,486,688 - - -
39947 Longwall Equipment 9,115,912 - 9,115,912 - - -
39948 Mainline Extension 20,274,157 - 20,274,157 - - - 39949 Section Extension 7,386,842 - 7,386,842 - - -
39951 Vehicles 1,321,430 - 788,378 - (533,052) -
39952 Heavy Construction Equip 6,023,975 - 5,902,004 - (121,971) -
39960 Miscellaneous General Equip 2,364,325 71,846 1,376,701 - (1,059,470) -
39961 Computers-Mainframe 467,717 (3,306) 355,511 - (108,900) -39970 Mine Development & Road Ext 38,657,119 - 38,657,119 - - -
39915 Coal Mine ARO 4,202,676 - 4,202,676 - - -
$ 302,661,738 $ 103,342 $297,230,126 $ - $(2,975,841) $2,559,113
Schedule Page: 204 Line No.: 97 Column: c
See footnote line 97, column b.
Schedule Page: 204 Line No.: 97 Column: d
See footnote line 97, column b.
Schedule Page: 204 Line No.: 97 Column: e
See footnote line 97, column b.
Schedule Page: 204 Line No.: 97 Column: f
See footnote line 97, column b.
Schedule Page: 204 Line No.: 97 Column: g
See footnote line 97, column b.
Schedule Page: 204 Line No.: 101 Column: c
Refer to Important Changes During the Year, Item 3, in this Form No. 1.
Schedule Page: 204 Line No.: 101 Column: e
Account 114, Electric plant acquisition adjustments
Schedule Page: 204 Line No.: 101 Column: f
Refer to Important Changes During the Year, Item 3, in this Form No. 1.
Schedule Page: 204 Line No.: 102 Column: c
Refer to Important Changes During the Year, Item 3, in this Form No. 1.
Schedule Page: 204 Line No.: 102 Column: f
Refer to Important Changes During the Year, Item 3, in this Form No. 1.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
/ /2015/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
1977North Horn Mountain Coal Properties 953,0142023-2028 2
2007Barnes Butte Substation 746,2682025 3
2007Wild Horse Wind Plant 6,763,0942028 4
2007Twelve Mile Wind Plant 2,160,2072028 5
2008Jumbers Point Substation 1,173,2762022 6
2009Mountain Green Substation 284,9962025 7
2009Hoggard Substation 254,3972025 8
2009Oquirrh-Terminal 345kV Transmission Line 396,0202021 9
2010Bend Service Center 3,507,8382022 10
2010Legacy Substation 562,2762025 11
2011Aeolus Substation 1,013,5772021 12
2011Anticline Substation 964,0432024 13
2011Populus Substation 254,7532024 14
2011Snyderville Substation 253,4012017 15
2012Lassen Substation 683,3182017 16
2012Old Mill Substation 1,838,2812020 17
2013Chimney Butte-Paradise 230kV Transmission Line 598,4572018 18
Miscellaneous, each under $250,000: 912,001 19
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.: 2 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.: 4 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.: 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.: 19 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
2015/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
/ /2015/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
28,544,601EMS/SCADA Replacement / Upgrade 2
2,465,534Wallowa Falls Hydro Relicensing 3
2,215,433Spectrum License Buildout 4
1,087,932EMS PI Upgrade 5
6
Production: 7
78,314,299Jim Bridger U4 Selective Catalytic Reduction System 8
14,677,256Craig U2 Selective Catalytic Reduction System 9
7,162,006Hayden U2 Selective Catalytic Reduction System 10
5,756,834Chehalis Combustion Turbine 2 Compressor Replace 11
4,842,074Lewis River System Relicensing Implementation 12
4,762,088Hunter U3 Cooling Tower Replacement 13
3,405,586Hunter U3 Generator Stator Rewind 14
2,852,299Cholla U4 Mercury Reduction 15
2,833,706Jim Bridger U4 Replace Finishing Superheater 16
2,327,415Hunter U3 Generator Excitation System 17
2,297,272Hunter U3 Submerged Drag Chain Conveyor 18
1,496,458Hunter U3 Baghouse Bags 19
1,394,450Dave Johnston Replace Ash Silo Flat Bottom with Cone 20
1,342,232Toketee Dam Rehabilitation Evaluation 21
1,074,597Last Chance Dam Rebuild 22
23
Transmission: 24
72,524,742Aeolus - Clover 500kV Line 25
66,658,132Windstar - Populus 230 - 500kV Line 26
45,264,515Boardman - Hemingway 500kV Line 27
44,830,945Populus - Hemingway 500kV Line 28
20,034,832Standpipe Substation New 230kV Substation 29
18,117,077Union Gap Substation Add 230 - 115kV Capacity 30
15,103,401Pinto Substation Add 3rd Phase Shifting Transformer 31
14,424,395Snow Goose 500 - 230kV Substation 32
10,975,575Oquirrh - Terminal 345kV Line 33
8,781,178Vantage - Pomona Heights 230kV Line 34
8,449,489West Point - New 138kV Line and 40 MVA Substation 35
4,725,345Southwest WY - Silver Creek Build 138kV Line 36
3,722,678Wallula - McNary 230kV Line 37
3,637,221Chehalis U3 Generator Step-Up Transformer Replacement 38
3,599,747Weed Substation 115 - 69kV LTC Transformer 39
2,900,867Troutdale Substation 230kV Switchyard 115kV Ring Bus 40
1,674,624Lincoln - Harrison 115kV Line Joint PGE Modifications 41
1,648,115Sigurd - Red Butte - Crystal 345kV Line 42
FERC FORM NO. 1 (ED. 12-87) Page 216
43 TOTAL 628,213,113
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
/ /2015/Q4
Line
No.
Description of Project Construction work in progress -
(b)(a)Electric (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
1,350,983Captain Jack - Snow Goose Replace 500kV Relays 1
1,328,268Purgatory Flat New 138kV Substation 2
1,302,112RMP Spare 161 - 138kV 200 MVA Transformer 3
4
Distribution: 5
2,878,046River Road Substation 25 MVA Transformer 6
2,518,766NE Portland Voltage Conversion Project 7
1,494,267Stadelman Fruit, Yakima WA 8
1,009,306Lassen Substation - New Substation 9
10
100,406,415Miscellaneous Projects each under $1,000,000 11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-87) Page 216.1
43 TOTAL 628,213,113
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
/ /2015/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 8,395,189,232 8,395,189,232
Depreciation Provisions for Year, Charged to 2
(403) Depreciation Expense 3 697,031,280 697,031,280
(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 40,650,578 40,650,578
9
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
10 737,681,858 737,681,858
Net Charges for Plant Retired: 11
Book Cost of Plant Retired 12 634,661,285 634,661,285
Cost of Removal 13 56,702,091 56,702,091
Salvage (Credit) 14 5,459,746 5,459,746
TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
15 685,903,630 685,903,630
Other Debit or Cr. Items (Describe, details in
footnote):
16 118,834,346 118,834,346
17
Book Cost or Asset Retirement Costs Retired 18
Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
19 8,565,801,806 8,565,801,806
Steam Production 20
Section B. Balances at End of Year According to Functional Classification
2,886,821,179 2,886,821,179
Nuclear Production 21
Hydraulic Production-Conventional 22 327,988,750 327,988,750
Hydraulic Production-Pumped Storage 23
Other Production 24 847,165,096 847,165,096
Transmission 25 1,503,737,225 1,503,737,225
Distribution 26 2,581,141,819 2,581,141,819
Regional Transmission and Market Operation 27
General 28 418,947,737 418,947,737
TOTAL (Enter Total of lines 20 thru 28) 29 8,565,801,806 8,565,801,806
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 $ 9,600,027
Account 143, Other accounts receivable: depreciation expense
billed to joint owners 281,680
Asset retirement obligation asset depreciation recorded
as a regulatory asset or liability 10,416,034
Deferral of Carbon depreciation recorded as a regulatory asset 3,372,072
Deferral of increased depreciation, due to depreciation study rates, 1,099,236
net of amortization, recorded as a regulatory asset
Transportation depreciation charged to operations and maintenance
expense and construction work in progress based on usage activity 14,214,593
Account 503, Steam from other sources: Blundell depletion 185,368
Account 503, Steam from other sources: Blundell depreciation 1,481,568
Total Other Accounts $ 40,650,578
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 $ 5,928,266
Other items include: 112,906,079
- Utah mine disposition
- Recovery from third parties for asset relocations and damaged property
- Insurance recoveries
- Adjustments of reserve related to electric plant sold and/or purchased
- Reclassifications from electric plant
Total Other Debit or Cr. Items $118,834,346
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
/ /2015/Q4
Line
No.
Description of Investment Date Acquired
(c)(b)(a)
Amount of Investment atBeginning of YearDate Of Maturity (d)
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
1973PACIFIC MINERALS, INC. 1
1 Common Stock 2
47,960,000 Paid-in Capital 3
135,509,939 Undistributed Subsidiary Earnings 4
183,469,940 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
6,652,381 Undistributed Subsidiary Earnings 21
12,690,381 SUBTOTAL 22
23
2011FOSSIL ROCK FUELS, LLC 24
31,322,429 Paid-in Capital 25
-13,673 Undistributed Subsidiary Earnings 26
31,308,756 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 227,471,078 85,538,430
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
/ /2015/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
148,768,673 13,258,734 4
196,728,674 13,258,734 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
7,010,024 445,700 21
13,048,024 445,700 22
23
24
31,538,428 25
-173,158 -159,485 26
31,365,270 -159,485 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 13,544,949 241,143,969
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 2015, Trapper Mining Inc., a subsidiary of PacifiCorp, paid a dividend of
$88,057 to PacifiCorp.
Schedule Page: 224 Line No.: 25 Column: g
In 2015, PacifiCorp contributed $216,000 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
2015/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
/ /2015/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.
198,515,639 Electric 192,305,988 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)
111,221,100 Electric 134,703,542 5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
94,012,733 Electric 84,947,332 7 Production Plant (Estimated)
490,752 Electric 653,625 8 Transmission Plant (Estimated)
12,319,645 Electric 12,772,256 9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant
(Estimated)
5,593,971 Electric 55,338 11 Assigned to - Other (provide details in footnote)
223,638,201 233,132,093 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
422,153,840 425,438,081 20 TOTAL Materials and Supplies (Per Balance Sheet)
Page 227FERC FORM NO. 1 (REV. 12-05)
Schedule Page: 227 Line No.: 11 Column: b
Mining materials and supplies $ 5,512,384
General plant materials and supplies 81,587
$ 5,593,971
Schedule Page: 227 Line No.: 11 Column: c
General plant materials and supplies $ 55,338
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
/ /2015/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.
2016
443,349.00 149,627.00Balance-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
34,135.00 Charges to Account 509 18
Other: 19
Prior Period Adjustments 20
Cost of Sales/Transfers: 21
22
23
24
25
26
27
Total 28
409,214.00 149,627.00Balance-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
/ /2015/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.
2017 2018
1 4,067,534.00 156,646.00 151,733.00 4,968,889.00
2
3
4
5 156,645.00 156,645.00
6
7
8
9
10
11
12
13
14
15
16
17
18 34,135.00
19
20
21
22
23
24
25
26
27
28
29 4,224,179.00 156,646.00 151,733.00 5,091,399.00
30
31
32
33
34
35
36 110,921.00 2,259.00 2,259.00 119,957.00
37 4,528.00 4,528.00
38
39 2,269.00 4,528.00
40 113,180.00 2,259.00 2,259.00 119,957.00
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-95) Page 229a
Schedule Page: 228 Line No.: 18 Column: b
Includes an adjustment to the balance at beginning of 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
2015/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 Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2015/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
Q1898 7,008 456 2
236Q1799 561.6 236 456 3
703Q1803 561.6 703 456 4
852Q1917 561.6 852 456 5
43,838Q1918 561.6 43,838 456 6
12,110Q1919 561.6 12,110 456 7
2,712Q1977 561.6 2,712 456 8
922Q1937a 561.6 922 456 9
1,865Q1937b 561.6 1,865 456 10
638Q1937c 561.6 638 456 11
355Q1948 561.6 355 456 12
89AREF 79456228 561.6 13
357AREF 79657068 561.6 14
2,582AREF 79857385 561.6 15
573AREF 79857389 561.6 16
1,312AREF 80149329 561.6 17
6,732AREF 80994031 561.6 18
1,575AREF 81045929 561.6 19
9,007AREF 81045934 561.6 20
Generation Studies 0.0 0 21
1,233GIQ0139 561.7 1,233 456 22
538GIQ0252 561.7 538 456 23
830GIQ0316 561.7 830 456 24
10,973GIQ0335 561.7 10,973 456 25
4,933GIQ0397 561.7 4,933 456 26
6,853GIQ0409 561.7 6,853 456 27
1,327GIQ0443 561.7 1,327 456 28
2,692GIQ0451 561.7 2,692 456 29
2,621GIQ0456 561.7 2,621 456 30
5,148GIQ0463 561.7 5,148 456 31
147GIQ0465 561.7 147 456 32
1,104GIQ0471 561.7 1,104 456 33
850GIQ0472 561.7 850 456 34
776GIQ0473 561.7 776 456 35
2,363GIQ0503 561.7 2,363 456 36
1,599GIQ0504 561.7 1,599 456 37
220GIQ0509 561.7 220 456 38
441GIQ0510 561.7 441 456 39
2,174GIQ0513 561.7 2,174 456 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
/ /2015/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
3,250AREF 81074553 561.6 2
1,846AREF 81235956 561.6 3
784AREF 81235960 561.6 4
1,337AREF 81269101 561.6 5
922AREF 81269111 561.6 6
1,199AREF 81287437 561.6 7
185AREF 81288775 561.6 8
694AREF 81288790 561.6 9
830AREF 81288866 561.6 10
1,017AREF 81315991 561.6 11
138AREF 81316049 561.6 12
1,708AREF 81316106 561.6 13
1,017AREF 81316143 561.6 14
1,201AREF 81369194 561.6 15
2,352AREF 81460501 561.6 16
284AREF 81550387 561.6 17
3,424 561.6 18
( 2,335)Customer Studies Accruals 561.6 19
20
Generation Studies 0.0 0 21
150GIQ0516 561.7 150 456 22
3,715GIQ0518 561.7 3,715 456 23
3,871GIQ0519 561.7 3,871 456 24
3,733GIQ0520 561.7 3,733 456 25
3,484GIQ0521 561.7 3,484 456 26
768GIQ0524 561.7 768 456 27
1,784GIQ0529 561.7 1,784 456 28
1,836GIQ0530 561.7 1,836 456 29
2,024GIQ0531 561.7 2,024 456 30
2,291GIQ0532 561.7 2,291 456 31
3,468GIQ0539 561.7 3,468 456 32
9,036GIQ0542 561.7 9,036 456 33
996GIQ0543 561.7 996 456 34
1,935GIQ0547 561.7 1,935 456 35
38GIQ0551 561.7 38 456 36
958GIQ0555 561.7 958 456 37
1,265GIQ0556 561.7 1,265 456 38
5,389GIQ0558 561.7 5,389 456 39
1,295GIQ0560 561.7 1,295 456 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
/ /2015/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 0.0 0 21
2,935GIQ0562 561.7 2,935 456 22
2,542GIQ0563 561.7 2,542 456 23
8,461GIQ0564 561.7 8,461 456 24
5,644GIQ0566 561.7 5,644 456 25
1,095GIQ0571 561.7 1,095 456 26
1,251GIQ0572 561.7 1,251 456 27
3,038GIQ0573 561.7 3,038 456 28
10,377GIQ0577 561.7 10,377 456 29
6,594GIQ0578 561.7 6,594 456 30
294GIQ0579 561.7 294 456 31
7,584GIQ0580 561.7 7,584 456 32
37GIQ0581 561.7 37 456 33
13,149GIQ0582 561.7 13,149 456 34
6,799GIQ0585 561.7 6,799 456 35
17,530GIQ0586 561.7 17,530 456 36
9,999GIQ0587 561.7 9,999 456 37
17,525GIQ0589 561.7 17,525 456 38
1,078GIQ0592 561.7 1,078 456 39
7,776GIQ0593 561.7 7,776 456 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
/ /2015/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 0.0 0 21
15,745GIQ0594 561.7 15,745 456 22
2,359GIQ0597 561.7 2,359 456 23
4,599GIQ0598 561.7 4,599 456 24
5,711GIQ0600 561.7 5,711 456 25
16,475GIQ0603 561.7 16,475 456 26
5,447GIQ0604 561.7 5,447 456 27
37GIQ0605 561.7 37 456 28
3,140GIQ0606 561.7 3,140 456 29
4,704GIQ0607 561.7 4,704 456 30
37GIQ0608 561.7 37 456 31
9,253GIQ0609 561.7 9,253 456 32
4,105GIQ0611 561.7 4,105 456 33
8,834GIQ0612 561.7 8,834 456 34
9,097GIQ0613 561.7 9,097 456 35
4,761GIQ0614 561.7 4,761 456 36
4,950GIQ0616 561.7 4,950 456 37
13,036GIQ0617 561.7 13,036 456 38
11,038GIQ0618 561.7 11,038 456 39
11,734GIQ0620 561.7 11,734 456 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
/ /2015/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 0.0 0 21
14,151GIQ0621 561.7 14,151 456 22
7,581GIQ0622 561.7 7,581 456 23
4,585GIQ0623 561.7 4,585 456 24
6,968GIQ0624 561.7 6,968 456 25
890GIQ0625 561.7 890 456 26
37GIQ0626 561.7 37 456 27
16,810GIQ0627 561.7 16,810 456 28
220GIQ0628 561.7 220 456 29
12,570GIQ0629 561.7 12,570 456 30
245GIQ0630 561.7 245 456 31
14,339GIQ0631 561.7 14,339 456 32
12,286GIQ0632 561.7 12,286 456 33
1,202GIQ0633 561.7 1,202 456 34
35,246GIQ0634 561.7 35,246 456 35
2,694GIQ0635 561.7 2,694 456 36
33,366GIQ0636 561.7 33,366 456 37
1,306GIQ0637 561.7 1,306 456 38
7,714GIQ0638 561.7 7,714 456 39
5,085GIQ0639 561.7 5,085 456 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
/ /2015/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 0.0 0 21
11,964GIQ0640 561.7 11,964 456 22
18,819GIQ0641 561.7 18,819 456 23
23,651GIQ0642 561.7 23,651 456 24
6,821GIQ0643 561.7 6,821 456 25
( 1)GIQ0644 561.7 ( 1) 456 26
6,450GIQ0645 561.7 6,450 456 27
2,154GIQ0646 561.7 2,154 456 28
23,974GIQ0647 561.7 23,974 456 29
12,841GIQ0648 561.7 12,841 456 30
10,100GIQ0649 561.7 10,100 456 31
19,652GIQ0650 561.7 19,652 456 32
4,966GIQ0651 561.7 4,966 456 33
4,965GIQ0652 561.7 4,965 456 34
4,298GIQ0653 561.7 4,298 456 35
8,301GIQ0654 561.7 8,301 456 36
12,163GIQ0655 561.7 12,163 456 37
16,220GIQ0656 561.7 16,220 456 38
4,379GIQ0657 561.7 4,379 456 39
2,173GIQ0658 561.7 2,173 456 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
/ /2015/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 0.0 0 21
15,328GIQ0659 561.7 15,328 456 22
11,605GIQ0660 561.7 11,605 456 23
15,593GIQ0661 561.7 15,593 456 24
17,576GIQ0662 561.7 17,576 456 25
4,500GIQ0663 561.7 4,500 456 26
4,677GIQ0664 561.7 4,677 456 27
2,985GIQ0665 561.7 2,985 456 28
12,124GIQ0666 561.7 12,124 456 29
4,843GIQ0667 561.7 4,843 456 30
3,378GIQ0668 561.7 3,378 456 31
9,131GIQ0669 561.7 9,131 456 32
13,060GIQ0670 561.7 13,060 456 33
13,760GIQ0671 561.7 13,760 456 34
14,736GIQ0672 561.7 14,736 456 35
420GIQ0674 561.7 420 456 36
828GIQ0675 561.7 828 456 37
989GIQ0676 561.7 989 456 38
1,611GIQ0677 561.7 1,611 456 39
9,724GIQ0678 561.7 9,724 456 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
/ /2015/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 0.0 0 21
6,603GIQ0679 561.7 6,603 456 22
975GIQ0680 561.7 975 456 23
737GIQ0681 561.7 737 456 24
13,215GIQ0682 561.7 13,215 456 25
165GIQ0683 561.7 165 456 26
15,073GIQ0684 561.7 15,073 456 27
110GIQ0685 561.7 110 456 28
5,599GIQ0686 561.7 5,599 456 29
3,765GIQ0687 561.7 3,765 456 30
1,066GIQ0688 561.7 1,066 456 31
927GIQ0689 561.7 927 456 32
854GIQ0690 561.7 854 456 33
664GIQ0691 561.7 664 456 34
1,029GIQ0692 561.7 1,029 456 35
692GIQ0693 561.7 692 456 36
692GIQ0694 561.7 692 456 37
692GIQ0695 561.7 692 456 38
695GIQ0696 561.7 695 456 39
1,248GIQ0697 561.7 1,248 456 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
/ /2015/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 0.0 0 21
1,156GIQ0698 561.7 1,156 456 22
889GIQ0699 561.7 889 456 23
711GIQ0700 561.7 711 456 24
1,183GIQ0701 561.7 1,183 456 25
9,329GIQ0702 561.7 9,329 456 26
10,219GIQ0703 561.7 10,219 456 27
6,959GIQ0704 561.7 6,959 456 28
1,252GIQ0705 561.7 1,252 456 29
1,201GIQ0706 561.7 1,201 456 30
833GIQ0707 561.7 833 456 31
851GIQ0708 561.7 851 456 32
1,303GIQ0709 561.7 1,303 456 33
2,672GIQ0710 561.7 2,672 456 34
2,366GIQ0711 561.7 2,366 456 35
1,279GIQ0712 561.7 1,279 456 36
1,128GIQ0713 561.7 1,128 456 37
2,530GIQ0714 561.7 2,530 456 38
2,424GIQ0715 561.7 2,424 456 39
2,663GIQ0716 561.7 2,663 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.8
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2015/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 0.0 0 21
484GIQ0717 561.7 484 456 22
941GIQ0718 561.7 941 456 23
1,244GIQ0719 561.7 1,244 456 24
1,227GIQ0720 561.7 1,227 456 25
1,189GIQ0721 561.7 1,189 456 26
797GIQ0722 561.7 797 456 27
490GIQ0723 561.7 490 456 28
2,895Pre-Application Studies - East 561.7 2,895 456 29
10,003Pre-Application Studies - West 561.7 10,003 456 30
6,789Q0583 561.7 0 31
( 15,190)Customer Studies Accruals 561.7 0 32
0 0 33
0 0 34
0 0 35
0 0 36
0 0 37
0 0 38
0 0 39
0 0 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.9
Schedule Page: 231 Line No.: 2 Column: d
Reimbursements received in 2015 for costs incurred during 2014.
Schedule Page: 231.1 Line No.: 18 Column: a
Other Transmission Project Queue #0113
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
/ /
2015/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)
1,166,810 856,824 2,768,936908,431 2,458,950DSM Balancing Account - CA 1
744,888 908,075 4,039,527908,431 4,202,714DSM Balancing Account - ID 2
18,414,133 14,269,911 67,228,493908 63,084,271DSM Balancing Account - UT 3
1,078,059 1,943,274 10,509,237908 11,374,452DSM Balancing Account - WA 4
323,788 323,788DSM Balancing Account - WY 5
7,094,731 6,395,828 3,888,191555 3,189,288Deferred Excess Net Power Costs - CA 6
25,605,859 22,396,531 20,202,740555 16,993,412Deferred Excess Net Power Costs - ID 7
63,084,452 40,428,344 41,755,669555 19,099,561Deferred Excess Net Power Costs - UT 8
26,163,378 16,420,025 19,330,406555 9,587,053Deferred Excess Net Power Costs - WY 9
19,001,916 11,354,395 7,776,194456 128,673Deferred Excess RECs in Rates - UT 10
2,207,437 613,882 1,785,479456 191,924Deferred Excess RECs/SO2 in Rates - WY 11
4,917,237 3,169,877 1,747,360456,419Deferred Excess RECs in Rates - WA 12
254,760 254,760410.1Income Tax Reg. Asset - WA Flow Through 13
446,017,017 436,870,019 11,149,689282,283 2,002,691Deferred Income Tax Electric 14
82,313 78,736 3,907282,283 330Solar ITC Basis Adjustment Regulatory Asset 15
2,682,984 1,788,655 894,329410.1Tax Adj on Postretirement Benefits - OR (5) 16
1 1410.1Tax Adj on Postretirement Benefits - WY (4) 17
22,041 4,408 17,633Tax Revenue Requirement Adjustment - WY (4) 18
473,546,816 473,328,654 40,501,178 40,283,016Pension 19
16,758,010 25,768,508 7,954,629 16,965,127Other Postretirement 20
8,361,445 3,417,221 4,944,224Postemployment Costs 21
156,362 130,146 26,216407.3Powerdale Decommissioning - ID (10) 22
2,106,371 2,393,193 319,092403 605,914Carbon Plant Regulatory Asset - ID (6) 23
14,599,216 17,223,206 2,296,427403 4,920,417Carbon Plant Regulatory Asset - UT (6) 24
5,329,679 5,790,939 1,127,903403 1,589,163Carbon Plant Regulatory Asset - WY (6) 25
1,589,451 3,258,921 1,669,470Depreciation Study Deferral - ID 26
2,112,712 1,984,669 128,043403Depreciation Study Deferral - UT (17) 27
7,296,150 6,853,959 442,191403Depreciation Study Deferral - WY (17) 28
1,407,280 1,352,992 54,288930.2Generating Plant Liquidated Damages - WY 29
665,000 630,000 35,000930.2Generating Plant Liquidated Damages - UT 30
3,000,000 3,000,000Chehalis Generating Facility Deferral - WA (6) 31
29,170,485 26,170,339 4,483,442404 1,483,296Klamath Hydroelectric Relicensing Costs - UT (10) 32
2,424,799 1,486,166 938,633557Cholla Plant Transaction Costs (26) 33
317,507 265,319 52,188456Washington Colstrip Unit No. 3 (22) 34
51,021 51,021407Naughton Unit No. 3 Environmental Costs - CA (2) 35
239,494 239,494407Naughton Unit No. 3 Environmental Costs - ID (2) 36
40,073,889 44,491,898 2,963,445253,925 7,381,454Environmental Costs (10) 37
51,344,265 65,097,432 13,753,167Asset Retirement Obligations Regulatory Difference 38
123,014,796 110,071,947 12,942,849242Unamortized Contract Values 39
85,415,690 132,542,310 47,126,620Unrealized Loss on Derivative Contracts 40
5,110,660 796,625 10,753,805555 6,439,770Greenhouse Gas Allowance Compliance Costs - CA 41
5,021,117 5,336,104 4,685,939 5,000,926Solar Feed-In Tariff Deferral - OR (1) 42
21,683 21,683Solar Incentive Program - UT 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
/ /
2015/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)
49,313 49,313Renewable Portfolio Standards Compliance - CA 1
1,069,569 1,442,958 373,389Deferred Intervenor Funding Grants - OR 2
40,347 40,406 59Deferred Intervenor Funding Grants - CA 3
39,031 26,865 16,431928 4,265Deferred Intervenor Funding Grants - ID (2) 4
3,091 3,091Alternative Rate for Energy (CARE) - CA 5
254,022 303,336 1,446,390501 1,495,704Deferred Overburden Cost - ID 6
677,346 842,293 3,873,848501 4,038,795Deferred Overburden Cost - WY 7
316,957 316,957440,442BPA Balancing Account - WA 8
1,468,531 1,939,461 470,930BPA Balancing Account - OR 9
142,389 247,471 105,082Asset Sales Balancing Account - OR 10
474,686 474,686Property Insurance Reserve - OR 11
470,868 122,561 349,810924 1,503Property Insurance Reserve - WY 12
486,204 73,531 418,483 5,810Misc. Regulatory Assets/Liabilities - OR 13
86,357,715 186,332,549 17,173,630 117,148,464Utah Mine Disposition 14
261,901 233,459 28,442407.3Preferred Stock Redemption Loss - WY (10) 15
759,970 677,439 82,531407.3Preferred Stock Redemption Loss - UT (10) 16
108,762 9,988407.3 118,750Preferred Stock Redemption Loss - WA (10) 17
162,586 366,726 529,312Merwin Fish Collector Project - WA (1) 18
1,729 1,729Mobile Home Park Conversion - CA 19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
1,589,995,081TOTAL :44 1,679,069,828 315,623,265 404,698,012
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232.1
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.
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, including Monsanto and Agrium net power cost components.
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 one year for deferred excess net power
cost mechanisms being amortized.
Schedule Page: 232 Line No.: 10 Column: a
Weighted average remaining life is approximately one year for deferred excess renewable
energy credits in rates being amortized.
Schedule Page: 232 Line No.: 11 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.: 12 Column: a
Weighted average remaining life is approximately one year for deferred excess renewable
energy credits 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 and expense 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.: 18 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 232 Line No.: 19 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.: 19 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.: 20 Column: a
Weighted average remaining life of portion being amortized 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.: 20 Column: d
Account 228.3, Accumulated provision for pensions and benefits
Account 426.5, Other deductions
Schedule Page: 232 Line No.: 21 Column: a
Weighted average remaining life is five years.
Schedule Page: 232 Line No.: 21 Column: d
Other postemployment costs are associated with labor and generally charged to operations
and maintenance expense and construction work in progress. Also credited to Account 228.3,
Accumulated provision for pensions and benefits.
Schedule Page: 232 Line No.: 29 Column: a
Weighted average remaining life is 27 years.
Schedule Page: 232 Line No.: 30 Column: a
Weighted average remaining life is 18 years.
Schedule Page: 232 Line No.: 31 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 232 Line No.: 39 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 Line No.: 40 Column: a
Weighted average remaining life is five years.
Schedule Page: 232 Line No.: 42 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.: 10 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.: 13 Column: d
Account 254, Other regulatory liabilities
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: a
Weighted average remaining life of portion being amortized is approximately four years.
Refer to Note 5 of Notes to Financial Statements in this Form No. 1.
Schedule Page: 232.1 Line No.: 14 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Account 501, Fuel
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
2015/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
/ /2015/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.
423,590 286,209 137,381557Joseph Settlement (21) 1
2
323,850 278,130 45,720557Lacomb Irrigation (24) 3
4
1,035,440 994,160 41,280557Bogus Creek (41) 5
6
Mead Phoenix Availability and 7
12,245,720 11,867,960 377,760565Transmission Charge (50) 8
9
78,656 63,183 15,473557TGS Buyout (23) 10
11
1,054,377 1,412,872 143,308 501,803 142Point-to-Point Transmission 12
13
3,705,711 3,534,017 171,694557Hermiston Swap (40) 14
15
Oregon Prepaid REC Purchases 16
98,273 11,950 138,949 52,626 555for RPS Compliance (1) 17
18
26,832 26,832501Deferred Longwall Costs 19
20
Deferred Coal Costs - Wyodak 21
2,681,454 2,346,272 335,182151Settlement (22) 22
23
Deferred Coal Costs - Naughton 24
2,752,307 1,376,154 1,376,153151Settlement (7) 25
26
Deferred Coal Costs - Jim 27
2,916,673 2,916,673151Bridger Plant 28
29
Deferred Colstrip Plant 30
325,000 25,000 300,000501Costs (5) 31
32
LT Lease Commissions 33
333,059 233,544 99,515931Prepaids (10) 34
35
LT Lease Commission - One Utah 36
66,739 66,739Center 37
38
26,426,083 5,147,854 27,641,784 6,363,555 107Lake Side Maintenance Prepaid 39
40
5,281,592 10,805,583 5,523,991Lake Side 2 Maintenance Prepaid 41
42
21,838,914 2,856,589 22,144,147 3,161,822 107Chehalis Maintenance Prepaid 43
44
13,996,108 20,193,323 6,197,215Currant Creek Maint. Prepaid 45
46
FERC FORM NO. 1 (ED. 12-94) Page 233
49 TOTAL
47 Misc. Work in Progress
48 Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
110,913,409 70,244,403
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
/ /2015/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.
492,642 331,194 161,448454Lease Incentives (10) 1
2
2,141,252 1,396,981 744,271427, 431Credit Agreement Costs (5) 3
4
88,026 142,490 122,894 177,358 427PCRB LOC/SBBPA Costs 5
6
245,844 259,714 102,679 116,549 427PCRB Mode Conversion Costs 7
8
611,783 549,568 62,215427'94 Series Restruct. Costs (16) 9
10
186,399 186,399Deferred S-3 Shelf Regis. Costs 11
12
LT Prepaid IBEW 57 Pension 13
4,787,907 850,198 4,083,647 145,938Contribution 14
15
4,717,195 3,902,426 984,796 170,027 565BPA LT Transmission Prepaid 16
17
306,510 306,510Emission Reduction Credits 18
19
131,614 131,614174Unamortized Contract Values 20
21
Sales of Electric Utility 22
1,845,747 711,003 2,003,907 869,163Facilities & Properties 23
24
108,381 132,199 240,580 921, 923IT Licenses and Maint. Prepaid 25
26
1,250 1,250181Other Deferred Charges 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)
110,913,409 70,244,403
Schedule Page: 233.1 Line No.: 5 Column: a
Weighted average life is two years.
Schedule Page: 233.1 Line No.: 7 Column: a
Weighted average life is nine 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.
Schedule Page: 233.1 Line No.: 23 Column: d
Account 102, Electric plant purchased or sold
Account 114, Electric plant acquisition adjustments
Account 539, Miscellaneous hydraulic power generation expenses
Account 592, Maintenance of station equipment
Account 593, Maintenance of overhead lines
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
/ /2015/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
189,756,726 182,825,392Employee benefits 2
93,561,265 79,219,960Derivative contracts and unamortized contract values 3
68,772,466 68,037,070State carryforwards 4
56,218,611 51,188,383Loss contingencies 5
80,689,134 47,023,073Asset retirement obligations 6
117,213,002 116,675,654Other 7
606,211,204 544,969,532TOTAL 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
606,211,204 544,969,532TOTAL (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 $ 28,575,535 $ 29,935,861
Other 88,100,119 87,277,141
$116,675,654 $117,213,002
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
/ /2015/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
/ /2015/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, 2015, 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
2015/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
/ /2015/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, 2015.
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
2015/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
/ /2015/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
/ /2015/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
46,946,000 8.294% Series due October 1, 2015 4
18,750,000 8.635% Series due October 1, 2016 5
19,609,000 8.470% Series due October 1, 2017 6
3,067,221 500,000,000 5.65% Series due July 15, 2018 7
905,000 8 D
2,515,793 350,000,000 5.50% Series due January 15, 2019 9
2,292,500 10 D
3,007,139 400,000,000 3.85% Series due June 15, 2021 11
744,000 12 D
2,424,350 350,000,000 2.95% Series due February 1, 2022 13
308,000 14 D
254,129 100,000,000 2.95% Series due February 1, 2022 15
-81,000 16 P
1,859,352 300,000,000 2.95% Series due June 1, 2023 17
900,000 18 D
3,345,164 425,000,000 3.60% Series due April 1, 2024 19
255,000 20 D
2,121,421 250,000,000 3.35% Series due July 1, 2025 21
320,000 22 D
2,874,150 300,000,000 7.70% Series due November 15, 2031 23
864,000 24 D
1,892,365 200,000,000 5.90% Series due August 15, 2034 25
722,000 26 D
2,912,021 300,000,000 5.25% Series due June 15, 2035 27
1,080,000 28 D
2,907,881 350,000,000 6.10% Series due August 1, 2036 29
1,141,000 30 D
589,216 600,000,000 5.75% Series due April 1, 2037 31
24,000 32 D
FERC FORM NO. 1 (ED. 12-96)Page 256
33 TOTAL 7,354,645,000 78,372,455
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
/ /2015/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
259,89210/01/201504/15/199210/01/201504/15/1992 4
1,686,000 246,29210/01/201604/15/199210/01/201604/15/1992 5
3,313,000 373,73910/01/201704/15/199210/01/201704/15/1992 6
500,000,000 28,250,00007/15/201807/17/200807/15/201807/17/2008 7
8
350,000,000 19,250,00001/15/201901/08/200901/15/201901/08/2009 9
10
400,000,000 15,400,00006/15/202105/12/201106/15/202105/12/2011 11
12
350,000,000 10,325,00002/01/202201/06/201202/01/202201/06/2012 13
14
100,000,000 2,950,00002/01/202203/06/201202/01/202203/06/2012 15
16
300,000,000 8,850,00006/01/202306/06/201306/01/202306/06/2013 17
18
425,000,000 15,300,00004/01/202403/13/201404/01/202403/13/2014 19
20
250,000,000 4,466,66707/01/202506/19/201507/01/202506/19/2015 21
22
300,000,000 23,100,00011/15/203111/21/200111/15/203111/21/2001 23
24
200,000,000 11,800,00008/15/203408/24/200408/15/203408/24/2004 25
26
300,000,000 15,750,00006/15/203506/13/200506/15/203506/13/2005 27
28
350,000,000 21,350,00008/01/203608/10/200608/01/203608/10/2006 29
30
600,000,000 34,500,00004/01/203703/14/200704/01/203703/14/2007 31
32
FERC FORM NO. 1 (ED. 12-96)Page 257
33 7,159,339,000 356,471,778
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
/ /2015/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.
5,127,281 600,000,000 6.25% Series due October 15, 2037 1
750,000 2 D
2,290,333 300,000,000 6.35% Series due July 15, 2038 3
1,671,000 4 D
6,134,687 650,000,000 6.00% Series due January 15, 2039 5
6,175,000 6 D
2,737,911 300,000,000 4.10% Series due February 1, 2042 7
987,000 8 D
115,202 15,000,000 8.53% Series C Medium-Term Notes due Dec. 16, 2021 9
38,400 5,000,000 8.375% Series C Medium-Term Notes due Dec. 31, 2021 10
33,243 5,000,000 8.26% Series C Medium-Term Notes due Jan. 7, 2022 11
30,594 4,000,000 8.27% Series C Medium-Term Notes due Jan. 10, 2022 12
131,471 15,000,000 8.05% Series E Medium-Term Notes due Sept. 1, 2022 13
70,118 8,000,000 8.07% Series E Medium-Term Notes due Sept. 9, 2022 14
438,238 50,000,000 8.12% Series E Medium-Term Notes due Sept. 9, 2022 15
105,177 12,000,000 8.11% Series E Medium-Term Notes due Sept. 9, 2022 16
87,648 10,000,000 8.05% Series E Medium-Term Notes due Sept. 14, 2022 17
208,198 26,000,000 8.08% Series E Medium-Term Notes due Oct. 14, 2022 18
200,190 25,000,000 8.08% Series E Medium-Term Notes due Oct. 14, 2022 19
37,914 5,000,000 8.23% Series E Medium-Term Notes due Jan. 20, 2023 20
30,331 4,000,000 8.23% Series E Medium-Term Notes due Jan. 20, 2023 21
-81,560 22 P
246,981 27,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 23
100,622 11,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 24
137,211 15,000,000 7.23% Series F Medium-Term Notes due Aug. 16, 2023 25
274,423 30,000,000 7.24% Series F Medium-Term Notes due Aug. 16, 2023 26
38,250 5,000,000 6.75% Series F Medium-Term Notes due Sept. 14, 2023 27
15,300 2,000,000 6.75% Series F Medium-Term Notes due Sept. 14, 2023 28
15,300 2,000,000 6.72% Series F Medium-Term Notes due Sept. 14, 2023 29
152,326 20,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 30
121,861 16,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 31
91,396 12,000,000 6.75% Series F Medium-Term Notes due Oct. 26, 2023 32
FERC FORM NO. 1 (ED. 12-96)Page 256.1
33 TOTAL 7,354,645,000 78,372,455
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
/ /2015/Q4
Line
No.Nominal Dateof Issue Date ofMaturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding withoutreduction for amounts held byrespondent)
Interest for YearAmount(d) (e) (f) (g) (h) (i)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year,
describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
600,000,000 37,500,00010/15/203710/03/200710/15/203710/03/2007 1
2
300,000,000 19,050,00007/15/203807/17/200807/15/203807/17/2008 3
4
650,000,000 39,000,00001/15/203901/08/200901/15/203901/08/2009 5
6
300,000,000 12,300,00002/01/204201/06/201202/01/204201/06/2012 7
8
15,000,000 1,279,50012/16/202112/16/199112/16/202112/16/1991 9
5,000,000 418,75012/31/202112/31/199112/31/202112/31/1991 10
5,000,000 413,00001/07/202201/08/199201/07/202201/08/1992 11
4,000,000 330,80001/10/202201/09/199201/10/202201/09/1992 12
15,000,000 1,207,50009/01/202209/18/199209/01/202209/18/1992 13
8,000,000 645,60009/09/202209/09/199209/09/202209/09/1992 14
50,000,000 4,060,00009/09/202209/11/199209/09/202209/11/1992 15
12,000,000 973,20009/09/202209/11/199209/09/202209/11/1992 16
10,000,000 805,00009/14/202209/14/199209/14/202209/14/1992 17
26,000,000 2,100,80010/14/202210/15/199210/14/202210/15/1992 18
25,000,000 2,020,00010/14/202210/15/199210/14/202210/15/1992 19
5,000,000 411,50001/20/202301/20/199301/20/202301/20/1993 20
4,000,000 329,20001/20/202301/29/199301/20/202301/29/1993 21
22
27,000,000 1,960,20007/21/202307/22/199307/21/202307/22/1993 23
11,000,000 798,60007/21/202307/22/199307/21/202307/22/1993 24
15,000,000 1,084,50008/16/202308/16/199308/16/202308/16/1993 25
30,000,000 2,172,00008/16/202308/16/199308/16/202308/16/1993 26
5,000,000 337,50009/14/202309/14/199309/14/202309/14/1993 27
2,000,000 135,00009/14/202309/14/199309/14/202309/14/1993 28
2,000,000 134,40009/14/202309/14/199309/14/202309/14/1993 29
20,000,000 1,350,00010/26/202310/26/199310/26/202310/26/1993 30
16,000,000 1,080,00010/26/202310/26/199310/26/202310/26/1993 31
12,000,000 810,00010/26/202310/26/199310/26/202310/26/1993 32
FERC FORM NO. 1 (ED. 12-96)Page 257.1
33 7,159,339,000 356,471,778
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
/ /2015/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.
904,467 100,000,000 6.71% Series G Medium-Term Notes due Jan. 15, 2026 1
68,661,215 6,784,305,000Subtotal - First Mortgage Bonds 2
3
Pollution Control Obligations - Secured by Pledged First Mortgage Bonds: 4
5
510,479 21,260,000 Poll Ctrl Rev Refunding Bonds, Sweetwater County, WY, Series 1994 6
209,777 8,190,000 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1994 7
3,274,246 121,940,000 Poll Ctrl Rev Refunding Bonds, Emery County, UT, Series 1994 8
206,519 9,365,000 Poll Ctrl Rev Refunding Bonds, Carbon County, UT, Series 1994 9
422,858 15,060,000 Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1994 10
771,836 45,000,000 Poll Ctrl Rev Refunding Bonds, Lincoln Cnty, WY, Series 1991 11
304,824 8,500,000 Poll Ctrl Revenue Bonds, City of Forsyth, MT, Series 1986 12
132,043 5,300,000 Environ. Imprvmnt Rev Bonds, Converse County, WY, Series 1995 13
404,262 22,000,000 Environ. Imprvmnt Rev Bonds, Lincoln County, WY, Series 1995 14
6,236,844 256,615,000Subtotal Pollution Control Obligations - Secured by Pledged First Mortgage Bonds 15
16
17
Pollution Control Obligations - Unsecured: 18
19
872,505 45,000,000 Poll Ctrl Rev Refndng Bonds, Emery County, UT, Series 1991 20
380,198 45,000,000 Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Series 1988 21
422,443 50,000,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Series 1988A 22
351,905 41,200,000 Poll Ctrl Rev Refndng Bonds, City of Gillette, WY, Ser. 1988 23
660,750 70,000,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1990A 24
167,524 9,335,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992A 25
242,163 22,485,000 Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 26
151,908 6,305,000 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992B 27
225,000 24,400,000 Environ. Imprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 28
3,474,396 313,725,000Subtotal - Pollution Control Obligations - Unsecured 29
30
31
78,372,455 7,354,645,000TOTAL ACCOUNT 221 32
FERC FORM NO. 1 (ED. 12-96)Page 256.2
33 TOTAL 7,354,645,000 78,372,455
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
/ /2015/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.
100,000,000 6,710,00001/15/202601/23/199601/15/202601/23/1996 1
6,703,999,000 351,588,640 2
3
4
5
21,260,000 248,04211/01/202411/17/199411/01/202411/17/1994 6
8,190,000 68,01411/01/202411/17/199411/01/202411/17/1994 7
121,940,000 1,289,58911/01/202411/17/199411/01/202411/17/1994 8
9,365,000 152,86602/18/201611/17/199411/01/202411/17/1994 9
15,060,000 141,62311/01/202411/17/199411/01/202411/17/1994 10
45,000,000 499,43301/01/201601/17/199101/01/201601/17/1991 11
8,500,000 53,16212/01/201612/01/198612/01/201612/01/1986 12
5,300,000 31,17411/01/202511/17/199511/01/202511/17/1995 13
22,000,000 138,01111/01/202511/17/199511/01/202511/17/1995 14
256,615,000 2,621,914 15
16
17
18
19
383,70207/01/201505/23/199107/01/201505/23/1991 20
45,000,000 490,89201/01/201801/01/198801/01/201801/01/1988 21
50,000,000 294,00201/01/201701/01/198801/01/201701/01/1988 22
41,200,000 233,57601/01/201801/01/198801/01/201801/01/1988 23
317,48307/01/201507/25/199007/01/201507/25/1990 24
9,335,000 80,86612/01/202009/29/199212/01/202009/29/1992 25
22,485,000 189,70912/01/202009/29/199212/01/202009/29/1992 26
6,305,000 55,78612/01/202009/29/199212/01/202009/29/1992 27
24,400,000 215,20811/01/202512/14/199511/01/202512/14/1995 28
198,725,000 2,261,224 29
30
31
7,159,339,000 356,471,778 32
FERC FORM NO. 1 (ED. 12-96)Page 257.2
33 7,159,339,000 356,471,778
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
/ /2015/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.
1
Reacquired Bonds: (Account 222) 2
3
Advances from Associated Companies: (Account 223) 4
5
Other Long-Term Debt: (Account 224) 6
7
8
Long-Term Debt Authorized but Unissued 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 256.3
33 TOTAL 7,354,645,000 78,372,455
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
/ /2015/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
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
FERC FORM NO. 1 (ED. 12-96)Page 257.3
33 7,159,339,000 356,471,778
Schedule Page: 256 Line No.: 21 Column: a
In June 2015, PacifiCorp issued $250 million of its 3.35% First Mortgage Bonds due July
2025. State commission authorizations for this issuance were as follows:
Oregon Public Utility Commission ("OPUC") - Docket No. UF-4288, Order No. 14-268,
dated July 22, 2014.
Idaho Public Utilities Commission ("IPUC") - Case No. PAC-E-14-05, Order No. 33083,
dated July 29, 2014.
Schedule Page: 256.2 Line No.: 9 Column: e
In February 2016, PacifiCorp redeemed the Pollution Control Revenue Refunding Bonds,
Carbon County, UT, Series 1994 and transferred the associated unamortized debt expense to
Account 189, Unamortized loss on reacquired debt.
Schedule Page: 256.2 Line No.: 32 Column: h
Refer to Item 6 in Important Changes During the Year and Note 7 in Notes to Financial
Statements in this Form No. 1 for a discussion of PacifiCorp's long-term debt.
Schedule Page: 256.2 Line No.: 32 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.: 9 Column: a
As of January 2016, PacifiCorp had an effective shelf registration statement filed with
the Unites States Securities and Exchange Commission on Form S-3 to issue up to $1.325
billion of future first mortgage bonds through January 2019.
For authorization for the issuance of long-term debt ($1.575 billion authorized; $1.325
billion available as of December 31, 2015), refer to Item 6 in Important Changes During
the Year 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, 2015) 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,
2015) 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
2015/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
/ /2015/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.
695,335,538Net Income for the Year (Page 117) 1
2
3
Taxable Income Not Reported on Books 4
5
6
7
141,770,817Other 8
Deductions Recorded on Books Not Deducted for Return 9
10
11
12
1,393,392,991Other 13
Income Recorded on Books Not Included in Return 14
15
16
17
37,044,036Other 18
Deductions on Return Not Charged Against Book Income 19
20
21
22
23
24
1,644,070,546Other 25
-23,936,240State Tax Deductions 26
525,448,524Federal Tax Net Income 27
Show Computation of Tax: 28
29
183,906,983Federal Income Tax at 35.00% 30
-2,001,391Provision to Return Adjustment 31
2,595,330Tax Reserve Changes 32
-59,173,010Renewable Energy Production Tax Credits 33
-5,937Other Federal Tax Credits 34
35
125,321,975Federal 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 108,326,668
Deferred Revenue - Lease Incentives 627,367
Federal Tax Fixed Asset Gain/Loss 9,602,156
Regulatory Asset - BPA Balancing Account - WA 316,957
Regulatory Asset - REC Sales Deferral - UT - Current 7,199,293
Regulatory Asset - REC Sales Deferral - UT - Noncurrent 448,228
Regulatory Asset - REC Sales Deferral - WA - Current 1,843,964
Regulatory Asset - REC Sales Deferral - WY - Current 2,198,465
Regulatory Asset - WA Colstrip #3 52,188
Reimbursements 1,386,597
Regulatory Liability - BPA Balancing Account - ID 1,328,270
Regulatory Liability - BPA Balancing Account - WA 54,637
Regulatory Liability - Deferred Excess NPC - OR - Noncurrent 5,772,211
Regulatory Liability - Deferred Excess NPC - WA - Noncurrent 132,174
Regulatory Liability - Depreciation Decrease - OR 999,943
Regulatory Liability - GHG Allowance Revenues - CA - Noncurrent 718,381
Regulatory Liability - OR 2012 GRC Giveback - Noncurrent 418,227
Regulatory Liability - Sale of REC - OR - Noncurrent 33,376
Regulatory Liability - WA Low Energy Program 311,715
Total $ 141,770,817
Schedule Page: 261 Line No.: 13 Column: a
Particulars (Details) Amounts
Fed/State Tax Expense 320,634,528
Fed/State Tax Expense - Interest 881,589
50% Meals and Entertainment 766,181
Accrued Royalties 1,685,119
Accrued Severance 103,470
Avoided Costs 23,148,802
Bear River Settlement Agreement 176,138
Book Depreciation 768,720,000
Book Depreciation Allocated to Medicare and M&E 76,634
Coal Pile Inventory Adjustment 6,766,483
Contra Receivable from Joint Owners 5,049,536
CWIP Reserve 422,245
Deferred Compensation - Mark to Market Gain/Loss - Income Statement 728,412
Deferred Coal Costs - Naughton Contract Settlement 1,376,154
Deferred Revenue - Other 95,833
Energy West Accrued Liabilities 645,912
Environmental Liability - Non-Regulated 5,577
Environmental Liability - Regulated 1,508,186
Fuel Cost Adjustment 14,014
Hermiston Swap 171,693
Hydro Relicensing Obligation 1,343,975
Insurance Reserve - Current 22,855,900
Inventory Reserve 952,973
Joseph Settlement 137,381
Lewis River Settlement Agreement 53,365
Lobbying Expenses 2,580,424
LT Incentive Plan - Noncurrent 1,549,445
LT Incentive Plan - Mark to Market Gain/Loss - Income Statement 78,855
Medicare Subsidy 8,060,641
MEHC Insurance Services - Receivable 29,933
Mine Rescue Training Credit Addback 5,937
Miscellaneous Current and Accrued Liability 887,932
Penalties 1,380,071
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Prepaid Aircraft Maintenance 10,622
Prepaid IBEW 57 Pension Contribution - Current 4,200,000
Prepaid Taxes - Property Taxes 231,066
Regulatory Asset - Asset Sales Balancing Account 142,389
Regulatory Asset - Chehalis Generating Facility Deferral - WA 3,000,000
Regulatory Asset - Cholla Plant Transaction Costs 1,122,425
Regulatory Asset - Deferred Excess NPC - CA - Current 3,404,629
Regulatory Asset - Deferred Excess NPC - ID - Current 19,801,431
Regulatory Asset - Deferred Excess NPC - UT - Current 42,492,609
Regulatory Asset - Deferred Excess NPC - WY - Current 21,672,534
Regulatory Asset - Deferred Intervenor Funding Grants - ID 12,165
Regulatory Asset - DSM - Current 21,403,890
Regulatory Asset - DSM - Noncurrent 1,211,413
Regulatory Asset - Depreciation Increase - UT 128,043
Regulatory Asset - Depreciation Increase - WY 442,191
Regulatory Asset - Environmental Costs - WA 206,865
Regulatory Asset - FAS 158 Pension Liability 41,324,556
Regulatory Asset - GHG Allowances - CA - Current 5,110,660
Regulatory Asset - Goodnoe Hills Settlement - WY 21,250
Regulatory Asset - Klamath Hydroelectric Relicensing Costs - UT 3,000,146
Regulatory Asset - Lake Side Settlement - WY 27,331
Regulatory Asset - Liquidation Damages - Naughton Unit #2 - WY 5,708
Regulatory Asset - Naughton Unit #3 Costs - CA 51,021
Regulatory Asset - Naughton Unit #3 Costs - ID 239,495
Regulatory Asset - OR Sch 203 Black Cap Solar 11,572
Regulatory Asset - Pension MMT - UT 283,176
Regulatory Asset - Post Employment Costs 4,944,224
Regulatory Asset - Post Merger Loss - Reacquired Debt 832,212
Regulatory Asset - Postretirement MMT - CA 17,488
Regulatory Asset - Postretirement MMT - OR 193,035
Regulatory Asset - Postretirement MMT - UT 278,648
Regulatory Asset - Powerdale Decommissioning - ID 26,216
Regulatory Asset - Preferred Stock Redemption Loss - WY 28,442
Regulatory Asset - Preferred Stock Redemption Loss - UT 82,531
Regulatory Asset - Solar Feed-in Tariff Deferral - OR - Current 4,122,390
Regulatory Asset - Tax Revenue Requirement Adj - WY 17,633
Regulatory Asset - UT Liquidation Damages 35,000
Regulatory Asset - Postretirement Settlement Loss 1,110,082
Regulatory Liability - 50% Bonus Tax Depreciation - WY 968,851
Regulatory Liability - ARO/Reg Diff - Trojan - WA Portion 8,336
Regulatory Liability - Blue Sky - CA 46,963
Regulatory Liability - Blue Sky - ID 33,755
Regulatory Liability - Blue Sky - OR 173,491
Regulatory Liability - Blue Sky - UT 1,426,381
Regulatory Liability - Blue Sky - WY 132,802
Regulatory Liability - Injuries & Damages Reserve - OR 3,134,945
Regulatory Liability - Property Insurance Reserve - ID 112,950
Regulatory Liability - Property Insurance Reserve - UT 814,186
Regulatory Liability - Property Insurance Reserve - WY 348,307
Regulatory Liability - Solar Feed-in Tariff Deferral - CA - Noncurrent 1,530,061
Regulatory Liability - Solar Incentive Program - UT - Noncurrent 13,835,120
Sales and Use Tax Audit Exposure 250,977
TGS Buyout 15,474
Trapper Mine Contract Obligation 5,723,944
USA Power Litigation 2,480,165
Utah Mine Disposition 7,931,642
Intercompany adjustment 286,215
Total $ 1,393,392,991
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 261 Line No.: 18 Column: a
Particulars (Details) Amounts
Book Fixed Asset Gain/Loss (10,995,672)
Dividend Received Deduction - Deferred Compensation (168,574)
Foote Creek Contract (17,100)
MCI F.O.G. Wire Lease (196)
Officer's Life Insurance (4,233,074)
Redding Contract (550,096)
Regulatory Asset - Alt Rate for Energy Program (CARE) - CA - Current (3,091)
Regulatory Asset - BPA Balancing Account - OR (470,930)
Regulatory Asset - REC Sales Deferral - WA - Noncurrent (96,604)
Regulatory Asset - REC Sales Deferral - WY - Noncurrent (604,911)
Regulatory Liability - Alt Rate for Energy Program (CARE) - CA - Current (674,990)
Regulatory Liability - Depreciation Decrease - WA (400,163)
Regulatory Liability - GHG Allowance Revenues - CA - Current (2,904,622)
Regulatory Liability - Sale of REC - OR - Current (404,974)
Regulatory Liability - UT Home Energy Lifeline (1,231,747)
Transmission Service Deposit (119,705)
Trapper Mining Stock Basis (571,734)
Unearned Joint Use Pole Contact Revenue (50,904)
Equity Earnings in Subsidiaries (13,544,949)
Total $ (37,044,036)
Schedule Page: 261 Line No.: 25 Column: a
Particulars (Details) Amounts
Accrued Bonus (162,237)
Accrued Final Reclamation (4,730,005)
Accrued Vacation (2,245,437)
Amortization NOPAs 99-00 RAR (50,796)
Basis Intangible Difference (219,947)
Capitalized Depreciation (4,977,004)
Capitalized Labor and Benefit Costs (809,045)
Cholla SHL NOPA (Lease Amortization) (191,965)
Cost of Removal (56,702,091)
Debt AFUDC (17,514,314)
Deferred Compensation - Noncurrent (50,737)
Deferred Revenue - Citibank (154,403)
Deseret Settlement Receivable (109,670)
Equity AFUDC - Temp (32,697,891)
FAS 112 Book Reserve - Postemployment Benefits (2,430,201)
FAS 158 Pension Liability (21,986,127)
FAS 158 Postretirement Liability (5,148,750)
FAS 158 SERP Liability (1,018,300)
Federal Tax Depreciation (1,137,695,628)
Injuries and Damages Accrual - Cash Basis (12,081,532)
LT Prepaid IBEW 57 Pension Contribution (262,290)
N Umpqua Settlement Agreement (284,997)
Non-deductible Postretirement Costs (8,060,641)
Oregon Regulatory Asset/Regulatory Liability Consolidation (17,126)
Other Environmental Liabilities (189,999)
Pension/Retirement Accrual (131,928)
Pre-1943 Preferred Stock Dividend - Deduction (64,760)
Prepaid Membership Fees (1,399,654)
Prepaid Taxes - IPUC (3,604)
Prepaid Taxes - OPUC (14,235)
Prepaid Taxes - UPSC (52,014)
Prepaid Water Rights (154,287)
Qualified Production Activities Deduction (15,808,349)
Regulatory Asset - CA Mobile Home Park Conversion (1,728)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Regulatory Asset - Carbon Unrecovered Plant - ID (286,822)
Regulatory Asset - Carbon Unrecovered Plant - UT (2,623,990)
Regulatory Asset - Carbon Unrecovered Plant - WY (461,260)
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 - Noncurrent (2,705,726)
Regulatory Asset - Deferred Excess NPC - ID - Noncurrent (16,592,103)
Regulatory Asset - Deferred Excess NPC - UT - Noncurrent (19,836,501)
Regulatory Asset - Deferred Excess NPC - WY '09 & After - Noncurrent (11,929,181)
Regulatory Asset - Deferred Independent Evaluator Fee - UT (62,152)
Regulatory Asset - Deferred Intervenor Funding Grants - CA (59)
Regulatory Asset - Deferred Intervenor Funding Grants - OR (373,388)
Regulatory Asset - Deferred Overburden Costs - ID (49,314)
Regulatory Asset - Deferred Overburden Costs - WY (164,947)
Regulatory Asset - Depreciation Increase - ID (1,669,470)
Regulatory Asset - DSM Balance Reclass (19,513,285)
Regulatory Asset - Environmental Costs (4,624,874)
Regulatory Asset - FAS 158 Postretirement Liability (5,177,908)
Regulatory Asset - GHG Allowances - CA - Noncurrent (796,626)
Regulatory Asset - Merwin Fish Collector Project - WA (162,586)
Regulatory Asset - OR Sch 94 Distribution Safety Surcharge (368,684)
Regulatory Asset - Preferred Stock Redemption Loss - WA (108,761)
Regulatory Asset - REC Sales Deferral - CA (49,313)
Regulatory Asset - Solar Feed-in Tariff Deferral - OR - Noncurrent (4,437,377)
Regulatory Asset - UT Subscriber Solar Program (21,683)
Regulatory Asset - Postretirement Settlement Loss CC - UT (217,007)
Regulatory Asset - Postretirement Settlement Loss CC - WY (88,977)
Regulatory Liability - Blue Sky - WA (139,550)
Regulatory Liability - Contra-Carbon Decommissioning - ID (281,047)
Regulatory Liability - Contra-Carbon Decommissioning - UT (2,281,573)
Regulatory Liability - Contra-Carbon Decommissioning - WY (215,893)
Regulatory Liability - Deferred Excess NPC - WA - Current (121,961)
Regulatory Liability - DSM - Current (1,890,608)
Regulatory Liability - OR Energy Conservation Charge (288,091)
Regulatory Liability - Property Insurance Reserve - OR (1,511,139)
Regulatory Liability - Solar Feed-in Tariff Deferral - CA - Current (945,656)
Regulatory Liability - Solar Incentive Program - UT - Current (10,116,877)
Regulatory Liability - Trojan Decommissioning (36,847)
Repairs Deduction (204,180,288)
Reserve for Bad Debts (95,341)
Rogue River - Habitat Enhancement Liability (25,104)
Tax Depletion - SRC (126,598)
Wasatch Workers Comp Reserve (153,941)
Western Coal Carrier Retiree Medical Accrual (626,000)
Total $ (1,644,070,546)
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 Company ("BHE"):
PPW Holdings LLC Sub-Group:
PacifiCorp
PPW Holdings LLC
PacifiCorp 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Energy West Mining Company
Glenrock Coal Company
Interwest Mining Company
Pacific Minerals, Inc.
BHE Sub-Group:
ABA Holding, LLC
ABA Management, L.L.C.
Alaska Gas Transmission Company, LLC
Allie Beth Allman Real Estate, Ltd
Arizona HomeServices, LLC
Berkshire Hathaway Energy Company
BG Energy Holding Company LLC
BHE AC Holding, LLC
BHE America Transco, LLC
BHE California Utility Holdco, LLC
BHE Canada LLC
BHE Geothermal, LLC
BHE Hydro, LLC
BHE Midcontinent Transmission Holdings LLC
BHE Renewables, LLC
BHE Solar, LLC
BHE Southwest Transmission Holdings 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
BHH Affiliates, LLC
BHH KC Real Estate, LLC
Big Spring Pipeline Company
Bishop Hill Energy II, LLC
Bishop Hill II Holdings, LLC
BRER Affiliates, LLC
BRER Real Estate Services, LLC
BRER Realty Holding Company, LLC
BRER Referral Services, 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 Operating Corporation
CalEnergy Pacific Holdings Corp
California Energy Development Corporation
California Energy Management Company
California Energy Yuma Corporation
Capitol Title Company
CBSHome Commercial, LLC
CBSHome Real Estate Company
CBSHome Real Estate of Iowa, Inc.
CBSHome Relocation Services, Inc.
CE Administrative Services, Inc.
CE Black Rock Holdings LLC
CE Butte Energy Holdings LLC
CE Butte Energy LLC
CE Electric (NY), Inc.
CE Gen Oil Company
CE Gen Pipeline Corporation
CE Gen Power Corporation
CE Generation LLC
CE Geothermal, Inc.
CE International Investments, Inc.
CE Leathers Company
CE Obsidian Energy LLC
CE Obsidian Holding LLC
CE Red Island Energy Holdings LLC
CE Red Island Energy LLC
CE Salton Sea 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
CE Texas Energy, LLC
CE Texas Fuel LLC
CE Texas Pipeline LLC
CE Texas Power LLC
CE Texas Resources LLC
CE Turbo LLC
Champion Realty, Inc.
Chancellor Title Services, Inc.
Cimmred Leasing Company
Columbia Title of Florida, Inc.
Commonsite, Inc.
Conejo Energy Company
Connecticut Referral Group, L.L.C.
Cordova Energy Company, LLC
Cordova Funding Corporation
CTHM, L.L.C.
CTRE, L.L.C.
Dakota Dunes Development Company
DCCO, Inc.
Desert Valley Company
DG-SB Project Holdings, LLC
Edina Financial Services, Inc.
Edina Realty Referral Network, Inc.
Edina Realty Relocation, Inc.
Edina Realty Title, Inc.
Edina Realty, Inc.
Elmore Company
eRealty, LLC
Esslinger-Wooten-Maxwell, Inc.
E-W-M Referral Services, Inc.
F&R/T LLC
Falcon Power Operating Company
FFR, Inc.
First Realty Group, Inc.
First Realty, Ltd
First Reserve Insurance, Inc.
First Weber Illinois, LLC
First Weber, Inc.
For Rent, Inc.
FRTC, LLC
FSRI Holdings, Inc.
Geronimo Community Solar Gardens, LLC
GPSF-B
Grande Prairie Wind, 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
HomeServices Financial Holdings, Inc.
HomeServices Insurance, Inc.
HomeServices Lending, LLC
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 Iowa, Inc.
HomeServices of Kentucky, Inc.
HomeServices of MOKAN, LLC
HomeServices of Nebraska, Inc.
HomeServices of Oregon, LLC
HomeServices of Texas, LLC
HomeServices of the Carolinas, Inc.
HomeServices of Washington, LLC
HomeServices of Wisconsin, LLC
HomeServices Referral Network, LLC
HomeServices Relocation, 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
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.
HSW Affiliates Holding, LLC
Huff Commercial Group, LLC
Huff-Drees Realty, Inc.
IES Holding II LLC
IES Holding LLC
IMO Company, Inc.
Imperial Magma LLC
InsuranceSouth, LLC
Intelligent Energy Solutions 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.
JRHBW Realty, Inc. d/b/a RealtySouth
Jumbo Road Holdings, LLC
Kansas City Title, Inc.
Kentucky Residential Referral, LLC
Kern River Funding Corporation
KR Acquisition 1, LLC
KR Acquisition 2, LLC
KR Holding, LLC
Lands of Sierra, Inc.
Larabee School of Real Estate & Insurance, Inc.
M & M Ranch Acquisition Company LLC
M & M Ranch Holding Company LLC
Magma Land Company I
Magma Power Company
Marshall Wind Energy, LLC
MEC Construction Services Company
MEHC Insurance Services Ltd.
MEHC Investment, Inc.
MEHC Merger Sub Inc.
MHC Investment Company
MHC, Inc.
Mid-America Referral Network, Inc.
MidAmerican Central California Transco LLC
MidAmerican Energy Company
MidAmerican Energy Machining Services LLC
MidAmerican Funding, LLC
MidAmerican Nuclear Energy Company LLC
MidAmerican Wind Tax Equity Holdings, LLC
Midland Escrow Services, Inc.
Midwest Capital Group, Inc.
Midwest Power Transmission Arkansas LLC
Midwest Power Transmission Iowa LLC
Midwest Realty Ventures, LLC
MTL Canyon Holdings LLC
MWR Capital, Inc.
Nebraska Land Title & Abstract Company
Nebraska Referral, Inc.
Nevada Electric Investment Company
Nevada Power Company d/b/a NV Energy
Niguel Energy Company
NMA, LLC
NNGC Acquisition LLC
Norcon Holdings, Inc.
Northern Aurora Inc.
Northern Consolidated Power, Inc.
Northern Natural Gas Company
NRS Referral Services, LLC
NV Energy, Inc.
NVE 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
NVE Insurance Co, Inc.
NW Referral Services, LLC
PCRE, L.L.C.
PFR Staffers, LLC
Pickford Escrow Company, Inc.
Pickford Holdings, LLC
Pickford Real Estate, Inc.
Pickford Services Company, Inc.
Pilot Butte, LLC
Pinon Pine Corporation
Pinon Pine Investment Company
Pinyon Pines I Holding Company, LLC
Pinyon Pines II Holding Company, LLC
Pinyon Pines Wind I, LLC
Pinyon Pines Wind II, LLC
PNW Referral, LLC
PPW Staffers, LLC
Preferred Carolinas Realty, Inc.
Preferred Carolinas Title Agency, LLC
Priority Title Corporation
Professional Referral Organization, Inc.
PW Fox Holding LLC
PW Fox, LLC
Quad Cities Energy Company
Real Estate Knowledge Services, L.L.C.
Real Estate Links, LLC
Real Estate Referral Network, Inc.
Real Living Real Estate, LLC
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
S.W. Hydro, Inc.
Salton Sea Funding Corporation
Salton Sea Minerals Corporation
Salton Sea Power Company
Salton Sea Power Generation Company
Salton Sea Power LLC
Salton Sea Royalty Company
San Diego PCRE, Inc.
San Felipe Energy Company
Saranac Energy Company, Inc.
SECI Holdings, Inc.
Semonin Realtors, Inc.
Shorebreak Holdings II, LLC
Sierra Gas Holding Company
Sierra Pacific Power Company d/b/a NV Energy
Solar Star 3, LLC
Solar Star California XIX, LLC
Solar Star California XX, LLC
Solar Star Funding, LLC
Solar Star Projects Holdings, LLC
Southwest Relocation, LLC
SSC XIX, LLC
SSC XX, LLC
The Escrow Firm
The Referral Company
TIAC LLC
TitleSouth, LLC
TLTC LLC
Topaz Solar Farms, LLC
TPZ Holding, LLC
TRMC LLC
Two Rivers, Inc.
TX Jumbo Road Wind, 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
VPC Geothermal LLC
Vulcan Power Company
Vulcan/BN Geothermal Power Company
Wailuku Holding Company LLC
Wailuku Investment LLC
Wailuku River Hydroelectric Power Co, Inc.
Walnut Ridge Wind, 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:
121 Acquisition Co., LLC
121 Development, Inc.
21 SPC, Inc.
2150 Cobb Development, Inc.
21st Communities, Inc.
21st Mortgage Corporation
2701 Camelback Development, Inc.
3Wire Group Inc.
6991 Development, Inc.
Accurate Installations, Inc.
Acme Brick Company
Acme Brick DFW, Inc.
Acme Brick Sales Company
Acme Brick Tile & Stone, Inc.
Acme Building Brands, Inc.
Acme Investment Company
Acme Management Company
Acme Ochs Brick and Stone, Inc.
Acme Services Company, L.P.
Active Organics, Inc.
Adalet/Scott Fetzer Company
AEG Processing Center No. 35, Inc.
AEG Processing Center No. 58, Inc.
Affiliated Agency Operations Co.
Affordable Housing Partners, Inc.
AJF Warehouse Distributors, Inc.
AL/TEX Homes, Inc.
Albacor Shipping (USA) Inc.
Albecca, Inc.
Alexander Road Insurance Agency, Inc.
Alpha Cargo Motor Express, Inc.
American All Risk Insurance Services Inc.
American Commercial Claims Administrators Inc.
American Dairy Queen Corporation
American Employers Group, Inc.
AmGUARD Insurance Company
Applied Group Insurance Holdings, Inc.
Applied Investigations Inc.
Applied Logistics, Inc.
Applied Premium Finance, Inc.
Applied Processing Center No. 60, Inc.
Applied Risk Services of New York, Inc.
Applied Risk Services, Inc.
Applied Underwriters Captive Risk Assurance Company, Inc.
Applied Underwriters, Inc.
Artform International Inc.
Astrex Electronics, Inc.
Astrex Holding Company
Atlanta International Insurance Company
AU Captive Risk Assurance Co.
AU Holding Company, Inc.
Baroness Small Estates, Inc.
Bayport Systems, Inc.
BCC Development, Inc.
Ben Bridge Jeweler, Inc.
Benjamin Moore & Co.
Benson Industries, Inc.
Benson, Ltd.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
Berkshire Hathaway Assurance Corporation
Berkshire Hathaway Automotive Inc.
Berkshire Hathaway Credit Corporation
Berkshire Hathaway Direct Insurance Company
Berkshire Hathaway Finance Corporation
Berkshire Hathaway Global Insurance Services, LLC
Berkshire Hathaway Homestate Insurance Company
Berkshire Hathaway Inc.
Berkshire Hathaway Life Insurance Company of Nebraska
Berkshire Hathaway Specialty Concierge, LLC
Berkshire Hathaway Specialty Insurance Company
Berkshire Indemnity Group Inc.
BH Columbia Inc.
BH Credit LLC
BH Finance, Inc.
BH Media Group Holdings, Inc.
BH Media Group, Inc.
BH Shoe Holdings, Inc.
BH, LLC
BHA Real Estate Holdings, LLC
BHG Life Insurance Company
BHG Structured Settlements, Inc.
BHSF, Inc.
Blue Chip Stamps, Inc.
BN Leasing Corporation
BNJ NetJets, Inc.
BNSF Communications, Inc.
BNSF Logistics International, Inc.
BNSF Railway Company
BNSF Railway International Services, Inc.
BNSF Spectrum, Inc.
Boat America Corporation
Boat Owners Association of the United States
Boat/U.S, Inc.
Boot Royalty Company
Borrego Holdings, Inc.
Borsheim Jewelry Company, Inc.
BR Agency, Inc.
Brainy Toys, Inc.
Brilliant National Services, Inc.
Brooks Sports, Inc.
Brookwood Insurance Company
BuilderMT, Inc.
Burlington Northern Railroad Holdings, Inc.
Burlington Northern Santa Fe British Columbia, Ltd.
Burlington Northern Santa Fe Insurance Company, Ltd.
Burlington Northern Santa Fe Manitoba, Inc.
Burlington Northern Santa Fe, LLC
Business Wire, Inc.
BWVT Motors, Inc.
C & R Insurance Services, Inc.
California Insurance Company
Camp Manufacturing Company
Campbell Hausfeld Holdings. Inc.
Campbell Hausfeld/Scott Fetzer Company
Cannon Equipment LLC
Carefree/Scott Fetzer Company
Cavalier Homes, Inc.
CCC Lonestar LLC
Central States Indemnity Co. of Omaha
Central States of Omaha Companies, Inc.
Charter Brokerage Holdings Corp.
Chatwell, Inc.
Chemtool Incorporated
Chippewa Shoe Company
CJE II
Claims Services, Inc.
Clayton Commercial Buildings, Inc.
Clayton Education Corp.
Clayton Homes, Inc.
CMH Capital, Inc.
CMH Hodgenville, 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
CMH Homes, Inc.
CMH Manufacturing West, Inc.
CMH Manufacturing, Inc.
CMH of KY, Inc.
CMH Parks, Inc.
CMH Services, Inc.
CMH Set and Finish, Inc.
CMH Transport, Inc.
Columbia Insurance Company
Combined Claims Services, Inc.
Commercial Casualty Insurance Company
Commercial General Indemnity, Inc.
Complementary Coatings Corporation
Consolidated Health Plans Inc.
Continental Divide Insurance Company
Continental Indemnity Company
Cornelius Inc.
Cornelius Renew, Inc.
Cort Business Services Corporation
Courtesy Dealership Property, Inc.
Coverage Dynamics Group, Inc.
CoverYourBusiness.com Inc.
Criterion Insurance Agency
CSI Life Insurance Company
CTB Credit Corp
CTB Inc.
CTB International Corp
CTB IW Inc.
CTB Midwest Inc.
CTB MN Investments
Cubic Designs, Inc.
Cumberland Asset Management, Inc.
Cypress Insurance Company
D.I. Properties Inc.
DAA Development, Inc.
Dairy Queen Corporate Stores, Inc.
Dairy Queen Of Georgia, Inc.
DCI Marketing Inc.
Delta Wholesale Liquors, Inc.
Denver Brick Company
DL Trading Holdings I, Inc.
DQ Funding Corporation
DQ Joint Venture Stores, Inc.
DQ Managed Stores, Inc.
DQ Wholly-Owned Stores, Inc.
DQF, Inc.
DQGC, Inc.
DragonFly Aeronautics LLC
Dynamic Development, Inc.
EastGUARD Insurance Company
Eco Color Company
Ecodyne Corporation
Ellis & Watts Global Industries, Inc.
Elm Street Corporation
Empire Distributors of North Carolina, Inc.
Empire Distributors, Inc.
Executive Jet Management, Inc.
Exsif Worldwide, Inc.
ExtruMed, Inc.
Faraday Capital Limited
FFBH Development, Inc.
Finial Holdings, Inc.
Finial Reinsurance Company
First American Carriers, Inc.
First Berkshire Hathaway Life Insurance Company
FlightSafety Capital Corp.
FlightSafety Development Corp.
FlightSafety International Inc.
FlightSafety New York, Inc.
FlightSafety Properties, Inc.
FlightSafety Services Corporation
Floors, 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.11
Fontaine Commercial Trailer, Inc.
Fontaine Engineered Products, Inc.
Fontaine Fifth Wheel Company
Fontaine Modification Company
Fontaine Spray Suppression Company
Fontaine Trailer Company LLC
Fontaine Truck Equipment Company LLC
Fontana Wood Products, Inc.
Footwear Investment Company
Forest River Financial Services, Inc.
Forest River Holdings, Inc.
Forest River Manufacturing LLC
Forest River, Inc.
Freedom Warehouse Corp.
FreightWise, Inc.
Fruit of the Loom Direct, Inc.
Fruit of the Loom Trading Company
Fruit of the Loom, Inc.
Fruit of the Loom, Inc. (Sub)
FTL Regional Sales Co., Inc.
Garan Central America Corp.
Garan Incorporated
Garan Manufacturing Corp.
Garan Services Corp
Gateway Underwriters Agency, Inc.
GEICO Advantage Insurance Company
GEICO Casualty Co.
GEICO Choice Insurance Company
GEICO Corporation
GEICO General Insurance Co.
GEICO Indemnity Co.
GEICO Insurance Agency
GEICO Marine Insurance Company
GEICO Products, Inc.
GEICO Secure Insurance Company
Gen Re Intermediaries Corporation
General Re Corporation
General Re Financial Products Corporation
General Re Life Corporation
General Re New England Asset Management
General Reinsurance Corporation
General Star Indemnity Company
General Star Management Company
General Star National Insurance Company
Genesis Insurance Company
Genesis Management and Insurance Services Corporation
Giles Industries, Inc.
Government Employees Financial Corp.
Government Employees Insurance Co.
GRD Holdings Corporation
GUARDco, Inc.
H. H. Brown Shoe Company, Inc.
H.J. Justin & Sons, Inc.
Halex/Scott Fetzer Company
Hallmark Sweet, Inc.
Hawthorn Life International, Ltd.
HDS Redevelopment Corporation
HeatPipe Technology, Inc.
Helzberg's Diamond Shops, Inc.
Henley Holdings, LLC
HFWBH Development, Inc.
HG-Power Plant. Inc.
Hohmann & Barnard, Inc.
Homefirst Agency, Inc.
Homemakers Plaza, Inc.
Horizon Wine & Spirits - Chattanooga, Inc.
Horizon Wine & Spirits - Nashville, Inc.
IdeaLife Insurance Company
Illinois Insurance Company
Ingersoll Cutting Tool Company
Innovative Building Products, Inc.
International American Group Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.12
International Dairy Queen, Inc.
International Insurance Underwriters, Inc.
International Traders, Inc.
Intrepid JSB, Inc.
Ironwood Plastics Inc.
Iscar Metals Inc.
ITTI Group USA Holdings, Inc.
ITTI Investment Holdings, Inc.
J.L. Mining Company
J.S Justin, Inc.
JDS Properties, Inc.
Johns Manville China, Ltd.
Johns Manville Corporation
Johns Manville, Inc.
Jordan's Furniture, Inc.
Justin Belt Company, Inc.
Justin Boot Company
Justin Brands, Inc.
Justin Industries, Inc.
Kahn Ventures, Inc.
Karmelkorn Shoppes, Inc.
Kova Solutions, Inc.
L.A. Terminals, Inc.
Leesburg Yarn Mills, Inc.
Lipotec Group Corp.
LMG Ventures, LLC
Lockwood Street Urban Renewal Corporation
Los Angeles Junction Railway Company
LSP Holding, Inc.
Lubricant Investments, Inc.
Lubrizol Advanced Materials China, Inc.
Lubrizol Advanced Materials Gibraltar, Inc.
Lubrizol Advanced Materials Holding Corporation
Lubrizol Advanced Materials International, Inc.
Lubrizol Advanced Materials, Inc.
Lubrizol Enterprises, Inc.
Lubrizol Inter-Americas Corporation
Lubrizol International Management Corporation
Lubrizol Oilfield Solutions, Inc.
Lubrizol Overseas Trading Corporation
Lubrizol Specialty Products, Inc.
M & C Products, Inc.
M&M Tradition Holdings Corp.
Mapletree Transportation, Inc.
Marathon Suspension Systems, Inc.
Marmon Beverage Technologies, Inc.
Marmon Crane Services, Inc.
Marmon Distribution Services, Inc.
Marmon Energy Services Company
Marmon Engineered Components Company
Marmon Foodservice Technologies LLC
Marmon Holdings, Inc.
Marmon Merchandising Holdings, Inc.
Marmon Retail Products, Inc.
Marmon Retail Store Equipment LLC
Marmon Retail Technologies Company
Marmon Tubing, Fittings & Wire Products, Inc.
Marmon Water, Inc.
Marmon Wire & Cable, Inc.
Marmon-Herrington Company
Marquis Jet Holdings, Inc.
Marquis Jet Partners, Inc.
Martin Mills, Inc.
Maryland Ventures, Inc.
McCarty-Hull Cigar Company, Inc.
McLane Beverage Distribution, Inc.
McLane Beverage Holding, Inc.
McLane Company, Inc.
McLane Eastern, Inc.
McLane Express, Inc.
McLane Foodservice, Inc.
McLane Mid-Atlantic, Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.13
McLane Midwest, Inc.
McLane Minnesota, Inc.
McLane New Jersey, Inc.
McLane Ohio, Inc.
McLane Southern, Inc.
McLane Suneast, Inc.
McLane Western, Inc.
Meadowbrook Meat Company, Inc.
Medical Protective Finance Corporation
Medical Protective Insurance Services, Inc.
MedPro Group, Inc.
MedPro Risk Retention Services, Inc.
Meyn LLC
Midwest Northwest Properties, Inc.
Miller-Sage, Inc.
Mindware Corporation
MiTek Holdings, Inc.
MiTek Industries, Inc.
MiTek USA, Inc.
Montana Retail Properties, Inc.
Morgantown-National Supply, Inc.
Mount Vernon Fire Insurance Company
Mount Vernon Specialty Insurance Company
Mouser Electronics, Inc.
MPP Administrators, Inc.
MPP Co., Inc.
MPP Pipeline Corporation
MS Property Company
MVVT Development, Inc.
MW Wholesale, Inc.
National Fire & Marine Insurance Company
National Indemnity Company
National Indemnity Company of Mid-America
National Indemnity Company of the South
National Liability & Fire Insurance Company
Nationwide Uniforms
Nebraska Furniture Mart, Inc.
NetJets Aviation, Inc.
NetJets Europe Holdings, LLC
NetJets Inc.
NetJets International, Inc.
NetJets Large Aircraft, Inc.
NetJets Sales, Inc.
NetJets Services, Inc.
NetJets U.S., Inc.
NFM of Kansas, Inc.
NFM SERVICES, LLC
NJE Holdings, LLC
NJI Sales, Inc.
Nocona Boot Company
NorGUARD Insurance Company
North American Casualty Co.
Northern States Agency, Inc.
Norvell Electronics, Inc.
Noveon Hilton Davis, Inc.
Oak River Insurance Company
Old United Casualty Company
Omaha World-Herald Company
Orange Julius Of America
Oriental Trading Company, Inc.
OTC Brands, Inc.
OTC Direct, Inc.
OTC Worldwide Holdings, Inc.
P Chem, Inc.
Particle Sciences, Inc.
Penn Coal Land, Inc.
Pennsylvania Insurance Company
Perfection Hy-Test Company
PFVT Development, Inc.
Pine Canyon Land Company
PJR Management, Inc.
Plaza Financial Services Co.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.14
Plaza Resources Co.
PLICO
PLICO Financial, Inc.
PLICO Sponsored Captive Insurance - Cell 1
PLICO Sponsored Captive Insurance Co.
Precision Brand Products, Inc.
Precision Steel Warehouse - Charlotte
Precision Steel Warehouse, Inc.
Princeton Advertising & Marketing Group, Inc.
Princeton Insurance Company
Princeton Risk Protection, Inc.
Priority One Financial Services, Inc.
Pro Installations, Inc.
Procrane Holdings, Inc.
Professional Datasolutions, Inc.
Promesa Health, Inc.
QS Partners LLC
R.C. Willey Home Furnishings
Rabun Apparel, Inc.
Radnor Specialty Insurance Company
Railserve, Inc.
Railsplitter Holdings Corporation
RCP Investment, Inc.
Red River Providers Association RPG
Redwood Fire and Casualty Insurance Company
RENTCO Trailer Corporation
Resolute Management Inc.
Richline Group, Inc.
Ridgeline Captive Management, Inc.
Ringwalt & Liesche Co.
Rio Grande, Inc.
Roxell USA, Inc.
Royal Cargo Line, Inc.
Rush Air Inc.
Russell Athletic Corporation
Sager Electrical Supply Co. Inc.
Salado Sales, Inc.
Santa Fe Pacific Insurance Company
Santa Fe Pacific Pipeline Holdings, Inc.
Santa Fe Pacific Pipelines, Inc.
Santa Fe Pacific Railroad Company
Scott Fetzer Financial Group, Inc.
ScottCare Corporation
See's Candies, Inc.
Sees Candy Shops, Incorporated
Seventeenth Street Realty, Inc.
SFEG Corp.
SFVT Development, Inc.
Shaw Contract Flooring Services, Inc.
Shaw Diversified Services, Inc.
Shaw Floors, Inc.
Shaw Funding Company
Shaw Industries Group, Inc.
Shaw Industries, Inc.
Shaw International Services, Inc.
Shaw Retail Properties, Inc.
Shaw Transport, Inc.
SHX Flooring, Inc.
SidePlate Systems, Inc.
Smilemakers Canada Inc.
Smilemakers, Inc.
SN Management, Inc.
Soco West, Inc.
Somerset Services, Inc.
Southern Energy Homes, Inc.
Spectra Contract Flooring Puerto Rico, Inc.
SSP-SiMatrix Inc.
SSS Acquisition Inc.
SSS Acquisition Sub, Corp
Stahl/Scott Fetzer Company
Star Furniture Company
Star Lake Railroad 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.15
Stern/Leach Company
Strategic Staff Management, Inc.
Syrgis Holdings, Inc.
Taegutec Inc.
TBS USA, Inc.
Texas Insurance Company
The Ben Bridge Corporation
The BN and SF Railway de Mexico, S.A. de C.V.
The Buffalo News, Inc.
The BVD Licensing Corporation
The Fechheimer Brothers Co.
The Indecor Group, Inc.
The Lubrizol Corporation
The Medical Protective Company
The Pampered Chef, Ltd.
The Scott Fetzer Company
The Wilkins Corporation
The Zia Company
TMI Climate Solutions, Inc.
TOHVT Development, Inc.
Tony Lama Company
Tool-Flo Manufacturing, Inc.
Top Five Club, Inc.
Total Quality Apparel Resources
TPC European Holdings, LTD.
TPC North America, Ltd.
Transco, Inc.
Transportation Technology Services, Inc.
TRH Holding Corp.
Triangle Suspension Systems, Inc.
TSE Brakes, Inc.
TTI, Inc.
Tucker Safety Products, Inc.
TXFM, Inc.
TXVT Development, Inc.
U.S. Investment Corporation
U.S. Underwriters Insurance Co.
UCFS Europe Company
Unified Supply Chain, Inc.
Uni-Form Components Co.
Union Sales, Inc.
Union Tank Car Company
Union Underwear Co., Inc.
Unione Italiana Reinsurance Company of America, Inc.
United Consumer Financial Services Company
United Direct Finance, Inc.
United States Aviation Underwriters, Incorporated
United States Liability Insurance Company
UTLX Company
Van Enterprises, Inc.
Vanderbilt ABS Corp.
Vanderbilt Mortgage and Finance, Inc.
Vanderbilt Property&Casualty Insurance Co., Ltd.
Vanderbilt SPC, Inc.
Vanity Fair, Inc.
Veritas Insurance Group, Inc.
Vesta Funding, Inc.
Vesta Intermediate Funding, Inc.
VFI-Mexico, Inc.
Vision Retailing, Inc.
VNDR Development, Inc.
VT Insurance Acquisition Sub Inc.
Warwick Chemicals USA, Inc.
Wayne/Scott Fetzer Company
Webb Wheel Products, Inc.
Western Builders Supply, Inc.
Western Fruit Express Company
Western/Scott Fetzer Company
WestGUARD Insurance Company
Whittaker, Clark & Daniels, Inc.
WMC Corp.
World Book Encyclopedia, 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.16
World Book, Inc.
World Book/Scott Fetzer Company
World Investments, Inc.
Worldwide Containers, Inc.
WPLG, Inc.
X-L-Co., Inc.
XTRA Companies, Inc.
XTRA Corporation
XTRA Finance Corporation
XTRA Intermodal, 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.17
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2015/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
19,256,508 106,147,921 125,321,975 148,956 Income 2
36,463,266 36,522,444 5,000 664,385 FICA 3
281,536 239,266 5,257 Unemployment 4
126,685 119,300 7,385 Excise Tax - Coal 5
1,522,888 Foreign Withholding Taxes 6
56,127,995 106,147,921 163,725,873 5,000 825,983Subtotal 7
8
State: 9
10
Arizona: 11
3,716,456 3,649,984 1,891,464 Property 12
776,758 89,867 866,625 Income 13
4,493,214 89,867 4,516,609 1,891,464Subtotal 14
15
California: 16
2,309,036 2,309,036 Property 17
32,625 30,348 2,207 Unemployment 18
797,578 438,206 1,235,784 Franchise-Income 19
96,067 151,826 2,641 Use 20
1,128,715 1,094,371 1,278,860 Local Franchise 21
4,364,021 438,206 4,821,365 1,283,708Subtotal 22
23
Colorado: 24
2,159,523 2,079,523 2,190,000 Property 25
-216 -216 Income 26
2,159,523 -216 2,079,307 2,190,000Subtotal 27
28
Idaho: 29
4,830,799 5,548,923 2,406,767 Property 30
1,686,970 620,002 2,306,972 Income 31
39,156 37,280 17,016 KWh 32
36,545 36,450 1,423 Unemployment 33
225,196 223,953 14,461 Use 34
6,818,666 620,002 8,153,578 2,439,667Subtotal 35
36
Montana: 37
4,507,433 4,700,074 2,155,918 Property 38
62,827 94,645 157,472 Corporate License-Income 39
720 720 Unemployment 40
12,376,039
FERC FORM NO. 1 (ED. 12-96)Page 262
TOTAL41 393,028,516 271,448,063 118,979,745 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 (Continued)
PacifiCorp X
/ /2015/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
4,267,107 121,054,868 66,502 2
36,522,444 5,000 723,563 3
239,266 -37,013 4
119,300 5
1,522,888 1,522,888 6
42,671,005 121,054,868 5,000 2,275,940 7
8
9
10
11
3,649,984 1,824,992 12
10,322 856,303 13
10,322 4,506,287 1,824,992 14
15
16
115,499 2,193,537 17
30,348 -70 18
28,863 1,206,921 19
151,826 58,400 20
1,094,371 1,244,516 21
326,536 4,494,829 1,302,846 22
23
24
325,171 1,754,352 2,110,000 25
14 -230 26
325,185 1,754,122 2,110,000 27
28
29
18,954 5,529,969 3,124,891 30
39,281 2,267,691 31
37,280 15,140 32
36,450 1,328 33
223,953 13,218 34
318,638 7,834,940 3,154,577 35
36
37
4,700,074 2,348,559 38
3,731 153,741 39
720 40
FERC FORM NO. 1 (ED. 12-96)Page 263
41 12,597,489 331,407,278 61,621,238 41,847,694
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2015/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.
241,715 241,715 62,000 Energy License 1
172,224 172,224 44,000 Wholesale Energy 2
4,984,919 94,645 5,272,205 2,261,918Subtotal 3
4
Nevada: 5
10,000 Commerce Tax 6
10,000Subtotal 7
8
New Mexico: 9
22,851 22,851 Property 10
105 -19,372 -19,267 Income 11
22,956 -19,372 3,584Subtotal 12
13
Oregon: 14
23,762,422 23,748,743 11,851,143 Property 15
1,462,047 1,454,515 53,901 Unemployment 16
3,773,226 5,462,539 9,235,765 Excise-Income 17
23,981 -532 23,449 City of Portland-Income 18
1,455,335 1,247,564 519,896 Department of Energy 19
1,082,106 1,051,047 427,121 Tri-Met 20
1,282 1,282 Lane County 21
28,866,802 28,784,862 4,621,877 Franchise 22
60,427,201 5,462,007 65,547,227 12,371,039 5,102,899Subtotal 23
24
Texas: 25
243 243 Unemployment 26
243 243Subtotal 27
28
Utah: 29
74,283,223 74,453,917 559,037 Property 30
5,694,571 6,146,685 11,841,256 Income 31
262,790 260,302 7,580 Unemployment 32
610 610 Navajo Nation 33
4,066,518 4,123,322 403,158 Use 34
84,307,712 6,146,685 90,679,407 969,775Subtotal 35
36
Washington: 37
10,381,694 11,341,694 10,290,000 Property 38
140,937 149,647 1,921 Unemployment 39
24,324 24,000 2,714 Business & Occupation 40
12,376,039
FERC FORM NO. 1 (ED. 12-96)Page 262.1
TOTAL41 393,028,516 271,448,063 118,979,745 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 (Continued)
PacifiCorp X
/ /2015/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.
241,715 62,000 1
172,224 44,000 2
4,451 5,267,754 2,454,559 3
4
5
10,000 10,000 6
10,000 10,000 7
8
9
22,851 10
698 -19,965 11
698 2,886 12
13
14
876,190 22,872,553 11,864,822 15
1,454,515 46,369 16
232,351 9,003,414 17
660 22,789 18
1,247,564 727,667 19
1,051,047 396,062 20
1,282 21
28,784,862 4,539,937 22
3,616,045 61,931,182 12,592,489 4,982,368 23
24
25
243 26
243 27
28
29
5,168,141 69,285,776 729,731 30
263,909 11,577,347 31
260,302 5,092 32
610 33
4,123,322 459,962 34
9,815,674 80,863,733 1,194,785 35
36
37
134,964 11,206,730 11,250,000 38
149,647 10,631 39
24,000 2,390 40
FERC FORM NO. 1 (ED. 12-96)Page 263.1
41 12,597,489 331,407,278 61,621,238 41,847,694
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2015/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.
13,124,413 13,134,413 1,325,000 Public Utility 1
1,503,066 1,252,182 354,168 Natural Gas Use Tax 2
875,578 856,172 90,103 Use 3
24,970 24,970 Forest excise tax 4
26,074,982 26,783,078 12,063,906Subtotal 5
6
Wyoming: 7
15,054,067 15,123,809 7,489,054 Property 8
1,998,855 1,738,070 2,027,954 Wind Generation Tax 9
91,325 88,914 5,157 Unemployment 10
1,960,866 1,950,466 285,300 Franchise 11
2,010,578 2,001,436 148,763 Use 12
70,261 70,261 Annual Report 13
21,185,952 20,972,956 9,956,228Subtotal 14
15
-17,909 20,512State Other 16
17
Miscellaneous: 18
23,401 23,401 Goshute Possessory 19
241,948 241,948 Sho-Ban Possessory 20
39,265 39,579 19,476 Navajo Possessory 21
38,782 38,782 Ute Possessory 22
70,632 70,632 Crow Possessory 23
66,651 66,651 Umatilla Possessory 24
480,679 463,084 39,988Subtotal 25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
12,376,039
FERC FORM NO. 1 (ED. 12-96)Page 262.2
TOTAL41 393,028,516 271,448,063 118,979,745 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 (Continued)
PacifiCorp X
/ /2015/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.
13,134,413 1,335,000 1
1,252,182 103,284 2
856,172 70,697 3
24,970 4
2,417,935 24,365,143 12,772,002 5
6
7
24,156 15,099,653 7,558,796 8
1,738,070 1,767,169 9
88,914 2,746 10
1,950,466 274,900 11
2,001,436 139,621 12
70,261 13
2,114,506 18,858,450 9,743,232 14
15
-17,909 2,603 16
17
18
23,401 19
241,948 20
39,579 19,790 21
38,782 22
70,632 23
66,651 24
463,084 22,393 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 12,597,489 331,407,278 61,621,238 41,847,694
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.: 6 Column: l
$1,271,911 Account 426.3, Penalties
250,977 Account 431, Other interest expense
$1,522,888
Schedule Page: 262 Line No.: 13 Column: f
Represents a reclassification of the balance at end of year to Account 143, Other accounts
receivable.
Schedule Page: 262 Line No.: 13 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262 Line No.: 17 Column: l
$113,930 Account 408.2, Taxes other than income taxes, other income and deductions
1,569 Account 589, Rents
$115,499
Schedule Page: 262 Line No.: 18 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 19 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.: 19 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.: 20 Column: l
Charged to same account as related goods.
Schedule Page: 262 Line No.: 25 Column: l
$ 784 Account 408.2, Taxes other than income taxes, other income and deductions
324,387 Account 107, Construction work in progress
$325,171
Schedule Page: 262 Line No.: 26 Column: f
Represents a reclassification of the balance at end of year to Account 143, Other accounts
receivable.
Schedule Page: 262 Line No.: 26 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.: 30 Column: l
$ 1,132 Account 408.2, Taxes other than income taxes, other income and deductions
17,822 Account 107, Construction work in progress
$ 18,954
Schedule Page: 262 Line No.: 31 Column: f
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
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.: 31 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.: 33 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 34 Column: l
Charged to same account as related goods.
Schedule Page: 262 Line No.: 39 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.: 39 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.: 40 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 11 Column: f
Represents a reclassification of the balance at end of year to Account 143, Other accounts
receivable.
Schedule Page: 262.1 Line No.: 11 Column: l
Account 409.2, Income tax, other income and deductions, which represents state income tax
applicable to other income and deductions.
Schedule Page: 262.1 Line No.: 15 Column: l
$ 22,107 Account 408.2, Taxes other than income taxes, other income and deductions
137,374 Account 589, Rents
716,709 Account 107, Construction work in progress
$876,190
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 a portion 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 a portion 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
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
$ 63,083 Account 408.2, Taxes other than income taxes, other income and deductions
524 Account 589, Rents
3,055,445 Account 107, Construction work in progress
2,049,089 Account 151, Fuel stock
$5,168,141
Schedule Page: 262.1 Line No.: 31 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: 262.1 Line No.: 31 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.: 32 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 34 Column: l
Charged to same account as related goods.
Schedule Page: 262.1 Line No.: 38 Column: l
$ 37,833 Account 408.2, Taxes other than income taxes, other income and deductions
97,131 Account 107, Construction work in progress
$134,964
Schedule Page: 262.1 Line No.: 39 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.2 Line No.: 2 Column: l
Account 151, Fuel stock
Schedule Page: 262.2 Line No.: 3 Column: l
Charged to same account as related goods.
Schedule Page: 262.2 Line No.: 4 Column: l
Account 408.2, Taxes other than income taxes, other income and deductions
Schedule Page: 262.2 Line No.: 8 Column: l
$ 3,702 Account 408.2, Taxes other than income taxes, other income and deductions
17,066 Account 589, Rents
3,388 Account 107, Construction work in progress
$24,156
Schedule Page: 262.2 Line No.: 10 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.2 Line No.: 12 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
2015/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
/ /2015/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% 25,438,102 411.4, 420 5,113,907 5
30% 269,158 420 11,696 6
Idaho 123,994 411.4, 420 15,695 7
TOTAL 25,831,254 5,141,298 8
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
9
10
Idaho 190 -940 1,382,683 601,685 420 168,262 11
Total Nonutility -940 1,382,683 601,685 168,262 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
/ /2015/Q4
Line
No.ADJUSTMENT EXPLANATIONAverage Periodof Allocationto Income
1
2
3
4
20,324,195 38.82 and 30 5
257,462 24 6
108,299 38.82 and 30 7
20,689,956 8
9
10
1,815,166 30 11
1,815,166 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% $24,753,083 - $ - 411.4(1) $4,749,955 $ - $20,003,128 38.82

10% 685,019 - - 420(2) 363,952 - 321,067 30
$25,438,102 $ - $5,113,907 $ - $20,324,195
(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 $ 60,087 - $ - 411.4(1) $ 6,453 $ - $ 53,634 38.82

Idaho 63,907 - - 420(2) 9,242 - 54,665 30
$ 123,994 $ - $ 15,695 $ - $ 108,299
(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 credited 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
2015/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
/ /2015/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.
6,804,201Working Capital Deposits 5,895,811 128,610 1,037,000131 1
2
5,617,504Reclamation Costs - Trapper Mine 5,860,476 242,972 3
4
Western Coal Carriers Benefits 5
12,417,000 Obligation 11,791,000 73,443 699,443131,232 6
7
268,873Program Incentives 114,470 154,403921 8
9
9,721,835Deferred Compensation Plans 9,671,098 768,377 819,114131,232,241 10
11
6,935,250Long-Term Incentive Plan 8,484,695 2,868,941 1,319,496426.5 12
13
550,096Redding Contract (20) 550,096456 14
15
17,102Foote Creek Contract (15) 17,102456 16
17
Regulated Environmental 18
21,619,912 Liabilities 22,938,098 5,794,521 4,476,335 19
20
Non-Regulated Environmental 21
2,217,266 Liabilities 2,222,843 101,067 95,490 22
23
Unearned Joint Use Pole 24
2,915,426 Contact 2,864,521 6,172,814 6,223,719454 25
26
1,900Misc. Security Deposits 3,400 1,500 27
28
279,558Lease Incentives 906,925 752,490 125,123931 29
30
118,811Cowlitz/Lewis River O&M (1) 120,418 289,003 287,396539 31
32
17,806Employee Housing Security Deposits 17,975 4,200 4,031131, 545 33
34
413,417Cogeneration Bonds-Sunnyside 413,417 35
36
1,104,607Transmission Security Deposits 2,392,500 1,361,000 73,107232 37
38
353,987Transmission Service Deposits 234,282 1,164,809 1,284,514131, 232 39
40
557,813MCI F.O.G. Wire Lease (1) 557,618 3,345,705 3,345,900454 41
42
110,203,561Unamortized Contract Values 97,918,622 12,284,939242 43
44
119,103,601Loss Contingency - USA Power 121,583,766 2,480,165 45
46
FERC FORM NO. 1 (ED. 12-94) Page 269
47 TOTAL 32,208,458 34,701,559 301,476,278 303,969,379
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
/ /2015/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.
2,249,800Accrued Right-of-Way Obligations 2,550,482 300,682 1
2
Navajo Tribal Utility Authority 3
480,053 Escrow 480,148 95 4
5
Facility Use Fee (2) 95,833 100,000 4,167456 6
7
Eagle Mountain Contract 8
Liability (2) 4,107,880 6,008,064 1,900,184555 9
10
Energy Supply Management 11
Deferral 250,000 250,000 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 32,208,458 34,701,559 301,476,278 303,969,379
Schedule Page: 269 Line No.: 8 Column: a
The weighted average life is five years.
Schedule Page: 269 Line No.: 19 Column: c
Account 131, Cash
Account 182.3, Other regulatory assets
Account 232, Accounts payable
Schedule Page: 269 Line No.: 22 Column: c
Account 131, Cash
Account 232, Accounts payable
Account 426.5, Other deductions
Schedule Page: 269 Line No.: 25 Column: a
The weighted average life is one year.
Schedule Page: 269 Line No.: 29 Column: a
The weighted average life is 10 years.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
/ /2015/Q4
Line
No.Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable
property.
2. For other (Specify),include deferrals relating to other income and deductions.
1 Accelerated Amortization (Account 281)
2 Electric
3 Defense Facilities
3,637,886 37,473,042 252,151,842 4 Pollution Control Facilities
5 Other (provide details in footnote):
6
7
3,637,886 37,473,042 252,151,842 8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilities
11 Pollution Control Facilities
12 Other (provide details in footnote):
13
14
15 TOTAL Gas (Enter Total of lines 10 thru 14)
16
3,637,886 37,473,042 252,151,842 17 TOTAL (Acct 281) (Total of 8, 15 and 16)
18 Classification of TOTAL
2,840,935 32,628,468 221,987,431 19 Federal Income Tax
796,951 4,844,574 30,164,411 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
/ /2015/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
285,986,998 4
5
6
7
285,986,998 8
9
10
11
12
13
14
15
16
285,986,998 17
18
251,774,964 19
34,212,034 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
/ /2015/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 4,244,780,923 719,875,460 544,311,157 2
Gas 3
4
TOTAL (Enter Total of lines 2 thru 4) 4,244,780,923 719,875,460 544,311,157 5
Nonutility 6
7
8
TOTAL Account 282 (Enter Total of lines 5 thru 8) 4,244,780,923 719,875,460 544,311,157 9
Classification of TOTAL 10
Federal Income Tax 3,767,325,446 617,035,002 465,523,833 11
State Income Tax 477,455,477 102,840,458 78,787,324 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
/ /2015/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of YearDebitsCreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 AccountCredited Amount DebitedAccount Amount
(e)(f)(h)(j)(k)(g)(i)
3. Use footnotes as required.
1
182.3 7,608,148 7,608,148 4,414,667,387 6,920,694182.3 1,242,855 2
3
4
7,608,148 7,608,148 4,414,667,387 6,920,694 1,242,855 5
6
7
8
7,608,148 7,608,148 4,414,667,387 6,920,694 1,242,855 9
10
6,742,731 6,742,731 3,913,838,011 5,612,702 614,098 11
865,417 865,417 500,829,376 1,307,992 628,757 12
13
FERC FORM NO. 1 (ED. 12-96)Page 275
NOTES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
PacifiCorp X
/ /2015/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
133,029,618 136,781,706 610,798,415Regulatory Assets 3
13,721,830 13,188,444 22,513,229Other 4
5
6
7
8
146,751,448 149,970,150 633,311,644TOTAL 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
146,751,448 149,970,150 633,311,644TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19
Classification of TOTAL 20
129,605,219 132,438,884 557,584,936Federal Income Tax 21
17,146,229 17,531,266 75,726,708State 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
/ /2015/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
639,634,358 26,274,301 33,146,353 46,119,436 14,163,529 3
17,892,378 14,089,080190, 283190, 283 8,183,117 8,064,405 18,057,833 4
5
6
7
8
657,526,736 40,363,381 41,329,470 54,183,841 32,221,362 9
10
11
12
13
14
15
16
17
18
657,526,736 40,363,381 41,329,470 54,183,841 32,221,362 19
20
578,903,244 35,428,550 36,438,407 47,755,038 28,260,538 21
78,623,492 4,934,831 4,891,063 6,428,803 3,960,824 22
23
FERC FORM NO. 1 (ED. 12-96)Page 277
NOTES (Continued)
Schedule Page: 276 Line No.: 3 Column: g
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Account 283, Accumulated deferred income taxes-other
Schedule Page: 276 Line No.: 3 Column: i
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Account 283, Accumulated deferred income taxes-other
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
/ /2015/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)
1,890,606 5,754,043 3,863,437DSM Balancing Account - WY 1
2,630,492 22,135,795 2,342,401 21,847,704Oregon Energy Conservation Charge 131,232 2
121,961 132,174 10,213Deferred Excess Net Power Costs - WA Hydro 3
300,002 358,557 58,555Deferred Excess RECs in Rates - OR 182.3 4
968,175 968,175Income Tax Reg. Liability - WA Flow Through 5
13,365,333 2,561,869 10,803,718 254Investment Tax Credit Regulatory Liability 190 6
968,851 968,8512014 Tax on Bonus Depreciation - WY 7
945,656 88,589 1,530,061 672,994Solar Feed-In Tariff Deferral - CA 440,442,444 8
10,116,877 3,479,769 13,835,120 7,198,012Solar Incentive Program - UT 9
104,972 143,401 33,376 71,805Renewable Portfolio Standards Compliance - OR (1)555 10
62,151 62,151Deferred Independent Evaluator Fee - UT (1)923 11
674,990 675,426 436Alternative Rate for Energy (CARE) - CA 440,442,444 12
2,496,697 1,330,986 1,264,950 99,239Utah Home Energy Lifeline 142 13
1,302,789 312,185 1,614,504 623,900Washington Low Income Program 142 14
368,684 572,602 203,918Schedule 94-Distribution Safety Surcharge - OR 182.3,923 15
6,025,257 11,797,468 5,772,2112013 FERC Rate True-up - OR 16
2,904,622 19,791,023 718,381 17,604,782Greenhouse Gas Allowance Revenues - CA 456,909,419 17
9,943,988 5,426,273 7,427,115 2,909,400Asset Retirement Obligations Reg. Difference 230 18
54,637 54,637BPA Balancing Account - WA 19
2,314,967 3,643,237 1,328,270BPA Balancing Account - ID 20
2,824,724 1,603,945 2,998,214 1,777,435Blue Sky - OR 440,442 21
346,504 320,068 206,954 180,518Blue Sky - WA 440,442 22
133,454 23,833 180,416 70,795Blue Sky - CA 440,442 23
3,163,064 1,560,852 4,589,446 2,987,234Blue Sky - UT 440,442 24
123,561 18,442 157,316 52,197Blue Sky - ID 440,442 25
351,243 70,499 484,045 203,301Blue Sky - WY 440,442 26
2,085,033 5,219,979 3,134,946Injuries & Damages Reserve - OR 27
1,036,454 8,105,022 7,068,568Property Insurance Reserve - OR 924 28
381,724 594 494,674 113,544Property Insurance Reserve - ID 924 29
3,473,648 1,338,050 4,287,834 2,152,236Property Insurance Reserve - UT 924 30
854,995 1,854,938 999,943Depreciation Deferral - OR 31
668,497 609,011 268,334 208,848Depreciation Deferral - WA (1)440,442,444 32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/3-Q (REV 02-04) Page 278
41 TOTAL 83,206,358 76,342,985 77,876,318 71,012,945
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.: 6 Column: a
Weighted average remaining life is 39 years.
Schedule Page: 278 Line No.: 9 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Account 445, Other sales to public authorities
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
/ /2015/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
1,732,822,429(440) Residential Sales 1,781,722,516 2
(442) Commercial and Industrial Sales 3
1,517,907,746Small (or Comm.) (See Instr. 4) 1,556,424,635 4
1,430,453,424Large (or Ind.) (See Instr. 4) 1,435,608,671 5
20,446,444(444) Public Street and Highway Lighting 19,942,747 6
17,499,523(445) Other Sales to Public Authorities 16,902,061 7
(446) Sales to Railroads and Railways 8
(448) Interdepartmental Sales 9
4,719,129,566TOTAL Sales to Ultimate Consumers 4,810,600,630 10
360,600,595(447) Sales for Resale 269,833,622 11
5,079,730,161TOTAL Sales of Electricity 5,080,434,252 12
(Less) (449.1) Provision for Rate Refunds 13
5,079,730,161TOTAL Revenues Net of Prov. for Refunds 5,080,434,252 14
Other Operating Revenues 15
9,670,249(450) Forfeited Discounts 9,141,277 16
5,956,286(451) Miscellaneous Service Revenues 5,531,248 17
(453) Sales of Water and Water Power 18
17,827,613(454) Rent from Electric Property 19,100,070 19
(455) Interdepartmental Rents 20
65,097,066(456) Other Electric Revenues 28,322,174 21
88,719,750(456.1) Revenues from Transmission of Electricity of Others 92,780,346 22
(457.1) Regional Control Service Revenues 23
(457.2) Miscellaneous Revenues 24
25
187,270,964TOTAL Other Operating Revenues 154,875,115 26
5,267,001,125TOTAL Electric Operating Revenues 5,235,309,367 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
/ /2015/Q4
Line
No.
MEGAWATT HOURS SOLD
Previous Year (no Quarterly)Current Year (no Quarterly)
AVG.NO. CUSTOMERS PER MONTH
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)
(d) (e) (f) (g)
6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by
the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of
classification in a footnote.)
7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
9. Include unmetered sales. Provide details of such Sales in a footnote.
1
15,567,753 1,545,529 1,574,480 15,565,510 2
3
17,073,151 200,454 201,691 17,261,893 4
21,933,602 33,373 33,305 21,402,658 5
143,147 3,534 3,496 140,686 6
281,624 3 3 270,465 7
8
9
54,999,277 1,782,893 1,812,975 54,641,212 10
10,270,247 8,889,451 11
65,269,524 1,782,893 1,812,975 63,530,663 12
13
65,269,524 1,782,893 1,812,975 63,530,663 14
Page 301
Line 12, column (b) includes $ of unbilled revenues.
Line 12, column (d) includes MWH relating to unbilled revenues
244,424,000
3,101,201
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, in
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, in
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:
2015 2014
Account service charges -
disconnects/reconnects/returned check charges $ 4,450,368 $ 4,450,910
Customer contract flat rate billings 1,038,530 1,464,397
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:
2015 2014
Amortization of California greenhouse gas
allowance revenue $ 11,212,184 $ 14,673,226
Energy exchange credits 10,083,346 9,010,784
Wind-based ancillary services 9,683,694 10,678,814
Flyash/by-product sales 5,099,321 4,998,296
Phase shifting equipment fee from
Western Electricity Coordinating Council 1,130,302 656,040
Revenue from generation interconnection and
transmission service request studies 1,077,939 1,162,487
Steam sales 665,336 988,645
Power sale and exchange agreements 550,096 685,320
Maintenance charges for work on transmission facilities 336,138 606,542
Service territory fixed cost recovery fee 317,733 302,725
Timber sales (a) 426,135
Net profit on sales of materials and supplies inventory (a) 381,251
Deferral of Oregon retail customers' allocated share of
the incremental Open Access Transmission Tariff
revenues associated with FERC Docket No. ER11-3643-000 (5,114,029) (3,442,129)
Renewable energy credit sales, including
amortization and deferrals (6,901,286) 23,779,972
(a) The 2015 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
2015/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
/ /2015/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
817 165 4,952 0.1128 92,168 5 06NETMT135 - RES NET MTR
297 321 925 0.2928 86,968 6 06OALT015R-OUTD AR LGT SR
157,531 17,178 9,171 0.1332 20,984,005 7 06RESD000D-RES SRVC
112,859 11,211 10,067 0.1336 15,078,172 8 06RESDDL06-CA LOW INCOME
1,254 473 2,651 0.2141 268,460 9 06RGNSV025-CA SMALL GEN
158 7 22,571 0.1067 16,863 10 06RESD0DM9 - MULTI FAMILY
1,079 16 67,438 0.0866 93,425 11 06RESD0DS8-MULT FAM SBMET
-1,648,508 12 REVENUE_ACCT ADJ
74,924 6,937 10,801 0.1358 10,174,117 13 06RESD00DN - RES SVC DEL NO
2 14 06UPPL000R-BASE SCH FALL
1,379,271 15 DSM REVENUE-RESIDENTIAL
21,569 16 BLUE SKY REV-RESIDENTIAL
37,806 17 SOLAR FEED-IN REVENUE
1,925 0.2410 464,000 18 UNBILLED REVENUE
19
20 IDAHO
1,139 21 07LNX00010-MNTHLY 80%GUAR
1,956 22 07LNX00035-ADV 80%MO GUAR
1,604 120 13,367 0.1029 164,990 23 07NETMT135 - ID RES NET MTR
10 1 10,000 0.3832 3,832 24 07OALCO007-CUST OWN LIGHT
95 121 785 0.4117 39,112 25 07OALT07AR-SECURITY AR LG
437,253 47,503 9,205 0.1138 49,768,610 26 07RESD0001-RES SRVC
212,070 12,933 16,398 0.0983 20,846,068 27 07RESD0036-RES SRVC-OPTIO
206 1 206,000 0.0784 16,149 28 07RGNSV06A-LRG GEN SVC-RES
7,747 966 8,020 0.1137 880,986 29 07RGNSV23A-SM GEN SVC-RES
14,000 30 UNBILLED REV - UNCOLLECTIBLE
-60,450 31 REVENUE_ACCT ADJ
-2,042 0.0597 -122,000 32 UNBILLED REVENUE
1,499,553 33 DSM REVENUE-RESIDENTIAL
-1 34 DSM REVENUE-RESIDENTIAL GEN
16,393 35 BLUE SKY REV-RESIDENTIAL
36
37 OREGON
1 38 01CHCK000R-RES CHECK MTR
4,829,655 0.0589 284,486,743 39 01COST0004 - 01RESD0004
89,533 0.0594 5,322,700 40 01COSTR023 RES GEN SRV CST
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
42,729 0.0595 2,542,845 1 01COSTR028, OR RES GEN SVC
-2 2 01FXRENEWR - FIXED
38,874 0.0580 2,253,154 3 01HABIT004 - 01RESD0004
134 0.0614 8,226 4 01HABTR023-RES GEN SVC HAB
9,948 5 01LNX00102-LINE EXT 80% G
5,092 6 01LNX00109-REF/NREF ADV +
291 7 01LNX00300 - LINE EXT 80% GTY
139 8 01LNX00311 - LINE EXT 80% GTY
3,168 1,391,147 9 01NETMT135-NET METERING
20 11,558 10 01NMTOU135-TOU NET METERING
2,269 2,589 876 0.1617 366,805 11 01OALTB15R-OUTD AR LGT RE
15,737 0.0608 956,381 12 01PTOU0004 - 01RESD0004
1 0.0570 57 13 01PTOU0005-01RESEV05T TOU
297,013 0.0571 16,953,462 14 01RENEW004 - 01RESD0004
397 0.0612 24,293 15 01RENWR023-RENEW USAGE
482,323 283,498,389 16 01RESD0004-RES SRVC
1,131 820,509 17 01RESD004T - RES TIME OPT
1 91 18 01RESEV05T-ELECT VEHICLE
16,571 6,920,652 19 01RGNSB023-SMALL GENERAL
200 1,267,262 20 01RGNSB028 -GEN SVC > 30 KW
39 112,272 21 01RNETM023-NET METER RES
3 22 01UPPL000R-BASE SCH FALL
418 330,789 23 01VIR04136-VOLUME INCENTIVE
45,857 24 OR GAIN ON SALE OF ASSET
-397,297 25 REVENUE ADJ - DEF NPC
-2,906,750 26 REVENUE_ACCT ADJ
1,729,825 27 SOLAR FEED-IN REVENUE
32,000 28 UNBILLED REV - UNCOLLECTIBLE
-15,748 0.0857 -1,350,000 29 UNBILLED REVENUE
12,392,225 30 DSM REVENUE-RESIDENTIAL
459,753 31 BLUE SKY REV-RESIDENTIAL
32
33 UTAH
-5 34 08BLSKY01R-BLUESKY ENERGY
838 35 08CFR00001-MTH FACILITY S
1 36 08CHCK000R-UT RES CHECK M
92,428 37 08COOLKPRR -COOL KEEPER
3,171 38 08LNX00001-MTHLY 80% GUAR
396 39 08LNX00005-MTHLY MIN GUAR
24,144 40 08LNX00013-80% MNTHLY MIN
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
2,288 1 08LNX00108-ANN COST MTHLY
11,456 8 1,432,000 0.0767 879,088 2 08MHTP0006-MOBILE HOME &
109 1 109,000 0.0945 10,296 3 08MHTP0023-MOBILE HOME &
23,815 4,479 5,317 0.1167 2,778,258 4 08NETMT135 - NET MTR
2,628 2,845 924 0.2856 750,468 5 08OALT007R-SECURITY AR LG
2 3 667 0.0655 131 6 08PTLD000R-POST TOP LIGHT
6,300,054 724,221 8,699 0.1109 698,573,018 7 08RESD0001-RES SRVC
3,063 381 8,039 0.1088 333,302 8 08RESD0002-RES SRVC-OPTIO
194,823 26,343 7,396 0.1089 21,217,627 9 08RESD0003-LIFELINE PRGRM
85,541 229 373,541 0.0780 6,671,742 10 08RGNSV006-GEN SRVC-RES
92,801 12,763 7,271 0.1126 10,448,106 11 08RGNSV023-GEN SRVC-RES
9,963 25 398,520 0.0850 847,321 12 08RGNSV06A-UT SM GEN SVC
31 1 31,000 0.0953 2,955 13 08RGNSV06B-UT SM GEN SVC
1,015 6 169,167 0.1073 108,868 14 08RNM06135 - UT NET MTR, GEN
243 40 6,075 0.1152 27,991 15 08RNM23135 - UT NET MTR, GEN
4 16 08UPPL000R-BASE SCH FALL
-3,226,427 17 REVENUE_ACCT ADJ
19,549,583 18 REVENUE ADJ - DEF NPC
1,308,320 19 SOLAR FEED-IN REVENUE
35,000 20 UNBILLED REV - UNCOLLECTIBLE
-9,705 0.0414 -402,000 21 UNBILLED REVENUE
26,999,960 22 DSM REVENUE-RESIDENTIAL
-3 23 DSM REVENUE-RES GEN SVC
1,240,358 24 BLUE SKY REV-RESIDENTIAL
25
26 WASHINGTON
1,844 27 02LNX00109-REF/NREF ADV +
3,549 276 12,859 0.0967 343,232 28 02NETMT135 - WA RES NET MTR
1,015 1,097 925 0.1503 152,536 29 02OALTB15R-WA OUTD AR LGT
1,419,849 99,506 14,269 0.0928 131,774,401 30 02RESD0016-WA RES SRVC
82,974 5,814 14,271 0.0919 7,621,617 31 02RESD0017-BILL ASSISTANCE
2,174 85 25,576 0.1020 221,685 32 02RESD0018-WA 3 PHASE RES
359 17 21,118 0.0995 35,707 33 02RESD018X-WA 3 PHASE RES
21,575 3,465 6,227 0.1162 2,507,732 34 02RGNSB024-WA SM GEN SVC
1 35 02UPPL000R-BASE SCH FALL
831,564 36 REVENUE ADJ - DEF NPC
-4,225,965 37 REVENUE_ACCT ADJ
-1,320,000 38 WASHINGTON - CHEHALIS DEF
1,000 39 UNBILLED REV - UNCOLLECTIBLE
11,250 0.1267 1,425,000 40 UNBILLED REVENUE
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
4,298,803 1 DSM REVENUE-RESIDENTIAL
250,373 2 BLUE SKY REV-RESIDENTIAL
3
4 WYOMING
768 5 05LNX00102-LINE EXT 80% G
1,379 136 10,140 0.1190 164,117 6 05NETMT135 - EXP PARTIALREQ
877 1,028 853 0.1480 129,812 7 05OALT015R-OUTD AR LGT SR
887,505 100,878 8,798 0.1101 97,749,577 8 05RESD0002-WY RES SRVC
9,142 1,419 6,443 0.1220 1,115,334 9 05RGNSV025-WY SM GEN SVC
132,736 10 REVENUE ADJ - DEF NPC
-244,928 11 REVENUE_ACCT ADJ
22,000 12 UNBILLED REV - UNCOLLECTIBLE
-14,570 0.1013 -1,476,000 13 UNBILLED REVENUE
1,515,434 14 DSM REVENUE-RESIDENTIAL
14,944 15 DSM REVENUE-RESIDENTIAL GEN
53,404 16 BLUE SKY REV-RESIDENTIAL
850 17 05LNX00109-REF/NREF ADV +
113,253 12,494 9,065 0.1120 12,681,404 18 05RESD0002-WY RES SRVC
396 127 3,118 0.1699 67,266 19 05RGNSV025- SM GEN SVC-RES
71 87 816 0.2731 19,388 20 09OALT207R-SECURITY AR LG
247 16 15,438 0.1171 28,928 21 05NETMT135 - EXP PARTIAL REQ
2 22 09RES00002
4 23 09RESD0002
245 0.1306 32,000 24 UNBILLED REVENUE
182,510 25 DSM REVENUE-RESIDENTIAL
282 26 DSM REVENUE-RES GEN SVC
19,349 27 BLUE SKY REV-RESIDENTIAL
28
-120,170 29 LESS MULTIPLE BILLINGS
30
15,565,510 1,574,480 9,886 0.1145 1,781,722,516 31 TOTAL RESIDENTIAL SALES
32
33 COMMERCIAL SALES
34 CALIFORNIA
51,820 6,433 8,055 0.1755 9,096,265 35 06GNSV0025-CA GEN SRVC
963 85 11,329 0.1916 184,475 36 06GNSV025F-GEN SRVC-< 20
78,934 1,038 76,044 0.1611 12,718,314 37 06GNSV0A32-GEN SRVC-20 KW
28,497 7 4,071,000 0.1064 3,031,059 38 06LGSV048T-LRG GEN SERV
2,525 1 2,525,000 0.1080 272,592 39 06NMT48135-CA GEN SVC NET
66,160 161 410,932 0.1365 9,028,658 40 06LGSV0A36-LRG GEN SRVC-O
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
5,791 1 06LNX00102-LINE EXT 80% GTY
4,128 2 06LNX00105-CNTRCT $ MIN G
87,569 3 06LNX00109-REF/NREF ADV +
862 4 06LNX00300 - 80% MTHLY MIN
15,219 5 06LNX00311 - LINE EXT 80% GTY
2,226 4 556,500 0.1406 312,999 6 06NMT36135-G SVC NT ->100
674 483 1,395 0.2947 198,653 7 06OALT015N-OUTD AR LGT SR
167 36 4,639 0.2323 38,786 8 06RCFL0042-AIRWAY & ATHLE
66 9 7,333 0.1770 11,680 9 06NMT25135-CA GEN SVC NET
605 10 60,500 0.1790 108,288 10 06NMT32135-CA GEN SVC NET
-1,129,356 11 REVENUE_ACCT ADJ
5,634 12 06LNX00110-REF/NREF ADV +
33,760 13 SOLAR FEED-IN REVENUE
2,623 0.1761 462,000 14 UNBILLED REVENUE
878,057 15 DSM REVENUE-COMMERCIAL
1,898 16 BLUE SKY REV-COMMERCIAL
17
18 IDAHO
4,760 97 49,072 0.0868 413,362 19 07CISH0019-COMM & IND SPA
223,044 978 228,061 0.0823 18,345,947 20 07GNSV0006-GEN SRVC-LRG P
43,868 2 21,934,000 0.0620 2,719,336 21 07GNSV0009-GEN SRVC-HI VO
141,692 6,453 21,958 0.0989 14,018,506 22 07GNSV0023-GEN SRVC-SML P
977 2 488,500 0.0630 61,548 23 07GNSV0035-GEN SRVCOPTION
24,328 179 135,911 0.0879 2,139,182 24 07GNSV006A-GEN SRVC-LRG P
24,446 1,243 19,667 0.0989 2,418,161 25 07GNSV023A-GEN SRVC-SML P
7 5 1,400 0.2687 1,881 26 07GNSV023F-GEN SRVC SML P
4,459 27 07LNX00010-MNTHLY 80%GUAR
223,961 28 07LNX00035-ADV 80%MO GUAR
52,383 29 07LNX00040-ADV+REFCHG+80%
262 175 1,497 0.3895 102,060 30 07OALT007N-SECURITY AR LG
10 11 909 0.4059 4,059 31 07OALT07AN-SECURITY AR LG
20,258 32 07LNX00312 - ID LINE EXT
1,786 4 446,500 0.0854 152,518 33 07NMT06135 - NET MTR - LG GEN
1,019 19 53,632 0.0883 89,989 34 07NMT23135 - NET MTR - SM GEN
332 35 07LNX00015-ANNUAL 80%GUAR
29,576 36 07LNX00311 - LINE EXT 80% GTY
8,144 37 07LNX00300 - 80% MTHLY MIN
-35,568 38 REVENUE_ACCT ADJ
-8,344 0.0779 -650,000 39 UNBILLED REVENUE
849,446 40 DSM REVENUE-COMMERCIAL
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
-6 1 DSM REVENUE-SMALL
1 1,784 2 BLUE SKY REV-COMMERCIAL
3
4 OREGON
981,016 0.0575 56,388,310 5 01COST0023, OR GEN SRV, COST
873,725 0.0484 42,284,798 6 01COST0048 - 01LGSV0048
2,939 0.0612 179,777 7 01COST023F - GEN SRV COST
22,721 0.0584 1,327,737 8 01COSTB023 - OR GEN SRV,
1,098,862 0.0513 56,360,170 9 01COSTL030 - OR LRG GEN SRV,
1,895,331 0.0596 112,972,531 10 01COSTS028, OR GEN SERV
2,830 1,570,484 11 01GNSB0023, OR GEN SRV BPA
293 1,960,233 12 01GNSB0028, OR GEN SRV BPA
56 30,153 13 01GNSB023T - OR GEN SRV TOU
55,480 52,891,072 14 01GNSV0023, GEN SRV < 30 KW
8,831 57,075,020 15 01GNSV0028, GEN SRV > 30 KW
10,258 773 13,270 0.1582 1,623,141 16 01GNSV023F - GEN SRV - FLAT RA
249 2 124,500 0.0877 21,839 17 01GNSV023M - GEN SRV, MANUAL
204 169,450 18 01GNSV023T, OR GEN SRV, TOU
2,443 0.0588 143,529 19 01HABT0023, OR HABITAT BLEND
24 0.0615 1,475 20 01HABTB023 - OR HABITAT BLEND
21 966,358 21 01LGSB0030, GEN DEL SRV, > 200
621 28,856,674 22 01LGSV0030 - LG GEN SRV > 1000
90 16,069,546 23 01LGSV0048-1000KW AND OVR
60,396 1 60,396,000 0.0617 3,723,758 24 01LGSV048M-LRG GEN SRVC 1
3,796 25 01LNX00100-LINE EXT 60% G
468,700 26 01LNX00102-LINE EXT 80% G
-430 27 01LNX00103-LINE EXT 80% G
14,561 28 01LNX00105-CNTRCT $ MIN G
1,060,206 29 01LNX00109-REF/NREF ADV +
12,798 30 01LNX00110-REF/NREF ADV +
154,027 31 01LNX00311 - LINE EXT 80% GTY
24,548 32 01LNX00120 - LINE EXT 60% GTY
184,844 33 01LNX00300 - LINE EXT 80% GTY
48,934 5 9,786,800 0.0956 4,676,673 34 01LPRS047M-PART REQ SRVC
256 222,257 35 01NMT23135 - NET MTR GEN < 30
131 1,035,762 36 01NMT28135 - NET MTR GEN > 30
22 1,054,653 37 01NMT30135 -NET MTR GEN > 200
4 410,744 38 01NMT48135-NET MTR GEN SVC =
5,546 2,863 1,937 0.1470 815,303 39 01OALT015N-OUTD AR LGT NR
1,477 1,076 1,373 0.1666 246,067 40 01OALTB15N-OUTD AR LGT NR
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
3,007 0.0581 174,669 1 01PTOU0023, OR GEN SRV, TOU
460 0.0604 27,768 2 01PTOUB023, OR GEN SRV, TOU
1,453 107 13,579 0.0984 142,946 3 01RCFL0054-REC FIELD LGT
8,183 0.0585 478,465 4 01RENW0023, OR RENW USAGE
115 0.0587 6,752 5 01RENWB023 - OR RENEWABLE
3,129 0.0560 175,271 6 01STDAY023 - DAY STD OFR SCH
13,194 0.0577 761,270 7 01STDAY028 - DAY STD OFF SCH
4,688 0.0506 237,075 8 01STDAY030 - STD DAY OFF SCH
94 147,037 9 01VIR23136-VOL INC <=30KW
91 605,647 10 01VIR28136-VOL INC >30KW
6 248,895 11 01VIR30136-VOL INC >200KW
1 127,899 12 01VIR48136-VOL INC >1000KW
1 82,843 13 01LGSB0048 - LG GSVC > 1000
509 1 509,000 0.0896 45,588 14 01LGSV028M - LGSV, <1000 kW, M
11 193,906 15 01GNSV0728 - GEN SVC DIR ACC
17 2,137,821 16 01GNSV0730 -GEN SVC DIR ACC
4 3,277,155 17 01GNSV0748 LG GEN SVC DIR
41,184 18 OR GAIN ON SALE OF ASSET
-298,611 19 REVENUE ADJ - DEF NPC
-2,503,161 20 REVENUE_ACCT ADJ
1,457,402 21 SOLAR FEED-IN REVENUE
9,410 0.0510 480,000 22 UNBILLED REVENUE
8,337,870 23 DSM REVENUE-COMMERCIAL
101 665,521 24 BLUE SKY REV-COMMERCIAL
25
26 UTAH
7,319 27 08ABL-NRES - APPLICANT BUILT
38,938 28 08CFR00051-MTH FAC SRVCHG
2 29 08CFR00052-ANN FAC SVCCHG
2,490 30 08COOLKPRN - A/C DIRECT LOAD
4,972,703 11,039 450,467 0.0842 418,768,050 31 08GNSV0006-GEN SRVC-DISTR
816,550 28 29,162,500 0.0568 46,401,551 32 08GNSV0009-GEN SRVC-HI VO
1,200,155 68,359 17,557 0.1001 120,139,584 33 08GNSV0023-GEN SRVC-DISTR
259,386 2,107 123,107 0.1187 30,790,016 34 08GNSV006A-GEN SRVC-ENERG
4,586 35 131,029 0.1096 502,414 35 08GNSV006B-GEN SRVC-DEM&
5,298 6 883,000 0.0694 367,767 36 08GNSV006M-MNL DIST VOLTG
25,073 2 12,536,500 0.0676 1,694,891 37 08GNSV009A-GEN SRVC HI VO
1,302 128 10,172 0.1444 188,034 38 08GNSV023F-GEN SRVC FIXED
105 4 26,250 0.0954 10,012 39 08GNSV023M-GNSV DIST VOLT
346 1 346,000 0.1121 38,772 40 08GNSV06AM-MNL ENERGY TOD
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
38,748 599 64,688 0.0772 2,992,465 1 08GNSV06MN-GNSV DIST VOLT
266,853 2 08LNX00002-MTHLY 80% GUAR
30,322 3 08LNX00004-ANNUAL 80%GUAR
3,518 4 08LNX00006-FIXD MTHLY MIN
-13,225 5 08LNX00008-ANNUALMIN GUAR
1,487,683 6 08LNX00014-80% MIN MNTHLY
140,416 7 08LNX00017-ADV/REF&80%ANN
32,125 8 08LNX00158-ANNUALCOST MTH
125,689 9 08LNX00300 - LINE EXT 80% PLUS
40,766 10 08LNX00310 - IRR 80% ANN MIN
5,426 11 08LNX00312 UT IRG LINE EXT
76,343 156 489,378 0.0876 6,684,427 12 08NMT06135-NET MTR GEN SV
60,428 7 8,632,571 0.0704 4,254,024 13 08NMT08135 -NET MTR GEN SVC
4,228 279 15,154 0.1070 452,354 14 08NMT23135 - UT NET MTR, GEN
2,518 19 132,526 0.1264 318,243 15 08NMT6A135-NET MTR GEN SVC T
7,936 4,199 1,890 0.2327 1,846,662 16 08OALT007N-SECURITY AR LG
2 226 17 08POLE0075-POLES W/LIGHT
48,403 4 12,100,750 0.0707 3,422,745 18 08PRSV031M-BKUP MNT&SUPPL
6 2 3,000 0.0757 454 19 08PTLD000N-POST TOP LIGHT
171 20 8,550 0.0933 15,948 20 08TOSS015F-TRAFFIC SIG NM
2,580 920 2,804 0.1077 277,989 21 08TOSS0015-TRAF & OTHER S
17,436 472 36,941 0.0708 1,234,321 22 08MONL0015-MTR OUTDONIGHT
-2,461,536 23 REVENUE_ACCT ADJ
20,304,110 24 REVENUE ADJ - DEF NPC
909,627 25 SOLAR FEED-IN REVENUE
285,206 26 08LNX00311 - LINE EXT 80% GTY
936,151 135 6,934,452 0.0747 69,959,661 27 08GNSV0008 -GEN SVC TOU
25,456 4 6,364,000 0.0789 2,007,322 28 08GNSV008M -GEN SVC TOU
22,744 0.0634 1,443,000 29 UNBILLED REVENUE
26,097,272 30 DSM REVENUE-COMMERCIAL
-1,166 31 DSM REVENUE-SMALL
241,224 32 BLUE SKY REV-COMMERCIAL
33
34 WASHINGTON
28,750 1,469 19,571 0.0954 2,741,664 35 02GNSB0024-WA GEN SRVC DO
154 6 25,667 0.1270 19,561 36 02GNSB024F-GEN SRVC DOM/F
291 81 3,593 0.3479 101,226 37 02GNSB24FP-WA GEN SVC
473,916 13,654 34,709 0.0912 43,218,596 38 02GNSV0024-WA GEN SRVC
1,099 109 10,083 0.1364 149,870 39 02GNSV024F-WA GEN SRVC-FL
60,856 103 590,835 0.0806 4,907,262 40 02LGSB0036-LRG GEN SVC IRG
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
776,739 874 888,717 0.0782 60,716,930 1 02LGSV0036-WA LRG GEN SRV
194,218 34 5,712,294 0.0710 13,786,152 2 02LGSV048T-LRG GEN SRVC 1
28,755 3 02LNX00102-LINE EXT 80% G
20 4 02LNX00103-LINE EXT 80% G
1,726 5 02LNX00105-CNTRCT $ MIN G
244,743 6 02LNX00109-REF/NREF ADV +
38,999 7 02LNX00110-REF/NREF ADV +
669 8 02LNX00112-YR INCURRED CH
7,699 9 02LNX00300-LINE EXT 80% G
983 10 02LNX00310 - IRG, 80% ANNUAL
59,787 11 02LNX00311 - LINE EXT 80% GTY
3,818 12 02LNX00312 - WA IRG LINE EXT
1,510 799 1,890 0.1401 211,625 13 02OALT015N-WA OUTD AR LGT
537 485 1,107 0.1531 82,212 14 02OALTB15N-WA OUTD AR LGT
263 29 9,069 0.0919 24,168 15 02RCFL0054-WA REC FIELD L
1,937 42 46,119 0.0895 173,345 16 02NMT24135, NET MTR, WA
5,399 8 674,875 0.0828 446,767 17 02NMT36135-NET METER LG SVC
6,974 1 6,974,000 0.0704 490,955 18 02NMT48135-WA LG SVC NET
793,685 19 REVENUE ADJ - DEF NPC
-3,939,277 20 REVENUE_ACCT ADJ
-1,020,000 21 WASHINGTON - CHEHALIS DEF
9,607 0.1060 1,018,000 22 UNBILLED REVENUE
3,997,645 23 DSM REVENUE-COMMERCIAL
5 68,831 24 BLUE SKY REV-COMMERCIAL
25
26 WYOMING
1 27 05CHCK000N-WY NRES CHECK
227,110 17,546 12,944 0.0992 22,538,106 28 05GNSV0025-WY GEN SRVC
891,781 3,360 265,411 0.0864 77,064,076 29 05GNSV0028-GEN SVC > 15 KW
1,011 179 5,648 0.1609 162,647 30 05GNSV025F-GEN SRVC-FL RA
158,332 18 8,796,222 0.0756 11,962,592 31 05LGSV0046-WY LRG GEN SRV
12,362 1 12,362,000 0.0778 961,948 32 05LGSV048T-LRG GENSRV TIM
342 33 05LNX00100-LINE EXT 60% G
662,980 34 05LNX00102-LINE EXT 80% G
1,857 35 05LNX00103-LINE EXT 80% G
5,417 36 05LNX00105-CNTRCT $ MIN G
595,567 37 05LNX00109-REF/NREF ADV +
6,321 38 05LNX00110-REF/NREF ADV +
1,401 39 05LNX00114-TEMP SVC 12MO>
213 24 8,875 0.1071 22,817 40 05NMT25135 - NET MTR, GEN
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
6,411 18 356,167 0.0645 413,693 1 05NMT28135-NET MTR SM GEN
2,698 1,654 1,631 0.1493 402,922 2 05OALT015N-OUTD AR LGT SR
803 54 14,870 0.0767 61,615 3 05RCFL0054-WY REC FIELD L
77,935 4 05LNX00300 - LINE EXT 80% GTY
85,546 5 05LNX00311 - LINE EXT 80% GTY
5,094 6 05LNX00312 - WY IRG LINE EXT
190,004 7 REVENUE ADJ - DEF NPC
-314,963 8 REVENUE_ACCT ADJ
4,726 0.0992 469,000 9 UNBILLED REVENUE
1,409,918 10 DSM REVENUE-SMALL
65,920 11 DSM REVENUE-LARGE
3,289 12 BLUE SKY REV-COMMERCIAL
31,090 2,356 13,196 0.0989 3,076,186 13 05GNSV0025-WY GEN SRVC
92,873 395 235,122 0.0866 8,038,500 14 05GNSV0028-GEN SVC > 15 KW
199 33 6,030 0.1277 25,404 15 05GNSV025F-GEN SRVC-FL RA
2,063 16 05LNX00102-LINE EXT 80% G
215,111 17 05LNX00109-REF/NREF ADV +
1,806 18 05LNX00110-REF/NREF ADV +
488 19 05LNX00114-TEMP SVC 12MO>
27 3 9,000 0.0850 2,294 20 05NMT25135 - WY NET MTR, GEN
515 3 171,667 0.0719 37,019 21 05NMT28135-NET MTR SM GEN
273 137 1,993 0.2374 64,804 22 09OALT207N-SECURITY AR LG
368 11 33,455 0.0626 23,021 23 09MONL0213-WY MTR OUTDOOR
7,815 24 05LNX00300 - LINE EXT 80%
6,076 25 05LNX00311 - LINE EXT 80%
-985 0.0924 -91,000 26 UNBILLED REVENUE
39,922 27 DSM REVENUE-SMALL
740 28 BLUE SKY REV-COMMERCIAL
29
-24,247 30 LESS MULTIPLE BILLINGS
31
17,261,893 201,691 85,586 0.0902 1,556,424,635 32 TOTAL COMMERCIAL SALES
33
34 INDUSTRIAL SALES
35 CALIFORNIA
642 90 7,133 0.1802 115,692 36 06GNSV0025-CA GEN SRVC
2,709 21 129,000 0.1695 459,045 37 06GNSV0A32-GEN SRVC-20 KW
49,537 9 5,504,111 0.1112 5,510,842 38 06LGSV048T-LRG GEN SERV
4,825 12 402,083 0.1465 706,647 39 06LGSV0A36-LRG GEN SRVC-O
-212,425 40 REVENUE_ACCT ADJ
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
6,435 1 SOLAR FEED-IN REVENUE
-370 0.0135 -5,000 2 UNBILLED REVENUE
163,191 3 DSM REVENUE-INDUSTRIAL
19 4 BLUE SKY REV-INDUSTRIAL
5
6 IDAHO
2,217 7 07CFR00001-MTH FACILITY S
44 2 22,000 0.0963 4,237 8 07CISH0019-COMM & IND SPA
93,755 107 876,215 0.0719 6,743,535 9 07GNSV0006-GEN SRVC-LRG P
80,119 16 5,007,438 0.0639 5,117,244 10 07GNSV0009-GEN SRVC-HI VO
12,511 319 39,219 0.0955 1,194,663 11 07GNSV0023-GEN SRVC-SML P
935 1 935,000 0.0693 64,824 12 07GNSV0035-GEN SRVCOPTION
3,337 22 151,682 0.0831 277,364 13 07GNSV006A-GEN SRVC LG P
2,027 147 13,789 0.1040 210,865 14 07GNSV023A-GEN SRVC-SML P
5 1 5,000 0.1298 649 15 07GNSV023S-IDAHO TRAFFIC
4,113 16 07LNX00010-MNTHLY 80%GUAR
1,996 17 07LNX00108-ANN COST MTHLY
13 16 813 0.3873 5,035 18 07OALT007N-SECURITY AR LG
1 238 19 07OALT07AN-SECURITY AR LG
1,456,100 1 1,456,100,000 0.0642 93,499,403 20 07SPCL0001
115,559 1 115,559,000 0.0619 7,156,495 21 07SPCL0002
-12,517 22 REVENUE_ACCT ADJ
-45,553 0.0453 -2,062,000 23 UNBILLED REVENUE
285,972 24 DSM REVENUE-INDUSTRIAL
25
26 OREGON
19,006 0.0575 1,093,503 27 01COST0023, GEN SRV CST BSD
1,696,132 0.0479 81,316,696 28 01COST0048 - 01LGSV0048
1 0.0630 63 29 01COST023F - GEN SRV CST-BSD
271 0.0534 14,482 30 01COSTB023 - GEN SRV, CST-BSD
213,245 0.0514 10,970,134 31 01COSTL030 - LRG GEN SRV, CST
89,486 0.0595 5,322,250 32 01COSTS028, OR GEN SERV
14 15,813 33 01GNSB0023, OR GEN SRV, BPA
1 3,447 34 01GNSB0028, OR GEN SRV, BPA
1,014 1,071,537 35 01GNSV0023, OR GEN SRV, < 30
445 3,508,181 36 01GNSV0028, OR GEN SRV > 30
2 2 1,000 0.3260 652 37 01GNSV023F - GEN SRV - FLT
19 1 19,000 0.1178 2,239 38 01GNSV023M - OR GEN SRV
3 2,484 39 01GNSV023T, GEN SRV, TOU OPT
1 45,076 40 01GNSV0730 -GEN SVC DIR
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
3 1,784,307 1 01GNSV0748 LG GEN SVC DIR
146 7,952,909 2 01LGSV0030 - LG G SRV > 1000
86 29,430,856 3 01LGSV0048-1000KW AND OVR
76,782 3 25,594,000 0.0781 5,997,485 4 01LGSV048M-LRG GEN SRVC 1
53,545 5 01LNX00102-LINE EXT 80% G
6,156 6 01LNX00109-REF/NREF ADV +
21,298 7 01LNX00300 - LINE EXT 80% GTY
18,999 2 9,499,500 0.1136 2,158,568 8 01LPRS047M-PART REQ SRVC
3 1,671 9 01NMT23135 - NET MTR GEN < 30
5 43,729 10 01NMT28135 - NET MTR GEN > 30
1 46,862 11 01NMT30135 - NET MTR GEN > 200
289 127 2,276 0.1431 41,350 12 01OALT015N-OUTD AR LGT NR
4 4 1,000 0.1363 545 13 01OALTB15N-OR OUTD AR LGT
34 0.0646 2,198 14 01PTOU0023, GEN SRV, TOU ENG
83 0.0558 4,631 15 01RENW0023, RENW USAGE SPLY
233 0.0591 13,765 16 01STDAY028 - DAY STD OFF SCH
1,913 0.0464 88,804 17 01STDAY030 - STD DAY OFF SCH
1 931 18 01VIR23136-VOL INC <=30KW
2 4,686 19 01VIR28136-VOL INC >30 KW
1 36,569 20 01VIR30136-VOL INC >200KW
28,463 21 OR GAIN ON SALE OF ASSET
-98,687 22 REVENUE ADJ - DEF NPC
-1,691,150 23 REVENUE_ACCT ADJ
967,544 24 SOLAR FEED-IN REVENUE
5,023 0.0892 448,000 25 UNBILLED REVENUE
760,093 26 DSM REVENUE-INDUSTRIAL
34 465,699 27 BLUE SKY REV-INDUSTRIAL
28
29 UTAH
18,725 30 08CFR00051-MTH FAC SRVCHG
1,700 2 850,000 0.1109 188,561 31 08EFOP0021-ELEC FURNACE O
976 3 325,333 0.1569 153,097 32 08EFOP021M-ELEC FURNACE O
655,316 1,078 607,900 0.0877 57,457,754 33 08GNSV0006-GEN SRVC-DISTR
3,286,865 114 28,832,149 0.0557 182,968,734 34 08GNSV0009-GEN SRVC-HI VO
53,605 3,332 16,088 0.1019 5,459,776 35 08GNSV0023-GEN SRVC-DISTR
63,064 258 244,434 0.1186 7,480,089 36 08GNSV006A-GEN SRVC-ENERG
221 1 221,000 0.0974 21,530 37 08GNSV006B-GEN SRVC-DEM&
15,585 6 2,597,500 0.0900 1,403,212 38 08GNSV009A-GEN SRVC HI VO
495,488 10 49,548,800 0.0554 27,448,075 39 08GNSV009M-MANL HIGH VOLT
4 1 4,000 0.6430 2,572 40 08GNSV023F-GEN SRVC FIXED
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
1,231 23 53,522 0.0862 106,067 1 08GNSV06MN-GNSV DIST VOLT
1,171 1 1,171,000 0.1189 139,288 2 08GNSV09AM-MAN TOD HIVOLT
565,912 3 08LNX00002-MTHLY 80% GUAR
9,731 4 08LNX00014-80% MIN MNTHLY
2,016 5 08LNX00311 - LINE EXT 80% GTY
44,988 6 08LNX00300 - LINE EXT 80% PLUS
8,942 7 08LNX00310 - IRR 80% ANN MIN
1,181 447 2,642 0.2150 253,942 8 08OALT007N-SECURITY AR LG
8 9 889 0.1638 1,310 9 08TOSS0015-TRAF & OTHER S
14 7 2,000 0.2073 2,902 10 08MONL0015-MTR OUTDONIGHT
2,802 7 400,286 0.1119 313,425 11 08NMT06135-NET MTR GEN SV
240 11 21,818 0.0943 22,635 12 08NMT23135 -NET MTR G <25
3,589 8 448,625 0.1297 465,460 13 08NMT6A135-NET MTR GEN SVC T
4,775 1 4,775,000 0.1497 714,887 14 08PRSV031M-BKUP MNT&SUPPL
571,512 1 571,512,000 0.0499 28,502,759 15 08SPCL0001
962,388 1 962,388,000 0.0458 44,043,605 16 08SPCL0002
1,163,268 1 1,163,268,000 0.0474 55,169,764 17 08SPCL0003
-2,652,805 18 REVENUE_ACCT ADJ
12,544,010 19 REVENUE ADJ - DEF NPC
269 2 134,500 0.1277 34,348 20 08GNSV06AM-MNL ENERGY TOD
964,487 99 9,742,293 0.0758 73,140,060 21 08GNSV0008 - GEN SVC TOU
60,925 7 8,703,571 0.0759 4,626,756 22 08GNSV008M - GEN SVC TOU
1,134,451 23 SOLAR FEED-IN REVENUE
13,332 0.0974 1,299,000 24 UNBILLED REVENUE
13,334,672 25 DSM REVENUE-INDUSTRIAL
-3,095 26 DSM REVENUE-SMALL
7 61,442 27 BLUE SKY REV-INDUSTRIAL
28
29 WASHINGTON
1,233 48 25,688 0.1045 128,835 30 02GNSB0024-WA GEN SRVC DO
4 1 4,000 0.4353 1,741 31 02GNSB24FP-WA GEN SVC
16,067 336 47,818 0.0921 1,479,221 32 02GNSV0024-WA GEN SRVC
33 4 8,250 0.2546 8,401 33 02GNSV024F-WA GEN SRVC-FL
102,598 101 1,015,822 0.0809 8,298,368 34 02LGSV0036-WA LRG GEN SRV
665,108 31 21,455,097 0.0630 41,928,936 35 02LGSV048T-LRG GEN SRVC 1
106 39 2,718 0.1303 13,814 36 02OALT015N-WA OUTD AR LGT
26 14 1,857 0.1508 3,921 37 02OALTB15N-WA OUTD AR LGT
2,386 1 2,386,000 0.1393 332,339 38 02PRSV47TM-LRG PART REQMT
1,836 11 166,909 0.1168 214,506 39 02LGSB0036-LRG GEN SVC IRG
428,559 40 REVENUE ADJ - DEF NPC
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
-1,601,642 1 REVENUE_ACCT ADJ
-510,000 2 WASHINGTON - CHEHALIS DEF
4,777 0.1063 508,000 3 UNBILLED REVENUE
1,626,843 4 DSM REVENUE-INDUSTRIAL
5
6 WYOMING
27,017 1,165 23,191 0.0898 2,426,201 7 05GNSV0025-WY GEN SRVC
267,032 483 552,861 0.0753 20,094,302 8 05GNSV0028-GEN SVC > 15 KW
26 8 3,250 0.1655 4,302 9 05GNSV025F-GEN SRVC-FL RA
1,679,461 58 28,956,224 0.0680 114,155,865 10 05LGSV0046-WY LRG GEN SRV
12,283 1 12,283,000 0.0711 873,310 11 05LGSV046M-WY LRG GEN SRV
298,416 1 298,416,000 0.0573 17,096,596 12 05LGSV048M-TOU>1000KW MAN
1,682,423 11 152,947,545 0.0591 99,360,650 13 05LGSV048T-LRG GENSRV TIM
46,228 14 05LNX00100-LINE EXT 60% G
1,011,109 15 05LNX00102-LINE EXT 80% G
7,266 16 05LNX00103-LINE EXT 80% G
40,585 17 05LNX00105-CNTRCT $ MIN G
337,944 18 05LNX00109-REF/NREF ADV +
263 19 05LNX00110-REF/NREF ADV +
24,537 20 05LNX00300 - LINE EXT 80%
32,249 21 05LNX00311 - LINE EXT 80%
80 40 2,000 0.1345 10,763 22 05OALT015N-OUTD AR LGT SR
1,220,084 8 152,510,500 0.0691 84,334,311 23 05PRSV033M-PART SERV REQ
890,567 24 REVENUE ADJ - DEF NPC
-1,216,183 25 REVENUE_ACCT ADJ
-14,881 0.0390 -581,000 26 UNBILLED REVENUE
346,413 27 DSM REVENUE-SMALL
1,654,360 28 DSM REVENUE-LARGE
-5,656 29 BLUE SKY REV-INDUSTRIAL
3,837 290 13,231 0.0996 382,103 30 05GNSV0025-WY GEN SRVC
54,750 75 730,000 0.0757 4,145,832 31 05GNSV0028-GEN SVC > 15 KW
4,106 3 1,368,667 0.0626 257,029 32 05GNSV028M-GEN SVC > 15 KW
45,268 4 11,317,000 0.0735 3,329,116 33 05LGSV0046-WY LRG GEN SRV
221,775 4 55,443,750 0.0601 13,320,751 34 05LGSV048M-TOU>1000KW MAN
1,273,793 12 106,149,417 0.0622 79,202,675 35 05LGSV048T-LRG GENSRV TIM
47,889 36 05LNX00102-LINE EXT 80% G
2,224,768 37 05LNX00109-REF/NREF ADV +
1,915 38 05LNX00300 - LINE EXT 80%
94,170 2 47,085,000 0.0645 6,078,162 39 05PRSV033M-PART SERV REQ
5 3 1,667 0.1972 986 40 09OALT207N-SECURITY AR LG
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
-3,008 0.0701 -211,000 1 UNBILLED REVENUE
19,326 2 DSM REVENUE-SMALL
408,691 3 DSM REVENUE-LARGE
14 4 BLUE SKY REV-INDUSTRIAL
5
-945 6 LESS MULTIPLE BILLINGS
7
19,882,544 9,911 2,006,109 0.0649 1,290,679,841 8 TOTAL INDUSTRIAL SALES
9
10 IRRIGATION SALES
11 CALIFORNIA
11,967 769 15,562 0.1424 1,704,024 12 06APSV0020-AG PMP SRVC
56,843 602 94,424 0.1494 8,493,671 13 06APSV020L-AG PMP SRVC-NO
976 1 976,000 0.1400 136,687 14 06LGSV048T-LRG GEN SERV
2,363 15 06LNX00103-LINE EXT 80% G
505 16 06LNX00109-REF/NREF ADV +
24,769 17 06LNX00110-REF/NREF ADV +
2,439 18 06LNX00310-80% ANN MIN + 80%
12,053 19 06LNX00312 - CA IRG LINE EXT
343 7 49,000 0.2152 73,809 20 06NML20135-AGRI PUMP-NET MTR
56 1 56,000 0.1740 9,746 21 06NMT20135-AGRI PUMP-NET
3,047 278 10,960 0.1759 535,953 22 06USBR0020-KLAM IRG ONPRJ
19,832 373 53,169 0.1652 3,276,173 23 06USBR020L-KLAM IRG PRJ-NO
10,106 24 SOLAR FEED-IN REVENUE
12 0.2500 3,000 25 UNBILLED REVENUE
335,180 26 DSM REVENUE-IRRIGATION
23 27 BLUE SKY REV-IRRIGATION
-434,910 28 REVENUE_ACCT ADJ
29
30 IDAHO
381,201 2,690 141,710 0.0936 35,666,439 31 07APSA010L - IRG & PUMP LG
4,928 351 14,040 0.1130 556,937 32 07APSA010S - IRG & PUMP SM
188,997 1,451 130,253 0.0928 17,534,870 33 07APSAL10X - IRG & PUMP - LG
6,474 396 16,348 0.1076 696,420 34 07APSAS10X - IRG & PUMP - SM
1,751 2 875,500 0.0792 138,724 35 07APSV006A-LRG POWER OPT
477 4 119,250 0.0981 46,794 36 07APSV023A-SM POWER OPT S
19,779 46 429,978 0.0827 1,636,272 37 07APSVCNLL-LG LOAD CANAL
38 12 3,167 0.1559 5,926 38 07APSVCNLS-SM LOAD CANAL
445 39 07LNX00015-ANNUAL 80%GUAR
1,516 40 07LNX00035-ADV 80%MO GUAR
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
159,528 1 07LNX00040-ADV+REFCHG+80%
1,485 2 07LNX00310 80% ANNUAL GTY
1,648 3 07LNX00311 - LINE EXT 80% GTY
55,276 4 07LNX00312 - ID LINE EXT
3,033 30 101,100 0.0991 300,569 5 07APSN010L - ID LG IRR & PUMP
200 5 40,000 0.0998 19,954 6 07APSN010S - IRRIGATION SM
213 15 14,200 0.1134 24,160 7 07APSNS10X - IRRIGATION SM
-43,506 8 REVENUE_ACCT ADJ
-3 1.6667 -5,000 9 UNBILLED REVENUE
1,190,211 10 DSM REVENUE-IRRIGATION
3 74 11 BLUE SKY REV-IRRIGATION
12
13 OREGON
3,137 1,874,099 14 01APSV0041-AG PMP SRVC
6 22,972 15 01APSV0215-OR IRR TOU PILO
837 3,019,301 16 01APSV041L-PUMP SERV >30KW
60 31,759 17 01APSV041T - AGR PUMP SRV
1,812 958,622 18 01APSV041X-AG PMP SRVC
322 1,542,226 19 01APSV41XL-OR Pumping Serv
149,477 0.0582 8,704,806 20 01COST0041 -01APSV0041
127,359 0.0491 6,251,514 21 01COST0048 - 01LGSV0048
6,975 0.0411 286,371 22 01COST0215-OR TOU PILOT COST
612 0.0595 36,407 23 01COSTS028 G SERV CST > 30
69,254 0.0582 4,032,271 24 01CSTUSB41-USBR IRR CONTRA
1 7,780 25 01GNSB0028-OR GENL SVC > 30
2 16,794 26 01GNSV0028, OR GEN SRV > 30
9 0.0562 506 27 01HABIT041 - 01APSV0041 AG
3 1,184,487 28 01LGSB0048 - LG GEN SVC > 1000
1 29 01LGSV0030-3P,DEMAND,VAR,SE
3 1,477,323 30 01LGSV0048-1000KW AND OVR
42,167 31 01LNX00103-LINE EXT 80% G
200,360 32 01LNX00110-REF/NREF ADV +
16,341 33 01LNX00310-LINE EXTENSION
609 0.0575 35,027 34 01PTOU0041 - 01APSV0041 AG
182 0.0581 10,576 35 01RENEW041 - 01APSV0041 AG
158 0.0604 9,539 36 01STDAY041 - DAILY STD OFFER
54 239,708 37 01USBR0215-OR IRG TOU PILOT
9 36,513 38 01USBRGV41-IRG TOU W/O BPA
511 1,574,072 39 01USBROF41-KLAMATH BASIN
-15 1,176 -13 -106.4193 1,596,289 40 01USBRON41-KLAMATH BASIN
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
17 45,393 1 01VIR41136-OR VOLUME INC
87 310,208 2 01VRU41136-VOL INC USB
7 59,367 3 01VRU41215-VOL INC USB TOU
34,420 4 SOLAR FEED-IN REVENUE
188 0.0426 8,000 5 UNBILLED REVENUE
522,065 6 DSM REVENUE-IRRIGATION
414 7 BLUE SKY REV-IRRIGATION
28,896 8 01LNX00312 - OR IRG LINE EXT
9 6,706 9 01NMT41135 - NETMTR AG PMP
1 6,764 10 01NMT41215-NET MTR APSV TOU
6 30,447 11 01NMU41135 -NET MTR <PRJ
-49 12 01NMU41215-IRG TOU PILOT
2,148 13 OR GAIN ON SALE OF ASSET
1,466 14 REVENUE ADJ - DEF NPC
-93,583 15 REVENUE_ACCT ADJ
16
17 UTAH
206,918 2,886 71,697 0.0764 15,804,068 18 08APSV0010-IRR & SOIL DRA
35,060 226 155,133 0.0709 2,484,994 19 08APSV10NS- LG SOIL DRAIN
4,179 20 08LNX00004-ANNUAL 80%GUAR
16,940 21 08LNX00014-80% MIN MNTHLY
196,401 22 08LNX00017-ADV/REF&80%ANN
9,462 23 08LNX00310 - IRR, 80% ANN MIN
356 24 08LNX00311 - LINE EXT 80% GTY
24,443 25 08LNX00312 UT IRG LINE EXT
1,392 14 99,429 0.0821 114,287 26 08NMT10135-UT IRR_SOIL DRNG
-66,570 27 REVENUE_ACCT ADJ
26,511 28 SOLAR FEED-IN REVENUE
-21 -0.1429 3,000 29 UNBILLED REVENUE
688,421 30 DSM REVENUE-IRRIGATION
31
32 WASHINGTON
141,779 3,364 42,146 0.0850 12,053,742 33 02APSV0040-WA AG PMP SRVC
56,949 1,835 31,035 0.0861 4,901,310 34 02APSV040X-WA AG PMP SRVC
6,190 35 02LNX00103-LINE EXT 80% G
86 36 02LNX00105-CNTRCT $ MIN G
8,130 37 02LNX00109-REF/NREF ADV +
149,167 38 02LNX00110-REF/NREF ADV +
7,772 39 02LNX00310 - IRG 80% ANN MIN
190 40 02LNX00311 - LINE EXT 80%
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
41,031 1 02LNX00312 - WA IRG LINE EXT
56 3 18,667 0.0892 4,993 2 02NMT40135-WA NET MTR -IRG
87,146 3 REVENUE ADJ - DEF NPC
-553,377 4 REVENUE_ACCT ADJ
-120,000 5 WASHINGTON - CHEHALIS DEF
173 -0.0347 -6,000 6 UNBILLED REVENUE
558,905 7 DSM REVENUE-IRRIGATION
7 199 8 BLUE SKY REV-IRRIGATION
9
10 WYOMING
17,235 684 25,197 0.0893 1,538,410 11 05APS00040-AG PUMPING SVC
1,055 15 70,333 0.0832 87,819 12 05APSNS040-AG PUMPING SVC -
6,838 13 05LNX00103-LINE EXT 80% G
1,339 14 05LNX00109-REF/NREF ADV +
53,904 15 05LNX00110-REF/NREF ADV +
945 16 05LNX00310-LINE EXTCONTRAC
9,566 17 05LNX00312 - WY IRG LINE EXT
-2 1.5000 -3,000 18 UNBILLED REVENUE
-2,524 19 REVENUE_ACCT ADJ
12,663 20 DSM REVENUE-IRRIGATION
134 1 134,000 0.0692 9,279 21 05APS00040-AG PUMPING SVC
20,269 22 05LNX00110-REF/NREF ADV +
1,017 23 05LNX00312 - WY IRG LINE EXT
223 2 111,500 0.1030 22,970 24 09APSNS210-IRR & SOIL DRA -
4,191 89 47,090 0.0901 377,453 25 09APSV0210-IRR & SOIL DRA
1,081 26 DSM REVENUE-IRRIGATION
27
-829 28 LESS MULTIPLE BILLINGS
29
1,520,114 23,394 64,979 0.0953 144,928,830 30 TOTAL IRRIGATION SALES
31
32 PUBLIC STREET & HWY LIGHTING
33 CALIFORNIA
1,273 109 11,679 0.1817 231,290 34 06CUSL053E-SPECIAL CUST O
188 22 8,545 0.2018 37,946 35 06CUSL058F-CUST OWND STR
680 78 8,718 0.3284 223,338 36 06HPSV0051-HI PRESSURE SO
12,475 37 DSM REVENUE-PUB ST & HWY LT
-15,969 38 REVENUE_ACCT ADJ
483 39 SOLAR FEED-IN REVENUE
137 0.2409 33,000 40 UNBILLED REVENUE
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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 IDAHO
142 24 5,917 0.1227 17,423 3 07GNSV023S-IDAHO TRAFFIC
101 44 2,295 0.4632 46,784 4 07SLCO0011-STR LGT CO-OWN
362 28 12,929 0.1115 40,374 5 07SLCU012E-ENGY STR LGT
1,867 190 9,826 0.1987 370,974 6 07SLCU012F-FULL MNT STR
194 16 12,125 0.1449 28,110 7 07SLCU012P-PART MNT STR LGT
-611 8 REVENUE_ACCT ADJ
10,576 9 DSM REVENUE-PUB ST & HWY LT
-3 0.3333 -1,000 10 UNBILLED REVENUE
11
12 OREGON
390 35 11,143 0.1511 58,933 13 01COSL0052-STR LGT SRVC C
743 73 10,178 0.0744 55,249 14 01CUSL0053-CUS-OWNED MTRD
8,831 176 50,176 0.0728 642,775 15 01CUSL053E-STR LGT SVC
124 9 13,778 0.0955 11,838 16 01CUSL053F-STR LGT SRVC C
19,660 741 26,532 0.2109 4,147,163 17 01HPSV0051-HI PRESSURE SO
119 34 3,500 0.3472 41,321 18 01LEDSL051-OR LED PILOT
7,587 236 32,148 0.1326 1,006,048 19 01MVSL0050-MERC VAPSTR LG
2 3 667 0.1825 365 20 01OALT015N-OUTD AR LGT NR
4 2 2,000 0.1508 603 21 01OALTB15N-OR OUTD AR LGT
123,541 22 DSM REVENUE-PUB ST & HWY LT
354 23 OR GAIN ON SALE OF ASSET
349 24 REVENUE ADJ - DEF NPC
-17,425 25 REVENUE_ACCT ADJ
8,395 26 SOLAR FEED-IN REVENUE
7 0.4286 3,000 27 UNBILLED REVENUE
28
29 UTAH
54 30 08CFR00012-STR LGTS (CONV
4,529 31 08CFR00051-MTH FAC SRVCHG
79 32 08CFR00062-STREET LIGHTS
5 4 1,250 0.2920 1,460 33 08OALT007N-SECURITY AR LG
1,152 121 9,521 0.0918 105,759 34 08TOSS015F-TRAFFIC SIG NM
14,920 759 19,657 0.3054 4,556,874 35 08SLCO0011-STR LGT CO-OWN
2,957 1,530 1,933 0.1185 350,400 36 08TOSS0015-TRAF & OTHER S
766 71 10,789 0.0821 62,911 37 08MONL0015-MTR OUTDONIGHT
4,760 193 24,663 0.1280 609,294 38 08SLCU012P-STR LGT CUST-O
1,172 79 14,835 0.1405 164,638 39 08SLCU012F-STR LGT CUST-O
50,473 696 72,519 0.0651 3,283,937 40 08SLCU012E-DECOR CUST-OWN
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
331,057 1 DSM REVENUE-PUB ST & HWY LT
-59,570 2 REVENUE_ACCT ADJ
26,166 3 SOLAR FEED-IN REVENUE
-188 0.1330 -25,000 4 UNBILLED REVENUE
5
6 WASHINGTON
91 7 02CFR00012-STR LGTS (CONV
189 14 13,500 0.1824 34,477 8 02COSL0052-WA STR LGT SRV
3,445 111 31,036 0.0722 248,880 9 02CUSL053F-WA STR LGT SRV
1,137 105 10,829 0.0715 81,291 10 02CUSL053M-WA STR LGT SRV
3,876 170 22,800 0.1973 764,641 11 02SLCO0051-WA COMPANY
1,729 40 43,225 0.1268 219,241 12 02MVSL0057-WA MERC VAPSTR
-30,000 13 WASHINGTON - CHEHALIS DEF
27,040 14 DSM REVENUE-PUB ST & HWY LT
5,417 15 REVENUE ADJ - DEF NPC
-26,390 16 REVENUE_ACCT ADJ
-236 0.1229 -29,000 17 UNBILLED REVENUE
18
19 WYOMING
268 17 15,765 0.2033 54,487 20 05COSL0057-CO-OWND STR LG
78 11 7,091 0.0636 4,958 21 05CUSL058M-CUST OWND STR
1,069 30 35,633 0.0632 67,575 22 05CUSL0E58-CUST OWNED STR
43 3 14,333 0.0763 3,280 23 05CUSL0M58-CUST OWNED STR
5,313 179 29,682 0.2048 1,088,249 24 05HPSV0051-HI PRESSURE SO
3,684 249 14,795 0.1260 464,342 25 05MVS00053-MERCURY VAPOR
26 2 13,000 0.1124 2,923 26 05OALT015N-OUTD AR LGT SR
31,015 27 DSM REVENUE-PUB ST & HWY LT
-53 28 REVENUE_ACCT ADJ
-51 0.1961 -10,000 29 UNBILLED REVENUE
26 1 26,000 0.1042 2,708 30 09MONL0213-WY MTR OUTDOOR
1,491 50 29,820 0.2512 374,586 31 09SLCO0211-STR LGT CO-OWN
34 5 6,800 0.1628 5,534 32 09SLCUP212-CUST OWNED
41 14 2,929 0.0557 2,282 33 09TOSS0213-TRAFFIC & OTHER
883 34 DSM REVENUE-PUB ST & HWY LT
99 0.2424 24,000 35 UNBILLED REVENUE
36
-2,778 37 LESS MULTIPLE BILLINGS
38
140,686 3,496 40,242 0.1418 19,942,747 39 TOTAL PUBLIC STREET & HWY LT
40
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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 OTHER SALES TO PUBLIC AUTH
2 UTAH
245,256 1 245,256,000 0.0573 14,047,644 3 08GNSV009M-MANL HIGH VOLT
25,658 2 12,829,000 0.0910 2,334,254 4 08PRSV031M-BKUP MNT&SUPPL
603,595 5 DSM REVENUE-OSPA
-96,304 6 REVENUE_ACCT ADJ
37,872 7 SOLAR FEED-IN REVENUE
-449 0.0557 -25,000 8 UNBILLED REVENUE
9
270,465 3 90,155,000 0.0625 16,902,061 10 TOTAL OTHER SALES TO PUBLIC
11
12 FORFEITED DISCOUNTS
13 CALIFORNIA
178,725 14 06LPAY0300-RES-LATEFEE
55,324 15 06LPAY0300-COM-LATEFEE
48,570 16 06LPAY0300-IND-LATEFEE
1,373 17 06LPAY0300-OTHER-LATEFEE
18
19 IDAHO
199,427 20 07LPAY0300-RES-LATEFEE
35,505 21 07LPAY0300-COM-LATEFEE
172,301 22 07LPAY0300-IND-LATEFEE
717 23 07LPAY0300-OTHER-LATEFEE
24
25 OREGON
2,825,166 26 01LPAY0300-RES-LATEFEE
599,977 27 01LPAY0300-COM-LATEFEE
189,013 28 01LPAY0300-IND-LATEFEE
33,225 29 01LPAY0300-OTHER-LATEFEE
30
31 UTAH
2,449,738 32 08LPAY0300-RES-LATEFEE
713,802 33 08LPAY0300-COM-LATEFEE
251,999 34 08LPAY0300-IND-LATEFEE
62,823 35 08LPAY0300-OTHER-LATEFEE
1,138 36 OTHER
37
38 WASHINGTON
470,625 39 02LPAY0300-RES-LATEFEE
107,345 40 02LPAY0300-COM-LATEFEE
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
28,345 1 02LPAY0300-IND-LATEFEE
7,933 2 02LPAY0300-OTHER-LATEFEE
3
4 WYOMING
394,935 5 05LPAY0300-RES-LATEFEE
99,796 6 05LPAY0300-COM-LATEFEE
145,406 7 05LPAY0300-IND-LATEFEE
2,708 8 05LPAY0300-OTHER-LATEFEE
46,777 9 05LPAY0300-RES-LATEFEE
11,380 10 05LPAY0300-COM-LATEFEE
6,814 11 05LPAY0300-IND-LATEFEE
390 12 05LPAY0300-OTHER-LATEFEE
13
9,141,277 14 TOTAL FORFEITED DISCOUNTS
15
16 MISCELLANEOUS SERVICE REV
17 CALIFORNIA
1,454 18 06CFR00003-MTH MAINTENANC
29,795 19 06CONN0300-CA RECONNECTIO
47,114 20 06FCBUYOUT
10,320 21 06RCHK0300-CA RET CHK CHR
1,050 22 06TAMP0300-CA TAMP & UNAU
3,205 23 06TEMP0300-CA TEMP SRVC C
226 24 06XMTRTAMP-TMPRING - UNAU
126 25 HOME COMFORT
-237 26 OTHER
27
28 IDAHO
1,682 29 07CFR00001-MTH FAC SRVCHG
28,010 30 07CONN0300-ID RECONNECTIO
5,282 31 07FCBUYOUT - FAC CHG BUYOUT
28,940 32 07RCHK0300-ID RET CHK CHR
24,625 33 07TEMP0014-TEMP SRVC CONN
8 34 OTHER
35
36 OREGON
115,184 37 01CFR00001-MTH FACILITY S
25,942 38 01CFR00003-MTH MAINTENANC
25,708 39 01CFR00004-MTH MAINTENANC
37,179 40 01CFR00005-INTERMTNT SRVC
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
28,213 1 01CFR00013-MTH MISC CHRG
5 2 01CFR00014-YR MISC CHRG
354,235 3 01CONN0300-RECONNECTION C
8,412 4 01CONTSERV-OR 3RD PARTY
270 5 01ESSC0600 - ESS CHARGES
303,016 6 01FCBUYOUT-FAC CHG BUYOUT
265,820 7 01RCHK0300-RETURNED CHECK
15,000 8 01TAMP0300-TAMP & UNAUTH
156,810 9 01TEMP0300-TEMP SRVC CHRG
3,531 10 01XMTRTAMP-TAMPRING - UNAU
-98,887 11 OTHER
12
13 UTAH
147,885 14 08CFR00013-MTH MISC CHRG
87,386 15 08CFR00051-MTH FAC SRVCHG
424 16 08CFR00052-ANN FAC SVCCHG
11,646 17 08CFR00053-MTHLY MAINTFEE
4,976 18 08CFR00054-NRES EMERGENCY
2,373 19 08CFR00063-MTH MISC CHARG
6,660 20 08CFR00064-ANN MISC CHARG
344,590 21 08CONN0300-RECONN&DISCONN
84,711 22 08CONTSERV-3RD PARTY O/S
142,513 23 08FCBUYOUT-FAC CHG BUYOUT
354 24 08INFO0300-CUST/3RD P REQ
60 25 08METR0300-UT FEE MTR TES
3,675 26 08NCON0300-UT FEE NRES RE
1,132 27 08NSMTR300-NON STAN MTR
254 28 08PRINT300-SCREEN PRINT FOR
441,321 29 08RCHK0300-UT RET CHK CHR
1,735,951 30 08RCON0001-CONNECT FEE
3,166 31 08RESD0001-RES SRVC
9,600 32 08TAMP0300-TAMPERING&UNAU
556,031 33 08TEMP0014-TEMP SRVC CONN
1,013 34 08XMTRTAMP-TMPRING - UNAU
4,095 35 ENERGY FINANSWER NEW COM
49,165 36 08VISIT300 - UT VISIT, SERVICE
-42,351 37 OTHER
38
39 WASHINGTON
1,320 40 02CFR00003-MTH MAINTENANC
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
5,892 1 02CFR00004-EMRGNCY ST&BY
4,302 2 02CFR00005-INTERMTNT SRVC
104,870 3 02CONN0300-WA RECONNECTIO
13,717 4 02FCBUYOUT - FAC CHG BUYOUT
54,260 5 02RCHK0300-WA RET CHK CHR
5,475 6 02TAMP0300-WA TAMP & UNAU
22,220 7 02TEMP0300-WA TEMP SRVC C
1,409 8 02XMTRTAMP-TMPRING - UNAU
5,809 9 02XTHEFREV-THEFT OF
281 10 HOME COMFORT
-33,684 11 OTHER
12
13 WYOMING
1,768 14 05CFR00003-MTH MAINTENANC
18,424 15 05CFR00004-EMRGNCY ST&BY
10,132 16 05CFR00005-INTERMTNT SRVC
3,186 17 05CFR00013-MTH MISC CHRG
76,041 18 05CONN0300-WY RECONNECTIO
48,185 19 05FCBUYOUT - FAC CHG BUYOUT
839 20 05NSMTR300-NON STANDARD
74,850 21 05RCHK0300-WY RET CHK CHR
66 22 05RESD0002-WY RES SRVC
120 23 05SERV0300-WY SRVC CALLS
450 24 05TAMP0300
63,495 25 05TEMP0300-WY TEMP SRVC C
93 26 05XMTRTAMP-TMPRING - UNAU
339 27 09CFR00005-INTERMTNT SRVC
-267 28 OTHER
8,800 29 05CONN0300-WY RECONNECTIO
7,747 30 05FCBUYOUT - FAC CHG BUYOUT
7,290 31 05RCHK0300-WY RET CHK CHR
5,103 32 09CFR00001-MTH FAC SRVCHG
3 33 09CFR00014-YR MISC CHRG
45 34 09TEMP0214-TEMP SRVC CONN
35
5,531,248 36 TOTAL MISC SERVICE REV
37
38 RENT FROM ELEC PROPERTIES
39 CALIFORNIA
1,710 40 06CFR00006-MTH RNTAL CHRG
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
1,200 1 RENT REVENUE-HYDRO
19,280 2 RENT REVENUE-SUBLEASES
541,370 3 JOINT USE
4
5 IDAHO
788 6 07CFR00009-YR LSE CHRG-EQ
149 7 07INVCHG00-INVEST MNT CHG
276 8 07POLE0075-STEEL POLES US
91,832 9 RENT REVENUE-HYDRO
4,850 10 RENT REVENUE-TRANSMISSION
550 11 RENT REVENUE-DISTRIBUTION
2,216 12 RENT REVENUE-SUBLEASES
157,199 13 JOINT USE
14
15 OREGON
821,283 16 01CFR00006-MTH RNTAL CHRG
732,419 17 RENTS - COMMON
25 18 RENTS - NON COMMON
3,345,901 19 MCI FOGWIRE REVENUE
36,707 20 RENT REVENUE-SUBLEASES
24,726 21 RENT REVENUE-HYDRO
266,557 22 RENT REVENUE-TRANSMISSION
56,794 23 RENT REVENUE-DISTRIBUTION
61,150 24 RENT REVENUE-GENERAL
2,706,302 25 JOINT USE
26
27 UTAH
33 28 08CFR00056-MTH EQUIP RENT
518,606 29 08CFR00058-MTH EQUIP LEAS
4,407 30 08INVCHG0N-INVEST MNT CHG
238 31 08INVCHG0R-INVEST MNT CHG
54,601 32 08POLE0075-STEEL POLES US
13,848 33 RENTS - NON COMMON
103,995 34 RENT REVENUE-STEAM
101,524 35 RENT REVENUE-HYDRO
1,041,210 36 RENT REVENUE-TRANSMISSION
645,143 37 RENT REVENUE-DISTRIBUTION
16,919 38 RENT REVENUE-GENERAL
2,796,428 39 RENT REVENUE-SUBLEASES
28,822 40 INTERCOMPANY RENT REVENUE
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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.
2,984,423 1 JOINT USE
2
3 WASHINGTON
2,123 4 02CFR00001-MTH FACILITY S
9,073 5 02CFR00006-MTH RNTAL CHRG
344,630 6 RENT REVENUE-HYDRO
18,649 7 RENT REVENUE-TRANSMISSION
20,744 8 RENT REVENUE-DISTRIBUTION
41,174 9 RENT REVENUE-GENERAL
843,243 10 JOINT USE
11
12 WYOMING
11,524 13 05CFR00001-MTH FACILITY S
2,482 14 05CFR00006-MTH RNTAL CHRG
23,436 15 RENT REVENUE-STEAM
18,284 16 RENT REVENUE-HYDRO
6,059 17 RENT REVENUE-TRANSMISSION
150 18 RENT REVENUE-DISTRIBUTION
163,706 19 RENT REVENUE-GENERAL
25,734 20 RENT REVENUE-SUBLEASES
339,365 21 JOINT USE
18,313 22 09POLE0075-STEEL POLES US
27,900 23 RENT REVENUE-STEAM
24
19,100,070 25 TOTAL RENT FROM ELEC PROP
26
27 OTHER ELECTRIC REVENUE
8,802,231 28 WIND BASED ANCILLARY SVC
-5,114,029 29 FERC TRANSMISSION REFUND
20,007 30 OTH ELEC ESTIMATE
-6,901,286 31 RENEWABLE ENERGY CREDITS
11,212,184 32 CA GHG ALLOW REV AMORT
11,659,010 33 NON-WHEELING SYSTEM
17,080 34 OTHER ELEC (EXCLUDE WHEELIN
35
36 CALIFORNIA
53,869 37 3RD PARTY TRANS O&M
5,891 38 FISH, WILDLIFE, RECR
-61 39 OTHER ELEC (EXCLUDE WHEELIN
40
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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
/ /2015/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
122,092 2 3RD PARTY TRANS O&M
-1,917 3 OTHER ELEC (EXCLUDE WHEELIN
4
5 OREGON
38,400 6 EIM REVENUE - FORECASTING
1,872 7 3RD PARTY TRANS O&M
2,260,928 8 OTHER ELEC (EXCLUDE WHEELIN
9
10 UTAH
62,627 11 ELEC INC-OTHR
2,379,327 12 FLYASH SALES
128,481 13 3RD PARTY TRANS O&M
2,120 14 FISH, WILDLIFE, RECR
7,844 15 I/C TRANS O&M REV - SIERRA
130 16 OTHER ELEC (EXCLUDE WHEELIN
1,479,354 17 M&S INVENTORY REVENUE
18
19 WASHINGTON
6,222 20 TIMBER SALES - UTILITY PROP
8,565 21 FISH, WILDLIFE, RECR
27 22 OTHER ELEC (EXCLUDE WHEELIN
-52,188 23 WASH COLSTRIP 3
24
25 WYOMING
10 26 ELEC INC-OTHR
2,719,994 27 FLYASH SALES
317,733 28 WY REG RECOVERY FEE
21,980 29 3RD PARTY TRANS O&M
3 30 OTHER ELEC (EXCLUDE WHEELIN
31
29,258,500 32 TOTAL OTHER ELEC REV
33
34
35
36
37
38
39
40
54,641,212 4,873,631,725 1,812,975 30,139 0.0892
-29,881 1,172,000 0 0 -0.0392
54,671,093 4,872,459,725 1,812,975 30,155 0.0891
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 / /2015/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 1518.018.0T-12RQ 2
Helper City 0.91.01.0T-6RQ 3
Helper City Annex 0.60.60.7T-6RQ 4
Navajo Tribal Util. Auth. (Mexican Hat)0.10.20.2T-6RQ 5
Navajo Tribal Util. Auth. (Red Mesa)1.01.01.0T-6RQ 6
Portland General Electric Company NANANA147RQ 7
Price City Corporation 10.011.011.0T-12RQ 8
Accrual NANANANARQ 9
10
Nonrequirement Sales: 11
Arizona Electric Power Cooperative NANANAT-12SF 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 / /2015/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
1,516,164 1,083,276 2,599,440 51,584 2
103,811 111,732 215,543 5,871 3
62,841 70,177 133,018 3,554 4
15,701 17,855 33,556 901 5
148,787 129,946 278,733 8,541 6
1,069,028 1,069,028 10,221 7
940,540 779,815 -80,927 1,639,428 31,855 8
782,687 782,687 16,030 9
10
11
2,688,603 2,688,603 125,780 12
1,610,143 1,610,143 55,938 13
969,924 969,924 46,813 14
FERC FORM NO. 1 (ED. 12-90) Page 311
3,856,872
407,854,406
411,711,278
128,557
8,760,894
8,889,451
701,760 6,751,433
-156,600,278
-155,898,518
263,082,189
269,833,622
2,192,801
11,828,061
14,020,862
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 / /2015/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
BP Energy Company NANANAT-12SF 2
Barclays Bank PLC NANANAT-12SF 3
Basin Electric Power Cooperative NANANAT-11AD 4
Basin Electric Power Cooperative NANANAT-11LF 5
Basin Electric Power Cooperative NANANAT-11SF 6
Basin Electric Power Cooperative NANANAT-12SF 7
Black Hills Power, Inc.49.050.050.0441LF 8
Black Hills Power, Inc.NANANAT-12SF 9
Black Hills Wyoming, Inc.NANANAT-11AD 10
Black Hills Wyoming, Inc.NANANAT-11SF 11
Bonneville Power Administration NANANAT-11AD 12
Bonneville Power Administration NANANAT-12AD 13
Bonneville Power Administration NANANA368LF 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 / /2015/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.
1,422 1,422 52 1
13,330,158 13,330,158 470,488 2
893,493 893,493 23,575 3
-8 -8 -1 4
8,856 8,856 285 5
124,305 124,305 3,681 6
4,052,038 4,052,038 171,500 7
6,400,325 7,431,861 13,832,186 318,240 8
4,753,246 4,753,246 201,400 9
-35 -35 10
903 903 26 11
11,882 11,882 396 12
-123,645 -123,645 13
80,194 80,194 2,501 14
FERC FORM NO. 1 (ED. 12-90) Page 311.1
3,856,872
407,854,406
411,711,278
128,557
8,760,894
8,889,451
701,760 6,751,433
-156,600,278
-155,898,518
263,082,189
269,833,622
2,192,801
11,828,061
14,020,862
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 / /2015/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-11LF 1
Bonneville Power Administration NANANA519LU 2
Bonneville Power Administration NANANAT-11SF 3
Bonneville Power Administration NANANAT-12SF 4
Bonneville Power Administration NANANAT-13SF 5
Bonneville Power Administration NANANAWSPP - QSF 6
British Columbia Hydro and Power NANANAT-13SF 7
Brookfield Energy Marketing L.P.NANANAT-12SF 8
California Independent System Operator NANANAT-12AD 9
California Independent System Operator NANANAT-12SF 10
Calpine Energy Services, L.P.NANANAT-12SF 11
Cargill Power Markets, LLC NANANAT-11AD 12
Cargill Power Markets, LLC NANANAT-12AD 13
Cargill Power Markets, LLC NANANAT-11SF 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 / /2015/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.
661,311 661,311 20,618 1
2,292,718 2,292,718 31,168 2
1,855 1,855 57 3
4,188,814 4,188,814 164,224 4
3,357 3,357 130 5
51,352 51,352 1,834 6
902 902 29 7
267,562 267,562 12,291 8
-128,844 -128,844 -4,244 9
2,186,648 2,186,648 65,730 10
812,320 812,320 39,413 11
52 52 12
600 600 13
44,647 44,647 1,248 14
FERC FORM NO. 1 (ED. 12-90) Page 311.2
3,856,872
407,854,406
411,711,278
128,557
8,760,894
8,889,451
701,760 6,751,433
-156,600,278
-155,898,518
263,082,189
269,833,622
2,192,801
11,828,061
14,020,862
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 / /2015/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.
Cargill Power Markets, LLC NANANAT-12SF 1
City of Anaheim NANANAT-11SF 2
City of Burbank NANANAT-12SF 3
City of Glendale NANANAT-12SF 4
City of Hurricane NANANAT-12LF 5
City of Redding NANANAT-12SF 6
Clatskanie People's Utility District NANANAT-12SF 7
ConocoPhillips Company NANANAT-12SF 8
Constellation Energy Commodities Group NANANAT-12AD 9
Deseret Generation & Transmission NANANAT-11SF 10
EDF Trading North America, LLC NANANAT-12SF 11
El Paso Electric Company NANANAT-12SF 12
Eugene Water & Electric Board NANANAT-12SF 13
Exelon Generation Company, LLC NANANAT-11LF 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 / /2015/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.
32,730,604 32,730,604 1,152,111 1
19,828 19,828 594 2
1,338,677 1,338,677 59,279 3
123,541 123,541 5,378 4
15,340 15,340 236 5
1,560,009 1,560,009 67,400 6
42,725 42,725 1,987 7
16,100 16,100 400 8
-119 -119 9
13,379 13,379 400 10
26,256,816 26,256,816 865,553 11
331,615 331,615 10,935 12
353,284 353,284 15,128 13
17,160 17,160 510 14
FERC FORM NO. 1 (ED. 12-90) Page 311.3
3,856,872
407,854,406
411,711,278
128,557
8,760,894
8,889,451
701,760 6,751,433
-156,600,278
-155,898,518
263,082,189
269,833,622
2,192,801
11,828,061
14,020,862
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 / /2015/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.
Exelon Generation Company, LLC NANANAT-11SF 1
Exelon Generation Company, LLC NANANAT-12SF 2
Gridforce Energy Management, LLC NANANAT-13SF 3
Iberdrola Renewables, LLC NANANAT-11AD 4
Iberdrola Renewables, LLC NANANAT-12AD 5
Iberdrola Renewables, LLC NANANAT-11LF 6
Iberdrola Renewables, LLC NANANAT-11SF 7
Iberdrola Renewables, LLC NANANAT-11SF 8
Iberdrola Renewables, LLC NANANAT-12SF 9
Idaho Power Company NANANAT-11LF 10
Idaho Power Company NANANAT-11SF 11
Idaho Power Company NANANAT-12SF 12
Idaho Power Company NANANAT-13SF 13
J. Aron & Company NANANAT-12AD 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 / /2015/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.
206 206 9 1
71,816,667 71,816,667 2,459,161 2
1,763 1,763 85 3
14,171 14,171 532 4
5 5 5
249,394 249,394 7,929 6
340,006 340,006 11,044 7
77 77 11 8
37,685,374 37,685,374 1,179,556 9
139,648 139,648 3,791 10
72,387 72,387 1,865 11
16,900 16,900 690 12
2,574 2,574 99 13
-28 -28 14
FERC FORM NO. 1 (ED. 12-90) Page 311.4
3,856,872
407,854,406
411,711,278
128,557
8,760,894
8,889,451
701,760 6,751,433
-156,600,278
-155,898,518
263,082,189
269,833,622
2,192,801
11,828,061
14,020,862
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 / /2015/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.
J.P. Morgan Ventures Energy Corporation NANANAT-11SF 1
Los Angeles Dept. of Water and Power NANANA301LU 2
Los Angeles Dept. of Water and Power NANANAT-11SF 3
Los Angeles Dept. of Water and Power NANANAT-12SF 4
Macquarie Energy LLC NANANAT-11SF 5
Macquarie Energy LLC NANANAT-12SF 6
Modesto Irrigation District NANANAT-12SF 7
Morgan Stanley Capital Group Inc.NANANAT-11AD 8
Morgan Stanley Capital Group Inc.NANANAT-11SF 9
Morgan Stanley Capital Group Inc.NANANAT-12SF 10
Municipal Energy Agency of Nebraska NANANAT-11SF 11
Municipal Energy Agency of Nebraska NANANAT-12SF 12
NaturEner Power Watch, LLC NANANAT-13SF 13
Nevada Power Company 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 / /2015/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 1 1
26,570,488 26,570,488 569,850 2
3,677 3,677 126 3
406,409 406,409 17,591 4
32 32 2 5
4,421,836 4,421,836 167,903 6
1,215,879 1,215,879 47,630 7
273 273 8
107,884 107,884 3,408 9
22,785,166 22,785,166 895,879 10
1 1 11
1,626,735 1,626,735 73,454 12
1,186 1,186 57 13
8,228 8,228 185 14
FERC FORM NO. 1 (ED. 12-90) Page 311.5
3,856,872
407,854,406
411,711,278
128,557
8,760,894
8,889,451
701,760 6,751,433
-156,600,278
-155,898,518
263,082,189
269,833,622
2,192,801
11,828,061
14,020,862
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 / /2015/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.
Nevada Power Company NANANAWSPP - QSF 1
NextEra Energy Power Marketing, LLC NANANAT-11LF 2
NextEra Energy Power Marketing, LLC NANANAT-11SF 3
NextEra Energy Power Marketing, LLC NANANAT-12SF 4
Noble Americas Energy Solutions LLC NANANAT-11AD 5
Noble Americas Energy Solutions LLC NANANAT-11LF 6
NorthWestern Corporation NANANAT-12SF 7
NorthWestern Corporation NANANAT-13SF 8
Pacific Gas & Electric Company NANANAT-11SF 9
Portland General Electric Company NANANAT-11SF 10
Portland General Electric Company NANANAT-12SF 11
Portland General Electric Company NANANAT-13SF 12
Powerex Corporation NANANAT-11LF 13
Powerex Corporation NANANAT-11SF 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 / /2015/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.
1,764,831 1,764,831 80,001 1
195,098 195,098 6,510 2
14,531 14,531 430 3
24,400 24,400 800 4
19,527 19,527 894 5
343,584 343,584 10,574 6
430,276 430,276 18,354 7
3,902 3,902 175 8
1,912 1,912 70 9
15,763 15,763 373 10
2,458,392 2,458,392 112,719 11
92 92 3 12
1,035,406 1,035,406 30,745 13
536,645 536,645 16,410 14
FERC FORM NO. 1 (ED. 12-90) Page 311.6
3,856,872
407,854,406
411,711,278
128,557
8,760,894
8,889,451
701,760 6,751,433
-156,600,278
-155,898,518
263,082,189
269,833,622
2,192,801
11,828,061
14,020,862
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 / /2015/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-12SF 1
Public Service Company of Colorado NANANAT-12SF 2
Public Service Company of New Mexico NANANAT-12SF 3
PUD No. 1 of Chelan County NANANAT-13SF 4
PUD No. 1 of Clark County NANANAT-12SF 5
PUD No. 1 of Douglas County NANANAT-12SF 6
PUD No. 1 of Snohomish County NANANAT-12SF 7
PUD No. 2 of Grant County NANANAT-12SF 8
PUD No. 2 of Grant County NANANAT-13SF 9
Puget Sound Energy, Inc.NANANAT-11SF 10
Puget Sound Energy, Inc.NANANAT-12SF 11
Puget Sound Energy, Inc.NANANAT-13SF 12
Rainbow Energy Marketing Corporation NANANAT-11SF 13
Rainbow Energy Marketing Corporation NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.7
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
2,624,092 72,820 2,696,912 126,566 1
3,417,997 3,417,997 144,978 2
4,032,526 4,032,526 150,400 3
218 218 7 4
377,042 377,042 12,902 5
16,065 16,065 615 6
206,750 206,750 7,135 7
366,606 366,606 15,235 8
130 130 7 9
2 2 10
587,470 587,470 26,550 11
1,143 1,143 40 12
780 780 23 13
4,440,746 4,440,746 191,954 14
FERC FORM NO. 1 (ED. 12-90) Page 311.7
3,856,872
407,854,406
411,711,278
128,557
8,760,894
8,889,451
701,760 6,751,433
-156,600,278
-155,898,518
263,082,189
269,833,622
2,192,801
11,828,061
14,020,862
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 / /2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Sacramento Municipal Utility District NANANA250AD 1
Sacramento Municipal Utility District NANANAT-11AD 2
Sacramento Municipal Utility District NANANAT-11LF 3
Sacramento Municipal Utility District NANANAT-12SF 4
Sacramento Municipal Utility District NANANAT-13SF 5
Salt River Project NANANAT-11LF 6
Salt River Project NANANAT-11SF 7
Salt River Project NANANAT-12SF 8
Seattle City Light NANANAT-12SF 9
Seattle City Light NANANAT-13SF 10
Sempra Generation, LLC NANANAT-12SF 11
Shell Energy North America (US), L.P.NANANAT-11AD 12
Shell Energy North America (US), L.P.NANANAT-11LF 13
Shell Energy North America (US), L.P.NANANAT-11SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.8
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2015/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.
261,923 261,923 1
18 18 2
174,302 174,302 5,650 3
4,141,800 4,141,800 181,647 4
636 636 33 5
182,062 182,062 5,860 6
36,168 36,168 1,058 7
5,030,598 5,030,598 208,890 8
585,272 585,272 25,791 9
419 419 12 10
33,243,075 33,243,075 998,850 11
-21 -21 12
101,220 101,220 3,128 13
38,067 38,067 1,250 14
FERC FORM NO. 1 (ED. 12-90) Page 311.8
3,856,872
407,854,406
411,711,278
128,557
8,760,894
8,889,451
701,760 6,751,433
-156,600,278
-155,898,518
263,082,189
269,833,622
2,192,801
11,828,061
14,020,862
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 / /2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Shell Energy North America (US), L.P.NANANAT-12SF 1
Sierra Pacific Power Company NANANAT-13SF 2
Southern California Edison Company NANANAT-11SF 3
Southern California Edison Company NANANAT-11SF 4
Southern California Edison Company NANANAT-12SF 5
Southern California Public Power Auth.NANANAT-11SF 6
Tacoma Power NANANAT-12SF 7
Tacoma Power NANANAT-13SF 8
Talen Energy Marketing, LLC NANANAT-11SF 9
Talen Energy Marketing, LLC NANANAT-12SF 10
Tenaska Power Services Co.NANANAT-11AD 11
Tenaska Power Services Co.NANANAT-11SF 12
Tenaska Power Services Co.NANANAT-12SF 13
The Energy Authority, Inc.NANANAT-11AD 14
FERC FORM NO. 1 (ED. 12-90) Page 310.9
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
13,508,250 13,508,250 503,934 1
4,644 4,644 239 2
102,435 102,435 3,211 3
491 491 17 4
1,489,340 1,489,340 64,609 5
104 104 3 6
442,420 442,420 19,605 7
833 833 50 8
22,585 22,585 564 9
293,473 293,473 14,074 10
15 15 11
14,240 14,240 319 12
10,170,295 10,170,295 416,667 13
-22 -22 14
FERC FORM NO. 1 (ED. 12-90) Page 311.9
3,856,872
407,854,406
411,711,278
128,557
8,760,894
8,889,451
701,760 6,751,433
-156,600,278
-155,898,518
263,082,189
269,833,622
2,192,801
11,828,061
14,020,862
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 / /2015/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.
The Energy Authority, Inc.NANANAT-11SF 1
The Energy Authority, Inc.NANANAT-12SF 2
Thermo No. 1 BE-01, LLC NANANAT-11AD 3
Thermo No. 1 BE-01, LLC NANANAT-11LF 4
TransAlta Energy Marketing (U.S.) Inc.NANANAT-11AD 5
TransAlta Energy Marketing (U.S.) Inc.NANANAT-11SF 6
TransAlta Energy Marketing (U.S.) Inc.NANANAT-12SF 7
TransCanada Energy Sales Ltd.NANANAT-12SF 8
Tri-State Gen. and Trans.NANANAT-11AD 9
Tri-State Gen. and Trans.NANANAT-11LF 10
Tri-State Gen. and Trans.NANANAT-11SF 11
Tri-State Gen. and Trans.NANANAT-12SF 12
Tucson Electric Power Company NANANAT-11SF 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 / /2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
36,343 36,343 543 1
1,606,488 1,606,488 64,599 2
5 5 3
86,555 86,555 2,734 4
-610 -610 5
64,011 64,011 1,906 6
6,426,770 6,426,770 262,300 7
157,200 157,200 6,000 8
383 383 9
179,477 179,477 5,510 10
806 806 30 11
4,997,034 4,997,034 218,277 12
1,532 1,532 34 13
14,283,371 14,283,371 570,685 14
FERC FORM NO. 1 (ED. 12-90) Page 311.10
3,856,872
407,854,406
411,711,278
128,557
8,760,894
8,889,451
701,760 6,751,433
-156,600,278
-155,898,518
263,082,189
269,833,622
2,192,801
11,828,061
14,020,862
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 / /2015/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
UNS Electric, Inc.NANANAT-12SF 2
Utah Associated Municipal Power Systems NANANAT-11SF 3
Utah Associated Municipal Power Systems NANANAT-12SF 4
Utah Municipal Power Agency NANANA637AD 5
Utah Municipal Power Agency 313534433LF 6
Utah Municipal Power Agency NANANA637LF 7
Utah Municipal Power Agency NANANAT-12SF 8
Vitol Inc.NANANAT-12SF 9
Western Area Power Administration NANANAT-11AD 10
Western Area Power Administration NANANAT-11SF 11
Western Area Power Administration NANANAT-12SF 12
Western Area Power Administration NANANAT-13SF 13
Netting - Bookouts 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 / /2015/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.
75,835 75,835 3,265 1
4,057,436 4,057,436 160,304 2
50,506 50,506 1,523 3
8,700 8,700 275 4
-774 -774 5
5,095,790 4,396,200 9,491,990 219,570 6
827,633 827,633 22,803 7
54,136 54,136 2,393 8
2,560,096 2,560,096 89,378 9
19 19 10
2,712 2,712 91 11
5,068,325 5,068,325 201,568 12
43 43 2 13
-161,672,255 -161,672,255 -5,859,056 14
FERC FORM NO. 1 (ED. 12-90) Page 311.11
3,856,872
407,854,406
411,711,278
128,557
8,760,894
8,889,451
701,760 6,751,433
-156,600,278
-155,898,518
263,082,189
269,833,622
2,192,801
11,828,061
14,020,862
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 / /2015/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 - Trading NANANANA 1
Accrual NANANANA 2
3
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 / /2015/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.
-496,450 -496,450 1
-541,373 -541,373 2,289 2
3
4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 311.12
3,856,872
407,854,406
411,711,278
128,557
8,760,894
8,889,451
701,760 6,751,433
-156,600,278
-155,898,518
263,082,189
269,833,622
2,192,801
11,828,061
14,020,862
Schedule Page: 310 Line No.: 5 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.: 6 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.: 8 Column: j
Settlement adjustment.
Schedule Page: 310 Line No.: 9 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.: 4 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 4 Column: j
Settlement adjustment.
Schedule Page: 310.1 Line No.: 5 Column: b
Basin Electric Power Cooperative - FERC T-11 [Network Transmission Service under the Open
Access Transmission Tariff (2nd Revised Service Agreement 505)] - Contract termination no
earlier than 12 months from notice.
Schedule Page: 310.1 Line No.: 5 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 6 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 8 Column: b
Black Hills Power, Inc. - FERC 441 - Contract termination date: December 31, 2023.
Schedule Page: 310.1 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 10 Column: j
Settlement adjustment.
Schedule Page: 310.1 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.1 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 12 Column: j
Settlement adjustment.
Schedule Page: 310.1 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 13 Column: j
Settlement adjustment.
Schedule Page: 310.1 Line No.: 14 Column: b
Bonneville Power Administration ("BPA") - FERC, 13th 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.: 14 Column: j
Transmission losses.
Schedule Page: 310.2 Line No.: 1 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: 310.2 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 310.2 Line No.: 3 Column: j
Transmission losses.
Schedule Page: 310.2 Line No.: 5 Column: j
Reserve share.
Schedule Page: 310.2 Line No.: 7 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.: 7 Column: j
Reserve share.
Schedule Page: 310.2 Line No.: 9 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.: 9 Column: b
Settlement adjustment.
Schedule Page: 310.2 Line No.: 9 Column: j
Settlement adjustment.
Schedule Page: 310.2 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 310.2 Line No.: 12 Column: j
Settlement adjustment.
Schedule Page: 310.2 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 310.2 Line No.: 13 Column: j
Settlement adjustment.
Schedule Page: 310.2 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 2 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 5 Column: b
City of Hurricane - FERC T-12 - Contract termination date: August 31, 2017.
Schedule Page: 310.3 Line No.: 9 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.: 9 Column: b
Settlement adjustment.
Schedule Page: 310.3 Line No.: 9 Column: j
Settlement adjustment.
Schedule Page: 310.3 Line No.: 10 Column: a
This footnote applies to all occurrences of "Deseret Generation & Transmission" on pages
310-311. Complete name is Deseret Generation & Transmission Co-operative.
Schedule Page: 310.3 Line No.: 10 Column: j
Transmission losses.
Schedule Page: 310.3 Line No.: 14 Column: b
Exelon Generation Company, LLC - FERC T-11 [Network Transmission Service under the Open
Access Transmission Tariff (Service Agreement 789)] - Contract termination upon
notification pursuant to Oregon Direct Access and Open Access Transmission Tariff.
Schedule Page: 310.3 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 1 Column: j
Unauthorized use charges.
Schedule Page: 310.4 Line No.: 3 Column: j
Reserve share.
Schedule Page: 310.4 Line No.: 4 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 310.4 Line No.: 4 Column: j
Settlement adjustment.
Schedule Page: 310.4 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 310.4 Line No.: 5 Column: j
Settlement adjustment.
Schedule Page: 310.4 Line No.: 6 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.: 6 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 7 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 8 Column: j
Unauthorized use charges.
Schedule Page: 310.4 Line No.: 10 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.: 10 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.4 Line No.: 13 Column: j
Reserve share.
Schedule Page: 310.4 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 310.4 Line No.: 14 Column: j
Settlement adjustment.
Schedule Page: 310.5 Line No.: 1 Column: j
Unauthorized use charges.
Schedule Page: 310.5 Line No.: 2 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.: 3 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 5 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 310.5 Line No.: 8 Column: j
Settlement adjustment.
Schedule Page: 310.5 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.5 Line No.: 13 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 14 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.: 14 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Transmission losses.
Schedule Page: 310.6 Line No.: 2 Column: b
NextEra Energy Power Marketing, LLC - FERC T-11 [Point-to-Point Transmission Service under
the Open Access Transmission Tariff (2nd Revised S.A. 733)] - Contract termination date:
November 17, 2017.
Schedule Page: 310.6 Line No.: 2 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 3 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 310.6 Line No.: 5 Column: j
Settlement adjustment.
Schedule Page: 310.6 Line No.: 6 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.: 6 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 8 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 10 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 12 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 13 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.: 13 Column: j
Transmission losses.
Schedule Page: 310.6 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.7 Line No.: 1 Column: j
Pond sales.
Schedule Page: 310.7 Line No.: 4 Column: a
This footnote applies to all occurrences of "PUD No. 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.: 4 Column: j
Reserve share.
Schedule Page: 310.7 Line No.: 5 Column: a
This footnote applies to all occurrences of "PUD No. 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.: 6 Column: a
This footnote applies to all occurrences of "PUD No. 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.: 7 Column: a
This footnote applies to all occurrences of "PUD No. 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.: 8 Column: a
This footnote applies to all occurrences of "PUD No. 2 of Grant County" on pages 310-311.
Complete name is Public Utility District No. 2 of Grant County.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 310.7 Line No.: 9 Column: j
Reserve share.
Schedule Page: 310.7 Line No.: 10 Column: j
Transmission losses.
Schedule Page: 310.7 Line No.: 12 Column: j
Reserve share.
Schedule Page: 310.7 Line No.: 13 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 310.8 Line No.: 1 Column: j
Settlement adjustment.
Schedule Page: 310.8 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 310.8 Line No.: 2 Column: j
Settlement adjustment.
Schedule Page: 310.8 Line No.: 3 Column: b
Sacramento Municipal Utility District - FERC T-11 [Point-to-Point Transmission Service
under the Open Access Transmission Tariff (Service Agreement 795)] - Contract termination
date: December 31, 2020.
Schedule Page: 310.8 Line No.: 3 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 5 Column: j
Reserve share.
Schedule Page: 310.8 Line No.: 6 Column: b
Salt River Project - FERC T-11 [Point-to-Point Transmission Service under the Open Access
Transmission Tariff (Service Agreement 809)] - Contract termination date: October 31,
2020.
Schedule Page: 310.8 Line No.: 6 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 7 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 10 Column: j
Reserve share.
Schedule Page: 310.8 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 310.8 Line No.: 12 Column: j
Settlement adjustment.
Schedule Page: 310.8 Line No.: 13 Column: b
Shell Energy North America (US), L.P. - FERC T-11 [Re-Sale Transmission Service under the
Open Access Transmission Tariff (Service Agreement 791)] - Resale termination upon
agreement between resale parties.
Schedule Page: 310.8 Line No.: 13 Column: j
Transmission losses.
Schedule Page: 310.8 Line No.: 14 Column: j
Transmission losses.
Schedule Page: 310.9 Line No.: 2 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.: 2 Column: j
Reserve share.
Schedule Page: 310.9 Line No.: 3 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Transmission losses.
Schedule Page: 310.9 Line No.: 4 Column: j
Unauthorized use charges.
Schedule Page: 310.9 Line No.: 6 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.: 6 Column: j
Unauthorized use charges.
Schedule Page: 310.9 Line No.: 8 Column: j
Reserve share.
Schedule Page: 310.9 Line No.: 9 Column: j
Transmission losses.
Schedule Page: 310.9 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 310.9 Line No.: 11 Column: j
Settlement adjustment.
Schedule Page: 310.9 Line No.: 12 Column: j
Transmission losses.
Schedule Page: 310.9 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 310.9 Line No.: 14 Column: j
Settlement adjustment.
Schedule Page: 310.10 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 310.10 Line No.: 3 Column: j
Settlement adjustment.
Schedule Page: 310.10 Line No.: 4 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.: 4 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 310.10 Line No.: 5 Column: j
Settlement adjustment.
Schedule Page: 310.10 Line No.: 6 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 9 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.: 9 Column: b
Settlement adjustment.
Schedule Page: 310.10 Line No.: 9 Column: j
Settlement adjustment.
Schedule Page: 310.10 Line No.: 10 Column: b
Tri-State Generation and Transmission Association, Inc. - FERC T-11 [Network Transmission
Service under the Open Access Transmission Tariff (6th Revised Service Agreement 628)] -
Contract termination date: June 30, 2021.
Schedule Page: 310.10 Line No.: 10 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 11 Column: j
Transmission losses.
Schedule Page: 310.10 Line No.: 13 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
Transmission losses.
Schedule Page: 310.11 Line No.: 3 Column: j
Transmission losses.
Schedule Page: 310.11 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 310.11 Line No.: 5 Column: j
Settlement adjustment.
Schedule Page: 310.11 Line No.: 6 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: b
Utah Municipal Power Agency - FERC 433 - Contract termination date: June 30, 2017.
Schedule Page: 310.11 Line No.: 7 Column: j
Transmission losses.
Schedule Page: 310.11 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 310.11 Line No.: 10 Column: j
Settlement adjustment.
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
Reflects transactions that did not physically settle.
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
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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2015/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 18,509,642 15,517,011
(501) Fuel 5 860,709,193 893,792,204
(502) Steam Expenses 6 43,153,691 84,614,045
(503) Steam from Other Sources 7 4,303,809 3,980,975
(Less) (504) Steam Transferred-Cr. 8
(505) Electric Expenses 9 3,921,304 2,351,648
(506) Miscellaneous Steam Power Expenses 10 41,560,988 -15,574,943
(507) Rents 11 379,252 394,702
(509) Allowances 12
TOTAL Operation (Enter Total of Lines 4 thru 12) 13 972,537,879 985,075,642
Maintenance 14
(510) Maintenance Supervision and Engineering 15 6,742,774 8,514,939
(511) Maintenance of Structures 16 28,711,998 30,664,954
(512) Maintenance of Boiler Plant 17 114,942,694 95,031,926
(513) Maintenance of Electric Plant 18 44,711,216 34,835,090
(514) Maintenance of Miscellaneous Steam Plant 19 11,939,661 11,894,236
TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 207,048,343 180,941,145
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 1,179,586,222 1,166,016,787
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 7,346,206 8,836,151
(536) Water for Power 45 200,374 121,947
(537) Hydraulic Expenses 46 4,387,105 4,327,999
(538) Electric Expenses 47
(539) Miscellaneous Hydraulic Power Generation Expenses 48 16,721,432 17,875,790
(540) Rents 49 921,405 1,573,497
TOTAL Operation (Enter Total of Lines 44 thru 49) 50 29,576,522 32,735,384
C. Hydraulic Power Generation (Continued) 51
Maintenance 52
(541) Mainentance Supervision and Engineering 53 388 388
(542) Maintenance of Structures 54 797,907 907,301
(543) Maintenance of Reservoirs, Dams, and Waterways 55 1,890,427 1,413,192
(544) Maintenance of Electric Plant 56 1,991,634 1,749,826
(545) Maintenance of Miscellaneous Hydraulic Plant 57 3,739,521 3,016,038
TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 8,419,877 7,086,745
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 37,996,399 39,822,129
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
/ /2015/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 62 353,767 418,092
(547) Fuel 63 396,700,941 272,426,195
(548) Generation Expenses 64 17,772,523 18,238,116
(549) Miscellaneous Other Power Generation Expenses 65 9,084,850 7,745,388
(550) Rents 66 4,187,040 3,491,472
TOTAL Operation (Enter Total of lines 62 thru 66) 67 428,099,121 302,319,263
Maintenance 68
(551) Maintenance Supervision and Engineering 69
(552) Maintenance of Structures 70 2,279,301 4,228,009
(553) Maintenance of Generating and Electric Plant 71 17,425,171 26,813,693
(554) Maintenance of Miscellaneous Other Power Generation Plant 72 2,986,641 1,481,768
TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 22,691,113 32,523,470
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 450,790,234 334,842,733
E. Other Power Supply Expenses 75
(555) Purchased Power 76 603,201,899 623,108,136
(556) System Control and Load Dispatching 77 1,262,603 1,426,643
(557) Other Expenses 78 53,534,340 48,032,087
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 657,998,842 672,566,866
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 2,326,371,697 2,213,248,515
2. TRANSMISSION EXPENSES 81
Operation 82
(560) Operation Supervision and Engineering 83 5,651,643 9,280,674
84
(561.1) Load Dispatch-Reliability 85
(561.2) Load Dispatch-Monitor and Operate Transmission System 86 7,564,076 6,818,716
(561.3) Load Dispatch-Transmission Service and Scheduling 87
(561.4) Scheduling, System Control and Dispatch Services 88 824,276 2,106,756
(561.5) Reliability, Planning and Standards Development 89 1,111,085 1,326,587
(561.6) Transmission Service Studies 90 76,025 106,311
(561.7) Generation Interconnection Studies 91 1,139,487 998,299
(561.8) Reliability, Planning and Standards Development Services 92 5,545,389 7,402,436
(562) Station Expenses 93 3,333,301 3,072,973
(563) Overhead Lines Expenses 94 488,475 409,509
(564) Underground Lines Expenses 95
(565) Transmission of Electricity by Others 96 151,335,724 148,425,345
(566) Miscellaneous Transmission Expenses 97 4,350,698 2,400,520
(567) Rents 98 1,917,195 2,248,767
TOTAL Operation (Enter Total of lines 83 thru 98) 99 183,337,374 184,596,893
Maintenance 100
(568) Maintenance Supervision and Engineering 101 1,369,666 1,186,503
(569) Maintenance of Structures 102 -46,352 19,905
(569.1) Maintenance of Computer Hardware 103 111,446 105,911
(569.2) Maintenance of Computer Software 104 448,520 406,743
(569.3) Maintenance of Communication Equipment 105 3,573,267 3,624,514
(569.4) Maintenance of Miscellaneous Regional Transmission Plant 106
(570) Maintenance of Station Equipment 107 7,895,835 8,037,307
(571) Maintenance of Overhead Lines 108 15,744,941 17,091,353
(572) Maintenance of Underground Lines 109 100,695 51,642
(573) Maintenance of Miscellaneous Transmission Plant 110 -1,477,863 543,682
TOTAL Maintenance (Total of lines 101 thru 110) 111 27,720,155 31,067,560
TOTAL Transmission Expenses (Total of lines 99 and 111) 112 211,057,529 215,664,453
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
/ /2015/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 9,856,256 11,287,882
(581) Load Dispatching 135 12,031,560 11,746,191
(582) Station Expenses 136 4,646,431 4,235,949
(583) Overhead Line Expenses 137 5,735,189 6,808,598
(584) Underground Line Expenses 138 128 6,628
(585) Street Lighting and Signal System Expenses 139 231,729 223,951
(586) Meter Expenses 140 7,226,408 6,584,411
(587) Customer Installations Expenses 141 10,081,874 10,551,937
(588) Miscellaneous Expenses 142 5,691,371 4,670,374
(589) Rents 143 2,539,539 3,315,582
TOTAL Operation (Enter Total of lines 134 thru 143) 144 58,040,485 59,431,503
Maintenance 145
(590) Maintenance Supervision and Engineering 146 5,882,500 5,710,663
(591) Maintenance of Structures 147 2,239,835 2,230,204
(592) Maintenance of Station Equipment 148 12,488,442 11,414,124
(593) Maintenance of Overhead Lines 149 95,268,142 91,628,672
(594) Maintenance of Underground Lines 150 21,417,732 22,910,745
(595) Maintenance of Line Transformers 151 872,964 922,335
(596) Maintenance of Street Lighting and Signal Systems 152 3,389,842 3,252,544
(597) Maintenance of Meters 153 5,985,723 4,294,012
(598) Maintenance of Miscellaneous Distribution Plant 154 1,977,891 5,240,622
TOTAL Maintenance (Total of lines 146 thru 154) 155 149,523,071 147,603,921
TOTAL Distribution Expenses (Total of lines 144 and 155) 156 207,563,556 207,035,424
5. CUSTOMER ACCOUNTS EXPENSES 157
Operation 158
(901) Supervision 159 2,621,299 1,739,975
(902) Meter Reading Expenses 160 17,785,403 17,341,069
(903) Customer Records and Collection Expenses 161 53,283,660 52,023,964
(904) Uncollectible Accounts 162 11,444,958 10,227,550
(905) Miscellaneous Customer Accounts Expenses 163 156,938 33,442
TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 85,292,258 81,366,000
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
/ /2015/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 167 150,177 271,770
(908) Customer Assistance Expenses 168 132,017,498 132,301,137
(909) Informational and Instructional Expenses 169 3,745,519 3,123,200
(910) Miscellaneous Customer Service and Informational Expenses 170 99,133 15,904
TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 136,012,327 135,712,011
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 75,687,733 78,097,396
(921) Office Supplies and Expenses 182 8,332,848 8,563,778
(Less) (922) Administrative Expenses Transferred-Credit 183 33,980,836 37,773,122
(923) Outside Services Employed 184 14,156,752 16,829,096
(924) Property Insurance 185 15,633,179 15,938,310
(925) Injuries and Damages 186 -23,490,203 5,349,612
(926) Employee Pensions and Benefits 187
(927) Franchise Requirements 188
(928) Regulatory Commission Expenses 189 24,280,590 22,275,686
(929) (Less) Duplicate Charges-Cr. 190 7,469,667 5,386,124
(930.1) General Advertising Expenses 191 6,832 319
(930.2) Miscellaneous General Expenses 192 2,426,050 2,386,938
(931) Rents 193 6,140,970 4,960,462
TOTAL Operation (Enter Total of lines 181 thru 193) 194 81,724,248 111,242,351
Maintenance 195
(935) Maintenance of General Plant 196 22,162,699 22,974,990
TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 103,886,947 134,217,341
TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 3,070,184,314 2,987,243,744
FERC FORM NO. 1 (ED. 12-93) Page 323
Schedule Page: 320 Line No.: 10 Column: b
Amount includes recovery of closure costs related to the Utah Mine Disposition offset in
Account 501, Fuel expense and established in Account 182.3, Other regulatory assets.
Schedule Page: 320 Line No.: 86 Column: c
Amended in accordance with Attachment H-2, Article IV of the Open Access Transmission
Tariff.
Schedule Page: 320 Line No.: 102 Column: c
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: c
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.: 135 Column: c
Amended in accordance with Attachment H-2, Article IV of the Open Access Transmission
Tariff.
Schedule Page: 320 Line No.: 186 Column: c
Amount includes expected insurance recovery related to the Sanpete County, Utah rangeland
fire.
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, 2015 and 2014, pensions and benefits expense was $124,649,217 and $126,017,454,
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
2015/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 / /2015/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
NANANA3Degrees Group, Inc. OS 2
NANANA3Degrees Group, Inc. OS 3
NANANAApple, Inc. LU 4
NANANAArizona Electric Power Cooperative SF 5
NANANAArizona Public Service Company LF 6
NANANAArizona Public Service Company SF 7
NANANAAvista Corporation SF 8
NANANABP Energy Company SF 9
0.030.030.03Ballard Hog Farms Inc. LU 10
NANANABarclays Bank PLC SF 11
NANANABasin Electric Power Cooperative SF 12
NANANABeaver City Corporation LF 13
NANANABell Mountain Hydro, LLC AD 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 / /2015/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
19,800 19,800 2
49,313 49,313 3
350,522 350,522 4 5,561
3,896,377 3,896,377 5 102,948
1,669,317 1,669,317 6 80,830
6,380,329 223,058 6,603,387 7 283,200
3,941,860 4,702 3,946,562 8 159,166
5,724,122 5,724,122 9 193,561
4,136 8,462 12,598 10 199
1,004,295 1,004,295 11 23,575
3,044,264 3,044,264 12 88,143
6,104 6,104 13 73
683 683 14 -1
FERC FORM NO. 1 (ED. 12-90) Page 327
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANABell Mountain Hydro, LLC LU 1
0.133Beryl Solar, LLC LU 2
NANANABig Top, LLC LU 3
NANANABiomass One, L.P. LU 4
NANANABirch Power Company, Inc. LU 5
NANANABlack Cap Solar, LLC LU 6
NANANABlack Hills Power, Inc. SF 7
NANANABonneville Power Administration AD 8
NANANABonneville Power Administration LF 9
NANANABonneville Power Administration OS 10
NANANABonneville Power Administration SF 11
NANANABourdet, Peter M. LU 12
0.92.52Box Canyon Limited Partnership LU 13
NANANABrigham Young University - Idaho IU 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 / /2015/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.
57,730 57,730 1 703
160,635 52,096 212,731 2 1,926
252,174 252,174 3 3,453
10,905,737 2,328,619 13,234,356 4 152,593
732,694 732,694 5 11,942
22,328 22,328 6 655
897,849 897,849 7 23,161
16,710 16,710 8
9,856 9,856 9
131,597 131,597 10
14,387,781 30,140 14,417,921 11 583,849
4,390 4,390 12 130
188,432 1,279,861 1,468,293 13 9,815
502,560 502,560 14 13,105
FERC FORM NO. 1 (ED. 12-90) Page 327.1
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANABrookfield Energy Marketing L.P. SF 1
NANANAButter Creek Power, LLC LU 2
NANANAC Drop Hydro, LLC LU 3
NANANACDM Hydroelectric Company LU 4
NANANACalifornia Independent System Operator AD 5
NANANACalifornia Independent System Operator SF 6
NANANACalpine Energy Services, L.P. SF 7
NANANACameron A. Curtiss LU 8
NANANACargill Power Markets, LLC SF 9
NANANACargill, Incorporated LU 10
02.95Cedar Valley Solar, LLC LU 11
344.6Central Oregon Irrigation District LU 12
NANANAChevron U.S.A. Inc. LU 13
NANANACity of Albany LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.2
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
4,600 4,600 1 200
840,220 840,220 2 11,565
164,653 164,653 3 2,246
1,602,564 1,602,564 4 26,173
-8,139 -8,139 5 -2,545
1,185,382 1,185,382 6 17,343
4,377,875 4,377,875 7 133,500
3,576 3,576 8 49
10,341,255 10,341,255 9 336,404
445,104 445,104 10 6,030
56 10 66 11
475,263 3,797,043 4,272,306 12 38,382
639,901 639,901 13 37,035
50,092 50,092 14 677
FERC FORM NO. 1 (ED. 12-90) Page 327.2
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANACity of Anaheim SF 1
NANANACity of Astoria LU 2
NANANACity of Burbank SF 3
NANANACity of Hurricane LF 4
NANANACity of Lehi AD 5
NANANACity of Lehi IF 6
NANANACity of Portland, Water Bureau LU 7
NANANACity of Preston Idaho LU 8
NANANACity of Redding SF 9
NANANAClatskanie People's Utility District SF 10
NANANACommercial Energy Management Inc. AD 11
NANANACommercial Energy Management Inc. LU 12
NANANAConocoPhillips Company OS 13
NANANAConocoPhillips Company SF 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 / /2015/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.
134 134 1 26
565 565 2 14
1,555,802 1,555,802 3 59,114
124,722 124,722 4 1,919
-40 -40 5
343 343 6 308
9,054 9,054 7 123
174,566 174,566 8 3,070
6,500 6,500 9 220
106,296 106,296 10 2,610
-1,879 -1,879 11 12
56,212 56,212 12 1,009
15,036 15,036 13
337,800 337,800 14 12,000
FERC FORM NO. 1 (ED. 12-90) Page 327.3
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANAConsolidated Irrigation Company LU 1
NANANACottonwood Hydro, LLC IU 2
NANANACrook County Solar 1, LLC LU 3
2.93.85.5Deschutes Valley Water District LU 4
9199100Deseret Generation & Transmission Coop LF 5
NANANADorena Hydro, LLC AD 6
NANANADorena Hydro, LLC LU 7
0.60.70.4Douglas County LU 8
NANANADouglas County, Inc. LU 9
NANANADraper Irrigation Company IU 10
NANANADry Creek LLC LU 11
NANANAEDF Trading North America, LLC SF 12
NANANAeBay Inc. LU 13
NANANAEl Paso Electric Company SF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.4
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
9,410 9,410 1 496
246,040 246,040 2 3,608
43,177 43,177 3 1,255
542,509 3,351,762 3,894,271 4 27,228
16,306,446 10,629,321 4,239,640 31,175,407 5 511,279
14,715 14,715 6 299
580,234 580,234 7 7,941
46,665 558,581 605,246 8 4,045
173,973 173,973 9 7,202
9,252 9,252 10 161
496,595 496,595 11 8,704
27,709,663 27,709,663 12 834,463
62,410 62,410 13 916
484,322 1,494 485,816 14 20,770
FERC FORM NO. 1 (ED. 12-90) Page 327.4
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAEugene Water & Electric Board SF 1
NANANAEurus Combine Hills I, LLC LU 2
NANANAEvergreen BioPower, LLC LU 3
NANANAExelon Generation Company, LLC IF 4
NANANAExelon Generation Company, LLC SF 5
NANANAExxonMobil Production Company LU 6
0.92.72.7Falls Creek H.P. Limited Partnership LU 7
NANANAFarm Power Misty Meadow, LLC AD 8
NANANAFarm Power Misty Meadow, LLC LU 9
NANANAFarmers Irrigation District LU 10
NANANAFillmore City Corporation LF 11
NANANAFinley BioEnergy, LLC LU 12
NANANAFlathead Electric Cooperative, Inc. LF 13
NANANAFoote Creek II, LLC 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 / /2015/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.
507,590 507,590 1 19,716
4,233,142 4,233,142 2 91,036
3,788,267 3,788,267 3 56,473
4,567,442 4,567,442 4 122,421
21,134,506 21,134,506 5 744,109
1,721 1,721 6 57
132,287 1,232,984 1,365,271 7 9,911
286 286 8
235,765 235,765 9 3,213
1,383,584 1,383,584 10 19,836
19,680 19,680 11 182
1,793,975 1,793,975 12 24,260
8,800 8,800 13 379
102,298 102,298 14 5,157
FERC FORM NO. 1 (ED. 12-90) Page 327.5
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANAFoote Creek III, LLC LU 1
NANANAFour Corners Windfarm, LLC LU 2
NANANAFour Mile Canyon Windfarm, LLC LU 3
0.30.40.27George DeRuyter & Sons Dairy LU 4
NANANAGeorgetown Irrigation Company LU 5
NANANAGrand Valley Power LF 6
0.72.93Granite Peak Solar, LLC LU 7
01.31.6Greenville Solar, LLC LU 8
NANANAGridforce Energy Management AD 9
NANANAGridforce Energy Management SF 10
NANANAHarold Foster & Robert Walker LU 11
NANANAHermiston Generating Company, L.P. AD 12
177229229Hermiston Generating Company, L.P. LU 13
NANANAIberdrola Renewables, LLC SF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.6
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2015/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.
1,372,923 1,372,923 1 62,479
1,859,588 1,859,588 2 25,626
1,681,155 1,681,155 3 23,104
8,184 76,579 84,763 4 2,399
123,310 123,310 5 2,047
8,608 8,608 6 34
61,705 53,286 114,991 7 1,693
43,448 4,214 47,662 8 99
20 20 9 1
690 690 10 33
35,525 35,525 11 902
-12,762 -12,762 12
37,360,795 27,578,896 251,657 65,191,348 13 1,200,393
66,770,664 66,770,664 14 2,434,744
FERC FORM NO. 1 (ED. 12-90) Page 327.6
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANAIdaho Falls, City of AD 1
NANANAIdaho Falls, City of LU 2
NANANAIdaho Power Company OS 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
1.23.53Laho Solar, LLC LU 11
NANANALos Angeles Dept. of Water and Power SF 12
NANANALower Valley Energy, Inc. IU 13
NANANALower Valley Energy, Inc. 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 / /2015/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.
-44,889 -44,889 1
2,601,032 2,601,032 2 40,781
3,300 -200 3,100 3 300
176,162 1,805 177,967 4 9,731
26,570,488 26,570,488 5 569,850
3,618 3,618 6 60
73,602 73,602 7 1,277
22,693 22,693 8 671
2,676,211 2,676,211 9 83,171
105,627 39,019 144,646 10 4,520
84,842 92,542 177,384 11 3,157
3,252,961 3,252,961 12 67,321
303,654 303,654 13 5,978
80,750 80,750 14 1,512
FERC FORM NO. 1 (ED. 12-90) Page 327.7
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANALoyd Fery LU 1
NANANAMacquarie Energy LLC SF 2
NANANAMarsh Valley Hydro Electric Company LU 3
NANANAMeadow Creek Project Company LLC LU 4
NANANAMiddle Fork Irrigation District LU 5
NANANAMilford Flat Solar, LLC LU 6
NANANAMink Creek Hydro LLC LU 7
NANANAMonroe Hydro, LLC LU 8
NANANAMonsanto Company IU 9
NANANAMorgan City Corporation LF 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 326.8
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 / /2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
12,149 12,149 1 335
5,384,850 5,384,850 2 188,432
193,132 193,132 3 3,143
20,668,300 20,668,300 4 298,255
1,599,847 1,599,847 5 23,904
62,685 62,685 6 2,655
509,486 509,486 7 8,576
1,114 1,114 8 44
19,806,635 19,806,635 9
814 814 10 9
22,665,837 22,665,837 11 517,655
2,936 2,936 12 40
11,908,767 11,908,767 13 183,055
7,899,282 7,899,282 14 140,487
FERC FORM NO. 1 (ED. 12-90) Page 327.8
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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 SF 3
NANANANextEra Energy Power Marketing, LLC OS 4
NANANANextEra Energy Power Marketing, LLC SF 5
0.40.50.8Nichols Gap Limited Partnership LU 6
NANANANicholson's Sunny Bar Ranch LU 7
NANANANorthWestern Corporation OS 8
NANANANorthWestern Corporation SF 9
NANANANucor Corporation IF 10
NANANAO.J. Power Company LU 11
NANANAObsidian Renewables, LLC LU 12
NANANAOregon Environmental Industries, LLC LU 13
NANANAOregon Institute of Technology LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.9
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2015/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.
434,279 434,279 1 9,889
70 70 2 4
1,960,549 72,510 2,033,059 3 54,621
52,626 52,626 4
53,856 53,856 5 3,025
41,232 410,435 451,667 6 3,152
75,861 75,861 7 1,253
3,790 3,790 8 230
182,341 4,436 186,777 9 8,618
6,273,000 6,273,000 10
15,397 15,397 11 310
32,475 32,475 12 946
1,310,511 1,310,511 13 19,622
22,068 22,068 14 1,130
FERC FORM NO. 1 (ED. 12-90) Page 327.9
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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
NANANAPacific Canyon Windfarm, LLC LU 3
NANANAPaul Luckey LU 4
NANANAPavant Solar, LLC 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 SF 12
NANANAProvo City Corporation LF 13
NANANAPublic Service Company of Colorado AD 14
FERC FORM NO. 1 (ED. 12-90) Page 326.10
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2015/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.
3,063 3,063 1 103
1,663,604 1,663,604 2 22,916
1,261,458 1,261,458 3 17,293
4,854 4,854 4 136
29,961 29,961 5 1,392
70,965 70,965 6 2,880
-23,485 -23,485 7
172,000 172,000 8 12,000
2,133,542 6,525 2,140,067 9 81,759
3,977,161 3,977,161 10 57,345
3,510,784 3,510,784 11 50,378
24,222,241 24,222,241 12 664,437
3,926 3,926 13 38
-600 -600 14 -20
FERC FORM NO. 1 (ED. 12-90) Page 327.10
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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 OS 3
NANANAPUD No. 1 of Chelan County SF 4
NANANAPUD No. 1 of Clark County SF 5
NANANAPUD No. 1 of Cowlitz County OS 6
NANANAPUD No. 1 of Douglas County AD 7
NANANAPUD No. 1 of Douglas County LF 8
NANANAPUD No. 1 of Douglas County LU 9
NANANAPUD No. 1 of Douglas County SF 10
NANANAPUD No. 1 of Snohomish County SF 11
NANANAPUD No. 2 of Grant County AD 12
NANANAPUD No. 2 of Grant County LU 13
NANANAPUD No. 2 of Grant County SF 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 / /2015/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.
188,267 188,267 1 5,191
962,041 166 962,207 2 40,207
8,570 8,570 3
507,838 1,554 509,392 4 16,595
293,551 293,551 5 12,882
39,189 39,189 6
-38,512 -38,512 7
2,224,195 2,224,195 8 66,010
3,577,732 3,577,732 9 228,377
1,179,745 363 1,180,108 10 50,707
1,327,762 1,327,762 11 65,137
1,048,402 1,048,402 12
-2,932,610 -2,932,610 13 88,272
1,608,957 2,165 1,611,122 14 62,403
FERC FORM NO. 1 (ED. 12-90) Page 327.11
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANAPuget Sound Energy, Inc. OS 1
NANANAPuget Sound Energy, Inc. SF 2
NANANARES Ag - Oak Lea LLC LU 3
NANANARainbow Energy Marketing Corporation SF 4
NANANARock River 1, LLC LU 5
NANANARoseburg Forest Products Company LU 6
NANANARoseburg LFG Energy, LLC LU 7
NANANARough & Ready Lumber Company 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 326.12
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 / /2015/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.
47,369 47,369 1
6,593,297 8,155 6,601,452 2 270,353
37,761 37,761 3 510
1,299,875 1,299,875 4 45,152
4,175,495 4,175,495 5 117,698
4,057,495 4,057,495 6 70,813
797,367 797,367 7 10,903
241,658 241,658 8 3,273
8,075 8,075 9 224
146,723 146,723 10
4,601,148 4,601,148 11 218,998
28,200 28,200 12 1,300
8,371,220 7,084 8,378,304 13 258,231
1,552,444 1,552,444 14 21,302
FERC FORM NO. 1 (ED. 12-90) Page 327.12
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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
NANANASierra Pacific Power Company SF 6
NANANASierra Pacific Power Company SF 7
0.40.92.1Slate Creek Hydro Company, Inc. LU 8
NANANASolwatt LLC LU 9
NANANASouth Utah Valley Electric LF 10
NANANASouthern California Edison Company SF 11
NANANASpanish Fork Wind Park 2, LLC LU 12
0.30.60.5Sprague Hydro LLC LU 13
NANANASt. Anthony 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 / /2015/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.
13,632 155,041 168,673 1 1,490
2,786,929 2,909 2,789,838 2 124,257
5,150,092 5,150,092 3 216,135
12,424,516 12,424,516 4 447,571
60,027 60,027 5 977
4,267 4,267 6 203
3,044 3,044 7 130
55,638 379,496 435,134 8 3,218
27,794 27,794 9 825
2,851 2,851 10 40
199,328 199,328 11 9,694
2,302,612 2,302,612 12 45,915
53,288 397,860 451,148 13 3,089
9,602 9,602 14
FERC FORM NO. 1 (ED. 12-90) Page 327.13
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANASt. Anthony Hydro, LLC LU 1
NANANAStahlbush Island Farms, Inc. IU 2
1.52.82.9SunE DB18, LLC LU 3
0.73.72.6SunE Solar XVII Project1, LLC LU 4
0.63.42.6SunE Solar XVII Project2, LLC LU 5
02.42.4SunE Solar XVII Project3, LLC LU 6
475352Sunnyside Cogeneration Associates LU 7
NANANASwalley Irrigation District LU 8
NANANATMF Biofuels, LLC LU 9
NANANATacoma Power SF 10
NANANATalen Energy Marketing, LLC SF 11
NANANATata Chemicals (Soda Ash) Partners LU 12
NANANATenaska Power Services Co. SF 13
NANANATesoro Refining & Marketing Co, 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 / /2015/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.
185,385 185,385 1 3,547
23,391 23,391 2 1,131
287,929 247,554 535,483 3 5,845
114,371 64,086 178,457 4 1,571
115,058 65,746 180,804 5 1,610
27,106 8,219 35,325 6 228
10,869,286 17,161,671 28,030,957 7 418,218
172,663 172,663 8 2,332
2,299,085 2,299,085 9 33,294
3,604,656 1,425 3,606,081 10 136,485
2,506,563 2,506,563 11 100,278
108,732 108,732 12 3,629
596,608 596,608 13 14,082
-552 -552 14
FERC FORM NO. 1 (ED. 12-90) Page 327.14
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANATesoro Refining & Marketing Co, LLC LU 1
NANANATesoro Refining & Marketing Co, LLC OS 2
0.30.40.3Thayn Hydro LLC LU 3
NANANAThe Confederated Tribe of Warm Springs LU 4
NANANAThe Energy Authority, Inc. SF 5
0.20.20.2The Town of the City of Buffalo LU 6
NANANAThree Buttes Windpower, LLC LU 7
NANANAThree Sisters Irrigation District AD 8
NANANAThree Sisters Irrigation District LU 9
NANANAThreemile Canyon Wind I, LLC LU 10
NANANATop of The World Wind Energy LLC LU 11
NANANATransAlta Energy Marketing (U.S.) Inc. SF 12
NANANATransCanada Energy Sales Ltd. SF 13
222525Tri-State Generation and Transmission LF 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 / /2015/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.
881,990 881,990 1 27,528
146,705 146,705 2 4,581
95,575 271,288 366,863 3 2,803
9,797 9,797 4 291
3,246,813 3,246,813 5 140,474
38,906 209,567 248,473 6 1,834
18,682,592 18,682,592 7 294,027
1,026 1,026 8
78,724 78,724 9 2,101
1,453,247 1,453,247 10 19,540
37,624,530 37,624,530 11 570,069
29,649,861 29,649,861 12 929,972
10,000 10,000 13 400
5,916,000 3,581,794 9,497,794 14 113,780
FERC FORM NO. 1 (ED. 12-90) Page 327.15
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANATri-State Generation and Transmission SF 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
NANANAUtah Municipal Power Agency IU 8
NANANAUtah Municipal Power Agency SF 9
NANANAUtah Red Hills Renewable Park, LLC LU 10
NANANAVitol Inc. SF 11
NANANAWagon Trail, LLC LU 12
NANANAWard Butte Windfarm, LLC LU 13
NANANAWasatch Integrated Waste Mgmt District AD 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 / /2015/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.
229,487 26,913 256,400 1 8,406
2,018,956 133,865 2,152,821 2 75,194
47,300 47,300 3 2,000
865 865 4 14
97,117 97,117 5 3,528
6,564,146 6,564,146 6
726,449 726,449 7 14,573
3,843,141 3,843,141 8 64,170
12,710 12,710 9 350
235,543 235,543 10 12,281
6,114,359 6,114,359 11 199,590
479,729 479,729 12 6,582
1,133,988 1,133,988 13 15,629
19,968 19,968 14
FERC FORM NO. 1 (ED. 12-90) Page 327.16
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
0.10.40.5Wasatch Integrated Waste Mgmt District LU 1
NANANAWeber County LU 2
NANANAWestern Area Power Administration AD 3
NANANAWestern Area Power Administration LF 4
NANANAWestern Area Power Administration SF 5
NANANAWestern Area Power Administration SF 6
NANANAWolverine Creek Energy, LLC LU 7
1.31.40.9Yakima-Tieton Irrigation District LU 8
NANANAOregon Solar Incentive LU 9
NANANASettlements/Reserves 10
NANANANetting - Bookouts 11
NANANANetting - Trading 12
NANANACA Greenhouse Gas Allowance Purchases 13
NANANAFair value adjustment amortization 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 / /2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
31,209 67,980 99,189 1 1,136
140,889 140,889 2 2,741
141 141 3
674,347 674,347 4 20,396
318,658 53 318,711 5 7,253
350,500 350,500 6 10,864
8,285,296 8,285,296 7 142,899
25,742 296,229 321,971 8 7,916
341,879 341,879 9 10,022
-2,071,120 -2,071,120 10
-161,672,255 -161,672,255 11 -5,859,001
-496,450 -496,450 12
3,107,838 3,107,838 13
-2,125,853 -2,125,853 14
FERC FORM NO. 1 (ED. 12-90) Page 327.17
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANANet Power Cost Deferrals 1
NANANAAccrual 2
3
Power Exchanges: 4
NANANAArizona Public Service Company 307EX 5
NANANAAvista Corporation T-13EX 6
NANANABasin Electric Power Cooperative T-11AD 7
NANANABasin Electric Power Cooperative T-11EX 8
NANANABasin Electric Power Cooperative T-11EX 9
NANANABonneville Power Administration 237AD 10
NANANABonneville Power Administration T-11AD 11
NANANABonneville Power Administration T-12AD 12
NANANABonneville Power Administration T-12AD 13
NANANABonneville Power Administration 237EX 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 / /2015/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.
39,311,037 39,311,037 1
12,880,840 12,880,840 2
3
4
571,373 571,029 2,330,000 2,330,000 5
1,570 6
2 38,016 38,016 7
-88 -88 8
598 7,285 228,148 228,148 9
-312,987 -312,987 10
-425 2,129 69,969 69,969 11
-816 -22,958 -22,958 12
-525,000 -525,000 13
12,550 -31,379 -31,379 14
FERC FORM NO. 1 (ED. 12-90) Page 327.18
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANABonneville Power Administration 256EX 1
NANANABonneville Power Administration 519EX 2
NANANABonneville Power Administration T-11EX 3
NANANABonneville Power Administration T-12EX 4
NANANABonneville Power Administration T-13EX 5
NANANACalifornia Independent System Operator T-11AD 6
NANANACalifornia Independent System Operator T-12AD 7
NANANACalifornia Independent System Operator T-11EX 8
NANANACalifornia Independent System Operator T-12EX 9
NANANACargill Power Markets, LLC T-11AD 10
NANANACargill Power Markets, LLC T-11EX 11
NANANACity of Redding 364EX 12
NANANAConstellation Energy Commodities Group T-11AD 13
NANANADeseret Generation & Transmission Coop 280AD 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 / /2015/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.
936 936 -7,488 -7,488 1
85,728 85,435 -110,953 -110,953 2
4,127 22,389 546,521 546,521 3
6,754 135,269 135,269 4
7,329 258,941 5
-5,341,762 -5,341,762 6
5,537,401 5,537,401 7
1,539,106 1,539,106 8
977,188 222,654 -23,996,507 -23,996,507 9
-251 -15 6,529 6,529 10
4,694 4,388 -28,481 -28,481 11
103,499 103,027 17,630 17,630 12
831 676 31,985 31,985 13
1,023 451 15,222 15,222 14
FERC FORM NO. 1 (ED. 12-90) Page 327.19
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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 280EX 1
NANANADeseret Generation & Transmission Coop 280EX 2
NANANAEDF Trading North America, LLC T-11EX 3
NANANAEmerald People's Utility District 351EX 4
NANANAEugene Water & Electric Board T-12EX 5
NANANAExelon Generation Company, LLC T-11EX 6
NANANAIberdrola Renewables, LLC T-11AD 7
NANANAIberdrola Renewables, LLC T-11EX 8
NANANAIdaho Power Company T-11AD 9
NANANAIdaho Power Company 380EX 10
NANANAIdaho Power Company T-11EX 11
NANANAJ.P. Morgan Ventures Energy Corp T-11AD 12
NANANAJ.P. Morgan Ventures Energy Corp T-11EX 13
NANANALos Angeles Dept. of Water & Power OV-1EX 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 / /2015/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.
292 10,103 10,103 1
171,954 191,711 273,345 273,345 2
2,633 2,323 -12,862 -12,862 3
763 -19,074 -19,074 4
15,482 15,537 3,605 3,605 5
83,122 139,172 859,318 859,318 6
1,670 478 -54,646 -54,646 7
145,931 121,344 -987,858 -987,858 8
-8,578 -7,380 -45 -45 9
163,504 278,322 10
85 120 1,001 1,001 11
-255 54 174 174 12
21,295 23,081 -61,222 -61,222 13
4,038 255,246 255,246 14
FERC FORM NO. 1 (ED. 12-90) Page 327.20
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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 T-11AD 1
NANANAMacquarie Energy LLC T-11EX 2
NANANAMilford Wind Corridor Phase I, LLC OV-1EX 3
NANANAMilford Wind Corridor Phase II, LLC OV-1EX 4
NANANAMorgan Stanley Capital Group Inc. T-11AD 5
NANANAMorgan Stanley Capital Group Inc. T-11EX 6
NANANANevada Power Company T-11AD 7
NANANANevada Power Company T-11EX 8
NANANANextEra Energy Power Marketing, LLC T-11AD 9
NANANANextEra Energy Power Marketing, LLC T-11EX 10
NANANANoble Americas Energy Solutions LLC T-11AD 11
NANANANoble Americas Energy Solutions LLC T-11AD 12
NANANANoble Americas Energy Solutions LLC T-11EX 13
NANANANorthWestern Corporation 160EX 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 / /2015/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.
2,525 -637 607 607 1
25 25 144 144 2
2,651 -165,628 -165,628 3
1,387 -89,619 -89,619 4
78 -725 -2,473 -2,473 5
81,126 80,882 -84,248 -84,248 6
-171 -171 -7 -7 7
235 235 1 1 8
6,260 17,460 342,086 342,086 9
97,477 173,749 2,422,650 2,422,650 10
5 -4 -145 -145 11
238 5 -71 -71 12
216 25,291 740,371 740,371 13
4,835 14
FERC FORM NO. 1 (ED. 12-90) Page 327.21
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAPortland General Electric Company T-11AD 1
NANANAPortland General Electric Company T-11EX 2
NANANAPortland General Electric Company T-13EX 3
NANANAPowerex Corporation T-11AD 4
NANANAPowerex Corporation T-11EX 5
NANANAPublic Service Company of Colorado 319EX 6
NANANAPublic Service Company of Colorado 334EX 7
NANANAPUD No. 1 of Cowlitz County 442EX 8
NANANASacramento Municipal Utility District T-11AD 9
NANANASacramento Municipal Utility District T-11EX 10
NANANASeattle City Light T-12AD 11
NANANASeattle City Light T-12EX 12
NANANAShell Energy North America (US), L.P. T-11AD 13
NANANAShell Energy North America (US), L.P. T-11EX 14
FERC FORM NO. 1 (ED. 12-90) Page 326.22
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 / /2015/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.
-55 92 -302 -302 1
1,945 1,934 6,821 6,821 2
153,039 154,195 3
6,796 8,860 90,302 90,302 4
60,664 60,910 32,632 32,632 5
2,435 6
1,309,193 1,313,999 5,400,000 5,400,000 7
207,238 181,567 8
-828 -671 9
348 348 10
-280 11,480 11,480 11
298,647 309,464 -239,210 -239,210 12
-280 1,027 21,119 21,119 13
6,432 3,392 -90,390 -90,390 14
FERC FORM NO. 1 (ED. 12-90) Page 327.22
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANASouthern California Edison Company T-11AD 1
NANANASouthern California Edison Company T-11EX 2
NANANASouthern CA Public Power Authority T-11EX 3
NANANAState of South Dakota T-11EX 4
NANANATalen Energy Marketing, LLC T-11AD 5
NANANATalen Energy Marketing, LLC T-11EX 6
NANANAThe Energy Authority, Inc. T-11AD 7
NANANAThe Energy Authority, Inc. T-11EX 8
NANANAThermo No. 1 BE-01, LLC T-11AD 9
NANANAThermo No. 1 BE-01, LLC T-11EX 10
NANANATransAlta Energy Marketing (U.S.) Inc. T-11AD 11
NANANATransAlta Energy Marketing (U.S.) Inc. T-11EX 12
NANANATri-State Generation and Transmission 319AD 13
NANANATri-State Generation and Transmission T-11AD 14
FERC FORM NO. 1 (ED. 12-90) Page 326.23
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 / /2015/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.
1,852 3,375 41,627 41,627 1
136,068 185,071 728,313 728,313 2
692 275 -10,366 -10,366 3
43 27 -644 -644 4
-10,913 -10,913 -24 -24 5
1,857 1,857 -14,797 -14,797 6
15 -30 -1,727 -1,727 7
5,509 5,509 -27,245 -27,245 8
357 375 -1,087 -1,087 9
2,143 2,221 592 592 10
3,497 5,188 -151 -151 11
33,990 34,327 -109,203 -109,203 12
-16,843 -16,843 13
-233 866 27,349 27,349 14
FERC FORM NO. 1 (ED. 12-90) Page 327.23
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANATri-State Generation and Transmission 319EX 1
NANANATri-State Generation and Transmission T-11EX 2
NANANAUtah Associated Municipal Power T-11AD 3
NANANAUtah Associated Municipal Power T-11AD 4
NANANAUtah Associated Municipal Power T-11EX 5
NANANAUtah Associated Municipal Power T-11EX 6
NANANAUtah Municipal Power Agency T-11AD 7
NANANAUtah Municipal Power Agency T-11AD 8
NANANAUtah Municipal Power Agency T-11EX 9
NANANAUtah Municipal Power Agency T-11EX 10
NANANAWarm Springs Power Enterprises T-11EX 11
NANANAWestern Area Power Administration LAS-4AD 12
NANANAWestern Area Power Administration LAS-4EX 13
NANANAImbalance Energy Accrual T-11EX 14
FERC FORM NO. 1 (ED. 12-90) Page 326.24
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 / /2015/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.
2,435 -15,184 -15,184 1
5,019 45,206 1,387,662 1,387,662 2
-1,697 -6,303 -166,860 -166,860 3
-9,821 284,281 284,281 4
111,858 184,426 2,409,957 2,409,957 5
20,830 5,405 5,405 6
-15 -64 -5,379 -5,379 7
13 350 350 8
3,734 48,619 1,524,958 1,524,958 9
67 2,640 2,640 10
4,024 6,845 41,832 41,832 11
3,142 544 -123,607 -123,607 12
26,393 4,919 -475,578 -475,578 13
69,301 69,301 14
FERC FORM NO. 1 (ED. 12-90) Page 327.24
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
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 / /2015/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.
NANANASystem Deviation NA 1
2
3
4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 326.25
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 / /2015/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 -8,439
2
3
4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 327.25
11,948,954 4,930,109 4,919,231 73,100,375 620,673,305 -70,665,544 623,108,136
Schedule Page: 326 Line No.: 2 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326 Line No.: 2 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio standard
requirements.
Schedule Page: 326 Line No.: 3 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326 Line No.: 3 Column: l
Purchase of renewable energy credit certificates for California renewable portfolio
standard requirements.
Schedule Page: 326 Line No.: 6 Column: b
Arizona Public Service Company - contract termination date: October 31, 2020.
Schedule Page: 326 Line No.: 7 Column: l
Line loss.
Schedule Page: 326 Line No.: 8 Column: l
Reserve share.
Schedule Page: 326 Line No.: 13 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326 Line No.: 14 Column: l
Settlement adjustment.
Schedule Page: 326.1 Line No.: 4 Column: l
Non-generation agreement.
Schedule Page: 326.1 Line No.: 6 Column: a
PacifiCorp has an agreement with Citizens 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.: 8 Column: b
Settlement adjustment.
Schedule Page: 326.1 Line No.: 8 Column: l
Ancillary services.
Schedule Page: 326.1 Line No.: 9 Column: b
Bonneville Power Administration - contract termination date: 30 days written notice.
Schedule Page: 326.1 Line No.: 9 Column: l
Ancillary services.
Schedule Page: 326.1 Line No.: 10 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.1 Line No.: 10 Column: l
Ancillary services.
Schedule Page: 326.1 Line No.: 11 Column: l
Reserve share.
Schedule Page: 326.2 Line No.: 5 Column: a
This footnote applies to all occurrences of "California Independent System Operator" on
pages 326-327. Complete name is California Independent System Operator Corporation.
Schedule Page: 326.2 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 326.2 Line No.: 5 Column: l
Settlement adjustment.
Schedule Page: 326.3 Line No.: 4 Column: b
City of Hurricane - contract termination date: August 31, 2017.
Schedule Page: 326.3 Line No.: 5 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 326.3 Line No.: 5 Column: l
Settlement adjustment.
Schedule Page: 326.3 Line No.: 7 Column: a
This footnote applies to all occurrences of "City of Portland, Water Bureau" on pages
326-327. Complete name is City of Portland, Portland Water Bureau.
Schedule Page: 326.3 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 326.3 Line No.: 11 Column: l
Settlement adjustment.
Schedule Page: 326.3 Line No.: 13 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.3 Line No.: 13 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio standard
requirements.
Schedule Page: 326.4 Line No.: 5 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: 326.4 Line No.: 5 Column: b
Deseret Generation and Transmission Co-operative - contract termination date: September
30, 2024.
Schedule Page: 326.4 Line No.: 5 Column: l
Reimbursement to counterparty for operation and maintenance costs at coal fired generating
facility located in Vernal, Utah.
Schedule Page: 326.4 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.4 Line No.: 6 Column: l
Settlement adjustment.
Schedule Page: 326.4 Line No.: 14 Column: l
Line loss.
Schedule Page: 326.5 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 326.5 Line No.: 8 Column: l
Settlement adjustment.
Schedule Page: 326.5 Line No.: 11 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.5 Line No.: 13 Column: b
Flathead Electric Cooperative, Inc. - contract termination date: September 30, 2016.
Schedule Page: 326.5 Line No.: 13 Column: l
Line loss.
Schedule Page: 326.6 Line No.: 6 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.6 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.6 Line No.: 9 Column: l
Reserve share.
Schedule Page: 326.6 Line No.: 10 Column: l
Reserve share.
Schedule Page: 326.6 Line No.: 12 Column: a
This footnote applies to all occurrences of "Hermiston Generating Company, L.P." on pages
326-327. Hermiston Generating Company, L.P. operates the Hermiston Generating Plant, which
is jointly owned. PacifiCorp owns 50% of the plant. See page 402.3 column (b) in this Form
No. 1 for further information on the Hermiston Generating Plant.
Schedule Page: 326.6 Line No.: 12 Column: b
Settlement adjustment.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 326.6 Line No.: 12 Column: l
On peak incentive, supplemental dispatch efficiency expense, start-up charges and
committee settlements.
Schedule Page: 326.6 Line No.: 13 Column: l
On peak incentive, supplemental dispatch efficiency expense, start-up charges and
committee settlements.
Schedule Page: 326.7 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 326.7 Line No.: 1 Column: l
Labor, equipment and administration fees associated with hydro project in Idaho Falls,
Idaho.
Schedule Page: 326.7 Line No.: 2 Column: l
Labor, equipment and administration fees associated with hydro project in Idaho Falls,
Idaho.
Schedule Page: 326.7 Line No.: 3 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.7 Line No.: 3 Column: l
Line loss settlement over delivery.
Schedule Page: 326.7 Line No.: 4 Column: l
Reserve share.
Schedule Page: 326.7 Line No.: 10 Column: l
Fixed annual payment.
Schedule Page: 326.7 Line No.: 12 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: 326.8 Line No.: 9 Column: l
Compensation for interruptible service and operating reserves.
Schedule Page: 326.8 Line No.: 10 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.9 Line No.: 2 Column: l
Reserve share.
Schedule Page: 326.9 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: 326.9 Line No.: 3 Column: l
Line loss.
Schedule Page: 326.9 Line No.: 4 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.9 Line No.: 4 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio standard
requirements.
Schedule Page: 326.9 Line No.: 8 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.9 Line No.: 9 Column: l
Reserve share.
Schedule Page: 326.9 Line No.: 10 Column: l
Ancillary services.
Schedule Page: 326.10 Line No.: 6 Column: l
Line loss.
Schedule Page: 326.10 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.10 Line No.: 7 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Operation expense plus amortization of unrecovered costs of Cove Project.
Schedule Page: 326.10 Line No.: 8 Column: b
Portland General Electric Company - contract termination date: terminates when the Round
Butte project is no longer operating for power production purposes.
Schedule Page: 326.10 Line No.: 8 Column: l
Operation expense plus amortization of unrecovered costs of Cove Project.
Schedule Page: 326.10 Line No.: 9 Column: l
Reserve share.
Schedule Page: 326.10 Line No.: 13 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.10 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.10 Line No.: 14 Column: l
Settlement adjustment.
Schedule Page: 326.11 Line No.: 2 Column: l
Line loss.
Schedule Page: 326.11 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: 326.11 Line No.: 3 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.11 Line No.: 3 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio standard
requirements.
Schedule Page: 326.11 Line No.: 4 Column: l
Reserve share.
Schedule Page: 326.11 Line No.: 5 Column: a
This footnote applies to all occurrences of "PUD No. 1 of Clark County" on pages 326-327.
Complete name is Public Utility District No. 1 of Clark County.
Schedule Page: 326.11 Line No.: 6 Column: a
This footnote applies to all occurrences of "PUD No. 1 of Cowlitz County" on pages
326-327. Complete name is Public Utility District No. 1 of Cowlitz County.
Schedule Page: 326.11 Line No.: 6 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.11 Line No.: 6 Column: l
Liability associated with paper pond at hydro facility located on the Lewis River in the
state of Washington.
Schedule Page: 326.11 Line No.: 7 Column: a
This footnote applies to all occurrences of "PUD No. 1 of Douglas County" on pages
326-327. Complete name is Public Utility District No. 1 of Douglas County.
Schedule Page: 326.11 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.11 Line No.: 7 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.11 Line No.: 8 Column: b
Public Utility District No. 1 of Douglas County - contract termination date: August 31,
2018.
Schedule Page: 326.11 Line No.: 9 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.11 Line No.: 10 Column: l
Reserve share.
Schedule Page: 326.11 Line No.: 11 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 326.11 Line No.: 12 Column: a
This footnote applies to all occurrences of "PUD No. 2 of Grant County" on pages 326-327.
Complete name is Public Utility District No. 2 of Grant County.
Schedule Page: 326.11 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.11 Line No.: 12 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.11 Line No.: 13 Column: l
Operating expense, bond interest, amortization and taxes.
Schedule Page: 326.11 Line No.: 14 Column: l
Reserve share.
Schedule Page: 326.12 Line No.: 1 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.12 Line No.: 1 Column: l
Purchase of renewable energy credit certificates for Oregon renewable portfolio standard
requirements.
Schedule Page: 326.12 Line No.: 2 Column: l
Reserve share.
Schedule Page: 326.12 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.12 Line No.: 10 Column: l
Settlement adjustment.
Schedule Page: 326.12 Line No.: 11 Column: b
Sacramento Municipal Utility District - contract termination date: December 31, 2015.
Schedule Page: 326.12 Line No.: 13 Column: l
Line loss.
Schedule Page: 326.13 Line No.: 2 Column: l
Reserve share.
Schedule Page: 326.13 Line No.: 6 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: 326.13 Line No.: 6 Column: l
Reserve share.
Schedule Page: 326.13 Line No.: 7 Column: l
Line loss.
Schedule Page: 326.13 Line No.: 10 Column: a
This footnote applies to all occurrences of "South Utah Valley Electric" on pages 326-327.
Complete name is South Utah Valley Electric Service District.
Schedule Page: 326.13 Line No.: 10 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
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.: 10 Column: l
Reserve share.
Schedule Page: 326.14 Line No.: 14 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: 326.14 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.14 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Settlement adjustment.
Schedule Page: 326.15 Line No.: 2 Column: b
Secondary, economy and/or non-firm.
Schedule Page: 326.15 Line No.: 4 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: 326.15 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 326.15 Line No.: 8 Column: l
Settlement adjustment.
Schedule Page: 326.15 Line No.: 14 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: 326.15 Line No.: 14 Column: b
Tri-State Generation and Transmission Association, Inc. - contract termination date:
December 31, 2020.
Schedule Page: 326.16 Line No.: 1 Column: l
Line loss.
Schedule Page: 326.16 Line No.: 2 Column: l
Line loss.
Schedule Page: 326.16 Line No.: 4 Column: a
This footnote applies to all occurrences of "U.S. Dept of the Interior" on pages 326-327.
Complete name is U.S. Department of the Interior - Bureau of Land Management.
Schedule Page: 326.16 Line No.: 6 Column: b
US Magnesium LLC - contract termination date: December 31, 2017.
Schedule Page: 326.16 Line No.: 6 Column: l
Ancillary services.
Schedule Page: 326.16 Line No.: 7 Column: a
This footnote applies to all occurrences of "United States Air Force at Hill Base" on
pages 326-327. Complete name is United States Air Force at Hill Air Force Base.
Schedule Page: 326.16 Line No.: 8 Column: a
This footnote applies to all occurrences of "Utah Associated Municipal Power Agency" on
pages 326-327. Complete name is Utah Associated Municipal Power Systems.
Schedule Page: 326.16 Line No.: 14 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: 326.16 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.16 Line No.: 14 Column: l
Settlement adjustment.
Schedule Page: 326.17 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.17 Line No.: 3 Column: l
Line loss.
Schedule Page: 326.17 Line No.: 4 Column: b
Western Area Power Administration - contract termination date: May 31, 2022.
Schedule Page: 326.17 Line No.: 4 Column: l
Line loss.
Schedule Page: 326.17 Line No.: 5 Column: l
Reserve share.
Schedule Page: 326.17 Line No.: 6 Column: l
Line loss.
Schedule Page: 326.17 Line No.: 10 Column: l
Settlement associated with insufficient line loss compensation in the past.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
Schedule Page: 326.17 Line No.: 11 Column: l
Reflects transactions that did not physically settle.
Schedule Page: 326.17 Line No.: 12 Column: l
Reflects transactions that did not physically settle.
Schedule Page: 326.17 Line No.: 13 Column: l
Purchases of greenhouse gas allowances for compliance with the California Air Resources
Board greenhouse gas cap-and-trade program.
Schedule Page: 326.17 Line No.: 14 Column: a
Purchase power agreement fair value adjustment amortization related to the acquisition of
Eagle Mountain City, a Utah municipal corporation.
Schedule Page: 326.17 Line No.: 14 Column: l
Amortization of a purchase power agreement adjusted to fair value as part of a service
territory acquisition.
Schedule Page: 326.18 Line No.: 1 Column: l
Deferrals and associated amortization under various energy cost adjustment mechanisms.
Schedule Page: 326.18 Line No.: 2 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: 326.18 Line No.: 5 Column: l
Exchange energy expense.
Schedule Page: 326.18 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.18 Line No.: 7 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.18 Line No.: 8 Column: l
Imbalance energy.
Schedule Page: 326.18 Line No.: 9 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.18 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.18 Line No.: 10 Column: l
Storage and exchange charges.
Schedule Page: 326.18 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 326.18 Line No.: 11 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.18 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.18 Line No.: 12 Column: l
Imbalance energy.
Schedule Page: 326.18 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.18 Line No.: 13 Column: l
Storage and exchange charges.
Schedule Page: 326.18 Line No.: 14 Column: l
Storage and exchange charges.
Schedule Page: 326.19 Line No.: 1 Column: l
Storage and exchange charges.
Schedule Page: 326.19 Line No.: 2 Column: l
Storage and exchange charges.
Schedule Page: 326.19 Line No.: 3 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.19 Line No.: 4 Column: l
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
Imbalance energy.
Schedule Page: 326.19 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 326.19 Line No.: 6 Column: l
Energy Imbalance Market entity settlements.
Schedule Page: 326.19 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.19 Line No.: 7 Column: l
Energy Imbalance Market participating resource settlements.
Schedule Page: 326.19 Line No.: 8 Column: l
Energy Imbalance Market entity settlements.
Schedule Page: 326.19 Line No.: 9 Column: l
Energy Imbalance Market participating resource settlements.
Schedule Page: 326.19 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326.19 Line No.: 10 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.19 Line No.: 11 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.19 Line No.: 12 Column: l
Exchange energy expense.
Schedule Page: 326.19 Line No.: 13 Column: a
This footnote applies to all occurrences of "Constellation Energy Commodities Group" on
pages 326-327. Complete name is Constellation Energy Commodities Group, Inc.
Schedule Page: 326.19 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.19 Line No.: 13 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.19 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.19 Line No.: 14 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 1 Column: l
Imbalance energy.
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: l
Storage and exchange charges.
Schedule Page: 326.20 Line No.: 5 Column: l
Exchange energy expense.
Schedule Page: 326.20 Line No.: 6 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.20 Line No.: 7 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 8 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.20 Line No.: 9 Column: l
PacifiCorp imbalance energy service for others.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
Schedule Page: 326.20 Line No.: 11 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.20 Line No.: 12 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: 326.20 Line No.: 12 Column: b
Settlement adjustment.
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
Station service for third party wind project.
Schedule Page: 326.21 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 326.21 Line No.: 1 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.21 Line No.: 2 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.21 Line No.: 3 Column: l
Reimbursement for providing station service to third party wind project.
Schedule Page: 326.21 Line No.: 4 Column: l
Reimbursement for providing station service to third party wind project.
Schedule Page: 326.21 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 326.21 Line No.: 5 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.21 Line No.: 6 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.21 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.21 Line No.: 7 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.21 Line No.: 8 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.21 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.21 Line No.: 9 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.21 Line No.: 10 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.21 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 326.21 Line No.: 11 Column: l
Imbalance energy.
Schedule Page: 326.21 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.21 Line No.: 12 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.21 Line No.: 13 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.22 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 326.22 Line No.: 1 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
PacifiCorp imbalance energy service for others.
Schedule Page: 326.22 Line No.: 2 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.22 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 326.22 Line No.: 4 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.22 Line No.: 5 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.22 Line No.: 7 Column: l
Storage and exchange charges.
Schedule Page: 326.22 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.22 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 326.22 Line No.: 11 Column: l
Exchange energy expense.
Schedule Page: 326.22 Line No.: 12 Column: l
Exchange energy expense.
Schedule Page: 326.22 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.22 Line No.: 13 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.22 Line No.: 14 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.23 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 326.23 Line No.: 1 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.23 Line No.: 2 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.23 Line No.: 3 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: 326.23 Line No.: 3 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.23 Line No.: 4 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.23 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 326.23 Line No.: 5 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.23 Line No.: 6 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.23 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.23 Line No.: 7 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.23 Line No.: 8 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.23 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 326.23 Line No.: 9 Column: l
Imbalance energy.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
Schedule Page: 326.23 Line No.: 10 Column: l
Imbalance energy.
Schedule Page: 326.23 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 326.23 Line No.: 11 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.23 Line No.: 12 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.23 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 326.23 Line No.: 13 Column: l
Imbalance energy.
Schedule Page: 326.23 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 326.23 Line No.: 14 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.24 Line No.: 1 Column: l
Imbalance energy.
Schedule Page: 326.24 Line No.: 2 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.24 Line No.: 3 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: 326.24 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 326.24 Line No.: 3 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.24 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 326.24 Line No.: 4 Column: l
Imbalance energy.
Schedule Page: 326.24 Line No.: 5 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.24 Line No.: 6 Column: l
Imbalance energy.
Schedule Page: 326.24 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326.24 Line No.: 7 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.24 Line No.: 8 Column: b
Settlement adjustment.
Schedule Page: 326.24 Line No.: 8 Column: l
Imbalance energy.
Schedule Page: 326.24 Line No.: 9 Column: l
PacifiCorp imbalance energy service for others.
Schedule Page: 326.24 Line No.: 10 Column: l
Imbalance energy.
Schedule Page: 326.24 Line No.: 11 Column: l
Imbalance energy.
Schedule Page: 326.24 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 326.24 Line No.: 12 Column: l
Imbalance energy.
Schedule Page: 326.24 Line No.: 13 Column: l
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.11
Imbalance energy.
Schedule Page: 326.24 Line No.: 14 Column: l
Allocations of energy imbalance market charge codes to transmission customers.
Schedule Page: 326.25 Line No.: 1 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.12
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 / /2015/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
Basin Electric Power Cooperative Western Area Power Administration Powder River Energy Corporation SFP 5
Black Hills/Colorado Electric Utility Company NF 6
Black Hills/Colorado Electric Utility Company SFP 7
Black Hills Corporation PacifiCorp Montana-Dakota Utilities FNO 8
Black Hills Corporation PacifiCorp Montana-Dakota Utilities AD 9
Black Hills Corporation PacifiCorp Black Hills Corporation LFP 10
Black Hills Corporation PacifiCorp Black Hills Corporation AD 11
Black Hills Corporation NF 12
Black Hills Corporation AD 13
Black Hills Corporation SFP 14
Black Hills Corporation AD 15
Black Hills Power Marketing NF 16
Black Hills Power Marketing AD 17
Black Hills Power Marketing SFP 18
Black Hills Power Marketing AD 19
Bonneville Power Administration OS 20
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 21
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 22
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration LFP 23
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 24
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative FNO 25
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative AD 26
Bonneville Power Administration Bonneville Power Administration Benton REA FNO 27
Bonneville Power Administration Bonneville Power Administration Benton REA AD 28
Bonneville Power Administration Bonneville Power Administration Umatilla Electric and Columbia FNO 29
Bonneville Power Administration Bonneville Power Administration Umatilla Electric and Columbia AD 30
Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration LFP 31
Bonneville Power Administration U. S. Bureau of Reclamation Bonneville Power Administration 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 / /2015/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 3,540 3,540 2
Yellowtail SubV11-1-4,9 Sheridan Substation 1 453 453 3
VariousV11-1,2,8 Various 2,334 2,334 4
VariousV11-1,2,7 Various 67,599 67,599 5
VariousV11-1,2,8 Various 768 768 6
VariousV11-1,2,7 Various 330 330 7
VariousV11-1,2 Sheridan Substation 46 8
VariousV11-1,2 Sheridan Substation 40 9
VariousV11-1,2,7 Wyodak Substation 52 219,571 219,571 10
VariousV11-1,2,7 Wyodak Substation 52 17,877 17,877 11
VariousV11-1,2,8 Various 18,012 18,012 12
VariousV11-1,2,8 Various 894 894 13
VariousV11-1,2,7 Various 14,023 14,023 14
VariousV11-1,2,7 Various 267 267 15
VariousV11-1,2,8 Various 1,583 1,583 16
VariousV11-1,2,8 Various 48 48 17
VariousV11-1,2,7 Various 471 471 18
VariousV11-1,2,7 Various 49 49 19
Midpoint SubstationR.S. 369 Summer Lake Sub 20
VariousR.S. 237 Various 351 1,103,020 1,103,020 21
VariousR.S. 237 Various 301 89,261 89,261 22
Lost Creek Hydro PltV11-2,7 Alvey Substation 58 195,283 195,283 23
Lost Creek Hydro PltV11-2,7 Alvey Substation 58 29,721 29,721 24
Bonneville Power AdmV11-1-3,5,6 Gazley Substation 3 22,533 22,533 25
Bonneville Power AdmV11-1-6,9 Gazley Substation 3 2,133 2,133 26
Bonneville Power AdmV11-1-3,5,6 Tieton Substation 1 4,650 4,650 27
Bonneville Power AdmV11-1-6,9 Tieton Substation 2 788 788 28
McNary SubstationV11-1-3,5,6 Hinkle Substation 1 1,027 1,027 29
McNary SubstationV11-1-6,9 Hinkle Substation 1 133 133 30
USBR Green SpringsV11-2,7 Bonneville Power Adm 19 54,521 54,521 31
USBR Green SpringsV11-2,7 Bonneville Power Adm 19 4,632 4,632 32
Malin SubstationR.S. 368 Malin Substation 668,212 668,212 33
Malin SubstationR.S. 368 Malin Substation 60,304 60,304 34
FERC FORM NO. 1 (ED. 12-90) Page 329
4,830 13,260,949 13,147,879
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 / /2015/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
9,405 23,601 14,196 2
1,663 1,663 3
19,871 875 18,996 4
439,506 19,397 420,109 5
3,815 165 3,650 6
1,556 133 1,423 7
1,224,999 1,280,190 55,191 8
25,614 25,614 9
1,341,098 1,400,807 59,709 10
56,274 56,274 11
6,978 296 6,682 12
499 499 13
10,236 244 9,992 14
1,865 1,865 15
2,080 516 1,564 16
2,317 2,317 17
8,633 768 7,865 18
5,391 5,391 19
20
4,337,356 4,405,303 67,947 21
650,754 650,754 22
1,502,041 1,517,452 15,411 23
57,585 57,585 24
81,559 240,089 158,530 25
40,453 40,453 26
17,398 22,848 5,450 27
7,582 7,582 28
5,904 7,365 1,461 29
1,213 1,213 30
482,800 487,592 4,792 31
62,110 62,110 32
246,946 246,946 33
44,899 44,899 34
FERC FORM NO. 1 (ED. 12-90) Page 330
50,709,199 92,780,346 32,610,035 9,461,112
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 / /2015/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying
facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Bonneville Power Administration Bonneville Power Administration Yakama Power FNO 1
Bonneville Power Administration Bonneville Power Administration Yakama Power AD 2
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 3
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 4
Bonneville Power Administration NF 5
Bonneville Power Administration SFP 6
Bonneville Power Administration Bonneville Power Administration Clark Public Utilities FNO 7
Bonneville Power Administration Bonneville Power Administration Clark Public Utilities AD 8
Cargill Power Markets, LLC NF 9
Cargill Power Markets, LLC AD 10
City of Anaheim NF 11
City of Anaheim SFP 12
Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration OS 13
Cowlitz County PUD Cowlitz County PUD Bonneville Power Administration AD 14
Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans.OS 15
Deseret Generation & Trans. Deseret Generation & Trans. Deseret Generation & Trans.AD 16
Deseret Generation & Trans.NF 17
Deseret Generation & Trans.AD 18
Eugene Water & Electric Board SFP 19
Enel Cove Fort, LLC Enel Cove Fort, LLC LFP 20
Exelon Generation Company, LLC. Bonneville Power Administration Oregon Direct Access FNO 21
Exelon Generation Company, LLC.NF 22
Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company OS 23
Fall River Rural Electric Cooperative Marysville Hydro Partners Idaho Power Company AD 24
Foote Creek III, LLC Foote Creek III, LLC PacifiCorp OS 25
Foote Creek III, LLC Foote Creek III, LLC PacifiCorp AD 26
Iberdrola Renewables, LLC NF 27
Iberdrola Renewables, LLC AD 28
Iberdrola Renewables, LLC SFP 29
Iberdrola Renewables, LLC AD 30
Iberdrola Renewables, LLC Iberdrola Renewables, LLC OS 31
Iberdrola Renewables, LLC Iberdrola Renewables, LLC AD 32
Iberdrola Renewables, LLC Exxon Mobil Nevada Power Company LFP 33
Iberdrola Renewables, LLC Exxon Mobil Nevada Power Company AD 34
FERC FORM NO. 1 (ED. 12-90) Page 328.1
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2015/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 AdmV11-1-3,5,6 5 33,133 33,133 1
Bonneville Power AdmV11-1-6,9 5 3,373 3,373 2
VariousR.S. 299 Various 185 850,964 850,964 3
VariousR.S. 299 Various 193 96,677 96,677 4
VariousV11-1,2,8 Various 1,342 1,342 5
VariousV11-1,2,7 Various 6
Cardwell-MerwinV11-1,2,3 19 103,419 103,419 7
Cardwell-MerwinV11-1-4,9 30 13,327 13,327 8
VariousV11-1,2,8 Various 28,739 28,739 9
VariousV11-1,2,8 Various 845 845 10
VariousV11-1,2,8 Various 13,205 13,205 11
VariousV11-1,2,7 Various 738 738 12
Swift Unit No. 2R.S. 234 Woodland Substation 13
Swift Unit No. 2R.S. 234 Woodland Substation 14
VariousR.S. 280 Various 98 638,185 638,185 15
VariousR.S. 280 Various 95 46,508 46,508 16
VariousV11-1,2,8 Various 9,328 9,328 17
VariousV11-1,2,8 Various 24 24 18
VariousV11-1,2,7 Various 19
Enel Cove FortV11-1-3,7 Red Butte Substation 16 20
Bonneville Power AdmV11-1-3,5,6 Various 3 8,583 8,583 21
VariousV 11-1-6,8,11 Various 97 97 22
Targhee SubstationR.S. 322 Goshen Substation 23
Targhee SubstationR.S. 322 Goshen Substation 24
Foote Creek SubS.A. 761 Various 25
Foote Creek SubS.A. 761 Various 26
VariousV11-1-3,8,9 Various 165,283 165,283 27
VariousV11-1-3,8,9 Various 19,167 19,167 28
VariousV11-1-3,7 Various 54,193 54,193 29
VariousV11-1-3,7 Various 4,298 4,298 30
V11-5,6 31
V11-5,6 32
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 31 59,830 59,830 33
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 31 6,935 6,935 34
FERC FORM NO. 1 (ED. 12-90) Page 329.1
4,830 13,260,949 13,147,879
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 / /2015/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.
138,584 266,144 127,560 1
44,996 44,996 2
874,891 1,899,464 1,024,573 3
174,718 174,718 4
12,465 577 11,888 5
7 7 6
480,451 618,984 138,533 7
140,458 140,458 8
173,811 7,622 166,189 9
5,497 5,497 10
105,964 4,310 101,654 11
5,754 233 5,521 12
147,267 147,267 13
13,235 13,235 14
2,663,278 4,814,246 2,150,968 15
70,491 70,491 16
82,361 3,602 78,759 17
173 173 18
700,403 691,976 8,427 19
148,600 170,620 22,020 20
35,023 48,121 13,098 21
119,678 63,778 55,900 22
138,699 138,699 23
12,609 12,609 24
52,367 52,367 25
7,548 7,548 26
1,546,498 65,969 1,480,529 27
140,508 140,508 28
533,222 23,457 509,765 29
40,538 40,538 30
217,279 217,279 31
74,479 74,479 32
804,659 840,484 35,825 33
33,764 33,764 34
FERC FORM NO. 1 (ED. 12-90) Page 330.1
50,709,199 92,780,346 32,610,035 9,461,112
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 / /2015/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 Bonneville Power Administration Oregon Direct Access FNO 1
Iberdrola Renewables, LLC Iberdrola Renewables, LLC AD 2
Idaho Power Company Idaho Power Company Idaho Power Company OS 3
Idaho Power Company Exxon Mobil Nevada Power Company LFP 4
Idaho Power Company Exxon Mobil Nevada Power Company AD 5
Idaho Power Company OS 6
Idaho Power Company AD 7
Idaho Power Company OS 8
Idaho Power Company AD 9
Idaho Power Company NF 10
Idaho Power Company SFP 11
Idaho Power Company Marketing NF 12
JP Morgan Ventures Energy Corp.NF 13
JP Morgan Ventures Energy Corp.AD 14
Los Angeles Department of Water & Power SFP 15
Macquarie Energy, LLC NF 16
Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association OS 17
Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association AD 18
Morgan Stanley Capital Group, Inc.NF 19
Morgan Stanley Capital Group, Inc.AD 20
Morgan Stanley Capital Group, Inc.SFP 21
Morgan Stanley Capital Group, Inc.AD 22
Municipal Energy Nebraska, Inc.NF 23
Nevada Power Company NF 24
Nevada Power Company SFP 25
NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD LFP 26
NextEra Energy Resources, LLC NextEra Energy Resources, LLC Grant County PUD AD 27
NextEra Energy Resources, LLC NF 28
NextEra Energy Resources, LLC AD 29
NextEra Energy Resources, LLC SFP 30
Noble Americas Energy Solutions LLC Bonneville Power Administration Oregon Direct Access FNO 31
Noble Americas Energy Solutions LLC Bonneville Power Administration Oregon Direct Access AD 32
Pacific Gas & Electric Company OS 33
Pacific Gas & Electric Company AD 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 / /2015/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.
Ponderosa SubstationV11-1-3,5,6 Various 11 70,895 70,895 1
Ponderosa SubstationV11-1-3,5,6 Various 5 3,806 3,806 2
Goshen SubstationR.S. 427 Goshen Substation 3
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 68,433 68,433 4
Trona SubstationV11-1,2,7 Red Butte/Mona Sub 5
Antelope SubstationR.S. 257 Antelope Substation 145,365 145,365 6
Antelope SubstationR.S. 257 Antelope Substation 20,179 20,179 7
Jim Bridger SubR.S. 203 Bridger Pump Sub 33,599 33,599 8
Jim Bridger SubR.S. 203 Bridger Pump Sub 3,689 3,689 9
VariousV11-1,2,8 Various 30,652 30,652 10
VariousV11-1,2,7 Various 52,680 52,680 11
VariousV11-1,2,8 Various 490 490 12
VariousV11-5,6,8,11 Various 13
VariousV11-5,6,8,11 Various 176 176 14
VariousV11-1,2,7 Various 2,955 2,955 15
VariousV11-1,2,8 Various 50 50 16
DuchesneR.S. 302 Duchesne 21,582 21,582 17
DuchesneR.S. 302 Duchesne 1,994 1,994 18
VariousV11-1-3,8 Various 63,940 63,940 19
VariousV11-1-3,8 Various 2,722 2,722 20
VariousV11-1,2,7 Various 1,381 1,381 21
VariousV11-1,2,7 Various 588 588 22
VariousV11-1,2,8 Various 1 1 23
VariousV11-1,2,8 Various 3,649 3,649 24
VariousV11-1,2,7 Various 700 700 25
Wallula SubstationV11-1-3,5-7 Wala-MIDC path 103 132,898 132,898 26
Wallula SubstationV11-5-7,9 Wala-MIDC path 103 15,845 15,845 27
VariousV11-1-3,8 Various 7,389 7,389 28
VariousV11-1,2,8 Various 222 222 29
VariousV11-1,2,7 Various 15,968 15,968 30
Bonneville Power AdmV11-1-3,5,6 Various 21 133,859 133,859 31
Bonneville Power AdmV11-1-6,9 Various 22 12,720 12,720 32
R.S. 607 33
VariousV11-1,2 Various 34
FERC FORM NO. 1 (ED. 12-90) Page 329.2
4,830 13,260,949 13,147,879
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 / /2015/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.
144,895 213,788 68,893 1
12,793 12,793 2
3
928,750 971,892 43,142 4
-65,539 -65,539 5
61,520 61,520 6
6,152 6,152 7
13,570 13,570 8
1,357 1,357 9
214,075 9,379 204,696 10
131,356 5,772 125,584 11
3,526 144 3,382 12
21,308 14,080 7,228 13
264,264 264,264 14
43,151 1,744 41,407 15
264 12 252 16
17,655 17,655 17
3,210 3,210 18
394,424 17,107 377,317 19
16,554 16,554 20
10,930 471 10,459 21
2,748 2,748 22
60 3 57 23
10,343 1,878 8,465 24
20,620 926 19,694 25
1,749,535 2,101,359 351,824 26
221,758 221,758 27
191,428 21,627 169,801 28
6,440 6,440 29
14,759 655 14,104 30
268,820 406,090 137,270 31
48,425 48,425 32
13,291,667 13,291,667 33
1,208,333 1,208,333 34
FERC FORM NO. 1 (ED. 12-90) Page 330.2
50,709,199 92,780,346 32,610,035 9,461,112
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 / /2015/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.
Pacific Gas & Electric Company OS 1
Pacific Gas & Electric Company NF 2
Pacific Gas & Electric Company AD 3
Portland General Electric Company NF 4
Portland General Electric Company SFP 5
Portland General Electric Company OS 6
Powder River Energy Corporation Western Area Power Administration Sheridan-Johnson Rural Elect.OS 7
Powder River Energy Corporation Western Area Power Administration Sheridan-Johnson Rural Elect.AD 8
Powerex Corporation Bonneville Power Administration CAISO LFP 9
Powerex Corporation Bonneville Power Administration CAISO AD 10
Powerex Corporation Powerex Corporation CAISO LFP 11
Powerex Corporation Powerex Corporation CAISO AD 12
Powerex Corporation Powerex Corporation CAISO LFP 13
Powerex Corporation Powerex Corporation 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 LFP 18
Powerex Corporation Powerex Corporation CAISO LFP 19
Powerex Corporation Powerex Corporation CAISO LFP 20
Powerex Corporation NF 21
Powerex Corporation AD 22
Powerex Corporation SFP 23
Powerex Corporation AD 24
Public Svc. Co. of CO AD 25
Puget Sound Power & Light Company NF 26
Puget Sound Power & Light Company AD 27
Rainbow Energy Marketing Corporation NF 28
Rainbow Energy Marketing Corporation SFP 29
Sacramento Municipal Utility District Sacramento Municipal Utility Dist Sacramento Municipal Utility Dist LFP 30
Sacramento Municipal Utility District Sacramento Municipal Utility Dist Sacramento Municipal Utility Dist AD 31
Salt River Project Salt River Project Salt River Project LFP 32
Salt River Project Salt River Project Salt River Project AD 33
Salt River Project NF 34
FERC FORM NO. 1 (ED. 12-90) Page 328.3
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2015/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.
Sigurd-Glen CanyonR.S. 298 Pinto-Four Corners 1
VariousV11-1,2,8 Various 1,024 1,024 2
VariousV11-1,2,8 Various 260 260 3
VariousV11-1,2,8 Various 6,594 6,594 4
VariousV11-1,2,7 Various 2,172 2,172 5
VariousR.S. 137 Various 6
VariousR.S. 123 Buffalo Substation 7
VariousR.S. 123 Buffalo Substation 8
Bonneville Power AdmV11-1,2,7 CRAG View Substation 83 690,921 690,921 9
Bonneville Power AdmV11-1,2,7 CRAG View Substation 83 46,151 46,151 10
Malin 500 SubstationV11-1,7 Round Mountain Sub 67 11
Malin 500 SubstationV11-1,7 Round Mountain Sub 67 12
Malin 500 SubstationV11-1,7 Round Mountain Sub 67 13
Malin 500 SubstationV11-1,7 Round Mountain Sub 67 14
Malin 500 SubstationV11-1,7 Round Mountain Sub 66 15
Malin 500 SubstationV11-1,7 Round Mountain Sub 66 16
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 17
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 18
Malin 500 SubstationV11-1,7 Round Mountain Sub 150 19
Malin 500 SubstationV11-1,7 Round Mountain Sub 50 20
VariousV11-1-3,8 Various 379,453 379,453 21
VariousV11-1,2,8 Various 4,485 4,485 22
VariousV11-1-3,7 Various 59,045 59,045 23
VariousV11-1,2,7 Various 388 388 24
VariousV11-1,2,7 Various 640 640 25
VariousV11-1,2,8 Various 1 1 26
VariousV11-1,2,8 Various 27
VariousV11-1,2,8 Various 535 535 28
VariousV11-1,2,7 Various 29
Malin SubstationV11-1,2,7 Malin Substation 31 115,619 115,619 30
Malin SubstationV11-1,2,7 Malin Substation 31 12,906 12,906 31
Enel Cove FortV11-1,2,7 Red Butte Substation 26 121,653 121,653 32
Enel Cove FortV11-1,2,7 Red Butte Substation 26 8,973 8,973 33
VariousV11-1-3,8 Various 22 22 34
FERC FORM NO. 1 (ED. 12-90) Page 329.3
4,830 13,260,949 13,147,879
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 / /2015/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.
204,979 204,979 1
12,047 933 11,114 2
1,871 1,871 3
39,026 1,682 37,344 4
15,850 712 15,138 5
3,314 3,314 6
341 341 7
31 31 8
2,145,757 2,254,552 108,795 9
90,039 90,039 10
1,723,643 1,766,605 42,962 11
69,255 69,255 12
1,723,643 1,766,605 42,962 13
69,255 69,255 14
1,697,917 1,740,237 42,320 15
68,222 68,222 16
1,286,302 1,318,364 32,062 17
51,683 51,683 18
3,858,904 3,955,087 96,183 19
155,049 155,049 20
2,389,897 118,072 2,271,825 21
38,666 38,666 22
149,393 8,937 140,456 23
2,836 2,836 24
4,603 4,603 25
14 14 26
22 22 27
1,889 83 1,806 28
11,620 484 11,136 29
804,659 840,484 35,825 30
33,764 33,764 31
546,716 572,500 25,784 32
28,137 28,137 33
180 7 173 34
FERC FORM NO. 1 (ED. 12-90) Page 330.3
50,709,199 92,780,346 32,610,035 9,461,112
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 / /2015/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.
Salt River Project AD 1
Salt River Project SFP 2
Sempra Generation NF 3
Shell Energy Corporation, Inc NextEra Energy Resources, LLC Grant County PUD LFP 4
Shell Energy Corporation, Inc NF 5
Shell Energy Corporation, Inc AD 6
Shell Energy Corporation, Inc SFP 7
Shell Energy Corporation, Inc AD 8
Sierra Pacific Power Company OS 9
Sierra Pacific Power Company AD 10
Southern California Edison Company OS 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 Public Power Authority Powerex Corporation Southern California Public Power OS 16
State of South Dakota Western Area Power Administration Black Hills Corporation LFP 17
State of South Dakota Western Area Power Administration Black Hills Corporation AD 18
Talen Energy Marketing, LLC NF 19
Talen Energy Marketing, LLC AD 20
Talen Energy Marketing, LLC SFP 21
Talen Energy Marketing, LLC AD 22
Tenaska Power Services Co NF 23
Tenaska Power Services Co AD 24
Tenaska Power Services Co SFP 25
The Energy Authority, Inc.NF 26
The Energy Authority, Inc.AD 27
The Energy Authority, Inc.SFP 28
Thermo No. 1 BE-01, LLC Thermo Geothermal Project LFP 29
Thermo No. 1 BE-01, LLC Thermo Geothermal Project AD 30
TransAlta Energy Marketing (U.S.) Inc NF 31
TransAlta Energy Marketing (U.S.) Inc AD 32
Tri-State Generation & Trans. Tri-State Generation & Trans.AD 33
Tri-State Generation & Trans. Tri-State Generation & Trans.FNO 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 / /2015/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.
VariousV11-1-3,8 Various 846 846 1
VariousV11-1,2,7 Various 24,820 24,820 2
VariousV11-1,2,8 Various 3
Wallula SubstationV11-1,2,7 Wala-MIDC path 63,618 63,618 4
VariousV11-1,2,8 Various 23,329 23,329 5
VariousV11-1,2,8 Various 2,082 2,082 6
VariousV11-1,2,7 Various 13,732 13,732 7
VariousV11-1,2,7 Various 5,286 5,286 8
Sigurd SubstationR.S. 674 Utah-Nevada Border 9
Sigurd SubstationR.S. 674 Utah-Nevada Border 10
Sigurd-Glen CanyonR.S. 298 Pinto-Four Corners 11
Various Various 73,743 73,743 12
Various Various 5,321 5,321 13
VariousV11-1-3,7 Various 270 270 14
VariousV11-1-3,7 Various 15
Tieton SubstationV11-1-3,11 Various 62 62 16
Yellowtail SubV11-1,2,7 Wyodak Substation 4 16,849 16,849 17
Yellowtail SubV11-1,2,7 Wyodak Substation 4 1,518 1,518 18
VariousV11-1,2,8 Various 9,590 9,590 19
VariousV11-1,2,8 Various 465 465 20
VariousV11-1,2,7 Various 3,631 3,631 21
VariousV11-1,2,7 Various 797 797 22
VariousV11-1-3,8 Various 5,680 5,680 23
VariousV11-1-3,8 Various 7,133 7,133 24
VariousV11-1,2,7 Various 1,617 1,617 25
VariousV11-1,2,8 Various 12,387 12,387 26
VariousV11-1,2,8 Various 760 760 27
VariousV11-1,2,7 Various 1,386 1,386 28
South Milford SubV11-1-3,5-7 Mona Substation 11 58,503 58,503 29
South Milford SubV11-1-3,5-7,9 Mona Substation 11 5,493 5,493 30
VariousV11-1,2,8 Various 42,662 42,662 31
VariousV11-1,2,8 Various 7,564 7,564 32
VariousR.S. 123 Various 33
Dave Johnston SubV11-1,2,3 Thermopolis Sub 28 178,814 178,814 34
FERC FORM NO. 1 (ED. 12-90) Page 329.4
4,830 13,260,949 13,147,879
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 / /2015/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.
4,322 4,322 1
127,904 4,071 123,833 2
7 7 3
4
120,466 6,735 113,731 5
11,554 11,554 6
7,409 305 7,104 7
19,823 19,823 8
68,919 68,919 9
12,531 12,531 10
274,174 274,174 11
2,698,689 458,283 2,240,406 12
248,346 248,346 13
2,377 306 2,071 14
3,496 3,496 15
3,382 3,382 16
107,277 112,053 4,776 17
6,596 6,596 18
63,285 2,829 60,456 19
3,346 3,346 20
22,132 982 21,150 21
5,735 5,735 22
35,093 1,597 33,496 23
41,695 41,695 24
10,258 931 9,327 25
66,835 2,783 64,052 26
4,639 4,639 27
9,574 427 9,147 28
295,052 384,052 89,000 29
19,505 19,505 30
232,348 9,818 222,530 31
43,994 43,994 32
16,723 16,723 33
729,540 969,342 239,802 34
FERC FORM NO. 1 (ED. 12-90) Page 330.4
50,709,199 92,780,346 32,610,035 9,461,112
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 / /2015/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. Tri-State Generation & Trans.AD 1
Tri-State Generation & Trans.NF 2
Tri-State Generation & Trans.AD 3
Tucson Power Company.NF 4
U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation FNO 5
U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation AD 6
U.S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.OS 7
U.S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.AD 8
U.S. Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District OS 9
Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power OS 10
Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power AD 11
Utah Associated Municipal Power Systems NF 12
Utah Associated Municipal Power Systems AD 13
Utah Associated Municipal Power Systems SFP 14
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency OS 15
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency AD 16
Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric Co OS 17
Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric Co AD 18
Western Area Power Administration Western Area Power Administration OS 19
Western Area Power Administration Western Area Power Administration AD 20
Western Area Power Administration Western Area Power Administration OS 21
Western Area Power Administration Western Area Power Administration AD 22
Western Area Power Administration Western Area Power Administration OS 23
Western Area Power Administration Western Area Power Administration Western Area Power Administration FNO 24
Western Area Power Administration Western Area Power Adm. CO River Western Area Power Administration AD 25
Western Area Power Adm CO River Western Area Power Adm. CO River NF 26
Western Area Power Adm CO River Western Area Power Adm CO River SFP 27
Western Area Power Adm CO MO Western Area Power Adm CO River NF 28
Western Area Power Adm CO MO Western Area Power Adm CO River AD 29
Western Area Power Adm CO MO Western Area Power Adm CO MO SFP 30
Western Area Power Adm CO MO Western Area Power Adm CO MO AD 31
Accrual 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 / /2015/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.
Dave Johnston SubV11-1-4 Thermopolis Sub 32 17,958 17,958 1
VariousV11-1,2,8 Various 709 709 2
VariousV11-1,2,8 Various 36 36 3
VariousV11-1,2,8 Various 800 800 4
Walla Walla SubV11-1,2,3 Burbank Pumps 1 2,048 2,048 5
Walla Walla SubV11-1,2,3 Burbank Pumps 1 3 3 6
VariousR.S. 286 Various 26,112 26,112 7
VariousR.S. 286 Various 981 981 8
Redmond SubstationR.S. 67 Crooked River Pumps 11,327 11,327 9
VariousR.S. 297 Various 519 2,682,662 2,682,662 10
VariousR.S. 297 Various 409 218,101 218,101 11
VariousV11-1-3,8 Various 4,608 4,608 12
VariousV11-1,2,8 Various 2,522 2,522 13
VariousV11-1-3,7 Various 31,154 31,154 14
VariousR.S. 637 Various 106 611,727 611,727 15
VariousR.S. 637 Various 77 53,740 53,740 16
Pelton ReregulatingR.S. 591 Round Butte Sub 74,331 74,331 17
Pelton ReregulatingR.S. 591 Round Butte Sub 9,001 9,001 18
VariousR.S. 262 Various 330 1,627,305 1,529,667 19
VariousR.S. 262 Various 330 169,693 159,511 20
VariousR.S. 263 Various 73,085 68,268 21
VariousR.S. 263 Various 8,718 8,073 22
Dave Johnston SubR.S. 684 Various 23
Wyoming DistributionV11-1,2 Wyoming Distribution 2 10,506 10,506 24
VariousV11-1,2,8 Wyoming Distribution 2 2 25
VariousV11-1,2,8 Various 1,439 1,439 26
VariousV11-1,2,7 Various 27
VariousV11-1,2,8 Various 498 498 28
VariousV11-1,2,8 Various 188 188 29
VariousV11-1,2,7 Various 190 190 30
VariousV11-1,2,7 Various 425 425 31
11,623 11,835 32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.5
4,830 13,260,949 13,147,879
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 / /2015/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.
102,672 102,672 1
4,563 197 4,366 2
214 214 3
5,978 265 5,713 4
6,414 16,863 10,449 5
-3,025 -3,025 6
26,112 26,112 7
981 981 8
10,579 10,579 9
13,403,473 16,057,651 2,654,178 10
592,552 592,552 11
27,674 3,562 24,112 12
13,103 13,103 13
168,154 21,610 146,544 14
2,730,510 3,235,158 504,648 15
128,183 128,183 16
109,725 109,725 17
9,975 9,975 18
2,312,834 2,862,834 550,000 19
269,047 269,047 20
45,470 45,470 21
6,170 6,170 22
23
40,463 87,025 46,562 24
-2,071 -2,071 25
8,539 364 8,175 26
166 7 159 27
3,874 291 3,583 28
1,115 1,115 29
822 44 778 30
1,746 1,746 31
1,485,257 1,485,257 32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.5
50,709,199 92,780,346 32,610,035 9,461,112
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
2014 transmission and ancillary services.
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.
Schedule Page: 328 Line No.: 5 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 5 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 6 Column: a
This footnote applies to all occurrences of "Black Hills/Colorado Electric Utility
Company" on pages 328-330. Complete name is Black Hills/Colorado Electric Utility Company,
L.P.
Schedule Page: 328 Line No.: 6 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 6 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 6 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 6 Column: m
Transmission resale, purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service.
Schedule Page: 328 Line No.: 7 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 7 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 7 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 8 Column: d
Network transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 347) terminating on December 31, 2017.
Schedule Page: 328 Line No.: 8 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 9 Column: d
Network transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 347) terminating on December 31, 2017.
Schedule Page: 328 Line No.: 9 Column: m
2014 transmission and ancillary services.
Schedule Page: 328 Line No.: 10 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.: 10 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 11 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.: 11 Column: m
2014 transmission and ancillary services.
Schedule Page: 328 Line No.: 12 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 12 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 12 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 12 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 13 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 13 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 13 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 13 Column: m
2014 transmission and ancillary services.
Schedule Page: 328 Line No.: 14 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 14 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 14 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328 Line No.: 14 Column: m
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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.: 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.: 15 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 16 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 16 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 16 Column: m
Transmission resale, amount paid by seller. Scheduling, system control and dispatch
service. Reactive supply and voltage control service.
Schedule Page: 328 Line No.: 17 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 17 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 17 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 18 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 18 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 18 Column: m
Transmission resale, amount paid by seller. Scheduling, system control and dispatch
service. Reactive supply and voltage control service.
Schedule Page: 328 Line No.: 19 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 19 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 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 Line No.: 19 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328 Line No.: 20 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.
Schedule Page: 328 Line No.: 20 Column: c
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.
Schedule Page: 328 Line No.: 20 Column: d
Legacy Contract executed between PacifiCorp and Bonneville Power Administration ("BPA")
concerning the exchange of transmission services over agreed-upon facilities
("Midpoint-Meridian Transmission Agreement", Rate Schedule 369). This agreement runs
concurrently with the AC Intertie Agreement (Rate Schedule 368), which terminates when the
facilities subject to that agreement are taken out of service. See also page 332,
Transmission of electricity by others, in this Form No. 1.
Schedule Page: 328 Line No.: 21 Column: d
Legacy Contract (3rd Revised Rate Schedule 237) executed between PacifiCorp and BPA for
transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge. Contract subject to termination upon the earlier of the termination of
the "Exchange Agreement" between PacifiCorp and BPA or the time of the termination of all
deliveries as defined in the agreement.
Schedule Page: 328 Line No.: 21 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. 2013-2014 transmission demand adjustments.
Schedule Page: 328 Line No.: 22 Column: d
Legacy Contract (3rd Revised Rate Schedule 237) executed between PacifiCorp and BPA for
transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge. Contract subject to termination upon the earlier of the termination of
the "Exchange Agreement" between PacifiCorp and BPA or the time of the termination of all
deliveries as defined in the agreement.
Schedule Page: 328 Line No.: 22 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. 2014 transmission and ancillary services.
Schedule Page: 328 Line No.: 23 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.: 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. Reactive supply and voltage control service.
Schedule Page: 328 Line No.: 24 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.: 24 Column: m
2014 transmission and ancillary services.
Schedule Page: 328 Line No.: 25 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.: 25 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.: 25 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. Operating reserve - spinning reserve service. Operating
reserve - supplemental reserve service.
Schedule Page: 328 Line No.: 26 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 328 Line No.: 26 Column: m
2014 transmission and ancillary services.
Schedule Page: 328 Line No.: 27 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.: 27 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.: 27 Column: m
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 Line No.: 28 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.: 28 Column: m
2014 transmission and ancillary services. Operating reserve - supplemental reserve
service.
Schedule Page: 328 Line No.: 29 Column: c
This footnote applies to all occurrences of "Umatilla Electric and Columbia" on pages
328-330. Complete name is Umatilla Electric Cooperative Association and Columbia Basin
Electric Cooperative, Inc.
Schedule Page: 328 Line No.: 29 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.: 29 Column: m
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 Line No.: 30 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.: 30 Column: m
2014 transmission and ancillary services.
Schedule Page: 328 Line No.: 31 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.: 31 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.: 31 Column: m
Reactive supply and voltage control service.
Schedule Page: 328 Line No.: 32 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.: 32 Column: m
2014 transmission and ancillary services.
Schedule Page: 328 Line No.: 33 Column: d
Legacy Contract (5th Revised Rate Schedule 368) executed between PacifiCorp and BPA for
transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge. Subject to termination upon mutual agreement.
Schedule Page: 328 Line No.: 33 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Schedule Page: 328 Line No.: 34 Column: d
Legacy Contract (5th Revised Rate Schedule 368) executed between PacifiCorp and BPA
for transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge. Subject to termination upon mutual agreement.
Schedule Page: 328 Line No.: 34 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. 2014 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 1 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: 328.1 Line No.: 1 Column: g
White Swan/Toppenish Substations
Schedule Page: 328.1 Line No.: 1 Column: m
Distribution voltage service charge. Primary delivery service. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Generation regulation
and frequency response service. Operating reserve - spinning reserve service. Operating
reserve - supplemental reserve service.
Schedule Page: 328.1 Line No.: 2 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: 328.1 Line No.: 2 Column: g
White Swan/Toppenish Substations
Schedule Page: 328.1 Line No.: 2 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 3 Column: d
Legacy Contract (2nd Revised Rate Schedule 299) executed between PacifiCorp and BPA for
transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge. Contract terminates with three years notice by BPA or five years notice
by PacifiCorp. PacifiCorp provided notice of termination on June 2011.
Schedule Page: 328.1 Line No.: 3 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. Charges for scheduling and operating reserves.
Schedule Page: 328.1 Line No.: 4 Column: d
Legacy Contract (2nd Revised Rate Schedule 299) executed between PacifiCorp and BPA for
transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge. Contract terminates with three years notice by BPA or five years notice
by PacifiCorp. PacifiCorp provided notice of termination on June 2011.
Schedule Page: 328.1 Line No.: 4 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. 2014 transmission and
ancillary services.
Schedule Page: 328.1 Line No.: 5 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 5 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 5 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 5 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 6 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 6 Column: c
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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.: 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.: 7 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.: 7 Column: g
Chelatchie/View 115kV
Schedule Page: 328.1 Line No.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.
Schedule Page: 328.1 Line No.: 8 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.: 8 Column: g
Chelatchie/View 115kV
Schedule Page: 328.1 Line No.: 8 Column: m
2014 transmission and ancillary services.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 10 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 10 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 10 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 10 Column: m
2014 transmission and ancillary services.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 12 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 12 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
Schedule Page: 328.1 Line No.: 12 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 12 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 13 Column: a
This footnote applies to all occurrences of "Cowlitz County PUD" on pages 328-330.
Complete name is Public Utility District No. 1 of Cowlitz County.
Schedule Page: 328.1 Line No.: 13 Column: d
Legacy Contract (Rate Schedule 234) providing for transmission and operation of Swift
Hydroelectric plant No. 2 and for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Agreement may be terminated subsequent to the
termination of the Power contract as defined in the agreement by the customer providing at
least six-months written notice and specifying the date on which the customer will assume
responsibility of operations and maintenance of Swift Hydroelectric plant No. 2.
Schedule Page: 328.1 Line No.: 13 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
Schedule Page: 328.1 Line No.: 14 Column: d
Legacy Contract (Rate Schedule 234) providing for transmission and operation of Swift
Hydroelectric plant No. 2 and for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Agreement may be terminated subsequent to the
termination of the Power contract as defined in the agreement by the customer providing at
least six months written notice and specifying the date on which the customer will assume
responsibility of operations and maintenance of Swift Hydroelectric plant No. 2.
Schedule Page: 328.1 Line No.: 14 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract. 2014 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 15 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.: 15 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.: 15 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.: 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
2014 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 17 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 17 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
Schedule Page: 328.1 Line No.: 17 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 17 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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
2014 transmission and ancillary services. 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
Transmission resale, purchase of point-to-point transmission. 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 on November 30, 2018.
Schedule Page: 328.1 Line No.: 20 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.1 Line No.: 21 Column: d
Transmission service under the Open Access Transmission Tariff (Service Agreement 789).
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: 328.1 Line No.: 21 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.
Schedule Page: 328.1 Line No.: 22 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 22 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 22 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.1 Line No.: 22 Column: m
Unauthorized use of transmission service. 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
reserve service.
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.
Schedule Page: 328.1 Line No.: 24 Column: d
Legacy Contract (Rate Schedule 322) executed between PacifiCorp and Fall River Rural
Electric Cooperative for transmission service over agreed-upon facilities and/or subject
to a sole-use or facilities charge. Terminating on July 31, 2027.
Schedule Page: 328.1 Line No.: 24 Column: m
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. 2014 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 25 Column: d
Service Agreement 761 executed between PacifiCorp and Foote Creek III, LLC (Terra-Gen
Operating, LLC) for transmission service over agreed-upon facilities and/or subject to a
sole-use or facilities charge. Terminating on 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. Distribution voltage service charge.
Schedule Page: 328.1 Line No.: 26 Column: d
Service Agreement 761 executed between PacifiCorp and Foote Creek III, LLC (Terra-Gen
Operating, LLC) for transmission service over agreed-upon facilities and/or subject to a
sole-use or facilities charge. Terminating on March 1, 2024.
Schedule Page: 328.1 Line No.: 26 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. 2014 transmission and ancillary services.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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
2014 transmission and ancillary services.
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 30 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 Line No.: 30 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1 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: 328.1 Line No.: 30 Column: m
2014 transmission and ancillary services.
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
Operating reserve - spinning reserve service. Operating reserve - supplemental reserve
service.
Schedule Page: 328.1 Line No.: 32 Column: c
Iberdrola Renewables, LLC and Utah Associated Municipal Power Systems
Schedule Page: 328.1 Line No.: 32 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.: 32 Column: f
Long Hollow, WY Switching Station
Schedule Page: 328.1 Line No.: 32 Column: g
Long Hollow, WY Switching Station
Schedule Page: 328.1 Line No.: 32 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.1 Line No.: 33 Column: c
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.
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) terminating on April 30, 2019.
Schedule Page: 328.1 Line No.: 33 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.1 Line No.: 34 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 279) terminating on April 30, 2019.
Schedule Page: 328.1 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.11
2014 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 1 Column: d
Network transmission service under the Open Access Transmission Tariff (Service Agreement
742) terminating on April 30, 2018.
Schedule Page: 328.2 Line No.: 1 Column: m
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: 328.2 Line No.: 2 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 2 Column: d
Network transmission service under the Open Access Transmission Tariff (Service Agreement
742) terminating on April 30, 2018.
Schedule Page: 328.2 Line No.: 2 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 3 Column: d
Legacy Contract (Rate Schedule 427) executed between PacifiCorp and Idaho Power Company
concerning the exchange of transmission services over agreed-upon facilities (Draft
Transmission Services Agreement between PacifiCorp and Idaho Power Company, Draft 1 –
5/19/95 (“Goshen Agreement”)). Termination of this agreement occurs at the end of the
calendar month following the earlier of the effectiveness of a replacement contract or
upon three years written notice of termination as long as PacifiCorp has facilities in
place to serve PacifiCorp's Big Grassy load. See also page 332, Transmission of
electricity by others, in this Form No. 1.
Schedule Page: 328.2 Line No.: 4 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 212) terminating on May 31, 2019.
Schedule Page: 328.2 Line No.: 4 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 5 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 212) terminating on May 31, 2019.
Schedule Page: 328.2 Line No.: 5 Column: m
2014 transmission and ancillary services.
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 Education Supply Agreement.
Schedule Page: 328.2 Line No.: 6 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Schedule Page: 328.2 Line No.: 7 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 7 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 7 Column: d
Legacy Contract (Rate Schedule 257) executed between PacifiCorp and Idaho Power Company
for transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge for the Antelope Substation terminating coterminous with the
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.12
Idaho/United States Department of Education Supply Agreement.
Schedule Page: 328.2 Line No.: 7 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. 2014 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 8 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 8 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 8 Column: d
Legacy Contract (Rate Schedule 203) executed between PacifiCorp and Idaho Power Company
for transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge (Service Agreement 203) for the Bridger Pump Substation. Agreement
terminates upon 12-months written notice.
Schedule Page: 328.2 Line No.: 8 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Schedule Page: 328.2 Line No.: 9 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 9 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 9 Column: d
Legacy Contract (Rate Schedule 203) executed between PacifiCorp and Idaho Power Company
for transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge (Service Agreement 203) for the Bridger Pump Substation. Agreement
terminates upon 12-months written notice.
Schedule Page: 328.2 Line No.: 9 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. 2014 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 10 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 10 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 10 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 10 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 11 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 11 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 11 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 12 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 12 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 12 Column: d
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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.13
Schedule Page: 328.2 Line No.: 12 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 13 Column: 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.: 13 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 13 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 13 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 13 Column: m
Unauthorized use of transmission service. 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.: 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
2014 transmission and ancillary services.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 16 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 16 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 16 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 16 Column: m
Transmission resale, amount paid by seller. Scheduling, system control and dispatch
service. Reactive supply and voltage control service.
Schedule Page: 328.2 Line No.: 17 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.: 17 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.14
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
Schedule Page: 328.2 Line No.: 18 Column: d
Legacy Contract (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.: 18 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract. 2014 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. Generation regulation and frequency response service.
Schedule Page: 328.2 Line No.: 20 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 20 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 20 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 20 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 21 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 21 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 21 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 21 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.2 Line No.: 22 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 22 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 22 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 22 Column: m
2014 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.15
Schedule Page: 328.2 Line No.: 23 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 23 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 24 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 24 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 24 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 24 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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: 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.: 26 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.: 26 Column: m
Transmission resale, purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Generation regulation
and frequency response service. Operating reserve - spinning reserve service. Operating
reserve - supplemental reserve service.
Schedule Page: 328.2 Line No.: 27 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.: 27 Column: m
2014 transmission and ancillary services.
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. Generation regulation and frequency response service.
Schedule Page: 328.2 Line No.: 29 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.16
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
2014 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 30 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 30 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 30 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.2 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.2 Line No.: 31 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.: 31 Column: m
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: 328.2 Line No.: 32 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.: 32 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.2 Line No.: 33 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 33 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.2 Line No.: 33 Column: d
Legacy Contract (Rate Schedule 607) executed between PacifiCorp and Pacific Gas & Electric
Company for transmission service over agreed-upon facilities (Malin to Round Mountain)
and/or subject to a sole-use or facilities charge. Terminating December 31, 2017. See
PacifiCorp, Docket No. ER07-882, et al, Settlement Agreement, Appendix 2 (filed November
20, 2007).
Schedule Page: 328.2 Line No.: 33 Column: f
Malin to Indian Springs line segment
Schedule Page: 328.2 Line No.: 33 Column: g
Malin to Indian Springs line segment
Schedule Page: 328.2 Line No.: 33 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.
Schedule Page: 328.2 Line No.: 34 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 34 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.17
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.2 Line No.: 34 Column: d
Legacy Contract (Rate Schedule 607) executed between PacifiCorp and Pacific Gas & Electric
Company for transmission service over agreed-upon facilities (Malin to Round Mountain)
and/or subject to a sole-use or facilities charge. Terminating December 31, 2017. See
PacifiCorp, Docket No. ER07-882, et al, Settlement Agreement, Appendix 2 (filed November
20, 2007).
Schedule Page: 328.2 Line No.: 34 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. 2014 transmission and ancillary services.
Schedule Page: 328.3 Line No.: 1 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 1 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 1 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.: 1 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Schedule Page: 328.3 Line No.: 2 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 2 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 2 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 2 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 3 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 3 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 3 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 3 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 4 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 4 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 4 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 4 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 5 Column: 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.18
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
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 6 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.3 Line No.: 6 Column: d
Legacy Contract (1st Revised Rate Schedule 137) executed between PacifiCorp and Portland
General Electric Company for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge for the Dalreed Substation, which terminated
December 2013.
Schedule Page: 328.3 Line No.: 6 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.: 7 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.: 7 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.: 7 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Schedule Page: 328.3 Line No.: 8 Column: d
Agreement providing for transmission service from Western Area Power Administration's
Casper Substation in Wyoming and Yellowtail Substation in Montana to Sheridan-Johnson
Rural Electric Association's load at PacifiCorp's Buffalo Substation in Wyoming.
Schedule Page: 328.3 Line No.: 8 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. 2014 transmission and ancillary services.
Schedule Page: 328.3 Line No.: 9 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.: 9 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.: 9 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 10 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.: 10 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.3 Line No.: 11 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (2nd 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.19
Service Agreement 700) terminating on March 31, 2017.
Schedule Page: 328.3 Line No.: 11 Column: m
Scheduling, system control and dispatch service.
Schedule Page: 328.3 Line No.: 12 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.: 12 Column: m
2014 transmission and ancillary services. Scheduling, system control and dispatch service.
Schedule Page: 328.3 Line No.: 13 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.: 13 Column: m
Scheduling, system control and dispatch service.
Schedule Page: 328.3 Line No.: 14 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.: 14 Column: m
2014 transmission and ancillary services. Scheduling, system control and dispatch service.
Schedule Page: 328.3 Line No.: 15 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.: 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 702) terminating on March 31, 2017.
Schedule Page: 328.3 Line No.: 16 Column: m
2014 transmission and ancillary services. 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 (Service
Agreement 748) terminating on December 31, 2018.
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 (Service
Agreement 748) terminating on December 31, 2018.
Schedule Page: 328.3 Line No.: 18 Column: m
Scheduling, system control and dispatch service.
Schedule Page: 328.3 Line No.: 19 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 749) terminating on December 31, 2018.
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 (Service
Agreement 749) terminating on December 31, 2018.
Schedule Page: 328.3 Line No.: 20 Column: m
Scheduling, system control and dispatch service.
Schedule Page: 328.3 Line No.: 21 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 21 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 21 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.20
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.: 21 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.
Schedule Page: 328.3 Line No.: 22 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 22 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 22 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 22 Column: m
2014 transmission and ancillary services.
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
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
2014 transmission and ancillary services.
Schedule Page: 328.3 Line No.: 25 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.: 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
2014 transmission and ancillary services.
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.21
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
2014 transmission and ancillary services.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 29 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 29 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 29 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 29 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 30 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: 328.3 Line No.: 30 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 795) terminating on December 31, 2020.
Schedule Page: 328.3 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.3 Line No.: 31 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 795) terminating on December 31, 2020.
Schedule Page: 328.3 Line No.: 31 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.3 Line No.: 32 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 809) terminating on October 31, 2020.
Schedule Page: 328.3 Line No.: 32 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.
Schedule Page: 328.3 Line No.: 33 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 809) terminating on October 31, 2020.
Schedule Page: 328.3 Line No.: 33 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.22
2014 transmission and ancillary services.
Schedule Page: 328.3 Line No.: 34 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 34 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.3 Line No.: 34 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.3 Line No.: 34 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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. Generation regulation and frequency response service.
Schedule Page: 328.4 Line No.: 2 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 2 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 2 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 2 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 3 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 3 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 4 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised
Service Agreement 791) terminating upon written notification.
Schedule Page: 328.4 Line No.: 5 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 5 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 5 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 5 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.4 Line No.: 6 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.23
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
2014 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 7 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 7 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 7 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.4 Line No.: 8 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 8 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 8 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 8 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 9 Column: a
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 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 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. 2014 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 11 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.24
Schedule Page: 328.4 Line No.: 11 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 11 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.: 11 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.: 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: e
V11-1-3,5,6,8,11
Schedule Page: 328.4 Line No.: 12 Column: m
Unauthorized use of transmission service. 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: e
V11-1-3,5,6,8,11
Schedule Page: 328.4 Line No.: 13 Column: m
2014 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
2014 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 16 Column: c
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.25
Complete name is Southern California Public Power Authority.
Schedule Page: 328.4 Line No.: 16 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.: 16 Column: m
Unauthorized use of transmission service. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Generation regulation and frequency response
service.
Schedule Page: 328.4 Line No.: 17 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.: 17 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.4 Line No.: 18 Column: d
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
2014 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 19 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 19 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 19 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 20 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 20 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 20 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 20 Column: m
2014 transmission and ancillary services.
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.26
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response 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
2014 transmission and ancillary services.
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
Transmission resale, amount paid by seller. Scheduling, system control and dispatch
service. Reactive supply and voltage control service.
Schedule Page: 328.4 Line No.: 26 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 26 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 26 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 26 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.4 Line No.: 27 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 27 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 27 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.27
Schedule Page: 328.4 Line No.: 27 Column: m
2014 transmission and ancillary services.
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: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 29 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 568) terminating on April 30, 2029.
Schedule Page: 328.4 Line No.: 29 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.: 30 Column: c
Various signatories to the Volume 11 Point-to-Point Transmissions Tariff.
Schedule Page: 328.4 Line No.: 30 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 568) terminating on April 30, 2029.
Schedule Page: 328.4 Line No.: 30 Column: m
2014 transmission and ancillary services.
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: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 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: 328.4 Line No.: 31 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
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: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 32 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.4 Line No.: 32 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 33 Column: a
This footnote applies to all occurrences of "Tri-State Generation & Trans." on pages
328-330. Complete name is Tri-State Generation and Transmission Association, Inc.
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.28
Legacy Contract (2nd Revised Rate Schedule 123) executed between PacifiCorp and Tri-State
Generation and Transmission Association, Inc. for transmission service over agreed-upon
facilities and/or subject to a sole-use or facilities charge. Terminating on October 1,
2014.
Schedule Page: 328.4 Line No.: 33 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.4 Line No.: 34 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.4 Line No.: 34 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 628) terminating on June 30, 2021.
Schedule Page: 328.4 Line No.: 34 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response 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: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 628) terminating on June 30, 2021.
Schedule Page: 328.5 Line No.: 1 Column: m
2014 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
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
2014 transmission and ancillary services.
Schedule Page: 328.5 Line No.: 4 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 4 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 Line No.: 4 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.29
Schedule Page: 328.5 Line No.: 5 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. Operating reserve - spinning reserve service. Operating
reserve - supplemental reserve service.
Schedule Page: 328.5 Line No.: 6 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (Service Agreement 506) terminating upon written notification.
Schedule Page: 328.5 Line No.: 6 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.5 Line No.: 7 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.: 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 termination any
time after April 1, 2040 with four years written notification.
Schedule Page: 328.5 Line No.: 7 Column: m
Energy consumption charge for deliveries at and below 138kV.
Schedule Page: 328.5 Line No.: 8 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 termination any
time after April 1, 2040 with four years written notification.
Schedule Page: 328.5 Line No.: 8 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.5 Line No.: 9 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.: 10 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.: 10 Column: d
Legacy Contract executed between PacifiCorp and Utah Associated Municipal Power Systems
for transmission service over agreed-upon facilities (3rd Amended and Restated
Transmission Service and Operating Agreement, 3rd Revised Rate Schedule 297). Agreement
subject to termination upon mutual agreement and replacement agreements are in effect.
Schedule Page: 328.5 Line No.: 10 Column: m
Distribution voltage service charge. 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: 328.5 Line No.: 11 Column: d
Legacy Contract executed between PacifiCorp and Utah Associated Municipal Power Systems
for transmission service over agreed-upon facilities (3rd Amended and Restated
Transmission Service and Operating Agreement, 3rd Revised Rate Schedule 297). Agreement
subject to termination upon mutual agreement and replacement agreements are in effect.
Schedule Page: 328.5 Line No.: 11 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.5 Line No.: 12 Column: b
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.30
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
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.
Schedule Page: 328.5 Line No.: 13 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 13 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 Line No.: 13 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.5 Line No.: 14 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 14 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 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: 328.5 Line No.: 15 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.: 15 Column: m
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.: 16 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.: 16 Column: m
2014 transmission and ancillary services.
Schedule Page: 328.5 Line No.: 17 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.: 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. Terminating on 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.31
contract.
Schedule Page: 328.5 Line No.: 18 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. Terminating on January 31, 2032.
Schedule Page: 328.5 Line No.: 18 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract. 2014 transmission and ancillary services.
Schedule Page: 328.5 Line No.: 19 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.5 Line No.: 19 Column: d
Legacy Contract (Rate Schedule 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.
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 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.: 20 Column: m
Fixed termination fee associated with a contract cancellation applied for the duration of
this agreement. 2014 transmission and ancillary services.
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
138kV. Agreement termination upon three years after written notice and mutual consent.
Schedule Page: 328.5 Line No.: 22 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.
Schedule Page: 328.5 Line No.: 22 Column: d
Legacy Contract (Rate Schedule 263) executed between PacifiCorp and Western Area Power
Administration for transmission and interconnection service over agreed-upon facilities
and/or subject to a sole-use or facilities charge for load service to low voltage
customers for deliveries of power and energy from Salt Lake City Area Integrated Projects,
including the Colorado River Storage Projects, to certain municipalities at service below
138kV. Agreement termination upon three years after written notice and mutual consent.
Schedule Page: 328.5 Line No.: 22 Column: m
Charges for low-voltage transmission of power and energy. 2014 transmission and ancillary
services.
Schedule Page: 328.5 Line No.: 23 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 23 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.32
Legacy Contract (Rate Schedule 684) 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.: 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
Distribution voltage service charge. Primary delivery 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: 328.5 Line No.: 25 Column: b
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: d
Evergreen network transmission service under the Open Access Transmission Tariff (3rd
Revised Service Agreement 175).
Schedule Page: 328.5 Line No.: 25 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. 2014 transmission and ancillary services.
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: 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: a
This footnote applies to all occurrences of "Western Area Power Adm. CO MO" on pages
328-330. Complete name is Western Area Power Administration Colorado Missouri.
Schedule Page: 328.5 Line No.: 28 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 Line No.: 28 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Schedule Page: 328.5 Line No.: 28 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.5 Line No.: 29 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 Line No.: 29 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.33
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.5 Line No.: 30 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.5 Line No.: 31 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.5 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: 328.5 Line No.: 31 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Schedule Page: 328.5 Line No.: 32 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
2015/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
/ /2015/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)
AD 233 233Arizona Public Service 1
LFP 1,706,862 1,706,862 509,724 509,724Arizona Public Service 2
NF 291,641 291,641 46,460 46,460Arizona Public Service 3
OS 16,579 16,579Arizona Public Service 4
OSArizona Public Service 5
SFP 501,421 501,421 79,131 79,131Arizona Public Service 6
FNS 20,835 20,835 2,168 2,168Ashland, City of 7
FNS 245,458 245,458 55,224 53,171Avista Corporation 8
NF 46,512 46,512 8,061 8,061Avista Corporation 9
FNS 163,833 163,833 42,640 42,640Avista Corporation 10
NF 4,190 4,190 2,812 2,812Basin Elect. Power Coop 11
OLF 175,561 175,561Big Horn Rural Electric 12
AD 53 8 45 7 7Black Hills Power, Inc. 13
NF 19,208 19,208 19,361 19,361Black Hills Power, Inc. 14
OS 28,028 28,028Black Hills Power, Inc. 15
SFP 42,280 42,280 7,832 7,832Black Hills Power, Inc. 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332
15,461,404 15,914,125 122,878,918 5,161,909 20,384,518 148,425,345TOTAL
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
/ /2015/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)
AD -142,693 27,044 -169,737Bonneville Power Admin 1
FNS 6,977,680 6,977,680Bonneville Power Admin 2
LFP 65,636,117 65,636,117 4,421,278 4,421,278Bonneville Power Admin 3
NF 245,170 245,170 48,909 48,909Bonneville Power Admin 4
OLF 24,013,159 100,881 23,912,278 4,580,617 4,328,027Bonneville Power Admin 5
OS 756,789 756,789 29,384 29,384Bonneville Power Admin 6
OSBonneville Power Admin 7
SFP 4,639,929 4,639,929 921,798 921,798Bonneville Power Admin 8
AD -1,242 -1,242CA Ind. Sys. Operator 9
OS 628,787 628,787CA Ind. Sys. Operator 10
SFP 180,843 180,843 18,375 18,375CA Ind. Sys. Operator 11
LFP 4,693,644 4,693,644 135,730 135,730Deseret Gen & Trans 12
NF 55,824 55,824 5,779 5,779Deseret Gen & Trans 13
NF 4,286 4,286 6,118 6,118El Paso Electric Co. 14
OS 3,408 3,408El Paso Electric Co. 15
SFP 17,291 17,291 23,387 23,387El Paso Electric Co. 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1
15,461,404 15,914,125 122,878,918 5,161,909 20,384,518 148,425,345TOTAL
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
/ /2015/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 68,820 68,820Flathead Elect Coop Inc 1
OS 194,174 194,174Hermiston Gen Co L.P. 2
AD 228,956 228,956Idaho Power Company 3
FNS 9,571 9,571Idaho Power Company 4
LFP 5,753,990 5,753,990 2,210,950 2,077,819Idaho Power Company 5
NF 2,148,304 2,148,304 742,597 688,028Idaho Power Company 6
OS 11,164,829 11,134,008 30,821Idaho Power Company 7
OSIdaho Power Company 8
SFP 440,732 440,732 172,152 172,152Idaho Power Company 9
FNS 292,085 292,085Moon Lake Elect. Assoc. 10
LFP 1,340 1,340 11 11Morgan City Corporation 11
SFP -1,300 -1,300Morgan Stanley C.G. Inc 12
AD -111,243 -12,460 -98,783Nevada Power Company 13
NF 301,481 301,481 52,053 52,053Nevada Power Company 14
OS 115,171 115,171Nevada Power Company 15
SFP 519,950 519,950 129,075 129,075Nevada Power Company 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.2
15,461,404 15,914,125 122,878,918 5,161,909 20,384,518 148,425,345TOTAL
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
/ /2015/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification(b)
NF 82,199 82,199 19,006 13,619NorthWestern Corp. 1
OS 33,032 33,032NorthWestern Corp. 2
SFP 601,062 601,062 138,671 138,671NorthWestern Corp. 3
LFP 849,700 849,700 159,142 159,142Platte River Pwr Auth 4
OS 15,707 15,707Platte River Pwr Auth 5
NF 108 108 150 150Portland Gen. Electric 6
OLF 964 964Portland Gen. Electric 7
OS 10 10Portland Gen. Electric 8
SFP -4,400 -4,400Powerex Corporation 9
LFP 1,015,396 1,015,396 71,399 68,905Public Service Co of CO 10
NF 255 255 39 39Public Service Co of CO 11
NF 1,062 1,062 200 200Public Service Co of NM 12
OS 110 110Public Service Co of NM 13
SFP 394,001 394,001 266,161 266,161Puget Sound Energy, Inc 14
NF 21,735 21,735 7,600 7,600Salt River Project 15
OS 5,324 5,324Salt River Project 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.3
15,461,404 15,914,125 122,878,918 5,161,909 20,384,518 148,425,345TOTAL
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
/ /2015/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 13,962 13,962 6,500 6,500Salt River Project 1
AD -33,370 -3,701 -29,669Sierra Pacific Power Co 2
NF 43,065 43,065 8,482 8,482Sierra Pacific Power Co 3
OS 5,891 5,891Sierra Pacific Power Co 4
OLF 8,279 8,279Surprise Valley Electr. 5
SFP -57,109 -57,109TransAlta Energy 6
LFP 1,015,396 1,015,396 56,358 53,861Tri-State Gen & Transm 7
NF 102,342 102,342 22,796 22,796Tri-State Gen & Transm 8
OS 27,324 27,324Tri-State Gen & Transm 9
LFP 546,739 546,739 169,060 169,060Tucson Electric Power 10
NF 17,032 17,032 3,915 3,915Tucson Electric Power 11
OS 50,377 50,377Tucson Electric Power 12
SFP 50 50 16 16Tucson Electric Power 13
LFP -3,705,509 -3,705,509Westport Field Svc LLC 14
AD 12,957 13,936 -979Western Area Power Admn 15
FNS 5,879,221 5,879,221Western Area Power Admn 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.4
15,461,404 15,914,125 122,878,918 5,161,909 20,384,518 148,425,345TOTAL
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
/ /2015/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 1,742,500 1,742,500 371,322 371,322Western Area Power Admn 1
NF 508,311 508,311 241,053 241,053Western Area Power Admn 2
OS 1,102,350 1,063,802 38,548 63 63Western Area Power Admn 3
OSWestern Area Power Admn 4
SFP 394,904 394,904 100,559 100,559Western Area Power Admn 5
3,950,568 3,950,568Reserve 6
1,685,254 1,685,254Accrual 7
8
9
10
11
12
13
14
15
16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.5
15,461,404 15,914,125 122,878,918 5,161,909 20,384,518 148,425,345TOTAL
Schedule Page: 332 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 2 Column: b
Arizona Public Service Company - contract termination dates: January 11, 2041 and May 31,
2047.
Schedule Page: 332 Line No.: 4 Column: g
Ancillary services.
Schedule Page: 332 Line No.: 5 Column: b
Arizona Public Service Company - Legacy contract executed between PacifiCorp and Arizona
Public Service Company concerning the exchange of transmission services over agreed-upon
facilities (Restated Transmission Service Agreement between PacifiCorp and Arizona Public
Service Company, Rate Schedule 436). The contract terminates October 31, 2020. See also
page 328, Transmission of electricity for others, in this Form No. 1.
Schedule Page: 332 Line No.: 12 Column: b
Big Horn Rural Electric Company - contract termination date: March 10, 2018.
Schedule Page: 332 Line No.: 12 Column: g
Use of facilities.
Schedule Page: 332 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 13 Column: g
Ancillary services.
Schedule Page: 332 Line No.: 15 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 332.1 Line No.: 1 Column: e
Prior period adjustments.
Schedule Page: 332.1 Line No.: 1 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 3 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.: 5 Column: b
Bonneville Power Administration - contract termination dates: December 31, 2018, September
30, 2027 and evergreen.
Schedule Page: 332.1 Line No.: 5 Column: g
Use of facilities.
Schedule Page: 332.1 Line No.: 6 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.1 Line No.: 7 Column: b
Bonneville Power Administration - Legacy contract executed between PacifiCorp and
Bonneville Power Administration concerning the exchange of transmission services over
agreed-upon facilities ("Midpoint-Meridian Transmission Agreement", Rate Schedule 369).
This agreement runs concurrently with the AC Intertie Agreement (Rate Schedule 368), which
terminates when the facilities subject to that agreement are taken out of service. See
also page 328, Transmission of electricity for others, in this Form No. 1.
Schedule Page: 332.1 Line No.: 9 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.: 9 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 332.1 Line No.: 9 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 10 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 12 Column: b
Deseret Generation & Transmission Cooperative - contract termination dates: January 1,
2018 and September 1, 2018.
Schedule Page: 332.1 Line No.: 15 Column: g
Ancillary services.
Schedule Page: 332.2 Line No.: 1 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 2 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.: 2 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 332.2 Line No.: 5 Column: b
Idaho Power Company - contract termination dates: April 1, 2025 and July 1, 2025.
Schedule Page: 332.2 Line No.: 7 Column: g
Ancillary services. Use of facilities. PacifiCorp's portion of specified costs of certain
facilities.
Schedule Page: 332.2 Line No.: 8 Column: b
Idaho Power Company - Legacy contract (Rate Schedule 427) executed between PacifiCorp and
Idaho Power Company concerning the exchange of transmission services over agreed-upon
facilities (Draft Transmission Services Agreement between PacifiCorp and Idaho Power
Company, Draft 1 – 5/19/95 (“Goshen Agreement”)). Termination of this agreement occurs at
the end of the calendar month following the earlier of the effectiveness of a replacement
contract, or upon three years written notice of termination as long as PacifiCorp has
facilities in place to serve PacifiCorp's Big Grassy load. See also page 328, Transmission
of electricity for others, in this Form No. 1.
Schedule Page: 332.2 Line No.: 10 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 11 Column: b
Morgan City Corporation - contract termination date: Evergreen.
Schedule Page: 332.2 Line No.: 12 Column: a
This footnote applies to all occurrences of "Morgan Stanley C.G. Inc" on page 332.
Complete name is Morgan Stanley Capital Group Inc.
Schedule Page: 332.2 Line No.: 12 Column: e
Reassignment of Bonneville Power Administration transmission.
Schedule Page: 332.2 Line No.: 13 Column: a
This footnote applies to all occurrences of "Nevada Power Company" on page 332. Nevada
Power Company is a wholly owned subsidiary of NV Energy, Inc., which is an indirect wholly
owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
company.
Schedule Page: 332.2 Line No.: 13 Column: b
Settlement adjustment.
Schedule Page: 332.2 Line No.: 13 Column: e
Prior period adjustments.
Schedule Page: 332.2 Line No.: 13 Column: g
Ancillary services.
Schedule Page: 332.2 Line No.: 15 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 2 Column: g
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Ancillary services.
Schedule Page: 332.3 Line No.: 4 Column: b
Platte River Power Authority - contract termination date: October 31, 2017.
Schedule Page: 332.3 Line No.: 5 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: g
Ancillary services.
Schedule Page: 332.3 Line No.: 9 Column: e
Reassignment of Bonneville Power Administration transmission.
Schedule Page: 332.3 Line No.: 10 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.: 13 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 16 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 2 Column: a
This footnote applies to all occurrences of "Sierra Pacific Power Co" on page 332. Sierra
Pacific Power Company is a wholly owned subsidiary of NV Energy, Inc., which is an
indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's
indirect parent company.
Schedule Page: 332.4 Line No.: 2 Column: b
Settlement adjustment.
Schedule Page: 332.4 Line No.: 2 Column: e
Prior period adjustments.
Schedule Page: 332.4 Line No.: 2 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 4 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 5 Column: b
Surprise Valley Electrification Corp. - contract termination date: Evergreen.
Schedule Page: 332.4 Line No.: 5 Column: g
Use of facilities.
Schedule Page: 332.4 Line No.: 6 Column: a
This footnote applies to all occurrences of "TransAlta Energy" on page 332. Complete name
is TransAlta Energy Marketing (U.S.) Inc.
Schedule Page: 332.4 Line No.: 6 Column: e
Reassignment of Bonneville Power Administration transmission.
Schedule Page: 332.4 Line No.: 7 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.: 9 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 10 Column: b
Tucson Electric Power Company - contract termination date: December 1, 2015.
Schedule Page: 332.4 Line No.: 12 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 332.4 Line No.: 14 Column: b
Westport Field Services, LLC - contract termination date: Evergreen.
Schedule Page: 332.4 Line No.: 14 Column: e
Reimbursement for third party services provided.
Schedule Page: 332.4 Line No.: 15 Column: b
Settlement adjustment.
Schedule Page: 332.4 Line No.: 15 Column: e
Prior period adjustments.
Schedule Page: 332.4 Line No.: 15 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.5 Line No.: 1 Column: b
Western Area Power Administration - contract termination date: May 31, 2022.
Schedule Page: 332.5 Line No.: 3 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.5 Line No.: 4 Column: b
Western Area Power Administration - Legacy contract (Rate Schedule 664) executed between
PacifiCorp and Western Area Power Administration concerning the exchange of transmission
services over agreed-upon facilities. The contract terminates 50 years from execution. See
also page 328, Transmission of electricity for others, in this Form No. 1.
Schedule Page: 332.5 Line No.: 6 Column: g
Reserve for a contingent liability.
Schedule Page: 332.5 Line No.: 7 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
2015/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 / /2015/Q4
Line Description Amount
(b)(a)No.
1,206,198Industry 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
13,779American Wind Energy Association 11
28,840Associated Oregon Industries 12
6,000Clatsop Economic Development Resources 13
8,000Economic Development for Central Oregon 14
10,000Four County Economic Development Corporation 15
9,000Intermountain Electrical Association 16
5,000Klamath County Economic Development Association 17
13,900Oregon Business Association 18
18,126Oregon Business Council 19
9,500Oregon Economic Development Association 20
15,000Oregon State University Utility Pole Research Coop 21
76,715Pacific Northwest Utilities Conference Committee 22
38,200Portland Business Alliance 23
7,000Redmond Economic Development, Inc. 24
18,000Rocky Mountain Electrical League 25
5,500Rural Development Initiatives, Inc. 26
27,000Salt Lake Area Chamber of Commerce 27
10,000South Coast Development Council, Inc. 28
6,500Southern Oregon Regional Economic Development, Inc. 29
6,400Strategic Economic Development Corporation 30
7,000Utah Governor's Economic Summit 31
6,600Utah Manufacturers Association 32
10,000Wyoming Business Alliance 33
12,000Yakima County Development Association 34
149,114Other (Individually < $5,000) 35
36
15,428Directors' Fees - Regional Advisory Board 37
38
Rating Agency and Trustee Fees: 39
123,085The Bank of New York Mellon 40
17,601Computershare Shareowner Services, LLC 41
39,323Fitch, Inc. 42
137,611Moody's Investors Service, Inc. 43
216,918Standard and Poor's Financial Services, LLC 44
13,296U.S. Bank National Association 45
2,386,938
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 / /2015/Q4
Line Description Amount
(b)(a)No.
Regulatory Asset Amortization: 6
35,000Generating Plant Liquidated Damages - UT 7
54,288Generating Plant Liquidated Damages - WY 8
9
General: 10
1,016Other 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
2,386,938
FERC FORM NO. 1 (ED. 12-94) Page 335.1
46 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
PacifiCorp X
/ /2015/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)
36,050,777 36,050,777 1 Intangible Plant
259,770,436 259,770,436 2 Steam Production Plant
3 Nuclear Production Plant
33,436,052 33,154,428 281,624 4 Hydraulic Production Plant-Conventional
5 Hydraulic Production Plant-Pumped Storage
126,685,049 126,685,049 6 Other Production Plant
99,238,672 99,238,672 7 Transmission Plant
138,874,436 138,874,436 8 Distribution Plant
9 Regional Transmission and Market Operation
40,666,418 39,308,259 1,358,159 10 General Plant
11 Common Plant-Electric
734,721,840 697,031,280 37,690,560 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
/ /2015/Q4
Line
No.Account No.
(c)(b)(a)(d) (e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f) (g)(Percent)
HYDRAULIC PROD. 12
Klamath River 13
2.97 4.00330.20 OR/CA 41 14
2.80 4.00330.40 OR/CA 1 15
8.45 4.00331.00 OR/CA 14,951 16
7.87 4.00332.00 OR/CA 36,719 17
7.53 4.00333.00 OR/CA 17,836 18
8.89 4.00334.00 OR/CA 15,862 19
6.13 4.00335.00 OR/CA 183 20
7.41 4.00336.00 OR/CA 2,595 21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337
Schedule Page: 336 Line No.: 12 Column: b
Depreciation expense associated with transportation equipment is generally charged to
operations and maintenance expense and construction work in progress. During the year
ended December 31, 2015, depreciation expense associated with transportation equipment was
$14,214,593.
Schedule Page: 336 Line No.: 12 Column: e
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as
either a regulatory asset or liability.
Schedule Page: 336 Line No.: 13 Column: a
The depreciation rate changes are for the Klamath hydroelectric system’s four mainstem
dams (JC Boyle, Iron Gate, Copco No. 1 and Copco No. 2). For further discussion, refer to
Note 13 of Notes to Financial Statements in this Form No. 1.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES
PacifiCorp X
/ /2015/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 5,394,502 5,394,502 2
Rate Cases and Proceedings 583,941 583,941 3
4
Oregon Public Utility Commission: 5
Annual Fee 3,490,574 3,490,574 6
Rate Cases and Proceedings 923,066 923,066 7
1,069,569Deferred Intervenor Funding Grants 8
9
Wyoming Public Service Commission: 10
Annual Fee 1,608,307 1,608,307 11
Rate Cases and Proceedings 1,545,757 1,545,757 12
13
Washington Utilities and Transportation 14
Commission: 15
Annual Fee 679,384 679,384 16
Rate Cases and Proceedings 907,701 907,701 17
18
Idaho Public Utilities Commission: 19
Annual Fee 694,786 694,786 20
Rate Cases and Proceedings 153,891 153,891 21
39,031Deferred Intervenor Funding Grants (2) 16,431 16,431 22
23
California Public Utilities Commission: 24
Annual Fee 454 454 25
Rate Cases and Proceedings 159,391 159,391 26
40,347Deferred Intervenor Funding Grants 27
28
California Environmental Protection Agency: 29
Industry Compliance Fee 112 10,539 10,651 30
31
Multi-State: 32
Rate Cases and Proceedings 696,394 696,394 33
Other Regulatory 491,735 491,735 34
35
Federal Energy Regulatory Commission: 36
Annual Fee 1,738,787 1,738,787 37
Anuual Fee - Hydroelectric Plants 2,362,642 2,362,642 38
Transmission Rate Cases 175,117 175,117 39
Other Regulatory 642,175 642,175 40
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96) Page 350
46 TOTAL 15,969,548 6,306,138 22,275,686 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
REGULATORY COMMISSION EXPENSES (Continued)
PacifiCorp X
/ /2015/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 5,394,502928
Electric 3 583,941928
4
5
Electric 6 3,490,574928
Electric 7 923,066928
1,442,958 373,389 8
9
10
Electric 11 1,608,307928
Electric 12 1,545,757928
13
14
15
Electric 16 679,384928
Electric 17 907,701928
18
19
Electric 20 694,786928
Electric 21 153,891928
26,865 16,431928 4,265Electric 22 16,431928
23
24
Electric 25 454928
Electric 26 159,391928
40,406 59 27
28
29
Electric 30 10,651928
31
32
Electric 33 696,394928
Electric 34 491,735928
35
36
Electric 37 1,738,787928
Electric 38 2,362,642928
Electric 39 175,117928
Electric 40 642,175928
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96) Page 351
46 22,275,686 377,713 16,431 1,510,229
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
/ /2015/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 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
/ /2015/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
10,896 5 12,180 920,921 23,076
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
/ /2015/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
98,830,452Production 3
15,085,437Transmission 4
Regional Market 5
34,092,097Distribution 6
37,464,104Customer Accounts 7
6,313,264Customer Service and Informational 8
Sales 9
35,922,353Administrative and General 10
227,707,707TOTAL Operation (Enter Total of lines 3 thru 10) 11
Maintenance 12
48,867,881Production 13
10,051,864Transmission 14
Regional Market 15
68,233,277Distribution 16
1,822,203Administrative and General 17
128,975,225TOTAL Maintenance (Total of lines 13 thru 17) 18
Total Operation and Maintenance 19
147,698,333Production (Enter Total of lines 3 and 13) 20
25,137,301Transmission (Enter Total of lines 4 and 14) 21
Regional Market (Enter Total of Lines 5 and 15) 22
102,325,374Distribution (Enter Total of lines 6 and 16) 23
37,464,104Customer Accounts (Transcribe from line 7) 24
6,313,264Customer Service and Informational (Transcribe from line 8) 25
Sales (Transcribe from line 9) 26
37,744,556Administrative and General (Enter Total of lines 10 and 17) 27
356,682,932 356,682,932TOTAL 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
/ /2015/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
356,682,932 356,682,932TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65
Utility Plant 66
Construction (By Utility Departments) 67
151,032,878 151,032,878Electric Plant 68
Gas Plant 69
Other (provide details in footnote): 70
151,032,878 151,032,878TOTAL Construction (Total of lines 68 thru 70) 71
Plant Removal (By Utility Departments) 72
9,252,820 9,252,820Electric Plant 73
Gas Plant 74
Other (provide details in footnote): 75
9,252,820 9,252,820TOTAL Plant Removal (Total of lines 73 thru 75) 76
Other Accounts (Specify, provide details in footnote): 77
2,722,964 2,722,964Fuel Stock 78
612,988 612,988Miscellaneous Other Income Deductions 79
667,582 667,582Miscellaneous Non-Operating and Non-Utility 80
3,674,951 3,674,951Charges to Affiliates 81
82
83
84
85
86
87
88
89
90
91
92
93
94
7,678,485 7,678,485TOTAL Other Accounts 95
524,647,115 524,647,115TOTAL 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
/ /2015/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 1,177,243 312 590,931 1,181,543
Net Sales (Account 447) 3 ( 2,057,804)( 538,380) ( 985,233) ( 1,667,302)
Transmission Rights 4
Ancillary Services 5
Other Items (list separately) 6
Energy Imbalance Market (Account 555) 7 ( 22,261,762)( 2,444,386) ( 11,341,992) ( 18,294,857)
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
( 23,142,323)( 2,982,454) ( 11,736,294) ( 18,780,616)
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
/ /2015/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
12,494,858MWh145,271,733Scheduling, System Control and Dispatch 1
9,213,724MWh136,672,907 8,497,326MWh126,182,822Reactive Supply and Voltage 2
36,316,840MWh107,771,335 32,998,011MWh 97,899,037Regulation and Frequency Response 3
11,740,994MWh 384,200Energy Imbalance 4
50,054,836MWh128,234,549 47,568,647MWh121,970,891Operating Reserve - Spinning 5
42,599,461MWh 50,785,942 41,470,103MWh 47,568,647Operating Reserve - Supplement 6
Other 7
162,420,713569,120,666130,534,087393,621,397Total (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 / /2015/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
1,386 1,621 3,358 128 8,5061800 2 14,999January 1
742 1,476 3,358 158 8,246 80023 13,980February 2
1,411 1,478 3,358 136 8,124 800 4 14,507March 3
3,539 4,575 10,074 422 24,876Total for Quarter 1 4
672 1,476 3,358 122 7,615 80015 13,243April 5
356 1,527 3,358 101 7,767180031 13,109May 6
1,593 2,224 3,531 159 10,906160029 18,413June 7
2,621 5,227 10,247 382 26,288Total for Quarter 2 8
2,532 2,147 3,531 144 10,8091600 2 19,163July 9
1,742 2,084 3,531 146 9,946160013 17,449August 10
1,430 1,992 3,505 131 9,0931600 1 16,151September 11
5,704 6,223 10,567 421 29,848Total for Quarter 3 12
633 1,797 3,489 103 8,1091700 1 14,131October 13
679 1,558 3,358 142 8,795180030 14,532November 14
412 1,641 3,363 140 8,530180028 14,086December 15
1,724 4,996 10,210 385 25,434Total for Quarter 4 16
13,588 21,021 41,098 1,610 106,446
Total Year to
Date/Year
17
FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400
Schedule Page: 400 Line No.: 1 Column: d
Pacific Standard Time.
Schedule Page: 400 Line No.: 2 Column: d
Pacific Standard Time.
Schedule Page: 400 Line No.: 3 Column: d
Pacific Standard Time.
Schedule Page: 400 Line No.: 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 2015 Net System Load information was compiled using material 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 2015 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 2015 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 2015 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 2015 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
2015/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
/ /2015/Q4
Line
No.
Item
(a)(b)(a)(b)
Line
No.MegaWatt Hours Item MegaWatt Hours
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
SOURCES OF ENERGY1
Generation (Excluding Station Use):2
44,612,067Steam3
Nuclear4
2,915,015Hydro-Conventional5
Hydro-Pumped Storage6
8,806,733Other7
2,776Less Energy for Pumping8
56,331,039Net Generation (Enter Total of lines 3
through 8)
9
11,948,954Purchases10
Power Exchanges:11
4,930,109Received12
4,919,231Delivered13
10,878Net Exchanges (Line 12 minus line 13)14
Transmission For Other (Wheeling)15
13,260,949Received16
13,147,879Delivered17
113,070Net Transmission for Other (Line 16 minus
line 17)
18
-452,721Transmission By Others Losses19
67,951,220TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
20
DISPOSITION OF ENERGY21
54,641,212Sales to Ultimate Consumers (Including
Interdepartmental Sales)
22
128,557Requirements Sales for Resale (See
instruction 4, page 311.)
23
8,760,894Non-Requirements Sales for Resale (See
instruction 4, page 311.)
24
Energy Furnished Without Charge25
122,063Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
26
4,298,494Total Energy Losses27
67,951,220TOTAL (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 / /2015/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 2 8,309 821,842 1800 PST 6,048,460
February 30 23 8,038 904,128 0800 PST 5,326,720
March 31 4 7,865 858,756 0800 PST 5,588,337
April 32 15 7,417 682,185 0800 PDT 5,251,800
May 33 31 7,476 423,611 1800 PDT 5,067,454
June 34 30 10,621 464,328 1700 PDT 5,798,377
July 35 1 10,494 565,913 1500 PDT 6,069,805
August 36 13 9,631 668,232 1700 PDT 6,025,426
September 37 1 8,712 831,497 1600 PDT 5,547,345
October 38 1 7,824 830,199 1700 PDT 5,405,659
November 39 30 8,550 717,629 1800 PST 5,559,595
December 40 14 8,333 992,574 1800 PST 6,262,242
FERC FORM NO. 1 (ED. 12-90) Page 401b
41 TOTAL 67,951,220 8,760,894
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
2015/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
/ /2015/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)
386176 6 Net Peak Demand on Plant - MW (60 minutes)
71862517 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
021 11 Average Number of Employees
2499474000392328000 12 Net Generation, Exclusive of Plant Use - KWh
2635317956546 13 Cost of Plant: Land and Land Rights
64422937155722 14 Structures and Improvements
4755307225162376 15 Equipment Costs
193250107036834 16 Asset Retirement Costs
56191398613311478 17 Total Cost
1357.280270.5655 18 Cost per KW of Installed Capacity (line 17/5) Including
143975632746 19 Production Expenses: Oper, Supv, & Engr
618160148451578 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
7969920464908 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
717209638918 25 Electric Expenses
1021693910649 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
22912760 29 Maintenance Supervision and Engineering
1392665137083 30 Maintenance of Structures
3211628699871 31 Maintenance of Boiler (or reactor) Plant
75205686810 32 Maintenance of Electric Plant
323098260686 33 Maintenance of Misc Steam (or Nuclear) Plant
8384319911483249 34 Total Production Expenses
0.03350.0293 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)
184303 218 0 1454545 4830 0 38 Quantity (Units) of Fuel Burned
12254 138000 0 9168 126670 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
44.169 124.810 0.000 39.786 112.700 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
45.709 124.810 0.000 42.124 112.700 0.000 41 Average Cost of Fuel per Unit Burned
1.865 21.536 1.871 2.297 21.184 2.316 42 Average Cost of Fuel Burned per Million BTU
0.021 0.000 0.021 0.025 0.000 0.025 43 Average Cost of Fuel Burned per KWh Net Gen
11512.654 3.220 11515.874 10670.004 10.281 10680.285 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
/ /2015/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
719163 164 6
87608754 8683 7
00 0 8
760148 165 9
00 0 10
1890 0 11
51409700001192557000 1068985000 12
104497931788644 137086 13
15524520961015586 38199720 14
853217693165015529 143059721 15
172426738592613 35149 16
1036155368236412372 181431676 17
1268.60121519.2621 1054.0387 18
39281936076 329648 19
5963602617911181 19435541 20
00 0 21
43804861069424 1715067 22
00 0 23
00 0 24
089118 734477 25
166635341869058 1010808 26
5506222399 0 27
00 0 28
0271598 748176 29
2425506471471 401781 30
105632372195492 2985580 31
7535947295709 1482574 32
1327573302598 849885 33
10298019024534124 29693537 34
0.02000.0206 0.0278 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
751369 1106 0 3570193 16464 0526537 183 0 38
8410 140000 0 8042 138000 010104 133693 0 39
20.914 115.158 0.000 16.213 87.006 0.00035.521 126.581 0.000 40
23.669 115.158 0.000 16.303 87.006 0.00036.663 126.581 0.000 41
1.407 19.584 1.416 1.014 15.011 1.0371.814 22.536 1.826 42
0.015 0.000 0.015 0.011 0.000 0.0110.018 0.000 0.018 43
10598.013 5.451 10603.464 11169.956 18.562 11188.5189953.236 0.963 9954.199 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
/ /2015/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)
423448 6 Net Peak Demand on Plant - MW (60 minutes)
84938551 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
3002762000554930000 12 Net Generation, Exclusive of Plant Use - KWh
9688261683069 13 Cost of Plant: Land and Land Rights
6329625417685365 14 Structures and Improvements
37844944485571224 15 Equipment Costs
2501143532363 16 Asset Retirement Costs
453935102104472021 17 Total Cost
991.70931283.9132 18 Cost per KW of Installed Capacity (line 17/5) Including
0189454 19 Production Expenses: Oper, Supv, & Engr
6166477313792469 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
6687851905136 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
0170583 25 Electric Expenses
-1109143618418 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
0249034 29 Maintenance Supervision and Engineering
2778774496638 30 Maintenance of Structures
64683591344748 31 Maintenance of Boiler (or reactor) Plant
1242405529700 32 Maintenance of Electric Plant
382638539558 33 Maintenance of Misc Steam (or Nuclear) Plant
7811565718835738 34 Total Production Expenses
0.02600.0339 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)
264015 297 0 1364974 1954 0 38 Quantity (Units) of Fuel Burned
11394 137269 0 11205 138000 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
48.636 115.441 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
52.005 115.441 0.000 45.034 0.000 0.000 41 Average Cost of Fuel per Unit Burned
2.282 20.024 2.292 2.010 17.135 2.015 42 Average Cost of Fuel Burned per Million BTU
0.025 0.000 0.025 0.020 0.000 0.020 43 Average Cost of Fuel Burned per KWh Net Gen
10841.312 3.089 10884.401 10187.222 3.771 10190.993 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
/ /2015/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
1247.78294.46 495.59 5
1366277 475 6
87607889 8416 7
00 0 8
1158269 471 9
00 0 10
2190 0 11
83356130001959744000 3373107000 12
296510919688261 10274569 13
20713584852603034 91236560 14
1054889953245411405 431029104 15
75034292501143 2501143 16
1299180321310203843 535041376 17
1041.19341053.4668 1079.6049 18
00 0 19
16907014439087715 68317656 20
00 0 21
184709344609812 7173271 22
00 0 23
00 0 24
3310 331 25
-11100376-9619104 -372129 26
00 0 27
00 0 28
00 0 29
80373762455295 2803307 30
237576258792854 8496412 31
50426602483602 1316653 32
1213278382227 448413 33
21449197248192401 88183914 34
0.02570.0246 0.0261 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
869168 919 0 3733160 9755 01499018 6882 0 38
11470 138000 0 11311 138000 011315 138000 0 39
0.000 0.000 0.000 41.695 99.733 0.0000.000 0.000 0.000 40
44.859 0.000 0.000 45.028 99.733 0.00045.120 0.000 0.000 41
1.956 18.283 1.960 1.990 17.207 2.0011.994 17.084 2.012 42
0.020 0.000 0.020 0.020 0.000 0.0200.020 0.000 0.020 43
10174.093 2.719 10176.812 10131.305 6.783 10138.08810056.667 11.825 10068.492 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
/ /2015/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)
1429904 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
340162 11 Average Number of Employees
91957730005988318000 12 Net Generation, Exclusive of Plant Use - KWh
12099122379205 13 Cost of Plant: Land and Land Rights
144935694120076780 14 Structures and Improvements
1098112165730851901 15 Equipment Costs
1951138710624210 16 Asset Retirement Costs
1263769158863932096 17 Total Cost
814.9932867.4017 18 Cost per KW of Installed Capacity (line 17/5) Including
125588287391 19 Production Expenses: Oper, Supv, & Engr
252108692158215307 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
2302117712982916 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
00 25 Electric Expenses
-23806621-21538635 26 Misc Steam (or Nuclear) Power Expenses
2912230 27 Rents
00 28 Allowances
7802742149966 29 Maintenance Supervision and Engineering
120487783248282 30 Maintenance of Structures
2329043811976826 31 Maintenance of Boiler (or reactor) Plant
101564753101246 32 Maintenance of Electric Plant
1865553936785 33 Maintenance of Misc Steam (or Nuclear) Plant
312314817171080084 34 Total Production Expenses
0.03400.0286 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)
2678630 4671 0 5193483 12367 0 38 Quantity (Units) of Fuel Burned
11439 138000 0 9175 138000 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
47.650 99.623 0.000 45.168 114.686 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
58.892 99.623 0.000 48.270 114.686 0.000 41 Average Cost of Fuel per Unit Burned
2.574 17.188 2.581 2.631 19.787 2.644 42 Average Cost of Fuel Burned per Million BTU
0.026 0.000 0.026 0.027 0.000 0.027 43 Average Cost of Fuel Burned per KWh Net Gen
10233.120 4.521 10237.641 10363.029 7.795 10370.824 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
/ /2015/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
173693 274 6
18328759 8154 7
00 0 8
238637 266 9
00 0 10
36125 62 11
889280004899321000 2032298000 12
12520901007450 210526 13
15101604118439921 51320998 14
67279520652859048 399209035 15
113280947409550 652977 16
84766023819715969 451393536 17
336.85431159.1006 1558.3565 18
79707392979 28095 19
625232397849265 29253664 20
00 0 21
1175797959262 4558432 22
00 0 23
00 0 24
01012 0 25
38668559107751 3170165 26
0964 18807 27
00 0 28
02024615 0 29
1558041243854 292258 30
98830310863884 2947252 31
13222963313923 928039 32
2532661100841 124077 33
13036133133858350 41320789 34
0.14660.0273 0.0203 35
Coal Gas Composite GasCoal Oil Composite 36
Tons MCF MCFTons Barrels 37
2662827 86236 0 1443258 0 01536071 3715 0 38
9946 1048 0 1050 0 08054 138000 0 39
36.530 6.702 0.000 4.332 0.000 0.00018.546 120.266 0.000 40
36.529 6.702 0.000 4.332 0.000 0.00018.754 120.266 0.000 41
1.836 6.392 1.844 4.127 0.000 0.0001.164 20.750 1.181 42
0.020 0.000 0.020 0.070 0.000 0.0000.014 0.000 0.014 43
10811.501 18.455 10829.956 17035.332 0.000 0.00012175.384 10.594 12185.978 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
/ /2015/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
38.10279.56 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
36250 6 Net Peak Demand on Plant - MW (60 minutes)
85087944 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
220 11 Average Number of Employees
2597030001202753000 12 Net Generation, Exclusive of Plant Use - KWh
41195596842245 13 Cost of Plant: Land and Land Rights
829551812844330 14 Structures and Improvements
101447600162916793 15 Equipment Costs
2062367407646 16 Asset Retirement Costs
153001081177011014 17 Total Cost
4015.7764633.1772 18 Cost per KW of Installed Capacity (line 17/5) Including
295120 19 Production Expenses: Oper, Supv, & Engr
026628707 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
9988040 22 Steam Expenses
39809750 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
07720793 25 Electric Expenses
26317580 26 Misc Steam (or Nuclear) Power Expenses
62470 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
3134580 30 Maintenance of Structures
2070420 31 Maintenance of Boiler (or reactor) Plant
2876550 32 Maintenance of Electric Plant
891540 33 Maintenance of Misc Steam (or Nuclear) Plant
854460534349500 34 Total Production Expenses
0.03290.0286 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)
8864789 0 0 0 0 0 38 Quantity (Units) of Fuel Burned
1033 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
3.004 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
3.004 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
2.908 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.022 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
7612.807 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
/ /2015/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
181.0561.50 593.30 5
12317 490 6
15164690 3938 7
00 0 8
11910 477 9
00 0 10
00 19 11
3486700045774000 1092993000 12
00 1973791 13
42730000 24026885 14
780662780 321726455 15
00 1030777 16
823392780 348757908 17
454.78750.0000 587.8273 18
00 151945 19
32334080 36529831 20
00 0 21
00 0 22
00 0 23
00 0 24
6324750 2245195 25
0362000 706444 26
00 0 27
00 0 28
00 0 29
1841850 28021 30
00 0 31
6504580 6497288 32
1641690 0 33
4864695362000 46158724 34
0.13950.0079 0.0422 35
GasGas 36
MCFMCF 37
0 0 0 563090 0 07813967 0 0 38
0 0 0 1052 0 01074 0 0 39
0.000 0.000 0.000 5.741 0.000 0.0004.675 0.000 0.000 40
0.000 0.000 0.000 5.741 0.000 0.0004.675 0.000 0.000 41
0.000 0.000 0.000 5.460 0.000 0.0004.354 0.000 0.000 42
0.000 0.000 0.000 0.093 0.000 0.0000.033 0.000 0.000 43
0.000 0.000 0.000 16983.796 0.000 0.0007676.629 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
/ /2015/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)
555522 6 Net Peak Demand on Plant - MW (60 minutes)
70608281 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
3421 11 Average Number of Employees
22724200002257106000 12 Net Generation, Exclusive of Plant Use - KWh
145322753403277 13 Cost of Plant: Land and Land Rights
3546559844164698 14 Structures and Improvements
337400017324856743 15 Equipment Costs
0134848 16 Asset Retirement Costs
387397890372559566 17 Total Cost
655.1630657.1875 18 Cost per KW of Installed Capacity (line 17/5) Including
6194786128 19 Production Expenses: Oper, Supv, & Engr
6614009269244606 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)
28140961910526 25 Electric Expenses
583997690551 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
2830122440419 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
36611981079804 32 Maintenance of Electric Plant
1748021504 33 Maintenance of Misc Steam (or Nuclear) Plant
7610893273473538 34 Total Production Expenses
0.03350.0326 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)
16300845 0 0 15150724 0 0 38 Quantity (Units) of Fuel Burned
1037 0 0 1042 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
4.248 0.000 0.000 4.365 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
4.248 0.000 0.000 4.365 0.000 0.000 41 Average Cost of Fuel per Unit Burned
4.095 0.000 0.000 4.190 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.031 0.000 0.000 0.029 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
7492.601 0.000 0.000 6946.098 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
/ /2015/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
0617 0 6
07497 0 7
00 0 8
0631 0 9
00 0 10
00 0 11
02276854000 0 12
016794626 0 13
053195814 0 14
0568560609 0 15
00 0 16
0638551049 0 17
0974.5895 0 18
071591 0 19
070649551 0 20
00 0 21
00 0 22
00 0 23
00 0 24
02414966 0 25
0617666 0 26
00 0 27
00 0 28
00 0 29
0745262 0 30
00 0 31
0663174 0 32
016896 0 33
075179106 0 34
0.00000.0330 0.0000 35
Gas 36
MCF 37
16234720 0 0 0 0 00 0 0 38
1042 0 0 0 0 00 0 0 39
4.352 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 40
4.352 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 41
4.177 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
7428.486 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: b
The Carbon Plant was idled in April 2015 and retired in December 2015 to comply with the
Mercury and Air Toxics Standards requirements and other environmental regulations as well
as in conformance with Utah's Regional Haze State Implementation Plan.
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 Talen 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
2015 were $1.4 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 2015 were $11.4
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
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
2015 were $29.5 million and were primarily credited to Account 506, Miscellaneous steam
power expenses.
Schedule Page: 403.2 Line No.: -1 Column: d
With the intent of allowing Naughton Unit No. 3 to continue to serve customer load needs
beyond its currently prescribed year end December 31, 2017 compliance deadline, PacifiCorp
is considering environmental compliance alternatives to accelerated retirement which
include reassessment of traditional natural gas conversion and deployment of other
emerging technologies.
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 2015 were $4.0
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
In December 2015, PacifiCorp sold to Georgia-Pacific Consumer Products LLC, 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. Refer to
Item 3 in Important Changes During the Year in this Form No. 1.
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
2015/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 - Fuel oil 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
2015/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
/ /2015/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 28 31
Plant Hours Connect to Load 7 7,196 6,947
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 60,539,000 77,098,000
Cost of Plant 13
Land and Land Rights 14 107,019 20,914
Structures and Improvements 15 1,700,478 2,336,557
Reservoirs, Dams, and Waterways 16 2,936,826 2,954,724
Equipment Costs 17 5,355,643 10,431,454
Roads, Railroads, and Bridges 18 133,348 479,588
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 10,233,314 16,223,237
Cost per KW of Installed Capacity (line 20 / 5) 21 511.6657 600.8606
Production Expenses 22
Operation Supervision and Engineering 23 21,449 26,450
Water for Power 24 0 0
Hydraulic Expenses 25 3,821 5,159
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 992,745 1,313,392
Rents 28 60,631 82,487
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 10,312 9,968
Maintenance of Reservoirs, Dams, and Waterways 31 9,816 10,329
Maintenance of Electric Plant 32 148,372 133,848
Maintenance of Misc Hydraulic Plant 33 15,845 21,391
Total Production Expenses (total 23 thru 33) 34 1,262,991 1,603,024
Expenses per net KWh 35 0.0209 0.0208
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
/ /2015/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 2310 6
8,521 5,5068,170 7
8
31 2918 9
31 2918 10
1 31 11
32,142,000 35,726,00031,575,000 12
13
0 3,511,1050 14
2,354,538 3,978,0991,477,267 15
14,779,679 9,178,3225,126,842 16
2,160,625 14,696,7261,327,300 17
250,151 572,05950,817 18
0 00 19
19,544,993 31,936,3117,982,226 20
751.7305 1,064.5437532.1484 21
22
29,817 93,55316,614 23
1,399 0807 24
69,669 91,13440,193 25
0 00 26
476,569 1,094,323282,538 27
106,815 11,84161,624 28
0 00 29
34,321 3,90833,440 30
16,533 40,95021,950 31
18,421 34,65793,583 32
91,082 284,87751,892 33
844,626 1,655,243602,641 34
0.0263 0.04630.0191 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
/ /2015/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 27
Plant Hours Connect to Load 7 1,518 7,499
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 7,941,000 63,251,000
Cost of Plant 13
Land and Land Rights 14 0 62,169
Structures and Improvements 15 1,725,441 2,090,821
Reservoirs, Dams, and Waterways 16 12,371,658 11,163,768
Equipment Costs 17 2,942,830 4,867,577
Roads, Railroads, and Bridges 18 533,015 341,093
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 17,572,944 18,525,428
Cost per KW of Installed Capacity (line 20 / 5) 21 1,597.5404 561.3766
Production Expenses 22
Operation Supervision and Engineering 23 13,318 107,598
Water for Power 24 592 0
Hydraulic Expenses 25 29,475 35,837
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 240,959 1,320,734
Rents 28 45,191 11,876
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 19,333 56,692
Maintenance of Reservoirs, Dams, and Waterways 31 2,371 110,043
Maintenance of Electric Plant 32 7,665 83,419
Maintenance of Misc Hydraulic Plant 33 38,054 39,677
Total Production Expenses (total 23 thru 33) 34 396,958 1,765,876
Expenses per net KWh 35 0.0500 0.0279
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
/ /2015/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
79 3119 6
4,991 8,6748,422 7
8
83 3219 9
83 3219 10
2 11 11
160,121,000 123,550,00082,043,000 12
13
25,845 0341,706 14
3,528,960 2,708,5667,367,591 15
15,570,539 15,724,31415,256,322 16
15,364,071 6,717,2942,724,771 17
886,710 488,8771,095,742 18
0 00 19
35,376,125 25,639,05126,786,132 20
361.0546 801.47081,488.1184 21
22
194,434 34,2531,437,841 23
0 1,7210 24
5,772 85,71920,379 25
0 00 26
764,435 615,413905,002 27
40,950 131,42454,568 28
0 00 29
14,259 42,2735,829 30
32,540 14,6978,916 31
20,795 21,379109,859 32
40,218 111,86814,261 33
1,113,403 1,058,7472,556,655 34
0.0070 0.00860.0312 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
/ /2015/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 33 145
Plant Hours Connect to Load 7 8,639 8,710
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 12 136,640,000 398,837,000
Cost of Plant 13
Land and Land Rights 14 0 1,086,564
Structures and Improvements 15 5,243,965 105,316,429
Reservoirs, Dams, and Waterways 16 31,435,214 29,886,552
Equipment Costs 17 11,835,096 17,827,191
Roads, Railroads, and Bridges 18 1,952,391 3,870,462
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 50,466,666 157,987,198
Cost per KW of Installed Capacity (line 20 / 5) 21 1,310.8225 1,161.6706
Production Expenses 22
Operation Supervision and Engineering 23 41,223 1,439,615
Water for Power 24 2,071 25,319
Hydraulic Expenses 25 103,163 755,695
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 646,118 666,372
Rents 28 158,170 104,941
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 50,129 54,828
Maintenance of Reservoirs, Dams, and Waterways 31 30,915 61,562
Maintenance of Electric Plant 32 12,746 129,734
Maintenance of Misc Hydraulic Plant 33 135,462 328,074
Total Production Expenses (total 23 thru 33) 34 1,179,997 3,566,140
Expenses per net KWh 35 0.0086 0.0089
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
/ /2015/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Storage Run-of-RiverStorage 1
Conventional ConventionalConventional 2
1915 19281949 3
1920 19281950 4
30.00 32.0042.50 5
14 3643 6
8,760 8,7598,650 7
8
28 3645 9
28 3645 10
2 11 11
28,864,000 166,763,000183,992,000 12
13
36,698 105,1680 14
1,893,739 3,530,1924,069,708 15
6,316,949 30,634,02612,752,241 16
6,316,113 7,058,2984,417,196 17
503,332 325,069264,441 18
0 00 19
15,066,831 41,652,75321,503,586 20
502.2277 1,301.6485505.9667 21
22
97,816 344,11169,365 23
0 11,3342,287 24
32,579 2,838113,881 25
0 00 26
803,125 636,432838,974 27
10,797 53,201174,603 28
0 2650 29
10,323 45,40659,235 30
1,901 166,15611,074 31
74,454 33,615109,519 32
34,440 204,619148,326 33
1,065,435 1,497,9771,527,264 34
0.0369 0.00900.0083 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
/ /2015/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 14.45
Net Peak Demand on Plant-Megawatts (60 minutes) 6 17 6
Plant Hours Connect to Load 7 8,237 5,124
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 44,735,000 14,474,000
Cost of Plant 13
Land and Land Rights 14 0 511,083
Structures and Improvements 15 2,185,789 732,396
Reservoirs, Dams, and Waterways 16 14,878,343 10,532,263
Equipment Costs 17 8,964,422 5,424,548
Roads, Railroads, and Bridges 18 463,083 0
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 26,491,637 17,200,290
Cost per KW of Installed Capacity (line 20 / 5) 21 1,471.7576 1,190.3315
Production Expenses 22
Operation Supervision and Engineering 23 38,542 45,979
Water for Power 24 968 0
Hydraulic Expenses 25 48,232 15,204
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 334,037 493,654
Rents 28 73,949 5,115
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 58,050 8,849
Maintenance of Reservoirs, Dams, and Waterways 31 9,060 92
Maintenance of Electric Plant 32 65,515 32,749
Maintenance of Misc Hydraulic Plant 33 74,266 16,072
Total Production Expenses (total 23 thru 33) 34 702,619 617,714
Expenses per net KWh 35 0.0157 0.0427
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
/ /2015/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
254 16712 6
5,462 5,7828,062 7
8
264 16412 9
264 16412 10
1 12 11
583,525,000 482,067,00034,278,000 12
13
14,160,894 8,363,0130 14
71,309,098 16,121,5714,226,017 15
46,964,944 30,362,73789,359,648 16
24,634,936 16,631,2232,633,367 17
1,133,091 2,051,6382,088,444 18
0 00 19
158,202,963 73,530,18298,307,476 20
659.1790 548.73278,937.0433 21
22
2,495,852 1,445,24113,181 23
44,680 24,946592 24
1,556,708 744,583400,872 25
0 00 26
678,442 570,766418,717 27
185,191 103,39845,191 28
0 00 29
30,657 29,12331,580 30
57,937 49,773217,095 31
149,641 115,930101,320 32
547,838 325,71639,880 33
5,746,946 3,409,4761,268,428 34
0.0098 0.00710.0370 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
/ /2015/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 6 0
Plant Hours Connect to Load 7 3,336 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 0 0
Net Generation, Exclusive of Plant Use - Kwh 12 6,475,000 0
Cost of Plant 13
Land and Land Rights 14 0 0
Structures and Improvements 15 0 0
Reservoirs, Dams, and Waterways 16 0 0
Equipment Costs 17 0 0
Roads, Railroads, and Bridges 18 0 0
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 0 0
Cost per KW of Installed Capacity (line 20 / 5) 21 0.0000 0.0000
Production Expenses 22
Operation Supervision and Engineering 23 32,120 0
Water for Power 24 0 0
Hydraulic Expenses 25 31,289 0
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 274,249 0
Rents 28 3,758 0
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 47,185 0
Maintenance of Reservoirs, Dams, and Waterways 31 4,129 0
Maintenance of Electric Plant 32 483 0
Maintenance of Misc Hydraulic Plant 33 81,844 0
Total Production Expenses (total 23 thru 33) 34 475,057 0
Expenses per net KWh 35 0.0734 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
/ /2015/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 had a
25-year lease agreement that ended in 2015 to operate and take all the generation. In
September 2015, the Olmsted Plant was retired when the U.S. Department of Interior decided
to replace the Olmsted Plant with a new hydroelectric facility in the same vicinity.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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 / /2015/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 6.4 29,969,000 33,475,8971917Ashton 2381 2
1.11 1.0 2,396,000 1,578,6231913Bend 3
4.15 4.6 26,515,000 7,599,3191910Big Fork 2652 4
2.81 2.8 16,857,000 1,934,2351957Eagle Point 5
3.20 1.0 2,000 1,991,6951924East Side 2082 6
2.20 2.0 9,699,000 1,434,4271903Fall Creek 2082 7
0.161922Fountain Green 8
2.00 1.2 5,516,000 5,237,4831896Granite 9
0.75 0.4 772,000 683,0451917Gunlock 10
1.73 0.8 1,929,000 2,805,0241983Last Chance 11
0.72 0.1 2,441,000 449,8041910Paris 12
5.00 3.4 9,846,000 11,380,6081897Pioneer 2722 13
3.76 4.6 6,378,000 2,590,6601912Prospect No. 1 2630 14
7.20 7.7 27,781,000 8,823,3201932Prospect No. 3 2337 15
1.00 0.9 1,219,000 2,409,7921944Prospect No. 4 2630 16
0.80 0.3 543,000 933,1521926Sand Cove 17
1.00 1.2 3,897,000 1,721,7381895Stairs 597 18
0.50 0.2 219,000 893,2521920Veyo 19
0.74 0.3 1,005,000 1,232,1151986Viva Naughton 20
1.10 1.0 3,490,000 3,220,8051921Wallowa Falls 308 21
3.85 2.0 9,926,000 3,638,5001911Weber 1744 22
0.60 0.6 -21,000 468,5741908West Side 2082 23
7,527,522Keno Regulating Dam 2082 24
3,847,268Upper Klamath Lake 2082 25
15,480,603North Umpqua 1927 26
27
Pumping Plant: 28
-2.80 -3.0 -2,776,000 19,497,5161917Lifton 29
30
Wind: 31
111.00 111.0 339,706,000 240,938,3862010Dunlap Ranch 1 32
32.15 32.6 81,453,000 38,474,1341999Foote Creek 33
99.00 99.0 289,386,000 202,236,4142008Glenrock 34
39.00 39.0 108,844,000 87,955,2082009Glenrock III 35
99.00 99.0 261,284,000 203,986,0262009Rolling Hills 36
94.00 94.0 186,746,000 185,577,1792008Goodnoe Hills 37
100.00 100.5 188,567,000 178,550,1772006Leaning Juniper 1 38
140.40 140.4 298,771,000 240,969,1432007Marengo 39
70.20 70.2 137,848,000 129,806,4432008Marengo II 40
99.00 99.0 296,563,000 201,814,4212008Seven Mile Hill 41
19.50 19.5 64,063,000 42,416,3342008Seven Mile Hill II 42
99.00 99.0 250,864,000 220,314,9192009High Plains 43
28.50 28.5 78,271,000 56,998,5302009McFadden 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 / /2015/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
115,703 4,996,403 2Water 481,644
5,180 1,422,183 3Water 149,990
124,971 1,831,161 4Water 353,290
109,046 688,340 5Water 269,271
104,823 622,405 6Water 104,657
38,165 652,012 7Water 140,680
8Water
34,177 2,618,742 9Water 187,487
20,811 910,727 10Water 70,522
5,360 1,621,401 11Water 116,375
25,603 624,728 12Water 57,645
124,185 2,276,122 13Water 544,871
46,686 689,005 14Water 147,766
299,957 1,225,461 15Water 346,785
12,222 2,409,792 16Water 48,524
58,326 1,166,440 17Water 86,787
18,206 1,721,738 18Water 154,740
87,544 1,786,504 19Water 78,359
95,081 1,665,020 20Water 180,063
3,660 2,928,005 21Water 97,524
11,921 945,065 22Water 277,627
2,655 780,957 23Water 4,477
3,787 24 52,169
24,661 25 293,332
26
27
28
36,804 -6,963,399 29Water 250,793
30
31
1,385,883 2,170,616 32Wind 319,675
1,648,045 1,196,707 33Wind 162,598
1,308,106 2,042,792 34Wind 601,778
517,762 2,255,262 35Wind 210,345
1,278,667 2,060,465 36Wind 594,395
2,300,670 1,974,225 37Wind 949,229
1,284,021 1,785,502 38Wind 1,269,677
1,278,094 1,716,304 39Wind 1,282,960
630,893 1,849,095 40Wind 569,870
1,350,189 2,038,530 41Wind 615,757
272,765 2,175,197 42Wind 136,646
1,844,714 2,225,403 43Wind 825,307
423,681 1,999,948 44Wind 231,636
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 / /2015/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 4,469,000 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 / /2015/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 506,332
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.: 6 Column: a
East Side
The East Side plant was significantly curtailed pursuant to Section 6.2 of the Klamath
Hydroelectric Settlement Agreement in FERC Docket No. P-2082-000.
Schedule Page: 410 Line No.: 8 Column: a
Fountain Green
The Fountain Green hydroelectric generating facility was sold in March 2015 to the Utah
Division of Wildlife Resources. For more information, refer to Item 3 in Important Changes
During the Year in this Form No. 1.
Schedule Page: 410 Line No.: 23 Column: a
West Side
The West Side plant generation supplies station use and was significantly curtailed
pursuant to Section 6.2 of the Klamath Hydroelectric Settlement Agreement in FERC Docket
No. P-2082-000.
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 PacifiCorp (previously
operated by SeaWest Energy) and is jointly owned by PacifiCorp and Eugene Water and
Electric Board with an undivided interest of 78.79% and 21.21%, respectively. Data
reported in line 33 represents PacifiCorp's share.
Schedule Page: 410.1 Line No.: 1 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Black Cap
PacifiCorp has an agreement with Citizens 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
2015/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 LINE STATISTICS
PacifiCorp X
/ /2015/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, ID 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 16,969.00 715.00 282
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
/ /2015/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
279,732,776 266,393,077 13,339,699 757,484 362,482 390,433 4,569 13
14
279,732,776 266,393,077 13,339,699 757,484 362,482 390,433 4,569 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
36 229,153,883 3,385,069,822 3,614,223,705 409,509 17,142,995 2,248,767 19,801,271
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
/ /2015/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
Steel - H 345.00 345.00 170.00 1 18 RED BUTTE, UT SIGURD, UT
Steel Tower 345.00 345.00 226.00 1 19 JIM BRIDGER, WY GOSHEN, ID
Wood - H 345.00 345.00 79.00 1 20 BORAH, ID MIDPOINT #1, ID
Wood - H 345.00 345.00 78.00 1 21 BORAH, ID MIDPOINT #2, ID
Steel - SP 345.00 345.00 113.00 1 22 KINPORT, ID MIDPOINT, ID
23 345kV costs and expenses
24
383.00 2,752.00 41 25 Subtotal 345 kV
26
Wood - H 230.00 230.00 59.00 1 27 ALVEY, OR DIXONVILLE, OR
Wood - H 230.00 230.00 76.00 1 28 ANTELOPE, ID ANACONDA, MT
Wood - H 230.00 230.00 20.00 1 29 ANTELOPE, ID LOST RIVER, ID
Wood - H 230.00 230.00 1.00 1 30 ATLANTIC CITY, WY COLUMBIA GENEVA, WY
Wood - H 230.00 230.00 88.00 1 31 BEN LOMOND, UT NAUGHTON #1, WY
Wood - H 230.00 230.00 88.00 1 32 BEN LOMOND, UT NAUGHTON #2, WY
Wood - H 230.00 230.00 19.00 1 33 BIRCH CREEK, UT RAILROAD, WY
Wood - H 230.00 230.00 3.00 1 34 BITTER CREEK, WY MONELL, WY
Wood - H 230.00 230.00 1.00 1 35 BRIDGER PUMP, WY MANS FACE, WY
FERC FORM NO. 1 (ED. 12-87) Page 422.1
36 TOTAL 16,969.00 715.00 282
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
/ /2015/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
2-954 ACSR 45/7 18
2-1272 ACSR 36/1 19
3-1272 ACSR 45/7 20
3-1272 ACSR 45/7 21
2-1272 ACSR 45/7 22
1,776,735,576 1,626,046,639 150,688,937 2,156,083 468,377 1,684,607 3,099 23
24
1,776,735,576 1,626,046,639 150,688,937 2,156,083 468,377 1,684,607 3,099 25
26
1272 ACSR 36/1 27
1272 ACSR 45/7 28
795 ACSR 45/7 29
1272 ACSR 36/1 30
795 ACSR 26/7 31
795 ACSR 26/7 32
954 ACSR 54/7 33
795 ACSR 26/7 34
1272 ACSR 36/1 35
FERC FORM NO. 1 (ED. 12-87) Page 423.1
36 229,153,883 3,385,069,822 3,614,223,705 409,509 17,142,995 2,248,767 19,801,271
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
/ /2015/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 230.00 230.00 107.00 1 1 BUFFALO, WY CASPER, WY
Wood - H 230.00 230.00 36.00 1 2 CASPER, WY DAVE JOHNSTON, WY
Wood - H 230.00 230.00 110.00 1 3 CASPER, WY RIVERTON, WY
Steel - SP 230.00 230.00 30.00 1 4 CHAPPEL CREEK, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 32.00 1 5 CHAPPEL CREEK, WY JONAH GAS, WY
Wood - H 230.00 230.00 6.00 29.00 1 6 CHAPPEL CREEK, WY RILEY RIDGE, WY
Wood - H 230.00 230.00 2.00 1 7 CRAVEN CREEK, WY PIONEER, WY
Wood - H 230.00 230.00 31.00 1 8 DAVE JOHNSTON, WY SPENCE, WY
Wood - H 230.00 230.00 69.00 1 9 DAVE JOHNSTON, WY WYODAK, WY
Wood - H 230.00 230.00 1.00 1 10 DIXONVILLE 500kV, OR DIXONVILLE 230kV, OR
Wood - H 230.00 230.00 17.00 1 11 DIXONVILLE, OR RESTON (BPA), OR
Wood - H 230.00 230.00 12.00 1 12 FAIRVIEW (BPA), OR ISTHMUS, OR
Wood - H 230.00 230.00 49.00 1 13 FIREHOLE, WY MONUMENT, WY
Wood - H 230.00 230.00 26.00 1 14 FRY, OR BETHEL, OR
Wood - H 230.00 230.00 45.00 1 15 FRY, OR ALVEY, OR
Wood - H 230.00 230.00 159.00 1 16 GLEN CANYON, AZ SIGURD, UT
Wood - H 230.00 230.00 98.00 1 17 GONDER, UT - NV STATE PAVANT, UT
Wood - H 230.00 230.00 40.00 1 18 BUFFALO, WY SHERIDAN (MDU), WY
Wood - H 230.00 230.00 62.00 1 19 DIXONVILLE, OR GRANTS PASS, OR
Wood - H 230.00 230.00 78.00 1 20 HURRICANE, OR WALLA WALLA, WA
Wood - H 230.00 230.00 209.00 1 21 POINT OF ROCKS, WY DAVE JOHNSTON, WY
Wood - H 230.00 230.00 149.00 1 22 JIM BRIDGER, WY SPENCE, WY
Wood - H 230.00 230.00 35.00 1 23 KLAMATH FALLS, OR MALIN, OR
Wood - H 230.00 230.00 2.00 1 24 LIMA, WY ROBERSON, WY
Wood - H 230.00 230.00 76.00 1 25 LONE PINE, OR KLAMATH FALLS, OR
Steel - SP 230.00 230.00 5.00 1 26 LONE PINE, OR MERIDIAN #1, OR
Steel - SP 230.00 230.00 5.00 1 27 LONE PINE, OR MERIDIAN #2, OR
Wood - H 230.00 230.00 56.00 1 28 MCNARY (BPA), WA WALLA WALLA, WA
Wood - H 230.00 230.00 35.00 1 29 MERIDIAN, OR GRANTS PASS, OR
Wood - H 230.00 230.00 38.00 1 30 HIGH PLAINS, WY STANDPIPE, WY
Wood - H 230.00 230.00 13.00 1 31 MONUMENT, WY EXXON, WY
Wood - H 230.00 230.00 20.00 1 32 MONUMENT, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 80.00 1 33 NAUGHTON, WY TREASURETON, ID
Wood - H 230.00 230.00 30.00 1 34 NAUGHTON, WY MONUMENT, WY
Wood - H 230.00 230.00 16.00 1 35 NAUGHTON, WY CRAVEN CREEK, WY
FERC FORM NO. 1 (ED. 12-87) Page 422.2
36 TOTAL 16,969.00 715.00 282
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
/ /2015/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
2
1272 ACSR 36/1 3
954 ACSR 54/7 4
1272 ACSR 45/7 5
1272 ACSR 45/7 6
1272 ACSR 45/7 7
1272 ACSR 45/7 8
1272 ACSR 36/1 9
1272 ACSR 36/1 10
795 ACSR 26/7 11
1272 ACSR 36/1 12
1272 ACSR 45/7 13
1272 ACSR 36/1 14
1272 ACSR 36/1 15
954 ACSR 45/7 16
795 ACSR 45/7 17
795 ACSR 26/7 18
1272 ACSR 36/1 19
1272 ACSR 36/1 20
1272 ACSR 36/1 21
1272 ACSR 36/1 22
1272 ACSR 36/1 23
1272 ACSR 45/7 24
795 ACSR 26/7 25
1272 ACSR 54/19 26
1272 ACSR 36/1 27
1272 ACSR 36/1 28
1272 ACSR 36/1 29
1272 ACSR 45/7 30
1272 ACSR 36/1 31
1272 ACSR 45/7 32
1272 ACSR 45/7 33
1272 ACSR 36/1 34
954 ACSR 54/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.2
36 229,153,883 3,385,069,822 3,614,223,705 409,509 17,142,995 2,248,767 19,801,271
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
/ /2015/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 4.00 1 1 PALISADES SS, WY BLUE RIM, WY
Wood - H 230.00 230.00 94.00 1 2 PAROWAN VALLEY, UT SIGURD, UT
Wood - H 230.00 230.00 26.00 1 3 PAROWAN VALLEY, UT WEST CEDAR, UT
Wood - H 230.00 230.00 43.00 1 4 PAVANT, UT SIGURD, UT
Wood - H 230.00 230.00 35.00 1 5 JIM BRIDGER, WY ROCK SPRINGS, WY
Wood - H 230.00 230.00 8.00 1 6 POMONA, WA UNION GAP, WA
Wood - H 230.00 230.00 118.00 1 7 RIVERTON, WY ROCK SPRINGS, WY
Wood - H 230.00 230.00 51.00 1 8 RIVERTON, WY THERMOPOLIS, WY
Wood - H 230.00 230.00 55.00 1 9 ROCK SPRINGS, WY FLAMING GORGE, UT
Wood - H 230.00 230.00 35.00 1 10 ROCK SPRINGS, WY JIM BRIDGER, WY
Wood - H 230.00 230.00 41.00 1 11 ROCK SPRINGS, WY MONUMENT, WY
Wood - H 230.00 230.00 12.00 1 12 SHIRLEY BASIN, WY DUNLAP RANCH, WY
Wood - H 230.00 230.00 2.00 1 13 SWIFT No. 1, WA SWIFT No. 2, WA
Wood - H 230.00 230.00 23.00 1 14 SWIFT No. 2, WA WOODLAND (BPA) SS, WA
Wood - H 230.00 230.00 7.00 1 15 TALBOT, WA MARENGO II, WA
Wood - H 230.00 230.00 9.00 1 16 TAP TO HANNA, OR NICKEL MOUNTAIN, OR
Wood - H 230.00 230.00 176.00 1 17 THERMOPOLIS, WY YELLOWTAIL, MT
Wood - H 230.00 230.00 66.00 1 18 TREASURETON, ID BRADY, ID
Steel Tower 230.00 230.00 6.00 1 19 TROUTDALE (BPA), OR GRESHAM (PGE), OR
230.00 230.00 7.00 1 20 TROUTDALE (BPA), OR LINNEMAN (PGE), OR
Wood - H 230.00 230.00 39.00 1 21 UNION GAP, WA MIDWAY (BPA), WA
Wood - H 230.00 230.00 45.00 1 22 WALLA WALLA, WA LEWISTON (AVISTA), ID
Wood - H 230.00 230.00 33.00 1 23 WALLA WALLA, WA WANAPUM (GPUD), WA
Wood - H 230.00 230.00 37.00 1 24 WANAPUM (GPUD), WA POMONA, WA
Wood - H 230.00 230.00 13.00 1 25 WINDSTAR, WY GLENROCK, WY
Wood - H 230.00 230.00 69.00 1 26 WYODAK, WY BUFFALO, WY
Wood - H 230.00 230.00 63.00 1 27 YAMSAY (BPA), OR KLAMATH FALLS, OR
Wood - H 230.00 230.00 62.00 1 28 SHERIDAN (MDU), WY YELLOWTAIL, MT
29 230kV costs and expenses
30
13.00 3,329.00 72 31 Subtotal 230 kV
32
Wood - H 161.00 161.00 82.00 1 33 BIG GRASSY, ID JEFFERSON, ID
Wood - H 161.00 161.00 45.00 1 34 ANTELOPE, ID GOSHEN, ID
Wood - SP 161.00 161.00 9.00 1 35 BONNEVILLE, ID EAGLEROCK, ID
FERC FORM NO. 1 (ED. 12-87) Page 422.3
36 TOTAL 16,969.00 715.00 282
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
/ /2015/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
795 ACSR 45/7 2
795 ACSR 45/7 3
795 ACSR 45/7 4
1272 ACSR 45/7 5
1272 ACSR 36/1 6
1272 ACSR 36/1 7
1272 ACSR 36/1 8
1272 ACSR 36/1 9
1272 ACSR 36/1 10
1272 ACSR 36/1 11
795 ACSR 26/7 12
954 ACSR 45/7 13
954 ACSR 45/7 14
795 ACSR 26/7 15
795 ACSR 26/7 16
1272 ACSR 36/1 17
795 ACSR 26/7 18
954 ACSR 45/7 19
900 ACSR 54/7 20
954 ACSR 45/7 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
795 ACSR 26/7 27
795 ACSR 26/7 28
407,554,337 388,558,750 18,995,587 4,239,846 520,222 3,653,604 66,020 29
30
407,554,337 388,558,750 18,995,587 4,239,846 520,222 3,653,604 66,020 31
32
250I CU /18 33
397.5 ACSR 26/7 34
954 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.3
36 229,153,883 3,385,069,822 3,614,223,705 409,509 17,142,995 2,248,767 19,801,271
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
/ /2015/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Wood - H 161.00 161.00 57.00 1 1 GOSHEN, ID GRACE, ID
Wood - H 161.00 161.00 31.00 1 2 GOSHEN, ID RIGBY, ID
Wood - SP 161.00 161.00 17.00 1 3 GOSHEN, ID SUGARMILL, ID
Wood - SP 161.00 161.00 17.00 1 4 SUGARMILL, ID RIGBY, ID
Wood - H 161.00 161.00 15.00 1 5 EAGLEROCK, ID GOSHEN, ID
Wood - H 161.00 161.00 46.00 1 6 YELLOWTAIL, MT RIMROCK, MT
Wood - SP 161.00 161.00 18.00 1 7 RIGBY, ID JEFFERSON, ID
Wood - H 161.00 161.00 30.00 1 8 GOSHEN, ID JEFFERSON, ID
9 161kV costs and expenses
10
112.00 255.00 11 11 Subtotal 161 kV
12
Steel - SP 138.00 138.00 1.00 1 13 90TH SOUTH, UT SANDY, UT
Wood - H 138.00 138.00 12.00 1 14 90TH SOUTH, UT DUMAS #1, UT
Wood - H 138.00 138.00 6.00 1 15 90TH SOUTH, UT DUMAS #2, UT
Wood - SP 138.00 138.00 10.00 1 16 90TH SOUTH, UT OQUIRRH, UT
Wood - H 138.00 138.00 44.00 1 17 ABAJO, UT PINTO, UT
Wood - H 138.00 138.00 4.00 1 18 AGRIUM, UT THREEMILE KNOLL, ID
Wood - H 138.00 138.00 22.00 1 19 ANSCHTZ CO-GEN, WY EVANSTON, WY
Wood - H 138.00 138.00 1.00 1 20 ANTELOPE, ID SCOVILLE #1, ID
Wood - H 138.00 138.00 1.00 1 21 ANTELOPE, ID SCOVILLE #2, ID
Wood - H 138.00 138.00 26.00 1 22 ASHGROVE, UT CLOVER, UT
Wood - H 138.00 138.00 102.00 1 23 ASHLEY, UT CARBON, UT
Wood - H 138.00 138.00 12.00 1 24 ASHLEY, UT VERNAL, UT
Wood - H 138.00 138.00 6.00 1 25 BANGERTER, UT OQUIRRH, UT
Wood - SP 138.00 138.00 1.00 1 26 BDO, UT BDO TAP, UT
Wood - H 138.00 138.00 14.00 1 27 BEN LOMOND, UT BRIGHAM CITY, UT
Steel - SP 138.00 138.00 14.00 1 28 BEN LOMOND #1, UT EL MONTE, UT
138.00 138.00 13.00 1 29 BEN LOMOND #2, UT EL MONTE, UT
Steel Tower 138.00 138.00 22.00 1 30 BEN LOMOND, UT HONEYVILLE, UT
Steel Tower 230.00 138.00 13.00 7.00 1 31 BEN LOMOND, UT SYRACUSE #1, UT
Steel - SP 138.00 138.00 28.00 1 32 BEN LOMOND, UT ANGLE, UT
Wood - SP 138.00 138.00 14.00 1 33 BEN LOMOND, UT W ZIRCONIUM, UT
Steel Tower 138.00 138.00 42.00 1 34 BEN LOMOND, UT WHEELON, UT
Steel Tower 138.00 138.00 25.00 1 35 BEN LOMOND, UT SYRACUSE, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.4
36 TOTAL 16,969.00 715.00 282
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
/ /2015/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
250HH CU /7 1
397.5 ACSR 26/7 2
795 AAC /37 3
397.5 ACSR 26/7 4
1272 ACSR 45/7 5
556.5 ACSR 26/7 6
397.5 ACSR 26/7 7
250HH CU /7 8
25,578,258 24,954,768 623,490 283,981 4,632 279,349 9
10
25,578,258 24,954,768 623,490 283,981 4,632 279,349 11
12
795 AAC /37 13
795 AAC /37 14
795 AAC /37 15
795 ACSR 26/7 16
397.5 ACSR 26/7 17
397.5 ACSR 26/7 18
795 ACSR 26/7 19
397.5 ACSR 26/7 20
397.5 ACSR 26/7 21
397.5 ACSR 26/7 22
397.5 ACSR 26/7 23
397.5 ACSR 26/7 24
25
397.5 ACSR 26/7 26
1272 ACSR 45/7 27
795 ACSR 45/7 28
795 ACSR 45/7 29
250 CUHD /12 30
795 AAC /37 31
397.5 ACSR 26/7 32
795 AAC /37 33
250 CUHD /12 34
1272 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.4
36 229,153,883 3,385,069,822 3,614,223,705 409,509 17,142,995 2,248,767 19,801,271
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
/ /2015/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 9.00 1 1 BONANZA, UT CHAPITA, UT
Wood - SP 138.00 138.00 16.00 1 2 BRIDGERLAND, UT GREEN CANYON, UT
Wood - H 138.00 138.00 24.00 1 3 BRIGHAM CITY, UT WHEELON, UT
Steel - SP 138.00 138.00 9.00 1 4 BUTLERVILLE, UT 90TH SOUTH, UT
Wood - H 138.00 138.00 35.00 1 5 CAMERON, UT PAROWAN, UT
Wood - H 138.00 138.00 64.00 1 6 CAMERON, UT SIGURD, UT
Wood - H 138.00 138.00 12.00 1 7 CANYON COMP, WY STR 204, WY
Wood - H 138.00 138.00 2.00 1 8 CARBON, UT HELPER #2, UT
Steel Tower 138.00 138.00 54.00 1 9 CARBON, UT SPANISH FORK #1, UT
Steel Tower 138.00 138.00 52.00 1 10 CARBON, UT SPANISH FORK #2, UT
Wood - H 138.00 138.00 120.00 1 11 CARBON, UT MOAB, UT
Wood - SP 138.00 138.00 5.00 1 12 CLEAR CREEK, WY PAINTER, UT
Wood - SP 138.00 138.00 8.00 1 13 CLOVER, UT NEBO, UT
Wood - H 138.00 138.00 2.00 1 14 COLUMBIA, UT SUNNYSIDE, UT
Steel - SP 138.00 138.00 6.00 1 15 COTTONWOOD, UT MCCLELLAND, UT
Wood - SP 138.00 138.00 5.00 1 16 COTTONWOOD, UT HAMMER, UT
Wood - SP 138.00 138.00 29.00 1 17 COTTONWOOD, UT SILVER CREEK, UT
Wood - SP 138.00 138.00 1.00 1 18 CUTLER, UT WHEELON, UT
Steel - SP 138.00 138.00 5.00 1 19 DRY CREEK, UT SPANISH FORK, UT
Wood - SP 138.00 138.00 18.00 1 20 DUMAS, UT WESTFIELD, UT
Steel - SP 138.00 138.00 2.00 1 21 DYNAMO, UT TRI-CITY #1, UT
138.00 138.00 3.00 1 22 DYNAMO, UT TRI-CITY #2, UT
Steel - SP 138.00 138.00 15.00 1 23 EAST LAYTON, UT 105 TAP, UT
Wood -SP 138.00 138.00 1.00 1 24 EBAY TAP, UT OQUIRRH, UT
Steel - SP 138.00 138.00 4.00 1 25 EL MONTE, UT STR 30B , UT
Steel - SP 138.00 138.00 1.00 1 26 EL MONTE, UT PIONEER, UT
Wood - SP 138.00 138.00 3.00 1 27 EVANSTON, WY RAILROAD, UT
Wood - SP 138.00 138.00 10.00 1 28 FRANKLIN, ID TREASURETON, ID
Wood - SP 138.00 138.00 25.00 1 29 FRANKLIN, ID GREEN CANYON, UT
Wood - SP 138.00 138.00 1.00 1 30 GADSBY, UT THIRD WEST, UT
Wood - SP 138.00 138.00 6.00 1 31 GADSBY, UT TERMINAL, UT
Wood - SP 138.00 138.00 1.00 1 32 GADSBY, UT JORDAN, UT
Wood - SP 138.00 138.00 7.00 1 33 GREEN CANYON, UT NIBLEY, UT
Wood - SP 138.00 138.00 19.00 1 34 GREEN CANYON, UT WHEELON, UT
Wood - H 138.00 138.00 19.00 1 35 HALE, UT MIDWAY, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.5
36 TOTAL 16,969.00 715.00 282
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
/ /2015/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
795 ACSR 26/7 3
795 AAC /37 4
397.5 ACSR 26/7 5
397.5 ACSR 26/7 6
795 ACSR 26/7 7
556.5 ACSR 26/7 8
795 ACSR 26/7 9
1272 ACSR 45/7 10
954 ACSR 54/7 11
795 ACSR 26/7 12
1272 ACSR 45/7 13
397.5 ACSR 26/7 14
795 AAC /37 15
795 AAC /37 16
397.5 ACSR 26/7 17
250 CUHD /12 18
1272 ACSR 45/7 19
795 ACSR 26/7 20
795 ACSR 26/7 21
795 ACSR 26/7 22
795 ACSR 26/7 23
795 ACSR 26/7 24
1272 ACSR 45/7 25
1272 ACSR 45/7 26
795 ACSR 26/7 27
795 ACSR 26/7 28
397.5 ACSR 26/7 29
1272 AAC /61 30
1272 ACSR 45/7 31
1272 ACSR 45/7 32
1272 ACSR 45/7 33
397.5 ACSR 26/7 34
397.5 ACSR 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.5
36 229,153,883 3,385,069,822 3,614,223,705 409,509 17,142,995 2,248,767 19,801,271
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
/ /2015/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 7.00 1 1 HALE, UT TANNER, UT
Wood - H 138.00 138.00 18.00 1 2 HALE, UT SPANISH FORK, UT
138.00 138.00 2.00 1 3 HAMMER, UT BUTLERVILLE, UT
Wood - H 138.00 138.00 25.00 1 4 HONEYVILLE, UT LAMPO, UT
138.00 138.00 14.00 1 5 HONEYVILLE, UT WHEELON, UT
Wood - H 138.00 138.00 7.00 1 6 HUNTINGTON, UT MCFADDEN, UT
Wood - H 138.00 138.00 26.00 1 7 JERUSALEM, UT NEBO, UT
Wood - SP 138.00 138.00 1.00 1 8 JORDAN, UT THIRDWEST, UT
Wood - SP 138.00 138.00 5.00 1 9 JORDAN, UT MCCLELLAND, UT
Wood - SP 138.00 138.00 6.00 1 10 JORDAN, UT TERMINAL, UT
Wood - SP 138.00 138.00 1.00 1 11 BARNEYS, UT GRINDING, UT
Wood - SP 138.00 138.00 3.00 1 12 KEARNS, UT TAYLORSVILLE, UT
Wood - SP 138.00 138.00 2.00 1 13 KEARNS, UT WEST VALLEY, UT
138.00 138.00 8.00 1 14 LONE PEAK, UT CAMP WILLIAMS, UT
Wood - SP 138.00 138.00 6.00 1 15 MCCLELLAND, UT MID VALLEY, UT
Wood - H 138.00 138.00 11.00 1 16 MCFADDEN, UT BLACKHAWK, UT
Wood - SP 138.00 138.00 2.00 4.00 1 17 MID VALLEY, UT TAYLORSVILLE, UT
Wood - SP 138.00 138.00 5.00 1 18 MID VALLEY #2, UT COTTONWOOD, UT
Wood - SP 138.00 138.00 3.00 1 19 MID VALLEY #1, UT COTTONWOOD, UT
Wood - H 138.00 138.00 9.00 1 20 MID VALLEY, UT 90TH SOUTH, UT
Wood - H 138.00 138.00 1.00 1 21 MIDDLETON, UT SAINT GEORGE, UT
Wood - H 138.00 138.00 68.00 1 22 MOAB, UT PINTO, UT
Wood - H 138.00 138.00 36.00 1 23 NAUGHTON, WY CANYON COMP, WY
Wood - H 138.00 138.00 48.00 1 24 NAUGHTON, WY PAINTER, WY
Wood - H 138.00 138.00 33.00 1 25 NEBO, UT DRY CREEK, UT
Wood - H 138.00 138.00 10.00 1 26 NUCOR STEEL, UT WHEELON, UT
Wood - H 138.00 138.00 23.00 1 27 ONEIDA, ID OVID, UT
Wood - H 138.00 138.00 19.00 1 28 ONIEDA, ID GRACE, ID
Wood - SP 138.00 138.00 14.00 1 29 GRINDING, UT OQUIRRH, UT
Wood - SP 138.00 138.00 7.00 1 30 GRINDING, UT TOOELE, UT
Steel - SP 138.00 138.00 23.00 1 31 OQUIRRH, UT TOOELE, UT
Wood - H 138.00 138.00 5.00 1 32 OQUIRRH, UT BARNEY, UT
Wood - H 138.00 138.00 8.00 1 33 OQUIRRH, UT BINGHAM CANYON, UT
Wood - H 138.00 138.00 7.00 1 34 PAINTER, UT RAILROAD, UT
Wood - H 138.00 138.00 21.00 1 35 PAROWAN, UT WEST CEDAR, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.6
36 TOTAL 16,969.00 715.00 282
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
/ /2015/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
795 ACSR 26/7 3
397.5 ACSR 26/7 4
250 CUHD /12 5
397.5 ACSR 26/7 6
397.5 ACSR 26/7 7
1272 AAC /61 8
795 AAC /37 9
1272 AAC /91 10
1272 AAC /61 11
500 AAC /19 12
13
1272 ACSR 45/7 14
795 AAC 26/7 15
795 AAC 26/7 16
1272 ACSR /61 17
18
19
1272 ACSR 45/7 20
397.5 ACSR 26/7 21
397.5 ACSR 26/7 22
795 AAC 26/7 23
795 AAC 26/7 24
795 AAC 26/7 25
397.5 ACSR 26/7 26
336.4 ACSR 26/7 27
250 CUHD /12 28
795 AAC 45/7 29
796 AAC 45/7 30
1272 ACSR 45/7 31
795 AAC 26/7 32
1557.4 ACSR/TW 33
1272 ACSR 45/7 34
397.5 ACSR 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.6
36 229,153,883 3,385,069,822 3,614,223,705 409,509 17,142,995 2,248,767 19,801,271
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
/ /2015/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Steel - SP 138.00 138.00 16.00 1 1 PARRISH, UT TERMINAL #1, UT
138.00 138.00 14.00 1 2 PARRISH, UT TERMINAL #2, UT
Steel - SP 138.00 138.00 14.00 1 3 PARRISH #105, UT TERMINAL, UT
Steel - SP 138.00 138.00 8.00 1 4 PARRISH, UT TAP TO N SALT LAKE, UT
Wood - H 138.00 138.00 17.00 1 5 RAILROAD, UT CANYON COMP, WY
Steel - SP 138.00 138.00 20.00 1 6 CENTRAL (UAMPS) #2, UT SAINT GEORGE, UT
Steel - SP 138.00 138.00 20.00 1 7 CENTRAL (UAMPS) #3, UT SAINT GEORGE, UT
Steel - SP 138.00 138.00 1.00 1 8 RED BUTTE, UT SAINT GEORGE, UT
Wood - H 138.00 138.00 49.00 1 9 RED BUTTE, UT WEST CEDAR, UT
Steel - SP 138.00 138.00 7.00 1 10 RIVERDALE, UT EAST LAYTON, UT
Wood - H 138.00 138.00 10.00 1 11 SHICK, UT PARRISH, UT
Wood - SP 138.00 138.00 10.00 1 12 SILVER CREEK, UT JORDANELLE, UT
Wood - H 138.00 138.00 10.00 1 13 SPANISH FORK, UT TANNER, UT
Wood - SP 138.00 138.00 2.00 1 14 SUNRISE, UT OQUIRRH, UT
Steel - SP 138.00 138.00 1.00 1 15 SYRACUSE, UT CLEARFIELD SOUTH, UT
Steel Tower 138.00 138.00 15.00 1 16 SYRACUSE, UT PARRISH, UT
138.00 138.00 9.00 1 17 SYRACUSE, UT ANGEL #1, UT
Wood - H 138.00 138.00 13.00 1 18 TAP TO ANGEL NORTH, UT TAP TO PARRISH, UT
Wood - SP 138.00 138.00 2.00 6.00 1 19 TAYLORSVILLE , UT 90TH SOUTH, UT
Steel - SP 138.00 138.00 9.00 1 20 TERMINAL, UT KENNECOTT, UT
Wood - H 138.00 138.00 53.00 1 21 TERMINAL, UT ROWLEY, UT
Wood - H 138.00 138.00 7.00 1 22 TERMINAL, UT MIDVALLEY #1, UT
Wood - H 138.00 138.00 7.00 1 23 TERMINAL, UT MIDVALLEY #2, UT
Wood - H 138.00 138.00 6.00 24.00 1 24 TERMINAL, UT TOOELE, UT
Wood - SP 138.00 138.00 7.00 1 25 TERMINAL, UT WEST VALLEY, UT
Wood - H 138.00 138.00 17.00 1 26 THREEMILE KNOLL, ID GRACE #1, ID
Wood - H 138.00 138.00 17.00 1 27 THREEMILE KNOLL, ID GRACE #2, ID
Wood - H 138.00 138.00 2.00 1 28 THREEMILE KNOLL, ID MONSANTO #1, ID
Steel - SP 138.00 138.00 2.00 1 29 THREEMILE KNOLL, ID MONSANTO #2, ID
Steel - SP 138.00 138.00 2.00 1 30 TIMP #1, UT DYNAMO, UT
138.00 138.00 2.00 1 31 TIMP #2, UT DYNAMO, UT
Steel - SP 138.00 138.00 4.00 1 32 TIMP, UT HALE, UT
Wood - H 138.00 138.00 23.00 1 33 TIMP, UT SPANISH FORK, UT
Steel Tower 138.00 138.00 25.00 1 34 TREASURETON, ID GRACE, ID
138.00 138.00 25.00 1 35 TREASURETON, ID GRACE #2, ID
FERC FORM NO. 1 (ED. 12-87) Page 422.7
36 TOTAL 16,969.00 715.00 282
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
/ /2015/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 45/7 1
795 AAC 26/7 2
795 AAC 45/7 3
795 AAC 26/7 4
795 ACSR 26/7 5
1272 ACSR 45/7 6
1272 ACSR 45/7 7
1272 ACSR 45/7 8
397.5 ACSR 26/7 9
795 AAC 26/7 10
250 CUHD /12 11
795 AAC 26/7 12
1272 ACSR 45/7 13
14
1272 ACSR 45/7 15
1272 ACSR 45/7 16
250 CUHD /12 17
795 AAC /37 18
795 AAC /37 19
795 AAC 26/7 20
795 AAC /37 21
1272 ACSR 45/7 22
1272 AAC /61 23
397.5 ACSR 26/7 24
25
250 CUHD /12 26
1272 ACSR 45/7 27
1272 AAC /61 28
1272 ACSR 45/7 29
30
31
32
33
250 CUHD /12 34
250 CUHD /12 35
FERC FORM NO. 1 (ED. 12-87) Page 423.7
36 229,153,883 3,385,069,822 3,614,223,705 409,509 17,142,995 2,248,767 19,801,271
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
/ /2015/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 6.00 1 1 TREASURETON, ID ONEIDA, ID
Wood - SP 138.00 138.00 22.00 1 2 TRI-CITY, UT SUNRISE, ID
Wood - SP 138.00 138.00 12.00 6.00 1 3 TRI-CITY, UT BANGERTER, UT
Wood - H 138.00 138.00 15.00 1 4 TRI-CITY, UT WESTFIELD, UT
Wood - SP 138.00 138.00 20.00 1 5 WEST CEDAR, UT THREE PEAKS, UT
Wood - H 138.00 138.00 9.00 1 6 WEST VALLEY, UT OQUIRRH, UT
Wood - H 138.00 138.00 14.00 1 7 WESTFIELD, UT HALE, UT
Wood - H 138.00 138.00 86.00 1 8 WHEELON, UT AMERICAN FALLS, ID
Steel Tower 138.00 138.00 29.00 1 9 WHEELON #1, UT TREASURETON, ID
138.00 138.00 29.00 1 10 WHEELON #2, UT TREASURETON, ID
Wood - H 138.00 138.00 29.00 1 11 WHEELON #3, UT TREASURETON, ID
Wood - SP 138.00 138.00 3.00 1 12 FORT DOUGLAS, UT MCCLELLAND, UT
Wood - SP 138.00 138.00 25.00 1 13 CAMERON, UT MILFORD, UT
Wood - SP 138.00 138.00 10.00 1 14 EAGLE MOUNTAIN, UT PONY EXPRESS, UT
Wood - SP 138.00 138.00 2.00 1 15 CLOVER, UT BURRASTON PONDS
Wood - SP 138.00 138.00 38.00 1 16 CROYDON, UT RAILROAD, WY
Wood - SP 138.00 138.00 1.00 1 17 GRAPHITE, UT MOUNTAIN VIEW, UT
Wood - SP 138.00 138.00 5.00 1 18 HIGHLAND, UT BULL RIVER (LEHI #5), UT
19 138kV costs and expenses
20
207.00 2,151.00 146 21 Subtotal 138 kV
22
1,662.00 23 All 115 kV Lines
24
2,954.00 25 All 69 kV Lines
26
113.00 27 All 57 kV Lines
28
2,541.00 29 All 46 kV Lines
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 422.8
36 TOTAL 16,969.00 715.00 282
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
/ /2015/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
2
3
1272 ACSR 45/7 4
795 AAC 26/7 5
6
795 AAC 26/7 7
250 CUHD /12 8
250 CUHD /12 9
250 CUHD /12 10
250 CUHD /12 11
12
397.5 ACSR 26/7 13
795 ACSR 26/7 14
397.5 ACSR 26/7 15
1272 ACSR 45/7 16
397.5 ACSR 26/7 17
1272 ACSR 45/7 18
379,543,648 356,517,639 23,026,009 2,810,451 156,582 2,514,220 139,649 19
20
379,543,648 356,517,639 23,026,009 2,810,451 156,582 2,514,220 139,649 21
22
192,386,545 187,284,252 5,102,293 2,818,810 416,438 2,378,644 23,728 23
24
279,777,794 272,505,105 7,272,689 3,855,368 251,656 3,531,003 72,709 25
26
10,930,250 10,883,923 46,327 168,249 3,430 142,597 22,222 27
28
261,984,521 251,925,669 10,058,852 2,710,999 64,948 2,568,538 77,513 29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 423.8
36 229,153,883 3,385,069,822 3,614,223,705 409,509 17,142,995 2,248,767 19,801,271
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 500kV line is jointly owned by PacifiCorp and Bonneville Power
Administration ("BPA"). Ownership of the line is as follows: PacifiCorp 50.0%, 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.: 6 Column: a
The Alvey - Dixonville 500kV line is jointly owned by PacifiCorp and BPA. Ownership of the
line is as follows: PacifiCorp 50.0%, 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
The Midpoint - Malin 500kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line is as follows:
Designation PacifiCorp Idaho Power Company
Hemingway – Summer Lake 78.05% 21.95%
Midpoint – Hemingway 63.00% 37.00%
Plant cost and operation and maintenance costs reported for this line reflect PacifiCorp’s
share.
Schedule Page: 422 Line No.: 8 Column: a
The Colstrip 4 - Switchyard 500kV 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 500kV 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 500kV 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 500kV 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 500kV 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.: 4 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
The Goshen - Kinport 345kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line is as follows: PacifiCorp 81.69%, Idaho Power Company 18.31%. Plant
cost and operation and maintenance costs reported for this line reflect PacifiCorp’s
share.
Schedule Page: 422.1 Line No.: 9 Column: a
The Jim Bridger - Borah 345kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line is as follows:
Designation PacifiCorp Idaho Power Company
Jim Bridger – Populus #1 70.83% 29.17%
Populus – Borah #1 70.83% 29.17%
Plant cost and operation and maintenance costs reported for this line reflect PacifiCorp’s
share.
Schedule Page: 422.1 Line No.: 10 Column: a
The Jim Bridger - Kinport 345kV line is jointly owned by PacifiCorp and Idaho Power
Company. Ownership of the line is as follows:
Designation PacifiCorp Idaho Power Company
Jim Bridger – Populus #2 70.83% 29.17%
Populus – Kinport 70.83% 29.17%
Plant cost and operation and maintenance costs reported for this line reflect PacifiCorp’s
share.
Schedule Page: 422.1 Line No.: 19 Column: a
The Jim Bridger - Goshen 345kV line is jointly owned by PacifiCorp and Idaho Power
Company. Ownership of the line is as follows: PacifiCorp 70.83%, Idaho Power Company
29.17%. Plant cost and operation and maintenance costs reported for this line reflect
PacifiCorp’s share.
Schedule Page: 422.1 Line No.: 20 Column: a
The Borah - Midpoint #1 345kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line designation Borah - Adelaide - Midpoint #1 is as follows: PacifiCorp
35.55%, Idaho Power Company 64.45%. Plant cost and operation and maintenance costs
reported for this line reflect PacifiCorp’s share.
Schedule Page: 422.1 Line No.: 21 Column: a
The Borah - Midpoint #2 345kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line designation Borah - Adelaide - Midpoint #2 is as follows: PacifiCorp
35.55%, Idaho Power Company 64.45%. Plant cost and operation and maintenance costs
reported for this line reflect PacifiCorp’s share.
Schedule Page: 422.1 Line No.: 22 Column: a
The Kinport - Midpoint 345kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line is as follows: PacifiCorp 26.82%, Idaho Power Company 73.18%. Plant
cost and operation and maintenance costs reported for this line reflect PacifiCorp’s
share.
Schedule Page: 422.2 Line No.: 2 Column: a
A 1.5 mile segment of the Casper - Dave Johnston 230kV 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: 422.2 Line No.: 2 Column: i
1557 ACSS/TW 45/7
Schedule Page: 422.2 Line No.: 17 Column: a
Complete name is Gonder (NV Energy), UT - NV State.
Schedule Page: 422.2 Line No.: 20 Column: a
The Hurricane - Walla Walla 230kV line is jointly owned by PacifiCorp and Idaho Power
Company. Ownership of the line is as follows: PacifiCorp 59.17%, Idaho Power 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
40.83%. Plant cost and operation and maintenance costs reported for this line reflect
PacifiCorp’s share.
Schedule Page: 422.3 Line No.: 33 Column: a
The Big Grassy - Jefferson 161kV line is jointly owned by PacifiCorp and Idaho Power
Company. Ownership of the line is as follows: PacifiCorp 62.24%, Idaho Power Company
37.76%. Plant cost and operation and maintenance costs reported for this line reflect
PacifiCorp’s share.
Schedule Page: 422.3 Line No.: 34 Column: a
The Antelope - Goshen 161kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line is as follows: PacifiCorp 78.13%, Idaho Power Company 21.87%. Plant
cost and operation and maintenance costs reported for this line reflect PacifiCorp’s
share.
Schedule Page: 422.4 Line No.: 8 Column: a
The Goshen - Jefferson 161kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line is as follows: PacifiCorp 62.24%, Idaho Power Company 37.76%. Plant
cost and operation and maintenance costs reported for this line reflect PacifiCorp’s
share.
Schedule Page: 422.4 Line No.: 20 Column: a
The Antelope - Scoville #1 138kV line is jointly owned by PacifiCorp and Idaho Power
Company. Ownership of the line is as follows: PacifiCorp 33.33%, Idaho Power Company
66.67%. Plant cost and operation and maintenance costs reported for this line reflect
PacifiCorp’s share.
Schedule Page: 422.4 Line No.: 21 Column: a
The Antelope - Scoville #2 138kV line is jointly owned by PacifiCorp and Idaho Power
Company. Ownership of the line is as follows: PacifiCorp 33.33%, Idaho Power Company
66.67%. Plant cost and operation and maintenance costs reported for this line reflect
PacifiCorp’s share.
Schedule Page: 422.4 Line No.: 25 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 13 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 18 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 19 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 33 Column: b
Complete name is Bingham Canyon (KCC), UT.
Schedule Page: 422.7 Line No.: 6 Column: a
The Central - Saint George 138kV 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.: 7 Column: a
See footnote on page 422.7, line 6, column (a).
Schedule Page: 422.7 Line No.: 14 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 25 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 30 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 31 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 32 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 33 Column: i
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
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.: 3 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 6 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 8 Column: a
The Wheelon - American Falls 138kV line is jointly owned by PacifiCorp and Idaho Power
Company. Ownership of the line designation American Falls - Malad is as follows:
PacifiCorp 96.38%, Idaho Power Company 3.62%. Plant cost and operation and maintenance
costs reported for this line reflect PacifiCorp’s share.
Schedule Page: 422.8 Line No.: 12 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 15 Column: b
Complete name is Burraston Ponds Metering, UT.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
TRANSMISSION LINES ADDED DURING YEAR
PacifiCorp X
/ /2015/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
6.00Wood - H 1 1 1 BORAH, ID MIDPOINT #1, ID 79.00
6.00Wood - H 1 1 2 BORAH, ID MIDPOINT #2, ID 78.00
15.00Wood - SP 3 EAGLE MOUNTAIN, UT PONY EXPRESS, UT 10.00
9.00Wood - H 4 BIG GRASSY, ID JEFFERSON, ID 21.00
6.00Steel Tower 5 JIM BRIDGER, WY GOSHEN, ID 226.00
6.00Steel - SP 1 1 6 KINPORT, ID MIDPOINT, ID 113.00
5.00Steel - H 7 RED BUTTE, UT SIGURD, UT 170.00
15.00Wood - SP 1 1 8 CAMERON, UT MILFORD, UT 25.00
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
722.00 68.00 4 4
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
/ /2015/Q4
Line
No.
(k)(j)(h) (l) (m)
CONDUCTORS
Size Configuration
Voltage
KV
LINE COST
Land and Poles, Towers
and Fixtures Conductors
(n) (p)
Specification and Spacing (Operating)Land Rights and Devices(i)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate
such other characteristic.
Asset
(o)Retire. Costs
Vertical 14'ACSR3-1272 912,291 3,863,065 2,950,774 345 1
Vertical 14'ACSR3-1272 712,888 4,459,385 3,746,497 345 2
Vertical 5'ACSR795 3,326,200 5,939,334 1,809,097 804,037 138 3
CU/ 18250I 32,757 83,186 50,429 161 4
Vertical 14'ACSR2-1272 2,883,299 5,984,584 3,101,285 345 5
Vertical 14'ACSR2-1272 1,640,115 3,977,817 2,337,702 345 6
ACSR2-954 94,435,771 298,341,332191,657,460 12,248,101 345 7
Vertical 10'ACSR397.5 2,887,035 6,503,621 3,410,427 206,159 138 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
106,830,356 209,063,671
FERC FORM NO. 1 (REV. 12-03) Page 425
44 13,258,297 329,152,324
Schedule Page: 424 Line No.: 4 Column: j
Horizontal 14'
Schedule Page: 424 Line No.: 7 Column: j
Horizontal 14'
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/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 / /2015/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 / /2015/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 69.00 115.00T/D-UNATTENDED 7
YREKA SUB 12.47 115.00 69.00T/D-UNATTENDED 8
TOTAL 81.47 230.00 69.00 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 / /2015/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
35 4 7
95 2 8
130 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
4 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 / /2015/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 67.00DISTRIBUTION-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 / /2015/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
6 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
30 1 31
20 1 32
20 1 33
14 1 34
8 1 35
5 1 36
12 1 37
13 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 / /2015/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 4000.00 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 138.00 161.00 12.50TRANSMISSION-UNATTEN 27
JEFFERSON SUB 69.00 161.00TRANSMISSION-UNATTEN 28
MIDPOINT SUB 345.00 500.00TRANSMISSION-UNATTEN 29
OVID SUB 69.00 138.00TRANSMISSION-UNATTEN 30
SCOVILLE SUB 69.00 138.00TRANSMISSION-UNATTEN 31
SUGARMILL SUB 46.00 161.00 69.00TRANSMISSION-UNATTEN 32
THREEMILE KNOLL SUB 138.00 345.00 46.00TRANSMISSION-UNATTEN 33
TREASURETON SUB 138.00 230.00TRANSMISSION-UNATTEN 34
TOTAL 1691.47 3444.00 223.84 35
Number of Substations-17 36
37
MONTANA 38
BROADVIEW SUB 230.00 500.00TRANSMISSION-UNATTEN 39
COLSTRIP SUB 230.00 500.00TRANSMISSION-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 / /2015/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
736 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 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
1500 1 29
30 1 30
76 2 31
168 3 32
775 2 33
533 2 34
5276 32 35
36
37
38
32 2 39
68 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/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).
YELLOWTAIL SUB 161.00 230.00TRANSMISSION-UNATTEN 1
TOTAL 621.00 1230.00 2
Number of Substations-3 3
4
OREGON 5
26TH STREET 4.16 20.80DISTRIBUTION-UNATTEN 6
35TH STREET 2.40 20.80DISTRIBUTION-UNATTEN 7
AGNESS AVE 12.47 115.00DISTRIBUTION-UNATTEN 8
ALDERWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
ARLINGTON 12.47 69.00DISTRIBUTION-UNATTEN 10
ATHENA 12.47 69.00DISTRIBUTION-UNATTEN 11
BANDON TIE SUB 12.47 20.80DISTRIBUTION-UNATTEN 12
BEACON SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
BEALL LANE SUB 12.47 115.00DISTRIBUTION-UNATTEN 14
BEATTY SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
BELKNAP SUB 12.47 115.00DISTRIBUTION-UNATTEN 16
BLALOCK SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
BLOSS SUB 12.47 115.00DISTRIBUTION-UNATTEN 18
BLY SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
BOISE CASCADE SUB 11.00 69.00DISTRIBUTION-UNATTEN 20
BONANZA SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
BOND STREET SUB 12.50 69.00DISTRIBUTION-UNATTEN 22
BROOKHURST SUB 12.47 115.00DISTRIBUTION-UNATTEN 23
BROWNSVILLE SUB 20.80 69.00DISTRIBUTION-UNATTEN 24
BRYANT SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
BUCHANAN SUB 20.80 115.00DISTRIBUTION-UNATTEN 26
BUCKAROO SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
CAMPBELL SUB 12.47 115.00DISTRIBUTION-UNATTEN 28
CANNON BEACH SUB 12.47 115.00DISTRIBUTION-UNATTEN 29
CANYONVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 30
CARNES SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
CASEBEER SUB 20.80 69.00DISTRIBUTION-UNATTEN 32
CAVEMAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 33
CHERRY LANE SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
CHILOQUIN MARKET SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
CHINA HAT SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
CIRCLE BLVD SUB 20.80 115.00DISTRIBUTION-UNATTEN 37
CLEVELAND AVE SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
CLOAKE SUB 20.80 69.00DISTRIBUTION-UNATTEN 39
COBURG SUB 20.80 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
100 1 1
200 5 2
3
4
5
5 1 6
30 6 7
25 1 8
45 2 9
5 1 10
9 1 11
8 3 1 12
11 3 13
25 1 14
6 1 15
40 2 16
2 3 17
32 2 18
8 3 19
3 1 20
8 3 21
25 1 22
50 2 23
13 1 24
34 2 25
45 2 26
34 2 27
20 2 28
13 1 29
25 1 30
9 3 31
20 1 32
45 2 33
25 1 34
6 3 35
25 1 36
80 2 37
45 2 38
20 1 39
10 3 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 / /2015/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).
COLISEUM SUB 4.16 20.80DISTRIBUTION-UNATTEN 1
COLUMBIA SUB 12.47 115.00 57.00DISTRIBUTION-UNATTEN 2
COOS RIVER SUB 20.80 115.00DISTRIBUTION-UNATTEN 3
COQUILLE SUB 20.80 115.00DISTRIBUTION-UNATTEN 4
CREEK SUB 34.50 69.00DISTRIBUTION-UNATTEN 5
CROOKED RIVER RANCH SUB 20.80 69.00DISTRIBUTION-UNATTEN 6
CROWFOOT SUB 12.47 115.00DISTRIBUTION-UNATTEN 7
CULLY SUB 12.47 115.00DISTRIBUTION-UNATTEN 8
CULVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
DAIRY SUB 12.47 69.00DISTRIBUTION-UNATTEN 10
DALLAS SUB 20.80 115.00DISTRIBUTION-UNATTEN 11
DALREED SUB 34.40 230.00DISTRIBUTION-UNATTEN 12
DESCHUTES SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
DEVILS LAKE SUB 20.80 115.00DISTRIBUTION-UNATTEN 14
DIXON SUB 4.16 115.00DISTRIBUTION-UNATTEN 15
DODGE BRIDGE SUB 20.80 69.00DISTRIBUTION-UNATTEN 16
DOWELL SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
EASY VALLEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 18
EMPIRE SUB 20.80 115.00DISTRIBUTION-UNATTEN 19
ENTERPRISE SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
FERN HILL SUB 12.47 115.00DISTRIBUTION-UNATTEN 21
FIELDER CREEK SUB 20.80 115.00DISTRIBUTION-UNATTEN 22
FOOTHILLS SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
FRALEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
GARDEN VALLEY SUB 20.80 69.00DISTRIBUTION-UNATTEN 25
GAZLEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 26
GLENDALE SUB 12.47 230.00DISTRIBUTION-UNATTEN 27
GLENEDEN SUB 4.16 20.80DISTRIBUTION-UNATTEN 28
GLIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 29
GOLD HILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
GORDON HOLLOW SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
GOSHEN SUB 20.80 115.00DISTRIBUTION-UNATTEN 32
GRANT STREET SUB 20.80 115.00DISTRIBUTION-UNATTEN 33
GRASS VALLEY SUB 4.16 20.80DISTRIBUTION-UNATTEN 34
GREEN SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
GRIFFIN CREEK SUB 12.47 115.00DISTRIBUTION-UNATTEN 36
HAMAKER SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
HARRISBURG SUB 20.80 69.00DISTRIBUTION-UNATTEN 38
HENLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
HERMISTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
9 2 1
55 2 1 2
20 1 3
40 2 4
5 1 5
25 2 6
20 1 7
25 1 8
13 1 9
25 1 10
50 2 11
95 4 12
25 1 13
50 2 14
7 1 15
13 1 16
20 1 17
45 2 18
20 1 19
19 2 20
12 1 21
25 1 22
21 4 23
5 3 24
20 1 25
8 4 26
25 2 27
6 1 28
12 1 29
11 3 30
6 1 31
20 1 32
45 2 33
1 4 34
25 1 35
20 1 36
8 3 37
13 1 38
6 3 39
40 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/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).
HILLVIEW SUB 20.80 115.00DISTRIBUTION-UNATTEN 1
HINKLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
HOLLADAY SUB 12.47 115.00DISTRIBUTION-UNATTEN 3
HOLLYWOOD SUB 12.47 115.00DISTRIBUTION-UNATTEN 4
HOOD RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
HORNET SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
HUMBUG CREEK SUB 12.50 67.00DISTRIBUTION-UNATTEN 7
HUNTERS CIRCLE TEMP SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
ILLAHEE FLATS SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
INDEPENDENCE SUB 20.80 69.00DISTRIBUTION-UNATTEN 10
JACKSONVILLE SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 11
JEFFERSON SUB 20.80 69.00DISTRIBUTION-UNATTEN 12
JEROME PRAIRIE SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
JORDAN POINT SUB 12.47 115.00DISTRIBUTION-UNATTEN 14
JOSEPH SUB 12.47 20.80DISTRIBUTION-UNATTEN 15
JUNCTION CITY SUB 20.80 69.00DISTRIBUTION-UNATTEN 16
KENWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
KILLINGWORTH SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
KNAPPA SVENSEN SUB 12.47 115.00DISTRIBUTION-UNATTEN 19
LAKEPORT SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
LANCASTER SUB 20.80 69.00DISTRIBUTION-UNATTEN 21
LEBANON SUB 20.80 115.00DISTRIBUTION-UNATTEN 22
LINCOLN SUB 12.47 115.00DISTRIBUTION-UNATTEN 23
LOCKHART SUB 20.80 115.00DISTRIBUTION-UNATTEN 24
LYONS SUB 20.80 69.00DISTRIBUTION-UNATTEN 25
MADRAS SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
MALLORY SUB 12.47 115.00DISTRIBUTION-UNATTEN 27
MARYS RIVER SUB 20.80 115.00DISTRIBUTION-UNATTEN 28
MEDCO SUB 12.47 115.00DISTRIBUTION-UNATTEN 29
MEDFORD 12.47 115.00DISTRIBUTION-UNATTEN 30
MERLIN SUB 12.47 115.00DISTRIBUTION-UNATTEN 31
MERRILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
MINAM SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
MODOC SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
MORO SUB 2.40 20.80DISTRIBUTION-UNATTEN 35
MURDER CREEK SUB 20.80 115.00DISTRIBUTION-UNATTEN 36
MYRTLE CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
MYRTLE POINT SUB 20.80 115.00DISTRIBUTION-UNATTEN 38
NELSCOTT SUB 4.16 20.80DISTRIBUTION-UNATTEN 39
NEW O'BRIEN 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 / /2015/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
45 2 1
20 1 2
75 3 3
50 2 4
40 2 5
20 1 6
9 1 7
12 1 8
2 1 9
20 1 10
75 2 11
12 1 12
20 1 13
20 1 14
6 1 1 15
22 2 16
3 3 17
40 2 18
6 1 19
50 2 20
12 3 21
40 2 22
105 3 23
40 2 24
25 2 25
25 2 26
25 1 27
20 1 28
20 1 29
67 8 30
45 2 31
17 6 32
1 33
6 3 34
2 3 35
100 4 36
14 1 37
9 1 38
4 1 39
9 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.6
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/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).
OAK KNOLL SUB 12.47 115.00DISTRIBUTION-UNATTEN 1
OAKLAND SUB 12.47 115.00DISTRIBUTION-UNATTEN 2
OREMET SUB 12.47 115.00DISTRIBUTION-UNATTEN 3
OVERPASS SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
PALLETTE SUB 20.80 69.00DISTRIBUTION-UNATTEN 5
PARK STREET SUB 12.47 115.00DISTRIBUTION-UNATTEN 6
PARKROSE SUB 12.47 57.00DISTRIBUTION-UNATTEN 7
PENDLETON SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
PILOT ROCK SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
POWELL BUTTE SUB 12.47 115.00DISTRIBUTION-UNATTEN 10
PRINEVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 11
PROVOLT SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
QUEEN AVE SUB 20.80 69.00DISTRIBUTION-UNATTEN 13
RED BLANKET SUB 4.16 69.00DISTRIBUTION-UNATTEN 14
REDMOND SUB 12.47 115.00DISTRIBUTION-UNATTEN 15
RIDDLE VENEER SUB 12.47 115.00DISTRIBUTION-UNATTEN 16
ROGUE RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
ROSEBURG SUB 20.80 115.00DISTRIBUTION-UNATTEN 18
ROSS AVE SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
ROXY ANN SUB 12.47 115.00DISTRIBUTION-UNATTEN 20
RUCH SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
RUNNING Y SUB 20.80 69.00DISTRIBUTION-UNATTEN 22
RUSSELLVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 23
SCENIC SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 24
SCIO SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
SEASIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 26
SELMA SUB 12.47 115.00DISTRIBUTION-UNATTEN 27
SHASTA WAY SUB 4.16 12.47DISTRIBUTION-UNATTEN 28
SHEVLIN PARK SUB 12.50 69.00DISTRIBUTION-UNATTEN 29
SIMTAG BOOSTER PUMP 4.16 34.50DISTRIBUTION-UNATTEN 30
SOUTH DUNES SUB 12.47 115.00DISTRIBUTION-UNATTEN 31
SOUTHGATE SUB 20.80 69.00DISTRIBUTION-UNATTEN 32
SPRAGUE RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
STATE STREET SUB 20.80 115.00DISTRIBUTION-UNATTEN 34
STAYTON SUB 20.80 69.00DISTRIBUTION-UNATTEN 35
STEAMBOAT SUB 7.20 115.00DISTRIBUTION-UNATTEN 36
STEVENS ROAD SUB 20.80 115.00DISTRIBUTION-UNATTEN 37
SUTHERLIN SUB 12.00 115.00DISTRIBUTION-UNATTEN 38
SWEET HOME SUB 20.80 115.00DISTRIBUTION-UNATTEN 39
TAKELMA SUB 20.80 115.00DISTRIBUTION-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 / /2015/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
45 2 1
8 1 2
75 2 3
45 2 4
1 1 1 5
40 2 6
39 2 7
46 7 1 8
22 2 9
12 1 10
50 2 11
11 3 12
50 2 13
2 3 14
50 2 15
25 1 16
25 2 17
50 2 18
9 3 19
25 1 20
9 1 21
9 1 22
45 2 23
70 3 24
8 1 25
40 2 26
9 1 27
2 3 28
25 1 29
19 2 30
9 1 31
20 1 32
7 3 33
40 2 34
55 2 35
1 36
50 2 37
25 1 38
42 2 39
12 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/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).
TALENT SUB 12.47 115.00DISTRIBUTION-UNATTEN 1
TEXUM SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
TILLER SUB 12.47 115.00DISTRIBUTION-UNATTEN 3
TOLO SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
TURKEY HILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
UMAPINE SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
UMATILLA SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
VERNON SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
VILAS SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
VILLAGE GREEN SUB 20.80 115.00DISTRIBUTION-UNATTEN 10
VINE STREET SUB 20.80 69.00DISTRIBUTION-UNATTEN 11
WALLOWA SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
WARM SPRINGS SUB 20.80 69.00DISTRIBUTION-UNATTEN 13
WARRENTON SUB 12.47 115.00DISTRIBUTION-UNATTEN 14
WASCO SUB 4.16 20.80DISTRIBUTION-UNATTEN 15
WECOMA BEACH SUB 4.16 20.80DISTRIBUTION-UNATTEN 16
WESTERN KRAFT SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
WESTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
WESTSIDE HYDRO/SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
WEYERHAUSER SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
WHITE CITY SUB 12.47 115.00DISTRIBUTION-UNATTEN 21
WILLOW COVE SUB 4.16 34.50DISTRIBUTION-UNATTEN 22
WINSTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
YEW AVENUE SUB 12.47 115.00DISTRIBUTION-UNATTEN 24
YOUNGS BAY SUB 12.47 115.00DISTRIBUTION-UNATTEN 25
TOTAL 2511.44 15660.27 195.00 26
Number of Substations-180 27
28
ALBINA SUB 12.47 115.00 69.00T/D-UNATTENDED 29
APPLEGATE SUB 69.00 115.00 12.47T/D-UNATTENDED 30
ASHLAND SUB 69.00 115.00 12.47T/D-UNATTENDED 31
BEND PLANT SUB 13.09 69.00 12.47T/D-UNATTENDED 32
CAVE JUNCTION SUB 12.47 115.00 69.00T/D-UNATTENDED 33
HAZELWOOD SUB 69.00 115.00 12.47T/D-UNATTENDED 34
KNOTT SUB 12.47 115.00 57.00T/D-UNATTENDED 35
MILE HI SUB 69.00 115.00 12.47T/D-UNATTENDED 36
PILOT BUTTE SUB 69.00 230.00 12.47T/D-UNATTENDED 37
RIDDLE SUB 69.00 115.00T/D-UNATTENDED 38
SAGE ROAD SUB 12.47 115.00T/D-UNATTENDED 39
WINCHESTER SUB 12.47 115.00 69.00T/D-UNATTENDED 40
FERC FORM NO. 1 (ED. 12-96) Page 426.8
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
50 2 1
25 1 2
1 1 3
11 1 4
13 3 5
20 1 6
25 2 7
50 2 8
25 1 9
40 2 10
20 1 11
7 1 12
12 3 13
25 2 14
2 3 15
3 1 16
50 2 17
22 2 18
22 9 19
40 2 20
60 3 21
28 3 22
22 3 23
25 1 24
37 2 25
4609 346 5 26
27
28
177 9 29
65 2 30
70 2 31
31 3 32
70 2 33
106 3 34
162 5 35
39 4 36
400 4 37
75 2 38
40 2 39
75 5 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 / /2015/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 489.44 1449.00 338.82 1
Number of Substations-12 2
3
LEMOLO #1 HYDRO 12.50 11.50TRANSMISSION-ATTENDE 4
CALAPOOYA SUB 69.00 230.00TRANSMISSION-UNATTEN 5
CHILOQUIN SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 6
COLD SPRINGS SUB 69.00 230.00 2.40TRANSMISSION-UNATTEN 7
COVE SUB 69.00 230.00TRANSMISSION-UNATTEN 8
DIAMOND HILL SUB 69.00 230.00TRANSMISSION-UNATTEN 9
DIXONVILLE 115/230 SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 10
DIXONVILLE 500 SUB 230.00 500.00TRANSMISSION-UNATTEN 11
FISH HOLE SUB 69.00 115.00TRANSMISSION-UNATTEN 12
FRY SUB 115.00 230.00TRANSMISSION-UNATTEN 13
GRANTS PASS SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 14
GREEN SPRINGS PLANT/SUB 69.00 115.00TRANSMISSION-UNATTEN 15
HURRICANE SUB 69.00 230.00 2.40TRANSMISSION-UNATTEN 16
ISTHMUS SUB 115.00 230.00TRANSMISSION-UNATTEN 17
KENNEDY SUB 57.00 69.00TRANSMISSION-UNATTEN 18
KLAMATH FALLS SUB 69.00 230.00TRANSMISSION-UNATTEN 19
LONE PINE SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 20
MALIN SUB 230.00 500.00 69.00TRANSMISSION-UNATTEN 21
MERIDIAN SUB 230.00 500.00TRANSMISSION-UNATTEN 22
MONPAC SUB 69.00 115.00TRANSMISSION-UNATTEN 23
NICKEL MOUNTAIN SUB 115.00 230.00TRANSMISSION-UNATTEN 24
PARRISH GAP SUB 69.00 230.00 12.47TRANSMISSION-UNATTEN 25
PONDEROSA SUB 115.00 230.00TRANSMISSION-UNATTEN 26
PROSPECT CENTRAL SUB 69.00 115.00TRANSMISSION-UNATTEN 27
ROBERTS CREEK SUB 69.00 115.00TRANSMISSION-UNATTEN 28
TROUTDALE SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 29
TUCKER SUB 69.00 115.00TRANSMISSION-UNATTEN 30
WHETSTONE SUB 115.00 230.00 12.47TRANSMISSION-UNATTEN 31
TOTAL 2806.50 6180.50 443.74 32
Number of Substations-28 33
34
UTAH 35
106TH SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 36
118TH SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 37
23RD ST SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
70TH SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 39
ALTAVIEW SUB 12.47 46.00DISTRIBUTION-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 / /2015/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.
1310 43 1
2
3
2 3 1 4
75 1 5
119 4 6
66 2 7
67 3 8
75 1 9
343 6 10
650 3 1 11
7 3 12
500 2 13
473 5 14
19 3 15
29 2 16
250 1 17
33 1 18
251 6 1 19
733 10 20
775 4 1 21
1300 6 1 22
50 1 23
114 1 24
150 1 25
500 2 26
30 3 27
50 1 28
500 3 29
100 2 30
250 1 31
7511 81 5 32
33
34
35
30 1 36
30 1 37
12 1 38
30 1 39
45 2 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 / /2015/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).
AMALGA SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
AMERICAN FORK SUB 12.47 138.00DISTRIBUTION-UNATTEN 2
ARAGONITE 7.20 46.00DISTRIBUTION-UNATTEN 3
AURORA SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
BANGERTER SUB 12.47 138.00DISTRIBUTION-UNATTEN 5
BEAR RIVER SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
BENJAMIN SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
BINGHAM SUB 7.62 46.00DISTRIBUTION-UNATTEN 8
BLUE CREEK 12.47 46.00DISTRIBUTION-UNATTEN 9
BLUFF SUB 12.47 69.00DISTRIBUTION-UNATTEN 10
BLUFFDALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
BOTHWELL SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
BRIAN HEAD SUB 12.47 34.50DISTRIBUTION-UNATTEN 13
BRICKYARD SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
BRIGHTON SUB 24.90 46.00DISTRIBUTION-UNATTEN 15
BROOKLAWN SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
BRUNSWICK SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
BURTON SUB 12.47 34.50DISTRIBUTION-UNATTEN 18
BUSH SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
CANNON SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
CANYONLANDS SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
CAPITOL SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
CARBIDE SUB 7.20 69.00DISTRIBUTION-UNATTEN 23
CARBONVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
CARLISLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 25
CASTO SUBSTATION 12.47 46.00DISTRIBUTION-UNATTEN 26
CENTERVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
CENTRAL SUB 12.47 43.80DISTRIBUTION-UNATTEN 28
CHAPEL HILL SUB 12.47 138.00DISTRIBUTION-UNATTEN 29
CHERRYWOOD SUB 12.47 138.00DISTRIBUTION-UNATTEN 30
CIRCLEVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
CLEAR CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
CLEAR LAKE SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
CLEARFIELD SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 34
CLINTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 35
CLIVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
COALVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
COLD WATER CANYON SUB 12.47 138.00DISTRIBUTION-UNATTEN 38
COLEMAN SUB 69.00 138.00 12.47DISTRIBUTION-UNATTEN 39
COLTON WELL SUB 2.40 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.10
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/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.
11 1 1
30 1 2
1 1 3
3 1 4
50 2 5
17 2 6
2 1 7
25 1 8
2 3 9
1 3 10
9 1 11
4 1 12
14 1 13
9 1 14
29 2 15
6 1 16
60 3 17
11 3 18
9 1 19
12 1 20
1 1 21
20 1 22
3 1 23
6 1 24
30 1 25
25 1 26
22 1 27
9 1 28
30 1 29
50 2 30
3 1 31
4 1 32
3 33
60 2 34
50 2 35
4 1 36
6 1 37
30 1 38
106 4 39
1 3 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 / /2015/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).
COMMERCE SUB 12.47 138.00DISTRIBUTION-UNATTEN 1
COPPER HILLS SUB 12.47 138.00DISTRIBUTION-UNATTEN 2
CORINNE SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
COVE FORT SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
COZYDALE SUB 12.47 138.00DISTRIBUTION-UNATTEN 5
CROSS HOLLOW SUB 12.47 138.00DISTRIBUTION-UNATTEN 6
CUDAHY SUB 12.47 138.00DISTRIBUTION-UNATTEN 7
DAMMERON VALLEY SUB 12.47 34.50DISTRIBUTION-UNATTEN 8
DECKER LAKE SUB 12.47 138.00DISTRIBUTION-UNATTEN 9
DELLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
DELTA SUB 69.00 46.00DISTRIBUTION-UNATTEN 11
DEWEYVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
DIMPLE DELL SUB 12.47 138.00DISTRIBUTION-UNATTEN 13
DRAPER SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
EAST BENCH SUB 12.47 138.00DISTRIBUTION-UNATTEN 15
EAST HYRUM SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
EAST LAYTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 17
EAST MILLCREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
EDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
ELBERTA SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
ELK MEADOWS SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
ELSINORE SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
EMERY CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
EMIGRATION SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
ENOCH SUB 12.47 138.00DISTRIBUTION-UNATTEN 25
ENTERPRISE VALLEY SUB 12.47 138.00DISTRIBUTION-UNATTEN 26
EUREKA SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
FARMINGTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 28
FAYETTE SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
FERRON SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
FIELDING SUB 12.00 46.00DISTRIBUTION-UNATTEN 31
FIFTH WEST SUB 12.47 138.00DISTRIBUTION-UNATTEN 32
FLUX SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
FOOL CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
FORT DOUGLAS 13.20 138.00DISTRIBUTION-UNATTEN 35
FOUNTAIN GREEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
FREEDOM SUB 7.20 46.00DISTRIBUTION-UNATTEN 37
FRUIT HEIGHTS SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
GARDEN CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
GATEWAY SUB 12.47 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.11
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
30 1 1
30 1 2
3 1 3
2 3 4
30 1 5
22 1 6
30 1 7
42 1 8
55 2 9
6 1 10
48 3 11
4 1 12
60 2 13
23 2 14
30 1 15
6 1 16
60 2 17
20 1 18
19 2 19
5 1 20
3 1 21
2 1 22
3 3 23
25 1 24
14 1 25
10 1 26
3 1 27
30 1 28
1 2 29
5 1 30
6 1 31
50 2 32
4 1 33
2 1 34
40 1 35
7 1 36
1 37
22 1 38
12 1 39
14 1 2 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 / /2015/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
GOLD RUSH SUB 12.47 138.00DISTRIBUTION-UNATTEN 1
GORDON AVENUE SUB 12.47 138.00DISTRIBUTION-UNATTEN 2
GOSHEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
GRANGER SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
GRANTSVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
GUNNISON SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
HAMMER SUB 12.47 138.00DISTRIBUTION-UNATTEN 7
HAVASU SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
HELPER CITY SUB 4.16 46.00DISTRIBUTION-UNATTEN 9
HENEFER SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
HERRIMAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 11
HIGHLAND DIST SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
HOGGARD SUB 12.47 138.00DISTRIBUTION-UNATTEN 13
HOLDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
HOLLADAY SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
HUNTER SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
HUNTINGTON CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
IRON MOUNTAIN SUB 7.20 34.50DISTRIBUTION-UNATTEN 18
IRONTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
IVINS SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
JORDAN NARROWS SUB 2.40 46.00DISTRIBUTION-UNATTEN 21
JORDAN PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 22
JORDANELLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 23
JUAB SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
JUNCTION SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
KAIBAB SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
KAMAS SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
KEARNS SUB 12.47 138.00DISTRIBUTION-UNATTEN 28
KENSINGTON SUB 4.16 46.00DISTRIBUTION-UNATTEN 29
KYUNE SUB 7.20 46.00DISTRIBUTION-UNATTEN 30
LAKE PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 31
LAYTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
LEGRANDE SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
LEWISTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
LINCOLN SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
LINDON SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
LISBON SUB 12.47 70.60DISTRIBUTION-UNATTEN 37
LOAFER SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
LOGAN CANYON SUB 7.20 46.00DISTRIBUTION-UNATTEN 39
LONE TREE SUB 12.47 34.50DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.12
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
30 1 1
30 1 2
2 1 3
50 2 4
23 1 5
11 2 6
60 2 7
3 1 8
3 3 9
4 1 10
30 1 11
25 1 12
50 2 13
4 1 14
32 2 15
22 1 16
12 2 17
1 1 18
2 1 19
22 1 20
13 2 21
30 1 22
30 1 23
4 1 24
3 1 25
5 1 26
7 1 27
60 2 28
7 1 29
1 30
53 2 31
40 2 32
2 1 33
14 1 34
20 1 35
20 1 36
3 1 37
1 38
1 1 39
20 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.12
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
LOWER BEAVER SUB 6.60 46.00DISTRIBUTION-UNATTEN 1
LYNNDYL SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
MAESER SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
MAGNA SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
MANILA SUB 12.47 138.00DISTRIBUTION-UNATTEN 5
MANTUA SUB 12.47 44.00DISTRIBUTION-UNATTEN 6
MAPLETON SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
MARRIOTT SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
MARYSVALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
MATHIS SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
MCCORNICK SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
MCKAY SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
MEADOWBROOK SUB 12.47 138.00 46.00DISTRIBUTION-UNATTEN 13
MEDICAL SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
MIDLAND SUB 12.47 138.00DISTRIBUTION-UNATTEN 15
MIDVALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
MILFORD SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
MILFORD TV SUB 13.20 46.00DISTRIBUTION-UNATTEN 18
MINERSVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
MOAB CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
MONTEZUMA SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
MOORE SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
MORGAN SUB 4.16 46.00DISTRIBUTION-UNATTEN 23
MORONI SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
MOSS JUNCTION SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
MOUNTAIN DELL SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
MOUNTAIN GREEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
MYTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
NEW HARMONY SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
NEWGATE SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
NEWTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
NIBLEY SUB 24.90 138.00DISTRIBUTION-UNATTEN 32
NORTH BENCH SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
NORTH FIELDS SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
NORTH LOGAN SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
NORTH OGDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
NORTH SALT LAKE SUB 13.20 46.00DISTRIBUTION-UNATTEN 37
NORTHEAST SUB 12.50 46.00DISTRIBUTION-UNATTEN 38
NORTHRIDGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
OAKLAND AVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.13
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
1 1 1
4 1 2
12 1 3
30 1 4
22 1 5
2 1 6
14 1 7
20 1 8
3 1 9
9 1 10
6 1 11
20 1 12
42 2 13
57 4 14
30 1 15
25 1 16
14 1 17
1 18
2 1 19
19 2 20
12 1 21
3 1 22
7 2 23
6 1 24
6 3 25
5 1 26
6 1 27
6 1 28
7 1 29
20 1 30
5 1 31
14 1 32
25 1 33
2 1 34
25 1 35
22 1 36
25 1 37
45 2 38
14 1 39
24 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.13
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
OAKLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
OLYMPUS SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
OPHIR SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
ORANGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
ORANGEVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
OREM SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
PACK CREEK RESERVOIR 12.47 46.00DISTRIBUTION-UNATTEN 7
PANGUITCH SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
PARIETTE SUB 24.94 69.00DISTRIBUTION-UNATTEN 9
PARK CITY SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
PARKSIDE SUB 12.47 138.00DISTRIBUTION-UNATTEN 11
PARKWAY SUB 12.47 138.00DISTRIBUTION-UNATTEN 12
PARLEYS SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
PELICAN POINT SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
PINE CANYON SUB 12.47 138.00DISTRIBUTION-UNATTEN 15
PINE CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
PINNACLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
PLAIN CITY SUB 12.47 138.00DISTRIBUTION-UNATTEN 18
PLEASANT GROVE SUB 12.47 138.00DISTRIBUTION-UNATTEN 19
PLEASANT VIEW SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
PONY EXPRESS SUB 12.47 138.00DISTRIBUTION-UNATTEN 21
PORTER ROCKWELL SUB 12.47 138.00DISTRIBUTION-UNATTEN 22
PROMONTORY SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
QUAIL CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
QUARRY SUB 12.47 138.00DISTRIBUTION-UNATTEN 25
QUICHAPA SUB 12.47 34.50DISTRIBUTION-UNATTEN 26
RAINS SUB 7.20 46.00DISTRIBUTION-UNATTEN 27
RANDOLPH SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
RASMUSON SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
RATTLESNAKE SUB 24.90 69.00DISTRIBUTION-UNATTEN 30
RED MOUNTAIN SUB 34.50 69.00DISTRIBUTION-UNATTEN 31
RED ROCK SUB 4.16 69.00DISTRIBUTION-UNATTEN 32
REDWOOD SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
RESEARCH PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
RICH SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
RICHFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
RICHMOND SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
RIDGELAND SUB 12.47 138.00DISTRIBUTION-UNATTEN 38
RITER SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
ROCK CANYON SUB 12.47 69.00DISTRIBUTION-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 / /2015/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
6 1 1
22 1 2
3 1 3
20 1 4
14 1 5
48 2 6
4 1 7
5 1 8
14 1 9
42 2 10
60 2 11
50 2 12
16 2 13
6 1 14
55 2 15
2 1 16
14 1 17
22 1 18
25 1 19
14 1 20
60 2 21
30 1 22
2 1 23
4 1 24
60 2 25
4 1 26
15 1 27
2 1 28
1 3 29
14 1 30
12 1 31
3 1 32
45 2 33
45 2 34
5 1 35
22 2 36
11 1 37
40 2 38
20 1 39
5 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.14
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/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).
ROCKVILLE SUB 12.47 34.50DISTRIBUTION-UNATTEN 1
ROCKY POINT 13.20 138.00DISTRIBUTION-UNATTEN 2
ROSE PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
ROYAL SUB 4.16 46.00DISTRIBUTION-UNATTEN 4
SALINA SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
SANDY SUB 12.47 138.00DISTRIBUTION-UNATTEN 6
SARATOGA SUB 12.47 138.00DISTRIBUTION-UNATTEN 7
SCIPIO SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
SCOFIELD RESERVOIR SUB 7.20 46.00DISTRIBUTION-UNATTEN 9
SCOFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
SECOND STREET SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
SEGO CANYON SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
SEVEN MILE SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
SHARON SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
SHIVWITS SUB 4.16 34.50DISTRIBUTION-UNATTEN 15
SHORELINE SUB 13.20 138.00DISTRIBUTION-UNATTEN 16
SIXTH SOUTH SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
SKULL VALLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
SKYPARK SUB 12.47 138.00 12.47DISTRIBUTION-UNATTEN 19
SNARR SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
SNOWVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
SNYDERVILLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 22
SOLDIER SUMMIT SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
SOUTH JORDAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 24
SOUTH MILFORD SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
SOUTH MOUNTAIN SUB 12.47 138.00DISTRIBUTION-UNATTEN 26
SOUTH OGDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
SOUTH PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 28
SOUTH WEBER SUB 12.47 138.00DISTRIBUTION-UNATTEN 29
SOUTHWEST SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
SPANISH VALLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
SPRINGDALE SUB 12.47 34.50DISTRIBUTION-UNATTEN 32
ST. JOHNS SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
STANSBURY SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
SUMMIT CREEK SUB 12.47 138.00DISTRIBUTION-UNATTEN 35
SUMMIT PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
SUNRISE SUB 12.47 138.00DISTRIBUTION-UNATTEN 37
SUPERIOR SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
SUTHERLAND SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
TAMARISK SUB 12.47 138.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.15
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/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
30 1 2
24 3 3
3 4
11 1 5
60 2 6
60 2 7
1 3 8
1 1 9
1 3 10
13 2 11
14 1 12
1 13
20 1 14
6 1 15
60 2 16
20 1 17
2 1 18
40 1 19
40 2 20
5 1 21
60 2 22
12 1 23
60 2 24
20 2 25
60 2 26
25 1 27
30 1 28
22 1 29
22 2 30
6 1 31
4 1 32
4 1 33
20 1 34
14 1 35
7 1 36
60 2 37
8 1 38
6 1 39
20 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.15
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/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).
TAYLOR SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
THIEF CREEK SUB 24.90 138.00DISTRIBUTION-UNATTEN 2
THIRD WEST SUB 13.20 138.00DISTRIBUTION-UNATTEN 3
THIRTEENTH SOUTH SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
TOOELE DEPOT SUB 12.50 46.00DISTRIBUTION-UNATTEN 5
TOQUERVILLE SUB 12.47 69.00 34.50DISTRIBUTION-UNATTEN 6
UINTAH SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
UNION SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
VALLEY CENTER SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
VERMILLION SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
VERNAL SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
VICKERS SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
VINEYARD SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
WALLSBURG SUB 12.47 138.00DISTRIBUTION-UNATTEN 14
WALNUT GROVE SUB 12.47 138.00DISTRIBUTION-UNATTEN 15
WARREN SUB 12.47 138.00DISTRIBUTION-UNATTEN 16
WASATCH STATE PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
WASHAKIE SUB 4.16 138.00DISTRIBUTION-UNATTEN 18
WELBY SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
WELFARE SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
WEST COMMERCIAL SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
WEST JORDAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 22
WEST OGDEN SUB 12.47 138.00DISTRIBUTION-UNATTEN 23
WEST ROY SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
WEST TEMPLE SUB 4.16 46.00DISTRIBUTION-UNATTEN 25
WESTWATER SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
WHITE MESA SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
WHITE ROCK SUB 12.47 138.00DISTRIBUTION-UNATTEN 28
WILLOWCREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
WILLOWRIDGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
WINCHESTER HILLS SUB 12.47 34.50DISTRIBUTION-UNATTEN 31
WINKLEMAN SUB 7.20 46.00DISTRIBUTION-UNATTEN 32
WOLF CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
WOOD CROSS SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
WOODRUFF SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
TOTAL 3548.08 20214.40 105.44 36
Number of Substations-280 37
38
90TH SOUTH SUB 138.00 345.00 12.47T/D-UNATTENDED 39
ANGEL SUB 12.47 138.00 46.00T/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 / /2015/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.
14 1 1
14 1 2
100 2 3
22 1 4
25 1 5
34 2 6
39 2 7
50 2 8
22 1 9
3 1 10
33 2 11
2 1 12
25 1 13
13 1 14
30 1 15
30 1 16
2 3 17
14 1 18
42 2 19
10 1 20
22 1 21
28 1 22
60 2 23
25 1 24
60 3 25
5 1 26
14 1 27
30 1 28
1 1 29
14 1 30
4 1 31
1 32
6 1 33
20 1 34
2 1 35
5578 381 2 36
37
38
1572 5 39
135 3 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 / /2015/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).
BDO SUBSTATION 12.47 138.00T/D-UNATTENDED 1
BUTLERVILLE SUB 46.00 138.00 12.47T/D-UNATTENDED 2
CENTENNIAL SUB 12.47 138.00T/D-UNATTENDED 3
COTTONWOOD SUB 12.47 138.00 46.00T/D-UNATTENDED 4
DECADE SUB 12.47 138.00T/D-UNATTENDED 5
DUMAS SUB 12.47 138.00T/D-UNATTENDED 6
EMMA PARK SUBSTATION 12.47 138.00T/D-UNATTENDED 7
GROW SUB 12.47 138.00 46.00T/D-UNATTENDED 8
HALE SUB 46.00 138.00 12.47T/D-UNATTENDED 9
HIGHLAND SUB 12.47 138.00 46.00T/D-UNATTENDED 10
JORDAN SUB 46.00 138.00 12.47T/D-UNATTENDED 11
JUDGE SUB 12.47 46.00T/D-UNATTENDED 12
MCCLELLAND SUB 46.00 138.00 12.47T/D-UNATTENDED 13
MORTON COURT SUB 12.47 138.00T/D-UNATTENDED 14
OQUIRRH SUB 46.00 345.00 138.00T/D-UNATTENDED 15
PARRISH SUB 12.47 138.00 46.00T/D-UNATTENDED 16
PIONEER PLANT 12.47 138.00T/D-UNATTENDED 17
RIVERDALE SUB 46.00 138.00 12.47T/D-UNATTENDED 18
SEVIER SUB 46.00 138.00 12.47T/D-UNATTENDED 19
SILVER CREEK SUB 12.47 138.00 46.00T/D-UNATTENDED 20
SOUTHEAST SUB 12.47 138.00 46.00T/D-UNATTENDED 21
SYRACUSE SUB 46.00 345.00 138.00T/D-UNATTENDED 22
TAYLORSVILLE SUB 46.00 138.00 12.47T/D-UNATTENDED 23
TERMINAL SUB 46.00 345.00 138.00T/D-UNATTENDED 24
TIMP SUB 46.00 138.00 12.47T/D-UNATTENDED 25
TOOELE SUB 46.00 138.00 12.47T/D-UNATTENDED 26
TRI CITY SUB 12.47 138.00T/D-UNATTENDED 27
WEST VALLEY SUB 12.47 138.00T/D-UNATTENDED 28
WESTFIELD SUB 12.47 138.00T/D-UNATTENDED 29
TOTAL 914.46 5014.00 860.70 30
Number of Substations-31 31
32
EMERY SUB 138.00 345.00 69.00TRANSMISSION-ATTENDE 33
GADSBY SUB 46.00 138.00TRANSMISSION-ATTENDE 34
ABAJO SUB 69.00 138.00TRANSMISSION-UNATTEN 35
ASHLEY SUB 46.00 138.00TRANSMISSION-UNATTEN 36
BARNEY SUB 46.00 138.00TRANSMISSION-UNATTEN 37
BEN LOMOND SUB 230.00 345.00 138.00TRANSMISSION-UNATTEN 38
BLACK ROCK SUB 69.00 230.00TRANSMISSION-UNATTEN 39
BLACKHAWK SUB 69.00 138.00 46.00TRANSMISSION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.17
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
30 1 1
205 4 2
40 2 3
289 7 4
60 2 5
60 2 6
8 1 7
72 3 8
114 2 9
97 2 10
164 2 11
22 1 12
340 3 13
65 2 14
835 4 1 15
97 2 16
30 1 17
180 3 18
34 4 19
100 2 20
50 2 21
600 5 22
358 4 23
1108 6 2 24
130 2 25
249 3 26
30 1 27
30 1 28
20 1 29
7124 83 3 30
31
32
783 13 33
318 2 34
67 1 35
133 2 36
100 1 37
1813 5 38
75 1 39
100 2 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 / /2015/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).
CAMERON SUB 46.00 138.00TRANSMISSION-UNATTEN 1
CAMP WILLIAMS SUB 138.00 345.00 12.47TRANSMISSION-UNATTEN 2
CLOVER SUB 138.00 345.00 14.40TRANSMISSION-UNATTEN 3
COLUMBIA SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 4
CRANER FLAT SUB 12.47 138.00TRANSMISSION-UNATTEN 5
CROYDON SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 6
CUTLER SUB 46.00 138.00TRANSMISSION-UNATTEN 7
EL MONTE SUB 46.00 138.00TRANSMISSION-UNATTEN 8
GARKANE SUB 46.00 69.00TRANSMISSION-UNATTEN 9
GREEN CANYON SUB 46.00 138.00TRANSMISSION-UNATTEN 10
GRINDING SUB 13.80 138.00TRANSMISSION-UNATTEN 11
HELPER SUB 46.00 138.00TRANSMISSION-UNATTEN 12
HONEYVILLE SUB 46.00 138.00TRANSMISSION-UNATTEN 13
HORSESHOE SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 14
HUNTINGTON SUB 138.00 345.00 24.90TRANSMISSION-UNATTEN 15
JERUSALEM SUB 46.00 138.00TRANSMISSION-UNATTEN 16
LAMPO SUB 46.00 138.00TRANSMISSION-UNATTEN 17
MATHINGTON SUB 46.00 138.00 13.20TRANSMISSION-UNATTEN 18
MCFADDEN SUB 46.00 138.00TRANSMISSION-UNATTEN 19
MIDDLETON SUB 69.00 138.00 34.50TRANSMISSION-UNATTEN 20
MIDVALLEY SUB 138.00 345.00TRANSMISSION-UNATTEN 21
MIDWAY CITY SUB 46.00 138.00TRANSMISSION-UNATTEN 22
MINERAL PRODUCTS SUB 46.00 69.00TRANSMISSION-UNATTEN 23
MOAB SUB 69.00 138.00TRANSMISSION-UNATTEN 24
NEBO SUB 46.00 138.00TRANSMISSION-UNATTEN 25
PAROWAN VALLEY SUB 138.00 230.00 34.50TRANSMISSION-UNATTEN 26
PAVANT SUB 46.00 230.00TRANSMISSION-UNATTEN 27
PINTO SUB 138.00 345.00 69.00TRANSMISSION-UNATTEN 28
RED BUTTE SUB 138.00 345.00TRANSMISSION-UNATTEN 29
SIGURD SUB 230.00 345.00 138.00TRANSMISSION-UNATTEN 30
SMITHFIELD SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 31
SPANISH FORK SUB 138.00 345.00 46.00TRANSMISSION-UNATTEN 32
ST GEORGE SUB 16.50 138.00TRANSMISSION-UNATTEN 33
THREE PEAKS SUB 138.00 345.00TRANSMISSION-UNATTEN 34
WEST CEDAR SUB 138.00 230.00 34.50TRANSMISSION-UNATTEN 35
TOTAL 3377.77 8441.00 724.35 36
Number of Substations-43 37
38
WASHINGTON 39
ATTALIA 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 / /2015/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
169 2 2
448 1 3
71 2 4
40 2 5
81 2 6
50 1 7
312 3 8
33 1 9
67 2 10
225 3 11
142 2 12
35 1 13
80 2 14
270 4 15
67 1 16
75 1 17
160 5 1 18
45 1 19
141 4 20
900 2 21
67 1 22
12 1 23
67 1 24
67 1 25
138 2 26
133 2 27
258 3 28
414 2 29
1124 6 30
63 2 31
1017 5 32
100 3 1 33
450 1 34
262 3 35
10997 106 2 36
37
38
39
25 1 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 / /2015/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).
BOWMAN SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
CASCADE KRAFT SUB 12.47 69.00 4.16DISTRIBUTION-UNATTEN 2
CLINTON SUB 12.47 115.00DISTRIBUTION-UNATTEN 3
DAYTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
DODD ROAD SUB 20.80 69.00DISTRIBUTION-UNATTEN 5
GRANDVIEW SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 6
HOPLAND SUB 12.47 115.00DISTRIBUTION-UNATTEN 7
NACHES 12.00 115.00DISTRIBUTION-UNATTEN 8
NOB HILL SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
NORTH PARK SUB 12.47 115.00DISTRIBUTION-UNATTEN 10
ORCHARD SUB 12.47 115.00DISTRIBUTION-UNATTEN 11
PACIFIC SUB 12.47 115.00DISTRIBUTION-UNATTEN 12
POMEROY SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
PROSPECT POINT SUB 12.47 69.00DISTRIBUTION-UNATTEN 14
PUNKIN CENTER SUB 12.47 115.00DISTRIBUTION-UNATTEN 15
RIVER ROAD SUB 12.47 115.00DISTRIBUTION-UNATTEN 16
SELAH SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
SULPHUR CREEK SUB 12.47 115.00DISTRIBUTION-UNATTEN 18
SUNNYSIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 19
TIETON SUB 12.47 115.00 34.50DISTRIBUTION-UNATTEN 20
TOPPENISH SUB 12.47 115.00DISTRIBUTION-UNATTEN 21
TOUCHET SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
VOELKER SUB 12.47 115.00DISTRIBUTION-UNATTEN 23
WAITSBURG SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
WAPATO SUB 12.47 115.00DISTRIBUTION-UNATTEN 25
WENAS SUB 12.47 115.00DISTRIBUTION-UNATTEN 26
WHITE SWAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 27
WILEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 28
TOTAL 369.49 2921.00 107.66 29
Number of Substations-29 30
31
CENTRAL SUB 12.47 69.00T/D-UNATTENDED 32
MILL CREEK SUB 12.47 69.00T/D-UNATTENDED 33
UNION GAP SUB 115.00 230.00 12.47T/D-UNATTENDED 34
TOTAL 139.94 368.00 12.47 35
Number of Substations-3 36
37
OUTLOOK SUB 115.00 230.00TRANSMISSION-UNATTEN 38
PASCO SUB 69.00 115.00 7.20TRANSMISSION-UNATTEN 39
POMONA HEIGHTS SUB 115.00 230.00 13.20TRANSMISSION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.19
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
45 2 1
118 6 2
25 1 3
23 2 4
25 4 5
42 2 6
50 2 7
25 1 8
42 2 9
45 2 10
50 2 11
28 3 12
9 1 13
40 2 14
20 2 15
51 4 16
45 2 17
25 1 18
45 2 19
29 2 20
50 2 21
6 1 22
25 1 23
9 1 24
45 2 25
25 2 26
22 2 27
45 2 28
1034 59 29
30
31
14 1 32
45 2 33
345 4 34
404 7 35
36
37
125 1 38
39 9 39
325 3 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 / /2015/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).
WALLA WALLA 230KV SUB 69.00 230.00TRANSMISSION-UNATTEN 1
WALLULA SUB 69.00 230.00TRANSMISSION-UNATTEN 2
WINE COUNTRY SUB 115.00 230.00TRANSMISSION-UNATTEN 3
TOTAL 552.00 1265.00 20.40 4
Number of Substations-6 5
6
WYOMING 7
ANTELOPE MINE SUB 34.50 230.00DISTRIBUTION-UNATTEN 8
ASTLE STREET 13.20 34.50DISTRIBUTION-UNATTEN 9
BAILEY DOME SUB 12.47 57.00DISTRIBUTION-UNATTEN 10
BAR NUNN 13.20 116.00DISTRIBUTION-UNATTEN 11
BAR X SUB 34.50 230.00DISTRIBUTION-UNATTEN 12
BIG MUDDY SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
BIG PINEY SUB 24.90 69.00DISTRIBUTION-UNATTEN 14
BLACKS FORK SUB 34.50 230.00DISTRIBUTION-UNATTEN 15
BRIDGER PUMP SUB 34.50 230.00 13.20DISTRIBUTION-UNATTEN 16
BRYAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
BUFFALO TOWN SUB 4.16 20.80DISTRIBUTION-UNATTEN 18
BYRON SUB 4.16 34.50DISTRIBUTION-UNATTEN 19
CASSA SUB 20.80 57.00 12.47DISTRIBUTION-UNATTEN 20
CENTER STREET SUB 4.16 115.00DISTRIBUTION-UNATTEN 21
CHAPMAN SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
CHUKAR SUB 4.16 12.47DISTRIBUTION-UNATTEN 23
CHURCH AND DWIGHT SUB 0.48 34.50DISTRIBUTION-UNATTEN 24
COKEVILLE SUB 24.90 46.00DISTRIBUTION-UNATTEN 25
COLUMBIA-GENEVA SUB 13.80 230.00DISTRIBUTION-UNATTEN 26
COMMUNITY PARK SUB 13.20 115.00DISTRIBUTION-UNATTEN 27
CROOKS GAP SUB 12.47 34.50DISTRIBUTION-UNATTEN 28
DEER CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
DJ COAL MINE SUB 34.50 69.00DISTRIBUTION-UNATTEN 30
DOUGLAS SUB 2.30 57.00DISTRIBUTION-UNATTEN 31
DRY FORK SUB 4.16 69.00DISTRIBUTION-UNATTEN 32
ELK BASIN SUB 7.20 34.50DISTRIBUTION-UNATTEN 33
EMIGRANT SUB 12.47 115.00DISTRIBUTION-UNATTEN 34
EVANS SUB 12.47 115.00DISTRIBUTION-UNATTEN 35
EVANSTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 36
FORT CASPER SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
FORT SANDERS SUB 13.20 115.00DISTRIBUTION-UNATTEN 38
FRANNIE SUB 34.50 230.00DISTRIBUTION-UNATTEN 39
FRONTIER SUB 4.16 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.20
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/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.
300 2 1
120 2 2
250 1 3
1159 18 4
5
6
7
25 1 8
12 1 9
2 1 10
30 1 11
25 1 12
7 1 13
14 1 14
150 2 15
73 4 16
25 1 17
2 3 18
2 3 19
2 6 20
12 1 21
4 1 22
1 3 23
3 2 24
4 1 25
45 2 26
45 2 27
5 3 28
9 1 29
12 1 30
6 3 31
9 1 32
5 1 33
12 1 34
9 1 35
40 2 36
28 1 37
20 1 38
50 2 39
6 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 / /2015/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).
GARLAND SUB 34.50 230.00DISTRIBUTION-UNATTEN 1
GLENDO SUB 4.16 57.00DISTRIBUTION-UNATTEN 2
GRASS CREEK SUB 34.50 230.00DISTRIBUTION-UNATTEN 3
GREAT DIVIDE SUB 34.50 115.00DISTRIBUTION-UNATTEN 4
GREYBULL SUB 4.16 34.50DISTRIBUTION-UNATTEN 5
HANNA SUB 12.47 34.50DISTRIBUTION-UNATTEN 6
JACKALOPE SUB 12.47 115.00DISTRIBUTION-UNATTEN 7
KEMMERER SUB 24.90 69.00DISTRIBUTION-UNATTEN 8
KIRBY CREEK PUMPING STATION 2.40 115.00DISTRIBUTION-UNATTEN 9
KIRBY CREEK SUB 4.16 34.50DISTRIBUTION-UNATTEN 10
LANDER SUB 12.47 34.50DISTRIBUTION-UNATTEN 11
LARAMIE SUB 13.20 115.00DISTRIBUTION-UNATTEN 12
LATHAM SUB 34.50 230.00DISTRIBUTION-UNATTEN 13
LINCH SUB 13.80 69.00DISTRIBUTION-UNATTEN 14
LITTLE MOUNTAIN SUB 34.50 230.00DISTRIBUTION-UNATTEN 15
LOVELL SUB 4.16 34.50DISTRIBUTION-UNATTEN 16
MILL IRON SUB 13.80 34.50DISTRIBUTION-UNATTEN 17
MILLS SUB 4.16 46.00DISTRIBUTION-UNATTEN 18
MURPHY DOME SUB 13.20 34.50DISTRIBUTION-UNATTEN 19
NUGGETT SUB 7.20 69.00DISTRIBUTION-UNATTEN 20
OPAL SUB 24.90 69.00DISTRIBUTION-UNATTEN 21
ORIN SUB 7.20 57.00DISTRIBUTION-UNATTEN 22
ORPHA SUB 7.20 57.00DISTRIBUTION-UNATTEN 23
PARADISE SUB 25.00 69.00DISTRIBUTION-UNATTEN 24
PARCO SUB 12.47 34.50DISTRIBUTION-UNATTEN 25
PINEDALE SUB 24.90 69.00DISTRIBUTION-UNATTEN 26
PITCHFORK SUB 24.90 69.00DISTRIBUTION-UNATTEN 27
POISON SPIDER SUB 2.40 69.00DISTRIBUTION-UNATTEN 28
POLECAT SUB 12.47 34.50DISTRIBUTION-UNATTEN 29
RAINBOW SUB 13.20 34.50DISTRIBUTION-UNATTEN 30
RAVEN SUB 34.50 230.00DISTRIBUTION-UNATTEN 31
RED BUTTE SUB 13.20 115.00DISTRIBUTION-UNATTEN 32
REFINERY SUB 12.47 115.00DISTRIBUTION-UNATTEN 33
SAGE HILL SUB 13.20 34.50DISTRIBUTION-UNATTEN 34
SHOSHONI SUB 2.40 34.50DISTRIBUTION-UNATTEN 35
SLATE CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
SOUTH CODY SUB 24.90 69.00DISTRIBUTION-UNATTEN 37
SOUTH ELK BASIN SUB 4.16 34.50DISTRIBUTION-UNATTEN 38
SOUTH TRONA SUB 34.50 230.00DISTRIBUTION-UNATTEN 39
SPRING CREEK SUB 13.20 115.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.21
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
45 2 1
3 4 2
25 1 3
20 1 4
3 1 5
6 1 6
25 1 7
10 1 8
3 3 9
2 3 10
25 2 11
50 2 12
25 1 13
12 1 14
20 1 15
4 1 16
12 1 17
1 3 18
5 1 19
1 20
8 1 21
1 1 22
3 3 23
30 1 24
5 1 25
20 1 26
17 9 2 27
3 1 28
1 3 29
12 1 30
200 2 31
30 1 32
45 2 33
6 1 34
2 3 35
1 1 36
14 3 1 37
2 6 38
150 2 39
28 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 / /2015/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).
SVILAR SUB 4.16 34.50DISTRIBUTION-UNATTEN 1
TEN MILE STEP DOWN SUB 12.50 34.50DISTRIBUTION-UNATTEN 2
TEN MILE SUB 34.50 69.00DISTRIBUTION-UNATTEN 3
THERMOPOLIS TOWN SUB 4.16 34.50DISTRIBUTION-UNATTEN 4
THUNDER CREEK SUB 12.47 57.00DISTRIBUTION-UNATTEN 5
VETERANS SUB 13.20 34.50DISTRIBUTION-UNATTEN 6
WELCH SUB 2.40 57.00DISTRIBUTION-UNATTEN 7
WERTZ-SINCLAIR SUB 4.16 57.00 12.50DISTRIBUTION-UNATTEN 8
WEST ADAMS SUB 4.16 34.50DISTRIBUTION-UNATTEN 9
WESTVACO SUB 34.50 230.00DISTRIBUTION-UNATTEN 10
WORLAND TOWN SUB 4.16 34.50DISTRIBUTION-UNATTEN 11
WYOPO SUB 34.50 230.00DISTRIBUTION-UNATTEN 12
WYUTA SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
TOTAL 1320.03 7769.27 38.17 14
Number of Substations-86 15
16
BUFFALO SUB 20.80 230.00T/D-UNATTENDED 17
ELK HORN SUB 12.47 115.00T/D-UNATTENDED 18
FIREHOLE SUB 34.50 230.00T/D-UNATTENDED 19
HILLTOP SUB 34.50 115.00 20.80T/D-UNATTENDED 20
LABARGE SUB 24.90 69.00T/D-UNATTENDED 21
POINT OF ROCKS SUB 34.50 230.00T/D-UNATTENDED 22
RIVERTON 230 SUB 12.47 230.00 34.50T/D-UNATTENDED 23
YELLOWCAKE SUB 34.50 230.00T/D-UNATTENDED 24
TOTAL 208.64 1449.00 55.30 25
Number of Substations-8 26
27
DAVE JOHNSTON PLANT/SUB 115.00 230.00 69.00TRANSMISSION-ATTENDE 28
JIM BRIDGER 345KV SUB 230.00 345.00 34.50TRANSMISSION-ATTENDE 29
NAUGHTON SUB 138.00 230.00 69.00TRANSMISSION-ATTENDE 30
BAIROIL SUB 34.50 115.00 57.00TRANSMISSION-UNATTEN 31
CASPER SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 32
CHAPPELL CREEK SUB 69.00 230.00TRANSMISSION-UNATTEN 33
CHIMNEY BUTTE SUB 69.00 230.00TRANSMISSION-UNATTEN 34
FOOTE CREEK WIND FARM 34.50 230.00TRANSMISSION-UNATTEN 35
GLENDO AUTO SUB 57.00 69.00TRANSMISSION-UNATTEN 36
MANSFACE SUB 34.50 230.00TRANSMISSION-UNATTEN 37
MIDWEST SUB 69.00 230.00 34.50TRANSMISSION-UNATTEN 38
MINERS SUB 34.50 230.00 9.70TRANSMISSION-UNATTEN 39
MUSTANG SUB 115.00 230.00TRANSMISSION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.22
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2015/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 3 1
5 1 2
12 1 3
5 1 4
9 1 5
25 2 6
3 3 7
2 6 8
3 1 9
25 1 10
5 1 11
20 1 1 12
1 13
1684 156 4 14
15
16
20 1 17
25 1 18
50 2 19
45 2 1 20
8 6 21
25 1 22
74 4 23
25 1 24
272 18 1 25
26
27
336 4 28
703 7 29
661 4 30
53 3 31
575 4 32
67 1 33
75 1 34
196 2 35
15 2 36
20 1 37
157 3 38
20 1 39
100 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 / /2015/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).
OREGON BASIN SUB 34.50 230.00 69.00TRANSMISSION-UNATTEN 1
PLATTE SUB 115.00 230.00 34.50TRANSMISSION-UNATTEN 2
RAILROAD SUB 138.00 230.00TRANSMISSION-UNATTEN 3
ROCK SPRINGS 230 SUB 34.50 230.00TRANSMISSION-UNATTEN 4
SAGE SUB 46.00 69.00TRANSMISSION-UNATTEN 5
THERMOPOLIS SUB 115.00 230.00TRANSMISSION-UNATTEN 6
TOTAL 1598.00 4048.00 446.20 7
Number of Substations-19 8
9
CALIFORNIA 10
Distribution - 42 11
T/D - 2 12
Transmission - 6 13
14
IDAHO 15
Distribution - 65 16
T/D - 5 17
Transmission - 17 18
19
MONTANA 20
Transmission - 3 21
22
OREGON 23
Distribution - 180 24
T/D - 12 25
Transmission - 28 26
27
UTAH 28
Distribution - 280 29
T/D - 31 30
Transmission - 43 31
32
WASHINGTON 33
Distribution - 29 34
T/D - 3 35
Transmission - 6 36
37
WYOMING 38
Distribution - 86 39
T/D - 8 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 / /2015/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.
65 2 1
140 3 2
400 1 3
50 2 4
23 1 5
175 2 6
3831 45 7
8
9
10
323 11
130 12
762 13
14
15
736 16
344 17
5276 18
19
20
200 21
22
23
4609 24
1310 25
7511 26
27
28
5578 29
7124 30
10997 31
32
33
1034 34
404 35
1159 36
37
38
1684 39
272 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 / /2015/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 - 19 1
2
ALL STATES 3
Distribution - 682 4
T/D - 61 5
Transmission - 122 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 / /2015/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.
3831 1
2
3
13964 4
9584 5
29736 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.: 19 Column: a
The Antelope 230kV, 161kV and 138kV Substation is jointly owned by PacifiCorp and Idaho
Power Company. Ownership and operations and maintenance costs vary by type of asset as
defined in the Joint Ownership and Operating Agreement.
Schedule Page: 426.3 Line No.: 21 Column: a
The Big Grassy 161kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.
Schedule Page: 426.3 Line No.: 26 Column: a
The Goshen 345kV and 161kV Substation is jointly owned by PacifiCorp and Idaho Power
Company. Ownership and operations and maintenance costs vary by type of asset as defined
in the Joint Ownership and Operating Agreement.
Schedule Page: 426.3 Line No.: 28 Column: a
The Jefferson 161kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.
Schedule Page: 426.3 Line No.: 29 Column: a
The Midpoint 500kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.
Schedule Page: 426.3 Line No.: 33 Column: a
The Threemile Knoll 345kV Substation is jointly owned by PacifiCorp and Idaho Power
Company. Ownership and operations and maintenance costs vary by type of asset as defined
in the Joint Ownership and Operating Agreement.
Schedule Page: 426.3 Line No.: 39 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.: 40 Column: a
The Colstrip 500kV and 230kV 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.: 11 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.: 16 Column: a
The Hurricane 230kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.
Schedule Page: 426.9 Line No.: 21 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.: 22 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: 426.20 Line No.: 1 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
The Walla Walla 230kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.
Schedule Page: 426.22 Line No.: 28 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.: 29 Column: a
The Jim Bridger 345kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/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
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
PacifiCorp X
/ /2015/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 / support services / construction
3 and maintenance / equipment rental 185,697,769Bridger Coal Company
4
5 Deer Creek coal mine closure/decommissioning
6 services and coal mining services 18,430,819Energy West Mining Company 151, 182.3
7
8 Coal purchases 15,484,422Trapper Mining Inc. 151
9
10 Administrative support services 1,068,243Interwest Mining Company
11
12 Administrative services under the IASA 4,737,182BHE
13 Administrative services under the IASA 4,871,181MEC
14 Administrative services under the IASA 64,298Kern River Gas Transmission Company 107, 426.5, 923
15
16 Gas transportation services 3,085,186Kern River Gas Transmission Company 547
17
18 Employee relocation services 1,759,354HomeServices of America, Inc.
19
20 Non-power Goods or Services Provided for Affiliate
21 Proceeds from sale of mining equipment and
22 information technology and administrative
23 support services 18,113,622Bridger Coal Company
24
25 Financial support services and employee benefits 475,819Interwest Mining Company 557
26
27 Joint use services 1,079,992Charter Communications, Inc.
28
29 Administrative services under the IASA 457,681BHE
30 Administrative services under the IASA 2,215,513MEC
31 Administrative services under the IASA 266,330HomeServices of America, Inc. 920, 921
32 Administrative services under the IASA 325,088Northern Natural Gas Company
33 Administrative services under the IASA 1,648,557BHE U.S. Transmission, LLC
34 Administrative services under the IASA 305,137MTL Canyon Holdings, LLC 560, 920, 921
35 Administrative services under the IASA 369,922MCCT 920, 921
36
37
38
39
40
41
42
1 Non-power Goods or Services Provided by Affiliated
2 Rail services / right-of-way fees 39,485,617BNSF Railway Company 151,507,567,589
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
/ /2015/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 Banking services and financial transactions
5 related to energy hedging activity 7,002,152Wells Fargo & Company
6
7 Banking services 568,431U.S. Bancorp
8
9 Computer hardware and software and computer
10 systems maintenance and support services 1,957,304International Business Machines Corp 165,909,921,935
11
12 Rating agency fees 314,111Moody's Investors Service 181, 186, 930.2
13
14 Surety bond premium 427,920National Indemnity Company 165
15
16
17
18
19
20 Non-power Goods or Services Provided for Affiliate
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
1 Non-power Goods or Services Provided by Affiliated
2
3
4
FERC FORM NO. 1 (New) Page 429.1
FERC FORM NO. 1-F (New)
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
/ /2015/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
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20 Non-power Goods or Services Provided for Affiliate
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (New) Page 429.2
FERC FORM NO. 1-F (New)
Schedule Page: 429 Line No.: 3 Column: c
Accounts charged for Bridger Coal Company: 107, 108, 151, 501 and 514.
Schedule Page: 429 Line No.: 3 Column: d
Non-power goods or services provided by Bridger Coal Company are as follows:
Coal purchases $185,643,100
Support services, construction and maintenance and equipment rental 54,669
$185,697,769
Schedule Page: 429 Line No.: 6 Column: d
Non-power goods or services provided by Energy West Mining Company are as follows:
Deer Creek coal mine closure/decommissioning services $17,648,065
Coal mining services 782,754
$18,430,819
Under the terms of the coal mining agreement between PacifiCorp and Energy West Mining
Company, Energy West Mining Company provided coal mining services to PacifiCorp that are
absorbed directly by PacifiCorp.
Schedule Page: 429 Line No.: 10 Column: c
Accounts charged for Interwest Mining Company: 421, 426.5, 557 and 928.
Schedule Page: 429 Line No.: 10 Column: d
Interwest Mining Company manages PacifiCorp's mining operations and charges management
services to Bridger Coal Company and Energy West Mining Company. Interwest Mining Company
also charges PacifiCorp for administrative support services. All costs incurred by
Interwest Mining Company are absorbed by PacifiCorp, Bridger Coal Company and Energy West
Mining Company.
Schedule Page: 429 Line No.: 12 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. Nine 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.
Plant: This allocator distributes costs of managing the corporate insurance function based
on assets for each affiliate.
Schedule Page: 429 Line No.: 12 Column: c
Accounts charged for BHE: 426.4, 426.5 and 923.
Schedule Page: 429 Line No.: 12 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
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.: 13 Column: b
This footnote applies to all occurrences of “MEC” on page 429. Complete name is
MidAmerican Energy Company.
Schedule Page: 429 Line No.: 13 Column: c
Accounts charged for MEC: 107, 143, 146, 426.4, 426.5, 921 and 923.
Schedule Page: 429 Line No.: 13 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.: 14 Column: d
Excluded from this line are "convenience" payments made to vendors by one entity on behalf
of, and charged to, other entities within the 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.: 18 Column: c
Accounts charged for HomeServices of America, Inc.: 184, 501, 502, 506, 535, 539, 548,
549, 553, 557, 560, 561.2, 580, 581, 590, 592, 593, 901, 902, 903, 908 and 921.
Schedule Page: 429 Line No.: 23 Column: c
Accounts charged for Bridger Coal Company: 107, 182.3, 501, 557, 909, 920 and 921.
Schedule Page: 429 Line No.: 23 Column: d
Non-power goods or services provided to Bridger Coal Company are as follows:
Proceeds from sale of mining equipment $17,741,467
Information technology and administrative support 372,155
$18,113,622
Schedule Page: 429 Line No.: 25 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.: 27 Column: c
Accounts charged for Charter Communications, Inc.: 253, 454, 593 and 929.
Schedule Page: 429 Line No.: 29 Column: c
Accounts charged for BHE: 426.5, 557, 560, 920 and 921.
Schedule Page: 429 Line No.: 29 Column: d
Excluded from this line are "convenience" payments made to vendors by one entity on behalf
of, and charged to, other entities within the 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.: 30 Column: c
Accounts charged for MEC: 426.5, 506, 549, 556, 557, 580, 588, 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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
constitute "services" as required by this page.
Schedule Page: 429 Line No.: 31 Column: d
Excluded from this line are "convenience" payments made to vendors by one entity on behalf
of, and charged to, other entities within the 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.: 32 Column: c
Accounts charged for Northern Natural Gas Company: 426.5, 557, 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: c
Accounts charged for BHE U.S. Transmission, LLC: 426.5, 557, 560, 580, 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
Complete name is MidAmerican Central California Transco, LLC.
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.: 2 Column: d
Non-power goods or services provided by BNSF Railway Company are as follows:
Rail services $39,428,357
Right-of-way fees 57,260
$39,485,617
Included in the rail services are amounts related to a jointly-owned plant that are paid
indirectly to BNSF Railway Company.
Schedule Page: 429.1 Line No.: 5 Column: c
Accounts charged for Wells Fargo & Company: 228.3, 419, 426.5, 427, 431, 501, 547, 560,
588, 903, 921 and 928.
Schedule Page: 429.1 Line No.: 5 Column: d
Non-power goods or services provided by Wells Fargo & Company are as follows:
Banking services $1,362,102
Financial transactions related to energy hedging activity 5,640,050
$7,002,152
Schedule Page: 429.1 Line No.: 7 Column: c
Accounts charged for U.S. Bancorp: 419, 427, 431, 537, 557, 903, 920, 928 and 930.2.
Schedule Page: 429.1 Line No.: 10 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
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
INDEX
Schedule Page No.
Accrued and prepaid taxes ........................................................................ 262-263
Accumulated Deferred Income Taxes .................................................................... 234
272-277
Accumulated provisions for depreciation of
common utility plant ............................................................................. 356
utility plant .................................................................................... 219
utility plant (summary) ...................................................................... 200-201
Advances
from associated companies .................................................................... 256-257
Allowances ....................................................................................... 228-229
Amortization
miscellaneous .................................................................................... 340
of nuclear fuel .............................................................................. 202-203
Appropriations of Retained Earnings .............................................................. 118-119
Associated Companies
advances from ................................................................................ 256-257
corporations controlled by respondent ............................................................ 103
control over respondent .......................................................................... 102
interest on debt to .......................................................................... 256-257
Attestation ............................................................................................ i
Balance sheet
comparative .................................................................................. 110-113
notes to ..................................................................................... 122-123
Bonds ............................................................................................ 256-257
Capital Stock ........................................................................................ 251
expense .......................................................................................... 254
premiums ......................................................................................... 252
reacquired ....................................................................................... 251
subscribed ....................................................................................... 252
Cash flows, statement of ......................................................................... 120-121
Changes
important during year ........................................................................ 108-109
Construction
work in progress - common utility plant .......................................................... 356
work in progress - electric ...................................................................... 216
work in progress - other utility departments ................................................. 200-201
Control
corporations controlled by respondent ............................................................ 103
over respondent .................................................................................. 102
Corporation
controlled by .................................................................................... 103
incorporated ..................................................................................... 101
CPA, background information on ....................................................................... 101
CPA Certification, this report form ................................................................. i-ii
FERC FORM NO. 1 (ED. 12-93)Index 1
INDEX (continued)
Schedule Page No.
Deferred
credits, other ................................................................................... 269
debits, miscellaneous ............................................................................ 233
income taxes accumulated - accelerated
amortization property ........................................................................ 272-273
income taxes accumulated - other property .................................................... 274-275
income taxes accumulated - other ............................................................. 276-277
income taxes accumulated - pollution control facilities .......................................... 234
Definitions, this report form ........................................................................ iii
Depreciation and amortization
of common utility plant .......................................................................... 356
of electric plant ................................................................................ 219
336-337
Directors ............................................................................................ 105
Discount - premium on long-term debt ............................................................. 256-257
Distribution of salaries and wages ............................................................... 354-355
Dividend appropriations .......................................................................... 118-119
Earnings, Retained ............................................................................... 118-119
Electric energy account .............................................................................. 401
Expenses
electric operation and maintenance ........................................................... 320-323
electric operation and maintenance, summary ...................................................... 323
unamortized debt ................................................................................. 256
Extraordinary property losses ........................................................................ 230
Filing requirements, this report form
General information .................................................................................. 101
Instructions for filing the FERC Form 1 ............................................................. i-iv
Generating plant statistics
hydroelectric (large) ........................................................................ 406-407
pumped storage (large) ....................................................................... 408-409
small plants ................................................................................. 410-411
steam-electric (large) ....................................................................... 402-403
Hydro-electric generating plant statistics ....................................................... 406-407
Identification ....................................................................................... 101
Important changes during year .................................................................... 108-109
Income
statement of, by departments ................................................................. 114-117
statement of, for the year (see also revenues) ............................................... 114-117
deductions, miscellaneous amortization ........................................................... 340
deductions, other income deduction ............................................................... 340
deductions, other interest charges ............................................................... 340
Incorporation information ............................................................................ 101
Index 2FERC FORM NO. 1 (ED. 12-95)
INDEX (continued)
Schedule Page No.

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